<PAGE>

                                  UNITED STATES

                       SECURITIES AND EXCHANGE COMMISSION

                             Washington, D. C. 20549

                                    FORM 10-K

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

                                       OR

|_|         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, 1999
                                             -----------------

Commission      Registrant, State of Incorporation,            IRS Employer
File Number        Address, and Telephone Number           Identification Number
-----------        -----------------------------           ---------------------

  1-10568                LG&E Energy Corp.                      61-1174555
                     (A Kentucky Corporation)
                       220 West Main Street
                          P. O. Box 32030
                    Louisville, Kentucky 40232
                          (502) 627-2000

  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

                                 (606) 255-2100

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

                                LG&E Energy Corp.

                                                        Name of each exchange on
                 Title of each class                        which registered
                 -------------------                        ----------------
           Common Stock, without par value               New York Stock Exchange
                                                                   and
        Rights to Purchase Series A Preferred            Chicago Stock Exchange
              Stock, without par value

                      Louisville Gas and Electric Company

                                                        Name of each exchange on
                 Title of each class                        which registered
                 -------------------                        ----------------
First Mortgage Bonds, Series due July 1, 2002, 7 1/2%    New York Stock Exchange

<PAGE>

                           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 29, 2000, the aggregate market value of LG&E Energy Corp.'s
voting common stock held by non-affiliates totaled $2,858,467,522, and it had
129,677,030 shares of common stock outstanding. As of February 29, 2000, the
aggregate market value of Louisville Gas and Electric Company's voting preferred
stock held by non-affiliates totaled $16,775,597, and it had 21,294,223 shares
of common stock outstanding, all held by LG&E Energy Corp, and 860,287 shares of
voting preferred stock outstanding. As of February 29, 2000, the aggregate
market value of Kentucky Utility Company's voting stock held by non-affiliates
totaled zero, and it 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 LG&E Energy Corp., 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. In particular, information contained herein related to
LG&E Energy Corp. or any of its direct or indirect subsidiaries other than
Louisville Gas and Electric Company or Kentucky Utilities Company is provided
solely by LG&E Energy Corp., not Louisville Gas and Electric Company or Kentucky
Utilities Company, and shall be deemed not included in the Form 10-K of
Louisville Gas and Electric Company or the Form 10-K of Kentucky Utilities
Company.

                       DOCUMENTS INCORPORATED BY REFERENCE

LG&E Energy Corp.'s and Louisville Gas and Electric Company's respective proxy
statements, to be filed with the Commission during April 2000, are incorporated
by reference into Part III of this Form 10-K.

<PAGE>

                                TABLE OF CONTENTS

                                     PART I

Item 1.    Business........................................................    1
           Overview of Operations..........................................    1
           Merger with KU Energy Corporation...............................    1
           Discontinuance of Merchant Energy Trading and Sales Business....    2
           Louisville Gas and Electric Company
                General....................................................    3
                Electric Operations........................................    5
                Gas Operations.............................................    6
                Rates and Regulation.......................................    7
                Construction Program and Financing.........................    7
                Coal Supply................................................    8
                Gas Supply.................................................    8
                Environmental Matters......................................    9
                Competition................................................    9
           Kentucky Utilities Company
                General....................................................    9
                Electric Operations........................................   10
                Rates and Regulation.......................................   11
                Construction Program and Financing.........................   11
                Coal Supply................................................   12
                Environmental Matters......................................   12
           LG&E Capital Corp...............................................   13
           Power Operations................................................   13
           Western Kentucky Energy.........................................   15
           Argentine Gas Distribution Division.............................   16
           Capital Corp. Other.............................................   17
           Discontinued Operations.........................................   19
           Employees and Labor Relations...................................   19
Item 2.    Properties......................................................   20
Item 3.    Legal Proceedings...............................................   24
Item 4.    Submission of Matters to a Vote of Security Holders.............   26
Executive Officers of the Company..........................................   27

                                     PART II

Item 5.    Market for the Registrant's Common Equity and Related
                Stockholder Matters........................................   34
Item 6.    Selected Financial Data.........................................   35
Item 7.    Management's Discussion and Analysis of Results of
                Operations and Financial Condition:
                    LG&E Energy Corp.......................................   38
                    Louisville Gas and Electric Company....................   56
                    Kentucky Utilities Company.............................   66
Item 7A.   Quantitative and Qualitative Disclosures About Market Risk......   74
Item 8.    Financial Statements and Supplementary Data:
                LG&E Energy Corp...........................................   75
                Louisville Gas and Electric Company........................  119
                Kentucky Utilities Company.................................  145
Item 9.    Changes in and Disagreements with Accountants on Accounting
                and Financial Disclosure...................................  167

<PAGE>

                            TABLE OF CONTENTS (CONT.)

                                    PART III

Item 10.   Directors and Executive Officers of the Registrant (a)..........  167
Item 11.   Executive Compensation (a)......................................  167
Item 12.   Security Ownership of Certain Beneficial Owners
                and Management (a).........................................  167
Item 13.   Certain Relationships and Related Transactions (a)..............  167

                                     PART IV

Item 14.   Exhibits, Financial Statement Schedules,
                and Reports on Form 8-K....................................  167
Signatures      ...........................................................  195

(a) Incorporated by reference.

<PAGE>

                             INDEX OF ABBREVIATIONS

Act                           The Clean Air Act Amendments of 1990
AP&L                          Arkansas Power & Light Company
Big Rivers                    Big Rivers Electric Corporation
BPA                           Bonneville Power Administration
Capital Corp.                 LG&E Capital Corp.
Centro                        Distribuidora de Gas Del Centro
Company                       LG&E Energy Corp.
CRC                           CRC-Evans Holdings Corp. and Affiliates
Cuyana                        Distribuidora de Gas Cuyana
CWLP                          City of Springfield, Illinois, City Water,
                              Light and Power Company
D&P                           Duff & Phelps Credit Rating Co.
DSM                           Demand Side Management
ECR                           Environmental Cost Recovery
EEI                           Electric Energy, Inc.
EITF                          Emerging Issues Task Force Issue
Energy Systems                LG&E Energy Systems Inc.
EPA                           U.S. Environmental Protection Agency
ESM                           Earnings Sharing Mechanism
EWG                           Exempt Wholesale Generator
FAC                           Fuel Adjustment Clause
FERC                          Federal Energy Regulatory Commission
FPA                           Federal Power Act
FT                            Firm Transportation
FUCO                          Foreign Utility Company
Gas BAN                       Gas Natural Ban, S.A.
Gas Operations                Natural Gas Gathering and Processing Business
Gas Systems                   LG&E Gas Systems Inc.
GSC                           Gas Supply Clause
Hancock                       John Hancock Mutual Life Insurance Company
Henderson                     City of Henderson, Kentucky
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
Inversora                     Inversora de Gas Del Centro
IT                            Information Technology
Kenetech                      Kenetech Windpower, Inc.
Kentucky Commission           Kentucky Public Service Commission
KIUC                          Kentucky Industrial Utility Consumers, Inc.
KU                            Kentucky Utilities Company
KU Capital                    KU Capital Corporation
KU Energy Common Stock        Each outstanding share of the common stock,
                              without par value, of KU Energy
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 Energy Common Stock      Common stock of LG&E Energy
LIBOR                         London Interbank Offered Rate
LII                           LG&E International Inc.
LIU                           Laborers International Union of North America
LPI                           LG&E Power Inc.
Mcf                           Thousand Cubic Feet

<PAGE>

                         INDEX OF ABBREVIATIONS (CONT.)

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.
MRA                           Master Restructuring Agreement
Mw                            Megawatts
Mwh                           Megawatt hours
NAAQS                         National Ambient Air Quality Standards
NGA                           Natural Gas Act
NGPA                          Natural Gas Policy Act of 1978
NIMO                          Niagara Mohawk Power Corporation
NNS                           No-Notice Service
Non-Utility Operations        Operations of Capital Corp. and LEM
NOx                           Nitrogen Oxide
OMU                           Owensboro Municipal Utilities
OPC                           Oglethorpe Power Corporation
PBR                           Performance-Based Ratemaking
Portland General              Portland General Electric Company
PowerGen                      PowerGen Plc
Power Operations              Capital Corp.'s Independent Power Operations
PPA                           Long-Term Power Purchase Agreement
PUHCA                         Public Utility Holding Company Act of 1935
PURPA                         Public Utility Regulatory Policy Act of 1978
QF                            Qualifying Cogeneration Facility
ROVA I                        Roanoke Valley I Facility
ROVA II                       Roanoke Valley II Facility
S&P                           Standard & Poor's Rating Services
SEC                           Securities and Exchange Commission
SERP                          Supplemental Security Plan
SFAS                          Statement of Financial Accounting Standards
SIP                           State Implementation Plan
SO2                           Sulfur Dioxide
SOP                           Statement of Position
Southampton                   Southampton Cogeneration Facility
Staff                         Virginia Commission Staff
Tarifa                        K.W. Tarifa, S.A.
Tennessee                     Tennessee Gas Pipeline Company
Texas Gas                     Texas Gas Transmission Corporation
TLP                           Tenaska Limited Partnerships
TRA                           Tennessee Regulatory Authority
Trimble County                LG&E's Trimble County Unit 1
UAJ-APPI                      United Association of Journeymen and Apprentices
                              of the Plumbing and Pipefitting Industry of the
                              United States and Canada
USEPA                         U.S. Environmental Protection Agency
USWA                          United Steelworkers of America
Utility Operations            Operations of LG&E and KU
VEPCO                         Virginia Electric and Power Company
Virginia Commission           Virginia State Corporation Commission
WKE                           Western Kentucky Energy Corp. and its Affiliates
WLP                           Westmoreland-LG&E Partners
WPP 93                        Windpower Partners 1993
WPP 94                        Windpower Partners 1994

<PAGE>

                                     PART I.

Item 1. Business.

                             OVERVIEW OF OPERATIONS

LG&E Energy, incorporated November 14, 1989, is a diversified energy-services
holding company with four direct operating subsidiaries: LG&E, KU, Capital
Corp., and LEM. The Company's domestic regulated operations are conducted by
LG&E and KU.

The Company and its subsidiaries currently are exempt from all provisions,
except Section 9(a)(2), of the Public Utility Holding Company Act of 1935 (the
"Holding Company Act") on the basis that the Company, LG&E and KU are
incorporated in the same state and their business is predominately intrastate in
character and carried on substantially in the state of incorporation.

The Company is not a public utility under the laws of the Commonwealths of
Kentucky or of Virginia and is not subject to regulation as such by the Kentucky
Commission or the Virginia Commission. See LG&E - Rates and Regulation and KU -
Rates and Regulation for descriptions of the regulation of LG&E and KU by the
Kentucky Commission, and of KU by the Virginia Commission and FERC, which
includes the ability to regulate certain intercompany transactions between LG&E,
KU and the Company, including the Company's non-utility subsidiaries.

                           POWERGEN TRANSACTION

On February 28, 2000, the Company announced that its Board of Directors
accepted an 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 the
Company's debt. Pursuant to the acquisition agreement, among other things,
LG&E Energy will become a wholly owned subsidiary of PowerGen and its U.S.
headquarters. The Utility Operations of the Company will continue their
separate identities and serve customers in Kentucky and Virginia under their
present names. The preferred stock and debt securities of the Utility
Operations will not be affected by this transaction. The acquisition is
expected to close 9 to 12 months from the announcement, shortly after all of
the conditions to consummation of the acquisition are met. Those conditions
include, without limitation, the approval of the holders of a majority of the
outstanding shares of common stock of each of LG&E Energy and PowerGen, the
receipt of all necessary governmental approvals and the making of all
necessary governmental filings, including approvals of various regulators in
Kentucky and Virginia under state utility laws, the approval of the FERC
under the FPA, the approval of the SEC under the PUHCA of 1935, and the
filing of requisite notifications with the Federal Trade Commission and the
Department of Justice under the Hart-Scott-Rodino Antitrust Improvements Act
of 1976, as amended, and the expiration of all applicable waiting periods
thereunder. Shareholder meetings to vote upon the approval of the acquisition
are expected to be held during the second quarter of 2000 for both LG&E
Energy and PowerGen. During the first quarter of 2000, the Company expensed
approximately $1.0 million relating to the PowerGen transaction. The
foregoing description of the acquisition does not purport to be complete and
is qualified in its entirety by reference to LG&E Energy's current reports on
Form 8-K, filed February 29, 2000, with the SEC.

                        MERGER WITH KU ENERGY CORPORATION

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 accompanying consolidated financial statements
reflect the accounting for the merger as a pooling of interests and are
presented as if the companies were combined as of the earliest period presented.
However, the financial information is not necessarily indicative of the results
of operations, financial position or cash flows that would have occurred had the
merger been consummated for the periods for which it is given effect, nor is it
necessarily


                                       1
<PAGE>

indicative of future results of operations, financial position, or cash flows.
The financial statements reflect the conversion of each outstanding share of KU
Energy common stock into 1.67 shares of LG&E Energy common stock. The
outstanding preferred stock of LG&E, a subsidiary of LG&E Energy, and KU, a
subsidiary of KU Energy, were not affected by the Merger. See Note 2 of LG&E
Energy's Notes to Financial Statements under Item 8.

          DISCONTINUANCE OF MERCHANT ENERGY TRADING AND SALES BUSINESS

Effective June 30, 1998, the Company discontinued its merchant energy trading
and sales business. This business consisted primarily of a portfolio of energy
marketing contracts entered into in 1996 and early 1997, nationwide deal
origination and some level of speculative trading activities, which were not
directly supported by the Company's physical assets. The Company's decision to
discontinue these operations was primarily based on the impact that volatility
and rising prices in the power market had on its portfolio of energy marketing
contracts. Exiting the merchant energy trading and sales business enabled the
Company to focus on optimizing the value of physical assets it owns or controls,
and reduced the earnings impact on continuing operations of extreme market
volatility in its portfolio of energy marketing contracts. The Company continues
to settle commitments that obligate it to buy and sell natural gas and electric
power. If the Company is unable to dispose of these commitments or assets it
will continue to meet its obligations under the terms of the contracts. The
Company, however, has maintained sufficient market knowledge, risk management
skills, technical systems and experienced personnel to maximize the value of
power sales from physical assets it owns or controls, including LG&E, KU and
WKE.

As a result of the Company's decision to discontinue its merchant energy trading
and sales activity, and the initial decision to sell the associated gas
gathering and processing business, the Company recorded an after-tax loss on
disposal of discontinued operations of $225 million in the second quarter of
1998. The loss on disposal of discontinued operations resulted primarily from
several fixed-price energy marketing contracts entered into in 1996 and early
1997, including the Company's long-term contract with OPC. Other components of
the write-off included costs relating to certain peaking options, goodwill
associated with the Company's 1995 purchase of merchant energy trading and sales
operations and exit costs.

At the time the Company decided to discontinue its merchant energy trading and
sales business, it also decided to sell its natural gas gathering and processing
business. Effective June 30, 1999, the Company decided to retain this business.
The accompanying financial statements reflect the reclassification of the
natural gas gathering and processing business as continuing operations for all
periods presented. Approximately $800,000 of net losses charged to the loss on
disposal of discontinued operations was reclassified to continuing operations in
the accompanying income statement in each of 1999 and 1998 related to the
natural gas gathering and processing business. See Note 4 of LG&E Energy's Notes
to Financial Statements under Item 8 for more information.

In the fourth quarter of 1999, the Company received an adverse decision from the
arbitration panel considering its contract dispute with OPC, which was commenced
by the Company in April 1998. As a result of this adverse decision, higher than
anticipated commodity prices, increased load demands, and other factors, the
Company increased its after-tax accrued loss on disposal of discontinued
operations by $175 million. The additional write-off included costs related to
the remaining commitments in its portfolio and exit costs expected to be
incurred to serve those commitments. Although the Company used what it believes
to be appropriate estimates for future energy prices, among other factors, to
calculate the net realizable value of discontinued operations, there are
inherent limitations in models to accurately predict future commodity prices,
load demands and other events that could impact the amounts recorded by the
Company. See Notes 3 and 18 of LG&E Energy's Notes to Financial Statements under
Item 8.


                                       2
<PAGE>

The Company reclassified its financial statements for prior periods to present
the operating results, financial position and cash flows of the merchant energy
trading and sales business as discontinued operations. See Notes 1, 3 and 4 of
LG&E Energy's Notes to Financial Statements under Item 8 for more information.

                                 CRC ACQUISITION

In July 1999, the Company purchased 100% of the outstanding common stock of CRC
for initial consideration of $45.6 million and retirement of approximately $35.3
million in CRC debt. CRC, based in Houston, Texas, is a provider of specialized
equipment and services used in the construction and rehabilitation of gas and
oil transmission pipelines. The purchase agreement provides for future annual
earn-out payments to the previous owners based on CRC's meeting certain
financial targets over the period ending March 31, 2002, and, under certain
circumstances, a change in control of LG&E Energy may accelerate the earnout.
The acquisition agreement capped the total of these payments at $34.3 million.
The Company accounted for the acquisition using the purchase method and recorded
goodwill of approximately $42.1 million. Additional goodwill will be recorded
contingent upon future earn-out payments. Goodwill is being amortized over a
period of twenty years. See Note 2 of LG&E Energy's Notes to Financial
Statements under Item 8.

                               GAS BAN ACQUISITION

In March 1999, the Company acquired an indirect 20% ownership interest in Gas
BAN, a natural gas distribution company that serves 1.1 million customers in the
northern portion of the province of Buenos Aires, Argentina. The purchase price
totaled $74.3 million, including transaction costs, which has been reflected in
investments in unconsolidated ventures in the accompanying balance sheet. The
Company accounted for the acquisition using the purchase method, and records its
share of earnings using the equity method. The purchase price exceeded the
underlying equity in Gas BAN by $13.0 million. The Company allocated this
difference to the assets and liabilities acquired based on their preliminary
estimated fair values. See Note 2 of LG&E Energy's Notes to Financial Statements
under Item 8.

                         LEASE OF BIG RIVERS FACILITIES

In July 1998, the Company closed the transaction to lease the generating assets
of Big Rivers. Under the 25-year operating lease, WKE operates Big Rivers'
coal-fired facilities, a combustion turbine and operates and maintains the
Station Two generating facility of Henderson. The combined generating capacity
of these facilities is approximately 1,700 Mw, net of the Henderson's capacity
and energy needs from Station Two. In related transactions, power is supplied to
Big Rivers at contractual prices over the term of the lease to meet the needs of
three member distribution cooperatives and their retail customers, including
major western Kentucky aluminum smelters. Excess generating capacity is
available to WKE to market throughout the region. In connection with these
transactions, WKE has undertaken to bear certain of the future capital
requirements of those generating assets, certain defined environmental
compliance costs and other obligations. Big Rivers' personnel at the plants
became employees of WKE upon the completion of the transactions. See Note 5 of
LG&E Energy's Notes to Financial Statements under Item 8.

                       LOUISVILLE GAS AND ELECTRIC COMPANY

General

Incorporated on July 2, 1913, LG&E is a regulated public utility that supplies
natural gas to approximately 295,000 customers and electricity to approximately
366,000 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


                                       3
<PAGE>

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, 1999, 82% of total operating revenues was
derived from electric operations and 18% 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                    $215,019  $103,655   $318,674            44%
     Commercial                      176,692    38,627    215,319            30
     Industrial                      112,038    10,401    122,439            17
     Public authorities               56,042     9,013     65,055             9
                                    --------  --------   --------           ---
       Total retail                  559,791   161,696    721,487           100%
                                                                            ===
     Wholesale sales                 221,336     8,118    229,454
     Gas transported - net                 -     6,350      6,350
     Provision for rate refunds       (1,735)        -     (1,735)
     Miscellaneous                    11,278     1,415     12,693
                                    --------  --------   --------
       Total                        $790,670  $177,579   $968,249
                                    ========  ========   ========

See Note 14 of LG&E's Notes to Financial Statements and Note 20 of LG&E Energy's
Notes to Financial Statements under Item 8 for financial information concerning
segments of business for the three years ended December 31, 1999.


                                       4
<PAGE>

Electric Operations

The sources of LG&E's electric operating revenues and the volumes of sales for
the three years ended December 31, 1999, were as follows:

                                                 1999         1998         1997
                                                 ----         ----         ----

      ELECTRIC OPERATING REVENUES
      (Thousands of $):
      Residential                            $215,019     $213,476     $205,137
      Small commercial and industrial          79,261       76,304       72,769
      Large commercial                         97,431       94,650       90,131
      Large industrial                        112,038      113,372      110,652
      Public authorities                       56,042       55,075       53,412
                                             --------     --------     --------
        Total retail                          559,791      552,877      532,101
      Wholesale sales                         221,336       99,340       70,942
      Provision for rate refunds               (1,735)      (4,500)           -
      Miscellaneous                            11,278       10,794       11,489
                                             --------     --------     --------
        Total                                $790,670     $658,511     $614,532
                                             ========     ========     ========

      ELECTRIC SALES (Thousands of Mwh):
      Residential                               3,680        3,534        3,302
      Small commercial and industrial           1,218        1,156        1,108
      Large commercial                          2,072        1,977        1,880
      Large industrial                          3,047        3,097        3,054
      Public authorities                        1,187        1,140        1,105
                                             --------     --------     --------
        Total retail                           11,204       10,904       10,449
      Wholesale sales                           8,428        4,970        3,800
                                             --------     --------     --------
        Total                                  19,632       15,874       14,249
                                             ========     ========     ========

LG&E uses efficient coal-fired boilers, fully equipped with sulfur dioxide
removal systems, to generate most of its electricity. LG&E's system wide
emission weighted-average rate for sulfur dioxide in 1999 was approximately .9
lbs./Mmbtu of heat input, which is significantly below the Year 2000 Phase II
limit of 1.2 lbs./Mmbtu established by the Act.

The 1999 maximum local peak load of 2,612 Mw occurred on Friday, July 30, 1999,
when the temperature at the time was 106 degrees F. Prior to 1999, the record
local peak load was 2,427 Mw (set on August 25, 1998).

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, 1999, 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.


                                       5
<PAGE>

Gas Operations

The sources of LG&E's gas operating revenues and the volumes of sales for the
three years ended December 31, 1999, were as follows:

                                               1999          1998         1997
                                               ----          ----         ----

GAS OPERATING REVENUES
(Thousands of $):
Residential                                $103,655      $113,430     $139,967
Commercial                                   38,627        40,888       52,440
Industrial                                   10,401        11,969       17,892
Public authorities                            9,013         8,884       12,052
                                           --------      --------     --------
  Total retail                              161,696       175,171      222,351
Wholesale sales                               8,118         8,720            -
Gas transported - net                         6,350         6,926        6,997
Miscellaneous                                 1,415           728        1,663
                                           --------      --------     --------
  Total                                    $177,579      $191,545     $231,011
                                           ========      ========     ========

GAS SALES (Millions of cu. ft.):
Residential                                  21,565        20,040       24,038
Commercial                                    9,033         8,448       10,212
Industrial                                    2,781         2,860        3,948
Public authorities                            2,228         1,967        2,467
                                           --------      --------     --------
  Total retail                               35,607        33,315       40,665
Wholesale sales                               3,881         3,880            -
Gas transported                              14,014        13,027       13,452
                                           --------      --------     --------
  Total                                      53,502        50,222       54,117
                                           ========      ========     ========

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
1999, the maximum day gas sendout was 511,000 Mcf, occurring on January 4, when
the average temperature for the day was 10 degrees F. Supply on that day
consisted of 230,000 Mcf from purchases, 222,000 Mcf delivered from underground
storage, and 59,000 Mcf transported for industrial customers. For a further
discussion, see Gas Supply under Item 1.


                                       6
<PAGE>

Rates and Regulation

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 such Act, 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 and LG&E Energy Corp. under Item 7 and Note 3 of LG&E's Notes to Financial
Statements and Note 6 of LG&E Energy'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 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.

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.

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, 1999, gross property additions amounted
to $645 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 21% of total
utility plant at December 31, 1999, and consisted of $493 million for electric
properties and $152 million for gas properties. Gross retirements during the
same period were $116 million, consisting of $88 million for electric properties
and $28 million for gas properties.


                                       7
<PAGE>

Coal Supply

Over 90% of LG&E's present electric generating capacity is coal-fired, the
remainder being made up of a hydroelectric plant and combustion turbine peaking
units fueled by natural gas and oil. 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 1999 and beyond. LG&E normally augments its coal supply
agreements with spot market purchases which, during 1999, were about 5% of total
purchases. LG&E has a coal inventory policy which it believes provides adequate
protection under most contingencies. LG&E had on hand at December 31, 1999, a
coal inventory of approximately 816,000 tons, or a 43-day supply.

LG&E expects, for the foreseeable future, to continue purchasing most of its
coal, which has a sulfur content in the 2%-4.5% range, from western Kentucky,
southwest Indiana, West Virginia and Ohio. The abundant supply of this
relatively low priced coal, combined with present and future desulfurization
technologies, is expected to enable LG&E to continue to provide adequate
electric service in a manner acceptable under 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 average delivered cost of coal purchased by LG&E, per ton and per Mmbtu, for
the periods shown were as follows:

                                     1999             1998              1997
                                     ----             ----              ----

      Per ton                      $21.49           $22.38            $21.66
      Per Mmbtu                       .95              .98               .94

The delivered cost of coal is expected to decrease during 2000.

Gas Supply

LG&E purchases transportation services from Texas Gas and Tennessee. LG&E
purchases natural gas supplies from multiple sources under contracts for varying
periods of time.

During 2000, Texas Gas filed with FERC for a change in its rates as required
under the settlement in its last rate case. LG&E plans to participate in that
and other proceedings, as appropriate. 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 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 system under Tennessee's
Rate FT-A. LG&E's contract levels with Tennessee are 51,000 Mmbtu per day
annually. The FT-A agreement with Tennessee 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


                                       8
<PAGE>

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 $2.99 in 1999,
$3.05 in 1998 and $3.46 in 1997.

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 1999, expenditures for
pollution control facilities represented $124 million or 19% of total
construction expenditures. For a discussion of environmental matters, see Rates
and Regulation for LG&E and LG&E Energy Corp. under Item 7 and Note 12 of LG&E's
Notes to Financial Statements and Note 18 of LG&E Energy'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 could take additional steps to better position itself for
competition in the future.

                           KENTUCKY UTILITIES COMPANY

General

KU was incorporated in Kentucky in 1912 and incorporated in Virginia in 1991. KU
is a public utility engaged in producing, transmitting and selling electric
energy. KU provides electric service to about 458,000 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 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.


                                       9
<PAGE>

Electric Operations

The sources of KU's electric operating revenues and the volumes of sales for the
three years ended December 31, 1999, were as follows:

                                                1999          1998          1997
                                                ----          ----          ----

ELECTRIC OPERATING REVENUES
(Thousands of $):
Residential                                $ 242,304     $ 238,566     $ 231,824
Commercial                                   160,895       158,340       150,794
Industrial                                   154,460       154,475       146,801
Mine Power                                    28,792        31,620        34,541
Public authorities                            58,500        58,740        56,243
                                           ---------     ---------     ---------
  Total - ultimate consumers                 644,951       641,741       620,203
Wholesale sales                              286,595       179,118        87,330
Provision for rate refunds                    (5,900)      (21,500)           --
Miscellaneous                                 11,664        10,755         8,904
                                           ---------     ---------     ---------
  Total                                    $ 937,310     $ 810,114     $ 716,437
                                           =========     =========     =========

ELECTRIC SALES (Thousands of Mwh):
Residential                                    5,447         5,247         5,061
Commercial                                     3,760         3,644         3,422
Industrial                                     4,911         4,747         4,464
Mine Power                                       752           838           926
Public authorities                             1,437         1,424         1,355
                                           ---------     ---------     ---------
  Total - ultimate consumers                  16,307        15,900        15,228
Wholesale sales                               10,188         7,224         3,397
                                           ---------     ---------     ---------
  Total                                       26,495        23,124        18,625
                                           =========     =========     =========

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

At December 31, 1999, KU owned steam and combustion turbine generating
facilities with a capacity of 3,898 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, 1999, KU's system
capability, including purchases from others, was 4,229 Mw. On July 30, 1999, a
record local peak load, on a one-hour integrated basis, was set at 3,764 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 1999. See Note 11 of KU's Notes to Financial
Statements and Note 18 of LG&E Energy'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's entitlement is 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 1999. See Note 11 of
KU's Notes to Financial Statements and Note 18 of LG&E Energy's Notes to


                                       10
<PAGE>

Financial Statements under Item 8.

Rates and Regulation

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. 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. FERC has classified KU as a "public utility" as defined in
the FPA. 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. 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
and LG&E Energy Corp. under Item 7 and under Note 3 of KU's Notes to the
Financial Statements and Note 6 of LG&E Energy's Notes to Financial Statements
under Item 8.

KU'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 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.

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.

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.

The Virginia Commission requires 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
Staff. The 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.

As a result of its ownership in EEI, KU is considered a holding company under
the Holding Company Act. KU however is presently exempt from all the provisions
of the Holding Company Act, except Section 9(a)(2) thereof (which relates to the
acquisition of securities of public utility companies), by virtue of the
exemption granted by an order of the SEC.

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


                                       11
<PAGE>

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, 1999, construction expenditures
aggregated about $596 million, which included five combustion turbine peaking
units. Three 126-Mw units were placed into commercial operation in 1995 and
1996. Two 164-Mw units, which are jointly owned with LG&E, were put into
commercial operation in August 1999.

Coal Supply

Coal-fired generating units provided more than 98% of KU's net kilowatt-hour
generation for 1999. The remainder of KU's net generation for 1999 was provided
by oil and/or natural gas burning units and hydroelectric plants. The average
delivered cost of coal purchased per Mmbtu and the percentage of spot coal
purchases for the periods indicated were as follows:

                                                 1999         1998         1997
                                                 ----         ----         ----

Per ton                                      $  26.65     $  26.97     $  27.97
Per Mmbtu - all sources                      $   1.11     $   1.12     $   1.15
Per Mmbtu - spot purchases only              $   1.11     $   1.10     $   1.12
Spot purchases as % of all sources                53%          42%          34%

The price of coal is expected to decrease slightly during 2000.

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 on hand at December 31, 1999, a coal inventory of approximately 1,063,000
tons, or a 48 day supply.

KU expects, for the foreseeable future, 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 and Pennsylvania.

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


                                       12
<PAGE>

period ending with 1999, expenditures for pollution control facilities
represented $42 million or 7% of total construction expenditures. See Note 11 of
KU's Notes to Financial Statements and Note 18 of LG&E Energy'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 could
take additional steps like these to better position itself for competition in
the future.

                          LG&E CAPITAL CORP. AND OTHER

Capital Corp., the holding company for all the Company's non-utility investments
other than trading operations, was formed on September 5, 1997, when the Company
merged two of its former direct subsidiaries, Energy Systems and Gas Systems,
and renamed the company LG&E Capital Corp. On July 24, 1998, KU Capital, a
former subsidiary of KU Energy, was merged into Capital Corp., with the latter
as the survivor corporation.

As previously discussed in item 1 under Discontinuance of Merchant Energy
Trading and Sales Business, effective June 30, 1998, the Company decided to
discontinue its merchant energy trading and sales business, and it decided to
sell its natural gas gathering and processing business. Effective June 30, 1999,
the Company decided to retain the natural gas gathering and processing business.
For a more detailed discussion of the discontinuance of the Company's merchant
energy trading and sales business, and the decision to retain the natural gas
gathering and processing business, see Discontinued Operations under this Item,
and Notes 3, 4 and 18 of LG&E Energy's Notes to Financial Statements under Item
8.

Capital Corp. conducts its operations through three principal business
segments: Power Operations, Western Kentucky Energy and Argentine Gas
Distribution. Capital Corp. is also engaged in other non-utility activities
including: providing specialized equipment and services used in construction
and rehabilitation of gas and oil transmission pipelines; the gathering,
processing, storing and transportation of natural gas; commercial and retail
initiatives designed to assess the energy and utility needs of large
commercial and industrial entities; providing maintenance and repair services
for customers' major household appliances; and, the asset optimization of the
Company's generation assets. See Notes 2, 5, 9, 10, 18 and 20 of LG&E
Energy's Notes to Financial Statements under Item 8. LEM conducts asset-based
energy marketing on behalf of the Company's utility and non-utility
operations.

                                POWER OPERATIONS

General

Capital Corp.'s Power Operations develop, operate, maintain and own domestic and
international power generation facilities that sell electric and steam energy to
utility and industrial customers. Power Operations currently has domestic
ownership interests in projects capable of generating nearly 600 Mw of electric
power in North Carolina, Virginia, California, Minnesota, Texas and Washington,
and international ownership interest in a windpower generating facility in
Tarifa, Spain, and ownership interests in three combustion turbines. Ownership
interests in each of these projects and the revenues from the sale of
electricity and steam are pledged as security to the lenders which provided the
financing. See Item 2, Properties, for a listing of the Power Operations'
projects.


                                       13
<PAGE>

In March 1999, LG&E Westmoreland - Rensselaer, in which Power Operations owned a
50% interest, sold the assets of the Rensselaer cogeneration facility. This
transaction resulted in an after-tax gain for Power Operations of approximately
$8.9 million.

In June 1998, Power Operations entered into a partnership with Columbia Electric
Corporation for the development of a natural gas-fired cogeneration project in
Gregory, Texas, providing electricity and steam equivalent of 550 Mw.
Construction commenced in August 1998 and non-recourse financing for a majority
of the construction and other costs was obtained in November 1998. The project
will sell steam and a portion of its electric output to Reynolds Metals Company.
A medium-term fixed-price contract has also been entered into with a third party
for a portion of the remaining electric output. The project is expected to begin
commercial operation in the summer of 2000. The Company's equity contribution is
expected to be approximately $30 to $35 million in connection with its 50%
interest in the project.

In February 1998, Power Operations sold its interest in a 114-Mw natural
gas-fired power plant in North Central Argentina. The transaction resulted in a
$2.8 million pre-tax loss.

Fuel Supply

Power Operations operates five coal fired and three wind plants. See Item 2,
Properties. Coal supply needed by Power Operations is generally purchased under
long-term contracts expiring at various times from 2008 through 2014. Each
contract has two five-year renewal options. All coal is delivered by rail.

Customer Base

Each project has long-term power purchase agreements with a single power
purchaser, except one of the Tenaska Limited Partnerships which has two. The
power purchasers are VEPCO for Southampton, Altavista, and Hopewell in Virginia
and ROVA I and ROVA II in North Carolina; Southern California Edison Co. for WPP
93 in California; Northern States Power Company for WPP 93 in Minnesota; Lower
Colorado River Authority for WPP 94, Brazos Electric Power Cooperative for TLP,
Texas Utilities Electric Company for TLP and Campbell Soup for TLP in Texas;
Puget Sound Power & Light for TLP in Washington; and Compania Sevillana de
Electricidad for Tarifa in Spain. WPP 94 also sells excess power to Texas
Utilities. See Item 2, Properties, for a listing of Power Operations projects.

In August 1999, four combustion turbines previously leased to Portland General
Electric Company in Oregon were sold to that company at a pre-tax gain of $.8
million. Capital Corp. owned 100% of two of these turbines and 49% ownership
interest in the others.

In October, 1999, one combustion turbine previously leased to Puget Sound Power
& Light Company in Washington was sold to that company at a pre-tax gain of $2.3
million. Capital Corp. held a 49% ownership interest in this turbine.

Throughout 1999, three combustion turbines were leased to AP&L. Capital Corp.
holds a 49% interest in these turbines through the CEC-APL, L.P. partnership.
Upon expiration of the AP&L leveraged lease, the $9 million residual value of
the turbines was reclassified to Investment in Unconsolidated Affiliates. See
Note 9 of LG&E Energy's Notes to Financial Statements under Item 8. In February
2000, Power Operations entered into an agreement to sell its interest to its
co-partner in the project.

Regulatory Environment

Except for its investments in wind power and ROVA I, each of Power Operations'
projects in the United States


                                       14
<PAGE>

is a QF under PURPA. See Item 3 and Note 18 of LG&E Energy's Notes to Financial
Statements under Item 8 for a discussion of certain issues regarding past
operations at certain of these facilities. Certain partnerships, in which
companies in the Power Operations business segment have ownership interests, are
operating wind power facilities which are qualifying small power production
facilities under PURPA. In addition, Power Operations has obtained EWG status
for the entities which own the ROVA I and ROVA II projects in North Carolina and
the Southampton, Altavista and Hopewell projects in Virginia.

Generally, QF status exempts projects from the application of the Holding
Company Act, many provisions of the FPA, and state laws and regulations
respecting rates and financial or organization regulation of electric utilities.
EWGs also are exempt from application of the Holding Company Act and many
provisions of the FPA, but once such an entity files its electric generation
rates with FERC, it becomes a jurisdictional public utility under the FPA. As a
"public utility," an EWG's rates and some of its corporate activities are
subject to FERC regulation. EWGs also are subject to non-rate regulation under
state laws governing electric utilities. While QF or EWG status entitles Power
Operations' projects to certain regulatory exceptions and benefits under PURPA
and the Holding Company Act, each project must still comply with other federal,
state and local laws, including those regarding siting, construction, operation,
licensing and pollution abatement.

The foreign power generation facility in which Power Operations has an ownership
interest has obtained FUCO status under the Holding Company Act. Generally, FUCO
status exempts this facility from application of the Holding Company Act.

Commitments and Contingencies

Power Operations is party to various legal proceedings relating to its joint
ventures. See Note 18 of LG&E Energy's Notes to Financial Statements under Item
8 for discussion regarding these legal proceedings.

                             WESTERN KENTUCKY ENERGY

General

In July 1998 the Company closed the transaction to lease the generating assets
of Big Rivers. Under the 25-year operating lease, WKE operates the operating
assets of Big Rivers' coal-fired facilities, a combustion turbine and operates
and maintains the Station Two generating facility of Henderson. The combined
generating capacity of these facilities is approximately 1,700 Mw, net of
Henderson's capacity and energy needs from Station Two. Under the terms of the
lease agreement, WKE prepaid $55.9 million for its first two years of lease
payments and will pay $31.0 million for each of the remaining 23 years. In
addition, WKE purchased Big Rivers' inventory, personal property and emission
allowances, and made a one-time payment to Big Rivers of $12.1 million.

In related transactions, power is supplied to Big Rivers at contractual prices
over the term of the lease to meet the needs of three member distribution
cooperatives and their retail customers, including major western Kentucky
aluminum smelters. The excess generating capacity is available to WKE to market
throughout the region.

Also, as part of the transaction, in July 1998, WKE began advancing Big Rivers
$50.0 million over a 24-month period to help it emerge from bankruptcy. The note
will be repaid over a three-year period, beginning August 2000, with interest at
7.165%.

WKE's business is affected by seasonal weather patterns. As a result, operating
revenues (and associated expenses) are not generated evenly throughout the year.


                                       15
<PAGE>

WKE is considering a merger of its three legal entities, Western Kentucky Energy
Corp., WKE Station Two Inc. and WKE Corp. to consolidate these entities into the
surviving entity of Western Kentucky Energy Corp. Should WKE complete the merger
of these entities, WKE anticipates decertifying as an EWG.

Construction Program and Financing

In connection with these transactions, WKE has undertaken to bear certain of the
future capital requirements of these generating assets. WKE's estimates of its
construction expenditures can vary substantially due to numerous items beyond
WKE's control, such as economic conditions, construction costs, and new
environmental or other governmental laws and regulations. In 1999, gross
property additions were $12.2 million. During 1998 gross property additions
amounted to $11.8 million excluding personal property acquired from Big Rivers.
Internally generated funds and intercompany financing from Capital Corp.
provided 100% of the construction expenditures.

Coal Supply

Coal-fired generating units provided 90% of the electric generating capacity
controlled by WKE, the remainder being made up of a combustion turbine peaking
unit fueled by fuel oil. Coal is the predominant fuel used by WKE, with fuel oil
being used for peaking capacity. WKE has entered into various multi-year coal
supply agreements with suppliers for coal deliveries for 2000 and beyond. WKE
normally augments its coal supply agreements with spot market purchases. At
December 31, 1999, WKE had on hand coal inventory of approximately 1.5 million
tons or a 75-day supply.

WKE expects, for the foreseeable future, to continue purchasing most of its
coal, which has a sulfur content in the 2%-4.5% range, from western Kentucky and
southwest Indiana. The abundant supply of this relatively low priced coal,
combined with present and future desulfurization technologies, is expected to
enable WKE to continue to provide adequate electric service in a manner
acceptable under existing environmental laws and regulations.

Coal for WKE's operations are delivered by barge and truck.

The average delivered cost per ton of coal purchased by WKE for 1999 and 1998
respectively was $20.86 and $20.85.

Environmental Matters

WKE engages in a variety of activities within the jurisdiction of federal, state
and local regulatory agencies. Those agencies have issued WKE permits for
various activities subject to air quality, water quality and waste management
laws and regulations. During 1999 and 1998, expenditures for pollution control
facilities represented approximately $1.4 million and $.5 million of WKE's
construction expenditures, respectively. See Note 18 of LG&E Energy's Notes to
Financial Statements under Item 8 for a discussion of specific environmental
proceedings.

                           ARGENTINE GAS DISTRIBUTION

General

In February 1997, the Company acquired interests in two Argentine natural gas
distribution companies. Capital Corp., through a subsidiary, purchased a
controlling interest in Centro and a minority interest in Cuyana. Centro and
Cuyana together serve approximately 732,000 customers in six provinces in
Argentina. The


                                       16
<PAGE>

investment in these companies totaled approximately $140 million. Each of these
companies has obtained FUCO status under the Holding Company Act. Generally,
FUCO status exempts these facilities from application of the Holding Company
Act.

In April 1999, the Company acquired an interest in another Argentine natural gas
distribution company. Capital Corp., through a subsidiary, purchased a minority
interest in Gas BAN, the second largest gas distribution company in Argentina.
Gas BAN serves approximately 1,188,000 customers in thirty counties in the
northern region of Buenos Aires. The Company's investments in Gas BAN totaled
$85.4 million through December 31, 1999.

Gas Operations

Centro's and Cuyana's primary source of gas supply is YPF, S.A., and its primary
source of gas transmission is TGN, S.A. Centro and Cuyana have no underground
storage facilities. Gas BAN's primary source of gas supply is YPF, S.A., and its
primary sources of gas transmission are TGS, S.A. and TGN, S.A. Gas BAN has a
shaving plant to cover peaking demand.

The Argentine federal regulator of gas transmission and distribution, Energas,
has granted Centro, Cuyana and GasBAN 35-year concessions to provide gas
distribution services in their service territories. The concessions end in 2028
and each concession contains a 10-year renewal option.

Centro derives approximately 12% of its revenues from electric power plants
located in its service territory. Some of these power plants are state-owned.
Centro sells gas to these plants under contracts ranging from two to 15 years.

Construction Program and Financing

Capital investments for Centro since 1992 have totaled approximately $284
million. Centro's capital expenditures for 1999 totaled $17 million and were
financed through borrowing and internal sources. Centro will spend approximately
$4.5 million in 2000 to expand and maintain its gas distribution network, and it
will finance the expenditures through borrowings and internal sources.

                               CAPITAL CORP. OTHER

Gas Operations

As previously discussed in item 1 under Discontinuance of Merchant Energy
Trading and Sales Business, effective June 30, 1998, the Company decided to
discontinue its merchant energy trading and sales business, and it decided to
sell its natural gas gathering and processing business. Effective June 30, 1999,
the Company decided to retain the natural gas gathering and processing business.
For a more detailed discussion of the discontinuance of the Company's merchant
energy trading and sales business, and the decision to retain the natural gas
gathering and processing business, see Discontinued Operations under this Item,
and Notes 3, 4 and 18 of LG&E Energy's Notes to Financial Statements under Item
8.

Capital Corp.'s Gas Operations, conducted through various subsidiaries, include:
gathering and processing operations consisting of 1,200 miles of pipeline
concentrated in southeastern New Mexico and the Permian Basin of west Texas; and
a 6.0 Bcf working gas storage facility connected to the Llano pipeline. For a
more detailed explanation of these assets see Item 2, Properties.

The Llano pipeline has a design capacity of approximately 180,000 Mcf of gas per
day and is capable of


                                       17
<PAGE>

delivering gas to three different interstate pipelines. Capital Corp., through
its various subsidiaries, purchases gas from over 50 producers connected to the
Llano pipeline and sells the gas directly to end-user customers or delivers the
gas into one of the interstate pipelines for sale. Also, through its various
subsidiaries, Capital Corp. transports natural gas through the Llano pipeline
for third parties and is paid a transportation fee for such services. An average
of approximately 100,000 Mcf of natural gas per day moved through the Llano
pipeline in 1999.

The 11 gathering systems owned (seven 100%, one leased and ownership interests
ranging from 11% to 50% in three others) and operated during 1999 gathered
approximately 216,500 Mcf of natural gas per day. During 1999, Capital Corp.
divested itself of its three partially owned gathering systems.

Connected to the Llano pipeline are two operating natural gas processing
facilities capable of processing approximately 75,000 Mmbtu of natural gas per
day. These facilities extract natural gas liquids, including propane, ethane,
butanes and natural gasoline, from the natural gas stream, at which point the
mixed stream of liquids is sold. Approximately 215,000 net gallons per day of
natural gas liquids were extracted and sold from these facilities in 1999.

Also connected to the Llano pipeline is a natural gas storage facility. As noted
above, this facility has current working capacity of approximately 6.0 Bcf.
Capital Corp., through a subsidiary, offers this storage capacity to third
parties on a fee basis. As of December 31, 1999, storage capacity of
approximately 3.0 Bcf was leased to other parties.

The production, transportation and certain sales of natural gas are subject to
federal, state or local regulations which have a significant impact upon Capital
Corp.'s energy products and services businesses. Regulation at the federal level
of domestically produced or transported natural gas is administered primarily by
the FERC pursuant to the NGA and the NGPA. Maximum selling prices of certain
categories of gas, whether sold in interstate or intrastate commerce, previously
were regulated pursuant to NGPA. The NGPA established various categories of gas
and provided for graduated deregulation of price controls of several categories
of gas and the deregulation of sales of certain categories of gas. All price
deregulation contemplated under the NGPA has already taken place. Subsequently,
the Natural Gas Wellhead Decontrol Act of 1989 terminated all NGA and NGPA
regulation of "first sales" of domestic natural gas on January 1, 1993. The sale
for resale of certain natural gas in interstate commerce is regulated, in part,
pursuant to the NGA, which requires certificate and abandonment authority to
initiate and terminate such sales. In addition, natural gas marketed by a
Capital Corp. subsidiary is usually transported by interstate pipeline companies
that are subject to the jurisdiction of the FERC. Similarly, some of the
transportation and storage services provided by Llano are subject to FERC
regulation under section 311 of the NGPA. These services are frequently sold to
gas distribution companies that contract with interstate pipeline companies for
transportation from the Llano facility to their respective service areas.
Section 311 permits intrastate pipelines under certain circumstances to sell gas
to, transport gas for, or have gas transported by, interstate pipeline
companies, and assign contract rights to purchase surplus gas from producers to
interstate pipeline companies without being regulated as interstate pipelines
under the NGA. Capital Corp., through a subsidiary, submitted a rate case for
transportation and storage rates to the FERC in 1998 which was approved without
intervention.

CRC - Evans

CRC provides specialized equipment and services used in the construction and
rehabilitation of gas and oil transmission pipelines. CRC sells and rents
automatic pipeline welding systems, pipe bending equipment, line-up clamps, pipe
coating plants, coating and cleaning equipment, pipeline rehabilitation
equipment and lay barge pipe handling equipment. CRC also provides specialized
services including joint coating, cement weighting, induction and resistance
heating and automatic welding systems training and supervision.


                                       18
<PAGE>

CRC sells its products and services through its salespeople and independent
international sales representatives and distributors covering 70 countries. The
company's sales offices are located in Houston, Texas; Tulsa, Oklahoma; Toms
River, New Jersey; Hoevelaken, Netherlands; Edmonton, Alberta; Burnley, England
and Didcot, England.

                             DISCONTINUED OPERATIONS

General

As previously discussed in item 1 under Discontinuance of Merchant Energy
Trading and Sales Business, effective June 30, 1998, the Company decided to
discontinue its merchant energy trading and sales business, and it decided to
sell its natural gas gathering and processing business. Effective June 30, 1999,
the Company decided to retain the natural gas gathering and processing business.
For a more detailed discussion of the discontinuance of the Company's merchant
energy trading and sales business, and the decision to retain the natural gas
gathering and processing business, see Discontinued Operations under this Item,
and Notes 3, 4 and 18 of LG&E Energy's Notes to Financial Statements under Item
8. In December 1999, LEM, the entity primarily conducting the discontinued
operations activities and formerly an indirect subsidiary of Capital Corp.,
became a direct subsidiary of LG&E Energy.

Product and Services

The merchant energy trading and sales business consisted primarily of a
portfolio of energy marketing contracts entered into in 1996 and 1997,
nationwide deal origination and some level of speculative trading activities,
which were not directly supported by the Company's physical assets.

Commitments and Contingencies

For discussions of commitments and contingencies relating to Discontinued
Operations, see Note 18 of LG&E Energy 's Notes to Financial Statements under
Item 8.

                          EMPLOYEES AND LABOR RELATIONS

LG&E Energy and its subsidiaries had 5,836 full-time employees at December 31,
1999, including 2,237 full-time employees of LG&E and 1,747 full-time employees
of KU. At December 31, 1999, LG&E had 1,297 operating, maintenance, and
construction employees that were members of IBEW Local 2100. The current three
year contract with the IBEW will expire in November 2001. At December 31, 1999,
KU had 239 operating, maintenance and construction employees who were members of
IBEW Local 101 and USWA Local 8686. The current contract will expire August 1,
2000. At December 31, 1999, WKE had 358 operating, maintenance and construction
employees that were members of the IBEW Local 1701. The current contract will
expire September 14, 2001.


                                       19
<PAGE>

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 and Note
                  19 of LG&E Energy'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, and Notes 18 and 19 of LG&E Energy'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, 1999, LG&E's electric transmission system included 21
substations with a total capacity of approximately 11,071,700 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,
3,672 structure miles of overhead lines, 342 miles of underground conduit, and
5,562 miles of underground conductors.

LG&E's gas transmission system includes 209 miles of transmission mains, and the
gas distribution system includes 3,789 miles of distribution mains.


                                       20
<PAGE>

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.


                                       21
<PAGE>

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                                                 30,000
                Unit 2                                                 33,000
                Unit 3                                                 73,000
                                                                  -----------
                     Total Tyrone                                     136,000

            Green River - South Carrollton, KY.
                Unit 1                                                 29,000
                Unit 2                                                 30,000
                Unit 3                                                 73,000
                Unit 4                                                107,000
                                                                  -----------
                     Total Green River                                239,000

            E.W. Brown - Burgin, KY.
                Unit 1                                                106,000
                Unit 2                                                170,000
                Unit 3                                                441,000
                                                                  -----------
                     Total E.W. Brown                                 717,000

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

            Ghent - Ghent, KY.
                Unit 1                                                487,000
                Unit 2                                                497,000
                Unit 3                                                513,000
                Unit 4                                                500,000
                                                                  -----------
                     Total Ghent                                    1,997,000

            Combustion Turbine Generators (Peaking capability):
            E.W. Brown - Burgin, KY.
                Unit 6 (a)                                            102,000
                Unit 7 (a)                                            102,000
                Unit 8                                                135,000
                Unit 9                                                120,000
                Unit 10                                               135,000
                Unit 11                                               122,000
            Haefling - Lexington, KY.
                Unit 1                                                 59,000
                                                                  -----------

                     Total combustion turbine generators              775,000
                                                                  -----------

            Total capability rating                                 3,898,000
                                                                  ===========

            (a)   Amount shown represents the KU's 62% interest in Unit 6 and 7
                  at E.W. Brown. See Notes 11and 12 of KU's Notes to Financial
                  Statements, and Notes 18 and 19 of LG&E Energy's Notes to
                  Financial Statements under Item 8 for further discussion on
                  ownership.


                                       22
<PAGE>

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, 1999, KU's electric transmission system included 112 substations
with a total capacity of approximately 14,755,396 Kva and approximately 4,227
structure miles of lines. The electric distribution system included 438
substations with a total capacity of approximately 5,024,307 Kva, 14,619
structure miles of lines.

At December 31, 1999, Power Operations owned the percentage indicated of the
following joint ventures:

                                                                             Net
                                             Ownership                Capability
         Name                                 Interest %     Fuel    Rating (Mw)
         ----                                ---------       ----    -----------

         LG&E Westmoreland-Southampton              50       Coal             63
         Franklin, Virginia

         LG&E Westmoreland-Altavista                50       Coal             63
         Altavista, Virginia

         LG&E Westmoreland-Hopewell                 50       Coal             63
         Hopewell, Virginia

         Westmoreland-LG&E Partners                 50       Coal            165
         (Roanoke Valley I)
         Weldon, North Carolina

         Windpower Partners 1993 L.P.               50       Wind             43
         Palm Springs, California

         Windpower Partners 1993 L.P.               50       Wind             25
         Buffalo Ridge, Minnesota

         Windpower Partners 1994 L.P.               25       Wind          25-35
         Culberson County, Texas

         Westmoreland-LG&E Partners                 50       Coal             44
         (Roanoke Valley II)
         Weldon, North Carolina

         K.W. Tarifa, S.A.                          46       Wind             30
         Tarifa, Spain

         Tenaska Limited Partnerships             5-10        Gas        223-258

         Gregory Power Partners                     50        Gas            550
         Gregory, Texas (under construction)

Power Operations' ownership interests in these projects and the revenues from
the sale of electricity and steam from the projects are pledged as security to
the lenders who provided the financing for the project. See Note 18 of LG&E
Energy's Notes to Financial Statements under Item 8 for a discussion Power
Operations' commitment and contingencies relating to its joint ventures. Also
see Note 9 of LG&E Energy's Notes to Financial


                                       23
<PAGE>

Statements under Item 8 for a discussion on investment in unconsolidated
ventures.

In March 1999, LG&E-Westmoreland Rensselaer, a California general partnership in
which the Company owns a 50% interest, sold substantially all the assets and
major contracts of its 79 Mw gas-fired cogeneration facility in Rensselaer, New
York, with net proceeds to the Company of approximately $34 million. The sale
resulted in an after-tax gain to the Company of approximately $8.9 million.

Capital Corp., through certain subsidiaries, owns or has an interest in eight
gas gathering systems consisting of 1,200 miles of pipeline (of which it owns
100% of four, leases one, and has ownership interests ranging from 11% to 50% in
the other three). These systems are located in Texas, New Mexico, Louisiana,
Montana and Oklahoma.

The major gas gathering system is the Llano pipeline, a 730-mile intrastate
pipeline and processing system in southeastern New Mexico with a throughput
capacity of 180,000 MCF of gas per day. Capital Corp., through subsidiaries,
owns two gas systems located in Texas. PowerTex Pipeline, a 76-mile pipeline
serving the City of Lubbock, Texas, has a design capacity of 90,000 MCF of gas
per day. The Sale Ranch system consists of a 16mmcfd processing plant and
approximately 350 miles of gathering pipelines. Through a subsidiary, Capital
Corp. owns majority interest and operates the Sale Ranch system. It also owns,
or has interests in, and operates three natural gas processing plants located in
southeastern New Mexico and western Texas with a total design capacity of 92,000
MCF of gas per day (owns a 100% interest in one of these plants, and majority
interests in the two remaining plants).

Under a 25-year operating lease, WKE operates Big Rivers' coal-fired facilities,
a combustion turbine and operates and maintains the Station Two generating
facility of Henderson. The combined generating capacity of these facilities is
approximately 1,700 Mw, net of Henderson's capacity and energy needs from
Station Two.

Centro's gas transmission and distribution system includes 6,646 miles of
transmission mains and distribution mains located in Cordoba, Argentina, and
neighboring provinces. Cuyana's gas transmission and distribution system
includes approximately 4,899 miles of transmission mains and distribution mains
located in Mendoza Province, Argentina, and neighboring provinces. Gas BAN's
transmission and distribution system includes 11,580 miles of transmission and
distribution mains in the northern region of Buenos Aires.

CRC owns a 29-acre equipment yard/manufacturing/maintenance facility and supply
warehouse in Tulsa, Oklahoma and a 9,800 square foot sales
office/warehouse/service facility in Edmonton, Canada. The company leases all
other facilities used in its operations, including its corporate offices in
Houston, Texas and various office facilities and equipment sites in the United
States, United Kingdom and the Netherlands.

LG&E Energy has operating leases for its corporate office space that expire
between 2000 and 2012.

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 the Company's PBR filings and the KIUC's rate filing, (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 2, 6, 18 and 22 of LG&E Energy
Corp.'s Notes to Financial Statements, Notes 3, 12 and 16 of LG&E's Notes to
Financial Statements and Notes 3, 11 and 14 of KU's Notes to Financial
Statements under Item 8.


                                       24
<PAGE>

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 by $27.2 and $36.5, respectively, 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 January and
February 2000, LG&E and KU submitted filings seeking adjustments in the rate
reductions and tariffs incorporating the ESM. See Rates and Regulations under
Item 7 and Notes 6 and 22 to LG&E Energy's Notes to Financial Statements, Notes
3 and 16 to LG&E's Notes to Financial Statements and Notes 3 and 14 to KU's
Notes to Financial Statements.

Fuel Adjustment Clause Proceedings

Pursuant to Kentucky statute, aspects of the Company's utility rates are
reviewed through semi-annual FAC proceedings at the Kentucky Commission.
Although the proceedings are routine, some items are noted herein. Certain
intervenors have challenged KU's recovery of certain energy charges for power
purchased from Owensboro Municipal Utilities and requested rate refunds for such
amounts. Kentucky Commission orders of August 1999 and January 2000 have
required aggregate refunds totaling approximately $8.4 million for the periods
between November 1996 to October 1999. These orders have been appealed by both
KU and the intervenor group. See also Note 6 to LG&E Energy's Notes to Financial
Statements, Note 3 to LG&E's Notes to Financial Statements and Note 3 to KU's
Notes to Financial Statements. 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 and
Cane Run generating plants and LG&E's and KU's manufactured gas plant sites, and
(c) other environmental items affecting LG&E Energy and its subsidiaries, see
Environmental Matters under Item 7 and Notes 18 and 22 of LG&E Energy's Notes to
Financial Statements, Notes 12 and 16 of LG&E's Notes to Financial Statements
and Notes 11 and 14 of KU's Notes to Financial Statements under Item 8,
respectively.

Southampton

For a discussion of the settlement of certain FERC proceedings and intra-party
matters involving the partnership that owns the Southampton facility, regarding
that facility's status as a qualifying facility for 1992, see Note 18 of LG&E
Energy Corp.'s Notes to Financial Statements under Item 8.

Roanoke Valley I

WLP is seeking the recovery of capacity payments withheld by VEPCO in respect
of the Roanoke Valley I facility. In January 2000, the Virginia Supreme Court
issued an opinion remanding this matter for a second trial, setting aside an
earlier trial court decision which had awarded WLP approximately $19 million
plus interest until paid. See Item 1 and Notes 18 and 22 of LG&E Energy
Corp.'s Notes to Financial Statements under Item 8.

Kenetech Bankruptcy

In May 1996, Kenetech filed for protection under Chapter 11 of the United States
Bankruptcy Code in the


                                       25
<PAGE>

United States Bankruptcy Court in the Northern District of California seeking,
among other things, to restructure certain contractual commitments between
Kenetech and its subsidiaries, on one hand, and various windpower projects
located in the U.S. and abroad, on the other hand. Included in these projects
are the WPP 93, WPP 94 and Tarifa projects. In April 1999, the Bankruptcy Court
approved a final plan of reorganization. See Note 18 of LG&E Energy Corp.'s
Notes to Financial Statements under Item 8 for a further discussion.

Windpower Partners 1994

WPP 94, in which the Company has a 25% interest through indirect subsidiaries,
has not made semiannual payments, since September 1997, to Hancock under certain
Notes issued by WPP 94 to Hancock. The parties are currently in negotiations
regarding a restructuring of these obligations. See Note 18 of LG&E Energy
Corp.'s Notes to Financial Statements under Item 8 for a further discussion.

Calgary

In November 1996, LG&E Natural Canada Inc., an indirect subsidiary of the
Company, initiated action in the Court of the Queens Bench of Alberta, Calgary
against a former employee as a result of the discovery that the former employee
had engaged in unauthorized transactions. See Note 18 to LG&E Energy's Notes to
Financial Statements, under Item 8 for a further discussion.

Springfield Municipal Contract

In July 1998, LEM, an indirect subsidiary of the Company, filed suit against
the CWLP in the United States District Court for the Western District of
Kentucky. In January 2000, LEM reached a settlement with CWLP pursuant to
which CWLP paid LEM approximately $16.6 million. See Note 18 to LG&E Energy's
Notes to Financial Statements under Item 8 for a further discussion.

Oglethorpe Power Contract

In October 1998, LEM initiated an arbitration proceeding against OPC in
connection with matters involving LEM's November 1996 power sales agreement
with OPC. In December 1999, the arbitration panel issued an adverse decision
in this proceeding enforcing the contract without modification. In connection
therewith, the Company increased its after-tax loss on disposal of
discontinued operations by $175 million. See Note 3 to LG&E Energy's Notes to
Financial Statements under Item 8 for a further discussion.

Other

In the normal course of business, other lawsuits, claims, environmental actions,
and other governmental proceedings arise against LG&E Energy and its
subsidiaries, including LG&E and KU. To the extent that damages are assessed in
any of these lawsuits, LG&E Energy, 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
Energy's, 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.


                                       26
<PAGE>

Executive Officers of LG&E Energy Corp.:

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

Roger W. Hale             56    Chairman of the Board        August 17, 1990
                                and Chief Executive
                                Officer

Victor A. Staffieri       44    President and Chief          February 16, 1999
                                Operating Officer

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

Stephen R. Wood           57    Group Executive -            January 1, 2000
                                Retail Business

Robert M. Hewett          53    Group Executive -            January 1, 2000
                                Regulatory Affairs

John R. McCall            56    Executive Vice President,    July 1, 1994
                                General Counsel and
                                Corporate Secretary

Wayne T. Lucas            52    Executive Vice President -   May 4, 1998
                                Power Generation

George W. Basinger        54    Senior Vice President -      May 4, 1998
                                Independent Power
                                Operations

Donald F. Santa, Jr.      41    Senior Vice President -      January 1, 2000
                                Strategic Planning

Frederick J. Newton III   44    Senior Vice President and    January 2, 1999
                                Chief Administrative
                                Officer

S. Bradford Rives         41    Senior Vice President -      February 16, 1999
                                Finance and Business
                                Development

Paul W. Thompson          43    Senior Vice President -      August 9, 1999
                                Energy Services

Rebecca L. Farrar         40    Senior Vice President -      January 1, 2000
                                Distribution Operations

Wendy C. Heck             46    Vice President - Infor-      February 3, 1998
                                mation Technology

Chris Hermann             52    Vice President, Supply       January 1, 2000
                                and Logistics


                                       27
<PAGE>

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

Charles A. Markel         52    Vice President -             January 1, 1993
                                Finance and Treasurer

Michael D. Robinson       44    Vice President and           February 16, 1999
                                Controller

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 2000.

There are no family relationships between executive officers of the Company or
executive officers of its subsidiaries.

Messrs. Hale, Lucas, Duncan, Wood, Hewett, McCall, Newton, Markel and Robinson,
and Ms. Farrar and Ms. Heck are also executive officers of LG&E and KU. Mr. Hale
is Chairman of the Board and Chief Executive Officer of LG&E and KU; Mr. Lucas
is Executive Vice President - Power Generation of LG&E and KU; Mr. Duncan is
Chief Financial Officer of LG&E and KU; Mr. Wood is Group Executive - Retail
Business of LG&E and KU; Mr. Hewett is Group Executive - Regulatory Affairs of
LG&E and KU; Mr. McCall is Executive Vice President, General Counsel and
Corporate Secretary of LG&E and KU; Mr. Newton is Senior Vice President and
Chief Administrative Officer of LG&E and KU; Mr. Markel is Treasurer of LG&E and
KU; Mr. Robinson is Vice President and Controller of LG&E and KU; Ms. Farrar is
Senior Vice President - Distribution Operations of LG&E and KU; and Ms. Heck is
Vice President - Information Technology of LG&E and KU. Mr. Hermann is also Vice
President, Supply and Logistics of LG&E.

Mr. Hale was President of LG&E Energy from December 1992 to May 1998.

Before he was elected to his current position, 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 current position, 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 position, Mr. Wood was Executive Vice
President and Chief Administrative Officer of LG&E Energy Corp. from January
1994 to May 1997 and President - Distribution Services Division and President -
Louisville Gas and Electric Company from May 1997 to December 1999.

Before he was elected to his current position, Mr. Hewett was Vice President -
Regulation and Economic Planning of KU from January 1982 to April 1997; Senior
Vice President - Customer Service and Marketing of KU from April 1997 to May
1998; and President of KU from May 1998 to December 1999.

Before he was elected to his current position, Mr. Lucas was Vice President,
Energy Supply of KU from November 1986 to November 1994; and Senior Vice
President, Energy Supply of KU from November 1994 to May 1998.


                                       28
<PAGE>

Before he was elected to his current position, Mr. Basinger was Senior Vice
President of Operations of LG&E Power Inc. from November 1994 to August 1996;
and Senior Vice President - Power Operations of LG&E Energy Corp. from August
1996 to May 1998.

Before he was elected to his current position, Mr. Santa was a member of the
Federal Energy Regulatory Commission from May 1993 to August 1997; and Vice
President and Deputy General Counsel of LG&E Energy Corp. from September 1997 to
October 1998; and Senior Vice President and Deputy General Counsel of LG&E
Energy Corp. from October 1998 to December 1999.

Before he was elected to his current position, 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 position, 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 Business of LG&E Energy Corp. from January
1996 to March 1996; and Vice President - Finance and Controller of LG&E Energy
Corp. from March 1996 to February 1999.

Before he was elected to his current position, 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; and Vice President, Retail Electric Business for LG&E from
December 1998 to August 1999.

Before she was elected to her current position, Ms. Farrar was General Manager,
Gas Operations of South Carolina Electric and Gas Company from July 1994 to
February 1995 and Vice President - Gas Service Business of LG&E from February
1995 to December 1999.

Before she was elected to her current position, Ms. Heck 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 position, 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 he was elected to his current position, Mr. Robinson was Controller of KU
Energy Corporation from June 1990 to May 1998; Controller of KU from August 1990
to May 1998, and Vice President and Controller of LG&E and KU from May 1998 to
the present.


                                       29
<PAGE>

Executive Officers of LG&E:

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

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

Stephen R. Wood          57     Group Executive -            January 1, 2000
                                Retail Business

Robert M. Hewett         53     Group Executive -            January 1, 2000
                                Regulatory Affairs

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

John R. McCall           56     Executive Vice President,    July 1, 1994
                                General Counsel and
                                Corporate Secretary

Wayne T. Lucas           52     Executive Vice President -   May 4, 1998
                                Power Generation

Frederick J. Newton III  44     Senior Vice President and    January 2, 1999
                                Chief Administrative
                                Officer

Rebecca L. Farrar        40     Senior Vice President -      January 1, 2000
                                Distribution Operations

Wendy C. Heck            46     Vice President - Infor-      February 3, 1998
                                mation Technology

Chris Hermann            52     Vice President, Supply       January 1, 2000
                                and Logistics

Michael D. Robinson      44     Vice President and           May 4, 1998
                                Controller

Charles A. Markel        52     Treasurer                    January 1, 1993

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 2000.

There are no family relationships between executive officers of LG&E.

Messrs. Hale, Lucas, Duncan, Wood, Hewett, McCall, Newton, Markel and Robinson,
and Ms. Farrar and Ms. Heck are also executive officers of LG&E Energy Corp. and
KU. Mr. Hale is Chairman of the Board and Chief Executive Officer of LG&E Energy
Corp. and KU; Mr. Lucas is Executive Vice President - Power Generation of LG&E
Energy Corp. and KU; Mr. Duncan is Chief Financial Officer of LG&E Energy Corp.
and KU; Mr. Wood is Group Executive - Retail Business of LG&E Energy Corp. and
KU; Mr. Hewett is Group Executive -


                                       30
<PAGE>

Regulatory Affairs of LG&E Energy Corp. and KU; Mr. McCall is Executive Vice
President, General Counsel and Corporate Secretary of LG&E Energy Corp. and KU;
Mr. Newton is Senior Vice President and Chief Administrative Officer of LG&E
Energy Corp. and KU; Mr. Markel is Vice President - Finance and Treasurer of
LG&E Energy Corp. and Treasurer of KU; Mr. Robinson is Vice President and
Controller of LG&E Energy Corp. and KU; Ms. Farrar is Senior Vice President -
Distribution Operations of LG&E Energy Corp. and KU; and Ms. Heck is Vice
President - Information Technology of LG&E Energy Corp and KU. Mr. Hermann is
also Vice President, Supply and Logistics of LG&E Energy Corp.

Before he was elected to his current position, Mr. Wood was Executive Vice
President and Chief Administrative Officer of LG&E Energy Corp. from January
1994 to May 1997 and President - Distribution Services Division and President -
Louisville Gas and Electric Company from May 1997 to December 1999.

Before he was elected to his current position, Mr. Hewett was Vice President -
Regulation and Economic Planning of KU from January 1982 to April 1997; Senior
Vice President - Customer Service and Marketing of KU from April 1997 to May
1998; and President of KU from May 1998 to December 1999.

Before he was elected to his current position, 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 position, Mr. Lucas was Vice President,
Energy Supply of KU from November 1986 to November 1994; and Senior Vice
President, Energy Supply of KU from November 1994 to May 1998.

Before he was elected to his current position, 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 she was elected to her current position, Ms. Farrar was General Manager,
Gas Operations of South Carolina Electric and Gas Company from July 1994 to
February 1995 and Vice President - Gas Service Business of LG&E from February
1995 to December 1999.

Before she was elected to her current position, Ms. Heck 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 position, 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 he was elected to his current position, Mr. Robinson was Controller of KU
Energy Corporation from June 1990 to May 1998; and Controller of KU from August
1990 to May 1998.


                                       31
<PAGE>

Executive Officers of KU:

                                                             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

Stephen R. Wood          57     Group Executive -            January 1, 2000
                                Retail Business

Robert M. Hewett         53     Group Executive -            January 1, 2000
                                Regulatory Affairs

Wayne T. Lucas           52     Executive Vice President -   May 4, 1998
                                Power Generation

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

John R. McCall           56     Executive Vice President,    May 4, 1998
                                General Counsel and
                                Corporate Secretary

Frederick J. Newton III  44     Senior Vice President and    January 2, 1999
                                Chief Administrative
                                Officer

Rebecca L. Farrar        40     Senior Vice President -      January 1, 2000
                                Distribution Operations

Wendy C. Heck            46     Vice President - Infor-      April 21, 1999
                                mation Technology

Gary E. Blake            46     Vice President - Sales       May 4, 1998
                                and Service

James J. Ellington       54     Vice President - Power       May 4, 1998
                                Generation

Michael D. Robinson      44     Vice President and           May 4, 1998
                                Controller

Charles A. Markel        52     Treasurer                    May 4, 1998

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 2000.

There are no family relationships between executive officers of KU.

Messrs. Hale, Lucas, Duncan, Wood, Hewett, McCall, Newton, Markel and Robinson,
and Ms. Farrar and Ms. Heck are also executive officers of LG&E Energy Corp. and
LG&E. Mr. Hale is Chairman of the Board and


                                       32
<PAGE>

Chief Executive Officer of LG&E Energy Corp. and LG&E; Mr. Lucas is Executive
Vice President - Power Generation of LG&E Energy Corp. and LG&E; Mr. Duncan is
Chief Financial Officer of LG&E Energy Corp. and LG&E; Mr. Wood is Group
Executive - Retail Business of LG&E Energy Corp. and LG&E; Mr. Hewett is Group
Executive - Regulatory Affairs of LG&E Energy Corp. and LG&E; Mr. McCall is
Executive Vice President, General Counsel and Corporate Secretary of LG&E Energy
Corp. and LG&E; Mr. Newton is Senior Vice President and Chief Administrative
Officer of LG&E Energy Corp. and LG&E; Mr. Markel is Vice President - Finance
and Treasurer of LG&E Energy Corp. and Treasurer of LG&E; Mr. Robinson is Vice
President and Controller of LG&E Energy Corp. and LG&E; Ms. Farrar is Senior
Vice President - Distribution Operations of LG&E Energy Corp. and KU; and Ms.
Heck is Vice President - Information Technology of LG&E Energy Corp. and KU.

Before he was elected to his current position, 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 position, Mr. Wood was Executive Vice
President and Chief Administrative Officer of LG&E Energy Corp. from January
1994 to May 1997 and President - Distribution Services Division and President -
Louisville Gas and Electric Company from May 1997 to December 1999.

Before he was elected to his current position, Mr. Hewett was Vice President -
Regulation and Economic Planning of KU from January 1982 to April 1997; Senior
Vice President - Customer Service and Marketing of KU from April 1997 to May
1998; and President of KU from May 1998 to December 1999.

Before he was elected to his current position, Mr. Lucas was Vice President,
Energy Supply of KU from November 1986 to November 1994; and Senior Vice
President, Energy Supply of KU from November 1994 to May 1998.

Before he was elected to his current position, 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 position, 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 position, 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 she was elected to her current position, Ms. Farrar was General Manager,
Gas Operations of South Carolina Electric and Gas Company from July 1994 to
February 1995 and Vice President - Gas Service Business of LG&E from February
1995 to December 1999.

Before she was elected to her current position, Ms. Heck 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; and Vice
President - Information Technology of LG&E Energy Corp. and LG&E from February
1998 to the present.


                                       33
<PAGE>

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 position, Mr. Robinson was Controller of KU
Energy Corporation from June 1990 to May 1998 and Controller of KU from August
1990 to May 1998.

Before he was elected to his current position, Mr. Markel was Vice President -
Finance and Treasurer of LG&E Energy Corp. and Treasurer of LG&E from January
1993 to the present.

                                    PART II.

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

LG&E Energy:

LG&E Energy 's Common Stock is listed on the New York and Chicago Stock
Exchanges. The ticker symbol is "LGE." The newspaper stock exchange listings are
"LGE Energy" or "LGE EN." The following table gives information with respect to
price ranges, as reported via the "GPC" screen by the Bloomberg L.P. Information
Service as New York Stock Exchange Composite Transactions, and dividends paid
for the periods shown (dividends paid have not been restated to reflect the KU
merger).

<TABLE>
<CAPTION>
                                   1999                                    1998
                                   ----                                    ----

                     Dividend       High          Low       Dividend        High         Low
                         Paid      Price        Price           Paid       Price       Price
                         ----      -----        -----           ----       -----       -----
<S>                    <C>      <C>          <C>              <C>       <C>         <C>
First quarter          $.3075   $28.7500     $20.7500         $.2975    $26.4375    $23.0000
Second quarter          .3075    23.0000      20.6875          .2975     27.7500     24.6875
Third quarter           .3075    23.6875      20.6875          .2975     27.8750     22.5000
Fourth quarter          .3175    23.3125      17.3750          .3075     29.3125     26.0625
</TABLE>

The number of record holders of Common Stock at December 31, 1999, totaled
48,296. The book value of the Company's Common Stock at December 31, 1999, was
$8.80 per share.

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 $):

                                                          1999              1998
                                                          ----              ----

         First quarter                                 $22,000           $20,000
         Second quarter                                 22,000            19,800
         Third quarter                                  22,000            21,200
         Fourth quarter                                 23,000            22,000


                                       34
<PAGE>

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 (in
thousands of $):

                                                          1999              1998
                                                          ----              ----

         First quarter                                 $18,000           $17,018
         Second quarter                                 18,000             5,673
         Third quarter                                  18,000            17,400
         Fourth quarter                                 19,000            18,000

ITEM 6. Selected Financial Data.

                             Years Ended December 31
                     (Thousands of $ Except per Share Data)

<TABLE>
<CAPTION>
                                                             1999               1998            1997            1996            1995
                                                            ----               ----            ----            ----            ----
<S>                                                  <C>             <C>                <C>             <C>             <C>
LG&E Energy:

Revenues:
Revenues                                             $ 2,714,911     $    2,112,246     $ 1,832,746     $ 1,645,719     $ 1,503,330
Provision for rate refunds                                (7,635)           (26,000)             --              --         (28,300)
                                                     -----------     --------------     -----------     -----------     -----------
  Net revenues                                         2,707,276          2,086,246       1,832,746       1,645,719       1,475,030
                                                     ===========     ==============     ===========     ===========     ===========

Operating income:
Before non-recurring items                               502,230            472,561         420,971         384,867         349,578
Provision for rate refunds                                (7,635)           (26,000)             --              --         (29,800)
Merger costs and non-
  recurring charges                                           --            (65,318)             --          (5,493)             --
                                                     -----------     --------------     -----------     -----------     -----------
     Operating income                                    494,595            381,243         420,971         379,374         319,778
                                                     ===========     ==============     ===========     ===========     ===========

Net income (loss):
Before non-recurring items                               241,953            230,617         208,363         195,659         176,674
Provision for rate refunds                                (5,690)           (15,556)             --              --         (17,852)
Merger costs and non-
  recurring charges                                           --            (56,389)             --          (2,400)             --
                                                     -----------     --------------     -----------     -----------     -----------
     Total continuing
        operations                                       236,263            158,672         208,363         193,259         158,822
Discontinued operations                                       --            (22,852)        (25,367)         (7,307)             61
Loss on disposal of dis-
  continued operations                                  (174,212)          (224,148)             --              --              --
Cumulative effect of
  accounting change                                           --             (7,162)             --              --              --
                                                                                        -----------     -----------     -----------
     Net income (loss)                               $    62,051     $      (95,490)    $   182,996     $   185,952     $   158,883
                                                     ===========     ==============     ===========     ===========     ===========

Average number of com-
  mon shares outstand-
  ing (000's)                                            129,677            129,679         129,627         129,450         129,261
</TABLE>


                                       35
<PAGE>

                             Years Ended December 31
                     (Thousands of $ Except per Share Data)

<TABLE>
<CAPTION>
                                                             1999               1998            1997            1996            1995
                                                            ----               ----            ----            ----            ----
<S>                                                  <C>             <C>                <C>             <C>             <C>
LG&E Energy: (cont.):

Basic earnings (loss) per
  share of common stock:
Before non-recurring items                           $      1.87     $         1.78     $      1.61     $      1.51     $      1.37
Provision for rate refunds                                  (.05)              (.12)             --              --            (.14)
Merger costs and non-
  recurring charges                                           --               (.43)             --            (.02)             --
Other - rounding                                              --               (.01)             --              --              --
                                                     -----------     --------------     -----------     -----------     -----------
     Total continuing
        operations                                          1.82               1.22            1.61            1.49            1.23
Discontinued operations                                       --               (.17)           (.20)           (.05)             --
Loss on disposal of dis-
  continued operations                                     (1.34)             (1.73)             --              --              --
Cumulative effect of
  accounting change                                           --               (.06)             --              --              --
                                                     -----------     --------------     -----------     -----------     -----------
     Basic earnings
        (loss) per share                             $       .48     $         (.74)    $      1.41     $      1.44     $      1.23
                                                     ===========     ==============     ===========     ===========     ===========

Diluted earnings (loss) per
  share of common stock:
Before non-recurring items                           $      1.87     $         1.77     $      1.61     $      1.51     $      1.37
Provision for rate refunds                                  (.05)              (.12)             --              --            (.14)
Merger costs and non-
  recurring charges                                           --               (.43)             --            (.02)             --
                                                     -----------     --------------     -----------     -----------     -----------
     Total continuing
        operations                                          1.82               1.22            1.61            1.49            1.23
Discontinued operations                                       --               (.17)           (.20)           (.05)             --
Loss on disposal of dis-
  continued operations                                     (1.34)             (1.72)             --              --              --
Cumulative effect of
  accounting change                                           --               (.06)             --              --              --
                                                     -----------     --------------     -----------     -----------     -----------
     Diluted earnings
        (loss) per share                             $       .48     $         (.73)    $      1.41     $      1.44     $      1.23
                                                     ===========     ==============     ===========     ===========     ===========

Cash dividends declared per
  share of common stock                              $     1.250     $        1.240     $     1.113     $     1.081     $     1.050

Payout ratio (from continuing
  operations before non-
  recurring items)                                          67.0%              69.7%           69.3%           71.5%           76.5%

Total assets                                         $ 5,133,757     $    4,823,118     $ 4,620,190     $ 4,190,249     $ 4,148,208

Long-term obligations
  (including amounts
  due within one year)                                 1,711,225          1,510,775       1,230,711       1,193,229       1,208,846
</TABLE>

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


                                       36
<PAGE>

                             Years Ended December 31
                                (Thousands of $)

<TABLE>
<CAPTION>
                                      1999           1998           1997          1996          1995
                                      ----           ----           ----          ----          ----
<S>                            <C>            <C>            <C>           <C>           <C>
LG&E:

Operating revenues:
Revenues                       $   969,984    $   854,556    $   845,543   $   821,115   $   751,763
Provision for rate refunds          (1,735)        (4,500)            --            --       (28,300)
                               -----------    -----------    -----------   -----------   -----------
  Total operating revenues         968,249        850,056        845,543       821,115       723,463
                               ===========    ===========    ===========   ===========   ===========

Net operating income:
Before unusual items               142,263        138,207        148,186       147,263       138,203
Provision for rate refunds          (2,172)        (2,684)            --            --       (16,877)
                               -----------    -----------    -----------   -----------   -----------
  Total net operating income       140,091        135,523        148,186       147,263       121,326
                               ===========    ===========    ===========   ===========   ===========

Net income:
Before unusual items               108,442        104,381        113,273       107,941       100,061
Provision for rate refunds          (2,172)        (2,684)            --            --       (16,877)
Merger costs                            --        (23,577)            --            --            --
                               -----------    -----------    -----------   -----------   -----------
  Net income                       106,270         78,120        113,273       107,941        83,184
                               ===========    ===========    ===========   ===========   ===========

Net income available
  for common stock                 101,769         73,552        108,688       103,373        76,873
                               ===========    ===========    ===========   ===========   ===========

Total assets                     2,171,452      2,104,637      2,055,641     2,006,712     1,979,490
                               ===========    ===========    ===========   ===========   ===========

Long-term obligations
  (including amounts
  due within one year)         $   626,800    $   626,800    $   646,800   $   646,800   $   662,800
                               ===========    ===========    ===========   ===========   ===========
</TABLE>

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 $)

<TABLE>
<CAPTION>
                                 1999         1998         1997        1996        1995
                            ---------    ---------    ---------   ---------   ---------
<S>                         <C>          <C>          <C>         <C>         <C>
KU:

Operating revenues:
Revenues                    $ 943,210    $ 831,614    $ 716,437   $ 711,711   $ 686,430
Provision for rate refund      (5,900)     (21,500)          --          --          --
                            ---------    ---------    ---------   ---------   ---------
  Operating revenues          937,310      810,114      716,437     711,711     686,430
                            =========    =========    =========   =========   =========

Net operating income:
Before unusual items          139,534      138,263      118,408     117,337     108,544
Provision for rate refund      (3,518)     (12,875)          --          --          --
                            ---------    ---------    ---------   ---------   ---------
  Operating income            136,016      125,388      118,408     117,337     108,544
                            =========    =========    =========   =========   =========

Net income:
Before unusual items          110,076      107,303       85,713      86,163      76,842
Provision for rate refund      (3,518)     (12,875)          --          --          --
Merger costs                       --      (21,664)          --          --          --
                            ---------    ---------    ---------   ---------   ---------
  Net income                  106,558       72,764       85,713      86,163      76,842
                            =========    =========    =========   =========   =========
</TABLE>



                                       37
<PAGE>

                             Years Ended December 31
                                (Thousands of $)

<TABLE>
<CAPTION>
                               1999         1998         1997         1996         1995
                               ----         ----         ----         ----         ----
<S>                      <C>          <C>          <C>          <C>          <C>
KU (cont.):

Net income available
  for common stock          104,302       70,508       83,457       83,907       74,586
                         ==========   ==========   ==========   ==========   ==========

Total assets              1,785,090    1,761,201    1,679,880    1,673,055    1,659,988
                         ==========   ==========   ==========   ==========   ==========

Long-term obligations
  (including amounts
  due within one year)   $  546,330   $  546,330   $  546,351   $  546,373   $  545,894
                         ==========   ==========   ==========   ==========   ==========
</TABLE>

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 Energy:

GENERAL

The following discussion and analysis by management focuses on those factors
that had a material effect on the LG&E Energy's financial results of operations
and financial condition during 1999, 1998 and 1997 and should be read in
connection with the consolidated financial statements and notes thereto. As set
forth in the discussion concerning the Discontinuance of the Merchant Energy
Trading and Sales Business below, future financial results from the Company's
operations will continue to reflect the results from its portfolio of
investments in electric generation, gas distribution and other energy-related
businesses in addition to the financial results provided by the Company's
regulated utilities, LG&E and KU.

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 Energy's reports
to the Securities and Exchange Commission, including Exhibit 99.01 to LG&E
Energy's Annual Report on Form 10-K for the year ended December 31, 1998.

MERGERS AND ACQUISITIONS

On February 28, 2000, the Company announced that its Board of Directors accepted
an 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 the Company's debt.
Pursuant to the acquisition agreement, among other things, LG&E Energy will
become a wholly owned subsidiary of PowerGen and its U.S. headquarters. The
Utility Operations of the Company will continue their separate identities and
serve customers in Kentucky and Virginia under their present names. The
preferred stock and debt securities of the Utility Operations will not be
affected by this transaction resulting in the Utility Operations' obligation to
continue to file SEC reports. The acquisition is expected to close later in
2000, shortly after all of the conditions to consummation of the acquisition are
met. Those conditions include,


                                       38
<PAGE>

LG&E Energy: (cont.):

without limitation, the approval of the holders of a majority of the outstanding
shares of common stock of each of LG&E Energy and PowerGen, the receipt of all
necessary governmental approvals and the making of all necessary governmental
filings, including approvals of various regulators in Kentucky and Virginia
under state utility laws, the approval of the FERC under the FPA, the approval
of the SEC under the PUHCA of 1935, and the filing of requisite notifications
with the Federal Trade Commission and the Department of Justice under the
Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and the
expiration of all applicable waiting periods thereunder. Shareholder meetings to
vote upon the approval of the Acquisition are expected to be held during the
second quarter of 2000 for both LG&E Energy and PowerGen. During the first
quarter of 2000, the Company expensed approximately $1.0 million relating to the
PowerGen transaction. The foregoing description of the acquisition does not
purport to be complete and is qualified in its entirety by reference to LG&E
Energy's current reports on Form 8-K, filed February 29, 2000, with the SEC.

In July 1999, the Company purchased 100% of the outstanding common stock of CRC
for initial consideration of $45.6 million and retirement of approximately $35.3
million in CRC debt. CRC, based in Houston, Texas, is a provider of specialized
equipment and services used in the construction and rehabilitation of gas and
oil transmission pipelines. The purchase agreement provides for future annual
earn-out payments to the previous owners based on CRC's meeting certain
financial targets over the period ending March 31, 2002, or, under certain
circumstances, a change in control of LG&E Energy may accelerate the earnout.
The agreement capped the total of these payments at $34.3 million. The Company
accounted for the acquisition using the purchase method and recorded goodwill of
approximately $42.1 million. Additional goodwill will be recorded contingent
upon future earn-out payments. Goodwill is being amortized over a period of
twenty years.

In March 1999, the Company acquired an indirect 20% ownership interest in Gas
BAN, a natural gas distribution company that serves 1.1 million customers in the
northern portion of the province of Buenos Aires, Argentina. The purchase price
totaled $74.3 million, including transaction costs, which has been reflected in
investments in unconsolidated ventures in the accompanying balance sheet. The
Company records its share of earnings using the equity method. The purchase
price exceeded the underlying equity in Gas BAN by $13.0 million. The Company
allocated this difference to the assets and liabilities acquired based on their
preliminary estimated fair values.

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 accompanying consolidated financial statements
reflect the accounting for the merger as a pooling of interests and are
presented as if the companies were combined as of the earliest period presented.
However, the financial information is not necessarily indicative of the results
of operations, financial position or cash flows that would have occurred had the
merger been consummated for the periods for which it is given effect, nor is it
necessarily indicative of future results of operations, financial position, or
cash flows. The financial statements reflect the conversion of each outstanding
share of KU Energy common stock into 1.67 shares of LG&E Energy common stock.
The outstanding preferred stock of LG&E and KU was not affected by the merger.
See Note 2 of LG&E Energy's Notes to Financial Statements under Item 8.

DISCONTINUANCE OF MERCHANT ENERGY TRADING AND SALES BUSINESS

Effective June 30, 1998, the Company discontinued its merchant energy trading
and sales business. This business consisted primarily of a portfolio of energy
marketing contracts entered into in 1996 and early 1997, nationwide deal
origination and some level of speculative trading activities, which were not
directly supported by the Company's physical assets. The Company's decision to
discontinue these operations was primarily based on the impact that volatility
and rising prices in the power market had on its portfolio of energy marketing


                                       39
<PAGE>

LG&E Energy: (cont.):

contracts. Exiting the merchant energy trading and sales business enabled the
Company to focus on optimizing the value of physical assets it owns or controls,
and reduced the earnings impact on continuing operations of extreme market
volatility in its portfolio of energy marketing contracts. The Company continues
to settle commitments that obligate it to buy and sell natural gas and electric
power. If the Company is unable to dispose of these commitments or assets it
will continue to meet its obligations under the terms of the contracts. The
Company, however, has maintained sufficient market knowledge, risk management
skills, technical systems and experienced personnel to maximize the value of
power sales from physical assets it owns or controls, including LG&E, KU and
WKE.

As a result of the Company's decision to discontinue its merchant energy trading
and sales activity, and the initial decision to sell the associated gas
gathering and processing business, the Company recorded an after-tax loss on
disposal of discontinued operations of $225 million in the second quarter of
1998. The loss on disposal of discontinued operations resulted primarily from
several fixed-price energy marketing contracts entered into in 1996 and early
1997, including the Company's long-term contract with OPC. Other components of
the write-off included costs relating to certain peaking options, goodwill
associated with the Company's 1995 purchase of merchant energy trading and sales
operations and exit costs.

At the time the Company decided to discontinue its merchant energy trading and
sales business, it also decided to sell its natural gas gathering and processing
business. Effective June 30, 1999, the Company decided to retain this business.
The accompanying financial statements reflect the reclassification of the
natural gas gathering and processing business as continuing operations for all
periods presented. Approximately $800,000 of net losses charged to the loss on
disposal of discontinued operations was reclassified to continuing operations in
the accompanying income statement in each of 1999 and 1998 related to the
natural gas gathering and processing business. See Note 4 of LG&E Energy's Notes
to Financial Statements under Item 8.

In the fourth quarter of 1999, the Company received an adverse decision from the
arbitration panel considering its contract dispute with OPC, which was commenced
by the Company in April 1998. As a result of this adverse decision, higher than
anticipated commodity prices, increased load demands, and other factors, the
Company increased its after-tax accrued loss on disposal of discontinued
operations by $175 million. The additional write-off included costs related to
the remaining commitments in its portfolio and exit costs expected to be
incurred to serve those commitments. Although the Company used what it believes
to be appropriate estimates for future energy prices, among other factors, to
calculate the net realizable value of discontinued operations, there are
inherent limitations in models to accurately predict future commodity prices,
load demands and other events that could impact the amounts recorded by the
Company.

Total pretax charges against the accrued loss on disposal of discontinued
operations through December 31, 1999, include $251.0 million for commitments
prior to disposal, $69.6 million for transaction settlements, $11.1 million for
goodwill, and $30.5 million for other exit costs. While the Company has been
successful in settling portions of its discontinued operations, significant
assets, operations and obligations remain. The Company continues to manage the
remaining portfolio and believes it has hedged certain of its future obligations
through various power purchase commitments and planned construction of physical
assets. Management cannot predict the ultimate effectiveness of these hedges.

The pretax net fair value of the remaining commitments as of December 31, 1999,
are currently estimated to be approximately $46 million in 2000, $37 million to
$54 million each year in 2001 through 2004 and $7 million in the aggregate
thereafter.

As of December 31, 1999, the Company's discontinued operations were under
various contracts to buy and sell


                                       40
<PAGE>

LG&E Energy: (cont.):

power and gas with net notional amounts of 22.1 million Mwh's of power and 44.3
million Mmbtu's of natural gas with a volumetric weighted-average period of
approximately 37 and 44 months, respectively. These notional amounts are based
on estimated loads since various commitments do not include specified firm
volumes. The Company is also under contract to buy or sell coal and SO2
allowances in support of its power contracts. Notional amounts reflect the
nominal volume of transactions included in the Company's price risk management
commitments, but do not reflect actual amounts of cash, financial instruments,
or quantities of the underlying commodity which may ultimately be exchanged
between the parties.

As of January 26, 2000, the Company estimates that a $1 change in electricity
prices and a 10-cent change in natural gas prices across all geographic areas
and time periods could change the value of the Company's remaining energy
portfolio by approximately $4.9 million. In addition to price risk, the value of
the Company's remaining energy portfolio is subject to operational and event
risks including, among others, increases in load demand, regulatory changes, and
forced outages at units providing supply for the Company. As of January 26,
2000, the Company estimates that a 1% change in the forecasted load demand could
change the value of the Company's remaining energy portfolio by $8.2 million.
See Notes 3 and 18 of LG&E Energy's Notes to Financial Statements under Item 8.

The Company reclassified its financial statements for prior periods to present
the operating results, financial position and cash flows of these businesses as
discontinued operations. See Notes 1 and 3 of LG&E Energy's Notes to Financial
Statements under Item 8 for more information.

RESULTS OF OPERATIONS

Earnings Per Share

Continuing operations for 1999 produced basic earnings per share of $1.82, an
increase of 60 cents from $1.22 earned from continuing operations in 1998, after
merger-related costs and environmental cost recovery refunds of approximately 43
cents and 12 cents, respectively. Earnings in both 1999 and 1998 include certain
non-recurring items relating to rate refunds and gains. Excluding the effects of
rate refunds in 1999 of 5 cents, and gains in 1999 and 1998 related to the
Company's investment in the Rensselaer power facility of approximately 7 cents
and 16 cents, respectively, earnings for 1999 were $1.80 per share compared with
$1.61 in 1998, an increase of 19 cents or 12%. The 19 cents per share increase
was primarily driven by the Company's non-utility operations including its 1999
acquisitions of Gas BAN and CRC, strong sales and excellent operating
performance at WKE, and improved operating results at the Company's other
Argentine gas operations. The Company's utility operations earnings from
continuing operations for 1999 and 1998 were approximately the same.

Continuing operations for 1998 produced basic earnings per share of $1.22,
before a decrease of 6 cents due to cumulative effect of an accounting change, a
decrease of 39 cents per share from $1.61 earned from continuing operations in
1997. Earnings for 1998 include non-recurring charges for merger-related costs
and environmental cost recovery refunds of approximately 43 cents and 12 cents,
respectively. Excluding these non-recurring charges, earnings per share from
continuing operations for 1998 were $1.78, an increase of 17 cents over 1997.
The 17 cent per share increase resulted from a 10 cent increase in core domestic
utility business and a 14 cent increase in non-utility business, partially
offset by an increase in corporate and other expenses of 7 cents. The 1998
non-utility results included 16 cents relating to the Rensselaer power purchase
contract settlement, 3 cents for first-year earnings related to the Big Rivers
transactions, 1 cent due to a full year of operations and an increase in core
business of the Company's Argentine operations, partially offset by an increase
in non-utility expenses of 4 cents, primarily related to the loss on disposition
of our gas-fired power


                                       41
<PAGE>

LG&E Energy: (cont.):

plant in San Miguel, Argentina and, the write-off of our WPP 94 investment.

In the fourth quarter of 1999, the Company increased its after-tax accrued loss
on disposal of discontinued operations by $175 million ($1.35) per share. This
increase was triggered by an adverse decision in the arbitration proceedings
with OPC and resulted from higher-than-anticipated commodity prices, increased
load demands and other factors. In June 1998, after the Company's decision to
exit the merchant energy trading and sales business, the Company recorded an
after-tax accrual for disposal of discontinued operations of approximately $224
million ($1.72) and reclassified approximately $23 million ($0.17) of losses due
to merchant energy trading and sales to loss from discontinued operations. See
Note 3 of LG&E Energy's Notes to Financial Statements under Item 8 for a
discussion of the Company's losses related to its discontinued operations in
1999 and 1998.

Electric and Gas Utility Results

Revenues

A comparison of utility revenues for the years 1999 and 1998, excluding
provisions recorded for rate refunds in 1999 and 1998, with the immediately
preceding year reflects both increases and decreases, which have been segregated
by the following principal causes (in thousands of $):

<TABLE>
<CAPTION>
                                               Increase (Decrease) From Prior Period
                                            Electric Revenues            Gas Revenues
                                               1999         1998         1999         1998
                                               ----         ----         ----         ----
<S>                                       <C>          <C>          <C>          <C>
Retail sales:
  Fuel and gas supply adjustments, etc    $  (3,758)   $   4,908    $ (24,791)   $  (4,393)
  Merger surcredit                           (8,317)      (7,501)          --           --
  Demand side management/decoupling          (2,985)      (6,299)      (6,462)        (369)
  Environmental cost recovery surcharge      (2,547)        (807)          --           --
  Performance based rate reduction          (11,634)          --           --           --
  Variation in sales volumes                 41,312       52,892       17,779      (42,418)
                                          ---------    ---------    ---------    ---------
     Total retail sales                      12,071       43,193      (13,474)     (47,180)
Wholesale sales                             215,374       88,851         (602)       8,720
Gas transportation-net                           --           --         (575)         (71)
Other                                           764        1,211          685         (935)
                                          ---------    ---------    ---------    ---------
  Total                                   $ 228,209    $ 133,255    $ (13,966)   $ (39,466)
                                          =========    =========    =========    =========
</TABLE>

Electric revenues increased in 1999 primarily due to wholesale electric sales
and increased retail sales volumes, partially offset by the PBR and merger
surcredit bill reductions. Wholesale sales increased in 1999 due to larger
amounts of power available for off-system sales, and an increase in the unit
price of electricity sold. 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.

Electric retail sales increased primarily due to the warmer weather in 1998 as
compared to 1997. Wholesale sales increased due to larger amounts of power
available for off-system sales, and an increase in the unit price of the sales.
Gas retail sales decreased from 1997 due to the warmer seasonal weather in 1998.
Gas wholesale sales increased to $8.7 million in 1998 from zero in 1997 due to
the implementation of LG&E's gas performance-based ratemaking mechanism.


                                       42
<PAGE>

LG&E Energy: (cont.):

Expenses

Fuel for electric generation and gas supply expenses comprise a large component
of the Company's total operating costs. LG&E's and KU's electric rates contain
an FAC and LG&E's gas rates contain a GSC, whereby increases or decreases in the
cost of fuel and gas supply are reflected in LG&E's and KU's rates, subject to
approval by the Kentucky Commission, the Virginia Commission and FERC. In July
1999, the Kentucky Commission approved LG&E's and KU's joint filing on PBR
resulting in the discontinuance of the FAC. In January 2000, the Kentucky
Commission rescinded its approval of LG&E's and KU's joint PBR filing and
ordered the reinstatement of the FAC. See Note 6 for a further discussion of the
PBR and the FAC.

Fuel for electric generation increased $6.9 million in 1999 primarily due to an
increase in generation to support increased electric sales at LG&E ($7.4
million) and KU ($5.1 million) offset partially by a lower cost of coal burned
at LG&E ($3.0 million) and at KU ($2.6 million). Fuel for electric generation
increased $34.1 million in 1998 primarily due to an increase in generation to
support increased electrical sales at KU ($27.3 million) and a higher cost of
coal burned at LG&E ($6.6 million). LG&E's average delivered cost per ton of
coal purchased was $21.49 in 1999, $22.38 in 1998 and $21.66 in 1997. KU's
average delivered cost per ton of coal purchased was $26.65 in 1999, $26.97 in
1998 and $27.97 in 1997.

Power purchased increased $219.9 million (147.3%) in 1999 primarily due to
increased purchases to serve native load customers and off-system sales
activity. Power purchased increased $59.5 million in 1998 to support the
increase in wholesale sales and due to increases in the unit price of purchases.

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).
Gas supply expenses decreased $33 million (21%) in 1998 primarily due to a
decrease in the volume of gas delivered to the distribution system. The average
unit cost per Mcf of purchased gas was $2.99 in 1999, $3.05 in 1998 and $3.46 in
1997.

Operation and maintenance expenses decreased $14.3 million (3.3%) in 1999
primarily due to decreased costs to operate LG&E's electric generating plants
($5.7 million), lower administrative costs at LG&E and KU ($7.0 million) and
lower costs to maintain KU's electric generating plants ($3.3 million).
Operation and maintenance expenses increased $14.6 million (3.8%) in 1998 over
1997 because of increased costs to operate and maintain LG&E's electric
generating plants ($8.8 million), amortization of deferred merger costs ($3.8
million), and an increase in storm damage expenses ($1.4 million).

Depreciation and amortization increased $7.3 million (4.1%) in 1999 because of
additional utility plant in service. Depreciation and amortization increased
$2.7 million (1.5%) in 1998 because of additional utility plant in service.

The companies incurred a pre-tax charge in the second quarter of 1998 for costs
associated with the merger of LG&E Energy and KU Energy of $53.9 million (of
this amount, $32.1 million was for LG&E, and $21.8 million was for KU). The
amount charged is in excess of the amount permitted to be deferred as a
regulatory asset by the Kentucky Commission.

Interest charges for 1998 decreased $3.9 million (7%) due to the retirement of
LG&E's 6.75% Series First Mortgage Bonds and lower interest rates. LG&E's
embedded cost of long-term debt was 5.46% at December 31, 1999 and 5.57% at
December 31, 1998. KU's embedded cost of long-term debt was 7.00% at December
31, 1999 and 6.99% at December 31, 1998.


                                       43
<PAGE>

LG&E Energy: (cont.):

Variations in income tax expenses 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 the Company's utility
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.

LG&E Capital Corp. and Other Results

Capital Corp., the holding company for all the Company's non-utility investments
other than trading operations, conducts its operations through three principal
segments: Power Operations, WKE and Argentine Gas Distribution. Involvement in
these and other non-utility businesses represents the Company's commitment to
understand, respond to, and capitalize on the opportunities presented by an
emerging competitive energy services industry. The Power Operations develop,
operate, maintain and own interests in domestic and international power
generation facilities that sell electric and steam energy to utility and
industrial customers. WKE leases and operates the generating facilities of Big
Rivers. Argentine Gas Distribution owns interests in three natural gas
distribution companies in Argentina. Capital Corp. and LEM are also engaged in
other non-utility activities including: providing specialized equipment and
services used in construction and rehabilitation of gas and oil transmission
pipelines; the gathering, processing, storing and transportation of natural gas;
commercial and retail initiatives designed to assess the energy and utility
needs of large commercial and industrial entities; providing maintenance and
repair services for customers' major household appliances; and, the asset
optimization of the Company's generation assets. See Notes 2, 5, 9, 10, 18 and
20 of LG&E Energy's Notes to Financial Statements under Item 8.

Power Operations

Revenues

Revenues from Power Operations, comprised mainly of contractual revenues from
various power plant operations, were approximately the same for the years 1997
to 1999. See Note 9 of LG&E Energy's Notes to Financial Statements under Item 8.

Equity in earnings of unconsolidated ventures includes the Company's share of
earnings from the ventures in which it maintains an equity interest, but does
not consolidate the results of operations. Equity in earnings for 1999 of $40.9
million was $30.4 million less than 1998, primarily due to transactions recorded
by its Rensselaer venture in 1999 and 1998, including a gain on a power purchase
contract settlement in 1998, the sale of the Company's ownership interest in
March, and a full year of earnings in 1998 versus 2 1/2 months in 1999. Without
the Rensselaer transactions in 1999 and 1998, equity in earnings of the
Company's other ventures were approximately the same. Equity in earnings for
1998 were $50.8 million higher (247%) than in 1997 due primarily to the
Rensselaer power purchase contract settlement and an arbitration award received
by the Frederickson, Washington, venture. These increases were partially offset
by a write-off of the Company's investment in a wind power venture. See Notes 9
and 20 of LG&E Energy's Notes to Financial Statements under Item 8.

Expenses

Direct costs of revenues are primarily comprised of labor and related expenses
associated with the Company 's operation of various power plants. Direct costs
increased by $1.7 million in 1999 to $15.1 million, primarily


                                       44
<PAGE>

LG&E Energy: (cont.):

due to development expenses of the Gregory, Texas, project. These costs were
approximately the same in 1998 and 1997.

Operation and maintenance expenses were approximately the same for all periods
presented. Depreciation and amortization decreased by $1.7 million in 1999
primarily due to the write-off of certain intangible assets in 1998 after the
Rensselaer power purchase contract settlement and the sale of a 114 Mw gas-fired
power plant in San Miguel, Argentina, offset by an additional write-off of
intangible assets upon the sale of the Rensselaer venture in March 1999.
Depreciation and amortization increased $3.3 million in 1998 due to the
write-off of certain intangible assets and capitalized interest associated with
the sale of the Company's interest in the San Miguel, Argentina, venture and the
closure of the Rensselaer power purchase contract settlement. See Note 9 of LG&E
Energy's Notes to Financial Statements under Item 8.

Western Kentucky Energy

WKE's 1999 results include twelve-months of operations versus 5 1/2 months in
1998, the primary driver in most year-over-year increases. Total revenues
increased by $205.3 million (159%) to $333.8 million due primarily to a full
year of operation in 1999 and higher power sales prices in the summer of 1999.
Cost of revenues increased by $136.6 million (186%) to $209.7 million due
primarily to a full year of operation in 1999 and higher purchase power costs.
Operations and maintenance expenses increased by $56.3 million (127%) to $103.1
million primarily due to a full year of operation in 1999 and higher
depreciation expenses related to an increase in capital assets. Net interest
expense increased by $1.5 million (58%) to $4.1 million related to the cost of
carrying its debt for a full year.

During WKE's partial year of operations in 1998 it reported a solid performance
with revenues of $128.5 million. WKE's cost of revenues, primarily composed of
fuel and purchased power expenses, amounted to $73.1 million for the year.
Operation and maintenance expenses of $45.4 million include $12.8 million of
rent expense associated with the lease of Big Rivers' operating facilities. WKE
incurred interest expense of approximately $2.6 million associated with
borrowings to fund the initial purchase of certain materials and supplies from
Big Rivers and to prepay the first two years' lease payments totaling $55.9
million. See Note 5 of LG&E Energy's Notes to Financial Statements under Item 8.

Argentine Gas Distribution

The Company has interests in three Argentine natural gas distribution companies:
Centro and Cuyana, both acquired in February 1997, and Gas BAN acquired in March
1999. Centro is consolidated within the Company's results while Cuyana's and Gas
BAN's results are recorded using the equity method of accounting. The Company's
investments in Argentina continue to contribute to non-utility operations, with
Centro's revenues increasing by $8 million (5%) in 1999 and $21 million (16%) in
1998. The increase in 1999 was primarily driven by higher per customer
consumption as a result of colder than normal weather. 1998's increase was due
to a full year of operations versus 10 1/2 months in 1997, higher per customer
consumption and an increase in the customer base. Centro's operating expenses
increased by $.8 million (3%) in 1999 due to higher consumption. Centro's 1998
operating expenses increased by $2.4 million (8%) due to a full year of
operations in 1998. Equity in earnings for 1999 increased by $6.3 million (253%)
due to the Gas BAN acquisition completed in March 1999. Equity in earnings of
Cuyana were approximately the same in all periods presented. See Notes 2 and 9
of LG&E Energy's Notes to Financial Statements under Item 8.


                                       45
<PAGE>

LG&E Energy: (cont.):

Other

The Company has entered into various initiatives to position itself for growth
in the energy industry, including: providing specialized equipment and services
used in construction and rehabilitation of gas and oil transmission pipelines;
the gathering, processing, storing and transportation of natural gas; consulting
services designed to assess the energy and utility needs of large commercial and
industrial entities; providing maintenance and repair services for customers'
major household appliances; and, the optimizing of the Company's generation
assets. The commercial initiatives represent new businesses and products
designed to leverage the Company's existing assets and experience, and to gain
access to new markets. Our retail initiatives enhance value for LG&E's and KU's
customers and are designed to help ensure that LG&E and KU remain the utility of
choice within their respective service areas when a fully competitive industry
framework takes shape. These commercial and retail initiatives have not had a
significant impact on the Company's financial position or required significant
capital investment over the last three years. We remain optimistic that these
non-traditional ventures will add to our knowledge base as well as our financial
results in the future.

The Company's interest costs increased by $22.7 million (83%) from 1998 to 1999
and $5.0 million (5%) from 1997 to 1998. The 1999 increase was primarily due to
the funding of discontinued operations and LG&E Energy's operating expenses,
along with funding the Gas BAN and CRC acquisitions. The increase in 1998 was
primarily due to the funding of discontinued operations and LG&E Energy's
operating expenses. See Notes 2, 3, 7 and 16 of LG&E Energy's Notes to Financial
Statements under Item 8.

LIQUIDITY AND CAPITAL RESOURCES

The Company uses net cash generated from its operations and external financing
to fund construction of plant and equipment, equity investments in
energy-related growth or acquisition opportunities, liquidity needs of its
discontinued energy marketing and trading activities and operating its existing
businesses. The Company 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 $343.3 million, $209.6 million and $333.7
million in 1999, 1998 and 1997, respectively. The 1999 increase was primarily
due to an increase in net income, a net decrease in non-cash income statement
items, including the recording of the reserve on loss on disposal of
discontinued operations, and a net increase in net current assets, including
increases in accounts payable, accrued taxed and interest, and materials and
supplies. The 1998 decrease was primarily due to a decrease in net income and an
increase in materials and supplies, partially offset by a net increase in
non-cash income statement items, including the recording a loss on disposal of
discontinued operations and increases in accounts payable and accrued taxes and
interest.

Investing Activities

LG&E Energy's primary use of funds continues to be for capital expenditures and
investments in subsidiaries/unconsolidated ventures. Capital expenditures were
$382.6 million, $343.6 million and $225.7 million in 1999, 1998 and 1997,
respectively. The Company expects its capital expenditures for 2000 and 2001
will total approximately $850 million, consisting primarily of construction
costs associated with installation of low nitrogen oxide burner systems for
LG&E, KU and WKE as described in the section titled "Environmental Matters."


                                       46
<PAGE>

LG&E Energy: (cont.):

Net cash used for investment activities increased by $115.4 million in 1999
compared to 1998. The increase was primarily due to the acquisition of CRC, the
20% investment in Gas BAN, and an increase in construction expenditures. This
increase was partially offset by proceeds received from the sales of the
Company's ownership interest in Rensselaer and five combustion turbines.

Net cash used for investment activities decreased by $45.5 million in 1998
compared to 1997 primarily due to a decrease in investment in subsidiaries and
unconsolidated ventures partially offset by an increase in construction
expenditures.

Financing Activities

Cash inflows from financing activities were $84.9 million, $111.6 million and
$42.8 million in 1999, 1998 and 1997, respectively. In 1999, total debt
increased by $284.9 million to $2,160.8 at December 31, 1999. The increase was
primarily due to funding operating expenses, discontinued operations and
business development activities including the acquisitions of CRC and Gas BAN.

As of December 1999, the Company had committed lines of credit aggregating
$900.0 million with various banks. Unused capacity under these lines totaled
$395.6 million after considering the commercial paper support and approximately
$51.7 million in letters of credit securing on- and off-balance sheet
commitments. The credit lines will expire at various times from 2000 through
2002. Management expects to renegotiate the lines as they expire.

The lenders under the credit facilities, the commercial paper facility, the
medium-term notes for Capital Corp. and the lessors of the operating lease for
the Monroe plant are entitled to the benefits of a Support Agreement with LG&E
Energy. See Note 18 of LG&E Energy's Notes to Financial Statements under Item 8.

Future Capital Requirements

Future utility 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. Other future capital funding requirements are dependent
upon the identification of suitable investment and acquisition opportunities.
The Company anticipates funding these investment opportunities through net cash
generated from operations, additional debt or an issuance of preferred stock.


                                       47
<PAGE>

LG&E Energy: (cont.):

The Company's debt ratings as of February 16, 2000, were:

                                       Moody's            S&P           D&P
                                       -------            ---           ---

         LG&E
         First mortgage bonds             A1              A+            AA-
         Unsecured debt                   A2              A-            A+
         Preferred stock                  a2              BBB+          A
         Commercial paper                 P-1             A-1           D-1

         KU
         First mortgage bonds             A1              A+            AA-
         Preferred stock                  a2              BBB+          A
         Commercial paper                 P-1             A-1           D-1

         Capital Corp.
         Medium-term notes                A3              A-            A-
         Commercial paper                 P-2             A-1           D-1-

The ratings stated above reflect the downgrades received by the Company
following an adverse decision in the OPC arbitration case, which resulted in an
additional $175 million after-tax charge to increase the Company's discontinued
operations reserve, and the PBR-related order received from the Kentucky
Commission to reduce base rates at LG&E and KU by $27.2 million and $36.5
million, respectively. As of March 21, 2000, Moody's, S&P and D&P had LG&E
Energy, LG&E, KU and Capital Corp. on Credit Watch with negative implications.
Based upon the downgrades received the Company's cost of funds could increase by
 .05% to .12% on short-term borrowings and .10% on new long-term borrowings.
These ratings reflect the views of Moody's, S&P and D&P. A security rating is
not a recommendation to buy, sell or hold securities and is subject to revision
or withdrawal at any time by the rating agency.

Market Risks

LG&E Energy is exposed to market risks in both its regulated and non-utility
operations. Both operations are exposed to market risks from changes in interest
rates and commodity prices, while the non-utility operations are also exposed to
changes in foreign exchange rates. To mitigate changes in cash flows
attributable to these exposures, the Company has entered into various derivative
instruments. Derivative positions are monitored using techniques that include
market value and sensitivity analysis.

Interest Rate Sensitivity

The Company has short-term and long-term variable rate debt obligations
outstanding. At December 31, 1999, the potential change in interest expense
associated with a 1% change in base interest rates of the Company's unswapped
debt is estimated at $7.0 million. These swaps hedge specific debt issuance and
consistent with management's designation are accorded hedge accounting
treatment.

As of December 31, 1999, the Company had swaps with a combined notional value of
$404 million. LG&E and Capital Corp. have entered into $251 million of swaps to
exchange their floating-rate interest payments for fixed interest payments to
reduce the impact of interest rate changes on their Pollution Control Bonds and
commercial paper program, respectively. LEC and KU have entered into $153
million to convert some of its fixed rate debt to variable rate debt. As of
December 31, 1999, 31% of the outstanding variable interest rate


                                       48
<PAGE>

LG&E Energy: (cont.):

borrowings were converted to fixed interest rates, while 11% of the outstanding
fixed interest rate borrowings were converted to floating 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 $13.1
million as of December 31, 1999. Changes in the market value of these swaps if
held to maturity, as the Company intends to do, will have no effect on the
Company's net income or cash flow. See Note 7 of LG&E Energy's Notes to
Financial Statements under Item 8.

Commodity Price Sensitivity

LG&E and KU have limited exposure to market price volatility in prices of fuel
and electricity, as long as cost-based regulations exist, including the FAC and
GSC. WKE is exposed to changes in fuel prices. To mitigate this risk, WKE has
entered into various multi-year fuel supply contracts which expire at various
times through 2003 and is also pursuing the use of alternative fuels. Realized
gains and losses are recognized in the income statement as incurred. At December
31, 1999, exposure from these activities was not material to the consolidated
financial statements of the Company.

Capital Corp., through its subsidiaries, operates and controls the generating
capacity of Big Rivers and Henderson. Some of the excess capacity generated by
these assets is currently being marketed by WKE. To mitigate residual risks
relative to the movements in electricity prices, WKE has entered into primarily
fixed-priced contracts for the purchase and sale of electricity through the
wholesale electricity market. Realized gains and losses are recognized in the
income statement as incurred. At December 31, 1999, exposure from these
activities was not material to the consolidated financial statements of the
Company.

The Company's discontinued merchant energy trading and sales business has
exposure to market volatility in electricity prices and load requirements. See
Discontinuance of Merchant Energy Trading and Sales Business under Management's
Discussion and Analysis and Note 3 of LG&E Energy's Notes to Financial
Statements under Item 8.

Exchange Rate Sensitivity

The Company has investments in Argentina, Canada, Spain and the UK that are not
hedged. The Company relies on the Argentine peso's currency peg to the U.S.
dollar to mitigate currency risk attributable to its Argentine investments and
views its investments in Canada, Spain and the UK as too small to
cost-effectively hedge. A 10% decline in the December 31, 1999 exchange rate for
the Argentine peso, the Canadian dollar, British pound sterling and the Spanish
peseta (versus the U.S. dollar) would not have a material effect on income from
continuing operations.

YEAR 2000 COMPUTER SOFTWARE ISSUE

Result of Year 2000 Preparation

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


                                       49
<PAGE>

LG&E Energy: (cont.):

Cost of Year 2000 Issues

The Company's system modification costs related to the Year 2000 issue were
expensed as incurred, with new system installations being capitalized pursuant
to generally accepted accounting principles. See Note 1 of LG&E Energy's Notes
to Financial Statements under Item 8. Through December 1999, the Company had
incurred approximately $26.7 million in capital and operating costs in
connection with the Year 2000 issue.

RATES AND REGULATION

LG&E and KU are 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. KU is also subject to the jurisdiction of the
Virginia Commission and FERC. Given LG&E's and KU's competitive position in the
market and the status of regulation in the states of Kentucky and Virginia,
neither LG&E nor KU has plans or intentions to discontinue its application of
SFAS No. 71. See Note 6 of LG&E Energy's Notes to Financial Statements under
Item 8.

Environmental Cost Recovery

In August 1994 and May 1995, respectively, KU and LG&E implemented an ECR
surcharge. The Kentucky Commission's order approving the surcharge for KU as
well as the constitutionality of the surcharge was challenged by certain
intervenors in Franklin Circuit Court. Decisions of the Circuit Court and the
Kentucky Court of Appeals in July 1995 and December 1997, respectively, upheld
the constitutionality of the ECR statute but differed on a claim of retroactive
recovery of certain amounts. Based on these decisions, the Kentucky Commission
ordered that certain surcharge revenues collected by LG&E and KU be subject to
refund pending final determination of all appeals.

In December 1998, the Kentucky Supreme Court rendered an opinion upholding the
constitutionality of the surcharge statute but denied recovery of costs
associated with pre-1993 environmental projects through the ECR. The court
remanded the case to the Kentucky Commission to determine amounts to be refunded
for revenues collected for such pre-1993 environmental projects. Accordingly,
the Company recorded a provision for rate refunds of $26 million in December
1998.

The parties to the proceedings reached a settlement agreement that was approved
in a Final Order issued by the Kentucky Commission in August 1999. This Final
Order resulted in the reversal of approximately $0.9 million of the provision
for rate refunds established by KU and LG&E in December 1998. The refund is
being applied to customers' bills during the twelve-month period beginning
October 1999.

Future Rate Regulation

In October 1998, LG&E and KU filed applications with the Kentucky Commission for
approval of a new method of determining electric rates that sought to provide
financial incentives for LG&E and 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 LG&E and 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
LG&E and 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.


                                       50
<PAGE>

LG&E Energy: (cont.):

In April 1999, LG&E and KU filed a joint agreement among the companies and the
Kentucky Attorney General to adopt the PBR plan subject to certain amendments.
The amended filing included requested Kentucky Commission approval of a
five-year rate reduction plan which proposed to reduce the electric rates of
LG&E and KU by $20 million in the first year (beginning July 1999), and by $8
million annually through June 2004. The proposed amended plan also included
establishment of a $6 million program for low-income customer assistance as well
as extension for one additional year of both the rate cap proposal and merger
savings surcredit established in the original merger plan of LG&E and KU. Under
the rate cap proposal, the companies agreed, in the absence of extraordinary
circumstances, not to increase base electric rates for five years following the
merger and LG&E also agreed to refrain from filing for an increase in natural
gas rates through June 2004.

In April 1999, 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 and KU's amended PBR plans and the KIUC
rate reduction petitions in August and September 1999. Legal briefs of the
parties were filed with the Kentucky Commission in October 1999. KIUC's position
called for annual revenue reductions for LG&E and KU of $69.6 million and $61.5
million, respectively.

In January 2000, the Kentucky Commission issued Orders for LG&E and KU in the
subject cases. The Kentucky Commission ruled that LG&E and KU should reduce base
rates by $27.2 million and $36.5 million, respectively, effective with bills
rendered beginning March 1, 2000. The Kentucky Commission eliminated the
utilities' proposal to operate under its PBR plan and reinstated the FAC
mechanism effective March 1, 2000. The Kentucky Commission offered the utilities
the opportunity to operate under an ESM for the next three years. Under this
mechanism, incremental annual earnings for each utility resulting in a rate of
return 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, the utilities 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 and KU
of $1.1 million and $7.7 million, respectively. The utilities also filed motions
for reconsideration with the Kentucky Commission on a number of items in the
case in late January. Certain intervening parties in the proceedings have also
filed motions for reconsideration asserting, among other things, that the
Kentucky Commission understated the amount of base rate reductions. In February
2000, LG&E and KU accepted the Kentucky Commission's proposed ESM and filed an
ESM tariff which contained detailed provisions for operation of the ESM rates.
Management cannot predict final outcome of these matters before the Kentucky
Commission or the timing in which resolution of these matters will ultimately be
reached.

Other Rate Matters

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 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.

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 are being determined for each 12-month
period


                                       51
<PAGE>

LG&E Energy: (cont.):

beginning November 1 and ending October 31. During the first two years of the
mechanism ended October 31, 1999 and 1998, LG&E recorded $2.2 million and $3.5
million, respectively, for its share of reduced gas costs. These amounts are
billed to customers through the gas supply clause.

Prior to implementation of the PBR in July 1999, and following its termination
in March 2000, LG&E and 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 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 the
utilities' method of computing fuel costs associated with electric line losses
on off-system sales appropriate for recovery through the FAC. LG&E requested
that the Kentucky Commission grant rehearing on the February orders, and further
requested that the Kentucky Commission stay the refund requirement until it
could rule on the rehearing request. The Kentucky Commission granted the request
for a stay, and in March 1999 granted rehearing on the appropriate line loss
factor associated with off-system sales for the 18-month period ended April
1998. The Kentucky Commission also granted rehearing on the KIUC's request for
rehearing on the Kentucky Commission's determination that it lacked authority to
require the utilities to pay interest on the refund amounts. The Kentucky
Commission conducted a hearing on the rehearing issues and issued a final ruling
in December 1999. The Kentucky Commission agreed with LG&E 's position on the
appropriate loss factor to use in the FAC computation and reduced the refund
level for the 18-month period under review to approximately $800,000. LG&E
implemented the refund with billings beginning in the month of January 2000.
LG&E and KIUC have each filed separate appeals from the Kentucky Commission's
February 1999 orders with the Franklin Circuit Court. A decision on the appeals
by the Court is expected in 2000.

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 off-system 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 $5.8 million from the original Order
amount of $10.1 million. In August 1999, LG&E and KU each recorded its estimated
share of anticipated FAC refunds of $8.7 million. KU began implementing the
refund in October and will continue the refund through September 2000. Both KU
and the KIUC have appealed the Order to the Franklin Circuit Court. A decision
is not expected on the appeal until later in 2000.

LG&E intends to file before the end of the first quarter an application with the
Kentucky Commission for authority to increase its natural gas rates in order to
recoup higher costs for providing natural gas distribution services. LG&E
expects implementation before the end of 2000.


                                       52
<PAGE>

LG&E Energy: (cont.):

Kentucky PSC 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, the Company, 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. Management does not expect the
ultimate resolution of this matter to have a material adverse effect on the
Company's financial position or results of operations.

Environmental Matters

The 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,
while KU met its Phase I SO2 requirements primarily through installation of a
scrubber on Ghent Unit 1. The Company's combined strategy for Phase II,
commencing 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. LG&E, KU, and WKE met the NOx emission
requirements of the Act through installation of low-NOx burner systems. The
Company'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. The Company 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
significant additional reductions in NOx emissions by May 2003, in order to
mitigate alleged ozone transport to the Northeast. While each of the 22 states
covered by the rule is free to allocate its assigned NOx reductions among
various emissions sectors as it deems appropriate, the regulation may ultimately
require electric generating units to reduce their NOx emissions to 0.15
lb./Mmbtu - an 85% reduction from 1990 levels. In related proceedings in
response to petitions filed by various Northeast states, in December 1999, EPA
issued a final rule directing similar NOx reductions from a number of
specifically named electric generating units including all LG&E and KU stations
in the eastern half of Kentucky. Additional petitions currently pending before
EPA may potentially result in orders encompassing the remaining KU and WKE
stations. Several states, various labor and industry groups, and individual
companies have appealed both EPA rulings to the U.S. Court of Appeals for the
Washington D.C. Circuit. Management is currently unable to determine the outcome
or exact impact of this matter until such time as the courts rule on the pending
legal challenges and the states implement the final regulatory mandate. However,
if the 0.15 lb. target is ultimately imposed, LG&E, KU, and WKE and the
independent power projects in which the Company has an interest will be required
to incur significant capital expenditures and increased operation and
maintenance costs for additional controls.

Subject to further study, analysis, and the outcome of pending litigation
against the EPA, the Company estimates that it may incur approximate capital
costs for NOx compliance ranging from $300 million to reduce emissions to the
level of .25 lb./Mmbtu (Commonwealth of Kentucky's proposed NOx compliance
level) to $550 million to reduce emissions to the level of .15 lb./Mmbtu
(current EPA regulations). These costs would


                                       53
<PAGE>

LG&E Energy: (cont.):

generally be incurred beginning in 2000. The Company believes its costs in this
regard to be comparable to those of similarly situated utilities with like
generation assets. LG&E and KU anticipate that such capital and operating costs
are the type of costs that are eligible for recovery from customers under their
environmental surcharge mechanisms and believe that a significant portion of
such costs could be recovered. However, Kentucky Commission approval is
necessary and there can be no guarantee of recovery.

The Company is also addressing other air quality issues. First, the Company 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. The Company continues to monitor
EPA actions to challenge that ruling. Second, the Company was notified by
regulatory agencies that the Cane Run Station may be the source of a potential
exceedance of the NAAQS that could require the Company to incur additional
capital expenditures or accept certain emissions limitations. After reviewing
additional modeling information submitted by the Company, in January 2000, EPA
concluded that the Cane Run Station does not contribute to any potential NAAQS
exceedance and that no further action is required from the Company. Third, the
Company is working with regulatory authorities to review the effectiveness of
remedial measures aimed at controlling particulate emissions from its Mill Creek
Station. The Company previously settled a number of property damage claims from
adjacent residents and completed significant plant modifications as part of its
ongoing capital construction program.

The Company 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. The Company has
completed the cleanup of a site owned by KU and reached agreements for other
parties to assume cleanup responsibility for two other sites formerly owned by
LG&E. In addition, the Company recently reached an agreement with the Kentucky
Division of Waste Management with respect to a third LG&E-owned site in which
the Company committed to impose certain property restrictions and conduct
additional monitoring in lieu of a cleanup. Based on currently available
information, management estimates that it will incur additional MGP costs of
less than $500,000. Accordingly, an accrual of $500,000 has been recorded in the
accompanying financial statements. With respect to other former MGP sites no
longer owned by the Company, the Company is unable to determine what, if any,
additional exposure or liability it may have as it lacks complete information on
current site conditions.

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, the Company commenced immediate spill
containment and recovery measures which prevented the spill from reaching the
Kentucky River. The Company 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. The Company is currently negotiating with the state
in an effort to reach a complete resolution of this matter. To date the Company
has incurred costs of approximately $1 million. The Company does not expect to
incur any material additional amounts.

See Note 18 of LG&E Energy's Notes to Financial Statements under Item 8 for an
additional discussion of the Company's environmental issues.

Public Utilities Regulatory Policies Act

Proposals have been introduced in Congress to repeal all or portions of the
PURPA. PURPA and its implementing regulations require, among other things, that
electric utilities purchase electricity generated by qualifying cogeneration
facilities at a price based on the purchasing utility's avoided costs. The
Company is the partial owner and contractual operator of several qualifying
cogeneration facilities. While the Company


                                       54
<PAGE>

LG&E Energy: (cont.):

supports the repeal of PURPA, the Company intends to oppose any efforts to
nullify existing contracts between electric utilities and qualifying
cogeneration facilities. The Company has been involved in proceedings before
FERC regarding its Southampton cogeneration facility and is in litigation with
the purchasing utility of the energy from its Roanoke Valley I cogeneration
facility. See Note 18 of LG&E Energy's Notes to Financial Statements under Item
8.

IMPACT OF NON-UTILITY BUSINESSES

The Company expects to continue investing in non-utility projects, including
domestic and international power production, gas distribution projects and other
energy-related businesses, as described in the sections titled LG&E Capital
Corp. and Other Results, and Future Capital Requirements. The non-utility
projects in which the Company has invested carry a higher level of risk than
LG&E's or KU's traditional utility businesses. Current investments in
non-utility projects are subject to competition, operating risks, dependence on
certain suppliers and customers, environmental and energy regulations, as well
as political and currency risks. In addition, significant expenses may be
incurred for projects pursued by the Company that do not materialize. The
aggregate effect of these factors creates the potential for more volatility in
the non-utility component of the Company's earnings. Also, the Company may seek
opportunities to divest certain of its existing non-utility assets under
suitable market conditions. Accordingly, the historical operating results of the
Company's non-utility businesses may not necessarily be indicative of future
operating results.

FUTURE OUTLOOK

Competition and Customer Choice

LG&E Energy 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, the Company has taken many
steps to prepare for the expected increase in competition in its regulated and
non-utility energy services businesses, 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. The Company 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 Energy 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
Energy 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 conducted 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.


                                       55
<PAGE>

LG&E Energy: (cont.):

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 the Company, which may be significant, cannot currently be predicted.

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 1999, 1998, and 1997 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 Louisville Gas and
Electric Company's reports to the Securities and Exchange Commission, and
Exhibit No. 99.01 to LG&E Energy's annual report on Form 10-K for the year ended
December 31, 1998.

MERGER

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 $28.2 million for 1999, as 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.

Net income decreased $35.2 million for 1998, as compared to 1997, primarily due
to non-recurring charges for merger-related expenses and the ECR refund of $23.6
million and $2.7 million, after tax, respectively. Excluding these non-recurring
charges, net income decreased $8.9 million. This decrease is mainly due to
higher operating expenses at the electric generating stations and lower gas
sales, partially offset by increased electric sales.

Revenues

A comparison of operating revenues for the years 1999 and 1998, excluding the
provisions recorded for refunds


                                       56
<PAGE>

LG&E: (cont.):

in 1999 and in 1998, with the immediately preceding year reflects both increases
and decreases, which have been segregated by the following principal causes (in
thousands of $):

<TABLE>
<CAPTION>
                                                Increase (Decrease) From Prior Period
                                            Electric Revenues           Gas Revenues
Cause                                          1999         1998         1999         1998
                                               ----         ----         ----         ----
<S>                                       <C>          <C>          <C>          <C>
Retail sales:
  Fuel and gas supply adjustments, etc    $  (2,014)   $   3,750    $ (24,791)   $  (4,393)
  Merger surcredit                           (4,194)      (3,466)          --           --
  Performance based rate reduction           (6,076)          --           --           --
  Demand side management/decoupling          (2,985)      (6,299)      (6,462)        (369)
  Environmental cost recovery surcharge        (570)        (260)          --           --
  Variation in sales volumes                 22,009       27,051       17,779      (42,418)
                                          ---------    ---------    ---------    ---------
     Total retail sales                       6,170       20,776      (13,474)     (47,180)
Wholesale sales                             121,996       28,398         (602)       8,720
Gas transportation-net                           --           --         (575)         (71)
Other                                         1,228         (695)         685         (935)
                                          ---------    ---------    ---------    ---------
  Total                                   $ 129,394    $  48,479    $ (13,966)   $ (39,466)
                                          =========    =========    =========    =========
</TABLE>

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.

Electric retail sales increased primarily due to the warmer weather in 1998 as
compared to 1997. Wholesale sales increased due to larger amounts of power
available for off-system sales, an increase in the unit price of the sales and
sales to KU of $11.6 million due to economic dispatch following the merger in
May 1998 of LG&E Energy and KU Energy. Gas retail sales decreased from 1997 due
to the warmer weather in 1998. Gas wholesale sales increased to $8.7 million in
1998 from zero in 1997 due to the implementation of LG&E's gas performance-based
ratemaking mechanism. See Note 3 of LG&E's Notes to Financial Statements under
Item 8.

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 base rates, subject to approval by the Kentucky
Commission. In July 1999, the Kentucky Commission approved LG&E's filing on PBR
resulting in the discontinuance of the FAC.
In January 2000, the Kentucky Commission rescinded its approval of LG&E's PBR
filing 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 $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). Fuel expenses
incurred in 1998 increased $5.2 million (3.5%) because of higher cost of coal
burned ($6.6 million), partially offset by a decrease in generation ($1.4
million). The average delivered cost per ton of coal purchased was $21.49 in
1999, $22.38 in 1998, and $21.66 in 1997.


                                       57
<PAGE>

LG&E: (cont.):

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. Power purchased increased $32.9 million (191%) in
1998 to support the increase in wholesale sales and increased purchases from KU
of $16 million as a result of economic dispatch following the merger of the two
companies in May 1998.

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).
Gas supply expenses decreased $33 million (21%) in 1998 primarily due to a
decrease in the volume of gas delivered to the distribution system. The average
unit cost per Mcf of purchased gas was $2.99 in 1999, $3.05 in 1998 and $3.46 in
1997.

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). Operation expenses increased $12.8
million (8.5%) in 1998 over 1997 because of increased costs to operate electric
generating plants ($6.6 million), amortization of deferred merger costs ($1.8
million), and an increase in storm damage expenses ($1.4 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). In 1998 maintenance expenses increased $5.2 million (10.9%) as
compared to 1997 primarily because of an increase in scheduled outages and
general repairs at the electric generating plants ($2.2 million) and an increase
in storm damage expenses ($1.4 million).

Depreciation and amortization increased $4 million (4.3%) in 1999 over 1998 due
to additional utility plant in service. Depreciation and amortization for 1998
were approximately the same as in 1997.

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

Interest charges for 1999 increased $1.6 million (4.5%) due to short term
borrowings and interest on debt to associated companies ($2.5 million),
partially offset by lower interest rates on variable rate debt ($.6 million).
Interest charges for 1998 decreased $2.9 million (7.3%) due to the retirement of
LG&E's 6.75% Series First Mortgage Bonds and lower variable interest rates. The
embedded cost of long-term debt was 5.46% at December 31, 1999, and 5.57% at
December 31, 1998. 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.

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.


                                       58
<PAGE>

LG&E: (cont.):

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 $180.5 million, $225.7 million and $185.0
million in 1999, 1998 and 1997, respectively. 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. The
1998 increase was primarily due to an increase in current assets, including
increases 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 $195 million, $138 million and
$111 million in 1999, 1998 and 1997, respectively. LG&E expects its capital
expenditures for 2000 and 2001 will total approximately $401 million which
consists primarily of construction estimates associated with installation of low
nitrogen oxide burner systems as described in the section titled "Environmental
Matters."

Net cash used for investment activities increased by $47.2 million in 1999
compared to 1998 and increased $10 million in 1998 compared to 1997 primarily
due to increased construction expenditures in both periods.

Financing Activities

Cash inflow from financing activities in 1999 was $26.7 million and cash
outflows for 1998 and 1997 were $107.6 million and $64.5 million, respectively.
In 1999, total debt increased by $120.1 million to $746.9 million at December
31, 1999. The increase was primarily due to funding operating expenses and
construction expenditures.

As of December 1999, LG&E had committed credit facility aggregating $200.0
million with various banks. Unused capacity under these lines were approximately
$90 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 utility 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 to fund its requirements through additional
operating cash flow, debt or an issuance of preferred cstock.


                                       59
<PAGE>

LG&E: (cont.):

LG&E's debt ratings as of February 16, 2000, were:

                                   Moody's              S&P              D&P
                                   -------              ---              ---

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

The ratings stated above reflect the downgrades received following an order from
the Kentucky Commission to reduce base rates at LG&E by $27.2 million. As of
March 21, 2000, Moody's, S&P and D&P had LG&E on Credit Watch with negative
implications. Based upon the downgrades received LG&E's cost of funds could
increase by .05% to .12% on short-term borrowings and .10% on new long-term
borrowings. These ratings reflect the views of Moody's, S&P and D&P. A security
rating is not a recommendation to buy, sell or hold securities and is subject to
revision or withdrawal at any time by the rating agency.

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
has entered into various derivative instruments. 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, 1999, the potential change in interest expense associated with a 1%
change in base interest rates of LG&E's unswapped debt is estimated at $1.0
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, 1999, LG&E had swaps with a combined notional value of $151
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, 1999, 61% 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 $2.1 million as of
December 31, 1999. Changes in the market value of these swaps if held to
maturity, as LG&E intends to do, will have no effect on LG&E's net income or
cash flow. See Note 4 of LG&E's Notes to Financial Statements under Item 8.

Commodity Price Sensitivity

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


                                       60
<PAGE>

LG&E: (cont.):

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 1999, 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 states 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 May 1995, LG&E implemented an ECR surcharge. The Kentucky Commission's order
approving the surcharge as well as the constitutionality of the surcharge was
challenged by certain intervenors in Franklin Circuit Court. Decisions of the
Circuit Court and the Kentucky Court of Appeals in July 1995 and December 1997,
respectively, upheld the constitutionality of the ECR statute but differed on a
claim of retroactive recovery of certain amounts. Based on these decisions, the
Kentucky Commission ordered that certain surcharge revenues collected by LG&E be
subject to refund pending final determination of all appeals.

In December 1998, the Kentucky Supreme Court rendered an opinion upholding the
constitutionality of the surcharge statute but denied recovery of costs
associated with pre-1993 environmental projects through the ECR. The court
remanded the case to the Kentucky Commission to determine amounts to be refunded
for revenues collected for such pre-1993 environmental projects. Accordingly,
LG&E recorded a provision for rate refunds of $4.5 million in December 1998.

The parties to the proceedings reached a settlement agreement that was approved
in a Final Order issued by the Kentucky Commission in August 1999. This Final
Order resulted in the additional accrual of approximately $0.6 million to what
had been recorded in December 1998. The refund is being applied to customers'
bills during the twelve-month period beginning October 1999.


                                       61
<PAGE>

LG&E: (cont.):

Future Rate Regulation

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 amended filing
included requested Kentucky Commission approval of a five-year rate reduction
plan which proposed to reduce the electric rates of LG&E by $9.4 million in the
first year (beginning July 1999), and by $3.8 million annually through June
2004. The proposed amended plan also included establishment of a $2.8 million
program for low-income customer assistance as well as extension for one
additional year of both the rate cap proposal and merger savings surcredit
established in the original merger plan of LG&E and KU. Under the rate cap
proposal, LG&E agreed, in the absence of extraordinary circumstances, not to
increase base electric rates for five years following the merger and LG&E also
agreed to refrain from filing for an increase in natural gas rates through June
2004.

In April 1999, 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. Legal briefs of the parties
were filed with the Kentucky Commission in October 1999. KIUC's position called
for annual revenue reductions for LG&E of $69.6 million.

In January 2000, the Kentucky Commission issued Orders for LG&E in the subject
cases. The Kentucky Commission ruled 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 fuel adjustment clause 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 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. LG&E also filed motions for reconsideration with the Kentucky
Commission on a number of items in the case in late January. Certain intervening
parties in the proceedings have also filed motions for reconsideration
asserting, among other things, that the Kentucky Commission understated the
amount of base rate reductions. 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. Management cannot predict final
outcome of these matters before the Kentucky Commission or the timing in which
resolution of these matters will ultimately be reached.


                                       62
<PAGE>

LG&E: (cont.):

Other Rate Matters

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 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.

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. During the first two years of
the mechanism ended October 31, 1999 and 1998, LG&E recorded $2.2 million and
$3.5 million, respectively, for its share of reduced gas costs. These amounts
are billed to customers through the gas supply clause.

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 off-system sales
appropriate for recovery through the FAC. LG&E requested that the Kentucky
Commission grant rehearing on the February orders, and further requested that
the Kentucky Commission stay the refund requirement until it could rule on the
rehearing request. The Kentucky Commission granted the request for a stay, and
in March 1999 granted rehearing on the appropriate line loss factor associated
with off-system sales for the 18-month period ended April 1998. The Kentucky
Commission also granted rehearing on the KIUC's request for rehearing on the
Kentucky Commission's determination that it lacked authority to require the
utilities to pay interest on the refund amounts. The Kentucky Commission
conducted a hearing on the rehearing issues and issued a final ruling in
December 1999. The Kentucky Commission agreed with LG&E 's position on the
appropriate loss factor to use in the FAC computation and reduced 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
have each filed separate appeals from the Kentucky Commission's February 1999
orders with the Franklin Circuit Court. A decision on the appeals by the Court
is expected in 2000.

LG&E intends to file before the end of the first quarter an application with the
Kentucky Commission for authority to increase its natural gas rates in order to
recoup higher costs for providing natural gas distribution services. LG&E
expects implementation before the end of 2000.

Kentucky PSC 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


                                       63
<PAGE>

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. Management does not expect the ultimate resolution of this matter to
have a material adverse effect on LG&E's financial position or results of
operations.

Environmental Matters

The 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, commencing 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. 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
significant additional reductions in NOx emissions by May 2003, in order to
mitigate alleged ozone transport to the Northeast. While each of the 22 states
covered by the rule is free to allocate its assigned NOx reductions among
various emissions sectors as it deems appropriate, the regulation may ultimately
require electric generating units to reduce their NOx emissions to 0.15
lb./Mmbtu - an 85% reduction from 1990 levels. In related proceedings in
response to petitions filed by various Northeast states, in December 1999, EPA
issued a final rule directing similar NOx reductions from a number of
specifically named electric generating units including all LG&E stations.
Several states, various labor and industry groups, and individual companies have
appealed both EPA rulings to the U.S. Court of Appeals for the Washington D.C.
Circuit. Management is currently unable to determine the outcome or exact impact
of this matter until such time as the courts rule on the pending legal
challenges and the states implement the final regulatory mandate. However, if
the 0.15 lb. target is ultimately imposed, LG&E will be required to incur
significant capital expenditures and increased operation and maintenance costs
for additional controls.

Subject to further study, analysis, and the outcome of pending litigation
against the EPA, LG&E estimates that it may incur approximate capital costs for
NOx compliance ranging from $65 million to reduce emissions to the level of .25
lb./Mmbtu (Commonwealth of Kentucky's proposed NOx compliance level) to $165
million to reduce emissions to the level of .15 lb./Mmbtu (current EPA
regulations). These costs would generally be incurred beginning in 2000. 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 their environmental surcharge mechanisms and believe 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 addressing other air quality issues. First, LG&E 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. LG&E continues to monitor EPA actions to
challenge that ruling. Second, LG&E was notified by regulatory agencies that the
Cane Run Station may be the source of a potential exceedance of the NAAQS that
could require LG&E to incur additional capital expenditures or accept certain
emissions limitations. After reviewing additional modeling information submitted
by


                                       64
<PAGE>

LG&E: (cont.):

LG&E, in January 2000, EPA concluded that the Cane Run Station does not
contribute to any potential NAAQS exceedance and that no further action is
required from LG&E. Third, LG&E is working with regulatory authorities to review
the effectiveness of remedial measures aimed at controlling particulate
emissions from its Mill Creek Station. LG&E previously settled a number of
property damage claims from adjacent residents and completed significant plant
modifications as part of its ongoing capital construction program.

LG&E owns or formerly owned three properties which contained past MGP
operations. Various contaminants are typically found at such former MGP sites
and environmental remediation measures are frequently required. LG&E has reached
agreements for other parties to assume cleanup responsibility for two other
sites it formerly owned. In addition, LG&E recently reached an agreement with
the Kentucky Division of Waste Management with respect to a third LG&E-owned
site in which LG&E committed to impose certain property restrictions and conduct
additional monitoring in lieu of a cleanup. Based on currently available
information, management estimates that it will incur additional MGP costs of
less than $500,000. Accordingly, an accrual of $500,000 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.

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


                                       65
<PAGE>

LG&E: (cont.):

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.

KU

GENERAL

The following discussion and analysis by management focuses on those factors
that had a material effect on KU's financial results of operations and financial
condition during 1999, 1998, and 1997 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, and Exhibit No. 99.01 to LG&E Energy's
annual report on Form 10-K for the year ended December 31, 1998.

MERGER

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 increased $33.8 million for 1999, as compared to 1998, primarily
due to non-recurring charges in 1998 for merger-related expenses and
environmental cost recovery 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
results, and lower operation and maintenance costs, offset by higher purchased
power expenses for the year.

KU's net income decreased $12.9 million for 1998 as compared to 1997, primarily
due to non-recurring charges for merger-related expenses and environmental cost
recovery refund of $21.5 million and $12.9 million, after tax, respectively.
Excluding these non-recurring charges, net income increased $21.5 million. The
increase is mainly due to higher residential sales, commercial sales, industrial
sales and sales for resale caused by the warmer weather and increased marketing
efforts.

Revenues

A comparison of operating revenues for the years 1999 and 1998, 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


                                       66
<PAGE>

KU (cont.):

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                                                         1999         1998
                                                              ----         ----

Retail sales:
  Fuel clause adjustments, etc                           $  (1,744)   $   1,158
  Merger surcredit                                          (4,123)      (4,035)
  Environmental cost recovery surcharge                     (1,977)        (547)
  Performance based rate reduction                          (5,558)          --
  Variation in sales volumes                                19,303       25,841
                                                         ---------    ---------
     Total retail sales                                      5,901       22,417
Wholesale sales                                            106,160       90,253
Other                                                         (465)       2,507
                                                         ---------    ---------
  Total                                                  $ 111,596    $ 115,177
                                                         =========    =========

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

Retail sales increased in 1998 due to increases in residential and commercial
sales primarily attributable to warmer weather experienced in the second and
third quarters. The increase in sales for resale was primarily due to more
aggressive marketing efforts, increases in the unit price of the sales,
efficiencies achieved from coordinated dispatch of a larger available pool of
generation following completion of the merger, and sales to LG&E of $16 million
due to economic dispatch following the merger in May 1998 of LG&E Energy and KU
Energy.

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 retail rates, 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 its approval of KU's PBR filing 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 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). Fuel for electric generation increased $29
million (13%) in 1998 because of an increase in generation ($26.2 million) and
an increase in the cost of coal burned ($2.8 million). KU's average delivered
cost per ton of coal purchased was $26.65 in 1999, $26.97 in 1998 and $27.97 in
1997.


                                       67
<PAGE>

KU (cont.):

Power purchased increased $115.7 million in 1999 primarily to support the
aforementioned sales for resale. Power purchased expense increased $54 million
(75%) in 1998 because of a 67% increase in megawatt-hour purchases which was
primarily attributable to increased marketing efforts and purchases from LG&E of
$11.6 million as a result of economic dispatch following the merger of the two
companies in May 1998.

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. Maintenance for 1998 was flat as compared to 1997.

Depreciation and amortization increased $3.3 million (3.8%) in 1999 and $2.5
million (1.5%) in 1998 because of additional utility plant in service in both
years.

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 and (deductions) 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 7.00% at December 31, 1999, and 6.99%
at December 31, 1998. 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 utility 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 $204.2 million, $239.4 million and $178.9
million in 1999, 1998 and 1997, respectively. The 1999 decrease of resulted from
an increase in net income and a net decrease in net current assets, including
decreases in accounts receivable, accounts payable, accrued taxes and provision
for rate refunds. The 1998 increase was primarily due to an increase in current
assets, including increases in accounts payable, accrued taxes and provision for
rate refunds, partially offset by an increase in accounts receivable.

Investing Activities

KU's primary use of funds continues to be for capital expenditures and the
payment of dividends. Capital expenditures were $181 million, $92 million and
$94 million in 1999, 1998 and 1997, respectively. The $89 million increase in
1999 capital expenditures was primarily due to the purchase of a 62% interest in
the two combustion turbines. KU expects its capital expenditures for 2000 and
2001 will total approximately $324 million which consists primarily of
construction costs associated with installation of low nitrogen oxide burner
systems as described in the section titled "Environmental Matters."


                                       68
<PAGE>

KU (cont.):

Net cash used for investment activities increased by $89.3 million in 1999
compared to 1998 and increased $2.1 million in 1998 compared to 1997 primarily
due to increased construction expenditures in both periods.

Future Capital Requirements

Future utility 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 to fund its requirements through additional
operating cash flow, debt or an issuance of preferred stock.

Financing Activities

Cash outflows from financing activities were $75.2 million, $94.0 million and
$89.4 million, in 1999, 1998 and 1997, respectively. In 1999, there was no
increase in total debt, balance as of December 31, 1999 remained $546.3 million.

KU's debt ratings as of February 16, 2000, were:

                                  Moody's              S&P              D&P
                                  -------              ---              ---

         First mortgage bonds        A1                A+               AA-
         Preferred stock             a2                BBB+             A
         Commercial paper            P-1               A-1              D-1

The ratings stated above reflect the downgrades received following the
PBR-related order from the Kentucky Commission to reduce base rates at KU by
$36.5 million. As of March 21, 2000, Moody's, S&P and D&P had KU on Credit Watch
with negative implications. Based upon the downgrades received KU's cost of
funds could increase by .05% to .12% on short-term borrowings and .10% on new
long-term borrowings. These ratings reflect the views of Moody's, S&P and D&P. A
security rating is not a recommendation to buy, sell or hold securities and is
subject to revision or withdrawal at any time by the rating agency.

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
has entered into various derivative instruments. Derivative positions are
monitored using techniques that include market value and sensitivity analysis.

Interest Rate Sensitivity

KU has long-term variable rate debt obligations outstanding. At December 31,
1999, the potential change in interest expense associated with a 1% change in
base interest rates of KU's unswapped debt is estimated at $1.0 million. These
swaps hedge specific debt issuance and consistent with management's designation
are accorded hedge accounting treatment.

As of December 31, 1999, KU has a swap with a notional value of $53 million. The
swaps exchange fixed-rate interest payments for floating interest payments on
KU's 7.92% Series P Pollution Control Bond. The potential loss in fair value
from these positions resulting from a hypothetical 1% adverse movement in base
interest rates


                                       69
<PAGE>

KU (cont.):

is estimated at $3.7 million as of December 31, 1999. 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 1999, KU incurred approximately $5.1
million in capital and operating costs in connection with the Year 2000 issue.

RATES AND REGULATION

KU is subject to the jurisdiction of the Kentucky Commission, the Virginia
Commission and FERC in virtually all matters related to electric utility
regulation, and as such, its accounting is subject to SFAS No. 71, Accounting
for the Effects of Certain Types of Regulation. Given KU's competitive position
in the market and the status of regulation in the states of Kentucky and
Virginia, KU no plans or intentions to discontinue its application of SFAS No.
71. See Note 6 of LG&E Energy's Notes to Financial Statements under Item 8.

Environmental Cost Recovery

In August 1994, KU implemented an ECR surcharge. The Kentucky Commission's order
approving the surcharge as well as the constitutionality of the surcharge was
challenged by certain intervenors in Franklin Circuit Court. Decisions of the
Circuit Court and the Kentucky Court of Appeals in July 1995 and December 1997,
respectively, upheld the constitutionality of the ECR statute but differed on a
claim of retroactive recovery of certain amounts. Based on these decisions, the
Kentucky Commission ordered that certain surcharge revenues collected by KU be
subject to refund pending final determination of all appeals.

In December 1998, the Kentucky Supreme Court rendered an opinion upholding the
constitutionality of the surcharge statute but denied recovery of costs
associated with pre-1993 environmental projects through the ECR. The court
remanded the case to the Kentucky Commission to determine amounts to be refunded
for revenues collected for such pre-1993 environmental projects. Accordingly, KU
recorded a provision for rate


                                       70
<PAGE>

KU (cont.):

refund of $21.5 million in December 1998.

The parties to the proceedings reached a settlement agreement that was approved
in a Final Order issued by the Kentucky Commission in August 1999. This Final
Order resulted in a reduction of approximately $1.5 million to the accrual that
had been recorded in December 1998. The refund is being applied to customers'
bills during the twelve-month period beginning October 1999.

Future Rate Regulation

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 amended filing
included requested Kentucky Commission approval of a five-year rate reduction
plan which proposed to reduce the electric rates of KU by $10.6 million in the
first year (beginning July 1999), and by $4.2 million annually through June
2004. The proposed amended plan also included establishment of a $3.2 million
program for low-income customer assistance as well as extension for one
additional year of both the rate cap proposal and merger savings surcredit
established in the original merger plan of LG&E Energy and KU Energy. Under the
rate cap proposal, KU agreed, in the absence of extraordinary circumstances, not
to increase base electric rates for five years following the merger through June
2004.

In April 1999, 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. Legal briefs of the parties
were filed with the Kentucky Commission in October 1999. KIUC's position called
for annual revenue reductions for KU of $61.5 million.

In January 2000, the Kentucky Commission issued Orders for KU in the subject
cases. The Kentucky Commission ruled 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
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. KU also filed motions for reconsideration with the Kentucky Commission
on a number of items in the case in late January. Certain intervening parties in
the proceedings have also filed motions for reconsideration asserting, among
other things, that the Kentucky Commission understated the amount of base


                                       71
<PAGE>

KU (cont.):

rate reductions. 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. Management cannot predict final outcome of these
matters before the Kentucky Commission or the timing in which resolution of
these matters will ultimately be reached.

Other Rate Matters

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 off-system 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 $5.8 million from the original Order
amount of $10.1 million. In August 1999, KU recorded its estimated share of
anticipated FAC refunds of $7.7 million. KU began implementing the refund in
October and will continue the refund through September 2000. Both KU and the
KIUC have appealed the Order to the Franklin Circuit Court. A decision is not
expected on the appeal until later in 2000.

Kentucky PSC 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. Management does not expect the ultimate
resolution of this matter to have a material adverse effect on KU's financial
position or results of operations.


                                       72
<PAGE>

KU (cont.):

Environmental Matters

The 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, commencing 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
significant additional reductions in NOx emissions by May 2003, in order to
mitigate alleged ozone transport to the Northeast. While each of the 22 states
covered by the rule is free to allocate its assigned NOx reductions among
various emissions sectors as it deems appropriate, the regulation may ultimately
require electric generating units to reduce their NOx emissions to 0.15
lb./Mmbtu - an 85% reduction from 1990 levels. In related proceedings in
response to petitions filed by various Northeast states, in December 1999, EPA
issued a final rule directing similar NOx reductions from a number of
specifically named electric generating units including all KU stations in the
eastern half of Kentucky. Several states, various labor and industry groups, and
individual companies have appealed both EPA rulings to the U.S. Court of Appeals
for the Washington D.C. Circuit. Management is currently unable to determine the
outcome or exact impact of this matter until such time as the courts rule on the
pending legal challenges and the states implement the final regulatory mandate.
However, if the 0.15 lb. target is ultimately imposed, KU will be required to
incur significant capital expenditures and increased operation and maintenance
costs for additional controls.

Subject to further study, analysis, and the outcome of pending litigation
against the EPA, KU estimates that it may incur capital costs for NOx compliance
ranging from $126 million to reduce emissions to the level of .25 lb./Mmbtu
(Commonwealth of Kentucky's proposed NOx compliance level) to $168 million to
reduce emissions to the level of .15 lb./Mmbtu (current EPA regulations). These
costs would generally be incurred beginning in 2000. 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 mechanisms and believe 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 unable to determine what, if any, additional exposure
or liability it may have as it lacks complete information on current site
conditions.

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. To date KU has incurred costs of
approximately $1 million.


                                       73
<PAGE>

KU (cont.):

The Company does not expect to incur any material additional amounts.

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

LG&E Energy 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 Energy 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. LG&E Energy 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 Energy 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
Energy 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.

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.

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

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


                                       74
<PAGE>

ITEM 8. Financial Statements and Supplementary Data.

                       LG&E Energy Corp. and Subsidiaries
                        Consolidated Statements of Income
                     (Thousands of $ Except Per Share Data)
<TABLE>
<CAPTION>
                                                                        Years Ended December 31
                                                                      1999           1998           1997
                                                                      ----           ----           ----
<S>                                                            <C>            <C>            <C>
REVENUES:
    Electric utility (Note 1) ..............................   $ 1,693,033    $ 1,464,824    $ 1,331,569
    Gas utility (Note 1) ...................................       177,579        191,545        231,011
    International and non-utility ..........................       844,299        455,877        270,166
    Provision for rate refunds (Note 6) ....................        (7,635)       (26,000)            --
                                                               -----------    -----------    -----------
       Net revenues ........................................     2,707,276      2,086,246      1,832,746
                                                               -----------    -----------    -----------

OPERATING EXPENSES:
Operation and maintenance:
    Fuel and power purchased ...............................     1,101,054        640,438        442,949
    Gas supply expenses ....................................       330,172        294,880        314,425
    Utility operation and maintenance ......................       418,510        432,763        415,882
    International and non-utility operation and maintenance        193,344        138,952         67,565
Depreciation and amortization ..............................       219,318        206,450        193,891
Merger costs (Note 2) ......................................            --         65,318             --
                                                               -----------    -----------    -----------
       Total operating expenses ............................     2,262,398      1,778,801      1,434,712
                                                               -----------    -----------    -----------

Equity in earnings of unconsolidated ventures (Note 9) .....        49,717         73,798         22,937
                                                               -----------    -----------    -----------

OPERATING INCOME ...........................................       494,595        381,243        420,971

Other income and (deductions) (Note 14) ....................        19,305          8,100         21,683
Interest charges and preferred dividends ...................       132,066        109,389        104,427
Minority interest ..........................................        12,047         10,453          9,035
                                                               -----------    -----------    -----------

Income from continuing operations, before income taxes .....       369,787        269,501        329,192

Income taxes (Note 13) .....................................       133,524        110,829        120,829
                                                               -----------    -----------    -----------

Income from continuing operations ..........................       236,263        158,672        208,363

Loss from discontinued operations, net of income tax
    benefit of $15,008 and $16,622 (Notes 1, 3 and 4) ......            --        (22,852)       (25,367)

Loss on disposal of discontinued operations, net of income
    tax benefit of $104,716 and $123,905 (Notes 3 and 4) ...      (174,212)      (224,148)            --
                                                               -----------    -----------    -----------

Income (loss) before cumulative effect of change in
    accounting principle ...................................        62,051        (88,328)       182,996

Cumulative effect of change in accounting for start-up
    costs, net of income tax benefit of $5,061 (Note 1) ....            --         (7,162)            --
                                                               -----------    -----------    -----------

NET INCOME (LOSS) ..........................................   $    62,051    $   (95,490)   $   182,996
                                                               ===========    ===========    ===========
</TABLE>

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


                                       75
<PAGE>

                       LG&E Energy Corp. and Subsidiaries
                    Consolidated Statements of Income (cont.)
                     (Thousands of $ Except Per Share Data)

<TABLE>
<CAPTION>
                                                                Years Ended December 31
                                                              1999           1998           1997
                                                              ----           ----           ----
<S>                                                    <C>            <C>            <C>
Average common shares outstanding ..................       129,677        129,679        129,627

Earnings (loss) per share of common stock - basic:
Continuing operations ..............................   $      1.82    $      1.22    $      1.61
Loss from discontinued operations ..................            --           (.17)          (.20)
Loss on disposal of discontinued operations ........         (1.34)         (1.73)            --
Cumulative effect of accounting change .............            --           (.06)            --
                                                       -----------    -----------    -----------
Total ..............................................   $       .48    $      (.74)   $      1.41
                                                       ===========    ===========    ===========

Earnings (loss) per share of common stock - diluted:
Continuing operations ..............................   $      1.82    $      1.22    $      1.61
Loss from discontinued operations ..................            --           (.17)          (.20)
Loss on disposal of discontinued operations ........         (1.34)         (1.72)            --
Cumulative effect of accounting change .............            --           (.06)            --
                                                       -----------    -----------    -----------
Total ..............................................   $       .48    $      (.73)   $      1.41
                                                       ===========    ===========    ===========
</TABLE>

                 Consolidated Statements of Comprehensive Income
                                (Thousands of $)

<TABLE>
<CAPTION>
                                                                       Years Ended December 31
                                                                      1999         1998         1997
                                                                      ----         ----         ----
<S>                                                              <C>          <C>          <C>
Net income (loss) ............................................   $  62,051    $ (95,490)   $ 182,996

Unrealized holding losses on available-for-sale securities
    arising during the period ................................        (403)        (168)        (567)

Reclassification adjustment for realized gains and (losses) on
    available-for-sale securities included in net income .....        (294)         123          337
                                                                 ---------    ---------    ---------

Other comprehensive loss before tax ..........................        (697)         (45)        (230)

Income tax (expense) benefit related to items of other
    comprehensive income .....................................         264           (5)         293
                                                                 ---------    ---------    ---------

Comprehensive income (loss) ..................................   $  61,618    $ (95,540)   $ 183,059
                                                                 =========    =========    =========
</TABLE>

                  Consolidated Statements of Retained Earnings
                                (Thousands of $)

<TABLE>
<CAPTION>
                                                                        Years Ended December 31
                                                                       1999         1998         1997
                                                                       ----         ----         ----
<S>                                                               <C>          <C>          <C>
Balance January 1 .............................................   $ 466,279    $ 722,584    $ 683,962
Add net income (loss) .........................................      62,051      (95,490)     182,996
Deduct: Cash dividends declared on common stock
        ($1.250 per share in 1999, $1.240 per share in 1998,
        and $1.113 per share in 1997) .........................    (162,096)    (160,815)    (144,366)
        Other .................................................          --           --           (8)
                                                                  ---------    ---------    ---------

Balance December 31 ...........................................   $ 366,234    $ 466,279    $ 722,584
                                                                  =========    =========    =========
</TABLE>

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


                                       76
<PAGE>

                       LG&E Energy Corp. and Subsidiaries
                           Consolidated Balance Sheets
                                (Thousands of $)

<TABLE>
<CAPTION>
                                                                                    December 31
                                                                                     1999         1998
                                                                                     ----         ----
<S>                                                                            <C>          <C>
ASSETS:
Current assets:
    Cash and temporary cash investments ....................................   $   91,413   $  105,604
    Marketable securities (Note 11) ........................................       10,126       20,862
    Accounts receivable - less reserve of $8,285 in 1999 and $10,532 in 1998      318,914      293,340
    Materials and supplies - primarily at average cost:
       Fuel (predominantly coal) ...........................................       91,931       78,855
       Gas stored underground ..............................................       49,038       39,249
       Other ...............................................................       90,259       72,456
    Net assets of discontinued operations (Notes 1 and 3) ..................           --        3,219
    Prepayments and other ..................................................       54,038       33,449
                                                                               ----------   ----------
       Total current assets ................................................      705,719      647,034
                                                                               ----------   ----------

Utility plant:
    At original cost (Note 1) ..............................................    5,916,905    5,581,667
    Less:  reserve for depreciation ........................................    2,503,851    2,352,306
                                                                               ----------   ----------
       Net utility plant ...................................................    3,413,054    3,229,361
                                                                               ----------   ----------

Other property and investments - less reserve:
    Investments in unconsolidated ventures (Notes 9 and 10) ................      249,455      167,878
    Non-utility property and plant, net (Notes 1 and 2) ....................      477,442      447,372
    Other ..................................................................       25,596      117,321
                                                                               ----------   ----------
       Total other property and investments ................................      752,493      732,571
                                                                               ----------   ----------

Deferred debits and other assets:
    Regulatory assets (Note 6) .............................................       54,476       65,871
    Goodwill, net (Note 2) .................................................       74,398       36,906
    Other ..................................................................      133,617      111,375
                                                                               ----------   ----------
       Total deferred debits and other assets ..............................      262,491      214,152
                                                                               ----------   ----------
           Total assets ....................................................   $5,133,757   $4,823,118
                                                                               ==========   ==========

CAPITAL AND LIABILITIES:
Current liabilities:
    Current portion of long-term debt (Note 16) ............................   $  411,810   $       --
    Notes payable (Note 17) ................................................      449,578      365,135
    Accounts payable .......................................................      220,460      254,225
    Net liabilities of discontinued operations (Notes 1 and 3) .............      158,222           --
    Taxes and interest accrued .............................................       72,674      102,228
    Common dividends declared ..............................................       41,172       39,876
    Provision for rate refunds .............................................       29,529       34,761
    Customer deposits ......................................................       17,838       17,404
    Other ..................................................................       87,628       37,954
                                                                               ----------   ----------
       Total current liabilities ...........................................    1,488,911      851,583
                                                                               ----------   ----------

Long-term debt (Note 16) ...................................................    1,299,415    1,510,775

Deferred credits and other liabilities:
    Accumulated deferred income taxes (Notes 1 and 13) .....................      585,880      568,103
    Investment tax credit, in process of amortization ......................       85,828       93,844
    Accumulated provision for pensions and related benefit (Note 12) .......      101,090      120,233
    Regulatory liability (Note 6) ..........................................      104,795      110,081
    Other ..................................................................       81,267       82,916
                                                                               ----------   ----------
       Total deferred credits and other liabilities ........................      958,860      975,177
                                                                               ----------   ----------

Minority interest (Note 2) .................................................      109,952      107,815
Cumulative preferred stock .................................................      135,328      136,530
Commitments and contingencies (Note 18)
Common equity ..............................................................    1,141,291    1,241,238
                                                                               ----------   ----------

           Total capital and liabilities ...................................   $5,133,757   $4,823,118
                                                                               ==========   ==========
</TABLE>

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


                                       77
<PAGE>

                       LG&E Energy Corp. and Subsidiaries
                      Consolidated Statements of Cash Flows
                                (Thousands of $)

<TABLE>
<CAPTION>
                                                                        Years Ended December 31
                                                                      1999           1998           1997
                                                                      ----           ----           ----
<S>                                                            <C>            <C>            <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
    Net income (loss) ......................................   $    62,051    $   (95,490)   $   182,996
    Items not requiring cash currently:
       Depreciation and amortization .......................       219,318        206,450        193,891
       Deferred income taxes - net .........................        12,041        (30,924)        11,974
       Investment tax credit - net .........................        (8,016)        (8,087)        (8,276)
       Undistributed earnings of unconsolidated ventures ...       (21,651)       (18,833)        (2,326)
       Loss from discontinued operations (Notes 1 and 3) ...            --         22,852         25,367
       Loss on disposal of discontinued
           operations (Note 3) .............................       174,212        224,148             --
       Cumulative effect of change in accounting
           principle (Note 1) ..............................            --          7,162             --
       Other ...............................................        17,978         21,838         14,213
    Change in certain net current assets:
       Accounts receivable .................................        (1,204)       (36,331)       (22,371)
       Materials and supplies ..............................       (21,009)       (45,894)        (8,704)
       Net assets of discontinued operations (Notes 1 and 3)       (13,723)      (156,662)        (7,196)
       Provision for rate refunds ..........................        (5,232)        21,513         (4,263)
       Accounts payable ....................................       (41,550)       100,341         (2,400)
       Accrued taxes and interest ..........................       (28,912)        57,216          5,859
       Customer deposits ...................................           434          1,609          2,392
       Prepayments and other ...............................        (4,374)       (25,303)          (960)
    Other ..................................................         2,965        (35,978)       (46,458)
                                                               -----------    -----------    -----------
           Net cash flows from operating activities ........       343,328        209,627        333,738
                                                               -----------    -----------    -----------

CASH FLOWS FROM INVESTING ACTIVITIES:
    Purchases of securities ................................        (1,645)       (18,421)       (21,526)
    Proceeds from sales of securities ......................        11,747         19,995          5,030
    Construction expenditures ..............................      (382,631)      (343,628)      (225,714)
    Investment in subsidiaries net of cash and
       temporary cash investments acquired (Note 2) ........       (39,693)            --        (81,719)
    Investments in unconsolidated ventures (Notes 2 and 9) .       (85,768)        (1,010)       (48,665)
    Proceeds from sale of investment in affiliate
       and sale of leveraged leases (Notes 9 and 10) .......        55,569         16,000             --
                                                               -----------    -----------    -----------
           Net cash flows used for investing activities ....      (442,421)      (327,064)      (372,594)
                                                               -----------    -----------    -----------

CASH FLOWS FROM FINANCING ACTIVITIES:
    Issuance of medium-term notes (Notes 16 and 17) ........       200,020        300,000             --
    Issuance of long-term debt .............................            --             --         69,776
    Retirement of long-term debt (Notes 2 and 16) ..........       (35,288)       (20,042)       (71,714)
    Short-term borrowings ..................................     4,973,725      6,751,089      3,871,905
    Repayment of short-term borrowings .....................    (4,891,553)    (6,776,845)    (3,690,321)
    Issuance of preferred stock ............................            --             --          3,025
    Redemption of preferred stock ..........................        (1,202)        (1,823)            --
    Issuance of common stock ...............................            --             --          3,781
    Payment of common dividends ............................      (160,800)      (140,731)      (143,647)
                                                               -----------    -----------    -----------
           Net cash flows from financing activities ........        84,902        111,648         42,805
                                                               -----------    -----------    -----------

Change in cash and temporary cash investments ..............       (14,191)        (5,789)         3,949

Beginning cash and temporary cash investments ..............       105,604        111,393        107,444
                                                               -----------    -----------    -----------

Ending cash and temporary cash investments .................   $    91,413    $   105,604    $   111,393
                                                               ===========    ===========    ===========

Supplemental disclosures of cash flow information:
    Cash paid during the year for:
       Income taxes ........................................   $    29,968    $    55,513    $    82,662
       Interest on borrowed money ..........................       115,446         96,356         93,451
</TABLE>

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


                                       78
<PAGE>

                       LG&E Energy Corp. and Subsidiaries
                    Consolidated Statements of Capitalization
                                (Thousands of $)

<TABLE>
<CAPTION>
                                                                          December 31
                                                                            1999           1998
                                                                            ----           ----
<S>                                                                  <C>            <C>
COMMON EQUITY:
    Common stock, without par value -
       Authorized 300,000,000 shares, outstanding
       129,677,030 shares (Note 15) ..............................   $   777,013    $   776,328
    Common stock expense .........................................        (1,690)        (1,536)
    Unrealized gain (loss) on marketable securities, net of income
       taxes (benefit) of ($170) in 1999 and $94 in 1998 (Note 11)          (266)           167
    Retained earnings ............................................       366,234        466,279
                                                                     -----------    -----------
       Total common equity .......................................     1,141,291      1,241,238
                                                                     -----------    -----------
</TABLE>

CUMULATIVE PREFERRED STOCK (Note 15):

<TABLE>
<CAPTION>
                                                            Shares           Current
                                                         Outstanding   Redemption Price
                                                         -----------   ----------------

    Cumulative and redeemable on 30 days notice by Louisville Gas and Electric
       Company:
<S>                                                        <C>              <C>          <C>         <C>
    $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          104.70        25,000      25,000
    Preferred stock expense.........................................................      (1,179)     (1,179)
                                                                                         -------     -------
       Total LG&E cumulative preferred stock........................................      95,328      95,328
                                                                                         -------     -------

<CAPTION>
    Cumulative and redeemable on 30 days notice by Kentucky Utilities Company:

    Without par value, 5,300,000 shares authorized -
<S>                                                        <C>              <C>          <C>         <C>
       4.75% series, $100 stated value...............      200,000          $101.00       20,000      20,000
       6.53% series, $100 stated value...............      200,000      Not redeemable    20,000      20,000
                                                                                        --------     -------
           Total KU cumulative preferred stock......................................      40,000      40,000
                                                                                        --------     -------

    $10 nominal value, 102,089 shares authorized and outstanding,
       (net of shares owned by affiliates) variable rate and
       redeemable by Inversora de Gas del Centro (Note 15)..........................          --       1,202
                                                                                        --------     -------

    Total cumulative preferred stock................................................     135,328     136,530
                                                                                        --------     -------
</TABLE>

LONG-TERM DEBT (Note 16):

    Louisville Gas and Electric Company:

<TABLE>
<CAPTION>
    First mortgage bonds -
<S>                                                                                      <C>         <C>
       Series due July 1, 2002, 7.5%................................................      20,000      20,000
       Series due August 15, 2003, 6%...............................................      42,600      42,600
       Pollution control series:
           P due June 15, 2015, 7.45%...............................................      25,000      25,000
           Q due November 1, 2020, 7.625%...........................................      83,335      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, 5.625%............................................     102,000     102,000
           W due October 15, 2020, 5.45%............................................      26,000      26,000
           X due April 15, 2023, 5.90%..............................................      40,000      40,000
                                                                                        --------     -------
              Total first mortgage bonds............................................     506,800     506,800
                                                                                        --------     -------
</TABLE>

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


                                       79
<PAGE>

                       LG&E Energy Corp. and Subsidiaries
                Consolidated Statements of Capitalization (cont.)
                                (Thousands of $)

<TABLE>
<CAPTION>
                                                                                             December 31
                                                                                             1999           1998
                                                                                             ----           ----
<S>                                                                                   <C>            <C>
    Pollution control bonds (unsecured) -
       Jefferson County Series due September 1, 2026, variable......................       22,500         22,500
       Trimble County Series due September 1, 2026, variable........................       27,500         27,500
       Jefferson County Series due November 1, 2027, variable.......................       35,000         35,000
       Trimble County Series due November 1, 2027, variable.........................       35,000         35,000
                                                                                      -----------    -----------
           Total unsecured pollution control bonds..................................      120,000        120,000
                                                                                      -----------    -----------

              Total LG&E bonds outstanding..........................................      626,800        626,800
                                                                                      -----------    -----------

    Kentucky Utilities Company:

       Series Q, due June 15, 2000, 5.95%...........................................       61,500         61,500
       Series Q, due June 15, 2003, 6.32%...........................................       62,000         62,000
       Series S, due January 15, 2006, 5.99%........................................       36,000         36,000
       Series P, due May 15, 2007, 7.92%............................................       53,000         53,000
       Series R, due June 1, 2025, 7.55%............................................       50,000         50,000
       Series P, due May 15, 2027, 8.55%............................................       33,000         33,000
       Pollution Control Series:
           Series 7, due May 1, 2010, 7.375%........................................        4,000          4,000
           Series 8, due September 15, 2016, 7.45%..................................       96,000         96,000
           Series 1B, due February 1, 2018, 6.25%...................................       20,930         20,930
           Series 2B, due February 1, 2018, 6.25%...................................        2,400          2,400
           Series 3B, due February 1, 2018, 6.25%...................................        7,200          7,200
           Series 4B, due February 1, 2018, 6.25%...................................        7,400          7,400
           Series 7, due May 1, 2020, 7.60%.........................................        8,900          8,900
           Series 9, due December 1, 2023, 5.75%....................................       50,000         50,000
           Series 10, due November 1, 2024, variable................................       54,000         54,000
                                                                                      -----------    -----------

              Total KU bonds outstanding............................................      546,330        546,330
                                                                                      -----------    -----------

    LG&E Capital Corp.:

    Argentine negotiable obligations, due August 2001, 10.5%........................       37,782         37,645
    Note payable, due May 2003, 6.75%...............................................          313              -
    Medium term notes, due September 7, 2000, variable..............................       50,000              -
    Medium term notes, due May 1, 2004, 6.205%......................................      150,000              -
    Medium term notes, due January 15, 2008, 6.46%..................................      150,000        150,000
    Medium term notes, due November 1, 2011, 5.75%..................................      150,000        150,000
                                                                                      -----------    -----------

              Total Capital Corp. bonds outstanding.................................      538,095        337,645
                                                                                      -----------    -----------

    Total bonds outstanding.........................................................    1,711,225      1,510,775

    Less current portion of long-term debt..........................................      411,810              -
                                                                                      -----------    -----------

    Long-term debt..................................................................    1,299,415      1,510,775
                                                                                      -----------    -----------

    Total capitalization............................................................  $ 2,576,034    $ 2,888,543
                                                                                      ===========    ===========
</TABLE>

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


                                       80
<PAGE>

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 - Summary of Significant Accounting Policies

Basis of Presentation. 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 accompanying
consolidated financial statements reflect the accounting for the merger as a
pooling of interests and are presented as if the companies were combined as of
the earliest period presented. However, the financial information is not
necessarily indicative of the results of operations, financial position or cash
flows that would have occurred had the merger been consummated for the periods
for which it is given effect, nor is it necessarily indicative of future results
of operations, financial position, or cash flows. The financial statements
reflect the conversion of each outstanding share of KU Energy common stock into
1.67 shares of LG&E Energy common stock. The outstanding preferred stock of
LG&E, a subsidiary of LG&E Energy, and KU, a subsidiary of KU Energy, were not
affected by the Merger.

Effective June 30, 1998, the Company discontinued its merchant energy trading
and sales business and announced its plans to sell its natural gas gathering and
processing business. In 1999 the Company chose to retain the natural gas
gathering and processing business. Accordingly, the accompanying financial
statements reflect the merchant energy trading and sales business as
discontinued operations and the natural gas and processing business as
continuing operations for all periods presented. See Note 3, Discontinued
Operations and Note 4, Gas Facilities Business.

The consolidated financial statements include the accounts of LG&E Energy, LG&E,
Capital Corp., KU, LEM and their respective wholly owned subsidiaries,
collectively referred to herein as the Company.

LG&E Energy's operations include utility operations and non-utility operations.
Capital Corp. has various subsidiaries referred to in these financial
statements, including LPI, LII, WKE, and CRC.

All significant intercompany items and transactions have been eliminated from
the consolidated financial statements. Certain reclassification entries have
been made to the 1998 and 1997 financial statements to conform to the 1999
presentation with no impact on previously reported net income. The Company is
exempt from regulation as a registered holding company under PUHCA.

Cash and Temporary Cash Investments. The Company 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. The costs of utility natural gas inventories are
included in gas stored underground in the balance sheets as of December 31, 1999
and 1998. Utility gas inventories were $38.8 million and $33.5 million at
December 31, 1999 and 1998, respectively. LG&E accounts for gas inventories
using the average-cost method. Non-utility gas inventories as of December 31,
1999 and 1998 were $10.2 million and $5.8 million, respectively.

Utility Plant. LG&E's and 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. Neither LG&E
nor KU has recorded any significant allowance for funds used during
construction.

The cost of utility plant retired or disposed of in the normal course of
business is deducted from utility plant accounts and such cost, plus removal
expense less salvage value, is charged to the reserve for depreciation.


                                       81
<PAGE>

When complete operating units are disposed of, appropriate adjustments are made
to the reserve for depreciation, and gains and losses, if any, are recognized.

Depreciation and Amortization. Utility depreciation is provided on the
straight-line method over the estimated service lives of depreciable plant. The
amounts provided for LG&E were 3.4% in 1999, 1998 and 1997. The amounts provided
for KU were 3.5% in 1999, 1998 and 1997.

Depreciation of non-utility plant and equipment is based on the straight-line
method over periods ranging from 3 to 40 years for domestic operations.
Intangible assets and goodwill have been allocated to the subsidiaries' lines of
business and are being amortized over periods ranging up to 25 years.

Financial Instruments. The Company uses over-the-counter interest-rate swap
agreements to hedge its exposure to interest rates. The Company 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
initially deferred and classified as unrealized losses on marketable securities
in common equity and then charged or credited to other income and deductions
when the securities are sold. See Note 7, Financial Instruments.

In connection with the Company's marketing of power from owned or controlled
generation assets, exchange traded futures are used to hedge its exposure to
price risk. The Company also uses financial instruments associated with its
discontinued merchant energy trading and sales business, the financial impact of
which is included in discontinued operations. See Note 3, Discontinued
Operations.

Debt Expense. Utility 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 the Company'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.

Common Stock. On May 4, 1998, 63,149,394 shares were issued to shareholders of
KU Energy to effect the merger, and the KU Energy shares were retired. Prior
period shares, dividends and earnings per share of common stock have been
restated to reflect the exchange of KU Energy's shares for shares of LG&E
Energy. Diluted earnings per share reflects the potential dilution that could
occur if securities or other contracts to issue common stock under the Company's
Omnibus Long-Term Incentive Plan and Stock Option Plan for Non-Employee
Directors resulted in the issuance of common stock that then shared in the
earnings of the Company. See Note 15 for more information about these plans.

Revenue Recognition. Utility revenues are recorded based on service rendered to
customers through month-end. LG&E and KU accrue estimates for unbilled revenues
from each meter reading date to the end of the accounting period. The unbilled
revenue estimates included in accounts receivable for both LG&E and KU at
December 31, 1999 and 1998, were approximately $60.7 million and $54.7 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


                                       82
<PAGE>

revenue on electric and gas residential sales. In 1998, the decoupling mechanism
was suspended. See Note 6, Utility 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 6, Utility 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 18, Commitments and
Contingencies, for a further discussion.

New Accounting Pronouncements. During 1999 and 1998, the following accounting
pronouncements were issued that affect the Company:

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 the Company must formally
document, designate, and assess the effectiveness of transactions that receive
hedge accounting. The Company has not yet quantified all the effects of adopting
SFAS No. 133 on the financial statements. However, SFAS No. 133 could increase
the volatility in earnings and other comprehensive income. The effect of this
statement will be recorded in cumulative effect of change in accounting when
adopted. 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.

EITF No. 98-10, Accounting for Energy Trading and Risk Management Activities was
adopted effective January 1, 1999. The pronouncement requires that 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
the Company's consolidated results of operations or financial position.

SOP 98-5, Reporting on the Costs of Start-Up Activities and 98-1, Accounting for
the Costs of Computer Software Developed or Obtained for Internal Use. SOP 98-5,
adopted as of January 1, 1998, requires companies to expense the costs of
start-up activities as incurred. The statement also requires certain previously
capitalized costs to be charged to expense at the time of adoption as a
cumulative effect of a change in accounting principle. The Company had
previously capitalized start-up costs related to its investments in various
unconsolidated ventures and other non-utility businesses. The cumulative effect
of adoption resulted in a $7.2 million after-tax charge. The effect of this
change on 1998 income before cumulative effect of changes in accounting
principles was not significant. SOP 98-1, adopted as of January 1, 1998,
clarifies the criteria for capital or expense treatment of costs incurred by an
enterprise to develop or obtain computer software to be used in its internal
operations. The statement does not change treatment of costs incurred in
connection with correcting computer programs to properly process the millennium
change to the Year 2000, which were expensed as incurred. Adoption of SOP 98-1
did not have a material effect on the Company's financial statements.


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<PAGE>

Note 2 - Mergers and Acquisitions

CRC-Evans. In July 1999, the Company purchased 100% of the outstanding common
stock of CRC for initial consideration of $45.6 million and retirement of
approximately $35.3 million in debt. CRC, based in Houston, Texas, is a provider
of specialized equipment and services used in the construction and
rehabilitation of gas and oil transmission pipelines. The purchase agreement
provides for future annual earn-out payments to the previous owners based on
CRC's meeting certain financial targets over the period ending March 31, 2002.
The agreement caps the total of these payments at $34.3 million.

The purchase consideration was paid 55% in cash and 45% in LG&E Energy common
stock. LG&E Energy will repurchase common stock from time to time in the open
market or through privately negotiated transactions in amounts equal to the
stock portions of the initial and subsequent earn-out payments. During the third
quarter 1999, the Company purchased approximately 935,000 shares in this regard
and completed the initial purchase installment.

The Company accounted for the acquisition using the purchase method and recorded
goodwill of approximately $42.1 million. Additional goodwill will be recorded
contingent upon future earn-out payments. Goodwill is being amortized over a
period of twenty years.

The preliminary fair values of the net assets acquired follow (in thousands of
$):

         Assets                                            $ 123,444
         Liabilities                                          78,899
                                                           ---------
         Cash paid, excluding transaction costs               44,545
         Cash and cash equivalents acquired                    5,943
                                                           ---------
         Net cash paid, excluding transaction costs           38,602
         Transaction costs                                     1,091
                                                           ---------
         Net cash paid                                     $  39,693
                                                           =========

The Company's pro forma results of operations for 1999 and 1998 follow (in
thousands of $, except earnings per share). The results for each period assume
the Company acquired CRC at the beginning of the period.

                                                       1999          1998
                                                       ----          ----

Revenues ....................................   $ 2,746,477   $ 2,181,034
Net income (loss) ...........................        60,607       (77,934)
Earnings (loss) per share (basic and diluted)           .47          (.60)

These unaudited pro forma results have been prepared for comparative purposes
only and include certain adjustments, such as additional amortization expense as
a result of recorded goodwill and increased interest expense on borrowings used
to finance the acquisition. The pro forma amounts presented do not purport to be
indicative of the results of operations that would have actually occurred had
the combination taken place as of January 1, 1998, nor are such amounts
necessarily indicative of results that may occur in future periods.

Argentine Gas Distribution Companies. In March 1999, the Company acquired an
indirect 20% ownership interest in Gas BAN, a natural gas distribution company
that serves 1.1 million customers in the northern portion of the province of
Buenos Aires, Argentina. The purchase price totaled $74.3 million, including
transaction costs, which has been reflected in investments in unconsolidated
ventures in the accompanying balance sheet. The Company accounted for the
acquisition using the purchase method, and it records its share of earnings
using the equity method. The purchase price exceeded the underlying equity in
Gas BAN by $13.0 million. The Company allocated this difference to the assets
and liabilities acquired based on their preliminary


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<PAGE>

estimated fair values. In the fourth quarter of 1999, the Company made an
additional net investment in Gas BAN of approximately $11.1 million. These funds
were used by the Company's Argentine holding company to repay its debt.

In February 1997, the Company acquired interests in two Argentine natural gas
distribution companies for $140 million, plus transaction-related costs and
expenses. The Company acquired a controlling interest in Centro and a combined
14.4% interest in Cuyana. The Company accounted for both acquisitions using the
purchase method. The Company allocated substantially all of the excess of the
purchase price over the underlying equity of Centro and Cuyana to property and
equipment.

The fair values of the Centro and Cuyana net assets acquired follow (in
thousands of $):

Assets                                                                  $330,215
Liabilities                                                               86,455
Minority interests                                                       103,916
                                                                        --------
Cash paid, excluding transaction costs                                   139,844
Cash and cash equivalents acquired                                        16,453
                                                                        --------
Net cash paid, excluding transaction costs                               123,391
Transaction costs                                                          1,202
                                                                        --------
Net cash paid                                                           $124,593
                                                                        ========

Centro's revenues, cost of revenues and operating expenses since the date of
acquisition are classified as components of international and non-utility in the
income statement. The earnings of Cuyana are included in Equity in earnings of
unconsolidated ventures. The Company includes Centro's property and equipment in
Non-utility property and plant, net, in its balance sheet, and it includes its
investment in Cuyana in Investments in unconsolidated ventures. Portions of
Centro not owned directly or indirectly by the Company are reported as minority
interests in the financial statements.

Liabilities assumed in the purchase included negotiable obligations issued by
Centro with a face amount of $38 million. The obligations mature in August 2001,
pay interest at 10.5% of face value and are classified as long-term debt.

KU Energy Corporation. 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
Company, 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 of $103.9 million were recorded in the second quarter of
1998, $38.6 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. The Company, LG&E and KU
expensed the remaining costs associated with the merger ($65.3 million) in the
second quarter of 1998. In regulatory filings associated with approval of the
merger, LG&E and 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 the operating
utility subsidiaries were not affected by the merger. The non-utility
subsidiaries of KU Energy have become subsidiaries of Capital Corp.

Pursuant to the merger, in accordance with the terms of the merger agreement,
each outstanding share KU Energy Common Stock together with the associated KU
Energy stock purchase rights, was converted into 1.67 shares LG&E Energy Common
Stock, together with the associated LG&E Energy stock purchase rights.


                                       85
<PAGE>

Immediately preceding the merger, there were 66,527,636 shares of LG&E Energy
common stock outstanding, and 37,817,517 shares of KU Energy common stock
outstanding. Based on such capitalization, immediately following the merger,
51.3% of the outstanding LG&E Energy common stock was owned by the shareholders
of LG&E Energy prior to the merger and 48.7% was owned by former KU Energy
shareholders.

LG&E Energy, as the parent of LG&E and KU, continues to be an exempt holding
company under PUHCA. Management has accounted for the merger as a pooling of
interests and as a tax-free reorganization under the Internal Revenue Code.

In the application filed with the Kentucky Commission, the utilities proposed
that 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
Kentucky Commission approved the surcredit and allocated the customer savings
53% to KU and 47% to LG&E. The surcredit will be about 2% of customer bills over
the next five years and will amount to approximately $55 million in net non-fuel
savings to LG&E customers and approximately $63 million in net non-fuel savings
to KU customers. Any fuel cost savings are passed to Kentucky customers through
the companies' fuel adjustment clauses. See Note 6 for more information about
LG&E's and KU's rates and regulatory matters.

Note 3 - Discontinued Operations

Effective June 30, 1998, the Company discontinued its merchant energy trading
and sales business. This business consisted primarily of a portfolio of energy
marketing contracts entered into in 1996 and early 1997, nationwide deal
origination and some level of speculative trading activities, which were not
directly supported by the Company's physical assets. The Company's decision to
discontinue these operations was primarily based on the impact that volatility
and rising prices in the power market had on its portfolio of energy marketing
contracts. Exiting the merchant energy trading and sales business enabled the
Company to focus on optimizing the value of physical assets it owns or controls,
and reduced the earnings impact on continuing operations of extreme market
volatility in its portfolio of energy marketing contracts. The Company continues
to settle commitments that obligate it to buy and sell natural gas and electric
power. If the Company is unable to dispose of these commitments or assets it
will continue to meet its obligations under the terms of the contracts. The
Company, however, has maintained sufficient market knowledge, risk management
skills, technical systems and experienced personnel to maximize the value of
power sales from physical assets it owns or controls, including LG&E, KU and
WKE.

As a result of the Company's decision to discontinue its merchant energy trading
and sales activity, and the initial decision to sell the associated gas
gathering and processing business, the Company recorded an after-tax loss on
disposal of discontinued operations of $225 million in the second quarter of
1998. The loss on disposal of discontinued operations resulted primarily from
several fixed-price energy marketing contracts entered into in 1996 and early
1997, including the Company's long-term contract with OPC. Other components of
the write-off included costs relating to certain peaking options, goodwill
associated with the Company's 1995 purchase of merchant energy trading and sales
operations and exit costs.

At the time the Company decided to discontinue its merchant energy trading and
sales business, it also decided to sell its natural gas gathering and processing
business. Effective June 30, 1999, the Company decided to retain this business.
The accompanying financial statements reflect the reclassification of the
natural gas gathering and processing business as continuing operations for all
periods presented. Approximately $800,000 of net losses charged to the loss on
disposal of discontinued operations was reclassified to continuing operations in
the accompanying income statement in each of 1999 and 1998 related to the
natural gas gathering and processing business. See Note 4 below.


                                       86
<PAGE>

In the fourth quarter of 1999, the Company received an adverse decision from the
arbitration panel considering its contract dispute with OPC, which was commenced
by the Company in April 1998. As a result of this adverse decision, higher than
anticipated commodity prices, increased load demands, and other factors, the
Company increased its after-tax accrued loss on disposal of discontinued
operations by $175 million. The additional write-off included costs related to
the remaining commitments in its portfolio and exit costs expected to be
incurred to serve those commitments. Although the Company used what it believes
to be appropriate estimates for future energy prices, among other factors, to
calculate the net realizable value of discontinued operations, there are
inherent limitations in models to accurately predict future commodity prices,
load demands and other events that could impact the amounts recorded by the
Company.

Actual operating results for each of the last three years ended December 31 for
the discontinued merchant energy trading and sales business, follow (in
thousands of $).

                                       1999              1998              1997
                                       ----              ----              ----

Revenues                        $   747,983       $ 3,755,187       $ 3,147,484
Loss before taxes                  (175,940)         (167,109)          (41,989)
Net loss                            (70,905)         (109,431)          (25,367)

Net (liabilities) assets of the merchant energy trading and sales business at
December 31, follow (in thousands of $).

                                                              1999         1998
                                                              ----         ----

Cash and temporary cash investments                      $      --    $   4,671
Accounts receivable                                         36,558       70,775
Price risk management assets, net                           29,576       98,885
Non-utility property and plant, net                             --        2,037
Accounts payable and accruals                              (25,233)     (58,526)
Price risk management liabilities, net                     (10,262)     (32,693)
Other assets and liabilities, net                          (18,163)      37,451
                                                         ---------    ---------

Net assets before accrued loss on disposal of dis-
  continued operations                                      12,476      122,600

Accrued loss on disposal of discontinued operations,
  net of income tax benefit of $109,503 and $74,297        170,698      119,381
                                                         ---------    ---------

Net assets (liabilities) of discontinued operations      $(158,222)   $   3,219
                                                         =========    =========

Total pretax charges against the accrued loss on disposal of discontinued
operations through December 31, 1999, include $251.0 million for commitments
prior to disposal, $69.6 million for transaction settlements, $11.1 million for
goodwill, and $30.5 million for other exit costs. While the Company has been
successful in settling portions of its discontinued operations, significant
assets, operations and obligations remain. The Company continues to manage the
remaining portfolio and believes it has hedged certain of its future obligations
through various power purchase commitments and planned construction of physical
assets. Management cannot predict the ultimate effectiveness of these hedges.

The pretax net fair value of the remaining commitments as of December 31, 1999,
are currently estimated to be approximately $46 million in 2000, $37 million to
$54 million each year in 2001 through 2004 and $7 million in the aggregate
thereafter.


                                       87
<PAGE>

As of December 31, 1999, the Company's discontinued operations were under
various contracts to buy and sell power and gas with net notional amounts of
22.1 million Mwh's of power and 44.3 million Mmbtu's of natural gas with a
volumetric weighted-average period of approximately 37 and 44 months,
respectively. These notional amounts are based on estimated loads since various
commitments do not include specified firm volumes. The Company is also under
contract to buy or sell coal and SO2 allowances in support of its power
contracts. Notional amounts reflect the nominal volume of transactions included
in the Company's price risk management commitments, but do not reflect actual
amounts of cash, financial instruments, or quantities of the underlying
commodity which may ultimately be exchanged between the parties.

As of January 26, 2000, the Company estimates that a $1 change in electricity
prices and a 10-cent change in natural gas prices across all geographic areas
and time periods could change the value of the Company's remaining energy
portfolio by approximately $4.9 million. In addition to price risk, the value of
the Company's remaining energy portfolio is subject to operational and event
risks including, among others, increases in load demand, regulatory changes, and
forced outages at units providing supply for the Company. As of January 26,
2000, the Company estimates that a 1% change in the forecasted load demand could
change the value of the Company's remaining energy portfolio by $8.2 million.

The Company's discontinued operations maintain policies intended to minimize
credit risk and revalue credit exposures daily to monitor compliance with those
policies. As of December 31, 1999, over 97% of the Company's price risk
management commitments were with counterparties rated BBB equivalent or better.
As of December 31, 1999, six counterparties represented 90% of the Company's
price risk management commitments.

Note 4 - Gas Facilities Business

In June 1999, the Company reclassified its natural gas gathering and processing
business to continuing operations from discontinued operations. The Company
chose to retain rather than dispose of this business at the end of the one-year
period established by accounting standards because of management's expectation
of more favorable future natural gas and natural gas liquids prices and the
related impact on this business. The Company has reflected the operating results
and net assets of the natural gas gathering and processing business as
continuing operations in the accompanying financial statements for all periods
presented.

Operating results for the natural gas gathering and processing business follow
(in thousands of $):

                                                  Three               Six
                                                 Months            Months
                                                  Ended             Ended
                                               Mar. 31,          Dec. 31,
                                                   1999              1998
                                                   ----              ----

         Revenues                              $ 33,302          $ 48,942
         Net loss                                  (788)             (852)


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<PAGE>

Net assets at December 31 follow (in thousands of $):

                                                             1999          1998
                                                             ----          ----

Cash and temporary cash investments                     $  12,073     $      --
Accounts receivable                                        24,622         7,425
Non-utility property and plant, net                       146,958       161,473
Accounts payable and accruals                              (6,274)       (6,148)
Goodwill and other assets and liabilities, net            (29,018)      (22,318)
                                                        ---------     ---------

Net assets                                              $ 148,361     $ 140,432
                                                        =========     =========

No loss on disposal of the net assets of the natural gas gathering and
processing business was included because the Company assumed it would sell these
assets for an amount at least equal to book value. It also included an after-tax
reserve of approximately $1.6 million for estimated losses from operations of
the natural gas gathering and processing business through the date of disposal.
Since this amount equaled the estimated losses from operations included in the
original accrued loss on disposal of discontinued operations, no reversal of the
accrued loss was included in income for 1999. The Company has recorded no
impairment losses related to the net assets of its natural gas gathering and
processing business.

Note 5 - Big Rivers Electric Corporation Lease

In July 1998, the Company closed the transaction to lease the generating assets
of Big Rivers. Under the 25-year operating lease, WKE operates Big Rivers'
coal-fired facilities, a combustion turbine and operates and maintains the
Station Two generating facility of Henderson. The combined generating capacity
of these facilities is approximately 1,700 Mw, net of Henderson's capacity and
energy needs from Station Two. WKE prepaid $55.9 million for its first two years
of lease payments. Lease expense for 1999 and 1998 was $27.9 million and $12.8
million, respectively. See Note 18, Commitments and Contingencies, for further
discussion.

In related transactions, power is supplied to Big Rivers at contractual prices
over the term of the lease to meet the needs of three-member distribution
cooperatives and their retail customers, including major western Kentucky
aluminum smelters. Excess generating capacity is available to WKE to market
throughout the region. In connection with these transactions, WKE has undertaken
to bear certain of the future capital requirements of those generating assets,
certain defined environmental compliance costs and other obligations.

In July 1998, as part of the deal structure with Big Rivers, WKE began advancing
Big Rivers $50 million over a 24-month period to help it emerge from bankruptcy.
The note will be repaid over a three-year period, beginning August 2000, with
interest at 7.165%.


                                       89
<PAGE>

Note 6 - 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. LG&E and KU are
subject to SFAS No. 71, Accounting for the Effects of Certain Types of
Regulation. Under SFAS No. 71, 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
flowback to customers in future rates. LG&E's and KU's current or expected
recovery of deferred costs and expected flowback of deferred credits is
generally based on specific ratemaking decisions or precedent for each item. The
following regulatory assets and liabilities were included in the consolidated
balance sheets as of December 31 (in thousands of $):

                                                         1999              1998
                                                         ----              ----

Unamortized loss on bonds                           $  24,150         $  26,302
Merger costs                                           27,026            34,749
Manufactured gas sites                                  2,185             3,684
Other                                                   1,115             1,136
                                                    ---------         ---------
Total regulatory assets                                54,476            65,871

Deferred income taxes - net                           (99,759)         (109,411)
Other                                                  (5,036)             (670)
                                                    ---------         ---------
Total regulatory liabilities                         (104,795)         (110,081)
                                                    ---------         ---------

Regulatory liabilities - net                        $ (50,319)        $ (44,210)
                                                    =========         =========

Environmental Cost Recovery. In August 1994 and May 1995, respectively, KU and
LG&E implemented an ECR surcharge. The Kentucky Commission's order approving the
surcharge for KU as well as the constitutionality of the surcharge was
challenged by certain intervenors in Franklin Circuit Court. Decisions of the
Circuit Court and the Kentucky Court of Appeals in July 1995 and December 1997,
respectively, upheld the constitutionality of the ECR statute but differed on a
claim of retroactive recovery of certain amounts. Based on these decisions, the
Kentucky Commission ordered that certain surcharge revenues collected by LG&E
and KU be subject to refund pending final determination of all appeals.

In December 1998, the Kentucky Supreme Court rendered an opinion upholding the
constitutionality of the surcharge statute but denied recovery of costs
associated with pre-1993 environmental projects through the ECR. The court
remanded the case to the Kentucky Commission to determine amounts to be refunded
for revenues collected for such pre-1993 environmental projects. Accordingly,
the Company recorded a provision for rate refunds of $26 million in December
1998.

The parties to the proceedings reached a settlement agreement that was approved
in a Final Order issued by the Kentucky Commission in August 1999. This Final
Order resulted in the reversal of approximately $0.9 million of the provision
for rate refunds established by KU and LG&E in December 1998. The refund is
being applied to customers' bills during the twelve-month period beginning
October 1999.

Future Rate Regulation. In October 1998, LG&E and KU filed applications with the
Kentucky Commission for approval of a new method of determining electric rates
that sought to provide financial incentives for LG&E and 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 LG&E and 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


                                       90
<PAGE>

incentives for LG&E and 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, LG&E and KU filed a joint agreement among the companies and the
Kentucky Attorney General to adopt the PBR plan subject to certain amendments.
The amended filing included requested Kentucky Commission approval of a
five-year rate reduction plan which proposed to reduce the electric rates of
LG&E and KU by $20 million in the first year (beginning July 1999), and by $8
million annually through June 2004. The proposed amended plan also included
establishment of a $6 million program for low-income customer assistance as well
as extension for one additional year of both the rate cap proposal and merger
savings surcredit established in the original merger plan of LG&E and KU. Under
the rate cap proposal, the companies agreed, in the absence of extraordinary
circumstances, not to increase base electric rates for five years following the
merger and LG&E also agreed to refrain from filing for an increase in natural
gas rates through June 2004.

In April 1999, 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 and KU's amended PBR plans and the KIUC
rate reduction petitions in August and September 1999. Legal briefs of the
parties were filed with the Kentucky Commission in October 1999. KIUC's position
called for annual revenue reductions for LG&E and KU of $69.6 million and $61.5
million, respectively.

In January 2000, the Kentucky Commission issued Orders for LG&E and KU in the
subject cases. The Kentucky Commission ruled that LG&E and KU should reduce base
rates by $27.2 million and $36.5 million, respectively, effective with bills
rendered beginning March 1, 2000. The Kentucky Commission eliminated the
utilities' proposal to operate under its PBR plan and reinstated the FAC
mechanism effective March 1, 2000. The Kentucky Commission offered the utilities
the opportunity to operate under an ESM for the next three years. Under this
mechanism, incremental annual earnings for each utility resulting in a rate of
return 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, the utilities 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 and KU
of $1.1 million and $7.7 million, respectively. The utilities also filed motions
for reconsideration with the Kentucky Commission on a number of items in the
case in late January. Certain intervening parties in the proceedings have also
filed motions for reconsideration asserting, among other things, that the
Kentucky Commission understated the amount of base rate reductions.

Other Rate Matters. 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
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.

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 are being determined for each 12-month
period beginning November 1 and ending October 31. During the first two years of
the mechanism ended October 31, 1999 and 1998, LG&E recorded $2.2 million and
$3.5 million, respectively, for its share of reduced gas costs. These amounts
are billed to customers through the gas supply clause.


                                       91
<PAGE>

Prior to implementation of the PBR in July 1999, and following its termination
in March 2000, LG&E and 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 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 the
utilities' method of computing fuel costs associated with electric line losses
on off-system sales appropriate for recovery through the FAC. LG&E requested
that the Kentucky Commission grant rehearing on the February orders, and further
requested that the Kentucky Commission stay the refund requirement until it
could rule on the rehearing request. The Kentucky Commission granted the request
for a stay, and in March 1999 granted rehearing on the appropriate line loss
factor associated with off-system sales for the 18-month period ended April
1998. The Kentucky Commission also granted rehearing on the KIUC's request for
rehearing on the Kentucky Commission's determination that it lacked authority to
require the utilities to pay interest on the refund amounts. The Kentucky
Commission conducted a hearing on the rehearing issues and issued a final ruling
in December 1999. The Kentucky Commission agreed with LG&E 's position on the
appropriate loss factor to use in the FAC computation and reduced the refund
level for the 18-month period under review to approximately $800,000. LG&E
implemented the refund with billings beginning in the month of January 2000.
LG&E and KIUC have each filed separate appeals from the Kentucky Commission's
February 1999 orders with the Franklin Circuit Court. A decision on the appeals
by the Court is expected in 2000.

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 off-system 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 $5.8 million from the original Order
amount of $10.1 million. In August 1999, LG&E and KU each recorded its estimated
share of anticipated FAC refunds of $8.7 million. KU began implementing the
refund in October and will continue the refund through September 2000. Both KU
and the KIUC have appealed the Order to the Franklin Circuit Court. A decision
is not expected on the appeal until later in 2000.

LG&E intends to file before the end of the first quarter an application with the
Kentucky Commission for authority to increase its natural gas rates in order to
recoup higher costs for providing natural gas distribution services. LG&E
expects implementation before the end of 2000.

Kentucky PSC 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


                                       92
<PAGE>

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, the Company, 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.
Management does not expect the ultimate resolution of this matter to have a
material adverse effect on the Company's financial position or results of
operations.

Note 7 - Financial Instruments

The cost and estimated fair values of the Company's non-trading financial
instruments (excluding the fair values of the Company's price risk management
assets and liabilities) as of December 31, 1999 and 1998 follow (in thousands of
$):
<TABLE>
<CAPTION>

                                                1999                          1998
                                                ----                          ----
                                                         Fair                               Fair
                                         Cost           Value             Cost             Value
                                         ----           -----             ----             -----
<S>                               <C>             <C>              <C>               <C>
Marketable securities             $    10,562     $    10,126      $    20,601       $    20,862
Long-term investments -
  Not practicable to estimate
     fair value                         2,269           2,269            2,527             2,527
Preferred stock subject
  to mandatory redemption              25,000          24,861           25,000            26,413
Long-term debt (including
  current portion)                  1,711,225       1,690,752        1,510,775         1,576,502
U.S. Treasury note and
  bond futures                             --             142               --               (87)
Interest rate swaps                        --          (2,138)              --            (9,527)
</TABLE>

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 the Company cannot
reasonably estimate fair value.

Interest Rate Swaps. The Company enters into interest rate swap agreements to
exchange fixed and variable interest rate payment obligations without the
exchange of underlying principal amounts. As of December 31, 1999 and 1998, the
Company was party to various interest rate swaps with aggregate notional amounts
of $487.3 million and $349.3 million, respectively. Under swap agreements the
Company paid fixed rates averaging 4.53% and 4.55% and received variable rates
of averaging 5.61% and 4.42% at December 31, 1999 and 1998, respectively. The
Company also paid variable rates averaging 6.46% and received fixed rates
averaging 7.13% at December 31, 1999. The swaps mature on dates ranging from
2000 to 2025.

At December 31, 1999, the Company 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 2000.

Note 8 - 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


                                       93
<PAGE>

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 295,000 customers and electricity to
approximately 366,000 customers in Louisville and adjacent areas in Kentucky.
KU's customer receivables and revenues arise from deliveries of electricity to
about 458,000 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, 1999, 91% of total utility revenue was derived from electric
operations and 9% from gas operations.

The financial position and results of operations of the domestic unconsolidated
ventures are substantially dependent upon the continuation of long-term power
sales contracts with purchasing utilities. The Argentine natural gas
distribution companies serve approximately 1.9 million customers in seven
provinces in Argentina. WKE's receivables and revenues arise from the deliveries
of electricity and generating capacity to Big Rivers for distribution to its
three member distribution cooperatives and other major wholesale customers. CRC
has a concentration of customers in the oil and gas pipeline construction
industry, which experiences cyclical fluctuations, and its receivables are
collateralized on a limited basis with negotiable letters of credit. Ten of
CRC's customers were responsible for 50% of its revenues for the period July 1,
1999, through December 31, 1999.

In August 1999, KU and their employees represented by IBEW Local 101 and USWA
Local 8686, which represents approximately 14% of KU's workforce, entered into a
one-year collective bargaining agreement. 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. In September 1998, WKE and
IBEW Local 1701 employees entered into a three-year collective bargaining
agreement. CRC contracts with employees represented by applicable locals of the
LIU and the UAJ-APPI on a project basis.

Note 9 - Investments in Unconsolidated Ventures

The Company's investments in unconsolidated ventures reflect interests in
domestic and foreign electric power and steam producing plants and two of the
Argentine gas distribution companies. These investments are accounted for using
the equity method.


                                       94
<PAGE>

The fuel type, ownership percentages and carrying amounts of the unconsolidated
ventures as of December 31, 1999, are summarized as follows (in thousands of $):

<TABLE>
<CAPTION>
                                                                                           Carrying
                                                     Fuel Type            % Owned            Amount
                                                     ---------            -------            ------
<S>                                                       <C>                <C>           <C>
LG&E Westmoreland - Southampton                           Coal                 50          $ 15,466
LG&E Westmoreland - Altavista                             Coal                 50            14,345
LG&E Westmoreland - Hopewell                              Coal                 50            12,737
Westmoreland - LG&E Partners - Roanoke Valley             Coal                 50            25,196
Electric Energy, Inc. (Note 18)                           Coal                 20             2,123
LG&E Power Gregory (under construction)                    Gas                 50              (450)
Distribuidora de Gas Cuyana (Note 2)                       Gas                 14            42,675
Gas Natural BAN, S.A. (Note 2)                             Gas                 20            92,231
Tenaska Limited Partnerships                               Gas               5-10             5,842
CEC-APL L.P.                                               Gas                 49             9,138
Windpower Partners 1994                                   Wind                 25                --
Windpower Partners 1993                                   Wind                 50            22,158
KW Tarifa, S.A.                                           Wind                 46             7,994
                                                                                           --------

Total                                                                                      $249,455
                                                                                           ========
</TABLE>

The Company's carrying amount exceeded the underlying equity in unconsolidated
ventures by $39.8 million and $33.3 million at December 31, 1999 and 1998,
respectively. This difference, which is being amortized, represents adjustments
to reflect the fair value of the underlying net assets acquired and related
goodwill.

In March 1999, LG&E-Westmoreland Rensselaer, a California general partnership in
which the Company owns a 50% interest, sold substantially all the assets and
major contracts of its 79 Mw gas-fired cogeneration facility in Rensselaer, New
York, with net proceeds to the Company of approximately $34 million. The sale
resulted in an after-tax gain to the Company of approximately $8.9 million.

In January 1999, a final order was entered in the bankruptcy proceedings
involving Westmoreland Coal Company and certain of its subsidiaries, including
Westmoreland Energy, Inc., the parent of various entities that are partners with
company subsidiaries in five of the independent generating facilities. However,
none of the partnerships and no partner of the current partnerships has been
under bankruptcy court protection, nor were these partnerships in a default
occasioned under the project loan documents.

With respect to the Wind projects listed above, certain of the Company's
partners (or affiliates of such partners) are in bankruptcy proceedings. During
the third quarter of 1998, the Company wrote off its aggregate remaining
investment in Windpower Partners 1994 of $3.8 million. During 1999, the Wind
projects received certain amounts in connection with such bankruptcy
proceedings. See Note 18, Commitments and Contingencies.

In November 1998, the Company received approximately $8.5 million in connection
with an arbitration proceeding concerning a former PPA between Tenaska
Washington Partners II, L.P. and the BPA. The Company has a 10% interest in this
partnership, which owned a partially constructed facility in Frederickson,
Washington. This facility was transferred to the BPA following payment of the
award.

In June 1998, the partnership that owns the Rensselaer facility, along with 14
other independent power producers, participated in the consummation of a MRA
with NIMO. As part of the MRA, the partnership restructured its power purchase
agreement with NIMO and entered into a new multi-year agreement with the
utility. Concurrent with the MRA, the Company reached a settlement with other
parties to retain a 50%


                                       95
<PAGE>

ownership in the Rensselaer facility. As a result of these transactions, the
Company recorded a $21 million, net after-tax gain in 1998.

In June 1998, the Company sold half of its interest in the Gregory, Texas,
project and became a 50% partner in the 550 Mw gas-fired project. The project is
currently under construction and anticipated to become operational in mid-2000.
See Note 18, Commitments and Contingencies.

In February 1998, the Company sold its indirect, one-third interest in the
company which owned and operated the San Miguel, Argentina generating facility
for a price of $16 million. The sale resulted in a $2.8 million pre-tax charge
to 1998 earnings.

Note 10 - Leveraged Leases

During 1999, all of the Company's leveraged leases in which Capital Corp. owned
an equity interest expired. The lessees who leased five of the turbines
exercised their options to purchase resulting in pre-tax gains totaling $3.1
million. The lessee who leased the remaining three turbines allowed its leases
to terminate and Capital Corp. is investigating options on the future use of
these turbines. The carrying value of Capital Corp.'s investment the three
remaining turbines totals $9.1 million, and the Company has reclassified this
amount to Investment in Unconsolidated Ventures at December 31, 1999. See Note
9, Investment in Unconsolidated Ventures and Note 18, Commitments and
Contingencies.

The following is a summary of the components of Capital Corp.'s net investment
in leveraged leases at December 31, 1998 (in thousands of $):

Rents receivable (net of nonrecourse debt)                               $ 1,556
Estimated residual value of leased property                               32,707
Less: unearned and deferred income                                         3,319
                                                                         -------
Investment in leveraged leases                                            30,944
Less: accumulated deferred income taxes                                    7,301
                                                                         -------
Net investment in leveraged leases                                       $23,643
                                                                         =======

See Note 14, Other Income and Deductions for income from leveraged leases.

Note 11 - Marketable Securities

The Company's marketable securities have been determined to be
"available-for-sale" under the provisions of SFAS No. 115, Accounting for
Certain Investments in Debt and Equity Securities. Proceeds from sales of
available-for-sale securities in 1999 were approximately $11.7 million, which
resulted in realized gains of approximately $.7 million and losses of
approximately $.2 million, calculated using the specific identification method.
Proceeds from sales of available-for-sale securities in 1998 were $20 million,
which resulted in realized gains of approximately $.2 million and losses of
approximately $.7 million.


                                       96
<PAGE>

Approximate cost, fair value and other required information pertaining to the
Company's available-for-sale securities by major security type, as of December
31, 1999 and 1998, follow (in thousands of $):

                                                     Fixed
                                       Equity       Income       Total
                                      --------    --------    --------
1999:
Cost                                  $  7,529    $  3,033    $ 10,562
Unrealized gains                           170           3         173
Unrealized losses                         (498)       (111)       (609)
                                      --------    --------    --------
Fair values                           $  7,201    $  2,925    $ 10,126
                                      ========    ========    ========

Fair values:
  No maturity                         $  7,201    $     --    $  7,201
  Contractual maturities:
     Less than one year                     --       2,134       2,134
     One to five years                      --         631         631
     Five to ten years                      --         160         160
                                      --------    --------    --------
Total fair values                     $  7,201    $  2,925    $ 10,126
                                      ========    ========    ========

1998:
Cost                                  $  6,467    $ 14,134    $ 20,601
Unrealized gains                           545          40         585
Unrealized losses                         (196)       (128)       (324)
                                      --------    --------    --------
Fair values                           $  6,816    $ 14,046    $ 20,862
                                      ========    ========    ========

Fair values:
  No maturity                         $  6,816    $    178    $  6,994
  Contractual maturities:
     Less than one year                     --       8,301       8,301
     One to five years                      --       3,861       3,861
     Over ten years                         --       1,706       1,706
                                      --------    --------    --------
Total fair values                     $  6,816    $ 14,046    $ 20,862
                                      ========    ========    ========


                                       97
<PAGE>

Note 12 - Pension Plans and Retirement Benefits

Pension Plans and Retirement Benefits. LG&E Energy Corp. 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, 1999, and a statement of the funded status as of
December 31 for each of the last three years (in thousands of $):

<TABLE>
<CAPTION>
                                                        1999         1998         1997
                                                        ----         ----         ----
<S>                                                <C>          <C>          <C>
Pension Plans:
Change in benefit obligation
  Benefit obligation at beginning of year          $ 558,641    $ 499,143    $ 432,551
  Service cost                                        13,761       14,242       12,675
  Interest cost                                       37,749       35,715       32,927
  Plan amendments                                     (2,311)       6,377        3,143
  Acquisitions/divestitures                               --       (2,243)          --
  Curtailment (gain) or loss                              --         (364)          --
  Special termination benefits                            --       23,965           --
  Benefits paid                                      (28,475)     (23,823)     (22,114)
  Actuarial (gain) or loss                           (57,951)       5,629       39,961
                                                   ---------    ---------    ---------
  Benefit obligation at end of year                $ 521,414    $ 558,641    $ 499,143
                                                   =========    =========    =========

Change in plan assets
  Fair value of plan assets at beginning of year   $ 550,711    $ 501,361    $ 432,612
  Actual return on plan assets                       102,824       70,631       81,645
  Employer contributions                              19,484        2,638       10,101
  Benefits paid                                      (28,475)     (23,823)     (22,114)
  Administrative expenses                             (2,329)         (96)        (883)
                                                   ---------    ---------    ---------
  Fair value of plan assets at end of year         $ 642,215    $ 550,711    $ 501,361
                                                   =========    =========    =========

Reconciliation of funded status
  Funded status                                    $ 120,801    $  (7,930)   $   2,218
  Unrecognized actuarial (gain) or loss             (200,620)     (96,368)     (79,891)
  Unrecognized transition (asset) or obligation       (7,839)      (9,059)     (10,358)
  Unrecognized prior service cost                     40,916       47,286       48,064
                                                   ---------    ---------    ---------
  Net amount recognized at year-end                $ (46,742)   $ (66,071)   $ (39,967)
                                                   =========    =========    =========
</TABLE>


                                       98
<PAGE>

<TABLE>
<CAPTION>
                                                      1999         1998         1997
                                                      ----         ----         ----
<S>                                                <C>          <C>          <C>
Other Benefits:
Change in benefit obligation
  Benefit obligation at beginning of year          $ 127,593    $ 115,894    $ 106,743
  Service cost                                         3,040        2,870        2,633
  Interest cost                                        7,248        8,255        7,860
  Plan amendments                                    (22,236)         613           --
  Acquisitions/divestitures                               --        2,283           --
  Curtailment (gain) or loss                              --        3,584           --
  Special termination benefits                            --        2,855           --
  Benefits paid                                       (7,709)      (5,260)      (6,648)
  Actuarial (gain) or loss                            (6,599)      (3,501)       5,306
                                                   ---------    ---------    ---------
  Benefit obligation at end of year                $ 101,337    $ 127,593    $ 115,894
                                                   =========    =========    =========

Change in plan assets
  Fair value of plan assets at beginning of year   $  30,484    $  22,192    $  15,568
  Actual return on plan assets                         7,221        5,313        3,649
  Employer contributions                               8,650        7,056        7,577
  Benefits paid                                       (6,458)      (4,077)      (4,602)
                                                   ---------    ---------    ---------
  Fair value of plan assets at end of year         $  39,897    $  30,484    $  22,192
                                                   =========    =========    =========

Reconciliation of funded status
  Funded status                                    $ (61,441)   $ (97,109)   $ (93,702)
  Unrecognized actuarial (gain) or loss              (31,838)     (20,115)     (16,730)
  Unrecognized transition (asset) or obligation       38,183       63,834       70,230
  Unrecognized prior service cost                      4,291        3,572        3,456
                                                   ---------    ---------    ---------
  Net amount recognized at year-end                $ (50,805)   $ (49,818)   $ (36,746)
                                                   =========    =========    =========
</TABLE>

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, 1999, 1998 and 1997 (in thousands of $):

<TABLE>
<CAPTION>
                                                                           1999         1998         1997
                                                                           ----         ----         ----
<S>                                                                     <C>          <C>          <C>
Pension Plans:
Amounts recognized in the consolidated balance
  sheet consisted of:
     Accrued benefit liability                                          $ (56,757)   $ (67,126)   $ (40,296)
     Intangible asset                                                         301          426          281
     Prepaid benefit cost                                                   6,471           --           --
     Other                                                                   (300)         706          710
                                                                        ---------    ---------    ---------
     Net amount recognized at year-end                                  $ (50,285)   $ (65,994)   $ (39,305)
                                                                        =========    =========    =========

Additional year-end information for plans with
  benefit obligations in excess of plan assets:
     Projected benefit obligation (1)                                   $ 159,131    $ 163,722    $ 138,492
     Accumulated benefit obligation (2)                                    11,249      142,941       11,879
     Fair value of plan assets (1)                                        141,346      111,914      102,775
</TABLE>

(1)   All years include LG&E's non-union plan, LG&E Energy's plan and the
      Company's unfunded SERPs. 1999 and 1998 also include WKE's union plan.
(2)   All years include the Company's SERPs plus in 1999 WKE's union plan and in
      1998 LG&E's non-union plan, LG&E Energy's plan and WKE's union plan.


                                       99
<PAGE>

<TABLE>
<CAPTION>
                                                     1999         1998         1997
                                                     ----         ----         ----
<S>                                               <C>          <C>          <C>
Other Benefits:
Amounts recognized in the consolidated
  balance sheet consisted of:
     Accrued benefit liability                    $ (50,805)   $ (49,818)   $ (36,746)
     Other                                               --       (4,421)      (4,166)
                                                  ---------    ---------    ---------
     Net amount recognized at year-end            $ (50,805)   $ (54,239)   $ (40,912)
                                                  =========    =========    =========

Additional year-end information for plans with
  benefit obligations in excess of plan assets:
     Projected benefit obligation                 $ 101,337    $ 127,593    $ 115,894
     Fair value of plan assets                       44,499       30,484       22,192
</TABLE>

The following table provides the components of net periodic benefit cost for the
plans for 1999, 1998 and 1997 (in thousands of $):

<TABLE>
<CAPTION>
                                                       1999        1998        1997
                                                       ----        ----        ----
<S>                                                  <C>         <C>         <C>
Pension Plans:
Components of net periodic benefit cost
  Service cost                                       $ 13,761    $ 14,242    $ 12,675
  Interest cost                                        37,749      35,715      32,927
  Expected return on plan assets                      (51,435)    (42,278)    (35,511)
  Amortization of prior service cost                    4,059       4,421       4,133
  Amortization of transition (asset) or obligation     (1,220)     (1,224)     (1,229)
  Recognized actuarial (gain) or loss                  (2,759)     (2,248)     (2,854)
                                                     --------    --------    --------
  Net periodic benefit cost                          $    155    $  8,628    $ 10,141
                                                     ========    ========    ========

Special charges
  Curtailment gain                                   $     --    $ (2,204)   $     --
  Prior service cost recognized                            --       2,015          --
  Special termination benefits                             --      23,965          --
                                                     --------    --------    --------
  Total charges                                      $     --    $ 23,776    $     --
                                                     ========    ========    ========

Other Benefits:
Components of net periodic benefit cost
  Service cost                                       $  3,040    $  2,870    $  2,633
  Interest cost                                         7,248       8,255       7,860
  Expected return on plan assets                       (2,302)     (1,722)     (1,204)
  Amortization of prior service cost                      473         373         332
  Amortization of transition (asset) or obligation      2,937       4,621       4,682
  Recognized actuarial (gain) or loss                    (700)       (467)       (810)
                                                     --------    --------    --------
  Net periodic benefit cost                          $ 10,696    $ 13,930    $ 13,493
                                                     ========    ========    ========

Special charges
  Curtailment loss                                   $     --    $  2,243    $     --
  Special termination benefits                             --       2,855          --
                                                     --------    --------    --------
  Total charges                                      $     --    $  5,098    $     --
                                                     ========    ========    ========
</TABLE>

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 Energy had both qualified
and nonqualified pension plans. During 1998, the Company invested approximately
$24.0 million in special termination benefits as a result of its early
retirement program offered to eligible employees post-merger. In May 1997, $4.7
million in lump sum payments were


                                      100
<PAGE>

made to retired employees of KU Energy due to a change-in-control provision in
the Supplemental Security Plan of the Merger Agreement.

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

<TABLE>
<CAPTION>
                                                                 1999             1998              1997
                                                                 ----             ----              ----
<S>                                                             <C>        <C>               <C>
Weighted-average assumptions as of December 31
  Discount rate                                                 8.00%            7.00%             7.00%
  Expected long-term rate of return on plan assets (1)          9.50%      8.25%-8.50%       8.25%-8.50%
  Rate of compensation increase (2)                             5.00%      3.50%-4.00%       2.00%-4.00%
</TABLE>

(1)   All plans used 8.50% for 1998 and 1997 except KU's.
(2)   All plans used 4.00% for 1998 and 1997 except LG&E's union plan which used
      3.50% for 1998 and 2.00% for 1997.

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 4.75% 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 $):

<TABLE>
<CAPTION>
                                                                           1% Decrease     1% Increase
                                                                           -----------     -----------
<S>                                                                           <C>            <C>
Effect on total of service and interest cost components for 1999              $  (535)       $   621
Effect on year-end 1999 postretirement benefit obligations                     (5,319)         6,123
</TABLE>

Thrift Savings Plans. The Company has thrift savings plans under section 401(k)
of the Internal Revenue Code. Under these plans, eligible employees may defer
and contribute to the plans a portion of current compensation in order to
provide future retirement benefits. The Company makes contributions to the plans
by matching a portion of the employee's contributions. The costs of this
matching were approximately $6.4 million, $6.0 million and $4.7 million for
1999, 1998 and 1997, respectively.

Note 13 - Income Taxes

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

<TABLE>
<CAPTION>
                                                 1999           1998            1997
                                                 ----           ----            ----
<S>                                          <C>            <C>             <C>
Included in Income Taxes:
  Current         - federal                  $ 91,825       $113,990        $ 88,531
                  - foreign                    15,160         12,208           9,055
                  - state                      22,514         23,642          19,545
  Deferred        - federal - net               7,173        (25,657)         10,435
                  - state - net                 4,868         (5,267)          1,539
Deferred investment tax credit                     --             --             102
Amortization of investment tax credit          (8,016)        (8,087)         (8,378)
                                             --------       --------        --------

Total                                        $133,524       $110,829        $120,829
                                             ========       ========        ========
</TABLE>


                                      101
<PAGE>

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

                                                             1999           1998
                                                             ----           ----

Deferred tax liabilities:
  Depreciation and other
     plant-related items                                 $716,064       $683,023
  Other liabilities                                        44,117         39,550
                                                         --------       --------
                                                          760,181        722,573
                                                         --------       --------

Deferred tax assets:
  Investment tax credit                                    34,642         37,878
  Income taxes due to customers                            39,300         43,021
  Deferred income                                          11,294         11,626
  Accrued liabilities not currently
     deductible and other                                  89,065         61,945
                                                         --------       --------
                                                          174,301        154,470
                                                         --------       --------

Net deferred income tax liability                        $585,880       $568,103
                                                         ========       ========

At December 31, 1999, there were $89.9 million of net operating loss
carryforwards related to discontinued operations. These carryforwards, which
expire in 2000 through 2009, are subject to an annual limitation of
approximately $6 million under provisions of the Internal Revenue Code, and
realization is dependent upon generating sufficient taxable income prior to
their expiration. At December 31, 1999 and 1998, the Company recorded valuation
allowances related to these deferred tax assets of $22.8 million and $25.6
million, respectively. Unamortized goodwill will be reduced if unrecorded net
operating loss carryforwards are realized.

A reconciliation of differences between the statutory U.S. federal income tax
rate and the Company's effective income tax rate as a percentage of income from
continuing operations before income taxes and preferred dividends follows:

<TABLE>
<CAPTION>
                                                              1999       1998       1997
                                                              ----       ----       ----
<S>                                                         <C>        <C>        <C>
Statutory federal income tax rate                             35.0%      35.0%      35.0%
State income taxes net of federal benefit                      4.9        4.4        3.9
Effect of foreign operations including foreign tax credit       .9        1.8        1.1
Investment and other tax credits                              (3.9)      (3.6)      (3.1)
Nondeductible merger expenses                                   --        4.7         --
Other differences - net                                       (1.4)      (2.2)      (0.9)
                                                            ------     ------     ------

Effective income tax rate                                     35.5%      40.1%      36.0%
                                                            ======     ======     ======
</TABLE>


                                      102
<PAGE>

Note 14 - Other Income and Deductions

Other income and deductions consisted of the following at December 31 (in
thousands of $):

                                                   1999        1998         1997
                                                   ----        ----         ----

Income from leveraged leases                   $  3,205    $  4,273     $  3,974
Interest and dividend income                      9,803      10,552       10,159
Gains (losses) on disposals - net                 3,801      (4,942)       7,083
Other                                             2,496      (1,783)         467
                                               --------    --------     --------

Total other income and (deductions)            $ 19,305    $  8,100     $ 21,683
                                               ========    ========     ========

Note 15 - Capital Stock

Changes in shares of common stock outstanding are shown in the table below (in
thousands). The amounts in the table have been restated to reflect the
merger-related exchange of 1.67 shares of LG&E Energy common stock for each
share of KU Energy common stock.

                                                   1999        1998         1997
                                                   ----        ----         ----

Outstanding January 1                           129,677     129,683      129,497
Issues under the Employee
  Common Stock Purchase
  Plan ($1,613)                                      --          --           77
Issues under the Omnibus
  Long-Term Incentive Plan ($2,195)                  --          --          109
Merger-related buy-back of
  fractional shares                                  --          (6)          --
                                               --------    --------     --------

Outstanding December 31                         129,677     129,677      129,683
                                               ========    ========     ========

The Company's shareholders approved an increase in the Company's authorized
shares of common stock from 125.0 million to 300.0 million in October 1997 in
conjunction with the proposed merger with KU Energy. This increase was effective
at the consummation of the merger on May 4, 1998.

The Company has an Omnibus Long-Term Incentive Plan, under which nonqualified
stock options, performance units and stock appreciation rights have been granted
to key personnel. Pursuant to an amendment approved by the Company's
shareholders in April 1999, a total of approximately 6.5 million shares,
including prior issuances, of common stock may be issued under the plan.
Performance units are paid out on a three-year rolling basis in 50% stock and
50% cash based on Company performance. Directors of the Company receive stock
options pursuant to the Stock Option Plan for Non-Employee Directors. A total of
500,000 shares of common stock may be issued under this plan. Each option
entitles the holder to acquire one share of the Company's stock no earlier than
one year from the date granted. The options are granted at market value and
generally expire 10 years from the date granted. In October 1997, the Company
announced a repurchase program authorizing the repurchase of up to 1.0 million
shares of its common stock to be used for, among other things, benefit and
compensation plans, including the Long-Term Plan, and has funded the plans via
open market purchases since that date. The Company also repurchased
approximately 935,000 shares during 1999 in connection with the funding of its
acquisition of CRC.


                                      103
<PAGE>

A summary of the status of the Company's nonqualified stock options follows:

<TABLE>
<CAPTION>
                                              Outstanding               Exercisable
                                              -----------               -----------
                                                      Weighted-                  Weighted-
                                                       Average                    Average
                                         Options         Price      Options         Price
                                         -------         -----      -------         -----
<S>                                    <C>          <C>           <C>          <C>
As of December 31, 1996                  864,344         19.57      443,074         18.09
  Options granted and
     exercisable                         394,945         24.15      352,966         21.22
  Options exercised                      (87,568)        18.97      (87,568)        18.97
  Options cancelled                      (77,100)        23.04           --            --
                                      ----------    ----------   ----------    ----------
As of December 31, 1997                1,094,621         21.01      708,472         19.54
  Options granted and
     exercisable                         901,588         24.19      437,373         24.19
  Options exercised                     (153,456)        20.42     (153,456)        20.42
  Options cancelled                     (100,284)        23.05           --            --
                                      ----------    ----------   ----------    ----------
As of December 31, 1998                1,742,469         22.60      992,389         21.46
  Options granted and
     exercisable                         660,641         25.75      732,080         24.11
  Options exercised                      (20,341)        20.89      (20,341)        20.89
  Options cancelled                      (56,481)        24.36      (28,628)        23.58
                                      ----------    ----------   ----------    ----------

As of December 31, 1999                2,326,288    $    23.46    1,675,500    $    22.59
                                      ==========    ==========   ==========    ==========
</TABLE>

Common stock equivalents resulting from the options granted under both the
Long-Term Plan and the Directors' Plan would not have a material dilutive effect
on reported earnings per share.

The Company has a Shareholders' Rights Plan designed to protect shareholders'
interests in the event the Company is ever confronted with an unfair or
inadequate acquisition proposal. Pursuant to the plan, each share of common
stock has one-third of a "right" entitling the holder to purchase from the
Company one one-hundredth of a share of new preferred stock of the Company under
certain circumstances. The holders of the rights will, under certain conditions,
also be entitled to purchase either shares of common stock of LG&E Energy or
common stock of the acquirer at a reduced percentage of market value. The rights
will expire on December 19, 2000.

In December 1997, Inversora, a subsidiary of the Company that holds part of the
Company's interest in Centro, issued 302,364 shares of preferred stock to
unaffiliated parties. The stock has a nominal value of $10 per share and a
variable dividend consisting of 5% of Inversora's annual net income. Inversora
can redeem the shares at the nominal value upon shareholder approval. During
1998, Inversora redeemed 200,275 shares of preferred stock. During 1999,
Inversora redeemed the remaining 102,089 shares.


                                      104
<PAGE>

Note 16 - Long-Term Debt

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 issued by LG&E and KU, and medium-term notes issued by Capital
Corp. Interest rates and maturities in the table below are for the amounts
outstanding at December 31, 1999.

<TABLE>
<CAPTION>
                                                            Weighted
                                                             Average
                                           Stated           Interest                      Principal
                                   Interest Rates               Rate      Maturities        Amounts
                                   --------------               ----      ----------        -------
<S>                                 <C>                        <C>       <C>            <C>
LG&E                                5.45% - 7.63%              6.44%     2002 - 2023    $   380,600
KU                                  5.75% - 8.55%              7.02%     2003 - 2027        430,830
Capital Corp.                       5.75% - 10.5%              6.48%     2001 - 2011        487,985
                                                               ----                      ----------
  Total long-term debt                                         6.65%                     $1,299,415
                                                               ====                      ==========

LG&E (pollution control bonds)           Variable              3.67%     2013 - 2027     $  246,200
KU (pollution control bonds)             Variable              5.40%            2024         54,000
KU (first mortgage bond)                    5.95%              5.95%            2000         61,500
Capital Corp. (medium-term notes)        Variable              6.48%            2000         50,110
                                                               ----                      ----------
  Total current portion of
     long-term debt                                            6.15%                     $  411,810
                                                               ====                      ==========
</TABLE>

Under the provisions for LG&E's and 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 were 3.98% and 3.35% for LG&E's and
KU's bonds, respectively.

Maturities of long-term debt outstanding (principal amounts stated in thousands
of $) at December 31, 1999, are summarized below.

         2001                                        $   37,873
         2002                                            20,091
         2003                                           104,623
         2004                                           150,000
         2005                                                --
         Thereafter                                     986,828
                                                     ----------
         Total                                       $1,299,415
                                                     ==========

In December 1999, LG&E notified bondholders of its intent to exercise its call
option on its $20.0 million 7.50% First Mortgage Bonds due July 1, 2002. The
bonds were redeemed in January 2000 utilizing proceeds from the issuance of
commercial paper.

In May 1999, Capital Corp. issued $150 million of medium-term notes due May 2004
with an effective rate of 6.13%.

In September 1999, Capital Corp. issued $50.0 million of floating-rate notes
under its medium-note program that mature in September 2000. The notes bear
interest at a rate of one-month LIBOR plus 10 basis points.

In November 1998, Capital Corp. issued $150 million of Reset Put Securities due
2011 with an effective rate of 5.4% through October 2001. As of November 1,
2001, the securities will be subject to automatic purchase by a


                                      105
<PAGE>

remarketing agent and either the interest rate will be reset or the bonds will
be repurchased by Capital Corp.

In June 1998, $20 million of LG&E's First Mortgage Bonds matured and were
retired.

In February 1998, Capital Corp. issued $150 million of medium-term notes due in
January 2008, with an effective rate of 6.82%.

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 and KU's utility plants are pledged as security for
its First Mortgage Bonds. LG&E's indenture, as supplemented, provides in
substance that, under certain specified conditions, portions of retained
earnings will not be available for the payment of dividends on common stock. No
portion of retained earnings is presently restricted by this provision.

Note 17 - Notes Payable

Capital Corp. had outstanding commercial paper of $329.5 million at December 31,
1999, at a weighted-average interest rate of 5.97%. Capital Corp. had notes
payable of $365.1 million at December 31, 1998, at a weighted-average interest
rate of 5.19%.

LG&E's short-term financing requirements are satisfied through the sale of
commercial paper. LG&E had outstanding commercial paper of $120.1 million at
December 31, 1999, at a weighted-average interest rate of 6.02%. LG&E had no
short-term borrowings at December 31, 1998.

KU's short-term financing requirements are satisfied through the sale of
commercial paper. KU had no short-term borrowings at December 31, 1999, and
1998.

At December 31, 1999, the Companies had lines of credit in place totaling $900
million ($200 million for LG&E and $700 million for Capital Corp.) for which
they pay commitment or facility fees. The LG&E credit facility provides support
of commercial paper borrowings. The Capital Corp. facility provides for
short-term borrowing, letter of credit issuance, and support of commercial-paper
borrowings. Unused capacity under these lines totaled $395.6 million after
considering the commercial paper support and approximately $51.7 million in
letters of credit securing on- and off-balance sheet commitments. The Capital
Corp. and LG&E credit lines will expire at various times from 2000 through 2002.
Management expects to renegotiate these lines when they expire. The KU credit
facilities that provided for short-term borrowing and support of commercial
paper borrowing expired on December 31, 1999.

The lenders under the credit facilities, commercial paper program, and
medium-term notes for Capital Corp. are entitled to the benefits of a Support
Agreement with LG&E Energy. The Support Agreement states, in substance, that
LG&E Energy will provide Capital Corp. with the necessary funds and financial
support to meet their obligations under the credit facilities, commercial paper
program, and medium-term notes.

Note 18 - Commitments and Contingencies

Construction Program

The Company had commitments, primarily in connection with the construction
program of LG&E and KU,


                                      106
<PAGE>

aggregating approximately $28 million at December 31, 1999. LG&E's construction
expenditures for 2000 and 2001 are estimated to total approximately $401
million. KU's construction expenditures for the same period are estimated to
total approximately $324 million. Non-utility construction expenditures for the
same two-year period are estimated to be $123 million.

Letters of Credit

Capital Corp. has provided letters of credit issued to third parties to secure
certain off-balance sheet obligations (including contingent obligations) of its
subsidiaries. The letters of credit securing such obligations totaled
approximately $27.9 million and $30.7 million at December 31, 1999 and 1998,
respectively. These letters of credit are subject to Support Agreements as more
fully described in Note 17, Notes Payable.

Capital Corp. has provided a guarantee of a lease obligation to a third party.
The obligation totaled $4.9 million and $7.6 million at December 31, 1999 and
1998, respectively.

Projects

Springfield Municipal Contract. In January 2000, LEM reached a settlement with
CWLP regarding a suit previously pending before the United States District Court
for the Western District of Kentucky. Pursuant to the settlement, CWLP paid LEM
approximately $16.6 million, $4.0 million less than expected. The dispute
involved CWLP's 1998 failure to sell electric energy to LEM pursuant to an
existing contract between the parties.

Monroe Project. In 1999, a subsidiary of the Company entered into an operating
lease wherein it agreed to lease three combustion turbines and related
facilities to be installed and constructed at a 450 Mw natural gas-fired
merchant power generation plant being developed by the Company in Monroe,
Georgia. The lease has a five year term, but no rent is payable until the
turbines have been completed and installed, currently anticipated in June 2001.
At the end of the lease term, the Company may purchase the leased assets or
assist the lessor in selling them. If the assets are sold, the Company is
obligated to make up any deficiency between the lease balance and the proceeds
subject to a cap. The total value of assets under the lease is expected to be
approximately $175 million.

Texas Project. In October 1999, a subsidiary of the Company entered into an
initial agreement to purchase six natural gas combustion turbines and is
negotiating terms of a definitive agreement. In connection therewith, the
Company is pursuing initial development of a possible 1,600 Mw generation
facility in Anderson County, Texas. Should the plant be developed as presently
planned, the aggregate cost is estimated to be approximately $790 million,
portions of which may be independently financed or shared with eventual outside
partners.

Roanoke Valley I. The Company owns a 50% interest in WLP, the owner of the
Roanoke Valley I facility which sells electric power to VEPCO pursuant to a PPA.
From May 1994 through December 1999, VEPCO withheld approximately $19.8 million
of capacity payments during periods of forced outages. In October 1994, WLP
filed a complaint against VEPCO seeking damages related to the withholding of
such payments. In June 1997, the Virginia Supreme Court reversed a lower court
ruling granting summary judgment in favor of VEPCO and remanded the case for a
trial which occurred in October 1998. In November 1998, the Circuit Court for
the City of Richmond, Virginia issued a decision awarding WLP approximately $19
million, plus interest until paid, and ruled WLP was entitled to receive future
capacity payments for eligible forced outages during the remainder of the PPA
term. In January 1999, VEPCO filed a notice of appeal to the Supreme Court of
Virginia regarding the Circuit Court decision. Appellate briefs were filed by
the parties during1999 and a hearing was held in January 2000. A decision is
anticipated in the first half of 2000. Pending resolution of all appeals by
VEPCO, the Company has not recognized any income on its 50% portion of the
capacity payments


                                      107
<PAGE>

being withheld by VEPCO. In the Company's opinion, WLP is entitled to recover
the withheld capacity payments, as well as the future capacity payments during
forced outages. The Company does not expect the ultimate resolution of this
matter to have a material adverse effect on its results of operations or
financial condition.

Southampton. In October 1998, LG&E-Westmoreland Southampton and VEPCO entered
into a settlement agreement which resolved issues pending before the FERC
regarding the status of the Southampton as a QF under PURPA for the year 1992,
including the possible payment of FERC-ordered refunds by Southampton of
capacity payments previously received from VEPCO for such year. The settlement,
which has been approved by the FERC, provides for, among other items, payments
by Southampton to VEPCO of $1 million annually for the years 1999-2001, followed
by a reduction in capacity payments from VEPCO to Southampton by $500,000
annually for the years 2002-2008. Following 2008, VEPCO may elect to terminate
its power purchases from Southampton or continue to receive the annual reduction
in capacity payments for the remainder of the power purchase agreement. The
Company has also been notified that its partners in the Southampton partnership
are disputing their responsibilities for their share of the refunds and are
asserting that the Company should bear full responsibility for such amounts. In
December 1999, the Company settled with one of its partners regarding its claims
and is currently negotiating these matters with the remaining partner. The
Company does not believe that the disputes with its partners, including the
settlement already achieved with the one partner, will have a material adverse
effect on its results of operations or financial condition.

Gregory Project. In June 1998, LPI entered into a partnership with Columbia
Electric Corporation for the development of a natural gas-fired cogeneration
project in Gregory, Texas, providing electricity and steam equivalent of 550 Mw.
Initial construction commenced in August 1998 and non-recourse financing for a
majority of the construction and other costs was obtained in November 1998. The
project will sell steam and a portion of its electric output to Reynolds Metals
Company. A medium-term fixed-price contract has also been entered into with a
third party for a portion of the remaining electric output. The project is
expected to begin commercial operation in the summer of 2000 at an anticipated
total project cost of approximately $240 million. The Company's equity
contribution is expected to be approximately $30 to $35 million in connection
with its 50% interest in the project.

Windpower Partners 1994. WPP 94 is a windpower generation facility in Texas, in
which the Company has a 25% interest. Since September 1997 WPP 94 has not made
its semiannual payments, due in March and September each year, to Hancock under
certain Notes issued by WPP 94 to Hancock. WPP 94 and Hancock have entered into
cash sweep and standstill agreements, with the standstill term currently
extended through March 2001, regarding the Notes and are presently engaged in
discussions concerning a possible restructuring of WPP 94's debt obligations.
Because of the continuing nature of the negotiations, the Company is not able to
predict the outcome of this event. The Company wrote off its aggregate
investment in WPP94 in 1998 and does not expect the ultimate resolution of this
matter to have a material effect on its results of operations or financial
condition.

Kenetech Bankruptcy. In May 1996, Kenetech filed in the United States Bankruptcy
Court in the Northern District of California for protection under Chapter 11 of
the United States Bankruptcy Code seeking, among other things, to restructure
certain contractual commitments between Kenetech and its subsidiaries, and
various windpower projects located in the U.S. and abroad. Included in these
projects are the WPP 93, WPP 94 and Tarifa wind projects in which the Company
has invested, collectively, approximately $31 million. As part of the bankruptcy
proceeding, Kenetech is also seeking to void certain warranty commitments made
to the owners of those projects with respect to the operation and output of the
facilities, and the repair and replacement of the windpower generation equipment
located there. In January 1997, the projects filed their respective breach of
contract and other claims against Kenetech in the bankruptcy proceeding. In
April 1999, the Bankruptcy Court approved a final plan of reorganization. Three
initial distributions pursuant to the Plan were made during 1999


                                      108
<PAGE>

of which the Company's share was approximately $7.45 million, which funds were
primarily used directly by the projects to pay unpaid interest and principal on
debt of the projects and legal fees. The WPP93 and WPP94 projects are discussing
a restructuring of their debt with their creditors, including certain revisions
to ownership structure and operating arrangements. Final bankruptcy plan
distributions and completion of the project restructurings are currently
anticipated during the second quarter of 2000. While the Company is unable to
predict the outcome of these events, it does not expect the ultimate resolution
of the bankruptcy or the restructurings to have a material adverse effect on its
results of operations or financial condition.

Calgary. In November 1996, LG&E Natural Canada Inc., a subsidiary of LEM,
initiated action in the Court of the Queens Bench of Alberta, Calgary against a
former employee. An amended statement of claim was filed in the Calgary action
in December 1996, naming additional parties. These lawsuits were filed as a
result of LEM's discovery in the fourth quarter of 1996 that the former employee
had engaged in unauthorized transactions. Counterclaims have been filed seeking
damages of approximately $40 million for, among other things, defamation and
breach of contract. In the second quarter of 1997, the Company received an
insurance settlement of $7.6 million (net of expenses) related to the losses.
Discovery proceedings in this action have continued during 1999. The Company
does not expect the ultimate resolution of this matter to have a material
adverse effect on its results of operations or financial condition.

Operating Leases

The Company leases office space, office equipment and vehicles and accounts for
these leases as operating leases. See also Note 5 for discussion of the Big
Rivers Electric Corporation operating lease. Total lease expense for 1999, 1998
and 1997, was $37.1 million, $21.7 million and $6.7 million, respectively. The
future minimum annual lease payments under lease agreements for years subsequent
to December 31, 1999, are as follows (in thousands of $):

         2000                                  $ 19,574
         2001                                    42,735
         2002                                    47,605
         2003                                    46,896
         2004                                   216,448
         Thereafter                             593,028
                                               --------
         Total                                 $966,286
                                               ========

Future minimum annual lease payments have been reduced by rental payments to be
received from noncancelable subleases of approximately $1.9 million in 2000, and
$1.3 million in 2001.

In December 1999, LG&E and KU entered into an 18-year cross-border lease of its
two combustion turbines recently installed at KU's Brown facility. The
utilities' obligations were defeased upon consummation of the cross-border
lease. The transaction produced a pre-tax gain of approximately $3.1 million
which has been deferred pending resolution of rate treatment by the Kentucky
Commission.

LG&E Power Monroe LLC, a subsidiary of Capital Corp., entered into a five-year
operating lease expiring on December 31, 2004, to finance the purchase and
construction of a 450-Mw gas-fired peaking facility in Monroe, Georgia. No lease
payments are due during construction and payments will be based on commercial
paper rates upon completion of the plant. Currently, the plant is expected to be
completed by mid-2001. The cost of the leased assets is expected to total
approximately $175 million.


                                      109
<PAGE>

Environmental

The 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,
while KU met its Phase I SO2 requirements primarily through installation of a
scrubber on Ghent Unit 1. The Company's combined strategy for Phase II,
commencing 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. LG&E, KU, and WKE met the NOx emission
requirements of the Act through installation of low-NOx burner systems. The
Company'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. The Company 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
significant additional reductions in NOx emissions by May 2003, in order to
mitigate alleged ozone transport to the Northeast. While each of the 22 states
covered by the rule is free to allocate its assigned NOx reductions among
various emissions sectors as it deems appropriate, the regulation may ultimately
require electric generating units to reduce their NOx emissions to 0.15
lb./Mmbtu - an 85% reduction from 1990 levels. In related proceedings in
response to petitions filed by various Northeast states, in December 1999, EPA
issued a final rule directing similar NOx reductions from a number of
specifically named electric generating units including all LG&E and KU stations
in the eastern half of Kentucky. Additional petitions currently pending before
EPA may potentially result in orders encompassing the remaining KU and WKE
stations. Several states, various labor and industry groups, and individual
companies have appealed both EPA rulings to the U.S. Court of Appeals for the
Washington D.C. Circuit. Management is currently unable to determine the outcome
or exact impact of this matter until such time as the courts rule on the pending
legal challenges and the states implement the final regulatory mandate. However,
if the 0.15 lb. target is ultimately imposed, LG&E, KU, and WKE and the
independent power projects in which the Company has an interest will be required
to incur significant capital expenditures and increased operation and
maintenance costs for additional controls.

Subject to further study, analysis, and the outcome of pending litigation
against the EPA, the Company estimates that it may incur approximate capital
costs for NOx compliance ranging from $300 million to reduce emissions to the
level of 0.25 lb./Mmbtu (Commonwealth of Kentucky's proposed NOx compliance
level) to $550 million to reduce emissions to the level of 0.15 lb./Mmbtu
(current EPA regulations). These costs would generally be incurred beginning in
2000. The Company believes its costs in this regard to be comparable to those of
similarly situated utilities with like generation assets. LG&E and KU anticipate
that such capital and operating costs are the type of costs that are eligible
for recovery from customers under their environmental surcharge mechanisms and
believe that a significant portion of such costs could be recovered. However,
Kentucky Commission approval is necessary and there can be no guarantee of
recovery.

The Company is also addressing other air quality issues. First, the Company 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. The Company continues to monitor
EPA actions to challenge that ruling. Second, the Company was notified by
regulatory agencies that the Cane Run Station may be the source of a potential
exceedance of the NAAQS that could require the Company to incur additional
capital expenditures or accept certain emissions limitations. After reviewing
additional modeling information submitted by the Company, in January 2000, EPA
concluded that the Cane Run Station does not contribute to any potential NAAQS
exceedance and that no further action is required from the Company. Third, the
Company is working with regulatory authorities to review the effectiveness of
remedial measures aimed at controlling particulate emissions from its Mill Creek
Station. The Company previously settled a number of property damage claims from
adjacent residents and completed significant plant modifica-


                                      110
<PAGE>

tions as part of its ongoing capital construction program.

The Company 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. The Company has
completed the cleanup of a site owned by KU and reached agreements for other
parties to assume cleanup responsibility for two other sites formerly owned by
LG&E. In addition, the Company recently reached an agreement with the Kentucky
Division of Waste Management with respect to a third LG&E-owned site in which
the Company committed to impose certain property restrictions and conduct
additional monitoring in lieu of a cleanup. Based on currently available
information, management estimates that it will incur additional MGP costs of
less than $500,000. Accordingly, an accrual of $500,000 has been recorded in the
accompanying financial statements. With respect to other former MGP sites no
longer owned by the Company, the Company is unable to determine what, if any,
additional exposure or liability it may have as it lacks complete information on
current site conditions.

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, the Company commenced immediate spill
containment and recovery measures which prevented the spill from reaching the
Kentucky River. The Company 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. The Company is currently negotiating with the state
in an effort to reach a complete resolution of this matter. To date the Company
has incurred costs of approximately $1 million. The Company does not expect to
incur any material additional amounts.

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 2000-2004, which is expected to be approximately 7%
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 $172 million
of OMU bonds outstanding at December 31, 1999. The debt service is allocated to
KU based on its annual allocated share of capacity, which averaged approximately
46% in 1999.

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. See Note 9.

KU has several other contracts for purchased power during 2000 - 2004 of various
Mw capacities and for varying periods with a maximum entitlement at any time of
62 Mw.


                                      111
<PAGE>

The estimated future minimum annual payments under purchased power agreements
for the five years ended December 31, 2004, are as follows (in thousands of $):

         2000                                     $ 28,765
         2001                                       31,495
         2002                                       30,683
         2003                                       30,947
         2004                                       31,155
                                                  --------
         Total                                    $153,045
                                                  ========

Note 19 - Jointly Owned Electric Utility Plant

LG&E owns a 75% undivided interest in Trimble County Unit 1. Accounting for the
75% portion of the Unit, which the Kentucky Commission has allowed to be
reflected in customer rates, is similar to LG&E's accounting for other wholly
owned utility plants.

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

The following data represents shares of the jointly owned property:

<TABLE>
<CAPTION>
                                                              Trimble County
                                        LG&E             IMPA               IMEA            Total
                                        ----             ----               ----            -----
<S>                                   <C>               <C>                <C>             <C>
Ownership interest                       75%           12.88%             12.12%             100%
Mw capacity                           371.25            63.75              60.00           495.00

(in thousands of $):
Cost                                $546,497
Accumulated depreciation             140,972
                                    --------
Net book value                      $405,525
                                    ========

Construction work in progress
  (included above)                      $673
</TABLE>

Note 20 - Segments of Business and Related Information

Effective December 31, 1998, the Company adopted SFAS No. 131, Disclosure About
Segments of an Enterprise and Related Information. The Company's principal
business segments consist of LG&E's regulated electric and gas utility
operations, KU's regulated electric utility operations and its non-utility
operations, including its Power Operations, WKE, Argentine gas distribution and
other.


                                      112
<PAGE>

The All Other category consists of elimination entries, adjustments and other
corporate. The Company does not allocate all expenses from corporate to
reportable segments. International long-lived assets consist of the long-lived
assets of the Argentine gas distribution companies, the Company's investment in
the San Miguel project in Argentina (sold in February 1999), and its investment
in the Tarifa project in Spain. The Company acquired its interest in Gas BAN in
March 1999, and it acquired its interests in Centro and Cuyana in February 1997.
Financial data for business segments, revenues by product, and long-lived assets
by geographic area follow (in thousands of $):

<TABLE>
<CAPTION>
                                    Utility Operations                     Non-Utility Operations
                              --------------------------------  -------------------------------------------
                                                                     Inde-               Argentine                Elim.
                                                                   pendent     Western         Gas                 Adj.
                                  LG&E        LG&E          KU       Power    Kentucky     Distri-                 and       Consol-
Year                          Electric         Gas    Electric  Operations      Energy      bution    Other       Corp.       idated
----                          --------         ---    --------  ----------      ------      ------    -----       -----       ------
<S>                         <C>         <C>         <C>         <C>         <C>         <C>        <C>       <C>          <C>
1999

Revenues                    $  790,670  $  177,579  $  937,310  $   24,713  $  333,785  $  156,249 $329,552  $  (42,582)  $2,707,276

Depreciation and
  amortization                  83,619      13,602      89,922       2,893       3,850       9,964   14,081       1,387      219,318

Interest income                  2,898         536       5,001      10,297       1,326          --   10,746     (21,001)       9,803

Interest expense                35,384       6,427      41,860          --       5,429      16,315   44,399     (17,748)     132,066

Equity in unconsolidated
  ventures                          --          --          --      40,897          --       8,820       --          --       49,717

Income taxes                    57,389         891      58,019      21,388       4,041      10,943   (9,281)     (9,866)     133,524

Income (loss) from
  continuing operations        100,598       1,171     104,302      20,475      13,385      12,173   (2,266)    (13,575)     236,263

Total assets                 1,821,849     349,604   1,785,090      98,327     188,421     437,764  403,851      48,851    5,133,757

Construction expenditures      160,844      33,800     181,341         669      12,227      28,343   86,756    (121,349)     382,631
</TABLE>

<TABLE>
<CAPTION>
                                    Utility Operations                     Non-Utility Operations
                            ----------------------------------  -------------------------------------------
                                                                   Inde-               Argentine                   Elim.
                                                                 pendent     Western         Gas                    Adj.
                               LG&E        LG&E           KU       Power    Kentucky     Distri-                    and      Consol-
Year                       Electric         Gas     Electric  Operations      Energy      bution    Other          Corp.      idated
----                       --------         ---     --------  ----------      ------      ------    -----          -----      ------
<S>                      <C>         <C>          <C>         <C>         <C>         <C>         <C>        <C>          <C>
1998

Revenues                 $  658,510  $  191,545   $  810,114  $   24,157  $  128,519  $  148,162  $155,039   $  (29,800)  $2,086,246

Depreciation and
  amortization               79,867      13,312       86,657       4,633       1,345       8,973    10,792          871      206,450

Interest income               3,672         679        1,811       5,025          18       2,313    14,734      (17,700)      10,552

Interest expense             34,221       6,668       40,896           6       2,631      12,581    27,694      (15,308)     109,389

Equity in unconsolidated
  ventures                       --          --           --      71,297          --       2,501        --           --       73,798

Merger costs                 32,073          --       21,830          --          --          --        --       11,415       65,318

Income taxes                 48,415        (152)      49,444      24,432       2,442      10,030    (6,315)     (17,467)     110,829

Income (loss) from
  continuing operations      71,536       2,016       70,508      41,608       3,592       5,752    (9,802)     (26,538)     158,672

Total assets              1,734,221     332,789    1,746,209     163,663     176,166     346,305   175,661      148,104    4,823,118

Construction expenditures   105,837      32,509       91,992       4,242      17,549      14,977    70,892        5,630      343,628
</TABLE>


                                      113
<PAGE>

<TABLE>
<CAPTION>
                                    Utility Operations                     Non-Utility Operations
                              --------------------------------  -------------------------------------------
                                                                     Inde-               Argentine                Elim.
                                                                   pendent     Western         Gas                 Adj.
                                  LG&E        LG&E          KU       Power    Kentucky     Distri-                 and       Consol-
Year                          Electric         Gas    Electric  Operations      Energy      bution    Other       Corp.       idated
----                          --------         ---    --------  ----------      ------      ------    -----       -----       ------
<S>                         <C>         <C>         <C>         <C>         <C>         <C>        <C>       <C>          <C>
1997

Revenues                   $  615,159    $  231,011  $  716,410  $  19,622  $       --  $  127,182  $123,362   $     --   $1,832,746

Depreciation and
  amortization                 79,958        13,062      84,111      1,287          --       7,569     7,426        478      193,891

Interest income                 5,400           953       1,673      2,321          --       1,697     7,836     (9,721)      10,159

Interest expense               37,236         6,539      41,955         --          --      10,472    16,819     (8,594)     104,427

Equity in unconsolidated
  ventures                         --            --          --     20,526          --       2,411        --         --       22,937

Income taxes                   61,426         4,667      47,789     10,154          --       7,264       613    (11,084)     120,829

Income (loss) from
  continuing operations       104,349         4,339      83,457     17,795          --       4,860      (138)    (6,299)     208,363

Total assets                1,728,761       325,864   1,676,436    214,952          --     340,144    76,287    257,746    4,620,190

Construction expenditures      81,713        29,180      94,006         45          --       4,369    15,730        671      225,714
</TABLE>

Revenue By Product:

                                       Asset-Based
                 Retail        Retail       Energy
Year           Electric           Gas    Marketing        Other       Totals
----           --------           ---    ---------        -----       ------

1999         $1,220,048      $333,828     $826,446     $326,954   $2,707,276

1998          1,189,185       339,707      390,567      166,787    2,086,246

1997          1,173,275       358,193      158,294      142,984    1,832,746

Long-Lived Assets By Geographic Area:

                                         Inter-
Year                      Domestic     national       Totals
----                      --------     --------       ------

1999                    $4,011,839     $416,199   $4,428,038

1998                     3,876,640      299,444    4,176,084

1997                     3,647,358      360,106    4,007,464


                                      114
<PAGE>

Note 21 - Selected Quarterly Data (Unaudited)

Selected financial data for the four quarters of 1999 and 1998 are shown below.
Because of seasonal fluctuations in temperature and other factors, results for
quarters may fluctuate throughout the year.

(Thousands of $ except per share data)
                                                   Quarters Ended
                                     March        June   September   December
                                     -----        ----   ---------   --------
1999
Revenues                         $ 599,265   $ 623,657   $ 865,390  $ 618,964

Operating income                   117,364     111,689     172,163     93,379

Net income (loss):
Continuing operations               56,779      49,965      87,166     42,353
Gain (loss) on disposal of
  discontinued operations              788          --          --   (175,000)
                                 ---------   ---------   ---------  ---------
     Total                          57,567      49,965      87,166   (132,647)

Earnings per share of common
  stock (basic and diluted):
Continuing operations                  .44         .39         .67        .33
Gain on disposal of discon-
  tinued operations                     --          --          --      (1.35)
                                 ---------   ---------   ---------  ---------
     Total                             .44         .39         .67      (1.02)

1998
Revenues                         $ 480,564   $ 472,188   $ 629,176  $ 504,318

Operating income                    94,669      73,534     157,361     55,679

Net income (loss):
Continuing operations               46,218      13,003      78,854     20,597
Discontinued operations             (3,050)    (19,802)         --         --
Gain (loss) on disposal of dis-
  continued operations                  --    (225,000)        658        194
Cumulative effect of account-
  ing change                        (7,162)         --          --         --
                                 ---------   ---------   ---------  ---------
     Total                          36,006    (231,799)     79,512     20,791

Earnings per share of common
  stock (basic and diluted):
Continuing operations                  .36         .10         .61        .16
Discontinued operations               (.02)       (.16)         --         --
Loss on disposal of discon-
  tinued operations                     --       (1.73)         --         --
Cumulative effect of account-
  ing change                          (.06)         --          --         --
                                 ---------   ---------   ---------  ---------
     Total                             .28       (1.79)        .61        .16


                                      115
<PAGE>

Note 22 - Subsequent Events

On February 28, 2000, the Company announced that its Board of Directors
accepted an 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 the
Company's debt. Pursuant to the acquisition agreement, among other things,
LG&E Energy will become a wholly owned subsidiary of PowerGen and its U.S.
headquarters. The Utility Operations of the Company will continue their
separate identities and serve customers in Kentucky and Virginia under their
present names. The preferred stock and debt securities of the Utility
Operations will not be affected by this transaction resulting in the Utility
Operations' obligation to continue to file SEC reports. The acquisition is
expected to close 9 to 12 months from the announcement, shortly after all of
the conditions to consummation of the acquisition are met. Those conditions
include, without limitation, the approval of the holders of a majority of the
outstanding shares of common stock of each of LG&E Energy and PowerGen, the
receipt of all necessary governmental approvals and the making of all
necessary governmental filings, including approvals of various regulators in
Kentucky and Virginia under state utility laws, the approval of the FERC
under the FPA, the approval of the SEC under the PUHCA of 1935, and the
filing of requisite notifications with the Federal Trade Commission and the
Department of Justice under the Hart-Scott-Rodino Antitrust Improvements Act
of 1976, as amended, and the expiration of all applicable waiting periods
thereunder. Shareholder meetings to vote upon the approval of the acquisition
are expected to be held during the second quarter of 2000 for both LG&E
Energy and PowerGen. During the first quarter of 2000, the Company expensed
approximately $1.0 million relating to the PowerGen transaction. The
foregoing description of the acquisition does not purport to be complete and
is qualified in its entirety by reference to LG&E Energy's current reports on
Form 8-K, filed February 29, 2000, with the SEC.

On March 3, 2000, the U.S. Court of Appeals for the Washington D.C. Circuit
issued a final opinion upholding the NOx SIP call rule requiring electric
generating units to reduce their NOx emissions to 0.15 lb./Mmbtu by May 2003.
Some of the litigants will likely seek further judicial review of the ruling.

In March 2000, the Virginia Supreme Court, remanded the Company's case against
VEPCO, pertaining to capacity payments withheld from its Roanoke Valley I joint
venture, for a new trial. Since the Company has not recognized any revenue in
its financial statements the remand to the trial court will have no adverse
effect on the Company's financial results.

In the first quarter of 2000, the Company will take a restructuring charge of
approximately $15 million pre-tax relating to the reduction of approximately 250
positions and the integration of LG&E's and KU's operations, including combining
retail gas and electric operations, consolidation of customer service centers
and the redesigning various other processes.

The Kentucky Commission responded to the motions filed by the utilities for
computational and other errors made in Orders received on base rate reductions
in February 2000 by reducing KU's annual revenue reductions by $2.5 million and
granting rehearings for LG&E and KU on other issues.


                                      116
<PAGE>

                                LG&E Energy Corp.
                              REPORT OF MANAGEMENT

The management of LG&E Energy Corp. and subsidiaries is responsible for the
preparation and integrity of the consolidated 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.

The Company's financial statements have been audited by Arthur Andersen LLP,
independent public accountants. Management has made available to Arthur Andersen
LLP all the Company'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 the Company'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, 1999, did not
identify any material weaknesses in the design and operation of the Company'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 the Company, the Audit Committee meets regularly with the
Company's independent public accountants, internal auditors and management. The
Audit Committee reviews the results of the independent accountants' audit of the
consolidated 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.

LG&E Energy Corp. and subsidiaries maintain and internally communicate 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.


                                      117
<PAGE>

                       LG&E Energy Corp. and Subsidiaries
                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Shareholders of LG&E Energy Corp.:

We have audited the accompanying consolidated balance sheets and statements of
capitalization of LG&E Energy Corp. (a Kentucky corporation) and subsidiaries as
of December 31, 1999 and 1998, and the related consolidated statements of
income, retained earnings, cash flows and comprehensive income for each of the
three years in the period ended December 31, 1999. These financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of LG&E Energy Corp.
and subsidiaries as of December 31, 1999 and 1998, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1999, 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, 2000 (Except with respect
to the matters discussed in Note 22, as
to which the date is March 3, 2000.)


                                      118
<PAGE>

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

<TABLE>
<CAPTION>
                                                                                               Years Ended December 31
                                                                                      1999                 1998                 1997
                                                                                      ----                 ----                 ----
<S>                                                                              <C>                  <C>                  <C>
OPERATING REVENUES:
    Electric .........................................................           $ 792,405            $ 663,011            $ 614,532
    Gas ..............................................................             177,579              191,545              231,011
    Provision for rate refunds (Note 3) ..............................              (1,735)              (4,500)                  --
                                                                                 ---------            ---------            ---------
       Net operating revenues (Note 1) ...............................             968,249              850,056              845,543
                                                                                 ---------            ---------            ---------

OPERATING EXPENSES:
    Fuel for electric generation .....................................             159,129              154,683              149,463
    Power purchased ..................................................             169,573               50,176               17,229
    Gas supply expenses ..............................................             114,745              125,894              158,929
    Other operation expenses .........................................             154,667              163,584              150,750
    Maintenance ......................................................              58,119               52,786               47,586
    Depreciation and amortization ....................................              97,221               93,178               93,020
    Federal and state income taxes (Note 8) ..........................              57,774               56,307               64,081
    Property and other taxes .........................................              16,930               17,925               16,299
                                                                                 ---------            ---------            ---------
       Total operating expenses ......................................             828,158              714,533              697,357
                                                                                 ---------            ---------            ---------

Net operating income .................................................             140,091              135,523              148,186

Merger costs (Note 2) ................................................                  --               32,072                   --
Other income and (deductions) (Note 9) ...............................               4,141               10,991                4,277
Interest charges .....................................................              37,962               36,322               39,190
                                                                                 ---------            ---------            ---------

Net income ...........................................................             106,270               78,120              113,273

Preferred stock dividends ............................................               4,501                4,568                4,585
                                                                                 ---------            ---------            ---------

Net income available for common stock ................................           $ 101,769            $  73,552            $ 108,688
                                                                                 =========            =========            =========
</TABLE>

                         Statements of Retained Earnings
                                (Thousands of $)

<TABLE>
<CAPTION>
                                                                                               Years Ended December 31
                                                                                      1999                 1998                 1997
                                                                                      ----                 ----                 ----
<S>                                                                              <C>                  <C>                  <C>
Balance January 1 ....................................................           $ 247,462            $ 258,910            $ 209,222
Add net income .......................................................             106,270               78,120              113,273
                                                                                 ---------            ---------            ---------
                                                                                   353,732              337,030              322,495
                                                                                 ---------            ---------            ---------

Deduct: Cash dividends declared on stock:
             5% cumulative preferred .................................               1,075                1,075                1,075
             Auction rate cumulative preferred .......................               1,957                2,024                2,041
             $5.875 cumulative preferred .............................               1,469                1,469                1,469
             Common ..................................................              90,000               85,000               59,000
                                                                                 ---------            ---------            ---------
                                                                                    94,501               89,568               63,585
                                                                                 ---------            ---------            ---------

Balance December 31 ..................................................           $ 259,231            $ 247,462            $ 258,910
                                                                                 =========            =========            =========
</TABLE>

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


                                      119
<PAGE>

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

<TABLE>
<CAPTION>
                                                                                           Years Ended December 31
                                                                                  1999                 1998                 1997
                                                                                  ----                 ----                 ----
<S>                                                                          <C>                  <C>                  <C>
Net income available for common stock ................................       $ 101,769            $  73,552            $ 108,688

Unrealized holding losses on available-for-sale securities
    arising during the period ........................................            (402)                 (14)                (426)

Reclassification adjustment for realized gains on
    available-for-sale securities included in net income .............              --                   --                  188
                                                                             ---------            ---------            ---------

Other comprehensive income (loss) before tax .........................            (402)                 (14)                (238)

Income tax (expense) benefit related to items of other
    comprehensive income .............................................             163                  (18)                 119
                                                                             ---------            ---------            ---------

Comprehensive income .................................................       $ 101,530            $  73,520            $ 108,569
                                                                             =========            =========            =========
</TABLE>

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


                                      120
<PAGE>

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

<TABLE>
<CAPTION>
                                                                                                                 December 31
                                                                                                             1999               1998
                                                                                                       ----------         ----------
<S>                                                                                                    <C>                <C>
ASSETS:
Utility plant, at original cost:
    Electric .................................................................................         $2,396,707         $2,268,860
    Gas ......................................................................................            365,128            339,647
    Common ...................................................................................            141,009            131,271
                                                                                                       ----------         ----------
                                                                                                        2,902,844          2,739,778
    Less:  reserve for depreciation ..........................................................          1,215,032          1,144,123
                                                                                                       ----------         ----------
                                                                                                        1,687,812          1,595,655
    Construction work in progress ............................................................            162,995            156,361
                                                                                                       ----------         ----------
                                                                                                        1,850,807          1,752,016
                                                                                                       ----------         ----------

Other property and investments - less reserve ................................................              1,224              1,154

Current assets:
    Cash and temporary cash investments ......................................................             54,761             31,730
    Marketable securities (Note 6) ...........................................................              6,936             17,851
    Accounts receivable - less reserve of $1,233 in 1999 and $1,399 in 1998 ..................            113,859            142,580
    Materials and supplies - at average cost:
       Fuel (predominantly coal) .............................................................             17,350             23,993
       Gas stored underground ................................................................             38,780             33,485
       Other .................................................................................             35,010             33,103
    Prepayments and other ....................................................................              2,775              2,285
                                                                                                       ----------         ----------
                                                                                                          269,471            285,027
                                                                                                       ----------         ----------

Deferred debits and other assets:
    Unamortized debt expense .................................................................              5,607              5,919
    Regulatory assets (Note 3) ...............................................................             31,443             37,643
    Other ....................................................................................             12,900             22,878
                                                                                                       ----------         ----------
                                                                                                           49,950             66,440
                                                                                                       ----------         ----------
                                                                                                       $2,171,452         $2,104,637
                                                                                                       ==========         ==========
CAPITAL AND LIABILITIES:
Capitalization (see statements of capitalization):
    Common equity ............................................................................         $  683,376         $  671,846
    Cumulative preferred stock ...............................................................             95,328             95,328
    Long-term debt (Note 10) .................................................................            380,600            626,800
                                                                                                       ----------         ----------
                                                                                                        1,159,304          1,393,974
                                                                                                       ----------         ----------
Current liabilities:
    Current portion of long-term debt ........................................................            246,200                 --
    Notes payable ............................................................................            120,097                 --
    Accounts payable .........................................................................            113,008            133,673
    Provision for rate refunds ...............................................................              8,962             13,261
    Dividends declared .......................................................................             24,236             23,168
    Accrued taxes ............................................................................             23,759             31,929
    Accrued interest .........................................................................              9,265              8,038
    Other ....................................................................................             15,725             15,242
                                                                                                       ----------         ----------
                                                                                                          561,252            225,311
                                                                                                       ----------         ----------
Deferred credits and other liabilities:
    Accumulated deferred income taxes (Notes 1 and 8) ........................................            255,910            254,589
    Investment tax credit, in process of amortization ........................................             67,253             71,542
    Accumulated provision for pensions and related benefits (Note 7) .........................             38,431             59,529
    Customers' advances for construction .....................................................             11,104             10,848
    Regulatory liability (Note 3) ............................................................             58,726             63,529
    Other ....................................................................................             19,472             25,315
                                                                                                       ----------         ----------
                                                                                                          450,896            485,352
                                                                                                       ----------         ----------
Commitments and contingencies (Note 12)
                                                                                                       $2,171,452         $2,104,637
                                                                                                       ==========         ==========
</TABLE>

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


                                      121
<PAGE>

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

<TABLE>
<CAPTION>
                                                                                              Years Ended December 31
                                                                                   1999                 1998                 1997
                                                                                   ----                 ----                 ----
<S>                                                                             <C>                  <C>                  <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
    Net income .......................................................          $ 106,270            $  78,120            $ 113,273
    Items not requiring cash currently:
       Depreciation and amortization .................................             97,221               93,178               93,020
       Deferred income taxes - net ...................................             (5,279)               2,747               (3,495)
       Investment tax credit - net ...................................             (4,289)              (4,258)              (4,240)
       Other .........................................................              6,924                5,534                4,640
    Change in certain net current assets:
       Accounts receivable ...........................................             28,721              (17,708)              (9,728)
       Materials and supplies ........................................               (559)                 423               (8,492)
       Accounts payable ..............................................            (20,665)              34,779                1,416
       Provision for rate refunds ....................................             (4,299)                  13               (4,263)
       Accrued taxes .................................................             (8,170)              13,206                6,741
       Accrued interest ..............................................              1,227                   22               (1,978)
       Prepayments and other .........................................                 (7)                 976                1,333
    Other ............................................................            (16,602)              18,679               (3,188)
                                                                                ---------            ---------            ---------
       Net cash flows from operating activities ......................            180,493              225,711              185,039
                                                                                ---------            ---------            ---------

CASH FLOWS FROM INVESTING ACTIVITIES:
    Purchases of securities ..........................................             (1,144)             (17,397)             (18,529)
    Proceeds from sales of securities ................................             11,662               18,841                2,544
    Construction expenditures ........................................           (194,644)            (138,345)            (110,893)
                                                                                ---------            ---------            ---------
       Net cash flows from investing activities ......................           (184,126)            (136,901)            (126,878)
                                                                                ---------            ---------            ---------

CASH FLOWS FROM FINANCING ACTIVITIES:
    Short-term borrowing .............................................            120,097                   --                   --
    Issuance of first mortgage bonds and pollution control bonds .....                 --                   --               69,776
    Retirement of first mortgage bonds and pollution control bonds ...                 --              (20,000)             (71,693)
    Payment of dividends .............................................            (93,433)             (87,552)             (62,564)
                                                                                ---------            ---------            ---------
       Net cash flows from financing activities ......................             26,664             (107,552)             (64,481)
                                                                                ---------            ---------            ---------

Change in cash and temporary cash investments ........................             23,031              (18,742)              (6,320)

Cash and temporary cash investments at beginning of year .............             31,730               50,472               56,792
                                                                                ---------            ---------            ---------

Cash and temporary cash investments at end of year ...................          $  54,761            $  31,730            $  50,472
                                                                                =========            =========            =========

Supplemental disclosures of cash flow information:
     Cash paid during the year for:
       Income taxes ..................................................          $  76,761            $  40,334            $  63,421
       Interest on borrowed money ....................................             33,507               34,245               39,582
</TABLE>

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


                                      122
<PAGE>

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

<TABLE>
<CAPTION>
                                                                                               December 31
                                                                                         1999               1998
                                                                                         ----               ----
<S>                                                                                  <C>                <C>
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)
    Unrealized gain (loss) on marketable securities, net of income
       taxes ($128) in 1999 and $34 in 1998 (Note 6) .......................               (189)                50
    Retained earnings ......................................................            259,231            247,462
                                                                                     ----------         ----------

                                                                                        683,376            671,846
                                                                                     ----------         ----------
</TABLE>

CUMULATIVE PREFERRED STOCK:
    Redeemable on 30 days notice by LG&E

<TABLE>
<CAPTION>
                                                           Shares           Current
                                                         Outstanding   Redemption Price
                                                         -----------   ----------------
<S>                                                        <C>              <C>          <C>                      <C>
    $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          104.70           25,000                   25,000
    Preferred stock expense.........................................................         (1,179)                  (1,179)
                                                                                         ----------               ----------

                                                                                             95,328                   95,328
                                                                                         ----------               ----------

LONG-TERM DEBT (Note 10):
    First mortgage bonds -
       Series due July 1, 2002, 7 1/2%..............................................         20,000                   20,000
       Series due August 15, 2003, 6%...............................................         42,600                   42,600
       Pollution control series:
           P due June 15, 2015, 7.45%...............................................         25,000                   25,000
           Q due November 1, 2020, 7 5/8%...........................................         83,335                   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
                                                                                         ----------               ----------
              Total first mortgage bonds............................................        506,800                  506,800
    Pollution control bonds (unsecured) -
       Jefferson County Series due September 1, 2026, variable......................         22,500                   22,500
       Trimble County Series due September 1, 2026, variable........................         27,500                   27,500
       Jefferson County Series due November 1, 2027, variable.......................         35,000                   35,000
       Trimble County Series due November 1, 2027, variable.........................         35,000                   35,000
                                                                                         ----------               ----------
           Total unsecured pollution control bonds..................................        120,000                  120,000
                                                                                         ----------               ----------

       Total bonds outstanding......................................................        626,800                  626,800

       Less current portion of long-term debt.......................................        246,200                       --
                                                                                         ----------               ----------

       Long-term debt...............................................................        380,600                  626,800
                                                                                         ----------               ----------

       Total capitalization.........................................................     $1,159,304               $1,393,974
                                                                                         ==========               ==========
</TABLE>

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


                                      123
<PAGE>

                       Louisville Gas and Electric Company
                          Notes to Financial Statements

Note 1 - Summary of Significant Accounting Policies

LG&E is a subsidiary of LG&E Energy. LG&E is a regulated public utility that is
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 energy services holding
company with wholly-owned subsidiaries consisting of LG&E, KU, Capital Corp.,
and LEM. All of the LG&E's Common Stock is held by LG&E Energy.

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 1999 were
3.4% (3.2% electric, 3.2% gas, and 7.1% common); for 1998 were 3.4% (3.2%
electric, 3.4% gas, and 7.4% common); and for 1997 were 3.4% (3.2% electric,
3.3% gas, and 6% common) of average depreciable plant.

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 $38.8 million and $33.5 million at
December 31, 1999 and 1998, 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 initially deferred and classified as
unrealized losses on marketable securities in common equity and then charged or
credited to other income and deductions when the securities are sold. See Note
4, Financial Instruments.

In connection with LG&E's marketing of power from owned generation assets,
exchange traded futures are used to hedge its exposure to price risk. Gains and
losses on these futures contracts are reflected in other income and deductions,
but are immaterial to LG&E's results of operations. At December 31, 1999, the
value of these futures contracts was not material to LG&E's financial position.

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


                                      124
<PAGE>

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, 1999
and 1998, were approximately $31.1 million and $25.1 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 1999 and 1998, 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. LG&E has not yet quantified all the effects of adopting SFAS No. 133
on the financial statements. However, SFAS No. 133 could increase the volatility
in earnings and other comprehensive income. The effect of this statement will be
recorded in cumulative effect of change in accounting when adopted. 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.

EITF No. 98-10, Accounting for Energy Trading and Risk Management Activities was
adopted effective January 1, 1999. The pronouncement requires that 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.

SOP 98-1, Accounting for the Costs of Computer Software Developed or Obtained
for Internal Use. Adopted


                                      125
<PAGE>

as of January 1, 1998, SOP 98-1 clarifies the criteria for capital or expense
treatment of costs incurred by an enterprise to develop or obtain computer
software to be used in its internal operations. The statement does not change
treatment of costs incurred in connection with correcting computer programs to
properly process the millennium change to the Year 2000, which were expensed as
incurred. Adoption of SOP 98-1 did not have a material effect on LG&E's
financial statements.

Note 2 - Merger

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.

LG&E Energy, as the parent of LG&E and KU, continues to be an exempt holding
company under PUHCA. Management has accounted for the merger as a pooling of
interests and as a tax-free reorganization under the Internal Revenue Code.

In the application filed with the Kentucky Commission, the utilities proposed
that 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
Kentucky Commission approved the surcredit and allocated the customer savings
53% to KU and 47% to LG&E. The surcredit will be about 2% of customer bills over
the next five years 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.


                                      126
<PAGE>

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 SFAS No. 71, 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 flowback to customers in future rates. LG&E's
current or expected recovery of deferred costs and expected flowback 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 $):

                                                           1999        1998
                                                           ----        ----

         Unamortized loss on bonds                     $ 16,556    $ 17,627
         Merger costs                                    12,702      16,332
         Manufactured gas sites                           2,185       3,684
                                                       --------    --------
         Total regulatory assets                         31,443      37,643
                                                       --------    --------

         Deferred income taxes - net                    (56,767)    (63,529)
         Deferred net gain                               (1,959)         --
                                                       --------    --------
         Total regulatory liabilities                   (58,726)    (63,529)
                                                       --------    --------

         Regulatory liabilities - net                  $(27,283)   $(25,886)
                                                       ========    ========

Environmental Cost Recovery. In May 1995, LG&E implemented an ECR surcharge. The
Kentucky Commission's order approving the surcharge for KU as well as the
constitutionality of the surcharge was challenged by certain intervenors in
Franklin Circuit Court. Decisions of the Circuit Court and the Kentucky Court of
Appeals in July 1995 and December 1997, respectively, upheld the
constitutionality of the ECR statute but differed on a claim of retroactive
recovery of certain amounts. Based on these decisions, the Kentucky Commission
ordered that certain surcharge revenues collected by LG&E be subject to refund
pending final determination of all appeals.

In December 1998, the Kentucky Supreme Court rendered an opinion upholding the
constitutionality of the surcharge statute but denied recovery of costs
associated with pre-1993 environmental projects through the ECR. The court
remanded the case to the Kentucky Commission to determine amounts to be refunded
for revenues collected for such pre-1993 environmental projects. Accordingly,
LG&E recorded a provision for rate refunds of $4.5 million in December 1998.

The parties to the proceedings reached a settlement agreement that was approved
in a Final Order issued by the Kentucky Commission in August 1999. This Final
Order resulted in the additional accrual of approximately $.6 million to what
had been recorded in December 1998. The refund is being applied to customers'
bills during the twelve-month period beginning October 1999.

Future Rate Regulation. 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 continued 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


                                      127
<PAGE>

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 amended filing
included requested Kentucky Commission approval of a five-year rate reduction
plan which proposed to reduce the electric rates of LG&E by $9.4 million in the
first year (beginning July 1999), and by $3.8 million annually through June
2004. The proposed amended plan also included establishment by LG&E of a $2.8
million program for low-income customer assistance as well as extension for one
additional year of both the rate cap proposal and merger savings surcredit
established in the original merger plan of LG&E and KU. Under the rate cap
proposal LG&E agreed, in the absence of extraordinary circumstances, not to
increase base electric rates for five years following the merger and LG&E also
agreed to refrain from filing for an increase in natural gas rates through June
2004.

In April 1999, 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. Legal briefs of the parties
were filed with the Kentucky Commission in October 1999. KIUC's position called
for annual revenue reductions for LG&E of $69.6 million.

In January 2000, the Kentucky Commission issued an Order for LG&E in the subject
cases. The Kentucky Commission ruled that LG&E should reduce base rates by $27.2
million effective with bills rendered beginning March 1, 2000. The Kentucky
Commission eliminated the proposal to operate under its PBR plan and reinstated
the fuel adjustment clause 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 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. LG&E also filed motions for reconsideration with the Kentucky
Commission on a number of items in the case in late January. Certain intervening
parties in the proceedings have also filed motions for reconsideration
asserting, among other things, that the Kentucky Commission understated the
amount of base rate reductions.

Other Rate Matters. 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
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.

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. During the first two years of
the mechanism ended October 31, 1999 and 1998, LG&E recorded $2.2 million and
$3.5 million, respectively, for its share of reduced gas costs. These amounts
are billed to customers through the gas supply clause.


                                      128
<PAGE>

Prior to implementation of the PBR in July 1999, and following its termination
in March 2000, LG&E employed a 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 off-system sales
appropriate for recovery through the FAC. LG&E requested that the Kentucky
Commission grant rehearing on the February orders, and further requested that
the Kentucky Commission stay the refund requirement until it could rule on the
rehearing request. The Kentucky Commission granted the request for a stay, and
in March 1999 granted rehearing on the appropriate line loss factor associated
with off-system sales for the 18-month period ended April 1998. The Kentucky
Commission also granted rehearing on the KIUC's request for rehearing on the
Kentucky Commission's determination that it lacked authority to require LG&E to
pay interest on the refund amounts. The Kentucky Commission conducted a hearing
on the rehearing issues and issued a final ruling in December 1999. The Kentucky
Commission agreed with LG&E 's position on the appropriate loss factor to use in
the FAC computation and reduced the refund level for the 18-month period under
review to approximately $800,000. LG&E implemented the refund with billings in
the month of January 2000. LG&E has filed an appeal from the Kentucky
Commission's February 1999 orders with the Franklin Circuit Court. A decision on
the appeals by the Court is expected in 2000.

LG&E intends to file before the end of the first quarter an application with the
Kentucky Commission for authority to increase its natural gas rates in order to
recoup higher costs for providing natural gas distribution services. LG&E
expects implementation before the end of 2000.

Kentucky PSC 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.
Management does not expect the ultimate resolution of this matter to have a
material adverse effect on LG&E's financial position or results of operations.


                                      129
<PAGE>

Note 4 - Financial Instruments

The cost and estimated fair values of LG&E's non-trading financial instruments
as of December 31, 1999 and 1998 follow (in thousands of $):

                                        1999                  1998
                                        ----                  ----
                                               Fair                  Fair
                                    Cost      Value       Cost      Value
                                    ----      -----       ----      -----

Marketable securities          $   7,253  $   6,936  $  17,767  $  17,851
Long-term investments -
  Not practicable to estimate
     fair value                      746        746        748        748
Preferred stock subject
  to mandatory redemption         25,000     24,861     25,000     26,413
Long-term debt (including
  current portion)               626,800    623,498    626,800    648,603
U.S. Treasury note and
  bond futures                        --         81         --        (50)
Interest-rate swaps                   --      1,666         --     (7,378)

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 payments obligations without the exchange of underlying
principal amounts. As of December 31, 1999 and 1998, LG&E was party to various
interest rate swaps with aggregate notional amounts of $234.3 million and $249.3
million, respectively. Under swap agreements LG&E paid fixed rates averaging
3.80% and 3.89% and received variable rates of averaging 5.46% and 4.00% at
December 31, 1999 and 1998, respectively. The swaps mature on dates ranging from
2001 to 2020.

At December 31, 1999, LG&E held U.S. Treasury note and bond futures contracts
with notional amounts totaling $3.5 million. These contracts are used to hedge
price risk associated with certain marketable securities and mature in March
2000.

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 295,000 customers and electricity to
approximately 366,000 customers in Louisville and adjacent areas in Kentucky.
For the year ended December 31, 1999, 82% of total revenue was derived from
electric operations and 18% 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.


                                      130
<PAGE>

Note 6 - Marketable Securities

LG&E's marketable securities have been determined to be "available-for-sale"
under the provisions of SFAS No. 115, Accounting for Certain Investments in Debt
and Equity Securities. Proceeds from sales of available-for-sale securities in
1999 were approximately $11.7 million, which resulted in an immaterial net
realized gain, calculated using the specific identification method. Proceeds
from sales of available-for-sale securities in 1998 were approximately $18.8
million, which resulted in immaterial realized gains and losses.

Approximate cost, fair value, and other required information pertaining to
LG&E's available-for-sale securities by major security type, as of December 31,
1999 and 1998, follow (in thousands of $):

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

1998:
Cost                                        $  3,798   $ 13,969   $ 17,767
Unrealized gains                                 276         31        307
Unrealized losses                                (95)      (128)      (223)
                                            --------   --------   --------
Fair values                                 $  3,979   $ 13,872   $ 17,851
                                            ========   ========   ========

Fair values:
  No maturity                               $  3,979   $    178   $  4,157
  Contractual maturities:
     Less than one year                           --      8,301      8,301
     One to five years                            --      3,861      3,861
     Over ten years                               --      1,532      1,532
                                            --------   --------   --------
Total fair values                           $  3,979   $ 13,872   $ 17,851
                                            ========   ========   ========


                                      131
<PAGE>

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, 1999, and a
statement of the funded status as of December 31 for each of the last three
years (in thousands of $):

<TABLE>
<CAPTION>
                                                       1999        1998        1997
                                                       ----        ----        ----
<S>                                               <C>         <C>         <C>
Pension Plans:
Change in benefit obligation
  Benefit obligation at beginning of year         $ 311,935   $ 274,095   $ 229,349
  Service cost                                        5,005       6,333       5,214
  Interest cost                                      21,014      19,873      17,629
  Plan amendments                                    (2,397)      3,724       3,085
  Curtailment (gain) or loss                             --      (2,218)         --
  Special termination benefits                           --      18,295          --
  Benefits paid                                     (15,471)    (10,866)     (8,735)
  Actuarial (gain) or loss                          (36,819)      2,699      27,553
                                                  ---------   ---------   ---------
  Benefit obligation at end of year               $ 283,267   $ 311,935   $ 274,095
                                                  =========   =========   =========

Change in plan assets
  Fair value of plan assets at beginning of year  $ 308,660   $ 280,238   $ 238,026
  Actual return on plan assets                       51,995      38,913      46,078
  Employer contributions                             14,911         375       4,869
  Benefits paid                                     (15,471)    (10,866)     (8,735)
                                                  ---------   ---------   ---------
  Fair value of plan assets at end of year        $ 360,095   $ 308,660   $ 280,238
                                                  =========   =========   =========

Reconciliation of funded status
  Funded status                                   $  76,828   $  (3,275)  $   6,143
  Unrecognized actuarial (gain) or loss            (126,554)    (72,037)    (61,720)
  Unrecognized transition (asset) or obligation      (6,965)     (8,076)     (9,188)
  Unrecognized prior service cost                    35,588      41,447      43,518
                                                  ---------   ---------   ---------
  Net amount recognized at end of year            $ (21,103)  $ (41,941)  $ (21,247)
                                                  =========   =========   =========

Other Benefits:
Change in benefit obligation
  Benefit obligation at beginning of year         $  44,964   $  43,373   $  39,951
  Service cost                                        1,205         761         746
  Interest cost                                       3,270       2,946       2,942
  Plan amendments                                     2,377         599          --
  Curtailment (gain) or loss                             --         344          --
  Special termination benefits                           --       2,855          --
  Benefits paid                                      (3,050)     (2,634)     (2,604)
  Actuarial (gain) or loss                           (3,769)     (3,280)      2,338
                                                  ---------   ---------   ---------
  Benefit obligation at end of year               $  44,997   $  44,964   $  43,373
                                                  =========   =========   =========

Change in plan assets
  Fair value of plan assets at beginning of year  $   6,062   $   4,384   $   2,284
  Actual return on plan assets                        1,776         199          80
  Employer contributions                              4,681       3,207       3,696
  Benefits paid                                      (1,993)     (1,728)     (1,676)
                                                  ---------   ---------   ---------
  Fair value of plan assets at end of year        $  10,526   $   6,062   $   4,384
                                                  =========   =========   =========
</TABLE>


                                      132
<PAGE>

                                                     1999       1998       1997
                                                     ----       ----       ----

Reconciliation of funded status
  Funded status                                  $(34,471)  $(38,902)  $(38,989)
  Unrecognized actuarial (gain) or loss            (1,638)      (285)     2,901
  Unrecognized transition (asset) or obligation    14,489     18,080     20,053
  Unrecognized prior service cost                   4,292      3,519      3,410
                                                 --------   --------   --------
  Net amount recognized at end of year           $(17,328)  $(17,588)  $(12,625)
                                                 ========   ========   ========

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, 1999, 1998 and 1997 (in thousands of $):

<TABLE>
<CAPTION>
                                                            1999        1998        1997
                                                            ----        ----        ----
<S>                                                    <C>         <C>         <C>
Pension Plans:
Amounts recognized in the balance sheet
  consisted of:
     Prepaid benefits cost                             $   6,466   $      --   $      --
     Accrued benefit liability                           (27,569)    (41,977)    (21,317)
     Intangible asset                                         --          36          70
                                                       ---------   ---------   ---------
     Net amount recognized at year-end                 $ (21,103)  $ (41,941)  $ (21,247)
                                                       =========   =========   =========

Additional year-end information for plans with
  benefit obligations in excess of plan assets:
     Projected benefit obligation (1)                  $ 139,491   $ 148,005   $ 121,902
     Accumulated benefit obligation (2)                    4,327     131,430       4,179
     Fair value of plan assets (1)                       133,336     107,988      99,151
</TABLE>

(1)   All years include non-union plan and unfunded SERPs.
(2)   1998 includes non-union plan and SERPs. 1999 and 1997 include SERPs only.

Other Benefits:
Amounts recognized in the balance sheet
  consisted of:
     Accrued benefit liability                   $(17,328)  $(17,588)  $(12,625)
                                                 ========   ========   ========

Additional year-end information for plans with
  benefit obligations in excess of plan assets:
     Projected benefit obligation                $ 44,997   $ 44,964   $ 43,373
     Fair value of plan assets                     13,074      6,062      4,384


                                      133
<PAGE>

The following table provides the components of net periodic benefit cost for the
plans for 1999, 1998 and 1997 (in thousands of $):

<TABLE>
<CAPTION>
                                                        1999       1998       1997
                                                        ----       ----       ----
<S>                                                 <C>        <C>        <C>
Pension Plans:
Components of net periodic benefit cost
  Service cost                                      $  5,005   $  6,333   $  5,214
  Interest cost                                       21,014     19,873     17,629
  Expected return on plan assets                     (28,946)   (23,701)   (19,849)
  Amortization of prior service cost                   3,462      3,882      3,708
  Amortization of transition (asset) or obligation    (1,112)    (1,112)    (1,112)
  Recognized actuarial (gain) or loss                 (2,621)    (2,248)    (2,866)
                                                    --------   --------   --------
  Net periodic benefit cost                         $ (3,198)  $  3,027   $  2,724
                                                    ========   ========   ========

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                                      $  1,205   $    761   $    746
  Interest cost                                        3,270      2,946      2,942
  Expected return on plan assets                        (401)      (296)      (151)
  Amortization of prior service cost                     473        367        328
  Amortization of transition (asset) or obligation     1,114      1,315      1,337
  Recognized actuarial gain                             (183)        --         --
                                                    --------   --------   --------
  Net periodic benefit cost                         $  5,478   $  5,093   $  5,202
                                                    ========   ========   ========

Special charges
  Curtailment loss                                  $     --   $  1,005   $     --
  Prior service cost recognized                           --        124         --
  Special termination benefits                            --      2,855         --
                                                    --------   --------   --------
  Total charges                                     $     --   $  3,984   $     --
                                                    ========   ========   ========
</TABLE>

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:

<TABLE>
<CAPTION>
                                                         1999          1998          1997
                                                         ----          ----          ----
<S>                                                      <C>     <C>           <C>
Weighted-average assumptions as of December 31:
Discount rate                                            8.00%         7.00%         7.00%
Expected long-term rate of return on plan assets         9.50%         8.50%         8.50%
Rate of compensation increase                            5.00%   3.50%-4.00%   2.00%-4.00%
</TABLE>

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 4.75% for 2005 and remain at that level thereafter.


                                      134
<PAGE>

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 $):

<TABLE>
<CAPTION>
                                                                    1% Decrease      1% Increase
                                                                    -----------      -----------
<S>                                                                    <C>               <C>
Effect on total of service and interest cost components for 1999       $   (150)         $   176
Effect on year-end 1999 postretirement benefit obligations               (1,189)           1,358
</TABLE>

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, $2.4 million, and $1.8 million for 1999, 1998, and 1997, respectively.

Note 8 - Income Taxes

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

                                                  1999         1998        1997
                                                  ----         ----        ----

Included in operating expenses:
  Current         - federal                    $53,981      $45,716     $57,590
                  - state                       13,680       11,895      14,593
  Deferred        - federal - net               (4,818)       2,276      (4,565)
                  - state - net                   (780)         678         703
  Deferred investment tax credit                    --           55         102
  Amortization of investment tax credit         (4,289)      (4,313)     (4,342)
                                               -------      -------     -------
     Total                                      57,774       56,307      64,081
                                               -------      -------     -------

Included in other income and (deductions):
  Current         - federal                        217          660       1,484
                  - federal - merger costs          --       (6,758)         --
                  - state                          (30)           6         161
                  - state - merger costs            --       (1,737)         --
  Deferred        - federal - net                  254         (165)        292
                  - state - net                     65          (42)         75
                                               -------      -------     -------
     Total                                         506       (8,036)      2,012
                                               -------      -------     -------

Total income tax expense                       $58,280      $48,271     $66,093
                                               =======      =======     =======


                                      135
<PAGE>

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

                                                           1999             1998
                                                           ----             ----

Deferred tax liabilities:
  Depreciation and other
     plant-related items                               $321,889         $323,869
  Other liabilities                                       5,324            9,644
                                                       --------         --------
                                                        327,213          333,513
                                                       --------         --------

Deferred tax assets:
  Investment tax credit                                  27,145           28,876
  Income taxes due to customers                          22,588           25,447
  Pension overfunding                                     2,193            2,099
  Accrued liabilities not currently
     deductible and other                                19,377           22,502
                                                       --------         --------
                                                         71,303           78,924
                                                       --------         --------

Net deferred income tax liability                      $255,910         $254,589
                                                       ========         ========

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

<TABLE>
<CAPTION>
                                                 1999          1998          1997
                                                 ----          ----          ----
<S>                                              <C>           <C>           <C>
Statutory federal income tax rate                35.0%         35.0%         35.0%
State income taxes net of federal benefit         5.1           5.5           5.7
Amortization of investment tax credit            (2.8)         (3.4)         (2.4)
Nondeductible merger expenses                      --           2.4            --
Other differences - net                          (1.9)         (1.3)         (1.5)
                                               ------        ------        ------

Effective income tax rate                        35.4%         38.2%         36.8%
                                               ======        ======        ======
</TABLE>

Note 9 - Other Income and Deductions

Other income and deductions consisted of the following at December 31 (in
thousands of $):

                                             1999         1998        1997
                                             ----         ----        2----

Interest and dividend income              $ 4,086     $  4,245     $ 4,786
Interest on income tax settlement              --           --       1,446
Gain on sale of stock options                  --           --       1,794
Gains (losses) on fixed asset disposal      2,394          530          77
Donations                                    (102)        (168)       (147)
Income taxes and other                     (2,237)      (2,111)     (3,679)
Income tax benefit on merger costs             --        8,495          --
                                          -------     --------     -------

Total other income and deductions         $ 4,141     $ 10,991     $ 4,277
                                          =======     ========     =======


                                      136
<PAGE>

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, 1999.

<TABLE>
<CAPTION>
                                                        Weighted
                                                         Average
                                            Stated      Interest                      Principal
                                    Interest Rates          Rate      Maturities        Amounts
                                    --------------          ----      ----------        -------
<S>                                  <C>                   <C>       <C>               <C>
Noncurrent portion                   5.45% - 7.63%         6.44%     2002 - 2023       $380,600
Current portion (pollution
  control bonds)                          Variable         3.67%     2013 - 2027        246,200
</TABLE>

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 were 3.98%.

Maturities of LG&E's first mortgage bonds and pollution control bonds (principal
amounts stated in thousands of $) at December 31, 1999, are summarized below.

         2001                                $     --
         2002                                  20,000
         2003                                  42,600
         2004                                      --
         2005                                      --
         Thereafter                           318,000
                                             --------
         Total                               $380,600
                                             ========

In December 1999, LG&E notified bondholders of its intent to exercise its call
option on its $20.0 million 7.50% First Mortgage Bonds due July 1, 2002. The
bonds were redeemed in January 2000 utilizing proceeds from issuance of
commercial paper.

In June 1998, $20 million of LG&E's First Mortgage Bonds matured and were
retired.

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 in substance that,
under certain specified conditions, portions of retained earnings will not be
available for the payment of dividends on common stock. No portion of retained
earnings is presently restricted by this provision.

Note 11 - Notes Payable

LG&E's short-term financing requirements are satisfied through the sale of
commercial paper. LG&E had outstanding commercial paper of $120.1 million at
December 31, 1999, at a weighted-average interest rate of


                                      137
<PAGE>

6.02%. LG&E had no short-term borrowings at December 31, 1998.

At December 31, 1999, 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 $14.5 million at December 31, 1999.
Construction expenditures for the years 2000 and 2001 are estimated to total
approximately $401 million.

Operating Lease. LG&E leases office space and accounts for all of its office
space leases as operating leases. Total lease expense for 1999, 1998, and 1997,
less amounts contributed by the parent company, was $1.5 million, $1.6 million,
and $1.8 million, respectively. The future minimum annual lease payments under
lease agreements for years subsequent to December 31, 1999, are as follows (in
thousands of $):

         2000                                        $ 3,321
         2001                                          3,654
         2002                                          3,594
         2003                                          3,507
         2004                                          3,507
         Thereafter                                    1,754
                                                     -------
         Total                                       $19,337
                                                     =======

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 has been
deferred pending resolution of rate treatment by the Kentucky Commission.

Environmental. The 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, commencing 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.
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
significant additional reductions in NOx emissions by May 2003, in order to
mitigate alleged ozone transport to the Northeast. While each of the 22 states
covered by the rule is free to allocate its assigned NOx reductions among
various emissions sectors as it deems appropriate, the regulation may ultimately
require electric generating units to reduce their NOx emissions to 0.15
lb./Mmbtu - an 85% reduction from 1990 levels. In related proceedings in
response to petitions filed by various Northeast states, in December 1999, EPA
issued a final rule directing similar NOx reductions from a number of
specifically named electric generating units including all LG&E stations.
Several states, various labor and industry groups, and individual companies have
appealed both EPA rulings to the U.S. Court of Appeals for the Washington D.C.
Circuit. Management is currently unable to determine the outcome or exact impact
of this matter until such time as the courts rule on the pending legal
challenges and the states


                                      138
<PAGE>

implement the final regulatory mandate. However, if the 0.15 lb. target is
ultimately imposed, LG&E will be required to incur significant capital
expenditures and increased operation and maintenance costs for additional
controls.

Subject to further study, analysis, and the outcome of pending litigation
against the EPA, LG&E estimates that it may incur capital costs for NOx
compliance ranging from $65 million to reduce emissions to the level of 0.25
lb./Mmbtu (Commonwealth of Kentucky's proposed NOx compliance level) to $165
million to reduce emissions to the level of 0.15 lb./Mmbtu (current EPA
regulations). These costs would generally be incurred beginning in 2000. 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 their environmental surcharge mechanisms and believe 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 addressing other air quality issues. First, LG&E 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. LG&E continues to monitor EPA actions to
challenge that ruling. Second, LG&E was notified by regulatory agencies that the
Cane Run Station may be the source of a potential exceedance of the NAAQS that
could require LG&E to incur additional capital expenditures or accept certain
emissions limitations. After reviewing additional modeling information submitted
by LG&E, in January 2000, EPA concluded that the Cane Run Station does not
contribute to any potential NAAQS exceedance and that no further action is
required from LG&E. Third, LG&E is working with regulatory authorities to review
the effectiveness of remedial measures aimed at controlling particulate
emissions from its Mill Creek Station. LG&E previously settled a number of
property damage claims from adjacent residents and completed significant plant
modifications as part of its ongoing capital construction program.

LG&E owns or formerly owned three properties which contained past MGP
operations. Various contaminants are typically found at such former MGP sites
and environmental remediation measures are frequently required. LG&E has reached
agreements for other parties to assume cleanup responsibility for two sites it
formerly owned. In addition, LG&E recently reached an agreement with the
Kentucky Division of Waste Management with respect to a third LG&E-owned site in
which LG&E committed to impose certain property restrictions and conduct
additional monitoring in lieu of a cleanup. Based on currently available
information, management estimates that it will incur additional MGP costs of
less than $500,000. Accordingly, an accrual of $500,000 has been recorded in the
accompanying financial statements.

Note 13 - Jointly Owned Electric Utility Plant

LG&E owns a 75% undivided interest in Trimble County Unit 1. Accounting for the
75% portion of the Unit, which the Kentucky Commission has allowed to be
reflected in customer rates, is similar to LG&E's accounting for other wholly
owned utility plants.

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


                                      139
<PAGE>

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                             $546,497
Accumulated depreciation          140,972
                                ---------
Net book value                   $405,525
                                =========

Construction work in progress
  (included above)                   $673

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.

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
                                         --------             ---          -----
1999

Operating revenues                     $  790,670(a)    $ 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(b)    $ 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


                                      140
<PAGE>

                                         Electric             Gas          Total
                                         --------             ---          -----
1997

Operating revenues                        $  614,532     $231,011     $  845,543
Depreciation and amortization                 79,958       13,062         93,020
Interest income                                5,279          953          6,232
Interest expense                              33,349        5,841         39,190
Operating income taxes                        59,415        4,666         64,081
Net income                                   108,236        5,037        113,273
Total assets                               1,677,278      378,363      2,055,641
Construction expenditures                     81,713       29,180        110,893

(a)   Net of provision for rate refund of $1.7 million.
(b)   Net of provision for rate refund of $4.5 million.

Note 15 - Selected Quarterly Data (Unaudited)

Selected financial data for the four quarters of 1999 and 1998 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 $)

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(a)    40,614      22,375(b)

1998
Operating revenues             $233,344    $ 201,389     $229,885    $185,438
Net operating income             32,326       33,629       53,420      16,148
Net income                       23,399           21       44,861       9,839
Net income (loss) available
  for common stock               22,276       (1,122)      43,726       8,672

(a)   The increase of $22.1 million compared to June 1998 was due to a
      non-recurring after-tax charge of $23.6 million from merger-related
      expenses.

(b)   The increase of $13.7 million compared to December 1998 was primarily due
      to a non-recurring charge to refund certain amounts collected under the
      ECR and colder weather in 1999.

Note 16 - Subsequent Events

On February 28, 2000, LG&E Energy announced that its Board of Directors
accepted an 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 will become a wholly owned subsidiary of PowerGen and its U.S.
headquarters. The Utility Operations of the Company will continue their
separate identities and serve customers in Kentucky and Virginia under their
present names. The preferred stock and debt securities of the Utility
Operations will not be affected by this transaction resulting in the Utility
Operations' obligation to continue to file SEC reports. The acquisition is
expected to close 9 to 12 months from the announcement,

                                      141
<PAGE>

shortly after all of the conditions to consummation of the acquisition are
met. Those conditions include, without limitation, the approval of the
holders of a majority of the outstanding shares of common stock of each of
LG&E Energy and PowerGen, the receipt of all necessary governmental approvals
and the making of all necessary governmental filings, including approvals of
various regulators in Kentucky and Virginia under state utility laws, the
approval of the FERC under the Federal Power Act, the approval of the SEC
under the Public Utility Holding Company Act of 1935, and the filing of
requisite notifications with the Federal Trade Commission and the Department
of Justice under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as
amended, and the expiration of all applicable waiting periods thereunder.
Shareholder meetings to vote upon the approval of the acquisition are
expected to be held during the second quarter of 2000 for both LG&E Energy
and PowerGen. During the first quarter of 2000, the Company expensed
approximately $1.0 million relating to the PowerGen transaction. The
foregoing description of the acquisition does not purport to be complete and
is qualified in its entirety by reference to LG&E Energy's current reports on
Form 8-K, filed February 29, 2000, with the SEC.

On March 3, 2000, the U.S. Court of Appeals for the Washington D.C. Circuit
issued a final opinion upholding the NOx SIP call rule requiring electric
generating units to reduce their NOx emissions to 0.15 lb./Mmbtu by May 2003.
Some of the litigants will likely seek further judicial review of the ruling.

In the first quarter of 2000, LG&E will take a restructuring charge relating to
the reduction of positions and the integration of LG&E's and KU's operations,
including combining retail gas and electric operations, consolidation of
customer service centers and the redesigning various other processes.

The Kentucky Commission responded to the motions filed by LG&E for computational
and other errors made in Orders received on base rate reductions in February
2000 by granting rehearings for LG&E on various issues.


                                      142
<PAGE>

                       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, 1999, 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.


                                      143
<PAGE>

                       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, 1999 and 1998,
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, 1999. 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, 1999 and 1998, and the results of its operations and
its cash flows for each of the three years in the period ended December 31,
1999, 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, 2000 (Except with respect
to the matters discussed in Note 16, as
to which the date is March 3, 2000.)


                                      144
<PAGE>

                           Kentucky Utilities Company
                              Statements of Income
                                (Thousands of $)

<TABLE>
<CAPTION>
                                                         Years Ended December 31
                                                       1999          1998         1997
                                                       ----          ----         ----
<S>                                               <C>           <C>           <C>
OPERATING REVENUES:
    Electric (Note 1) ........................    $ 943,210     $ 831,614     $716,437
    Provision for rate refunds (Note 3) ......       (5,900)      (21,500)          --
                                                  ---------     ---------     --------
       Total operating revenues ..............      937,310       810,114      716,437
                                                  ---------     ---------     --------

OPERATING EXPENSES:
    Fuel, principally coal, used in generation      219,883       217,401      188,439
    Power purchased ..........................      242,315       126,584       72,542
    Other operation expenses .................      116,521       121,275      120,951
    Maintenance ..............................       57,318        63,608       64,990
    Depreciation and amortization ............       89,922        86,657       84,111
    Federal and state income taxes (Note 7) ..       60,380        53,256       51,690
    Property and other taxes .................       14,955        15,945       15,306
                                                  ---------     ---------     --------
       Total operating expenses ..............      801,294       684,726      598,029
                                                  ---------     ---------     --------

Net operating income .........................      136,016       125,388      118,408

Merger costs (Note 2) ........................           --        21,830           --
Interest and dividend income (Note 8) ........        4,293         1,811        1,673
Other income and (deductions) (Note 8) .......        5,144         6,035        5,330
Interest charges .............................       38,895        38,640       39,698
                                                  ---------     ---------     --------

Net income ...................................      106,558        72,764       85,713

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

Net income available for common stock ........    $ 104,302     $  70,508     $ 83,457
                                                  =========     =========     ========
</TABLE>

                         Statements of Retained Earnings
                                (Thousands of $)

<TABLE>
<CAPTION>
                                                             Years Ended December 31
                                                       1999             1998           1997
                                                       ----             ----           ----
<S>                                               <C>           <C>           <C>

Balance January 1................................  $299,167         $304,750       $287,852
Add net income...................................   106,558           72,764         85,713
                                                   --------         --------       --------
                                                    405,725          377,514        373,565

Deduct:    Cash dividends declared on stock:
             4.75% cumulative preferred..........       950              950            950
             6.53% cumulative preferred..........     1,306            1,306          1,306
             Common..............................    73,999           76,091         66,559
                                                   --------         --------       --------
                                                     76,255           78,347         68,815
                                                   --------         --------       --------

Balance December 31..............................  $329,470         $299,167       $304,750
                                                   ========         ========       ========
</TABLE>

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


                                      145
<PAGE>

                           Kentucky Utilities Company
                                 Balance Sheets
                                (Thousands of $)

<TABLE>
<CAPTION>
                                                                                December 31
                                                                              1999          1998
                                                                              ----          ----
<S>                                                                     <C>           <C>
ASSETS:
Utility plant, at original cost (Note 1) ...........................    $2,744,380    $2,602,167
Less:  reserve for depreciation ....................................     1,288,819     1,208,183
                                                                        ----------    ----------
                                                                         1,455,561     1,393,984
Construction work in progress ......................................       106,686        83,361
                                                                        ----------    ----------
                                                                         1,562,247     1,477,345
                                                                        ----------    ----------

Other property and investments - less reserve ......................        14,349        14,238

Current assets:
    Cash and temporary cash investments ............................         6,793        58,949
    Accounts receivable - less reserve of
       $800 in 1999 and $520 in 1998 ...............................        88,549       106,125
    Materials and supplies - at average cost:
       Fuel (predominantly coal) ...................................        30,225        23,927
       Other .......................................................        26,213        24,248
    Prepayments and other ..........................................         3,743         3,055
                                                                        ----------    ----------
                                                                           155,523       216,304
                                                                        ----------    ----------

Deferred debits and other assets:
    Unamortized debt expense .......................................         4,827         5,227
    Regulatory assets (Note 3) .....................................        23,033        28,228
    Other ..........................................................        25,111        19,859
                                                                        ----------    ----------
                                                                            52,971        53,314
                                                                        ----------    ----------
                                                                        $1,785,090    $1,761,201
                                                                        ==========    ==========


CAPITAL AND LIABILITIES:
Capitalization (see statements of capitalization):
    Common equity ..................................................    $  637,015    $  606,713
    Cumulative preferred stock .....................................        40,000        40,000
    Long-term debt (Note 9) ........................................       430,830       546,330
                                                                        ----------    ----------
                                                                         1,107,845     1,193,043
                                                                        ----------    ----------

Current liabilities:
    Current portion of long-term debt (Note 9) .....................       115,500            --
    Accounts payable ...............................................       116,546       110,268
    Provision for rate refunds .....................................        20,567        21,500
    Dividends declared .............................................        19,150        18,188
    Accrued taxes ..................................................        10,502        16,733
    Accrued interest ...............................................         7,329         8,110
    Other ..........................................................        18,617        20,971
                                                                        ----------    ----------
                                                                           308,211       195,770
                                                                        ----------    ----------

Deferred credits and other liabilities:
    Accumulated deferred income taxes (Notes 1 and 7) ..............       243,620       244,493
    Investment tax credit, in process of amortization ..............        18,575        22,302
    Accumulated provision for pensions and related benefits (Note 6)        48,285        52,287
    Customers' advances for construction ...........................         1,174         1,264
    Regulatory liability (Note 3) ..................................        46,069        46,552
    Other ..........................................................        11,311         5,490
                                                                        ----------    ----------
                                                                           369,034       372,388
                                                                        ----------    ----------
Commitments and contingencies (Note 11)
                                                                        $1,785,090    $1,761,201
                                                                        ==========    ==========
</TABLE>

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


                                      146
<PAGE>

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

<TABLE>
<CAPTION>
                                                                 Years Ended December 31
                                                            1999          1998            1997
                                                            ----          ----            ----
<S>                                                    <C>           <C>           <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
    Net income ....................................    $ 106,558     $  72,764     $    85,713
    Items not requiring cash currently:
       Depreciation and amortization ..............       89,922        86,657          84,111
       Deferred income taxes - net ................       (3,763)       (2,437)          4,606
       Investment tax credit - net ................       (3,727)       (3,829)         (4,036)
    Change in certain net current assets:
       Accounts receivable ........................       17,576       (31,482)            280
       Materials and supplies .....................       (8,263)        3,272           1,104
       Accounts payable ...........................        6,514        71,162           4,807
       Provision for rate refunds .................         (933)       21,500              --
       Accrued taxes ..............................       (6,231)        9,260           2,090
       Accrued interest ...........................         (781)         (173)            235
       Prepayments and other ......................       (3,042)          (53)          1,922
    Other .........................................       10,346        12,776          (1,943)
                                                       ---------     ---------     -----------
       Net cash flows from operating activities ...      204,176       239,417         178,889
                                                       ---------     ---------     -----------

CASH FLOWS FROM INVESTING ACTIVITIES:
    Proceeds from insurance reimbursement .........          206           179           4,270
    Construction expenditures .....................     (181,341)      (91,992)        (94,006)
                                                       ---------     ---------     -----------
       Net cash flows used for investing activities     (181,135)      (91,813)        (89,736)
                                                       ---------     ---------     -----------

CASH FLOWS FROM FINANCING ACTIVITIES:
    Short-term borrowings .........................           --       381,500       2,645,500
    Repayments of short-term borrowings ...........           --      (415,100)     (2,666,100)
    Repayment of long-term debt ...................           --           (42)            (21)
    Payment of dividends ..........................      (75,197)      (60,347)        (68,815)
                                                       ---------     ---------     -----------
       Net cash flows from financing activities ...      (75,197)      (93,989)        (89,436)
                                                       ---------     ---------     -----------

Change in cash and temporary cash investments .....      (52,156)       53,615            (283)

Beginning cash and temporary cash investments .....       58,949         5,334           5,617
                                                       ---------     ---------     -----------

Ending cash and temporary cash investments ........    $   6,793     $  58,949     $     5,334
                                                       =========     =========     ===========

Supplemental disclosures of cash flow information:
    Cash paid during the year for:
       Income taxes ...............................    $  71,258     $  46,490     $    44,857
       Interest on borrowed money .................       35,508        36,008          37,053
</TABLE>

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


                                      147
<PAGE>

                           Kentucky Utilities Company
                          Statements of Capitalization
                                (Thousands of $)

                                                               December 31
                                                          1999             1998
                                                          ----             ----

COMMON EQUITY:
    Common stock, without par value -
       outstanding 37,817,878 shares .........       $ 308,140        $ 308,140
    Retained earnings ........................         329,470          299,168
    Other ....................................            (595)            (595)
                                                     ---------        ---------

                                                       637,015          606,713
                                                     ---------        ---------

CUMULATIVE PREFERRED STOCK:
    Cumulative and redeemable on 30 days notice by KU:

<TABLE>
<CAPTION>
                                                           Shares           Current
                                                         Outstanding   Redemption Price
                                                         -----------   ----------------
<S>                                                        <C>          <C>              <C>                      <C>
    Without par value, 5,300,000 shares authorized -
       4.75% series, $100 stated value...............      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                   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                    4,000
       7, due May 1, 2020, 7.60%....................................................          8,900                    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
                                                                                         ----------               ----------

       Total bonds outstanding......................................................        546,330                  546,330

       Less current portion of long-term debt.......................................        115,500                       --
                                                                                         ----------               ----------

       Long-term debt...............................................................        430,830                  546,330
                                                                                         ----------               ----------

       Total capitalization.........................................................     $1,107,845               $1,193,043
                                                                                         ==========               ==========
</TABLE>

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


                                      148
<PAGE>

                           Kentucky Utilities Company
                          Notes to Financial Statements

Note 1 - Summary of Significant Accounting Policies

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

Certain reclassification entries have been made to the 1998 and 1997 financial
statements to conform to the 1999 presentation with no impact on previously
reported net income.

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 allowance for
funds used during construction.

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

Depreciation and amortization. Depreciation is provided on the straight-line
method over the estimated service lives of depreciable plant. The amounts
provided for KU approximated 3.5% in 1999, 1998 and 1997.

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
$29.6 million at December 31, 1999 and 1998.

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


                                      149
<PAGE>

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 1999 and 1998, 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. KU has not yet quantified all the effects of adopting SFAS No. 133
on the financial statements. However, SFAS No. 133 could increase the volatility
in earnings and other comprehensive income. The effect of this statement will be
recorded in cumulative effect of change in accounting when adopted. 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.

EITF No. 98-10, Accounting for Energy Trading and Risk Management Activities was
adopted effective January 1, 1999. The pronouncement requires that 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
KU's results of operations or financial position.

SOP 98-1, Accounting for the Costs of Computer Software Developed or Obtained
for Internal Use. Adopted as of January 1, 1998, SOP 98-1 clarifies the criteria
for capital or expense treatment of costs incurred by an enterprise to develop
or obtain computer software to be used in its internal operations. The statement
does not change treatment of costs incurred in connection with correcting
computer programs to properly process the millennium change to the Year 2000,
which were expensed as incurred. Adoption of SOP 98-1 did not have a material
effect on KU's financial statements.

Note 2 - LG&E - Kentucky Utilities Merger

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


                                      150
<PAGE>

five-year period. The preferred stock and debt securities of KU were not
affected by the merger.

LG&E Energy, as the parent of LG&E and KU, continues to be an exempt holding
company under PUHCA. Management has accounted for the merger as a pooling of
interests and as a tax-free reorganization under the Internal Revenue Code.

In the application filed with the Kentucky Commission, the utilities proposed
that 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
Kentucky Commission approved the surcredit and allocated the customer savings
53% to KU and 47% to LG&E. The surcredit will be about 2% of customer bills over
the next five years 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
SFAS No. 71, 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 flowback to
customers in future rates. KU's current or expected recovery of deferred costs
and expected flowback 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 $):

                                                         1999              1998
                                                         ----              ----

Unamortized loss on bonds                            $  7,594          $  8,675
Merger costs                                           14,324            18,417
Other                                                   1,115             1,136
                                                     --------          --------
Total regulatory assets                                23,033            28,228
                                                     --------          --------

Deferred income taxes - net                           (42,992)          (45,882)
Other                                                  (3,077)             (670)
                                                     --------          --------
Total regulatory liabilities                          (46,069)          (46,552)
                                                     --------          --------

Regulatory liabilities - net                         $(23,036)         $(18,324)
                                                     ========          ========

Environmental Cost Recovery. In August 1994 KU implemented an ECR surcharge. The
Kentucky Commission's order approving the surcharge for KU as well as the
constitutionality of the surcharge was challenged by certain intervenors in
Franklin Circuit Court. Decisions of the Circuit Court and the Kentucky Court of
Appeals in July 1995 and December 1997, respectively, upheld the
constitutionality of the ECR statute but differed on a claim of retroactive
recovery of certain amounts. Based on these decisions, the Kentucky Commission
ordered that certain surcharge revenues collected by KU be subject to refund
pending final determination of all appeals.

In December 1998, the Kentucky Supreme Court rendered an opinion upholding the
constitutionality of the surcharge statute but denied recovery of costs
associated with pre-1993 environmental projects through the ECR. The court
remanded the case to the Kentucky Commission to determine amounts to be refunded
for


                                      151
<PAGE>

revenues collected for such pre-1993 environmental projects. Accordingly, KU
recorded a provision for rate refund of $21.5 million in December 1998.

The parties to the proceedings reached a settlement agreement that was approved
in a Final Order issued by the Kentucky Commission in August 1999. This Final
Order resulted in the reversal of approximately $1.5 million of the provision
for rate refunds established by KU in December 1998. The refund is being applied
to customers' bills during the twelve-month period beginning October 1999.

Future Rate Regulation. 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 LG&E and 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 amended filing
included requested Kentucky Commission approval of a five-year rate reduction
plan which proposed to reduce the electric rates of KU by $10.6 million in the
first year (beginning July 1999), and by $4.2 million annually through June
2004. The proposed amended plan also included establishment by KU of a $3.2
million program for low-income customer assistance as well as extension for one
additional year of both the rate cap proposal and merger savings surcredit
established in the original merger plan of LG&E and KU. Under the rate cap
proposal KU agreed, in the absence of extraordinary circumstances, not to
increase base electric rates for five years following the merger and LG&E also
agreed to refrain from filing for an increase in natural gas rates through June
2004.

In April 1999, 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 and KU's amended PBR plans and the KIUC
rate reduction petitions in August and September 1999. Legal briefs of the
parties were filed with the Kentucky Commission in October 1999. KIUC's position
called for annual revenue reductions for KU of $61.5 million.

In January 2000, the Kentucky Commission issued Orders for KU in the subject
cases. The Kentucky Commission ruled that KU should reduce base rates by $36.5
million effective with bills rendered beginning March 1, 2000. The Kentucky
Commission eliminated 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 each utility resulting in a rate of
return 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. KU also filed motions for reconsideration with the Kentucky Commission
on a number of items in the case in late January. Certain intervening parties in
the proceedings have also filed motions for reconsideration asserting, among
other things, that the Kentucky Commission understated the amount of base rate
reductions.


                                      152
<PAGE>

Other Rate Matters. 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 off-system 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 $5.8 million from the original Order
amount of $10.1 million. In August 1999, KU recorded its estimated share of
anticipated FAC refunds of $7.7 million. KU began implementing the refund in
October and will continue the refund through September 2000. Both KU and the
KIUC have appealed the Order to the Franklin Circuit Court. A decision is not
expected on the appeal until later in 2000.

Kentucky PSC 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.
Management does not expect the ultimate resolution of this matter to have a
material adverse effect on the Company's financial position or results of
operations.


                                      153
<PAGE>

Note 4 - Financial Instruments

The cost and estimated fair values of the KU's non-trading financial instruments
as of December 31, 1999 and 1998 follow (in thousands of $):

                                        1999                       1998
                                        ----                       ----
                                                Fair                     Fair
                                   Cost        Value         Cost       Value
                                   ----        -----         ----       -----
Long-term debt (including
  current portion)             $546,330    $ 542,242     $546,330    $587,245
Interest-rate swaps                  --       (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 Swap. KU entered into an interest rate swap agreement to exchange
fixed interest rate payment obligations for variable interest rate payments
without the exchange of underlying principal amounts. As of December 31, 1999,
KU was party to an interest rate swap with a notional amount of $53.0 million.
Under the swap agreement KU received a fixed rate of 7.92% and paid a variable
rate of 7.90% at December 31, 1999. The swap matures in 2004.

Note 5 - Concentrations of Credit and Other Risk

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

KU's customer receivables and revenues arise from deliveries of electricity to
about 458,000 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, 1999, 100% of total utility revenue was derived from electric
operations.

In August 1999, KU and their employees represented by IBEW Local 101 and USWA
Local 8686, which represents approximately 14% of KU's workforce, entered into a
one-year collective bargaining agreement.


                                      154
<PAGE>

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, 1999, and a statement
of the funded status as of December 31 for each of the last three years (in
thousands of $):

<TABLE>
<CAPTION>
                                                         1999          1998          1997
                                                         ----          ----          ----
<S>                                                 <C>           <C>           <C>
Pension Plans:
Change in benefit obligation
  Benefit obligation at beginning of year           $ 233,288     $ 214,657     $ 194,874
  Service cost                                          6,210         6,672         6,728
  Interest cost                                        15,564        15,043        14,680
  Plan amendment                                           --         2,226            --
  Acquisitions/divestitures                                --        (2,243)           --
  Curtailment (gain) or loss                               --         1,901            --
  Special termination benefits                             --         5,427            --
  Benefits paid                                       (12,822)      (12,762)      (13,313)
  Actuarial (gain) or loss                            (22,612)        2,367        11,688
                                                    ---------     ---------     ---------
  Benefit obligation at end of year                 $ 219,628     $ 233,288     $ 214,657
                                                    =========     =========     =========

Change in plan assets
  Fair value of plan assets at beginning of year    $ 238,124     $ 217,500     $ 191,879
  Actual return on plan assets                         49,883        31,209        35,066
  Employer contributions                                   --         2,273         4,750
  Benefits paid                                       (12,822)      (12,762)      (13,314)
  Administrative expenses                              (1,076)          (96)         (882)
                                                    ---------     ---------     ---------
  Fair value of plan assets at end of year          $ 274,109     $ 238,124     $ 217,499
                                                    =========     =========     =========

Reconciliation of funded status
  Funded status                                     $  54,481     $   4,835     $   2,843
  Unrecognized actuarial (gain) or loss               (74,579)      (26,487)      (19,552)
  Unrecognized transition (asset) or obligation          (988)       (1,128)       (1,350)
  Unrecognized prior service cost                       3,564         4,943         3,635
                                                    ---------     ---------     ---------
  Net amount recognized at year-end                 $ (17,522)    $ (17,837)    $ (14,424)
                                                    =========     =========     =========

Other Benefits:
Change in benefit obligation
  Benefit obligation at beginning of year           $  79,650     $  72,139     $  66,519
  Service cost                                          1,596         2,012         1,853
  Interest cost                                         3,837         5,207         4,895
  Plan amendments                                     (24,488)           --            --
  Curtailment (gain) or loss                               --         3,240            --
  Special termination benefits                             --            --        (4,038)
  Benefits paid                                        (4,646)       (2,617)           --
  Actuarial (gain) or loss                             (1,748)         (331)        2,910
                                                    ---------     ---------     ---------
  Benefit obligation at end of year                 $  54,201     $  79,650     $  72,139
                                                    =========     =========     =========

Change in plan assets
  Fair value of plan assets at beginning of year    $  24,337     $  17,763     $  13,270
  Actual return on plan assets                          7,612         5,117         3,569
  Employer contributions                                3,520         3,805         3,848
  Benefits paid                                        (4,459)       (2,348)       (2,924)
                                                    ---------     ---------     ---------
  Fair value of plan assets at end of year          $  31,010     $  24,337     $  17,763
                                                    =========     =========     =========
</TABLE>


                                      155
<PAGE>

<TABLE>
<CAPTION>
                                                       1999         1998         1997
                                                       ----         ----         ----
<S>                                                <C>          <C>          <C>
Reconciliation of funded status
  Funded status                                    $(23,191)    $(55,313)    $(54,376)
  Unrecognized actuarial (gain) or loss             (31,266)     (19,944)     (19,697)
  Unrecognized transition (asset) or obligation      23,694       45,701       50,118
                                                   --------     --------     --------
  Net amount recognized at year-end                $(30,763)    $(29,556)    $(23,955)
                                                   ========     ========     ========
</TABLE>

There are no plan assets in the non-qualified 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, 1999, 1998 and 1997 (in thousands of $):

<TABLE>
<CAPTION>
                                                             1999         1998         1997
                                                             ----         ----         ----
<S>                                                      <C>          <C>          <C>
Pension Plans:
Amounts recognized in the balance sheet
  consisted of:
     Accrued benefit liability                           $(17,522)    $(17,837)    $(14,424)
     Other                                                     --          (22)          --
                                                         --------     --------     --------
     Net amount recognized at year-end                   $(17,522)    $(17,859)    $(14,424)
                                                         ========     ========     ========

Additional year-end information for plans with
  benefit obligations in excess of plan assets:
     Projected benefit obligation                        $  1,132     $  2,300     $  6,199
     Accumulated benefit obligation                            40           99        3,975

Other Benefits:
Amounts recognized in the balance sheet consisted of:
     Accrued benefit liability                           $(30,763)    $(29,556)    $(23,955)
     Other                                                     --       (2,817)      (2,955)
                                                         --------     --------     --------
     Net amount recognized at year-end                   $(30,763)    $(32,373)    $(26,910)
                                                         ========     ========     ========

Additional year-end information for plans with
  benefit obligations in excess of plan assets:
     Projected benefit obligation                        $ 54,201     $ 79,650     $ 72,139
     Fair value of plan assets                             31,010       24,337       17,763
</TABLE>


                                      156
<PAGE>

The following table provides the components of net periodic benefit cost for the
plans for 1999, 1998 and 1997 (in thousands of $):

<TABLE>
<CAPTION>
                                                          1999         1998         1997
                                                          ----         ----         ----
<S>                                                   <C>          <C>          <C>
Pension Plans:
Components of net periodic benefit cost
  Service cost                                        $  6,211     $  6,673     $  6,728
  Interest cost                                         15,564       15,043       14,680
  Expected return on plan assets                       (21,957)     (18,264)     (15,427)
  Amortization of transition (asset) or obligation        (141)         435          354
  Amortization of prior service cost                       410         (146)        (150)
  Amortization of net (gain) loss                         (319)        (151)         (26)
                                                      --------     --------     --------
  Net periodic benefit cost                           $   (232)    $  3,590     $  6,159
                                                      ========     ========     ========

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                                        $  1,596     $  2,012     $  1,853
  Interest cost                                          3,837        5,207        4,895
  Expected return on plan assets                        (1,897)      (1,424)      (1,051)
  Amortization of transition (asset) or obligation       1,823        3,303        3,341
  Amortization of net (gain) loss                         (445)        (536)        (812)
                                                      --------     --------     --------
  Net periodic benefit cost                           $  4,914     $  8,562     $  8,226
                                                      ========     ========     ========

Special charges
  Curtailment loss                                    $     --     $  1,114     $     --
                                                      ========     ========     ========
</TABLE>

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. Under the provisions of the Supplemental Security
Plan (SERP), the Merger Agreement constituted a change-in-control which required
that a lump sum present value payment be made out of KU's SERP to retired
employees entitled to retirement benefits on the date of the Merger Agreement.
In May 1997, $4.7 million in lump sum payments were made to these retired
employees.

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.


                                      157
<PAGE>

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

                                                       1999     1998     1997
                                                       ----     ----     ----

Weighted-average assumptions as of December 31:
  Discount rate                                       8.00%    7.00%    7.75%
  Expected long-term rate of return on plan assets    9.50%    8.25%    8.25%
  Rate of compensation increase                       5.00%    4.00%    4.75%

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 4.75% 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 $):

<TABLE>
<CAPTION>
                                                                    1% Decrease     1% Increase
                                                                    -----------     -----------
<S>                                                                    <C>              <C>
Effect on total of service and interest cost components for 1999       $   (366)        $   423
Effect on year-end 1999 postretirement benefit obligations               (4,029)          4,650
</TABLE>

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 $2.3 million for 1999 and $2.2 million for each of 1998 and 1997.

Note 7 - Income Taxes

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

                                                 1999         1998       1997
                                                 ----         ----       ----

Included in operating expenses:
  Current         - federal                   $50,969      $46,321    $39,353
                  - state                      13,459       10,245      8,964
  Deferred        - federal - net              (4,833)      (3,186)     1,996
                  - state - net                   785         (124)     1,377
                                              -------      -------    -------
     Total                                     60,380       53,256     51,690

Included in other income and (deductions):
  Current         - federal                     1,028         (617)      (853)
                  - state                          54         (237)      (246)
  Deferred        - federal - net                 182          694        975
                  - state - net                   102          178        258
  Amortization of investment tax credit        (3,727)      (3,829)    (4,036)
                                              -------      -------    -------
     Total                                     (2,361)      (3,811)    (3,902)
                                              -------      -------    -------

Total income tax expense                      $58,019      $49,445    $47,788
                                              =======      =======    =======


                                      158
<PAGE>

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

                                                            1999            1998
                                                            ----            ----
Deferred tax liabilities:
  Depreciation and other
     plant-related items                                $313,202        $289,147
  Other liabilities                                       11,286           5,598
                                                        --------        --------
                                                         324,488         294,745
                                                        --------        --------

Deferred tax assets:
  Investment tax credit                                    7,497           9,001
  Income taxes due to customers                           16,712          17,574
  Accrued liabilities not currently
     deductible and other                                  5,797           6,162
  Less:  amounts included in
     current assets                                       50,862          17,515
                                                        --------        --------
                                                          80,868          50,252
                                                        --------        --------

Net deferred income tax liability                       $243,620        $244,493
                                                        ========        ========

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

                                                  1999        1998        1997
                                                  ----        ----        ----

Statutory federal income tax rate                 35.0%       35.0%       35.0%
State income taxes net of federal benefit          5.7         5.4         5.0
Amortization of investment tax credit             (2.9)       (3.1)       (3.0)
Nondeductible merger expenses                       --         6.4          --
Other differences - net                           (2.5)       (2.2)       (1.2)
                                                ------      ------      ------

Effective income tax rate                         35.3%       41.5%       35.8%
                                                ======      ======      ======

Note 8 - Other Income and Deductions

Other income and deductions consisted of the following at December 31 (in
thousands of $):

                                                   1999        1998        1997
                                                   ----        ----        ----

Equity in earnings - subsidiary company         $ 2,334     $ 2,167     $ 2,480
Interest and dividend income                      4,293       1,811       1,673
Gains (losses) on fixed asset disposal              759         272         412
Donations                                          (107)       (453)       (388)
Income taxes and other                            2,158       4,049       2,826
                                                -------     -------     -------

Net other income                                $ 9,437     $ 7,846     $ 7,003
                                                =======     =======     =======


                                      159
<PAGE>

Note 9 - First Mortgage Bonds and Pollution Control Bonds

Long-term debt and the current portion of long-term debt, summarized below in
thousands, 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, 1999.

Stated interest rates                                         5.75% - 8.55%
Weighted-average interest rate                                        7.02%
Maturities                                                      2003 - 2027
Noncurrent portion at December 31, 1999                            $430,830
Current portion at December 31, 1999                               $115,500

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 were 3.35% for KU's bonds.

Maturities of KU's first mortgage bonds and pollution control bonds (principal
amounts stated in thousands of $) at December 31, 1999, are summarized below.

2001                                               $     --
2002
2003                                                 62,000
2004                                                     --
2005                                                     --
Thereafter                                          368,830
                                                   --------
Total                                              $430,830
                                                   ========

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

Note 10 - Notes Payable

KU's short-term financing requirements are satisfied through the sale of
commercial paper. KU had no short-term borrowings at December 31, 1999, and
1998.

The KU credit facilities that provided for short-term borrowing and support of
commercial paper borrowing expired on December 31, 1999.

Note 11 - Commitments and Contingencies

Construction Program. KU had $13.8 million of commitments in connection with its
construction program at December 31, 1999. Construction expenditures for the
years 2000 and 2001 are estimated to total approximately $324 million.

Operating Leases. KU leases office space, office equipment, and vehicles. KU
accounts for these leases as operating leases. Total lease expense for 1999,
1998, and 1997, was $1.7 million, $1.9 million, and $1.8 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 has


                                      160
<PAGE>

been deferred pending resolution of rate treatment by the Kentucky Commission.

Environmental. The 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,
commencing 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
significant additional reductions in NOx emissions by May 2003, in order to
mitigate alleged ozone transport to the Northeast. While each of the 22 states
covered by the rule is free to allocate its assigned NOx reductions among
various emissions sectors as it deems appropriate, the regulation may ultimately
require electric generating units to reduce their NOx emissions to 0.15
lb./Mmbtu - an 85% reduction from 1990 levels. In related proceedings in
response to petitions filed by various Northeast states, in December 1999, EPA
issued a final rule directing similar NOx reductions from a number of
specifically named electric generating units including all KU stations in the
eastern half of Kentucky. Additional petitions currently pending before EPA may
potentially result in orders encompassing the remaining KU stations. Several
states, various labor and industry groups, and individual companies have
appealed both EPA rulings to the U.S. Court of Appeals for the Washington D.C.
Circuit. Management is currently unable to determine the outcome or exact impact
of this matter until such time as the courts rule on the pending legal
challenges and the states implement the final regulatory mandate. However, if
the 0.15 lb. target is ultimately imposed, KU will be required to incur
significant capital expenditures and increased operation and maintenance costs
for additional controls.

Subject to further study, analysis, and the outcome of pending litigation
against the EPA, KU estimates that it may incur approximate capital costs for
NOx compliance ranging from $126 million to reduce emissions to the level of .25
lb./Mmbtu (Commonwealth of Kentucky's proposed NOx compliance level) to $168
million to reduce emissions to the level of .15 lb./Mmbtu (current EPA
regulations). These costs would generally be incurred beginning in 2000. 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 mechanisms and believe 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.

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 unable to determine what, if any, additional exposure
or liability it may have as it lacks complete information on current site
conditions.

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


                                      161
<PAGE>

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. To date KU has incurred costs of
approximately $1 million. The Company does not expect to incur any material
additional amounts.

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 2000-2004, which is expected to be
approximately 7% 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
$172 million of OMU bonds outstanding at December 31, 1999. The debt service is
allocated to KU based on its annual allocated share of capacity, which averaged
approximately 46% in 1999.

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 2000 - 2004 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, 2004, are as follows (in thousands of $):

2000                                             $ 28,765
2001                                               31,495
2002                                               30,683
2003                                               30,947
2004                                               31,155
                                                 --------
Total                                            $153,045
                                                 ========

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.


                                      162
<PAGE>

Note 13 - Selected Quarterly Data (Unaudited)

Selected financial data for the four quarters of 1999 and 1998 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 $)
1999
----
Revenues                       $217,349    $ 225,794     $281,503    $212,664
Operating income                 36,966       34,997       32,529      31,524
Net income                       29,628       27,757       24,426      24,747
Net income available
  for common stock               29,064       27,193(a)    23,862(b)   24,183(c)

1998
----
Revenues                       $183,219    $ 193,079     $246,117    $187,699
Operating income                 33,035       28,144       44,677      19,532
Net income (loss)                25,049       (1,119)      36,980      11,854
Net income (loss) available
  for common stock               24,485       (1,683)      36,416      11,290

(a)   The increase of $28.9 million compared to June 1998 was primarily due to a
      non-recurring after-tax charge of $21.5 million from merger-related
      expenses.

(b)   The decrease of $12.6 million compared to September 1998 was primarily due
      to a charge to record a net provision for the refund of certain revenues
      under the FAC and ECR.

(c)   The increase of $12.9 million compared to December 1998 was primarily due
      to a charge to refund certain amounts collected under the ECR.

Note 14 - Subsequent Events

On February 28, 2000, LG&E Energy announced that its Board of Directors
accepted an 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 will become a wholly owned subsidiary of PowerGen and its U.S.
headquarters. The Utility Operations of the Company will continue their
separate identities and serve customers in Kentucky and Virginia under their
present names. The preferred stock and debt securities of the Utility
Operations will not be affected by this transaction resulting in the Utility
Operations' obligation to continue to file SEC reports. The acquisition is
expected to close 9 to 12 months from the announcement, shortly after all of
the conditions to consummation of the acquisition are met. Those conditions
include, without limitation, the approval of the holders of a majority of the
outstanding shares of common stock of each of LG&E Energy and PowerGen, the
receipt of all necessary governmental approvals and the making of all
necessary governmental filings, including approvals of various regulators in
Kentucky and Virginia under state utility laws, the approval of the Federal
Energy Regulatory Commission under the Federal Power Act, the approval of the
SEC under the Public Utility Holding Company Act of 1935, and the filing of
requisite notifications with the Federal Trade Commission and the Department
of Justice under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as
amended, and the expiration of all applicable waiting periods thereunder.
Shareholder meetings to vote upon the approval of the acquisition are
expected to be held during the second quarter of 2000 for both LG&E Energy
and PowerGen. During the first quarter of 2000, the Company expensed
approximately $1.0 million relating to the PowerGen transaction. The
foregoing

                                      163
<PAGE>

description of the acquisition does not purport to be complete and is qualified
in its entirety by reference to LG&E Energy's current reports on Form 8-K, filed
February 29, 2000, with the SEC.

On March 3, 2000, the U.S. Court of Appeals for the Washington D.C. Circuit
issued a final opinion upholding the NOx SIP call rule requiring electric
generating units to reduce their NOx emissions to 0.15 lb./Mmbtu by May 2003.
Some of the litigants will likely seek further judicial review of the ruling.

In the first quarter of 2000, KU will take a restructuring charge relating to
the reduction of positions and the integration of LG&E's and KU's operations,
including combining retail gas and electric operations, consolidation of
customer service centers and the redesigning various other processes.

The Kentucky Commission responded to the motions filed by KU for computational
and other errors made in Orders received on base rate reductions in February
2000 by reducing KU's annual revenue reductions by $2.5 million and granting
rehearings on other issues.


                                      164
<PAGE>

                           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, 1998, 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.


                                      165
<PAGE>

                           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, 1999 and 1998,
and the related statements of income, retained earnings and cash flows for each
of the three years in the period ended December 31, 1999. 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.

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

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Kentucky Utilities Company as
of December 31, 1999 and 1998, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 1999, 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, 2000 (Except with respect
to the matters discussed in Note 14, as
to which the date is March 3, 2000.)


                                      166
<PAGE>

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 Energy and
LG&E is incorporated herein by reference to their respective definitive proxy
statements to be filed during April 2000 with the Commission pursuant to
Regulation 14A of the Securities and Exchange Act of 1934. The information
required by ITEMS 10, 11, 12 and 13 for KU is incorporated herein by reference
to the material appearing in Exhibit 99.03, which is filed herewith.
Additionally, in accordance with General Instruction G, the information required
by ITEM 10 relating to executive officers of LG&E Energy, 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 Energy:
      Consolidated statements of income for the three years ended December
      31, 1999 (page 75).
      Consolidated statements of retained earnings for the three years
      ended December 31, 1999 (page 76).
      Consolidated statements of comprehensive income for the three years
      ended December 31, 1999 (page 76)
      Consolidated balance sheets - December 31, 1999, and 1998 (page 77).
      Consolidated statements of cash flows for the three years ended
      December 31, 1999 (page 78).
      Consolidated statements of capitalization - December 31, 1999, and
      1998 (page 79).
      Notes to consolidated financial statements (pages 81-116).
      Report of management (page 117).
      Report of independent public accountants (page 118).

      LG&E:
      Statements of income for the three years ended December 31, 1999
      (page 119).
      Statements of retained earnings for the three years ended December
      31, 1999 (page 119).
      Statements of comprehensive income for the three years ended December
      31, 1999 (page 120).
      Balance sheets - December 31, 1999, and 1998 (page 121).
      Statements of cash flows for the three years ended December 31, 1999
      (page 122).
      Statements of capitalization - December 31, 1999, and 1998 (page
      123).
      Notes to financial statements (pages 124-142).
      Report of management (page 143).
      Report of independent public accountants (page 144).
                                     167
<PAGE>

      KU:
      Statements of income for the three years ended December 31, 1999
      (page 145).
      Statements of retained earnings for the three years ended December
      31, 1999 (page 145).
      Balance sheets - December 31, 1999, and 1998 (page 146).
      Statements of cash flows for the three years ended December 31, 1999
      (page 147).
      Statements of capitalization - December 31, 1999, and 1998 (page
      148).
      Notes to financial statements (pages 149-164).
      Report of management (page 165).
      Report of independent public accountants (page 166).

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

      Schedule II         Valuation and Qualifying Accounts for the
                          three years ended December 31, 1999, for LG&E
                          Energy (page 192), LG&E (page 193), and KU (page 194).

      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:

           Applicable
         to Form 10-K of

Exhibit  LG&E
No.     Energy  LG&E    KU    Description
---     ------  ----    --    -----------

2.01       x      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
                              Energy's Current Report on Form 8-K filed
                              February 29, 2000 and incorporated by
                              reference herein]

2.02       x      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
                              Energy's Current Report on Form 8-K filed May
                              30, 1997 and incorporated by reference
                              herein]

3.01       x                  Copy of LG&E Energy's Amended and Restated
                              Articles of Incorporation dated May 4, 1998.
                              [Filed as Exhibit 4.1 to LG&E Energy's
                              Current Report on Form 8-K dated May 4, 1998,
                              and incorporated by reference herein]

3.02              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]

3.03       x                  Copy of Bylaws of LG&E Energy, as amended
                              through June 2, 1999.


                                    168
<PAGE>

           Applicable
         to Form 10-K of

Exhibit  LG&E
No.     Energy  LG&E    KU    Description
---     ------  ----    --    -----------

3.04              x           Copy of By-Laws of LG&E, as amended through
                              June 2, 1999.

3.05                    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]

3.06                    x     Copy of By-laws of KU, as amended through
                              June 2, 1999.

4.01       x      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      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      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      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      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      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      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      x           Copy of Supplemental Indenture dated June 1,
                              1970, which is a


                                    169
<PAGE>

           Applicable
         to Form 10-K of

Exhibit  LG&E
No.     Energy  LG&E    KU    Description
---     ------  ----    --    -----------

                              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      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      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      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      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      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      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      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      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      x           Copy of Supplemental Indenture dated
                              September 1, 1979, which


                                    170
<PAGE>

           Applicable
         to Form 10-K of

Exhibit  LG&E
No.     Energy  LG&E    KU    Description
---     ------  ----    --    -----------

                              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      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      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      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      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      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      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      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      x           Copy of Supplemental Indenture dated November
                              15, 1986,


                                    171
<PAGE>

           Applicable
         to Form 10-K of

Exhibit  LG&E
No.     Energy  LG&E    KU    Description
---     ------  ----    --    -----------

                              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      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      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      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      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      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      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      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]


                                    172
<PAGE>

           Applicable
         to Form 10-K of

Exhibit  LG&E
No.     Energy  LG&E    KU    Description
---     ------  ----    --    -----------

4.33       x      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      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      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      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            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


                                    173
<PAGE>

           Applicable
         to Form 10-K of

Exhibit  LG&E
No.     Energy  LG&E    KU    Description
---     ------  ----    --    -----------

                              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.

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

10.01      x      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      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      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


                                    174
<PAGE>

           Applicable
         to Form 10-K of

Exhibit  LG&E
No.     Energy  LG&E    KU    Description
---     ------  ----    --    -----------

                              Registration Statement 2-61607 and
                              incorporated by reference herein]

10.04      x      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      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     x     Copies of (i) Inter-Company Power Agreement,
                              dated July 10, 1953, between Ohio Valley
                              Electric Corporation and Sponsoring Companies
                              (which Agreement includes as Exhibit A the
                              Power Agreement, dated July 10, 1953, between
                              Ohio Valley Electric Corporation and
                              Indiana-Kentucky Electric Corporation); (ii)
                              First Supplementary Transmission Agreement,
                              dated July 10, 1953, between Ohio Valley
                              Electric Corporation and Sponsoring
                              Companies; (iii) Inter-Company Bond
                              Agreement, dated July 10, 1953, between Ohio
                              Valley Electric Corporation and Sponsoring
                              Companies; (iv) Inter-Company Bank Credit
                              Agreement, dated July 10, 1953, between Ohio
                              Valley Electric Corporation and Sponsoring
                              Companies. [Filed as Exhibit 5.02f to LG&E's
                              Registration Statement 2-61607 and
                              incorporated by reference herein]

10.07      x      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      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      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


                                    175
<PAGE>

           Applicable
         to Form 10-K of

Exhibit  LG&E
No.     Energy  LG&E    KU    Description
---     ------  ----    --    -----------

                              Companies. [Filed as Exhibit 5.02i to LG&E's
                              Registration Statement 2-61607 and
                              incorporated by reference herein]

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

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

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

10.14      x      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     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      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      x           Copy of Modification No. 8 dated June 23,
                              1977, to the Power Agreement between Ohio
                              Valley Electric Corporation and


                                    176
<PAGE>

           Applicable
         to Form 10-K of

Exhibit  LG&E
No.     Energy  LG&E    KU    Description
---     ------  ----    --    -----------

                              Atomic Energy Commission. [Filed as Exhibit
                              5.02q to LG&E's Registration Statement
                              2-61607 and incorporated by reference herein]

10.18      x      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      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      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     x     Copy of Modification No. 5 dated September 1,
                              1979, to Inter-Company Power Agreement dated
                              July 5, 1953, among Ohio Valley Electric
                              Corporation and Sponsoring Companies. [Filed
                              as Exhibit 4 to LG&E's Annual Report on Form
                              10-K for the year ended December 31, 1979,
                              and incorporated by reference herein]

10.22      x      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     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      x      x           * Copy of LG&E Energy Corp. Deferred Stock
                              Compensation Plan effective January 1, 1992,
                              covering non-employee directors of the
                              Company and its subsidiaries. [Filed as
                              Exhibit 10.34 to


                                    177
<PAGE>

           Applicable
         to Form 10-K of

Exhibit  LG&E
No.     Energy  LG&E    KU    Description
---     ------  ----    --    -----------

                              the Company's Annual Report on Form 10-K
                              for the year ended December 31, 1991, and
                              incorporated by reference herein]

10.25      x      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      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      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      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     x     Copy of Modification No. 7 dated January 15,
                              1992, to Inter-Company Power Agreement dated
                              July 10, 1953, among Ohio Valley Electric
                              Corporation and Sponsoring Companies. [Filed
                              as Exhibit 10.44 to LG&E's Annual Report on
                              Form 10-K for the year ended December 31,
                              1993, and incorporated by reference herein]

10.30      x      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      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 Corpora-


                                    178
<PAGE>

           Applicable
         to Form 10-K of

Exhibit  LG&E
No.     Energy  LG&E    KU    Description
---     ------  ----    --    -----------

                              tion 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      x      x     x     * Copy of LG&E Energy Corp. Stock Option Plan
                              for Non-Employee Directors. [Filed as Exhibit
                              10.51 to the Company's Annual Report on Form
                              10-K for the year ended December 31, 1993,
                              and incorporated by reference herein]

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

10.36      x      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]


                                    179
<PAGE>

           Applicable
         to Form 10-K of

Exhibit  LG&E
No.     Energy  LG&E    KU    Description
---     ------  ----    --    -----------

10.37      x      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      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      x      x     x     * Copy of Amended and Restated Omnibus
                              Long-Term Incentive Plan effective January 1,
                              1996, covering officers and key employees of
                              the Company. [Filed as Exhibit 10.52 to the
                              Company's Annual Report on Form 10-K for the
                              year ended December 31, 1995, and
                              incorporated by reference herein]

10.40      x      x     x     * Copy of Short-Term Incentive Plan effective
                              January 1, 1996, covering officers and key
                              employees of the Company. [Filed as Exhibit
                              10.53 to the Company's Annual Report on Form
                              10-K for the year ended December 31, 1995,
                              and incorporated by reference herein]

10.41      x      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      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      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]


                                    180
<PAGE>

           Applicable
         to Form 10-K of

Exhibit  LG&E
No.     Energy  LG&E    KU    Description
---     ------  ----    --    -----------

10.44      x      x           Copy of Form of Master Gas Purchase
                              Agreement, dated December 14, 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      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      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      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      x      x           Copy of Power Purchase and Sale Agreement,
                              dated as of November 19, 1996, among the
                              Company, LG&E Power Marketing Inc., and
                              Oglethorpe Power Corporation. [Filed as
                              Exhibit 10.66 to LG&E Energy's Annual Report
                              on Form 10-K for the year ended December 31,
                              1996, 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]

10.49      x      x           Copy of Power Purchase and Sale Agreement,
                              dated as of January 1, 1997, among LG&E Power
                              Marketing Inc., LG&E Power Inc., and
                              Oglethorpe Power Corporation. [Filed as
                              Exhibit 10.67 to LG&E Energy's Annual Report
                              on Form 10-K for the year ended December 31,
                              1996, and incorporated by reference herein]
                              [Certain portions of this exhibit have been
                              omitted pursuant to a confidential treatment
                              request filed with the Secu-


                                    181
<PAGE>

           Applicable
         to Form 10-K of

Exhibit  LG&E
No.     Energy  LG&E    KU    Description
---     ------  ----    --    -----------

                              rities and Exchange Commission]

10.50      x                  Copy of U.S. $500,000,000 Credit Agreement,
                              dated as of September 5, 1997, among LG&E
                              Capital Corp., as Borrower, and the Banks
                              named therein, as Lenders, and Chase
                              Securities Inc., as Syndication Agent, Bank
                              of Montreal, as Administrative Agent, and
                              Morgan Guaranty Trust Company of New York,
                              PNC Bank, Kentucky, Inc., The Bank of New
                              York, The First National Bank of Chicago and
                              Wachovia Bank, N.A., as Co-Agents. [Filed as
                              Exhibit 10.01 to LG&E Energy's Quarterly
                              Report on Form 10-Q for the quarter ended
                              September 30, 1997, and incorporated by
                              reference herein]

10.51      x                  Copy of U.S. $ 200,000,000 Credit Agreement,
                              dated as of September 5, 1997, among LG&E
                              Capital Corp., as Borrower, and the Banks
                              named therein, as Lenders, and Chase
                              Securities Inc., as Syndication Agent, Bank
                              of Montreal, as Administrative Agent, and
                              Morgan Guaranty Trust Company of New York,
                              PNC Bank, Kentucky, Inc., The Bank of New
                              York, The First National Bank of Chicago and
                              Wachovia Bank, N.A., as Co-Agents. [Filed as
                              Exhibit 10.02 to LG&E Energy's Quarterly
                              Report on Form 10-Q for the quarter ended
                              September 30, 1997, and incorporated by
                              reference herein]

10.52      x                  Copy of Support Agreement, dated as of
                              September 5, 1997, between LG&E Energy Corp.
                              and LG&E Capital Corp. [Filed as Exhibit
                              10.03 to LG&E Energy's Quarterly Report on
                              Form 10-Q for the quarter ended September 30,
                              1997, and incorporated by reference herein]

10.53      x                  KU Energy Stock Option Agreement, dated as of
                              May 20, 1997, by and between KU Energy and
                              LG&E Energy. [Filed as Exhibit 99.1 to the
                              Company's Current Report on Form 8-K filed
                              May 30, 1997 and incorporated by reference
                              herein]

10.54      x                  Copy of LG&E Energy Stock Option Agreement,
                              dated as of May 20, 1997, by and between KU
                              Energy and LG&E Energy. [Filed as Exhibit
                              99.2 to the Company's Current Report on Form
                              8-K filed May 30, 1997 and incorporated by
                              reference herein]

10.55      x      x     x     * Copy of Employment Agreement between LG&E
                              Energy and Roger W. Hale dated May 20, 1997,
                              effective May 4, 1998. [Filed as Annex D to
                              Exhibit 2.01 of LG&E Energy's Annual Report
                              on Form 10-K for the year ended December 31,
                              1997, and incorporated by reference herein]


                                    182
<PAGE>

           Applicable
         to Form 10-K of

Exhibit  LG&E
No.     Energy  LG&E    KU    Description
---     ------  ----    --    -----------

10.56      x      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      x                  Copy of Indenture between LG&E Capital Corp.
                              and the Bank of New York as Trustee dated as
                              of January 15, 1998. [Filed as Exhibit 10.72
                              to LG&E Energy's Annual Report on Form 10-K
                              for the year ended December 31, 1997, and
                              incorporated by reference herein]

10.58      x                  Copy of First Supplemental Indenture between
                              LG&E Capital Corp. and The Bank of New York
                              as Trustee dated as of January 15, 1998.
                              [Filed as Exhibit 10.73 to LG&E Energy's
                              Annual Report on Form 10-K for the year ended
                              December 31, 1997, and incorporated by
                              reference herein]

10.59      x      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      x      x     x     * Copy of form of Change in Control Agreement
                              for officers of LG&E Energy Corp. [Filed as
                              Exhibit 10.75 to LG&E Energy's Annual Report
                              on Form 10-K for the year ended December 31,
                              1997, and incorporated by reference herein]

10.61      x      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      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      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


                                    183
<PAGE>

           Applicable
         to Form 10-K of

Exhibit  LG&E
No.     Energy  LG&E    KU    Description
---     ------  ----    --    -----------

                              Report on Form 10-K for the year ended
                              December 31, 1997, and incorporated by
                              reference herein]

10.64      x      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      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.]

10.67                         [Not used.]

10.68                         [Not used.]

10.69                         [Not used.]

10.70                         [Not used.]

10.71                         [Not used.]

                                    184
<PAGE>

           Applicable
         to Form 10-K of

Exhibit  LG&E
No.     Energy  LG&E    KU    Description
---     ------  ----    --    -----------


10.72                         [Not used.]

10.73                         [Not used.]

10.74      x            x     * KU Energy's Long-Term Incentive Plan [Filed
                              as Exhibit 10.27 to Form 10-K Annual Report
                              of KU Energy for the year ended December 31,
                              1996, and incorporated by reference herein]

10.75      x                  * Employment Agreement by and between KU
                              Energy Corporation and Michael R. Whitley
                              [Filed as Exhibit (2)-5 to S-4 Registration
                              Statement File No. 333-34219; Annex E to Form
                              DEFM14A Joint Proxy Statement of LG&E Energy
                              Corp. and KU Energy Corporation dated August
                              22, 1997, and incorporated by reference
                              herein]

10.76      x      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      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 incorporated by
                              reference herein]

10.78                         [Not used.]

10.79                         [Not used.]


                                    185
<PAGE>

           Applicable
         to Form 10-K of

Exhibit  LG&E
No.     Energy  LG&E    KU    Description
---     ------  ----    --    -----------

10.80      x            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            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            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      x                  Copy of New Participation Agreement dated
                              April 6, 1998, among Big Rivers Electric
                              Corporation. LG&E Energy Marketing Inc.,
                              Western Kentucky Leasing Corp., WKE Station
                              Two Inc. and Western Kentucky Energy Corp.
                              [Certain portions of this exhibit have been
                              omitted pursuant to a confidential treatment
                              request filed with the Securities and
                              Exchange Commission.] [Filed as Exhibit 10.83
                              to LG&E Energy's Annual Report on Form 10-K
                              for the year ended December 31, 1998 and
                              incorporated by reference herein]

10.84      x                  Copy of Letter Agreement from WKE Station Two
                              Inc. to Big Rivers Electric Corporation dated
                              April 6, 1998 amending New Participation
                              Agreement dated April 6, 1998 among Big
                              Rivers Electric Corporation. LG&E Energy
                              Marketing Inc., Western Kentucky Leasing
                              Corp., WKE Station Two Inc. and Western
                              Kentucky Energy Corp. [Certain portions of
                              this exhibit have been omitted pursuant to a
                              confidential treatment request filed with the
                              Securities and Exchange Commission.] [Filed
                              as Exhibit 10.84 to LG&E Energy's Annual
                              Report on Form 10-K for the year ended
                              December 31, 1998 and incorporated by
                              reference herein]


                                    186
<PAGE>

           Applicable
         to Form 10-K of

Exhibit  LG&E
No.     Energy  LG&E    KU    Description
---     ------  ----    --    -----------

10.85      x                  Copy of Second Amendment dated June 15, 1998
                              to New Participation Agreement dated April 6,
                              1998 among Big Rivers Electric Corporation.
                              LG&E Energy Marketing Inc., Western Kentucky
                              Leasing Corp., WKE Station Two Inc. and
                              Western Kentucky Energy Corp. [Certain
                              portions of this exhibit have been omitted
                              pursuant to a confidential treatment request
                              filed with the Securities and Exchange
                              Commission.] [Filed as Exhibit 10.85 to LG&E
                              Energy's Annual Report on Form 10-K for the
                              year ended December 31, 1998 and incorporated
                              by reference herein]

10.86      x                  Copy of Third Amendment dated July 15, 1998
                              to New Participation Agreement dated April 6,
                              1998 among Big Rivers Electric Corporation.
                              LG&E Energy Marketing Inc., Western Kentucky
                              Leasing Corp., WKE Station Two Inc. and
                              Western Kentucky Energy Corp. [Certain
                              portions of this exhibit have been omitted
                              pursuant to a confidential treatment request
                              filed with the Securities and Exchange
                              Commission.] [Filed as Exhibit 10.86 to LG&E
                              Energy's Annual Report on Form 10-K for the
                              year ended December 31, 1998 and incorporated
                              by reference herein]

10.87      x                  Copy of Form of Lease and Operating Agreement
                              Between Western Kentucky Energy Corp. and Big
                              Rivers Electric Corporation dated July 15,
                              1998. [Certain portions of this exhibit have
                              been omitted pursuant to a confidential
                              treatment request filed with the Securities
                              and Exchange Commission.] [Filed as Exhibit
                              10.87 to LG&E Energy's Annual Report on Form
                              10-K for the year ended December 31, 1998 and
                              incorporated by reference herein]

10.88      x                  Copy of Power Purchase Agreement Between Big
                              Rivers Electric Corporation and LG&E Energy
                              Marketing Inc. dated July 15, 1998. [Certain
                              portions of this exhibit have been omitted
                              pursuant to a confidential treatment request
                              filed with the Securities and Exchange
                              Commission.] [Filed as Exhibit 10.88 to LG&E
                              Energy's Annual Report on Form 10-K for the
                              year ended December 31, 1998 and incorporated
                              by reference herein]

10.89      x                  Copy of Agreement and Amendments to
                              Agreements By and Among City of Henderson,
                              Kentucky, City of Henderson Utility


                                    187
<PAGE>

           Applicable
         to Form 10-K of

Exhibit  LG&E
No.     Energy  LG&E    KU    Description
---     ------  ----    --    -----------

                              Commission, Big Rivers Electric Corporation,
                              WKE Station Two Inc., LG&E Energy Marketing
                              Inc., and Western Kentucky Energy Corp. dated
                              July 15, 1998. [Filed as Exhibit 10.89 to
                              LG&E Energy's Annual Report on Form 10-K for
                              the year ended December 31, 1998 and
                              incorporated by reference herein]

10.90      x      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     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      x                  Copy of Terms Agreement among LG&E Capital
                              Corp., LG&E Energy Corp., Morgan Stanley &
                              Co. Incorporated, Chase Securities Inc.,
                              Merrill Lynch, Pierce, Fenner & Smith
                              Incorporated and J.P. Morgan Securities Inc.
                              dated October 29, 1998. [Filed as Exhibit
                              10.92 to LG&E Energy's Annual Report on Form
                              10-K for the year ended December 31, 1998 and
                              incorporated by reference herein]

10.93      x      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]

10.94      x      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.

10.95      x      x     x     * Copy of Amendment dated as of April
                              21, 1999, to Amended and Restated Omnibus
                              Long-Term Incentive Plan, covering officers
                              and key employees of LG&E Energy.

10.96      x      x     x     * Copy of Amendment, effective October 1,
                              1999, to LG&E Energy's Non-Qualified Savings
                              Plan.

10.97      x      x     x     * Copy of Amendment, effective December 1,
                              1999, to LG&E


                                    188
<PAGE>

           Applicable
         to Form 10-K of

Exhibit  LG&E
No.     Energy  LG&E    KU    Description
---     ------  ----    --    -----------

                              Energy's Non-Qualified Savings Plan.

10.98                         [Not used.]

10.99      x                  Copy of Agency Agreement, dated September 1,
                              1999, between LG&E Capital Corp. and Wachovia
                              Securities Inc.

10.100     x                  Copy of Terms Agreement, dated May 4, 1999,
                              among LG&E Capital Corp., J.P. Morgan Securities
                              Inc., Chase Securities Inc. and Merrill Lynch
                              & Co.

10.101     x                  Copy of Second Supplemental Indenture, dated
                              as of September 1, 1999 between LG&E Capital
                              Corp. and The Bank of New York as Trustee.

10.102     x      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.

10.103     x      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.

10.104     x      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.

10.105     x      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.

10.106     x      x           Copy of Letter Amendment, dated September 15,
                              1999, to Transportation Agreement, dated
                              November 1, 1993, between LG&E and Texas Gas
                              Transmission Corporation.

12                x     x     Computation of Ratio of Earnings to Fixed
                              Charges for LG&E and KU.

21         x      x     x     Subsidiaries of the Registrant.

23.01      x                  Consent of Independent Public Accountants for
                              LG&E Energy Corp.

23.02             x           Consent of Independent Public Accountants for
                              LG&E.

23.03                   x     Consent of Independent Public Accountants for
                              KU.

24         x      x     x     Power of Attorney.

27         x      x     x     Financial Data Schedules for LG&E Energy
                              Corp., LG&E and KU.

99.01      x      x     x     Cautionary Statement for purposes of the
                              "Safe Harbor" provisions of the Private
                              Securities Litigation Reform Act of 1995.

99.02      x                  Description of Common Stock.

99.03                   x     Director and Officer Information.

(b)   Executive Compensation Plans and Arrangements:

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


                                      189
<PAGE>

(c)   Reports on Form 8-K:

      On December 21, 1999, the Company filed a report on Form 8-K announcing
      that LG&E Energy, LG&E and KU realigned their management structures to
      support their efforts to prepare for the changing energy marketplace.

      On January 6, 2000, the Company filed a report on Form 8-K announcing that
      on December 21, 1999, it received an adverse order from the arbitration
      panel considering its contract dispute with OPC.

      On January 25, 2000, the Company filed a report on Form 8-K announcing
      that on January 7, 2000, it issued a statement regarding the Kentucky
      Commission's decision in the PBR case involving its two utility
      subsidiaries, LG&E and KU.

      On February 29, 2000, the Company filed a report on Form 8-K announcing
      that on February 27, 2000, it and PowerGen entered into an Agreement and
      Plan of Merger.

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

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

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

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

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

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

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

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


                                      190
<PAGE>

      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.


                                      191
<PAGE>

                                                                     Schedule II

                       LG&E Energy Corp. and Subsidiaries
                 Schedule II - Valuation and Qualifying Accounts
                   For the Three Years Ended December 31, 1999
                                (Thousands of $)

<TABLE>
<CAPTION>
                                                                                                              (b)
                                                                                              (a)     Accumulated
                                                           Other         Accounts         Discon-        Deferred
                                                        Property       Receivable          tinued    Income Taxes
                                                             and   (Uncollectible      Operations     (NOL Carry-
                                                     Investments        Accounts)         Reserve        forwards)
                                                     -----------        ---------         -------        ---------
<S>                                                      <C>             <C>             <C>              <C>
Balance December 31, 1996                                $18,966         $ 7,121         $     --         $25,601

Additions:
    Charged to costs and expenses                         11,875           5,356               --              --
    Other additions                                        7,570           1,997               --              --
Deductions:
    Net charges of nature for which
       reserves were created                                 354           4,212               --              --
    Other deductions                                          --              75               --              --
                                                         -------         -------         --------         -------

Balance December 31, 1997                                 38,057          10,187               --          25,601

Additions:
    Charged to costs and expenses                         23,791           4,770          224,148              --
    Other additions                                        1,750             248               --              --
Deductions:
    Net charges of nature for which
       reserves were created                              11,399           4,648          104,767              --
    Other deductions                                         108              25               --              --
                                                         -------         -------         --------         -------

Balance December 31, 1998                                 52,091          10,532          119,381          25,601

Additions:
    Charged to costs and expenses                         26,956           4,746          174,212              --
    Other additions                                           --           1,030               --              --
Deductions:
    Net charges of nature for which
       reserves were created                               6,890           8,023          122,895           2,815
                                                         -------         -------         --------         -------

Balance December 31, 1999                                $72,157         $ 8,285         $170,698         $22,786
                                                         =======         =======         ========         =======
</TABLE>

(a)   Amounts presented are after tax.
(b)   Partially offsets a deferred tax debit included in net assets of
      discontinued operations. The debit represents net operating loss
      carryforwards available from a previous acquisition.


                                      192
<PAGE>

                                                                     Schedule II

                      Louisville Gas and Electric Company
                 Schedule II - Valuation and Qualifying Accounts
                   For the Three Years Ended December 31, 1999
                                (Thousands of $)

                                                       Other           Accounts
                                                    Property         Receivable
                                                         and     (Uncollectible
                                                 Investments           Accounts)
                                                 -----------           ---------

Balance December 31, 1996                                $63             $1,470

Additions:
    Charged to costs and expenses                         --              2,300
Deductions:
    Net charges of nature for which
       reserves were created                              --              2,475
                                                         ---             ------

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
                                                         ===             ======


                                      193
<PAGE>

                                                                     Schedule II

                           Kentucky Utilities Company
                 Schedule II - Valuation and Qualifying Accounts
                   For the Three Years Ended December 31, 1999
                                (Thousands of $)

                                           Other       Accounts
                                        Property     Receivable
                                             and (Uncollectible
                                     Investments       Accounts)
                                     -----------       ---------

Balance December 31, 1996                   $263         $  520

Additions:
    Charged to costs and expenses             82          1,374
Deductions:
    Net charges of nature for which
       reserves were created                  --          1,374
                                            ----         ------

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
                                            ====         ======


                                      194
<PAGE>

                         SIGNATURES - LG&E ENERGY CORP.
                              (First of Two Pages)

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.

                              LG&E ENERGY CORP.
                              Registrant

March 24, 2000                /s/ R. Foster Duncan
--------------                --------------------
(Date)                        R. Foster Duncan
                              Executive Vice President and
                              Chief Financial Officer

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

Signature                         Title                              Date
---------                         -----                              ----

Roger W. Hale                     Chairman of the Board,
                                  and Chief Executive
                                  Officer (Principal
                                  Executive Officer);

R. Foster Duncan                  Executive Vice President and
                                  Chief Financial Officer
                                  (Principal Financial Officer);

Michael D. Robinson               Vice President and Controller
                                  (Principal Accounting Officer);

Mira S. Ball                      Director;

William C. Ballard, Jr.           Director;

Owsley Brown, II                  Director;

Carol M. Gatton                   Director;

J. David Grissom                  Director;

David B. Lewis                    Director;

Anne H. McNamara                  Director;

By  /s/ R. Foster Duncan                                          March 24, 2000
    --------------------
    R. Foster Duncan
   (Attorney-In-Fact)


                                      195
<PAGE>

                         SIGNATURES - LG&E ENERGY CORP.
                              (Second of Two Pages)

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
---------                             -----                   ----

T. Ballard Morton, Jr.                Director;

Frank V. Ramsey, Jr.                  Director;

William L. Rouse, Jr.                 Director;

Charles L. Shearer, Ph.D.             Director; and

Lee T. Todd, Jr., Ph.D.               Director.

By  /s/ R. Foster Duncan                                      March 24, 2000
    --------------------
    R. Foster Duncan
    (Attorney-In-Fact)


                                      196
<PAGE>

                SIGNATURES - LOUISVILLE GAS AND ELECTRIC COMPANY
                              (First of Two Pages)

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 24, 2000                /s/ R. Foster Duncan
--------------                --------------------
(Date)                        R. Foster Duncan
                              Executive Vice President and
                              Chief Financial Officer

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

Signature                         Title                              Date
---------                         -----                              ----

Roger W. Hale                     Chairman of the Board,
                                  and Chief Executive
                                  Officer (Principal
                                  Executive Officer);

R. Foster Duncan                  Executive Vice President and
                                  Chief Financial Officer
                                  (Principal Financial Officer);

Michael D. Robinson               Vice President and Controller
                                  (Principal Accounting Officer);

Mira S. Ball                      Director;

William C. Ballard, Jr.           Director;

Owsley Brown, II                  Director;

Carol M. Gatton                   Director;

J. David Grissom                  Director;

David B. Lewis                    Director;

By  /s/ R. Foster Duncan                                          March 24, 2000
    --------------------
    R. Foster Duncan
   (Attorney-In-Fact)


                                      197
<PAGE>

                SIGNATURES - LOUISVILLE GAS AND ELECTRIC COMPANY
                              (Second of Two Pages)

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
---------                               -----                 ----

Anne H. McNamara                        Director;

T. Ballard Morton, Jr.                  Director;

Frank V. Ramsey, Jr.                    Director;

William L. Rouse, Jr.                   Director;

Charles L. Shearer, Ph.D.               Director;

Lee T. Todd, Jr., Ph.D.                 Director.

By  /s/ R. Foster Duncan                                      March 24, 2000
    --------------------
    R. Foster Duncan
    (Attorney-In-Fact)


                                      198
<PAGE>

                     SIGNATURES - KENTUCKY UTILITIES COMPANY
                              (First of Two Pages)

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.

                              KENTUCKY UTILITIES COMPANY
                              Registrant

March 24, 2000                /s/ R. Foster Duncan
--------------                --------------------
(Date)                        R. Foster Duncan
                              Executive Vice President and
                              Chief Financial Officer

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

Signature                         Title                              Date
---------                         -----                              ----

Roger W. Hale                     Chairman of the Board,
                                  and Chief Executive
                                  Officer (Principal
                                  Executive Officer);

R. Foster Duncan                  Executive Vice President and
                                  Chief Financial Officer
                                  (Principal Financial Officer);

Michael D. Robinson               Vice President and Controller
                                  (Principal Accounting Officer);

Mira S. Ball                      Director;

William C. Ballard, Jr.           Director;

Owsley Brown, II                  Director;

Carol M. Gatton                   Director;

J. David Grissom                  Director;

David B. Lewis                    Director;

Anne H. McNamara                  Director;

By  /s/ R. Foster Duncan                                          March 24, 2000
    --------------------
    R. Foster Duncan
    (Attorney-In-Fact)


                                      199
<PAGE>

                     SIGNATURES - KENTUCKY UTILITIES COMPANY
                              (Second of Two Pages)

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
---------                             -----                     ----

T. Ballard Morton, Jr.                Director;

Frank V. Ramsey, Jr.                  Director;

William L. Rouse, Jr.                 Director;

Charles L. Shearer, Ph.D.             Director; and

Lee T. Todd, Jr., Ph.D.               Director.

By  /s/ R. Foster Duncan                                        March 24, 2000
    --------------------
    R. Foster Duncan
    (Attorney-In-Fact)