<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, 1998

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 3/4% cumulative,              Philadelphia Stock Exchange
   tated 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. [ ]

As of February 26, 1999, the aggregate market value of LG&E Energy Corp.'s
voting common stock held by non-affiliates totaled $2,915,904,217, and it had
129,677,030 shares of common stock outstanding. As of February 26, 1999, the
aggregate market value of Louisville Gas and Electric Company's voting preferred
stock held by non-affiliates totaled $18,066,027, 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 26, 1999, 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 proxy statement, filed with the Commission on March 26,
1999, and Louisville Gas and Electric Company's proxy statement, filed with the
Commission on March 26, 1999, 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.... 1
           Louisville Gas and Electric Company
               General..................................................... 3
               Electric Operations......................................... 4
               Gas Operations.............................................. 6
               Rates and Regulation........................................ 7
               Construction Program and Financing..........................10
               Coal Supply.................................................10
               Gas Supply..................................................11
               Environmental Matters.......................................11
               Competition.................................................11
           Kentucky Utilities Company
               General.....................................................12
               Electric Operations.........................................13
               Rates and Regulation........................................14
               Construction Program and Financing..........................16
               Coal Supply.................................................17
               Environmental Matters.......................................17
           LG&E Capital Corp...............................................18
           Independent Power Operations....................................18
           Western Kentucky Energy.........................................20
           Argentine Gas Distribution Division.............................22
           Discontinued Operations.........................................23
           Employees and Labor Relations...................................24
Item 2.    Properties......................................................25
Item 3.    Legal Proceedings...............................................29
Item 4.    Submission of Matters to a Vote of Security Holders.............31
Executive Officers of the Company..........................................32

                                     PART II

Item 5.    Market for the Registrant's Common Equity and Related
                  Stockholder Matters......................................39
Item 6.    Selected Financial Data.........................................40
Item 7.    Management's Discussion and Analysis of Results of
                  Operations and Financial Condition:
                  LG&E Energy Corp.........................................44
                  Louisville Gas and Electric Company......................62
                  Kentucky Utilities Company...............................73
Item 7A.   Quantitative and Qualitative Disclosures About Market
                  Risk.....................................................83
Item 8.    Financial Statements and Supplementary Data:
                  LG&E Energy Corp.........................................84
                  Louisville Gas and Electric Company.....................127
                  Kentucky Utilities Company..............................152
Item 9.    Changes in and Disagreements with Accountants on
                  Accounting and Financial Disclosure.....................172


<PAGE>


                            TABLE OF CONTENTS (CONT.)

                                    PART III

 Item 10.   Directors and Executive Officers of the Registrant (a)........172
 Item 11.   Executive Compensation (a)....................................172
 Item 12.   Security Ownership of Certain Beneficial Owners
                 and Management (a).......................................172
 Item 13.   Certain Relationships and Related Transactions (a)............172

                             PART IV

 Item 14.   Exhibits, Financial Statement Schedules,
                 and Reports on Form 8-K..................................172
 Signatures      .........................................................198

 (a) Incorporated by reference.


<PAGE>


                                     PART I.

Item 1.  Business.

                             OVERVIEW OF OPERATIONS

LG&E Energy Corp. (the Company or LG&E Energy), incorporated November 14, 1989,
is a diversified energy-services holding company with three direct subsidiaries:
Louisville Gas and Electric Company (LG&E), Kentucky Utilities Company (KU) and
LG&E Capital Corp. (Capital Corp.). 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 Commonwealth of
Kentucky and is not subject to regulation as such by the Kentucky Public Service
Commission (Kentucky Commission) or the Virginia State Corporation Commission
(Virginia Commission). See LG&E - Rates and Regulation and - Rates and
Regulation for descriptions of the regulation of LG&E and KU by the Kentucky
Commission, and of KU by the Virginia Commission, which includes the ability to
regulate certain intercompany transactions between LG&E, KU and the Company,
including the Company's non-utility subsidiaries.

                        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 Corporation (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 were not affected by the Merger. See Note 2 of LG&E Energy Corp.'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 enables the
Company to focus on optimizing the value of physical assets it owns or controls,
and to reduce the earnings impact on continuing operations of extreme market
volatility in its portfolio of energy marketing contracts. The Company is in the
process of settling commitments that obligate it to buy and sell natural gas and
electric power. It also plans to sell its natural gas gathering and processing
business. If the Company is unable to dispose of these commitments or assets it
will continue to meet its obligations under the contracts. The Company, however,
has maintained sufficient market knowledge, risk management skills, technical
systems and experienced personnel to maximize

                                      1

<PAGE>

the value of power sales from physical assets it owns or controls, including
LG&E, KU and the Big Rivers Electric Corporation (Big Rivers).

As a result of the Company's decision to discontinue its merchant energy trading
and sales activity, and the 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 results primarily from several
fixed-price energy marketing contracts entered into in 1996 and early 1997,
including the Company's long-term contract with Oglethorpe Power Corporation
(OPC). Other components of the write-off include costs relating to certain
peaking options, goodwill associated with the Company's 1995 purchase of
merchant energy trading and sales operations and exit costs, including labor and
related benefits, severance and retention payments, and other general and
administrative expenses. 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, it also recognizes that
there are inherent limitations in models to accurately predict future events. As
a result, there is no guarantee that higher-than-anticipated future commodity
prices or load demands, lower- than-estimated asset sales prices or other
factors could not result in additional losses. The Company has been successful
in settling portions of its discontinued operations, but significant assets,
operations and obligations remain. As of January 27, 1999, 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 $8.8 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 27, 1999, the Company estimates that a 1% change
in the forecasted load demand could change the value of the Company's remaining
energy portfolio by $9.3 million. See Notes 3 and 18 of LG&E Energy Corp.'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 Corp.'s Notes to
Financial Statements under Item 8 for more information.

                         LEASE OF BIG RIVERS FACILITIES

On July 15, 1998, the Company closed the transaction to lease the generating
assets of Big Rivers following receipt of necessary regulatory approvals. Under
the 25-year operating lease, Western Kentucky Energy Corp. and its affiliates
(WKE) are leasing and operating Big Rivers' three coal-fired facilities. In
addition, WKE operates and maintains the Station Two generating facility of the
City of Henderson (Henderson). The combined generating capacity of these
facilities amounts to approximately 1,700 megawatts (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 four 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 4 of
LG&E Energy Corp.'s Notes to Financial Statements under Item 8.


                                       2
<PAGE>


                       LOUISVILLE GAS AND ELECTRIC COMPANY

General

Incorporated on July 2, 1913, LG&E is a regulated public utility that supplies
natural gas to approximately 289,000 customers and electricity to approximately
360,000 customers in Louisville and adjacent areas in Kentucky. LG&E's service
area covers approximately 700 square miles in 17 counties and has an estimated
population of one million. Included in this area is the Fort Knox Military
Reservation, to which LG&E transports gas and provides electric service, but
which maintains its own distribution systems. LG&E also provides gas service in
limited additional areas. LG&E's coal-fired electric generating plants, which
are all equipped with systems to reduce sulfur dioxide emissions, produce most
of LG&E's electricity. The remainder is generated by a hydroelectric power plant
and combustion turbines. Underground natural gas storage fields help LG&E
provide economical and reliable gas service to customers.

LG&E's Trimble County Unit 1 (Trimble County), a 495-Mw, coal-fired electric
generating unit was placed in commercial operation in December 1990. In December
1995, the Commission approved a settlement agreement that excluded 25% of the
Trimble County costs from customer rates. LG&E owns a 75% undivided interest in
Trimble County. See Electric Operations under Item 1, Note 13 of LG&E's Notes to
Financial Statements and Note 19 of LG&E Energy Corp.'s Notes to Financial
Statements under Item 8.

In September 1998, the U.S. Environmental Protection Agency announced its final
regulation requiring significant additional reductions in nitrogen oxide (NOx)
emissions to mitigate alleged ozone transport to the Northeast. While each state
is free to allocate its assigned NOx reductions among various emissions sectors
as it deems appropriate, the regulation may ultimately require utilities to
reduce their NOx emissions to 0.15 lb./mmBtu (million British thermal units) -
an 85% reduction from 1990 levels. Under the regulation, each state must
incorporate the additional NOx reductions in its State Implementation Plan (SIP)
by September 1999 and affected sources must install control measures by May
2003, unless granted extensions. Several states, various labor and industry
groups, and individual companies have appealed the final regulation to the U.S.
Court of Appeals for the D.C. Circuit. Management is currently unable to
determine the outcome or exact impact of this matter until such time as the
states identify specific emissions reductions in their SIPs and the courts rule
on the various legal challenges to the final rule. 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 and analysis, LG&E estimates that it may incur capital
costs in the range of $100 million to $200 million. 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 cost recovery from customers under its environmental
surcharge mechanism and believes that a significant portion of such costs could
be recovered. However, Kentucky Commission approval is necessary and there can
be no guarantee of such recovery.


                                       3
<PAGE>


For the year ended December 31, 1998, 77% of total operating revenues was
derived from electric operations and 23% 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:

<TABLE>
<CAPTION>
                                                                 (Thousands of $)
                                                    Electric           Gas            Combined         %Combined
                                                    --------           ---            --------         ---------
<S>                                                 <C>              <C>              <C>                    <C>
         Residential                                $213,476         $113,430         $326,906               45%
         Commercial                                  170,954           40,888          211,842               29
         Industrial                                  113,372           11,969          125,341               17
         Public authorities                           55,075            8,884           63,959                9
                                                    --------         --------         --------              ---
           Total retail                              552,877          175,171          728,048              100%
                                                                                                            ---
                                                                                                            ---
         Wholesale sales                              99,340            8,720          108,060
         Gas transported - net                             -            6,926            6,926
         Provision for rate refund - ECR              (4,500)               -           (4,500)
         Miscellaneous                                10,794              728           11,522
                                                    --------         --------         -------- 
           Total                                    $658,511         $191,545         $850,056
                                                    --------         --------         -------- 
                                                    --------         --------         --------  
</TABLE>

See Note 14 of LG&E's Notes to Financial Statements and Note 20 of LG&E Energy
Corp.'s Notes to Financial Statements under Item 8 for financial information
concerning segments of business for the three years ended December 31, 1998.

Electric Operations

The sources of LG&E's electric operating revenues and the volumes of sales for
the three years ended December 31, 1998, were as follows:

<TABLE>
<CAPTION>
                                                                          1998             1997              1996
                                                                          ----             ----              ----
<S>                                                                   <C>             <C>                <C>   
         ELECTRIC OPERATING REVENUES 
         (Thousands of $):
         Residential                                                  $213,476         $205,137          $202,318
         Small commercial and industrial                                76,304           72,769            74,034
         Large commercial                                               94,650           90,131            88,993
         Large industrial                                              113,372          110,652           110,914
         Public authorities                                             55,075           53,412            54,318
                                                                      --------         --------          --------
           Total retail                                                552,877          532,101           530,577
         Wholesale sales                                                99,340           70,942            67,854
         Provision for rate refund - ECR                                (4,500)               -                 -
         Miscellaneous                                                  10,794           11,489             8,265
                                                                      --------         --------          --------
           Total                                                      $658,511         $614,532          $606,696
                                                                      --------         --------          --------
                                                                      --------         --------          --------

         ELECTRIC SALES (Thousands of mwh):
         Residential                                                     3,534            3,302             3,382
         Small commercial and industrial                                 1,156            1,108             1,131
         Large commercial                                                1,977            1,880             1,850
         Large industrial                                                3,097            3,054             3,059
         Public authorities                                              1,140            1,105             1,122
                                                                        ------           ------            ------
           Total retail                                                 10,904           10,449            10,544
         Wholesale sales                                                 4,970            3,800             3,589
                                                                        ------           ------            ------
           Total                                                        15,874           14,249            14,133
                                                                        ------           ------            ------
                                                                        ------           ------            ------
</TABLE>

At December 31, 1998, LG&E had 360,024 electric customers.

                                       4

<PAGE>


LG&E uses efficient coal-fired boilers that are fully equipped with sulfur
dioxide removal systems to generate electricity. LG&E's system wide emission
weighted-average rate for sulfur dioxide in 1998 was approximately .97
lbs./MMBtu of heat input, which is significantly below the Phase II limit of 1.2
lbs./MMBtu established by the Clean Air Act Amendments of 1990 for the year
2000.

The 1998 maximum local peak load of 2,427 Mw occurred on Tuesday, August 25,
1998, when the temperature at the time was 94(degree)F. Prior to 1998, the
record local peak load was 2,414 Mw (set on July 21, 1997).

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 14%. At December 31, 1998, LG&E owned steam and
combustion turbine generating facilities with a capacity of 2,512 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.

The Illinois Municipal Electric Agency (IMEA), based in Springfield, Illinois,
which is an agency of 35 municipalities that own and operate their own electric
systems, has a 12.12% ownership interest in LG&E's Trimble County Unit 1. The
Indiana Municipal Power Agency (IMPA), based in Carmel, Indiana, has a 12.88%
interest in the Trimble County Unit. IMPA is composed of 31 municipalities that
have joined together to meet their long-term electric power needs. Both IMEA and
IMPA pay their proportionate share for operation and maintenance expenses of
Trimble County and for fuel and reactant used. They are also responsible for
their proportionate share of incremental capital assets acquired. See Note 13 of
LG&E's Notes to Financial Statements and Note 19 of LG&E Energy Corp.'s Notes to
Financial Statements under Item 8 for a further discussion.



                                       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, 1998, were as follows:

<TABLE>
<CAPTION>
                                                                          1998             1997              1996
                                                                          ----             ----              ----

<S>                                                                  <C>               <C>               <C>
         GAS OPERATING REVENUES 
         (Thousands of $):
         Residential                                                  $113,430         $139,967          $125,327
         Commercial                                                     40,888           52,440            47,415
         Industrial                                                     11,969           17,892            21,229
         Public authorities                                              8,884           12,052            11,731
                                                                      --------         --------          --------
           Total retail                                                175,171          222,351           205,702
         Wholesale sales                                                 8,720                -                 -
         Gas transported - net                                           6,926            6,997             6,850
         Miscellaneous                                                     728            1,663             1,867
                                                                      --------         --------          --------
           Total                                                      $191,545         $231,011          $214,419
                                                                      --------         --------          --------
                                                                      --------         --------          --------
         GAS SALES (Millions of cu. ft.):
         Residential                                                    20,040           24,038            25,531
         Commercial                                                      8,448           10,212            10,656
         Industrial                                                      2,860            3,948             5,190
         Public authorities                                              1,967            2,467             2,790
                                                                      --------         --------          --------
           Total retail                                                 33,315           40,665            44,167
         Wholesale sales                                                 3,880                -                 -
         Gas transported                                                13,027           13,452            12,540
                                                                      --------         --------          --------
           Total                                                        50,222           54,117            56,707
                                                                      --------         --------          --------
                                                                      --------         --------          --------
</TABLE>

At December 31, 1998, LG&E had 288,777 gas customers.

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. Accessing least cost gas was
made easier in November 1993 when the Federal Energy Regulatory Commission Order
No. 636 went into effect. Previously, LG&E and other utilities purchased most of
their gas services from pipeline companies. The order "unbundled" gas services,
allowing utilities to purchase gas, transportation, and storage services
separately from many different sources. 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.


                                       6
<PAGE>

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(degree)F. During
1998, the maximum day gas sendout was 425,000 Mcf, occurring on March 11, when
the average temperature for the day was 20(degree)F. Supply on that day
consisted of 105,000 Mcf from purchases, 263,000 Mcf delivered from underground
storage, and 57,000 Mcf transported for industrial customers.
For a further discussion, see Gas Supply under Item 1.

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 Federal
Power Act, 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 5 of LG&E Energy Corp.'s Notes to Financial Statements under
Item 8.

Increases and decreases in the cost of fuel for electric generation are
reflected in the rates charged to all of LG&E's electric customers by means of
LG&E's fuel adjustment clause (FAC). 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
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.

As of February 12, 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 for the period from November 1994 through
April 1998. LG&E estimates up to an additional $1.3 million could be refundable
to retail electric customers for the period from May 1998 through December 1998.
See Note 3 of LG&E's Notes to Financial Statements and Note 5 of LG&E Energy
Corp.'s Notes to Financial Statements under Item 8.

LG&E filed a Petition of Rehearing of all of the orders and a motion to suspend
the refund obligation. On February 25, 1999, the Commission suspended the
obligation to refund pending further direction by the Commission. It also
advised that LG&E may have to pay interest on the refund amounts for the
suspension period. On March 11, 1999 the Commission denied LG&E's Petition for
Rehearing for the period November 1994 through October 1996 and directed LG&E to
reduce future fuel expense by $1.9 million in the first billing month after the
Order. The Company is considering the filing of an Appeal with the Franklin
Circuit Court. In a separate series of Orders on March 11, 1999, the PSC granted
LG&E's Petition for Rehearing for the period November 1996 through April 1998
and established a procedural schedule for LG&E and other parties to submit
evidence and for a hearing before the Commission. In the same Orders the PSC
granted the Petition for Rehearing of the Kentucky Industrial Utility Customers
to determine if interest should be paid on any fuel refunds for this latter
period.

LG&E's gas rates contain a gas supply clause (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 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.




                                       7
<PAGE>

In May 1995, LG&E implemented an environmental cost recovery (ECR) surcharge to
recover certain environmental compliance costs, including costs to comply with
the 1990 Clean Air Act, as amended, and other environmental regulations,
including those applicable to coal combustion wastes and related by-products.
The ECR mechanism was authorized by state statute in 1992 and was first approved
by the Kentucky Commission in a KU case in July 1994.

The Commission's order approving the surcharge in the KU case and the
constitutionality of the surcharge was challenged by certain intervenors,
including the Attorney General of Kentucky, in Franklin Circuit Court. Decisions
of the Circuit Court and the Kentucky Court of Appeals in July 1995 and December
1997, respectively, have upheld the constitutionality of the ECR statute but
differed on a claim of retroactive recovery of certain amounts. The Commission
ordered that certain surcharge revenues collected by LG&E be subject to refund
pending final determination of all appeals.

On December 19, 1998, the Kentucky Supreme Court rendered an opinion upholding
the constitutionality of the surcharge statute. The decision, however, reversed
the ruling of the Court of Appeals on the retroactivity claim, thereby denying
recovery through the ECR of costs associated with pre-1993 environmental
projects. The court remanded the case to the Commission to determine the proper
adjustments to refund amounts collected for such pre-1993 environmental
projects. The parties to the proceeding have notified the Commission that they
have reached agreement as to the terms, proper adjustments and forward
application of the ECR. The settlement agreement is subject to Commission
approval. LG&E recorded a provision for rate refund of $4.5 million in December
1998. See Rates and Regulation for LG&E and LG&E Energy Corp. under Item 7 for a
further discussion.

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.

In January 1994, LG&E implemented a Commission-approved demand side management
(DSM) program that LG&E, the Jefferson County Attorney, and representatives of
several customer interest groups had filed with the Commission. The program
included a rate mechanism that (1) provided LG&E concurrent recovery of DSM
costs, (2) provided an incentive for implementing DSM programs and (3) allowed
LG&E to recover revenues from lost sales associated with the DSM program
(decoupling). In June 1998, LG&E and customer interest groups requested an end
to the decoupling rate mechanism. On June 1, 1998, LG&E discontinued recording
revenues from lost sales due to DSM. Accrued decoupling revenues recorded for
periods prior to June 1, 1998, will continue to be collected through the DSM
recovery mechanism. In September 1998, the Commission accepted LG&E's modified
tariff reflecting this proposal effective as of June 1, 1998. See Rates and
Regulation for LG&E and LG&E Energy Corp. under Item 7 for a discussion of
Commission approved changes to the original program and requested revisions
pending before the Commission.

In October 1997, LG&E implemented a Commission-approved, experimental
performance-based ratemaking mechanism related to gas procurement activities and
off-system gas sales. 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 year of
operation of the mechanism LG&E recorded $3.6 million for its share of reduced
gas costs. The $3.6 million will be billed to customers through the gas supply
clause beginning February 1, 1999.

                                       8
<PAGE>

In October 1998, LG&E and KU filed separate, but parallel applications with the
Commission for approval of a new method of determining electric rates that
provides financial incentives for LG&E and KU to further reduce customers'
rates. The filing was made pursuant to the September 1997 Commission order
approving the merger of LG&E Energy and KU Energy, wherein the 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 new ratemaking method, known as performance-based ratemaking (PBR), would
include 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 provides financial penalties and rewards to assure
continued high quality service and reliability.

The PBR plan proposed by LG&E and KU consists of five components:

    The utilities' fuel adjustment clause mechanism will be withdrawn and
    replaced with a cap that limits recovery of actual changes in fuel cost to
    changes in a fuel price index for a five-state region. If the utilities
    outperform the index, benefits will be shared equally between shareholders
    and customers. If the utilities' fuel costs exceed the index, the difference
    will be absorbed by LG&E Energy's shareholders.

    Customers will continue to receive the benefits from the post-merger joint
    dispatch of power from LG&E's and KU's generating plants.

    Power plant performance will be measured against the best performance
    achieved between 1991 and 1997. If the performance exceeds this level,
    customers will share equally with LG&E Energy's shareholders in up to $10
    million annually of benefits from this performance at each of LG&E and KU.

    The utilities will be encouraged to maintain and improve service quality,
    reliability, customer satisfaction and safety, which will be measured
    against six objective benchmarks. The plan provides for annual rewards or
    penalties to LG&E Energy of up to $5 million per year at each of LG&E and
    KU.

    The plan provides the utilities with greater flexibility to customize rates
    and services to meet customer needs. Services will continue to be priced
    above marginal cost and customers will continue to have the option to elect
    standard tariff service.

These proposals are subject to approval by the Commission. Approval proceedings
commenced in October 1998 and a final decision likely will occur in 1999.
Several intervenors are participating in the case. Some have requested that the
Commission reduce base rates before implementing PBR.

On March 8, 1999, the Kentucky Industrial Utility Customers filed a Complaint
with the Kentucky Commission alleging that LG&E's electric rates are excessive
and should be reduced by an amount between $43 and $90 million and that the
Kentucky Commission establish a proceeding to reduce LG&E's electric rates. LG&E
has asked the Kentucky Commission to dismiss the Complaint.

LG&E is not able to predict the ultimate outcome of these proceedings, however,
should the Commission mandate significant rate reductions at LG&E, through the
PBR proposal or otherwise, such actions could have a material effect on LG&E's
financial condition and results of operations.

As part of the corporate reorganization whereby LG&E became the subsidiary of
LG&E Energy, LG&E obtained the approval of the Kentucky Commission. The order of
the Kentucky Commission authorizing LG&E to reorganize into a holding company
structure contains certain provisions, which, among other things, ensure the
Kentucky Commission access to books and records of LG&E Energy and its
affiliates which relate to transactions with LG&E; requires LG&E Energy and its
subsidiaries to employ accounting and other procedures and controls to


                                       9
<PAGE>

protect against subsidization of non-utility activities by LG&E's customers; and
precludes LG&E from guaranteeing any obligations of LG&E Energy without prior
written consent from the Kentucky Commission. In addition, the order provides
that LG&E's Board of Directors has the responsibility to use its dividend policy
consistent with preserving the financial strength of LG&E and that the Kentucky
Commission, through its authority over LG&E's capital structure, can protect
LG&E's ratepayers from the financial effects resulting from non-utility
activities.

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, 1998, gross property additions amounted
to $546 million. Internally generated funds for the five-year period were
sufficient to provide for all of these gross additions. The gross additions
during this period amounted to approximately 20% of total utility plant at
December 31, 1998, and consisted of $405 million for electric properties and
$141 million for gas properties. Gross retirements during the same period were
$112 million, consisting of $91 million for electric properties and $21 million
for gas properties.

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 1998, were about 21% 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,
1998, a coal inventory of approximately 1,015,000 tons, or a 56 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. Starting the second half of 2000,
Cane Run is also expected to have the capability for barge delivery of coal.

The average delivered cost of coal purchased by LG&E, per ton and per million
Btu, for the periods shown were as follows:

<TABLE>
<CAPTION>
                                                                          1998             1997              1996
                                                                          ----             ----              ----

<S>                                                                     <C>              <C>               <C>   
         Per ton                                                        $22.38           $21.66            $21.73
         Per million Btu                                                   .98              .94               .97
</TABLE>

                              10
<PAGE>

The delivered cost of coal is expected to decrease during 1999.

Gas Supply

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

During 1997, Texas Gas filed with FERC for a change in its rates as required
under the settlement in its last rate case. LG&E participated in that and other
proceedings, as appropriate. Resolution of that rate case took place in 1998
when the settlement was approved effective December 1. LG&E received a refund of
$1.5 million from Texas Gas in January 1999 which will be refunded to customers
in 1999.

LG&E transports on the Texas Gas system under No-Notice Service (NNS) and Firm
Transportation (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 2000, 2001, and 2003. 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 which are market-responsive. These firm supplies, in tandem
with pipeline transportation services, provide the reliability and flexibility
necessary to serve LG&E's customers.

LG&E operates five underground gas storage fields with a current working gas
capacity of 14.6 million Mcf. Gas is purchased and injected into storage during
the summer season and is then withdrawn to supplement pipeline supplies to meet
the gas-system load requirements during the winter heating season.

The estimated maximum deliverability from storage during the early part of the
1998-1999 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 $3.05 in 1998 and
$3.46 in each of 1997 and 1996.

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 1998, expenditures for
pollution control facilities represented $106 million or 19% of total
construction expenditures. See Note 12 of LG&E's Notes to Financial Statements
and Note 18 of LG&E Energy Corp.'s Notes to Financial Statements under Item 8
for a discussion of specific environmental proceedings affecting LG&E.

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 not only commercial and industrial customers, but
residential customers

                                       11

<PAGE>

 as well; 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
like these 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 449,000 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.

In September, 1998, the U.S. Environmental Protection Agency (USEPA) announced
its final regulation requiring significant additional reductions in nitrogen
oxide (NOx) emissions to mitigate alleged ozone transport to the Northeast.
While each state is free to allocate its assigned NOx reductions among various
emissions sectors as it deems appropriate, the regulation may ultimately require
utilities to reduce their NOx emissions to 0.15 lb./MMBTU - an 85% reduction
from 1990 levels. Under the regulation, each state must incorporate the
additional NOx reductions in its State Implementation Plan (SIP) by September
1999 and affected sources must install control measures by May 2003, unless
granted extensions. Several states, various labor and industry groups, and
individual companies have appealed the final regulation to the U.S. Court of
Appeals for the D.C. Circuit. Management is currently unable to determine the
outcome or exact impact of this matter until such time as the states identify
specific emissions reductions in their SIP and the courts rule on the various
legal challenges to the final rule. 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 and analysis, KU estimates that it may incur capital
costs of approximately $100 to $200 million. These costs would generally be
incurred beginning in 2000. KU believes its costs for these matters 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 cost recovery from customers under its environmental surcharge
mechanisms and believes that a significant portion of such costs could be so
recovered. However, Kentucky Commission approval is necessary and there can be
no guarantee of such recovery.


                                       12

<PAGE>

Electric Operations

The sources of KU's electric operating revenues and the volumes of sales for the
three years ended December 31, 1998, were as follows:

<TABLE>
<CAPTION>
                                                                          1998             1997              1996
                                                                          ----             ----              ----

<S>                                                                   <C>             <C>                <C>    
         ELECTRIC OPERATING REVENUES 
         (Thousands of $):
         Residential                                                  $238,898         $231,824          $236,229
         Commercial                                                    158,549          150,794           150,640
         Industrial                                                    154,662          146,801           136,856
         Mine Power                                                     31,697           34,541            34,014
         Public authorities                                             58,814           56,243            56,023
                                                                      --------         --------          --------
           Total - ultimate consumers                                  642,620          620,203           613,762
         Wholesale sales                                               179,118           87,330            89,208
         Provision for rate refund - ECR                               (21,500)               -                 -
         Miscellaneous                                                   9,876            8,904             8,741
                                                                      --------         --------          --------
           Total                                                      $810,114         $716,437          $711,711
                                                                      --------         --------          --------
                                                                      --------         --------          --------
 
         ELECTRIC SALES (Thousands of mwh):
         Residential                                                     5,247            5,061             5,148
         Commercial                                                      3,644            3,422             3,411
         Industrial                                                      4,747            4,464             4,107
         Mine Power                                                        838              926               894
         Public authorities                                              1,424            1,355             1,350
                                                                        ------           ------            ------
           Total - ultimate consumers                                   15,900           15,228            14,910
         Wholesale sales                                                 7,224            3,397             3,721
                                                                        ------           ------            ------
           Total                                                        23,124           18,625            18,631
                                                                        ------           ------            ------
                                                                        ------           ------            ------
</TABLE>

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, 1998, KU owned steam and combustion turbine generating
facilities with a capacity of 3,694 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, 1998, KU's system
capability, including purchases from others, was 4,235 Mw. On August 25, 1998, a
record local peak load, on a one-hour integrated basis, was set at 3,559 Mw.

Under a contract expiring 2020 with Owensboro Municipal Utilities (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 9% of KU's net system output during 1998. 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 Electric Energy, Inc. (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 



                                       13
<PAGE>

about 8% of KU's net system output in 1998. See Note 11 of KU's Notes to
Financial Statements and Note 18 of LG&E Energy Corp.'s Notes to Financial
Statements under Item 8. See also Item 3, Legal Proceedings.

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 Federal Power Act (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 Tennessee Regulatory Authority (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 5 of LG&E Energy Corp.'s Notes to Financial
Statements under Item 8.

KU's fuel adjustment clause (FAC) for Kentucky customers operates to reflect
changes in the cost of fuel in billings to customers, and is designed to conform
with the Kentucky Commission's regulation providing for a uniform monthly fuel
adjustment clause for all electric utilities in Kentucky subject to the
jurisdiction of the Kentucky Commission. The Kentucky Commission's regulation is
based on a formula approved by FERC but with certain modifications, including
the exclusion of excess fuel expense attributable to certain forced outages, the
filing of fuel procurement documentation, a procedure for billing over- and
under-recoveries of fuel cost fluctuations from the base rate level and
provision for periodic public hearings to review past adjustments, to make
allowance for any past adjustments found not justified, to disallow any improper
expenses and to re-index base rates to include current fuel costs. The fuel
adjustment clause 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.

As of February 12, 1999, the Kentucky Commission ordered KU's affiliate utility,
LG&E, to refund FAC charges to retail electric customers after a review of
LG&E's FAC from November 1994 through April 1998. The Kentucky Commission
subsequently on March 11, 1999, denied LG&E's Petition for Rehearing for the
period November 1994 through October 1996, but granted rehearing for the period
November 1996 through April 1998 on the same issue. KU has not received an order
from the Kentucky Commission but estimates that it may be required to refund to
its retail electric customers up to $3.5 million in FAC charges for the period
November 1994 through October 1998.

Rate regulation in Kentucky allows each electric utility, with the Kentucky
Commission's approved environmental compliance plan and environmental surcharge,
to recover on a current basis the cost of complying with federal, state or local
environmental requirements, including the Federal Clean Air Act as amended,
applicable to coal combustion wastes and byproducts from facilities utilized for
the production of energy from coal. In 1994, the Kentucky Commission approved
KU's environmental surcharge, which is designed to allow KU to recover
compliance related operating expenses and to earn a return on those
compliance-related capital expenditures not already included in existing rates
through the application of the surcharge each month to customers' bills.
Surcharge billings are subject to periodic Kentucky Commission review of the
level of environmental expenditures and reconciliation of previous surcharge
billings with actual costs. For additional information regarding the
environmental surcharge, including information concerning pending legal
proceedings, see Note 3 of KU's Notes to Financial Statements and Note 5 of LG&E
Energy Corp.'s Notes to Financial Statements under Item 8.


                                       14
<PAGE>

The Commission's order approving the surcharge in the KU case and the
constitutionality of the surcharge was challenged by certain intervenors,
including the Attorney General of Kentucky, in Franklin Circuit Court. Decisions
of the Circuit Court and the Kentucky Court of Appeals in July 1995 and December
1997, respectively, have upheld the constitutionality of the ECR statute but
differed on a claim of retroactive recovery of certain amounts. The Commission
ordered that certain surcharge revenues collected by KU be subject to refund
pending final determination of all appeals.

On December 19, 1998, the Kentucky Supreme Court rendered an opinion upholding
the constitutionality of the surcharge statute. The decision, however, reversed
the ruling of the Court of Appeals on the retroactivity claim, thereby denying
recovery of costs associated with pre-1993 environmental projects through the
ECR. The court remanded the case to the Commission to determine the proper
adjustments to refund amounts collected for such pre-1993 environmental
projects. The parties to the proceeding have notified the Commission that they
have reached agreement as to the terms, proper adjustments and forward
application of the ECR. The settlement agreement is subject to Commission
approval. KU recorded a provision for rate refund of $21.5 million in December
1998. See Rates and Regulation for KU and LG&E Energy Corp. under Item 7 for a
further discussion.

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
Virginia Commission Staff (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 Securities and Exchange Commission.

For information regarding regulatory matters related to the merger of LG&E
Energy and KU Energy, see Note 2 of KU's Notes to Financial Statements and Note
2 of LG&E Energy Corp.'s Notes to Financial Statements under Item 8.

In October 1998, LG&E and KU filed separate but parallel applications with the
Commission for approval of a new method of determining electric rates that
provides financial incentives for LG&E and KU to further reduce customers'
rates. The filing was made pursuant to the September 1997 Commission order
approving the merger of LG&E Energy and KU Energy, wherein the 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 new ratemaking method, known as performance-based ratemaking (PBR), would
include 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 provides financial penalties and rewards to assure
continued high quality service and reliability.


                                       15
<PAGE>

The PBR plan proposed by LG&E and KU consists of five components:

    The utilities' fuel adjustment clause mechanism will be withdrawn and
    replaced with a cap that limits recovery of actual changes in fuel cost to
    changes in a fuel price index for a five-state region. If the utilities
    outperform the index, benefits will be shared equally between shareholders
    and customers. If the utilities' fuel costs exceed the index, the difference
    will be absorbed by LG&E Energy's shareholders.

    Customers will continue to receive the benefits from the post-merger joint
    dispatch of power from LG&E's and KU's generating plants.

    Power plant performance will be measured against the best performance
    achieved between 1991 and 1997. If the performance exceeds this level,
    customers will share equally with LG&E Energy's shareholders in up to $10
    million annually of benefits from this performance at each of LG&E and KU.

    The utilities will be encouraged to maintain and improve service quality,
    reliability, customer satisfaction and safety, which will be measured
    against six objective benchmarks. The plan provides for annual rewards or
    penalties to LG&E Energy of up to $5 million per year at each of LG&E and
    KU.

    The plan provides the utilities with greater flexibility to customize rates
    and services to meet customer needs. Services will continue to be priced
    above marginal cost and customers will continue to have the option to elect
    standard tariff service.

These proposals are subject to approval by the Commission. Approval proceedings
commenced in October 1998 and a final decision may occur in 1999. Several
intervenors are participating in the case. Some have requested that the
Commission reduce base rates before implementing PBR.

On March 8, 1999, the Kentucky Industrial Utility Customers filed a Complaint
with the Kentucky Commission alleging that KU's electric rates are excessive and
should be reduced by an amount between $42 and $56 million, and that the
Kentucky Commission establish a proceeding to reduce KU's rates. KU has asked
the Kentucky Commission to dismiss the Complaint.

KU is not able to predict the ultimate outcome of these proceedings, however,
should the Commission mandate significant rate reductions at KU, through the PBR
proposal or otherwise, such actions could have a material effect on KU's
financial condition and results of operations.

Construction Program and Financing

KU'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. KU's estimates of its construction
expenditures can vary substantially due to numerous items beyond KU's control,
such as changes in rates, economic conditions, construction costs, and new
environmental or other governmental laws and regulations.

During the last five years ended December 31, 1998, construction expenditures
aggregated about $609 million, which included four 126-Mw combustion turbine
peaking units. The first peaking unit was placed into commercial operation in
late 1994. The second and third units were placed into commercial operation in
February 1995 and December 1995, respectively. The fourth unit was placed into
commercial operation in May 1996.



                                       16
<PAGE>

Coal Supply

Coal-fired generating units provided more than 98% of KU's net kilowatt- hour
generation for 1998. The remainder of KU's net generation for 1998 was provided
by oil and/or natural gas burning units and hydroelectric plants. The average
delivered cost of coal purchased per million BTU (MBTU) and the percentage of
spot coal purchases for the periods indicated were as follows:

<TABLE>
<CAPTION>
                                                                          1998             1997              1996
                                                                          ----             ----              ----

<S>                                                                     <C>              <C>               <C>   
         Per ton                                                        $26.97           $27.97            $27.54
         Per MBTU - all sources                                          $1.12            $1.15             $1.14
         Per MBTU - spot purchases only                                  $1.10            $1.12             $1.08
         Spot purchases as % of all sources                                42%              34%               33%
</TABLE>

The price of coal, due to using low sulfur content coal and transportation costs
are expected to increase slightly during 1998.

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 substantial
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, 1998, a coal inventory of
approximately 866,000 tons, or a 42 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 period ending with 1998, expenditures for
pollution control facilities represented $174 million or 29% 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.


                                       17
<PAGE>

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.

LG&E Capital Corp. (Capital Corp.), the holding company for all non-utility
investments, was formed on September 5, 1997, when the Company merged two of its
former direct subsidiaries, LG&E Energy Systems Inc. and LG&E Gas Systems Inc.,
and renamed the company LG&E Capital Corp. On July 24, 1998, KU Capital
Corporation (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 discontinued
this business operation. For a more detailed discussion of the discontinuance of
the Company's merchant energy trading and sales business, see Discontinued
Operations under this Item, and Notes 3 and 18 of LG&E Energy's Notes to
Financial Statements under Item 8.

Capital Corp. conducts its operations through three principal business segments:
Independent Power Operations, Western Kentucky Energy and Argentine Gas
Distribution. See Note 20 of LG&E Energy's Notes to Financial Statements under
Item 8.

                          INDEPENDENT POWER OPERATIONS

General

Capital Corp.'s Independent Power Operations (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. Additionally,
Power Operations owns and / or has ownership interests in eight 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.

On March 15, 1999, LG&E Westmoreland - Rensselaer, in which Power Operations has
a 50% interest, sold the assets of the Rensselaer cogeneration facility. This
transaction will result in a pre-tax gain for Power Operations of approximately
$14.5 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.


                                       18
<PAGE>

In February 1998, Power Operations sold its interest in a 114-Mw natural
gas-fired power plant in North Central Argentina.

Fuel Supply

Power Operations operates five coal fired and three wind plants. See Item 2,
Properties. Coal supply needed by Power Operations is 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 Virginia Electric and Power (VEPCO) for Southampton,
Altavista, and Hopewell in Virginia and Roanoke Valley I (ROVA I) and Roanoke
Valley II (ROVA II) in North Carolina; Southern California Edison Co. for
Windpower Partners 1993 (WPP 93) in California; Northern States Power Company
for WPP 93 in Minnesota; Lower Colorado River Authority for Windpower Partners
1994 (WPP 94), Brazos Electric Power Cooperative for Tenaska Limited
Partnerships (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 K.W. Tarifa in Spain. WPP 94 also sells excess
power to Texas Utilities. See Item 2, Properties, for a listing of Power
Operations projects.

Each of Power Operations combustion turbines are leased to utility companies.
The lessees are Portland General Electric Company (Portland General) in Oregon,
Arkansas Power and Light Company in Arkansas and Puget Sound Power & Light
Company in Washington. The leases expire in 1999. Upon expiration each of the
leases, each of the lessees has the option to extend the lease, purchase the
unit or allow the lease to terminate. Portland General has notified the Company
that it will exercise its rights to purchase the units covered by its leases
when they expire.

Regulatory Environment

Except for its investments in wind power and ROVA I, each of Power Operations'
projects in the United States is a qualifying cogeneration facility (QF) under
the Public Utility Regulatory Policy Act of 1978 (PURPA). See Item 3 and Note 18
of LG&E Energy Corp.'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 exempt wholesale generator (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 Federal Power Act, 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 Federal Power Act, but once such an entity files
its electric generation rates with FERC, it becomes a jurisdictional public
utility under the Federal Power Act. 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.

                                       19
<PAGE>

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

Commitments & Contingencies

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 in
four of Power Operations' 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. See Note 18 of LG&E Energy Corp.'s Notes to
Financial Statements under Item 8.

Westmoreland-LG&E Partners (WLP), the partnership that owns the ROVA I and II
facilities, is seeking the recovery of capacity payments withheld by VEPCO. 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 regarding the Circuit Court decision. See Note 18 of LG&E
Energy Corp.'s Notes to Financial Statements under Item 8.

In May 1996, Kenetech Windpower, Inc. (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 KW Tarifa, S.A. (Tarifa)
wind projects in which Power Operations has invested, collectively,
approximately $31 million. See Note 18 of LG&E Energy Corp.'s Notes to Financial
Statements under Item 8.

WPP 94, in which the Company has a 25% interest through indirect subsidiaries,
did not make its semiannual payments, due September 1997, March 1998, September
1998 and March 1999, to John Hancock Mutual Life Insurance Company (Hancock)
under certain notes issued by WPP94 to Hancock. WPP 94 and Hancock 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 does not expect
the ultimate resolution of this matter to have a material effect on its results
of operations or financial condition. During the third quarter of 1998, the
Company wrote off its aggregate remaining investment in WPP94. See Note 18 of
LG&E Energy Corp.'s Notes to Financial Statements under Item 8.

                             WESTERN KENTUCKY ENERGY

General

In July 1998, following receipt of necessary regulatory approvals, the Company
closed the transaction to lease the generating assets of Big Rivers. Under the
25-year operating lease, Western Kentucky Energy Corp. and its affiliates (WKE)
lease and operate the operating assets of Big Rivers (three coal-fired plants
and one combustion turbine). In addition, WKE operates and maintains the Station
Two generating facility of the City of Henderson (Henderson). The combined
generating capacity of these facilities amounts to approximately 1,700 Mw, net
of Henderson's capacity and energy needs from Station Two. Under the terms of
the lease agreement, WKE paid Big Rivers a total of $55.9 million for the first
two years 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.


                                       20
<PAGE>

In related transactions, power is supplied to Big Rivers at contractual prices
over the term of the lease to meet the needs of four member distribution
cooperatives serving approximately 91,000 customers in 22 western Kentucky
counties and two aluminum smelters. The excess generating capacity is available
to WKE to market throughout the region.

Also, as part of the transaction, WKE agreed to provide Big Rivers a $50.0
million note to help it emerge from bankruptcy. The terms of the note are that
WKE will provide $1.7 million per month for the first 12 months beginning August
1998 and $2.5 million per month over the subsequent 12 months. 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.

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. 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 will be the predominant fuel used by WKE, with
fuel oil being used for peaking capacity. WKE has entered into coal supply
agreements with various suppliers for coal deliveries for 1999 and beyond. WKE
normally augments its coal supply agreements with spot market purchases. At
December 31, 1998, WKE had on hand coal inventory of approximately 1.1 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 1998 was $20.85.

Environmental Matters

In September 1998, the U.S. Environmental Protection Agency announced its final
regulation requiring significant additional reductions in NOx emissions to
mitigate alleged ozone transport to the Northeast. While each state is free to
allocate its assigned NOx reductions among various emissions sectors as it deems
appropriate, the regulation may ultimately require utilities to reduce their NOx
emissions to 0.15 lb./mmBtu (million British thermal units) - an 85% reduction
from 1990 levels. Under the regulation, each state must incorporate the
additional NOx reductions in its State Implementation Plan (SIP) by September
1999 and affected sources must install control measures by May 2003, unless
granted extensions. Several states, various 



                                       21
<PAGE>

labor and industry groups, and individual companies have appealed the final
regulation to the U.S. Court of Appeals for the D.C. Circuit. Management is
currently unable to determine the outcome or exact impact of this matter until
such time as the states identify specific emissions reductions in their SIP and
the courts rule on the various legal challenges to the final rule. However, if
the 0.15 lb. target is ultimately imposed, WKE will be required to incur
significant capital expenditures and increased operation and maintenance costs
for additional controls. Subject to further study and analysis, WKE estimates
that it may incur capital costs of approximately $100 million. These costs would
generally be incurred beginning in 2000.

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 1998, expenditures for pollution controlled
facilities represented $.5 million of WKE's construction expenditures. 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 Distribuidora de Gas del Centro (Centro) and a minority
interest in Distribuidora de Gas Cuyana (Cuyana). Centro and Cuyana together
serve approximately 706,000 customers in six provinces in Argentina. The
investment in these companies totaled approximately $140 million. Each of these
companies has obtained foreign utility company (FUCO) status under the Holding
Company Act. Generally, FUCO status exempts these facilities from application of
the Holding Company Act.

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.

The Argentine federal regulator of gas transmission and distribution, Energas,
has granted Centro a concession that gives Centro the exclusive right to
distribute natural gas in its service territories. The concession ends in 2028.

Centro and Cuyana have been granted exclusive 35-year concessions to provide gas
distribution services to their respective service territories. These
concessions, which originally expire in 2028, also contain the possibility of a
single 10-year extension.

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

Centro's capital expenditures for 1998 totaled $15 million and were financed
internally. Centro will spend approximately $30 million in 1999 to expand and
maintain its gas distribution network, and it will finance the expenditures
through borrowings and internal sources.


                                       22
<PAGE>

                             DISCONTINUED OPERATIONS

General

Effective June 30, 1998, the Company discontinued its merchant energy trading
and sales business and announced a plan to sell its natural gas gathering and
processing business (Gas Operations). For a more detailed discussion of the
costs incurred see Discontinuance of Merchant Energy Trading and Sales Business
previously discussed in this Item and Notes 3 and 18 of LG&E Energy's Notes to
Financial Statements under Item 8.

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.

Capital Corp.'s Gas Operations, conducted through various subsidiaries, include:
a transportation operation consisting of a 90-mile intrastate pipeline located
in southeast New Mexico (Llano pipeline); 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 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 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 1998.

The 11 gathering systems owned (seven 100%, one leased and ownership interests
ranging from 11% to 50% in three others) and operated during 1998 gathered
approximately 205,000 Mcf of natural gas per day during 1998. During 1998,
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 85,000 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 gallons per day of
natural gas liquids were extracted and sold from these facilities in 1998.

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, 1998, storage capacity of
approximately 3.0 Bcf was leased to other parties.

Governmental Regulations

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 



                                       23
<PAGE>

pursuant to the Natural Gas Act (NGA) and the Natural Gas Policy Act of 1978
(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.

Commitments and Contingencies

For discussions of lawsuits filed as a result of the Company's discovery in the
fourth quarter of 1996 that unauthorized transactions had occurred in its gas
trading business, a lawsuit related to the failure to sell electricity to the
Company pursuant to an interchange agreement, and an arbitration proceeding
related to load projections provided as inducement to enter into a power supply
agreement see Note 18 of LG&E Energy Corp.'s Notes to Financial Statements under
Item 8.

                          EMPLOYEES AND LABOR RELATIONS

LG&E Energy and its subsidiaries had 5,403 full-time employees at December 31,
1998, including 2,315 full-time employees of LG&E and 1,779 full-time employees
of KU. At December 31, 1998, LG&E had 1,385 operating, maintenance, and
construction employees that were members of the International Brotherhood of
Electrical Workers (IBEW) Local 2100. The current three year contract with the
IBEW will expire in November 2001. At December 31, 1998, KU had 233 operating,
maintenance and construction employees who were members of IBEW Local 101 and
United Steelworkers of America (USWA) Local 8686. The current contract will
expire August 1, 1999. At December 31, 1998, WKE had 352 operating, maintenance
and construction employees that were members of the IBEW Local 1701.
The current contract will expire September 14, 2001.


                                       24
<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:

<TABLE>
<CAPTION>

                                                                                                       Capability
                                                                                                      Rating (Kw)
                                                                                                      -----------
                  <S>                                                                                  <C>    
                  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
                                                                                                      -----------
                      Total combustion turbine generators                                                 108,000
                                                                                                      -----------
                  Total capability rating                                                               2,512,000
                                                                                                      -----------
                                                                                                      -----------
</TABLE>

                  (a) Amount shown represents LG&E's 75% interest in Trimble
                      County. LG&E is responsible for operation of Unit 1 and is
                      reimbursed by IMEA and IMPA for expenditures related to
                      Trimble County based on their proportionate share of
                      ownership interest. See Note 19 of LG&E Energy Corp.'s
                      Notes to Financial Statements, Jointly Owned Electric
                      Utility Plant, 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, 1998, 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 82 substations with a total capacity of approximately 3,313,730 Kva,
3,659 structure miles of overhead lines, 341 miles of underground conduit, and
5,451 miles of underground conductors.

LG&E's gas transmission system includes 209 miles of transmission mains, and the
gas distribution system includes 3,720 miles of distribution mains.



                                       25
<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. LG&E Energy has operating leases for its
corporate office space that expire between 1999 and 2012.

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

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

KU's power generating system consists of the coal-fired units operated at its
five steam generating stations. KU owns and operates the following electric
generating stations:

<TABLE>
<CAPTION>

                                                                                                       Capability
                                                                                                      Rating (kw)
                                                                                                      -----------
                  Steam Stations:
                  Tyrone - Tyrone, KY.
                      <S>                                                                                <C>   
                      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

</TABLE>


                                       26
<PAGE>


<TABLE>
<CAPTION>
                                                                                                       Capability
                                                                                                      Rating (kw)
                                                                                                      -----------
                  <S>                                                                                 <C>    
                  Combustion Turbine Generators (Peaking capability):
                  E.W. Brown - Burgin, KY.
                      Unit 8                                                                              135,000
                      Unit 9                                                                              120,000
                      Unit 10                                                                             135,000
                      Unit 11                                                                             122,000
                                                                                                       ----------
                           Total E.W. Brown                                                               512,000
                  Haefling - Lexington, KY.
                      Unit 1                                                                               59,000
                                                                                                      -----------
                  Total capability rating                                                               3,694,000
                                                                                                       ----------
                                                                                                       ----------
</TABLE>

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, 1998, KU's electric transmission system included 107 substations
with a total capacity of approximately 14,538,240 Kva and approximately
4,272,330 structure miles of lines. The electric distribution system included
437 substations with a total capacity of approximately 4,302,120 Kva, 4,272
structure miles of overhead lines.

At December 31, 1998, Power Operations owned the percentage indicated of the
following joint ventures:


<TABLE>
<CAPTION>
                                                                                     Net
                                                  Ownership                        Capability
         Name                                     Interest %             Fuel      Rating (Mw)
         -------                                  ----------             ----      -----------
<S>                                                      <C>            <C>              <C>
         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

         LG&E Westmoreland-Rensselaer                    50           Natural              79
         Rensselaer, New York (sold March 15,                             Gas
         1999 - see below)

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

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

</TABLE>


                                       27
<PAGE>

<TABLE>
<CAPTION>

                                                                                  Net
                                                  Ownership                 Capability
         Name                                     Interest %      Fuel      Rating (Mw)
         ------                                   ----------      ----      -----------
         <S>                                      <C>            <C>           <C>  
         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
</TABLE>

Power Operations' ownership interests in these projects (except Rensselaer) 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 Corp.'s Notes to Financial Statements under Item 8
for a discussion of the bankruptcy filing of an affiliate of Power Operations'
partner in the Southampton, Altavista, Hopewell, Rensselaer and Roanoke Valley
joint ventures. Also, see the same note for a discussion of the bankruptcy
filing of an affiliate of Power Operations' partner in the Windpower Partners
1993 and Windpower Partners 1994 joint ventures. See Note 8 of LG&E Energy
Corp.'s Notes to Financial Statements under Item 8.

On March 15, 1999, LG&E Westmoreland - Rensselaer, in which Power Operations has
a 50% interest, sold the assets of the Rensselaer cogeneration facility. This
transaction will result in a pre-tax gain for Power Operations of approximately
$14.5 million.

At December 31, 1998, Power Operations owned equity interests in the following
combustion turbine units which are leased to utility companies. The leases
expire in 1999. Upon expiration of each of the leases, each of the lessees has
the option to extend the lease, purchase the unit or allow the lease to
terminate.

<TABLE>
<CAPTION>
                                                                                                       Capacity
                                                                                     Ownership             (Mw)
         Unit                                       Quantity             Fuel       Interest %         Per Unit
         -----                                      --------             ----       ----------         --------
<S>                                                        <C>        <C>                  <C>             <C> 
         Beaver, OR                                        2          Gas/Oil              100             59.3

         Blytheville, AR                                   3              Gas               49             64.6

         Beaver, OR                                        2          Gas/Oil               49             59.3

         Ferndale, WA                                      1              Gas               49             56.9
</TABLE>

Portland General Electric Company (Portland General) is the lessee of the units
in Beaver, Arkansas Power & Light Company (AP&L) is the lessee of the units in
Blytheville, and Puget Sound Power & Light Company (PSP&L) is the lessee of the
unit in Ferndale.

Portland General has agreed to purchase the four units in Beaver for
approximately $20 million. This transaction is expected to close in the second
half of 1999. AP&L has decided to allow its lease to terminate and not to buy
the turbines in Blytheville. PSP&L has not decided if it will exercise its
option to extend its lease, purchase the unit in Ferndale, or allow its lease to
terminate.


                                       28
<PAGE>

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. These gas gathering systems make up part of the Company's
Merchant Energy Trading and Sales Business, which the Company discontinued
effective June 30, 1998. See Discontinued Operations under this Item.

The major gas gathering system is the Llano pipeline, a 90-mile intrastate
pipeline system in southeastern New Mexico with a throughput capacity of 180,000
MCF of gas per day. Capital Corp., through subsidiaries, owns two gas
transmission systems located in Texas which total 76 miles. This system has a
design capacity of 90,000 MCF of gas per day. It also owns, or has interests in,
and operates five natural gas processing plants located in southeastern New
Mexico and western Texas with a total design capacity of 125,000 MCF of gas per
day (owns 100% interests in three of these plants, and a majority of the two
remaining plants). Only three of the five plants are active currently. In
addition, Capital Corp. owns and operates a sour gas treating facility in Texas
and an underground natural gas storage facility adjacent to the Llano pipeline
in southeastern New Mexico with a current working capacity of approximately six
BCF of natural gas. The Llano pipeline makes up part of the Company's Merchant
Energy Trading and Sales Business, which the Company discontinued effective June
30, 1998.

WKE is leasing and operating for 25 years all of the generating assets owned by
Big Rivers, a Henderson, Kentucky-based power generation cooperative with 1,459
Mw of owned net generating capacity. Big Rivers owns three coal-fired plants and
one combustion turbine. In addition, WKE operates a 312 Mw coal-fired facility
owned by the City of Henderson, Kentucky, with contractual rights to any surplus
power generated by such facility, which historically has been about 80% of the
unit's capacity.

Centro's gas transmission and distribution system includes 5,963 miles of
transmission mains and distribution mains located in Cordoba, Argentina, and
neighboring provinces. Cuyana's gas transmission and distribution system
includes approximately 4,800 miles of transmission mains and distribution mains
located in Mendoza Province, Argentina, and neighboring provinces.

ITEM 3.  Legal Proceedings.

Rates and Regulatory Matters

For a discussion of current regulatory matters, including a discussion of (a)
rate matters addressed in the Kentucky Commission's order approving the KU
Merger, (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, 5 and 18
of LG&E Energy Corp.'s Notes to Financial Statements, Note 3 LG&E's Notes to
Financial Statements and Notes 3 of KU's Notes to Financial Statements under
Item 8.

Performance-Based Ratemaking

In October, 1998, LG&E and KU filed applications with the Kentucky Commission
for appeal of a performance-based method for determining electric rates. The
companies' proposals include financial incentives to reduce fuel costs and
increase generating efficiency, as well as financial penalties and rewards in
other performance areas. The proposals are subject to approval by the Kentucky
Commission, with a decision likely to occur during 1999. Certain intervenors
have requested that the Kentucky Commission significantly reduce base rates
before implementing PBR. See Rates and Regulations under Item 7 and Notes 5 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 



                                       29
<PAGE>

and 13 to KU's Notes to Financial Statements.

Fuel Adjustment Clause Proceedings

Pursuant to Kentucky statute, aspects of the Company's utilities rates are
reviewed through semi-annual fuel adjustment clause (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. Although the outcome of this proceeding cannot be
predicted, the Company believes that, based upon its review of the legal and
regulatory precedence, its position should prevail and that the PSC should not
disallow any of the energy charges in this category for any part of the four
year period. KU estimates the amount of disputed costs to be approximately $12.8
million through October 31, 1998. See also Note 18 to LG&E Energy's Notes to
Financial Statements and Note 11 to KU's Notes to Financial Statements. See
Rates and Regulatory Matters above regarding electric line loss matters arising
during LG&E's and KU's FAC proceedings.

Environmental

For a discussion of environmental matters concerning (a) currently proposed NOx
and SO2 emission limit decreases, (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 Note 18 of LG&E Energy's Notes to
Financial Statements, Note 12 of LG&E's Notes to Financial Statements and Note
11 of KU's Notes to Financial Statements under Item 8, respectively.

Southampton

For a discussion of the settlement of certain FERC proceedings involving
LG&E-Westmoreland Southampton, the partnership that owns the Southampton
facility, regarding the Southampton facility 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

Westmoreland-LG&E Partners (WLP), the partnership that owns the Roanoke Valley I
and II facilities, is seeking the recovery of capacity payments withheld by
Virginia Electric and Power Company (VEPCO). In November 1998, the Circuit Court
for the City of Richmond, Virginia issued an opinion awarding WLP approximately
$19 million plus interest until paid, and addressed certain other issues. In
January 1999, VEPCO appealed the decision. See Item 1 and Note 18 of LG&E Energy
Corp.'s Notes to Financial Statements under Item 8.

Kenetech Bankruptcy

In May 1996, Kenetech Windpower, Inc. (Kenetech) filed for protection under
Chapter 11 of the United States Bankruptcy Code in the 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 Windpower
Partners 1993, Windpower Partners 1994 and KW Tarifa, S.A. wind projects. In
January 1999, the Bankruptcy Court approved an initial plan of reorganization.
See Note 18 of LG&E Energy Corp.'s Notes to Financial Statements under Item 8
for a further discussion.


                                       30
<PAGE>

Windpower Partners 1994

Windpower Partners 1994 (WPP 94), in which the Company has a 25% interest
through indirect subsidiaries, did not make semiannual payments, due September
1997, March 1998, September 1998 and March 1999 to John Hancock Mutual Life
Insurance Company (Hancock) under certain Notes issued by WPP 94 to Hancock. The
Company has offered WPP 94 financial support with respect to the appropriate
proportion of its debt obligations, but certain of the three other investor
groups are unable to offer funds to WPP 94 in support of the partnership. See
Note 18 of LG&E Energy Corp.'s Notes to Financial Statements under Item 8 for a
further discussion.

Calgary

On November 22, 1996 LG&E Natural Canada Inc., an indirect subsidiary of LG&E
Energy, 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

LG&E Energy Marketing Inc. (LEM), an indirect subsidiary of LG&E Energy, filed
suit against the City of Springfield, Illinois, City Water, Light and Power
Company in the United States District Court for the Western District of
Kentucky. 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 Oglethorpe
Power Corporation (OPC) in connection with matters involving LEM's November 1996
power sales agreement with OPC. Selection of arbitrators was completed in
February 1999 and discovery proceedings have commenced in this matter. See Note
18 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.



                                       31
<PAGE>

Executive Officers of LG&E Energy Corp.:

<TABLE>
<CAPTION>
                                                                                    Effective Date of
                                                                                    Election to Present
         Name                          Age             Position                     Position
         ------                        ---             --------                     --------------------
<S>                                    <C>             <C>                          <C>
         Roger W. Hale                 55              Chairman of the Board        August 17, 1990
                                                       and Chief Executive
                                                       Officer

         Victor A. Staffieri           43              President and Chief          February 16, 1999
                                                       Operating Officer

         R. Foster Duncan              45              Executive Vice President     February 16, 1999
                                                       and Chief Financial Officer

         Stephen R. Wood               56              President - Distribution     May 15, 1997
                                                       Services Division
                                                       President - Louisville Gas
                                                       and Electric Company

         Robert M. Hewett              52              President - Kentucky         May 4, 1998
                                                       Utilities Company

         John R. McCall                55              Executive Vice President,    July 1, 1994
                                                       General Counsel and
                                                       Corporate Secretary

         Wayne T. Lucas                51              Executive Vice President -   May 4, 1998
                                                       Power Generation

         George W. Basinger            53              Senior Vice President -      May 4, 1998
                                                       Independent Power
                                                       Operations

         Donald F. Santa, Jr.          40              Senior Vice President and    October 1, 1998
                                                       Deputy General Counsel

         Frederick J. Newton III       43              Senior Vice President and    January 2, 1999
                                                       Chief Administrative
                                                       Officer

         S. Bradford Rives             40              Senior Vice President -      February 16, 1999
                                                       Finance and Business
                                                       Development

         Wendy C. Heck                 45              Vice President - Infor-      February 3, 1998
                                                       mation Technology

         Charles A. Markel             51              Vice President -             January 1, 1993
                                                       Finance and Treasurer

         Michael D. Robinson           43              Vice President and           February 16, 1999
                                                       Controller
</TABLE>



                                       32
<PAGE>

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 April 21, 1999.

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

Messrs. Hale, Lucas, Duncan, McCall, Newton, Markel and Robinson 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. 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; and Mr. Robinson
is Vice President and Controller of LG&E and KU. Mr. Wood and Ms. Heck are also
officers of LG&E. Mr. Wood is President of LG&E; and Ms. Heck is Vice President
- Information Technology 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 Senior Vice
President, Public Policy and General Counsel of LG&E Energy Corp. and LG&E from
November 1992 to January 1994; 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 Senior Vice
President, Corporate Finance and Business Development of Freeport-McMoRan
Resource Partners from March 1993 to May 1994; 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 Senior Vice
President and Chief Administrative Officer of LG&E from August 1990 to January
1994, and Executive Vice President and Chief Administrative Officer of LG&E
Energy Corp. from January 1994 to May 1997.

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; and
Senior Vice President - Customer Service and Marketing of KU from April 1997 to
May 1998.

Before he was elected to his current position, Mr. McCall was Partner and
Litigation Chairman of Brown, Todd & Heyburn, a law firm.

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 June 1998.

Before he was elected to his current position, Mr. Basinger was Partner of
National Power Company prior to November 1993; Vice President of Venture
Management of LG&E Power Inc. from December 1993 to November 1994; 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 



                                       33
<PAGE>

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.

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 Woolworth Corporation
from August 1996 to July 1997; Senior Vice President, Human Resources, at
Woolworth Corporation'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 Associate General
Counsel of LG&E Energy Corp. from January 1994 to June 1994; 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 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. 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.

Executive Officers of LG&E:

<TABLE>
<CAPTION>
                                                                                    Effective Date of
                                                                                    Election to Present
         Name                         Age              Position                     Position
         ------                       ---              --------                     -------------------
<S>                                    <C>             <C>                          <C>    
         Roger W. Hale                 55              Chairman of the Board,       January 1, 1992
                                                       and Chief Executive
                                                       Officer

         Stephen R. Wood               56              President                    May 15, 1997

         R. Foster Duncan              45              Executive Vice President     February 16, 1999
                                                       and Chief Financial Officer

         John R. McCall                55              Executive Vice President,    July 1, 1994
                                                       General Counsel and
                                                       Corporate Secretary

         Wayne T. Lucas                51              Executive Vice President -   May 4, 1998
                                                       Power Generation

         Frederick J. Newton III       43              Senior Vice President and    January 2, 1999
                                                       Chief Administrative
                                                       Officer

         Rebecca L. Farrar             39              Vice President, Gas          February 15, 1995
                                                       Service Business

</TABLE>


                                       34
<PAGE>

<TABLE>
<CAPTION>
                                                                                    Effective Date of
                                                                                    Election to Present
         Name                         Age              Position                     Position
         ----                         ---              --------                     -------------------
<S>                                    <C>             <C>                          <C>    
         Wendy C. Heck                 45              Vice President - Infor-      February 3, 1998
                                                       mation Technology

         Chris Hermann                 51              Vice President, Power        May 4, 1998
                                                       Generation and Engineering
                                                       Services

         Paul W. Thompson              42              Vice President, Retail       September 15, 1996
                                                       Electric Business

         Ronald L. Willhite            52              Vice President -             May 4, 1998
                                                       Regulatory Affairs

         Michael D. Robinson           43              Vice President and           May 4, 1998
                                                       Controller

         Charles A. Markel             51              Treasurer                    January 1, 1993
</TABLE>


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 April 21, 1999.

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

Messrs. Hale, Lucas, Duncan, McCall, Newton, Markel and Robinson 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. 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; and Mr. Robinson is Vice
President and Controller of LG&E Energy Corp. and KU. Mr. Wood and Ms. Heck are
also officers of LG&E Energy Corp. Mr. Wood is President - Distribution Services
of LG&E Energy Corp.; and Ms. Heck is Vice President - Information Technology of
LG&E Energy Corp. Mr. Willhite is also Vice President - Regulatory Affairs of
KU.

Before he was elected to his current position, Mr. Wood was Senior Vice
President and Chief Administrative Officer of LG&E from August 1990 to January
1994, and Executive Vice President and Chief Administrative Officer of LG&E
Energy Corp. from January 1994 to May 1997.

Before he was elected to his current position, Mr. Duncan was Senior Vice
President, Corporate Finance and Business Development of Freeport-McMoRan
Resource Partners from March 1993 to May 1994; 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 Partner and
Litigation Chairman of Brown, Todd & Heyburn, a law firm.

                                       35
<PAGE>

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 June 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 Woolworth Corporation
from August 1996 to July 1997; Senior Vice President, Human Resources, at
Woolworth Corporation'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 Division Manager,
Central Division-Gas Operations of South Carolina Electric and Gas Company from
February 1992 to July 1994; and General Manager, Gas Operations of South
Carolina Electric and Gas Company from July 1994 to February 1995.

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; and Vice President, Business Integration of LG&E from June 1997 to
May 1998.

Before he was elected to his current position, Mr. Thompson was
Director-Business Development for LG&E Energy Corp. prior to December 1993;
General Manager-Gas Operations for LG&E from December 1993 to July 1994; and
Vice President-Business Development for LG&E Energy Corp. from July 1994 to
September 1996.

Before he was elected to his current position, Mr. Willhite was Director of
Regulation for Kentucky Utilities prior to April 1997; and Vice President of
Regulation and Economic Planning for Kentucky Utilities from April 1997 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.

Executive Officers of KU:

<TABLE>
<CAPTION>
                                                                                    Effective Date of
                                                                                    Election to Present
         Name                          Age             Position                     Position
         ----                          ---             --------                     -------------------
<S>                                    <C>             <C>                          <C>    
         Roger W. Hale                 55              Chairman of the Board,       May 4, 1998
                                                       and Chief Executive
                                                       Officer

         Robert M. Hewett              52              President                    May 4, 1998

         Wayne T. Lucas                51              Executive Vice President -   May 4, 1998
                                                       Power Generation
</TABLE>




                                       36
<PAGE>

<TABLE>
<CAPTION>

                                                                                    Effective Date of
                                                                                    Election to Present
         Name                          Age             Position                     Position
         ----                          ---             --------                     -------------------
<S>                                    <C>             <C>                          <C>    
         R. Foster Duncan              45              Executive Vice President     February 16, 1999
                                                       and Chief Financial Officer

         John R. McCall                55              Executive Vice President,    May 4, 1998
                                                       General Counsel and
                                                       Corporate Secretary

         Frederick J. Newton III       43              Senior Vice President and    January 2, 1999
                                                       Chief Administrative
                                                       Officer

         Gary E. Blake                 45              Vice President - Sales       May 4, 1998
                                                       and Service

         James J. Ellington            53              Vice President - Power       May 4, 1998
                                                       Generation

         Ronald L. Willhite            52              Vice President -             May 4 1998
                                                       Regulatory Affairs

         Michael D. Robinson           43              Vice President and           August 1, 1990
                                                       Controller

         Charles A. Markel             51              Treasurer                    May 4, 1998
</TABLE>

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 April 21, 1999.

There are no family relationships between executive officers of KU.

Messrs. Hale, Lucas, Duncan, McCall, Newton, Markel and Robinson are also
executive officers of LG&E Energy Corp. and LG&E. Mr. Hale is Chairman of the
Board and 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. 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; and Mr. Robinson is
Vice President and Controller of LG&E Energy Corp. and LG&E. Mr. Willhite is
also Vice President - Regulatory Affairs of LG&E.

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. Hewett was Vice President -
Regulation and Economic Planning of KU from January 1982 to April 1997; and
Senior Vice President - Customer Service and Marketing of KU from April 1997 to
May 1998.

Before he was elected to his current position, Mr. Lucas was Vice President,
Energy Supply of KU from 



                                       37
<PAGE>

November 1986 to November 1994; and Senior Vice President, Energy Supply of KU
from November 1994 to June 1998.

Before he was elected to his current position, Mr. Duncan was Senior Vice
President, Corporate Finance and Business Development of Freeport-McMoRan
Resource Partners from March 1993 to May 1994; 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 Partner and
Litigation Chairman of Brown, Todd & Heyburn, a law firm, through June 1994; and
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 Woolworth Corporation
from August 1996 to July 1997; Senior Vice President, Human Resources, at
Woolworth Corporation'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. 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. Willhite was Director of
Regulation for Kentucky Utilities prior to April 1997; and Vice President of
Regulation and Economic Planning for Kentucky Utilities from April 1997 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.



                                       38


<PAGE>


                                    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 in THE WALL STREET 
JOURNAL 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>
                                            1998                                            1997
                                            ----                                            ----
                              Dividend       High          Low               Dividend        High         Low
                                  Paid      Price        Price                   Paid       Price       Price
                             ---------      -----        -----               --------       -----       -----
<S>                          <C>         <C>         <C>                    <C>         <C>          <C>
         First quarter          $.2975   $26.4375     $23.0000                 $.2875    $25.8750    $23.5000
         Second quarter          .2975    27.7500      24.6875                  .2875     25.0000     21.8125
         Third quarter           .2975    27.8750      22.5000                  .2875     23.4375     21.2500
         Fourth quarter          .3075    29.3125      26.0625                  .2975     25.0625     21.2500
</TABLE>

The number of record holders of Common Stock at December 31, 1998, totaled
50,199. The book value of the Company's Common Stock at December 31, 1998, was
$9.57 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 $):

<TABLE>
<CAPTION>
                                                          1998              1997
                                                          ----              ----
<S>                                                    <C>               <C>
         First quarter                                 $20,000           $19,000
         Second quarter                                 19,800                 -
         Third quarter                                  21,200            19,000
         Fourth quarter                                 22,000            20,000
</TABLE>


                                       39

<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 to
LG&E Energy (in thousands of $):

<TABLE>
<CAPTION>
                                                          1998              1997
                                                          ----              ----
<S>                                                    <C>               <C>
         First quarter                                 $17,018           $16,639
         Second quarter                                 23,071            16,640
         Third quarter                                  18,000            16,640
         Fourth quarter                                 18,000            16,640
</TABLE>

ITEM 6.  Selected Financial Data.

<TABLE>
<CAPTION>
                                                              Years Ended December 31
                                                      (Thousands of $ Except Per Share Data)
                                               --------------------------------------------------------------------------
                                               1998              1997             1996              1995             1994
                                               ----              ----             ----              ----             ----
<S>                                    <C>               <C>               <C>              <C>               <C>
         LG&E ENERGY:
         Revenues:
         Revenues                        $2,002,413        $1,725,055       $1,560,460        $1,460,980       $1,467,258
         Provision for rate refunds         (26,000)               --               --           (28,300)              --
                                        -----------       -----------      -----------       -----------      -----------
           Net revenues                   1,976,413         1,725,055        1,560,460         1,432,680        1,467,258
                                        -----------       -----------      -----------       -----------      -----------
                                        -----------       -----------      -----------       -----------      -----------

         Operating income:
         Before non-recurring items         475,285           418,855          380,038           350,898          335,691
         Provision for rate refunds         (26,000)               --               --           (29,800)              --
         Merger costs to achieve and
           non-recurring charges            (65,318)               --          (5,493)                --         (48,743)
                                        -----------       -----------      -----------       -----------      -----------
              Operating income              383,967           418,855          374,545           321,098          286,948
                                        -----------       -----------      -----------       -----------      -----------
                                        -----------       -----------      -----------       -----------      -----------

         Net income (loss):
         Before non-recurring items         232,216           207,040          192,786           177,467          171,622
         Provision for rate refunds         (15,556)               --               --           (17,852)              --
         Merger costs to achieve and
           non-recurring charges            (56,389)               --           (2,400)               --          (38,696)
                                        -----------       -----------      -----------       -----------      -----------
              Total continuing
                 operations                 160,271           207,040          190,386           159,615          132,926
         Discontinued operations            (23,599)          (24,044)          (4,434)             (732)            (241)
         Gain (loss) on sale of
           discontinued operations         (225,000)               --               --                --           51,805
         Cumulative effect of
           accounting change                 (7,162)               --               --                --           (3,369)
                                        -----------       -----------      -----------       -----------      -----------
              Net income (loss)        $    (95,490)     $    182,996     $    185,952      $    158,883     $    181,121
                                        -----------       -----------      -----------       -----------      -----------
                                        -----------       -----------      -----------       -----------      -----------

         Average number of com-
           mon shares outstanding       129,679,020       129,626,875      129,449,526       129,261,031      129,137,726
</TABLE>


                                               40
<PAGE>

<TABLE>
<CAPTION>
                                                              Years Ended December 31
                                                      (Thousands of $ Except Per Share Data)
                                               --------------------------------------------------------------------------
                                               1998              1997             1996              1995             1994
                                               ----              ----             ----              ----             ----
<S>                                    <C>               <C>               <C>              <C>               <C>
         LG&E ENERGY (CONT.):
         Earnings (loss) per share of 
           common stock (basic):
         Before non-recurring items           $1.79             $1.60            $1.49             $1.37            $1.33
         Provision for rate refunds            (.12)               --               --              (.14)              --
         Merger costs to achieve and
           non-recurring charges               (.43)               --             (.02)               --             (.30)
                                        -----------       -----------      -----------       -----------      -----------
              Total continuing
                 operations                    1.24              1.60              1.47             1.23             1.03
         Discontinued operations               (.18)             (.19)             (.03)              --               --
         Gain (loss) on sale of
           discontinued operations            (1.74)               --                --               --              .40
         Cumulative effect of
           accounting change                   (.06)               --                --               --             (.03)
                                        -----------       -----------      -----------       -----------      -----------
              Earnings (loss) per
                 share                        $(.74)            $1.41            $1.44             $1.23            $1.40
                                        -----------       -----------      -----------       -----------      -----------
                                        -----------       -----------      -----------       -----------      -----------


         Earnings (loss) per share of 
           common stock (diluted):
         Before non-recurring items           $1.79             $1.60            $1.49            $1.37             $1.33
         Provision for rate refunds            (.12)               --               --             (.14)               --
         Merger costs to achieve and
           non-recurring charges               (.44)               --             (.02)              --              (.30)
                                        -----------       -----------      -----------       -----------      -----------
             Total continuing
                 operations                    1.23              1.60             1.47             1.23              1.03
         Discontinued operations               (.17)             (.19)            (.03)              --                --
         Gain (loss) on sale of
           discontinued operations            (1.73)               --               --               --               .40
         Cumulative effect of
           accounting change                   (.06)               --               --               --              (.03)
                                        -----------       -----------      -----------       -----------      -----------
              Earnings (loss) per
                 share                        $(.73)            $1.41            $1.44            $1.23             $1.40
                                        -----------       -----------      -----------       -----------      -----------
                                        -----------       -----------      -----------       -----------      -----------

         Cash dividends declared per
           share of common stock             $1.240            $1.113           $1.081           $1.050            $1.021
         Payout ratio (from continuing
           operations before non-
           recurring items)                   69.3%             69.7%             72.6%            76.5%             76.8%

         Total assets                   $4,773,268        $4,562,944        $4,132,599        $4,101,526       $3,887,122

         Long-term obligations
           (including amounts
           due within one year)          1,510,775         1,230,711         1,193,229         1,208,846        1,158,895
</TABLE>


         LG&E Energy Corp.'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.


                                       41

<PAGE>


<TABLE>
<CAPTION>
                                                              Years Ended December 31
                                                                 (Thousands of $)
                                               --------------------------------------------------------------------------
                                               1998              1997             1996              1995             1994
                                               ----              ----             ----              ----             ----
<S>                                      <C>             <C>             <C>                  <C>              <C>  
         LG&E:
         Operating revenues:
         Revenues                          $854,556          $845,543         $821,115          $751,763         $759,075
         Provision for rate refunds          (4,500)               --               --           (28,300)              --
                                         ----------        ----------       ----------        ----------       ----------
           Total operating revenues         850,056           845,543          821,115           723,463          759,075
                                         ----------        ----------       ----------        ----------       ----------
                                         ----------        ----------       ----------        ----------       ----------

         Net operating income:
         Before unusual items               138,207           148,186          147,263           138,203          134,393
         Provision for rate refunds          (2,684)               --               --           (16,877)              --
         Non-recurring charges                   --                --               --                --          (23,353)
                                         ----------        ----------       ----------        ----------       ----------
           Operating income                 135,523           148,186          147,263           121,326          111,040
                                         ----------        ----------       ----------        ----------       ----------
                                         ----------        ----------       ----------        ----------       ----------

         Net income:
         Before unusual items               104,381           113,273          107,941           100,061           94,423
         Provision for rate refunds          (2,684)               --               --           (16,877)              --
         Merger costs to achieve and
           non-recurring charges            (23,577)               --               --                --          (32,734)
         Cumulative effect of
           accounting change                     --                --               --                --           (3,369)
                                         ----------        ----------       ----------        ----------       ----------
              Net income                     78,120           113,273          107,941            83,184           58,320
                                         ----------        ----------       ----------        ----------       ----------
                                         ----------        ----------       ----------        ----------       ----------

         Net income available
           for common stock                  73,552           108,688          103,373            76,873           52,492
                                         ----------        ----------       ----------        ----------       ----------
                                         ----------        ----------       ----------        ----------       ----------

         Total assets                     2,104,637         2,055,641        2,006,712         1,979,490        1,966,590
                                         ----------        ----------       ----------        ----------       ----------
                                         ----------        ----------       ----------        ----------       ----------

         Long-term obligations
           (including amounts
           due within one year)            $626,800          $646,800         $646,800          $662,800         $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.

<TABLE>
<CAPTION>
                                                              Years Ended December 31
                                                                 (Thousands of $)
                                               --------------------------------------------------------------------------
                                               1998              1997             1996              1995             1994
                                               ----              ----             ----              ----             ----
<S>                                      <C>              <C>               <C>               <C>              <C>      
         KU:
         Operating revenues:
         Revenues                          $831,614          $716,437         $711,711          $686,430         $656,013
         Provision for rate refund          (21,500)               --               --                --          (19,385)
                                         ----------        ----------       ----------        ----------       ----------
           Operating revenues               810,114           716,437          711,711           686,430          636,628
                                         ----------        ----------       ----------        ----------       ----------

         Net operating income:
         Before unusual items               138,263           118,408          117,337           108,544          120,571
         Provision for rate refund          (12,875)               --               --                --          (19,385)
                                         ----------        ----------       ----------        ----------       ----------
           Operating income                 125,388           118,408          117,337           108,544          101,186
                                         ----------        ----------       ----------        ----------       ----------
                                         ----------        ----------       ----------        ----------       ----------
</TABLE>

                                       42

<PAGE>

<TABLE>
<CAPTION>
                                                              Years Ended December 31
                                                                 (Thousands of $)
                                               --------------------------------------------------------------------------
                                               1998              1997             1996              1995             1994
                                               ----              ----             ----              ----             ----
<S>                                    <C>               <C>                <C>               <C>             <C>        
         KU (CONT.):
         Net income:
         Before unusual items               107,303            85,713           86,163            76,842           96,897
         Provision for rate refund          (12,875)               --               --                --          (19,385)
         Merger cost to achieve             (21,664)               --               --                --               --
                                         ----------        ----------       ----------        ----------       ----------
           Net income                        72,764            85,713           86,163            76,842           77,512
                                         ----------        ----------       ----------        ----------       ----------
                                         ----------        ----------       ----------        ----------       ----------

         Net income available
           for common stock                  70,508            83,457           83,907            74,586           75,128
                                         ----------        ----------       ----------        ----------       ----------
                                         ----------        ----------       ----------        ----------       ----------

         Total assets                     1,763,797         1,679,880        1,673,055         1,659,988        1,618,100
                                         ----------        ----------       ----------        ----------       ----------
                                         ----------        ----------       ----------        ----------       ----------

         Long-term obligations
           (including amounts
           due within one year)            $546,330          $546,351         $546,373          $545,894         $495,916
                                         ----------        ----------       ----------        ----------       ----------
                                         ----------        ----------       ----------        ----------       ----------
</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.


                                       43

<PAGE>




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 Company's financial results of operations 
and financial condition during 1998, 1997 and 1996 and should be read in 
connection with the consolidated financial statements and notes thereto. As 
set forth in the discussion concerning Discontinued Operations below, future 
financial results from the Company's operations will continue to reflect the 
results from its portfolio of investments in electric generation and gas 
distribution in addition to the financial results provided by the Company's 
regulated utilities, Louisville Gas and Electric Company (LG&E) and Kentucky 
Utilities Company (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 Corp.'s reports to the Securities and Exchange 
Commission, including Exhibit 99.01 to LG&E Energy Corp.'s report on Form 8-K 
filed October 21, 1998.

MERGER

Effective May 4, 1998, following the receipt of all required state and 
federal regulatory approvals, LG&E Energy Corp. (LG&E Energy) and KU Energy 
Corporation (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 contracts. Exiting the merchant energy trading and sales 
business enables the Company to focus on optimizing the value of physical 
assets it owns or controls, and to reduce the earnings impact on continuing 
operations of extreme market volatility in its portfolio of energy marketing 
contracts. The Company is in the process of settling commitments that 
obligate it to buy and sell natural gas and electric power. It also plans to 
sell its natural gas gathering and processing business. If the Company is 
unable to dispose of these commitments or assets it will continue to meet its 
obligations under the contracts. The Company, however, has maintained 
sufficient market knowledge, risk management skills, technical systems and 
experienced personnel to maximize 


                                       44

<PAGE>

LG&E Energy (cont.):

the value of power sales from physical assets it owns or controls, including 
LG&E, KU and the Big Rivers Electric Corporation (Big Rivers).

As a result of the Company's decision to discontinue its merchant energy 
trading and sales activity, and the 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 results primarily from 
several fixed-price energy marketing contracts entered into in 1996 and early 
1997, including the Company's long-term contract with Oglethorpe Power 
Corporation (OPC). Other components of the write-off include costs relating 
to certain peaking options, goodwill associated with the Company's 1995 
purchase of merchant energy trading and sales operations and exit costs, 
including labor and related benefits, severance and retention payments, and 
other general and administrative expenses. 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, it 
also recognizes that there are inherent limitations in models to accurately 
predict future events. As a result, there is no guarantee that 
higher-than-anticipated future commodity prices or load demands, lower- 
than-estimated asset sales prices or other factors could not result in 
additional losses. The Company has been successful in settling portions of 
its discontinued operations, but significant assets, operations and 
obligations remain. As of January 27, 1999, 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 $8.8 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 27, 1999, the Company estimates that a 
1% change in the forecasted load demand could change the value of the 
Company's remaining energy portfolio by $9.3 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.

MASTER RESTRUCTURING AGREEMENT

On June 30, 1998, the partnership that owns the Rensselaer cogeneration 
facility, along with 14 other independent power producers, participated in 
the consummation of a Master Restructuring Agreement (MRA) with Niagara 
Mohawk Power Corporation (NIMO), the utility purchasing energy from the 
Rensselaer facility. The Company recognized a net after-tax gain on the MRA 
transaction and settlement of $21 million. See Note 8 of LG&E Energy's Notes 
to Financial Statements under Item 8.

LEASE OF BIG RIVERS FACILITIES

On July 15, 1998, the Company closed the transaction to lease the generating 
assets of Big Rivers following receipt of necessary regulatory approvals. 
Under the 25-year operating lease, Western Kentucky Energy Corp. and its 
affiliates (WKE) are leasing and operating Big Rivers' three coal-fired 
facilities. In addition, WKE operates and maintains the Station Two 
generating facility of the City of Henderson (Henderson). The combined 
generating capacity of these facilities amounts to approximately 1,700 
megawatts, 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 four 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 


                                       45

<PAGE>

LG&E Energy (cont.):

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.

RESULTS OF OPERATIONS

Earnings per Share

Continuing operations for 1998 produced basic earnings per share of $1.24, 
before a decrease of 6 cents due to cumulative effect of an accounting 
change, a decrease of 36 cents per share from $1.60 earned from continuing 
operations in 1997. Earnings for 1998 include non-recurring charges for 
merger-related costs and environmental cost recovery refunds of 43 cents and 
12 cents, respectively. Excluding these non-recurring charges, earnings per 
share from continuing operations for 1998 were $1.79, an increase of 19 cents 
over 1997. The 19 cent per share increase resulted from a 10 cent increase in 
core domestic utility business and a 16 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 
consummation of the MRA with NIMO, 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 our 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 plant in San Miguel, Argentina and, the 
write-off of our Windpower Partners 1994 investment.

Earnings per share from continuing operations for 1997 were $1.60, an 
increase of 13 cents per share from the $1.47 earned from continuing 
operations in 1996. Earnings for 1996 included a charge of 2 cents resulting 
from a write-off associated with non-utility investments. Excluding this 
charge, earnings per share from continuing operations for 1996 were $1.49; 
thus, 1997 earnings from continuing operations increased 11 cents. The 11 
cent per share increase resulted from an increase in core utility business 
earnings of 3 cents, first-year earnings related to the acquisition of 
interests in two Argentine gas distribution units of 4 cents, and an increase 
in the non-utility power generation business of 8 cents, partially offset by 
an increase in corporate and other expenses, including interest expense on 
debt incurred to acquire non-utility businesses of 4 cents. The 3 cent 
increase in utility earnings was primarily due to higher contributions from 
wholesale electric sales and lower maintenance expenses.

Loss from discontinued operations decreased from 19 cents in 1997 to 18 cents 
in 1998, due primarily to the Company's decision to exit the merchant energy 
trading and sales business effective June 30, 1998. See Note 3 of LG&E 
Energy's Notes to Financial Statements under Item 8.

Loss from discontinued operations increased from 3 cents in 1996 to 19 cents 
in 1997, due primarily to abnormal weather, price volatility in the energy 
market and narrowing margins in the natural gas business.


                                       46

<PAGE>

LG&E Energy (cont.):

Electric and Gas Utility Results

Revenues

A comparison of utility revenues for the years 1998 and 1997, excluding the 
$26 million provision recorded for refund of environmental costs previously 
recovered from customers (ECR refund), 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
                                                                  1998          1997             1998        1997
                                                                  ----          ----             ----        ----
<S>                                                       <C>              <C>             <C>           <C>
         Sales to ultimate consumers:
           Fuel and gas supply adjustments, etc.           $     4,908      $ (7,569)       $  (4,393)   $ 27,192
           Merger surcredit                                     (7,501)           --               --          --
           Demand side management/decoupling                    (6,299)        8,041             (369)      4,348
           Environmental cost recovery surcharge                  (807)        1,002               --          --
           Variation in sales volumes                           52,892         6,491          (42,418)    (14,891)
                                                           -----------     ---------        ---------    --------
              Total retail sales                                43,193         7,965          (47,180)     16,649
         Wholesale sales                                        90,386         1,210            8,720          --
         Gas transportation-net                                     --            --              (71)        147
         Other                                                    (324)        3,548             (935)       (204)
                                                           -----------     ---------        ---------    --------
           Total                                             $ 133,255      $ 12,723        $ (39,466)   $ 16,592
                                                           -----------     ---------        ---------    --------
                                                           -----------     ---------        ---------    --------
</TABLE>

Electric retail sales increased primarily due to the warmer weather 
experienced 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 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 performance-based 
ratemaking mechanism. See Note 5 of LG&E Energy's Notes to Financial 
Statements under Item 8.

Electric revenues increased in 1997 due to a higher level of industrial sales 
and other revenues. Gas revenues increased primarily as a result of higher 
gas supply costs billed to customers through the gas supply clause, partially 
offset by decreased gas sales due mainly to warmer weather.

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 a fuel adjustment clause (FAC) and LG&E's gas rates contain a 
gas supply clause, 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 Public Service Commission (Kentucky Commission or Commission), the 
Virginia State Corporation Commission (Virginia Commission) and the Federal 
Energy Regulatory Commission (FERC).

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). Fuel 
expenses incurred in 1997 decreased $10 million primarily due to a decrease 
in generation at KU which resulted from an increase in economic power 
purchased. LG&E's average delivered cost per ton of coal purchased was $22.38 
in 1998, $21.66 in 1997, and $21.73 in 1996. KU's average delivered cost per 
ton of coal purchased was 

                                       47

<PAGE>

LG&E Energy (cont.):

$26.97 in 1998, $27.97 in 1997, and $27.54 in 1996.

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. 
Purchased power expense increased $10.7 million (13%) in 1997, due to an 
increase at KU in kilowatt hour (kWh) purchases associated with increased 
availability of surplus power on favorable pricing terms and to a one-time 
reduction at KU in demand costs in 1996 of about $4 million under a contract 
with a neighboring utility.

Gas supply expenses decreased $33 million (21%) in 1998 primarily due to a 
decrease in the volume of gas delivered to the distribution system. Gas 
supply expenses for 1997 increased $18.4 million (13%) because of the higher 
cost of net gas supply ($29.3 million), partially offset by a decrease in the 
volume of gas delivered to the distribution system ($10.9 million). The 
average unit cost per thousand cubic feet (Mcf) of purchased gas was $3.05 in 
1998 and $3.46 in 1997 and 1996.

Operation and maintenance expenses increased $14.6 million (3.8%) 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).

Operation and maintenance expenses for 1997 were approximately the same as 
1996. Maintenance decreased in 1997 due mainly to decreased repairs at LG&E's 
electric generating plants caused by fewer outages and a lower level of storm 
damage repairs. These decreases were offset by an increase in costs to 
operate LG&E's power plants and a write-off of certain previously deferred 
items at LG&E that amounted to approximately $3 million. Items written off 
include expenses associated with the hydroelectric plant and a management 
audit fee. Even though LG&E believes it could have reasonably expected to 
recover these costs in future rate proceedings, it decided not to seek 
recovery and expensed these costs because of increasing competitive pressures 
in the industry.

Depreciation and amortization increased $2.7 million (1.5%) in 1998 because 
of additional utility plant in service. Depreciation and amortization 
increased in 1997 primarily because of additional plant in service at both KU 
and LG&E. In addition, 1997 reflects the accelerated write-off of losses on 
early retirements of facilities at LG&E.

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 Public Service Commission. See 
Note 2 of LG&E Energy's Notes to Financial Statements under Item 8.

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 5.57% at December 31, 1998 and 5.68% at 
December 31, 1997. KU's embedded cost of long-term debt was 6.99% at December 
31, 1998 and 6.98% at December 31, 1997. See Note 16 of LG&E Energy'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 the Company's utility 
operations, its ability to control 


                                       48

<PAGE>

LG&E Energy (cont.):

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. Results

LG&E Capital Corp. (Capital Corp.), the holding company for all non-utility 
investments, conducts its operations through three principal segments: 
Independent 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 Independent 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, and own equity interests in combustion 
turbines which are leased to others. WKE leases and operates the generating 
facilities of Big Rivers. Argentine Gas Distribution owns interests in two 
natural gas distribution companies in Argentina. Capital Corp. is also 
engaged in commercial and retail initiatives designed to assess the energy 
and utility needs of large commercial and industrial entities, provide 
maintenance and repair services for customers' major household appliances and 
provide third party metering and billing services. See Notes 2, 4, 8, 9, 18 
and 20 of LG&E Energy's Notes to Financial Statements under Item 8.

Independent Power Operations

Revenues

Revenues from Independent Power Operations, comprised mainly of contractual 
revenues from various power plant operations, were approximately the same in 
1998 and 1997. Revenues increased 9% to $19.6 million in 1997 due to the 
addition of plant operating contracts at the Windpower Partners 1993 (WPP 93) 
California and Minnesota facilities, as well as the Windpower Partners 1994 
(WPP 94) Texas facility. See Note 18 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. The 247% increase in equity in 
earnings in 1998 to $71.3 million was primarily attributable to the closure 
of the MRA transaction with NIMO and an arbitration award received by the 
Frederickson, Washington, venture, partially offset by a write-off of the 
Company's investment in the WPP 94 venture. Equity in Earnings were 
approximately the same in 1997 and 1996. See Notes 8 and 18 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. 
These costs were approximately the same in 1998 and 1997. Expenses increased 
9% to $12.2 million in 1997 due to the addition of the operating contracts at 
the WPP 93 and WPP 94 facilities.

Operation and maintenance expenses were approximately the same for all 
periods presented. 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 a 114 MW 
gas-fired power plant in San Miguel, Argentina and the closure of the MRA 
transaction with NIMO. Depreciation and amortization expenses were 
approximately the same in 1997 and 1996. See Note 8 of LG&E Energy's Notes to 
Financial Statements under Item 8.


                                       49

<PAGE>

LG&E Energy (cont.):

Western Kentucky Energy

WKE commenced operations effective July 15, 1998, after closing its lease 
transaction with Big Rivers and reported solid performance during its first 
partial year of operations 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 of $55.9 million. See Note 4 of LG&E Energy's 
Notes to Financial Statements under Item 8.

Argentine Gas Distribution

In February 1997, the Company acquired interests in two Argentine natural gas 
distribution companies: Distribuidora de Gas del Centro (Centro) and 
Distribuidora de Gas Cuyana (Cuyana). Centro is consolidated within the 
Company's results while Cuyana's results are recorded using the equity method 
of accounting. Our investments in Argentina continue to contribute to our 
non-utility operations, with Centro's revenues increasing by 16% or $21 
million due to a full year of operations in 1998 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% or $2.4 million due to a full 
year of operations in 1998. Equity in earnings of Cuyana were approximately 
the same in 1997 and 1998. See Notes 2 and 8 of LG&E Energy's Notes to 
Financial Statements under Item 8.

Other

The Company has entered into various commercial and retail initiatives to 
position itself for growth in the energy industry. 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 developing ventures will add to our knowledge base as well as 
our financial results in the future.

Interest costs increased by $10.4 million, or 62%, from 1997 to 1998 
primarily due to the funding of discontinued operations and LG&E Energy's 
operating expenses. The increase of $7.5 million, or 80%, from 1996 to 1997 
was primarily due to the Argentine gas distribution acquisition. See Notes 2, 
3, 6 and 16 of LG&E Energy's Notes to Financial Statements under Item 8.

LIQUIDITY AND CAPITAL RESOURCES

The Company's need for capital funds is largely related to the construction 
of plant and equipment necessary to meet the needs of electric and gas 
utility customers and equity investments in connection with independent power 
production projects and other energy-related growth or acquisition 
opportunities among the non-utility businesses. Capital funds are also needed 
for the Company's capital obligations under the Big Rivers lease 
arrangements, losses incurred in connection with the discontinuance of the 
merchant energy trading and sales business, information system enhancements, 
and other business development opportunities. Fluctuations in the Company's 
discontinued energy marketing and trading activities also affected liquidity 
throughout the year. Lines of credit and commercial paper programs are 
maintained to fund these temporary capital requirements.


                                       50

<PAGE>

LG&E Energy (cont.):

Construction Expenditures and Equity Investments

Utility construction expenditures for 1998 were $230 million compared with 
$205 million for 1997 and $215 million for 1996. Non-utility construction 
expenditures (other than unconsolidated ventures) were approximately $112 
million in 1998, $5 million in 1997, and $1 million in 1996. The 1998 
increase for non-utility is mainly due to the purchase of two gas turbine 
peaking units by Capital Corp., system expansion and refurbishment at Centro, 
and generating asset upgrades at WKE.

Past Financing Activities

During 1998, 1997 and 1996, the Company's primary sources of capital were 
internally generated funds from operating cash flows and debt financing. 
Internally generated funds provided financing for 100% of the Company's 
utility construction expenditures for 1998, 1997 and 1996. In 1998, the 
Company financed $92 million in closing costs related to the WKE lease with 
commercial paper. The Company provided its merchant energy trading and sales 
business with additional cash to meet obligations and general working capital 
needs from funds obtained via Capital Corp.'s borrowings. The results of the 
merchant energy trading and sales business are included in discontinued 
operations. The Company acquired interests in two Argentine natural gas 
distribution companies in 1997 for $140 million, plus transaction related 
fees and expenses. This acquisition was financed with cash and lines of 
credit.

The Company's combined cash and marketable securities balance decreased by 
$3.7million in 1998 and increased by $21 million in 1997. The decrease in 
1998 reflects expenses incurred to discontinue our merchant energy trading 
and sales business, merger costs and an increase in capital expenditures, 
partially offset by increased borrowings and cash flow from continuing 
operations. The increase for 1997 reflects cash flows from operations and an 
increase in borrowings, partially offset by capital expenditures and 
dividends paid. In 1996, combined cash and marketable securities decreased 
$15.7 million. This decrease reflects capital expenditures, dividends paid 
and a net decrease in borrowings, partially offset by cash flows from 
operations.

The increases in accounts receivable and accounts payable during 1998 
resulted primarily from the Big Rivers transaction. Variations in accounts 
receivable and accounts payable are not generally significant indicators of 
the Company's liquidity, as such variations are primarily attributable to 
fluctuations in weather in LG&E's and KU's service territories.

In November 1998, Capital Corp. issued $150 million of Reset Put Securities 
due 2011. The interest rate is set at 5.75% through November 1, 2001. The 
securities will be subject to automatic purchase by a remarketing agent, at 
which time the interest rate will be reset, or to automatic repurchase by 
Capital Corp. on November 1, 2001. After taking into account the net effect 
of the derivative instruments entered into in September 1998 to hedge the 
interest rate on the notes and other issuance costs, the effective rate 
through October 31, 2001 is approximately 5.4%. The proceeds were used to 
repay a portion of Capital Corp.'s outstanding commercial paper. See Note 16 
of LG&E Energy's Notes to Financial Statements under Item 8.

On June 1, 1998, LG&E's First Mortgage Bonds, 6.75% Series of $20 million 
matured and were retired by LG&E.  The bonds were redeemed with available 
funds.

In February 1998, Capital Corp. issued $150 million of medium-term notes due 
January 2008, with a stated interest rate on the notes of 6.46%. After taking 
into account the effects of an interest rate swap entered into in 1997 to 
hedge the interest rate on $100 million of such medium-term notes and other 
issuance costs, the effective rate will be 6.82%. The proceeds were used to 
repay outstanding commercial paper. See Note 16 of 


                                       51

<PAGE>

LG&E Energy (cont.):

LG&E Energy's Notes to Financial Statements under Item 8.

In November 1997, LG&E issued $35 million of Jefferson County, Kentucky and 
$35 million of Trimble County, Kentucky, Pollution Control Bonds, Flexible 
Rate Series, due November 1, 2027. The interest rates for these bonds were 
3.09% and 3.39%, respectively, at December 31, 1998. The proceeds from these 
bonds were used to redeem the outstanding 7.75% Series of Jefferson County, 
Kentucky and Trimble County, Kentucky, Pollution Control Bonds due February 
1, 2019.

In September 1997, LG&E Energy Systems Inc. and LG&E Gas Systems Inc. merged 
to form Capital Corp.  At the same time, Capital Corp. implemented a $600 
million commercial paper facility backed by new lines of credit totaling $700 
million.  The Company terminated the previous lines of credit which totaled 
$460 million.

The Company's equity investments in non-utility projects and non-utility 
construction expenditures were financed through internally generated funds 
and short-term borrowings. Construction expenditures for new generating 
projects were generally funded through project debt.

The Company had non-utility short-term borrowings outstanding of $365.1 
million as of December 31, 1998. These borrowings consisted of commercial 
paper, which had maturity dates ranging between 1 and 270 days. Because of 
the rollover of these maturity dates, total short-term borrowings and 
repayments during the year were approximately $6.8 billion. Short-term 
borrowings were $360.2 million as of December 31, 1997, and $158 million as 
of December 31, 1996. The increase in 1997 was primarily due to the 
acquisition of the interests in the Argentine natural gas distribution 
companies and the funding of working capital requirements.

KU had no short-term borrowings at December 31, 1998. At the end of 1997, 
KU's short-term borrowings were $34 million compared to $54 million at 
December 31, 1996. KU has used short-term borrowings to temporarily finance 
ongoing construction expenditures and general corporate requirements. The 
decrease in 1998 from 1997 and 1997 from 1996 was due primarily to KU's cash 
provided by operations exceeding cash required for investing and financing 
activities (exclusive of short-term borrowings). LG&E had no short-term 
borrowings at December 31, 1998 or 1997.

In May 1998, upon closing of the merger with KU Energy, the Company issued 
63,149,394 shares of common stock to former KU Energy shareholders. The 
Company issued 186,192 shares of new common stock in 1997 and 146,678 shares 
in 1996, under various employee plans. The Company announced a program on 
October 14, 1997, authorizing the repurchase of up to 1,000,000 shares of its 
common stock to be used for, among other things, benefit and compensation 
plans. See Note 15 of LG&E Energy's Notes to Financial Statements under Item 
8.

Future Capital Requirements

Future utility financing 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. The Company estimates that LG&E's construction 
expenditures will total $384 million for 1999 and 2000, and that KU's 
construction expenditures for the same period will total approximately $341 
million. Both utilities construction estimates include capital expenditures 
associated with installation of low nitrogen oxide burner systems as 
described in the section titled "Environmental Matters." In addition, KU's 
capital requirements for 2000 include $61.5 million for scheduled debt 
retirements. Capital expenditures for the non-utility businesses are 
anticipated to total $68 million for 1999 and 2000. Other future capital 
funding requirements are dependent 


                                       52

<PAGE>

LG&E Energy (cont.):

upon the identification of suitable investment opportunities to enhance 
shareholder returns and achieve long-term financial objectives through 
business acquisitions.

In October 1998, the Company negotiated for the purchase of two gas turbine 
peaking units at a total cost of approximately $125 million, of which $62 
million was expended in 1998.

In July 1998, as part of the deal structure with Big Rivers, WKE agreed to 
provide Big Rivers a $50 million note to help it emerge from bankruptcy. WKE 
will provide $1.7 million per month for the first 12 months of the note, 
beginning August 1998, and $2.5 million per month over the subsequent 12 
months. The note will be repaid over a three-year period, beginning August 
2000, with interest at 7.165%.

In July 1998, following the Company's decision to discontinue its merchant 
energy trading and sales business, Standard & Poor's (S&P) downgraded the 
credit ratings of the Company and its subsidiaries while Moody's and Duff & 
Phelps (D&P) kept the Company and its subsidiaries at their prior ratings.

The Company's current debt ratings are:

<TABLE>
<CAPTION>
                                                                       Moody's         S&P           D&P
                                                                       -------       ------        ------
<S>                                                                    <C>            <C>           <C>
         LG&E
         First mortgage bonds                                             Aa2          A+            AA
         Unsecured debt                                                   Aa3          A             AA-
         Preferred stock                                                  aa3          A-            AA-

         KU
         First mortgage bonds                                             Aa2          AA-           AA
         Preferred stock                                                  aa3          A-            AA-
         Commercial paper                                                 P-1          A-1           D-1+

         CAPITAL CORP.
         Medium-term notes                                                A1           A             A+
         Commercial paper                                                 P-1          A-1           D-1+
</TABLE>

These ratings reflect the views of Moody's, S&P and D&P. An explanation of 
the significance of these ratings may be obtained from them. 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.

Future Sources of Financing

Internally generated funds from operations and new debt are expected to fund 
LG&E's and KU's anticipated construction expenditures in 1999 and 2000. 
Similarly, the Company anticipates having sufficient internal cash 
generation, borrowing capacity and access to securities markets to meet 
anticipated equity investments and non-utility capital expenditures in 1999 
and 2000.

At December 31, 1998, loan agreements and lines of credit were in place 
totaling $960 million ($200 million for LG&E, $60 million for KU, and $700 
million for Capital Corp.) for which the companies pay commitment or facility 
fees. The LG&E credit facility provides for short-term borrowing. KU's credit 
facilities provide for short-term borrowing and support of commercial paper 
borrowings. The Capital Corp. facilities provide for short-term borrowing, 
letter of credit issuance, and support of commercial paper borrowings. Unused 
capacity 


                                       53

<PAGE>

LG&E Energy (cont.):

under these lines totaled $536.8 million after considering the commercial 
paper support and approximately $58.1 million in letters of credit securing 
on- and off-balance sheet commitments. The credit lines will expire at 
various times from 1999 through 2002. Management expects to renegotiate the 
lines when they expire.

The lenders under the credit facilities, commercial paper facility and the 
medium-term notes for Capital Corp. are entitled to the benefits of a Support 
Agreement with LG&E Energy Corp. See Note 17 of LG&E Energy's Notes to 
Financial Statements under Item 8.

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 financial 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, 1998, the potential change in interest expense 
associated with a 1% change in base interest rates of the Company's unswapped 
debt is estimated at $4 million.

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

LG&E and Capital Corp. have entered into swaps to reduce the impact of 
interest rate changes on their Pollution Control Bonds and commercial paper 
program. The swap agreements involve the exchange of floating-rate interest 
payments for fixed interest payments over the life of the agreements. As of 
December 31, 1998, 40% 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 $5.6 million as of December 
31, 1998. 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 6 of LG&E Energy's Notes to Financial Statements under 
Item 8.

In April 1998, LG&E entered into a forward starting swap agreement. The 
forward swap involves the exchange of floating-rate interest payments for 
fixed interest payments over the life of the agreement. The forward swap was 
entered into to hedge LG&E's exposure to interest rates for the anticipated 
call of its Trimble County, Kentucky, Pollution Control Bonds, 7 5/8% Series, 
due November 1, 2020. The potential loss in fair value from this position 
resulting from a hypothetical 10% change in the yield curve is estimated at 
$7.5 million as of December 31, 1998. See Note 6 of LG&E Energy's Notes to 
Financial Statements under Item 8.

Commodity Price Sensitivity

LG&E and KU have limited exposure to market volatility in prices of fuel or 
electricity, as long as cost-based regulations exist. To mitigate residual 
risks relative to the movements in fuel or electricity prices, LG&E and KU 
have entered into primarily fixed-priced contracts for the purchase and sale 
of electricity through the wholesale electricity market. WKE is exposed to 
changes in fuel prices. To mitigate this risk, WKE has 


                                       54

<PAGE>

LG&E Energy (cont.):

entered into various fuel supply contracts which expire at various times 
through 2001. Realized gains and losses are recognized in the income 
statement as incurred. At December 31, 1998, 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 the City of Henderson. Some of the excess capacity 
generated by Big Rivers and the City 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, 
1998, 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 prices of electricity. See Discontinuance of 
Merchant Energy Trading and Sales Business under Management's Discussion and 
Analysis and Note 3 of Notes to Financial Statements.

Exchange Rate Sensitivity

The Company has investments in Argentina and Spain which 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 Spanish investment as too small to hedge cost-effectively. A 10% decline 
in the December 31, 1998 exchange rate for the Argentine peso 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

The Company and its subsidiaries use various software, systems and technology 
that may be affected by the "Year 2000 Issue." This concerns the ability of 
electronic processing equipment (including microprocessors embedded in other 
equipment) to properly process the millennium change to the year 2000 and 
related issues. A failure to timely correct any such processing problems 
could result in material operational and financial risks if significant 
systems either cease to function or produce erroneous data. Such risks are 
more fully detailed in the sections that follow, but could include an 
inability to operate its generating plants, disruptions in the operation of 
transmission and distribution systems and an inability to access 
interconnections with the systems of neighboring utilities.

The Company began its project regarding the Year 2000 issue in 1996. The 
Board of Directors has approved the general Year 2000 plan and receives 
regular updates. In addition, monthly reporting procedures have been 
established at senior management levels. Since 1996, a single-purpose Year 
2000 team has been established in the Information Technology (IT) Department. 
This team, which is headed by an officer of the Company, is responsible for 
planning, implementing and documenting the Company's Year 2000 process. The 
team also provides direct and detailed assistance to the Company's 
operational divisions and smaller units, where identified personnel are 
responsible for Year 2000 work and remediation in their specific areas. In 
many cases, the Company also uses the services of third parties, including 
technical consultants, vendor representatives and auditors.

The Company's Year 2000 effort generally follows a three-phase process:

    Phase I - inventory and identify potential Year 2000 issues, determine 
solutions;


                                       55

<PAGE>

LG&E Energy (cont.):

    Phase II - survey vendors regarding their Year 2000 readiness, determine  
   solutions to deal with possible vendor non-compliance, develop work plans  
   regarding Company and vendors non-compliance issues; and

    Phase III - implementation, testing, certification, contingency planning.

The Company has long recognized the complexity of the Year 2000 issue. Work 
has progressed concurrently on (a) replacing or modifying IT systems, 
including mainframes, client-server, PCs and software applications, (b) 
replacing or modifying non-IT systems, including embedded systems such as 
mechanical control units and (c) evaluating the readiness of key third 
parties, including customers, suppliers, business partners and neighboring 
utilities.

State of Readiness

As of January 1999, the Company and its subsidiaries have substantially 
completed the internal inventory, vendor survey and compliance assessment 
portions (Phases I and II) of their Year 2000 plan for critical mainframe and 
PC hardware and software. Remediation efforts (Phase III) in these areas are 
approximately 60% complete. With respect to embedded systems, the Company, 
LG&E and KU have substantially completed their Phase I and Phase II efforts. 
For each entity, Phase III remediation efforts are also in progress for 
embedded systems. Testing has commenced and will continue as remediation 
efforts are implemented and are expected to run until July 1999.

As a general matter, corrective action for major IT systems, including 
customer information, financial and trading systems, are in process or have 
been completed. For smaller or more isolated systems, including embedded and 
plant operational systems, the Company has completed much of the evaluative 
process and is commencing corrective plans. The Company has communicated with 
its key suppliers, customers and business partners regarding their Year 2000 
progress, particularly in the IT software and embedded component areas, to 
determine the areas in which the Company's operations are vulnerable to those 
parties' failure to complete their remediation efforts. The Company is 
currently evaluating and, in certain cases, initiating follow-up actions 
regarding the responses from these parties. The Company regularly attends and 
participates in trade group efforts focusing on Year 2000 issues in the 
energy industry.

Cost of Year 2000 Issues

The Company's system modification costs related to the Year 2000 issue are 
being expensed as incurred, while new system installations are generally 
being capitalized pursuant to generally accepted accounting principles. See 
Note 1 of LG&E Energy' Notes to Financial Statements under Item 8. Through 
December 1998, the Company has incurred approximately $20.2 million in 
capital and operating costs in connection with the Year 2000 issue. Based 
upon studies and projections to date, the Company expects to spend an 
additional $11.9 million to complete its Year 2000 efforts.

It should be noted that these figures include total hardware, software, 
embedded systems and consulting costs. In many cases, these costs include 
system replacements which were already contemplated or which provided 
additional benefits or efficiencies beyond the Year 2000 aspect. 
Additionally, many costs are not incremental costs but constitute 
redeployment of existing IT and other resources. These costs represent 
management's current estimates; however, there can be no assurance that 
actual costs associated with the Company's Year 2000 issues will not be 
higher.


                                       56

<PAGE>

LG&E Energy (cont.):

Risks of Year 2000 Issues

As described above, the Company has made significant progress in the 
implementation of its Year 2000 plan. Based upon the information currently 
known regarding its internal operations and assuming successful and timely 
completion of its remediation plan, the Company does not anticipate material 
business disruptions from its internal systems due to the Year 2000 issue. 
However, the Company may possibly experience limited interruptions to some 
aspects of its activities, whether IT, generation, transmission or 
distribution, operational, administrative functions or otherwise, and the 
Company is considering such potential occurrences in planning for the most 
reasonably likely worst-case scenarios.

Additionally, risk exists regarding the non-compliance of third parties with 
key business or operational importance to the Company. Year 2000 problems 
affecting key customers, interconnected utilities, fuel suppliers and 
transporters, telecommunications providers or financial institutions could 
result in lost power or gas sales, reduced power production or transmission 
capabilities or internal operational or administrative difficulties on the 
part of the Company. The Company is not presently aware of any such 
situations; however, severe occurrences of this type could have material 
adverse impacts upon the business, operating results or financial condition 
of the Company. There can be no assurance that the Company will be able to 
identify and correct all aspects of the Year 2000 problem among these third 
parties that affect it in sufficient time, that it will develop adequate 
contingency plans or that the costs of achieving Year 2000 readiness will not 
be material.

Contingency planning is under way for material areas of Year 2000 risk. This 
effort will address certain areas, including the most reasonably likely 
worst-case scenarios and delays in completion in the Company's remediation 
plans, failure or incomplete remediation results and failure of key third 
parties to be Year 2000 compliant. Contingency plans will include provisions 
for extra staffing, back-up communications, review of unit dispatch and load 
shedding procedures, carrying of additional energy reserves and manual energy 
accounting procedures. Completion of contingency plan formulation is 
scheduled for June 1999.

Forward-Looking Statements

The foregoing discussion regarding the timing, effectiveness, implementation 
and cost of the Company's Year 2000 efforts, contains forward-looking 
statements, which are based on management's best estimates and assumptions. 
These forward-looking statements involve inherent risks and uncertainties, 
and actual results could differ materially from those contemplated by such 
statements. Factors that might cause material differences include, but are 
not limited to, the availability of key Year 2000 personnel, the Company's 
ability to locate and correct all relevant computer codes, the readiness of 
third parties and the Company's ability to respond to unforeseen Year 2000 
complications and other factors described from time to time in the Company's 
reports to the Securities and Exchange Commission, including Exhibit 99.01 to 
the Form 8-K filed October 21, 1998. Such material differences could result 
in, among other things, business disruption, operational problems, financial 
loss, legal liability and similar risks.

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 Statement of Financial Accounting 
Standards No. 71, Accounting for the Effects of Certain Types of Regulation 
(SFAS No. 71). 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 5 of LG&E Energy's Notes to 


                                       57

<PAGE>

LG&E Energy (cont.):

Financial Statements under Item 8.

Since May 1995 and August 1994, respectively, LG&E and KU have implemented an 
environmental cost recovery (ECR) surcharge to recover certain environmental 
compliance costs. Such costs include compliance with the 1990 Clean Air Act, 
as amended, and other environmental regulations, including those applicable 
to coal combustion wastes and related by-products. The ECR mechanism was 
authorized by state statute in 1992 and was first approved by the Kentucky 
Commission in a KU case in July 1994.

The Commission's order approving the surcharge in the KU case and the 
constitutionality of the surcharge were challenged by certain intervenors, 
including the Attorney General of Kentucky, in Franklin Circuit Court. 
Decisions of the Circuit Court and the Kentucky Court of Appeals in July 1995 
and December 1997, respectively, have upheld the constitutionality of the ECR 
statute but differed on a claim of retroactive recovery of certain amounts. 
The Commission ordered that certain surcharge revenues collected by LG&E and 
KU be subject to refund pending final determination of all appeals.

On December 19, 1998, the Kentucky Supreme Court rendered an opinion 
upholding the constitutionality of the surcharge statute. The decision, 
however, reversed the ruling of the Court of Appeals on the retroactivity 
claim, thereby denying recovery of costs associated with pre-1993 
environmental projects through the ECR. The court remanded the case to the 
Commission to determine the proper adjustments to refund amounts collected 
for such pre-1993 environmental projects. The parties to the proceeding have 
notified the Commission that they have reached agreement as to the terms, 
proper adjustments and forward application of the ECR. The settlement 
agreement is subject to Commission approval. The Company recorded a provision 
for rate refund of $26 million in December 1998.

In January 1994, LG&E implemented a Commission-approved demand side 
management (DSM) program that LG&E, the Jefferson County, Kentucky, Attorney 
and representatives of several customer interest groups had filed with the 
Commission. The program included a rate mechanism that (1) provided LG&E 
concurrent recovery of DSM costs, (2) provided an incentive for implementing 
DSM programs and (3) allowed LG&E to recover revenues from lost sales 
associated with the DSM program (decoupling). In June 1998, LG&E and customer 
interest groups requested an end to the decoupling rate mechanism. On June 1, 
1998, LG&E discontinued recording revenues from lost sales due to DSM. 
Accrued decoupling revenues recorded for periods prior to June 1, 1998, will 
continue to be collected through the DSM recovery mechanism. On September 23, 
1998, the Commission accepted LG&E's modified tariff reflecting this proposal 
effective as of June 1, 1998.

In October 1998, LG&E and KU filed separate but parallel applications with 
the Commission for approval of a new method of determining electric rates 
that provides financial incentives for LG&E and KU to further reduce 
customers' rates. The filing was made pursuant to the September 1997 
Commission order approving the merger of LG&E Energy and KU Energy, wherein 
the 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 new ratemaking method, known as 
performance-based ratemaking (PBR), would include 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 provides 
financial penalties and rewards to assure continued high quality service and 
reliability.

The PBR plan proposed by LG&E and KU consists of five components:

    The utilities' fuel adjustment clause mechanism will be withdrawn and
    replaced with a cap that limits 


                                       58

<PAGE>

LG&E Energy (cont.):

    recovery of actual changes in fuel cost to changes in a fuel price index 
    for a five-state region. If the utilities outperform the index, benefits 
    will be shared equally between shareholders and customers. If the 
    utilities' fuel costs exceed the index, the difference will be absorbed 
    by the Company's shareholders.

    Customers will continue to receive the benefits from the post-merger joint
    dispatch of power from LG&E's and KU's generating plants.

    Power plant performance will be measured against the best performance
    achieved between 1991 and 1997. If the performance exceeds this level,
    customers will share in up to $10 million annually of benefits from this
    performance at each of LG&E and KU.

    The utilities will be encouraged to maintain and improve service quality,
    reliability, customer satisfaction and safety, which will be measured
    against six objective benchmarks. The plan provides for annual rewards or
    penalties to the Company of up to $5 million per year at each of LG&E and
    KU.

    The plan provides the utilities with greater flexibility to customize rates
    and services to meet customer needs. Services will continue to be priced
    above marginal cost, and customers will continue to have the option to elect
    standard tariff service.

These proposals are subject to approval by the Commission. Approval 
proceedings commenced in October 1998 and a final decision likely will occur 
in 1999. Several intervenors are participating in the case. Some have 
requested that the Commission reduce base rates before implementing PBR.

On March 8, 1999, the Kentucky Industrial Utility Customers filed a Complaint 
with the Kentucky Commission alleging that LG&E's and KU's electric rates are 
excessive and should be reduced by an amount between $85 and $146 million and 
that the Kentucky Commission establish a proceeding to reduce LG&E's and KU's 
electric rates. LG&E and KU have asked the Kentucky Commission to dismiss the 
Complaint.

The Company is not able to predict the ultimate outcome of these proceedings, 
however, should the Commission mandate significant rate reductions at LG&E 
and/or KU, through the PBR proposal or otherwise, such actions could have a 
material effect on the Company's financial condition and results of 
operations.

Since October 1997, LG&E has implemented a Commission-approved, 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 year of the mechanism ended October 31, 1998, LG&E recorded $3.6 
million for its share of reduced gas costs. The $3.6 million will be billed 
to customers through the gas supply clause beginning February 1, 1999.

In December 1997, the Kentucky Commission opened Administrative Case No. 369 
to consider Commission policy regarding cost allocations, affiliate 
transactions and codes of conduct governing the relationship between 
utilities and their non-utility operations and affiliates. The 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 which result in unfair competition caused by cost 
shifting from the non-utility affiliate to the utility. In September 1998, 
the Commission issued 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 Commission draft proposals. Initial hearings are scheduled 
for the first 


                                       59

<PAGE>

LG&E Energy (cont.):

quarter of 1999. 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.

As of February 12, 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. The 
Company estimates up to an additional $4.8 million could be refundable to 
LG&E and KU retail electric customers through future Kentucky Commission 
orders. See Note 5 of LG&E Energy's Notes to Financial Statements under Item 
8.

Environmental Matters

The Clean Air Act Amendments of 1990 (the Act) imposed stringent new sulfur 
dioxide (SO2) emission limits. LG&E is currently in compliance with the Phase 
II SO2 emission limits required by the year 2000, as it had previously 
installed scrubbers on all of its coal-fired generating units. KU met the 
Phase I requirements of the Act primarily through the installation of a 
scrubber on Unit 1 of the Ghent Generating Station, while WKE utilized fuel 
switching and emission allowance strategies. The Company's combined strategy 
for Phase II 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 nitrogen oxide (NOx) 
emission reduction 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 U.S. Environmental Protection Agency announced its 
final regulation requiring significant additional reductions in NOx emissions 
to mitigate alleged ozone transport to the Northeast. While each state is 
free to allocate its assigned NOx reductions among various emissions sectors 
as it deems appropriate, the regulation may ultimately require utilities to 
reduce their NOx emissions to 0.15 lb./mmBtu (million British thermal 
units)-an 85% reduction from 1990 levels. Under the regulation, each state 
must incorporate the additional NOx reductions in its State Implementation 
Plan (SIP) by September 1999 and affected sources must install control 
measures by May 2003, unless granted extensions. Several states, various 
labor and industry groups, and individual companies have appealed the final 
regulation to the U.S. Court of Appeals for the D.C. Circuit. Management is 
currently unable to determine the outcome or exact impact of this matter 
until such time as the states identify specific emissions reductions in their 
SIPs and the courts rule on the various legal challenges to the final rule. 
However, if the 0.15 lb. target is ultimately imposed, LG&E, KU, 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 and analysis, the Company estimates that it may 
incur capital costs in the range of $300 million to $500 million in the 
aggregate for LG&E, KU and WKE. 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 cost 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.

See Note 18 of LG&E Energy's Notes to Financial Statements under Item 8 for a 
complete discussion of the Company's environmental issues concerning 
manufactured gas plant sites and certain other environmental 


                                       60

<PAGE>

LG&E Energy (cont.):

issues.

Public Utilities Regulatory Policies Act

Proposals also have been introduced in Congress to repeal all or portions of 
the Public Utility Regulatory Policies Act (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 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 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 and gas distribution projects, as 
described under 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. 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 
are 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 


                                       61

<PAGE>

LG&E Energy (cont.):

Kentucky General Assembly have 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. The purpose of the task force is to make 
recommendations to the Kentucky General Assembly for possible legislative 
action during its 2000 session.

However, 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:

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 1998, 1997, and 1996 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 
Corp's report on Form 8-K filed October 21, 1998.

MERGER

Effective May 4, 1998, following the receipt of all required state and 
federal regulatory approvals, LG&E Energy Corp. (LG&E Energy) and KU Energy 
Corporation (KU Energy) merged, with LG&E Energy as the surviving 
corporation. The outstanding preferred stock of Louisville Gas and Electric 
Company (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 decreased $35.2 million for 1998, as compared to 1997, 
primarily due to non-recurring charges for merger-related expenses and the 
Environmental Cost Recovery 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.

Net income increased $5.3 million for 1997 over 1996. This improvement was 
mainly due to increased sales of electricity to wholesale customers, a lower 
level of maintenance expenses and increased investment and interest income. 
These items were partially offset by reduced gas sales volumes due to warmer 
winter weather and a write-off of certain expenses deferred in prior periods.


                                       62

<PAGE>

LG&E (cont.):

Revenues

A comparison of operating revenues for the years 1998 and 1997, excluding the 
$4.5 million provision recorded for refund of environmental costs previously 
recovered from customers (ECR refund), 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                                                    1998          1997             1998        1997
         -----                                                    ----          ----             ----        ----
<S>                                                          <C>           <C>             <C>           <C>
         Sales to ultimate consumers:
           Fuel and gas supply adjustments, etc.             $   3,750      $ (2,155)       $  (4,393)   $ 27,192
           Merger surcredit                                     (3,466)           --               --          --
           Demand side management/decoupling                    (6,299)        8,041             (369)      4,348
           Environmental cost recovery surcharge                  (260)          448               --          --
           Variation in sales volumes                           27,051        (4,810)         (42,418)    (14,891)
                                                             ---------     ---------        ---------    --------
              Total retail sales                                20,776         1,524          (47,180)     16,649
         Wholesale sales                                        28,398         3,088            8,720          --
         Gas transportation-net                                     --            --              (71)        147
         Other                                                    (695)        3,224             (935)       (204)
                                                             ---------     ---------        ---------    --------
           Total                                              $ 48,479     $   7,836        $ (39,466)   $ 16,592
                                                             ---------     ---------        ---------    --------
                                                             ---------     ---------        ---------    --------
</TABLE>

Electric retail sales increased primarily due to the warmer weather 
experienced 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 Kentucky Utilities (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.

Electric revenues increased in 1997 due to a slightly higher level of 
wholesale sales and other revenues. Gas revenues increased primarily as a 
result of higher gas supply costs billed to customers through the gas supply 
clause, partially offset by decreased gas sales due mainly to warmer weather.

Expenses

Fuel for electric generation and gas supply expenses comprise a large 
component of LG&E's total operating costs. LG&E's electric and gas rates 
contain a fuel adjustment clause (FAC) and a gas supply clause, respectively, 
whereby increases or decreases in the cost of fuel and gas supply are 
reflected in LG&E's rates, subject to approval by the Public Service 
Commission of Kentucky (Kentucky Commission or Commission).

Fuel for electric generation increased $5.2 million (3.5%) in 1998 because of 
higher cost of coal burned ($6.6 million), partially offset by a decrease in 
generation ($1.4 million). Fuel expenses incurred in 1997 were approximately 
the same as in 1996. The average delivered cost per ton of coal purchased was 
$22.38 in 1998, $21.66 in 1997, and $21.73 in 1996.

Power purchased expense increased $32.9 million in 1998 to support the 
increase in electric sales and increased purchases from KU of $16 million as 
a result of economic dispatch following the merger of the two companies


                                       63

<PAGE>

LG&E (cont.):

in May 1998. Power purchased expense increased $.6 million (4%) in 1997 due 
to an increase in the amount of purchased power needed to support native load 
requirements.

Gas supply expenses decreased $33 million (21%) in 1998 primarily due to a 
decrease in the volume of gas delivered to the distribution system. Gas 
supply expenses for 1997 increased $18.4 million (13%) because of the higher 
cost of net gas supply ($29.3 million), partially offset by a decrease in the 
volume of gas delivered to the distribution system ($10.9 million). The 
average unit cost per thousand cubic feet (Mcf) of purchased gas was $3.05 in 
1998 and $3.46 in each of 1997 and 1996.

Other operation expenses increased $12.8 million (8.5%) over 1997 because of 
increased costs to operate the electric generating plants ($6.6 million), 
increased administrative costs ($2.2 million), and amortization of deferred 
merger costs ($1.8 million). Other operation expenses increased $7.4 million 
(5%) in 1997 primarily because of increased costs to operate the electric 
generating plants ($5.1 million) and a write-off of certain previously 
deferred items ($3.2 million). Items written off include expenses associated 
with the hydro-electric plant and a management audit fee. Even though LG&E 
believes it could have reasonably expected to recover these costs in future 
rate proceedings, it decided not to seek recovery and expensed these costs 
because of increasing competitive pressures in the industry.

Maintenance expenses increased $5.2 million (11%) in 1998 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). Maintenance expenses decreased $7.2 million (13%) in 
1997 from 1996 due to decreased repairs at the electric generating plants 
resulting from fewer scheduled outages ($5 million) and a lower level of 
storm damage repairs ($1.8 million).

Depreciation and amortization for 1998 were approximately the same as in 
1997. Depreciation and amortization increased $4 million (4.5%) in 1997 
because of additional utility plant in service. In addition, 1997 reflects 
the accelerated write-off of losses on early retirements of facilities.

Variations in income tax expenses are largely attributable to changes in 
pre-tax income.

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.

Other income for 1997 increased by $3.4 million primarily because of the 
recording in 1997 of interest income due to a favorable tax settlement and 
the sale of stock options which LG&E had acquired in a commercial 
transaction. See Note 9 of LG&E's Notes to Financial Statements under Item 8.

Interest charges for 1998 decreased $2.9 million (7%) due to the retirement 
of LG&E's 6.75% Series First Mortgage Bonds and lower interest rates. 
Interest charges for 1997 decreased $1.1 million (3%) due to favorable 
refinancing activities in 1996. The embedded cost of long-term debt was 5.57% 
at December 31, 1998, and 5.68% at December 31, 1997. See Note 10 of LG&E's 
Notes to Financial Statements under Item 8.

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

                                       64

<PAGE>

LG&E (cont.):

LIQUIDITY AND CAPITAL RESOURCES

LG&E's need for capital funds is largely related to the construction of plant
and equipment necessary to meet the needs of electric and gas utility customers
and protection of the environment.

Construction Expenditures

New construction expenditures for 1998 were $138 million compared with $111 
million for 1997 and $108 million for 1996.

Past Financing Activities

During 1998, 1997 and 1996, LG&E's primary source of capital was internally 
generated funds from operating cash flows. Internally generated funds 
provided financing for 100% of LG&E's construction expenditures for 1998, 
1997, and 1996.

LG&E's combined cash and marketable securities balance decreased by $20 
million in 1998 and increased $9 million in 1997. The decrease for 1998 
reflects retirement of a $20 million first mortgage bond. In 1997, the 
increase reflects cash flows from operations, partially offset by 
construction expenditures and dividends paid.

Variations in accounts receivable and accounts payable are not generally 
significant indicators of LG&E's liquidity, as such variations are primarily 
attributable to fluctuations in weather in LG&E's service territory, which 
has a direct affect on sales of electricity and natural gas.

On June 1, 1998, LG&E's First Mortgage Bonds, 6.75% Series of $20 million 
matured and were retired by LG&E. The bonds were redeemed with available 
funds.

In November 1997, LG&E issued $35 million of Jefferson County, Kentucky and 
$35 million of Trimble County, Kentucky, Pollution Control Bonds, Flexible 
Rate Series, due November 1, 2027. The interest rates for these bonds were 
3.09% and 3.39%, respectively, at December 31, 1998. The proceeds from these 
bonds were used to redeem the outstanding 7.75% Series of Jefferson County, 
Kentucky and Trimble County, Kentucky, Pollution Control Bonds due February 
1, 2019.

Future Capital Requirements

Future financing 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 estimates construction expenditures will total $384 
million for 1999 and 2000. This estimate includes capital expenditures 
associated with installation of low nitrogen oxide burner systems as 
described in "Environmental Matters."

In July 1998, following LG&E Energy's decision to discontinue its merchant 
energy trading and sales business, Standard & Poor's (S&P) downgraded the 
credit ratings of LG&E Energy and its subsidiaries while Moody's and Duff & 
Phelps (D&P) kept LG&E Energy and its subsidiaries at their prior ratings.

                                       65

<PAGE>

LG&E (cont.):

LG&E's current debt ratings are:

<TABLE>
<CAPTION>
                               Moody's        S&P          D&P
                               -------        ---          ---
<S>                           <C>            <C>          <C>

First mortgage bonds            Aa2            A+          AA
Unsecured debt                  Aa3            A           AA-
Preferred stock                 aa3            A-          AA-

</TABLE>

These ratings reflect the views of Moody's, S&P and D&P. An explanation of 
the significance of these ratings may be obtained from them. 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.

Future Sources of Financing

Internally generated funds from operations and new debt are expected to fund 
substantially all anticipated construction expenditures in 1999 and 2000.

At December 31, 1998, LG&E had unused lines of credit of $200 million for 
which it pays commitment fees. These credit facilities provide for short-term 
borrowing and are scheduled to expire in 2001. Management expects to 
renegotiate them when they expire.

To the extent permanent financings are needed in 1999 and 2000, LG&E expects 
that it will have ready access to the securities markets to raise needed 
funds.

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 financial instruments. Derivative 
positions are monitored using techniques that include market value and 
sensitivity analysis.

Interest Rate Sensitivity

LG&E has certain variable rate Pollution Control Bonds outstanding. At 
December 31, 1998, the potential change in interest expense associated with a 
1% change in base interest rates of LG&E's unswapped debt is estimated at $.8 
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.

LG&E has entered into swaps to reduce the impact of interest rate changes on 
its Pollution Control Bonds. The swap agreements involve the exchange of 
floating-rate interest payments for fixed interest payments over the life of 
the agreements. As of December 31, 1998, 67% 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 $3.5 
million as of December 31, 1998. 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 LG&E's of Notes to Financial Statements under 
Item 8.

In April 1998, LG&E entered into a forward starting swap agreement. The 
forward swap involves the exchange

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LG&E (cont.):

of floating-rate interest payments for fixed interest payments over the life 
of the agreement. The forward swap was entered into to hedge LG&E's exposure 
to interest rates for the anticipated call of its Trimble County, Kentucky, 
Pollution Control Bonds, 7 5/8% Series, due November 1, 2020. The potential 
loss in fair value from this position resulting from a hypothetical 10% 
change in the yield curve is estimated at $7.5 million as of December 31, 
1998. See Note 4 of LG&E's Notes to Financial Statements under Item 8.

Commodity Price Sensitivity

LG&E has limited exposure to market volatility in prices of fuel or 
electricity, as long as cost-based regulations exist. To mitigate residual 
risks relative to the movements in fuel or in electricity prices, LG&E 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, 
1998, exposure from these activities was not material to the financial 
statements of LG&E.

Year 2000 Issue

LG&E uses various software, systems and technology that may be affected by 
the "Year 2000 Issue." This concerns the ability of electronic processing 
equipment (including microprocessors embedded in other equipment) to properly 
process the millennium change to the year 2000 and related issues. A failure 
to timely correct any such processing problems could result in material 
operational and financial risks if significant systems either cease to 
function or produce erroneous data. Such risks are more fully described in 
the sections that follow, but could include an inability to operate its 
generating plants, disruptions in the operation of transmission and 
distribution systems and an inability to access interconnections with the 
systems of neighboring utilities.

LG&E began its project regarding the Year 2000 issue in 1996. The Board of 
Directors has approved the general Year 2000 plan and receives regular 
updates. In addition, monthly reporting procedures have been established at 
senior management levels. Since 1996, a single-purpose Year 2000 team has 
been established in the Information Technology (IT) Department. This team, 
which is headed by an officer of LG&E, is responsible for planning, 
implementing, and documenting LG&E's Year 2000 process. The team also 
provides direct and detailed assistance to LG&E's operational divisions and 
smaller units, where identified personnel are responsible for Year 2000 work 
and remediation in their specific areas. In many cases, LG&E also uses the 
services of third parties, including technical consultants, vendor 
representatives and auditors.

LG&E's Year 2000 effort generally follows a three-phase process:

     Phase I - inventory and identify potential Year 2000 issues, determine
     solutions;

     Phase II - survey vendors regarding their Year 2000 readiness, determine
     solutions to deal with possible vendor non-compliance, develop work plans
     regarding LG&E and vendors non-compliance issues; and

     Phase III - implementation, testing, certification, contingency planning.

LG&E has long recognized the complexity of the Year 2000 issue. Work has 
progressed concurrently on (a) replacing or modifying IT systems, including 
mainframes, client-server, PCs and software applications, (b) replacing or 
modifying non-IT systems, including embedded systems such as mechanical 
control units, (c) evaluating the readiness of key third parties, including 
customers, suppliers, business partners and neighboring utilities, and (d) 
contingency planning.

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<PAGE>

LG&E (cont.):

State of Readiness

As of January 1999, LG&E has substantially completed the internal inventory, 
vendor survey and compliance assessment portions (Phases I and II) of its 
Year 2000 plan for critical mainframe and PC hardware and software, as well 
as embedded systems. Remediation efforts (Phase III) in these areas are 
approximately 65% complete. Phase III remediation efforts are also in 
progress for embedded systems. Testing and contingency planning has commenced 
and will continue as remediation efforts are implemented and are expected to 
run until July 1999.

As a general matter, corrective action for major IT systems, including 
customer information and financial systems, and smaller or more isolated 
systems, including embedded and plant operational systems, are in process or 
have been completed. LG&E has communicated with its key suppliers, customers 
and business partners regarding their Year 2000 progress, particularly in the 
IT software and embedded component areas, to determine the areas in which 
LG&E's operations are vulnerable to those parties' failure to complete their 
remediation efforts. LG&E is currently evaluating and, in certain cases, 
initiating follow-up actions regarding the responses from these parties. LG&E 
regularly attends and participates in trade group efforts focusing on Year 
2000 issues in the energy industry.

Costs of Year 2000 Issues

LG&E's system modification costs related to the Year 2000 issue are being 
expensed as incurred, while new system installations are generally being 
capitalized pursuant to generally accepted accounting principles. See Note 1 
of LG&E's Notes to Financial Statements under Item 8. Through December 1998, 
LG&E has incurred approximately $16 million in capital and operating costs in 
connection with the Year 2000 issue. Based upon studies and projections to 
date, LG&E expects to spend an additional $4.6 million to complete its Year 
2000 efforts.

It should be noted that these figures include total hardware, software, 
embedded systems and consulting costs. In many cases, these costs include 
system replacements which were already contemplated or which provided 
additional benefits or efficiencies beyond the Year 2000 aspect. 
Additionally, many costs are not incremental costs, but constitute 
redeployment of existing IT and other resources. These costs represent 
management's current estimates; however, there can be no assurance that 
actual costs associated with LG&E's Year 2000 issues will not be higher.

Risks of Year 2000 Issues

As described above, LG&E has made significant progress in the implementation 
of its Year 2000 plan. Based upon the information currently known regarding 
its internal operations and assuming successful and timely completion of its 
remediation plan, LG&E does not anticipate material business disruptions from 
its internal systems due to the Year 2000 issue. However, LG&E may possibly 
experience limited interruptions to some aspects of its activities, whether 
IT, generation, transmission or distribution, operational, administrative 
functions or otherwise, and LG&E is considering such potential occurrences in 
planning for the most reasonably likely worst-case scenarios.

Additionally, risk exists regarding the non-compliance of third parties with 
key business or operational importance to LG&E. Year 2000 problems affecting 
key customers, interconnected utilities, fuel suppliers and transporters, 
telecommunications providers or financial institutions could result in lost 
power or gas sales, reduced power production or transmission capabilities or 
internal operational or administrative difficulties on

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<PAGE>

LG&E (cont.):

the part of LG&E. LG&E is not presently aware of any such situations; 
however, severe occurrences of this type could have material adverse impacts 
upon the business, operating results or financial condition of LG&E. There 
can be no assurance that LG&E will be able to identify and correct all 
aspects of the Year 2000 problem among these third parties that affect it in 
sufficient time, that it will develop adequate contingency plans or that the 
costs of achieving Year 2000 readiness will not be material.

Contingency planning is under way for material areas of Year 2000 risk. This 
effort will address certain areas, including the most reasonably likely 
worst-case scenarios and delays in completion in LG&E's remediation plans, 
failure or incomplete remediation results and failure of key third parties to 
be Year 2000 compliant. Contingency plans will include provisions for extra 
staffing, back-up communications, review of unit dispatch and load shedding 
procedures, carrying of additional energy reserves and manual energy 
accounting procedures. Completion of contingency plan formation is scheduled 
for June 1999.

Forward-Looking Statements

The foregoing discussion regarding the timing, effectiveness, implementation 
and cost of LG&E's Year 2000 efforts, contains forward-looking statements, 
which are based on management's best estimates and assumptions. These 
forward-looking statements involve inherent risks and uncertainties, and 
actual results could differ materially from those contemplated by such 
statements. Factors that might cause material differences include, but are 
not limited to, the availability of key Year 2000 personnel, LG&E's ability 
to locate and correct all relevant computer codes, the readiness of third 
parties and LG&E's ability to respond to unforeseen Year 2000 complications 
and other factors described from time to time in LG&E's reports to the 
Securities and Exchange Commission, and Exhibit 99.01 to LG&E Energy Corp.'s 
Form 8-K filed October 21, 1998. Such material differences could result in, 
among other things, business disruption, operational problems, financial 
loss, legal liability and similar risks.

Rates and Regulation

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

Since May 1995, LG&E implemented an environmental cost recovery (ECR) 
surcharge to recover certain environmental compliance costs. Such costs 
include compliance with the 1990 Clean Air Act, as amended, and other 
environmental regulations, including those applicable to coal combustion 
wastes and related by-products. The ECR mechanism was authorized by state 
statute in 1992 and was first approved by the Kentucky Commission in a KU 
case in July 1994.

The Commission's order approving the surcharge in the KU case and the 
constitutionality of the surcharge were challenged by certain intervenors, 
including the Attorney General of Kentucky, in Franklin Circuit Court. 
Decisions of the Circuit Court and the Kentucky Court of Appeals in July 1995 
and December 1997, respectively, have upheld the constitutionality of the ECR 
statute but differed on a claim of retroactive recovery of certain amounts. 
The Commission ordered that certain surcharge revenues collected by LG&E be 
subject to refund pending final determination of all appeals.

On December 19, 1998, the Kentucky Supreme Court rendered an opinion upholding
the constitutionality of the

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LG&E (cont.):

surcharge statute. The decision, however, reversed the ruling of the Court of 
Appeals on the retroactivity claim, thereby denying recovery of costs 
associated with pre-1993 environmental projects through the ECR. The court 
remanded the case to the Commission to determine the proper adjustments to 
refund amounts collected for such pre-1993 environmental projects. The 
parties to the proceeding have notified the Commission that they have reached 
agreement as to the terms, proper adjustments and forward application of the 
ECR. The settlement agreement is subject to Commission approval. LG&E 
recorded a provision for rate refund of $4.5 million in December 1998.

In January 1994, LG&E implemented a Commission-approved demand side 
management (DSM) program that LG&E, the Jefferson County Attorney, and 
representatives of several customer interest groups had filed with the 
Commission. The program included a rate mechanism that (1) provided LG&E 
concurrent recovery of DSM costs, (2) provided an incentive for implementing 
DSM programs and (3) allowed LG&E to recover revenues from lost sales 
associated with the DSM program (decoupling). In June 1998, LG&E and customer 
interest groups requested an end to the decoupling rate mechanism. On June 1, 
1998, LG&E discontinued recording revenues from lost sales due to DSM. 
Accrued decoupling revenues recorded for periods prior to June 1, 1998, will 
continue to be collected through the DSM recovery mechanism. On September 23, 
1998, the Commission accepted LG&E's modified tariff reflecting this proposal 
effective as of June 1, 1998.

In October 1998, LG&E and KU filed separate, but parallel applications with 
the Commission for approval of a new method of determining electric rates 
that provides financial incentives for LG&E and KU to further reduce 
customers' rates. The filing was made pursuant to the September 1997 
Commission order approving the merger of LG&E Energy and KU Energy, wherein 
the 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 new ratemaking method, known as 
performance-based ratemaking (PBR), would include 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 provides 
financial penalties and rewards to assure continued high quality service and 
reliability.

The PBR plan proposed by LG&E and KU consists of five components:

     The utilities' fuel adjustment clause mechanism will be withdrawn and
     replaced with a cap that limits recovery of actual changes in fuel cost to
     changes in a fuel price index for a five-state region. If the utilities
     outperform the index, benefits will be shared equally between shareholders
     and customers. If the utilities' fuel costs exceed the index, the
     difference will be absorbed by LG&E Energy's shareholders.

     Customers will continue to receive the benefits from the post-merger joint
     dispatch of power from LG&E's and KU's generating plants.

     Power plant performance will be measured against the best performance
     achieved between 1991 and 1997. If the performance exceeds this level,
     customers will share equally with LG&E Energy's shareholders in up to $10
     million annually of benefits from this performance at each of LG&E and KU.

     The utilities will be encouraged to maintain and improve service quality,
     reliability, customer satisfaction and safety, which will be measured
     against six objective benchmarks. The plan provides for annual rewards or
     penalties to LG&E Energy of up to $5 million per year at each of LG&E and
     KU.

     The plan provides the utilities with greater flexibility to customize rates
     and services to meet customer needs. Services will continue to be priced
     above marginal cost and customers will continue to have the

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<PAGE>

LG&E (cont.):

     option to elect standard tariff service.

These proposals are subject to approval by the Commission. Approval 
proceedings commenced in October 1998 and a final decision likely will occur 
in 1999. Several intervenors are participating in the case. Some have 
requested that the Commission reduce base rates before implementing PBR.

On March 8, 1999, the Kentucky Industrial Utility Customers filed a Complaint 
with the Kentucky Commission alleging that LG&E's electric rates are 
excessive and should be reduced by an amount between $43 and $90 million and 
that the Kentucky Commission establish a proceeding to reduce LG&E's electric 
rates. LG&E has asked the Kentucky Commission to dismiss the Complaint.

LG&E is not able to predict the ultimate outcome of these proceedings, 
however, should the Commission mandate significant rate reductions at LG&E, 
through the PBR proposal or otherwise, such actions could have a material 
effect on LG&E's financial condition and results of operations.

Since October 1997, LG&E has implemented a Commission-approved, 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 year of the mechanism ended October 31, 1998, LG&E recorded $3.6 
million for its share of reduced gas costs. The $3.6 million will be billed 
to customers through the gas supply clause beginning February 1, 1999.

In December 1997, the Kentucky Commission opened Administrative Case No. 369 
to consider Commission policy regarding cost allocations, affiliate 
transactions and codes of conduct governing the relationship between 
utilities and their non-utility operations and affiliates. The 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 which result in unfair competition caused by cost 
shifting from the non-utility affiliate to the utility. In September 1998, 
the Commission issued 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 Commission draft proposals. Initial hearings are scheduled 
for the first quarter of 1999. 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.

As of February 12, 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. LG&E 
estimates up to an additional $1.3 million could be refundable to retail 
electric customers for the period from May 1998 through December 1998. See 
Note 3 of LG&E's Notes to Financial Statements under Item 8.

LG&E filed a Petition for Rehearing of all of the orders and a motion to 
suspend the refund obligation. On February 25, 1999, the Commission suspended 
the obligation to refund pending further direction by the Commission. It also 
advised that LG&E may have to pay interest on the refund amounts for the 
suspension period. On March 11, 1999 the Commission denied LG&E's Petition 
for Rehearing for the period November 1994 through October 1996 and directed 
LG&E to reduce future fuel expense by $1.9 million in the first billing month 
after the Order. The Company is considering the filing of an Appeal with the 
Franklin Circuit Court. In a separate series of Orders on March 11, 1999, the 
PSC granted LG&E's Petition for Rehearing for the period November 1996 
through April 1998 and established a procedural schedule for LG&E and other 
parties to

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<PAGE>

LG&E (cont.):

submit evidence and for a hearing before the Commission. In the same Orders 
the PSC granted the Petition for Rehearing of the Kentucky Industrial Utility 
Customers to determine if interest should be paid on any fuel refunds for 
this latter period.

Environmental Matters

The Clean Air Act Amendments of 1990 (the Act) imposed stringent new sulfur 
dioxide (SO2) emission limits. LG&E is currently in compliance with the Phase 
II SO2 emission limits required by the year 2000, as it had previously 
installed scrubbers on all of its coal-fired generating units. LG&E met the 
nitrogen oxide (NOx) emission reduction 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 U.S. Environmental Protection Agency announced its 
final regulation requiring significant additional reductions in NOx emissions 
to mitigate alleged ozone transport to the Northeast. While each state is 
free to allocate its assigned NOx reductions among various emissions sectors 
as it deems appropriate, the regulation may ultimately require utilities to 
reduce their NOx emissions to 0.15 lb./mmBtu (million British thermal units) 
- an 85% reduction from 1990 levels. Under the regulation, each state must 
incorporate the additional NOx reductions in its State Implementation Plan 
(SIP) by September 1999 and affected sources must install control measures by 
May 2003, unless granted extensions. Several states, various labor and 
industry groups, and individual companies have appealed the final regulation 
to the U.S. Court of Appeals for the D.C. Circuit. Management is currently 
unable to determine the outcome or exact impact of this matter until such 
time as the states identify specific emissions reductions in their SIP and 
the courts rule on the various legal challenges to the final rule. 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 and analysis, LG&E estimates that it may incur 
capital costs in the range of $100 million to $200 million. 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 cost recovery from customers under 
its environmental surcharge mechanism and believes that a significant portion 
of such costs could be recovered. However, Kentucky Commission approval is 
necessary and there can be no guarantee of such recovery.

See Note 12 of LG&E's Notes to Financial Statements under Item 8 for a 
complete discussion of LG&E's environmental issues concerning manufactured 
gas plant sites and certain other 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 
regulated and non-utility energy services businesses, including support for 
performance-based ratemaking structures; aggressive cost reduction 
activities;

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LG&E (cont.):

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 that 
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 
are 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 have 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. The purpose of the task force is to make 
recommendations to the Kentucky General Assembly for possible legislative 
action during its 2000 session.

However, at the time of this report, neither the Kentucky General Assembly 
nor the Kentucky Commission has adopted or approved a plan or timetable for 
retail electric industry competition in Kentucky. The nature or timing of the 
ultimate legislative or regulatory actions regarding industry restructuring 
and their impact on LG&E, which may be significant, cannot be currently 
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 1998, 1997, and 1996 and should be read in 
connection with KU's 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 Kentucky Utilities Company's reports to the Securities and 
Exchange Commission, including Exhibit No. 99.01 to LG&E Energy Corp.'s 
report on Form 8-K filed October 21, 1998.

Merger

Effective May 4, 1998, following the receipt of all required state and 
federal regulatory approvals, LG&E Energy Corp. (LG&E Energy) and KU Energy 
Corporation (KU Energy) merged, with LG&E Energy as the surviving 
corporation. The outstanding preferred stock of Kentucky Utilities Company 
(KU), which was 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.

                                       73

<PAGE>

KU (cont.):


RESULTS OF OPERATIONS

Net Income

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. Net income for 1997 as 
compared to 1996 was flat.

Revenues

A comparison of KU's revenues for the years 1998 and 1997, excluding the 
provision recorded for refund of environmental costs previously recovered 
(ECR refund) from customers (which reduced electric revenues by $21.5 
million), 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
    CAUSE                                       1998             1997
    -----                                       ----             ----
<S>                                         <C>               <C> 
    Sales to ultimate consumers:
      Fuel clause adjustments, etc.          $  1,158         $ (5,414)
      Merger surcredit                         (4,035)               -
      Environmental cost recovery surcharge      (547)             554
      Variation in sales volumes               25,841           11,301
                                             --------         --------
         Total retail sales                    22,417            6,441
    Sales for resale                           91,788           (1,878)
    Other                                         972              163
                                             --------         --------
           Total                             $115,177         $  4,726
                                             --------         --------
                                             --------         --------

</TABLE>

Retail sales increased due to increases in residential and commercial sales 
primarily attributable to warmer weather experienced in the second and third 
quarters of 1998 as compared to 1997. The increase in sales for resale 
(7,224,156 megawatt-hours versus 3,397,423 megawatt-hours) was primarily due 
to a more aggressive marketing efforts, increase 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.

Total sales for 1997 were flat as compared to 1996. Residential sales 
decreased 2% for the year due to milder weather in 1997 compared to 1996. 
Industrial sales increased 9% reflecting continued growth in the 
manufacturing sector of the service area economy. Sales for resale, which 
include wholesale and opportunity sales, declined 9% in 1997; however, 
revenues did not decline by a comparable amount due to higher market prices 
per megawatt-hour on opportunity sales.

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.

                                        74
<PAGE>

KU (cont.):

Expenses

Fuel for electric generation comprises a large component of KU's total 
operating costs. KU's electric rates contain a fuel adjustment clause (FAC), 
whereby increases or decreases in the cost of fuel are reflected in KU's 
rates, subject to approval by the Public Service Commission of Kentucky 
(Kentucky Commission or Commission), Virginia State Corporation Commission 
(Virginia Commission), and the Federal Energy Regulatory Commission (FERC).

Fuel for electric generation increased $27.4 million (15%) in 1998 primarily 
due to a 12% increase in MBTU (Million British Thermal Units) used. Fuel 
expenses increased by $30.3 million (22%) in 1997 primarily due to a 18% 
increase in MBTU (Million British Thermal Units) used. The increased 
consumption was primarily caused by the previously mentioned increase in 
kilowatt-hour sales. KU's average delivered cost per ton of coal purchased 
was $26.97 in 1998 , $27.97 in 1997, and $27.54 in 1996.

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. Power purchased expense increased $10.1 million (16%) in 1997 due to a 
19% increase in kWH purchases associated with increased availability of 
surplus power on favorable pricing terms and to a one-time reduction in 
demand costs in 1996 of about $4 million under a contract with a neighboring 
utility.

Depreciation and amortization increased $2.5 million (1.5%) in 1998 because 
of additional utility plant in service. Depreciation and amortization 
increased in 1997 primarily because of additional plant in service at KU.

KU's embedded cost of long-term debt was 6.99% at December 31, 1998, and 
6.98% at December 31, 1997.  See Note 10 of KU's Notes to Financial 
Statements under Item 8.

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).

Variations in income tax expense are largely attributable to changes in 
pre-tax income.

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's need for capital funds is largely related to the construction of plant 
and equipment necessary to meet the needs of electric utility customers and 
protection of the environment.

Construction Expenditures

New construction expenditures for 1998 were $92 million compared with $94 
million for 1997 and $106.5 million for 1996.

                                       75

<PAGE>

KU (cont.):

Past Financing Activities

During 1998, 1997, and 1996, KU's primary source of capital was internally 
generated funds from operating cash flows and debt financing. Internally 
generated funds provided financing for 100% of KU's construction expenditures 
for 1998, 1997, and 1996.

Variations in accounts receivable and accounts payable are not generally 
significant indicators of KU's liquidity, as such variations are primarily 
attributable to fluctuations in weather in KU's service territory, which has 
a direct affect on sales of electricity.

KU has no short-term borrowings outstanding at December 31, 1998. At the end 
of 1997, KU's short-term borrowings were $34 million compared to $54 million 
at December 31, 1996. KU has used short-term borrowings to temporarily 
finance ongoing construction expenditures and general corporate requirements. 
The decrease in 1997 from 1996 was due primarily to KU's cash provided by 
operations exceeding cash required for investing and financing activities 
(exclusive of short-term borrowings).

Future Capital Requirements

Future financing requirements may be affected in varying degrees by factors 
such as load growth, changes in construction expenditure levels, rate actions 
allowed by regulatory agencies, new legislation, market entry of competing 
electric power generators, changes in environmental regulations and other 
regulatory requirements. KU estimates construction expenditures will total 
$341 million for 1999 and 2000. In addition, KU's capital requirements for 
2000 include $61.5 million for scheduled debt retirements.

In July 1998, following LG&E Energy's decision to discontinue its merchant 
energy trading and sales business, Standard & Poor's (S&P) downgraded the 
credit ratings of LG&E Energy and its subsidiaries while Moody's and Duff & 
Phelps (D&P) kept LG&E Energy and its subsidiaries at their prior ratings.

KU's current debt ratings are:

<TABLE>
<CAPTION>
                               Moody's        S&P          D&P
                               -------        ---          ---
<S>                           <C>            <C>          <C>

First mortgage bonds            Aa2            A+          AA
Preferred stock                 Aa3            A-          AA-
Commercial paper                P-1            A-1         D-1+

</TABLE>

These ratings reflect the views of Moody's, S&P and D&P. An explanation of 
the significance of these ratings may be obtained from them. 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.

Future Sources of Financing

Internally generated funds from operations and new debt are expected to fund 
substantially all anticipated construction expenditures in 1999 and 2000.

At December 31, 1998, KU had unused lines of credit of $60 million for which 
it pays commitment fees. The KU credit facilities provide for short-term 
borrowing and support of commercial-paper borrowings. These credit facilities 
are scheduled to expire in 1999. Management expects to renegotiate them when 
they expire.

                                       76
<PAGE>

KU (cont.):

To the extent permanent financings are needed in 1999 and 2000, KU expects 
that it will have ready access to the securities markets to raise needed 
funds.

Interest Rate Sensitivity

KU has variable rate debt obligations outstanding. At December 31, 1998, the 
potential change in interest expense associated with a 1% change in base 
interest rates is immaterial.

Commodity Price Sensitivity

KU has limited exposure to market volatility in prices of fuel or 
electricity, as long as cost-based regulations exist. To mitigate residual 
risks relative to the movements in fuel or electricity prices, KU 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, 
1998, exposure from these activities was not material to the financial 
statements.

Year 2000 Issue

KU uses various software, systems and technology that are affected by the 
"Year 2000 Issue." This issue concerns the ability of electronic processing 
equipment (including microprocessors embedded in other equipment) to properly 
process the millennium change to 2000 and related issues. A failure to timely 
correct any such processing problems could result in material operational and 
financial risks if significant systems either cease to function or produce 
erroneous data. Such risks are described in more detail following, but could 
include an inability to operate its generating plants, disruptions in the 
operation of transmission and distribution systems, and an inability to 
access interconnections with the systems of neighboring utilities.

KU began its project regarding the Year 2000 issue in 1996. The Board of 
Directors has approved the general Year 2000 plan and receives regular 
updates. In addition, monthly reporting procedures have been established at 
senior management levels. Since 1996, a single-purpose Year 2000 team has 
been established in the Information Technology (IT) Department. This team, 
which is headed by an officer, is responsible for planning, implementing, and 
documenting KU's Year 2000 process. The team also provides direct and 
detailed assistance to KU's operational divisions and smaller units, where 
identified personnel are responsible for Year 2000 work and remediation in 
their specific areas. In many cases, KU also uses the services of third 
parties, including technical consultants, vendor representatives and auditors.

KU's Year 2000 effort generally follows a three phase process:

     Phase I - inventory and identify potential Year 2000 issues, determine
     solutions;

     Phase II - survey vendors regarding their Year 2000 readiness, determine
     solutions to deal with possible vendor non-compliance, develop work plans
     regarding KU and vendors non-compliance issues; and

     Phase III - implementation, testing, certification, contingency planning.

KU has long recognized the complexity of the Year 2000 issue. Work has 
progressed concurrently on (a) replacing or modifying IT systems, including 
mainframes, PC's and software applications, (b) replacing or modifying non-IT 
systems, including embedded systems such as mechanical control units, (c) 
evaluating the readiness of key third parties, including customers, 
suppliers, business partners and neighboring utilities, and (d)

                                       77

<PAGE>

KU (cont.):

contingency planning.

State of Readiness

As of January 1999, KU has substantially completed the internal inventory, 
vendor survey, and compliance assessment portions (Phases I and II) of their 
Year 2000 plan for critical mainframe and PC hardware and software, as well 
as embedded systems. Remediation efforts (Phase III) in these areas are 
approximately 55% complete. Testing and contingency planning has commenced 
and will continue as remediation efforts are implemented and are expected to 
run until July 1999.

As a general matter, corrective action for major IT systems, including 
customer information, financial and trading systems, and smaller or more 
isolated systems, including embedded and plant operational systems, are in 
process or have been completed. KU has communicated with its key suppliers, 
customers and business partners regarding their Year 2000 progress, 
particularly in the IT software and embedded component areas, to determine 
the areas in which KU's operations are vulnerable to those parties failure to 
complete their remediation efforts. KU is currently evaluating and, in 
certain cases, initiating follow-up actions regarding the responses from 
these parties. KU regularly attends and participates in trade group efforts 
focusing on Year 2000 issues in the energy industry context.

Costs of Year 2000 Issues

KU's system modification costs related to the Year 2000 issue are being 
expensed as incurred, while new system installations are generally being 
capitalized pursuant to generally accepted accounting principles. (See Note 1 
of KU's Notes to Financial Statements under Item 8). Through December 1998, 
KU has incurred approximately $2.4 million in capital and operating costs in 
connection with the Year 2000 issue. Based upon studies and projections to 
date, KU expects to spend an additional $4.5 million to complete its Year 
2000 efforts.

It should be noted that these figures include total hardware, software, 
embedded systems and consulting costs. In many cases, these costs include 
system replacements which were already contemplated or which provided 
additional benefits or efficiencies beyond the Year 2000 aspect. Additionally 
many costs are not incremental costs, but constitute redeployment of existing 
IT and other resources. These costs represent management's current estimates; 
however, there can be no assurance that actual costs associated with KU's 
Year 2000 issues will not be higher.

Risks of Year 2000 Issues

As described above, KU has made significant progress in the implementation of 
its Year 2000 plan. Based upon the information currently known regarding its 
internal operations and assuming successful and timely completion of its 
remediation plan, KU does not anticipate material business disruptions from 
its internal systems due to the Year 2000 issue. However, KU may possibly 
experience limited interruptions to some aspects of its activities, whether 
IT, generation, transmission or distribution, operational, administrative 
functions or otherwise, and KU is considering such potential occurrences in 
planning for the most reasonably likely worst-case scenarios.

Additionally, risk exists regarding the non-compliance of third parties with 
key business or operational importance to KU. Year 2000 problems affecting 
key customers, interconnected utilities, fuel suppliers and transporters, 
telecommunications providers or financial institutions could result in lost 
power or gas sales,

                                       78

<PAGE>

KU (cont.):

reduced power production or transmission capabilities or internal operational 
or administrative difficulties on the part of the KU. KU is not presently 
aware of any such situations; however, severe occurrences of this type could 
have material adverse impacts upon the business, operating results or 
financial condition of KU. There can be no assurance that KU will be able to 
identify and correct all aspects of the Year 2000 problem among these third 
parties that affect it in sufficient time, that it will develop adequate 
contingency plans or that the costs of achieving Year 2000 readiness will not 
be material.

Contingency planning is under way for material areas of Year 2000 risk. This 
effort will address certain areas, including the most reasonably likely 
worst-case scenarios and delays in completion in KU's remediation plans, 
failure or incomplete remediation results and failure of key third parties to 
be Year 2000 compliant. Contingency plans will include provisions for extra 
staffing, back-up communications, review of unit dispatch and load shedding 
procedures, carrying of additional energy reserves and manual energy 
accounting procedures. Completion of contingency plan formation is scheduled 
for June 1999.

Forward Looking Statements

The foregoing discussion regarding the timing, effectiveness, implementation, 
and cost of KU's Year 2000 efforts, contains forward-looking statements, 
which are based on management's best estimates and assumptions. These 
forward-looking statements involve inherent risks and uncertainties, and 
actual results could differ materially from those contemplated by such 
statements. Factors that might cause material differences include, but are 
not limited to, the availability of key Year 2000 personnel, KU's ability to 
locate and correct all relevant computer codes, the readiness of third 
parties, and KU's ability to respond to unforeseen Year 2000 complications 
and other factors described from time to time in KU's reports to the 
Securities and Exchange Commission, including Exhibit 99.01 to LG&E Energy 
Corp.'s report on Form 8-K filed October 21, 1998. Such material differences 
could result in, among other things, business disruption, operational 
problems, financial loss, legal liability and similar risks.

Rates and Regulation

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

In August 1994, KU implemented an environmental cost recovery (ECR) surcharge 
to recover certain environmental compliance costs. Such costs include 
compliance with the 1990 Clean Air Act, as amended, as well as other 
environmental regulations, including those applicable to coal combustion 
wastes and related by-products. The ECR mechanism was authorized by state 
statute in 1992 and was first approved by the Kentucky Commission in a KU 
case in July 1994.

The Commission's order approving the surcharge in the KU case and the 
constitutionality of the surcharge was challenged by certain intervenors, 
including the Attorney General of Kentucky, in Franklin Circuit Court. 
Decisions of the Circuit Court and the Kentucky Court of Appeals in July 1995 
and December 1997, respectively, have upheld the constitutionality of the ECR 
statute but differed on a claim of retroactive recovery of certain amounts. 
The Commission ordered that certain surcharge revenues collected by KU be 
subject to refund pending final determination of all appeals.

                                       79

<PAGE>

KU (cont.):

On December 19, 1998, the Kentucky Supreme Court rendered an opinion 
upholding the constitutionality of the surcharge statute. The decision, 
however, reversed the ruling of the Court of Appeals on the retroactivity 
claim, thereby denying recovery of costs associated with pre-1993 
environmental projects. The court remanded the case to the Commission to 
determine the proper adjustments to refund amounts collected for such 
pre-1993 environmental projects. The parties to the proceeding have notified 
the Commission that they have reached agreement as to the terms, proper 
adjustments and forward application of the ECR. The settlement agreement is 
subject to Commission approval. KU recorded a provision for rate refund of 
$21.5 million in December 1998. See Rates and Regulation in KU's Management's 
Discussion and Analysis of Results of Operations and Financial Condition 
under Item 7 for a further discussion.

In October 1998, LG&E and KU filed separate but parallel applications with 
the Commission for approval of a new method of determining electric rates 
that provides financial incentives for LG&E and KU to further reduce 
customers' rates. The filing was made pursuant to the September 1997 
Commission order approving the merger of LG&E Energy and KU Energy, wherein 
the 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 new ratemaking method, known as 
performance-based ratemaking (PBR), would include 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 provides 
financial penalties and rewards to assure continued high quality service and 
reliability.

The PBR plan proposed by LG&E and KU consists of five components:

    The utilities' fuel adjustment clause mechanism will be withdrawn and
    replaced with a cap that limits recovery of actual changes in fuel cost to
    changes in a fuel price index for a five-state region. If the utilities
    outperform the index, benefits will be shared equally between shareholders
    and customers. If the utilities' fuel costs exceed the index, the difference
    will be absorbed by the LG&E Energy's shareholders.

    Customers will continue to receive the benefits from the post-merger joint
    dispatch of power from LG&E's and KU's generating plants.

    Power plant performance will be measured against the best performance
    achieved between 1991 and 1997. If the performance exceeds this level,
    customers will share equally with LG&E Energy's shareholders in up to $10
    million annually of benefits from this performance at each of LG&E and KU.

    The utilities will be encouraged to maintain and improve service quality,
    reliability, customer satisfaction and safety, which will be measured
    against six objective benchmarks. The plan provides for annual rewards or
    penalties to LG&E Energy of up to $5 million per year at each of LG&E and
    KU.

    The plan provides the utilities with greater flexibility to customize rates
    and services to meet customer needs. Services will continue to be priced
    above marginal cost and customers will continue to have the option to elect
    standard tariff service.

These proposals are subject to approval by the Commission. Approval 
proceedings commenced in October 1998 and a final decision may occur in 1999. 
Several intervenors are participating in the case. Some have requested that 
the Commission reduce base rates before implementing PBR.

In December 1997, the Kentucky Commission opened Administrative Case No. 369 
to consider Commission policy regarding cost allocations, affiliate 
transactions and codes of conduct governing the relationship between 

                                       80

<PAGE>

KU (cont.):

utilities and their non-utility operations and affiliates. The 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 which result in unfair competition caused by cost 
shifting from the non-utility affiliate to the utility. In September 1998, 
the Commission issued draft code of conduct and cost allocation guidelines. 
In January 1999, KU, as well as all parties to the proceeding, filed comments 
on the Commission draft proposals. Initial hearings are scheduled for the 
first quarter of 1999. 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.

As of February 12, 1999, the Kentucky Commission ordered KU's affiliate 
utility, LG&E, to refund FAC charges to retail electric customers after a 
review of LG&E's FAC from November 1994 through April 1998. The Kentucky 
Commission subsequently on March 11, 1999, denied LG&E's Petition for 
Rehearing for the period November 1994 through October 1996, but granted 
rehearing for the period November 1996 through April 1998 on the same issue. 
KU has not received an order from the Kentucky Commission but estimates that 
it may be required to refund to its retail electric customers approximately 
$3.5 million in FAC charges for the period November 1994 through October 1998.

On March 8, 1999, the Kentucky Industrial Utility Customers filed a Complaint 
with the Kentucky Commission alleging that KU's electric rates are excessive 
and should be reduced by an amount between $42 and $56 million, and that the 
Kentucky Commission establish a proceeding to reduce KU's rates. KU has asked 
the Kentucky Commission to dismiss the Complaint.

KU is not able to predict the ultimate outcome of these proceedings, however, 
should the Commission mandate significant rate reductions at KU, through the 
PBR proposal or otherwise, such actions could have a material effect on KU's 
financial condition and results of operations.

Environmental Matters

The Clean Air Act Amendments of 1990 (the Act) imposed stringent new sulfur 
dioxide (SO2) emission limits. KU met the Phase I requirements of the Act 
primarily through the installation of a scrubber on Unit 1 of the Ghent 
Generating Station. KU's current strategy for Phase II 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 nitrogen oxide (NOx) emission reduction 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 U.S. Environmental Protection Agency (USEPA) announced 
its final regulation requiring significant additional reductions in NOx 
emissions to mitigate alleged ozone transport to the Northeast. While each 
state is free to allocate its assigned NOx reductions among various emissions 
sectors as it deems appropriate, the regulation may ultimately require 
utilities to reduce their NOx emissions to 0.15 lb./mmBtu (million British 
thermal units) -an 85% reduction from 1990 levels. Under the regulation, each 
state must incorporate the additional NOx reductions in its State 
Implementation Plan (SIP) by September 1999 and affected sources must install 
control measures by May 2003, unless granted extensions. Several states, 
various labor and industry groups, and individual companies have appealed the 
final regulation to the U.S. Court of Appeals for the D.C. Circuit. 
Management is currently unable to determine the outcome or exact impact of 
this

                                       81

<PAGE>

KU (cont.):

matter until such time as the states identify specific emissions reductions 
in their SIP and the courts rule on the various legal challenges to the final 
rule. 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 and 
analysis, KU estimates that it may incur capital costs in the range of $100 
million to $200 million. These costs would generally be incurred beginning in 
the year 2000.

KU believes its costs for these matters 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 
cost recovery from customers under its environmental surcharge mechanism and 
believes that a significant portion of such costs could be so recovered. 
However, Kentucky Commission approval is necessary and there can be no 
guarantee of such recovery. See Note 11 of KU's Notes to Financial Statements 
under Item 8 for a complete discussion of KU's environmental issues.

In July, 1997, USEPA issued revised National Ambient Air Quality Standards 
(NAAQS) for ozone and particulate matter. KU is monitoring USEPA's 
implementation of the revised standards. Until USEPA completes additional 
implementation steps, including monitoring and nonattainment demonstrations, 
management is unable to determine the precise impact of the revised standards.

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 
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. 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 and federal regulatory agencies 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 that federal legislation be adopted 
specifying a date certain and appropriate transition regulations implementing 
deregulation.

In December 1997, the Kentucky Commission issued a set of principles which 
are intended to serve as its guide in consideration of issues relating to 
industry restructuring. Among these principles were: 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 have 
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. The purpose of the task force is to make recommendations to the 
Kentucky General Assembly for possible legislative action during its 2000 
session.

However, 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 
future legislative or regulatory actions regarding industry restructuring and 
their impact on KU, which may be significant, cannot be predicted currently.

                                       82

<PAGE>

KU (cont.):

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

See Management's Discussion and Analysis of Results of Operations and 
Financial Condition, Market Risks, under Item 7.

















                                       83


<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
                                                    1998          1997         1996
                                                    ----          ----         ----
<S>                                             <C>           <C>            <C>
REVENUES:
    Electric utility...........................  $1,464,824    $1,331,569     $1,318,846
    Gas utility................................     191,545       231,011        214,419
    International and non-utility..............     346,044        162,475        27,195
                                                 ----------     ----------   -----------
       Total revenues..........................   2,002,413      1,725,055     1,560,460
    Provision for rate refund (Note 5).........     (26,000)             -             -
                                                 ----------     ----------   -----------
       Net revenues (Note 1)...................   1,976,413      1,725,055     1,560,460
                                                 ----------     ----------   -----------
OPERATING EXPENSES:
Operation and maintenance:
    Fuel and power purchased...................     640,438        442,949       440,570
    Gas supply expenses........................     207,041        229,033       140,482
    Utility operation and maintenance..........     432,763        415,882       416,597
    International and non-utility operation
      and maintenance..........................     123,267         54,724        31,101
Depreciation and amortization..................      197,417        186,549       171,399
Merger costs to achieve and
    non-recurring charges (Notes 2 and 10).....       65,318              -         5,493
                                                  ----------     ----------   -----------
       Total operating expenses................    1,666,244      1,329,137     1,205,642
                                                  ----------     ----------    ----------

Equity in earnings of unconsolidated
  ventures (Note 8)............................       73,798         22,937        19,727
                                                  ----------     ----------   -----------
OPERATING INCOME...............................      383,967        418,855       374,545

Other income and (deductions) (Note 14)........        7,451         20,970        11,575
Interest charges and preferred dividends.......      108,871        104,427        94,412
Minority interest..............................      10,453           9,035             -
                                                  ----------     ----------   -----------

Income from continuing operations, before
  income taxes.................................      272,094        326,363       291,708

Income taxes (Note 13).........................      111,823        119,323       101,322
                                                  ----------     ----------   -----------
Income from continuing operations..............      160,271        207,040       190,386

Loss from discontinued operations,
  net of income tax (benefit) expense
  of $(14,907), $(15,116) and $2,371
  (Notes 1 and 3)..............................      (23,599)       (24,044)       (4,434)

Loss on disposal of discontinued operations,
  net of income tax benefit of $125,000
  (Note 3) ....................................     (225,000)             -             -
                                                  ----------     ----------   -----------

Income (loss) before cumulative effect of
  change in accounting principle...............      (88,328)       182,996       185,952

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)..............................  $   (95,490)   $   182,996   $   185,952
                                                  ----------     ----------   -----------
                                                  ----------     ----------   -----------
</TABLE>

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

                                       84


<PAGE>


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

<TABLE>
<CAPTION> 
                                                                    Years Ended December 31
                                                                1998          1997         1996
                                                                ----          ----         ----
<S>                                                            <C>         <C>            <C>

Average common shares outstanding...........................    129,679     129,627       129,450

Earnings (loss) per share of common stock - basic:
Continuing operations.......................................      $1.24       $1.60         $1.47
Loss from discontinued operations...........................       (.18)       (.19)         (.03)
Loss on disposal of discontinued operations.................      (1.74)          -             -
Cumulative effect of accounting change......................       (.06)          -             -
                                                                -------    --------      --------
Total  .....................................................     $ (.74)      $1.41         $1.44
                                                                -------    --------      --------
                                                                -------    --------      --------

Earnings (loss) per share of common stock - diluted:
Continuing operations.......................................     $1.23       $1.60          $1.47
Loss from discontinued operations...........................      (.17)       (.19)          (.03)
Loss on disposal of discontinued operations.................     (1.73)          -              -
Cumulative effect of accounting change......................      (.06)          -              -
                                                                -------    --------     ---------
Total  .....................................................    $ (.73)      $1.41          $1.44
                                                                -------    --------     ---------
                                                                -------    --------     ---------

</TABLE>

                 Consolidated Statements of Comprehensive Income
                                (Thousands of $)

<TABLE>
<CAPTION> 
                                                                    Years Ended December 31
                                                                1998          1997         1996
                                                                ----          ----         ----
<S>                                                            <C>         <C>            <C>

Net income (loss)............................................ $(95,490)   $182,996       $185,952

Unrealized holding gains (losses) on available-for-sale
  securities arising during the period.......................     (168)       (567)           196

Reclassification adjustment for realized and losses on
    available-for-sale securities included in net income.....      123         337            981
                                                                -------    --------     ---------

Other comprehensive income (loss) before tax.................      (45)       (230)         1,177

Income tax expense (benefit) related to items of other
    comprehensive income.....................................        5        (293)           450
                                                                -------    --------     ---------

Comprehensive income (loss)..................................  $(95,540)   $183,059      $186,679
                                                                -------    --------     ---------
                                                                -------    --------     ---------

</TABLE>

                  Consolidated Statements of Retained Earnings
                                (Thousands of $)

<TABLE>
<CAPTION> 
                                                                    Years Ended December 31
                                                                1998          1997         1996
                                                                ----          ----         ----
<S>                                                            <C>         <C>            <C>

Balance January 1...........................................  $722,584    $683,962       $637,996
Add net income (loss).......................................   (95,490)    182,996        185,952
Deduct:  Cash dividends declared on common stock
         ($1.240 per share in 1998, $1.113 per share
         in 1997, and $1.081 per share in 1996).............  (160,815)   (144,366)      (139,986)
         Preferred stock redemption expense and other.......         -          (8)             -
                                                              ---------   ---------      ---------

Balance December 31.........................................  $466,279    $722,584       $683,962
                                                              ---------   ---------      ---------
                                                              ---------   ---------      ---------

</TABLE>

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

                                       85
<PAGE>


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

<TABLE>
<CAPTION>                                                                             December 31
                                                                                1998               1997
                                                                                ----               ----
<S>                                                                       <C>               <C>
ASSETS:
Current assets:
   Cash and temporary cash investments...............................     $   108,723       $   111,003
   Marketable securities (Note 11)...................................          20,862            22,300
   Accounts receivable - less reserve of $10,532 in 1998 and
     $10,187 in 1997..........................................                285,794           242,942
   Materials and supplies - primarily at average cost:
      Fuel (predominantly coal)......................................          78,855            45,450
      Gas stored underground.........................................          34,144            42,104
      Other..........................................................          72,457            55,514
   Net assets of discontinued operations (Notes 1 and 3).............         143,651           222,784
   Prepayments and other.............................................          37,784             9,304
                                                                         ------------      ------------
      Total current assets...........................................         782,270           751,401
                                                                         ------------      ------------

Utility plant:
   At original cost (Note 1).........................................       5,581,667         5,390,868
   Less:  reserve for depreciation...................................       2,352,306         2,201,124
                                                                         ------------      ------------
      Net utility plant..............................................       3,229,361         3,189,744
                                                                         ------------      ------------
Other property and investments - less reserve:
   Investments in unconsolidated ventures (Note 8)...................         167,877           177,006
   Non-utility property and plant, net (Notes 1 and 2)...............         285,899           248,119
   Other  ...........................................................         117,321            53,534
                                                                          ------------      ------------
       Total other property and investments...........................        571,097           478,659
                                                                          ------------      ------------

Deferred debits and other assets:
   Regulatory assets (Note 5)........................................          65,871            39,672
   Goodwill, net.....................................................          13,273            13,675
   Other  ...........................................................         111,396            89,793
                                                                          -----------     -------------
      Total deferred debits and other assets.........................         190,540           143,140
                                                                         ------------      ------------
          Total assets...............................................      $4,773,268        $4,562,944
                                                                         ------------      ------------
                                                                         ------------      ------------
CAPITAL AND LIABILITIES:
Current liabilities:
   Long-term debt due within one year................................      $        -        $   20,021
   Notes payable (Note 17)...........................................         365,135           393,784
   Accounts payable..................................................         237,820           134,714
   Taxes and interest accrued........................................         104,656            45,011
   Common dividends declared.........................................          39,876            19,792
   Provision for rate refunds........................................          34,761            13,248
   Customer deposits.................................................          17,404            15,795
   Other  ...........................................................          47,002            42,182
                                                                         ------------      ------------
      Total current liabilities......................................         846,654           684,547
                                                                         ------------      ------------

Long-term debt (Note 16)..............................................      1,510,775         1,210,690

Deferred credits and other liabilities:
   Accumulated deferred income taxes (Notes 1 and 13)................         520,721          548,477
   Investment tax credit, in process of amortization.................          93,844          101,931
   Accumulated provision for pensions and related benefits...........         120,233           80,217
   Regulatory liability (Note 5).....................................         109,411          117,079
   Other  ...........................................................          86,047           76,471
                                                                         -------------     ------------
      Total deferred credits and other liabilities...................         930,256          924,175
                                                                         -------------     ------------

Minority interest (Note 2)............................................        107,815          105,985
Cumulative preferred stock............................................        136,530          138,353
Commitments and contingencies (Note 18)
Common equity........................................................       1,241,238        1,499,194
                                                                         -------------     ------------

   Total capital and liabilities.....................................      $4,773,268      $4,562,944
                                                                         -------------     ------------
                                                                         -------------     ------------

</TABLE>

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

                                       86

<PAGE>


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

<TABLE>
<CAPTION>
                                                                               Years Ended December 31

                                                                             1998           1997         1996
                                                                             ----          ----         ----
<S>                                                                     <C>            <C>            <C>

CASH FLOWS FROM OPERATING ACTIVITIES:
  Net income (loss).................................................    $ (95,490)     $ 182,996   $  185,952
  Items not requiring cash currently:
     Depreciation and amortization..................................      197,417        186,549      171,399
     Deferred income taxes - net....................................      (30,860)        10,316       55,589
     Investment tax credit - net....................................       (8,087)        (8,276)      (8,010)
     Undistributed earnings of unconsolidated ventures..............      (18,833)        (2,326)      (2,102)
     Loss from discontinued operations (Notes 1 and 3)..............       23,599         24,044        4,434
     Loss on disposal of discontinued
         operations (Note 3)........................................      225,000              -            -
     Cumulative effect of change in accounting
         principle (Note 1).........................................        7,162              -            -
     Other..........................................................       21,838         14,213       10,147
  Change in certain net current assets:
     Accounts receivable............................................      (42,852)       (22,771)      (3,976)
     Materials and supplies.........................................      (42,388)        (7,514)      (1,468)
     Net assets of discontinued operations (Notes 1 and 3)..........     (145,867)       (10,946)      13,539
     Provision for rate refunds.....................................       21,513         (4,263)     (12,289)
     Accounts payable...............................................      103,106          1,826      (11,396)
     Accrued taxes and interest.....................................       59,645          5,859       (5,009)
     Customer deposits..............................................        1,609          2,392        2,867
     Prepayments and other..........................................      (23,660)          (411)       4,022
  Other.............................................................      (41,130)       (52,942)     (35,313)
                                                                        ---------    -----------    -----------
     Net cash flows from operating activities.......................      211,722        318,746      368,386
                                                                        ---------     ----------     ----------

CASH FLOWS FROM INVESTING ACTIVITIES:
  Purchases of securities...........................................      (18,421)       (21,526)     (20,625)
  Proceeds from sales of securities.................................       19,995          5,030       44,609
  Construction expenditures.........................................     (342,214)      (210,131)    (215,954)
  Investment in subsidiaries net of cash and
     temporary cash investments acquired (Note 2)...................            -       (124,593)          -
  Investments in unconsolidated ventures (Note 8)...................       (1,010)        (5,791)      (1,490)
  Proceeds from sale of investment in affiliate.....................       16,000              -           -
                                                                        ---------     ----------     ----------
     Net cash flows from investing activities.......................     (325,650)      (357,011)    (193,460)
                                                                        ---------     ----------     ----------

CASH FLOWS FROM FINANCING ACTIVITIES:
  Issuance of medium-term notes.....................................      300,000              -           -
  Issuance of bonds.................................................            -         69,776       89,190
  Retirement of bonds...............................................      (20,042)       (71,714)    (103,205)
  Short-term borrowings.............................................    6,751,089      3,871,905    2,784,700
  Repayment of short-term borrowings................................   (6,776,845)    (3,690,321)  (2,801,100)
  Issuance of preferred stock.......................................            -          3,025            -
  Redemption of preferred stock.....................................       (1,823)             -            -
  Issuance of common stock..........................................            -          3,781        2,293
  Payment of common dividends.......................................     (140,731)      (143,647)    (139,282)
                                                                        ---------    -----------  ----------
     Net cash flows from financing activities.......................      111,648         42,805     (167,404)
                                                                        ---------    -----------  ----------

Change in cash and temporary cash investments.......................       (2,280)         4,540        7,522

Beginning cash and temporary cash investments.......................      111,003        106,463       98,941
                                                                       ----------    ----------  ----------

Ending cash and temporary cash investments..........................    $ 108,723      $ 111,003   $ 106,463
                                                                        ---------     ----------  ----------
                                                                        ---------     ----------  ----------

Supplemental disclosures of cash flow information: Cash paid
  during the year for:
       Income taxes.................................................    $  55,513      $  82,662  $   67,780
       Interest on borrowed money...................................       96,356         93,451      86,045

</TABLE>

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

                                       87

 
<PAGE>


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

<TABLE>
<CAPTION>
                                                                                                        December 31
                                                                                               1998                     1997
                                                                                               ----                     ----
<S>                                                      <C>           <C>             <C>                      <C>
COMMON EQUITY:
    Common stock, without par value -
       Authorized 300,000,000 shares, outstanding 129,677,030
       shares in 1998 and 129,682,889 shares in 1997 (Note 15)......................   $    778,273             $    778,273
    Common stock expense............................................................         (3,481)                  (1,880)
    Unrealized gain on marketable securities, net of income
       taxes of $94 in 1998 and $89 in 1997 (Note 11)...............................            167                      217
    Retained earnings...............................................................        466,279                  722,584
                                                                                       ------------             ------------
       Total common equity..........................................................      1,241,238                1,499,194
                                                                                       ------------             ------------

PREFERRED STOCK (Note 15):

                                                           Shares           Current
                                                         Outstanding   Redemption Price
                                                         -----------   ----------------
    Cumulative and redeemable on 30 days notice by 
       Louisville Gas and Electric Company:

    $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          105.875          25,000                   25,000
    Preferred stock expense.........................................................         (1,179)                  (1,179)
                                                                                       ------------              -----------
       Total LG&E preferred stock...................................................         95,328                   95,328
                                                                                       ------------              -----------

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

    $100 stated value, 200,000 shares authorized -
       4 3/4% series.................................      200,000          $101.00          20,000                   20,000
    $100 stated value, 200,000 shares authorized -
       6.53% series..................................      200,000      Not redeemable       20,000                   20,000
                                                                                       ------------              -----------
       Total KU preferred stock.....................................................         40,000                   40,000
                                                                                       ------------              -----------

    $10 nominal value, 102,089 and 302,364 shares authorized and outstanding,
       (net of shares owned by affiliates) for 1998 and 1997, respectively,
       variable rate and redeemable by Inversora de Gas del Centro..................          1,202                    3,025
                                                                                      -------------             ------------

    Total preferred stock...........................................................        136,530                  138,353
                                                                                      -------------             ------------

LONG-TERM DEBT (Note 16):

    Louisville Gas and Electric Company:

    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
                                                                                      -------------            -------------
</TABLE>

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

                                       88

<PAGE>


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

<TABLE>
<CAPTION>
                                                                                                        December 31
                                                                                               1998                     1997
                                                                                               ----                     ----
<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 long-term debt.............................................        626,800                  626,800
                                                                                       ------------             ------------

    Kentucky Utilities Company:

    First mortgage bonds:
       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 3/8%........................................          4,000                    4,000
           Series 8, due September 15, 2016, 7.45%..................................         96,000                   96,000
           Series 1B, due February 1, 2018, 6 1/4%..................................         20,930                   20,930
           Series 2B, due February 1, 2018, 6 1/4%..................................          2,400                    2,400
           Series 3B, due February 1, 2018, 6 1/4%..................................          7,200                    7,200
           Series 4B, due February 1, 2018, 6 1/4%..................................          7,400                    7,400
           Series 7, due May 1, 2020, 7.60%.........................................          8,900                    8,900
           Series 9, due December 1, 2023, 5 3/4%...................................         50,000                   50,000
           Series 10, due November 1, 2024, variable................................         54,000                   54,000
                                                                                       ------------              -----------
              Total first mortgage bonds............................................        546,330                  546,330

    Other        ...................................................................              -                       21
                                                                                       ------------              -----------

       Total KU long-term debt......................................................        546,330                  546,351
                                                                                       ------------              -----------

    LG&E Capital Corp.:

    Argentine negotiable obligations, due August 2001, 10 1/2%......................         37,645                   37,539
    Medium term notes, due January 15, 2008, 6.46% (Note 16)........................        150,000                        -
    Medium term notes, due November 1, 2011, 5.75% (Note 16)........................        150,000                        -
                                                                                       ------------              -----------

       Total Capital Corp. long-term debt...........................................        337,645                   37,539
                                                                                       ------------              -----------

    Total long-term debt............................................................      1,510,775                1,210,690
                                                                                       ------------              -----------

    Total capitalization............................................................    $ 2,888,543              $ 2,848,237
                                                                                       ------------              -----------
                                                                                       ------------              -----------
</TABLE>

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

                                       89

<PAGE>

                          NOTES TO 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 Corp. (LG&E Energy
or the Company) and KU Energy Corporation (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 Louisville Gas and Electric Company (LG&E), a
subsidiary of LG&E Energy, and Kentucky Utilities Company (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. As a result of this decision, the Company recorded 
an after-tax loss on disposal of discontinued operations of $225 million in 
the second quarter of 1998. See Note 3, Discontinued Operations.

The consolidated financial statements include the accounts of LG&E Energy, LG&E,
LG&E Capital Corp. (Capital Corp.), KU and their respective wholly owned
subsidiaries, collectively referred to herein as the Company. KU and KU Capital
Corporation (KU Capital) were subsidiaries of KU Energy before the merger. On
September 5, 1997, LG&E Energy merged two of its direct subsidiaries, LG&E
Energy Systems Inc. (Energy Systems) and LG&E Gas Systems Inc. (Gas Systems),
and renamed the surviving company LG&E Capital Corp. In July 1998, KU Capital
was merged into Capital Corp. with the latter as the surviving corporation.

LG&E Energy's regulated operations are conducted by LG&E and KU. Its non-utility
operations are conducted by Capital Corp., which has various subsidiaries
referred to in these financial statements, including LG&E Power Inc. (LPI), LG&E
Energy Marketing (LEM), LG&E International Inc. (LII) and Western Kentucky
Energy Corp. (with its affiliates, WKE).

All significant intercompany items and transactions have been eliminated from
the consolidated financial statements. The Company is exempt from regulation as
a registered holding company under the Public Utility Holding Company Act of
1935 (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, 1998
and 1997. Utility gas inventories were $33 million and $41 million at December
31, 1998 and 1997, respectively. LG&E accounts for gas inventories using the
average-cost method. Non-utility gas inventories are included in net assets or
liabilities of discontinued operations.

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

                                       90

<PAGE>

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. 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 in 1998 and 1997 were 3.4% and for 1996 were 3.3%. The
amounts provided for KU were 3.5% in 1998, 1997 and 1996.

Depreciation of non-utility plant and equipment is based on the straight-line
method over periods ranging from 3 to 33 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 40 years.

FINANCIAL INSTRUMENTS. The Company uses over-the-counter interest-rate swap
agreements to hedge its exposure to fluctuations in the interest rates it pays
on variable-rate debt, and it 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
6, 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. Effective April 15, 1996, the outstanding shares of the Company's
common stock were split on a two-for-one basis. The new shares were issued to
shareholders of record on April 1, 1996. 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 stock split and to reflect the
exchange of KU Energy's shares for shares of LG&E Energy.

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. Under an
agreement approved by the Public Service Commission of Kentucky (Kentucky
Commission or Commission) in 1995, LG&E implemented a demand-side management
program, including a 

                                       91

<PAGE>

"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 5, 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 Commission approved experimental
performance-based ratemaking mechanism related to gas procurement and off-system
gas sales activity. See Note 5, 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 1998, the Company adopted the 
following accounting pronouncements:

Statements of Financial Accounting Standards No. 132, Employers' Disclosures 
about Pensions and Other Postretirement Benefits (SFAS No. 132), No. 131, 
Disclosures about Segments of an Enterprise and Related Information (SFAS No. 
131) and No. 130, Reporting Comprehensive Income (SFAS No. 130).  Pursuant to 
SFAS No. 132, the Company has disclosed additional information on changes in 
benefit obligations and fair values of plan assets and eliminated certain 
disclosures that are no longer relevant.  This standard does not change the 
measurement or financial statement recognition of the plans (see Note 12, 
Pension Plans and Retirement Benefits).  Under SFAS No. 131, the Company has 
provided information about its various business segments that is intended to 
allow readers to view certain financial information as if "through the eyes 
of management" (see Note 20, Segments of Business and Related Information 
Disclosures).  Pursuant to SFAS No. 130, the Company has presented 
information in the Consolidated Statements of Comprehensive Income that 
measures changes in equity that are not required to be recorded as a 
component of net income.  These standards had no impact on the calculation of 
net income or earnings per share presented in the Consolidated Statements of 
Income.

Statement of Position Nos. 98-5, Reporting on the Costs of Start-Up Activities
(SOP 98-5) and 98-1, Accounting for the Costs of Computer Software Developed or
Obtained for Internal Use (SOP 98-1). 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 must be expensed as incurred. Adoption
of SOP 98-1 did not have a material effect on the Company's financial
statements. The following accounting pronouncements have been issued but are not
yet effective:

Statement of Financial Accounting Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities. The statement is effective for fiscal years
beginning after June 15, 1999, and establishes accounting and reporting
standards that every derivative instrument be recorded in the balance sheet as
either an asset or 

                                       92

<PAGE>

liability measured at its fair value. The statement 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 a company must 
formally document, designate, and assess the effectiveness of transactions 
that use hedge accounting. The Company is currently analyzing the provisions 
of the statement and cannot predict the impact this statement will have on 
its consolidated operations and financial position; however, the statement 
could increase volatility in earnings and other comprehensive income. The 
effect of this statement will be recorded in cumulative effect of change in 
accounting when adopted.

Emerging Issues Task Force Issue No. 98-10, Accounting for Energy Trading and
Risk Management Activities (EITF No. 98-10). This pronouncement is effective for
fiscal years beginning after December 15, 1998. The task force concluded that
energy trading contracts should be recorded at mark 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. The effects of adopting EITF No. 98-10, if
applicable, will be reported as a cumulative effect of a change in accounting
principle with no prior period restatement. The Company does not expect the
adoption of EITF No. 98-10 to have a material adverse impact on its consolidated
operations and financial position.

NOTE 2 - MERGERS AND ACQUISITIONS

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 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.

Under the terms of the Agreement and Plan of Merger dated May 20, 1997 (the
Merger Agreement), each outstanding share of the common stock, without par
value, of KU Energy (KU Energy Common Stock) together with the associated KU
Energy stock purchase rights, was converted into 1.67 shares of common stock of
LG&E Energy (LG&E Energy Common Stock), together with the associated LG&E Energy
stock purchase rights. 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.

Regulatory and administrative approvals were obtained from the Federal Energy
Regulatory Commission (FERC), the Federal Trade Commission, the Securities and
Exchange Commission, the Virginia State Corporation Commission and the
stockholders of LG&E Energy and KU Energy prior to the effective date of the
merger. LG&E Energy, as the parent of LG&E and KU, continues to be an exempt
holding company under 

                                       93

<PAGE>

the Public Utility Holding Company Act of 1935. 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 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 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.

ARGENTINE GAS DISTRIBUTION COMPANIES. On February 13, 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 Distribuidora de Gas del Centro (Centro) and a combined 14.4%
interest in Distribuidora de Gas Cuyana (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 Company recognized no goodwill on the
acquisition.

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

<TABLE>

<S>                                                                                   <C>
         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
                                                                                       --------
                                                                                       --------
</TABLE>

Centro's revenues, cost of revenues and operating expenses since the date of
acquisition are classified as components of international and non-utility in
these Statements of Income. 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.

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 enables the
Company to focus on optimizing the value of physical assets it owns or controls,
and to reduce the earnings impact on continuing operations of 

                                       94

<PAGE>

extreme market volatility in its portfolio of energy marketing contracts. The 
Company is in the process of settling commitments that obligate it to buy and 
sell natural gas and electric power. It also plans to sell its natural gas 
gathering and processing business. If the Company is unable to dispose of 
these commitments or assets it will continue to meet its obligations under 
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 the Big Rivers Electric Corporation (Big 
Rivers).

As a result of the Company's decision to discontinue its merchant energy trading
and sales activity, and the 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 results primarily from several
fixed-price energy marketing contracts entered into in 1996 and early 1997,
including the Company's long-term contract with Oglethorpe Power Corporation
(OPC). Other components of the write-off include costs relating to certain
peaking options, goodwill associated with the Company's 1995 purchase of
merchant energy trading and sales operations and exit costs, including labor and
related benefits, severance and retention payments, and other general and
administrative expenses. 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, it also recognizes that
there are inherent limitations in models to accurately predict future events. As
a result, there is no guarantee that higher-than-anticipated future commodity
prices or load demands, lower-than-estimated asset sales prices or other factors
could not result in additional losses. The Company has been successful in
settling portions of its discontinued operations, but significant assets,
operations and obligations remain. As of January 27, 1999, the Company estimates
that a $1 change in electricity prices and a 10 cents 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 $8.8 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 27, 1999, the Company estimates that a 1% change
in the forecasted load demand could change the value of the Company's remaining
energy portfolio by $9.3 million. See Note 18, Commitments and Contingencies,
for a discussion of the OPC contract. See also Note 1, Summary of Significant
Accounting Policies.

Operating results for discontinued operations follow (in thousands of $):

<TABLE>
<CAPTION>
                                                                          1998             1997              1996
                                                                          ----             ----              ----
<S>                                                                <C>              <C>               <C>
         Revenues                                                  $ 3,865,020      $ 3,255,175       $ 2,740,691
         Loss before taxes                                            (173,423)         (39,160)           (2,063)
         Loss from discontinued operations,
           net of income taxes                                     $  (113,273)     $   (24,044)      $    (4,434)
</TABLE>

                                       95

<PAGE>


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

<TABLE>
<CAPTION>
                                                                                           1998              1997
                                                                                           ----              ----
<S>                                                                                   <C>              <C>
         Cash and temporary cash investments                                          $   1,674        $   15,089
         Accounts receivable                                                             78,200           353,162
         Price risk management assets, net                                               98,885           164,581
         Non-utility property and plant, net                                            163,510           176,032
         Accounts payable and accruals                                                  (71,265)         (344,265)
         Price risk management liabilities, net                                         (32,693)         (154,910)
         Goodwill and other assets and liabilities, net                                  24,721            13,095
                                                                                      ---------        ----------

         Net assets before accrued loss on disposal of dis-
           continued operations                                                         263,032           222,784

         Accrued loss on disposal of discontinued operations,
           net of income tax benefit of $74,297                                         119,381                 -
                                                                                      ---------        ----------

         Net assets of discontinued operations                                        $ 143,651        $  222,784
                                                                                      ---------        ----------
                                                                                      ---------        ----------
</TABLE>

ACCOUNTING TREATMENT. Effective January 1, 1996, the Company adopted the mark to
market method of accounting for most of its merchant energy trading and sales
activities. The Company has included these activities in Discontinued Operations
in the accompanying financial statements. Under mark to market accounting, all
electric power and natural gas contracts which qualify for such accounting
treatment, including both physical transactions and financial instruments, were
recorded at market value, net of future servicing costs and reserves, and were
recognized as price risk management assets and liabilities in the balance sheet.
To qualify for mark to market accounting treatment, merchant energy trading and
sales contracts generally must include, among other factors, a firm term, volume
and price and allow for settlement in cash or with another financial instrument.
Changes in the value of these price risk management assets and liabilities
resulting from the execution of new contracts and changes in market factors were
recognized as merchant energy trading and sales revenues in the period of the
change.

Revenues and cost of revenues associated with merchant energy trading and sales
activities that did not qualify for mark to market accounting treatment were
recognized using the accrual method of accounting at the time of delivery of the
underlying commodity. Prior to January 1, 1996, all of the Company's merchant
energy trading and sales activities were accounted for under the accrual method.
The effect of this change in accounting was immaterial to prior periods at the
time of adoption.

In addition, the Company entered into transactions to hedge the impact of market
fluctuations in its energy-related assets, liabilities and other contractual
commitments. Changes in the market value of these hedge transactions were
afforded hedge accounting treatment whereby gains and losses were deferred until
the gains or losses on the hedged items were recognized or the instrument was
terminated.

As a result of the Company's decision to discontinue its merchant energy trading
and sales activity, all transactions are recorded using discontinued operations
accounting. Most transactions previously recorded using the mark to market
method of accounting have now been settled. The effects of the previously
adopted mark to market method of accounting for the remaining unsettled
transactions are applied against the reserve for discontinued operations.

Total charges against the reserve through December 31, 1998 include $77.3
million for commitments prior to disposal, $51.2 million for transaction
settlements, $11.1 million for goodwill, and $16.7 million for other exit 

                                       96

<PAGE>

costs. The reserve as of December 31, 1998, represents management's best 
estimate of the loss from remaining discontinued operations until disposal 
and the costs of disposing of these operations.

MARKET RISK. The primary market risk inherent in the Company's discontinued
operations relates to commodity price risk principally associated with
fluctuations in the supply and demand of electricity and natural gas. The
Company's price risk management strategy involved using various derivative
instruments to hedge the impact of market fluctuations in its energy-related
assets, liabilities and other contractual commitments. Derivative instruments
utilized as hedges include futures contracts; swap agreements, where settlement
is based on the difference between a fixed and index-based price;
exchange-traded options; over-the-counter options, which are settled in cash or
the physical delivery of the commodity; exchange-for-physical transactions, in
which payment for delivery of the underlying commodity is in the form of futures
contracts; and tolling arrangements. The changes in the market value of these
instruments correspond to the price changes in the underlying commodities.

The Company has reduced its price risk by settling contracts or entering into
back-to-back agreements with third parties to act on its behalf as the purchaser
or seller for specified transactions. For all other transactions, the Company is
actively attempting to mitigate its risk and no new overall positions are being
taken. The remaining net open positions on these transactions could result in
additional losses to the Company if prices do not move in the manner or
direction anticipated.

The Company has established trading policies and limits designed to minimize its
exposure to price risk and regularly revalues exposures against the stipulated
limits. The Company also continually reviews these policies to ensure they are
responsive to changing business conditions.

The Company's discontinued operations utilize various methodologies which
simulate forward price curves in the energy markets to estimate the size and
probability of changes in market value resulting from price movements. The use
of these methodologies requires a number of key assumptions including selection
of confidence levels, the holding period of the positions, and the depth and
applicability to future periods of historical price information. In addition to
price risk, the value of the Company's entire energy portfolio is subject to
operational and event risks including, among others, regulatory changes,
increases in load demand, and forced outages at units providing supply for the
Company.

NOTIONAL AMOUNTS. As of December 31, 1998, the Company's discontinued operations
were under various contracts to buy and sell power and gas with net notional
amounts of 30.6 million MWh's of power and 22.7 million MMBTU's of natural gas
with a volumetric weighted-average period of approximately 45 and 16 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 immaterial amounts of 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.

                                       97

<PAGE>

FAIR VALUES. The fair values of discontinued operations' price risk management
assets and liabilities recorded on a mark to market basis as of December 31,
1998 and 1997, and the average fair values during the year by commodity are set
forth below (in thousands of $):

<TABLE>
<CAPTION>
                                                              Fair Value                    Average Fair Value
                                                     ---------------------------     ----------------------------
                                                       Assets        Liabilities       Assets         Liabilities
                                                     ---------       -----------     ---------        -----------
<S>                                                  <C>             <C>              <C>               <C>
         1998:

         By Commodity:
         -------------
         Electricity                                 $  98,823       $  31,950        $ 230,816         $ 194,233
         Natural gas                                        62               -           69,972            61,701
         Other                                               -               -              265                 -
                                                     ---------       ---------        ---------         ---------

         Total                                          98,885          31,950        $ 301,053         $ 255,934
         Reserves                                            -             743        ---------         ---------
                                                     ---------       ---------        ---------         ---------

         Net values                                   $ 98,885        $ 32,693
                                                     ---------       ---------
                                                     ---------       ---------

         1997:
         -----
         By Commodity:
         -------------
         Electricity                                 $  69,704       $  56,308        $  81,765         $  31,093
         Natural gas                                    94,252          92,245           55,676            65,414
         Other                                             625           1,119              505               848
                                                     ---------       ---------        ---------         ---------

         Total                                         164,581         149,672        $ 137,946         $  97,355
         Reserves                                            -           5,238        ---------         ---------
                                                     ---------       ---------        ---------         ---------

         Net values                                   $164,581        $154,910
                                                     ---------       ---------
                                                     ---------       ---------
</TABLE>

The table above does not include the fair value of various transactions not
previously recorded using mark to market accounting since these transactions
commit the Company to the sale or purchase of electricity or natural gas without
specified firm volumes.

The fair values above are based on quotes from exchanges and over-the-counter
markets, price volatility factors, the use of established pricing models and the
time value of money. They also reflect management estimates of counterparty
credit risk, location differentials and the potential impact of liquidating the
Company's position in an orderly manner over a reasonable period of time under
present market conditions. The increase in values from 1997 to 1998 results from
volatility and risk management actions taken in connection with discontinuing
the merchant energy trading and sales business.

If the Company is unable to dispose of its remaining commitments, it will
continue to meet its obligations through the terms of the contracts. The net
fair value of these commitments as of December 31, 1998 are currently estimated
to be approximately $24.6 million in 1999, $19.6 million to $36.6 million each
year in 2000 through 2004, and $5.4 million for later years.

CREDIT RISK. 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, 1998, over 90% of the Company's price
risk management commitments were with counterparties rated BBB equivalent or
better. As of December 31, 1998, seven counterparties represented 86% of the
Company's price risk management commitments.

                                       98

<PAGE>


NOTE 4 - BIG RIVERS ELECTRIC CORPORATION LEASE

On July 15, 1998, the Company closed the transaction to lease the generating
assets of Big Rivers Electric Corporation (Big Rivers). Under the 25-year
operating lease, WKE is leasing and operating Big Rivers' three coal-fired
facilities. In addition, WKE operates and maintains the Station Two generating
facility of the City of Henderson (Henderson). The combined generating capacity
of these facilities amounts to approximately 1,700 megawatts, net of the
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 1998 was
$12.8 million. See Note 18, Commitments and Contingencies, for a 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 four-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 agreed to
provide Big Rivers a $50 million note to help it emerge from bankruptcy. WKE
will provide $1.7 million per month for the first 12 months of the note,
beginning August 1998, and $2.5 million per month over the subsequent 12 months.
The note will be repaid over a three-year period, beginning August 2000, with
interest at 7.165%.

NOTE 5 - 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 Statement of Financial Accounting Standards No. 71, Accounting for
the Effects of Certain Types of Regulation (SFAS No. 71). 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 $):

<TABLE>
<CAPTION>
                                                                                           1998              1997
                                                                                           ----              ----
<S>                                                                                  <C>               <C>
         Unamortized loss on bonds                                                   $   26,302        $   28,454
         Merger costs                                                                    34,749             7,000
         Manufactured gas sites                                                           3,684             3,263
         Other                                                                            1,136               955
                                                                                     ----------        ----------
         Total regulatory assets                                                         65,871            39,672
         Deferred income taxes - net                                                   (109,411)         (117,079)
                                                                                     ----------        ----------
         Regulatory assets and liabilities - net                                     $  (43,540)       $  (77,407)
                                                                                     ----------        ----------
                                                                                     ----------        ----------
</TABLE>

During 1997, LG&E wrote off certain previously deferred assets that amounted to
approximately $4.2 million. Items written off include expenses associated with
LG&E's hydro-electric plant, a management audit fee, and the accelerated
write-off of losses on early retirement of facilities.

ENVIRONMENTAL COST RECOVERY. Since May 1995 and August 1994, respectively, LG&E
and KU have implemented an environmental cost recovery (ECR) surcharge to
recover certain environmental compliance costs, including costs to comply with
the 1990 Clean Air Act, as amended, as well as other environmental 

                                       99

<PAGE>

regulations, including those applicable to coal combustion wastes and related 
by-products. The ECR mechanism was authorized by state statute in 1992 and 
was first approved by the Kentucky Commission in KU's Case No. 93-465 in July 
1994.

The Commission's order approving the surcharge in the KU case and the
constitutionality of the surcharge was challenged by certain intervenors,
including the Attorney General of Kentucky, in Franklin Circuit Court. Decisions
of the Circuit Court and the Kentucky Court of Appeals in July 1995 and December
1997, respectively, have upheld the constitutionality of the ECR statute but
differed on a claim of retroactive recovery of certain amounts. The Commission
ordered that certain surcharge revenues collected by LG&E and KU be subject to
refund pending final determination of all appeals.

On December 19, 1998 the Kentucky Supreme Court rendered an opinion upholding
the constitutionality of the surcharge statute. The decision, however, reversed
the ruling of the Court of Appeals on the retroactivity claim, thereby denying
recovery of costs associated with pre-1993 environmental projects through the
ECR. The court remanded the case to the Commission to determine the proper
adjustments to refund amounts collected for such pre-1993 environmental
projects. The parties to the proceeding have notified the Commission that they
have reached agreement as to the terms, refund amounts, refund procedure and
forward application of the ECR. The settlement agreement is subject to
Commission approval. The Company recorded a provision for rate refund of $26
million in December 1998.

OTHER RATE MATTERS. In January 1994, LG&E implemented a Commission-approved
demand side management (DSM) program that LG&E, the Jefferson County, Kentucky,
Attorney and representatives of several customer interest groups had filed with
the Commission. The program included a rate mechanism that (1) provided LG&E
concurrent recovery of DSM costs, (2) provided an incentive for implementing DSM
programs and (3) allowed LG&E to recover revenues from lost sales associated
with the DSM program (decoupling). In June 1998, LG&E and customer interest
groups requested an end to the decoupling rate mechanism. On June 1, 1998, LG&E
discontinued recording revenues from lost sales due to DSM. Accrued decoupling
revenues recorded for periods prior to June 1, 1998, will continue to be
collected through the DSM recovery mechanism. On September 23, 1998, the
Commission accepted LG&E's modified tariff reflecting this proposal effective as
of June 1, 1998.

Since October 1997, LG&E has implemented a Commission-approved, 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
year of the mechanism ended October 31, 1998, LG&E recorded $3.6 million for its
share of reduced gas costs. The $3.6 million will be billed to customers through
the gas supply clause beginning February 1, 1999.

LG&E and KU employ a fuel adjustment clause (FAC) mechanism, which under
Kentucky law allows the companies to recover from customers, the actual fuel
costs associated with retail electric sales. As of February 12, 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. The orders changed the Company's
method of computing fuel costs associated with electric line losses on
off-system sales appropriate for recovery through the FAC. The orders require
these amounts to be refunded to customers during first quarter 1999.

The Kentucky Commission has not issued LG&E an order for the review period May
1998 through October 1998, nor have they issued orders pertaining to KU's FAC
for review periods after November 1994. However, following the methods set forth
in the LG&E orders, the Company estimates up to an additional $4.8 million could
be refundable to LG&E and KU retail electric customers for open review periods
through December 

                                      100

<PAGE>

1998. Management intends to file a request for rehearing on the Kentucky 
Commission's rulings. Management does not believe final resolution of these 
proceedings will have a material adverse effect on the Company's financial 
position or results of operations.

FUTURE RATE REGULATION. In October 1998, LG&E and KU filed separate but parallel
applications with the Commission for approval of a new method of determining
electric rates that provides financial incentives for LG&E and KU to further
reduce customers' rates. The filing was made pursuant to the September 1997
Commission order approving the merger of LG&E Energy and KU Energy, wherein the
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 new ratemaking method, known as performance-based ratemaking (PBR), would
include 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 provides financial penalties and rewards to assure
continued high quality service and reliability.

The PBR plan proposed by LG&E and KU consists of five components:

    The utilities' fuel adjustment clause mechanism will be withdrawn and
    replaced with a cap that limits recovery of actual changes in fuel cost to
    changes in a fuel price index for a five-state region. If the utility
    outperform the index, benefits will be shared equally between shareholders
    and customers. If the utility's fuel costs exceed the index, the difference
    will be absorbed by the Company's shareholders.

    Customers will continue to receive the benefits from the post-merger joint
    dispatch of power from LG&E's and KU's generating plants.

    Power plant performance will be measured against the best performance
    achieved between 1991 and 1997. If the performance exceeds this level,
    customers will share in up to $10 million annually of benefits from this
    performance at each of LG&E and KU.

    The utilities will be encouraged to maintain and improve service quality,
    reliability, customer satisfaction and safety, which will be measured
    against six objective benchmarks. The plan provides for annual rewards or
    penalties to the Company of up to $5 million per year at each of LG&E and
    KU.

    The plan provides the utilities with greater flexibility to customize rates
    and services to meet customer needs. Services will continue to be priced
    above marginal cost and customers will continue to have the option to elect
    standard tariff service.

These proposals are subject to approval by the Commission. Approval proceedings
commenced in October 1998 and a final decision likely will occur in 1999.

Several intervenors are participating in the case. Some have requested that the
Commission reduce base rates before implementing PBR. The Company is not able to
predict the ultimate outcome of these proceedings, however, should the
Commission mandate significant rate reductions at LG&E or KU, through the PBR
proposal or otherwise, such actions could have a material effect on the
Company's financial condition and results of operations.

KENTUCKY PSC ADMINISTRATIVE CASE FOR AFFILIATE TRANSACTIONS. In December 1997,
the Kentucky Commission opened Administrative Case No. 369 to consider
Commission policy regarding cost allocations, affiliate transactions and codes
of conduct governing the relationship between utilities and their non-utility
operations and affiliates. The 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; 

                                      101

<PAGE>

and whether a code of conduct should be established to assure that 
non-utility segments of the holding company are not engaged in practices 
which result in unfair competition caused by cost shifting from the 
non-utility affiliate to the utility. In September 1998, the Commission 
issued 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 
Commission draft proposals. Initial hearings are scheduled for the first 
quarter of 1999. 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 6 - FINANCIAL INSTRUMENTS

At December 31, 1998, the Company held U.S. Treasury note and bond futures
contracts with notional amounts totaling $4.9 million. These contracts are used
to hedge price risk associated with certain marketable securities and mature in
March 1999.

As of December 31, 1998, LG&E had in effect six interest-rate swap agreements to
hedge its exposure to tax exempt rates related to Pollution Control Bonds,
Variable Rate Series. The swaps have notional amounts totaling $166 million and
mature at various times from 1999 to 2005. LG&E pays a weighted-average fixed
rate on the swaps of 3.89% and receives a variable rate based on the JJ Kenny
Index (in the case of one of the swaps) or the Bond Market Association Municipal
Swap Index. The indices averaged 3.48% in 1998.

In April 1998, LG&E entered into a forward-starting interest-rate swap with a
notional amount of $83.3 million. The swap will hedge anticipated variable-rate
borrowing commitments. It will start in August 2000 and mature in November 2020.
LG&E will pay a fixed rate of 5.21% and receive a variable rate based on the
Bond Market Association Municipal Swap Index. Under certain conditions, the
counterparty to the agreement may terminate the swap at no cost after August
2010.

Capital Corp. had two interest rate swaps outstanding at December 31, 1998,
which hedge a portion of its notes payable. One swap has a notional amount of
$50 million and matures in June 2002. Capital Corp. receives a variable rate
based on the three-month London Interbank Offered Rate which equaled 5.24% at
year end and pays a fixed rate of 6.49%. The second swap has a notional amount
of $50 million and matures in January 2000. The Company receives a variable rate
based on a one-month commercial paper rate index and pays a fixed rate of 4.78%.
The index for December 1998 was 5.23%.

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

<TABLE>
<CAPTION>
                                                                 1998                          1997
                                                                 ----                          ----
                                                                          Fair                               Fair
                                                          Cost           Value             Cost             Value
                                                   -----------     -----------      -----------       -----------
<S>                                                <C>             <C>              <C>               <C>
         Marketable securities                     $    20,592     $    20,862      $    21,994       $    22,300
         Long-term investments -
           Not practicable to estimate
              fair value                                 1,721           1,721            3,983             3,983
         Preferred stock subject
           to mandatory redemption                      25,000          26,413           25,000            26,250
         Long-term debt                              1,510,795       1,576,502        1,210,690         1,266,030
         U.S. Treasury note and
           bond futures                                      -             (87)               -               (81)
         Interest rate swaps                                 -          (9,527)               -            (4,328)
</TABLE>

                                      102

<PAGE>

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.

NOTE 7 - CONCENTRATIONS OF CREDIT AND OTHER RISK

Credit risk represents the accounting loss that would be recognized at the
reporting date if counterparties failed completely 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 289,000 customers and electricity to
approximately 360,000 customers in Louisville and adjacent areas in Kentucky.
KU's customer receivables and revenues arise from deliveries of electricity to
about 449,000 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, 1998, 90% of total utility revenue was derived from electric
operations and 10% 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 706,000 customers in six provinces in
Argentina. WKE's customer receivables and revenues arise from the deliveries of
electricity and generating capacity to Big Rivers for distribution to its four
members distribution cooperatives, as well as to other major wholesale
customers.

LG&E's operation and maintenance employees are members of the International
Brotherhood of Electrical Workers (IBEW) Local 2100 which represents
approximately 60% of LG&E's workforce. On December 10, 1998, LG&E and IBEW
employees entered into a three-year collective bargaining agreement following a
vote by IBEW members which ratified the contract providing for certain wage and
benefit improvements, and opportunities for early retirement. KU's operation and
maintenance employees are members of the IBEW Local 101 and United Steelworkers
of America (USWA) Local 8686. KU has approximately 15% of its workforce covered
by union contracts expiring August 1, 1999. In September 1998, WKE and
approximately 350 WKE employees entered into a three-year collective bargaining
agreement providing for, among other things, annual wage increases and fixed
pension benefits.

NOTE 8 - INVESTMENTS IN UNCONSOLIDATED VENTURES

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

                                      103

<PAGE>

The fuel type, ownership percentages and carrying amounts of the unconsolidated
ventures as of December 31, 1998 are summarized as follows (in thousands of $):

<TABLE>
<CAPTION>
                                                                                                               Carrying
                                                                         Fuel Type            % Owned            Amount
                                                                         ---------            -------          --------
<S>                                                                    <C>                     <C>             <C>
         LG&E Westmoreland - Southampton                                      Coal                 50          $ 13,784
         LG&E Westmoreland - Altavista                                        Coal                 50            12,669
         LG&E Westmoreland - Hopewell                                         Coal                 50            11,330
         LG&E Westmoreland - Rensselaer                                Natural Gas                 50            23,023
         Westmoreland - LG&E Partners                                         Coal                 50            25,141
         Windpower Partners 1993                                              Wind                 50            21,345
         Windpower Partners 1994                                              Wind                 25                 -
         KW Tarifa, S.A.                                                      Wind                 46             5,999
         Distribuidora de Gas Cuyana                                             -                 14            44,531
         Tenaska Limited Partnerships                                          Gas               5-10             7,899
         Electric Energy, Inc. (Note 18)                                      Coal                 20             2,156
                                                                                                               --------
         Total                                                                                                 $167,877
                                                                                                               --------
                                                                                                               --------
</TABLE>

The Company's carrying amount exceeded the underlying equity in unconsolidated
ventures by $33.3 million and $32.9 million at December 31, 1998 and 1997,
respectively. This difference, which is being amortized, represents adjustments
to reflect the fair value of the underlying net assets acquired and related
goodwill.

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 Windpower Partners 1993 and Windpower Partners 1994 (WPP94)
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 WPP94 of $3.8 million.
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 Power Purchase Agreement
between Tenaska Washington Partners II, L.P. and the Bonneville Power
Administration (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 Master
Restructuring Agreement (MRA) with Niagara Mohawk Power Corporation (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% ownership in the Rensselaer facility. As a result of these transactions, the
Company recorded a $21 million, net after-tax gain in 1998. 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-

                                      104

<PAGE>

tax charge to 1998 earnings.

NOTE 9 - LEVERAGED LEASES

Capital Corp. owns equity interests in several leveraged leases for combustion
turbine units leased to utility companies. The leases expire in 1999 at which
time the Company will release, sell or reacquire these assets. Capital Corp.'s
equity investment represents 75% of the aggregate purchase price of the leases.
The remaining 25% represents the non-recourse debt provided by lenders at the
inception of the leases in 1974. The lenders have been granted, as their sole
remedy in the event of default by the lessees, an assignment of rentals due
under the leases and a security interest in the leased properties.

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

<TABLE>
<CAPTION>
                                                                                           1998              1997
                                                                                           ----              ----
<S>                                                                                    <C>               <C>
         Rents receivable (net of nonrecourse debt)                                    $  1,556          $  3,039
         Estimated residual value of leased property                                     32,707            32,707
         Less:  unearned and deferred income                                              3,319             7,594
                                                                                       --------          --------
         Investment in leveraged leases                                                  30,944            28,152
         Less:  accumulated deferred income taxes                                         7,301             5,750
                                                                                       --------          --------
         Net investment in leveraged leases                                             $23,643           $22,402
                                                                                       --------          --------
                                                                                       --------          --------
</TABLE>

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

NOTE 10 - NON-RECURRING CHARGES

Under certain agreements with Tenaska, Inc., a developer of domestic gas-fired
cogeneration and independent power generation projects, the Company has been
funding a portion of the costs associated with identifying and pursuing
potential independent power projects in North America. Such funding, which was
expensed as incurred, totaled about $1 million in 1997. In 1996, the Company
wrote off $5.5 million of costs funded during 1994-1996 that was associated with
unsuccessful projects. As of December 31, 1998, the Company has no remaining
funding commitment.

                                      105

<PAGE>


NOTE 11 - MARKETABLE SECURITIES

The Company's marketable securities have been determined to be
"available-for-sale" under the provisions of Statement of Financial Accounting
Standards SFAS No. 115, Accounting for Certain Investments in Debt and Equity
Securities. Proceeds from sales of available-for-sale securities in 1998 were
approximately $20 million, which resulted in realized gains of approximately $.2
million and losses of approximately $.7 million, calculated using the specific
identification method. Proceeds from sales of available-for-sale securities in
1997 were approximately $5 million, which resulted in immaterial realized gains
and losses.

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

<TABLE>
<CAPTION>
                                                                                          Fixed
                                                                        Equity           Income             Total
                                                                        ------           ------             -----
<S>                                                                     <C>             <C>               <C>
         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
              Five to ten years                                              -                -                 -
              Over ten years                                                 -            1,706             1,706
              Not due at a single maturity date                              -                -                 -
                                                                        ------          -------           -------
         Total fair values                                              $6,816          $14,046           $20,862
                                                                        ------          -------           -------
                                                                        ------          -------           -------
         1997:
         -----
         Cost                                                           $6,379          $15,615           $21,994
         Unrealized gains                                                  445               18               463
         Unrealized losses                                                 (90)             (67)             (157)
                                                                        ------          -------           -------
         Fair values                                                    $6,734          $15,566           $22,300
                                                                        ------          -------           -------
                                                                        ------          -------           -------
         Fair values:
           No maturity                                                  $6,734          $   114           $ 6,848
           Contractual maturities:
              Less than one year                                             -            8,795             8,795
              One to five years                                              -            5,442             5,442
              Five to ten years                                              -                -                 -
              Over ten years                                                 -            1,215             1,215
              Not due at a single maturity date                              -                -                 -
                                                                        ------          -------           -------
         Total fair values                                              $6,734          $15,566           $22,300
                                                                        ------          -------           -------
                                                                        ------          -------           -------
</TABLE>

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 

                                      106

<PAGE>

ending December 31, 1998 and a statement of the funded status as of December 
31 for each of the last three years (in thousands of $):

<TABLE>
<CAPTION>
                                                                          1998             1997              1996
                                                                          ----             ----              ----
<S>                                                                   <C>              <C>               <C>
         Pension Plans:
         --------------
         Change in benefit obligation
           Benefit obligation at beginning of year                    $499,143         $432,551          $397,155
           Service cost                                                 14,242           12,675            11,965
           Interest cost                                                35,715           32,927            31,132
           Plan amendments                                               6,377            3,143            19,186
           Acquisitions/divestitures                                    (2,243)               -                 -
           Curtailment (gain) or loss                                     (364)               -                 -
           Special termination benefits                                 23,965                -                 -
           Benefits paid                                               (23,823)         (22,114)          (16,811)
           Actuarial (gain) or loss                                      5,629           39,961           (10,076)
                                                                      --------         --------          --------
           Benefit obligation at end of year                          $558,641         $499,143          $432,551
                                                                      --------         --------          --------
                                                                      --------         --------          --------

         Change in plan assets
           Fair value of plan assets at beginning of year             $501,361         $432,612          $389,303
           Actual return on plan assets                                 70,631           81,645            53,713
           Employer contributions                                        2,638           10,101             7,139
           Benefits paid                                               (23,823)         (22,114)          (16,811)
           Administrative expenses                                         (96)            (883)             (732)
                                                                      --------         --------          --------
           Fair value of plan assets at end of year                   $550,711         $501,361          $432,612
                                                                      --------         --------          --------
                                                                      --------         --------          --------
         Reconciliation of funded status
           Funded status                                              $ (7,930)        $  2,218          $     61
           Unrecognized actuarial (gain) or loss                       (96,368)         (79,891)          (77,495)
           Unrecognized transition (asset) or obligation                (9,059)         (10,358)          (11,587)
           Unrecognized prior service cost                              47,286           48,064            49,054
                                                                      --------         --------          --------
           Net amount recognized at year-end                          $(66,071)        $(39,967)        $ (39,967)
                                                                      --------         --------          --------
                                                                      --------         --------          --------
         Other Benefits:
         ---------------
         Change in benefit obligation
           Benefit obligation at beginning of year                    $115,894         $106,743          $101,667
           Service cost                                                  2,870            2,633             2,661
           Interest cost                                                 8,255            7,860             7,746
           Plan amendments                                                 613                -             4,120
           Acquisitions/divestitures                                     2,283                -                 -
           Curtailment (gain) or loss                                    3,584                -                 -
           Special termination benefits                                  2,855                -                 -
           Benefits paid                                                (5,260)          (6,648)           (6,535)
           Actuarial (gain) or loss                                     (3,501)           5,306            (2,917)
                                                                      --------         --------          --------
           Benefit obligation at end of year                          $127,593         $115,894          $106,742
                                                                      --------         --------          --------
                                                                      --------         --------          --------
         Change in plan assets
           Fair value of plan assets at beginning of year             $ 22,192         $ 15,568          $ 10,427
           Actual return on plan assets                                  5,313            3,649             1,582
           Employer contributions                                        7,056            7,577             6,037
           Benefits paid                                                (4,077)          (4,602)           (2,478)
           Administrative expenses                                           -                -                 -
                                                                      --------         --------          --------
           Fair value of plan assets at end of year                   $ 30,484         $ 22,192          $ 15,568
                                                                      --------         --------          --------
                                                                      --------         --------          --------
</TABLE>

                                      107

<PAGE>

<TABLE>
<CAPTION>
                                                                          1998             1997              1996
                                                                          ----             ----              ----
<S>                                                                   <C>              <C>               <C>
         Reconciliation of funded status
           Funded status                                              $(97,109)        $(93,702)         $(91,175)
           Unrecognized actuarial (gain) or loss                       (20,115)         (16,730)          (19,477)
           Unrecognized transition (asset) or obligation                63,834           70,230            74,912
           Unrecognized prior service cost                               3,572            3,456             3,787
                                                                      --------         --------          --------
           Net amount recognized at year-end                          $(49,818)        $(36,746)         $(31,953)
                                                                      --------         --------          --------
                                                                      --------         --------          --------
</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 statement of
financial position and information for plans with benefit obligations in excess
of plan assets as of December 31, 1998, 1997 and 1996 (in thousands of $):

<TABLE>
<CAPTION>
                                                                          1998             1997              1996
                                                                          ----             ----              ----
<S>                                                                   <C>              <C>               <C>
         Pension Plans:
         --------------
         Amounts recognized in the balance sheet consisted of:
              Accrued benefit liability                               $(67,126)        $(40,296)         $(40,032)
              Intangible asset                                             426              281                65
              Other                                                        706              710                 -
                                                                      --------         --------          --------
              Net amount recognized at year-end                       $(65,994)        $(39,305)         $(39,967)
                                                                      --------         --------          --------
                                                                      --------         --------          --------

         Additional year-end information for plans with benefit
           obligations in excess of plan assets:
              Projected benefit obligation (1)                        $163,722         $138,492          $120,254
              Accumulated benefit obligation (2)                       142,941           11,879            14,656
              Fair value of plan assets (1)                            111,914          102,775            84,555

              (1) All years include LG&E's non-union plan, Energy Corp.'s plan and all of the Company's unfunded 
                  Supplemental Executive Retirement Plans (SERPs).

              (2) 1998 includes LG&E's non-union plan, Energy Corp.'s plan and all SERPs.  1997 and 1996 include 
                  SERPs only.

         Other Benefits:
         ---------------
         Amounts recognized in the balance sheet consisted of:
              Accrued benefit liability                               $(49,818)        $(36,746)         $(31,953)
              Intangible asset                                               -                -                 -
              Other                                                     (4,421)          (4,166)                -
                                                                      --------         --------          --------
              Net amount recognized at year-end                       $(54,239)        $(40,912)         $(31,953)
                                                                      --------         --------          --------
                                                                      --------         --------          --------
         Additional year-end information for plans with benefit 
           obligations in excess of plan assets:
              Projected benefit obligation                            $127,593         $115,894          $106,743
              Fair value of plan assets                                 30,484           22,192            15,568
</TABLE>

                                      108

<PAGE>


The following table provides the components of net periodic benefit cost for the
plans for 1998, 1997 and 1996 (in thousands of $):

<TABLE>
<CAPTION>

                                                                          1998             1997              1996
                                                                          ----             ----              ----
<S>                                                                 <C>               <C>               <C>
         Pension Plans:
         --------------
         Components of net periodic benefit cost
           Service cost                                             $   14,242        $  12,675         $  11,965
           Interest cost                                                35,715           32,927            31,132
           Expected return on plan assets                              (42,278)         (35,511)          (32,320)
           Amortization of prior service cost                            4,421            4,133             3,911
           Amortization of transition (asset) or obligation             (1,224)          (1,229)           (1,229)
           Recognized actuarial (gain) or loss                          (2,248)          (2,854)           (2,031)
                                                                    ----------        ---------         ---------
           Net periodic benefit cost                                $    8,628        $  10,141         $  11,428
                                                                    ----------        ---------         ---------
                                                                    ----------        ---------         ---------
         FAS88 special charges
           Curtailment (gain)/loss                                  $   (2,204)       $       -         $       -
           Prior service cost recognized                                 2,015                -                 -
           Special termination benefits                                 23,965                -                 -
                                                                    ----------        ---------         ---------
           Total FAS88 charges                                       $  23,776        $       -         $       -
                                                                    ----------        ---------         ---------
                                                                    ----------        ---------         ---------
         Other Benefits:
         ---------------
         Components of net periodic benefit cost
           Service cost                                             $    2,870        $   2,633         $   2,662
           Interest cost                                                 8,255            7,860             7,746
           Expected return on plan assets                               (1,722)          (1,204)             (827)
           Amortization of prior service cost                              373              332               332
           Amortization of transition (asset) or obligation              4,621            4,682             4,682
           Recognized actuarial (gain) or loss                            (467)            (810)             (704)
                                                                    ----------        ---------         ---------
           Net periodic benefit cost                                $   13,930        $  13,493         $  13,891
                                                                    ----------        ---------         ---------
                                                                    ----------        ---------         ---------
         FAS88 special charges
           Curtailment (gain)/loss                                  $    2,243        $       -         $       -
           Special termination benefits                                  2,855                -                 -
                                                                    ----------        ---------         ---------
           Total FAS88 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. On May 30, 1997,
$4.7 million in lump sum payments were made to retired employees of KU Energy
due to a change-in-control provision in the provisions of the Supplemental
Security Plan of the Merger Agreement.

                                      109

<PAGE>


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

<TABLE>
<CAPTION>
                                                                          1998             1997              1996
                                                                          ----             ----              ----
<S>                                                                <C>              <C>               <C>
         Weighted-average assumptions as of December 31
           Discount rate                                                 7.00%            7.00%             7.75%
           Expected long-term rate of return on plan assets (1)    8.25%-8.50%      8.25%-8.50%       8.25%-8.50%
           Rate of compensation increase (2)                       3.50%-4.00%      2.00%-4.00%       2.00%-4.75%
</TABLE>

(1)  All plans used 8.50% except KU's.
(2)  All plans used 4.00% except LG&E's union plan which used 3.50% for
     1998 and 2.00% for 1997. Rate of compensation increase for 1996
     was 2.00% for LG&E's union plan, 4.25% for LG&E and 4.75% for KU.

For measurement purposes, a 7% annual increase in the per capita cost of covered
health care benefits was assumed for 1999. The rate was assumed to decrease
gradually to 4.25% 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:

<TABLE>
<CAPTION>
                                                                                      1% Change
<S>                                                                                   <C>
         Effect on total of service and interest cost components for 1998             $  (1,214)
         Effect on year-end 1998 postretirement benefit obligations                     (11,752)
         Effect on total of service and interest cost components for 1998                 1,544
         Effect on year-end 1998 postretirement benefit obligations                      15,197
</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 were
approximately $6.0 million, $4.7 million and $4.2 million for 1998, 1997 and
1996, respectively.

NOTE 13 - INCOME TAXES

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

<TABLE>
<CAPTION>
                                                                          1998             1997              1996
                                                                          ----             ----              ----
<S>                                                                   <C>              <C>               <C>
         Included in Income Taxes:
           Current         - federal                                  $114,741         $ 88,654          $ 52,018
                           - foreign                                    12,208            9,055                 -
                           - state                                      23,821           19,574             1,725
           Deferred        - federal - net                             (25,605)           9,024            36,848
                           - state - net                                (5,255)           1,292            18,741
         Deferred investment tax credit                                      -              102               409
         Amortization of investment tax credit                          (8,087)          (8,378)           (8,419)
                                                                      --------         --------          --------
         Total                                                        $111,823         $119,323          $101,322
                                                                      --------         --------          --------
                                                                      --------         --------          --------
</TABLE>

                                      110

<PAGE>

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

<TABLE>
<CAPTION>
                                                                          1998             1997
                                                                          ----             ----
<S>                                                                   <C>              <C>
         Deferred tax liabilities:
           Depreciation and other
              plant-related items                                     $632,593         $670,540
           Other liabilities                                            39,966           43,199
                                                                      --------         --------
                                                                       672,559          713,739
                                                                      --------         --------
         Deferred tax assets:
           Investment tax credit                                        37,878           41,142
           Income taxes due to customers                                43,021           45,574
           Deferred income                                              11,626           11,878
           Accrued expenses not currently
              deductible and other                                      59,313           66,668
                                                                      --------         --------
                                                                       151,838          165,262
                                                                      --------         --------
         Net deferred income tax liability                            $520,721         $548,477
                                                                      --------         --------
                                                                      --------         --------
</TABLE>

At December 31, 1998, there were $116 million of net operating loss
carryforwards related to discontinued operations. These carryforwards, which
expire in years 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 both December 31, 1998 and 1997, the Company recorded
valuation allowances of $25.6 million, related to these deferred tax assets.
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>
                                                                          1998             1997              1996
                                                                          ----             ----              ----
<S>                                                                       <C>              <C>               <C>
         Statutory federal income tax rate                                35.0%            35.0%             35.0%
         State income taxes net of federal benefit                         4.4              3.9               4.7
         Effect of foreign operations including foreign tax credit         1.8              1.1                 -
         Investment and other tax credits                                 (3.6)            (3.1)             (3.6)
         Nondeductible merger expenses                                     4.7                -                 -
         Other differences - net                                          (2.2)            (1.1)             (2.2)
                                                                          ----             ----             -----
         Effective income tax rate                                        40.1%            35.8%             33.9%
                                                                          ----             ----             -----
                                                                          ----             ----             -----
</TABLE>

                                      111

<PAGE>


NOTE 14 - OTHER INCOME AND DEDUCTIONS

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

<TABLE>
<CAPTION>
                                                                          1998             1997              1996
                                                                          ----             ----              ----
<S>                                                                   <C>              <C>               <C>
         Income from leveraged leases                                 $  4,273         $  3,974          $  3,613
         Interest and dividend income                                   10,552           11,605             8,765
         Gains (losses) on disposals - net                              (4,942)           7,083                51
         Other                                                          (2,432)          (1,692)             (854)
                                                                      --------         --------          --------
         Total other income and (deductions)                          $  7,451         $ 20,970          $ 11,575
                                                                      --------         --------          --------
                                                                      --------         --------          --------
</TABLE>

NOTE 15 - CAPITAL STOCK

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

<TABLE>
<CAPTION>
                                                                          1998             1997              1996
                                                                          ----             ----              ----
<S>                                                                    <C>              <C>               <C>
         Outstanding January 1                                         129,683          129,497           129,350
         Issues under the Employee
           Common Stock Purchase
           Plan (1997, $1,613;
           1996, $1,457)                                                     -               77                78
         Issues under the Omnibus
           Long-Term Incentive Plan
           (1997, $2,195; 1996, $1,167)                                      -              109                69
         Merger-related buy-back of
           fractional shares                                                (6)               -                 -
                                                                       -------          -------           -------
         Outstanding December 31                                       129,677          129,683           129,497
                                                                       -------          -------           -------
                                                                       -------          -------           -------
</TABLE>

The Company's shareholders approved an increase in the Company's authorized 
shares of common stock from 125,000,000 to 300,000,000 on October 14, 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. A total of 3,000,000 shares of common stock have been reserved
for issuance 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 have been
reserved for issuance 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. Although shares are reserved as described above, the
Company announced a repurchase program on October 14, 1997, authorizing the
repurchase of up to 1,000,000 shares of its common stock to be used for, among
other things, benefit and compensation plans, including the Omnibus Long-Term
Incentive Plan.

                                      112

<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, 1995            513,550       18.04      332,386         17.26
   Options granted and                                                            
      exercisable                   415,348       21.24      158,914         19.57
   Options exercised                (48,226)      17.26      (48,226)        17.26
   Options cancelled                (16,328)      21.01            -             -
                                  ---------      ------      -------        ------
 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
                                  ---------      ------      -------        ------
                                  ---------      ------      -------        ------
</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 in the year 2000.

In December 1997, Inversora de Gas del Centro (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.

NOTE 16 - LONG-TERM DEBT

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. It is the intent of LG&E to apply property
additions to meet 1999 sinking fund requirements of the First Mortgage Bonds.

                                   113


<PAGE>


The trust indenture securing the First Mortgage Bonds constitutes a direct first
mortgage lien upon a substantial portion of all property owned by LG&E. The
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.

Pollution Control Bonds (LG&E Projects) issued by Jefferson and Trimble
Counties, Kentucky, are secured by the assignment of loan payments by LG&E to
the Counties pursuant to loan agreements, and certain series are further secured
by the delivery from time to time of an equal amount of LG&E's First Mortgage
Bonds, Pollution Control Series. First Mortgage Bonds so delivered are
summarized in the Statements of Capitalization. No principal or interest on
these First Mortgage Bonds is payable unless default on the loan agreements
occurs. The interest rate reflected in the Statements of Capitalization applies
to the Pollution Control Bonds.

On June 1, 1998, LG&E's First Mortgage Bonds, 6.75% Series of $20 million
matured and were retired by the Company.

In November 1997, LG&E issued $35 million of Jefferson County, Kentucky and $35
million of Trimble County, Kentucky, Pollution Control Bonds, Flexible Rate
Series, due November 1, 2027. Interest rates for these bonds were 3.09% and
3.39%, respectively, at December 31, 1998. The proceeds from these bonds were
used to redeem the outstanding 7.75% Series of Jefferson County, Kentucky and
Trimble County, Kentucky, Pollution Control Bonds due February 1, 2019.

LG&E's First Mortgage Bonds, 7.5% Series of $20 million is scheduled to mature
in 2002, and the $42.6 million, 6% Series is scheduled for maturity in 2003.
There are no scheduled maturities of Pollution Control Bonds for the five years
subsequent to December 31, 1998. The Company has no cash sinking fund
requirements.

Under the provisions for the KU's variable rate Pollution Control Bonds Series
10, KU can choose between various interest rate options. The daily interest rate
option was utilized at December 31, 1998. The average annual interest rate on
the bonds during 1998 and 1997 was 3.54% and 3.77%, respectively. The variable
rate 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. If tendered
bonds are not remarketed, KU has available lines of credit which may be used to
repurchase the bonds.

Substantially all of KU's utility plant is pledged as security for its first
mortgage bonds.

Capital Corp. has established a $500 million medium-term note program. On
November 3, 1998, Capital Corp. issued $150 million of Reset Put Securities due
2011. The interest rate is set at 5.75% through November 1, 2001. The securities
will be subject to automatic purchase by a remarketing agent, at which time the
interest rate will be reset, or to automatic repurchase by Capital Corp., on
November 1, 2001. After taking into account the net effect of the derivative
instruments entered into in September 1998 to hedge the interest rate on the
notes and other issuance costs, the effective rate through October 31, 2001, is
approximately 5.4%. The proceeds were used to repay a portion of Capital Corp.'s
outstanding commercial paper. In February 1998, Capital Corp. issued $150
million of medium-term notes due in January 2008, with a stated interest rate on
the notes of 6.46%. After taking into account the effects of an interest-rate
swap entered into in 1997 to hedge the interest rate on $100 million (See Note
6, Financial Instruments) and other issuance costs, the effective rate will be
6.82%. The proceeds were used to repay outstanding commercial paper.

                                   114


<PAGE>


Centro maintains a $100 million global note program. As of December 31, 1998 and
1997, Centro had outstanding $37.6 million in negotiable obligations, net of
issuance costs as part of this program. The maturity date of the debt is August
21, 2001. Interest is paid semi-annually based upon a fixed rate of 10.5%.

NOTE 17 - NOTES PAYABLE
 Capital Corp. had outstanding commercial paper of $365.1 million at December 
31, 1998, at a weighted-average interest rate of 5.19%.  The Company had no 
other notes payable at December 31, 1998.  Capital Corp. had notes payable of 
$360.2 million at December 31, 1997, at a weighted-average interest rate of 
5.79%.

KU's short-term financing requirements are satisfied through the sale of
commercial paper. KU had no short-term borrowings at December 31, 1998. KU had
outstanding commercial paper of $33.6 million at December 31, 1997, at a
weighted-average interest rate of 6.79%.

At December 31, 1998, the Company had lines of credit in place totaling $960
million ($200 million for LG&E, $60 million for KU, and $700 million for Capital
Corp.) for which the Companies pays commitment or facility fees. The LG&E credit
facility provides for short-term borrowing. KU credit facilities provide for
short-term borrowing and support of commercial paper borrowing. 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 $536.8 million after considering the commercial paper support and
approximately $58.1 million in letters of credit securing on- and off-balance
sheet commitments. The credit lines will expire at various times from 1999
through 2002. Management expects to renegotiate the lines when they expire.

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.

On September 5, 1997, Energy Systems and Gas Systems merged to form Capital 
Corp. At the same time, Capital Corp. implemented a $600 million commercial 
paper facility backed by new lines of credit totaling $700 million.  The 
Company terminated the previous lines of credit which totaled $460 million.

NOTE 18 - COMMITMENTS AND CONTINGENCIES

CONSTRUCTION PROGRAM

The Company had commitments, primarily in connection with the construction
program of LG&E and KU, aggregating approximately $15 million at December 31,
1998. LG&E's construction expenditures for the years 1999 and 2000 are estimated
to total approximately $384 million. KU's construction expenditures for the same
period are estimated to total approximately $341 million. Non-utility
construction expenditures for the same two-year period are estimated to be $68
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 $30.7 million and $38.3 million at December 31, 1998 and 1997,
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 $7.6 million

                                   115


<PAGE>


and $10.2 million at December 31, 1998 and 1997, respectively.

PROJECT CONTINGENCIES

SOUTHAMPTON. In October 1998, LG&E-Westmoreland Southampton and Virginia
Electric and Power Company (VEPCO) entered into a settlement agreement which
resolved issues pending before the FERC regarding the status of the Southampton
cogeneration facility (Southampton) as a qualifying facility (QF) under the
Public Utility Regulatory Policies Act 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. The Company and its
partners are currently negotiating these matters. The Company does not believe
that the disputes with its partners will have a material adverse effect on its
results of operations or financial condition.

ROANOKE VALLEY I. The Company owns a 50% interest in Westmoreland-LG&E Partners
(WLP), the owner of the Roanoke Valley I facility which sells electric power to
VEPCO pursuant to a long-term power purchase agreement (PPA). From May 1994
through December 1998, VEPCO withheld approximately $14.8 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 regarding the Circuit Court
decision. Pending resolution of all appeals by VEPCO, the Company has not
recognized any income on its 50% portion of the capacity payments 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.

RENSSELAER. In November 1998, LG&E Westmoreland-Rensselaer (LWR), in which the
Company has a 50% interest, entered into a non-binding letter of intent for the
sale of the assets of the Rensselaer cogeneration facility. The proposed sale is
subject to a number of contingencies, including satisfactory completion of
certain due diligence, corporate approvals by buyer and seller parties, receipt
of all necessary regulatory and third party approvals and consents and other
matters. Should all conditions precedent be satisfied or waived, a sale is
scheduled for early 1999.

KENETECH BANKRUPTCY. In May 1996, Kenetech Windpower, Inc. (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 Windpower Partners 1993 (WPP 93),
Windpower Partners 1994 (WPP 94) and KW Tarifa, S.A. (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

                                   116


<PAGE>


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 
January 1999, the Bankruptcy Court approved an initial plan of 
reorganization. The Plan is subject to a number of filed objections, the 
resolution of which and satisfaction of other conditions precedent are 
required prior to initial distributions currently planned for the first 
quarter 1999.

The projects are discussing with their creditors the allocation of any such
distributions. The Company is unable to predict the outcome of these
proceedings. However, the Company does not expect the ultimate resolution of the
bankruptcy to have a material adverse effect on its results of operations or
financial condition.

WINDPOWER PARTNERS 1994. WPP 94 is a windpower generation facility in Texas, in
which the Company has a 25% interest. WPP 94 did not make its semiannual
payments, due September 1997, March 1998 and September 1998 to John Hancock
Mutual Life Insurance Company (Hancock) under certain Notes issued by WPP 94 to
Hancock. WPP 94 and Hancock 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 does not expect the ultimate resolution of this matter
to have a material effect on its results of operations or financial condition.

GREGORY. 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.

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 occurred in 1998. 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.

SPRINGFIELD MUNICIPAL CONTRACT. In July 1998, LEM filed suit in the United
States District Court for the Western District of Kentucky in Louisville,
against the City of Springfield, Illinois, City Water, Light and Power Company
(Springfield CWLP). The action seeks damages for Springfield CWLP's failure,
including in late June 1998, to sell electric energy to LEM pursuant to a
February 1997 Interchange Agreement and transaction confirmations thereunder, as
well as for other related claims. LEM has estimated that its damages in this
matter may be approximately $21 million. The parties have commenced discovery
which is scheduled to continue into late 1999.

OGLETHORPE POWER CONTRACT. In November 1996, the Company, through LEM, entered
into a 15-year agreement with OPC to supply approximately one-half of OPC's
systemwide power needs during the term of the agreement and with rights to
market OPC's surplus power. The Company has been in settlement negotia-

                                   117


<PAGE>


tions with OPC over load projections provided by OPC as an inducement for LEM 
to enter into the 1996 agreement. In October 1998, LEM initiated an 
arbitration proceeding against OPC related to these load projections. Final 
selection of the arbitration panel is expected to occur in the first quarter 
of 1999. See also Discontinuance of Merchant Energy Trading and Sales 
Business in Management's Discussion and Analysis of Operations and Financial 
Condition.

OPERATING LEASES

The Company leases office space, office equipment and vehicles. See also Note 4
for discussion of the Big Rivers Electric Corporation operating lease. The
Company accounts for these leases as operating leases. Total lease expense for
1998, 1997 and 1996, was $21.7 million, $6.7 million and $7.8 million,
respectively. The future minimum annual lease payments under lease agreements
for years subsequent to December 31, 1998 are as follows (in thousands of $):

<TABLE>
                 <S>                     <C>
                 1999                     $  5,650
                 2000                       19,926
                 2001                       36,669
                 2002                       37,072
                 2003                       36,574
                 Thereafter                627,073
                                          --------
                 Total                    $762,964
                                          --------
                                          --------
</TABLE>

Future minimum annual lease payments have been reduced by rental payments to be
received from noncancelable subleases of approximately $1.8 million per year
through 1999 and 2000, and $1.3 million in 2001.

ENVIRONMENTAL

In September 1998, the U.S. Environmental Protection Agency (USEPA) announced
its final regulation requiring significant additional reductions in NOx
emissions to mitigate alleged ozone transport to the Northeast. While each state
is free to allocate its assigned NOx reductions among various emissions sectors
as it deems appropriate, the regulation may ultimately require utilities to
reduce their NOx emissions to 0.15 lb./mmBtu-an 85% reduction from 1990 levels.
Under the regulation, each state must incorporate the additional NOx reductions
in its State Implementation Plan (SIP) by September 1999 and affected sources
must install control measures by May 2003, unless granted extensions. Several
states, various labor and industry groups, and individual companies have
appealed the final regulation to the U.S. Court of Appeals for the D.C. Circuit.
Management is currently unable to determine the outcome or exact impact of this
matter until such time as the states identify specific emissions reductions in
their SIPs and the courts rule on the various legal challenges to the final
rule. However, if the 0.15 lb. target is ultimately imposed, LG&E, KU, 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 and analysis, the Company estimates that it may incur
capital costs in the range of $300 million to $500 million in the aggregate for
LG&E, KU, and WKE. 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. The Company
anticipates that such capital and operating costs are the type of costs that are
eligible for cost recovery from customers under its environmental surcharge
mechanisms and believes that, in the cases of LG&E and KU, a significant portion
of such costs could be so recovered. However, Kentucky Commission approval is
necessary and there can be no guarantee of such recovery.

The Company is also addressing other air quality issues. First, the Company is
monitoring USEPA's

                                   118


<PAGE>


implementation of the revised National Ambient Air Quality Standards (NAAQS) 
for ozone and particulate matter. Until USEPA completes additional 
implementation steps, including monitoring and nonattainment designations, 
management is unable to determine the precise impact of the revised 
standards. Second, the Company is conducting modeling activities at LG&E's 
Cane Run Station and WKE's Coleman Station in response to notifications from 
regulatory agencies that those plants may be the source of potential 
exceedances of the NAAQS for SO2. Depending on future regulatory 
determinations, the Company may be required to undertake corrective action 
that could include significant capital expenditures or emissions limitations. 
Third, the Company is working with regulatory authorities to review the 
effectiveness of remedial measures aimed at controlling particulate emissions 
from LG&E's 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 is currently awaiting a final regulatory determination regarding 
remedial measures. In management's opinion, resolution of any remaining 
property damage claims from adjacent residents should not have a material 
adverse impact on the financial position or results of operations of the 
Company.

The Company is addressing potential liabilities for the cleanup of properties
where hazardous substances may have been released. The Company has identified
contamination at certain manufactured gas plant (MGP) sites currently or
formerly owned by the Company. A cleanup has been completed at a site owned by
KU and the Company is negotiating with state agencies with respect to cleanup of
a site owned by LG&E. In addition, several other former MGP sites have been
conveyed to other parties over a substantial period of time. In agreements
reached in 1996 and 1998 with the current owners of two sites formerly owned by
LG&E, the current owners of those sites have expressly agreed to assume
responsibility for environmental liabilities in return for an aggregate payment
of $400,000. Until conclusion of discussions with state agencies regarding the
site currently owned by LG&E and the receipt of additional information on sites
no longer owned by the Company, management is unable to precisely determine
remaining liability for cleanup costs at MGP sites. However, management
estimates total cleanup costs to be approximately $3 million. Accordingly, an
accrual of $3 million has been recorded in the accompanying financial
statements.

LG&E and KU along with other companies have been identified by USEPA as
potentially responsible parties allegedly liable for cleanup of certain off-site
disposal facilities under the Comprehensive Environmental Response Compensation
and Liability Act. LG&E has entered into final settlements for an aggregate of
$150,000 resolving liability in two cases, while KU is currently participating
as a de minimis party in an additional case.

WKE and LPI and subsidiaries are also subject to extensive federal, state and
local environmental laws and regulations governing the operation of various
facilities in which they participate as an owner or managing operator. To the
extent that there have been any developments pursuant to environmental laws and
regulations, such developments have not been material, except as otherwise
disclosed herein.

PURCHASED POWER

KU has purchase power arrangements with Owensboro Municipal Utilities (OMU),
Electric Energy, Inc. (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 1999-2003, which is expected to be approximately 9% 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 $180 million of OMU
bonds outstanding at December 31, 1998. The debt service is allocated to KU
based on its annual allocated share of capacity, which averaged approximately
49% in 1998.

                                   119


<PAGE>


KU has a 20% equity ownership in EEI, which is accounted for on the equity
method of accounting. See Note 8. 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 1999-2003 of various
MW capacities and for varying periods with a maximum entitlement at any time of
282 MW.

The estimated future minimum annual payments under purchased power agreements
for the five years ended December 31, 2003, are as follows (in thousands of $):

<TABLE>
                 <S>                       <C>
                 1999                       $ 34,291
                 2000                         26,712
                 2001                         29,621
                 2002                         29,561
                 2003                         29,670
                                            --------
                 Total                      $149,855
                                            --------
                                            --------
</TABLE>

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 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, Illinois Municipal Electric Agency (IMEA) owns
a 12.12% undivided interest, and Indiana Municipal Power Agency (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       495
</TABLE>

NOTE 20 - SEGMENTS OF BUSINESS AND RELATED INFORMATION

Effective December 31, 1998, the Company adopted Statements of Financial
Accounting Standards 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 Capital Corp.'s non-utility operations. Capital Corp.'s principal
business segments include its independent power operations, WKE and Argentine
gas distribution subsidiaries.

                                   120


<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, and its investment in the Tarifa project in
Spain. The Company acquired its interests in the Argentine gas distribution
companies in February 1997, and it sold its interest in the San Miguel project
in February 1998. Financial data for business segments, revenues by product, and
long-lived assets by geographic area follow (in thousands of $):

<TABLE>
<CAPTION>
                                                                          LG&E CAPITAL CORP.
                                                             -------------------------------------------
                                                                  Inde-             Argentine
                                                                pendent    Western        Gas      Other
                                  LG&E       LG&E         KU      Power   Kentucky    Distri-    Capital        All    Consol-
Year                          Electric        Gas   Electric Operations     Energy     Bution      Corp.   Other (1)    idated
----                          --------        ---   -------- ----------     ------     ------      -----   ---------    ------
<S>                         <C>          <C>      <C>        <C>          <C>        <C>         <C>       <C>        <C>
1998
----
Revenues                    $  658,510   $191,545 $  810,114 $  19,884    $128,519   $148,162    $49,479   $(29,800)  $1,976,413

Depreciation and 
 amortization                   79,867     13,312     86,657     4,633       1,345      8,973      1,759        871      197,417

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     27,176    (15,308)     108,871

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

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

Income taxes                    48,415       (152)    49,444     24,432      2,442     10,030     (5,321)   (17,467)     111,823

Income from continuing 
 operations                     71,536     2,016     70,508     41,608      3,592      5,752     (8,203)   (26,538)      160,271

Total assets                 1,734,221    332,789  1,751,048    163,663    176,166    346,305    120,972    148,104    4,773,268

Construction expenditures      105,837     32,509     91,992      4,242     17,549     14,977     69,478      5,630      342,214

</TABLE>

(1) This column includes eliminations, adjustments and corporate.

<TABLE>
<CAPTION>
                                                                          LG&E CAPITAL CORP.
                                                             -------------------------------------------
                                                                  Inde-             Argentine
                                                                pendent    Western        Gas      Other
                                  LG&E       LG&E         KU      Power   Kentucky    Distri-    Capital        All    Consol-
Year                          Electric        Gas   Electric Operations     Energy     Bution      Corp.   Other (1)    idated
----                          --------        ---   -------- ----------     ------     ------      -----   ---------    ------
<S>                         <C>          <C>      <C>        <C>          <C>        <C>         <C>       <C>        <C>
1997
----
Revenues                    $  615,159   $231,011 $  716,410 $  19,622    $     -    $127,182$    15,671   $     -   $1,725,055

Depreciation and 
 amortization                   79,958     13,062     84,111     1,287          -      7,569         84        478      186,549

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       (893)   (11,084)     119,323

Income from continuing 
 operations                    104,349      4,339     83,457    17,795          -      4,860     (1,461)    (6,299)     207,040

Total assets                 1,728,761    325,864  1,679,676   214,952          -    340,144     15,801    257,746    4,562,944

Construction expenditures       81,713     29,180     94,006        45          -      4,369        147        671      210,131
</TABLE>

(1) This column includes eliminations, adjustments and corporate.

                                   121


<PAGE>



<TABLE>
<CAPTION>
                                                                          LG&E CAPITAL CORP.
                                                             -------------------------------------------
                                                                  Inde-             Argentine
                                                                pendent    Western        Gas      Other
                                  LG&E       LG&E         KU      Power   Kentucky    Distri-    Capital        All    Consol-
Year                          Electric        Gas   Electric Operations     Energy     Bution      Corp.   Other (1)    idated
----                          --------        ---   -------- ----------     ------     ------      -----   ---------    ------
<S>                         <C>          <C>      <C>        <C>          <C>        <C>         <C>       <C>        <C>
1996
----
Revenues                    $  607,160   $214,419 $  711,711 $  17,956    $      -   $    -      $ 9,239   $    (25)  $1,560,460

Depreciation and 
 amortization                   76,929     12,073     80,424      1,308          -          -        250        415      171,399

Interest income                  3,521        576      2,800        127          -          -      1,134        607        8,765

Interest expense                38,488      6,322     41,873     (1,281)         -          -      9,337       (327)      94,412

Equity in unconsolidated 
 ventures                            -          -          -     19,727          -          -          -          -       19,727

Non-recurring charges                -          -          -      5,493          -          -          -          -        5,493

Income taxes                    58,854      4,812     47,206      4,522          -          -     (6,146)    (7,926)     101,322

Income from continuing 
 operations                     96,197      7,176     83,907     10,337          -          -       (963)    (6,268)     190,386

Total assets                 1,709,942    294,444  1,672,954    214,421          -          -     21,122    219,716    4,132,599

Construction expenditures       79,541     28,338    106,582      1,080          -          -         74        339      215,954

</TABLE>

(1) This column includes eliminations, adjustments and corporate.


Revenue By Product:

<TABLE>
<CAPTION>
                                                            Asset-Based
                                      Retail        Retail       Energy
Year                                Electric           Gas    Marketing        Other       Totals

<S>                               <C>             <C>          <C>           <C>       <C>
1998                              $1,189,185      $339,707     $390,567      $56,954   $1,976,413

1997                               1,173,275       358,193      158,294       35,293    1,725,055

1996                               1,153,039       214,419      165,832       27,170    1,560,460
</TABLE>

Long-Lived Assets By Geographic Area:

<TABLE>
<CAPTION>
                                         Inter-
Year                      Domestic     national       Totals

<S>                     <C>            <C>        <C>
1998                    $3,691,554     $299,444   $3,990,998

1997                     3,451,437      360,106    3,811,543

1996                     3,441,488       25,089    3,466,577
</TABLE>

                                   122


<PAGE>


NOTE 21 - SELECTED QUARTERLY DATA (UNAUDITED)

Selected financial data for the four quarters of 1998 and 1997 are shown below.
Because of seasonal fluctuations in temperature and other factors, results for
quarters may fluctuate throughout the year.

<TABLE>
<CAPTION>
(Thousands of $ except per share data)                               Quarters Ended
                                                   March           June       September      December
                                                   -----           ----       ---------      --------
<S>                                            <C>            <C>             <C>            <C>
1998
----
Revenues                                       $ 450,724      $ 441,137       $ 603,855      $ 480,697
Operating income                                  94,850         73,650         158,583         56,884
Net income (loss):
Continuing operations                             46,674         13,294 (a)      79,512         20,791(b)
Discontinued operations                           (3,506)       (20,093)              -              -
Loss on disposal of discon-
  tinued operations                                    -       (225,000)              -              -
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)          (.15)              -              -
Loss on disposal of discon-
  tinued operations                                    -          (1.74)              -              -
Cumulative effect of account-
  ing change                                        (.06)             -               -              -
                                                --------      ---------       ---------      ---------
     Total                                           .28          (1.79)            .61            .16

1997
----
Revenues                                       $ 423,073      $ 388,538       $ 461,512      $ 451,932

Operating income                                  96,090         75,945         143,124        103,696
Net income (loss):
Continuing operations                             47,530         32,784          70,869         55,857
Discontinued operations                           (1,428)           883         (15,123)        (8,376)
                                                --------      ---------       ---------      ---------
  Total                                           46,102         33,667          55,746         47,481

Earnings per share of common 
 stock (basic and diluted):
Continuing operations                                .37            .25             .55            .43
Discontinued operations                             (.01)           .01            (.12)          (.06)
                                                   -----            ---           -----          -----
  Total                                              .36            .26             .43            .37
</TABLE>

(a) The decrease of $20.4 million compared to June 1997 was due to an 
after-tax charge of $56.4 million from merger-related expenses, offset by an 
increase in our core utility business of approximately $13.0 million and the 
consummation of the MRA with NIMO resulting in a $21.0 million gain.

(b) The decrease of $26.7 million compared to December 1997 was due to an 
after-tax charge of $15.6 million related to refunds of certain amounts 
collected under the environmental cost recovery surcharge, warmer weather and 
higher utility operating expenses.

                             123


<PAGE>


NOTE 22 - SUBSEQUENT EVENT

On March 8, 1999, the Kentucky Industrial Utility Customers (KIUC) filed a
separate complaints with the Kentucky Commission alleging that LG&E's and KU's
electric rates are excessive and should be reduced by an amount between $85 and
$146 million and that the Kentucky Commission establish a proceeding to reduce
LG&E's and KU's electric rates. LG&E and KU have asked the Kentucky Commission
to dismiss the complaint. The Company is not able to predict the ultimate
outcome of these proceedings, however, should the Commission mandate significant
rate reductions at LG&E and KU, through the PBR proposal or otherwise, such
actions could have a material effect on LG&E's and KU's financial condition and
results of operations.

On March 11, 1999, the Commission denied LG&E's Petition for Rehearing for the
period November 1994 through October 1996 and directed LG&E to reduce future
fuel expense by $1.9 million in the first billing month after the Order. The
Company is considering the filing of an Appeal with the Franklin Circuit Court.
In a separate series of Orders on March 11,1999, the PSC granted LG&E's Petition
for Rehearing for the period November 1996 through April 1998 and established a
procedural schedule for LG&E and other parties to submit evidence and for a
hearing before the Commission. In the same Orders the PSC granted the Petition
for Rehearing of the KIUC to determine if interest should be paid on any fuel
refunds for this latter period.

On March 15, 1999, LG&E Westmoreland - Rensselaer, in which the Company has a
50% interest, sold the assets of the Rensselaer cogeneration facility. This
transaction will result in a pre-tax gain for the Company of approximately $14.5
million.

                                   124


<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, 1998, 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.

                                   125


<PAGE>


                                LG&E Energy Corp.
                    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, 1998 and 1997, 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, 1998. 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 generally accepted auditing
standards. 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, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted accounting principles.

As explained in Notes 1 and 3 to the consolidated financial statements,
effective January 1, 1998, the Company changed its method of accounting for
start-up costs and effective January 1, 1996, the Company changed its method of
accounting for price risk management activities.

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 27, 1999 (Except with respect 
to the matters discussed in the 
eighth and ninth paragraphs of Note 
5, as to which the date is February 
12, 1999, and Note 22, as to which 
the date is March 15, 1999.)

                                   126


<PAGE>


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

<TABLE>
<CAPTION>
                                                                                          Years Ended December 31
                                                                                   1998               1997              1996
                                                                                   ----               ----              ----

<S>                                                                           <C>                <C>               <C>
OPERATING REVENUES:
    Electric..........................................................        $ 663,011          $ 614,532         $ 606,696
    Gas...............................................................          191,545            231,011           214,419
                                                                              ---------          ---------         ---------
       Total operating revenues.......................................          854,556            845,543           821,115
    Provision for rate refund (Note 3)................................           (4,500)                 -                 -
                                                                              ---------          ---------         ---------
       Net operating revenues (Note 1)................................          850,056            845,543           821,115
                                                                              ---------          ---------         ---------

OPERATING EXPENSES:
    Fuel for electric generation......................................          154,683            149,463           149,697
    Power purchased...................................................           50,176             17,229            16,626
    Gas supply expenses...............................................          125,894            158,929           140,482
    Other operation expenses..........................................          163,584            150,750           143,338
    Maintenance.......................................................           52,786             47,586            54,790
    Depreciation and amortization.....................................           93,178             93,020            89,002
    Federal and state income taxes (Note 8)...........................           56,307             64,081            63,259
    Property and other taxes..........................................           17,925             16,299            16,658
                                                                              ---------          ---------         ---------
       Total operating expenses.......................................          714,533            697,357           673,852
                                                                              ---------          ---------         ---------

Net operating income..................................................          135,523            148,186           147,263

Merger costs to achieve (Note 2)......................................           32,072                  -                 -
Other income and (deductions) (Note 9)................................           10,991              4,277               920
Interest charges......................................................           36,322             39,190            40,242
                                                                              ---------          ---------         ---------

Net income............................................................           78,120            113,273           107,941

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


Net income available for common stock.................................        $  73,552          $ 108,688         $ 103,373
                                                                              ---------          ---------         ---------
                                                                              ---------          ---------         ---------
</TABLE>


                         Statements of Retained Earnings
                                (Thousands of $)

<TABLE>
<CAPTION>
                                                                                          Years Ended December 31
                                                                                   1998               1997             1996
                                                                                   ----               ----             ----

<S>                                                                            <C>                <C>              <C>
Balance January 1.....................................................         $258,910           $209,222         $181,049
Add net income........................................................           78,120            113,273          107,941
                                                                               --------           --------         --------
                                                                                337,030            322,495          288,990

Deduct:    Cash dividends declared on stock:
             5% cumulative preferred..................................            1,075              1,075            1,075
             Auction rate cumulative preferred........................            2,024              2,041            2,024
             $5.875 cumulative preferred..............................            1,469              1,469            1,469
             Common...................................................           85,000             59,000           75,200
                                                                               --------           --------         --------
                                                                                 89,568             63,585           79,768
                                                                               --------           --------         --------


Balance December 31...................................................         $247,462           $258,910         $209,222
                                                                               --------           --------         --------
                                                                               --------           --------         --------
</TABLE>

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

                                   127


<PAGE>


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

<TABLE>
<CAPTION>
                                                                                          Years Ended December 31
                                                                                   1998               1997             1996
                                                                                   ----               ----             ----

<S>                                                                            <C>                <C>               <C>
Net income available for common stock.................................         $ 73,552           $108,688          $103,373

Unrealized holding gains (losses) on available-for-sale securities
    arising during the period.........................................              (14)              (426)              169

Reclassification adjustment for realized and losses on
    available-for-sale securities included in net income..............                -                188               547
                                                                               --------           --------          --------

Other comprehensive income (loss) before tax..........................              (14)              (238)              716

Income tax expense (benefit) related to items of other
    comprehensive income..............................................               18               (119)              289
                                                                               --------           --------          --------


Comprehensive income..................................................         $ 73,520           $108,569          $103,800
                                                                               --------           --------          --------
                                                                               --------           --------          --------
</TABLE>

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

                                   128


<PAGE>


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

<TABLE>
<CAPTION>
                                                                                                        December 31
                                                                                               1998                     1997
                                                                                               ----                     ----
<S>                                                                                      <C>                      <C>
ASSETS:
Utility plant, at original cost:
    Electric....................................................................         $2,268,860               $2,242,980
    Gas    .....................................................................            339,647                  337,619
    Common .....................................................................            131,271                  137,496
                                                                                         ----------               ----------
                                                                                          2,739,778                2,718,095
    Less:  reserve for depreciation.............................................          1,144,123                1,072,842
                                                                                         ----------               ----------
                                                                                          1,595,655                1,645,253
    Construction work in progress...............................................            156,361                   61,139
                                                                                         ----------               ----------
                                                                                          1,752,016                1,706,392
                                                                                         ----------               ----------

Other property and investments - less reserve...................................              1,154                    1,365

Current assets:
    Cash and temporary cash investments.........................................             31,730                   50,472
    Marketable securities (Note 6)..............................................             17,851                   19,311
    Accounts receivable - less reserve of $1,399 in 1998 and $1,295 in 1997.....            142,580                  124,872
    Materials and supplies - at average cost:
       Fuel (predominantly coal)................................................             23,993                   17,651
       Gas stored underground...................................................             33,485                   41,487
       Other....................................................................             33,103                   31,866
    Prepayments.................................................................              2,285                    2,627
                                                                                         ----------               ----------
                                                                                            285,027                  288,286
                                                                                         ----------               ----------

Deferred debits and other assets:
    Unamortized debt expense....................................................              5,919                    6,074
    Regulatory assets (Note 3)..................................................             37,643                   24,899
    Other  .....................................................................             22,878                   28,625
                                                                                         ----------               ----------

                                                                                             66,440                   59,598
                                                                                         ----------               ----------
                                                                                         $2,104,637               $2,055,641
                                                                                         ----------               ----------
                                                                                         ----------               ----------


CAPITAL AND LIABILITIES:
Capitalization (see statements of capitalization):
    Common equity...............................................................         $  671,846               $  683,326
    Cumulative preferred stock..................................................             95,328                   95,328
    Long-term debt (Note 10)....................................................            626,800                  626,800
                                                                                         ----------               ----------
                                                                                          1,393,974                1,405,454
                                                                                         ----------               ----------

Current liabilities:
    Long-term debt due within one year..........................................                  -                   20,000
    Accounts payable............................................................            133,673                   98,894
    Provision for rate refunds..................................................             13,261                   13,248
    Dividends declared..........................................................             23,168                   21,152
    Accrued taxes...............................................................             31,929                   18,723
    Accrued interest............................................................              8,038                    8,016
    Other  .....................................................................             15,242                   14,608
                                                                                         ----------               ----------
                                                                                            225,311                  194,641
                                                                                         ----------               ----------

Deferred credits and other liabilities:
    Accumulated deferred income taxes (Notes 1 and 8)...........................            254,589                  249,851
    Investment tax credit, in process of amortization...........................             71,542                   75,800
    Accumulated provision for pensions and related benefits (Note 7)............             59,529                   33,872
    Customers' advances for construction........................................             10,848                   10,385
    Regulatory liability (Note 3)...............................................             63,529                   65,502
    Other  .....................................................................             25,315                   20,136
                                                                                         ----------               ----------
                                                                                            485,352                  455,546
                                                                                         ----------               ----------
Commitments and contingencies (Note 12)

                                                                                         $2,104,637               $2,055,641
                                                                                         ----------               ----------
                                                                                         ----------               ----------
</TABLE>

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

                                   129


<PAGE>


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

<TABLE>
<CAPTION>
                                                                                          Years Ended December 31
                                                                                   1998               1997             1996
                                                                                   ----               ----             ----

<S>                                                                          <C>                <C>              <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
    Net income........................................................       $   78,120         $  113,273       $  107,941
    Items not requiring cash currently:
       Depreciation and amortization..................................           93,178             93,020           89,002
       Deferred income taxes - net....................................            2,747             (3,495)          26,055
       Investment tax credit - net....................................           (4,258)            (4,240)          (3,997)
       Other..........................................................            5,534              4,640            3,911
    Change in certain net current assets:
       Accounts receivable............................................          (17,708)            (9,728)          (9,555)
       Materials and supplies.........................................              423             (8,492)          (1,418)
       Accounts payable...............................................           34,779              1,416            3,772
       Provision for rate refunds.....................................               13             (4,263)         (10,789)
       Accrued taxes..................................................           13,206              6,741            4,168
       Accrued interest...............................................               22             (1,978)          (1,070)
       Prepayments and other..........................................              976              1,333              685
    Other.............................................................           18,679             (3,188)         (23,153)
                                                                              ---------         ----------       ----------
       Net cash flows from operating activities.......................          225,711            185,039          185,552
                                                                              ---------         ----------       ----------

CASH FLOWS FROM INVESTING ACTIVITIES:
    Purchases of securities...........................................          (17,397)           (18,529)         (11,039)
    Proceeds from sales of securities.................................           18,841              2,544           28,605
    Construction expenditures.........................................         (138,345)          (110,893)        (107,879)
                                                                              ---------         ----------       ----------
       Net cash flows from investing activities.......................         (136,901)          (126,878)         (90,313)
                                                                              ---------         ----------       ----------

CASH FLOWS FROM FINANCING ACTIVITIES:
    Issuance of first mortgage bonds and pollution control bonds......                -             69,776           49,745
    Retirement of first mortgage bonds and pollution control bonds....          (20,000)           (71,693)         (67,013)
    Payment of dividends..............................................          (87,552)           (62,564)         (79,310)
                                                                              ---------         ----------       ----------
       Net cash flows from financing activities.......................         (107,552)           (64,481)         (96,578)
                                                                              ---------         ----------       ----------

Change in cash and temporary cash investments.........................          (18,742)            (6,320)          (1,339)

Cash and temporary cash investments at beginning of year..............           50,472             56,792           58,131
                                                                              ---------         ----------       ----------


Cash and temporary cash investments at end of year....................       $   31,730         $   50,472       $   56,792
                                                                              ---------         ----------       ----------
                                                                              ---------         ----------       ----------


Supplemental disclosures of cash flow information: Cash paid during the year
    for:
       Income taxes...................................................        $  40,334          $  63,421        $  41,508
       Interest on borrowed money.....................................           34,245             39,582           40,334
</TABLE>

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

                                   130


<PAGE>


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

<TABLE>
<CAPTION>
                                                                                                        December 31
                                                                                               1998                     1997
                                                                                               ----                     ----
<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 on marketable securities, net of income
       taxes $34 in 1998 and $16 in 1997 (Note 6)...................................             50                       82
    Retained earnings...............................................................        247,462                  258,910
                                                                                         ----------               ----------

                                                                                            671,846                  683,326
                                                                                         ----------               ----------

CUMULATIVE PREFERRED STOCK:
    Redeemable on 30 days notice by LG&E

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

    $25 par value, 1,720,000 shares authorized -
       5% series ....................................      860,287          $28.00           21,507                   21,507
    Without par value, 6,750,000 shares authorized -
       Auction rate..................................      500,000          100.00           50,000                   50,000
       $5.875 series.................................      250,000          105.875          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 long-term bonds.................................................        626,800                  626,800
                                                                                         ----------               ----------


       Total capitalization.........................................................     $1,393,974               $1,405,454
                                                                                         ----------               ----------
                                                                                         ----------               ----------
</TABLE>


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

                                   131


<PAGE>


                       Louisville Gas and Electric Company
                          Notes to Financial Statements

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Louisville Gas and Electric Company (LG&E) is a subsidiary of LG&E Energy Corp.
(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, Kentucky Utilities Company (KU),
and LG&E Capital Corp. (Capital Corp.). 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 1998 were
3.4% (3.2% electric, 3.4% gas, and 7.4% common); for 1997 were 3.4% (3.2%
electric, 3.3% gas, and 6% common); and for 1996 were 3.3% (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 $33 million and $41 million at
December 31, 1998 and 1997, 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, and it 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 gains or 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 the LG&E's marketing of power from owned generation assets,
exchange traded futures are used to hedge market risk associated with price
fluctuations for commitments to sell or purchase electricity. Gains and losses
on these futures contracts are reflected in other income and deductions, but are
immaterial to the LG&E's results of operations. At December 31, 1998, the value
of these futures contracts was not material to the LG&E's financial position.

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

                                   132


<PAGE>


practices.

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

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

REVENUE RECOGNITION. Revenues are recorded based on service rendered to
customers through month-end. LG&E accrues an estimate for unbilled revenues from
each meter reading date to the end of the accounting period. Under an agreement
approved by the Public Service Commission of Kentucky (Kentucky Commission or
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 Commission-approved experimental
performance-based ratemaking mechanism related to gas procurement and off-system
gas sales activity. See Note 3, Rates and Regulatory Matters.

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

NEW ACCOUNTING PRONOUNCEMENTS.  During 1998, LG&E adopted the following 
accounting pronouncements:

Statements of Financial Accounting Standards No. 132, Employers' Disclosures 
about Pensions and Other Postretirement Benefits (SFAS No. 132), No. 130, 
Reporting Comprehensive Income (SFAS No. 130), and No. 131, Disclosures about 
Segments of an Enterprise and Related Information (SFAS No. 131).   Pursuant 
to SFAS No. 132, LG&E has disclosed additional information on changes in 
benefit obligations and fair values of plan assets and eliminated certain 
disclosures that are no longer relevant.  This standard does not change the 
measurement or financial statement recognition of the plans.  See Note 7, 
Pension Plans and Retirement Benefits. Under SFAS No. 131, LG&E has provided 
information about its various business segments that is intended to allow 
readers to view certain financial information as if "through the eyes of 
management".  See Note 14, Segments of Business and Related Information.   
Pursuant to SFAS No. 130, LG&E has presented information in the Statements of 
Comprehensive Income that measures changes in equity that are not required to 
be recorded as a component of net income. These standards had no impact on 
the calculation of net income presented in the Statements of Income.

Statement of Position No. 98-1, Accounting for the Costs of Computer Software
Developed or Obtained for Internal Use (SOP 98-1). 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 must be expensed as
incurred. Adoption of SOP 98-1 did not have a material effect on LG&E's
financial statements.

                                   133


<PAGE>


The following accounting pronouncements have been issued but are not yet
effective:

Statement of Financial Accounting Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities. The statement is effective for fiscal years
beginning after June 15, 1999, and establishes accounting and reporting
standards that every derivative instrument be recorded in the balance sheet as
either an asset or liability measured at its fair value. The statement 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 a company
must formally document, designate, and assess the effectiveness of transactions
that use hedge accounting. LG&E is currently analyzing the provisions of the
statement and cannot predict the impact this statement will have on its results
of operations and financial position, however, the statement could increase
volatility in earnings and other comprehensive income. The effect of this
statement will be recorded in cumulative effect of change in accounting when
adopted.

Emerging Issues Task Force Issue No. 98-10, Accounting for Energy Trading and
Risk Management Activities (EITF No. 98-10). This pronouncement is effective for
fiscal years beginning after December 15, 1998. The task force concluded that
energy trading contracts should be recorded at mark 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. The effects of adopting EITF No. 98-10, if
applicable, will be reported as a cumulative effect of a change in accounting
principle with no prior period restatement. LG&E does not expect the adoption of
EITF No. 98-10 to have a material adverse impact on its operations and financial
position.

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, LG&E Energy, which is the
parent of LG&E, became the parent company of Kentucky Utilities Company (KU).
LG&E and KU have continued to maintain their separate corporate identities and
serve customers 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 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 common stock, preferred stock and debt securities of LG&E
were not affected by the merger.

Regulatory and administrative approvals were obtained from the Federal Energy
Regulatory Commission, (FERC), the Federal Trade Commission, the Securities and
Exchange Commission, the Public Service Commission of Kentucky (Kentucky
Commission or Commission), the Virginia State Corporation Commission and the
stockholders of LG&E Energy and KU Energy prior to the effective date of the
merger. LG&E Energy, as the parent of LG&E and KU, continues to be an exempt
holding company under the Public Utility Holding Company Act of 1935. 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 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

                                   134


<PAGE>


such savings by LG&E, be applied to reduce customer rates through a surcredit 
on customers' bills and the remaining 50% be retained by the companies. The 
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's customers. Any fuel cost savings are passed to customers 
through LG&E's fuel adjustment clause.

NOTE 3 - RATES AND REGULATORY MATTERS

LG&E 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 Statement of Financial Accounting Standards No.
71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71).
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 the balance sheets as of December 31 (in
thousands of $):

<TABLE>
<CAPTION>
                                                   1998              1997
                                                   ----              ----
   <S>                                           <C>               <C>
   Unamortized loss on bonds                     $ 17,627          $ 18,698
   Merger costs                                    16,332             2,938
   Manufactured gas sites                           3,684             3,263
                                                 --------          --------
   Total regulatory assets                         37,643            24,899
   Deferred income taxes - net                    (63,529)          (65,502)
                                                 --------          --------
   Regulatory assets and (liabilities) - net     $(25,886)         $(40,603)
                                                 --------          --------
                                                 --------          --------
</TABLE>

During 1997, LG&E wrote off certain previously deferred assets that amounted to
approximately $4.2 million. Items written off include expenses associated with
LG&E's hydro-electric plant, a management audit fee, and the accelerated
write-off of losses on early retirement of facilities.

ENVIRONMENTAL COST RECOVERY. Since May 1995, LG&E implemented an environmental
cost recovery (ECR) surcharge to recover certain environmental compliance costs,
including costs to comply with the 1990 Clean Air Act, as amended, as well as
other environmental regulations, including those applicable to coal combustion
wastes and related by-products. The ECR mechanism was authorized by state
statute in 1992 and was first approved by the Kentucky Commission in a KU case
in July 1994.

The Commission's order approving the surcharge in the KU case and the
constitutionality of the surcharge was challenged by certain intervenors,
including the Attorney General of Kentucky, in Franklin Circuit Court. Decisions
of the Circuit Court and the Kentucky Court of Appeals in July 1995 and December
1997, respectively, have upheld the constitutionality of the ECR statute but
differed on a claim of retroactive recovery of certain amounts. The Commission
ordered that certain surcharge revenues collected by LG&E be subject to refund
pending final determination of all appeals.

On December 19, 1998, the Kentucky Supreme Court rendered an opinion upholding
the constitutionality of the surcharge statute. The decision, however, reversed
the ruling of the Court of Appeals on the retroactivity claim, thereby denying
recovery of costs associated with pre-1993 environmental projects through the
ECR. The court remanded the case to the Commission to determine the proper
adjustments to refund amounts collected for such pre-1993 environmental
projects. The parties to the proceeding have notified the Commission that they
have reached agreement as to the terms, refund amounts, refund procedure and
forward application of the ECR. The

                                   135


<PAGE>


settlement agreement is subject to Commission approval. LG&E recorded a 
provision for rate refund of $4.5 million in December 1998.

DEMAND SIDE MANAGEMENT. In January 1994, LG&E implemented a Commission-approved
demand side management (DSM) program that LG&E, the Jefferson County Attorney,
and representatives of several customer interest groups had filed with the
Commission. The program included a rate mechanism that (1) provided LG&E
concurrent recovery of DSM costs, (2) provided an incentive for implementing DSM
programs and (3) allowed LG&E to recover revenues from lost sales associated
with the DSM program (decoupling). In June 1998, LG&E and customer interest
groups requested an end to the decoupling rate mechanism. On June 1, 1998, LG&E
discontinued recording revenues from lost sales due to DSM. Accrued decoupling
revenues recorded for periods prior to June 1, 1998, will continue to be
collected through the DSM recovery mechanism. On September 23, 1998, the
Commission accepted LG&E's modified tariff reflecting this proposal effective as
of June 1, 1998.

PERFORMANCE-BASED RATEMAKING. Since October 1997, LG&E has implemented a
Commission-approved, experimental performance-based ratemaking mechanism related
to gas procurement activities and off-system gas sales. 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 year of the mechanism ended October 31, 1998, LG&E
recorded $3.6 million for its share of reduced gas costs. The $3.6 million will
be billed to customers through the gas supply clause beginning February 1, 1999.

FUEL ADJUSTMENT CLAUSE. LG&E has a fuel adjustment clause (FAC) mechanism, which
under Kentucky law allows LG&E to recover from customers, the actual fuel costs
associated with retail electric sales. As of February 12, 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. The orders changed LG&E's method of assigning
fuel costs associated with electric line losses on off-system sales through the
FAC. The orders require these amounts to be refunded to customers during 1999
and to include in the FAC calculation the cost of fuel associated with line
losses incurred in making off-system sales.

The Kentucky Commission has not issued LG&E an order for the review period May
1998 through October 1998, however, following the methods set forth in the
previous orders, LG&E estimates up to an additional $1.3 million could be
refundable to retail electric customers for open review periods through December
1998. LG&E filed a request for rehearing on the Kentucky Commission's rulings.
LG&E does not believe final resolution of these proceedings will have a material
adverse effect on LG&E's financial position or results of operations.

The Kentucky Commission granted LG&E's motion to suspend the refund obligation
until further direction by the Commission. The Commission advised that LG&E may
have to pay interest on the refund amounts for the suspension period. LG&E is
awaiting a Commission response to a motion to revoke the orders, or in the
alternative, grant a rehearing.

FUTURE RATE REGULATION. In October 1998, LG&E and KU filed separate, but
parallel applications with the Commission for approval of a new method of
determining electric rates that provides financial incentives for LG&E and KU to
further reduce customers' rates. The filing was made pursuant to the September
1997 Commission order approving the merger of LG&E Energy and KU Energy, wherein
the 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 new ratemaking method, known as performance-based ratemaking
(PBR), would include 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 provides financial

                                   136


<PAGE>


penalties and rewards to assure continued high quality service and 
reliability.

The PBR plan proposed by LG&E and KU consists of five components:

    The utilities' fuel adjustment clause mechanism will be withdrawn and
    replaced with a cap that limits recovery of actual changes in fuel cost to
    changes in a fuel price index for a five-state region. If the utilities
    outperform the index, benefits will be shared equally between shareholders
    and customers. If the utilities' fuel costs exceed the index, the difference
    will be absorbed by LG&E Energy's shareholders.

    Customers will continue to receive the benefits from the post-merger joint
    dispatch of power from LG&E's and KU's generating plants.

    Power plant performance will be measured against the best performance
    achieved between 1991 and 1997. If the performance exceeds this level,
    customers will share equally with LG&E Energy's shareholders in up to $10
    million annually of benefits from this performance at each of LG&E and KU.

    The utilities will be encouraged to maintain and improve service quality,
    reliability, customer satisfaction and safety, which will be measured
    against six objective benchmarks. The plan provides for annual rewards or
    penalties to LG&E Energy of up to $5 million per year at each of LG&E and
    KU.

    The plan provides the utilities with greater flexibility to customize rates
    and services to meet customer needs. Services will continue to be priced
    above marginal cost and customers will continue to have the option to elect
    standard tariff service.

These proposals are subject to approval by the Commission. Approval proceedings
commenced in October 1998 and a final decision likely will occur in 1999.
Several intervenors are participating in the case. Some have requested that the
Commission reduce base rates before implementing PBR. LG&E is not able to
predict the ultimate outcome of these proceedings, however, should the
Commission mandate significant rate reductions at LG&E, through the PBR proposal
or otherwise, such actions could have a material effect on LG&E's financial
condition and results of operations.

KENTUCKY PSC ADMINISTRATIVE CASE FOR AFFILIATE TRANSACTIONS. In December 1997,
the Kentucky Commission opened Administrative Case No. 369 to consider
Commission policy regarding cost allocations, affiliate transactions and codes
of conduct governing the relationship between utilities and their non-utility
operations and affiliates. The 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 which result in unfair competition
caused by cost shifting from the non-utility affiliate to the utility. In
September 1998, the Commission issued 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 Commission draft proposals. Initial hearings are scheduled
for the first quarter of 1999. 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.

NOTE 4 - FINANCIAL INSTRUMENTS

At December 31, 1998, LG&E held U.S. Treasury note and bond futures contracts
with notional amounts totaling $2.8 million. These contracts are used to hedge
price risk associated with certain marketable securities and mature in March
1999.


                                   137
<PAGE>

As of December 31, 1998, LG&E had in effect six interest-rate swap agreements 
to hedge its exposure to tax exempt rates related to Pollution Control Bonds, 
Variable Rate Series. The swaps have notional amounts totaling $166 million 
and mature at various times from 1999 to 2005. LG&E pays a weighted-average 
fixed rate on the swaps of 3.89% and receives a variable rate based on the JJ 
Kenny Index (in the case of one of the swaps) or the Bond Market Association 
Municipal Swap Index. The indices averaged 3.48% in 1998.

In April 1998, LG&E entered into a forward-starting interest-rate swap with a 
notional amount of $83.3 million. The swap will hedge anticipated 
variable-rate borrowing commitments. It will start in August 2000 and mature 
in November 2020. LG&E will pay a fixed rate of 5.21% and receive a variable 
rate based on the Bond Market Association Municipal Swap Index. Under certain 
conditions, the counterparty to the agreement may terminate the swap at no 
cost after August 2010.

The cost and estimated fair values of LG&E's non-trading financial 
instruments as of December 31, 1998 and 1997 follow (in thousands of $):

<TABLE>
<CAPTION>
                                                                 1998                              1997
                                                                 ----                              ----
                                                                          Fair                               Fair
                                                          Cost           Value             Cost             Value
                                                          ----           -----             ----             -----
        <S>                                         <C>             <C>              <C>               <C>
         Marketable securities                       $  17,767       $  17,851        $  19,213         $  19,311
         Long-term investments -
           Not practicable to estimate
              fair value                                   748             748              747               747
         Preferred stock subject
           to mandatory redemption                      25,000          26,413           25,000            26,250
         Long-term debt                                626,800         648,603          626,800           649,491
         U.S. Treasury note and
           bond futures                                      -             (50)               -               (37)
         Interest-rate swaps                                 -          (7,378)               -              (248)
</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 LG&E 
cannot reasonably estimate fair value.

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 completely 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 289,000 customers and electricity 
to approximately 360,000 customers in Louisville and adjacent areas in 
Kentucky. For the year ended December 31, 1998, 77% of total revenue was 
derived from electric operations and 23% from gas operations.

LG&E's operation and maintenance employees are members of the International 
Brotherhood of Electrical Workers (IBEW) Local 2100 which represents 
approximately 60% of LG&E's workforce. On December 10, 1998, LG&E and IBEW 
employees entered into a three-year collective bargaining agreement following 
a vote by IBEW members which ratified the contract providing for certain wage 
and benefit improvements, and opportunities for early retirement.

                                      138
<PAGE>

NOTE 6 - MARKETABLE SECURITIES

LG&E's marketable securities have been determined to be "available-for-sale" 
under the provisions of Statement of Financial Accounting Standards SFAS No. 
115, Accounting for Certain Investments in Debt and Equity Securities. 
Proceeds from sales of available-for-sale securities in 1998 were 
approximately $18.8 million, which resulted in immaterial realized gains and 
losses. Proceeds from sales of available-for-sale securities in 1997 were 
approximately $2.5 million, which resulted in immaterial realized gains and 
losses, calculated using the specific identification method.

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

<TABLE>
<CAPTION>
                                                                                         Fixed
                                                                        Equity           Income             Total
                                                                        ------           ------             -----
        <S>                                                           <C>              <C>               <C> 
         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
              Five to ten years                                              -                -                 -
              Over ten years                                                 -            1,532             1,532
              Not due at a single maturity date                              -                -                 -
                                                                      --------       ----------        ----------

         Total fair values                                              $3,979          $13,872           $17,851
                                                                      --------       ----------        ----------
                                                                      --------       ----------        ----------

         1997:
         Cost                                                           $3,763          $15,450           $19,213
         Unrealized gains                                                  192               13               205
         Unrealized losses                                                 (40)             (67)             (107)
                                                                      --------      -----------        ----------
         Fair values                                                    $3,915          $15,396           $19,311
                                                                      --------       ----------        ----------
                                                                      --------       ----------        ----------

         Fair values:
           No maturity                                                  $3,915        $     114          $  4,029
           Contractual maturities:
              Less than one year                                             -            8,795             8,795
              One to five years                                              -            5,442             5,442
              Five to ten years                                              -                -                 -
              Over ten years                                                 -            1,045             1,045
              Not due at a single maturity date                              -                -                 -
                                                                    ----------    -------------     -------------

         Total fair values                                              $3,915          $15,396           $19,311
                                                                      --------       ----------        ----------
                                                                      --------       ----------        ----------

</TABLE>

                                      139
<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, 1998 and a statement of the funded status as of December 31 for 
each of the last three years (in thousands of $):

<TABLE>
<CAPTION>
                                                                          1998             1997              1996
                                                                          ----             ----              ----
        <S>                                                         <C>              <C>              <C>
         Pension Plans:
         --------------
         Change in benefit obligation
           Benefit obligation at beginning of year                    $274,095         $229,349          $206,866
           Service cost                                                  6,333            5,214             4,989
           Interest cost                                                19,873           17,629            16,697
           Plan amendments                                               3,724            3,085            18,694
           Curtailment (gain) or loss                                   (2,218)               -                 -
           Special termination benefits                                 18,295                -                 -
           Benefits paid                                               (10,866)          (8,735)           (7,745)
           Actuarial (gain) or loss                                      2,699           27,553           (10,152)
                                                                     ---------        ---------        ----------
           Benefit obligation at end of year                          $311,935         $274,095          $229,349
                                                                     ---------        ---------        ----------
                                                                     ---------        ---------        ----------

         Change in plan assets
           Fair value of plan assets at beginning of year             $280,238         $238,026          $207,471
           Actual return on plan assets                                 38,913           46,078            31,921
           Employer contributions                                          375            4,869             6,379
           Benefits paid                                               (10,866)          (8,735)           (7,745)
                                                                     ---------        ---------        ----------
           Fair value of plan assets at end of year                   $308,660         $280,238          $238,026
                                                                     ---------        ---------        ----------
                                                                     ---------        ---------        ----------

         Reconciliation of funded status
           Funded status                                             $  (3,275)      $    6,143        $    8,677
           Unrecognized actuarial (gain) or loss                       (72,037)         (61,720)          (65,850)
           Unrecognized transition (asset) or obligation                (8,076)          (9,188)          (10,300)
           Unrecognized prior service cost                              41,447           43,518            44,141
                                                                     ---------        ---------        ----------
           Net amount recognized at end of year                      $ (41,941)       $ (21,247)        $ (23,332)
                                                                     ---------        ---------        ----------
                                                                     ---------        ---------        ----------

         Other Benefits:
         --------------
         Change in benefit obligation
           Benefit obligation at beginning of year                     $43,373          $39,951           $37,815
           Service cost                                                    761              746               773
           Interest cost                                                 2,946            2,942             2,976
           Plan amendments                                                 599                -             4,066
           Curtailment (gain) or loss                                      344                -                 -
           Special termination benefits                                  2,855                -                 -
           Benefits paid                                                (2,634)          (2,604)           (2,678)
           Actuarial (gain) or loss                                     (3,280)           2,338            (3,001)
                                                                     ---------        ---------        ----------
           Benefit obligation at end of year                           $44,964          $43,373           $39,951
                                                                     ---------        ---------        ----------
                                                                     ---------        ---------        ----------

         Change in plan assets
           Fair value of plan assets at beginning of year             $  4,384         $  2,284      $          -
           Actual return on plan assets                                    199               80                 -
           Employer contributions                                        3,207            3,696             2,284
           Benefits paid                                                (1,728)          (1,676)                -
                                                                     ---------        ---------        ----------
           Fair value of plan assets at end of year                   $  6,062         $  4,384          $  2,284
                                                                     ---------        ---------        ----------
                                                                     ---------        ---------        ----------
</TABLE>

                                      140
<PAGE>

<TABLE>
<CAPTION>
                                                                          1998             1997              1996
                                                                          ----             ----              ----
        <S>                                                        <C>              <C>              <C>
         Reconciliation of funded status
           Funded status                                             $ (38,902)       $ (38,989)        $ (37,667)
           Unrecognized actuarial (gain) or loss                          (285)           2,901               493
           Unrecognized transition (asset) or obligation                18,080           20,053            21,390
           Unrecognized prior service cost                               3,519            3,410             3,738
                                                                   -----------      -----------       -----------
           Net amount recognized at end of year                      $ (17,588)       $ (12,625)        $ (12,046)
                                                                   -----------      -----------       -----------
                                                                   -----------      -----------       -----------
</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 statement of
financial position and information for plans with benefit obligations in excess
of plan assets as of December 31, 1998, 1997 and 1996 (in thousands of $):

<TABLE>
<CAPTION>
                                                                          1998             1997              1996
                                                                          ----             ----              ----
        <S>                                                        <C>              <C>              <C>
         Pension Plans:
         --------------
         Amounts recognized in the balance sheet consisted of:
              Accrued benefit liability                              $ (41,977)       $ (21,317)        $ (23,372)
              Intangible asset                                              36               70                40
                                                                   -----------      -----------       -----------
              Net amount recognized at year-end                      $ (41,941)       $ (21,247)        $ (23,332)
                                                                   -----------      -----------       -----------
                                                                   -----------      -----------       -----------

         Additional year-end information for plans with 
           benefit obligations in excess of plan assets:
              Projected benefit obligation (1)                        $148,005         $121,902          $101,260
              Accumulated benefit obligation (2)                       131,430            4,179             3,634
              Fair value of plan assets (1)                            107,988           99,151            81,848


         (1) All years include LG&E's non-union plan and unfunded Supplemental Executive Retirement Plans (SERPs).
         (2) 1998 includes LG&E's non-union plan and SERPs. 1997 and 1996 include SERPs only.

         Other Benefits:
         ---------------
         Amounts recognized in the balance sheet consisted of:
              Accrued benefit liability                              $ (17,588)       $ (12,625)        $ (12,046)
                                                                   -----------      -----------       -----------
                                                                   -----------      -----------       -----------

         Additional year-end information for plans with benefit obligations in
           excess of plan assets:
              Projected benefit obligation                             $44,964          $43,373           $39,951
              Fair value of plan assets                                  6,062            4,384             2,284
</TABLE>

                                      141
<PAGE>

The following table provides the components of net periodic benefit cost for the
plans for 1998, 1997 and 1996 (in thousands of $):

<TABLE>
<CAPTION>
                                                                          1998             1997              1996
                                                                          ----             ----              ----
        <S>                                                         <C>              <C>               <C>
         Pension Plans:
         --------------
         Components of net periodic benefit cost
           Service cost                                               $  6,333         $  5,214          $  4,989
           Interest cost                                                19,873           17,629            16,697
           Expected return on plan assets                              (23,701)         (19,849)          (17,706)
           Amortization of prior service cost                            3,882            3,708             3,491
           Amortization of transition (asset) or obligation             (1,112)          (1,112)           (1,112)
           Recognized actuarial (gain) or loss                          (2,248)          (2,866)           (2,047)
                                                                     ---------        ---------         ---------
           Net periodic benefit cost                                  $  3,027         $  2,724          $  4,312
                                                                     ---------        ---------         ---------
                                                                     ---------        ---------         ---------

         FAS88 special charges
           Curtailment (gain)/loss                                   $  (2,168)       $       -          $      -
           Prior service cost recognized                                 1,914                -                 -
           Special termination benefits                                 18,295                -                 -
                                                                     ---------        ---------         ---------
           Total FAS88 charges                                        $ 18,041        $       -          $      -
                                                                     ---------        ---------         ---------
                                                                     ---------        ---------         ---------

         Other Benefits:
         ---------------
         Components of net periodic benefit cost
           Service cost                                               $    761         $    746          $    773
           Interest cost                                                 2,946            2,942             2,976
           Expected return on plan assets                                 (296)            (151)                -
           Amortization of prior service cost                              367              328               328
           Amortization of transition (asset) or obligation              1,315            1,337             1,337
                                                                     ---------        ---------         ---------
           Net periodic benefit cost                                   $ 5,093          $ 5,202           $ 5,414
                                                                     ---------        ---------         ---------
                                                                     ---------        ---------         ---------

         FAS88 special charges
           Curtailment (gain)/loss                                     $ 1,005         $      -          $      -
           Prior service cost recognized                                   124                -                 -
           Special termination benefits                                  2,855                -                 -
                                                                     ---------        ---------         ---------
           Total FAS88 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 incurred approximately $18 million in
special termination pension 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>
                                                                          1998             1997              1996
                                                                          ----             ----              ----
        <S>                                                       <C>             <C>               <C>
         Weighted-average assumptions as of December 31: 
         Discount rate                                                   7.00%            7.00%             7.75%
         Expected long-term rate of return on plan assets                8.50%            8.50%             8.50%
         Rate of compensation increase                             3.50%-4.00%      2.00%-4.00%       2.00%-4.25%
</TABLE>

For measurement purposes, a 7% annual increase in the per capita cost of covered
health care benefits was assumed for 1999. The rate was assumed to decrease each
year to 4.25% for 2005 and remain at that level thereafter.

                                      142
<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 1998               $   122                   $   146
         Effect on year-end 1998 postretirement benefit obligations                       1,188                     1,971
</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 $2.4 million
for 1998 and $1.8 million for each of 1997 and 1996.

NOTE 8 - INCOME TAXES

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

<TABLE>
<CAPTION>
                                                                          1998             1997              1996
                                                                          ----             ----              ----
        <S>                                                           <C>              <C>               <C>
         Included in operating expenses:
           Current         - federal                                   $45,716          $57,590           $33,823
                           - state                                      11,895           14,593             7,685
           Deferred        - federal - net                               2,276           (4,565)           19,161
                           - state - net                                   678              703             6,587
           Deferred investment tax credit                                   55              102               409
           Amortization of investment tax credit                        (4,313)          (4,342)           (4,406)
                                                                      --------         --------          --------
              Total                                                     56,307           64,081            63,259

         Included in other income and (deductions):
           Current         - federal                                       660            1,484               196
                           - federal - merger costs                     (6,758)               -                 -
                           - state                                           6              161               (96)
                           - state - merger costs                       (1,737)               -                 -
           Deferred        - federal - net                                (165)             292               246
                           - state - net                                   (42)              75                61
                                                                      --------         --------          --------
              Total                                                     (8,036)           2,012               407
                                                                      --------         --------          --------

         Total income tax expense                                      $48,271          $66,093           $63,666
                                                                      --------         --------          --------
                                                                      --------         --------          --------
</TABLE>

                                      143
<PAGE>

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

<TABLE>
<CAPTION>
                                                                          1998             1997
                                                                          ----             ----
        <S>                                                       <C>              <C>
         Deferred tax liabilities:
           Depreciation and other
              plant-related items                                     $323,869         $321,442
           Other liabilities                                             9,644            6,702
                                                                     ---------        ---------
                                                                       333,513          328,144
                                                                     ---------        ---------

         Deferred tax assets:
           Investment tax credit                                        28,876           30,595
           Income taxes due to customers                                25,447           26,357
           Pension overfunding                                           2,099            7,265
           Accrued liabilities not currently
              deductible and other                                      22,502           14,076
                                                                     ---------        ---------
                                                                        78,924           78,293
                                                                     ---------        ---------

         Net deferred income tax liability                            $254,589         $249,851
                                                                     ---------        ---------
                                                                     ---------        ---------
</TABLE>

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

<TABLE>
<CAPTION>
                                                                          1998             1997              1996
                                                                          ----             ----              ----
        <S>                                                             <C>              <C>               <C> 
         Statutory federal income tax rate                                35.0%            35.0%             35.0%
         State income taxes net of federal benefit                         5.5              5.7               5.4
         Amortization of investment tax credit                            (3.4)            (2.4)             (2.6)
         Nondeductible merger expenses                                     2.4                -                 -
         Other differences - net                                          (1.3)            (1.5)              (.7)
                                                                         -----            -----             -----

         Effective income tax rate                                        38.2%            36.8%             37.1%
                                                                         -----            -----             -----
                                                                         -----            -----             -----
</TABLE>

NOTE 9 - OTHER INCOME AND DEDUCTIONS

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

<TABLE>
<CAPTION>
                                                                          1998             1997              1996
                                                                          ----             ----              ----
        <S>                                                         <C>                <C>               <C>
         Interest and dividend income                                $   4,245          $ 4,786           $ 4,096
         Interest on income tax settlement                                   -            1,446                 -
         Gain on sale of stock options                                       -            1,794                 -
         Gains (losses) on fixed asset disposal                            530               77               (36)
         Donations                                                        (168)            (147)             (150)
         Income taxes and other                                         (2,111)          (3,679)           (2,990)
         Income tax benefit on merger costs to achieve                   8,495                -                 -
                                                                     ---------        ---------         ---------

         Total other income and deductions                            $ 10,991          $ 4,277          $    920
                                                                     ---------        ---------         ---------
                                                                     ---------        ---------         ---------
</TABLE>

NOTE 10 - FIRST MORTGAGE BONDS AND POLLUTION CONTROL BONDS

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 

                                      144
<PAGE>

amounts of bonds otherwise required to be so redeemed) have been applied in 
lieu of cash. It is the intent of LG&E to apply property additions to meet 
1999 sinking fund requirements of the First Mortgage Bonds.

The trust indenture securing the First Mortgage Bonds constitutes a direct 
first mortgage lien upon a substantial portion of all property owned by LG&E. 
The 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.

Pollution Control Bonds (Louisville Gas and Electric Company Projects) issued 
by Jefferson and Trimble Counties, Kentucky, are secured by the assignment of 
loan payments by LG&E to the Counties pursuant to loan agreements, and 
certain series are further secured by the delivery from time to time of an 
equal amount of LG&E's First Mortgage Bonds, Pollution Control Series. First 
Mortgage Bonds so delivered are summarized in the Statements of 
Capitalization. No principal or interest on these First Mortgage Bonds is 
payable unless default on the loan agreements occurs. The interest rate 
reflected in the Statements of Capitalization applies to the Pollution 
Control Bonds.

On June 1, 1998, LG&E's First Mortgage Bonds, 6.75% Series of $20 million 
matured and were retired by LG&E.

In November 1997, LG&E issued $35 million of Jefferson County, Kentucky and 
$35 million of Trimble County, Kentucky, Pollution Control Bonds, Flexible 
Rate Series, due November 1, 2027. Interest rates for these bonds were 3.09% 
and 3.39%, respectively, at December 31, 1998. The proceeds from these bonds 
were used to redeem the outstanding 7.75% Series of Jefferson County, 
Kentucky and Trimble County, Kentucky, Pollution Control Bonds due February 
1, 2019.

LG&E's First Mortgage Bonds, 7.5% Series of $20 million is scheduled to 
mature in 2002, and the $42.6 million, 6% Series is scheduled for maturity in 
2003. There are no scheduled maturities of Pollution Control Bonds for the 
five years subsequent to December 31, 1998. LG&E has no cash sinking fund 
requirements.

NOTE 11 - NOTES PAYABLE

LG&E had no notes payable at December 31, 1998, and 1997.

At December 31, 1998, LG&E had unused lines of credit of $200 million, for 
which it pays commitment fees. The credit facility provides for short-term 
borrowings and support of variable rate Pollution Control Bonds. 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 $8 million at December 31, 
1998. Construction expenditures for the years 1999 and 2000 are estimated to 
total approximately $384 million.

                                      145
<PAGE>

OPERATING LEASE. LG&E leases office space and accounts for all of its office 
space leases as operating leases. Total lease expense for 1998, 1997, and 
1996, less amounts contributed by the parent company, was $1.6 million, $1.8 
million, and $1.9 million, respectively. The future minimum annual lease 
payments under lease agreements for years subsequent to December 31, 1998, 
are as follows (in thousands of $):

<TABLE>
        <S>                                                              <C>
         1999                                                              $   3,055
         2000                                                                  3,321
         2001                                                                  3,654
         2002                                                                  3,594
         2003                                                                  3,507
         Thereafter                                                            5,260
                                                                           ---------
         Total                                                               $22,391
                                                                           ---------
                                                                           ---------
</TABLE>

ENVIRONMENTAL. In September 1998, the U.S. Environmental Protection Agency 
(USEPA) announced its final regulation requiring significant additional 
reductions in nitrogen oxide (NOx) emissions to mitigate alleged ozone 
transport to the Northeast. While each state is free to allocate its assigned 
NOx reductions among various emissions sectors as it deems appropriate, the 
regulation may ultimately require utilities to reduce their NOx emissions to 
0.15 lb./mmBtu (million British thermal units ) - an 85% reduction from 1990 
levels. Under the regulation, each state must incorporate the additional NOx 
reductions in its State Implementation Plan (SIP) by September 1999 and 
affected sources must install control measures by May 2003, unless granted 
extensions. Several states, various labor and industry groups, and individual 
companies have appealed the final regulation to the U.S. Court of Appeals for 
the D.C. Circuit. Management is currently unable to determine the outcome or 
exact impact of this matter until such time as the states identify specific 
emissions reductions in their SIP and the courts rule on the various legal 
challenges to the final rule. 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 and analysis, LG&E estimates that it may incur 
capital costs in the range of $100 million to $200 million. 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 cost recovery from customers under 
its environmental surcharge mechanism and believes that a significant portion 
of such costs could be so recovered. However, Kentucky Commission approval is 
necessary and there can be no guarantee of such recovery.

LG&E is also addressing other air quality issues. First, LG&E is monitoring 
USEPA's implementation of the revised National Ambient Air Quality Standards 
(NAAQS) for ozone and particulate matter. Until USEPA completes additional 
implementation steps, including monitoring and nonattainment designations, 
management is unable to determine the precise impact of the revised 
standards. Second, LG&E is conducting modeling activities at its Cane Run 
Station in response to notifications from regulatory agencies that the plant 
may be the source of potential exceedances of the NAAQS for sulfur dioxide 
(SO2). Depending on future regulatory determinations, LG&E may be required to 
undertake corrective action that could include significant capital 
expenditures or emissions limitations. 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 is currently awaiting a final regulatory 
determination regarding remedial measures. In management's opinion, 
resolution of any remaining property damage claims from adjacent residents 
should not have a material adverse impact on the financial position or 
results of operations of LG&E.

                                      147
<PAGE>

LG&E is addressing potential liabilities for the cleanup of properties where 
hazardous substances may have been released. LG&E has identified 
contamination at certain manufactured gas plant (MGP) sites currently or 
formerly owned by LG&E. LG&E is negotiating with state agencies with respect 
to cleanup of a site owned by LG&E. In agreements reached in 1996 and 1998 
with the current owners of two sites formerly owned by LG&E, the current 
owners of those sites have expressly agreed to assume responsibility for 
environmental liabilities in return for an aggregate payment of $400,000. 
Until conclusion of discussions with state agencies regarding the site 
currently owned by LG&E, management is unable to precisely determine 
remaining liability for cleanup costs at MGP sites. However, management 
estimates total cleanup costs to be $3 million. Accordingly, an accrual of $3 
million has been recorded in the accompanying financial statements.

LG&E, along with other companies, has been identified by USEPA as potentially 
responsible parties allegedly liable for cleanup of certain off-site disposal 
facilities under the Comprehensive Environmental Response Compensation and 
Liability Act. LG&E has entered into final settlements for an aggregate of 
$150,000 resolving liability in these matters.

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 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, Illinois Municipal Electric Agency (IMEA) 
owns a 12.12% undivided interest and Indiana Municipal Power Agency (IMPA) 
owns a 12.88% undivided interest. Each is responsible for their proportionate 
ownership share of fuel cost, operation and maintenance expenses, and 
incremental assets.

The following data represent 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               495
</TABLE>

                                      147

<PAGE>

NOTE 14 - SEGMENTS OF BUSINESS AND RELATED INFORMATION

Effective December 31, 1998, LG&E adopted Statements of Financial Accounting 
Standards 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 $):

<TABLE>
<CAPTION>
                                                                      Electric              Gas             Total
        <S>                                                      <C>                 <C>              <C>
         1998

         Operating revenues                                        $   658,511(a)      $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 to achieve                                        32,072                -            32,072
         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

         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
         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

         1996

         Operating revenues                                        $   606,696         $214,419        $  821,115
         Depreciation and amortization                                  76,929           12,073            89,002
         Interest income                                                 3,520              576             4,096
         Interest expense                                               34,566            5,676            40,242
         Income taxes                                                   58,448            4,811            63,259
         Net income                                                    100,119            7,822           107,941
         Total assets                                                1,673,857          332,855         2,006,712
         Construction expenditures                                      79,541           28,338           107,879
</TABLE>

         (a) Net of provision for rate refund of $4.5 million.

                                      148
<PAGE>

NOTE 15 - SELECTED QUARTERLY DATA (UNAUDITED)

Selected financial data for the four quarters of 1998 and 1997 are shown below.
Because of seasonal fluctuations in temperature and other factors, results for
quarters may fluctuate throughout the year.

<TABLE>
<CAPTION>
                                                                             Quarters Ended
                                                            March           June       September      December
                                                            -----           ----       ---------      --------
                                                                            (Thousands of $)
        <S>                                            <C>            <C>             <C>            <C>
         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) (a)     43,726          8,672(b)

         1997
         Operating revenues                              $225,399       $180,276        $208,435       $231,433
         Net operating income                              32,895         30,422          46,562         38,307
         Net income                                        23,967         21,487          37,223         30,596
         Net income (loss) available
           for common stock                                22,840         20,326          36,077         29,445
</TABLE>

         (a)  The decrease of $21.5 million compared to June 1997 was due to a
              non-recurring after-tax charge of $23.6 million from
              merger-related expenses offset by increased electric sales caused
              by warmer weather.

         (b)  The decrease of $20.8 million compared to December 1997 was due to
              a non-recurring charge to refund certain amounts collected under
              the Environmental Cost Recovery surcharge, decreased gas sales due
              to warmer weather and higher operating expenses at the electric
              generating stations.

NOTE 16 - SUBSEQUENT EVENT

On March 8,1999, the Kentucky Industrial Utility Customers (KIUC) filed a
complaint with the Kentucky Commission alleging that LG&E's electric rates are
excessive and should be reduced by an amount between $43 and $90 million and
that the Kentucky Commission establish a proceeding to reduce LG&E's electric
rates. LG&E has asked the Kentucky Commission to dismiss the complaint. LG&E is
not able to predict the ultimate outcome of these proceedings, however, should
the Commission mandate significant rate reductions at LG&E, through the PBR
proposal or otherwise, such actions could have a material effect on LG&E's
financial condition and results of operations.

On March 11, 1999, the Commission denied LG&E's Petition for Rehearing for the
period November 1994 through October 1996 and directed LG&E to reduce future
fuel expense by $1.9 million in the first billing month after the Order. The
Company is considering the filing of an Appeal with the Franklin Circuit Court.
In a separate series of Orders on March 11,1999, the PSC granted LG&E's Petition
for Rehearing for the period November 1996 through April 1998 and established a
procedural schedule for LG&E and other parties to submit evidence and for a
hearing before the Commission. In the same Orders the PSC granted the Petition
for Rehearing of the KIUC to determine if interest should be paid on any fuel
refunds for this latter period.

                                      149

<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, 1998, 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.

                                      150
<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, 1998 
and 1997, 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, 1998. 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 generally accepted auditing 
standards. 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, 1998 and 1997, and the results of its operations 
and its cash flows for each of the three years in the period ended December 
31, 1998, in conformity with generally accepted accounting principles.

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 27, 1999 (Except with respect
to the matters discussed in the eighth 
and ninth paragraphs of Note 3, as to
which the date is February 12, 1999, 
and Note 16, as to which the date is 
March 11, 1999.)

                                      151
<PAGE>


                           Kentucky Utilities Company
                              Statements of Income
                                (Thousands of $)
<TABLE>
<CAPTION>
                                                                                          Years Ended December 31
                                                                                   1998               1997              1996
                                                                                   ----               ----              ----
<S>                                                                         <C>                <C>               <C>
OPERATING REVENUES:
    Electric..........................................................        $ 831,614          $ 716,437         $ 711,711
    Provision for rate refund (Note 3)................................          (21,500)                 -                 -
                                                                              ---------          ---------         ---------
       Total operating revenues (Note 1)..............................          810,114            716,437           711,711
                                                                              ---------          ---------         ---------

OPERATING EXPENSES:
    Fuel, principally coal, used in generation........................          217,401            188,439           198,198
    Power purchased...................................................          126,584             72,542            62,490
    Other operation expenses..........................................          121,275            120,951           122,872
    Maintenance.......................................................           63,608             64,990            64,161
    Depreciation and amortization.....................................           86,657             84,111            80,424
    Federal and state income taxes (Note 7)...........................           53,256             51,690            51,452
    Property and other taxes..........................................           15,945             15,306            14,777
                                                                              ---------          ---------         ---------
       Total operating expenses.......................................          684,726            598,029           594,374
                                                                              ---------          ---------         ---------

Net operating income..................................................          125,388            118,408           117,337

Merger costs to achieve (Note 2)......................................           21,830                  -                 -
Interest and dividend income..........................................            1,811              1,673             1,733
Other income and (deductions) (Note 8)................................            6,035              5,330             6,710
Interest charges......................................................           38,640             39,698            39,617
                                                                              ---------          ---------         ---------

Net income............................................................           72,764             85,713            86,163

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

Net income available for common stock.................................        $  70,508          $  83,457        $   83,907
                                                                              ---------          ---------         ---------
                                                                              ---------          ---------         ---------
</TABLE>

                         Statements of Retained Earnings
                                (Thousands of $)
<TABLE>
<CAPTION>
                                                                                          Years Ended December 31
                                                                                   1998               1997             1996
                                                                                   ----               ----             ----
<S>                                                                          <C>                <C>              <C> 
Balance January 1.....................................................         $304,750           $287,852         $268,992
Add net income........................................................           72,764             85,713           86,163
                                                                               --------           --------         --------
                                                                                377,514            373,565          355,155

Deduct:    Cash dividends declared on stock:
             4.75% cumulative preferred...............................              950                950              950
             6.53% cumulative preferred...............................            1,306              1,306            1,306
             Common...................................................           76,091             66,559           65,047
                                                                               --------           --------         --------
                                                                                 78,347             68,815           67,303
                                                                               --------           --------         --------

Balance December 31...................................................         $299,167           $304,750         $287,852
                                                                               --------           --------         --------
                                                                               --------           --------         --------
</TABLE>
The accompanying notes are an integral part of these financial statements.

                                      152
<PAGE>


                           Kentucky Utilities Company
                                 Balance Sheets
                                (Thousands of $)
<TABLE>
<CAPTION>
                                                                                                     December 31
                                                                                               1998                1997
                                                                                               ----                ----
<S>                                                                                    <C>                 <C>
ASSETS:
Utility plant, at original cost.................................................         $2,602,167          $2,552,695
Less:  reserve for depreciation.................................................          1,208,183           1,128,282
                                                                                         ----------          ----------
                                                                                          1,393,984           1,424,413
Construction work in progress...................................................             83,361              58,939
                                                                                         ----------          ----------
                                                                                          1,477,345           1,483,352
                                                                                         ----------          ----------

Other property and investments - less reserve...................................             14,238              12,808

Current assets:
    Cash and temporary cash investments.........................................             59,071               5,453
    Accounts receivable - less reserve of $520 in 1998 and 1997.................            106,003              74,524
    Materials and supplies - at average cost:
       Fuel (predominantly coal)................................................             23,927              27,799
       Other....................................................................             24,877              24,466
    Prepayments and other.......................................................              5,022               4,951
                                                                                         ----------          ----------
                                                                                            218,900             137,193
                                                                                         ----------          ----------

Deferred debits and other assets:
    Unamortized debt expense....................................................              5,227               5,628
    Regulatory assets (Note 3)..................................................             28,228              14,771
    Other  .....................................................................             19,859              26,128
                                                                                         ----------          ----------
                                                                                             53,314              46,527
                                                                                         ----------          ----------
                                                                                         $1,763,797          $1,679,880
                                                                                         ----------          ----------
                                                                                         ----------          ----------


CAPITAL AND LIABILITIES:
Capitalization (see statements of capitalization):
    Common equity...............................................................         $  606,713          $  612,295
    Cumulative preferred stock..................................................             40,000              40,000
    Long-term debt..............................................................            546,330             546,351
                                                                                         ----------          ----------
                                                                                          1,193,043           1,198,646
                                                                                         ----------          ----------

Current liabilities:
    Long-term debt due within one year..........................................                  -                  21
    Notes payable...............................................................                  -              33,600
    Accounts payable............................................................            100,012              33,386
    Provision for rate refund...................................................             21,500                   -
    Dividends declared..........................................................             18,188                 188
    Accrued taxes...............................................................             16,733               7,473
    Accrued interest............................................................              8,110               8,283
    Other  .....................................................................             31,226              26,216
                                                                                         ----------          ----------
                                                                                            195,769             109,167
                                                                                         ----------          ----------

Deferred credits and other liabilities:
    Accumulated deferred income taxes (Note 7)..................................            247,088             245,150
    Investment tax credit, in process of amortization...........................             22,302              26,131
    Accumulated provision for pensions and related benefits.....................             50,044              41,334
    Customers' advances for construction........................................              1,265               1,464
    Regulatory liability (Note 3)...............................................             45,882              51,576
    Other  .....................................................................              8,404               6,412
                                                                                         ----------          ----------
                                                                                            374,985             372,067
                                                                                         ----------          ----------
Commitments and contingencies (Note 11)
                                                                                         $1,763,797          $1,679,880
                                                                                         ----------          ----------
                                                                                         ----------          ----------
</TABLE>

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

                                      153
<PAGE>


                           Kentucky Utilities Company
                            Statements of Cash Flows
                                (Thousands of $)
<TABLE>
<CAPTION>
                                                                                          Years Ended December 31
                                                                                   1998               1997             1996
                                                                                   ----               ----             ----
<S>                                                                         <C>                <C>              <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
    Net income........................................................       $   72,764         $   85,713       $   86,163
    Items not requiring cash currently:
       Depreciation and amortization..................................           86,657             84,111           80,424
       Deferred income taxes - net....................................           (2,437)             4,606            3,750
       Investment tax credit - net....................................           (3,829)            (4,036)          (4,013)
       Deferred merger-related costs..................................          (14,322)            (4,062)               -
    Change in certain net current assets and liabilities:
       Accounts receivable............................................          (31,479)               297            2,551
       Fuel inventory.................................................            3,872              3,095           (1,456)
       Materials and supplies.........................................             (411)            (1,755)           1,764
       Accounts payable...............................................           66,626              4,426           (9,040)
       Provision for rate refund......................................           21,500                  -                -
       Accrued taxes..................................................            9,260              2,090              182
       Accrued interest...............................................             (173)               235              492
       Prepayments and other..........................................               71             (1,481)             278
    Other.............................................................           49,321              5,667           10,702
                                                                             ----------         ----------       ----------
       Net cash flows from operating activities.......................          257,420            178,906          171,797
                                                                             ----------         ----------       ----------

CASH FLOWS FROM INVESTING ACTIVITIES:
    Proceeds form insurance reimbursement.............................              179              4,270              257
    Construction expenditures.........................................          (91,992)           (94,006)        (106,503)
    Other.............................................................                 -                 -              (79)
                                                                             ----------         ----------       ----------
       Net cash flows from investing activities.......................          (91,813)           (89,736)        (106,325)
                                                                             ----------         ----------       ----------

CASH FLOWS FROM FINANCING ACTIVITIES:
    Short-term borrowings.............................................          381,500          2,645,500        2,570,200
    Repayments of short-term borrowings...............................         (415,100)        (2,666,100)      (2,571,600)
    Issuance of first mortgage bonds..................................                -                  -           39,445
    Repayment of first mortgage bonds.................................              (42)               (21)         (36,192)
    Payment of dividends..............................................          (78,347)           (68,815)         (67,303)
                                                                             ----------         ----------       ----------
       Net cash flows from financing activities.......................         (111,989)           (89,436)         (65,450)
                                                                             ----------         ----------       ----------

Change in cash and temporary cash investments.........................           53,618               (266)              22

Cash and temporary cash investments at beginning of year..............            5,453              5,719            5,697
                                                                             ----------         ----------       ----------

Cash and temporary cash investments at end of year....................       $   59,071         $    5,453       $    5,719
                                                                             ----------         ----------       ----------
                                                                             ----------         ----------       ----------

Supplemental disclosures of cash flow information: Cash paid during the year
    for:
       Income taxes...................................................        $  46,490      $      44,857    $      47,539
       Interest on borrowed money.....................................           36,008             37,053           36,729

</TABLE>

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

                                      154
<PAGE>


                           Kentucky Utilities Company
                          Statements of Capitalization
                                (Thousands of $)
<TABLE>
<CAPTION>
                                                                                                      December 31
                                                                                               1998                1997
                                                                                               ----                ----
<S>                                                                                     <C>                 <C>
COMMON EQUITY:
    Common stock, without par value -
       outstanding 37,817,878 shares, respectively..................................     $  308,140          $  308,140
    Retained earnings...............................................................        299,168             304,750
    Other...........................................................................           (595)               (595)
                                                                                         ----------          ----------
                                                                                            606,713             612,295
                                                                                         ----------          ----------
</TABLE>

CUMULATIVE PREFERRED STOCK:
    Redeemable on 30 days notice by KU, except 6.53% series
<TABLE>
<CAPTION>
                                                           Shares           Current
                                                         Outstanding   Redemption Price
                                                         -----------   ----------------
   <S>                                                   <C>           <C>              <C>                 <C>
    Without par value, 5,300,000 shares authorized -
       4.75% series..................................      200,000          100.00           20,000              20,000
       6.53% series..................................      200,000      Not redeemable       20,000              20,000
                                                                                         ----------          ----------
                                                                                             40,000              40,000
                                                                                         ----------          ----------
</TABLE>

<TABLE>
<S>                                                                                     <C>                 <C>
LONG-TERM DEBT (Note 10):
    First mortgage bonds -
       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, 7.38%................................................          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 first mortgage bonds............................................        546,330             546,330

    8% secured note, due January 5, 1999 (net of current maturity)..................              -                  21
                                                                                         ----------          ----------

       Total long-term bonds........................................................        546,330             546,351
                                                                                         ----------          ----------

       Total capitalization.........................................................     $1,193,043          $1,198,646
                                                                                         ----------          ----------
                                                                                         ----------          ----------
</TABLE>

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

                                      155
<PAGE>


                           Kentucky Utilities Company
                          Notes to Financial Statements

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Kentucky Utilities Company (KU) is a subsidiary of LG&E Energy Corp. KU is a 
regulated public utility that is engaged in the generation, transmission, 
distribution, and sale of electric energy. Effective May 4, 1998, following 
the receipt of all required state and federal regulatory approvals, LG&E 
Energy Corp. (LG&E Energy) and KU Energy Corporation (KU Energy) merged, with 
LG&E Energy as the surviving corporation. LG&E Energy is an exempt energy 
services holding company with wholly-owned subsidiaries consisting of KU, 
Louisville Gas and Electric Company (LG&E) and LG&E Capital Corp (Capital 
Corp.) All of KU's Common Stock is held by LG&E Energy.

Certain reclassifications have been made to the 1997 and 1996 financial 
statements to conform to the 1998 presentation with no impact on previously 
reported income.

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

The cost of 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. 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 KU 
approximated 3.5% in 1998, 1997 and 1996.

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.

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.

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

MANAGEMENT'S USE OF ESTIMATES. The preparation of financial statements in 
conformity with generally accepted accounting principles requires management 
to make estimates and assumptions that affect the reported assets and 

                                      156
<PAGE>

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 1998, KU adopted the following 
accounting pronouncements:

Statements of Financial Accounting Standards No. 132, Employers' Disclosures 
about Pensions and Other Post retirement Benefits (SFAS No. 132), effective 
for periods beginning after December 15, 1997. Pursuant to SFAS No. 132, KU 
has disclosed additional information on changes in benefit obligations and 
fair values of plan assets and eliminated certain disclosures that are no 
longer relevant. This standard does not change the measurement or financial 
statement recognition of the plans (See Note 6, Pension Plans and Retirement 
Benefits).

Statement of Position No 98-1, Accounting for the Costs of Computer Software 
Developed or Obtained for Internal Use (SOP 98-1), adopted 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 must be expensed as incurred. 
Adoption of SOP 98-1 did not have a material effect on KU's financial 
statements.

The following accounting pronouncements have been issued but are not yet 
effective:

Statement of Financial Accounting Standards No. 133, Accounting for 
Derivative Instruments and Hedging Activities. The statement is effective for 
fiscal years beginning after June 15, 1999, and establishes accounting and 
reporting standards that every derivative instrument be recorded in the 
balance sheet as either an asset or liability measured at its fair value. The 
statement 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 a company must formally document, designate, and assess the 
effectiveness of transactions that use hedge accounting. KU is currently 
analyzing the provisions of the statement and cannot predict the impact this 
statement will have on its operations and financial position; however, the 
statement could increase volatility in earnings. The effect of this statement 
will be recorded in cumulative effect of change in accounting when adopted.

The Emerging Issues Task Force issue No. 98-10, Accounting for Energy Trading 
and Risk Management Activities (EITF No. 98-10), which is effective for 
fiscal years beginning after December 15, 1998. The task force concluded that 
energy trading contracts should be recorded at mark to market on the balance 
sheet, with the gains and losses shown net in the income statement. EITF 
98-10 more broadly defines what represents energy trading to include economic 
activities related to physical assets which were not previously recorded at 
mark to market by established industry practice. The effects of adopting EITF 
No. 98-10, if applicable, will be reported as a cumulative effect of a change 
in accounting principle with no prior period restatement. KU does not expect 
the adoption of EITF No. 98-10 to have a material adverse impact on its 
operations and financial position.

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, 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 approxi-

                                      157
<PAGE>

mately $760 million in gross non-fuel savings over a ten-year period 
following the merger. Costs to achieve these savings 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 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 net 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.

Under the terms of the Agreement and Plan of Merger dated May 20, 1997 (the 
Merger Agreement) each outstanding share of the common stock, without par 
value, of KU Energy (KU Common Stock) together with the associated KU Energy 
stock purchase rights, was converted into 1.67 shares of common stock of LG&E 
Energy (LG&E Energy Common Stock), together with the associated LG&E Energy 
stock purchase rights. 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.

Regulatory and administrative approvals were obtained from the Federal Energy 
Regulatory Commission (FERC), the Federal Trade Commission, the Securities 
and Exchange Commission, the Virginia State Corporation Commission and the 
stockholders of LG&E Energy and KU Energy prior to the effective date of the 
merger. LG&E Energy, as the parent of LG&E and KU, continues to be an exempt 
holding company under the Public Utility Holding Company Act of 1935. 
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 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 
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 customers. Any fuel cost savings are passed to Kentucky 
customers through KU's fuel adjustment clause.

                                158

<PAGE>

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 the FERC, the Kentucky Commission and the Virginia 
Commission. KU is subject to Statement of Financial Accounting Standards No. 
71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71). 
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 on the balance sheet as of 
December 31 (in thousands of $):

<TABLE>
<CAPTION>
                                                                      1998              1997
                                                                      ----              ----
        <S>                                                   <C>               <C>
         Unamortized loss on bonds                               $   8,675         $   9,756
         Merger costs                                               18,417             4,062
         Other                                                       1,136               953
                                                                 ---------         ---------
         Total regulatory assets                                    28,228            14,771
         Deferred income taxes - net                               (45,882)          (51,576)
         Other regulatory liability                                   (670)             (673)
                                                                 ---------         ---------
         Regulatory assets and (liabilities) - net                $(18,324)         $(37,478)
                                                                 ---------         ---------
                                                                 ---------         ---------
</TABLE>

ENVIRONMENTAL COST RECOVERY. In August 1994, KU implemented an environmental 
cost recovery (ECR) surcharge to recover certain environmental compliance 
costs, including costs to comply with the 1990 Clean Air Act, as amended, as 
well as, other environmental regulations, including those applicable to coal 
combustion wastes and related by-products. The ECR mechanism was authorized 
by state statute in 1992 and was first approved by the Kentucky Commission in 
July 1994.

The Commission's order approving the surcharge in the KU case and the 
constitutionality of the surcharge was challenged by certain intervenors, 
including the Attorney General of Kentucky, in Franklin Circuit Court. 
Decisions of the Circuit Court and the Kentucky Court of Appeals in July 1995 
and December 1997, respectively, have upheld the constitutionality of the ECR 
statute but differed on a claim of retroactive recovery of certain amounts. 
The Commission ordered that certain surcharge revenues collected by KU be 
subject to refund pending final determination of all appeals.

On December 19, 1998, the Kentucky Supreme Court rendered an opinion 
upholding the constitutionality of the surcharge statute. The decision, 
however, reversed the ruling of the Court of Appeals on the retroactivity 
claim, thereby denying recovery of costs associated with pre-1993 
environmental projects through the ECR. The court remanded the case to the 
Commission to determine the proper adjustments to refund amounts collected 
for such pre-1993 environmental projects. The parties to the proceeding have 
notified the Commission that they have reached agreement as to the terms, 
refund amounts, refund procedure and forward application of the ECR. The 
settlement agreement is subject to Commission approval. KU recorded a 
provision for rate refund of $21.5 million in December 1998.

FUEL ADJUSTMENT CLAUSE. KU employs a fuel adjustment clause (FAC) mechanism, 
which under Kentucky law allows the company to recover from customers, the 
actual fuel costs associated with retail electric sales. As of February 12, 
1999, LG&E, a subsidiary of LG&E Energy Corp., received orders from the 
Kentucky Commission requiring a refund to retail electric customers which 
resulted from reviews of the FAC from November 1994 through April 1998. The 
orders changed the method of assigning fuel costs associated with electric 
line losses on off-system sales appropriate for recovery through the FAC. The 
orders require these

                                     159

<PAGE>

amounts to be refunded to customers during first quarter 1999 and to include 
in the FAC calculation the cost of fuel associated with line losses incurred 
in making off-system sales. KU has not received an order from the Kentucky 
Commission but anticipates that it will be required to refund to retail 
electric customers of approximately $3.5 million for the review period 
November 1994 through December 1998. Management does not believe final 
resolution of these proceedings will have a material adverse effect on KU's 
financial position or results of operations.

FUTURE RATE REGULATION. In October 1998, LG&E and KU filed separate but 
parallel with the Commission for approval of a new method of determining 
electric rates that provides financial incentives for LG&E and KU to further 
reduce customers' rates. The filing was made pursuant to the September 1997 
Commission order approving the merger of LG&E Energy and KU Energy, wherein 
the Commission directed LG&E and KU to indicate whether it desired to remain 
under traditional rate of return regulation or commence non-traditional 
regulation. The new ratemaking method, known as performance-based ratemaking 
(PBR), would include 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 provides financial penalties and 
rewards to assure continued high quality service and reliability.

The PBR plan proposed by LG&E and KU consists of five components:

1)       The utilities' fuel adjustment clause mechanism will be withdrawn and
         replaced with a cap that limits recovery of actual changes in fuel cost
         to changes in a fuel price index for a five-state region. If the
         utilities outperform the index, benefits will be shared equally between
         shareholders and customers. If the utilities' fuel costs exceed the
         index, the difference will be absorbed by LG&E Energy's shareholders.

2)       Customers will continue to receive the benefits from the post-merger
         joint dispatch of power from LG&E's and KU's generating plants.

3)       Power plant performance will be measured against the best performance
         achieved between 1991 and 1997. If the performance exceeds this level,
         customers will share equally with LG&E Energy's shareholders in up to
         $10 million annually of benefits from this performance at each of LG&E
         and KU.

4)       The utilities will be encouraged to maintain and improve service
         quality, reliability, customer satisfaction and safety, which will be
         measured against six objective benchmarks. The plan provides for annual
         rewards or penalties to LG&E Energy of up to $5 million per year at
         each of LG&E and KU.

5)       The plan provides KU with greater flexibility to customize rates and
         services to meet customer needs. Services will continue to be priced
         above marginal cost and customers will continue to have the option to
         elect standard tariff service.

These proposals are subject to approval by the Commission. Approval 
proceedings commenced in October 1998 and a final decision likely will occur 
in 1999. Several intervenors are participating in the case. Some have 
requested the Commission to reduce base rates before implementing PBR. KU is 
not able to predict the ultimate outcome of these proceedings, however, 
should the Commission mandate significant rate reductions at KU, through the 
PBR proposal or otherwise, such actions could have a material effect on KU's 
financial condition and result of operations.

KENTUCKY PSC ADMINISTRATIVE CASE FOR AFFILIATE TRANSACTIONS. In December 
1997, the Kentucky Commission opened Administrative Case No. 369 to consider 
Commission policy regarding cost allocations, affiliate transactions and 
codes of conduct governing the relationship between utilities and their 
non-utility 

                                      160
<PAGE>

operations and affiliates. The 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 which result in 
unfair competition caused by cost shifting from the non-utility affiliate to 
the utility. In September 1998, the Commission issued draft code of conduct 
and cost allocation guidelines. In January 1999, KU, as well as all parties 
to the proceeding, issued comments on the Commission draft proposals. Initial 
hearings are scheduled for the first quarter of 1999. 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.

NOTE 4 - FINANCIAL INSTRUMENTS

The cost and estimated fair values of the KU's non-trading financial 
instruments as of December 31, 1998 and 1997 follow (in thousands of $):

<TABLE>
<CAPTION>
                                                                 1998                              1997
                                                                 ----                              ----
                                                                          Fair                               Fair
                                                          Cost           Value             Cost             Value
                                                          ----           -----             ----             -----
       <S>                                           <C>             <C>              <C>               <C>
         Long-term debt                               $546,330        $587,245         $546,351          $578,835
                                                      --------        --------         --------          --------
                                                      --------        --------         --------          --------
</TABLE>

The above valuations reflect prices quoted by exchanges.

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 completely 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 electric revenues arise from deliveries of 
electricity to about 449,000 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, 1998, 100% of total utility revenue 
was derived from electric operations.

KU's operation and maintenance employees are members of the International 
Brotherhood of Electrical Workers (IBEW) Local 101 and United Steelworkers of 
America (USWA) Local 8686. KU has approximately 15% of its workforce covered 
by union contracts expiring August 1, 1999.

                                      161

<PAGE>


NOTE 6 - PENSION PLANS AND RETIREMENT BENEFITS

PENSION PLANS. KU sponsors a 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, 1998 and 
a statement of the funded status as of December 31 of the three years (in 
thousands of $):

<TABLE>
<CAPTION>
                                                                          1998             1997              1996
                                                                          ----             ----              ----
<S>                                                                   <C>              <C>              <C>
         PENSION PLANS:
         Change in benefit obligation
           Benefit obligation at beginning of year                    $214,657         $194,874          $183,795
           Service cost                                                  6,702            6,728             6,399
           Interest cost                                                14,939           14,680            13,856
           Acquisitions/divestitures                                    (2,243)              --                --
           Curtailment (gain) or loss                                    1,901               --                --
           Special termination benefits                                  5,427               --                --
           Benefits paid                                               (12,762)         (13,313)           (9,001)
           Actuarial (gain) or loss                                      2,367           11,688              (175)
                                                                      --------         --------          --------
           Benefit obligation at end of year                          $230,988         $214,657          $194,874
                                                                      --------         --------          --------
                                                                      --------         --------          --------

         Change in plan assets
           Fair value of plan assets at beginning of year             $217,500         $191,879          $179,371
           Actual return on plan assets                                 31,209           35,066            21,463
           Employer contributions                                        2,273            4,750               777
           Benefits paid                                               (12,762)         (13,314)           (9,001)
           Administrative expenses                                         (96)            (882)             (731)
                                                                      --------         --------          --------
           Fair value of plan assets at end of year                   $238,124         $217,499          $191,879
                                                                      --------         --------          --------
                                                                      --------         --------          --------

         Reconciliation of funded status
           Funded status                                             $   7,135        $   2,843         $  (2,995)
           Unrecognized actuarial (gain) or loss                       (26,487)         (19,552)          (12,549)
           Unrecognized transition (asset) or obligation                (1,128)          (1,350)           (1,500)
           Unrecognized prior service cost                               2,831            3,635             3,990
                                                                      --------         --------          --------
           Net amount recognized at year-end                          $(17,649)        $(14,424)         $(13,054)
                                                                      --------         --------          --------
                                                                      --------         --------          --------

         OTHER BENEFITS:
         Change in benefit obligation
           Benefit obligation at beginning of year                    $ 72,139          $66,519           $63,656
           Service cost                                                  2,012            1,853             1,859
           Interest cost                                                 5,207            4,895             4,751
           Curtailment (gain) or loss                                    3,240               --                --
           Special termination benefits                                      -           (4,038)           (3,857)
           Benefits paid                                                (2,617)              --                --
           Actuarial (gain) or loss                                       (331)           2,910               110
                                                                      --------         --------          --------
           Benefit obligation at end of year                          $ 79,650         $ 72,139           $66,519
                                                                      --------         --------          --------
                                                                      --------         --------          --------

         Change in plan assets
           Fair value of plan assets at beginning of year             $ 17,763         $ 13,270          $ 10,427
           Actual return on plan assets                                  5,117            3,569             1,581
           Employer contributions                                        3,805            3,848             3,740
           Benefits paid                                                (2,348)          (2,924)           (2,478)
                                                                      --------         --------          --------
           Fair value of plan assets at end of year                   $ 24,337         $ 17,763          $ 13,270
                                                                      --------         --------          --------
                                                                      --------         --------          --------
</TABLE>


                                       162

<PAGE>

<TABLE>
<CAPTION>
                                                                          1998             1997              1996
                                                                          ----             ----              ----
<S>                                                                  <C>              <C>              <C>
         Reconciliation of funded status
           Funded status                                              $(55,313)        $(54,376)        $ (53,249)
           Unrecognized actuarial (gain) or loss                       (19,944)         (19,697)          (19,977)
           Unrecognized transition (asset) or obligation                45,701           50,118            53,460
                                                                      --------         --------          --------
           Net amount recognized at year-end                          $(29,556)        $(23,955)        $ (19,766)
                                                                      --------         --------          --------
                                                                      --------         --------          --------
</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 statement of
financial position and information for plans with benefit obligations in excess
of plan assets as of December 31, 1998, 1997 and 1996 (in thousands of $):

<TABLE>
<CAPTION>
                                                                          1998             1997              1996
                                                                          ----             ----              ----
<S>                                                                  <C>             <C>               <C>     
         PENSION PLANS:
         Amounts recognized in the statement 
           financial position consisted of:
              Accrued benefit liability                               $(17,649)       $ (14,424)        $ (13,054)
              Other                                                        (22)              --                --
                                                                      --------         --------          --------
              Accrued benefit liability                               $(17,671)       $ (14,424)        $ (13,054)
                                                                      --------         --------          --------
                                                                      --------         --------          --------

         Additional year-end information for plans with benefit obligations in
           excess of plan assets:
              Projected benefit obligation                           $   2,300       $    6,199         $  10,667
              Accumulated benefit obligation                                99            3,975             8,235

         OTHER BENEFITS:
         Amounts recognized in the statement
           financial position consisted of:
              Accrued benefit liability                              $ (29,556)       $ (23,955)        $ (19,766)
              Other                                                     (2,817)          (2,955)               --
                                                                      --------         --------          --------
              Net amount recognized at year-end                      $ (32,373)       $ (26,910)        $ (19,766)
                                                                      --------         --------          --------
                                                                      --------         --------          --------

         Additional year-end information for plans with benefit obligations in
           excess of plan assets:
              Projected benefit obligation                            $ 79,650         $ 72,139          $ 66,519
              Fair value of plan assets                                 24,337           17,763            13,270
</TABLE>


                                       163

<PAGE>


The following table provides the components of net periodic benefit cost for 
the plans for fiscal years 1998, 1997 and 1996 (in thousands of $):

<TABLE>
<CAPTION>
                                                                          1998             1997              1996
                                                                          ----             ----              ----
<S>                                                                <C>               <C>              <C>
         PENSION PLANS:
         Components of net periodic benefit cost
           Service cost                                             $    6,703         $  6,728         $   6,399
           Interest cost                                                14,939           14,680            13,856
           Expected return on plan assets                              (18,264)         (15,427)          (14,410)
           Amortization of transition (asset) or obligation                321              354               354
           Amortization of prior service cost                             (146)            (150)             (150)
           Amortization of net (gain) loss                                (151)             (26)              (24)
                                                                    ----------       ----------        ----------
           Net periodic benefit cost                                $    3,402       $    6,159         $   6,025
                                                                    ----------       ----------        ----------
                                                                    ----------       ----------        ----------

         FAS88 special charges
           Prior service cost recognized                            $       67       $       --         $      --
           Special termination benefits                                  5,427               --                --
                                                                    ----------       ----------        ----------
           Total FAS88 charges                                      $    5,494       $       --        $       --
                                                                    ----------       ----------        ----------
                                                                    ----------       ----------        ----------

         OTHER BENEFITS:
         Components of net periodic benefit cost
           Service cost                                             $    2,012       $    1,853        $    1,859
           Interest cost                                                 5,207            4,895             4,751
           Expected return on plan assets                               (1,424)          (1,051)             (827)
           Amortization of transition (asset) or obligation              3,303            3,341             3,341
           Amortization of net (gain) loss                                (536)            (812)             (703)
                                                                    ----------       ----------        ----------
           Net periodic benefit cost                                $    8,562       $    8,226        $    8,421
                                                                    ----------       ----------        ----------
                                                                    ----------       ----------        ----------

         FAS88 special charges
           Curtailment (gain)/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.
On May 30, 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
Corp'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 post retirement benefits for eligible retired employees.


                                       164

<PAGE>


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

<TABLE>
<CAPTION>
                                                                          1998             1997              1996
                                                                          ----             ----              ----
<S>                                                                     <C>              <C>               <C>
         Weighted-average assumptions as of December 31:
           Discount rate                                                 7.00%            7.75%             7.75%
           Expected long-term rate of return on plan assets              8.25%            8.25%             8.25%
           Rate of compensation increase                                 4.00%            4.75%             4.75%
</TABLE>

For measurement purposes, a 7.00% annual increase in the per capita cost of
covered health care benefits was assumed for 1999. The rate was assumed to
decrease gradually to 4.25% 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:

<TABLE>
<CAPTION>
                                                                                    1% INCREASE
                                                                                    -----------
<S>                                                                                <C>
         Effect on total of service and interest cost components for 1998             $  (1,071)
         Effect on year-end 1998 postretirement benefit obligation                      (10,219)
         Effect on total of service and interest cost components for 1998                 1,373
         Effect on year-end 1998 postretirement benefit obligation                       12,815
</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 were approximately $2.2 million
for each of 1998 and 1997, and $2.1 million for 1996.

NOTE 7 - INCOME TAXES

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

<TABLE>
<CAPTION>
                                                                          1998             1997              1996
                                                                          ----             ----              ----
<S>                                                                <C>               <C>                 <C>
         Included in operating expenses:
           Current         - federal                                   $46,321          $39,353           $35,656
                           - state - net                                10,245            8,964             7,387
           Deferred        - federal - net                              (3,186)           1,996             5,510
                           - state - net                                  (124)           1,377             2,899
                                                                     ---------        ---------          --------
              Total                                                     53,256           51,690            51,452

         Included in other income and (deductions):
           Current         - federal                                      (617)            (853)            3,565
                           - state                                        (237)            (246)              861
           Deferred        - federal - net                                 694              975            (3,665)
                           - state - net                                   178              258              (994)
           Amortization of investment tax credit                        (3,829)          (4,036)           (4,013)
                                                                     ---------        ----------        ----------
              Total                                                     (3,811)          (3,902)           (4,246)
                                                                     ---------        ----------        ----------

         Total income tax expense                                      $49,445          $47,788           $47,206
                                                                     ---------        ----------        ----------
                                                                     ---------        ----------        ----------
</TABLE>

                                       165

<PAGE>


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

<TABLE>
<CAPTION>
                                                                          1998             1997
                                                                          ----             ----
<S>                                                               <C>                <C> 
         Deferred tax liabilities:
           Depreciation and other
              plant-related items                                     $289,147         $285,034
           Other liabilities                                             5,598            5,389
                                                                     ---------        ---------
                                                                       294,745          290,423
                                                                     ---------        ---------

         Deferred tax assets:
           Investment tax credit                                         9,001           10,547
           Income taxes due to customers                                17,574           19,217
           Accrued liabilities not currently
              deductible and other                                      23,677           18,750
           Less:  amounts included in
              current assets                                             2,595            3,241
                                                                     ---------        ---------
                                                                        47,657           45,273
                                                                     ---------        ---------

         Net deferred income tax liability                            $247,088         $245,150
                                                                     ---------        ---------
                                                                     ---------        ---------
</TABLE>

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

<TABLE>
<CAPTION>
                                                                          1998             1997              1996
                                                                          ----             ----              ----
<S>                                                                      <C>              <C>               <C>
         Statutory federal income tax rate                                35.0%            35.0%             35.0%
         State income taxes net of federal benefit                         5.4              5.0               4.9
         Amortization of investment tax credit                            (3.1)            (3.0)             (3.0)
         Nondeductible merger expenses                                     6.4               --                --
         Other differences - net                                          (2.2)            (1.2)             (1.5)
                                                                         -----            -----             -----

         Effective income tax rate                                        41.5%            35.8%             35.4%
                                                                         -----            -----             -----
                                                                         -----            -----             -----
</TABLE>

NOTE 8 - OTHER INCOME AND DEDUCTIONS

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

<TABLE>
<CAPTION>
                                                                          1998             1997              1996
                                                                          ----             ----              ----
<S>                                                                    <C>             <C>                <C>
         Equity in earnings - subsidiary company                       $ 2,167         $  2,480           $ 2,436
         Interest and dividend income                                    1,811            1,673             1,733
         Gains (losses) on fixed asset disposal                            272              412                87
         Donations                                                        (453)            (388)             (379)
         Income taxes and other                                          4,049            2,826             4,566
                                                                      --------         --------          --------

         Total other income and deductions                             $ 7,846          $ 7,003           $ 8,443
                                                                      --------         --------          --------
                                                                      --------         --------          --------
</TABLE>

NOTE 9 - FIRST MORTGAGE BONDS AND POLLUTION CONTROL BONDS

Under the provisions for the KU's variable rate Pollution Control Bonds Series
10, KU can choose between various interest rate options. The daily interest rate
option was utilized at December 31, 1998. The average annual interest rate on
the bonds during 1998 and 1997 was 3.54% and 3.77%, respectively. The variable
rate 


                                       166

<PAGE>

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. If tendered
bonds are not remarketed, KU has available lines of credit which may be used to
repurchase the bonds.

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, 1998. KU had
outstanding commercial paper of $33.6 million at December 31, 1997, at a
weighted average interest rate of 6.79%.

At December 31, 1998, KU had lines of credit in place totaling $60 million, all
of which remained unused at December 31, 1998. In support of these lines of
credit, KU pays commitment or facility fees. The KU credit facilities provide
for short-term borrowing and support of commercial paper borrowings. The credit
lines will expire in December 1999. Management expects to renegotiate these
lines when they expire.

NOTE 11 - COMMITMENTS AND CONTINGENCIES

CONSTRUCTION PROGRAM. KU had $6.5 million of commitments in connection with its
construction program at December 31, 1998. Construction expenditures for the
years 1999 and 2000 are estimated to total approximately $341 million.

OPERATING LEASES. KU leases office space, office equipment, and vehicles. KU
accounts for these leases as operating leases. Total lease expense for 1998,
1997, and 1996, was $1.9 million, $1.8 million, and $1.7 million, respectively.
The future minimum annual lease payments under lease agreements for years
subsequent to December 31, 1998, are as follows (in thousands of $):

<TABLE>
<S>                                                                          <C>
         1999                                                                $ 1,059
         2000                                                                    983
         2001                                                                    927
         2002                                                                    862
         2003                                                                    811
                                                                            --------
         Total                                                               $ 4,642
                                                                            --------
                                                                            --------
</TABLE>

ENVIRONMENTAL. In September, 1998, the U.S. Environmental Protection Agency
(USEPA) announced its final regulation requiring significant additional
reductions in nitrogen oxide (NOx) emissions to mitigate alleged ozone transport
to the Northeast. While each state is free to allocate its assigned NOx
reductions among various emissions sectors as it deems appropriate, the
regulation may ultimately require utilities to reduce their NOx emissions to
0.15 lb./mmBtu (million British thermal units) - an 85% reduction from 1990
levels. Under the regulation, each state must incorporate the additional NOx
reductions in its State Implementation Plan (SIP) by September 1999 and affected
sources must install control measures by May 2003, unless granted extensions.
Several states, various labor and industry groups, and individual companies have
appealed the final regulation to the U.S. Court of Appeals for the D.C. Circuit.
Management is currently unable to determine the outcome or exact impact of this
matter until such time as the states identify specific emissions reductions in
their SIP and the courts rule on the various legal challenges to the final rule.
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 and analysis, KU
estimates that it may incur capital costs of approximately $100 to $200 million
for KU. These costs would generally be incurred beginning in 2000.


                                       167

<PAGE>

KU believes its costs for these matters 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 cost recovery
from customers under its environmental surcharge mechanisms and believes that,
in the case of KU, a significant portion of such costs could be so recovered.
However, Kentucky Commission approval is necessary and there can be no guarantee
of such recovery.

In July, 1997, USEPA issued revised National Ambient Air Quality Standards
(NAAQS) for ozone and particulate matter. KU is monitoring USEPA's
implementation of the revised standards. Until USEPA completes additional
implementation steps, including monitoring and nonattainment demonstrations,
management is unable to determine the precise impact of the revised standards.

KU is addressing potential liabilities for the cleanup of properties where
hazardous substances may have been released. KU along with other companies has
been identified by USEPA as a potentially responsible party allegedly liable for
cleanup of off-site disposal facilities under the Comprehensive Environmental
Response Compensation and Liability Act. KU is currently participating as a de
minimis party in one such matter. In addition, KU has conducted various
voluntary cleanups of KU owned properties, including cleanup of a former
manufactured gas plant site.

PURCHASED POWER. KU has purchase power arrangements with Owensboro Municipal
Utilities (OMU), Electric Energy, Inc. (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 1999-2003, which is expected to be approximately 9% 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 $180 million
of OMU bonds outstanding at December 31, 1998. The debt service is allocated to
KU based on its annual allocated share of capacity, which averaged approximately
49% in 1998.

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 1999-2003 of various
MW capacities and for varying periods with a maximum entitlement at any time of
282 MW.

The estimated future minimum annual payments under purchased power agreements
for the five years ended December 31, 2003 follow (in thousands of $):

<TABLE>
<S>                                                                       <C>
         1999                                                             $   34,291
         2000                                                                 26,712
         2001                                                                 29,621
         2002                                                                 29,561
         2003                                                                 29,670
                                                                          ----------
         Total                                                             $ 149,855
                                                                          ----------
                                                                          ----------
</TABLE>


                                       168

<PAGE>


NOTE 12 - SELECTED QUARTERLY DATA (UNAUDITED)

Selected financial data for the four quarters of 1998 and 1997 are shown below.
Because of seasonal fluctuations in temperature and other factors, results for
quarters may fluctuate throughout the year.

<TABLE>
<CAPTION>
                                                                             Quarters Ended
                                                             March         June        September       December
                                                          ------------  -----------   -------------  ------------
                                                                            (Thousands of $)
<S>                                                       <C>            <C>            <C>          <C>
         1998
         Revenues                                         $183,219       $193,079       $246,117      $187,699
         Operating income                                   33,035         28,144         44,677        19,531
         Net income (loss)                                  25,049         (1,119)        36,980        11,854
         Net income (loss) available
           for common stock                                 24,485         (1,683) (a)    36,416 (b)    11,290(c)

         1997
         Revenues                                         $178,914       $162,868       $192,102      $182,553
         Operating income                                   33,424         19,742         35,343        29,889
         Net income                                         24,961         12,088         26,924        21,740
         Net income available
           for common stock                                 24,397         11,524         26,360        21,176
</TABLE>

(a)           The decrease of $13.2 million compared to June 1997 was due to a
              non-recurring after-tax charge of $21.5 million from
              merger-related expenses, offset by an increase of $8.3 million due
              to increased sales caused by warmer weather and lower maintenance
              expenses.

(b)           The increase of $10.1 million compared to September 1997 was due
              to increased sales caused by warmer weather and an increase in
              wholesale sales.

(c)           The decrease of $9.9 million compared to December 1997 was due to
              an after-tax charge of $12.9 million related to refunds of certain
              amounts collected under the Environmental Cost Recovery surcharge,
              partially offset by higher wholesale sales.

NOTE 13 - SUBSEQUENT EVENT

On March 8, 1999, the Kentucky Industrial Utility Customers filed a complaint
with the Kentucky Commission alleging that KU's electric rates are excessive and
should be reduced by an amount between $42 and $56 million, and that the
Kentucky Commission establish a proceeding to reduce KU's rates. KU has asked
the Kentucky Commission to dismiss the complaint. KU is not able to predict the
ultimate outcome of these proceedings, however, should the Commission mandate
significant rate reductions at KU, through the PBR proposal or otherwise, such
actions could have a material effect on KU's financial condition and results of
operations.


                                       169

<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.


                                       170

<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, 1998 and 1997, and the related statements of income, retained 
earnings and cash flows for each of the three years in the period ended 
December 31, 1998. 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 generally accepted auditing
standards. 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, 1998 and 1997, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 1998, in
conformity with generally accepted accounting principles.

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 27, 1999 (Except with respect
to the matters discussed in the fifth paragraph of Note 3, as to which the date
is February 12, 1999, and Note 13, as to which the date is March 8, 1999.)


                                       171

<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, inasmuch
as LG&E Energy and LG&E filed copies of their definitive proxy statements with
the Commission on March 26, 1999, respectively, pursuant to Regulation 14A under
the Securities Exchange Act of 1934. Such proxy and information statements are
incorporated herein by this reference. In accordance with General Instruction G
of Form 10-K, the information required by Item 10 relating to executive officers
has been included in Part I of this Form 10-K. 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. In accordance with General
Instruction G of Form 10-K, the information required by Item 10 relating to
executive officers of 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, 1998 (page 84). 
           Consolidated statements of retained earnings for the three years 
             ended December 31, 1998 (page 85). 
           Consolidated statements of comprehensive income for the three years 
             ended December 31, 1998 (page 85) 
           Consolidated balance sheets - December 31, 1998, and 1997 (page 86). 
           Consolidated statements of cash flows for the 
             three years ended December 31, 1998 (page 87). 
           Consolidated statements of capitalization - December 31, 1998, and 
             1997 (page 88).
           Notes to consolidated financial statements (pages 90-123). 
           Report of management (page 125). 
           Report of independent public accountants (page 126).

           LG&E:
           Statements of income for the three years ended December 31, 1998
             (page 127). 
           Statements of retained earnings for the three years ended
             December 31, 1998 (page 127). 
           Statements of comprehensive income for the three years ended 
             December 31, 1998 (page 128).
           Balance sheets - December 31, 1998, and 1997 (page 129).
           Statements of cash flows for the three years ended December 31, 1998
             (page 130). 
           Statements of capitalization - December 31, 1998, and 1997 
             (page 131).
           Notes to financial statements (pages 132-149). 
           Report of management (page 150). 
           Report of independent public accountants (page 151).


                                       172

<PAGE>


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

           KU:
           Statements of income for the three years ended December 31, 1998
             (page 152). 
           Statements of retained earnings for the three years ended 
             December 31, 1998 (page 152).
           Balance sheets - December 31, 1998, and 1997 (page 153).
           Statements of cash flows for the three years ended December 31, 1998
             (page 154). 
           Statements of capitalization - December 31, 1998, and 1997 
             (page 155).
           Notes to financial statements (pages 156-169). 
           Report of management (page 170). 
           Report of independent public accountants (page 170).

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

           Schedule            II Valuation and Qualifying Accounts for the
                               three years ended December 31, 1998, for LG&E
                               Energy (page 195), LG&E (page 196), and 
                               KU (page 197).

           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:

<TABLE>
<CAPTION>
                            Applicable
                          to Form 10-K of
Exhibit            LG&E
No.              Energy        LG&E        KU          Description
-------         ----------   ----------  ----------   -------------
<S>             <C>           <C>        <C>          <C>

2.01                  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 May 4,
                                                       1998.  [Filed as Exhibit 4.2 to LG&E Energy's Current
                                                       Report on Form 8-K dated May 4, 1998, and incorporated by
                                                       reference herein]
</TABLE>


                                       173

<PAGE>

<TABLE>
<CAPTION>
                            Applicable
                          to Form 10-K of
Exhibit            LG&E
No.              Energy        LG&E        KU          Description
-------         ----------   ----------  ----------   -------------
<S>             <C>           <C>        <C>          <C>

3.04                             x                     Copy of By-Laws of LG&E, as amended through May 4, 1998.

3.05                                        x          Amended and Restated Articles of Incorporation of Kentucky
                                                       Utilities Company  [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          By-laws of Kentucky Utilities Company dated April 28, 1998.

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 
</TABLE>


                                       174

<PAGE>

<TABLE>
<CAPTION>
                            Applicable
                          to Form 10-K of
Exhibit            LG&E
No.              Energy        LG&E        KU          Description
-------         ----------   ----------  ----------   -------------
<S>             <C>           <C>        <C>          <C>

                                                       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 
</TABLE>


                                       175

<PAGE>

<TABLE>
<CAPTION>
                            Applicable
                          to Form 10-K of
Exhibit            LG&E
No.              Energy        LG&E        KU          Description
-------         ----------   ----------  ----------   -------------
<S>             <C>           <C>        <C>          <C>
                                                       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 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,
</TABLE>


                                       176

<PAGE>

<TABLE>
<CAPTION>
                            Applicable
                          to Form 10-K of
Exhibit            LG&E
No.              Energy        LG&E        KU          Description
-------         ----------   ----------  ----------   -------------
<S>             <C>           <C>        <C>          <C>
                                                       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]
</TABLE>


                                       177

<PAGE>

<TABLE>
<CAPTION>
                            Applicable
                          to Form 10-K of
Exhibit            LG&E
No.              Energy        LG&E        KU          Description
-------         ----------   ----------  ----------   -------------
<S>             <C>           <C>        <C>          <C>
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 Kentucky Utilities Company 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 
</TABLE>


                                       178

<PAGE>

<TABLE>
<CAPTION>
                            Applicable
                          to Form 10-K of
Exhibit            LG&E
No.              Energy        LG&E        KU          Description
-------         ----------   ----------  ----------   -------------
<S>             <C>           <C>        <C>          <C>
                                                       (Exhibit 2 to Form 10-Q Quarterly Report of KU for the quarter
                                                       ended June 30, 1980), September 15, 1982 (Exhibit 4.04 in File
                                                       No. 2-79891), August 1, 1984 (Exhibit 4B to Form 10-K
                                                       Annual Report of KU for the year ended December 31, 1984),
                                                       June 1, 1985 (Exhibit 4 to Form 10-Q Quarterly Report of
                                                       KU for the quarter ended June 30, 1985), May 1, 1990
                                                       (Exhibit 4 to Form 10-Q Quarterly Report of KU for the
                                                       quarter ended June 30, 1990), May 1, 1991 (Exhibit 4 to
                                                       Form 10-Q Quarterly Report of KU for the quarter ended
                                                       June 30, 1991), May 15, 1992 (Exhibit 4.02 to Form 8-K of
                                                       KU dated May 14, 1992), August 1, 1992 (Exhibit 4 to Form
                                                       10-Q Quarterly Report of KU for the quarter ended
                                                       September 30, 1992), June 15, 1993 (Exhibit 4.02 to Form
                                                       8-K of KU dated June 15, 1993) and December 1, 1993
                                                       (Exhibit 4.01 to Form 8-K of KU dated December 10, 1993),
                                                       November 1, 1994 (Exhibit 4.C to Form 10-K Annual Report
                                                       of KU for the year ended December 31, 1994), June 1, 1995
                                                       (Exhibit 4 to Form 10-Q Quarterly Report of KU for the
                                                       quarter ended June 30, 1995) and January 15, 1996 (Exhibit
                                                       4.E to Form 10-K Annual Report of KU for the year ended
                                                       December 31, 1995).  Incorporated by reference.

4.38                  x                     x          Supplemental Indenture dated March 1, 1992 between
                                                       Kentucky Utilities Company 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 
</TABLE>


                                       179

<PAGE>

<TABLE>
<CAPTION>
                            Applicable
                          to Form 10-K of
Exhibit            LG&E
No.              Energy        LG&E        KU          Description
-------         ----------   ----------  ----------   -------------
<S>             <C>           <C>        <C>          <C>
                                                       Agreement between Ohio Valley Electric Corporation
                                                       and Atomic Energy Commission.  [Filed as Exhibit 5.02c to
                                                       LG&E's Registration Statement 2-61607 and incorporated by
                                                       reference herein]

10.04                 x          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                     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                     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 
</TABLE>


                                       180

<PAGE>

<TABLE>
<CAPTION>
                            Applicable
                          to Form 10-K of
Exhibit            LG&E
No.              Energy        LG&E        KU          Description
-------         ----------   ----------  ----------   -------------
<S>             <C>           <C>        <C>          <C>
                                                       Supplementary Transmission Agreement, dated July 10,
                                                       1953, among Ohio Valley Electric Corporation and the
                                                       Sponsoring Companies.  [Filed as Exhibit 5.02i to LG&E's
                                                       Registration Statement 2-61607 and incorporated by
                                                       reference herein]

10.10                 x          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                     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                     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]
</TABLE>


                                       181

<PAGE>
<TABLE>
<CAPTION>
                            Applicable
                          to Form 10-K of
Exhibit            LG&E
No.              Energy        LG&E        KU          Description
-------         ----------   ----------  ----------   -------------
<S>             <C>           <C>        <C>          <C>
10.17                 x          x                     Copy of Modification No. 8 dated June 23, 1977, to the
                                                       Power Agreement between Ohio Valley Electric Corporation
                                                       and Atomic Energy Commission.  [Filed as Exhibit 5.02q to
                                                       LG&E's Registration Statement 2-61607 and incorporated by
                                                       reference herein]

10.18                 x          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                     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                     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
</TABLE>


                                       182

<PAGE>

<TABLE>
<CAPTION>
                            Applicable
                          to Form 10-K of
Exhibit            LG&E
No.              Energy        LG&E        KU          Description
-------         ----------   ----------  ----------   -------------
<S>             <C>           <C>        <C>          <C>

                                                       Plan effective January 1, 1992, covering non-employee
                                                       directors of the Company and its subsidiaries.  [Filed as
                                                       Exhibit 10.34 to 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                     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.
</TABLE>


                                       183

<PAGE>

<TABLE>
<CAPTION>
                            Applicable
                          to Form 10-K of
Exhibit            LG&E
No.              Energy        LG&E        KU          Description
-------         ----------   ----------  ----------   -------------
<S>             <C>           <C>        <C>          <C>
                                                       Copy of Firm No Notice Transportation Agreement
                                                       effective November 1, 1993, between Texas Gas
                                                       Transmission Corporation and LG&E (expires October
                                                       31, 2000) covering the transmission of natural gas.

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

                                                       [Filed as Exhibit 10.47 to LG&E's Annual Report
                                                       on Form 10-K for the year ended December 31, 1993,
                                                       and incorporated by reference herein]

10.32                 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                     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                     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 
</TABLE>


                                       184

<PAGE>

<TABLE>
<CAPTION>
                            Applicable
                          to Form 10-K of
Exhibit            LG&E
No.              Energy        LG&E        KU          Description
-------         ----------   ----------  ----------   -------------
<S>             <C>           <C>        <C>          <C>
                                                       February 21, 1995, and incorporated by reference herein]

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 
</TABLE>


                                       185

<PAGE>

<TABLE>
<CAPTION>
                            Applicable
                          to Form 10-K of
Exhibit            LG&E
No.              Energy        LG&E        KU          Description
-------         ----------   ----------  ----------   -------------
<S>             <C>           <C>        <C>          <C>
                                                       Annual Report on Form 10-K for the year ended
                                                       December 31, 1995, and incorporated by reference herein]

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 
</TABLE>


                                       186

<PAGE>

<TABLE>
<CAPTION>
                            Applicable
                          to Form 10-K of
Exhibit            LG&E
No.              Energy        LG&E        KU          Description
-------         ----------   ----------  ----------   -------------
<S>             <C>           <C>        <C>          <C>
                                                       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]

10.50                 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.
</TABLE>


                                       187

<PAGE>

<TABLE>
<CAPTION>
                            Applicable
                          to Form 10-K of
Exhibit            LG&E
No.              Energy        LG&E        KU          Description
-------         ----------   ----------  ----------   -------------
<S>             <C>           <C>        <C>          <C>
                                                       [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]

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]
</TABLE>


                                       188

<PAGE>

<TABLE>
<CAPTION>
                            Applicable
                          to Form 10-K of
Exhibit            LG&E
No.              Energy        LG&E        KU          Description
-------         ----------   ----------  ----------   -------------
<S>             <C>           <C>        <C>          <C>
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 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                 x                     x          *  KU's Amended and Restated Performance Share Plan
                                                       [Filed as Exhibit 10.A to Form 10-Q Quarterly Report of KU
                                                       for the quarter ended June 30, 1993, and incorporated by
                                                       reference herein]

10.67                 x                     x          *  KU's Annual Performance Incentive Plan  [Filed as
                                                       Exhibit 10B to Form 10-K Annual Report of KU for the year
                                                       ended December 31, 1990, and incorporated by reference
                                                       herein]

10.68                 x                     x          *  Amendment No. 1 to KU's Performance Share Plan  [Filed
                                                       as Exhibit 10.03 to Form 10-K Annual Report for KU for the
                                                       year ended December 31, 1996, and incorporated by
                                                       reference herein]

10.69                 x                     x          *  Amendment No. 1 to KU's Annual Performance Incentive
                                                       Plan  [Filed as Exhibit 10D to Form 10-K Annual Report of
                                                       KU for the year ended December 31, 1991, and incorporated
                                                       by reference herein]

10.70                 x                     x          *  Amendment No. 2 to KU's Annual Performance Incentive
                                                       Plan  [Filed as Exhibit 10.H to Form 10-K Annual Report of
                                                       KU for the year ended December 31, 1993, and incorporated
                                                       by reference herein]
</TABLE>


                                       189

<PAGE>

<TABLE>
<CAPTION>
                            Applicable
                          to Form 10-K of
Exhibit            LG&E
No.              Energy        LG&E        KU          Description
-------         ----------   ----------  ----------   -------------
<S>             <C>           <C>        <C>          <C>
10.71                 x                     x          *  Amendment No. 3 to KU's Annual Performance Incentive
                                                       Plan  [Filed as Exhibit 10.I to Form 10-K Annual Report of
                                                       KU for the year ended December 31, 1993, and incorporated
                                                       by reference herein]

10.72                 x                     x          *  Amendment No. 4 to KU's Annual Performance Incentive
                                                       Plan  [Filed as Exhibit 10.07 to Form 10-K Annual Report
                                                       for KU for the year ended December 31, 1996, and
                                                       incorporated by reference herein]

10.73                 x                     x          *  KU's Executive Optional Deferred Compensation Plan
                                                       [Filed as Exhibit 10.08 to Form 10-K Annual Report for KU
                                                       for the year ended December 31, 1996, and incorporated by
                                                       reference herein]

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.

10.77                 x          x                     Copy of Coal Supply Agreement dated January 1, 1999
                                                       between LG&E and Peabody COALSALES Company.

10.78                 x                     x          Copy of Coal Supply Agreement dated December 31, 1997
                                                       between KU and Leslie Resources, Inc.

10.79                 x                     x          Copy of Amendment No. One to Contract dated November 16,
                                                       1998 between KU, Leslie Resources, Inc., AEI Coal Sales
                                                       Company, Inc. and AEI Holding Company, Inc. regarding Coal
                                                       Supply Agreement dated December 31, 1997.

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.
</TABLE>


                                       190

<PAGE>

<TABLE>
<CAPTION>
                            Applicable
                          to Form 10-K of
Exhibit            LG&E
No.              Energy        LG&E        KU          Description
-------         ----------   ----------  ----------   -------------
<S>             <C>           <C>        <C>          <C>
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.

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.

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.]

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.]

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.]

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.]

10.87                 x                                Copy of Form of Lease and Operating Agreement Between
                                                       Western Kentucky Energy Corp. and Big Rivers Electric
                                                       Corporation 
</TABLE>


                                       191

<PAGE>

<TABLE>
<CAPTION>
                            Applicable
                          to Form 10-K of
Exhibit            LG&E
No.              Energy        LG&E        KU          Description
-------         ----------   ----------  ----------   -------------
<S>             <C>           <C>        <C>          <C>
                                                       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.]

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.]

10.89                 x                                Copy of Agreement and Amendments to Agreements By and
                                                       Among City of Henderson, Kentucky, City of Henderson
                                                       Utility Commission, Big Rivers Electric Corporation, WKE
                                                       Station Two Inc., LG&E Energy Marketing Inc., and Western
                                                       Kentucky Energy Corp. dated July 15, 1998.

10.90                 x          x          x          *  Copy of Amendment to LG&E Energy's Supplemental
                                                       Executive Retirement Plan, effective September 2, 1998.

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.

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.

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.
</TABLE>


                                       192

<PAGE>

<TABLE>
<CAPTION>
                            Applicable
                          to Form 10-K of
Exhibit            LG&E
No.              Energy        LG&E        KU          Description
-------         ----------   ----------  ----------   -------------
<S>             <C>           <C>        <C>          <C>
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.
</TABLE>



(b) Executive Compensation Plans and Arrangements:

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

(c) Reports on Form 8-K:

    On October 2, 1998, the Company filed a report on Form 8-K announcing
    that Michael R. Whitley, Vice Chairman of the Board of Directors,
    President and Chief Operating Officer of LG&E Energy Corp. announced his
    retirement, effective November 1, 1998. Mr. Whitley also retired from the
    positions of Vice Chairman of the Board of Directors and Chief Operating
    Officer of Louisville Gas and Electric Company and Kentucky Utilities
    Company, two public utility subsidiaries of the Company.

    On October 21, 1998, the Company filed a report on Form 8-K containing
    management's discussion and analysis and consolidated financial
    statements of the Company as of December 31, 1997. The Company filed this
    report in connection with the May 4, 1998, merger of KU Energy
    Corporation and LG&E Energy Corp.

    On December 21, 1998, the Company filed a report on Form 8-K announcing
    that LG&E Energy Corp. noted the recent decision of the Kentucky Supreme
    Court regarding the environmental cost recovery mechanism allowing its
    subsidiaries, Kentucky Utilities Company and Louisville Gas and Electric
    Company, to recover certain costs associated with environmental
    compliance and requiring certain refunds.

    On February 11, 1999, the Company filed a report on Form 8-K announcing
    that it had realigned its management structure to support its strategy of
    aggressively growing the company as the energy services industry moves
    toward deregulation.

    On March 23, 1999, the Company filed a report on Form 8-K announcing that
    on March 15, 1999, LG&E-Westmoreland Rensselaer, a California general
    partnership in which LG&E Energy owns a 50% interest, completed the sale
    of substantially all the assets and major contracts of its 79 MW
    gas-fired cogeneration facility in Rensselaer, New York to Fulton
    Cogeneration Associates, L.P., an affiliate of The Coastal Corporation.

(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.


                                       193

<PAGE>

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

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

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

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

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

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

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

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



                                       194

<PAGE>

                                                                    Schedule II

                       LG&E Energy Corp. and Subsidiaries
                 Schedule II - Valuation and Qualifying Accounts
                   For the Three Years Ended December 31, 1998
                                (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, 1995                                $  8,785            $  6,724          $        -              $29,501

Additions:
    Charged to costs and expenses                          11,019               4,840                   -                    -
    Other additions                                           641                 616                   -                    -
Deductions:
    Net charges of nature for which
       reserves were created                                    -               5,059                   -                    -
    Other deductions                                        1,479                   -                   -                3,900
                                                        ---------           ---------          ----------             --------

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             225,000                    -
    Other additions                                         1,750                 248                   -                    -
Deductions:
    Net charges of nature for which
       reserves were created                               11,399               4,648             105,619                    -
    Other deductions                                          108                  25                                        -
                                                        ---------           ---------          ----------             --------

Balance December 31, 1998                                 $52,091             $10,532            $119,381              $25,601
                                                        ---------           ---------          ----------             --------
                                                        ---------           ---------          ----------             --------
</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.

                                      195

<PAGE>

                                                                    Schedule II

                        Louisville Gas and Electric Company
                 Schedule II - Valuation and Qualifying Accounts
                   For the Three Years Ended December 31, 1998
                                (Thousands of $)

<TABLE>
<CAPTION>
                                                                                            Other                  Accounts
                                                                                         Property                Receivable
                                                                                              and            (Uncollectible
                                                                                      Investments                 Accounts)
                                                                                      -----------            --------------
<S>                                                                                      <C>                       <C>
Balance December 31, 1995                                                                $     63                  $  1,360

Additions:
    Charged to costs and expenses                                                               -                     2,600
Deductions:
    Net charges of nature for which
       reserves were created                                                                    -                     2,490
                                                                                         --------                  --------

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
                                                                                         --------                  --------
                                                                                         --------                  --------
</TABLE>

                                      196

<PAGE>

                                                                    Schedule II

                            Kentucky Utilities Company
                 Schedule II - Valuation and Qualifying Accounts
                   For the Three Years Ended December 31, 1998
                                (Thousands of $)

<TABLE>
<CAPTION>
                                                                                            Other                  Accounts
                                                                                         Property                Receivable
                                                                                              and            (Uncollectible
                                                                                      Investments                 Accounts)
                                                                                      -----------            --------------
<S>                                                                                   <C>                    <C>
Balance December 31, 1995                                                                 $   178                   $   455

Additions:
    Charged to costs and expenses                                                              85                     1,900
Deductions:
    Net charges of nature for which
       reserves were created                                                                    -                     1,835
                                                                                          -------                   -------

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
                                                                                          -------                   -------
                                                                                          -------                   -------
</TABLE>

                                      197

<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 31, 1999                                   /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.

<TABLE>
<CAPTION>

Signature                       Title                                 Date
---------                       -----                                 ----
<S>                             <C>                                   <C>
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;

Jeffery T. Grade                Director;

J. David Grissom                Director;

David B. Lewis                  Director;

Anne H. McNamara                Director;

By /s/ R. Foster Duncan                                               March 31, 1999
   --------------------
   R. Foster Duncan
   (Attorney-In-Fact)
</TABLE>

                                      198

<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.

<TABLE>
<CAPTION>
Signature                       Title                                 Date
---------                       -----                                 ----
<S>                             <C>                                   <C>
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 31, 1999
   --------------------
   R. Foster Duncan
   (Attorney-In-Fact)
</TABLE>

                                      199

<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 31, 1999                              /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.

<TABLE>
<CAPTION>
Signature                       Title                                 Date
---------                       -----                                 ----
<S>                             <C>                                   <C>
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;

Gene P. Gardner                 Director; 

Carol M. Gatton                 Director;

Jeffery T. Grade                Director;

J. David Grissom                Director;

David B. Lewis                  Director;

By /s/ R. Foster Duncan                                               March 31, 1999
   --------------------
   R. Foster Duncan
   (Attorney-In-Fact)
</TABLE>

                                      200

<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.

<TABLE>
<CAPTION>
Signature                       Title                                 Date
---------                       -----                                 ----
<S>                             <C>                                   <C>
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;

Dr. Donald C. Swain             Director; and

Lee T. Todd, Jr., Ph.D.         Director.

By  /s/ R. Foster Duncan                                              March 31, 1999
    --------------------
    R. Foster Duncan
    (Attorney-In-Fact)
</TABLE>

                                      201

<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 31, 1999                                   /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.

<TABLE>
<CAPTION>
Signature                       Title                                 Date
---------                       -----                                 ----
<S>                             <C>                                   <C>
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;

Jeffery T. Grade                Director;

J. David Grissom                Director;

David B. Lewis                  Director;

Anne H. McNamara                Director;

By  /s/ R. Foster Duncan                                              March 31, 1999
    --------------------
    R. Foster Duncan
    (Attorney-In-Fact)
</TABLE>

                                      202

<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.

<TABLE>
<CAPTION>
Signature                       Title                                 Date
---------                       -----                                 ----
<S>                             <C>                                   <C>
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 31, 1999
    --------------------
    R. Foster Duncan
    (Attorney-In-Fact)
</TABLE>

                                      203