<PAGE>



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

                          ---------------------------

                                  FORM 10-K

[x] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
    OF 1934 (FEE REQUIRED)

For the fiscal year ended DECEMBER 31, 1995

                                      OR

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

                          Commission File No. 2-26720


            --------------------------------------------------------
                     LOUISVILLE GAS AND ELECTRIC COMPANY
            (Exact name of registrant as specified in its charter)
            --------------------------------------------------------


           KENTUCKY                                         61-0264150
(State or other jurisdiction of                              (I.R.S.Employer
incorporation or organization)                             Identification No.)

220 W. MAIN STREET
P. O. BOX 32010                                        (502) 627-2000
LOUISVILLE, KENTUCKY 40232                          (Registrant's telephone
(Address of principal executive offices)          number, including area code)

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
                                                        Name of each exchange on
                 Title of each class                        which registered
                 -------------------                    ------------------------
               First Mortgage Bonds,                    New York Stock Exchange
          Series due July 1, 2002, 7 1/2%

SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
                        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)

Indicate by check mark whether the registrant (1) has 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 registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.   Yes /X/ .    No    .
                                        -----       ----

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.  [X]
            ---
As of February 29, 1996, the aggregate market value of the registrant's voting
stock held by non-affiliates was $16,882,700 and the number of outstanding
shares of the registrant's common stock, without par value, was 21,294,223 all
of which were held by LG&E Energy Corp.

                     DOCUMENTS INCORPORATED BY REFERENCE
The proxy statement of Louisville Gas and Electric Company filed with the
Commission on March 13, 1996, is incorporated by reference into Part III of this
Form 10-K.


<PAGE>

                                TABLE OF CONTENTS


                                     PART I                             PAGE

   Item  1. Business...................................................    1
              General..................................................    1
              Electric Operations......................................    4
              Gas Operations...........................................    6
              Regulation and Rates.....................................    7
              Construction Program and Financing.......................    8
              Coal Supply..............................................    9
              Gas Supply...............................................   10
              Environmental Matters....................................   11
              Labor Relations..........................................   11
              Employees................................................   11

   Item  2. Properties.................................................   12

   Item  3. Legal Proceedings..........................................   13

   Item  4. Submission of Matters to a Vote of Security Holders........   14

   Executive Officers of the Company...................................   14

                                    PART II

   Item  5. Market for the Registrant's Common Equity and Related
              Stockholder Matters......................................   16

   Item  6. Selected Financial Data....................................   16

   Item  7. Management's Discussion and Analysis of Results of
              Operations and Financial Condition.......................   16

   Item  8. Financial Statements and Supplementary Data................   26

   Item  9. Changes in and Disagreements with Accountants on Accounting
              and Financial Disclosure.................................   49

                                   PART III

   Item 10. Directors and Executive Officers of the Registrant (a).....   50

   Item 11. Executive Compensation (a).................................   50

   Item 12. Security Ownership of Certain Beneficial Owners
              and Management (a).......................................   50

   Item 13. Certain Relationships and Related Transactions (a).........   50

                                    PART IV

   Item 14. Exhibits, Financial Statement Schedules,
              and Reports on Form 8-K..................................   50

   Signatures..........................................................   67

   Exhibit 12 - Computation of Ratio of Earnings to Fixed Charges......   68

   Exhibit 23 - Consent of Independent Public Accountants..............   69



(a) Incorporated by reference.


<PAGE>


                                     PART I

ITEM 1.  BUSINESS.

General

     Incorporated July 2, 1913, Louisville Gas and Electric Company (the
Company) is an operating public utility that supplies natural gas to
approximately 272,000 customers and electricity to approximately 346,000
customers in Louisville and adjacent areas in Kentucky.  The Company's service
area covers approximately 700 square miles in 17 counties and has an estimated
population of 800,000.  Included in this area is the Fort Knox Military
Reservation, to which the Company transports gas and provides electric service,
but which maintains its own distribution systems.  The Company also provides gas
service in limited additional areas.  The Company's coal-fired electric
generating plants, which are all equipped with systems to remove sulfur dioxide,
produce most of the Company's electricity; the remainder is generated by a
hydroelectric power plant and combustion turbines.  Underground natural gas
storage fields help the Company provide economical and reliable gas service to
customers.

     In August 1990, the Company and LG&E Energy Corp. (Energy Corp.)
implemented a  corporate reorganization pursuant to a mandatory share exchange
whereby each share of outstanding common stock of the Company was exchanged on a
share-for-share basis for the common stock of Energy Corp.  The reorganization
created a corporate structure that gives the holding company the flexibility to
take advantage of opportunities to expand into other businesses while insulating
the Company's utility customers and senior security holders from any risks
associated with such businesses.  The Company's preferred stock and first
mortgage bonds were not exchanged and remained securities of the Company.

     The Company's Trimble County Unit 1 (Trimble County or the Unit), a
495-megawatt, coal-fired electric generating unit, which the Company began
constructing in 1979, was placed in commercial operation on December 23, 1990.
The Unit had been subject to numerous reviews by the Public Service Commission
of Kentucky (Kentucky Commission or Commission).  On December 8, 1995, the
Commission approved a settlement agreement filed by the Company and all
intervenors in the Trimble County proceedings, including various consumer
interest groups and government agencies, that in effect, resolves all of the
regulatory and legal issues related to the appropriate ratemaking treatment to
exclude 25% of the Trimble County costs from customer rates.  The Company has
sold a 25% ownership interest in the Unit.  For a more detailed discussion of
the proceedings relating to Trimble County and the sale of 25% of the Unit, see
Electric Operations and Notes 14 and 15 of Notes to Financial Statements under
Item 8.

     The Clean Air Act Amendments of 1990 (the Act) impose stringent limits on
emissions of sulfur dioxide and nitrogen oxides by electric utility generating
plants.  All of the Company's coal-fired boilers are equipped with sulfur
dioxide "scrubbers" and already achieve the final sulfur dioxide emission rates
required by the year 2000 under the legislation.  However, as part of its
ongoing construction program, the Company has spent $22 million to date and
anticipates incurring capital expenditures of approximately $8 million in 1996
for remedial measures necessary to meet the Act's requirements for nitrogen
oxides.  The overall financial impact of the legislation on the Company is
expected to be minimal.  The Company is well-positioned in the market to be a
"clean" power provider without the large capital expenditures that are expected
to be incurred by many other utilities.  For a more detailed discussion of the
Clean Air Act and other environmental issues, see


                                     -1-
<PAGE>


Environmental Matters under this Item, Item 3, Item 7, and Note 13 of the Notes
to Financial Statements under Item 8.

     The Energy Policy Act of 1992 is designed to give utilities a wider choice
of sources for their electrical supply than previously available, while creating
generating supply options that did not exist under the old law.  In passing this
legislation, Congress also anticipated that greater competition among electric
supply options should result in lower consumer rates.

     Pursuant to the Energy Policy Act, the Federal Energy Regulatory Commission
(FERC) earlier this year issued a Notice of Proposed Rulemaking on Open Access
Non-discriminatory Transmission Services and a Supplemental Notice of Proposed
Rulemaking on Stranded Investment (collectively, the Mega-NOPR).  The Mega-NOPR
is intended, among other things, to create a vigorous wholesale electric market
by requiring transmission providers to offer open access to their transmission
systems.  The Company is supportive of proposals to increase competition at all
levels of the electric power market and intends to pursue opportunities created
by a more competitive market.

     The Company 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; a write-off of previously deferred expenses; an
increase in focus on commercial and industrial customers; an increase in
employee involvement and training; a major realignment and formation of new
business units, and a modification of its organizational structure.

     Effective December 15, 1995, LG&E Energy Corp. modified its organizational
structure.  Changes are designed to facilitate decision making, improve response
to customers and better align operating units with the changing competitive
marketplace.  Four operating divisions were established:

        Distribution Services Division - which includes the distribution
        resources of the Company, is responsible for expanding and developing
        the distribution businesses and investing in enhanced service offerings
        behind the customer's meter.

        Gas Marketing Division - primarily consists of the businesses of LG&E
        Natural Inc. (a subsidiary of LG&E Energy Corp.), which markets gas
        throughout the United States and Canada.

        Power Marketing Division - includes LG&E Power Marketing Inc. (LPM), is
        responsible for project development and the marketing and sale of
        wholesale power throughout the United States.

        Power Generation Division - which includes the generation resources of
        the Company, LG&E Power Inc. and LG&E International Inc., has
        responsibility for all utility and non-utility power plant operations,
        asset management, and development functions both domestically and
        internationally.

     The Company's wholesale power will continue to be marketed and brokered by
LG&E Power Marketing Inc. (LPM), a wholly-owned subsidiary of LG&E Energy Corp.
LPM was among the first utility-affiliated marketers in the country to secure
FERC approval to sell power at market-based rates and engage in wholesale power
marketing activities.  During 1995, its first full year of operations, LPM sold
or brokered 1.8 million megawatt-hours of power in 30 states.  This


                                     -2-
<PAGE>


volume of activity placed LPM among the five largest marketers of wholesale
energy in 1995 and the largest seller affiliated with a regulated electric
utility.  LPM is predicting that the market for electric energy will expand and
its revenues and contributions to corporate income will increase in future
years.

     The realignment does not affect LG&E Energy Corp.'s legal structure,
regulation of the Company by the Commission or LG&E Energy Corp.'s status as an
exempt holding company.

     By using gas storage fields strategically, the Company 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 FERC's Order No. 636 went
into effect.  Previously, the Company 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, the Company buys
competitively priced gas from several large producers under contracts of varying
duration.  By purchasing from multiple suppliers, and storing any excess gas,
the Company is able to secure favorably priced gas for its customers.  Without
storage capacity, the Company would be forced to buy additional gas when
customer demand increases, which is usually when the price is highest.  See FERC
Order No. 636 under Item 7 for a further discussion.

     During the last quarter of 1995, the Company negotiated a five-year
transportation agreement with Tennessee Gas Pipeline Company (Tennessee) to
become the Company's second natural gas pipeline transporter.  The agreement
with Tennessee becomes effective November 1, 1996.  For many years, Texas Gas
Transmission Corporation (Texas Gas) has been the sole provider of gas transport
services to the Company.  For further discussion, see Gas Supply.

     On July  31, 1995, Vantage Consulting, Inc. released its report on the
Kentucky Commission's management audit of the Company.  This comprehensive
audit, which began in September 1994, included more than 300 interviews and over
875 requests for information.  This was the second management audit of the
Company mandated by the Kentucky Commission, the first being completed in 1986.
The overall audit findings were very favorable and recognized that the Company
has become an innovative industry leader that has implemented many performance
improvements to lower costs, improve efficiency, prepare for increased
competition, and increase its focus on customer satisfaction.  For further
discussion, see Regulation and Rates.


                                     -3-
<PAGE>


     For the year ended December 31, 1995, 75% of total operating revenues was
derived from electric operations and 25% 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..........................          $201,357       $107,762       $309,119            44%
     Commercial...........................           160,571         38,161        198,732            29
     Industrial...........................           110,800         17,430        128,230            18
     Public authorities...................            53,861          8,679         62,540             9
                                                    --------       --------       --------           ----
     Total service revenues...............           526,589        172,032        698,621           100%
     Refund - Trimble County Settlement              (28,300) (a)         -        (28,300)          ----
                                                    --------       --------       --------           ----
        Total-ultimate consumers                     498,289        172,032        670,321
     Sales for resale.....................            37,471              -         37,471
     Gas transportation-net...............                 -          7,821          7,821
     Miscellaneous........................             6,577          1,273          7,850
                                                    --------       --------       --------
        Total.............................          $542,337       $181,126       $723,463
                                                    --------       --------       --------
                                                    --------       --------       --------
</TABLE>

     (a)  See Note 14 of Notes to Financial Statements under Item 8.

     See Note 16 of Notes to Financial Statements under Item 8 for financial
information concerning segments of business for the three years ended
December 31, 1995.


Electric Operations

     The sources of electric operating revenues and the volumes of sales for the
three years ended December 31, 1995, were as follows:

<TABLE>
<CAPTION>
                                                      1995           1994           1993
                                                      ----           ----           ----
     <S>                                          <C>            <C>            <C>
     ELECTRIC OPERATING REVENUES
     (Thousands of $):
        Residential...........................      $201,357       $194,145       $195,273
        Small commercial and industrial.......        73,074         70,916         70,106
        Large commercial......................        87,497         84,931         84,231
        Large industrial......................       110,800        108,004        104,506
        Public authorities....................        53,861         53,191         52,183
        Refund - Trimble County Settlement           (28,300)             -              -
                                                    --------       --------       --------
           Total-ultimate consumers...........       498,289        511,187        506,299
        Sales for resale......................        37,471         42,720         58,959
        Miscellaneous.........................         6,577          5,039          4,952
                                                    --------       --------       --------
           Total..............................      $542,337       $558,946       $570,210
                                                    --------       --------       --------
                                                    --------       --------       --------

     ELECTRIC SALES (Thousands of kwh):
        Residential...........................     3,415,225      3,204,330      3,230,463
        Small commercial and industrial.......     1,112,130      1,073,152      1,056,977
        Large commercial......................     1,802,035      1,729,668      1,696,686
        Large industrial......................     3,023,543      2,874,411      2,736,269
        Public authorities....................     1,113,063      1,085,741      1,053,928
                                                  ----------     ----------     ----------
           Total-ultimate consumers...........    10,465,996      9,967,302      9,774,323
        Sales for resale......................     2,000,607      2,315,311      3,299,510
                                                  ----------     ----------     ----------
           Total..........................        12,466,603     12,282,613     13,073,833
                                                  ----------     ----------     ----------
                                                  ----------     ----------     ----------
</TABLE>

     At December 31, 1995, the Company had 346,099 electric customers.


                                     -4-
<PAGE>


     The Company uses efficient coal-fired boilers that are fully equipped with
sulfur dioxide removal systems to generate electricity.  The Company's system
wide emission rate for sulfur dioxide in 1995 was approximately .85 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 for the year 2000.

     On Thursday, August 17, 1995, the Company set a record local peak load 
of 2,357 Mw, when the temperature at the time of peak reached 94 DEG. F 
(average for the day was 86 DEG. F).  The 1994 maximum local peak load of 
2,219 Mw occurred on Wednesday, June 15, when the temperature at time of peak 
was 95 DEG. F (average for the day was 85 DEG. F).  The record system peak of 
3,223 Mw (which included purchases from and short-term sales to other 
electric utilities) occurred on Thursday, May 30, 1991.

     The Company's current reserve margin is 16%.  At February 29, 1996, the
Company 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.

     The Company 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.
The Company 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.  The Company 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.

     On February 28, 1991, the Company sold a 12.12% ownership interest in
Trimble County Unit 1 to the Illinois Municipal Electric Agency (IMEA), based in
Springfield, Illinois, which is an agency of 30 municipalities that own and
operate their own electric systems.  On February 1, 1993, the Indiana Municipal
Power Agency (IMPA), based in Carmel, Indiana, purchased 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 the Unit and
for fuel and reactant used.  They are also responsible for their proportionate
share of incremental capital assets acquired.

     Electric and magnetic fields (sometimes referred to as EMF) surround
electric wires or conductors of electricity such as electrical tools, household
wiring and appliances, and high voltage electric transmission lines such as
those owned by the Company.  Certain studies have suggested a possible
association between electric and magnetic fields and adverse health effects.
The Electric Power Research Institute, of which the Company is a participating
member, has expended approximately $83 million since 1987 in its investigation
and research with regard to possible health effects posed by exposure to
electric and magnetic fields.


                                     -5-
<PAGE>


Gas Operations

     The sources of gas operating revenues and the volumes of sales for the
three years ended December 31, 1995, were as follows:

<TABLE>
<CAPTION>
                                                      1995           1994           1993
                                                      ----           ----           ----
     <S>                                            <C>            <C>            <C>
     GAS OPERATING REVENUES
     (Thousands of $):
        Residential...........................      $107,762       $110,553       $112,508
        Commercial............................        38,161         40,474         43,568
        Industrial............................        17,430         27,956         28,310
        Public authorities....................         8,679         12,930         13,846
                                                    --------       --------       --------
           Total-ultimate consumers...........       172,032        191,913        198,232
        Gas transportation-net................         7,821          6,759          5,147
        Miscellaneous.........................         1,273          1,457          1,536
                                                    --------       --------       --------
           Total..............................      $181,126       $200,129       $204,915
                                                    --------       --------       --------
                                                    --------       --------       --------

     GAS SALES (Millions of cu. ft.):
        Residential.....................              24,242         22,935         24,330
        Commercial......................               9,885          9,450         10,308
        Industrial......................               5,188          7,505          7,817
        Public authorities..............               2,423          3,268          3,515
                                                    --------       --------       --------
           Total-ultimate consumers.......            41,738         43,158         45,970
        Gas transported.................              12,241          6,854          5,249
                                                    --------       --------       --------
           Total..........................            53,979         50,012         51,219
                                                    --------       --------       --------
                                                    --------       --------       --------
</TABLE>

     At December 31, 1995, the Company had 272,135 gas customers.

     The Company has underground natural gas storage fields that help provide
economical and reliable gas service to ultimate consumers.

     Reflecting the changing nature of the gas business, a number of industrial
customers purchase their natural gas requirements directly from alternate
suppliers for delivery through the Company's distribution system.  Generally,
transportation of natural gas for the Company'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 the Company economically
indifferent as to whether gas is sold or merely transported.

     The all-time maximum day gas sendout of 545,000 Mcf occurred on Sunday, 
January 20, 1985,  when the average temperature for the day was -11 DEG. F.  
During 1995, the maximum day gas sendout was 454,000 Mcf, occurring on 
December 9, when the average temperature for the day was 9 DEG. F.  Supply on 
that day consisted of 208,000 Mcf from purchases, 199,000 Mcf delivered from 
underground storage, and 47,000 Mcf transported for industrial customers.  
For further discussion, see Gas Supply.

     Under FERC Order No. 636, pipelines may recover costs associated with the
transition to and implementation of this order from pipeline customers,
including the Company.  During 1995, the Company paid and began recovering from
its customers approximately $4.8 million in transition costs under Order No.
636.  It is estimated that about $1.4 million in additional transition costs
will be incurred by the Company during 1996 and about $1.3 million in 1997, and
these costs are also expected to be recovered from customers.  See Note 13 of
Notes to Financial Statements under Item 8 for further discussion of FERC Order
No. 636.


                                     -6-
<PAGE>


Regulation and Rates

     The Kentucky Commission has regulatory jurisdiction over the rates and
service of the Company and over the issuance of certain of its securities.  The
Company 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 the Company of short-term securities.

     For a discussion of current regulatory matters, see Rates and Regulation
under Item 7 and Notes 2 and 14 of 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 the Company's electric customers by
means of the Company's fuel adjustment clause.  The Kentucky Commission requires
public hearings at six-month intervals to examine past fuel adjustments, and at
two-year intervals for the purpose of additional examination and transfer of the
then current fuel adjustment charge or credit to the base charges.  The
Commission also requires that electric utilities, including the Company, file
certain documents relating to fuel procurement and the purchase of power and
energy from other utilities.

     The Company's gas rates contain a gas supply clause (GSC), whereby
increases or decreases in the cost of gas supply are reflected in the Company'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.

     On December 8, 1995, the Commission approved a settlement agreement filed
by the Company and all intervenors in the Trimble County proceedings, including
various consumer interest groups and government agencies, that, in effect,
resolves all the regulatory and legal issues related to the appropriate
ratemaking treatment to exclude 25% of the Trimble County plant costs from
customer rates.  See Note 14 of Notes to Financial Statements under Item 8 for
further discussion of this matter.

     On July 31, 1995, Vantage Consulting, Inc. released its report on the
Kentucky Commission's management audit of the Company.  This comprehensive
audit, which began in September 1994, included more than 300 interviews and over
875 requests for information.  This was the second management audit of the
Company mandated by the Kentucky Commission, the first being completed in 1986.

     The overall audit findings were very favorable and recognized that the
Company has become an innovative industry leader that has implemented many
performance improvements to lower costs, improve efficiency, prepare for
increased competition, and increase its focus on customer satisfaction.  The
audit report identified additional improvement opportunities and contained a
series of recommendations which should assist the Company with its future plans.
It is estimated that implementation of the audit recommendations could provide
the Company with as much as $11


                                     -7-
<PAGE>


million in annual gross savings.  However, incremental costs will be incurred to
achieve the full benefits of the recommendations and the ultimate savings will
be realized over the long-term.

     On October 7, 1994, the Company filed an application with the Kentucky
Commission in which it requested approval of an environmental cost recovery
surcharge to recover certain costs required to comply with the Federal Clean Air
Act, as amended, and those federal, state, and local environmental requirements
which apply to coal combustion wastes and by-products from facilities utilized
for production of energy from coal.  On April 6, 1995, the Commission approved,
with modifications, an environmental cost recovery surcharge that increased
electric revenues by $3.2 million in 1995 and will increase revenues by an
estimated $5.7 million in 1996.  The Company, the Kentucky Attorney General, and
the Kentucky Industrial Utility Customers have filed appeals on certain issues
included in the April 6 order.  See Rates and Regulation under Item 7 for a
further discussion of the surcharge.

     On January 1, 1994, the Company implemented a Commission approved demand
side management (DSM) program.  The program contains a rate mechanism that
provides for the recovery of DSM program costs, allows the Company to recover
revenues due to lost sales associated with the DSM programs and provides the
Company an incentive for implementing DSM programs.  See Rates and Regulation
under Item 7 for a further discussion of DSM.

     As part of the corporate reorganization whereby the Company became the
subsidiary of LG&E Energy Corp., the Company obtained the approval of the
Kentucky Commission.  The order of the Kentucky Commission authorizing the
Company to reorganize into a holding company structure contains certain
provisions, which, among other things, ensure the Kentucky Commission access to
books and records of Energy Corp. and its affiliates which relate to
transactions with the Company; require Energy Corp. and its subsidiaries to
employ accounting and other procedures and controls to protect against
subsidization of non-utility activities by the Company's customers; and preclude
the Company from guaranteeing any obligations of Energy Corp. without prior
written consent from the Kentucky Commission.  In addition, such order provides
that the Company's Board of Directors has the responsibility to use its dividend
policy consistent with preserving the financial strength of the Company and that
the Kentucky Commission, through its authority over the Company's capital
structure, can protect the Company's ratepayers from the financial effects
resulting from non-utility activities.


Construction Program and Financing

     The Company's construction program is designed to assure 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.  The Company's
estimates of its construction expenditures can vary substantially due to
numerous items beyond the Company'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, 1995, gross property additions
amounted to $476 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 18% of total utility
plant at December 31, 1995, and consisted of $356 million for electric
properties and $120


                                     -8-
<PAGE>


million for gas properties.  Gross retirements during the same period were $82
million, consisting of $67 million for electric properties and $15 million for
gas properties.

     At December 31, 1995, the Company's embedded cost of long-term debt was
6.3% and its ratio of earnings to fixed charges was 3.99.  See Exhibit 12.  For
a further discussion of construction expenditures and financing, see Liquidity
and Capital Resources under Item 7.


Coal Supply

     Over 90% of the Company'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 the Company in the foreseeable future, with natural gas
and oil being used for peaking capacity and flame stabilization in coal-fired
boilers or in emergencies.  The Company has no nuclear generating units and has
no plans to build any in the foreseeable future.

     In January 1996, the Company bought out the last year of its three year
contract with Andalex Resources, Inc. at a cost of $3.5 million.  The Company
has filed an application with the Kentucky Commission to recover the cost of the
buyout through the fuel  adjustment clause.  As a result of the buyout of the
coal contract, the Company's customers will realize a net savings in excess of
$1 million.

     The Company has entered into coal supply agreements with various suppliers
for coal deliveries for 1996 and beyond.  The Company normally augments its coal
supply agreements with spot market purchases which, during 1995, were about 10%
of total purchases.  The Company has a coal inventory policy, which is in
compliance with the Kentucky Commission's directives and which the Company
believes provides adequate protection under most contingencies.  The Company had
on hand at December 31, 1995, a coal inventory of approximately 600,000 tons, or
a 35 day supply.

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

     Coal for the Company's Mill Creek plant is delivered by rail and barge.
Deliveries to the Cane Run and Trimble County plants are by rail and barge,
respectively.

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

<TABLE>
<CAPTION>
                                              1995        1994        1993
                                             ------      ------      ------
     <S>                                     <C>         <C>         <C>
     Per ton...........................      $23.68      $25.27      $26.58
     Per million Btu...................        1.04        1.10        1.14
</TABLE>

     This downward trend in the delivered cost of coal is expected to continue
through 1996.


                                     -9-
<PAGE>


Gas Supply

     Prior to the implementation of FERC Order No. 636, the Company had
purchased natural gas and pipeline transportation services from Texas Gas
Transmission Corporation (Texas Gas).  The Company now purchases only
transportation services from Texas Gas and purchases natural gas from many other
sources under contracts for varying periods of time.  See Management's
Discussion and Analysis, Future Outlook, under Item 7.

     Under Order No. 636, pipelines may recover costs associated with the
transition to and implementation of this order from pipeline customers,
including the Company.  The Commission issued an order, based on proceedings
that were held to investigate the impact of Order No. 636 on utilities and
ratepayers in Kentucky, providing that transition costs assessed on utilities by
the pipelines, which are clearly identifiable as being related to the cost of
the commodity itself, are appropriate to be recovered from customers through the
gas supply clause.  During 1995, the Company paid Texas Gas and began recovering
from its customers approximately $4.8 million in transition costs.  It is
estimated that about $1.4 million in additional transition costs will be
incurred by the Company during 1996 and about $1.3 million in 1997, and these
costs are also expected to be recovered from customers.  These transition costs
are billed by Texas Gas pursuant to orders issued by FERC in transition cost
regulatory proceedings in which the Company is a party.  Pursuant to these FERC
orders, no additional transition costs are expected to be billed after 1997.

     During 1995, the Company participated in several regulatory proceedings at
FERC.  These proceedings resolved, subject to final FERC approval, issues in
Texas Gas' rate case as well as transition cost issues from the implementation
of Order No. 636 by Texas Gas.  The Company does not expect significant
regulatory initiatives by Texas Gas at FERC during 1996.

     The Company transports on the Texas Gas System under No-Notice Service
(NNS) and Firm Transportation (FT) rates.  In 1995, the Company made two
important modifications to its transportation agreements with Texas Gas.  During
the winter months, the Company has 184,900 MMBtu (180,390 mcf) per day in NNS.
During 1995, the Company's summer NNS level was reduced from 135,000 MMBtu
(131,708 Mcf) per day to 111,000 MMBtu (108,293 Mcf), and 24,000 MMBtu (23,415
Mcf) per day was converted to FT service.  Each of these NNS and FT agreements
with Texas Gas expire in equal portions in 1998, 2000, and 2001.  Each agreement
includes a unilateral five year roll-over provision exercisable at the Company's
option.

     The Company also has a transportation agreement with Texas Gas which
provides for 30,000 MMBtu (29,268 Mcf) per day in FT service throughout the
year.  The primary term of this FT agreement expired October 31, 1995, subject
to a year-to-year termination by either party.  During 1995, the Company
provided the required one year prior written notice to terminate this FT
agreement effective November 1, 1996.

     During the last quarter of 1995, the Company negotiated a five year
transportation agreement with Tennessee Gas Pipeline Company (Tennessee) for
30,000 MMBtu (29,268 Mcf) per day in Firm Transportation service under
Tennessee's Rate FT-A.  This agreement with Tennessee becomes effective November
1, 1996.  For many years, Texas Gas had been the sole provider of gas transport
services to the Company.

     The Company 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


                                     -10-
<PAGE>


market-responsive.  These firm supplies, in tandem with pipeline transportation
services, provide the reliability and flexibility necessary to serve the
Company's customers.

     The Company 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 1994-1995 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 the Company was $2.62
in 1995, $2.78 in 1994, and $2.91 in 1993.


Environmental Matters

     Protection of the environment is a major priority for the Company.  The
Company engages in a variety of activities within the jurisdiction of federal,
state, and local regulatory agencies.  Those agencies have issued the Company
permits for various activities subject to air quality, water quality, and waste
management laws and regulations.  For the five year period ending with 1995,
expenditures for pollution control facilities represented $90 million or 19% of
total construction expenditures. The cost of operating and maintaining
scrubber-related facilities amounted to $21 million in 1995 and $22 million in
1994.  The Company's anticipated capital expenditures for 1996 to comply with
environmental laws are approximately $8 million.  See Note 13 of Notes to
Financial Statements under Item 8 for a discussion of specific environmental
proceedings affecting the Company.


Labor Relations

     On December 8, 1995, members of the International Brotherhood of Electrical
Workers Local 2100 ratified a new three year collective bargaining agreement
with the Company, which covers approximately 1,600 employees.  The contract
provides wage and employment protection for employees participating in the
Company's continuous improvement initiative, greater workforce flexibility to
help the Company respond to growing competition, and improved retirement
benefits.


Employees

     The Company had 2,594 full-time employees at December 31, 1995.


                                     -11-
<PAGE>


ITEM 2.  PROPERTIES.

     The Company'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.  At February 29, 1996, the Company
owned the following electric generating stations:

<TABLE>
<CAPTION>
                                                           Year in
                                                           Service       Capability Rating (Kw)
                                                           -------       ----------------------
     <S>                                                   <C>           <C>          <C>
     Steam Stations:
       Mill Creek-Kosmosdale, Ky.
         Unit 1...........................................   1972        303,000
         Unit 2...........................................   1974        301,000
         Unit 3...........................................   1978        386,000
         Unit 4...........................................   1982        480,000      1,470,000
                                                                         -------
       Cane Run-near Louisville, Ky.
         Unit 4...........................................   1962        155,000
         Unit 5...........................................   1966        168,000
         Unit 6...........................................   1969        240,000        563,000
                                                                         -------
       Trimble County-Bedford, Ky.
         Unit 1...........................................   1990                       371,000 (a)

     Combustion Turbine Generators (Peaking capability):
       Zorn...............................................   1969         16,000
       Paddy's Run........................................   1968         43,000
       Cane Run...........................................   1968         16,000
       Waterside..........................................   1964         33,000        108,000
                                                                         -------      ---------
                                                                                      2,512,000
                                                                                      ---------
                                                                                      ---------
</TABLE>

    (a) Amount shown represents the Company's 75% interest in the Unit.  See
        Note 15 of Notes to Financial Statements, Jointly Owned Electric Utility
        Plant, under Item 8 for a discussion of the sale of 25% of the Unit to
        IMEA and IMPA.  The Company is responsible for operation of the Unit and
        is reimbursed by IMEA and IMPA for expenditures related to the Unit
        based on their proportionate share of ownership interest.

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

     At December 31, 1995, the Company's electric transmission system included
21 substations with a total capacity of approximately 11,026,897 Kva and
approximately 651 structure miles of lines.  The electric distribution system
included 82 substations with a total capacity of approximately 3,193,127 Kva,
3,507 structure miles of overhead lines, 233 miles of underground conduit, and
5,380 miles of underground conductors.

     The Company's gas transmission system includes 177 miles of transmission
mains, and the gas distribution system includes 3,466 miles of distribution
mains.

     The Company 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, the Company 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 in June 2005.


                                     -12-
<PAGE>


     Other properties owned by the Company 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 the Company's First Mortgage Bonds constitutes
a direct first mortgage lien upon substantially all property owned by the
Company.


ITEM 3.  LEGAL PROCEEDINGS.

Rates, Regulatory Matters, and Trimble County Generating Plant

     For a discussion of current regulatory matters and a detailed discussion of
the Trimble County Unit 1 settlement agreement, see Rates and Regulation under
Item 7 and Notes 2 and 14 of Notes to Financial Statements under Item 8.


Statewide Power Planning

     On March 14, 1995, the Commission staff issued its report on its review of
the Company's 1993 biennial Integrated Resource Plan.  The Staff Report
specifically found that the Company's plan contained some of the better analyses
among those filed by the electric utilities under the Commission's jurisdiction,
and presented several suggestions for the Company's consideration when it
develops its next plan.  By order issued on March 17, 1995, the Commission
formally closed its proceeding for the review of the Company's plan.  On May 5,
1995, the Commission granted the Company's request that the Commission waive the
requirement that the Company file an Integrated Resource Plan during 1995.  On
July 21, 1995, the Kentucky Commission amended its Integrated Resource Planning
regulations to replace the biennial filing requirement with a triennial
requirement.  The amended regulations also specified that the Company's next
Integrated Resource Plan is to be filed 39 months from the effective date of the
amended regulation, or October 21, 1998.


Environmental

     For a complete discussion of the Company's environmental issues concerning
its Mill Creek and Cane Run generating plants, manufactured gas plant sites, and
certain other environmental issues, see Note 13 of Notes to Financial Statements
under Item 8.


Other

     In the normal course of business, other lawsuits, claims, environmental
actions, and other governmental proceedings arise against the Company.  To the
extent that damages are assessed in any of these lawsuits, the Company believes
that its 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 the Company's consolidated financial position or results of
operations.


                                     -13-
<PAGE>


ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

     None

                             --------------------

Executive Officers of the Company.

<TABLE>
<CAPTION>
                                                                                          Effective Date of Election
     Name                            Age        Position                                  to Present Position
     ----                            ---        --------                                  --------------------------
     <S>                             <C>        <C>                                       <C>
     Roger W. Hale                   52         Chairman of the Board and
                                                Chief Executive Officer                   January 1, 1992

     Victor A. Staffieri             40         President                                 January 1, 1994

     Walter Z. Berger                40         Executive Vice President
                                                and Chief Financial Officer               February 5, 1996

     John R. McCall                  52         Executive Vice President,
                                                General Counsel and
                                                Corporate Secretary                       July 1, 1994

     M. Lee Fowler                   59         Vice President and
                                                Controller                                September 1, 1988

     Wendy C. Heck                   42         Vice President, Information
                                                Services                                  January 1, 1994

     Chris Hermann                   48         Vice President and General
                                                Manager, Wholesale
                                                Electric Business                         January 1, 1993

     Rebecca L. Holt                 36         Vice President, Gas
                                                Service Business                          February 15, 1995

     Charles A. Markel III           48         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
Stockholders, scheduled to be held April 23, 1996.

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

     Mr. Hale, Mr. Fowler, Ms. Heck, Mr. Hermann, and Mr. Markel have been
employed for more than five years in executive or management positions with the
Company.  Prior to election to the position shown in the table, the following
executive officers held other positions with the Company since January 1, 1991:
Mr. Hale was Chairman of the Board, President and Chief Executive Officer; Ms.
Heck was Vice President-Internal Auditing prior to January 1992, Vice
President-Fuels and Operating Services prior to January 1993, and Vice
President-Fuels and


                                     -14-
<PAGE>


Information Services thereafter; Mr. Hermann was General Manager-Power
Production prior to January 1992 and General Manager-Wholesale Electric
thereafter; Mr. Markel was Vice President-Finance and Treasurer prior to January
1992, and Senior Vice President and Chief Financial Officer thereafter.
Effective January 1993, Mr. Markel was named Corporate Vice President-Finance,
and Treasurer of the parent company, LG&E Energy Corp.

     Prior to election to his current position, Mr. Staffieri was Senior Vice
President-Public Policy, and General Counsel of the Company, and prior to
November 1992, Senior Vice President, General Counsel and Corporate Secretary.
Prior to March 1992, Mr. Staffieri was employed by Long Island Lighting Company
and held the position of General Counsel and Secretary.

     Prior to election to his current position, Mr. Berger was employed by Enron
Oil Trading and Transportation and held the position of Vice President, Finance
and Business Development.  Prior to November 1992, Mr. Berger was Controller for
Enron America, Inc., and prior to February 1992, Vice President and Chief
Financial Officer for Baker Hughes, Inc.

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

     Prior to election to her current position, Ms. Holt was employed by South
Carolina Electric and Gas Company and held the position of General Manager, Gas
Operations from July 1994 to February 1995, Division Manager, Central
Division-Gas Operations prior to July 1994, and General Manager, Northern
Division-Gas Operations prior to February 1992.


                                     -15-
<PAGE>


                                     PART II

ITEM 5.  MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.

     All Louisville Gas and Electric Company common stock, 21,294,223 shares, is
held by LG&E Energy Corp.  Therefore, there is no public trading market for the
Company's common stock.

     The following table sets forth the cash distributions on common stock paid
to LG&E Energy Corp. for the periods indicated:

<TABLE>
<CAPTION>
                                         1995       1994
                                         ----       ----
                                         (Thousands of $)
<S>                                    <C>         <C>
First Quarter.............             $18,000     $17,500
Second Quarter............              34,000      17,500
Third Quarter.............              18,000           -
Fourth Quarter............              18,500      18,000
</TABLE>


ITEM 6.  SELECTED FINANCIAL DATA.

<TABLE>
<CAPTION>

                                                                        Years Ended December 31
                                                                           (Thousands of $)
                                             ---------------------------------------------------------------------------
                                                 1995            1994            1993            1992            1991
                                                 ----            ----            ----            ----            ----
<S>                                          <C>             <C>             <C>             <C>             <C>
Operating Revenues . . . . . . . . . . .     $   723,463     $   759,075     $   775,125     $   700,195     $   708,706
                                             -----------     -----------     -----------     -----------     -----------
Net Operating Income:
   Before Unusual Items. . . . . . . . .         138,203         134,393         136,118         125,829         142,730
   Trimble County Settlement . . . . . .         (16,877)              -               -               -               -
   Non-Recurring Charges . . . . . . . .               -         (23,353)              -               -               -
                                             -----------     -----------     -----------     -----------     -----------
      Total Net Operating Income . . . .         121,326         111,040         136,118         125,829         142,730
                                             -----------     -----------     -----------     -----------     -----------
Net Income:
   Before Unusual Items. . . . . . . . .         100,061          94,423          90,535          73,793          94,643
   Trimble County Settlement . . . . . .         (16,877)              -               -               -               -
   Non-Recurring Charges,
      Charitable Foundation, etc.. . . .               -         (32,734)              -               -               -
   Cumulative Effect of
      Accounting Change. . . . . . . . .               -          (3,369)              -               -               -
                                             -----------     -----------     -----------     -----------     -----------
      Total Net Income . . . . . . . . .          83,184          58,320          90,535          73,793          94,643
                                             -----------     -----------     -----------     -----------     -----------
Net Income Available for
  Common Stock . . . . . . . . . . . . .          76,873          52,492          84,554          66,620          85,179
                                             -----------     -----------     -----------     -----------     -----------

Total Assets . . . . . . . . . . . . . .       1,979,490       1,966,590       1,974,584       1,960,860       1,936,909
Long-Term Obligations (including
  amounts due within one year) . . . . .         662,800         662,800         662,800         686,262         687,662
</TABLE>



ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION.

     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 1995, 1994 and 1993 and should be read
in connection with the financial statements and notes thereto.


                                     -16-
<PAGE>


Results of Operations

Net Income

     The Company's net income increased $24.9 million for 1995 over 1994 in
spite of recording a charge of $28.3 million ($16.9 million after-tax) in 1995
to recognize the effects of the settlement of the long-standing issues
surrounding the Company's Trimble County electric generating plant.  (See Note
14 of Notes to Financial Statements, Trimble County Generating Plant, under Item
8).  In 1994 net income of $58.3 million included the write-off of certain
non-recurring items ($23.9 million), the expense of establishing a charitable
foundation ($8.9 million), and the adoption of Statement of Financial Accounting
Standards No. 112, EMPLOYERS' ACCOUNTING FOR POST-EMPLOYMENT BENEFITS ($3.4
million).  Without consideration of the charges against income in 1995 and 1994
as discussed above, the Company's 1995 net income increased $5.6 million over
1994.  This improvement is primarily due to higher retail electric sales during
1995 partially offset by increased purchased power expenses resulting from
unplanned power plant outages this summer.

     In 1994 the Company's net income decreased $32.2 million.  This decrease
was due to the 1994 write-off of non-recurring items as discussed in the
preceding paragraph totaling $36.2 million.  Without consideration of the
non-recurring charges against income discussed above, the Company's 1994 net
income would have increased $3.9 million over 1993.  This improvement is
primarily a result of increased sales of electricity to retail customers and
reduced interest on debt due to favorable refinancing activities in 1993.


Rates and Regulation

     The Company is subject to the jurisdiction of the Public Service Commission
of Kentucky (Kentucky Commission or 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 the Company's
competitive position in the market and the status of regulation in the state of
Kentucky, the Company has no plans or intentions to discontinue its application
of SFAS No. 71.  See Note 2 of Notes to Financial Statements under Item 8.

     On December 8, 1995, the Commission approved a settlement agreement filed
by the Company and all intervenors in the Trimble County proceedings, including
various consumer interest groups and government agencies, that, in effect,
resolves all of the regulatory and legal issues related to the appropriate
ratemaking treatment to exclude 25% of the Trimble County plant costs from
customer rates.  Under the settlement, ratepayers are to receive $22 million in
refunds, most of which is to be refunded over a five-year period, commencing in
1996, based on a per kilowatt-hour credit.  In addition, the Company also agreed
to provide $900,000 annually for five years to fund low-income energy assistance
programs and to revise the decoupling methodology described in this section in a
manner that will reduce revenues collected from residential customers during
1996 and 1997 by a total of approximately $1.8 million.

     The overall effect of the settlement, which the Company recognized in its
entirety in the fourth quarter of 1995, was to reduce electric revenues by $28.3
million and net income by $16.9 million.  See Note 14 of Notes to Financial
Statements under Item 8 for further discussion.


                                     -17-
<PAGE>


     On July  31, 1995, Vantage Consulting, Inc. released its report on the
Kentucky Commission's management audit of the Company.  This comprehensive
audit, which began in September 1994, included more than 300 interviews and over
875 requests for information.  This was the second management audit of the
Company mandated by the Kentucky Commission, the first being completed in 1986.

     The overall audit findings were very favorable and recognized that the
Company has become an innovative industry leader that has implemented many
performance improvements to lower costs, improve efficiency, prepare for
increased competition, and increase its focus on customer satisfaction.  The
audit report identified additional improvement opportunities and contained a
series of recommendations which should assist the Company with its future plans.
It is estimated that implementation of the audit recommendations could provide
the Company with as much as $11 million in annual gross savings.  However,
incremental costs will be incurred to achieve the full benefits of the
recommendations and the ultimate savings will be realized over the long-term.

     On October 7, 1994, the Company filed an application with the Kentucky
Commission in which it requested approval of an environmental cost recovery
surcharge to recover certain costs required to comply with the Federal Clean Air
Act, as amended, and those federal, state, and local environmental requirements
which apply to coal combustion wastes and by-products from facilities utilized
for production of energy from coal.  On April 6, 1995, the Commission approved,
with modifications, an environmental cost recovery surcharge that increased
electric revenues by $3.2 million in 1995 and will increase revenues by an
estimated $5.7 million in 1996.  The surcharge became effective on May 1, 1995.
The Company, the Kentucky Attorney General (KAG) and the Kentucky Industrial
Utility Customers (KIUC) filed applications for rehearing on certain issues in
the April 6 order.  Among other things, the KAG and KIUC requested a reduction
of the amounts recoverable by the Company through the surcharge.  The Commission
denied all motions for rehearing, and appeals are currently pending in Franklin
Circuit Court.  The amount of refunds that may be ordered, if any, are not
expected to have a material adverse effect on the Company's financial position
or results of operations.

     On January 1, 1994, the Company implemented a Commission approved demand
side management (DSM) program that the Company, KAG, the Jefferson County
Attorney, and representatives of several customer-interest groups had filed with
the Commission.  Under the agreement, the Company committed up to $3.3 million
over three years (from 1994 through 1996) for initial programs that include a
residential energy conservation and education program and a commercial
conservation audit program.  The agreement also provided for a formal
collaborative process to develop future DSM programs.  The agreement contains a
rate mechanism that (1) provides the Company concurrent recovery of DSM program
costs, (2) provides an incentive for implementing DSM programs, and (3) allows
the Company to recover revenues from lost sales associated with the DSM
programs.

     Revenues from lost sales to residential customers are collected through a
"decoupling mechanism."  The Company's residential decoupling mechanism breaks
the link between the level of the Company's residential kilowatt-hour and Mcf
sales and its non-fuel revenues.  Under traditional regulation, a utility's
revenue varies with changes in its level of kilowatt-hour or Mcf sales.  The
residential decoupling mechanism allows the Company to recover a predetermined
level of revenue per residential customer based on the rate set in the Company's
last rate case, which will not vary with the level of kilowatt-hour or Mcf
sales.  Residential revenues will be adjusted to reflect (1) changes in the
number of residential customers and (2) a pre-established annual growth


                                     -18-
<PAGE>


factor in residential revenue per customer.  To the extent that actual revenues
are different from the predetermined level of revenues, rates are subsequently
adjusted to correct for any over or under recoveries.  Residential revenues
reported in the financial statements for 1994 through 1996 will be determined in
accordance with the predetermined amount per customer plus growth, and recovery
of fuel and gas costs.  The difference between the revenues shown in the
financial statements and the amounts billed to customers will be deferred for
future recovery from, or return to, customers.

     On December 1, 1995, the Company and the DSM collaborative members filed a
plan which would modify the existing programs and add five new programs.  The
proposed filing would increase the Company's commitment to DSM programs by
approximately $4.1 million.  The Company expects the Commission to rule on the
filing in the second quarter of 1996.

     In 1993, the Federal Energy Regulatory Commission (FERC) gave final
approval for a market-based generation sales tariff and two transmission service
tariffs which were filed by the Company.  The market-based tariff enables the
Company to sell up to 75 Mw of firm generation capacity and an unlimited amount
of non-firm power at market-based rates.  On July 26, 1995, FERC approved a new
network transmission service and a flexible point-to-point transmission service
which will provide transmission service to other parties comparable to the
transmission service utilized by the Company to serve retail customers.

     The Company last filed for a rate increase with the Commission in June 1990
based on the test-year ended April 30, 1990.  The Commission issued a final
order in September 1991 that effectively granted the Company an annual increase
in rates of $6.8 million ($6.1 million electric and $.7 million gas).  The
Commission's order authorized a rate of return on common equity of 12.5%.


Revenues

     A comparison of operating revenues for the years 1995 and 1994, excluding
the Trimble County settlement (which reduced electric revenues by $28.3
million), with the immediately preceding years 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                                        1995           1994           1995           1994
         -----                                        ----           ----           ----           ----
<S>                                                <C>            <C>            <C>            <C>
Sales to Ultimate Consumers:
     Fuel and gas supply adjustments, etc.......   $(10,566)      $   (841)      $(16,940)      $  1,823
     Demand side management/decoupling..........     (4,619)         1,853            479          3,997
     Environmental cost recovery surcharge......      3,205              -              -              -
     Variation in sales volumes.................     27,382          3,876         (3,420)       (12,139)
                                                   --------       --------       --------       --------
        Total...................................     15,402          4,888        (19,881)        (6,319)
Sales for resale................................     (5,249)       (16,239)             -              -
Gas transportation-net..........................          -              -          1,062          1,612
Other...........................................      1,538             87           (184)           (79)
                                                   --------       --------       --------       --------
        Total...................................   $ 11,691       $(11,264)      $(19,003)      $ (4,786)
                                                   --------       --------       --------       --------
                                                   --------       --------       --------       --------
</TABLE>

     Electric revenues increased in 1995 mainly because of an increase in sales
to ultimate consumers as a result of the warmer summer weather and improved
economic conditions in the


                                      -19-
<PAGE>


Company's service territory.  Gas revenues decreased as a result of lower gas
supply adjustment revenues which reflected the lower cost of natural gas in
1995.

     The Company's electric revenues decreased in 1994 compared with 1993
primarily because of a decrease in the sales of electricity for resale.  Gas
sales to ultimate consumers decreased 6% due primarily to the warmer than normal
weather in the last quarter of 1994.


Expenses

     Fuel for electric generation and gas supply expenses comprise a large
segment of the Company's total operating costs.  The Company's electric and gas
rates contain a fuel adjustment clause and a gas supply clause, respectively,
whereby increases or decreases in the cost of fuel and gas supply are reflected
in the Company's rates, subject to the approval by the Commission.

     Fuel expenses decreased $5.6 million (4%) in 1995 due to a decrease in the
cost of coal burned ($7.5 million) partially offset by increased generation of
2%.  Fuel expenses decreased $5.8 million (4%) in 1994 primarily because of a
decrease in the cost of coal burned ($3.9 million) and decreased generation of
3%.  The average delivered cost per ton of coal purchased was $23.68 in 1995,
$25.27 in 1994, and $26.58 in 1993.  This downward trend in the delivered cost
of coal is expected to continue through 1996.

     Power purchased increased $7.1 million in 1995 primarily because of
increased purchases resulting from unplanned outages at the electric generating
plants during the extremely hot summer weather.  The decrease of $7.5 million in
1994 was primarily due to less power wheeled for other utilities as a result of
milder weather in the region.

     Gas supply expenses decreased $20.8 million (16%) in 1995 because of the
lower cost of net gas supply ($18.7 million) and a decrease in the volume of gas
delivered to the distribution system ($2.1 million).  Gas supply expenses
decreased $7.5 million (5%) in 1994 due mainly to a decrease in the volume of
gas delivered to the distribution system ($9.2 million), partially offset by an
increase in net gas supply cost ($1.7 million).  The average unit cost per Mcf
of purchased gas was $2.62 in 1995, $2.78 in 1994, and $2.91 in 1993.

     Other operation expenses decreased $1.6 million in 1995, as compared to
1994, primarily as a result of a $6 million credit to expense representing a
portion of the proceeds received in a commercial dispute (see the following
paragraph for more discussion) and a decrease in expenses ($1.2 million)
associated with property damage claims.  These decreases were partially offset
by an increase in labor related expenses ($3.8 million) and  an increase in
various administrative expenses ($1.8 million).  Maintenance expense increased
$3.4 million in 1995 primarily as a result of an increase in repairs at the
electric power plants ($4.2 million), partially offset by a decrease in storm
damage expenses ($1 million).

     During 1995, the Company received cash proceeds of $8 million in connection
with the settlement of a commercial dispute.   Pursuant to a study to determine
the proper amount of income to be recognized, the Company recognized $6 million
as a reduction of operation expenses.  The remaining $2 million was recorded as
a reserve for future payments in connection with the dispute.


                                     -20-
<PAGE>


     Other operation expenses decreased $.5 million in 1994 mainly as a result
of decreases in various administrative expenses ($1.8 million), partially offset
by increased costs to operate electric generating plants and gas and electric
distribution systems ($.7 million), and an increase in the provision for
uncollectible accounts ($.6 million).  Maintenance expenses were up only
slightly over 1993.

     Non-recurring charges in 1994 include the Company's write-off of costs in
connection with early retirements and workforce reductions that occurred in 1992
and 1993, costs in connection with property damage claims pertaining to
particulate emissions from the Mill Creek electric generating plant, and certain
costs previously deferred resulting from adoption of Statement of Financial
Accounting Standards No. 106, EMPLOYERS' ACCOUNTING FOR POST-RETIREMENT
BENEFITS OTHER THAN PENSIONS.  See Note 3 of Notes to Financial Statements
under Item 8.

     Depreciation and amortization increased in both 1995 and 1994 primarily
because of additional depreciable plant in service.

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

     Other income and (deductions) increased $1.3 million primarily because of
an increase in dividend and interest income from investments.  Other income and
(deductions) increased $.5 million in 1994 partially due to recognition of a
gain on the sale of construction equipment.  See Note 9 of Notes to Financial
Statements under Item 8 for further detail.

     Contribution to the Company's charitable foundation reflects the expense
associated with establishing a tax-exempt foundation during 1994. Contributions
made from this Foundation are not charged against income, and therefore, do not
affect the Company's net income.  See Note 3 of Notes to Financial Statements
under Item 8.

     Interest charges for 1995 decreased $.9 million primarily due to a reversal
of an interest expense reserve resulting from a favorable ruling on certain
income tax matters.  Interest charges decreased in 1994 because of the lower
composite interest rate on outstanding debt, which reflects the full year effect
of the Company's 1993 aggressive program to refinance approximately $205 million
of outstanding debt at lower interest rates.  Since 1993, an immaterial
component of interest expense has been the cost associated with interest rate
swaps.  See Note 4, Financial Instruments, under Item 8 for further discussion.

     Preferred dividends increased $.5 million in 1995 because of a higher rate
associated with the Auction Rate Series.  Preferred dividends in 1994 reflect
the lower dividends that resulted from the Company's refunding of its $25
million, $8.90 Series with a $5.875 Series in May 1993.  See Liquidity and
Capital Resources.

     The rate of inflation may have a significant impact on the Company'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.


                                     -21-
<PAGE>


LIQUIDITY AND CAPITAL RESOURCES

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


1995 Capital Requirements

     New construction expenditures for 1995 were $93 million compared with $95
million for 1994 and $99 million for 1993.


Past Financing Activities

     During 1995, 1994, and 1993, the Company's primary source of capital was
internally generated funds from operating cash flows.  Internally generated
funds provided financing for 100% of the Company's construction expenditures for
1995, 1994, and 1993.

     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 the Company's service
territory, which has a direct effect on sales of electricity and gas.  In 1995,
accounts receivable and accounts payable were higher due to colder weather in
the last quarter of the year as compared to 1994.

     In December 1995, the Company redeemed the outstanding shares of its 7.45%
Cumulative Preferred Stock with a par value of $25 per share at a redemption
price of $25.75 per share.  The Company funded the $22 million redemption with
cash generated internally.

     In April 1995, the Company issued $40 million of Jefferson County,
Kentucky, Pollution Control Revenue Bonds, 5.90% Series, due April 15, 2023.
The proceeds of the bonds were used to redeem the outstanding 9.25% Series of
Pollution Control Bonds due July 1, 2015.


Future Capital Requirements

     Future financing requirements may be affected in varying degrees by factors
such as load growth, changes in construction expenditure levels, rate increases
allowed by regulatory agencies, new legislation, market entry of competing
electric power generators, changes in environmental regulations and other
regulatory requirements.  The Company estimates construction expenditures will
total $220 million for 1996 and 1997.  In addition, capital requirements for
1996 include $16 million to retire long-term debt.


Future Sources of Financing

     Internally generated funds from operations are expected to fund
substantially all anticipated construction expenditures in 1996 and 1997.


                                     -22-
<PAGE>


     At December 31, 1995, the Company had unused lines of credit of $160
million for which it pays commitment fees.  These credit facilities are
scheduled to expire during the year 2000.  Management expects to renegotiate
them when they expire.

     To the extent permanent financings are needed in 1996 and 1997, the Company
expects that it will have ready access to the securities markets to raise needed
funds.


Environmental Matters

     The Clean Air Act Amendments of 1990 (the Act) impose stringent limits on
emissions of sulfur dioxide and nitrogen oxides by electric utility generating
plants.  All of the Company's coal-fired boilers are equipped with sulfur
dioxide "scrubbers" and already achieve the final sulfur dioxide emission rates
required by the year 2000 under the legislation.  However, as part of its
ongoing construction program, the Company has spent $22 million to date and
anticipates incurring capital expenditures of approximately $8 million in 1996
for remedial measures necessary to meet the Act's requirements for nitrogen
oxides.  The overall financial impact of the legislation on the Company is
expected to be minimal.  The Company is well-positioned in the market to be a
"clean" power provider without the large capital expenditures that are expected
to be incurred by many other utilities.

     Reference is made to Note 13, Environmental, under Item 8 for a complete
discussion of the Company's environmental issues concerning its Mill Creek and
Cane Run electric generating plants, manufactured gas plant sites, and certain
other environmental issues.


Energy Policy Act of 1992 and Related Matters

     The Energy Policy Act of 1992 is designed to give utilities a wider choice
of sources for their electrical supply than previously available, while creating
generating supply options that did not exist under the old law.  In passing this
legislation, Congress also anticipated that greater competition among electric
supply options should result in lower consumer rates.

     Pursuant to the Energy Policy Act, the FERC earlier this year issued a
Notice of Proposed Rulemaking on Open Access Non-discriminatory Transmission
Services and a Supplemental Notice of Proposed Rulemaking on Stranded Investment
(collectively, the Mega-NOPR).  The Mega-NOPR is intended, among other things,
to create a vigorous wholesale electric market by requiring transmission
providers to offer open access to their transmission systems.  The Company is
supportive of proposals to increase competition at all levels of the electric
power market and intends to pursue opportunities created by a more competitive
market.


FERC Order No. 636

     Under Order No. 636, pipelines may recover costs associated with the
transition to and implementation of this order from pipeline customers,
including the Company.  During 1995, the Company paid and began recovering from
its customers approximately $4.8 million in transition costs under Order No.
636.  It is estimated that about $1.4 million in additional transition costs
will be incurred by the Company during 1996 and about $1.3 million in 1997, and
these costs are also


                                     -23-
<PAGE>


expected to be recovered from customers.  See FERC Order No. 636 under Note 13
of Notes to Financial Statements under Item 8 for further discussion.


FUTURE OUTLOOK

Business Realignment

     Effective December 15, 1995, LG&E Energy Corp. modified its organizational
structure.  The changes are designed to facilitate decision making, improve
response to customers and better align operating units with the changing
competitive marketplace.  Four operating divisions were established:

        Distribution Services Division - which includes the distribution
        resources of Louisville Gas and Electric Company (LG&E), is responsible
        for expanding and developing the distribution businesses and investing
        in enhanced service offerings behind the customer's meter.

        Gas Marketing Division - primarily consists of the businesses of LG&E
        Natural Inc. (a subsidiary of LG&E Energy Corp.), which markets gas
        throughout the United States and Canada.

        Power Marketing Division - includes LG&E Power Marketing Inc. (LPM), is
        responsible for project development and the marketing and sale of
        wholesale power throughout the United States.

        Power Generation Division - which includes the generation resources of
        LG&E, LG&E Power Inc. and LG&E International Inc., has responsibility
        for all utility and non-utility power plant operations, asset
        management, and development functions both domestically and
        internationally.

     Wholesale power will continue to be marketed and brokered by LPM, a
wholly-owned subsidiary of LG&E Energy Corp.  LPM was among the first
utility-affiliated marketers in the country to secure FERC approval to sell
power at market-based rates and engage in wholesale power marketing activities.
During 1995, its first full year of operations, LPM sold or brokered 1.8 million
megawatt-hours of power in 30 states.  This volume of activity placed LPM among
the five largest marketers of wholesale energy in 1995 and the largest seller
affiliated with a regulated electric utility.  LPM is predicting that the market
for electric energy will expand and its revenues will increase in future years.

     The realignment does not affect LG&E Energy Corp.'s legal structure,
regulation of the Company by the Commission or LG&E Energy Corp.'s status as an
exempt holding company.


                                     -24-
<PAGE>


Tennessee Gas Pipeline Company

     During the last quarter of 1995, the Company negotiated a five-year
transportation agreement with Tennessee Gas Pipeline Company (Tennessee) to
become the Company's second natural gas pipeline transporter.  The agreement
with Tennessee becomes effective November 1, 1996.  For many years, Texas Gas
Transmission Corporation has been the sole provider of gas transport services to
the Company.


Union Contract

     On December 8, 1995, members of the International Brotherhood of Electrical
Workers Local 2100 ratified a new three-year collective bargaining agreement
with the Company, which covers approximately 1,600 employees.  The contract
provides wage and employment protection for employees participating in the
Company's continuous improvement initiative, greater workforce flexibility to
help the Company respond to growing competition, and improved retirement
benefits.


Competition

     The Company 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; a write-off of previously deferred expenses; an
increase in focus on commercial and industrial customers; an increase in
employee involvement and training; a major realignment and formation of new
business units, and a modification of its organization structure.


                                     -25-
<PAGE>


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                        LOUISVILLE GAS AND ELECTRIC COMPANY
                               STATEMENTS OF INCOME
                                 (Thousands of $)

<TABLE>
<CAPTION>
                                                                      Years Ended December 31
                                                              ---------------------------------------
                                                                1995           1994           1993
                                                                ----           ----           ----
<S>                                                           <C>            <C>            <C>
Operating Revenues
  Electric..............................................      $570,637       $558,946       $570,210
  Refund - Trimble County Settlement (Note 14)                 (28,300)             -              -
  Gas...................................................       181,126        200,129        204,915
                                                              --------       --------       --------

    Total operating revenues (Note 1).....................     723,463        759,075        775,125
                                                              --------       --------       --------

Operating Expenses
  Fuel for electric generation..........................       138,002        143,602        149,436
  Power purchased.......................................        16,830          9,754         17,228
  Gas supply expenses...................................       110,738        131,561        139,054
  Other operation expenses..............................       134,655        136,214        136,693
  Maintenance...........................................        52,101         48,731         48,414
  Non-recurring charges (Note 3)........................             -         38,613              -
  Depreciation and amortization.........................        85,759         82,519         79,655
  Federal and State income taxes (Note 8)...............        47,524         39,922         52,334
  Property and other taxes..............................        16,528         17,119         16,193
                                                              --------       --------       --------
    Total operating expenses..............................     602,137        648,035        639,007
                                                              --------       --------       --------

Net Operating Income....................................       121,326        111,040        136,118

Other Income and (Deductions) (Note 9)..................         3,776          2,451          1,913
Contribution to Charitable Foundation - net (Note 3)....             -          8,946              -
Interest Charges........................................        41,918         42,856         47,496
                                                              --------       --------       --------

Income before Cumulative Effect of a Change in
  Accounting Principle..................................        83,184         61,689         90,535

Cumulative Effect of a Change in Accounting for
  Post-Employment Benefits, net of income taxes
  of $2,280 (Note 7)....................................             -         (3,369)             -
                                                              --------       --------       --------

Net Income..............................................        83,184         58,320         90,535
Preferred Stock Dividends...............................         6,311          5,828          5,981
                                                              --------       --------       --------

Net Income Available for Common Stock...................      $ 76,873       $ 52,492       $ 84,554
                                                              --------       --------       --------
                                                              --------       --------       --------
</TABLE>


                          STATEMENTS OF RETAINED EARNINGS
                                 (Thousands of $)

<TABLE>
<CAPTION>
                                                                      Years Ended December 31
                                                              --------------------------------------
                                                                1995           1994           1993
                                                                ----           ----           ----
<S>                                                           <C>            <C>            <C>
Balance January 1.......................................      $193,895       $194,903       $178,667
Add net income..........................................        83,184         58,320         90,535
                                                              --------       --------       --------
                                                               277,079        253,223        269,202
                                                              --------       --------       --------

Deduct:  Cash dividends declared on stock:
      5% cumulative preferred...........................         1,075          1,075          1,075
      7.45% cumulative preferred........................         1,527          1,598          1,598
      $8.90 cumulative preferred........................             -              -          1,113
      Auction rate cumulative preferred.................         2,240          1,686          1,322
      $5.875 cumulative preferred.......................         1,469          1,469            873
      Common............................................        89,000         53,500         67,500
    Preferred stock redemption expense..................           719              -            818
                                                              --------       --------       --------
                                                                96,030         59,328         74,299
                                                              --------       --------       --------

Balance December 31.....................................      $181,049       $193,895       $194,903
                                                              --------       --------       --------
                                                              --------       --------       --------
</TABLE>

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


                                     -26-
<PAGE>


                        LOUISVILLE GAS AND ELECTRIC COMPANY
                                  BALANCE SHEETS
                                 (Thousands of $)

                                      ASSETS
<TABLE>
<CAPTION>
                                                                            December 31
                                                                 --------------------------------
                                                                    1995                 1994
                                                                    ----                 ----
<S>                                                              <C>                 <C>
Utility Plant, at original cost
  Electric..................................................     $2,123,699          $2,084,334
  Gas.......................................................        299,070             280,877
  Common....................................................        128,902             137,662
                                                                 ----------          ----------
                                                                  2,551,671           2,502,873
  Less:  Reserve for depreciation...........................        934,942             881,861
                                                                 ----------          ----------
                                                                  1,616,729           1,621,012
  Construction work in progress.............................         47,189              35,022
                                                                 ----------          ----------
                                                                  1,663,918           1,656,034
                                                                 ----------          ----------
Other Property and Investments - less reserve (Note 6)......            760              50,681
                                                                 ----------          ----------

Current Assets
  Cash and temporary cash investments.......................         58,131              39,138
  Marketable securities (Note 6)............................         20,449                   -
  Accounts receivable-less reserve of
  $1,360 in 1995 and $1,203 in 1994.........................        105,589              86,058
  Materials and supplies-at average cost
     Fuel (predominantly coal)..............................         14,996              13,869
     Gas stored underground.................................         31,714              31,354
     Other..................................................         34,384              37,299
  Prepayments...............................................          2,108                 253
                                                                 ----------          ----------
                                                                    267,371             207,971
                                                                 ----------          ----------

Deferred Debits and Other Assets
  Unamortized debt expense..................................          7,710               7,776
  Regulatory assets (Note 2)................................         29,926              31,726
  Other.....................................................          9,805              12,402
                                                                 ----------          ----------
                                                                     47,441              51,904
                                                                 ----------          ----------
                                                                 $1,979,490          $1,966,590
                                                                 ----------          ----------
                                                                 ----------          ----------
                                    CAPITAL AND LIABILITIES

Capitalization (see Statements of Capitalization)
  Common equity.............................................       $605,157            $616,478
  Cumulative preferred stock................................         95,328             116,716
  Long-term debt............................................        646,845             662,862
                                                                 ----------          ----------
                                                                  1,347,330           1,396,056
                                                                 ----------          ----------

Current Liabilities
  Long-term debt due within one year........................         16,000                   -
  Accounts payable..........................................         93,706              70,770
  Trimble County Settlement (Note 14).......................         28,300                   -
  Dividends declared........................................         19,672              19,567
  Accrued taxes.............................................          7,814               8,247
  Accrued interest..........................................         11,064              13,394
  Other.....................................................         12,071              10,277
                                                                 ----------          ----------
                                                                    188,627             122,255
                                                                 ----------          ----------

Deferred Credits and Other Liabilities
  Accumulated deferred income taxes (Notes 1 and 8).........        204,816             193,236
  Investment tax credit, in process of amortization.........         84,037              88,779
  Accumulated provision for pensions and related benefits...         47,099              49,104
  Customers' advances for construction......................          9,251               8,621
  Regulatory liability (Note 2).............................         88,242              91,492
  Other.....................................................         10,088              17,047
                                                                 ----------          ----------
                                                                    443,533             448,279
                                                                 ----------          ----------
Commitments and Contingencies (Note 13)
                                                                 $1,979,490          $1,966,590
                                                                 ----------          ----------
                                                                 ----------          ----------
</TABLE>

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


                                     -27-
<PAGE>


                        LOUISVILLE GAS AND ELECTRIC COMPANY
                             STATEMENTS OF CASH FLOWS
                                 (Thousands of $)

<TABLE>
<CAPTION>
                                                                                Years Ended December 31
                                                                       ----------------------------------------
                                                                          1995           1994           1993
                                                                          ----           ----           ----
<S>                                                                    <C>            <C>            <C>
Cash Flows from Operating Activities
  Net Income........................................................   $  83,184      $  58,320      $  90,535
  Items not requiring cash currently:
    Depreciation and amortization...................................      85,759         82,519         79,887
    Deferred income taxes-net.......................................       7,049         (2,274)         4,938
    Investment tax credit-net.......................................      (4,742)        (4,619)        (7,821)
    Cumulative effect of change in accounting principle.............           -          3,369              -
    Non-recurring charges...........................................           -         38,613              -
    Gain on sale of capital asset...................................           -              -         (3,869)
    Other...........................................................       3,958          6,603          5,877
  (Increase) decrease in certain net current assets:
    Accounts receivable.............................................     (19,531)        18,339        (11,678)
    Materials and supplies..........................................       1,428          3,280         10,671
    Trimble County Settlement.......................................      28,300              -              -
    Accounts payable................................................      22,936        (22,781)        21,099
    Accrued taxes...................................................        (433)        (1,247)         2,343
    Accrued interest................................................      (2,330)           530            757
    Prepayments and other...........................................         (61)          (743)          (260)
  Other.............................................................      (6,917)           972        (15,587)
                                                                       ---------      ---------      ---------
    Net cash provided from operating activities.....................     198,600        180,881        176,892
                                                                       ---------      ---------      ---------

Cash Flows from Investing Activities
  Purchases of securities...........................................    (119,151)       (87,896)       (38,398)
  Proceeds from sales of securities.................................     151,422         56,085         27,301
  Construction expenditures.........................................     (93,423)       (95,398)       (98,787)
  Sale of capital asset.............................................           -              -         91,076
                                                                       ---------      ---------      ---------
    Net cash used for investing activities..........................     (61,152)      (127,209)       (18,808)
                                                                       ---------      ---------      ---------

Cash Flows from Financing Activities
  Issuance of preferred stock.......................................           -              -         24,716
  Issuance of first mortgage bonds and pollution control bonds......      39,914              -        198,918
  Redemption of preferred stock.....................................     (22,108)             -        (25,558)
  Retirement of first mortgage bonds and pollution control bonds....     (41,055)             -       (231,876)
  Repayment of short-term borrowings................................           -              -         (8,000)
  Payment of dividends..............................................     (95,206)       (58,639)       (73,125)
                                                                       ---------      ---------      ---------
  Net cash used for financing activities............................    (118,455)       (58,639)      (114,925)
                                                                       ---------      ---------      ---------

Net Increase (Decrease) in Cash and Temporary Cash Investments......      18,993         (4,967)        43,159

Cash and Temporary Cash Investments at Beginning of Year............      39,138         44,105            946
                                                                       ---------      ---------      ---------

Cash and Temporary Cash Investments at End of Year..................   $  58,131      $  39,138      $  44,105
                                                                       ---------      ---------      ---------
                                                                       ---------      ---------      ---------



Supplemental Disclosures of Cash Flow Information
  Cash paid during the year for:
  Income taxes......................................................   $  40,049      $  42,803      $  54,686
  Interest on borrowed money........................................      42,589         40,827         45,360
</TABLE>


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


                                     -28-
<PAGE>


                        LOUISVILLE GAS AND ELECTRIC COMPANY
                           STATEMENTS OF CAPITALIZATION
                                 (Thousands of $)

<TABLE>
<CAPTION>
                                                                                    December 31
                                                                           -----------------------------
                                                                              1995           1994
                                                                              ----           ----
<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 loss on marketable securities, net of income
    taxes of $153 in 1995 and $1,434 in 1994 (Note 6).................           (226)        (1,751)
  Retained earnings...................................................        181,049        193,895
                                                                           ----------     ----------

                                                                              605,157        616,478
                                                                           ----------     ----------

Cumulative Preferred Stock
  Redeemable on 30 days notice by the Company except, $5.875 series

<CAPTION>

                                            Shares             Current
                                       Outstanding    Redemption Price
                                       -----------    ----------------
<S>                                    <C>            <C>
  $25 par value, 1,720,000 shares authorized -
    5% series......................        860,287              $28.00         21,507         21,507
    7.45% series (Note 10).........              -                   -              -         21,453
  Without par value, 6,750,000 shares authorized -
    Auction Rate...................        500,000              100.00         50,000         50,000
    $5.875 series..................        250,000      Not redeemable         25,000         25,000
  Preferred stock expense.............................................         (1,179)        (1,244)
                                                                           ----------     ----------
                                                                               95,328        116,716
                                                                           ----------     ----------

Long-Term Debt (Note 11)
  First mortgage bonds -
    Series due June 1, 1996, 5 5/8%...................................         16,000         16,000
    Series due June 1, 1998, 6 3/4%...................................         20,000         20,000
    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:
      J due July 1, 2015, 9 1/4%......................................              -         40,000
      K due December 1, 2016, 7 1/4%..................................         27,500         27,500
      L due December 1, 2016, 7 1/4%..................................         22,500         22,500
      N due February 1, 2019, 7 3/4%..................................         35,000         35,000
      O due February 1, 2019, 7 3/4%..................................         35,000         35,000
      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              -
                                                                           ----------     ----------
    Total bonds outstanding...........................................        662,800        662,800
    Less long-term debt due within one year...........................         16,000              -
                                                                           ----------     ----------
    Long-term first mortgage bonds....................................        646,800        662,800
  Unamortized premium on bonds........................................             45             62
                                                                           ----------     ----------
                                                                              646,845        662,862
                                                                           ----------     ----------

Total Capitalization..................................................     $1,347,330     $1,396,056
                                                                           ----------     ----------
                                                                           ----------     ----------
</TABLE>

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


                                     -29-
<PAGE>


                        LOUISVILLE GAS AND ELECTRIC COMPANY

                           NOTES TO FINANCIAL STATEMENTS



     NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     Louisville Gas and Electric Company (the Company) is the primary subsidiary
     of LG&E Energy Corp.  The Company 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 Corp. is an exempt energy
     services holding company with wholly-owned subsidiaries consisting of the
     Company, LG&E Energy Systems Inc., and LG&E Gas Systems Inc.  All of the
     Company's Common Stock is held by LG&E Energy Corp.

     Certain reclassification entries have been made to the 1994 financial
     statements to conform with the 1995 presentation with no impact on
     previously reported income.

     UTILITY PLANT.  The Company'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, and, accordingly, the Company 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
     1995 were 3.3% (3.2% electric, 3.3% gas, and 6% common); for 1994, 3.3%
     (3.2% electric, 3.3% gas, and 5% common); and for 1993, 3.3% (3.2%
     electric, 3.2% gas, and 5% common) of average depreciable plant.

     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.

     FINANCIAL INSTRUMENTS.  The Company uses over-the-counter interest-rate
     swap agreements to hedge its exposure to fluctuations in 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 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 loss 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.



                                     -30-
<PAGE>


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

     The Company adopted Statement of Financial Accounting Standards No. 109,
     ACCOUNTING FOR INCOME TAXES (SFAS No. 109) January 1, 1993.  Regulatory
     assets and liabilities have been established to recognize the future
     revenue requirement impact from the deferred income taxes which were not
     immediately recognized in operating results because of ratemaking
     treatment.  The adoption of SFAS No. 109 did not have a material impact on
     the results of operations or financial position.

     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.  Investment tax
     credits deferred and charged to income in prior years are being amortized
     to income over the estimated lives of the related property that gave rise
     to the credits.

     DEBT PREMIUM AND EXPENSE.  Debt premium and expense are amortized over
     the lives of the related debt issues, consistent with regulatory practices.

     REVENUE RECOGNITION.  Revenues are recorded based on service rendered to
     customers through month end.  The Company accrues an estimate for unbilled
     revenues from the date of each meter reading date to the end of the
     accounting period.  Effective January 1, 1994, under an agreement approved
     by the Public Service Commission of Kentucky (Kentucky Commission or
     Commission), the Company implemented a demand side management program and a
     "decoupling mechanism," which allows the Company to recover a predetermined
     level of revenue on electric and gas residential sales.  See Management's
     Discussion and Analysis, Rates and Regulation, under Item 7 for further
     discussion.

     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.

     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
     amounts of assets and liabilities and disclosure of contingent assets and
     liabilities 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 13, Commitments and
     Contingencies, for further discussion.

     NEW ACCOUNTING PRONOUNCEMENT.  LONG-LIVED ASSETS - In March 1995, the
     Financial Accounting Standards Board issued Statement of Financial
     Accounting Standards No. 121, ACCOUNTING FOR THE IMPAIRMENT OF LONG-LIVED
     ASSETS AND FOR LONG-LIVED ASSETS TO BE DISPOSED OF (SFAS No. 121),
     effective for fiscal years beginning after December 15, 1995.  The Company
     plans to adopt the provisions of SFAS No. 121 in the first quarter of 1996.
     The new standard requires that long-lived assets and certain identified
     intangibles be reviewed for impairment whenever events or changes in
     circumstances indicate that the carrying amount of an asset may not be
     recoverable.  In performing such impairment reviews, companies will be
     required to estimate the sum of future cash flows from an asset and compare
     such amount to the asset's carrying amount.  Any excess of carrying amount
     over expected cash flows will result in a possible write-down of an asset
     to its fair value.  Based on current operating


                                     -31-
<PAGE>


     conditions, legal requirements and regulatory environment, the Company does
     not expect adoption of SFAS No. 121 to have a material adverse impact on
     its financial position or results of operations.

     NOTE 2 - RATES AND REGULATORY MATTERS

     The Company conforms with generally accepted accounting principles as
     applied to regulated public utilities and as prescribed by the Federal
     Energy Regulatory Commission (FERC) and the Kentucky Commission.  The
     Company 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.  Management's 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>
                                                       1995           1994
                                                       ----           ----
     <S>                                            <C>            <C>
     Unamortized loss on bonds...................   $ 16,443       $ 15,704
     Unamortized extraordinary retirements.......      6,935          9,752
     Manufactured gas sites......................      3,220          3,149
     Other.......................................      3,328          3,121
                                                    --------       --------
     Total regulatory assets.....................     29,926         31,726

     Deferred income taxes - net.................    (88,242)       (91,492)
                                                    --------       --------

     Regulatory assets and (liabilities) - net...   $(58,316)      $(59,766)
                                                    --------       --------
                                                    --------       --------
</TABLE>

     Substantially all of the Company's regulatory assets are being recovered
     through rates charged to customers.  The Company expects to seek regulatory
     approval to recover any remaining regulatory assets in its next general
     rate case.

     ENVIRONMENTAL COST RECOVERY. The Company filed an application with the
     Kentucky Commission in October 1994, in which it requested approval of an
     environmental cost recovery surcharge to recover certain costs incurred to
     comply with federal, state, and local environmental requirements.  On April
     6, 1995, the Commission approved the surcharge with modifications. The
     surcharge became effective on May 1, 1995.  The Company recovered $3.2
     million in 1995 and expects to recover an additional $5.7 million in 1996
     through the surcharge.

     An appeal of the Commission's April 6 order by various intervenors in the
     proceeding (including the Kentucky Attorney General) is currently pending
     in the Franklin Circuit Court of Kentucky.  The intervenors are contesting
     the validity of the order on several grounds, including the
     constitutionality of the Kentucky statute that authorizes the surcharge.
     The Company is vigorously contesting the legal challenges to the surcharge,
     but cannot predict the outcome of the appeal.  The amount of refunds that
     may be ordered, if any, are not expected to have a material adverse effect
     on the Company's financial position or results of operations.  See
     Management's Discussion and Analysis, Rates and Regulation, under Item 7
     for a further discussion.


                                     -32-
<PAGE>


     NOTE 3 - NON-RECURRING CHARGES

     As part of a study of LG&E Energy Corp.'s business strategy and realignment
     during 1994, the Company re-evaluated its regulatory strategy which
     previously had been to seek full recovery of certain costs deferred in
     accordance with prior precedents established by the Commission.  As a
     result of this re-evaluation, the Company wrote off certain expenses that
     had previously been deferred amounting to approximately $38.6 million
     before taxes.  While the Company continues to believe that it could have
     reasonably expected to recover these costs in future rate proceedings
     before the Commission, the Company decided to deduct these expenses
     currently and not seek recovery for such expenses in future rates due to
     increasing competitive pressures and the existing and anticipated future
     economic conditions.  The items written off include costs incurred in
     connection with early retirements and workforce reductions that occurred in
     1992 and 1993, which consist primarily of separation payments, enhanced
     early retirement benefits, and health care benefits; costs associated with
     property damage claims pertaining to particulate emissions from its Mill
     Creek electric generating plant which primarily consist of spotting on
     automobile finish and aluminum siding; and certain costs previously
     deferred resulting from adoption in January 1993 of Statement of Financial
     Accounting Standards No. 106, EMPLOYERS' ACCOUNTING FOR POST-RETIREMENT
     BENEFITS OTHER THAN PENSIONS.

     In the first quarter of 1994, the Board of Directors of the Company
     approved the formation of a tax-exempt charitable foundation (Foundation)
     that makes charitable contributions to qualified persons and entities.  In
     1994, the Company recorded a pre-tax charge against income and made an
     irrevocable payment of $15 million to fund the Foundation.  On June 6,
     1994, the Internal Revenue Service issued a letter stating that it had
     determined the Foundation was exempt from Federal income tax under the
     Internal Revenue Code.

     NOTE 4 - FINANCIAL INSTRUMENTS

     INSTRUMENTS USED IN HEDGING ACTIVITIES.  The Company uses exchange-traded
     futures and over-the-counter (OTC) swap agreements to hedge its exposure to
     changes in the valuation of investments in marketable securities and
     changes in interest rates on variable rate debt, respectively.  Futures
     reduce exposure to fluctuations in pricing of marketable securities as of a
     future delivery date.  Swaps allow the Company to change certain
     index-based interest payment commitments to fixed amounts based on a stated
     rate.


                                     -33-
<PAGE>


     The following summarizes the Company's use of financial instruments for
     hedging purposes at December 31, 1995:


<TABLE>
<CAPTION>
                                             NOTIONAL AMOUNT
             CATEGORY                           /MATURITY                              PURPOSE
     -----------------------------     -------------------------------     ------------------------------
     <S>                               <C>                                 <C>
     Exchange-traded U.S. Treasury     $4.3 million, matures March         Reduce exposure to changes in
     notes and bond futures            1996                                market value of investments in
                                                                           preferred stock.

     OTC interest rate swaps           $15 million matures September       Convert $30 million of Series S
                                       1997; $15 million matures           variable rate Pollution Control
                                       September 1999                      Bonds to average composite
                                                                           rates of 4.55%.  Average
                                                                           variable rate received based on
                                                                           JJ Kenny index, 3.87%, 2.84%,
                                                                           and 2.38% in 1995, 1994, and
                                                                           1993, respectively.
</TABLE>


     Initial margin requirements and daily margin calls for exchange-traded
     futures are met in cash and all transactions are settled in cash or through
     delivery of the underlying security.

     FAIR VALUES OF FINANCIAL INSTRUMENTS.  The carrying amounts of cash,
     accounts receivable, and accounts payable reflected on the balance sheets
     approximates the fair value of these instruments due to the short duration
     to maturity.  The fair value for certain of the Company's investments and
     debt are estimated based on quoted market prices for those or similar
     instruments.  Investments for which there are no quoted market prices are
     stated at cost because a reasonable estimate of fair value cannot be made
     without incurring excessive costs.  The fair value of exchange-traded
     financial instruments reflects market prices reported by the exchanges.
     Fair values of swaps are based on price quotes obtained from dealers.  Fair
     value estimates are made at a certain point in time and changes in
     assumptions, economic conditions, risk characteristics of various
     instruments and other factors could cause significant changes in these
     estimates.

     The fair value information contained herein does not include an assessment
     of assets and liabilities that are not financial instruments, such as
     property and equipment or other assets and liabilities.  Accordingly, these
     fair value disclosures are not intended to present a valuation of the
     Company taken as a whole.


                                     -34-
<PAGE>


     The cost and estimated fair values of the Company's financial instruments
     as of December 31, 1995 and 1994 follow (in thousands of $):

<TABLE>
<CAPTION>
                                                                   1995                         1994
                                                         ------------------------     -------------------------
                                                                            Fair                          Fair
                                                             Cost          Value           Cost          Value
                                                         --------       ---------     ---------       --------
     <S>                                                 <C>            <C>            <C>            <C>
     Marketable securities.............................  $ 20,828       $ 20,449       $      -       $      -
     Long-term investments:
       Practicable to estimate fair value..............         -              -         53,323         50,138
       Not practicable.................................       740            740            515            515
     Preferred stock subject to mandatory redemption...    25,000         25,000         25,000         22,125
     Long-term debt....................................   662,800        688,977        662,800        648,697
     U.S. Treasury note and bond futures...............         -           (105) (a)         -           (383)
     OTC interest rate swaps...........................         -           (522)             -            965
</TABLE>

     (a) Gains and losses realized on the future sale or purchase of marketable
         securities will generally offset any net unrealized gains and losses.

     See Note 5, Concentrations of Credit and Other Risk, for a discussion of
     credit risk as it pertains to certain of the above financial instruments.

     NOTE 5 - CONCENTRATIONS OF CREDIT AND OTHER RISK

     Credit risk represents the accounting loss that would be recognized at the
     reporting date if counterparties (See Note 4, Financial Instruments, for
     further discussion) 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.  The Company does not have a significant loss exposure to any
     individual customer or counterparty.

     The Company's customer receivables and gas and electric revenues arise from
     deliveries of natural gas to approximately 272,000 customers and
     electricity to approximately 346,000 customers in Louisville and adjacent
     areas in Kentucky.  For the year ended December 31, 1995, 75% of total
     revenue was derived from electric operations and 25% from gas operations.

     The Company's operation and maintenance employees are members of the
     International Brotherhood of Electrical Workers (IBEW) Local 2100 which
     represents approximately one-half of the Company's workforce.  The
     Company's collective bargaining agreement with IBEW employees expires in
     November 1998.

    NOTE 6 - MARKETABLE SECURITIES

     The Company adopted the provisions of Statement of Financial Accounting
     Standards No. 115, ACCOUNTING FOR CERTAIN INVESTMENTS IN DEBT AND EQUITY
     SECURITIES January 1, 1994.  Accordingly, the Company's marketable
     securities have been determined to be "available-for-sale" and are stated
     at market value in the accompanying balance sheets.  The available-for-sale
     category of investments results in the classification of unrealized gains
     and losses on investments in common equity, net of income taxes, until such
     gains and losses are realized, at which time they are recognized in
     earnings.  Proceeds from sales of available-for-sale securities in 1995
     were $151,422,000, which resulted in realized gains of


                                     -35-
<PAGE>


     $1,621,000 and losses of $3,440,000, calculated using the specific
     identification method.  Proceeds from sales of available-for-sale
     securities in 1994 were $56,085,000, which resulted in realized gains of
     $1,557,000 and losses of $1,538,000.  The differences between amortized and
     unamortized cost basis of the Company's investments in marketable
     securities as of December 31, 1995 and 1994, were immaterial.

     Approximate cost, fair value, and other required information about the
     Company's available-for-sale securities by major security type as of
     December 31, 1995 and 1994, follow (in thousands of $):


<TABLE>
<CAPTION>
                                                  1995                                        1994
                                  -------------------------------------      ---------------------------------------
                                                 Fixed                                       Fixed
                                   Equity        Income         Total          Equity        Income          Total
                                  --------      --------       -------        --------      --------       --------
     <S>                          <C>           <C>            <C>            <C>           <C>            <C>
     Cost.......................  $7,399        $13,429        $20,828        $23,622        $29,701        $53,323
     Unrealized gains...........      58              1             59             41              -             41
     Unrealized losses..........    (198)          (240)          (438)        (2,399)          (827)        (3,226)
                                  ------        -------        -------        -------        -------        -------
     Fair values................  $7,259        $13,190        $20,449        $21,264        $28,874        $50,138
                                  ------        -------        -------        -------        -------        -------
                                  ------        -------        -------        -------        -------        -------

-------------------------------------------------------------------------------------------------------------------

     Fair Values:
       No maturity..............  $6,620        $     -        $ 6,620        $20,415        $     -        $20,415
       Maturities:
         Less than one year.....     639          2,710          3,349            849          2,519          3,368
         One to five years......       -          8,808          8,808              -         16,968         16,968
         Five to ten years......       -            831            831              -          1,958          1,958
         Over ten years.........       -            164            164              -          3,381          3,381
         No single date.........       -            677            677              -          4,048          4,048
                                  ------        -------        -------        -------        -------        -------
     Total Fair Values..........  $7,259        $13,190        $20,449        $21,264        $28,874        $50,138
                                  ------        -------        -------        -------        -------        -------
                                  ------        -------        -------        -------        -------        -------
</TABLE>

     The Company's available-for-sale securities were classified as Marketable
     Securities at December 31, 1995.  In 1994, available-for-sale securities
     were classified as Other Property and Investments in the accompanying
     balance sheet.

     NOTE 7 - PENSION PLANS AND RETIREMENT BENEFITS

     PENSION PLANS.  The Company has two non-contributory, defined-benefit
     pension plans, covering all eligible employees.  Retirement benefits are
     based on the employee's years of service, age at retirement and
     compensation.  The Company's policy is to fund annual actuarial costs, up
     to the maximum amount deductible for income tax purposes, as determined
     under the frozen entry age actuarial cost method.  The assets of the plans
     consist primarily of common stocks, corporate bonds and United States
     government securities.

     The Company also has a supplemental executive retirement plan that covers
     officers of the Company.  The plan provides retirement benefits based on
     average earnings during the final three years prior to retirement, reduced
     by social security benefits, any pension benefits received from plans of
     prior employers, and by amounts received under the pension plans referred
     to in the preceding paragraph.



                                     -36-
<PAGE>


     Pension costs were $4,977,000 for 1995, $4,423,000 for 1994, and
     $2,669,000 for 1993, of which approximately $761,000, $693,000, and
     $425,000, respectively, were charged to construction.  The components of
     periodic pension expense are shown below (in thousands of $):

<TABLE>
<CAPTION>
                                                            1995          1994            1993
                                                            ----          ----            ----
     <S>                                                 <C>            <C>            <C>
     Service cost-benefits earned during the period..    $  4,361       $  4,813       $  4,516
     Interest cost on projected benefit obligation...      14,328         13,057         12,117
     Actual return on plan assets....................     (45,608)          (489)       (13,602)
     Amortization of transition asset................      (1,112)        (1,112)        (1,112)
     Net amortization and deferral...................      33,008        (11,846)           750
                                                         --------       --------       --------
     Net pension cost................................    $  4,977       $  4,423       $  2,669
                                                         --------       --------       --------
                                                         --------       --------       --------
</TABLE>

     The funded status of the pension plans at December 31 is shown below (in
     thousands of $):

<TABLE>
<CAPTION>
                                                                     1995           1994
                                                                     ----           ----
     <S>                                                           <C>            <C>
     Actuarial present value of accumulated plan benefits:
       Vested...............................................       $166,525       $132,260
       Non-Vested...........................................          8,577         14,023
                                                                   --------       --------

       Accumulated benefit obligation.......................        175,102        146,283
       Effect of projected future compensation..............         31,764         18,473
                                                                   --------       --------

       Projected benefit obligation.........................        206,866        164,756
       Plan assets at fair value............................        207,470        159,638
                                                                   --------       --------

       Plan assets in excess of (less than) projected
         benefit obligation.................................            604         (5,118)
       Unrecognized net transition asset....................        (11,412)       (12,524)
       Unrecognized prior service cost......................         28,938         24,257
       Unrecognized net gain................................        (43,652)       (36,266)
                                                                   --------       --------

     Accrued pension liability..............................       $(25,522)      $(29,651)
                                                                   --------       --------
                                                                   --------       --------
</TABLE>
     The assumptions used in determining the actuarial valuations are as
     follows:

<TABLE>
<CAPTION>
                                                                      1995            1994
                                                                      ----            ----
     <S>                                                          <C>            <C>
     Assumed discount rate to determine
       projected benefit obligation...........                         7.5%           8.5%
     Assumed long-term rate of return
       on plan assets.........................                         8.5%           8.5%
     Assumed annual rate of increase in
       future compensation levels.............                    3.5% - 4%      4.5% - 5%
</TABLE>

     POST-RETIREMENT BENEFITS.  The Company provides certain health care and
     life insurance benefits for eligible retired employees.  Post-retirement
     health care benefits are subject to a maximum amount payable by the
     Company.  The Company adopted Statement of Financial Accounting Standards
     No. 106, EMPLOYERS' ACCOUNTING FOR POST-RETIREMENT BENEFITS OTHER THAN
     PENSIONS (SFAS No. 106) January 1, 1993.  SFAS No. 106 requires the
     accrual of the expected cost of retiree benefits other than pensions during
     the employee's years of service with the Company.  The Company is
     amortizing the discounted present value of the post-retirement benefit
     obligation at the date of adoption over 20 years.  Prior to January 1,


                                     -37-
<PAGE>


     1993, the cost of retiree health care and life insurance benefits was
     generally recognized when paid.

     The components of the net periodic post-retirement benefit cost as
     calculated under SFAS No. 106 are as follows (in thousands of $):

<TABLE>
<CAPTION>
                                                  1995       1994       1993
                                                  ----       ----       ----
     <S>                                          <C>        <C>        <C>
     Service cost ...........................     $  595     $  621     $  701
     Interest cost...........................      2,706      2,386      2,614
     Amortization of transition obligation...      1,337      1,337      1,395
                                                  ------     ------     ------
     Post-retirement benefit cost............     $4,638     $4,344     $4,710
                                                  ------     ------     ------
                                                  ------     ------     ------
</TABLE>

     The accumulated post-retirement benefit obligation as calculated under SFAS
     No. 106 at December 31, is shown below (in thousands of $):

<TABLE>
<CAPTION>
                                                               1995       1994
                                                               ----       ----
      <S>                                                    <C>        <C>
      Retirees............................................   $(19,965)  $(18,487)
      Fully eligible active employees.....................     (2,768)    (1,927)
      Other active employees..............................    (15,082)    (9,789)
                                                             --------   --------

      Accumulated post-retirement benefit obligation......    (37,815)   (30,203)
      Unrecognized net loss (gain)........................      3,480     (3,275)
      Unrecognized transition obligation..................     22,727     24,064
                                                             --------   --------

      Accrued post-retirement benefit liability...........   $(11,608)  $ (9,414)
                                                             --------   --------
                                                             --------   --------
</TABLE>

     The accumulated post-retirement benefit obligation was determined using an
     assumed discount rate of 7.5% for 1995 and 8.5% for 1994.  Assumed
     compensation increases for projected life insurance benefits for affected
     groups was 4% for 1995 and 5% for 1994.  An assumed health care cost trend
     rate of 10% was assumed for 1995, gradually decreasing to 5% in ten years
     and thereafter.

     A 1% increase in the assumed health care cost trend rate would increase the
     accumulated post-retirement benefit obligation by approximately $1.5
     million and the annual service and interest cost by approximately $200,000.
     No funding has been established by the Company for post-retirement
     benefits.

     POST-EMPLOYMENT BENEFITS.  The Company adopted Statement of Financial
     Accounting Standards No. 112, EMPLOYERS' ACCOUNTING FOR POST-EMPLOYMENT
     BENEFITS (SFAS No. 112) January 1, 1994.  SFAS No. 112 requires the
     accrual of the expected cost of benefits to former or inactive employees
     after employment but before retirement.  The cumulative effect of the
     accounting change was recorded in the first quarter of 1994 and decreased
     net income by $3.4 million.

     EARLY RETIREMENT/WORKFORCE REDUCTION.  During the last quarter of 1993,
     the Company eliminated approximately 350 full-time positions.  The cost of
     the employee reduction program was approximately $11.5 million, and
     consisted primarily of separation payments, enhanced early retirement
     benefits, and health care benefits.  See Note 3, Non-Recurring Charges.


                                     -38-
<PAGE>


     THRIFT SAVINGS PLAN.  The Company has a Thrift Savings Plan under
     Section 401(k) of the Internal Revenue Code.  The plan covers all regular
     full-time employees with one year or more of service at the Company.  Under
     the plan, eligible employees may defer and contribute to the plan a portion
     of current compensation in order to provide future retirement benefits.
     The Company makes contributions to the plan by matching a portion of
     employee contributions according to a formula established by the plan.
     These costs were approximately $1,750,000 for 1995, $1,701,000 for 1994,
     and $1,795,000 for 1993.

     NOTE 8 - FEDERAL AND STATE INCOME TAXES

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

<TABLE>
<CAPTION>
                                                       1995           1994           1993
                                                       ----           ----           ----
     <S>                                             <C>            <C>            <C>
     Included in Operating:
       Current  - Federal........................    $36,379        $35,552        $31,082
                - State..........................      9,138          9,003          8,920
       Deferred - Federal-net....................      4,021           (969)        13,185
                - State-net......................      2,728            955          3,933
       Amortization of investment tax credit.....     (4,742)        (4,619)        (4,786)
                                                     -------        -------        -------
           Total.................................    $47,524        $39,922        $52,334
                                                     -------        -------        -------

     Included in Other Income and (Deductions):
       Current  - Federal........................    $  (555)       $(4,626)       $11,009
                - State..........................       (343)        (1,277)         4,034
       Deferred - Federal-net....................        240             19         (8,473)
                - State-net......................         60              1         (3,707)
       Amortization of investment tax credit.....          -              -         (3,035)
                                                     -------        -------        -------

           Total.................................    $  (598)       $(5,883)       $  (172)
                                                     -------        -------        -------

     Included in Cumulative Effect of a Change
     in Accounting for Post-Employment Benefits:
       Deferred - Federal........................    $     -        $(1,814)       $     -
                - State..........................          -           (466)             -
                                                     -------        -------        -------

           Total.................................    $     -        $(2,280)       $     -
                                                     -------        -------        -------

     Total Income Tax Expense....................    $46,926        $31,759        $52,162
                                                     -------        -------        -------
                                                     -------        -------        -------
</TABLE>

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

     Provisions for deferred income taxes-net consist of the tax effects of the
     following temporary differences (in thousands of $):

<TABLE>
<CAPTION>
                                                       1995           1994            1993
                                                       ----           ----            ----
     <S>                                             <C>            <C>             <C>
     Depreciation and amortization.................  $15,140        $12,609         $ (255)
     Alternative minimum tax.......................        -              -          5,387
     Pension overfunding...........................    2,078         (4,357)          (823)
     Accrued liabilities not currently deductible..   (9,076)        (5,343)         1,210
     Change in accounting principle................        -         (2,280)             -
     Other........................................    (1,093)        (2,903)          (581)
                                                     -------        -------         ------
       Total.......................................  $ 7,049        $(2,274)        $4,938
                                                     -------        -------         ------
                                                     -------        -------         ------
</TABLE>


                                       -39-
<PAGE>



     The net provisions for deferred income taxes increased in 1995 largely due
     to current year funding of one of the Company's defined-benefit pension
     plans.  Fluctuations in deferred income taxes attributable to liabilities
     accrued for financial reporting, which are not currently deductible on the
     Company's tax return, occurred in 1995 and 1994 due to the timing of when
     such liabilities are paid.  Deferred income taxes attributable to
     depreciation and amortization in 1993 reflect the reversal of prior years'
     accumulated deferred income taxes as a result of the sale of a portion of
     Trimble County Unit 1.  See Note 15, Jointly Owned Electric Utility Plant,
     for a further discussion of the sale.

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

<TABLE>
<CAPTION>
                                                            1995        1994
                                                            ----        ----
     <S>                                                  <C>         <C>
     Deferred Tax Liabilities:
       Depreciation and other plant related items...      $297,929    $281,696
       Other liabilities............................         7,714       7,305
                                                          --------    --------
                                                           305,643     289,001
                                                          --------    --------
     Deferred Tax Assets:
       Investment tax credit........................        33,919      35,833
       Income taxes due to customers................        32,363      33,456
       Pension overfunding..........................         9,075      11,145
       Other assets.................................        25,470      15,331
                                                          --------    --------
                                                           100,827      95,765
                                                          --------    --------

         Net deferred income tax liability..........      $204,816    $193,236
                                                          --------    --------
                                                          --------    --------
</TABLE>

     The Company's effective income tax rate is computed by dividing the
     aggregate of current income taxes, deferred income taxes-net, and the
     amortization of investment tax credit by net income before the deduction of
     such taxes.  Reconciliation of the statutory Federal income tax rate to the
     effective income tax rate is shown in the table below:

<TABLE>
<CAPTION>
                                                       1995        1994        1993
                                                       ----        ----        ----
     <S>                                               <C>         <C>         <C>
     Statutory Federal income tax rate.............    35.0%       35.0%       35.0%
     State income taxes net of Federal benefit.....     5.8         5.9         6.0
     Amortization of investment tax credit.........    (3.6)       (5.1)       (5.5)
     Other differences-net.........................    (1.1)        (.5)        1.1
                                                       ----        ----        ----
     Effective Income Tax Rate.....................    36.1%       35.3%       36.6%
                                                       ----        ----        ----
                                                       ----        ----        ----
</TABLE>

     NOTE 9 - OTHER INCOME AND DEDUCTIONS

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

<TABLE>
<CAPTION>
                                                            1995      1994       1993
                                                            ----      ----       ----
     <S>                                                  <C>       <C>        <C>
     Interest and dividend income.......................  $ 5,732   $ 4,568    $ 3,112
     Gains (losses) on fixed asset disposal.............    1,090     1,427     (3,523)
     Gain on sale of 12.88% portion of Trimble County...        -         -      3,869
     Donations..........................................     (144)   (1,015)      (909)
     Income taxes and other.............................   (2,902)   (2,529)      (636)
                                                          -------   -------    -------
     Total other income and deductions..................  $ 3,776   $ 2,451    $ 1,913
                                                          -------   -------    -------
                                                          -------   -------    -------
</TABLE>


                                     -40-
<PAGE>



     NOTE 10 - PREFERRED STOCK

     In December 1995, the Company redeemed the 858,128 outstanding shares of
     its 7.45% Cumulative Preferred Stock with a par value of $25 per share at a
     redemption price of $25.75 per share.

     NOTE 11 - FIRST MORTGAGE BONDS

     Annual requirements for the sinking funds of the Company's First Mortgage
     Bonds (other than the First Mortgage Bonds issued in connection with the
     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 the Company to apply property additions to meet 1996 sinking fund
     requirements of the First Mortgage Bonds.

     The trust indenture securing the First Mortgage Bonds constitutes a direct
     first mortgage lien upon substantially all property owned by the Company.
     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 the Company to the Counties pursuant to loan
     agreements, and further secured by the delivery from time to time of an
     equal amount of the Company'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.

     In April 1995, the Company issued $40 million of Jefferson County,
     Kentucky, Pollution Control Revenue Bonds, 5.90% Series, due April 15,
     2023.  The proceeds of the bonds were used to redeem the outstanding 9.25%
     Series of Pollution Control Bonds due July 1, 2015.

     The Company has outstanding interest rate swap agreements totaling $30
     million related to its Pollution Control Revenue Bonds, Variable Rate
     Series, due September 1, 2017.  See Note 4, Financial Instruments.

     The Company's First Mortgage Bonds, 5.625% Series of $16 million is
     scheduled to mature June 1, 1996, and the 6.75% Series of $20 million is
     scheduled to mature in 1998.  There are no scheduled maturities of
     Pollution Control Bonds for the five years subsequent to December 31, 1995.
     The Company has no cash sinking fund requirements.

     NOTE 12 - NOTES PAYABLE

     The Company had no notes payable at December 31, 1995, and 1994.



                                     -41-
<PAGE>


     At December 31, 1995, the Company had unused lines of credit of $160
     million, for which it pays commitment fees.  The credit lines are scheduled
     to expire during the year 2000.  Management expects to renegotiate these
     lines when they expire.

     NOTE 13 - COMMITMENTS AND CONTINGENCIES

     CONSTRUCTION PROGRAM.  The Company had commitments in connection with its
     construction program aggregating approximately $11 million at December 31,
     1995.  Construction expenditures for the years 1996 and 1997 are estimated
     to total approximately $220 million.

     FERC ORDER NO. 636.  Prior to the implementation of Order No. 636, the
     Company had purchased natural gas and pipeline transportation services from
     Texas Gas Transmission Corporation (Texas Gas).  The Company now purchases
     only transportation services from Texas Gas and purchases natural gas from
     many other sources under contracts for varying periods of time.  See
     Management's Discussion and Analysis, Future Outlook, under Item 7.

     Under Order No. 636, pipelines may recover costs associated with the
     transition to and implementation of this order from pipeline customers,
     including the Company.  The Commission issued an order, based on
     proceedings that were held to investigate the impact of Order No. 636 on
     utilities and ratepayers in Kentucky, providing that transition costs
     assessed on utilities by the pipelines, which are clearly identifiable as
     being related to the cost of the commodity itself, are appropriate to be
     recovered from customers through the gas supply clause.  During 1995, the
     Company paid Texas Gas and began recovering from its customers
     approximately $4.8 million in transition costs.  It is estimated that about
     $1.4 million in additional transition costs will be incurred by the Company
     during 1996 and about $1.3 million in 1997, and these costs are also
     expected to be recovered from customers.  These transition costs are billed
     by Texas Gas pursuant to orders issued by FERC in transition cost
     regulatory proceedings in which the Company is a party.  Pursuant to these
     FERC orders, no additional transition costs are expected to be billed after
     1997.

     OPERATING LEASE.  The Company has an operating lease for its corporate
     office building that is scheduled to expire in June 2005.  Total expense in
     connection with this lease for 1995, 1994, and 1993 was $2,020,000,
     $2,192,000, and $2,436,000, respectively.  The future minimum annual lease
     payments under the lease agreement for years subsequent to December 31,
     1995, are as follows (in thousands of $):


<TABLE>
           <S>                                              <C>
           1996.............................                $ 2,850
           1997.............................                  2,850
           1998.............................                  2,850
           1999.............................                  2,850
           2000.............................                  3,178
           Thereafter.......................                 15,782
                                                            -------
              Total.........................                $30,360
                                                            -------
                                                            -------
</TABLE>

     ENVIRONMENTAL.  The Clean Air Act Amendments of 1990 (the Act) impose
     stringent limits on emissions of sulfur dioxide and nitrogen oxides by
     electric utility generating plants.  The Company is well-positioned in the
     market to be a "clean" power provider without the large capital
     expenditures that are expected to be incurred by many other utilities.  All
     of the


                                     -42-
<PAGE>


     Company's coal-fired boilers are equipped with sulfur dioxide "scrubbers"
     and already achieve the final sulfur dioxide emission rates required by the
     year 2000 under the legislation.  However, as part of its ongoing capital
     construction program, the Company has spent $22 million to date and, based
     on engineering estimates from contractors, anticipates incurring additional
     capital expenditures of approximately $8 million in 1996 for remedial
     measures necessary to meet the Act's requirements for nitrogen oxides.  The
     overall financial impact of the legislation on the Company is expected to
     be minimal.

     In May 1994, the Company completed extensive modification at its Mill Creek
     plant aimed at controlling certain particulate emissions which have
     allegedly damaged metal surfaces on adjacent properties.  The Air Pollution
     Control District of Jefferson County (APCD) and the Company are currently
     conducting a field sampling program to demonstrate the effectiveness of the
     plant modifications.  In an effort to resolve property damage claims of
     adjacent residents, the Company commenced extensive negotiations and
     property damage settlements with residents who are not parties to any
     pending litigation.  Through December 1995, the Company has settled
     property damage claims filed by residents at an aggregate cost of
     approximately $14.7 million.  In management's opinion, settlement of the
     limited number of these remaining non-litigated claims should not have a
     material adverse impact on the financial position or results of operations
     of the Company.

     In August 1993, 34 persons filed a complaint in Jefferson Circuit Court
     against the Company seeking certification of a class consisting of all
     persons within 2.5 miles of the Mill Creek plant who have allegedly
     suffered personal injury or property damage as a result of emissions from
     the plant.  The plaintiffs sought compensation for personal injury and
     property damage, injunctive relief, a fund to finance future medical
     monitoring of area residents and other relief.  In June 1994, the court
     denied the plaintiffs' motion for certification of the class and thus
     limited the scope of the litigation to the claims of the individual
     plaintiffs.  In August 1995, the court granted the plaintiffs' motion for
     leave to file an amended complaint to bring a total of 537 individual
     plaintiffs into the pending litigation.   The plaintiffs subsequently filed
     a motion to certify a class consisting of all persons within 3.5 miles of
     the plant who have allegedly suffered property damage.  The court has not
     yet ruled on that motion.  In January 1996, the plaintiffs waived all
     claims for compensation for personal injuries, fear of cancer, emotional
     distress, loss of income, injunctive relief, and medical monitoring.  The
     Company stipulated nuisance as to plaintiffs located within 2.5 miles of
     the plant, but reserved the right to assert lack of causation and all
     affirmative defenses including statute of limitations.  The plaintiffs also
     waived claims for punitive damages with respect to all plaintiffs located
     within 2.5 miles.  The plaintiffs are currently pursuing claims solely for
     property damage and annoyance allegedly due to emissions from the plant.
     The Company intends to vigorously defend itself in the pending litigation.

     In response to a notification from the APCD that the Company's Cane Run
     plant may be the source of a potential exceedance of the National Ambient
     Air Quality Standards for sulfur dioxide, the Company submitted a draft
     action plan and modeling schedule to the APCD and the United States
     Environmental Protection Agency (USEPA).  The APCD and USEPA have approved
     the submittals, and a Company contractor is currently conducting additional
     modeling activities.  Although it is expected that corrective action will
     be accomplished through capital improvements, until the modeling activities
     are complete, the Company cannot determine the precise impact of this
     matter.



                                     -43-
<PAGE>


     In March 1994, the APCD adopted a regulation requiring a 15% reduction
     from 1990 volatile organic compound (VOC) emissions from industrial sources
     in an effort to ensure compliance with the National Ambient Air Quality
     Standards for ozone.  There are currently no demonstrated technologies for
     control of VOC emissions from coal-fired boilers.  Consequently, compliance
     with the regulation could require limits on generation at the Mill Creek
     and Cane Run plants, unless the APCD adopts a provision for compliance
     through utilization of banked emission allowances.  The Company is
     currently negotiating with the APCD for an exclusion from the VOC reduction
     requirements.  As an alternative, the APCD is considering additional
     nitrogen oxide reduction requirements for the Company.  The Company cannot
     determine the precise impact of this matter.

     The Company owns or formerly owned three primary sites where manufactured
     gas plant operations were conducted.  Remedial investigations performed at
     the three sites have identified coal tar and other contaminants typical of
     manufactured gas plant operations.  The Company is currently awaiting
     regulatory determinations from the Kentucky Natural Resources and
     Environmental Protection Cabinet on the level of remediation required for
     each site.  Until such regulatory determinations are made, the Company is
     unable to precisely determine cleanup costs for these sites.  However,
     based on the results of studies at the three sites, management currently
     estimates that total cleanup costs will fall within a range of $3 million
     to $12 million and has recorded an accrual of approximately $3 million in
     the accompanying financial statements.

     The Company, along with a number of other companies, has been identified as
     a potentially responsible party (PRP) allegedly liable for cleanup under
     the Comprehensive Environmental Response Compensation and Liability Act as
     amended at four off-site waste treatment or disposal sites.  Under the law,
     each PRP potentially could be held jointly and severally liable for the
     cost of cleanup, but would have the right to seek contribution from other
     PRPs.  The sites targeted for cleanup in which the Company has been
     identified as a PRP include:  the Smith's Farm site located in Bullitt
     County, Kentucky, the Sonora and Carlie Middleton Burn sites located in
     Hardin County, Kentucky, and the M.T. Richards site located in Crossville,
     Illinois.  With respect to the Smith's Farm site, USEPA has identified the
     Company as a de minimis PRP and is currently pursuing other parties for the
     vast majority of the $60 million in cleanup costs as estimated by USEPA.
     The Company is participating in settlement discussions in an effort to
     resolve any alleged liability which it may have.  With respect to the
     Sonora Site and Carlie Middleton Burn Site, the Company is involved in
     litigation with USEPA and approximately 10 companies in an effort to
     resolve liability for approximately $1.8 million in cleanup costs incurred
     by USEPA.  With respect to the M.T. Richards site, the Company has been
     identified as a de minimis party and has reached a tentative settlement for
     $7,500, subject to approval by the government and entry by the court.
     While it is not possible at this time to predict the exact outcome or
     precise impact of these matters, management believes that these matters
     should not have a material adverse impact on the financial position or
     results of operations of the Company.

     NOTE 14 - TRIMBLE COUNTY GENERATING PLANT

     Trimble County Unit 1 (Trimble County), a 495-megawatt coal-fired electric
     generating unit placed into service in December 1990, has been the subject
     of numerous legal and regulatory proceedings to determine the appropriate
     ratemaking treatment to implement the Kentucky


                                     -44-
<PAGE>


     Public Service Commission's 1988 decision that the Company should not be
     allowed to recover 25% of the cost of the Unit from ratepayers.

     On July 19, 1995, the Commission issued an order in which it ruled that the
     Company refund $33.8 million to its electric customers, including interest.
     The Commission stated in its July 19 order that the principal amount to be
     refunded represented 25% of the revenues collected by the Company, during
     the period May 1988 through December 1990, on Trimble County construction
     work in progress (CWIP) included in the Company's rate base in the 1988
     rate case.  The order also required the Company to file a plan for
     implementing the refund.

     On December 1, 1995, the Company and the other parties to the proceedings
     filed with the Commission a unanimous settlement agreement that was
     approved by the Commission on December 8, 1995.  Under the agreement, which
     resolves all outstanding issues, the Company has agreed to refund
     approximately $22 million to current electric customers, the majority of
     which will be paid by credits to customers' bills over five years.  In
     addition, the Company has agreed to pay $900,000 per year for five years to
     the Metro Human Needs Alliance, Inc., a not-for-profit Louisville-based
     corporation, for the sole purpose of funding low-income energy assistance
     programs in the service territory.  The Company also agreed to revise the
     residential decoupling methodology approved by the Commission in 1994 in a
     manner that would reduce revenues collected from residential customers
     during 1996 and 1997 by a total of approximately $1.8 million.  Finally,
     the parties agreed that all appeals currently pending in state courts
     regarding the Commission's orders in the Company's most recent general rate
     case would be dismissed.

     Reference is made to Note 15, Jointly Owned Electric Utility Plant, for a
     discussion of the sale of 25% of Trimble County.

     NOTE 15 - JOINTLY OWNED ELECTRIC UTILITY PLANT

     The Company 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 the Company's
     accounting for other wholly-owned utility plants.

     Of the remaining 25% of the Unit, Illinois Municipal Electric Agency (IMEA)
     purchased a 12.12% undivided interest in the Unit on February 28, 1991, and
     Indiana Municipal Power Agency (IMPA) purchased a 12.88% undivided interest
     on February 1, 1993.  Each is responsible for their proportionate ownership
     share of operation and maintenance expenses and incremental assets, and for
     fuel used.

     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>


                                     -45-
<PAGE>


     NOTE 16 - SEGMENTS OF BUSINESS

     The Company is a regulated public utility engaged in the generation,
     transmission, distribution, and sale of electricity and the storage,
     distribution, and sale of natural gas.

<TABLE>
<CAPTION>
                                                        1995          1994        1993
                                                        ----          ----        ----
                                                               (Thousands of $)
        <S>                                         <C>           <C>         <C>
        Operating Information
          Operating Revenues
           Electric...........................      $  542,337(a) $  558,946  $  570,210
           Gas................................         181,126       200,129     204,915
                                                    ----------    ----------  ----------
             Total............................      $  723,463    $  759,075  $  775,125
                                                    ----------    ----------  ----------
                                                    ----------    ----------  ----------

          Pre-tax Operating Income
           Electric...........................      $  152,199    $  139,594  $  171,016
           Gas................................          16,651        11,368      17,436
                                                    ----------    ----------  ----------
             Total............................      $  168,850    $  150,962  $  188,452
                                                    ----------    ----------  ----------
                                                    ----------    ----------  ----------

        Other Information
          Depreciation and Amortization
           Electric...........................      $   74,437    $   71,882  $   69,753
           Gas................................          11,322        10,637       9,902
           Non-Jurisdictional.................               -             -         232
                                                    ----------    ----------  ----------
             Total............................      $   85,759    $   82,519  $   79,887
                                                    ----------    ----------  ----------
                                                    ----------    ----------  ----------

          Construction Expenditures
           Electric...........................      $   66,661    $   71,592  $   74,165
           Gas................................          26,762        23,806      24,622
                                                    ----------    ----------  ----------
             Total............................      $   93,423    $   95,398  $   98,787
                                                    ----------    ----------  ----------
                                                    ----------    ----------  ----------

        Investment Information-December 31
          Identifiable Assets
           Electric...........................      $1,501,568    $1,514,287  $1,537,387
           Gas................................         268,840       252,946     241,930
                                                    ----------    ----------  ----------
             Total............................       1,770,408     1,767,233   1,779,317
          Other Assets (b)....................         209,082       199,357     195,267
                                                    ----------    ----------  ----------
             Total Assets.....................      $1,979,490    $1,966,590  $1,974,584
                                                    ----------    ----------  ----------
                                                    ----------    ----------  ----------
</TABLE>


        (a) Net of Refund - Trimble County Settlement of $28.3 million.
        (b) Includes cash and temporary cash investments, marketable securities,
            accounts receivable, unamortized debt expense, and other property
            and investments.



                                     -46-
<PAGE>


                               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.

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
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 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, 1995 did not identify any significant deficiencies 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
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.


                                     -47-
<PAGE>


                     REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

TO 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, 1995 and
1994, and the related statements of income, retained earnings and cash flows for
each of the three years in the period ended December 31, 1995.  These financial
statements and the schedule referred to below are the responsibility of the
Company's management.  Our responsibility is to express an opinion on these
financial statements and schedule 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, 1995 and 1994, and the results of its operations and
its cash flows for each of the three years in the period ended December 31,
1995, in conformity with generally accepted accounting principles.

     As discussed in Notes 1 and 7 to the financial statements, effective
January 1, 1993, the Company changed its methods of accounting for income taxes
and post-retirement benefits other than pensions, and effective January 1, 1994,
the Company changed its method of accounting for post-employment benefits.

     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 our audits 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 30, 1996


                   ------------------------------------------


                                     -48-
<PAGE>


                   SELECTED QUARTERLY FINANCIAL DATA (Unaudited)
                                 (Thousands of $)


     Selected financial data for the four quarters of 1995 and 1994 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
                                           -----           ----         ---------       --------
<S>                                       <C>            <C>            <C>            <C>
1995
Operating Revenues..................      $199,517       $167,821       $196,351       $159,774(a)
Net Operating Income................        32,409         30,015         47,774         11,128
Net Income..........................        21,839         21,085         38,346          1,914
Net Income Available for
  Common Stock......................        20,222         19,458         36,780            413


1994
Operating Revenues..................      $219,679       $173,042       $190,117       $176,237
Net Operating Income................         6,603         29,873         45,913         28,651
Net Income (Loss)...................       (16,695)        20,636         35,438         18,941
Net Income (Loss) Available for
  Common Stock......................       (18,073)        19,256         33,935         17,374
</TABLE>

(a)  Net of Refund - Trimble County Settlement of $28.3 million.

                       ----------------------------------

ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.

     None.


                                     -49-
<PAGE>


                                    PART III

     ITEMS 10, 11, 12, AND 13 are omitted pursuant to General Instruction G,
inasmuch as the Company filed copies of a definitive proxy statement with the
Commission on March 13, 1996, pursuant to Regulation 14A under the Securities
Exchange Act of 1934.  Such proxy statement is 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 Louisville Gas and Electric Company (LG&E) is
a subsidiary of LG&E Energy Corp.  At December 31, 1995, LG&E Energy Corp.
controlled 100% of the common stock of LG&E.  There are situations where LG&E
Energy Corp. interacts with its affiliated companies through the use of shared
facilities, common employees, and other business relationships.  In these
situations, LG&E receives payment in accordance with regulatory requirements for
the services provided to affiliated companies.

                                     PART IV

ITEM 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
   (a)  1. Financial Statements (included in Item 8):
             Statements of Income for the three years ended December 31, 1995
              (page 26).
             Statements of Retained Earnings for the three years ended
              December 31, 1995 (page 26).
             Balance Sheets - December 31, 1995, and 1994 (page 27).
             Statements of Cash Flows for the three years ended December 31,
              1995 (page 28).
             Statements of Capitalization - December 31, 1995, and 1994
              (page 29).
             Notes to Financial Statements (pages 30-46).
             Report of Management (page 47).
             Report of Independent Public Accountants (page 48).
             Selected Quarterly Financial Data for 1995 and 1994 (page 49).

        2. Financial Statement Schedule (included in Part IV):
             Schedule II - Valuation and Qualifying Accounts for the three years
                           ended December 31, 1995 (page 66).

     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.


                                     -50-
<PAGE>


3. Exhibits:
   Exhibit
      No.                                 Description
   --------                               -----------

      3.01  Copy of Restated Articles of Incorporation, as amended.  [Filed as
            Exhibit 3.01 to the Company's Annual Report on Form 10-K for the
            year ended December 31, 1993, and incorporated by reference herein]

      3.02  Copy of Amendment to Articles of Incorporation, effective May 25,
            1989.  [Filed as Exhibit 3.02 to the Company's Annual Report on Form
            10-K for the year ended December 31, 1993, and incorporated by
            reference herein]

      3.03  Copy of Amendment to Articles of Incorporation, effective February
            6, 1992.  [Filed as Exhibit 3.03 to the Company's Annual Report on
            Form 10-K for the year ended December 31, 1993, and incorporated by
            reference herein]

      3.04  Copy of Amendment to Articles of Incorporation, effective April 8,
            1993.  [Filed as Exhibit 3.04 to the Company's Annual Report on Form
            10-K for the year ended December 31, 1993, and incorporated by
            reference herein]

      3.05  Copy of Amendment to Articles of Incorporation, effective May 19,
            1993.  [Filed as Exhibit 3.05 to the Company's Form 10-K for the
            year ended December 31, 1993, and incorporated by reference herein]

      3.06  Copy of Bylaws, as amended through December 15, 1995.

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

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

      4.03  Copy of Supplemental Indenture dated February 1, 1954, which is a
            supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit
            4.03 to Registration Statement 2-11923 and incorporated by reference
            herein]


                                     -51-
<PAGE>


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

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

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

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

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

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

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

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

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

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


                                     -52-
<PAGE>



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

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

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

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

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

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

      4.20  Copy of Supplemental Indenture dated March 1, 1982, which is a
            supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit
            4.20 to the Company's Annual Report on Form 10-K for the year ended
            December 31, 1982, and incorporated by reference herein]

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


                                     -53-
<PAGE>


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

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

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

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

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

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

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

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


                                     -54-
<PAGE>


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

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

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

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

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

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

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

     10.01  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 Registration Statement 2-9975 and incorporated by reference
            herein]


                                     -55-
<PAGE>



     10.02  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 Registration Statement
            2-24920 and incorporated by reference herein]

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

     10.04  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 Registration Statement 2-26063 and
            incorporated by reference herein]

     10.05  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 Registration Statement
            2-27316 and incorporated by reference herein]

     10.06  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 5.02(f) to
            Registration Statement 2-61607 and incorporated by reference herein]

     10.07  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 Registration
            Statement 2-26063 and incorporated by reference herein]

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



                                     -56-
<PAGE>


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

     10.10  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 5.02(j) to Registration Statement 2-61607 and
            incorporated by reference herein]

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

     10.12  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 Registration Statement
            2-28524 and incorporated by reference herein]

     10.13  Copy of Modification No. 3, dated November 15, 1967, to the
            Inter-Company Power Agreement dated July 10, 1953.  [Filed as
            Exhibit 4.02(m) to Registration Statement 2-37368 and incorporated
            by reference herein]

     10.14  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 5.02(n) to Registration Statement
            2-56357 and incorporated by reference herein]

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

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


                                     -57-
<PAGE>


     10.17  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 5.02(q) to Registration Statement
            2-61607 and incorporated by  reference herein]

     10.18  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 5.02(r) to Registration Statement
            2-63149 and incorporated by reference herein]

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

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

     10.21  Copy of Modification No. 5, dated September 1, 1979, to the
            Inter-Company Power Agreement dated July 5, 1953, among Ohio Valley
            Electric Corporation and Sponsoring Companies.  [Filed as Exhibit 4
            to the Company's Annual Report on Form 10-K for the year ended
            December 31, 1979, and incorporated by reference herein]

     10.22  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 the Company's Annual Report
            on Form 10-K for the year ended December 31, 1981, and incorporated
            by reference herein]

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

     10.24  Copy of Diversity Power Agreement dated September 9, 1987, between
            East Kentucky Power Cooperative and the Company covering the
            purchase and sale of power between the two companies from 1988
            through 1995.  [Filed as Exhibit 10.28 to the Company's Annual
            Report on Form 10-K for the year ended December 31, 1987, and
            incorporated by reference herein]



                                     -58-
<PAGE>


     10.25  Copy of Supplemental Executive Retirement Plan as amended through
            January 3, 1990, covering all officers of the Company.  [Filed as
            Exhibit 10.29 to the Company's Annual Report on Form 10-K for the
            year ended December 31, 1989, and incorporated by reference herein]

     10.26  Copy of LG&E Energy Corp. Deferred Stock Compensation Plan effective
            January 1, 1992, covering non-employee directors of LG&E Energy
            Corp. and its subsidiaries.  [Filed as Exhibit 10.34 to LG&E Energy
            Corp.'s Annual Report on Form 10-K for the year ended December 31,
            1991, and incorporated by reference herein]

     10.27  Copy of form of change in control agreement for officers of
            Louisville Gas and Electric Company.  [Filed as Exhibit 10.38 to the
            Company's Annual Report on Form 10-K for the year ended December 31,
            1992, and incorporated by reference herein]

     10.28  Copy of Supplemental Executive Retirement Plan for Roger W. Hale,
            effective June 1, 1989.  [Filed as Exhibit 10.40 to the Company's
            Annual Report on Form 10-K for the year ended December 31, 1992, and
            incorporated by reference herein]

     10.29  Copy of Nonqualified Savings Plan covering officers of the Company,
            effective January 1, 1992.  [Filed as Exhibit 10.41 to the Company's
            Annual Report on Form 10-K for the year ended December 31, 1992, and
            incorporated by reference herein]

     10.30  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 the Company's Annual Report
            on Form 10-K for the year ended December 31, 1993, and incorporated
            by reference herein]

     10.31  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 the Company's Annual Report
            on Form 10-K for the year ended December 31, 1993, and incorporated
            by reference herein]

     10.32  Copy of Modification No. 7, dated January 15, 1992, to the
            Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley
            Electric Corporation and Sponsoring Companies.  [Filed as Exhibit
            10.44 to the Company's Annual Report on Form 10-K for the year ended
            December 31, 1993, and incorporated by reference herein]


                                     -59-
<PAGE>


     10.33  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 the Company's Annual Report
            on Form 10-K for the year ended December 31, 1993, and incorporated
            by reference herein]

     10.34  Copy of Firm Transportation Agreement, dated November 1, 1993,
            between Texas Gas Transmission Corporation and the Company covering
            the transmission of natural gas.  [Filed as Exhibit 10.46 to the
            Company's Annual Report on Form 10-K for the year ended December 31,
            1993, and incorporated by reference herein]

     10.35  Copy of Firm No-Notice Transportation Agreement effective November
            1, 1993, between Texas Gas Transmission Corporation and the Company
            (8-year term) covering the transmission of natural gas.  [Filed as
            Exhibit 10.47 to the Company's Annual Report on Form 10-K for the
            year ended December 31, 1993, and incorporated by reference herein]

            Copy of Firm No-Notice Transportation Agreement effective November
            1, 1993, between Texas Gas Transmission Corporation and the Company
            (2-year term) covering the transmission of natural gas.  [Filed as
            Exhibit 10.47 to the Company's Annual Report on Form 10-K for the
            year ended December 31, 1993, and incorporated by reference herein]

            Copy of Firm No-Notice Transportation Agreement effective November
            1, 1993, between Texas Gas Transmission Corporation and the Company
            (5-year term) covering the transmission of natural gas.  [Filed as
            Exhibit 10.47 to the Company's Annual Report on Form 10-K for the
            year ended December 31, 1993, and incorporated by reference herein]

     10.36  Copy of Employment Contract between LG&E Energy Corp. and Roger W.
            Hale effective November 3, 1993.  [Filed as Exhibit 10.50 to LG&E
            Energy Corp.'s Annual Report on Form 10-K for the year ended
            December 31, 1993, and incorporated by reference herein]

     10.37  Copy of LG&E Energy Corp. Stock Option Plan for Non-Employee
            Directors.  [Filed as Exhibit 10.51 to LG&E Energy Corp.'s Annual
            Report on Form 10-K for the year ended December 31, 1993, and
            incorporated by reference herein]


                                     -60-
<PAGE>


     10.38  Copy of Coal Supply Agreement, dated August 9, 1989, between Shawnee
            Coal Company, Roberts Brothers Coal Company, and the Company
            covering the purchase of coal.  [Filed as Exhibit 10.41 to the
            Company's Annual Report on Form 10-K for the year ended December 31,
            1994, and incorporated by reference herein]

     10.39  Copy of Amendment No. 1, dated January 1, 1991, to the Coal Supply
            Agreement, dated August 9, 1989, between Shawnee Coal Company,
            Roberts Brothers Coal Company, and the Company covering the purchase
            of coal.  [Filed as Exhibit 10.42 to the Company's Annual Report on
            Form 10-K for the year ended December 31, 1994, and incorporated by
            reference herein]

     10.40  Copy of Amendment No. 2, dated November 27, 1991, to the Coal Supply
            Agreement, dated August 9, 1989, between Shawnee Coal Company,
            Roberts Brothers Coal Company, and the Company covering the purchase
            of coal.  [Filed as Exhibit 10.43 to the Company's Annual Report on
            Form 10-K for the year ended December 31, 1994, and incorporated by
            reference herein]

     10.41  Copy of Amendment No. 3, dated January 1, 1994, to the Coal Supply
            Agreement, dated August 9, 1989, between Shawnee Coal Company,
            Roberts Brothers Coal Company, and the Company covering the purchase
            of coal.  [Filed as Exhibit 10.44 to the Company's Annual Report on
            Form 10-K for the year ended December 31, 1994, and incorporated by
            reference herein]

     10.42  Copy of Amendment No. 4, dated January 1, 1995, to the Coal Supply
            Agreement, dated August 9, 1989, between Shawnee Coal Company,
            Roberts Brothers Coal Company, and the Company covering the purchase
            of coal.  [Filed as Exhibit 10.45 to the Company's Annual Report on
            Form 10-K for the year ended December 31, 1994, and incorporated by
            reference herein]

     10.43  Copy of Modification No. 8, dated January 19, 1994, to the
            Inter-Company Power Agreement, dated July 10, 1953, among Ohio
            Valley Electric Corporation and the Sponsoring Companies.

     10.44  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 the
            Company covering the transmission of natural gas.


                                     -61-
<PAGE>


     10.45  Copy of Firm Transportation Agreement, dated March 1, 1995, between
            Texas Gas Transmission Corporation and the Company (expires October
            31, 1998) covering the transportation of natural gas.

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

     10.46  Copy of Coal Supply Agreement, dated January 1, 1996, between
            Lafayette Coal Company, Black Beauty Coal Company and the Company
            covering the purchase of coal.

     10.47  Copy of Coal Supply agreement, dated January 1, 1996, between Green
            Coal Company and the Company covering the purchase of coal.

     10.48  Copy of Coal Supply Agreement, dated December 15, 1995, between W.
            B. Coal Company, Inc., Windsor Coal Company and the Company covering
            the purchase of coal.

     10.49  Copy of Coal Supply Agreement dated January 1, 1996, between Peabody
            Coalsales Company and the Company covering the purchase of coal.

     10.50  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 LG&E Energy Corp.'s Annual
            Report on Form 10-K for the year ended December 31, 1995, and
            incorporated by reference herein]

     10.51  Copy of Short-Term Incentive Plan effective January 1, 1996,
            covering officers and key employees of the Company.  [Filed as
            Exhibit 10.53 to LG&E Energy Corp.'s Annual Report on Form 10-K for
            the year ended December 31, 1995, and incorporated by reference
            herein]

     10.52  Copy of form of first amendment to change in control agreement for
            officers of the Company and key employees.  [Filed as Exhibit 10.54
            to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended
            December 31, 1995, and incorporated by reference herein]

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



                                     -62-
<PAGE>


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

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

     10.56  Copy of Amendment to the Supplemental Executive Retirement Plan,
            effective January 1, 1992.  [Filed as Exhibit 10.58 to LG&E Energy
            Corp.'s Annual Report on Form 10-K for the year ended December 31,
            1995, and incorporated by reference herein]

     10.57  Copy of Amendment to the Supplemental Executive Retirement Plan,
            effective January 1, 1993.  [Filed as Exhibit 10.59 to LG&E Energy
            Corp.'s Annual Report on Form 10-K for the year ended December 31,
            1995, and incorporated by reference herein]

     10.58  Copy of Amendment to the Supplemental Executive Retirement Plan,
            effective January 1, 1995.  [Filed as Exhibit 10.60 to LG&E Energy
            Corp.'s Annual Report on Form 10-K for the year ended December 31,
            1995, and incorporated by reference herein]

     10.59  Copy of Amendment to the Supplemental Executive Retirement Plan,
            effective May 1, 1995.  [Filed as Exhibit 10.61 to LG&E Energy
            Corp.'s Annual Report on Form 10-K for the year ended December 31,
            1995, and incorporated by reference herein]

     12     Computation of Ratio of Earnings to Fixed Charges

     23     Consent of Independent Public Accountants

     24     Power of Attorney

     27     Financial Data Schedule

(b)  Executive Compensation Plans and Arrangements:

            Supplemental Executive Retirement Plan as amended through January 3,
            1990, covering all officers of the Company.  [Filed as Exhibit 10.29
            to the Company's Annual Report on Form 10-K for the year ended
            December 31, 1989, and incorporated by reference herein]


                                     -63-
<PAGE>


            LG&E Energy Corp. Deferred Stock Compensation Plan effective January
            1, 1992, covering non-employee directors of LG&E Energy Corp. and
            its subsidiaries.  [Filed as Exhibit 10.34 to LG&E Energy Corp.'s
            Annual Report on Form 10-K for the year ended December 31, 1991, and
            incorporated by reference herein]

            Form of change in control agreement for officers of Louisville Gas
            and Electric Company.  [Filed as Exhibit 10.38 to the Company's
            Annual Report on Form 10-K for the year ended December 31, 1992, and
            incorporated by reference herein]

            Supplemental Executive Retirement Plan for R. W. Hale, effective
            June 1, 1989.  [Filed as Exhibit 10.40 to the Company's Annual
            Report on Form 10-K for the year ended December 31, 1992, and
            incorporated by reference herein]

            Nonqualified Savings Plan covering officers of the Company effective
            January 1, 1992.  [Filed as Exhibit 10.41 to the Company's Annual
            Report on Form 10-K for the year ended December 31, 1992, and
            incorporated by reference herein]

            Employment Contract between LG&E Energy Corp. and Roger W. Hale
            effective November 3, 1993.  [Filed as Exhibit 10.50 to LG&E Energy
            Corp.'s Annual Report on Form 10-K for the year ended December 31,
            1993, and incorporated by reference herein]

            LG&E Energy Corp. Stock Option Plan for Non-Employee Directors.
            [Filed as Exhibit 10.51 to LG&E Energy Corp.'s Annual Report on Form
            10-K for the year ended December 31, 1993, and incorporated by
            reference herein]

            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 LG&E Energy Corp.'s Annual Report on Form
            10-K for the year ended December 31, 1995, and incorporated by
            reference herein]

            Short-Term Incentive Plan effective January 1, 1996, covering
            officers and key employees of the Company.  [Filed as Exhibit 10.53
            to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended
            December 31, 1995, and incorporated by reference herein]

            Form of first amendment to change in control agreement for officers
            of the Company and key employees.  [Filed as Exhibit 10.54 to LG&E
            Energy Corp.'s Annual Report on Form 10-K for the year ended
            December 31, 1995, and incorporated by reference herein]



                                     -64-
<PAGE>


            Amendment to the Non-Qualified Savings Plan, effective January 1,
            1992.  [Filed as Exhibit 10.55 to LG&E Energy Corp.'s Annual Report
            on Form 10-K for the year ended December 31, 1995, and incorporated
            by reference herein]

            Amendment to the Non-Qualified Savings Plan, effective January 1,
            1995.  [Filed as Exhibit 10.56 to LG&E Energy Corp.'s Annual Report
            on Form 10-K for the year ended December 31, 1995, and incorporated
            by reference herein]

            Amendment to the Non-Qualified Savings Plan, effective January 1,
            1995.  [Filed as Exhibit 10.57 to LG&E Energy Corp.'s Annual Report
            on Form 10-K for the year ended December 31, 1995, and incorporated
            by reference herein]

            Amendment to the Supplemental Executive Retirement Plan, effective
            January 1, 1992.  [Filed as Exhibit 10.58 to LG&E Energy Corp.'s
            Annual Report on Form 10-K for the year ended December 31, 1995, and
            incorporated by reference herein]

            Amendment to the Supplemental Executive Retirement Plan, effective
            January 1, 1993.  [Filed as Exhibit 10.59 to LG&E Energy Corp.'s
            Annual Report on Form 10-K for the year ended December 31, 1995, and
            incorporated by reference herein]

            Amendment to the Supplemental Executive Retirement Plan, effective
            January 1, 1995.  [Filed as Exhibit 10.60 to LG&E Energy Corp.'s
            Annual Report on Form 10-K for the year ended December 31, 1995, and
            incorporated by reference herein]

            Amendment to the Supplemental Executive Retirement Plan, effective
            May 1, 1995.  [Filed as Exhibit 10.61 to LG&E Energy Corp.'s Annual
            Report on Form 10-K for the year ended December 31, 1995, and
            incorporated by reference herein]

(c)  Reports on Form 8-K:

            On December 12, 1995, a report on Form 8-K was filed announcing the
      Public Service Commission of Kentucky's approval of the Trimble County
      power plant settlement agreement.


                                     -65-
<PAGE>


                                                                     SCHEDULE II



                        LOUISVILLE GAS AND ELECTRIC COMPANY
                  SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
                    FOR THE THREE YEARS ENDED DECEMBER 31, 1995
                                 (Thousands of $)



<TABLE>
<CAPTION>
                                                                        Reserves Deducted from
                                                                        Assets in Balance Sheet
                                                                   ---------------------------------
                                                                      Other              Accounts
                                                                    Property            Receivable
                                                                       and            (Uncollectible
                                                                   Investments           Accounts)
                                                                   -----------        --------------
<S>                                                                <C>                <C>
Balance January 1, 1993.....................................         $5,645              $1,109

  Additions:
    Charged to costs and expenses
      Trimble County - non-jurisdictional depreciation......            233
      Other.................................................                              2,500
  Deductions:
    Net charges of nature for which reserves were created...
    Other...................................................          5,815               2,135
                                                                     ------              ------

Balance December 31, 1993...................................             63               1,474

  Additions:
    Charged to costs and expenses...........................                              3,100
  Deductions:
    Net charges of nature for which reserves were created...                              3,371
                                                                     ------              ------

Balance December 31, 1994...................................             63               1,203

  Additions:
    Charged to costs and expenses...........................                              3,200
  Deductions:
    Net charges of nature for which reserves were created...                              3,043
                                                                     ------              ------

Balance December 31, 1995...................................         $   63              $1,360
                                                                     ------              ------
                                                                     ------              ------
</TABLE>


                                      -66-
<PAGE>


                                   SIGNATURES

     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 27, 1996                     By  Walter Z. Berger
--------------                         -------------------------------------
   (Date)                                         Walter Z. Berger
                                       Executive Vice President and Chief
                                        Financial Officer

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

     Signature                          Title                  Date
     ---------                          -----                 ------
ROGER W. HALE                   Chairman of the Board and
                                Chief Executive Officer
                                (Principal Executive Officer);

WALTER Z. BERGER                Executive Vice President and
                                Chief Financial Officer
                                (Principal Financial and 
                                Accounting Officer);

WILLIAM C. BALLARD, JR.         Director;

OWSLEY BROWN II                 Director;

S. GORDON DABNEY                Director;

GENE P. GARDNER                 Director;

J. DAVID GRISSOM                Director;

DAVID B. LEWIS                  Director;

ANNE H. MCNAMARA                Director;

T. BALLARD MORTON, JR.          Director; and

DR. DONALD C. SWAIN             Director.


By   Walter Z. Berger                                            March 27, 1996
     -----------------------------------
     WALTER Z. BERGER (Attorney-In-Fact)


                                     -67-