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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, 1994
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, Series due July 1, 2002, 7 1/2% New York Stock
Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
5% Cumulative Preferred Stock, $25 Par Value
7.45% 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. [ ]
As of February 28, 1995, the aggregate market value of the registrant's
voting stock held by non-affiliates was $34,357,392 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 16, 1995, is incorporated by reference into Part III of this
Form 10-K.
PART I PAGE
----
Item 1. Business. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
General. . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Electric Operations. . . . . . . . . . . . . . . . . . . . . . 3
Gas Operations . . . . . . . . . . . . . . . . . . . . . . . . 5
Regulation and Rates . . . . . . . . . . . . . . . . . . . . . 6
Construction Program and Financing . . . . . . . . . . . . . . 7
Coal Supply. . . . . . . . . . . . . . . . . . . . . . . . . . 8
Gas Supply . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Environmental Matters. . . . . . . . . . . . . . . . . . . . . 9
Labor Relations. . . . . . . . . . . . . . . . . . . . . . . . 10
Employees. . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Item 2. Properties. . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . 11
Item 4. Submission of Matters to a Vote of Security Holders . . . . . . . 12
Executive Officers of the Company. . . . . . . . . . . . . . . . . . . . . 13
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters. . . . . . . . . . . . . . . . . . . . . . 15
Item 6. Selected Financial Data . . . . . . . . . . . . . . . . . . . . . 15
Item 7. Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . . . 15
Item 8. Financial Statements and Supplementary Data . . . . . . . . . . . 23
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure . . . . . . . . . . . . . . . . . . . 46
PART III
Item 10. Directors and Executive Officers of the Registrant (a). . . . . . 47
Item 11. Executive Compensation (a). . . . . . . . . . . . . . . . . . . . 47
Item 12. Security Ownership of Certain Beneficial Owners
and Management (a) . . . . . . . . . . . . . . . . . . . . . . 47
Item 13. Certain Relationships and Related Transactions (a). . . . . . . . 47
PART IV
Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K. . . . . . . . . . . . . . . . . . . . 47
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61
Exhibit 12 - Computation of Ratio of Earnings to Fixed Charges . . . . . . 62
Exhibit 23 - Consent of Independent Public Accountants . . . . . . . . . . 63
(a) Incorporated by reference.
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 266,000 customers and electricity to approximately 341,000
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 provides both gas and 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 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 has been subject to numerous reviews by the Public Service Commission
of Kentucky (Kentucky Commission or Commission). In July 1988, the Kentucky
Commission issued an order stating that 25% of the total cost of the Unit would
not be allowed for ratemaking purposes. The Company has sold a 25% ownership
interest in the Unit. For a more detailed discussion of the proceedings
relating to Trimble County Unit 1 and the sale of 25% of the Unit, see Electric
Operations and Notes 11 and 12 of Notes to Financial Statements under Item 8.
The Clean Air Act Amendments of 1990 impose stringent limits on emissions
of sulfur dioxide and nitrogen oxides by electric generating plants. The
Company is closely monitoring the continuing rule-making process in order to
assess the precise impact of the legislation on the Company. 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 capital
construction program, the Company has spent $10 million to date and anticipates
incurring capital expenditures of approximately $29 million through 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
-1-
environmental issues, see Environmental Matters under this Item, Item 3, Item 7,
and Note 10 of the Notes to Financial Statements under Item 8.
Competition among energy suppliers is increasing. In particular,
competition for off-system sales, which is based primarily on price and
availability of energy, has become much more intense in recent years. The
addition of electric generating capacity by other utilities in the Midwest has
reduced the opportunities for the Company to make interchange sales and has
heightened price competition for such sales. However, such additional capacity
has made lower cost power available for purchase by the Company which, in
certain instances, is at a cost lower than the variable cost of generating power
from the generating stations owned by the Company. In addition, the 1992 Energy
Policy Act provides utilities a wider choice of sources for their electrical
supply than previously available. The Act also creates generating supply
options that did not exist under previous legislation and is expected to
increase competition for wholesale electric sales. See Energy Policy Act of
1992 under Item 7 for a further discussion.
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; and a major realignment and formation of new
business units.
Effective January 1, 1994, Energy Corp. realigned its business to reflect
its outlook for rapidly emerging competition in all segments of the energy
services industry. Under the realignment, a national business unit, LG&E Energy
Services was formed to develop and manage all of its utility and non-utility
electric power generation and concentrate on the marketing and brokering of
wholesale electric power on a regional and national basis. The realignment has
allowed the Company to increase its focus on customer service and develop more
customer options as the utility industry becomes more competitive. As part of
the business realignment, a new subsidiary was formed to market power throughout
the United States. LG&E Power Marketing Inc. (LPM), an indirect wholly owned
subsidiary of Energy Corp., was among the first utility-affiliated marketers in
the country to secure Federal Energy Regulatory Commission (FERC) approval to
sell power at market-based rates and engage in wholesale power marketing
activities. The realignment does not affect Energy Corp.'s legal structure,
regulation of the Company by the Kentucky Commission or Energy Corp.'s status as
an exempt holding company.
The Company envisions an open electricity transmission system that
facilitates delivery of competitively priced power to all customers in the
region. Toward that vision, the Company filed tariffs with FERC in 1994 which
would provide transmission service to wholesale customers at rates, terms, and
conditions which are comparable to those which the Company applies to itself.
This comparable transmission service is a key feature of a more competitive
electric utility industry.
As part of its efforts to retain existing customers and expand to new
customers, in 1994 the Company began securing long-term, mutually beneficial
written contracts with key customers. By entering into such agreements, the
Company is assured of a market for its energy and can prudently invest in plant
and equipment upgrades and enhanced delivery services that will benefit
customers and make the utility more competitive. In 1994, the Company also
formalized its economic development strategic plan, integrating many of its
industry-attraction efforts with that of the city of Louisville and other
regional businesses.
-2-
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.
The Company is experiencing some of the issues common to electric and gas
utility companies, namely, increased competition for customers and costs of
compliance with environmental laws and regulations.
For the year ended December 31, 1994, 74% of total operating revenues was
derived from electric operations and 26% from gas operations. Electric and gas
operating revenues and the percentages by classes of service on a combined basis
for this period were as follows:
(Thousands of $)
------------------------------------
Electric Gas Combined % Combined
-------- --- -------- ----------
Residential. . . . . . . . . . . $194,145 $110,553 $304,698 43%
Commercial . . . . . . . . . . . 155,847 40,474 196,321 28
Industrial . . . . . . . . . . . 108,004 27,956 135,960 19
Public authorities . . . . . . . 53,191 12,930 66,121 10
------- ------- ------- ---
Total-ultimate consumers. . . 511,187 191,913 703,100 100%
---
---
Sales for resale . . . . . . . . 42,720 -- 42,720
Gas transportation-net . . . . . -- 6,759 6,759
Miscellaneous. . . . . . . . . . 5,039 1,457 6,496
------- ------- -------
Total . . . . . . . . . . . . $558,946 $200,129 $759,075
------- ------- -------
See Note 13 of Notes to Financial Statements under Item 8 for financial
information concerning segments of business for the three years ended December
31, 1994.
Electric Operations
The sources of electric operating revenues and the volumes of sales for the
three years ended December 31, 1994, were as follows:
1994 1993 1992
---- ---- ----
ELECTRIC OPERATING REVENUES
(Thousands of $):
Residential . . . . . . . . . . . . . $ 194,145 $ 195,273 $ 174,559
Small commercial and industrial . . . 70,916 70,106 66,183
Large commercial. . . . . . . . . . . 84,931 84,231 80,041
Large industrial. . . . . . . . . . . 108,004 104,506 101,699
Public authorities. . . . . . . . . . 53,191 52,183 49,599
-------- ------- -------
Total-ultimate consumers . . . . . 511,187 506,299 472,081
Sales for resale. . . . . . . . . . . 42,720 58,959 45,698
Miscellaneous . . . . . . . . . . . . 5,039 4,952 3,890
-------- -------- --------
Total. . . . . . . . . . . . . . . $ 558,946 $ 570,210 $ 521,669
-------- -------- --------
-------- -------- --------
-3-
1994 1993 1992
---- ---- ----
ELECTRIC SALES (Thousands of kwh):
Residential . . . . . . . . . . . . . . . 3,204,330 3,230,463 2,923,517
Small commercial and industrial . . . . . 1,073,152 1,056,977 1,010,830
Large commercial. . . . . . . . . . . . . 1,729,668 1,696,686 1,624,441
Large industrial. . . . . . . . . . . . . 2,874,411 2,736,269 2,671,212
Public authorities. . . . . . . . . . . . 1,085,741 1,053,928 1,004,911
---------- ---------- ----------
Total-ultimate consumers . . . . . . . 9,967,302 9,774,323 9,234,911
Sales for resale. . . . . . . . . . . . . 2,315,311 3,299,510 3,234,758
---------- ---------- ----------
Total. . . . . . . . . . . . . . . . . 12,282,613 13,073,833 12,469,669
---------- ---------- ----------
---------- ---------- ----------
At December 31, 1994, the Company had 340,810 electric customers.
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 1994 was approximately .84 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 Monday, August 30, 1993, the Company set a record local peak load of
2,239 Mw, when the temperature at the time of peak reached 94 degrees F (average
for the day was 84 degrees F). The 1994 maximum local peak load of 2,219 Mw
occurred on Wednesday, June 15, when the temperature at the time of peak was 95
degrees F (average for the day was 85 degrees 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 28, 1995, the
Company owned steam and combustion turbine generating facilities with a
capacity of 2,613 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 (OVEC) whose primary customer is the Portsmouth
Area uranium-enrichment complex of the U.S. Department of Energy at Piketon,
Ohio. The Company has electric transmission interconnections and/or
interconnection/interchange agreements with PSI Energy, Kentucky Utilities
Company, Southern Indiana Gas and Electric Company, The Cincinnati Gas &
Electric Company, Indiana Michigan Power Company, OVEC, Big Rivers Electric
Corporation, Tennessee Valley Authority, Wabash Valley Power Association,
Indiana Municipal Power Agency, East Kentucky Power Cooperative (East Kentucky),
Illinois Municipal Electric Agency, Jacksonville Electric Authority, and
Ogelthorpe Power Corporation providing for various interchanges, emergency
services, and other working arrangements.
The Company entered into an agreement with East Kentucky to provide about
40 megawatts of electricity to Gallatin Steel Company's (Gallatin) new steel
mill in north central Kentucky. The agreement will continue for 10 years and is
expected to result in approximately $6 million of revenues annually. Gallatin
makes steel for manufacturing plants in Kentucky. The Company will supply the
electricity from its power plants in the Louisville area. This transaction was
negotiated by LPM, an affiliate of the Company, and the terms of the transaction
were approved by the Kentucky Commission.
The Company and East Kentucky had an agreement that allowed East Kentucky
to purchase power during its peak season, and the Company to sell power during
its off-peak season. The
-4-
agreement entitled East Kentucky to buy from the Company up to 145 megawatts
from mid-December to mid-February through 1994-95.
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 $75 million since 1987 in its investigation
and research with regard to possible health effects posed by exposure to
electric and magnetic fields.
Gas Operations
The sources of gas operating revenues and the volumes of sales for the
three years ended December 31, 1994, were as follows:
1994 1993 1992
---- ---- ----
GAS OPERATING REVENUES
(Thousands of $):
Residential . . . . . . . . . . . . . . $ 110,553 $ 112,508 $ 96,175
Commercial. . . . . . . . . . . . . . . 40,474 43,568 36,801
Industrial. . . . . . . . . . . . . . . 27,956 28,310 26,156
Public authorities. . . . . . . . . . . 12,930 13,846 13,884
-------- ------- --------
Total-ultimate consumers. . . . . . . 191,913 198,232 173,016
Gas transportation-net. . . . . . . . . 6,759 5,147 4,169
Miscellaneous . . . . . . . . . . . . . 1,457 1,536 1,341
-------- ------- -------
Total . . . . . . . . . . . . . . . . $ 200,129 $ 204,915 $ 178,526
-------- ------- -------
-------- ------- -------
GAS SALES (Millions of cu. ft.):
Residential . . . . . . . . . . . . . . 22,935 24,330 22,465
Commercial. . . . . . . . . . . . . . . 9,450 10,308 9,527
Industrial. . . . . . . . . . . . . . . 7,505 7,817 8,077
Public authorities. . . . . . . . . . . 3,268 3,515 3,864
------- ------- -------
Total-ultimate consumers. . . . . . . 43,158 45,970 43,933
Gas transported . . . . . . . . . . . . 6,854 5,249 4,155
------- ------- -------
Total . . . . . . . . . . . . . . . . 50,012 51,219 48,088
------- ------- -------
------- ------- -------
At December 31, 1994, the Company had 265,688 gas customers.
The Company has underground natural gas storage fields that help provide
economical and reliable gas service to ultimate consumers.
-5-
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 degrees F.
During 1994, the maximum day gas sendout was 524,000 Mcf, occurring on
January 15, when the average temperature for the day was 2 degrees F. Supply on
that day consisted of 176,000 Mcf from purchases, 314,000 Mcf delivered from
underground storage, and 34,000 Mcf transported for industrial customers. For
further discussion, see Gas Supply.
In 1994, the Company experienced its first full year operating under FERC
Order No. 636. While the Company had previously been able to purchase natural
gas and pipeline transportation services from Texas Gas Transmission Corporation
(Texas Gas), the Company now purchases only transportation services from Texas
Gas pursuant to its FERC-approved tariff and acquires its supply of natural gas
from other sources. For further discussion see Gas Supply and Note 10 of Notes
to Financial Statements under Item 8.
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 11 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.
-6-
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.
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. Under state law, the Commission has until
April 7, 1995, to rule on the application. If the Company's application is
approved as filed, the surcharge will increase electric revenues by
approximately $5.5 million in 1995 and $8.3 million in 1996. The Commission has
previously approved environmental cost recovery surcharges for two other
regulated electric utilities in Kentucky.
A management audit of Louisville Gas and Electric Company, which began in
September 1994, is nearing completion. Vantage Consulting Inc. is conducting
the audit under contract to the Kentucky Commission. Vantage has interviewed
some 300 employees and the Company has made written responses to more than 800
requests for data and documents. The final report is not expected until June.
A similar audit of the Company was conducted in 1986 under a mandate from the
1984 Kentucky General Assembly that requires such audits of the Commonwealth's
10 largest utilities.
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 to meet the future 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.
-7-
At December 31, 1994, the Company's embedded cost of long-term debt was
6.5% and its ratio of earnings to fixed charges was 3.14. See Exhibit 12. For
a further discussion of construction expenditures and financing, see Liquidity
and Capital Resources under Item 7.
During the five years ended December 31, 1994, gross property additions
amounted to $501 million. Internally generated funds for the five year period
were sufficient to provide for all of these gross additions. The gross
additions during this period amounted to approximately 20% of total utility
plant at December 31, 1994, and consisted of $391 million for electric
properties and $110 million for gas properties. Gross retirements during the
same period were $55 million, consisting of $44 million for electric properties
and $11 million for gas properties.
Coal Supply
Approximately 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.
The Company has entered into coal supply agreements with various suppliers
for coal deliveries for 1995 and beyond. The Company normally augments its coal
supply agreements with spot market purchases which, during 1994, 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, 1994, a coal inventory of approximately 580,000 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%-3.5% 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,
whereas deliveries to the Cane Run plant are primarily by rail and also by
truck. Deliveries to the Trimble County plant are by barge only.
The average delivered cost of coal purchased by the Company, per ton and
per million Btu, for the periods shown were as follows:
1994 1993 1992
---- ---- ----
Per ton . . . . . . . . . . . . . . $ 25.27 $ 26.58 $ 25.17
Per million Btu . . . . . . . . . . 1.10 1.14 1.09
-8-
Gas Supply
During 1994, the Company experienced its first full year of operation under
FERC Order No. 636. Although the Company continues to transport natural gas
supplies through Texas Gas at rates and terms regulated by the FERC, the Company
now purchases its supply of natural gas from other sources.
As a result of FERC Order No. 636 and effective November 1, 1993, the
Company entered into new transportation service agreements with Texas Gas.
These agreements provide for 30,000 MMBtu (29,268 Mcf) per day in Firm
Transportation (FT) throughout the year. This FT agreement expires October 31,
1995. During the winter months, the Company also has 184,900 MMBtu (180,390
Mcf) per day in No-Notice Service (NNS); during the summer months that NNS level
is 135,000 MMBtu (131,707 Mcf) per day. The Company's NNS agreements with Texas
Gas incorporate terms of two, five, and eight years, and include unilateral
roll-over provisions at the Company's option. These transportation services are
provided by Texas Gas pursuant to its FERC-approved tariff.
The Company has also entered into a series of long-term firm supply
arrangements with various suppliers in order to meet its firm sales obligations.
The gas supply arrangements include pricing provisions which are
market-responsive. These firm supplies, in tandem with pipeline transportation
services, provide the reliable and flexible supply needed to replace the bundled
sales service supplied by the pipeline prior to the implementation of FERC Order
No. 636.
During 1995, the Company will be participating in several regulatory
proceedings at FERC. In particular, the Company will be involved in reviewing
Texas Gas' most recent rate filing, and Texas Gas' filing to recover certain
transition costs associated with the FERC-mandated implementation of FERC Order
No. 636. As a separate matter, the Kentucky Commission has indicated in an
order issued in its Administrative Case No. 346 that transition costs, which are
clearly identified as being related to the cost of the commodity itself, are
appropriately recoverable as a gas cost through the Company's gas supply clause.
See Note 10 of Notes to Financial Statements under Item 8.
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 1993-1994 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 $2.78
in 1994, $2.91 in 1993, and $2.77 in 1992.
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,
-9-
and waste management laws and regulations. For the five year period ending with
1994, expenditures for pollution control facilities represented $106 million or
21% of total construction expenditures. The cost of operating and maintaining
scrubber-related facilities amounted to $22 million in both 1994 and 1993. The
Company's anticipated capital expenditures for 1995 to comply with environmental
laws are approximately $16 million. See Note 10 of Notes to Financial
Statements under Item 8 for a discussion of specific environmental proceedings
affecting the Company.
Labor Relations
The Company's 1,625 operating, maintenance and construction employees are
members of the International Brotherhood of Electrical Workers (IBEW) Local
2100. The current three-year contract will expire in November 1995.
Employees
The Company had 2,650 full-time employees at December 31, 1994. During the
last quarter of 1993, the Company eliminated a number of full-time positions.
See Note 5 of Notes to Financial Statements under Item 8 for a further
discussion of this matter.
ITEM 2. PROPERTIES.
At February 28, 1995, the Company owned the following electric generating
stations:
Year in
Service Capability Rating (Kw)
Steam Stations:
Mill Creek-Kosmosdale, Ky.
Unit 1. . . . . . . . . . . . . . . . . . 1972 303,000
Unit 2. . . . . . . . . . . . . . . . . . 1974 301,000
Unit 3. . . . . . . . . . . . . . . . . . 1978 386,000
Unit 4. . . . . . . . . . . . . . . . . . 1982 466,000 1,456,000
-------
Cane Run-near Louisville, Ky.
Unit 3 (natural gas only) . . . . . . . . 1958 115,000
Unit 4. . . . . . . . . . . . . . . . . . 1962 155,000
Unit 5. . . . . . . . . . . . . . . . . . 1966 168,000
Unit 6. . . . . . . . . . . . . . . . . . 1969 240,000 678,000
-------
Trimble County-Bedford, Ky.
Unit 1. . . . . . . . . . . . . . . . . . 1990 371,000 (1)
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
------ ---------
2,613,000
---------
---------
(1) Amount shown represents the Company's 75% interest in the Unit.
See Note 12 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.
-10-
The Company's steam stations consist mainly of coal-fired units except for
Cane Run Unit 3 which must use natural gas because of restrictions mandated by
environmental regulations.
The Company also owns an 80 Mw hydroelectric generating station located in
Louisville, operated under license issued by the FERC.
At December 31, 1994, the Company's electric transmission system included
21 substations with a total capacity of approximately 10,623,697 Kva and
approximately 648 structure miles of lines. The electric distribution system
included 83 substations with a total capacity of approximately 3,068,277 Kva,
3,505 structure miles of overhead lines, 233 miles of underground conduit, and
5,335 miles of underground conductors.
The Company's gas transmission system includes 177 miles of transmission
mains, and the gas distribution system includes 3,312 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 June 30, 2005.
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 current status concerning Trimble County Unit 1, see Rates and Regulation
under Item 7 and Notes 2 and 11 of Notes to Financial Statements under Item 8.
Statewide Power Planning
As required by the regulations of the Kentucky Commission, on November 15,
1993, the Company filed its 1993 biennial Integrated Resource Plan with the
Kentucky Commission. The plan, which updates the Company's first Integrated
Resource Plan filed in 1991, proposes to meet customers' future demand through
2007 by adding resources in small increments such as short-term power purchases
(1996-1999), a customer-owned standby generation program (1997), two combustion
turbines (1999-2000), an air conditioner load controls program (1997,
2001-2003), an upgrade to the Company's existing hydroelectric plant (2003), and
a compressed air energy storage plant (2004). The Kentucky Commission staff is
reviewing the Company's plan, and is expected to issue its report
-11-
and recommendations concerning the plan during the first quarter of 1995. The
Kentucky Commission's regulations do not require it to hold any hearings or
issue any formal orders regarding the plan.
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 10 of Notes to Financial Statements
under Item 8.
Other
The Company is a defendant in lawsuits seeking compensatory and, in certain
instances, punitive damages. To the extent that damages are assessed in any of
these lawsuits, the Company believes that its insurance coverage is adequate and
that the effect of any such damages will not be material to the Company's
results of operation or financial position.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None
-----------------------------
-12-
Executive Officers of the Company.
Effective Date of
Election to
Name Age Position Present Position
- ---- --- -------- -----------------
Roger W. Hale 51 Chairman of the Board and
Chief Executive Officer January 1, 1992
Victor A. Staffieri 39 President January 1, 1994
John R. McCall 51 Executive Vice President,
General Counsel and
Corporate Secretary July 1, 1994
David R. Carey 41 Senior Vice President,
Operations January 1, 1994
M. Lee Fowler 58 Vice President and
Controller September 1, 1988
Wendy C. Heck 41 Vice President, Information
Services January 1, 1994
Chris Hermann 47 Vice President and General
Manager, Wholesale
Electric Business January 1, 1993
Rebecca L. Holt 35 Vice President, Gas Service
Business February 15, 1995
Charles A. Markel III 47 Treasurer January 1, 1993
The present term of office of each of the above executive officers extends
to the meeting of the Board of Directors following the Annual Meeting of
Stockholders, scheduled to be held April 25, 1995.
There are no family relationships between executive officers of the
Company.
Mr. Hale, Mr. Carey, 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, 1990: Mr. Hale was President and Chief Executive Officer prior to
February 1990, and Chairman of the Board, President and Chief Executive Officer
thereafter; Mr. Carey was Vice President-Marketing and Sales prior to July 1990,
Vice President-Marketing and Planning prior to January 1992, Vice
President-Marketing and General Manager, Electric Service, prior to
January 1993, and Vice President and General Manager, Retail Electric Business
thereafter; 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 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 and Treasurer prior to
March 1990, 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.
-13-
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. 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, General Manager, Northern
Division-Gas Operations prior to February 1992, and Manager, Columbia Gas
Operations prior to July 1990.
-14-
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:
1994 1993
---- ----
(Thousands of $)
First Quarter. . . . . . . . $17,500 $17,000
Second Quarter . . . . . . . 17,500 16,500
Third Quarter. . . . . . . . - 16,500
Fourth Quarter . . . . . . . 18,000 17,000
ITEM 6. SELECTED FINANCIAL DATA.
Years Ended December 31
(Thousands of $)
------------------------------------------------------------------------------
1994 1993 1992 1991 1990
---- ---- ---- ---- ----
Operating Revenues . . . . . . . . . . $759,075 $775,125 $700,195 $708,706 $698,758
------- ------- ------- ------- -------
Net Operating Income:
Before Non-Recurring Charges. . . . 149,653 136,118 125,829 142,730 137,717
Non-Recurring Charges . . . . . . . 38,613 - - - -
------- ------- ------- ------- -------
Total. . . . . . . . . . . . . . 111,040 136,118 125,829 142,730 137,717
------- ------- ------- ------- -------
Net Income:
Before Non-Recurring Charges, etc.. 94,423 90,535 73,793 94,643 83,450
Non-Recurring Charges,
Charitable Foundation, etc.. . . 32,734 - - - -
Cumulative Effect of
Accounting Change. . . . . . . . (3,369) - - - 18,236
------- ------- ------- ------- -------
Total Net Income . . . . . . . . 58,320 90,535 73,793 94,643 101,686
------- ------- ------- ------- -------
Net Income Available for
Common Stock . . . . . . . . . . . . 52,492 84,554 66,620 85,179 92,221
Total Assets . . . . . . . . . . . . . 1,966,590 1,974,584 1,960,860 1,936,909 1,985,872
Long-Term Obligations (including
amounts due within one year) . . . . 662,800 662,800 686,262 687,662 688,250
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 1994, 1993, and 1992 and should be
read in connection with the financial statements and notes thereto.
-15-
Results of Operations
Net Income Available for Common Stock
In 1994 the Company's net income available for common stock decreased $32.1
million. This decrease was due to the write-off of certain non-recurring items
($23.8 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 discussed above, the
Company's 1994 income would have increased $3.9 million over 1993. This
improvement is primarily due to increased sales of electricity to retail
customers and reduced interest on debt due to favorable refinancing activities
in 1993.
The $17.9 million increase in earnings for 1993 over 1992 resulted
primarily from increased electric sales attributable to warmer summer weather
experienced in 1993, higher sales to other utilities, reduced costs for debt and
preferred stock attributable to favorable refinancing activities, and a gain
recognized on the sale of the remaining disallowed portion of the Trimble County
plant to the Indiana Municipal Power Agency (IMPA). These items were partially
offset by a higher level of operation and maintenance expense.
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.
The Company last filed for a rate increase with the Commission in June 1990
based on the test-year ended April 30, 1990. A final order was issued 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%.
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. Under state law, the Commission has until
April 7, 1995, to rule on the application. If the Company's application is
approved as filed, the surcharge will increase electric revenues by
approximately $5.5 million in 1995 and $8.3 million in 1996. The Commission has
previously approved environmental cost recovery surcharges for two other
regulated electric utilities in Kentucky.
On January 1, 1994, the Company implemented a Commission approved demand
side management (DSM) program that the Company, the Kentucky Attorney General,
the Jefferson County Attorney, and representatives of several customer-interest
groups had filed with the Commission.
-16-
Under the agreement, the Company will commit 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.
Future programs will be developed through a formal collaborative process. The
agreement contains a rate mechanism that will (1) provide the Company concurrent
recovery of DSM program costs, (2) provide the Company an incentive for
implementing DSM programs, and (3) allow the Company to recover revenues due to
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 factor
in residential revenue per customer. Decoupling, in effect, removes the impact
on the Company's non-fuel revenues from changes in kilowatt-hour or Mcf sales
due to weather, fluctuations in the economy, and conservation efforts. Under
this mechanism, if actual sales produce lower revenues than are produced by the
predetermined per-customer amount, the difference is deferred for recovery from
customers through an adjustment in rates over a period that will not exceed two
years. Conversely, if actual sales produce more revenues than would be realized
using the predetermined per-customer amount, the difference will be returned to
customers through subsequent rate adjustments over a period not to exceed two
years. 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.
As more fully discussed in Note 11 of Notes to Financial Statements under
Item 8, the Commission has scheduled a formal hearing on May 9, 1995, to
determine the appropriate ratemaking treatment to exclude 25% of the Trimble
County plant from customer rates. The Company is unable to predict the outcome
of the Commission proceedings, or the amount of additional refunds or
recoveries, if any, that may be ordered.
On May 24, 1993, the Federal Energy Regulatory Commission (FERC) gave final
approval for a market-based rate tariff and two transmission service tariffs
that were filed by the Company. This market-based tariff enables the Company to
sell up to 75 Mw of firm generation capacity at market-based rates. It also
enables the Company to sell an unlimited amount of non-firm power at market-
based rates, as long as the power is from the Company's own generation
resources. In 1994, the Company made its first power sales under its
market-based tariff.
Although the Company has both firm and non-firm open access transmission
rate schedules which were approved by FERC in 1994, the Company took the
additional steps of filing a new network transmission service and a new flexible
point-to-point transmission service to provide transmission service to other
parties comparable to the transmission service the Company provides itself.
-17-
The Company is currently undergoing a planned management and operations
audit initiated by the Kentucky Commission. The audit results will include an
evaluation of the Company's operations and identify opportunities for
improvements. An audit report is scheduled to be issued by mid-1995.
Revenues
A comparison of operating revenues for the years 1994 and 1993 with the
immediately preceding years reflects both increases and decreases, which have
been segregated by the following principal causes (in thousands of $):
Increase (Decrease) From Prior Period
--------------------------------------------------------------
Electric Revenues Gas Revenues
------------------------- ------------------------
Cause 1994 1993 1994 1993
----- ---- ---- ---- ----
Sales to Ultimate Consumers:
Fuel and gas supply adjustments, etc. . . $ (841) $ 6,832 $ 1,823 $19,479
Demand side management/decoupling . . . . 1,853 - 3,997 -
Variation in sales volumes. . . . . . . . 3,876 27,386 (12,139) 5,737
------- ------ ------- ------
Total. . . . . . . . . . . . . . . . . 4,888 34,218 (6,319) 25,216
Sales for resale . . . . . . . . . . . . . . . (16,239) 13,261 - -
Gas transportation-net . . . . . . . . . . . . - - 1,612 978
Other. . . . . . . . . . . . . . . . . . . . . 87 1,062 (79) 195
------- ------ ------- ------
Total. . . . . . . . . . . . . . . . . $(11,264) $48,541 $ (4,786) $26,389
------- ------ ------- ------
------- ------ ------- ------
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.
Electric revenues increased in 1993 primarily because of the warmer summer
weather. Sales of electricity for resale increased over 1992 levels due to the
Company's aggressive efforts in marketing off-system sales of energy. The
increase in gas sales for 1993 is largely attributable to cooler winter weather
in the region and customer growth.
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 $5.8 million (4%) in 1994 primarily because of a
decrease in the cost of coal burned ($3.9 million) and decreased generation of
3%. Fuel expenses for 1993 increased $13.8 million over 1992 because of
increased generation. The average delivered cost per ton of coal purchased was
$25.27 in 1994, $26.58 in 1993, and $25.17 in 1992.
Power purchased decreased $7.5 million in 1994 primarily because less power
was wheeled for other utilities as a result of milder weather in the region.
The increase of $5.2 million in 1993 was largely attributable to more power
purchased because of wheeling arrangements with other utilities.
-18-
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).
Gas supply expenses for 1993 increased $23.5 million primarily because of an
increase in net gas supply cost ($17.6 million) and a 5% increase in the volume
of gas delivered to the distribution system. The average unit cost per Mcf of
purchased gas was $2.78 in 1994, $2.91 in 1993, and $2.77 in 1992.
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. In 1993, operation expenses increased $6 million (5%) over
1992 primarily because of increased costs of electric generating plants ($2
million), and an increase in various administrative expenses ($4.2 million).
The 1993 maintenance expenses increased $1.5 million (3%), primarily due to
increased repairs at the electric generating plants.
Non-recurring charges 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 Notes 2 and 3 of Notes to Financial Statements under
Item 8.
Depreciation and amortization increased in both 1994 and 1993 because of
additional depreciable plant in service.
Variations in income tax expenses are largely attributable to changes in
pre-tax income and an increase in the corporate Federal income tax rate from 34%
to 35%, effective January 1, 1993.
Other income and (deductions) increased $.5 million in 1994 partially due
to recognition of a gain on the sale of construction equipment. Other income
and (deductions) increased in 1993 primarily because of a $3.2 million after-tax
gain recorded on the sale of a 12.88% ownership interest in the Trimble County
plant to IMPA. See Note 7 of Notes to Financial Statements under Item 8 for
further detail.
Contribution to the charitable foundation reflects the expense associated
with establishing a tax-exempt foundation during 1994. Contributions made from
this Foundation will not be charged against income, and therefore, will not
affect the Company's net income in the future. See Note 3 of Notes to Financial
Statements under Item 8.
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. Interest charges also decreased in 1993 as
compared to 1992 primarily because of this refinancing program. Since 1992, an
immaterial component of interest expense has been the cost associated with
interest rate swaps. See Liquidity and Capital Resources.
Preferred dividends reflect the lower dividends that resulted from the
Company's refunding its $25 million, $8.90 Series with a $5.875 Series in May
1993.
-19-
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.
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.
1994 Capital Requirements
New construction expenditures for 1994 were $95 million compared with $99
million for 1993 and $101 million for 1992.
Past Financing Activities
During 1994, 1993, and 1992, 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
1994 and 1993 and 87% of utility capital expenditures in 1992. 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 1994, accounts
receivable and accounts payable were lower due to warmer weather in the last
quarter of the year as compared to 1993.
In 1993, the Company refinanced approximately $205 million of its long-term
debt and $25 million of its preferred stock. These refinancings produced
significant savings from lower interest rates and preferred dividend rates in
1994 and 1993. See Note 8 of Notes to Financial Statements under Item 8.
The Company's liquidity was also positively affected in 1993 by the sale of
a 12.88% portion of the Company's Trimble County Generating Unit. At
December 31, 1994, marketable securities classified as Other Property and
Investments amounted to $50 million. See Note 4 of Notes to Financial
Statements under Item 8.
The Company has outstanding interest rate swap agreements with a notional
amount of $30 million. These swaps were entered into as a standard hedging
device in connection with the 1992 issuance of the Company's Pollution Control
Bonds Series S, due September 1, 2017. The swaps are designed to reduce the
Company's exposure to interest rate risk. Under the agreements, the Company
pays a fixed rate of 4.35% on $15 million for a five-year period and 4.74% on
$15 million for a seven-year period resulting in interest payments based on a
composite rate of 4.55% in 1994, 1993, and 1992. In return, the Company
receives a floating rate based on the weighted average JJ Kenny index. The
Company received interest at composite rates of 2.84%, 2.38%, and 2.73% in 1994,
1993, and 1992, respectively.
-20-
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 $200 million for 1995 and 1996. In addition, expected 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 1995 and 1996.
At December 31, 1994, the Company had unused lines of credit of $145
million for which it pays commitment fees. These credit facilities are
scheduled to expire at various periods during 1995 and 1996 and management
intends to renegotiate them when they expire.
To the extent permanent financings are needed in 1995 and 1996, 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 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 $10 million to date and anticipates
incurring capital expenditures of approximately $29 million through 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 10 of Notes to Financial Statements,
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
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. The Company plans to
aggressively pursue opportunities created by a more competitive electric power
market.
-21-
FERC Order No. 636
In 1994, the Company experienced its first full year of operations under
the provisions of Order No. 636. During 1994, the Company paid and began
recovering from its customers approximately $2.8 million in transition costs
under Order No. 636. It is estimated that $6 million to $8 million in
additional transition costs will be incurred by the Company during 1995, and
these costs are also expected to be recovered from customers. See FERC Order
No. 636 in Note 10 of Notes to Financial Statements under Item 8 for further
discussion.
FUTURE OUTLOOK
Business Realignment
Effective January 1, 1994, LG&E Energy Corp. realigned its business to
reflect its outlook for rapidly emerging competition in all segments of the
energy services industry. Under the realignment, a national business unit, LG&E
Energy Services was formed to develop and manage all of its utility and
non-utility electric power generation and concentrate on the marketing and
brokering of wholesale electric power on a regional and national basis.
Louisville Gas and Electric Company, LG&E Energy Corp.'s principal subsidiary,
will increase its focus on customer service and develop more customer options as
the utility industry becomes more competitive.
As part of the business realignment, a new subsidiary was formed to market
power throughout the United States. LG&E Power Marketing Inc. (LPM), an
indirect wholly owned subsidiary of LG&E Energy Corp., 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.
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.
Gallatin Steel Company
The Company entered into an agreement with East Kentucky Power Cooperative,
Inc. to provide about 40 megawatts of electricity to Gallatin Steel Company's
(Gallatin) new steel mill in north central Kentucky. The agreement will
continue for 10 years and is expected to result in approximately $6 million of
revenues annually. Gallatin makes steel for manufacturing plants in Kentucky.
The Company will supply the electricity from its power plants in the Louisville
area. This transaction was negotiated by LPM, and the terms of the transaction
were approved by the Commission.
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; and a major realignment and formation of new
business units.
-22-
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
LOUISVILLE GAS AND ELECTRIC COMPANY
STATEMENTS OF INCOME
(Thousands of $)
Years Ended December 31
------------------------------------------------------
1994 1993 1992
---- ---- ----
Operating Revenues
Electric . . . . . . . . . . . . . . . . . . . . . . . $ 558,946 $ 570,210 $ 521,669
Gas. . . . . . . . . . . . . . . . . . . . . . . . . . 200,129 204,915 178,526
------- ------- -------
Total operating revenues (Note 1). . . . . . . . . . 759,075 775,125 700,195
------- ------- -------
Operating Expenses
Fuel for electric generation . . . . . . . . . . . . . 143,602 149,436 132,551
Power purchased. . . . . . . . . . . . . . . . . . . . 9,754 17,228 12,044
Gas supply expenses. . . . . . . . . . . . . . . . . . 131,561 139,054 115,521
Other operation expenses . . . . . . . . . . . . . . . 136,214 136,693 130,740
Maintenance. . . . . . . . . . . . . . . . . . . . . . 48,731 48,414 46,931
Non-recurring charges (Note 3) . . . . . . . . . . . . 38,613 - -
Depreciation and amortization. . . . . . . . . . . . . 82,519 79,655 76,903
Federal and State income taxes (Note 6). . . . . . . . 39,922 52,334 43,840
Property and other taxes . . . . . . . . . . . . . . . 17,119 16,193 15,836
------ ------ ------
Total operating expenses . . . . . . . . . . . . . . 648,035 639,007 574,366
------- ------- -------
Net Operating Income . . . . . . . . . . . . . . . . . . 111,040 136,118 125,829
Other Income and (Deductions) (Note 7) . . . . . . . . . 2,451 1,913 (2,203)
Contribution to Charitable Foundation - net (Note 3) . . 8,946 - -
Interest Charges . . . . . . . . . . . . . . . . . . . . 42,856 47,496 49,833
------ ------ ------
Income before Cumulative Effect of a Change in
Accounting Principle . . . . . . . . . . . . . . . . . 61,689 90,535 73,793
Cumulative Effect of a Change in Accounting for
Post-Employment Benefits, net of income taxes
of $2,280 (Note 5) . . . . . . . . . . . . . . . . . . (3,369) - -
------ ------ ------
Net Income . . . . . . . . . . . . . . . . . . . . . . . 58,320 90,535 73,793
Preferred Stock Dividends. . . . . . . . . . . . . . . . 5,828 5,981 7,173
------ ------ ------
Net Income Available for Common Stock. . . . . . . . . . $ 52,492 $ 84,554 $ 66,620
------ ------ ------
------ ------ ------
STATEMENTS OF RETAINED EARNINGS
(Thousands of $)
Years Ended December 31
-----------------------------------------------------
1994 1993 1992
---- ---- ----
Balance January 1. . . . . . . . . . . . . . . . . . . . $ 194,903 $ 178,667 $ 181,694
Add net income . . . . . . . . . . . . . . . . . . . . . 58,320 90,535 73,793
------- ------- -------
253,223 269,202 255,487
------- ------- -------
Deduct: Cash dividends declared on stock:
5% cumulative preferred . . . . . . . . . . . . 1,075 1,075 1,076
7.45% cumulative preferred. . . . . . . . . . . 1,598 1,598 1,598
$8.72 cumulative preferred. . . . . . . . . . . - - 454
$8.90 cumulative preferred. . . . . . . . . . . - 1,113 2,225
$9.54 cumulative preferred. . . . . . . . . . . - - 497
Auction rate cumulative preferred . . . . . . . 1,686 1,322 1,323
$5.875 cumulative preferred . . . . . . . . . . 1,469 873 -
Common. . . . . . . . . . . . . . . . . . . . . 53,500 67,500 67,500
Preferred stock redemption expense. . . . . . . . - 818 2,147
------- ------- -------
59,328 74,299 76,820
------- ------- -------
Balance December 31. . . . . . . . . . . . . . . . . . . $ 193,895 $ 194,903 $ 178,667
------- ------- -------
------- ------- -------
The accompanying notes are an integral part of these financial statements.
-23-
LOUISVILLE GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Thousands of $)
ASSETS
December 31
----------------------------------------
1994 1993
---- ----
Utility Plant, at original cost
Electric . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,084,334 $ 2,019,139
Gas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 280,877 260,485
Common . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 137,662 132,692
--------- ---------
2,502,873 2,412,316
Less: Reserve for depreciation. . . . . . . . . . . . . . . . . . 881,861 823,141
--------- ---------
1,621,012 1,589,175
Construction work in progress. . . . . . . . . . . . . . . . . . . 35,022 51,785
--------- ---------
1,656,034 1,640,960
--------- ---------
Other Property and Investments - less reserve (Note 4) 50,681 22,067
--------- ---------
Current Assets
Cash and temporary cash investments. . . . . . . . . . . . . . . . 39,138 44,105
Accounts receivable - less reserve of
$1,203 in 1994 and $1,474 in 1993. . . . . . . . . . . . . . . . 86,058 104,397
Materials and supplies - at average cost
Fuel (predominantly coal). . . . . . . . . . . . . . . . . . . . 13,869 12,075
Gas stored underground . . . . . . . . . . . . . . . . . . . . . 31,354 33,370
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37,299 40,357
Prepayments. . . . . . . . . . . . . . . . . . . . . . . . . . . . 253 360
--------- ---------
207,971 234,664
--------- ---------
Deferred Debits and Other Assets
Unamortized debt expense . . . . . . . . . . . . . . . . . . . . . 7,776 8,076
Regulatory assets (Note 2) . . . . . . . . . . . . . . . . . . . . 31,726 61,642
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12,402 7,175
--------- ---------
51,904 76,893
--------- ---------
$ 1,966,590 $ 1,974,584
--------- ---------
--------- ---------
CAPITAL AND LIABILITIES
Capitalization (see Statements of Capitalization)
Common equity. . . . . . . . . . . . . . . . . . . . . . . . . . . $ 616,478 $ 619,237
Cumulative preferred stock . . . . . . . . . . . . . . . . . . . . 116,716 116,716
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . 662,862 662,879
--------- ---------
1,396,056 1,398,832
--------- ---------
Current Liabilities
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . 70,770 93,551
Dividends declared . . . . . . . . . . . . . . . . . . . . . . . . 19,567 18,878
Accrued taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . 8,247 9,494
Accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . 13,394 12,864
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,277 11,127
--------- ---------
122,255 145,914
--------- ---------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes (Notes 1 and 6). . . . . . . . . 275,814 281,560
Investment tax credit, in process of amortization. . . . . . . . . 88,779 91,572
Accumulated provision for pensions and related benefits. . . . . . 49,104 31,536
Customers' advances for construction . . . . . . . . . . . . . . . 8,621 7,384
Regulatory liability (Note 2). . . . . . . . . . . . . . . . . . . 8,914 6,876
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17,047 10,910
--------- ---------
448,279 429,838
--------- ---------
Commitments and Contingencies (Notes 10 and 11)
$ 1,966,590 $ 1,974,584
--------- ---------
--------- ---------
The accompanying notes are an integral part of these financial statements.
-24-
LOUISVILLE GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(Thousands of $)
Years Ended December 31
------------------------------------------
1994 1993 1992
---- ---- ----
Cash Flows from Operating Activities
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 58,320 $ 90,535 $ 73,793
Items not requiring cash currently:
Cumulative effect of change in accounting principle. . . . . . . . . 3,369 - -
Non-recurring charges. . . . . . . . . . . . . . . . . . . . . . . . 38,613 - -
Depreciation and amortization. . . . . . . . . . . . . . . . . . . . 82,519 79,887 79,686
Deferred income taxes - net. . . . . . . . . . . . . . . . . . . . . (2,274) 4,938 28,911
Investment tax credit - net. . . . . . . . . . . . . . . . . . . . . (4,619) (7,821) (5,033)
Gain on sale of capital asset. . . . . . . . . . . . . . . . . . . . - (3,869) -
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,603 5,877 3,768
(Increase) decrease in certain net current assets:
Accounts receivable. . . . . . . . . . . . . . . . . . . . . . . . . 18,339 (11,678) (7,494)
Materials and supplies . . . . . . . . . . . . . . . . . . . . . . . 3,280 10,671 (8,014)
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . (22,781) 21,099 4,546
Accrued taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,247) 2,343 1,967
Accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . . 530 757 (1,716)
Prepayments and other. . . . . . . . . . . . . . . . . . . . . . . . (743) (260) 538
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 972 (15,587) (11,321)
------- ------- -------
Net cash provided from operating activities. . . . . . . . . . . . . 180,881 176,892 159,631
------- ------- -------
Cash Flows from Investing Activities
Sale of capital asset. . . . . . . . . . . . . . . . . . . . . . . . . - 91,076 -
Purchase of securities . . . . . . . . . . . . . . . . . . . . . . . . (87,896) (38,398) (26,677)
Proceeds from sales of securities. . . . . . . . . . . . . . . . . . . 56,085 27,301 16,236
Construction expenditures. . . . . . . . . . . . . . . . . . . . . . . (95,398) (98,787) (101,175)
-------- ------- -------
Net cash used for investing activities . . . . . . . . . . . . . . . (127,209) (18,808) (111,616)
-------- ------- -------
Cash Flows from Financing Activities
Issuance of preferred stock. . . . . . . . . . . . . . . . . . . . . . - 24,716 49,099
Issuance of first mortgage bonds and pollution control bonds . . . . . - 198,918 88,462
Redemption of preferred stock. . . . . . . . . . . . . . . . . . . . . - (25,558) (51,443)
Retirement of first mortgage bonds and pollution control bonds . . . . - (231,876) (92,400)
Repayment of short-term borrowings . . . . . . . . . . . . . . . . . . - (8,000) (4,000)
Payment of dividends . . . . . . . . . . . . . . . . . . . . . . . . . (58,639) (73,125) (74,517)
------- ------- --------
Net cash used for financing activities . . . . . . . . . . . . . . . (58,639) (114,925) (84,799)
------ ------- ------
Net (Decrease) Increase in Cash and Temporary Cash Investments . . . . . (4,967) 43,159 (36,784)
Cash and Temporary Cash Investments at Beginning of Year . . . . . . . . 44,105 946 37,730
------ ------ ------
Cash and Temporary Cash Investments at End of Year . . . . . . . . . . . $ 39,138 $ 44,105 $ 946
------ ------- -------
------ ------- -------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year for:
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 42,803 $ 54,686 $ 19,741
Interest on borrowed money . . . . . . . . . . . . . . . . . . . . . 40,827 45,360 50,508
The accompanying notes are an integral part of these financial statements.
-25-
LOUISVILLE GAS AND ELECTRIC COMPANY
STATEMENTS OF CAPITALIZATION
(Thousands of $)
December 31
------------------------------------------
1994 1993
---- ----
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 $1,434 (Note 4) . . . . . . . . . . . . . . . . . . . . . . . . (1,751) -
Retained earnings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 193,895 194,903
-------- --------
$ 616,478 $ 619,237
-------- --------
Cumulative Preferred Stock
Redeemable on 30 days notice by the Company
except, $5.875 series
Shares Current
Outstanding Redemption Price
----------- ----------------
$25 par value, 1,720,000 shares authorized -
5% series. . . . . . . . . . . . . . 860,287 $ 28.00 $ 21,507 $ 21,507
7.45% series . . . . . . . . . . . . 858,128 25.75 21,453 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. . . . . . . . . . . . . . . . . . . . . . . . . . . (1,244) (1,244)
--------- ---------
$ 116,716 $ 116,716
--------- ---------
Long-Term Debt (Note 8)
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 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
-------- --------
Total bonds outstanding. . . . . . . . . . . . . . . . . . . . . . . . . 662,800 662,800
Unamortized premium on bonds . . . . . . . . . . . . . . . . . . . . . . . 62 79
-------- --------
$ 662,862 $ 662,879
-------- --------
Total Capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,396,056 $ 1,398,832
--------- ---------
--------- ---------
The accompanying notes are an integral part of these financial statements.
-26-
LOUISVILLE GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Louisville Gas and Electric Company (the Company) completed a corporate
restructuring on August 17, 1990, pursuant to which the Company became 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. LG&E Energy Corp. is an exempt energy services holding company with
wholly owned subsidiaries consisting of the Company and LG&E Energy Systems
Inc., a non-regulated subsidiary. All of the Company's Common Stock is
held by LG&E Energy Corp.
Certain reclassifications have been made to the 1993 and 1992 financial
statements to conform with the 1994 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 1994 were 3.3% (3.2% electric, 3.3% gas, and 5% common); for 1993 3.3%
(3.2% electric, 3.2% gas, and 5% common); and for 1992, 3.3% (3.2%
electric, 3.2% gas, and 5.4% 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.
DEFERRED INCOME TAXES. Deferred income taxes have been provided for all
book-tax temporary differences.
-27-
The Company adopted Statement of Financial Accounting Standards No. 109,
ACCOUNTING FOR INCOME TAXES (SFAS No. 109), effective 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.
INTEREST RATE CONTRACTS. Interest rate swaps are used by the Company to
convert variable rate debt to a fixed rate. The cost or benefit of the
interest rate swaps is recorded as a component of interest expense.
REVENUES AND CUSTOMER RECEIVABLES. The Company is an operating public
utility that supplies natural gas to approximately 266,000 customers and
electricity to approximately 341,000 customers in Louisville and adjacent
areas in Kentucky. Customer receivables and gas and electric revenues
arise from deliveries of natural gas and electric energy to a diversified
base of residential, commercial and industrial customers and to public
authorities and other utilities. For the year ended December 31, 1994, 74%
of total operating revenue was derived from electric operations and 26%
from gas 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).
-28-
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 $):
1994 1993
---- ----
Unamortized loss on bonds . . . . . . . $15,704 $16,622
Unamortized extraordinary retirements . 9,752 12,540
Post-retirement benefits. . . . . . . . - 1,200
Early retirement/workforce reduction. . - 17,617
Property damage settlements . . . . . . - 9,817
Manufactured gas sites. . . . . . . . . 3,149 926
Other . . . . . . . . . . . . . . . . . 3,121 2,920
Deferred income taxes - net . . . . . . (8,914) (6,876)
------ ------
Regulatory assets and liabilities - net $22,812 $54,766
------ ------
------ ------
As of December 31, 1994, approximately $15 million of the Company's net
regulatory assets are being recovered through rates charged to customers
over periods ranging from three to 22 years. The Company expects to obtain
recovery of the remaining regulatory assets in its next general rate case.
For additional information regarding post-retirement benefits and early
retirement/workforce reduction costs, deferred income taxes, and
environmental costs, see Notes 5, 6, and 10, respectively. In early 1994,
the Company, based on a re-evaluation of its regulatory strategy, wrote off
certain regulatory assets included in the 1993 balance sheet. See Note 3,
Non-Recurring Charges, for a further discussion.
In October 1994, the Company filed an application with the Kentucky
Commission to implement an environmental cost recovery surcharge. The
surcharge will allow the Company to recover certain costs incurred to
comply with federal, state, and local environmental requirements. If
approved by the Commission, the surcharge will take effect in May 1995.
See Management's Discussion and Analysis, Rates and Regulation, under
Item 7 for a further discussion.
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
-29-
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)
which will make 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 - MARKETABLE SECURITIES AND OTHER FINANCIAL INSTRUMENTS
MARKETABLE SECURITIES. The Company adopted the provisions of Statement of
Financial Accounting Standards No. 115, ACCOUNTING FOR CERTAIN INVESTMENTS
IN DEBT AND EQUITY SECURITIES, effective 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
December 31, 1994, balance sheet. 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 were $56,085,000,
which resulted in realized gains of $1,557,000 and losses of $1,538,000,
calculated using the specific identification method. The difference
between amortized and unamortized cost basis of the Company's investments
in marketable securities as of December 31, 1994, was 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, 1994, follows (in thousands of $):
Fixed
Equity Income Total
------ ------ -----
Cost. . . . . . . . . . . . . . . . . . . . . . . . . . . $23,622 $29,701 $53,323
Unrealized gains. . . . . . . . . . . . . . . . . . . . . 41 - 41
Unrealized losses . . . . . . . . . . . . . . . . . . . . (2,399) (827) (3,226)
------ ------ ------
Fair values . . . . . . . . . . . . . . . . . . . . . . . $21,264 $28,874 $50,138
------ ------ ------
------ ------ ------
- ---------------------------------------------------------------------------------------------------------------------
Fair Values:
No maturity . . . . . . . . . . . . . . . . . . . . . . $20,415 $ - $20,415
Contractual maturities:
Less than one year. . . . . . . . . . . . . . . . . . 849 2,519 3,368
One to five years . . . . . . . . . . . . . . . . . . - 16,968 16,968
Five to ten years . . . . . . . . . . . . . . . . . . - 1,958 1,958
Over ten years. . . . . . . . . . . . . . . . . . . . - 3,381 3,381
Not due at a single maturity date . . . . . . . . . . - 4,048 4,048
------ ------ ------
Total fair values . . . . . . . . . . . . . . . . . . . $21,264 $28,874 $50,138
------- ------ ------
------- ------ ------
-30-
The Company's available-for-sale securities above include approximately $.6
million market value ($18.5 million notional amount) of short futures on
U.S. Treasury Notes and Bonds maturing March 1995. The Company uses such
instruments to hedge a major portion of its preferred equity portfolio to
substantially reduce price volatility of the securities due to interest
rate changes. The Company does not maintain any margin accounts relative
to its investment positions.
The Company's available-for-sale securities are classified as Other
Property and Investments in the accompanying 1994 balance sheet.
FINANCIAL INSTRUMENTS. Pursuant to Statement of Financial Accounting
Standards No. 107, DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS,
the Company is required to disclose the fair value of financial instruments
where practicable. The disclosure of such information does not purport to
be a market valuation of the Company as a whole. The carrying amounts of
cash, accounts receivable, notes payable, 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 interest rate swaps is based
on the quoted market price as provided by the financial institution which
is the counterparty to the swap.
The cost and estimated fair value of the Company's financial instruments as
of December 31, 1994 and 1993, are as follows (in thousands of $):
1994 1993
--------------------- --------------------
Fair Fair
Cost Value Cost Value
---- ----- ---- -----
Long-term investments:
Practicable to estimate fair value. . . . . . . . . . $53,323 $50,138 $21,186 $21,538
Not practicable . . . . . . . . . . . . . . . . . . . 490 490 490 490
Preferred stock subject to mandatory redemption . . . . 25,000 22,125 25,000 24,750
Long-term debt. . . . . . . . . . . . . . . . . . . . . 662,800 648,697 662,800 706,078
Interest rate swaps . . . . . . . . . . . . . . . . . . - 965 - (896)
NOTE 5 - 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 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.
-31-
In addition, the Company 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 above.
Pension costs were $4,423,000 for 1994, $2,669,000 for 1993, and $2,598,000
for 1992, of which approximately $693,000, $425,000, and $241,000,
respectively, were charged to construction. The components of periodic
pension expense are shown below (in thousands of $):
1994 1993 1992
---- ---- ----
Service cost-benefits earned during the period. . . . . . . . . . . $ 4,813 $ 4,516 $ 5,459
Interest cost on projected benefit obligation . . . . . . . . . . . 13,057 12,117 11,006
Actual return on plan assets. . . . . . . . . . . . . . . . . . . . (489) (13,602) (8,850)
Amortization of transition asset. . . . . . . . . . . . . . . . . . (1,112) (1,112) (1,076)
Net amortization and deferral . . . . . . . . . . . . . . . . . . . (11,846) 750 (3,941)
------ ------ ------
Net pension cost. . . . . . . . . . . . . . . . . . . . . . . . . . $ 4,423 $ 2,669 $ 2,598
------ ------ ------
------ ------ ------
The assets of the plans consist primarily of common stocks, corporate
bonds, United States government securities, and interests in a pooled real
estate investment fund.
The funded status of the pension plans at December 31 is shown below (in
thousands of $):
1994 1993
Actuarial present value of accumulated plan benefits:
Vested. . . . . . . . . . . . . . . . . . . . . . . . . . . . $132,260 $137,655
Non-Vested. . . . . . . . . . . . . . . . . . . . . . . . . . 14,023 17,158
------- -------
Accumulated benefit obligation. . . . . . . . . . . . . . . . 146,283 154,813
Effect of projected future compensation . . . . . . . . . . . 18,473 25,234
------- -------
Projected benefit obligation. . . . . . . . . . . . . . . . . 164,756 180,047
Plan assets at fair value . . . . . . . . . . . . . . . . . . 159,638 165,088
------- -------
Plan assets less than projected benefit obligation. . . . . . (5,118) (14,959)
Unrecognized net transition asset . . . . . . . . . . . . . . (12,524) (13,636)
Unrecognized prior service cost . . . . . . . . . . . . . . . 24,257 28,671
Unrecognized net gain . . . . . . . . . . . . . . . . . . . . (36,266) (23,860)
------- -------
Accrued pension liability . . . . . . . . . . . . . . . . . $(29,651) $(23,784)
------- -------
------- -------
The projected benefit obligation was determined using an assumed discount
rate of 8.5% for 1994 and 7.5% for 1993. An assumed annual rate of
increase in future compensation levels ranged from 4.5% to 5% for 1994 and
3.5% to 4.5% for 1993. The assumed long-term rate of return on plan assets
was 8.5% for 1994 and 1993. Transition assets and prior service costs are
being amortized over the average remaining service period of active
participants.
-32-
POST-RETIREMENT BENEFITS. The Company adopted Statement of Financial
Accounting Standards No. 106, EMPLOYERS' ACCOUNTING FOR POST-RETIREMENT
BENEFITS OTHER THAN PENSIONS (SFAS No. 106), effective 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.
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. Prior to January 1,
1993, the cost of retiree health care and life insurance benefits was
generally recognized when paid. This cost was $1,078,000 for 1992. In
1993, the Company began to account for post-retirement benefits according
to the provisions of SFAS No. 106.
In 1993, the Company, based on an order from the Commission, created a
regulatory asset and deferred the level of SFAS No. 106 expense in excess
of the previous level of pay-as-you-go expense. Therefore, the adoption of
SFAS No. 106 did not have an effect on results of operations in 1993.
However, in the first quarter of 1994, the Company began recognizing the
excess SFAS No. 106 expense currently, including the amount previously
deferred. See Note 3, Non-Recurring Charges.
The components of the net periodic post-retirement benefit cost as
calculated under SFAS No. 106 are as follows (in thousands of $):
1994 1993
---- ----
Service cost . . . . . . . . . . . . . . . . $ 621 $ 701
Interest cost. . . . . . . . . . . . . . . . 2,386 2,614
Amortization of transition obligation. . . . 1,337 1,395
----- -----
Post-retirement benefit cost $4,344 $4,710
----- -----
----- -----
The accumulated post-retirement benefit obligation as calculated under SFAS
No. 106 at December 31, is shown below (in thousands of $):
1994 1993
---- ----
Retirees . . . . . . . . . . . . . . . . . .$(18,487) $(17,826)
Fully eligible active employees. . . . . . . (1,927) (4,001)
Other active employees . . . . . . . . . . . (9,789) (15,945)
------- -------
Accumulated post-retirement benefit
obligation . . . . . . . . . . . . . . . . . (30,203) (37,772)
Unrecognized net (gain) loss . . . . . . . . (3,275) 4,966
Unrecognized transition obligation . . . . . 24,064 26,508
Previously recognized amount . . . . . . . . - 3,696
------ -------
Accrued post-retirement benefit liability. .$ (9,414) $ (2,602)
------ -------
------ -------
-33-
The accumulated post-retirement benefit obligation was determined using an
assumed discount rate of 8.5% for 1994 and 7.5% for 1993. Assumed
compensation increases for projected life insurance benefits for affected
groups was 5% for 1994 and 4.5% for 1993. An assumed health care cost
trend rate of 10.5% was assumed for 1994, gradually decreasing to 5.25% 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 million
and the annual service and interest cost by approximately $100,000. 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) on January 1, 1994, as required. 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.
In 1992, an early retirement program was made available to all Company
union employees who had reached age 55, or who had 35 years or more of
continuous service regardless of age. The cost of the program was
approximately $7 million and consisted primarily of enhanced early
retirement and health care benefits.
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 $1,701,000 for 1994, $1,795,000 for 1993,
and $767,000 for 1992. The increase in 1993 401(k) expenses over 1992 is
due to the expansion of the program to the Company's union employees.
-34-
NOTE 6 - FEDERAL AND STATE INCOME TAXES
Components of income tax expense are shown in the table below (in thousands
of $):
1994 1993 1992
---- ---- ----
Included in Operating:
Current - Federal. . . . . . . . . . $35,552 $31,082 $20,756
- State. . . . . . . . . . . 9,003 8,920 6,354
Deferred - Federal-net. . . . . . . . (969) 13,185 15,771
- State-net. . . . . . . . . 955 3,933 5,774
Amortization of investment tax credit (4,619) (4,786) (4,815)
------- ------- ------
Total . . . . . . . . . . . $39,922 $52,334 $43,840
------- ------- -------
Included in Other Income and (Deductions):
Current - Federal . . . . . . . . . . $(4,626) $11,009 $(6,971)
- State. . . . . . . . . . . (1,277) 4,034 (3,214)
Deferred - Federal-net. . . . . . . . 19 (8,473) 4,670
- State-net. . . . . . . . . 1 (3,707) 2,696
Deferred investment tax credit. . . . - - 390
Amortization of investment tax credit - (3,035) (608)
------- ------- -------
Total . . . . . . . . . . .$ (5,883) $ (172) $(3,037)
------- ------- -------
Included in Cumulative Effect of a Change in Accounting
for Post-Employment Benefits:
Deferred - Federal. . . . . . . . . .$ (1,814) $ - $ -
- State. . . . . . . . . . . (466) - -
------- ------ ------
Total. . . . . . . . . . . . . .$ (2,280) $ - $ -
------- ------ ------
Total Income Tax Expense. . . . . . . .$ 31,759 $52,162 $40,803
------- ------ ------
------- ------ ------
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 $):
1994 1993 1992
---- ---- ----
Depreciation and amortization $12,609 $ (255) $33,839
Alternative minimum tax. . . - 5,387 (5,387)
Pension overfunding. . . . . (4,357) (823) (900)
Accrued liabilities not
currently deductible . . . . (5,343) 1,210 295
Change in accounting principle (2,280) - -
Other . . . . . . . . . . (2,903) (581) 1,064
------ ------ -------
Total . . . . . . . . . . $(2,274) $4,938 $28,911
------ ------ -------
------ ------ -------
The net provisions for deferred income taxes decreased in 1994 due largely
to recording certain liabilities which are not deductible until such
liabilities are paid. Deferred income taxes attributable to depreciation
and amortization decreased in 1993 because of the reversal of prior years'
accumulated taxes as a result of the sale of a portion of Trimble County
Unit 1. See Note 12, Jointly Owned Electric Utility Plant for a further
discussion of the sale.
-35-
Net deferred tax liabilities resulting from book-tax temporary differences
are shown below (in thousands of $):
December 31 January 31
1994 1993 1993
---- ---- ----
Deferred Tax Liabilities:
Depreciation and other
plant related items. . $334,252 $322,544 $326,527
Income taxes due from
customers . . . . . . 10,179 10,233 14,608
Other liabilities . . . 7,977 7,458 5,548
------- ------- -------
$352,408 $340,235 $346,683
------- ------- -------
Deferred Tax Assets:
Investment tax credit . $ 35,833 $ 36,961 $ 42,229
Income taxes due to
customers . . . . . . 13,942 14,361 15,477
Pension overfunding . . 11,145 6,781 5,951
Other assets. . . . . . 15,674 572 5,066
------- ------- -------
$ 76,594 $ 58,675 $ 68,723
------- ------- -------
Net deferred income tax
liability. . . . . . $275,814 $281,560 $277,960
------- ------- -------
------- ------- -------
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:
1994 1993 1992
---- ---- ----
Statutory Federal income tax rate . . . 35.0% 35.0% 34.0%
State income taxes net of Federal benefit 5.9 6.0 6.7
Investment tax credits. . . . . . . . . (5.1) (5.5) (4.7)
Other differences-net . . . . . . . . . (.5) 1.1 (.4)
---- ---- ----
Effective Income Tax Rate . . . . . . . 35.3% 36.6% 35.6%
---- ---- ----
---- ---- ----
NOTE 7 - OTHER INCOME AND (DEDUCTIONS)
Other income and (deductions) consisted of the following at December 31 (in
thousands of $):
1994 1993 1992
---- ---- ----
Interest and dividend income . . . . . . . . . . $ 4,568 $ 3,112 $ 1,980
Gains (losses) on fixed asset disposal . . . . . 1,427 (3,523) 608
Gain on sale of 12.88% portion of Trimble County - 3,869 -
Donations . . . . . . . . . . . . . . . . . (1,015) (909) (652)
Income taxes and other . . . . . . . . . . . . . (2,529) (636) (4,139)
------ ------ ------
Total . . . . . . . . . . . . . . . . . $ 2,451 $ 1,913 $(2,203)
------ ------ ------
------ ------ ------
NOTE 8 - 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
-36-
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 1995 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 March 1993, due to the sale of 12.88% of Trimble County Unit 1, the
Company completed the defeasance of $25 million of its Pollution Control
Bonds ($16.665 million of the 7.625% Series and $8.335 million of the 6.55%
Series).
The Company issued several series of lower interest bearing First Mortgage
and Pollution Control Bonds in 1993 to refinance bonds with higher interest
rates. In August 1993, the Company issued two separate series of Pollution
Control Bonds (a $35.2 million, Variable Rate Series, which had an average
interest rate of 3.740% at December 31, 1994, and 2.586% at December 31,
1993, and a $102 million, 5.625% Series) and redeemed five series of
Pollution Control Bonds totaling $137.2 million with interest rates ranging
from 6.125% to 6.7%. In August 1993, the Company also issued $42.6 million
of 6% First Mortgage Bonds and redeemed two series of First Mortgage Bonds
($19.7 million at 8.25% and $21.362 million at 8.5%). In November 1993,
the Company issued $26 million of Pollution Control Bonds, 5.45% Series and
redeemed the $26 million, 9.75% Series.
The Company entered into an agreement in November 1993 with Goldman, Sachs
& Co. to issue $40 million of tax-exempt Pollution Control Bonds in 1995 at
a rate of 5.9%. The issuance of the bonds in 1995 is subject to certain
conditions. If issued, the proceeds will be used to redeem, in 1995, the
outstanding 9.25% series of Pollution Control Bonds due July 1, 2015.
The Company has outstanding interest rate swap agreements totaling $30
million. Under the agreements, which were entered into in 1992, the
Company pays a fixed rate of 4.35% on $15 million for a five-year period
and 4.74% on $15 million for a seven-year period. In return, the Company
receives a floating rate based on the weighted average JJ Kenny index. The
JJ Kenny index is a tax-exempt municipal bond interest rate index. These
swaps were entered into as a standard hedging device in connection with the
issuance of the Series S Pollution Control Bonds due September 1, 2017.
The swaps are designed to reduce the Company's exposure to interest rate
risk. The Company received interest at composite rates of 2.84%, 2.38%,
and 2.73% in
-37-
1994, 1993, and 1992, respectively and paid interest at a composite rate of
4.55% pursuant to the swaps.
The Company's First Mortgage Bonds, 5.625% Series of $16 million is
scheduled to mature in 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, 1994.
The Company has no cash sinking fund requirements.
NOTE 9 - NOTES PAYABLE
The Company had no notes payable at December 31, 1994, or December 31,
1993.
At December 31, 1994, the Company had unused lines of credit of $145
million, for which it pays commitment fees. The credit lines are scheduled
to expire at various periods throughout 1995 and 1996. Management intends
to renegotiate these lines when they expire.
NOTE 10 - COMMITMENTS AND CONTINGENCIES
CONSTRUCTION PROGRAM. The Company had commitments, primarily in connection
with its construction program, aggregating approximately $8 million at
December 31, 1994. Construction expenditures for the calendar years 1995
and 1996 are estimated to total approximately $200 million.
FERC ORDER NO. 636. In 1994, the Company experienced its first full year
operating under Order No. 636. Whereas the Company had previously
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 other
sources.
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 1994, the
Company paid and began recovering from its customers approximately $2.8
million in transition costs. It is estimated that $6 million to $8 million
in additional transition costs will be incurred by the Company during 1995,
and these costs are also expected to be recovered from customers. The
Company is a party to proceedings before FERC which will determine a number
of pipeline transition issues. Because of the impact such issues may have
on future costs, management is unable to estimate the level of transition
costs, if any, for years subsequent to 1995.
-38-
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 1994, 1993, and 1992 was $2,192,000,
$2,436,000, and $2,478,000, respectively. The future minimum annual lease
payments under the lease agreement for years subsequent to December 31,
1994, are as follows (in thousands of $):
1995. . . . . . . . . . . . . $ 2,499
1996. . . . . . . . . . . . . 2,850
1997. . . . . . . . . . . . . 2,850
1998. . . . . . . . . . . . . 2,850
1999. . . . . . . . . . . . . 2,850
Thereafter. . . . . . . . . . 18,960
-------
Total . . . . . . . . . . $ 32,859
-------
-------
ENVIRONMENTAL. The Clean Air Act Amendments of 1990 impose stringent
limits on emissions of sulfur dioxide and nitrogen oxides by electric
utility generating plants. The legislation is extremely complex and its
effect will substantially depend on regulations issued by the U.S.
Environmental Protection Agency (USEPA). The Company is closely monitoring
the continuing rule-making process in order to assess the precise impact of
the legislation on the Company. 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 capital construction program,
the Company has spent $10 million to date and anticipates incurring
additional capital expenditures of approximately $29 million through 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.
In 1992, the Company entered two agreed orders with the Air Pollution
Control District (APCD) of Jefferson County in which the Company committed
to undertake remedial measures to address certain particulate emissions and
alleged excess sulfur dioxide emissions from its Mill Creek electric
generating plant. In May 1994, the Company completed all specified
remedial measures in accordance with the terms of the agreed orders. The
Company has agreed to commence a joint field sampling program with the APCD
to demonstrate the effectiveness of the remedial measures.
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. The plaintiffs seek
compensation for alleged personal injury and property damage attributable
to emissions from the Mill Creek plant, 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. The Company intends to vigorously defend itself in
the pending litigation.
In an effort to resolve property damage claims relating to particulate
emissions from the Mill Creek plant, in July 1993, the Company commenced
extensive negotiations and property damage settlements with adjacent
residents who are not parties to the pending litigation. The negotiations
and settlements are continuing and the Company currently estimates that
property
-39-
damage claims for the particulate emissions should be settled for an
aggregate amount of approximately $15 million. Accordingly, the Company
has recorded an accrual of this amount.
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 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.
In March 1994, the APCD adopted a regulation requiring a 15% reduction from
1990 volatile organic compound (VOC) emissions from industrial sources.
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 in an effort to demonstrate its eligibility for
an exclusion from the VOC reduction requirements.
The Company owns or formerly owned three primary sites where manufactured
gas plant operations were located. Such manufactured gas plant operations,
conducted in the 1838 to 1960 time period, typically produced coal tar
byproducts and other constituents that may necessitate cleanup measures.
The Company has completed an investigation of the level of contaminants
present at the two company-owned sites, and the Company, along with the
current owner of the third site and another party completed an
investigation of the third site. Investigation and testing at these three
sites has identified the presence of contaminants typical of manufactured
gas operations. A report on the results of the investigation at each site
has been prepared and submitted to the Kentucky Natural Resources and
Environmental Protection Cabinet (KNREPC). The KNREPC will review the
findings submitted by the Company, and through negotiations with the
Company, the level of remediation required at each site will be determined.
Although a precise determination of the costs associated with cleanup
activities at these three sites cannot be made until the required level of
remediation is established, management currently estimates that the total
cost 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.
In November 1993, the Company was served with a third-party complaint filed
in federal district court in Illinois by three third-party plaintiffs. The
third-party plaintiffs allege that the Company and 31 other parties are
liable under the Comprehensive Environmental Response, Compensation, and
Liability Act as amended (CERCLA) for $1.4 million in costs allegedly
incurred by USEPA in conducting cleanup activities at the M.T. Richards
Site in Crossville, Illinois. A number of de minimis third party
defendants, including the Company, have commenced settlement discussions
with the third-party plaintiffs. In the Company's opinion, the resolution
of this issue will not have a material adverse impact on its financial
position or results of operations.
In June 1992, USEPA identified the Company as a potentially responsible
party (PRP) allegedly liable under CERCLA for $1.6 million in costs
allegedly incurred by USEPA in cleanup of the Sonora Site and Carlie
Middleton Burn Site located in Hardin County, Kentucky. The USEPA
-40-
has since increased the amount of its demand to $1.8 million to reflect
additional cleanup costs. In September 1994, USEPA filed a CERCLA cost
recovery action in U.S. District Court against the Company and six other
parties. In the Company's opinion, the resolution of this issue will not
have a material adverse impact on its financial position or results of
operations.
In 1987, USEPA identified the Company as one of the numerous PRPs allegedly
liable under CERCLA for the Smith's Farm Site in Bullitt County, Kentucky.
In March 1990, USEPA issued an administrative order requiring the Company
and 35 other PRPs to conduct certain cleanup activities. In February 1992,
four PRPs filed a complaint in federal district court in Kentucky against
the Company and 52 other PRPs. Under the law, each PRP could be held
jointly and severally liable for the cost of site cleanup, but would have
the right to seek contribution from other PRPs. In July 1993, upon motion
of the plaintiffs, the federal court dismissed the Company and a number of
others from the litigation in order to facilitate settlement negotiations
among the parties. Cleanup costs for the site are currently estimated at
approximately $70 million. The Company and several other parties have
shared certain cleanup costs in the interim until a voluntary allocation of
liability can be reached among the parties. It is not possible at this
time to predict the outcome or precise impact of this matter. However,
management believes that this matter should not have a material adverse
impact on the financial position or results of operations of the Company as
other financially viable PRPs appear to have primary liability for the
site.
NOTE 11 - TRIMBLE COUNTY GENERATING PLANT
Trimble County Unit 1 (Trimble County), a 495-megawatt, coal-fired electric
generating unit placed into service in December 1990, is currently the
subject of an administrative proceeding before the Commission. This
proceeding, which originally began in 1988, was initiated by the Commission
to determine the appropriate ratemaking treatment to implement its 1988
decision that the Company should not be allowed to recover 25% of the cost
of the Unit from ratepayers. As a result of a non-unanimous settlement
agreement in the initial 1989 proceedings reached between the Company and
the Commission staff, which was approved by the Kentucky Commission in
October 1989, the Company returned to its customers $11.1 million through
refunds and rate reductions. The Commission's approval of the settlement
agreement was appealed by certain intervenors in the case who had not
joined in the agreement. In April 1993, the Kentucky Court of Appeals held
that the Commission exceeded its authority in approving the agreement, and
ordered the Commission to hold new hearings on the underlying issues.
Pursuant to a Commission procedural order, the Company filed direct
testimony on January 7, 1994, in which the Company recommended that the
Commission allow it to recover the $11.1 million it refunded to customers
under the 1989 settlement agreement. Testimony filed by intervenors
recommended that the Commission order the Company to refund approximately
$183 million, based upon their argument that the Company should refund 25%
of the revenue requirements associated with Trimble County's
construction-work-in-progress (CWIP) collected through rates over the
course of the Trimble County construction project.
On March 25, 1994, the Kentucky Attorney General and the Jefferson County
Attorney filed a motion with the Commission in which they requested that
two of the three members of the Commission and certain unspecified
Commission staff employees be recused from further participation in the
case. The intervenors supported the motion by arguing that past statements
and orders of the Commission in this and other proceedings showed that the
Commissioners had
-41-
prejudged the issues relevant to the current proceeding. The issues
referred to in the motion centered on the intervenors' claims that the
Company should refund 25% of all revenues associated with Trimble County
CWIP collected through rates during the course of the plant's construction.
On July 8, 1994, the Commission entered an order which denied the
intervenors' motion. In the order, the Commission stated that it had not
prejudged any issues but rather had decided a number of issues in past
proceedings which are binding on it and all other parties. The Commission
also stated that it had never implied in prior orders that the amounts of
Trimble County CWIP included in rate base prior to the issuance of its
July 1, 1988, order in Case No. 10064, a general rate case, would be
subject to later review. The Commission concluded that the scope of the
present case had been limited since at least 1985 when the Commission
issued an order that put the Company on notice that in future rate cases
the continuation of allowing a return on further additions to Trimble
County CWIP would be an issue.
The Company believes that the Commission's July 8 order makes it unlikely
that the Commission will entertain the position that the intervenors have
taken in their previously-filed testimony that the Company refund
approximately $183 million to its customers. The Company believes that
remaining at issue is what amount, if any, of the approximately $30 million
it collected subject to refund under a rate case order issued in 1988
should be returned to ratepayers. As discussed previously, approximately
$11.1 million has already been returned to ratepayers under the 1989
settlement agreement. However, the Company is unable to predict the
outcome of the Commission proceedings, or the amount of additional refunds
or recoveries, if any, that may be ordered.
The Commission has set May 9, 1995, as the formal hearing date in the
Trimble County proceedings. The purpose of the hearing is to determine the
proper ratemaking treatment to exclude 25% of Trimble County from customer
rates for the period from May 1988 to December 31, 1990. The Company's
current rates, which became effective January 1, 1991, reflect the
disallowance of 25% of the plant.
Reference is made to Note 12, Jointly Owned Electric Utility Plant, for a
discussion of the sale of 25% of Trimble County.
NOTE 12 - 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.
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The following data represent shares of the jointly owned property:
Trimble County
----------------------------------
LG&E IMPA IMEA Total
---- ---- ---- -----
Ownership interest . . . 75% 12.88% 12.12% 100%
Mw capacity. . . . . . . 371.25 63.75 60 495
NOTE 13 - SEGMENTS OF BUSINESS
The Company is an operating public utility engaged in the generation,
transmission, distribution, and sale of electricity and the transmission,
distribution, and sale of natural gas.
1994 1993 1992
---- ---- ----
(Thousands of $)
Operating Information
Operating Revenues
Electric. . . . . . . . . . . . $ 558,946 $ 570,210 $ 521,669
Gas . . . . . . . . . . . . . . 200,129 204,915 178,526
------- ------- -------
Total . . . . . . . . . . . . $ 759,075 $ 775,125 $ 700,195
------- ------- -------
------- ------- -------
Pre-tax Operating Income
Electric. . . . . . . . . . . . . $ 139,594 $ 171,016 $ 154,547
Gas . . . . . . . . . . . . . . . 11,368 17,436 15,122
------- ------- -------
Total . . . . . . . . . . . . $ 150,962 $ 188,452 $ 169,669
------- ------- -------
------- ------- -------
Other Information
Depreciation and Amortization
Electric . . . . . . . . . . . . $ 71,882 $ 69,753 $ 67,869
Gas. . . . . . . . . . . . . . . 10,637 9,902 9,034
Non-Jurisdictional . . . . . . . - 232 2,783
------- ------- --------
Total. . . . . . . . . . . . . $ 82,519 $ 79,887 $ 79,686
------- ------- --------
------- ------- --------
Construction Expenditures
Electric. . . . . . . . . . . . . $ 71,592 $ 74,165 $ 75,630
Gas. . . . . . . . . . . . . . . 23,806 24,622 25,545
------- ------- -------
Total. . . . . . . . . . . . . $ 95,398 $ 98,787 $ 101,175
------- ------- -------
------- ------- -------
Investment Information-December 31
Identifiable Assets
Electric. . . . . . . . . . . . $1,514,287 $1,537,387 $1,528,123
Gas . . . . . . . . . . . . . . 252,946 241,930 222,958
--------- --------- ---------
Total . . . . . . . . . . . . 1,767,233 1,779,317 1,751,081
Trimble County (a). . . . . . . . - - 87,794
Other Assets (b). . . . . . . . . 199,357 195,267 121,985
--------- --------- ---------
Total Assets. . . . . . . . . $1,966,590 $1,974,584 $1,960,860
--------- --------- ---------
--------- --------- ---------
(a) Represents the portion of Trimble County not allowed in customer
rates.
(b) Includes cash and temporary cash investments, accounts receivable,
unamortized debt expense, and other property and investments.
-43-
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, 1994 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.
-44-
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, 1994 and
1993, and the related statements of income, retained earnings and cash flows for
each of the three years in the period ended December 31, 1994. 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, 1994 and 1993, and the results of its operations and
its cash flows for each of the three years in the period ended December 31,
1994, in conformity with generally accepted accounting principles.
As further discussed in Note 11, the potential amount of future rate
refunds that may be required, if any, once the outcome of the legal and
regulatory process is known, is uncertain at this time.
As discussed in Notes 1 and 5 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, 1995
--------------------------------
-45-
SELECTED QUARTERLY FINANCIAL DATA (Unaudited)
(Thousands of $)
Selected financial data for the four quarters of 1994 and 1993 are shown
below. Because of seasonal fluctuations in temperature and other factors,
results for quarters may fluctuate throughout the year.
Quarters Ended
-------------------------------------------------
March June September December
----- ---- --------- --------
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) (a) 20,636 35,438 18,941
Net Income (Loss) Available
for Common Stock . . . . . (18,073) (a) 19,256 33,935 17,374
1993
Operating Revenues . . . . . $208,631 $166,906 $200,408 $199,180
Net Operating Income . . . . 32,754 28,395 47,786 27,183
Net Income . . . . . . . 20,786 16,566 36,447 16,736
Net Income Available for
Common Stock . . . . . . . 19,199 14,898 35,099 15,358
(a) See Note 3 of Notes to Financial Statements under Item 8.
-------------------------------------
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
-46-
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 16, 1995, 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, 1994, 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,
1994 (page 23).
Statements of Retained Earnings for the three years ended
December 31, 1994
(page 23).
Balance Sheets - December 31, 1994, and 1993 (page 24).
Statements of Cash Flows for the three years ended December
31, 1994 (page 25).
Statements of Capitalization - December 31, 1994, and 1993
(page 26).
Notes to Financial Statements (pages 27-43).
Report of Management (page 44).
Report of Independent Public Accountants (page 45).
Selected Quarterly Financial Data for 1994 and 1993 (page 46).
2. Financial Statement Schedule (included in Part IV):
Schedule II - Valuation and Qualifying Accounts for the three
years ended December 31, 1994 (page 60).
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.
-47-
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 May 13, 1993. [Filed as
Exhibit 3.01 to the Company's Form 10-Q for the quarter ended
June 30, 1993, and incorporated by reference herein]
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]
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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]
-49-
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]
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]
-50-
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]
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]
-51-
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 Copy of Agreement dated September 1, 1970, between Texas Gas
Transmission Corporation and the Company covering the purchase
of natural gas. [Filed as Exhibit 4.01 to Registration
Statement 2-40985 and incorporated by reference herein]
10.02 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]
10.03 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]
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10.04 Copy of Modification No. 2 dated March 15, 1964, to the Power
Agreement between Ohio Valley Electric Corporation and Atomic
Energy Commission. [Filed as Exhibit 5.02c to Registration
Statement 2-61607 and incorporated by reference herein]
10.05 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]
10.06 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]
10.07 Copies of (i) Inter-Company Power Agreement, dated July 10,
1953, between Ohio Valley Electric Corporation and Sponsoring
Companies (which Agreement includes as Exhibit A the Power
Agreement, dated July 10, 1953, between Ohio Valley Electric
Corporation and Indiana-Kentucky Electric Corporation); (ii)
First Supplementary Transmission Agreement, dated July 10,
1953, between Ohio Valley Electric Corporation and Sponsoring
Companies; (iii) Inter-Company Bond Agreement, dated July 10,
1953, between Ohio Valley Electric Corporation and Sponsoring
Companies; (iv) Inter-Company Bank Credit Agreement, dated
July 10, 1953, between Ohio Valley Electric Corporation and
Sponsoring Companies. [Filed as Exhibit 5.02f to Registration
Statement 2-61607 and incorporated by reference herein]
10.08 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]
10.09 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 5.02h to Registration Statement
2-61607 and incorporated by reference herein]
10.10 Copy of Modification No. 1, dated August 20, 1958, to First
Supplementary Transmission Agreement, dated July 10, 1953,
among Ohio Valley Electric Corporation and the Sponsoring
Companies. [Filed as Exhibit 5.02i to Registration Statement
2-61607 and incorporated by reference herein]
-53-
10.11 Copy of Modification No. 2, dated April 1, 1965, to the First
Supplementary Transmission Agreement, dated July 10, 1953,
among Ohio Valley Electric Corporation and the Sponsoring
Companies. [Filed as Exhibit 5.02j to Registration Statement
2-6l607 and incorporated by reference herein]
10.12 Copy of Modification No. 3, dated January 20, 1967, to First
Supplementary Transmission Agreement, dated July 10, 1953,
among Ohio Valley Electric Corporation and the Sponsoring
Companies. [Filed as Exhibit 4(a)(7) to Registration
Statement 2-26063 and incorporated by reference herein]
10.13 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]
10.14 Copy of Modification No. 3 dated November 15, 1967, to the
Inter-Company Power Agreement dated July 10, 1953. [Filed as
Exhibit 4.02m to Registration Statement 2-37368 and
incorporated by reference herein]
10.15 Copy of Modification No. 7 dated November 5, 1975, to the
Power Agreement between Ohio Valley Electric Corporation and
Atomic Energy Commission. [Filed as Exhibit 5.02n to
Registration Statement 2-56357 and incorporated by reference
herein]
10.16 Copy of Modification No. 4 dated November 5, 1975, to the
Inter-Company Power Agreement dated July 10, 1953. [Filed as
Exhibit 5.02o to Registration Statement 2-56357 and
incorporated by reference herein]
10.17 Copy of Modification No. 4 dated April 30, 1976, to First
Supplementary Transmission Agreement, dated July 10, 1953,
among Ohio Valley Electric Corporation and the Sponsoring
Companies. [Filed as Exhibit 5.02p to Registration Statement
2-6l607 and incorporated by reference herein]
10.18 Copy of Modification No. 8 dated June 23, 1977, to the Power
Agreement between Ohio Valley Electric Corporation and Atomic
Energy Commission. [Filed as Exhibit 5.02q to Registration
Statement 2-61607 and incorporated by reference herein]
10.19 Copy of Modification No. 9 dated July 1, 1978, to the Power
Agreement between Ohio Valley Electric Corporation and Atomic
Energy Commission. [Filed as Exhibit 5.02r to Registration
Statement 2-63149 and incorporated by reference herein]
-54-
10.20 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]
10.21 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]
10.22 Copy of Modification No. 5 dated September 1, 1979, to
Inter-Company Power Agreement dated July 5, 1953, among Ohio
Valley Electric Corporation and Sponsoring Companies. [Filed
as Exhibit 4 to the Company's Annual Report on Form 10-K for
the year ended December 31, 1979, and incorporated by
reference herein]
10.23 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]
10.24 Copy of Modification No. 6 dated August 1, 1981, to
Inter-Company Power Agreement dated July 5, 1953, among Ohio
Valley Electric Corporation and Sponsoring Companies. [Filed
as Exhibit 10.26 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1981, and incorporated by
reference herein]
10.25 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]
10.26 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]
10.27 Copy of Omnibus Long-Term Incentive Plan effective January 1,
1990, covering officers and key employees of the Company.
[Filed as Exhibit 4.01 to the Company's Registration
Statement 33-38557 and incorporated by reference herein]
-55-
10.28 Copy of Key Employee Incentive Plan effective January 1, 1990,
covering officers and key employees of the Company. [Filed as
Exhibit 10.33 to the Company's Annual Report on Form 10-K for
the year ended December 31, 1989, and incorporated by
reference herein]
10.29 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]
10.30 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]
10.31 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]
10.32 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]
10.33 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]
10.34 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]
10.35 Copy of Modification No. 7 dated January 15, 1992, to Inter-
Company Power Agreement dated July 10, 1953, among Ohio Valley
Electric Corporation and Sponsoring Companies. [Filed as
Exhibit 10.44 to the Company's Annual Report on Form 10-K for
the year ended December 31, 1993, and incorporated by reference
herein]
-56-
10.36 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]
10.37 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]
10.38 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]
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]
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]
10.39 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]
10.40 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]
10.41 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.
10.42 Copy of Amendment No. 1 dated January 1, 1991, to Coal Supply
Agreement, dated August 9, 1989, between Shawnee Coal
-57-
Company, Roberts Brothers Coal Company, and the Company
covering the purchase of coal.
10.43 Copy of Amendment No. 2 dated November 27, 1991, to Coal Supply
Agreement, dated August 9, 1989, between Shawnee Coal Company,
Roberts Brothers Coal Company, and the Company covering the
purchase of coal.
10.44 Copy of Amendment No. 3 dated January 1, 1994, to Coal Supply
Agreement, dated August 9, 1989, between Shawnee Coal Company,
Roberts Brothers Coal Company, and the Company covering the
purchase of coal.
10.45 Copy of Amendment No. 4 dated January 1, 1995, to Coal Supply
Agreement, dated August 9, 1989, between Shawnee Coal Company,
Roberts Brothers Coal Company, and the Company covering the
purchase of coal.
10.46 Copy of Coal Supply Agreement dated January 1, 1994, between
Peabody Coalsales Company and the Company covering the purchase
of coal.
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]
Omnibus Long-Term Incentive Plan effective January 1, 1990,
covering officers and key employees of the Company. [Filed as
Exhibit 4.01 to the Company's Registration Statement 33-38557
and incorporated by reference herein]
Key Employee Incentive Plan effective January 1, 1990, covering
officers and key employees of the Company. [Filed as
Exhibit 10.33 to the Company's Annual Report on Form 10-K for
the year ended December 31, 1989, and incorporated by reference
herein]
-58-
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]
(c) Reports on Form 8-K:
The Company was not required to file a Form 8-K report during
the fourth quarter of 1994.
-59-
SCHEDULE II
LOUISVILLE GAS AND ELECTRIC COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1994
(Thousands of $)
Reserves Deducted from
Assets in Balance Sheet
------------------------------------
Other Accounts
Property Receivable
and (Uncollectible
Investments Accounts)
----------- -------------
Balance January 1, 1992. . . . . . . $ 2,862 $ 1,413
Additions:
Charged to costs and expenses
Trimble County -
non-jurisdictional
depreciation . . . . . . 2,783
Other. . . . . . . . . . . 2,158
Deductions:
Net charges of nature for which
reserves were created. . . 2,462
----- -----
Balance December 31, 1992. . . . . . 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. . . 2,135
Other . . . . . . . . . . . 5,815
----- -----
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
----- -----
----- -----
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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 24, 1995 By
- -------------- ------------------------------------------
(Date) M. L. Fowler
Vice President and Controller
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);
CHARLES A. MARKEL III Treasurer
(Principal Financial Officer);
M. L. FOWLER Vice President and Controller
(Principal 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__________________________________ March 24, 1995
M. L. FOWLER (Attorney-In-Fact)
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