1
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
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FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 (FEE REQUIRED)
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
For the fiscal year ended December 31, 1993 Commission file number 2-26720
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LOUISVILLE GAS AND ELECTRIC COMPANY
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(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 West Main Street
P.O. Box 32010
Louisville, Kentucky 40232
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (502) 627-2000
2
Securities registered pursuant to Section 12(b) of the Act:
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Name of each exchange on
Title of each class which registered
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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:
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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, 1994, the aggregate market value of the registrant's
voting stock held by non-affiliates was $37,310,812 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
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The proxy statement of Louisville Gas and Electric Company filed with
the Commission on March 28, 1994, is incorporated by reference into Part III
of this Form 10-K.
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TABLE OF CONTENTS
PART I PAGE
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Item 1. Business................................................ 4
General............................................... 4
Electric Operations................................... 7
Gas Operations........................................ 9
Regulation and Rates.................................. 10
Construction Program and Financing.................... 11
Coal Supply........................................... 12
Gas Supply............................................ 12
Environmental Matters................................. 14
Labor Relations....................................... 14
Employees............................................. 14
Item 2. Properties.............................................. 15
Item 3. Legal Proceedings....................................... 16
Item 4. Submission of Matters to a Vote of Security Holders..... 18
Executive Officers of the Company................................. 18
PART II
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Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters................................... 20
Item 6. Selected Financial Data................................. 20
Item 7. Management's Discussion and Analysis of Results of
Operations and Financial Condition.................... 20
Item 8. Financial Statements and Supplementary Data............. 29
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure................... 56
PART III
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Item 10. Directors and Executive Officers of the Registrant (a).. 57
Item 11. Executive Compensation (a).............................. 57
Item 12. Security Ownership of Certain Beneficial Owners
and Management (a).................................... 57
Item 13. Certain Relationships and Related Transactions (a)...... 57
PART IV
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Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K............................... 57
Signatures........................................................ 84
(a) Incorporated by reference.
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PART I
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ITEM 1. Business.
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General
Incorporated July 2, 1913, Louisville Gas and Electric Company (the
Company) is an operating public utility that supplies natural gas to
approximately 258,000 customers and electricity to approximately 336,000
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
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 (the "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. For a more
detailed discussion of the proceedings relating to Trimble County Unit 1, see
Note 8 of the Notes to Financial Statements under Item 8.
In February 1993, the Company sold a 12.88% ownership interest in the Unit
to Indiana Municipal Power Agency, completing the Company's plan to sell the
25% not allowed for ratemaking. The Company had previously sold a 12.12%
ownership interest in the Unit to the Illinois Municipal Electric Agency in
1991. See Note 9 of the Notes to Financial Statements, Jointly Owned
Electric Utility Plant, under Item 8 for a further discussion.
5
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. 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 anticipates incurring capital expenditures
during the next four years of approximately $40 million for remedial measures
necessary to meet the Act's requirements for nitrogen oxides. The overall
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 which are expected to be incurred by
many other utilities. For a more detailed discussion of the Clean Air Act
and other environmental issues, see Environmental Matters under this Item,
Item 3, Item 7, and Note 7 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 is responding to increased competition in a number
of ways designed to lower its costs and increase sales.
One such response has been for the Company's parent, LG&E Energy Corp.,
to realign into new business units effective January 1, 1994. Under the
realignment, Energy Corp. formed a national business unit, LG&E Energy
Services, to develop and manage all of its utility and non-utility electric
power generation and concentrate on the marketing and brokering of electric
power on a regional and national basis. The realignment will allow the
Company to increase its focus on customer service and to develop more
customer options as the utility industry becomes more competitive. The
realignment does not affect the regulation of the Company by the Commission.
In addition to the realignment, the Company is re-evaluating its regulatory
strategy to pursue full cost recovery of certain deferred expenses which are
recorded as a regulatory asset. See Notes 1, 2, and 7 of Notes to Financial
Statements under Item 8, for a discussion of these regulatory assets.
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. The market-based rate 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.
6
Under the two transmission service tariffs that were approved by FERC,
utilities, independent power producers, and qualifying co-generation or small
power production facilities may obtain firm or coordination transmission
service from the Company. These tariffs provide open access to the Company's
transmission system and enable parties requesting either type of transmission
service to transmit wholesale power across the Company's system. However,
service under these tariffs is not available to ultimate consumers of
electric utility service.
In responding to competition in the gas distribution business, the Company
has upgraded gas storage facilities and invested in new equipment. By using
the 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 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, delays and
uncertainties in the regulatory process and costs of compliance with
environmental laws and regulations.
For the year ended December 31, 1993, 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 $)
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Electric Gas Combined % Combined
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Residential................. $195,273 $112,508 $307,781 44%
Commercial.................. 154,337 43,568 197,905 28
Industrial.................. 104,506 28,310 132,816 19
Public authorities.......... 52,183 13,846 66,029 9
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Total-ultimate consumers.. 506,299 198,232 704,531 100%
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Other utilities............. 58,959 - 58,959
Gas transportation-net...... - 5,147 5,147
Miscellaneous............... 4,952 1,536 6,488
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Total.................... $570,210 $204,915 $775,125
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See Note 10 of the Notes to Financial Statements under Item 8 for
financial information concerning segments of business for the three years
ended December 31, 1993.
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Electric Operations
The sources of electric operating revenues and the volumes of sales for
the three years ended December 31, 1993, were as follows:
1993 1992 1991
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ELECTRIC OPERATING REVENUES
(Thousands of $):
Residential........................ $195,273 $174,559 $193,923
Small commercial and industrial.... 70,106 66,183 68,332
Large commercial................... 84,231 80,041 81,171
Large industrial................... 104,506 101,699 102,558
Public authorities................. 52,183 49,599 51,390
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Total-ultimate consumers.......... 506,299 472,081 497,374
Other electric utilities........... 58,959 45,698 40,745
Miscellaneous...................... 4,952 3,890 4,296
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Total............................. $570,210 $521,669 $542,415
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ELECTRIC SALES (Thousands of kwh):
Residential.......................... 3,230,463 2,923,517 3,229,153
Small commercial and industrial...... 1,056,977 1,010,830 1,042,543
Large commercial..................... 1,696,686 1,624,441 1,650,894
Large industrial..................... 2,736,269 2,671,212 2,625,915
Public authorities................... 1,053,928 1,004,911 1,046,035
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Total-ultimate consumers............ 9,774,323 9,234,911 9,594,540
Other electric utilities............. 3,299,510 3,234,758 2,476,921
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Total............................... 13,073,833 12,469,669 12,071,461
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At December 31, 1993, the Company had 336,124 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 1993 was approximately .78
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
Fahrenheit (average for the day was 84 degrees Fahrenheit). 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 reliability criterion for generation capacity planning is to provide
a minimum reserve margin of 18%. At February 28, 1994, 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.
8
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 and East Kentucky have an agreement that allows East Kentucky
to purchase power during its peak season, that period during which the
utility's customers use the greatest amount of power, and the Company to sell
power during its off-peak season. The agreement entitles East Kentucky to
buy from the Company 30 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 $65 million since 1987 in
its investigation and research with regard to possible health effects posed
by exposure to electric and magnetic fields.
9
Gas Operations
The sources of gas operating revenues and the volumes of sales for the
three years ended December 31, 1993, were as follows:
1993 1992 1991
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GAS OPERATING REVENUES
(Thousands of $):
Residential........................ $112,508 $ 96,175 $ 92,142
Commercial......................... 43,568 36,801 34,913
Industrial......................... 28,310 26,156 18,683
Public authorities................. 13,846 13,884 13,107
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Total-ultimate consumers.......... 198,232 173,016 158,845
Gas transportation-net............. 5,147 4,169 5,886
Miscellaneous...................... 1,536 1,341 1,560
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Total............................. $204,915 $178,526 $166,291
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GAS SALES (Millions of cu. ft.):
Residential........................ 24,330 22,465 21,795
Commercial......................... 10,308 9,527 9,160
Industrial......................... 7,817 8,077 5,945
Public authorities................. 3,515 3,864 3,721
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Total-ultimate consumers.......... 45,970 43,933 40,621
Gas transported.................... 5,249 4,155 6,231
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Total............................. 51,219 48,088 46,852
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At December 31, 1993, the Company had 258,185 gas customers.
The Company has extensive underground natural gas storage fields that help
provide economical and reliable gas service to ultimate consumers.
Reflecting the changing nature of the gas business, a number of industrial
customers purchase their natural gas requirements directly from producers or
brokers for delivery through the Company's distribution system.
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. The 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
Fahrenheit. During 1993, the maximum day gas sendout was 447,000 Mcf,
occurring on February 18, when the average temperature for the day was
11 degrees Fahrenheit. Supply on that day consisted of 171,000 Mcf from
purchases, 238,000 Mcf delivered from underground storage, and 38,000 Mcf
transported for industrial customers. For further discussion, see Gas
Supply.
10
On November 1, 1993, the Company began purchasing and transporting its
natural gas supplies under the new requirements created by FERC Order No. 636
which was issued in 1992. 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 several other sources.
Throughout 1993, the Company undertook a review to evaluate and select the
pipeline services and gas supplies needed. As a result of this review, the
Company entered into several distinct transportation and purchase agreements.
The Company should benefit from FERC Order No. 636 through enhanced access
to competitively priced natural gas supplies as well as more flexible
transportation services. The Company has made the necessary modifications
to its operations and to its gas supply clause to reflect these Order No. 636
changes. (For further discussion see Gas Supply.)
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 the most recent rate order of the Kentucky Commission,
see Rates and Regulation under Item 7 and Note 8 of the 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.
11
In November 1993, the Commission approved a comprehensive agreement on
demand side management (DSM) programs. The agreement contains a rate
mechanism that provides for the recovery of DSM program costs, allows the
Company to recover revenues due to lost sales associated with the DSM
programs and provides the Company an incentive for implementing DSM programs.
See Rates and Regulation under Item 7 for a further discussion of DSM.
As part of the corporate reorganization whereby the Company became the
subsidiary of LG&E Energy Corp., the Company obtained the approval of the
Kentucky Commission. The order of the Kentucky Commission authorizing the
Company to reorganize into a holding company structure contains certain
provisions, which, among other things, ensure the Kentucky Commission access
to books and records of Energy Corp. and its affiliates which relate to
transactions with the Company; require Energy Corp. and its subsidiaries to
employ accounting and other procedures and controls to protect against
subsidization of non-utility activities by the Company's customers; and
preclude the Company from guaranteeing any obligations of Energy Corp.
without prior written consent from the Kentucky Commission. In addition,
such order provides that the Company's board of directors has the
responsibility to use its dividend policy consistent with preserving the
financial strength of the Company and that the Kentucky Commission, through
its authority over the Company's capital structure, can protect the Company's
ratepayers from the financial effects resulting from non-utility activities.
Construction Program and Financing
The Company's construction program is designed to assure that there will
be adequate capacity 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.
At December 31, 1993, the Company's embedded cost of long-term debt was
6.4% and its ratio of earnings to fixed charges was 3.87. See Exhibit 12.
For a further discussion of construction expenditures and financing, see
Construction Expenditures and Capitalization and Liquidity under Item 7.
During the five years ended December 31, 1993, gross property additions
amounted to $580 million. Funds for about 97% of these gross additions were
generated internally. The gross additions during this period amounted to
approximately 24% of total utility plant at December 31, 1993, and consisted
of $480 million for electric properties and $100 million for gas properties.
Gross retirements during the same period were $40 million, consisting of $29
million for electric properties and $11 million for gas properties.
12
Coal Supply
Ninety percent of the Company's present electric generating capacity is
coal-fired, the remainder being made up of a hydroelectric plant and
combustion turbine peaking units fueled by natural gas and oil. Coal will
be the predominant fuel used by the Company in the foreseeable future, with
natural gas and oil being used for peaking capacity and flame stabilization
in coal-fired boilers or in emergencies. The Company has no nuclear
generating units and has no plans to build any in the foreseeable future.
In 1992, the Company entered into coal supply agreements with various
suppliers for coal deliveries for 1993 and beyond. The Company normally
augments its coal supply agreements with spot market purchases which, during
1993, 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, 1993, a coal
inventory of approximately 433,000 tons, or a 28 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:
1993 1992 1991
---- ---- ----
Per ton.............................. $26.58 $25.17 $24.51
Per million Btu...................... 1.14 1.09 1.06
Gas Supply
During 1993, the Company continued to purchase natural gas from and
transport other natural gas supplies through Texas Gas at rates and terms
regulated by the FERC. The Company also continued purchasing a portion of
its natural gas supplies on the spot-market and transporting those supplies
under various transportation agreements with Texas Gas pursuant to applicable
FERC-approved tariffs. The Company received standby service from Texas Gas
until its implementation of FERC Order No. 636.
13
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, 1997. 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 2, 5, and 8 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.
Contemporaneously with the conclusion of its transportation arrangements
with Texas Gas, the Company 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 formerly supplied by the pipeline.
During 1994, the Company will be participating in several regulatory
proceedings at FERC. Particularly, 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 recovered as a gas cost through the Company's
purchased gas adjustment.
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 1992-1993 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 $2.91
in 1993, $2.77 in 1992, and $2.39 in 1991. Although upcoming regulatory
changes may alter the ways in which the Company contracts for natural gas
supplies, it is expected that the Company will continue to have adequate
access to natural gas supplies at market sensitive prices.
14
Environmental Matters
Protection of the environment is a major priority for the Company. The
Company engages in a variety of activities within the jurisdiction of
federal, state, and local regulatory agencies. Those agencies have issued
the Company permits for various activities subject to air quality, water
quality, and waste management laws and regulations. For the five year period
ending with 1993, expenditures for pollution control facilities represented
$128 million or 22% of total construction expenditures. The cost of operating
and maintaining these facilities amounted to $22 million in both 1993 and
1992. The Company's anticipated capital expenditures for 1994 to comply with
environmental laws are approximately $22 million. See Item 3 and Note 7 of
Notes to Financial Statements under Item 8 for a discussion of specific
environmental proceedings affecting the Company.
Labor Relations
The Company's 1,652 operating, maintenance and construction employees are
members of the International Brotherhood of Electrical Workers (IBEW) Local
2100. On May 31, 1992, the IBEW voted to ratify a new three-year collective
bargaining agreement. The new agreement became effective in November 1992
and will expire in November 1995.
Employees
The Company had 2,749 full-time employees at December 31, 1993. During
the last quarter of 1993 and early 1994, the Company eliminated a number of
full-time positions, and made early retirement available to a number of other
employees. See Note 2 of Notes to Financial Statements under Item 8 for a
further discussion of this matter.
15
ITEM 2. Properties.
- --------------------
At February 28, 1994, the Company owned and operated the following
electric generating stations:
Year in
Steam Stations: Service Capability Rating (Kw)
------- ----------------------
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.......................... 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 9 of the Notes to Financial Statements, Jointly Owned
Electric Utility Plant, under Item 8 for a discussion of the sale
of 25% of the Unit to IMEA and IMPA. The Company is responsible
for operation of the Unit and is reimbursed by IMEA and IMPA for
expenditures related to the Unit based on their proportionate
share of ownership interest.
The Company'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, 1993, the Company's electric transmission system included
20 substations with a total capacity of approximately 10,518,897 Kva and
approximately 645 structure miles of lines. The electric distribution system
included 84 substations with a total capacity of approximately 2,948,768 Kva,
3,499 structure miles of overhead lines, 231 miles of underground conduit,
and 5,170 miles of underground conductors.
16
The Company's gas transmission system includes 177 miles of transmission
mains, and the gas distribution system includes 3,226 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.
- ---------------------------
Rate Case and Trimble County Station
For a discussion of the most recent rate order of the Public Service
Commission of Kentucky and a detailed discussion of the orders of the
Kentucky Commission and rulings of the Franklin Circuit Court and the
Kentucky Court of Appeals concerning Trimble County Unit 1, see Item 7 and
Note 8 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
(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 in the process of reviewing the Company's plan, and is not expected
to issue its report and recommendations concerning the plan until late 1994
at the earliest. The Kentucky Commission's regulations do not require it to
hold any hearings or issue any formal orders regarding the Plan.
17
Environmental
The Clean Air Act Amendments of 1990 impose stringent limits on emissions
of sulfur dioxide and nitrogen oxides by electric utility generating plants.
This legislation is extremely complex and its effect will substantially
depend on regulations issued by the U.S. Environmental Protection Agency.
While the Company will incur some capital expenditures to comply with the
Act's requirements, the overall impact of the Act on the Company is expected
to be minimal. The Company is closely monitoring the continuing rule-making
process in order to assess the precise impact of the legislation on the
Company.
For a complete discussion of the Company's environmental issues concerning
its Mill Creek and Cane Run generating plants, manufacturing gas plant sites,
and certain other environmental issues, see Note 7 of the Notes to Financial
Statements under Item 8.
Based upon prior precedents established by the Kentucky Commission and the
Environmental Cost Recovery legislation, the Company expects to have an
opportunity to recover through future ratemaking proceedings, its costs
associated with remedial measures required to comply with environmental laws
and regulations.
Other
The Company is a defendant in lawsuits seeking compensatory and, in
certain instances, punitive damages for injuries purportedly incurred by
individuals coming into contact with the Company's electric or gas facilities
and/or services. 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.
18
ITEM 4. Submission of Matters to a Vote of Security Holders.
- -------------------------------------------------------------
None
Executive Officers of the Company.
Effective Date of Election
Name Age Position to Present Position
- ---- --- -------- --------------------------
Roger W. Hale 50 Chairman of the
Board and Chief
Executive Officer January 1, 1992
Victor A. Staffieri 38 President January 1, 1994
David R. Carey 40 Senior Vice
President,
Operations January 1, 1994
Raymond A. Bennett 60 Vice President,
Gas Service
Business January 1, 1994
M. Lee Fowler 57 Vice President
and Controller September 1, 1988
Wendy C. Heck 40 Vice President,
Information
Services January 1, 1994
Chris Hermann 46 Vice President
and General
Manager, Wholesale
Electric Business January 1, 1993
Charles A. Markel III 46 Treasurer January 1, 1993
19
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 May 24, 1994.
There are no family relationships between executive officers of the
Company.
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, 1989:
Ms. Heck was Manager-Internal Audit prior to January 1990, Vice
President-Internal Auditing prior to January 1, 1992, Vice President-Fuels
and Operating Services prior to January 1, 1993, and Vice President-Fuels and
Information Services thereafter; Mr. Hermann was Manager-Administration,
Power Production prior to November 1989, General Manager-Power Production
prior to January 1992 and General Manager-Wholesale Electric thereafter;
Mr. Markel was Vice President and Treasurer prior to March 1, 1990, Vice
President-Finance and Treasurer prior to January 1, 1992, and Senior Vice
President and Chief Financial Officer thereafter. Effective January 1, 1993,
Mr. Markel was named Corporate Vice President-Finance and Treasurer of the
parent company, LG&E Energy Corp.
Prior to election to his current position, Mr. Hale was Chairman of the
Board, President and Chief Executive Officer of the Company, and prior to
February 1, 1990, President and Chief Executive Officer. Prior to June 1,
1989, Mr. Hale was employed by BellSouth Enterprises, Inc. and held the
position of Executive Vice President.
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 15, 1992, Senior Vice President, General Counsel and Corporate
Secretary. Prior to March 15, 1992, Mr. Staffieri was employed by Long
Island Lighting Company and held the position of General Counsel and
Secretary from April 1989 to March 1992, and Deputy General Counsel prior to
April 1989.
Prior to election to his current position, Mr. Carey was Vice President
and General Manager, Retail Electric Business of the Company, prior to
January 1, 1993, Vice President-Marketing and General Manager, Electric
Service, prior to January 1, 1992, Vice President-Marketing and Planning, and
prior to July 14, 1990, Vice President-Marketing and Sales. Prior to January
1990, Mr. Carey was employed by AT&T General Business Systems and held the
position of Director-Strategic and Business Planning.
Prior to election to his current position, Mr. Bennett was Vice President
and General Manager, Gas Service Business of the Company, and prior to
January 1, 1992, General Manager, Gas Operations. Prior to May 1990,
Mr. Bennett was employed by the Railroad Commission of Texas and held the
position of Director of Transportation-Gas Utility Division.
20
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:
1993 1992
---- ----
(Thousands of $)
First Quarter................................ $17,000 $16,000
Second Quarter............................... 16,500 16,000
Third Quarter................................ 16,500 17,000
Fourth Quarter............................... 17,000 17,500
ITEM 6. Selected Financial Data.
- ---------------------------------
Years Ended December 31
(Thousands of $)
-----------------------------------------------------
1993 1992 1991 1990 1989
---- ---- ---- ---- ----
Operating Revenues.... $775,125 $700,195 $708,706 $698,758 $686,996
Net Operating Income.. 136,118 125,829 142,730 137,717 127,560
Net Income............ 90,535 73,793 94,643 101,686 76,091
Net Income Available
for Common Stock.... 84,554 66,620 85,179 92,221 66,625
Total Assets.......... 2,072,910 1,973,039 1,948,410 1,995,782 1,905,306
Long-Term Obligations
(including amounts
due within one
year)............... 662,800 686,262 687,662 688,250 629,500
ITEM 7. Management's Discussion and Analysis of Results of Operations and
Financial Condition.
- --------------------------------------------------------------------------
OVERVIEW
The Company's financial condition improved during 1993. Net income
increased $16.7 million or 23% over 1992 due primarily to higher electric
sales which resulted from the warmer summer weather experienced in 1993. The
Company also maintained its strong credit ratings throughout 1993.
21
Effective January 1, 1994, the Company's parent, LG&E Energy Corp.,
announced a major realignment of its business units to reflect its outlook
for rapidly emerging competition in all segments of the energy services
industry. In addition to the organizational change implemented by the
parent, the Company is presently re-evaluating its regulatory strategy to
pursue full cost recovery of certain deferred expenses which the Company has
recorded as regulatory assets. See Future Outlook for a further discussion
of this matter.
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 1993 and 1992 and should be read
in connection with the financial statements and notes thereto.
RESULTS OF OPERATIONS
Net Income Available for Common Stock
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.
The decrease in earnings for 1992 from 1991 resulted primarily from
decreased electric sales to residential customers as a result of the cooler
summer weather experienced in 1992, the gain recognized in 1991 on the sale
of a portion of the Trimble County plant to the Illinois Municipal Electric
Agency (IMEA), higher depreciation and operation expenses and decreased
interest earned on temporary cash investments. These decreases were
partially offset by favorable financing activities and decreased maintenance
expenses.
Rates and Regulation
The Company is subject to the jurisdiction of the Public Service
Commission of Kentucky (Commission) in virtually all matters related to
electric and gas utility regulation. The Company last filed for a rate
increase with the Commission in June 1990 based on the test-year ended
April 30, 1990. The request was for a general rate increase of $34.9 million
($31.0 million electric and $3.9 million gas). 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%.
22
On April 21, 1993, the Company, the Kentucky Attorney General, the
Jefferson County Attorney, and representatives of several customer-interest
groups filed with the Commission a request for approval of a comprehensive
agreement on demand side management (DSM) programs. 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. On November 12,
1993, the Commission approved the agreement.
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 will allow the Company to
recover a predetermined level of revenue per 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 agreed upon 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 recorded on the balance sheet and
deferred for future recovery from or return to customers.
As more fully discussed in Note 8 of Notes to Financial Statements under
Item 8, the Commission has set a procedural schedule to determine the
appropriate ratemaking treatment to exclude 25% of the Trimble County plant
from customer rates.
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 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.
23
Under the two transmission service tariffs that were approved by FERC,
utilities, independent power producers, and qualifying co-generation or small
power production facilities may obtain firm or coordination transmission
service from the Company. These tariffs provide open access to the Company's
transmission system and enable parties requesting either type of transmission
service to transmit wholesale power across the Company's system. However,
service under these tariffs is not available to ultimate consumers of
electric utility service.
Revenues
A comparison of operating revenues for the years 1993 and 1992 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 1993 1992 1993 1992
----- ---- ---- ---- ----
Sales to Ultimate Consumers:
Rate increases effective in 1991. $ - $ 748 $ - $ 173
Fuel and gas supply
adjustments, etc............... 6,832 313 19,479 1,044
Variation in sales volumes....... 27,385 (26,354) 5,736 12,954
------ ------ ------ ------
Total.......................... 34,217 (25,293) 25,215 14,171
Sales to other utilities........... 13,261 4,953 - -
Gas transportation-net............. - - 978 (1,717)
Other.............................. 1,063 (406) 196 (219)
------ ------ ------ -------
Total.......................... $48,541 $(20,746) $26,389 $12,235
------ ------ ------ ------
------ ------ ------ ------
Electric revenues increased in 1993 primarily because of the warmer summer
weather. Sales of electricity to other utilities 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 account for 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 may be reflected in the Company's rates, subject to the approval of
the Commission.
24
Fuel expenses increased in 1993 primarily because of an increase in
generation and the higher cost of coal purchased. The average delivered cost
per ton of coal purchased was $26.58 in 1993, $25.17 in 1992, and $24.51 in
1991.
The increase in power purchased expense reflects an increase in the
quantity of power purchased mainly because of wheeling arrangements with
other utilities.
Gas supply expenses increased in 1993 and 1992 largely because of an
increase in both the cost and the volume of gas purchased. The average unit
cost per Mcf of purchased gas was $2.91 in 1993, $2.77 in 1992, and $2.39 in
1991.
Other operation and maintenance expenses increased $7.4 million in 1993.
This increase is primarily attributable to increased expenses for the
operation and maintenance of electric generating plants and higher
administrative and general costs. The increase in 1992 over 1991 resulted
primarily from costs associated with legal settlements relating to personal
injury claims and storm damage expenses. General increases in labor and
material costs are also reflected in operation and maintenance expenses.
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 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 in February 1993. A decrease
in 1992 from 1991 resulted primarily from a $4.2 million after-tax gain
recorded in 1991 on the sale of a 12.12% ownership interest in Trimble County
to IMEA and decreased interest income of $1.1 million from temporary cash
investments.
Interest charges decreased in 1993 and 1992 primarily because of an
aggressive program to refinance at lower interest rates. The Company
refinanced approximately $205 million of its outstanding debt in 1993. The
embedded cost of long-term debt at December 31, 1993, was 6.4%; at
December 31, 1992, 7.0%.
Preferred dividends reflect the lower dividend rates that resulted from
the Company's refunding of the $25 million, $8.90 Series with a $5.875 Series
in May 1993. In February 1992, the Company refunded the $8.72 and $9.54
Series with $50 million of Auction Rate Series. The weighted average
preferred dividend rate at December 31, 1993, was 4.72%; at December 31,
1992, 5.36%.
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.
25
Reference is made to Note 2 of Notes to Financial Statements under Item 8
for a discussion of SFAS No. 112, Employers' Accounting for Post-Employment
Benefits which will be effective in 1994. Reference is also made to Notes 1
and 2 which refer to the adoption of SFAS No. 106, Employers' Accounting for
Post-Retirement Benefits Other Than Pensions and SFAS No. 109, Accounting for
Income Taxes.
LIQUIDITY AND CAPITAL RESOURCES
- -------------------------------
The Company's need for capital funds is primarily related to the
construction of plant and equipment necessary to meet electric and gas
customers' needs and protection of the environment.
The Company's capital needs, earnings and cash flow are somewhat dependent
on events beyond the Company's control, such as weather, regulatory actions,
the state of the economy, and changes in existing governmental and
environmental regulations. Based on current conditions, the Company expects
to have sufficient cash flow and the ability to raise sufficient capital in
1994 and 1995 to meet its capital requirements and operating expenses.
Construction Expenditures
New construction expenditures for 1993 were $99 million compared with $101
million in 1992 and $88 million in 1991. Internally generated funds provided
for 100% of the construction expenditures in 1993, 87% in 1992, and 100% in
1991.
Construction expenditures for the calendar years 1994 and 1995 are
estimated to total approximately $200 million. The Company presently expects
to fund its construction expenditures for the two years mainly from internal
cash generation.
Capitalization and Liquidity
The Company maintains a strong capital structure. Reference is made to
Notes 4 and 5 of Notes to Financial Statements under Item 8 for a discussion
of preferred stock and long-term debt refinancings during the year which have
produced significant savings from lower interest and preferred dividend
rates.
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. At December 31,
1993, the rate on the JJ Kenny index was 3.25%.
At December 31, 1993, the Company had unused lines of credit of $145
million for which it pays commitment fees. The lines are scheduled to expire
at various periods during 1994 and the Company intends to renegotiate such
lines when they expire.
26
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.
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 construction
program, the Company anticipates incurring capital expenditures during the
next four years of approximately $40 million 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 7 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 generating
plants, manufactured gas plant sites, and certain other environmental issues.
Based upon prior precedents established by the Commission and the
Environmental Cost Recovery legislation, the Company expects to have an
opportunity to recover through future ratemaking proceedings, its costs
associated with remedial measures required to comply with environmental laws
and regulations.
Energy Policy Act of 1992
The Energy Policy Act of 1992 (EPA92), passed by Congress and signed into
law on October 24, 1992, outlines standards for utility industry structure,
competition in wholesale power generation and energy conservation. It
represents a thorough overhaul of legislation and related regulations that,
for the most part, have guided the industry since the 1930s -- the Public
Utility Holding Company Act (PUHCA) and the Federal Power Act.
EPA92 eliminates the statutory barriers to increased participation by
non-utility generators in wholesale power markets. PUHCA was amended to
allow qualifying non-utility generators (called "Exempt Wholesale
Generators") to operate without the Act's restrictions and to permit
utilities subject to PUHCA to invest in non-utility generators. The
legislation grants FERC authority to order transmission access and directs
FERC to use certain guidelines in establishing transmission rates. The
transmission tariffs that FERC approved for the Company provide the type of
open access mandated in EPA92.
27
The Act 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. Although the Company cannot
predict the exact impact of this legislation, the Company is planning to be
a competitive supplier of electric energy.
FERC Order No. 636
On November 1, 1993, the Company began purchasing and transporting its
natural gas supplies under the new requirements created by FERC Order No. 636
issued in 1992. Whereas 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 several other sources.
Throughout 1993, the Company undertook a review to evaluate and select the
pipeline services and gas supplies needed. As a result of this review, the
Company entered into the appropriate transportation and purchase agreements.
The Company should benefit from Order No. 636 through enhanced access to
competitively priced natural gas supplies as well as more flexible
transportation services. The Company has made the necessary modifications
to its operations and to its gas supply clause to reflect these Order No. 636
changes.
Certain aspects of Order No. 636 have yet to be resolved by the courts,
and still others await resolution at FERC. Issues still to be resolved at
FERC include the determination and recovery of pipeline costs associated with
the transition to and implementation of Order No. 636. Based on pipeline
filings to date, the Company estimates that its share of transition costs,
which must be approved by FERC, will be approximately $2 million to $3
million a year for both 1994 and 1995. 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 identified as being
related to the cost of the commodity itself, are appropriate to be recovered
from customers through the gas supply clause.
FUTURE OUTLOOK
Work Force Reduction
In the fourth quarter of 1993, the Company announced it was reducing its
construction, warehouse, and janitorial work force primarily because no new
major construction projects are expected in the near future. The Company
also offered voluntary separation, primarily through early retirement, to
various other employees. This reduction in work force of about 350 employees
is projected to cost approximately $11.5 million. The Company will realize
significant savings in future years as a result of this work force reduction.
28
Business Realignment
In November 1993, LG&E Energy Corp. announced a major realignment and
formation of new business units, effective January 1, 1994, to reflect its
outlook for rapidly emerging competition in all segments of the energy
service industry. The realignment does not affect the regulation of the
Company by the Commission.
Under the realignment, LG&E Energy Corp. is forming a national business
unit, LG&E Energy Services, 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 will allow the Company to increase its focus on customer service
and to develop more customer options as the local utility industry becomes
more competitive in the future.
Other
In addition to the business realignment mentioned above, the Company is
currently in the process of re-evaluating its regulatory strategy to pursue
full cost recovery of certain deferred expenses which are recorded as
regulatory assets. Depending on the results of this re-evaluation, which
should be completed in early 1994, all or part of such regulatory assets may
be immediately expensed. See Notes 1, 2, and 7 of Notes to Financial
Statements under Item 8 for a discussion of these regulatory assets.
The Board of Directors of the Company recently approved the formation of
a tax-exempt charitable foundation which will make local, regional, and
national charitable contributions to qualified persons and entities. The
Board has authorized an initial contribution to the foundation of up to $15
million. The effect of this contribution will be an after-tax charge against
income of up to $9 million for the first quarter of 1994. The Company
believes this action to be beneficial because it will provide a vehicle to
make contributions in support of community needs on a consistent basis. It
will also reduce charges against income in future years as contributions will
be made by the foundation, rather than directly by the Company. The Company
anticipates that funding will occur following the receipt of exempt status
for the foundation under the Internal Revenue Code.
29
Item 8. Financial Statements and Supplementary Data
- ---------------------------------------------------
LOUISVILLE GAS AND ELECTRIC COMPANY
STATEMENTS OF INCOME
(Thousands of $)
Years Ended December 31
------------------------------
1993 1992 1991
---- ---- ----
Operating Revenues
Electric................................. $570,210 $521,669 $542,415
Gas...................................... 204,915 178,526 166,291
------- ------- -------
Total operating revenues (Note 1)...... 775,125 700,195 708,706
------- ------- -------
Operating Expenses
Fuel for electric generation............. 149,436 132,551 132,392
Power purchased.......................... 17,228 12,044 11,478
Gas supply expenses...................... 139,054 115,521 104,212
Other operation expenses................. 136,693 130,740 126,842
Maintenance.............................. 48,414 46,931 49,079
Depreciation and amortization............ 79,655 76,903 73,273
Federal and State income
taxes (Note 3)......................... 52,334 43,840 53,195
Property and other taxes................. 16,193 15,836 15,505
------- ------- -------
Total operating expenses............... 639,007 574,366 565,976
------- ------- -------
Net Operating Income....................... 136,118 125,829 142,730
Other Income and (Deductions).............. 1,913 (2,203) 4,593
------- ------- -------
Income before Interest Charges............. 138,031 123,626 147,323
Interest Charges........................... 47,496 49,833 52,680
------- ------- -------
Net Income................................. 90,535 73,793 94,643
Preferred Stock Dividends.................. 5,981 7,173 9,464
------- ------- -------
Net Income Available for Common Stock...... $ 84,554 $ 66,620 $ 85,179
------- ------- -------
------- ------- -------
The accompanying notes are an integral part of these financial statements.
30
LOUISVILLE GAS AND ELECTRIC COMPANY
STATEMENTS OF RETAINED EARNINGS
(Thousands of $)
Years Ended December 31
------------------------------
1993 1992 1991
---- ---- ----
Balance January 1.......................... $178,667 $181,694 $219,515
Add net income............................. 90,535 73,793 94,643
------- ------- -------
269,202 255,487 314,158
------- ------- -------
Deduct: Cash dividends declared on stock:
5% cumulative preferred........... 1,075 1,076 1,076
7.45% cumulative preferred........ 1,598 1,598 1,598
$8.72 cumulative preferred........ - 454 2,180
$8.90 cumulative preferred........ 1,113 2,225 2,225
$9.54 cumulative preferred........ - 497 2,385
Auction rate cumulative preferred. 1,322 1,323 -
$5.875 cumulative preferred....... 873 - -
Common............................ 67,500 67,500 123,000
Preferred stock redemption expense. 818 2,147 -
------- ------- -------
74,299 76,820 132,464
------- ------- -------
Balance December 31........................ $194,903 $178,667 $181,694
------- ------- -------
------- ------- -------
The accompanying notes are an integral part of these financial statements.
31
LOUISVILLE GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Thousands of $)
ASSETS
December 31
-----------------------------
1993 1992
---- ----
Utility Plant, at original cost
Electric................................... $2,019,139 $1,976,206
Gas........................................ 260,485 240,818
Common..................................... 132,692 121,105
--------- ---------
2,412,316 2,338,129
Less: Reserve for depreciation............ 823,141 754,429
--------- ---------
1,589,175 1,583,700
Construction work in progress.............. 51,785 35,367
--------- ---------
1,640,960 1,619,067
--------- ---------
Other Property and Investments -
less reserve (Note 1)...................... 22,067 98,832
--------- ---------
Current Assets
Cash and temporary cash investments........ 44,105 946
Accounts receivable - less reserve of
$1,474 in 1993 and $1,109 in 1992........ 104,397 92,719
Materials and supplies - at average cost
Fuel (predominantly coal)................ 12,075 21,360
Gas stored underground................... 33,370 34,079
Other.................................... 40,357 41,034
Prepayments................................ 360 467
--------- ---------
234,664 190,605
--------- ---------
Deferred Debits and Other Assets
Unamortized debt expense................... 24,698 17,282
Accumulated deferred income taxes (Notes 1
and 3)................................... 58,675 12,179
Regulatory asset-income taxes (Note 1)..... 39,651 -
Other...................................... 52,195 35,074
--------- ---------
175,219 64,535
--------- ---------
$2,072,910 $1,973,039
--------- ---------
--------- ---------
The accompanying notes are an integral part of these financial statements.
32
LOUISVILLE GAS AND ELECTRIC COMPANY
CAPITAL AND LIABILITIES
(Thousands of $)
December 31
-----------------------------
1993 1992
---- ----
Capitalization (see Statements
of Capitalization)
Common equity.............................. $ 619,237 $ 603,001
Cumulative preferred stock................. 116,716 116,740
Long-term debt............................. 662,879 686,119
--------- ---------
1,398,832 1,405,860
--------- ---------
Current Liabilities
Long-term debt due within one year......... - 400
Notes payable (Note 6)..................... - 8,000
Accounts payable........................... 93,551 72,452
Dividends declared......................... 18,878 18,522
Accrued taxes.............................. 9,494 7,151
Accrued interest........................... 12,864 12,107
Other...................................... 11,127 11,494
--------- ---------
145,914 130,126
--------- ---------
Deferred Credits and Other Credits
Accumulated deferred income taxes (Notes 1
and 3)................................... 340,235 295,677
Investment tax credit,
in process of amortization............... 91,572 104,623
Customers' advances for construction....... 7,384 6,849
Regulatory liability-income taxes (Note 1). 46,528 -
Other...................................... 42,445 29,904
--------- ---------
528,164 437,053
--------- ---------
Commitments and Contingencies (Notes 7 and 8)
$2,072,910 $1,973,039
--------- ---------
--------- ---------
The accompanying notes are an integral part of these financial statements.
33
LOUISVILLE GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(Thousands of $)
Years Ended December 31
--------------------------------
1993 1992 1991
---- ---- ----
Cash Flows from Operating Activities
Net income............................. $ 90,535 $ 73,793 $ 94,643
Items not requiring cash currently:
Depreciation and amortization........ 79,887 79,686 76,431
Deferred income taxes - net.......... 4,938 28,911 23,292
Investment tax credit - net.......... (7,821) (5,033) (11,472)
Gain on sale of capital asset........ (3,869) - (7,908)
Other................................ 5,877 3,768 3,548
(Increase) decrease in certain net
current assets:
Accounts receivable.................. (11,678) (7,494) (4,629)
Materials and supplies............... 10,671 (8,014) 5,390
Accounts payable..................... 21,099 4,546 (2,963)
Accrued taxes........................ 2,343 1,967 (6,353)
Accrued interest..................... 757 (1,716) 471
Prepayments and other................ (260) 538 71
Other.................................. (15,587) (11,321) (1,928)
------- ------- -------
Net cash provided from
operating activities............... 176,892 159,631 168,593
------- ------- -------
Cash Flows from Investing Activities
Sale of capital asset.................. 91,076 - 94,164
Long-term investment in securities..... (11,097) (10,441) -
Construction expenditures.............. (98,787) (101,175) (88,052)
------- ------- -------
Net cash provided from (used for)
investing activities............... (18,808) (111,616) 6,112
------- ------- -------
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 4,233
Redemption of preferred stock.......... (25,558) (51,443) -
Retirement of first mortgage bonds
and pollution control bonds.......... (231,876) (92,400) (5,088)
Decrease in notes payable.............. (8,000) (4,000) (13,000)
Payment of dividends................... (73,125) (74,517) (131,662)
------- ------- -------
Net cash used for financing
activities......................... (114,925) (84,799) (145,517)
------- ------- -------
The accompanying notes are an integral part of these financial statements.
34
LOUISVILLE GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(Thousands of $)
Years Ended December 31
--------------------------------
1993 1992 1991
---- ---- ----
Net Increase (Decrease) in Cash and
Temporary Cash Investments............. $ 43,159 $(36,784) $ 29,188
Cash and Temporary Cash Investments at
Beginning of Year...................... 946 37,730 8,542
------- ------- -------
Cash and Temporary Cash Investments at
End of Year............................ $ 44,105 $ 946 $ 37,730
------- ------- -------
------- ------- -------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year for:
Income taxes......................... $ 54,686 $ 19,741 $ 46,481
Interest on borrowed money........... 45,360 50,508 50,744
The accompanying notes are an integral part of these financial statements.
35
LOUISVILLE GAS AND ELECTRIC COMPANY
STATEMENTS OF CAPITALIZATION
(Thousands of $)
December 31
-----------------------------
1993 1992
---- ----
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)
Retained earnings......................... 194,903 178,667
--------- ---------
$ 619,237 $ 603,001
--------- ---------
Cumulative Preferred Stock (Note 4)
Redeemable on 30 days notice by the Company
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 -
$8.90 series..... - - - 25,000
Auction Rate..... 500,000 100.00 50,000 50,000
$5.875 series.... 250,000 Not Redeemable 25,000 -
Preferred stock expense..................... (1,244) (1,220)
--------- ---------
$ 116,716 $ 116,740
--------- ---------
The accompanying notes are an integral part of these financial statements.
36
LOUISVILLE GAS AND ELECTRIC COMPANY
STATEMENTS OF CAPITALIZATION
(Thousands of $)
December 31
-----------------------------
1993 1992
---- ----
Long-Term Debt (Note 5)
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 August 1, 2001, 8 1/4%....... - 19,700
Series due July 1, 2002, 7 1/2%......... 20,000 20,000
Series due August 15, 2003, 6%.......... 42,600 -
Series due November 1, 2006, 8 1/2%..... - 21,362
Pollution control series:
B due September 1, 2006, 6 1/8%....... - 35,200
C due June 1, 1998, 6 1/8%............ - 7,000
C due June 1, 2008, 6 3/8%............ - 35,000
D due October 1, 2004, 6.6%........... - 20,000
D due October 1, 2009, 6.7%........... - 40,000
I due February 15, 2011, 9 3/4%....... - 26,000
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%........ 83,335 100,000
R due November 1, 2020, 6.55%......... 41,665 50,000
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 -
V due August 15, 2019, 5 5/8%......... 102,000 -
W due October 15, 2020, 5.45%......... 26,000 -
--------- ---------
Total bonds outstanding................. 662,800 686,262
Less long-term debt due within one year. - 400
--------- ---------
Long-term first mortgage bonds.......... 662,800 685,862
Unamortized premium on bonds.............. 79 257
--------- ---------
662,879 686,119
--------- ---------
Total Capitalization........................ $1,398,832 $1,405,860
--------- ---------
--------- ---------
The accompanying notes are an integral part of these financial statements.
37
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. All of the Company's Common Stock
is held by LG&E Energy Corp.
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 Public Service Commission of Kentucky
(Commission). The Company is subject to Statement of Financial Accounting
Standards No. 71, Accounting for the Effects of Certain Types of Regulation.
The Company has recorded certain regulatory assets at December 31, 1993,
totaling approximately $31 million. See Note 2, Post-Retirement Benefits and
Early Retirement/Work Force Reduction, and Note 7, Environmental, for a
discussion of these regulatory assets. See Future Outlook under Item 7,
Management's Discussion and Analysis, for a discussion of the Company's
re-evaluation of its current regulatory strategy in regards to these assets.
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.
In December 1990, the 25% portion of the construction costs of the Trimble
County Generating Station (Trimble County), which the Commission disallowed
in setting customer rates, was reclassified from the Utility Plant section
on the balance sheet to Other Property and Investments. In February 1991,
the Company sold a 12.12% undivided interest in Trimble County to the
Illinois Municipal Electric Agency (IMEA). In February 1993, the remaining
12.88% of Trimble County not allowed in rates was sold to the Indiana
Municipal Power Agency (IMPA). See Notes 8 and 9, Trimble County Generating
Plant and Jointly Owned Electric Utility Plant, respectively, for a further
discussion.
38
Depreciation. Depreciation is provided on the straight-line method over the
estimated service lives of depreciable plant. The amounts provided for 1993
were approximately 3.3% (3.2% electric, 3.2% gas, and 5% common); for 1992,
3.3% (3.2% electric, 3.2% gas, and 5.4% common); and for 1991, 3.3% (3.2%
electric, 3% gas, and 6.3% 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.
The Company adopted Statement of Financial Accounting Standards (SFAS)
No. 109, Accounting for Income Taxes, effective January 1, 1993. SFAS No.
109 adopts the liability method of accounting for income taxes, requiring
deferred income tax assets and liabilities to be computed using tax rates
that will be in effect when the book and tax temporary differences reverse.
For the Company, the change in tax rates applied to accumulated deferred
income taxes was not immediately recognized in operating results because of
ratemaking treatment. At December 31, 1993, the deferred tax asset, which
resulted primarily from unamortized investment tax credits, amounted to
approximately $47 million. The deferred tax liability, which resulted
primarily from book/tax utility property basis differences, totaled
approximately $40 million. Regulatory assets and liabilities were
established to recognize the future revenue requirement impact from these
deferred taxes. The adoption of SFAS No. 109 did not have a material impact
on the results of operations or financial position. The deferred tax
balances and related regulatory assets and liabilities have been adjusted to
reflect the increase in the corporate income tax rate from 34% to 35%.
Investment Tax Credits. Investment tax credits resulted from provisions of
the tax law which 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. See Management's Discussion and Analysis, Rates and
Regulation, under Item 7, for changes in recording residential revenues
effective January 1, 1994.
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.
39
Revenues and Customer Receivables. The Company is an operating public
utility that supplies natural gas to approximately 258,000 customers and
electricity to approximately 336,000 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, 1993, 74% of total
operating revenues was derived from electric operations and 26% from gas
operations.
Fair Value of Financial Instruments. Pursuant to the Financial Accounting
Standards Board SFAS No. 107, Disclosures about Fair Value of Financial
Instruments, the Company is required to disclose the fair value of financial
instruments where practicable.
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 cost and estimated fair value of the Company's financial instruments as
of December 31, 1993 and 1992, are as follows (in thousands of $):
1993 1992
------------------ ------------------
Fair Fair
Cost Value Cost Value
---- ----- ---- -----
Long-term investments:
Practicable to estimate
fair value................. $ 21,538 $ 21,538 $ 10,441 $ 10,441
Not practicable.............. 490 490 557 557
Preferred stock subject to
mandatory redemption......... 25,000 24,750 - -
Long-term debt................. 662,800 706,078 686,262 726,801
Note 2 - 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.
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.
40
Pension cost was $2,669,000 for 1993, $2,598,000 for 1992, and $2,245,000 for
1991, of which approximately $425,000, $241,000, and $306,000, respectively,
were charged to construction. The components of periodic pension expense are
shown below (in thousands of $):
1993 1992 1991
---- ---- ----
Service cost-benefits earned
during the period.................. $ 4,516 $ 5,459 $ 4,098
Interest cost on projected
benefit obligation................. 12,117 11,006 9,340
Actual return on plan assets......... (13,602) (8,850) (26,805)
Amortization of transition asset..... (1,112) (1,076) (1,076)
Net amortization and deferral........ 750 (3,941) 16,688
------ ------ ------
Net pension cost..................... $ 2,669 $ 2,598 $ 2,245
------ ------ ------
------ ------ ------
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 $):
1993 1992
---- ----
Actuarial present value of accumulated plan benefits:
Vested.............................................. $137,655 $102,980
Non-Vested.......................................... 17,158 12,900
------- -------
Accumulated benefit obligation...................... 154,813 115,880
Effect of projected future compensation............. 25,234 31,336
------- -------
Projected benefit obligation........................ 180,047 147,216
Plan assets at fair value........................... 165,088 155,937
------- -------
Plan assets (less than) in excess of
projected benefit obligation...................... (14,959) 8,721
Unrecognized net transition asset................... (13,636) (14,403)
Unrecognized prior service cost..................... 28,671 25,863
Unrecognized net gain............................... (23,860) (41,703)
------- -------
Accrued pension liability............................. $(23,784) $(21,522)
------- -------
------- -------
The projected benefit obligation was determined using an assumed discount
rate of 7.5% for 1993 and 8.5% for 1992. An assumed annual rate of increase
in future compensation levels ranged from 3.5% to 4.5% for 1993 and 3.5% to
6.5% for 1992. The assumed long-term rate of return on plan assets was 8.5%
for both periods. Transition assets and prior service costs are being
amortized over the average remaining service period of active participants.
41
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) 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. Beginning in 1993, the Company began to account for
post-retirement benefits according to the provisions of SFAS No. 106.
The Company, based on an order from the Commission, has created a regulatory
asset and is deferring the level of SFAS No. 106 expense in excess of the
previous level of pay-as-you-go expense. The Commission's generic order
stated that the proper level of expense for SFAS No. 106 would be determined
in each utility's next general rate case.
The components of the net periodic post-retirement benefit cost for 1993 as
calculated under SFAS No. 106 are as follows (in thousands of $):
Service cost .............................................. $ 701
Interest cost.............................................. 2,614
Amortization of transition obligation...................... 1,395
------
Post-retirement benefit cost............................... $ 4,710
------
------
The accumulated post-retirement benefit obligation as calculated under SFAS
No. 106 at December 31, 1993, is shown below (in thousands of $):
Retirees................................................... $(17,826)
Fully eligible active employees............................ (4,001)
Other active employees..................................... (15,945)
------
Accumulated post-retirement benefit obligation............. (37,772)
Unrecognized net loss...................................... 4,966
Unrecognized transition obligation......................... 26,508
Previously recognized amount............................... 3,696
------
Accrued post-retirement benefit liability.................. $ (2,602)
------
------
The annual service cost was calculated using an assumed discount rate of 8.5%
at January 1, 1993, and 7.5% at December 31, 1993. A medical cost increase
factor that ranged between 6% and 11% was also used.
42
A 1% increase in the health care cost trend rate would increase the
Accumulated Post-Retirement Benefit Obligation by approximately $1.8 million
and the annual service and interest cost by approximately $200,000. No
funding has been established by the Company for post-retirement benefits.
Post-Employment Benefits. The Financial Accounting Standards Board issued
SFAS No. 112, Employers' Accounting for Post-Employment Benefits, which
requires the accrual of the expected cost of benefits to former or inactive
employees after employment but before retirement. The Company adopted the
new standard effective January 1, 1994, as required. Adoption of SFAS
No. 112 will not have a material adverse impact on the financial position or
results of operation of the Company.
Early Retirement/Work Force Reduction. During the last quarter of 1993 and
early 1994, the Company eliminated approximately 350 full-time positions.
The cost of the employee reduction program, approximately $11.5 million,
consists primarily of separation payments, enhanced early retirement
benefits, and health care benefits.
In 1992, an early retirement program was made available to all the 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 post-retirement 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 $1,795,000 for 1993, $767,000 for 1992, and $584,000 for
1991. The increase in 1993 401(k) expenses is due to the expansion of the
program to the Company's union employees.
43
Note 3 - Federal and State Income Taxes
- ---------------------------------------
Components of income tax expense are shown in the table below (in thousands
of $):
1993 1992 1991
---- ---- ----
Included in Operating:
Current - Federal.................... $31,082 $20,756 $33,727
- State...................... 8,920 6,354 8,126
Deferred - Federal-net................ 13,185 15,771 16,642
- State-net.................. 3,933 5,774 5,939
Deferred investment tax credit........ - - (6,385)
Amortization of investment tax credit. (4,786) (4,815) (4,854)
------ ------ ------
Total............................... $52,334 $43,840 $53,195
------ ------ ------
Included in Other Income and (Deductions):
Current - Federal.................... $11,009 $(6,971) $ 1,763
- State...................... 4,034 (3,214) 299
Deferred - Federal-net................ (8,473) 4,670 565
- State-net.................. (3,707) 2,696 146
Deferred investment tax credit........ - 390 26
Amortization of investment tax credit. (3,035) (608) (259)
------ ------ ------
Total............................... $ (172) $(3,037) $ 2,540
------ ------ ------
Total Income Tax Expense................ $52,162 $40,803 $55,735
------ ------ ------
------ ------ ------
Variations in the 1993 income tax expense from 1992 and 1991 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.
Provisions for deferred income taxes consist of the tax effects of the
following temporary differences (in thousands of $):
1993 1992 1991
---- ---- ----
Depreciation and amortization........... $ (255) $33,839 $23,440
Alternative minimum tax................. 5,387 (5,387) -
Other................................... (194) 459 (148)
----- ------ ------
Total................................. $4,938 $28,911 $23,292
----- ------ ------
----- ------ ------
44
Depreciation and amortization fluctuations for 1993 are primarily
attributable to the reversal of prior years' accumulated taxes as a result
of the sale of a portion of Trimble County Unit 1 to IMPA. See Note 8,
Trimble County Generating Plant, for a further discussion of the sale.
The following are the tax effects of book-tax temporary differences resulting
in deferred tax assets and liabilities as of December 31, 1993 (in thousands
of $):
Deferred Tax Assets:
Investment tax credit................................. $ 36,961
Income taxes due to customers......................... 14,361
Other assets.......................................... 7,353
-------
$ 58,675
-------
-------
Deferred Tax Liabilities:
Depreciation and other plant related items............ $322,544
Income taxes due from customers....................... 10,233
Other liabilities..................................... 7,458
-------
$340,235
-------
-------
The Company's effective income tax rate is computed by dividing the aggregate
of current income taxes, deferred income taxes-net, and the investment tax
credit-net, 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:
1993 1992 1991
---- ---- ----
Statutory Federal income tax rate........ 35.0% 34.0% 34.0%
State income taxes net of Federal benefit. 6.0 6.7 6.4
Amortization of investment tax credit..... (5.5) (4.7) (3.4)
Other differences-net..................... 1.1 (.4) .1
---- ---- ----
Effective Income Tax Rate................. 36.6% 35.6% 37.1%
---- ---- ----
---- ---- ----
Note 4 - Preferred Stock
- ------------------------
In May 1993, the Company issued $25 million of $5.875 Cumulative Preferred
Stock. The proceeds from the sale were used to redeem the outstanding $8.90
Cumulative Preferred Stock.
45
Note 5 - First Mortgage Bonds
- -----------------------------
Annual requirements for the sinking funds of the Company's First Mortgage
Bonds (other than the First Mortgage Bonds issued in connection with the
Pollution Control Bonds) are the amounts necessary to redeem 1% of the
highest principal amount of each series of bonds at any time outstanding.
Property additions (166 2/3% of principal amounts of bonds otherwise required
to be so redeemed) have been applied in lieu of cash. It is the intent of
the Company to apply property additions to meet 1994 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, the Company issued two separate series of Pollution
Control Bonds (a $35.2 million, Variable Rate Series, which had an interest
rate of 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, 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, the Company issued $26 million of Pollution Control Bonds, 5.45%
Series and redeemed the $26 million, 9.75% Series.
The Company also 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 5.9% rate. 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.
46
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. At December 31,
1993, the rate on the JJ Kenny index was 3.25%.
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, 1993.
Note 6 - Notes Payable
- ----------------------
The Company had no notes payable at December 31, 1993. At December 31, 1992,
trust demand notes amounted to $8 million on which the composite interest
rate was 3.45%.
At December 31, 1993, 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 1994. Management intends to renegotiate these
lines when they expire.
Note 7 - Commitments and Contingencies
- --------------------------------------
Construction Program. The Company had commitments, primarily in connection
with its construction program, aggregating approximately $6 million at
December 31, 1993. Construction expenditures for the calendar years 1994 and
1995 are estimated to total approximately $200 million.
FERC Order No. 636. Order No. 636, which was issued by FERC in 1992,
required the Company and all other local distribution companies to revise
their practices for purchasing and transporting gas. 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. Based on pipeline filings to date, the Company
estimates that its share of transition costs, which must be approved by FERC,
will be approximately $2 million to $3 million a year for both 1994 and 1995.
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.
47
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 1993, 1992, and 1991 was $2,436,000,
$2,478,000, and $2,471,000, respectively. The future minimum annual lease
payments under the lease agreement for years subsequent to December 31, 1993,
are as follows (in thousands of $):
1994.............................. $ 2,148
1995.............................. 2,499
1996.............................. 2,850
1997.............................. 2,850
1998.............................. 2,850
Thereafter........................ 21,810
------
Total.......................... $35,007
------
------
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 anticipates
incurring capital expenditures during the next four years of approximately
$40 million 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
excess sulfur dioxide emissions from its Mill Creek generating plant. The
Company is currently conducting work in compliance with the agreed-upon
schedule for remedial measures and has incurred total capital expenditures
of approximately $24 million through 1993. Based on current remedial
designs, the Company anticipates incurring additional capital costs of
approximately $14 million for this project in 1994 as part of its ongoing
capital construction program.
48
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. The Company currently estimates that property damage claims for
the particulate emissions should be settled for an aggregate amount of
approximately $12 million. Accordingly, the Company has recorded an accrual
of this amount. In August 1993, 34 persons filed a complaint in Jefferson
Circuit Court against the Company in which they are seeking certification of
a class consisting of all persons within 2.5 miles of the Mill Creek plant.
The court has not acted on the request for certification of a class. The
plaintiffs seek compensation for alleged personal injury and property damage
attributable to the particulate emissions from the Mill Creek plant,
injunctive relief, a fund to finance future medical monitoring of area
residents, and other relief. The Company intends to vigorously defend itself
in the pending litigation.
In response to a notification from the APCD that the Company's Cane Run plant
may be the source of a potential exceedance of the National Ambient Air
Quality Standards for sulfur dioxide, the Company retained a contractor to
conduct certain air dispersion modeling. In 1992, the Company submitted a
draft action plan and modeling schedule to the APCD and USEPA. The APCD and
USEPA have approved the submittals and the Company's contractor is currently
conducting additional modeling activities. Although it is expected that
corrective action will be accomplished through capital improvements, until
the contractor completes its modeling activities, the Company cannot
determine the precise impact of this matter.
The Company owns or formerly owned three primary sites where manufactured gas
plant operations were 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 commenced site investigations at the two Company owned sites to
determine if significant levels of contaminants are present. The Company has
commenced discussions with the current owner of the third site regarding
joint performance of a site investigation. The Company anticipates spending
a total of approximately $1.3 million on site investigations expected to be
completed by 1995. Preliminary testing at all three sites has identified
contaminants typical of manufactured gas plant operations. Until an
investigation and associated regulatory review is completed for each site,
the Company will be unable to predict what, if any, cleanup activities may
be necessary.
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 for contributions 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 preliminary discussions
with the third-party plaintiffs. In the Company's opinion, the resolution
of the issue will not have a material adverse impact on its financial
position or results of operations.
49
In February 1993, the Company was served with an amended complaint filed in
federal district court in West Virginia by three potentially responsible
parties (PRPs) against the Company and 39 other parties. The plaintiffs
alleged that the parties were liable under CERCLA for in excess of $3 million
in costs allegedly incurred by the plaintiffs in conducting cleanup
activities at the Spencer Transformer Site located in Roane County, West
Virginia. In November 1993, the federal court approved a consent decree that
resolved the case as to the Company and nine other de minimis parties. Under
the terms of the consent decree, the Company reimbursed the plaintiffs for
$10,000 in cleanup costs. No further involvement of the Company is
anticipated.
In June 1992, USEPA identified the Company as a 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. In November 1992, USEPA demanded immediate payment from the PRPs.
To date, USEPA has identified nine PRPs for the site. The Company and
several other parties have commenced discussions with USEPA. 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 contributions 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.
Based upon prior precedents established by the Commission and the
Environmental Cost Recovery legislation, the Company expects to have an
opportunity to recover, through future ratemaking proceedings, its costs
associated with remedial measures required to comply with environmental laws
and regulations.
Charitable Foundation. The Board of Directors of the Company has approved
the formation of a tax-exempt charitable foundation with an initial
contribution of up to $15 million. See Future Outlook under Item 7,
Management's Discussion and Analysis, for a further discussion of this
matter.
Note 8 - Trimble County Generating Plant
- ----------------------------------------
Trimble County Unit 1, a 495-megawatt, coal-fired electric generating unit,
was placed in commercial operation on December 23, 1990.
50
This Unit, which during its first three years of commercial operations has
operated more reliably than projected, has been the subject of numerous
regulatory and legal proceedings. The current regulatory process involving
Trimble County is related to an order issued by the Commission on July 1,
1988, which stated that 25% of the total cost of the Unit would not be
allowed for ratemaking purposes. In a rehearing order issued in April 1989,
the Commission reaffirmed its decision that the Company would not be allowed
to include 25% of the cost of the Unit in customer rates; however, this order
stated that "the disallowed portion of Trimble County remains with the
Company and stockholders for their use."
In 1989, the Commission initiated a proceeding to determine the appropriate
ratemaking treatment to carry out the order that disallowed rate recovery for
25% of the Unit. Prior to the start of the hearings in this proceeding, the
Company filed a motion requesting the Commission to adopt a proposed plan to
settle all of the issues surrounding Trimble County. Settlement discussions
ensued between the Company, intervenors, and the Commission staff. On
October 2, 1989, the Commission approved the settlement agreement reached
between the Company and the Commission staff and, in accordance with the
terms of the agreement, the Company refunded $2.5 million to its customers
in 1989 and reduced its electric rates by $8.5 million for the year beginning
January 1, 1990.
Certain intervenors, who participated in the proceedings but did not agree
to the settlement, appealed the Commission's order approving the settlement
to Franklin Circuit Court, claiming, among other things, that the Commission
lacked the statutory authority to approve the agreement and that the
intervenors who refused to sign the agreement were deprived of due process
rights.
In February 1991, the Franklin Circuit Court vacated the October 2, 1989
order of the Commission approving the settlement agreement. On September 27,
1991, the Court issued an opinion requiring a refund to ratepayers in excess
of $100 million as a result of the Commission's order that disallowed 25% of
the total cost of Trimble County from customer rates. The Court further
ordered the Company to post a bond if it appealed the Circuit Court's
decision.
The Company posted a bond of $107 million and appealed all orders of the
Circuit Court to the Kentucky Court of Appeals.
On April 23, 1993, the Kentucky Court of Appeals overturned the Franklin
Circuit Court ruling previously entered in the case. Although the decision
upheld the Circuit Court's order vacating the 1989 settlement agreement
approved by the Commission, the appeals court ruled that the Franklin Circuit
Court order of September 27, 1991, improperly set utility rates in ordering
refunds. The intervenor parties requested the Kentucky Supreme Court to
review the case, and their request for review was denied on October 20, 1993.
Under Kentucky procedural rules, this ruling makes final the Court of Appeals
decision and returns the case to the Commission for further proceedings.
The Commission has issued orders which set a portion of the procedural
schedule for the case. Pursuant to the Commission's orders, the Company
filed direct testimony on January 7, 1994. Intervenor parties are scheduled
to file testimony on March 28, 1994. No date has been set for a hearing.
51
The Company anticipates that the focus of Commission proceedings will be the
determination of the appropriate ratemaking treatment to insulate ratepayers
from 25% of Trimble County's costs and the amount of additional refunds, if
any, that the Company should return to ratepayers. In previous proceedings
in 1988, the Commission had authorized rate increases, subject to refund, of
$11.4 million on an annual basis, pending a determination of the appropriate
ratemaking treatment for the disallowance. The order remained in effect from
May 1988 through December 1990, resulting in an amount subject to refund of
approximately $30 million. The Company, through refunds and rate reductions,
has already returned to its customers approximately $11 million of the total
amount subject to refund. The Company's position is that no additional
refunds are needed to carry out the Commission's objective of reflecting the
disallowance of 25% of Trimble County in customer rates and the Company may
be entitled to recover a portion, or all, of the amounts previously returned
to customers. However, the Company is unable to predict the outcome of the
Commission proceedings, the amount of additional refunds or recoveries, if
any, that may be ordered or whether the Commission will revise its earlier
position.
Sale of Portion of Trimble County. On February 28, 1991, the Company sold
a 12.12% ownership interest in the Trimble County Unit to the Illinois
Municipal Electric Agency, based in Springfield, Illinois, which is an agency
of 30 municipalities that own and operate their own electric systems. The
sale price was $94.2 million and a book gain of $4.2 million, after-tax, was
recognized in 1991 as a result of this sale.
On February 1, 1993, the Indiana Municipal Power Agency (IMPA), based in
Carmel, Indiana, purchased a 12.88% interest in the Trimble County plant.
IMPA is composed of 31 municipalities that have joined together to meet their
long-term electric power needs. The sale price was $91.1 million and an
after-tax book gain of $3.2 million was recorded in 1993 as a result of this
sale.
The Company has now completed the sale of the entire 25% of Trimble County
that the Commission disallowed from customer rates.
52
Note 9 - Jointly Owned Electric Utility Plant
- ---------------------------------------------
As of December 31, 1993, the Company owned 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. IMEA pays for 12.12% of the
operation and maintenance expenses, their proportionate share of
incremental assets acquired and for fuel used.
. Indiana Municipal Power Agency (IMPA) purchased a 12.88% undivided
interest in the Unit on February 1, 1993. IMPA is responsible for 12.88%
of the operation and maintenance expenses, their proportionate share of
incremental assets acquired and for fuel used.
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
53
Note 10 - 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.
1993 1992 1991
---- ---- ----
(Thousands of $)
Operating Information
Operating Revenues
Electric........................ $ 570,210 $ 521,669 $ 542,415
Gas............................. 204,915 178,526 166,291
--------- --------- ---------
Total......................... $ 775,125 $ 700,195 $ 708,706
--------- --------- ---------
--------- --------- ---------
Pre-tax Operating Income
Electric........................ $ 171,016 $ 154,547 $ 182,349
Gas............................. 17,436 15,122 13,576
--------- --------- ---------
Total......................... $ 188,452 $ 169,669 $ 195,925
--------- --------- ---------
--------- --------- ---------
Other Information
Depreciation and Amortization
Electric........................ $ 69,753 $ 67,869 $ 65,236
Gas............................. 9,902 9,034 8,037
Non-Jurisdictional.............. 232 2,783 3,158
--------- --------- ---------
Total......................... $ 79,887 $ 79,686 $ 76,431
--------- --------- ---------
--------- --------- ---------
Construction Expenditures
Electric........................ $ 74,165 $ 75,630 $ 69,514
Gas............................. 24,622 25,545 18,538
--------- --------- ---------
Total......................... $ 98,787 $ 101,175 $ 88,052
--------- --------- ---------
--------- --------- ---------
Investment Information-December 31
Identifiable Assets
Electric........................ $1,616,595 $1,537,219 $1,524,018
Gas............................. 261,048 226,041 195,251
--------- --------- ---------
Total......................... $1,877,643 $1,763,260 $1,719,269
Trimble County (a)................ - 87,794 89,824
Other Assets (b).................. 195,267 121,985 139,317
--------- --------- ---------
Total Assets.................... $2,072,910 $1,973,039 $1,948,410
--------- --------- ---------
--------- --------- ---------
(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.
54
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
& Co., independent public accountants whose report follows this Report of
Management. Management has made available to Arthur Andersen & Co. 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 and the independent public accountants. These
recommendations for the year ended December 31, 1993 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.
55
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, 1993
and 1992, and the related statements of income, retained earnings and cash
flows for each of the three years in the period ended December 31, 1993.
These financial statements and the schedules referred to below are the
responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements and schedules 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, 1993 and 1992, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1993, in conformity with generally accepted accounting
principles.
As further discussed in Note 8, 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 2 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.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedules listed under Item
14(a)2 are presented for purposes of complying with the Securities and
Exchange Commission's rules and are not part of the basic financial
statements. These schedules have been subjected to the auditing procedures
applied in our audits of the basic financial statements and, in our opinion,
fairly state 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 & Co.
January 28, 1994
--------------------------------------
56
SELECTED QUARTERLY FINANCIAL DATA (Unaudited)
Operating revenues, net operating income, net income and net income
available for common stock for the four quarters of 1993 and 1992 are shown
below. Because of seasonal fluctuations in temperature and other factors,
results for quarters may fluctuate throughout the year.
Quarters Ended
----------------------------------------------
(Thousands of $) March June September December
----- ---- --------- --------
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
1992
Operating Revenues...... $182,699 $150,908 $179,491 $187,097
Net Operating Income.... 28,985 27,849 41,850 27,145
Net Income.............. 15,915 15,301 29,050 13,527
Net Income Available for
Common Stock.......... 13,510 13,676 27,474 11,960
--------------------------------------
ITEM 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.
- ---------------------------------------------------------------------
None.
57
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 28, 1994, 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, 1993,
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, 1993 (page 29).
Statements of Retained Earnings for the three years
ended December 31, 1993 (page 30).
Balance Sheets - December 31, 1993, and 1992 (page 31-32).
Statements of Cash Flows for the three years ended
December 31, 1993 (page 33-34).
Statements of Capitalization - December 31, 1993,
and 1992 (page 35-36).
Notes to Financial Statements (pages 37-53).
Report of Management (page 54).
Report of Independent Public Accountants (page 55).
Selected Quarterly Financial Data for 1993, and
1992 (page 56).
2. Financial Statement Schedules (included in Part IV):
Schedule V - Property, Plant and Equipment for the
three years ended December 31, 1993
(pages 72-77).
Schedule VI - Accumulated Depreciation, Depletion,
and Amortization of Property, Plant
and Equipment for the three years
ended December 31, 1993 (pages 78-80).
Schedule VIII - Valuation and Qualifying Accounts for
the three years ended December 31,
1993 (page 81).
Schedule IX - Short-Term Borrowings for the three
years ended December 31, 1993
(page 82).
Schedule X - Supplementary Income Statement
Information for the three years ended
December 31, 1993 (page 83).
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.
58
3. Exhibits:
Exhibit
No. Description
-------- -----------
3.01 Copy of Restated Articles of Incorporation, as
amended. [Filed as Exhibit 4.01 to Registration
Statement 33-18302 and incorporated by reference
herein]
3.02 Copy of Amendment to Articles of Incorporation,
effective May 25, 1989. [Filed as Exhibit 3.01
to the Company's Form 10-Q for the quarter ended
June 30, 1989 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, 1991, and
incorporated by reference herein]
3.04 Copy of Amendment to Articles of Incorporation,
effective April 8, 1993. [Filed as Exhibit 3.01
to the Company's Form 10-Q for the quarter ended
March 31, 1993, and incorporated by reference
herein]
3.05 Copy of Amendment to Articles of Incorporation,
effective May 19, 1993.
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]
59
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]
60
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]
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]
61
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]
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]
62
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]
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.
4.35 Copy of Supplemental Indenture dated August 16,
1993, which is a supplemental instrument to
Exhibit 4.01 hereto.
4.36 Copy of Supplemental Indenture dated October 15,
1993, which is a supplemental instrument to
Exhibit 4.01 hereto.
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]
63
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]
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]
64
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]
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]
65
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]
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]
66
10.23 Copy of Agreement dated December 16, 1966,
between Peabody Coal Company and the Company
covering the purchase of coal. [Filed as
Exhibit 10.23 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1980,
and incorporated by reference herein]
10.24 Copy of Amendments to Coal Supply Agreement
referred to in 10.23 above as follows: (i)
Amendment effective July 1, 1970, (ii) effective
January 1, 1975, and (iii) effective December 1,
1976. [Filed as Exhibit 10.24 to the Company's
Annual Report on Form 10-K for the year ended
December 31, 1980, and incorporated by reference
herein]
10.25 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]
10.26 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]
10.27 Copy of Agreement dated December 20, 1985,
between Shawnee Coal Company and the Company
covering the purchase of coal. [Filed as
Exhibit 10.27 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1985,
and incorporated by reference herein]
10.28 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]
10.29 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]
67
10.30 Copy of Termination Agreement and Release dated
February 1, 1989, between Peabody Coal Company
and the Company canceling the Coal Supply
Agreement dated December 16, 1966 referred to in
Exhibit Nos. 10.23 and 10.24. [Filed as Exhibit
10.30 to the Company's Annual Report on Form
10-K for the year ended December 31, 1988, and
incorporated by reference herein]
10.31 Copy of Agreements dated February 1 and
February 15, 1989, between Peabody Development
Company and the Company covering the purchase of
coal. [Filed as Exhibit 10.31 to the Company's
Annual Report on Form 10-K for the year ended
December 31, 1988, and incorporated by reference
herein]
10.32 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]
10.33 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]
10.34 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]
10.35 Copy of Agreement dated August 1, 1991, between
Texas Gas Transmission Corporation and the
Company covering the purchase of natural gas.
[Filed as Exhibit 10.35 to the Company's Annual
Report on Form 10-K for the year ended
December 31, 1991, and incorporated by reference
herein]
10.36 Copy of Sales Service Agreement between Texas
Gas Transmission Corporation and the Company
effective February 1, 1992. [Filed as
Exhibit 10.36 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1992,
and incorporated by reference herein]
68
10.37 Copy of Sales Service Agreement between Texas
Gas Transmission Corporation and the Company
effective November 1, 1992. [Filed as
Exhibit 10.37 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1992,
and incorporated by reference herein]
10.38 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]
10.39 Copy of Employment Agreement between Roger W.
Hale and Louisville Gas and Electric Company,
effective June 1, 1989, as amended. [Filed as
Exhibit 10.39 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1992,
and incorporated by reference herein]
10.40 Copy of 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]
10.41 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]
10.42 Copy of Modification No. 13 dated September 1,
1989, to the Power Agreement between Ohio Valley
Electric Corporation and Atomic Energy
Commission.
10.43 Copy of Modification No. 14 dated January 15,
1992, to the Power Agreement between Ohio Valley
Electric Corporation and Atomic Energy
Commission.
10.44 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.
10.45 Copy of Modification No. 15 dated February 15,
1993, to the Power Agreement between Ohio Valley
Electric Corporation and Atomic Energy
Commission.
69
10.46 Firm Transportation Agreement, dated November 1,
1993, between Texas Gas Transmission Corporation
and the Company covering the transmission of
natural gas.
10.47 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.
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.
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.
10.48 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]
10.49 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]
12 Computation of Ratio of Earnings to Fixed
Charges
23 Consent of Independent Public Accountants
24 Power of Attorney
70
(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]
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]
Employment Agreement between Roger W. Hale and Louisville
Gas and Electric Company, effective June 1, 1989, as
amended. [Filed as Exhibit 10.39 to the Company's Annual
Report on Form 10-K for the year ended December 31, 1992]
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]
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]
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]
71
(c) Reports on Form 8-K:
The following 8-K reports were filed during the fourth
quarter of 1993:
(i) On October 27, 1993, a report on Form 8-K was filed
announcing the following:
Trimble County Generating Plant. On October 20,
1993, the Kentucky Supreme Court declined to review
a Kentucky Court of Appeals order overturning a
lower court's order that had improperly directed the
Company to refund approximately $150 million to its
customers in a case involving the Company's Trimble
County electric generating station.
Management Change. Walter M. Higgins, III,
President and Chief Operating Officer of the Company
resigned to accept the position of President and
Chief Operating Officer of Sierra Pacific Resources.
Sierra Pacific Resources indicated plans for
Mr. Higgins to become Chief Executive Officer early
in 1994.
(ii) On November 23, 1993, a report on Form 8-K was filed
announcing that LG&E Energy Corp., of which the Company
is the principal subsidiary, would undergo a major
realignment and formation of new business units
effective January 1, 1994, to reflect its outlook for
rapidly emerging competition in all segments of the
energy services industry.
72
LOUISVILLE GAS AND ELECTRIC COMPANY
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
(INCLUDING INTANGIBLES)
FOR THE YEAR ENDED DECEMBER 31, 1993
(Thousands of $)
Column A Column B Column C Column D Column E Column F
-------- ---------- ---------- ----------- ---------- ----------
Other
Balance Changes Balance
Beginning Additions Retirements Add End of
Classification of Year at Cost at Cost (Deduct) Year
-------------- ---------- ---------- ----------- ---------- ----------
Electric Department:
Intangible..................... $ 2 $ 2
Steam production............... 1,371,584 $ 10,904 $ 2,024 $ (615) <F5> 1,379,849
Hydraulic production........... 8,222 40 19 8,243
Other production............... 11,147 39 2 11,184
Transmission................... 163,407 9,817 291 { 1,020 <F2> 173,837
{ (116) <F1>
Distribution................... 406,046 25,483 2,392 { 116 <F1> 429,252
{ (1) <F3>
General........................ 15,799 1,640 628 (39) <F1> 16,772
Construction work in progress.. 30,948 17,084 48,032
--------- --------- --------- --------- ---------
Total electric department.... 2,007,155 65,007 5,356 365 2,067,171
--------- --------- --------- --------- ---------
Gas Department:
Intangible..................... 1 1
Storage:
Land rights and leaseholds... 568 568
Other........................ 32,282 628 60 32,850
Transmission................... 11,783 4 37 11,750
Distribution................... 186,007 20,217 1,839 204,385
General........................ 8,037 1,407 624 (29) <F1> 8,791
Construction work in progress.. 3,090 (851) 2,239
Gas stored underground-
noncurrent................... 2,140 2,140
--------- --------- --------- --------- ---------
Total gas department......... 243,908 21,405 2,560 (29) 262,724
--------- --------- --------- --------- ---------
Common Utility:
Intangible..................... 17,498 4,025 98 21,425
General........................ 103,606 8,165 458 { 68 <F1> 111,267
{ (114) <F4>
Construction work in progress.... 1,329 185 1,514
--------- --------- --------- --------- ---------
Total common utility......... 122,433 12,375 556 (46) 134,206
--------- --------- --------- --------- ---------
Total utility plant at
original cost.............. $2,373,496 $ 98,787 $ 8,472 $ 290 $2,464,101
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
73
<FN>
NOTES:
<F1> Transfer between functional groups.
<F2> Transfer from Nonutility Property.
<F3> Sale of land.
<F4> Transfer to LG&E Energy Corp.
<F5> Transfer to Nonutility Property.
74
LOUISVILLE GAS AND ELECTRIC COMPANY
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
(INCLUDING INTANGIBLES)
FOR THE YEAR ENDED DECEMBER 31, 1992
(Thousands of $)
Column A Column B Column C Column D Column E Column F
-------- ---------- ---------- ----------- ---------- ----------
Other
Balance Changes Balance
Beginning Additions Retirements Add End of
Classification of Year at Cost at Cost (Deduct) Year
-------------- ---------- ---------- ----------- ---------- ----------
Electric Department:
Intangible..................... $ 2 $ 2
Steam production............... 1,364,349 $ 8,224 $ 1,000 $ 11 <F1> 1,371,584
Hydraulic production........... 8,204 18 8,222
Other production............... 11,147 11,147
Transmission................... 160,904 2,957 419 (35) <F1> 163,407
Distribution................... 378,582 29,804 2,386 { 47 <F1> 406,046
{ (1) <F3>
General........................ 2,246 3,729 1,532 11,356 <F1> 15,799
Construction work in progress.. 15,729 16,084 { (853) <F2> 30,948
{ (12) <F1>
--------- --------- --------- --------- ---------
Total electric department.... 1,941,163 60,816 5,337 10,513 2,007,155
--------- --------- --------- --------- ---------
Gas Department:
Intangible..................... 1 1
Storage:
Land rights and leaseholds... 568 568
Other........................ 31,412 1,089 219 32,282
Transmission................... 11,902 (2) 117 11,783
Distribution................... 170,878 16,853 1,724 186,007
General........................ 1,454 1,804 449 5,228 <F1> 8,037
Construction work in progress.. 2,494 596 3,090
Gas stored underground-
noncurrent................... 2,140 2,140
--------- --------- --------- --------- ---------
Total gas department......... 220,849 20,340 2,509 5,228 243,908
--------- --------- --------- --------- ---------
Common Utility:
Intangible..................... 6,573 10,925 17,498
General........................ 105,498 19,169 4,444 { (16,595) <F1> 103,606
{ (22) <F4>
Construction work in progress.... 11,405 (10,075) (1) <F4> 1,329
--------- --------- --------- --------- ---------
Total common utility......... 123,476 20,019 4,444 (16,618) 122,433
--------- --------- --------- --------- ---------
Total utility plant at
original cost.............. $2,285,488 $ 101,175 $ 12,290 $ (877) $2,373,496
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
75
<FN>
NOTES:
<F1> Transfer between functional groups.
<F2> Transfer 25% of Trimble County to Nonutility Property.
<F3> Sale of land.
<F4> Transfer to LG&E Energy Corp.
76
LOUISVILLE GAS AND ELECTRIC COMPANY
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
(INCLUDING INTANGIBLES)
FOR THE YEAR ENDED DECEMBER 31, 1991
(Thousands of $)
Column A Column B Column C Column D Column E Column F
-------- ---------- ---------- ----------- ---------- ----------
Other
Balance Changes Balance
Beginning Additions Retirements Add End of
Classification of Year at Cost at Cost (Deduct) Year
-------------- ---------- ---------- ----------- ---------- ----------
Electric Department:
Intangible..................... $ 3 $ 1 $ $ 2
Steam production............... 1,343,270 $ 21,407 2,318 { 2,568 <F1> 1,364,349
{ (578) <F3>
Hydraulic production........... 8,049 156 1 8,204
Other production............... 11,155 8 11,147
Transmission................... 157,662 3,685 423 { (18) <F1> 160,904
{ (2) <F3>
Distribution................... 353,842 27,369 2,647 18 <F1> 378,582
General........................ 2,076 181 11 2,246
Construction work in progress.. 18,272 798 (3,341) <F2> 15,729
--------- --------- --------- --------- ---------
Total electric department.... 1,894,329 53,596 5,409 (1,353) 1,941,163
--------- --------- --------- --------- ---------
Gas Department:
Intangible..................... 1 1
Storage:
Land rights and leaseholds... 568 568
Other........................ 29,850 1,676 114 31,412
Transmission................... 10,622 1,290 10 11,902
Distribution................... 161,192 10,663 976 (1) <F3> 170,878
General........................ 1,255 250 51 1,454
Construction work in progress.. 2,590 (96) 2,494
Gas stored underground-
noncurrent................... 2,140 2,140
--------- --------- --------- --------- ---------
Total gas department......... 208,218 13,783 1,151 (1) 220,849
--------- --------- --------- --------- ---------
Common Utility:
Intangible..................... 4,968 1,605 6,573
General........................ 89,472 21,382 2,717 { (2,568) <F1> 105,498
{ (71) <F4>
Construction work in progress.... 18,169 (2,314) (4,450) <F5> 11,405
--------- --------- --------- --------- ---------
Total common utility......... 112,609 20,673 2,717 (7,089) 123,476
--------- --------- --------- --------- ---------
Total utility plant at
original cost.............. $2,215,156 $ 88,052 $ 9,277 $ (8,443) $2,285,488
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
77
<FN>
NOTES:
<F1> Transfer between functional groups.
<F2> Transfer 25% of Trimble County to Nonutility Property.
<F3> Sale of land.
<F4> Transfer to LG&E Energy Corp.
<F5> Transfer to Preliminary Survey and Investigation Charges.
78
LOUISVILLE GAS AND ELECTRIC COMPANY
SCHEDULE VI - ACCUMULATED DEPRECIATION, DEPLETION, AND AMORTIZATION
OF PROPERTY, PLANT AND EQUIPMENT
FOR THE YEAR ENDED DECEMBER 31, 1993
(Thousands of $)
Column A Column B Column C Column D Column E Column F
-------- ---------- ------------------------- ---------- ---------- ----------
Additions Charged to
Costs and Expenses
-------------------------
Provisions
Charged Other
Balance Provisions to Clearing Changes Balance
Beginning Charged and Other Retire- Add End of
Classification of Year to Income Accounts ments <F1> (Deduct) Year
-------------- ---------- ---------- ----------- ---------- ---------- ----------
Electric Department:
Steam production............... $ 401,102 $ 43,449 $ 503 $ 2,818 $ 442,236
Hydraulic production........... 7,794 154 25 7,923
Other production............... 10,668 1 2 $ 10,667
Transmission................... 73,981 4,098 356 { (79) <F2> 77,695
{ 51 <F3>
Distribution................... 131,883 14,258 3,212 79 <F2> 143,008
General........................ 8,719 89 1,353 615 (11) <F2> 9,535
--------- --------- --------- --------- --------- ---------
Total electric department.... 634,147 62,049 1,856 7,028 40 $ 691,064
--------- --------- --------- --------- --------- ---------
Gas Department:
Intangible..................... 1 1
Storage:
Land rights and leaseholds... 397 21 418
Other........................ 16,660 1,247 79 17,828
Transmission................... 8,343 275 37 8,581
Distribution................... 60,711 5,574 2,791 63,494
General........................ 3,181 72 853 623 (29) <F2> 3,454
--------- --------- --------- --------- --------- ---------
Total gas department......... 89,293 7,189 853 3,530 (29) 93,776
--------- --------- --------- --------- --------- ---------
Common Utility:
Intangible..................... 4,462 2,528 98 6,892
General........................ 26,527 4,978 297 422 { 40 <F2> 31,409
{ (11) <F4>
--------- --------- --------- --------- --------- ---------
Total common utility......... 30,989 7,506 297 520 29 38,301
--------- --------- --------- --------- --------- ---------
Totals....................... $ 754,429 $ 76,744 $ 3,006 $ 11,078 $ 40 $ 823,141
--------- --------- --------- --------- --------- ---------
--------- --------- --------- --------- --------- ---------
<FN>
NOTES:
<F1> Net of gross retirements, salvage, and removal expense.
<F2> Transfer of depreciation reserve between functional groups.
<F3> Transfer from Nonutility Property.
<F4> Transfer of depreciation reserve to LG&E Energy Corp.
79
LOUISVILLE GAS AND ELECTRIC COMPANY
SCHEDULE VI - ACCUMULATED DEPRECIATION, DEPLETION, AND AMORTIZATION
OF PROPERTY, PLANT AND EQUIPMENT
FOR THE YEAR ENDED DECEMBER 31, 1992
(Thousands of $)
Column A Column B Column C Column D Column E Column F
-------- ---------- ------------------------- ---------- ---------- ----------
Additions Charged to
Costs and Expenses
-------------------------
Provisions
Charged Other
Balance Provisions to Clearing Changes Balance
Beginning Charged and Other Retire- Add End of
Classification of Year to Income Accounts ments <F1> (Deduct) Year
-------------- ---------- ---------- ----------- ---------- ---------- ----------
Electric Department:
Steam production............... $ 359,701 $ 43,502 $ 504 $ 2,606 $ 1 <F3> $ 401,102
Hydraulic production........... 7,661 150 17 7,794
Other production............... 10,667 1 10,668
Transmission................... 70,639 3,927 568 (17) <F2> 73,981
Distribution................... 121,322 13,397 2,853 17 <F2> 131,883
General........................ 551 70 1,104 1,533 8,527 <F2> 8,719
--------- --------- --------- --------- --------- ---------
Total electric department.... 570,541 61,047 1,608 7,577 8,528 634,147
--------- --------- --------- --------- --------- ---------
Gas Department:
Intangible..................... 1 1
Storage:
Land rights and leaseholds... 376 21 397
Other........................ 15,709 1,223 271 (1) <F2> 16,660
Transmission................... 8,183 277 117 8,343
Distribution................... 58,526 5,118 2,933 60,711
General........................ 300 55 567 441 2,700 <F2> 3,181
--------- --------- --------- --------- --------- ---------
Total gas department......... 83,095 6,694 567 3,762 2,699 89,293
--------- --------- --------- --------- --------- ---------
Common Utility:
Intangible..................... 2,909 1,553 4,462
General........................ 36,695 4,704 886 4,528 { (11,226) <F2> 26,527
{ (4) <F4>
--------- --------- --------- --------- --------- ---------
Total common utility......... 39,604 6,257 886 4,528 (11,230) 30,989
--------- --------- --------- --------- --------- ---------
Totals....................... $ 693,240 $ 73,998 $ 3,061 $ 15,867 $ (3) $ 754,429
--------- --------- --------- --------- --------- ---------
--------- --------- --------- --------- --------- ---------
<FN>
NOTES:
<F1> Net of gross retirements, salvage, and removal expense.
<F2> Transfer of depreciation reserve between functional groups.
<F3> Transfer to Nonutility Property.
<F4> Transfer of depreciation reserve to LG&E Energy Corp.
80
LOUISVILLE GAS AND ELECTRIC COMPANY
SCHEDULE VI - ACCUMULATED DEPRECIATION, DEPLETION, AND AMORTIZATION
OF PROPERTY, PLANT AND EQUIPMENT
FOR THE YEAR ENDED DECEMBER 31, 1991
(Thousands of $)
Column A Column B Column C Column D Column E Column F
-------- ---------- ------------------------- ---------- ---------- ----------
Additions Charged to
Costs and Expenses
-------------------------
Provisions
Charged Other
Balance Provisions to Clearing Changes Balance
Beginning Charged and Other Retire- Add End of
Classification of Year to Income Accounts ments <F1> (Deduct) Year
-------------- ---------- ---------- ----------- ---------- ---------- ----------
Electric Department:
Steam production............... $ 316,739 $ 43,000 $ 504 $ 2,596 $ 2,054 <F2> $ 359,701
Hydraulic production........... 7,514 148 1 7,661
Other production............... 11,091 1 425 10,667
Transmission................... 67,386 3,862 574 (35) <F2> 70,639
Distribution................... 111,484 12,511 2,708 35 <F2> 121,322
General........................ 496 66 11 551
--------- --------- --------- --------- --------- ---------
Total electric department.... 514,710 59,588 504 6,315 2,054 570,541
--------- --------- -------- --------- --------- ---------
Gas Department:
Intangible..................... 1 1
Storage:
Land rights and leaseholds... 354 22 376
Other........................ 14,734 1,183 208 15,709
Transmission................... 7,932 264 13 8,183
Distribution................... 55,771 4,775 2,020 58,526
General........................ 311 48 59 300
--------- --------- --------- --------- --------- ---------
Total gas department......... 79,103 6,292 2,300 83,095
--------- --------- --------- --------- --------- ---------
Common Utility:
Intangible..................... 2,121 788 2,909
General........................ 35,477 3,708 2,312 2,735 { (13) <F3> 36,695
{ (2,054) <F2>
--------- --------- --------- --------- --------- ---------
Total common utility......... 37,598 4,496 2,312 2,735 (2,067) $ 39,604
--------- --------- --------- --------- --------- ---------
Totals....................... $ 631,411 $ 70,376 $ 2,816 $ 11,350 $ (13) $ 693,240
--------- --------- --------- --------- --------- ---------
--------- --------- --------- --------- --------- ---------
<FN>
NOTES:
<F1> Net of gross retirements, salvage, and removal expense.
<F2> Transfer of depreciation reserve between functional groups and LG&E Energy Corp.
<F3> Transfer of depreciation reserve to LG&E Energy Corp.
81
LOUISVILLE GAS AND ELECTRIC COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1993
(Thousands of $)
Reserves Deducted from
Assets in Balance Sheet
--------------------------------------
Other Accounts
Property Receivable
and (Uncollectible
Investments Accounts)
----------- --------------
Balance January 1, 1991..................................... $ 190 $ 1,596
Additions:
Charged to costs and expenses...........................
Trimble County - non-jurisdictional depreciation...... 3,158
Other................................................. 2,000
Deductions:
Net charges of nature for which reserves were created... 2,183
Other................................................... 486
----- -----
Balance December 31, 1991................................... 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
Other...................................................
----- -----
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
----- -----
----- -----
82
LOUISVILLE GAS AND ELECTRIC COMPANY
SCHEDULE IX - SHORT-TERM BORROWINGS
FOR THE THREE YEARS ENDED DECEMBER 31, 1993
(Thousands of $)
Column A Column B Column C Column D Column E Column F
-------- ---------- ------------- --------------- ----------- --------------
Weighted Maximum Average Weighted
Average Amount Amount Average
Short-Term Balance at Interest Rate Outstanding Outstanding Interest Rate
Bank End of at End at Month-End During the During the
Borrowings <F1> Year of Year During the Year Year <F2> Year <F3>
--------------- ---------- ------------- --------------- ----------- -------------
1993
Trust Demand Notes........... $ - -
Other Notes.................. - -
--------- -------------
Total $ - - $16,000 $2,000 3.73%
--------- ------------- --------------- ----------- -------------
--------- ------------- --------------- ----------- -------------
1992
Trust Demand Notes........... $ 8,000 3.45%
Other Notes.................. - -
--------- -------------
Total $ 8,000 3.45% $12,800 $11,358 3.89%
--------- ------------- --------------- ----------- -------------
--------- ------------- --------------- ----------- -------------
1991
Trust Demand Notes........... $ 12,000 4.21%
Other Notes.................. - -
--------- -------------
Total $ 12,000 4.21% $28,200 $20,933 6.32%
--------- ------------- --------------- ----------- -------------
--------- ------------- --------------- ----------- -------------
<FN>
NOTES:
<F1> See Note 6 of Notes to Financial Statements under Item 8.
<F2> Computed on average monthly balances.
<F3> Computed on a daily weighted average basis.
83
LOUISVILLE GAS AND ELECTRIC COMPANY
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
FOR THE THREE YEARS ENDED DECEMBER 31, 1993
(Thousands of $)
Charged to
Operating Expenses
------------------
Years Ended December 31
-----------------------------------------
1993 1992 1991
---- ---- ----
Taxes other than income taxes:
Real estate and personal property (including franchise)..... $ 7,580 $ 7,525 $ 7,344
Payroll..................................................... 7,301 7,189 7,156
Other....................................................... 1,312 1,122 1,005
------ ------ ------
Total taxes other than income taxes per
statements of income.................................... $16,193 $15,836 $15,505
------ ------ ------
------ ------ ------
The amounts of royalties and advertising costs charged to operating
expenses were each less than one percent of total operating revenues.
84
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 28, 1994 By 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;
DAVID B. LEWIS Director;
ANNE H. MCNAMARA Director;
T. BALLARD MORTON, JR. Director; and
DR. DONALD C. SWAIN Director.
By M. L. FOWLER March 28, 1994
- ------------------------------------------------
(Attorney-In-Fact)