<PAGE>
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
---------------------------
FORM 10-K
[x] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 (FEE REQUIRED)
For the fiscal year ended DECEMBER 31, 1994
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
Commission File No. 2-26720
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LOUISVILLE GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
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KENTUCKY 61-0264150
(State or other jurisdiction of (I.R.S.Employer
incorporation or organization) Identification No.)
220 W. MAIN STREET
P. O. BOX 32010 (502) 627-2000
LOUISVILLE, KENTUCKY 40232 (Registrant's telephone
(Address of principal executive offices) number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
Name of each exchange on
Title of each class which registered
------------------- ------------------------
First Mortgage Bonds, Series due July 1, 2002, 7 1/2% New York Stock
Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
5% Cumulative Preferred Stock, $25 Par Value
7.45% Cumulative Preferred Stock, $25 Par Value
$5.875 Cumulative Preferred Stock, Without Par Value
Auction Rate Series A Preferred Stock, Without Par Value
(Title of class)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X . No____.
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
As of February 28, 1995, the aggregate market value of the registrant's
voting stock held by non-affiliates was $34,357,392 and the number of
outstanding shares of the registrant's common stock, without par value, was
21,294,223 all of which were held by LG&E Energy Corp.
DOCUMENTS INCORPORATED BY REFERENCE
The proxy statement of Louisville Gas and Electric Company filed with the
Commission on March 16, 1995, is incorporated by reference into Part III of this
Form 10-K.
<PAGE>
PART I PAGE
----
Item 1. Business. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
General. . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Electric Operations. . . . . . . . . . . . . . . . . . . . . . 3
Gas Operations . . . . . . . . . . . . . . . . . . . . . . . . 5
Regulation and Rates . . . . . . . . . . . . . . . . . . . . . 6
Construction Program and Financing . . . . . . . . . . . . . . 7
Coal Supply. . . . . . . . . . . . . . . . . . . . . . . . . . 8
Gas Supply . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Environmental Matters. . . . . . . . . . . . . . . . . . . . . 9
Labor Relations. . . . . . . . . . . . . . . . . . . . . . . . 10
Employees. . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Item 2. Properties. . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . 11
Item 4. Submission of Matters to a Vote of Security Holders . . . . . . . 12
Executive Officers of the Company. . . . . . . . . . . . . . . . . . . . . 13
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters. . . . . . . . . . . . . . . . . . . . . . 15
Item 6. Selected Financial Data . . . . . . . . . . . . . . . . . . . . . 15
Item 7. Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . . . 15
Item 8. Financial Statements and Supplementary Data . . . . . . . . . . . 23
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure . . . . . . . . . . . . . . . . . . . 46
PART III
Item 10. Directors and Executive Officers of the Registrant (a). . . . . . 47
Item 11. Executive Compensation (a). . . . . . . . . . . . . . . . . . . . 47
Item 12. Security Ownership of Certain Beneficial Owners
and Management (a) . . . . . . . . . . . . . . . . . . . . . . 47
Item 13. Certain Relationships and Related Transactions (a). . . . . . . . 47
PART IV
Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K. . . . . . . . . . . . . . . . . . . . 47
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61
Exhibit 12 - Computation of Ratio of Earnings to Fixed Charges . . . . . . 62
Exhibit 23 - Consent of Independent Public Accountants . . . . . . . . . . 63
(a) Incorporated by reference.
<PAGE>
PART I
ITEM 1. BUSINESS.
General
Incorporated July 2, 1913, Louisville Gas and Electric Company (the
Company) is an operating public utility that supplies natural gas to
approximately 266,000 customers and electricity to approximately 341,000
customers in Louisville and adjacent areas in Kentucky. The Company's service
area covers approximately 700 square miles in 17 counties and has an estimated
population of 800,000. Included in this area is the Fort Knox Military
Reservation, to which the Company provides both gas and electric service, but
which maintains its own distribution systems. The Company also provides gas
service in limited additional areas. The Company's coal-fired electric
generating plants, which are all equipped with systems to remove sulfur dioxide,
produce most of the Company's electricity; the remainder is generated by a
hydroelectric power plant and combustion turbines. Underground gas storage
fields help the Company provide economical and reliable gas service to
customers.
In August 1990, the Company and LG&E Energy Corp. (Energy Corp.)
implemented a corporate reorganization pursuant to a mandatory share exchange
whereby each share of outstanding common stock of the Company was exchanged on a
share-for-share basis for the common stock of Energy Corp. The reorganization
created a corporate structure that gives the holding company the flexibility to
take advantage of opportunities to expand into other businesses while insulating
the Company's utility customers and senior security holders from any risks
associated with such businesses. The Company's preferred stock and first
mortgage bonds were not exchanged and remained securities of the Company.
The Company's Trimble County Unit 1 (Trimble County or the Unit), a
495-megawatt, coal-fired electric generating unit, which the Company began
constructing in 1979, was placed in commercial operation on December 23, 1990.
The Unit has been subject to numerous reviews by the Public Service Commission
of Kentucky (Kentucky Commission or Commission). In July 1988, the Kentucky
Commission issued an order stating that 25% of the total cost of the Unit would
not be allowed for ratemaking purposes. The Company has sold a 25% ownership
interest in the Unit. For a more detailed discussion of the proceedings
relating to Trimble County Unit 1 and the sale of 25% of the Unit, see Electric
Operations and Notes 11 and 12 of Notes to Financial Statements under Item 8.
The Clean Air Act Amendments of 1990 impose stringent limits on emissions
of sulfur dioxide and nitrogen oxides by electric generating plants. The
Company is closely monitoring the continuing rule-making process in order to
assess the precise impact of the legislation on the Company. All of the
Company's coal fired boilers are equipped with sulfur dioxide "scrubbers" and
already achieve the final sulfur dioxide emission rates required by the year
2000 under the legislation. However, as part of its ongoing capital
construction program, the Company has spent $10 million to date and anticipates
incurring capital expenditures of approximately $29 million through 1996 for
remedial measures necessary to meet the Act's requirements for nitrogen oxides.
The overall financial impact of the legislation on the Company is expected to be
minimal. The Company is well-positioned in the market to be a "clean" power
provider without the large capital expenditures that are expected to be incurred
by many other utilities. For a more detailed discussion of the Clean Air Act
and other
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environmental issues, see Environmental Matters under this Item, Item 3, Item 7,
and Note 10 of the Notes to Financial Statements under Item 8.
Competition among energy suppliers is increasing. In particular,
competition for off-system sales, which is based primarily on price and
availability of energy, has become much more intense in recent years. The
addition of electric generating capacity by other utilities in the Midwest has
reduced the opportunities for the Company to make interchange sales and has
heightened price competition for such sales. However, such additional capacity
has made lower cost power available for purchase by the Company which, in
certain instances, is at a cost lower than the variable cost of generating power
from the generating stations owned by the Company. In addition, the 1992 Energy
Policy Act provides utilities a wider choice of sources for their electrical
supply than previously available. The Act also creates generating supply
options that did not exist under previous legislation and is expected to
increase competition for wholesale electric sales. See Energy Policy Act of
1992 under Item 7 for a further discussion.
The Company has taken many steps to prepare for the expected increase in
competition in its industry, including a reduction in the number of employees;
aggressive cost cutting; a write-off of previously deferred expenses; an
increase in focus on commercial and industrial customers; an increase in
employee involvement and training; and a major realignment and formation of new
business units.
Effective January 1, 1994, Energy Corp. realigned its business to reflect
its outlook for rapidly emerging competition in all segments of the energy
services industry. Under the realignment, a national business unit, LG&E Energy
Services was formed to develop and manage all of its utility and non-utility
electric power generation and concentrate on the marketing and brokering of
wholesale electric power on a regional and national basis. The realignment has
allowed the Company to increase its focus on customer service and develop more
customer options as the utility industry becomes more competitive. As part of
the business realignment, a new subsidiary was formed to market power throughout
the United States. LG&E Power Marketing Inc. (LPM), an indirect wholly owned
subsidiary of Energy Corp., was among the first utility-affiliated marketers in
the country to secure Federal Energy Regulatory Commission (FERC) approval to
sell power at market-based rates and engage in wholesale power marketing
activities. The realignment does not affect Energy Corp.'s legal structure,
regulation of the Company by the Kentucky Commission or Energy Corp.'s status as
an exempt holding company.
The Company envisions an open electricity transmission system that
facilitates delivery of competitively priced power to all customers in the
region. Toward that vision, the Company filed tariffs with FERC in 1994 which
would provide transmission service to wholesale customers at rates, terms, and
conditions which are comparable to those which the Company applies to itself.
This comparable transmission service is a key feature of a more competitive
electric utility industry.
As part of its efforts to retain existing customers and expand to new
customers, in 1994 the Company began securing long-term, mutually beneficial
written contracts with key customers. By entering into such agreements, the
Company is assured of a market for its energy and can prudently invest in plant
and equipment upgrades and enhanced delivery services that will benefit
customers and make the utility more competitive. In 1994, the Company also
formalized its economic development strategic plan, integrating many of its
industry-attraction efforts with that of the city of Louisville and other
regional businesses.
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By using gas storage fields strategically, the Company can buy gas when
prices are low, store it, and retrieve the gas when demand is high. Accessing
least cost gas was made easier in November 1993 when FERC's Order No. 636 went
into effect. Previously, the Company and other utilities purchased most of
their gas services from pipeline companies. The order "unbundled" gas services,
allowing utilities to purchase gas, transportation, and storage services
separately from many different sources. Currently, the Company buys
competitively priced gas from several large producers under contracts of varying
duration. By purchasing from multiple suppliers, and storing any excess gas,
the Company is able to secure favorably priced gas for its customers. Without
storage capacity, the Company would be forced to buy additional gas when
customer demand increases, which is usually when the price is highest. See FERC
Order No. 636 under Item 7 for a further discussion.
The Company is experiencing some of the issues common to electric and gas
utility companies, namely, increased competition for customers and costs of
compliance with environmental laws and regulations.
For the year ended December 31, 1994, 74% of total operating revenues was
derived from electric operations and 26% from gas operations. Electric and gas
operating revenues and the percentages by classes of service on a combined basis
for this period were as follows:
<TABLE>
<CAPTION>
(Thousands of $)
------------------------------------
Electric Gas Combined % Combined
-------- --- -------- ----------
<S> <C> <C> <C> <C>
Residential. . . . . . . . . . . $194,145 $110,553 $304,698 43%
Commercial . . . . . . . . . . . 155,847 40,474 196,321 28
Industrial . . . . . . . . . . . 108,004 27,956 135,960 19
Public authorities . . . . . . . 53,191 12,930 66,121 10
------- ------- ------- ---
Total-ultimate consumers. . . 511,187 191,913 703,100 100%
---
---
Sales for resale . . . . . . . . 42,720 -- 42,720
Gas transportation-net . . . . . -- 6,759 6,759
Miscellaneous. . . . . . . . . . 5,039 1,457 6,496
------- ------- -------
Total . . . . . . . . . . . . $558,946 $200,129 $759,075
------- ------- -------
</TABLE>
See Note 13 of Notes to Financial Statements under Item 8 for financial
information concerning segments of business for the three years ended December
31, 1994.
Electric Operations
The sources of electric operating revenues and the volumes of sales for the
three years ended December 31, 1994, were as follows:
<TABLE>
<CAPTION>
1994 1993 1992
---- ---- ----
<S> <C> <C> <C>
ELECTRIC OPERATING REVENUES
(Thousands of $):
Residential . . . . . . . . . . . . . $ 194,145 $ 195,273 $ 174,559
Small commercial and industrial . . . 70,916 70,106 66,183
Large commercial. . . . . . . . . . . 84,931 84,231 80,041
Large industrial. . . . . . . . . . . 108,004 104,506 101,699
Public authorities. . . . . . . . . . 53,191 52,183 49,599
-------- ------- -------
Total-ultimate consumers . . . . . 511,187 506,299 472,081
Sales for resale. . . . . . . . . . . 42,720 58,959 45,698
Miscellaneous . . . . . . . . . . . . 5,039 4,952 3,890
-------- -------- --------
Total. . . . . . . . . . . . . . . $ 558,946 $ 570,210 $ 521,669
-------- -------- --------
-------- -------- --------
</TABLE>
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<PAGE>
<TABLE>
<CAPTION>
1994 1993 1992
---- ---- ----
<S> <C> <C> <C>
ELECTRIC SALES (Thousands of kwh):
Residential . . . . . . . . . . . . . . . 3,204,330 3,230,463 2,923,517
Small commercial and industrial . . . . . 1,073,152 1,056,977 1,010,830
Large commercial. . . . . . . . . . . . . 1,729,668 1,696,686 1,624,441
Large industrial. . . . . . . . . . . . . 2,874,411 2,736,269 2,671,212
Public authorities. . . . . . . . . . . . 1,085,741 1,053,928 1,004,911
---------- ---------- ----------
Total-ultimate consumers . . . . . . . 9,967,302 9,774,323 9,234,911
Sales for resale. . . . . . . . . . . . . 2,315,311 3,299,510 3,234,758
---------- ---------- ----------
Total. . . . . . . . . . . . . . . . . 12,282,613 13,073,833 12,469,669
---------- ---------- ----------
---------- ---------- ----------
</TABLE>
At December 31, 1994, the Company had 340,810 electric customers.
The Company uses efficient coal-fired boilers that are fully equipped with
sulfur dioxide removal systems to generate electricity. The Company's system
wide emission rate for sulfur dioxide in 1994 was approximately .84 lbs./MMBtu
of heat input, which is significantly below the Phase II limit of 1.2 lbs./MMBtu
established by the Clean Air Act Amendments for the year 2000.
On Monday, August 30, 1993, the Company set a record local peak load of
2,239 Mw, when the temperature at the time of peak reached 94 degrees F (average
for the day was 84 degrees F). The 1994 maximum local peak load of 2,219 Mw
occurred on Wednesday, June 15, when the temperature at the time of peak was 95
degrees F (average for the day was 85 degrees F). The record system peak of
3,223 Mw (which included purchases from and short-term sales to other electric
utilities) occurred on Thursday, May 30, 1991.
The Company's current reserve margin is 16%. At February 28, 1995, the
Company owned steam and combustion turbine generating facilities with a
capacity of 2,613 Mw and an 80 Mw hydroelectric facility on the Ohio River. See
Item 2, Properties.
The Company is a participating owner with 14 other electric utilities of
Ohio Valley Electric Corporation (OVEC) whose primary customer is the Portsmouth
Area uranium-enrichment complex of the U.S. Department of Energy at Piketon,
Ohio. The Company has electric transmission interconnections and/or
interconnection/interchange agreements with PSI Energy, Kentucky Utilities
Company, Southern Indiana Gas and Electric Company, The Cincinnati Gas &
Electric Company, Indiana Michigan Power Company, OVEC, Big Rivers Electric
Corporation, Tennessee Valley Authority, Wabash Valley Power Association,
Indiana Municipal Power Agency, East Kentucky Power Cooperative (East Kentucky),
Illinois Municipal Electric Agency, Jacksonville Electric Authority, and
Ogelthorpe Power Corporation providing for various interchanges, emergency
services, and other working arrangements.
The Company entered into an agreement with East Kentucky to provide about
40 megawatts of electricity to Gallatin Steel Company's (Gallatin) new steel
mill in north central Kentucky. The agreement will continue for 10 years and is
expected to result in approximately $6 million of revenues annually. Gallatin
makes steel for manufacturing plants in Kentucky. The Company will supply the
electricity from its power plants in the Louisville area. This transaction was
negotiated by LPM, an affiliate of the Company, and the terms of the transaction
were approved by the Kentucky Commission.
The Company and East Kentucky had an agreement that allowed East Kentucky
to purchase power during its peak season, and the Company to sell power during
its off-peak season. The
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agreement entitled East Kentucky to buy from the Company up to 145 megawatts
from mid-December to mid-February through 1994-95.
On February 28, 1991, the Company sold a 12.12% ownership interest in
Trimble County Unit 1 to the Illinois Municipal Electric Agency (IMEA), based in
Springfield, Illinois, which is an agency of 30 municipalities that own and
operate their own electric systems. On February 1, 1993, the Indiana Municipal
Power Agency (IMPA), based in Carmel, Indiana, purchased a 12.88% interest in
the Trimble County Unit. IMPA is composed of 31 municipalities that have joined
together to meet their long-term electric power needs. Both IMEA and IMPA pay
their proportionate share for operation and maintenance expenses of the Unit and
for fuel and reactant used. They are also responsible for their proportionate
share of incremental capital assets acquired.
Electric and magnetic fields (sometimes referred to as EMF) surround
electric wires or conductors of electricity such as electrical tools, household
wiring and appliances, and high voltage electric transmission lines such as
those owned by the Company. Certain studies have suggested a possible
association between electric and magnetic fields and adverse health effects.
The Electric Power Research Institute, of which the Company is a participating
member, has expended approximately $75 million since 1987 in its investigation
and research with regard to possible health effects posed by exposure to
electric and magnetic fields.
Gas Operations
The sources of gas operating revenues and the volumes of sales for the
three years ended December 31, 1994, were as follows:
<TABLE>
<CAPTION>
1994 1993 1992
---- ---- ----
<S> <C> <C> <C>
GAS OPERATING REVENUES
(Thousands of $):
Residential . . . . . . . . . . . . . . $ 110,553 $ 112,508 $ 96,175
Commercial. . . . . . . . . . . . . . . 40,474 43,568 36,801
Industrial. . . . . . . . . . . . . . . 27,956 28,310 26,156
Public authorities. . . . . . . . . . . 12,930 13,846 13,884
-------- ------- --------
Total-ultimate consumers. . . . . . . 191,913 198,232 173,016
Gas transportation-net. . . . . . . . . 6,759 5,147 4,169
Miscellaneous . . . . . . . . . . . . . 1,457 1,536 1,341
-------- ------- -------
Total . . . . . . . . . . . . . . . . $ 200,129 $ 204,915 $ 178,526
-------- ------- -------
-------- ------- -------
GAS SALES (Millions of cu. ft.):
Residential . . . . . . . . . . . . . . 22,935 24,330 22,465
Commercial. . . . . . . . . . . . . . . 9,450 10,308 9,527
Industrial. . . . . . . . . . . . . . . 7,505 7,817 8,077
Public authorities. . . . . . . . . . . 3,268 3,515 3,864
------- ------- -------
Total-ultimate consumers. . . . . . . 43,158 45,970 43,933
Gas transported . . . . . . . . . . . . 6,854 5,249 4,155
------- ------- -------
Total . . . . . . . . . . . . . . . . 50,012 51,219 48,088
------- ------- -------
------- ------- -------
</TABLE>
At December 31, 1994, the Company had 265,688 gas customers.
The Company has underground natural gas storage fields that help provide
economical and reliable gas service to ultimate consumers.
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Reflecting the changing nature of the gas business, a number of industrial
customers purchase their natural gas requirements directly from alternate
suppliers for delivery through the Company's distribution system. Generally,
transportation of natural gas for the Company's customers does not have an
adverse effect on earnings because of the offsetting decrease in gas supply
expenses. Transportation rates are designed to make the Company economically
indifferent as to whether gas is sold or merely transported.
The all-time maximum day gas sendout of 545,000 Mcf occurred on Sunday,
January 20, 1985, when the average temperature for the day was -11 degrees F.
During 1994, the maximum day gas sendout was 524,000 Mcf, occurring on
January 15, when the average temperature for the day was 2 degrees F. Supply on
that day consisted of 176,000 Mcf from purchases, 314,000 Mcf delivered from
underground storage, and 34,000 Mcf transported for industrial customers. For
further discussion, see Gas Supply.
In 1994, the Company experienced its first full year operating under FERC
Order No. 636. While the Company had previously been able to purchase natural
gas and pipeline transportation services from Texas Gas Transmission Corporation
(Texas Gas), the Company now purchases only transportation services from Texas
Gas pursuant to its FERC-approved tariff and acquires its supply of natural gas
from other sources. For further discussion see Gas Supply and Note 10 of Notes
to Financial Statements under Item 8.
Regulation and Rates
The Kentucky Commission has regulatory jurisdiction over the rates and
service of the Company and over the issuance of certain of its securities. The
Company is a "public utility" as defined in the Federal Power Act, and is
subject to the jurisdiction of the Department of Energy and the FERC with
respect to the matters covered in such Act, including the sale of electric
energy at wholesale in interstate commerce. In addition, the FERC has sole
jurisdiction over the issuance by the Company of short-term securities.
For a discussion of current regulatory matters, see Rates and Regulation
under Item 7 and Notes 2 and 11 of Notes to Financial Statements under Item 8.
Increases and decreases in the cost of fuel for electric generation are
reflected in the rates charged to all of the Company's electric customers by
means of the Company's fuel adjustment clause. The Kentucky Commission requires
public hearings at six-month intervals to examine past fuel adjustments, and at
two-year intervals for the purpose of additional examination and transfer of the
then current fuel adjustment charge or credit to the base charges. The
Commission also requires that electric utilities, including the Company, file
certain documents relating to fuel procurement and the purchase of power and
energy from other utilities.
The Company's gas rates contain a gas supply clause (GSC), whereby
increases or decreases in the cost of gas supply are reflected in the Company's
rates, subject to approval of the Kentucky Commission. The GSC procedure
prescribed by order of the Commission provides for quarterly rate adjustments to
reflect the expected cost of gas supply in that quarter. In addition, the GSC
contains a mechanism whereby any over- or under-recoveries of gas supply cost
from prior quarters will be refunded to or recovered from customers through the
adjustment factor determined for subsequent quarters.
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On January 1, 1994, the Company implemented a Commission approved demand
side management (DSM) program. The program contains a rate mechanism that
provides for the recovery of DSM program costs, allows the Company to recover
revenues due to lost sales associated with the DSM programs and provides the
Company an incentive for implementing DSM programs. See Rates and Regulation
under Item 7 for a further discussion of DSM.
On October 7, 1994, the Company filed an application with the Kentucky
Commission in which it requested approval of an environmental cost recovery
surcharge to recover certain costs required to comply with the Federal Clean Air
Act, as amended, and those federal, state, and local environmental requirements
which apply to coal combustion wastes and by-products from facilities utilized
for production of energy from coal. Under state law, the Commission has until
April 7, 1995, to rule on the application. If the Company's application is
approved as filed, the surcharge will increase electric revenues by
approximately $5.5 million in 1995 and $8.3 million in 1996. The Commission has
previously approved environmental cost recovery surcharges for two other
regulated electric utilities in Kentucky.
A management audit of Louisville Gas and Electric Company, which began in
September 1994, is nearing completion. Vantage Consulting Inc. is conducting
the audit under contract to the Kentucky Commission. Vantage has interviewed
some 300 employees and the Company has made written responses to more than 800
requests for data and documents. The final report is not expected until June.
A similar audit of the Company was conducted in 1986 under a mandate from the
1984 Kentucky General Assembly that requires such audits of the Commonwealth's
10 largest utilities.
As part of the corporate reorganization whereby the Company became the
subsidiary of LG&E Energy Corp., the Company obtained the approval of the
Kentucky Commission. The order of the Kentucky Commission authorizing the
Company to reorganize into a holding company structure contains certain
provisions, which, among other things, ensure the Kentucky Commission access to
books and records of Energy Corp. and its affiliates which relate to
transactions with the Company; require Energy Corp. and its subsidiaries to
employ accounting and other procedures and controls to protect against
subsidization of non-utility activities by the Company's customers; and preclude
the Company from guaranteeing any obligations of Energy Corp. without prior
written consent from the Kentucky Commission. In addition, such order provides
that the Company's Board of Directors has the responsibility to use its dividend
policy consistent with preserving the financial strength of the Company and that
the Kentucky Commission, through its authority over the Company's capital
structure, can protect the Company's ratepayers from the financial effects
resulting from non-utility activities.
Construction Program and Financing
The Company's construction program is designed to assure that there will be
adequate capacity to meet the future electric and gas needs of its service area.
These needs are continually being reassessed and appropriate revisions are made,
when necessary, in construction schedules. The Company's estimates of its
construction expenditures can vary substantially due to numerous items beyond
the Company's control, such as changes in rates, economic conditions,
construction costs, and new environmental or other governmental laws and
regulations.
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At December 31, 1994, the Company's embedded cost of long-term debt was
6.5% and its ratio of earnings to fixed charges was 3.14. See Exhibit 12. For
a further discussion of construction expenditures and financing, see Liquidity
and Capital Resources under Item 7.
During the five years ended December 31, 1994, gross property additions
amounted to $501 million. Internally generated funds for the five year period
were sufficient to provide for all of these gross additions. The gross
additions during this period amounted to approximately 20% of total utility
plant at December 31, 1994, and consisted of $391 million for electric
properties and $110 million for gas properties. Gross retirements during the
same period were $55 million, consisting of $44 million for electric properties
and $11 million for gas properties.
Coal Supply
Approximately 90% of the Company's present electric generating capacity is
coal-fired, the remainder being made up of a hydroelectric plant and combustion
turbine peaking units fueled by natural gas and oil. Coal will be the
predominant fuel used by the Company in the foreseeable future, with natural gas
and oil being used for peaking capacity and flame stabilization in coal-fired
boilers or in emergencies. The Company has no nuclear generating units and has
no plans to build any in the foreseeable future.
The Company has entered into coal supply agreements with various suppliers
for coal deliveries for 1995 and beyond. The Company normally augments its coal
supply agreements with spot market purchases which, during 1994, were about 10%
of total purchases. The Company has a coal inventory policy, which is in
compliance with the Kentucky Commission's directives and which the Company
believes provides adequate protection under most contingencies. The Company had
on hand at December 31, 1994, a coal inventory of approximately 580,000 tons, or
a 35 day supply.
The Company expects, for the foreseeable future, to continue purchasing
most of its coal from western Kentucky and southwest Indiana, which has a sulfur
content in the 2%-3.5% range. The abundant supply of this relatively low priced
coal, combined with present and future desulfurization technologies, is expected
to enable the Company to continue to provide adequate electric service in a
manner acceptable under existing environmental laws and regulations.
Coal for the Company's Mill Creek plant is delivered by rail and barge,
whereas deliveries to the Cane Run plant are primarily by rail and also by
truck. Deliveries to the Trimble County plant are by barge only.
The average delivered cost of coal purchased by the Company, per ton and
per million Btu, for the periods shown were as follows:
<TABLE>
<CAPTION>
1994 1993 1992
---- ---- ----
<S> <C> <C> <C>
Per ton . . . . . . . . . . . . . . $ 25.27 $ 26.58 $ 25.17
Per million Btu . . . . . . . . . . 1.10 1.14 1.09
</TABLE>
-8-
<PAGE>
Gas Supply
During 1994, the Company experienced its first full year of operation under
FERC Order No. 636. Although the Company continues to transport natural gas
supplies through Texas Gas at rates and terms regulated by the FERC, the Company
now purchases its supply of natural gas from other sources.
As a result of FERC Order No. 636 and effective November 1, 1993, the
Company entered into new transportation service agreements with Texas Gas.
These agreements provide for 30,000 MMBtu (29,268 Mcf) per day in Firm
Transportation (FT) throughout the year. This FT agreement expires October 31,
1995. During the winter months, the Company also has 184,900 MMBtu (180,390
Mcf) per day in No-Notice Service (NNS); during the summer months that NNS level
is 135,000 MMBtu (131,707 Mcf) per day. The Company's NNS agreements with Texas
Gas incorporate terms of two, five, and eight years, and include unilateral
roll-over provisions at the Company's option. These transportation services are
provided by Texas Gas pursuant to its FERC-approved tariff.
The Company has also entered into a series of long-term firm supply
arrangements with various suppliers in order to meet its firm sales obligations.
The gas supply arrangements include pricing provisions which are
market-responsive. These firm supplies, in tandem with pipeline transportation
services, provide the reliable and flexible supply needed to replace the bundled
sales service supplied by the pipeline prior to the implementation of FERC Order
No. 636.
During 1995, the Company will be participating in several regulatory
proceedings at FERC. In particular, the Company will be involved in reviewing
Texas Gas' most recent rate filing, and Texas Gas' filing to recover certain
transition costs associated with the FERC-mandated implementation of FERC Order
No. 636. As a separate matter, the Kentucky Commission has indicated in an
order issued in its Administrative Case No. 346 that transition costs, which are
clearly identified as being related to the cost of the commodity itself, are
appropriately recoverable as a gas cost through the Company's gas supply clause.
See Note 10 of Notes to Financial Statements under Item 8.
The Company operates five underground gas storage fields with a current
working gas capacity of 14.6 million Mcf. Gas is purchased and injected into
storage during the summer season and is then withdrawn to supplement pipeline
supplies to meet the gas-system load requirements during the winter heating
season.
The estimated maximum deliverability from storage during the early part of
the 1993-1994 heating season was approximately 373,000 Mcf per day.
Deliverability decreases during the latter portion of the heating season as the
storage inventory is reduced by seasonal withdrawals.
The average cost per Mcf of natural gas purchased by the Company was $2.78
in 1994, $2.91 in 1993, and $2.77 in 1992.
Environmental Matters
Protection of the environment is a major priority for the Company. The
Company engages in a variety of activities within the jurisdiction of federal,
state, and local regulatory agencies. Those agencies have issued the Company
permits for various activities subject to air quality, water quality,
-9-
<PAGE>
and waste management laws and regulations. For the five year period ending with
1994, expenditures for pollution control facilities represented $106 million or
21% of total construction expenditures. The cost of operating and maintaining
scrubber-related facilities amounted to $22 million in both 1994 and 1993. The
Company's anticipated capital expenditures for 1995 to comply with environmental
laws are approximately $16 million. See Note 10 of Notes to Financial
Statements under Item 8 for a discussion of specific environmental proceedings
affecting the Company.
Labor Relations
The Company's 1,625 operating, maintenance and construction employees are
members of the International Brotherhood of Electrical Workers (IBEW) Local
2100. The current three-year contract will expire in November 1995.
Employees
The Company had 2,650 full-time employees at December 31, 1994. During the
last quarter of 1993, the Company eliminated a number of full-time positions.
See Note 5 of Notes to Financial Statements under Item 8 for a further
discussion of this matter.
ITEM 2. PROPERTIES.
At February 28, 1995, the Company owned the following electric generating
stations:
<TABLE>
<CAPTION>
Year in
Service Capability Rating (Kw)
<S> <C> <C> <C>
Steam Stations:
Mill Creek-Kosmosdale, Ky.
Unit 1. . . . . . . . . . . . . . . . . . 1972 303,000
Unit 2. . . . . . . . . . . . . . . . . . 1974 301,000
Unit 3. . . . . . . . . . . . . . . . . . 1978 386,000
Unit 4. . . . . . . . . . . . . . . . . . 1982 466,000 1,456,000
-------
Cane Run-near Louisville, Ky.
Unit 3 (natural gas only) . . . . . . . . 1958 115,000
Unit 4. . . . . . . . . . . . . . . . . . 1962 155,000
Unit 5. . . . . . . . . . . . . . . . . . 1966 168,000
Unit 6. . . . . . . . . . . . . . . . . . 1969 240,000 678,000
-------
Trimble County-Bedford, Ky.
Unit 1. . . . . . . . . . . . . . . . . . 1990 371,000 (1)
Combustion Turbine Generators (Peaking capability):
Zorn. . . . . . . . . . . . . . . . . . . . 1969 16,000
Paddy's Run . . . . . . . . . . . . . . . . 1968 43,000
Cane Run. . . . . . . . . . . . . . . . . . 1968 16,000
Waterside . . . . . . . . . . . . . . . . . 1964 33,000 108,000
------ ---------
2,613,000
---------
---------
<FN>
(1) Amount shown represents the Company's 75% interest in the Unit.
See Note 12 of Notes to Financial Statements, Jointly Owned
Electric Utility Plant, under Item 8 for a discussion of the sale
of 25% of the Unit to IMEA and IMPA. The Company is responsible
for operation of the Unit and is reimbursed by IMEA and IMPA for
expenditures related to the Unit based on their proportionate
share of ownership interest.
</TABLE>
-10-
<PAGE>
The Company's steam stations consist mainly of coal-fired units except for
Cane Run Unit 3 which must use natural gas because of restrictions mandated by
environmental regulations.
The Company also owns an 80 Mw hydroelectric generating station located in
Louisville, operated under license issued by the FERC.
At December 31, 1994, the Company's electric transmission system included
21 substations with a total capacity of approximately 10,623,697 Kva and
approximately 648 structure miles of lines. The electric distribution system
included 83 substations with a total capacity of approximately 3,068,277 Kva,
3,505 structure miles of overhead lines, 233 miles of underground conduit, and
5,335 miles of underground conductors.
The Company's gas transmission system includes 177 miles of transmission
mains, and the gas distribution system includes 3,312 miles of distribution
mains.
The Company operates underground gas storage facilities with a current
working gas capacity of approximately 14.6 million Mcf. See Gas Supply under
Item 1.
In 1990, the Company entered into an operating lease for its corporate
office building located in downtown Louisville, Kentucky. The lease is for a
period of 15 years and is scheduled to expire June 30, 2005.
Other properties owned by the Company include office buildings, service
centers, warehouses, garages, and other structures and equipment, the use of
which is common to both the electric and gas departments.
The trust indenture securing the Company's First Mortgage Bonds constitutes
a direct first mortgage lien upon substantially all property owned by the
Company.
ITEM 3. LEGAL PROCEEDINGS.
Rates, Regulatory Matters, and Trimble County Generating Plant
For a discussion of current regulatory matters and a detailed discussion of
the current status concerning Trimble County Unit 1, see Rates and Regulation
under Item 7 and Notes 2 and 11 of Notes to Financial Statements under Item 8.
Statewide Power Planning
As required by the regulations of the Kentucky Commission, on November 15,
1993, the Company filed its 1993 biennial Integrated Resource Plan with the
Kentucky Commission. The plan, which updates the Company's first Integrated
Resource Plan filed in 1991, proposes to meet customers' future demand through
2007 by adding resources in small increments such as short-term power purchases
(1996-1999), a customer-owned standby generation program (1997), two combustion
turbines (1999-2000), an air conditioner load controls program (1997,
2001-2003), an upgrade to the Company's existing hydroelectric plant (2003), and
a compressed air energy storage plant (2004). The Kentucky Commission staff is
reviewing the Company's plan, and is expected to issue its report
-11-
<PAGE>
and recommendations concerning the plan during the first quarter of 1995. The
Kentucky Commission's regulations do not require it to hold any hearings or
issue any formal orders regarding the plan.
Environmental
For a complete discussion of the Company's environmental issues concerning
its Mill Creek and Cane Run generating plants, manufactured gas plant sites, and
certain other environmental issues, see Note 10 of Notes to Financial Statements
under Item 8.
Other
The Company is a defendant in lawsuits seeking compensatory and, in certain
instances, punitive damages. To the extent that damages are assessed in any of
these lawsuits, the Company believes that its insurance coverage is adequate and
that the effect of any such damages will not be material to the Company's
results of operation or financial position.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None
-----------------------------
-12-
<PAGE>
Executive Officers of the Company.
Effective Date of
Election to
Name Age Position Present Position
- ---- --- -------- -----------------
Roger W. Hale 51 Chairman of the Board and
Chief Executive Officer January 1, 1992
Victor A. Staffieri 39 President January 1, 1994
John R. McCall 51 Executive Vice President,
General Counsel and
Corporate Secretary July 1, 1994
David R. Carey 41 Senior Vice President,
Operations January 1, 1994
M. Lee Fowler 58 Vice President and
Controller September 1, 1988
Wendy C. Heck 41 Vice President, Information
Services January 1, 1994
Chris Hermann 47 Vice President and General
Manager, Wholesale
Electric Business January 1, 1993
Rebecca L. Holt 35 Vice President, Gas Service
Business February 15, 1995
Charles A. Markel III 47 Treasurer January 1, 1993
The present term of office of each of the above executive officers extends
to the meeting of the Board of Directors following the Annual Meeting of
Stockholders, scheduled to be held April 25, 1995.
There are no family relationships between executive officers of the
Company.
Mr. Hale, Mr. Carey, Mr. Fowler, Ms. Heck, Mr. Hermann, and Mr. Markel have
been employed for more than five years in executive or management positions with
the Company. Prior to election to the position shown in the table, the
following executive officers held other positions with the Company since January
1, 1990: Mr. Hale was President and Chief Executive Officer prior to
February 1990, and Chairman of the Board, President and Chief Executive Officer
thereafter; Mr. Carey was Vice President-Marketing and Sales prior to July 1990,
Vice President-Marketing and Planning prior to January 1992, Vice
President-Marketing and General Manager, Electric Service, prior to
January 1993, and Vice President and General Manager, Retail Electric Business
thereafter; Ms. Heck was Vice President-Internal Auditing prior to January 1992,
Vice President-Fuels and Operating Services prior to January 1993, and Vice
President-Fuels and Information Services thereafter; Mr. Hermann was General
Manager-Power Production prior to January 1992 and General Manager-Wholesale
Electric thereafter; Mr. Markel was Vice President and Treasurer prior to
March 1990, Vice President-Finance and Treasurer prior to January 1992, and
Senior Vice President and Chief Financial Officer thereafter. Effective
January 1993, Mr. Markel was named Corporate Vice President-Finance and
Treasurer of the parent company, LG&E Energy Corp.
-13-
<PAGE>
Prior to election to his current position, Mr. Staffieri was Senior Vice
President-Public Policy, and General Counsel of the Company, and prior to
November 1992, Senior Vice President, General Counsel and Corporate Secretary.
Prior to March 1992, Mr. Staffieri was employed by Long Island Lighting Company
and held the position of General Counsel and Secretary.
Prior to election to his current position, Mr. McCall was Partner and
Litigation Chairman of Brown, Todd & Heyburn, a law firm.
Prior to election to her current position, Ms. Holt was employed by South
Carolina Electric and Gas Company and held the position of General Manager, Gas
Operations from July 1994 to February 1995, Division Manager, Central
Division-Gas Operations prior to July 1994, General Manager, Northern
Division-Gas Operations prior to February 1992, and Manager, Columbia Gas
Operations prior to July 1990.
-14-
<PAGE>
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
All Louisville Gas and Electric Company common stock, 21,294,223 shares, is
held by LG&E Energy Corp. Therefore, there is no public trading market for the
Company's common stock.
The following table sets forth the cash distributions on common stock paid
to LG&E Energy Corp. for the periods indicated:
<TABLE>
<CAPTION>
1994 1993
---- ----
(Thousands of $)
<S> <C> <C>
First Quarter. . . . . . . . $17,500 $17,000
Second Quarter . . . . . . . 17,500 16,500
Third Quarter. . . . . . . . - 16,500
Fourth Quarter . . . . . . . 18,000 17,000
</TABLE>
ITEM 6. SELECTED FINANCIAL DATA.
<TABLE>
<CAPTION>
Years Ended December 31
(Thousands of $)
------------------------------------------------------------------------------
1994 1993 1992 1991 1990
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Operating Revenues . . . . . . . . . . $759,075 $775,125 $700,195 $708,706 $698,758
------- ------- ------- ------- -------
Net Operating Income:
Before Non-Recurring Charges. . . . 149,653 136,118 125,829 142,730 137,717
Non-Recurring Charges . . . . . . . 38,613 - - - -
------- ------- ------- ------- -------
Total. . . . . . . . . . . . . . 111,040 136,118 125,829 142,730 137,717
------- ------- ------- ------- -------
Net Income:
Before Non-Recurring Charges, etc.. 94,423 90,535 73,793 94,643 83,450
Non-Recurring Charges,
Charitable Foundation, etc.. . . 32,734 - - - -
Cumulative Effect of
Accounting Change. . . . . . . . (3,369) - - - 18,236
------- ------- ------- ------- -------
Total Net Income . . . . . . . . 58,320 90,535 73,793 94,643 101,686
------- ------- ------- ------- -------
Net Income Available for
Common Stock . . . . . . . . . . . . 52,492 84,554 66,620 85,179 92,221
Total Assets . . . . . . . . . . . . . 1,966,590 1,974,584 1,960,860 1,936,909 1,985,872
Long-Term Obligations (including
amounts due within one year) . . . . 662,800 662,800 686,262 687,662 688,250
</TABLE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION.
The following discussion and analysis by management focuses on those
factors that had a material effect on the Company's financial results of
operations and financial condition during 1994, 1993, and 1992 and should be
read in connection with the financial statements and notes thereto.
-15-
<PAGE>
Results of Operations
Net Income Available for Common Stock
In 1994 the Company's net income available for common stock decreased $32.1
million. This decrease was due to the write-off of certain non-recurring items
($23.8 million), the expense of establishing a charitable foundation ($8.9
million), and the adoption of Statement of Financial Accounting Standards
No. 112, EMPLOYERS' ACCOUNTING FOR POST-EMPLOYMENT BENEFITS ($3.4 million).
Without consideration of the charges against income discussed above, the
Company's 1994 income would have increased $3.9 million over 1993. This
improvement is primarily due to increased sales of electricity to retail
customers and reduced interest on debt due to favorable refinancing activities
in 1993.
The $17.9 million increase in earnings for 1993 over 1992 resulted
primarily from increased electric sales attributable to warmer summer weather
experienced in 1993, higher sales to other utilities, reduced costs for debt and
preferred stock attributable to favorable refinancing activities, and a gain
recognized on the sale of the remaining disallowed portion of the Trimble County
plant to the Indiana Municipal Power Agency (IMPA). These items were partially
offset by a higher level of operation and maintenance expense.
Rates and Regulation
The Company is subject to the jurisdiction of the Public Service Commission
of Kentucky (Kentucky Commission or Commission) in virtually all matters related
to electric and gas utility regulation, and as such, its accounting is subject
to Statement of Financial Accounting Standards No. 71, ACCOUNTING FOR THE
EFFECTS OF CERTAIN TYPES OF REGULATION (SFAS No. 71). Given the Company's
competitive position in the market and the status of regulation in the state of
Kentucky, the Company has no plans or intentions to discontinue its application
of SFAS No. 71. See Note 2 of Notes to Financial Statements under Item 8.
The Company last filed for a rate increase with the Commission in June 1990
based on the test-year ended April 30, 1990. A final order was issued in
September 1991 that effectively granted the Company an annual increase in rates
of $6.8 million ($6.1 million electric and $.7 million gas). The Commission's
order authorized a rate of return on common equity of 12.5%.
On October 7, 1994, the Company filed an application with the Kentucky
Commission in which it requested approval of an environmental cost recovery
surcharge to recover certain costs required to comply with the Federal Clean Air
Act, as amended, and those federal, state, and local environmental requirements
which apply to coal combustion wastes and by-products from facilities utilized
for production of energy from coal. Under state law, the Commission has until
April 7, 1995, to rule on the application. If the Company's application is
approved as filed, the surcharge will increase electric revenues by
approximately $5.5 million in 1995 and $8.3 million in 1996. The Commission has
previously approved environmental cost recovery surcharges for two other
regulated electric utilities in Kentucky.
On January 1, 1994, the Company implemented a Commission approved demand
side management (DSM) program that the Company, the Kentucky Attorney General,
the Jefferson County Attorney, and representatives of several customer-interest
groups had filed with the Commission.
-16-
<PAGE>
Under the agreement, the Company will commit up to $3.3 million over three years
(from 1994 through 1996) for initial programs that include a residential energy
conservation and education program and a commercial conservation audit program.
Future programs will be developed through a formal collaborative process. The
agreement contains a rate mechanism that will (1) provide the Company concurrent
recovery of DSM program costs, (2) provide the Company an incentive for
implementing DSM programs, and (3) allow the Company to recover revenues due to
lost sales associated with the DSM programs.
Revenues from lost sales to residential customers are collected through a
"decoupling mechanism". The Company's residential decoupling mechanism breaks
the link between the level of the Company's residential kilowatt-hour and Mcf
sales and its non-fuel revenues. Under traditional regulation, a utility's
revenue varies with changes in its level of kilowatt-hour or Mcf sales. The
residential decoupling mechanism allows the Company to recover a predetermined
level of revenue per residential customer based on the rate set in the Company's
last rate case, which will not vary with the level of kilowatt-hour or Mcf
sales. Residential revenues will be adjusted to reflect (1) changes in the
number of residential customers and (2) a pre-established annual growth factor
in residential revenue per customer. Decoupling, in effect, removes the impact
on the Company's non-fuel revenues from changes in kilowatt-hour or Mcf sales
due to weather, fluctuations in the economy, and conservation efforts. Under
this mechanism, if actual sales produce lower revenues than are produced by the
predetermined per-customer amount, the difference is deferred for recovery from
customers through an adjustment in rates over a period that will not exceed two
years. Conversely, if actual sales produce more revenues than would be realized
using the predetermined per-customer amount, the difference will be returned to
customers through subsequent rate adjustments over a period not to exceed two
years. Residential revenues reported in the financial statements for 1994
through 1996 will be determined in accordance with the predetermined amount per
customer plus growth, and recovery of fuel and gas costs. The difference
between the revenues shown in the financial statements and the amounts billed to
customers will be deferred for future recovery from, or return to, customers.
As more fully discussed in Note 11 of Notes to Financial Statements under
Item 8, the Commission has scheduled a formal hearing on May 9, 1995, to
determine the appropriate ratemaking treatment to exclude 25% of the Trimble
County plant from customer rates. The Company is unable to predict the outcome
of the Commission proceedings, or the amount of additional refunds or
recoveries, if any, that may be ordered.
On May 24, 1993, the Federal Energy Regulatory Commission (FERC) gave final
approval for a market-based rate tariff and two transmission service tariffs
that were filed by the Company. This market-based tariff enables the Company to
sell up to 75 Mw of firm generation capacity at market-based rates. It also
enables the Company to sell an unlimited amount of non-firm power at market-
based rates, as long as the power is from the Company's own generation
resources. In 1994, the Company made its first power sales under its
market-based tariff.
Although the Company has both firm and non-firm open access transmission
rate schedules which were approved by FERC in 1994, the Company took the
additional steps of filing a new network transmission service and a new flexible
point-to-point transmission service to provide transmission service to other
parties comparable to the transmission service the Company provides itself.
-17-
<PAGE>
The Company is currently undergoing a planned management and operations
audit initiated by the Kentucky Commission. The audit results will include an
evaluation of the Company's operations and identify opportunities for
improvements. An audit report is scheduled to be issued by mid-1995.
Revenues
A comparison of operating revenues for the years 1994 and 1993 with the
immediately preceding years reflects both increases and decreases, which have
been segregated by the following principal causes (in thousands of $):
<TABLE>
<CAPTION>
Increase (Decrease) From Prior Period
--------------------------------------------------------------
Electric Revenues Gas Revenues
------------------------- ------------------------
Cause 1994 1993 1994 1993
----- ---- ---- ---- ----
<S> <C> <C> <C> <C>
Sales to Ultimate Consumers:
Fuel and gas supply adjustments, etc. . . $ (841) $ 6,832 $ 1,823 $19,479
Demand side management/decoupling . . . . 1,853 - 3,997 -
Variation in sales volumes. . . . . . . . 3,876 27,386 (12,139) 5,737
------- ------ ------- ------
Total. . . . . . . . . . . . . . . . . 4,888 34,218 (6,319) 25,216
Sales for resale . . . . . . . . . . . . . . . (16,239) 13,261 - -
Gas transportation-net . . . . . . . . . . . . - - 1,612 978
Other. . . . . . . . . . . . . . . . . . . . . 87 1,062 (79) 195
------- ------ ------- ------
Total. . . . . . . . . . . . . . . . . $(11,264) $48,541 $ (4,786) $26,389
------- ------ ------- ------
------- ------ ------- ------
</TABLE>
The Company's electric revenues decreased in 1994 compared with 1993
primarily because of a decrease in the sales of electricity for resale. Gas
sales to ultimate consumers decreased 6% due primarily to the warmer than normal
weather in the last quarter of 1994.
Electric revenues increased in 1993 primarily because of the warmer summer
weather. Sales of electricity for resale increased over 1992 levels due to the
Company's aggressive efforts in marketing off-system sales of energy. The
increase in gas sales for 1993 is largely attributable to cooler winter weather
in the region and customer growth.
Expenses
Fuel for electric generation and gas supply expenses comprise a large
segment of the Company's total operating costs. The Company's electric and gas
rates contain a fuel adjustment clause and a gas supply clause, respectively,
whereby increases or decreases in the cost of fuel and gas supply are reflected
in the Company's rates, subject to the approval by the Commission.
Fuel expenses decreased $5.8 million (4%) in 1994 primarily because of a
decrease in the cost of coal burned ($3.9 million) and decreased generation of
3%. Fuel expenses for 1993 increased $13.8 million over 1992 because of
increased generation. The average delivered cost per ton of coal purchased was
$25.27 in 1994, $26.58 in 1993, and $25.17 in 1992.
Power purchased decreased $7.5 million in 1994 primarily because less power
was wheeled for other utilities as a result of milder weather in the region.
The increase of $5.2 million in 1993 was largely attributable to more power
purchased because of wheeling arrangements with other utilities.
-18-
<PAGE>
Gas supply expenses decreased $7.5 million (5%) in 1994 due mainly to a
decrease in the volume of gas delivered to the distribution system ($9.2
million), partially offset by an increase in net gas supply cost ($1.7 million).
Gas supply expenses for 1993 increased $23.5 million primarily because of an
increase in net gas supply cost ($17.6 million) and a 5% increase in the volume
of gas delivered to the distribution system. The average unit cost per Mcf of
purchased gas was $2.78 in 1994, $2.91 in 1993, and $2.77 in 1992.
Other operation expenses decreased $.5 million in 1994 mainly as a result
of decreases in various administrative expenses ($1.8 million), partially offset
by increased costs to operate electric generating plants and gas and electric
distribution systems ($.7 million), and an increase in the provision for
uncollectible accounts ($.6 million). Maintenance expenses were up only
slightly over 1993. In 1993, operation expenses increased $6 million (5%) over
1992 primarily because of increased costs of electric generating plants ($2
million), and an increase in various administrative expenses ($4.2 million).
The 1993 maintenance expenses increased $1.5 million (3%), primarily due to
increased repairs at the electric generating plants.
Non-recurring charges include the Company's write-off of costs in
connection with early retirements and workforce reductions that occurred in 1992
and 1993, costs in connection with property damage claims pertaining to
particulate emissions from the Mill Creek electric generating plant, and certain
costs previously deferred resulting from adoption of Statement of Financial
Accounting Standards No. 106, EMPLOYERS' ACCOUNTING FOR POST-RETIREMENT BENEFITS
OTHER THAN PENSIONS. See Notes 2 and 3 of Notes to Financial Statements under
Item 8.
Depreciation and amortization increased in both 1994 and 1993 because of
additional depreciable plant in service.
Variations in income tax expenses are largely attributable to changes in
pre-tax income and an increase in the corporate Federal income tax rate from 34%
to 35%, effective January 1, 1993.
Other income and (deductions) increased $.5 million in 1994 partially due
to recognition of a gain on the sale of construction equipment. Other income
and (deductions) increased in 1993 primarily because of a $3.2 million after-tax
gain recorded on the sale of a 12.88% ownership interest in the Trimble County
plant to IMPA. See Note 7 of Notes to Financial Statements under Item 8 for
further detail.
Contribution to the charitable foundation reflects the expense associated
with establishing a tax-exempt foundation during 1994. Contributions made from
this Foundation will not be charged against income, and therefore, will not
affect the Company's net income in the future. See Note 3 of Notes to Financial
Statements under Item 8.
Interest charges decreased in 1994 because of the lower composite interest
rate on outstanding debt, which reflects the full year effect of the Company's
1993 aggressive program to refinance approximately $205 million of outstanding
debt at lower interest rates. Interest charges also decreased in 1993 as
compared to 1992 primarily because of this refinancing program. Since 1992, an
immaterial component of interest expense has been the cost associated with
interest rate swaps. See Liquidity and Capital Resources.
Preferred dividends reflect the lower dividends that resulted from the
Company's refunding its $25 million, $8.90 Series with a $5.875 Series in May
1993.
-19-
<PAGE>
The rate of inflation may have a significant impact on the Company's
operations, its ability to control costs, and the need to seek timely and
adequate rate adjustments. However, relatively low rates of inflation in the
past few years have moderated the impact on current operating results.
LIQUIDITY AND CAPITAL RESOURCES
The Company's need for capital funds is primarily related to the
construction of plant and equipment necessary to meet the needs of electric and
gas utility customers and protection of the environment.
1994 Capital Requirements
New construction expenditures for 1994 were $95 million compared with $99
million for 1993 and $101 million for 1992.
Past Financing Activities
During 1994, 1993, and 1992, the Company's primary source of capital was
internally generated funds from operating cash flows. Internally generated
funds provided financing for 100% of the Company's construction expenditures for
1994 and 1993 and 87% of utility capital expenditures in 1992. Variations in
accounts receivable and accounts payable are not generally significant
indicators of the Company's liquidity, as such variations are primarily
attributable to fluctuations in weather in the Company's service territory,
which has a direct effect on sales of electricity and gas. In 1994, accounts
receivable and accounts payable were lower due to warmer weather in the last
quarter of the year as compared to 1993.
In 1993, the Company refinanced approximately $205 million of its long-term
debt and $25 million of its preferred stock. These refinancings produced
significant savings from lower interest rates and preferred dividend rates in
1994 and 1993. See Note 8 of Notes to Financial Statements under Item 8.
The Company's liquidity was also positively affected in 1993 by the sale of
a 12.88% portion of the Company's Trimble County Generating Unit. At
December 31, 1994, marketable securities classified as Other Property and
Investments amounted to $50 million. See Note 4 of Notes to Financial
Statements under Item 8.
The Company has outstanding interest rate swap agreements with a notional
amount of $30 million. These swaps were entered into as a standard hedging
device in connection with the 1992 issuance of the Company's Pollution Control
Bonds Series S, due September 1, 2017. The swaps are designed to reduce the
Company's exposure to interest rate risk. Under the agreements, the Company
pays a fixed rate of 4.35% on $15 million for a five-year period and 4.74% on
$15 million for a seven-year period resulting in interest payments based on a
composite rate of 4.55% in 1994, 1993, and 1992. In return, the Company
receives a floating rate based on the weighted average JJ Kenny index. The
Company received interest at composite rates of 2.84%, 2.38%, and 2.73% in 1994,
1993, and 1992, respectively.
-20-
<PAGE>
Future Capital Requirements
Future financing requirements may be affected in varying degrees by factors
such as load growth, changes in construction expenditure levels, rate increases
allowed by regulatory agencies, new legislation, market entry of competing
electric power generators, changes in environmental regulations and other
regulatory requirements. The Company estimates construction expenditures will
total $200 million for 1995 and 1996. In addition, expected capital
requirements for 1996 include $16 million to retire long-term debt.
Future Sources of Financing
Internally generated funds from operations are expected to fund
substantially all anticipated construction expenditures in 1995 and 1996.
At December 31, 1994, the Company had unused lines of credit of $145
million for which it pays commitment fees. These credit facilities are
scheduled to expire at various periods during 1995 and 1996 and management
intends to renegotiate them when they expire.
To the extent permanent financings are needed in 1995 and 1996, the Company
expects that it will have ready access to the securities markets to raise needed
funds.
Environmental Matters
The Clean Air Act Amendments of 1990 impose stringent limits on emissions
of sulfur dioxide and nitrogen oxides by electric utility generating plants.
All of the Company's coal-fired boilers are equipped with sulfur dioxide
"scrubbers" and already achieve the final sulfur dioxide emission rates required
by the year 2000 under the legislation. However, as part of its ongoing
construction program, the Company has spent $10 million to date and anticipates
incurring capital expenditures of approximately $29 million through 1996 for
remedial measures necessary to meet the Act's requirements for nitrogen oxides.
The overall financial impact of the legislation on the Company is expected to be
minimal. The Company is well-positioned in the market to be a "clean" power
provider without the large capital expenditures that are expected to be incurred
by many other utilities.
Reference is made to Note 10 of Notes to Financial Statements,
Environmental, under Item 8 for a complete discussion of the Company's
environmental issues concerning its Mill Creek and Cane Run electric generating
plants, manufactured gas plant sites, and certain other environmental issues.
Energy Policy Act of 1992
The Energy Policy Act of 1992 is designed to give utilities a wider choice
of sources for their electrical supply than previously available, while creating
generating supply options that did not exist under the old law. In passing this
legislation, Congress also anticipated that greater competition among electric
supply options should result in lower consumer rates. The Company plans to
aggressively pursue opportunities created by a more competitive electric power
market.
-21-
<PAGE>
FERC Order No. 636
In 1994, the Company experienced its first full year of operations under
the provisions of Order No. 636. During 1994, the Company paid and began
recovering from its customers approximately $2.8 million in transition costs
under Order No. 636. It is estimated that $6 million to $8 million in
additional transition costs will be incurred by the Company during 1995, and
these costs are also expected to be recovered from customers. See FERC Order
No. 636 in Note 10 of Notes to Financial Statements under Item 8 for further
discussion.
FUTURE OUTLOOK
Business Realignment
Effective January 1, 1994, LG&E Energy Corp. realigned its business to
reflect its outlook for rapidly emerging competition in all segments of the
energy services industry. Under the realignment, a national business unit, LG&E
Energy Services was formed to develop and manage all of its utility and
non-utility electric power generation and concentrate on the marketing and
brokering of wholesale electric power on a regional and national basis.
Louisville Gas and Electric Company, LG&E Energy Corp.'s principal subsidiary,
will increase its focus on customer service and develop more customer options as
the utility industry becomes more competitive.
As part of the business realignment, a new subsidiary was formed to market
power throughout the United States. LG&E Power Marketing Inc. (LPM), an
indirect wholly owned subsidiary of LG&E Energy Corp., was among the first
utility-affiliated marketers in the country to secure FERC approval to sell
power at market-based rates and engage in wholesale power marketing activities.
The realignment does not affect LG&E Energy Corp.'s legal structure,
regulation of the Company by the Commission or LG&E Energy Corp.'s status as an
exempt holding company.
Gallatin Steel Company
The Company entered into an agreement with East Kentucky Power Cooperative,
Inc. to provide about 40 megawatts of electricity to Gallatin Steel Company's
(Gallatin) new steel mill in north central Kentucky. The agreement will
continue for 10 years and is expected to result in approximately $6 million of
revenues annually. Gallatin makes steel for manufacturing plants in Kentucky.
The Company will supply the electricity from its power plants in the Louisville
area. This transaction was negotiated by LPM, and the terms of the transaction
were approved by the Commission.
Competition
The Company has taken many steps to prepare for the expected increase in
competition in its industry, including a reduction in the number of employees;
aggressive cost cutting; a write-off of previously deferred expenses; an
increase in focus on commercial and industrial customers; an increase in
employee involvement and training; and a major realignment and formation of new
business units.
-22-
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
LOUISVILLE GAS AND ELECTRIC COMPANY
STATEMENTS OF INCOME
(Thousands of $)
<TABLE>
<CAPTION>
Years Ended December 31
------------------------------------------------------
1994 1993 1992
---- ---- ----
<S> <C> <C> <C>
Operating Revenues
Electric . . . . . . . . . . . . . . . . . . . . . . . $ 558,946 $ 570,210 $ 521,669
Gas. . . . . . . . . . . . . . . . . . . . . . . . . . 200,129 204,915 178,526
------- ------- -------
Total operating revenues (Note 1). . . . . . . . . . 759,075 775,125 700,195
------- ------- -------
Operating Expenses
Fuel for electric generation . . . . . . . . . . . . . 143,602 149,436 132,551
Power purchased. . . . . . . . . . . . . . . . . . . . 9,754 17,228 12,044
Gas supply expenses. . . . . . . . . . . . . . . . . . 131,561 139,054 115,521
Other operation expenses . . . . . . . . . . . . . . . 136,214 136,693 130,740
Maintenance. . . . . . . . . . . . . . . . . . . . . . 48,731 48,414 46,931
Non-recurring charges (Note 3) . . . . . . . . . . . . 38,613 - -
Depreciation and amortization. . . . . . . . . . . . . 82,519 79,655 76,903
Federal and State income taxes (Note 6). . . . . . . . 39,922 52,334 43,840
Property and other taxes . . . . . . . . . . . . . . . 17,119 16,193 15,836
------ ------ ------
Total operating expenses . . . . . . . . . . . . . . 648,035 639,007 574,366
------- ------- -------
Net Operating Income . . . . . . . . . . . . . . . . . . 111,040 136,118 125,829
Other Income and (Deductions) (Note 7) . . . . . . . . . 2,451 1,913 (2,203)
Contribution to Charitable Foundation - net (Note 3) . . 8,946 - -
Interest Charges . . . . . . . . . . . . . . . . . . . . 42,856 47,496 49,833
------ ------ ------
Income before Cumulative Effect of a Change in
Accounting Principle . . . . . . . . . . . . . . . . . 61,689 90,535 73,793
Cumulative Effect of a Change in Accounting for
Post-Employment Benefits, net of income taxes
of $2,280 (Note 5) . . . . . . . . . . . . . . . . . . (3,369) - -
------ ------ ------
Net Income . . . . . . . . . . . . . . . . . . . . . . . 58,320 90,535 73,793
Preferred Stock Dividends. . . . . . . . . . . . . . . . 5,828 5,981 7,173
------ ------ ------
Net Income Available for Common Stock. . . . . . . . . . $ 52,492 $ 84,554 $ 66,620
------ ------ ------
------ ------ ------
</TABLE>
<TABLE>
<CAPTION>
STATEMENTS OF RETAINED EARNINGS
(Thousands of $)
Years Ended December 31
-----------------------------------------------------
1994 1993 1992
---- ---- ----
<S> <C> <C> <C>
Balance January 1. . . . . . . . . . . . . . . . . . . . $ 194,903 $ 178,667 $ 181,694
Add net income . . . . . . . . . . . . . . . . . . . . . 58,320 90,535 73,793
------- ------- -------
253,223 269,202 255,487
------- ------- -------
Deduct: Cash dividends declared on stock:
5% cumulative preferred . . . . . . . . . . . . 1,075 1,075 1,076
7.45% cumulative preferred. . . . . . . . . . . 1,598 1,598 1,598
$8.72 cumulative preferred. . . . . . . . . . . - - 454
$8.90 cumulative preferred. . . . . . . . . . . - 1,113 2,225
$9.54 cumulative preferred. . . . . . . . . . . - - 497
Auction rate cumulative preferred . . . . . . . 1,686 1,322 1,323
$5.875 cumulative preferred . . . . . . . . . . 1,469 873 -
Common. . . . . . . . . . . . . . . . . . . . . 53,500 67,500 67,500
Preferred stock redemption expense. . . . . . . . - 818 2,147
------- ------- -------
59,328 74,299 76,820
------- ------- -------
Balance December 31. . . . . . . . . . . . . . . . . . . $ 193,895 $ 194,903 $ 178,667
------- ------- -------
------- ------- -------
</TABLE>
The accompanying notes are an integral part of these financial statements.
-23-
<PAGE>
<TABLE>
<CAPTION>
LOUISVILLE GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Thousands of $)
ASSETS
December 31
----------------------------------------
1994 1993
---- ----
<S> <C> <C>
Utility Plant, at original cost
Electric . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,084,334 $ 2,019,139
Gas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 280,877 260,485
Common . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 137,662 132,692
--------- ---------
2,502,873 2,412,316
Less: Reserve for depreciation. . . . . . . . . . . . . . . . . . 881,861 823,141
--------- ---------
1,621,012 1,589,175
Construction work in progress. . . . . . . . . . . . . . . . . . . 35,022 51,785
--------- ---------
1,656,034 1,640,960
--------- ---------
Other Property and Investments - less reserve (Note 4) 50,681 22,067
--------- ---------
Current Assets
Cash and temporary cash investments. . . . . . . . . . . . . . . . 39,138 44,105
Accounts receivable - less reserve of
$1,203 in 1994 and $1,474 in 1993. . . . . . . . . . . . . . . . 86,058 104,397
Materials and supplies - at average cost
Fuel (predominantly coal). . . . . . . . . . . . . . . . . . . . 13,869 12,075
Gas stored underground . . . . . . . . . . . . . . . . . . . . . 31,354 33,370
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37,299 40,357
Prepayments. . . . . . . . . . . . . . . . . . . . . . . . . . . . 253 360
--------- ---------
207,971 234,664
--------- ---------
Deferred Debits and Other Assets
Unamortized debt expense . . . . . . . . . . . . . . . . . . . . . 7,776 8,076
Regulatory assets (Note 2) . . . . . . . . . . . . . . . . . . . . 31,726 61,642
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12,402 7,175
--------- ---------
51,904 76,893
--------- ---------
$ 1,966,590 $ 1,974,584
--------- ---------
--------- ---------
CAPITAL AND LIABILITIES
Capitalization (see Statements of Capitalization)
Common equity. . . . . . . . . . . . . . . . . . . . . . . . . . . $ 616,478 $ 619,237
Cumulative preferred stock . . . . . . . . . . . . . . . . . . . . 116,716 116,716
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . 662,862 662,879
--------- ---------
1,396,056 1,398,832
--------- ---------
Current Liabilities
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . 70,770 93,551
Dividends declared . . . . . . . . . . . . . . . . . . . . . . . . 19,567 18,878
Accrued taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . 8,247 9,494
Accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . 13,394 12,864
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,277 11,127
--------- ---------
122,255 145,914
--------- ---------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes (Notes 1 and 6). . . . . . . . . 275,814 281,560
Investment tax credit, in process of amortization. . . . . . . . . 88,779 91,572
Accumulated provision for pensions and related benefits. . . . . . 49,104 31,536
Customers' advances for construction . . . . . . . . . . . . . . . 8,621 7,384
Regulatory liability (Note 2). . . . . . . . . . . . . . . . . . . 8,914 6,876
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17,047 10,910
--------- ---------
448,279 429,838
--------- ---------
Commitments and Contingencies (Notes 10 and 11)
$ 1,966,590 $ 1,974,584
--------- ---------
--------- ---------
</TABLE>
The accompanying notes are an integral part of these financial statements.
-24-
<PAGE>
LOUISVILLE GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(Thousands of $)
<TABLE>
<CAPTION>
Years Ended December 31
------------------------------------------
1994 1993 1992
---- ---- ----
<S> <C> <C> <C>
Cash Flows from Operating Activities
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 58,320 $ 90,535 $ 73,793
Items not requiring cash currently:
Cumulative effect of change in accounting principle. . . . . . . . . 3,369 - -
Non-recurring charges. . . . . . . . . . . . . . . . . . . . . . . . 38,613 - -
Depreciation and amortization. . . . . . . . . . . . . . . . . . . . 82,519 79,887 79,686
Deferred income taxes - net. . . . . . . . . . . . . . . . . . . . . (2,274) 4,938 28,911
Investment tax credit - net. . . . . . . . . . . . . . . . . . . . . (4,619) (7,821) (5,033)
Gain on sale of capital asset. . . . . . . . . . . . . . . . . . . . - (3,869) -
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,603 5,877 3,768
(Increase) decrease in certain net current assets:
Accounts receivable. . . . . . . . . . . . . . . . . . . . . . . . . 18,339 (11,678) (7,494)
Materials and supplies . . . . . . . . . . . . . . . . . . . . . . . 3,280 10,671 (8,014)
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . (22,781) 21,099 4,546
Accrued taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,247) 2,343 1,967
Accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . . 530 757 (1,716)
Prepayments and other. . . . . . . . . . . . . . . . . . . . . . . . (743) (260) 538
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 972 (15,587) (11,321)
------- ------- -------
Net cash provided from operating activities. . . . . . . . . . . . . 180,881 176,892 159,631
------- ------- -------
Cash Flows from Investing Activities
Sale of capital asset. . . . . . . . . . . . . . . . . . . . . . . . . - 91,076 -
Purchase of securities . . . . . . . . . . . . . . . . . . . . . . . . (87,896) (38,398) (26,677)
Proceeds from sales of securities. . . . . . . . . . . . . . . . . . . 56,085 27,301 16,236
Construction expenditures. . . . . . . . . . . . . . . . . . . . . . . (95,398) (98,787) (101,175)
-------- ------- -------
Net cash used for investing activities . . . . . . . . . . . . . . . (127,209) (18,808) (111,616)
-------- ------- -------
Cash Flows from Financing Activities
Issuance of preferred stock. . . . . . . . . . . . . . . . . . . . . . - 24,716 49,099
Issuance of first mortgage bonds and pollution control bonds . . . . . - 198,918 88,462
Redemption of preferred stock. . . . . . . . . . . . . . . . . . . . . - (25,558) (51,443)
Retirement of first mortgage bonds and pollution control bonds . . . . - (231,876) (92,400)
Repayment of short-term borrowings . . . . . . . . . . . . . . . . . . - (8,000) (4,000)
Payment of dividends . . . . . . . . . . . . . . . . . . . . . . . . . (58,639) (73,125) (74,517)
------- ------- --------
Net cash used for financing activities . . . . . . . . . . . . . . . (58,639) (114,925) (84,799)
------ ------- ------
Net (Decrease) Increase in Cash and Temporary Cash Investments . . . . . (4,967) 43,159 (36,784)
Cash and Temporary Cash Investments at Beginning of Year . . . . . . . . 44,105 946 37,730
------ ------ ------
Cash and Temporary Cash Investments at End of Year . . . . . . . . . . . $ 39,138 $ 44,105 $ 946
------ ------- -------
------ ------- -------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year for:
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 42,803 $ 54,686 $ 19,741
Interest on borrowed money . . . . . . . . . . . . . . . . . . . . . 40,827 45,360 50,508
</TABLE>
The accompanying notes are an integral part of these financial statements.
-25-
<PAGE>
LOUISVILLE GAS AND ELECTRIC COMPANY
STATEMENTS OF CAPITALIZATION
(Thousands of $)
<TABLE>
<CAPTION>
December 31
------------------------------------------
1994 1993
---- ----
<S> <C> <C>
Common Equity
Common stock, without par value -
Authorized 75,000,000 shares, outstanding 21,294,223 shares. . . . . . . $ 425,170 $ 425,170
Common stock expense . . . . . . . . . . . . . . . . . . . . . . . . . . . (836) (836)
Unrealized loss on marketable securities, net of income
taxes of $1,434 (Note 4) . . . . . . . . . . . . . . . . . . . . . . . . (1,751) -
Retained earnings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 193,895 194,903
-------- --------
$ 616,478 $ 619,237
-------- --------
Cumulative Preferred Stock
Redeemable on 30 days notice by the Company
except, $5.875 series
Shares Current
Outstanding Redemption Price
----------- ----------------
$25 par value, 1,720,000 shares authorized -
5% series. . . . . . . . . . . . . . 860,287 $ 28.00 $ 21,507 $ 21,507
7.45% series . . . . . . . . . . . . 858,128 25.75 21,453 21,453
Without par value, 6,750,000 shares authorized -
Auction Rate. . . . . . . . . . . . . 500,000 100.00 50,000 50,000
$5.875 series . . . . . . . . . . . . 250,000 Not Redeemable 25,000 25,000
Preferred stock expense. . . . . . . . . . . . . . . . . . . . . . . . . . . (1,244) (1,244)
--------- ---------
$ 116,716 $ 116,716
--------- ---------
Long-Term Debt (Note 8)
First mortgage bonds -
Series due June 1, 1996, 5 5/8%. . . . . . . . . . . . . . . . . . . . . $ 16,000 $ 16,000
Series due June 1, 1998, 6 3/4%. . . . . . . . . . . . . . . . . . . . . 20,000 20,000
Series due July 1, 2002, 7 1/2%. . . . . . . . . . . . . . . . . . . . . 20,000 20,000
Series due August 15, 2003, 6% . . . . . . . . . . . . . . . . . . . . . 42,600 42,600
Pollution control series:
J due July 1, 2015, 9 1/4% . . . . . . . . . . . . . . . . . . . . . . 40,000 40,000
K due December 1, 2016, 7 1/4% . . . . . . . . . . . . . . . . . . . . 27,500 27,500
L due December 1, 2016, 7 1/4% . . . . . . . . . . . . . . . . . . . . 22,500 22,500
N due February 1, 2019, 7 3/4% . . . . . . . . . . . . . . . . . . . . 35,000 35,000
O due February 1, 2019, 7 3/4% . . . . . . . . . . . . . . . . . . . . 35,000 35,000
P due June 15, 2015, 7.45% . . . . . . . . . . . . . . . . . . . . . . 25,000 25,000
Q due November 1, 2020, 7 5/8% . . . . . . . . . . . . . . . . . . . . 83,335 83,335
R due November 1, 2020, 6.55%. . . . . . . . . . . . . . . . . . . . . 41,665 41,665
S due September 1, 2017, variable. . . . . . . . . . . . . . . . . . . 31,000 31,000
T due September 1, 2017, variable. . . . . . . . . . . . . . . . . . . 60,000 60,000
U due August 15, 2013, variable. . . . . . . . . . . . . . . . . . . . 35,200 35,200
V due August 15, 2019, 5 5/8%. . . . . . . . . . . . . . . . . . . . . 102,000 102,000
W due October 15, 2020, 5.45%. . . . . . . . . . . . . . . . . . . . . 26,000 26,000
-------- --------
Total bonds outstanding. . . . . . . . . . . . . . . . . . . . . . . . . 662,800 662,800
Unamortized premium on bonds . . . . . . . . . . . . . . . . . . . . . . . 62 79
-------- --------
$ 662,862 $ 662,879
-------- --------
Total Capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,396,056 $ 1,398,832
--------- ---------
--------- ---------
</TABLE>
The accompanying notes are an integral part of these financial statements.
-26-
<PAGE>
LOUISVILLE GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Louisville Gas and Electric Company (the Company) completed a corporate
restructuring on August 17, 1990, pursuant to which the Company became the
primary subsidiary of LG&E Energy Corp. The Company is a regulated public
utility that is engaged in the generation, transmission, distribution, and
sale of electric energy and the storage, distribution, and sale of natural
gas. LG&E Energy Corp. is an exempt energy services holding company with
wholly owned subsidiaries consisting of the Company and LG&E Energy Systems
Inc., a non-regulated subsidiary. All of the Company's Common Stock is
held by LG&E Energy Corp.
Certain reclassifications have been made to the 1993 and 1992 financial
statements to conform with the 1994 presentation with no impact on
previously reported income.
UTILITY PLANT. The Company's plant is stated at original cost, which
includes payroll-related costs such as taxes, fringe benefits, and
administrative and general costs. Construction work in progress has been
included in the rate base, and, accordingly, the Company has not recorded
any allowance for funds used during construction.
The cost of plant retired or disposed of in the normal course of business
is deducted from plant accounts and such cost plus removal expense less
salvage value is charged to the reserve for depreciation. When complete
operating units are disposed of, appropriate adjustments are made to the
reserve for depreciation and gains and losses, if any, are recognized.
DEPRECIATION. Depreciation is provided on the straight-line method over
the estimated service lives of depreciable plant. The amounts provided
for 1994 were 3.3% (3.2% electric, 3.3% gas, and 5% common); for 1993 3.3%
(3.2% electric, 3.2% gas, and 5% common); and for 1992, 3.3% (3.2%
electric, 3.2% gas, and 5.4% common) of average depreciable plant.
CASH AND TEMPORARY CASH INVESTMENTS. The Company considers all highly
liquid debt instruments purchased with a maturity of three months or less
to be cash equivalents. Temporary cash investments are carried at cost,
which approximates fair value.
DEFERRED INCOME TAXES. Deferred income taxes have been provided for all
book-tax temporary differences.
-27-
<PAGE>
The Company adopted Statement of Financial Accounting Standards No. 109,
ACCOUNTING FOR INCOME TAXES (SFAS No. 109), effective January 1, 1993.
Regulatory assets and liabilities have been established to recognize the
future revenue requirement impact from the deferred income taxes which were
not immediately recognized in operating results because of ratemaking
treatment. The adoption of SFAS No. 109 did not have a material impact on
the results of operations or financial position.
INVESTMENT TAX CREDITS. Investment tax credits resulted from provisions of
the tax law that permitted a reduction of the Company's tax liability based
on credits for certain construction expenditures. Investment tax credits
deferred and charged to income in prior years are being amortized to income
over the estimated lives of the related property that gave rise to the
credits.
DEBT PREMIUM AND EXPENSE. Debt premium and expense are amortized over the
lives of the related debt issues, consistent with regulatory practices.
REVENUE RECOGNITION. Revenues are recorded based on service rendered to
customers through month end. The Company accrues an estimate for unbilled
revenues from the date of each meter reading date to the end of the
accounting period. Effective January 1, 1994, under an agreement approved
by the Public Service Commission of Kentucky (Kentucky Commission or
Commission), the Company implemented a demand side management program and a
"decoupling mechanism," which allows the Company to recover a predetermined
level of revenue on electric and gas residential sales. See Management's
Discussion and Analysis, Rates and Regulation, under Item 7 for further
discussion.
FUEL AND GAS COSTS. The cost of fuel for electric generation is charged to
expense as used, and the cost of gas supply is charged to expense as
delivered to the distribution system.
INTEREST RATE CONTRACTS. Interest rate swaps are used by the Company to
convert variable rate debt to a fixed rate. The cost or benefit of the
interest rate swaps is recorded as a component of interest expense.
REVENUES AND CUSTOMER RECEIVABLES. The Company is an operating public
utility that supplies natural gas to approximately 266,000 customers and
electricity to approximately 341,000 customers in Louisville and adjacent
areas in Kentucky. Customer receivables and gas and electric revenues
arise from deliveries of natural gas and electric energy to a diversified
base of residential, commercial and industrial customers and to public
authorities and other utilities. For the year ended December 31, 1994, 74%
of total operating revenue was derived from electric operations and 26%
from gas operations.
NOTE 2 - RATES AND REGULATORY MATTERS
The Company conforms with generally accepted accounting principles as
applied to regulated public utilities and as prescribed by the Federal
Energy Regulatory Commission (FERC) and the Kentucky Commission. The
Company is subject to Statement of Financial Accounting Standards No. 71,
ACCOUNTING FOR THE EFFECTS OF CERTAIN TYPES OF REGULATION (SFAS No. 71).
-28-
<PAGE>
Under SFAS No. 71, certain costs that would otherwise be charged to expense
are deferred as regulatory assets based on expected recovery from customers
in future rates. Likewise, certain credits that would otherwise be
reflected as income are deferred as regulatory liabilities based on
expected flowback to customers in future rates. Management's expected
recovery of deferred costs and expected flowback of deferred credits is
generally based on specific ratemaking decisions or precedent for each
item. The following regulatory assets and liabilities were included in the
balance sheets as of December 31 (in thousands of $):
<TABLE>
<CAPTION>
1994 1993
---- ----
<S> <C> <C>
Unamortized loss on bonds . . . . . . . $15,704 $16,622
Unamortized extraordinary retirements . 9,752 12,540
Post-retirement benefits. . . . . . . . - 1,200
Early retirement/workforce reduction. . - 17,617
Property damage settlements . . . . . . - 9,817
Manufactured gas sites. . . . . . . . . 3,149 926
Other . . . . . . . . . . . . . . . . . 3,121 2,920
Deferred income taxes - net . . . . . . (8,914) (6,876)
------ ------
Regulatory assets and liabilities - net $22,812 $54,766
------ ------
------ ------
</TABLE>
As of December 31, 1994, approximately $15 million of the Company's net
regulatory assets are being recovered through rates charged to customers
over periods ranging from three to 22 years. The Company expects to obtain
recovery of the remaining regulatory assets in its next general rate case.
For additional information regarding post-retirement benefits and early
retirement/workforce reduction costs, deferred income taxes, and
environmental costs, see Notes 5, 6, and 10, respectively. In early 1994,
the Company, based on a re-evaluation of its regulatory strategy, wrote off
certain regulatory assets included in the 1993 balance sheet. See Note 3,
Non-Recurring Charges, for a further discussion.
In October 1994, the Company filed an application with the Kentucky
Commission to implement an environmental cost recovery surcharge. The
surcharge will allow the Company to recover certain costs incurred to
comply with federal, state, and local environmental requirements. If
approved by the Commission, the surcharge will take effect in May 1995.
See Management's Discussion and Analysis, Rates and Regulation, under
Item 7 for a further discussion.
NOTE 3 - NON-RECURRING CHARGES
As part of a study of LG&E Energy Corp.'s business strategy and realignment
during 1994, the Company re-evaluated its regulatory strategy which
previously had been to seek full recovery of certain costs deferred in
accordance with prior precedents established by the Commission. As a
result of this re-evaluation, the Company wrote off certain expenses that
had previously been deferred amounting to approximately $38.6 million
before taxes. While the Company continues to believe that it could have
reasonably expected to recover these costs in future rate proceedings
before the Commission, the Company decided to deduct these expenses
currently and not seek recovery for such expenses in future rates due to
increasing competitive pressures and the existing and anticipated future
economic conditions. The items written off include costs incurred in
connection with early retirements and workforce reductions that occurred in
1992 and 1993 which consist primarily of separation payments, enhanced
early retirement benefits, and health care benefits; costs associated with
property damage claims pertaining to particulate
-29-
<PAGE>
emissions from its Mill Creek electric generating plant which primarily
consist of spotting on automobile finish and aluminum siding; and certain
costs previously deferred resulting from adoption in January 1993 of
Statement of Financial Accounting Standards No. 106, EMPLOYERS' ACCOUNTING
FOR POST-RETIREMENT BENEFITS OTHER THAN PENSIONS.
In the first quarter of 1994, the Board of Directors of the Company
approved the formation of a tax-exempt charitable foundation (Foundation)
which will make charitable contributions to qualified persons and entities.
In 1994, the Company recorded a pre-tax charge against income and made an
irrevocable payment of $15 million to fund the Foundation. On June 6,
1994, the Internal Revenue Service issued a letter stating that it had
determined the Foundation was exempt from Federal income tax under the
Internal Revenue Code.
NOTE 4 - MARKETABLE SECURITIES AND OTHER FINANCIAL INSTRUMENTS
MARKETABLE SECURITIES. The Company adopted the provisions of Statement of
Financial Accounting Standards No. 115, ACCOUNTING FOR CERTAIN INVESTMENTS
IN DEBT AND EQUITY SECURITIES, effective January 1, 1994. Accordingly, the
Company's marketable securities have been determined to be
"available-for-sale" and are stated at market value in the accompanying
December 31, 1994, balance sheet. The available-for-sale category of
investments results in the classification of unrealized gains and losses on
investments in common equity, net of income taxes, until such gains and
losses are realized, at which time they are recognized in earnings.
Proceeds from sales of available-for-sale securities were $56,085,000,
which resulted in realized gains of $1,557,000 and losses of $1,538,000,
calculated using the specific identification method. The difference
between amortized and unamortized cost basis of the Company's investments
in marketable securities as of December 31, 1994, was immaterial.
Approximate cost, fair value, and other required information about the
Company's available-for-sale securities by major security type as of
December 31, 1994, follows (in thousands of $):
<TABLE>
<CAPTION>
Fixed
Equity Income Total
------ ------ -----
<S> <C> <C> <C>
Cost. . . . . . . . . . . . . . . . . . . . . . . . . . . $23,622 $29,701 $53,323
Unrealized gains. . . . . . . . . . . . . . . . . . . . . 41 - 41
Unrealized losses . . . . . . . . . . . . . . . . . . . . (2,399) (827) (3,226)
------ ------ ------
Fair values . . . . . . . . . . . . . . . . . . . . . . . $21,264 $28,874 $50,138
------ ------ ------
------ ------ ------
- ---------------------------------------------------------------------------------------------------------------------
Fair Values:
No maturity . . . . . . . . . . . . . . . . . . . . . . $20,415 $ - $20,415
Contractual maturities:
Less than one year. . . . . . . . . . . . . . . . . . 849 2,519 3,368
One to five years . . . . . . . . . . . . . . . . . . - 16,968 16,968
Five to ten years . . . . . . . . . . . . . . . . . . - 1,958 1,958
Over ten years. . . . . . . . . . . . . . . . . . . . - 3,381 3,381
Not due at a single maturity date . . . . . . . . . . - 4,048 4,048
------ ------ ------
Total fair values . . . . . . . . . . . . . . . . . . . $21,264 $28,874 $50,138
------- ------ ------
------- ------ ------
</TABLE>
-30-
<PAGE>
The Company's available-for-sale securities above include approximately $.6
million market value ($18.5 million notional amount) of short futures on
U.S. Treasury Notes and Bonds maturing March 1995. The Company uses such
instruments to hedge a major portion of its preferred equity portfolio to
substantially reduce price volatility of the securities due to interest
rate changes. The Company does not maintain any margin accounts relative
to its investment positions.
The Company's available-for-sale securities are classified as Other
Property and Investments in the accompanying 1994 balance sheet.
FINANCIAL INSTRUMENTS. Pursuant to Statement of Financial Accounting
Standards No. 107, DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS,
the Company is required to disclose the fair value of financial instruments
where practicable. The disclosure of such information does not purport to
be a market valuation of the Company as a whole. The carrying amounts of
cash, accounts receivable, notes payable, and accounts payable reflected on
the balance sheets approximates the fair value of these instruments due to
the short duration to maturity.
The fair value for certain of the Company's investments and debt are
estimated based on quoted market prices for those or similar instruments.
Investments for which there are no quoted market prices are stated at cost
because a reasonable estimate of fair value cannot be made without
incurring excessive costs. The fair value of interest rate swaps is based
on the quoted market price as provided by the financial institution which
is the counterparty to the swap.
The cost and estimated fair value of the Company's financial instruments as
of December 31, 1994 and 1993, are as follows (in thousands of $):
<TABLE>
<CAPTION>
1994 1993
--------------------- --------------------
Fair Fair
Cost Value Cost Value
---- ----- ---- -----
<S> <C> <C> <C> <C>
Long-term investments:
Practicable to estimate fair value. . . . . . . . . . $53,323 $50,138 $21,186 $21,538
Not practicable . . . . . . . . . . . . . . . . . . . 490 490 490 490
Preferred stock subject to mandatory redemption . . . . 25,000 22,125 25,000 24,750
Long-term debt. . . . . . . . . . . . . . . . . . . . . 662,800 648,697 662,800 706,078
Interest rate swaps . . . . . . . . . . . . . . . . . . - 965 - (896)
</TABLE>
NOTE 5 - PENSION PLANS AND RETIREMENT BENEFITS
PENSION PLANS. The Company has two non-contributory, defined-benefit
pension plans, covering all eligible employees. Retirement benefits are
based on the employee's years of service and compensation. The Company's
policy is to fund annual actuarial costs, up to the maximum amount
deductible for income tax purposes, as determined under the frozen entry
age actuarial cost method.
-31-
<PAGE>
In addition, the Company has a supplemental executive retirement plan that
covers officers of the Company. The plan provides retirement benefits
based on average earnings during the final three years prior to retirement,
reduced by social security benefits, any pension benefits received from
plans of prior employers, and by amounts received under the pension plans
referred to above.
Pension costs were $4,423,000 for 1994, $2,669,000 for 1993, and $2,598,000
for 1992, of which approximately $693,000, $425,000, and $241,000,
respectively, were charged to construction. The components of periodic
pension expense are shown below (in thousands of $):
<TABLE>
<CAPTION>
1994 1993 1992
---- ---- ----
<S> <C> <C> <C>
Service cost-benefits earned during the period. . . . . . . . . . . $ 4,813 $ 4,516 $ 5,459
Interest cost on projected benefit obligation . . . . . . . . . . . 13,057 12,117 11,006
Actual return on plan assets. . . . . . . . . . . . . . . . . . . . (489) (13,602) (8,850)
Amortization of transition asset. . . . . . . . . . . . . . . . . . (1,112) (1,112) (1,076)
Net amortization and deferral . . . . . . . . . . . . . . . . . . . (11,846) 750 (3,941)
------ ------ ------
Net pension cost. . . . . . . . . . . . . . . . . . . . . . . . . . $ 4,423 $ 2,669 $ 2,598
------ ------ ------
------ ------ ------
</TABLE>
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 $):
<TABLE>
<CAPTION>
1994 1993
<S> <C> <C>
Actuarial present value of accumulated plan benefits:
Vested. . . . . . . . . . . . . . . . . . . . . . . . . . . . $132,260 $137,655
Non-Vested. . . . . . . . . . . . . . . . . . . . . . . . . . 14,023 17,158
------- -------
Accumulated benefit obligation. . . . . . . . . . . . . . . . 146,283 154,813
Effect of projected future compensation . . . . . . . . . . . 18,473 25,234
------- -------
Projected benefit obligation. . . . . . . . . . . . . . . . . 164,756 180,047
Plan assets at fair value . . . . . . . . . . . . . . . . . . 159,638 165,088
------- -------
Plan assets less than projected benefit obligation. . . . . . (5,118) (14,959)
Unrecognized net transition asset . . . . . . . . . . . . . . (12,524) (13,636)
Unrecognized prior service cost . . . . . . . . . . . . . . . 24,257 28,671
Unrecognized net gain . . . . . . . . . . . . . . . . . . . . (36,266) (23,860)
------- -------
Accrued pension liability . . . . . . . . . . . . . . . . . $(29,651) $(23,784)
------- -------
------- -------
</TABLE>
The projected benefit obligation was determined using an assumed discount
rate of 8.5% for 1994 and 7.5% for 1993. An assumed annual rate of
increase in future compensation levels ranged from 4.5% to 5% for 1994 and
3.5% to 4.5% for 1993. The assumed long-term rate of return on plan assets
was 8.5% for 1994 and 1993. Transition assets and prior service costs are
being amortized over the average remaining service period of active
participants.
-32-
<PAGE>
POST-RETIREMENT BENEFITS. The Company adopted Statement of Financial
Accounting Standards No. 106, EMPLOYERS' ACCOUNTING FOR POST-RETIREMENT
BENEFITS OTHER THAN PENSIONS (SFAS No. 106), effective January 1, 1993.
SFAS No. 106 requires the accrual of the expected cost of retiree benefits
other than pensions during the employee's years of service with the
Company. The Company is amortizing the discounted present value of the
post-retirement benefit obligation at the date of adoption over 20 years.
The Company provides certain health care and life insurance benefits for
eligible retired employees. Post-retirement health care benefits are
subject to a maximum amount payable by the Company. Prior to January 1,
1993, the cost of retiree health care and life insurance benefits was
generally recognized when paid. This cost was $1,078,000 for 1992. In
1993, the Company began to account for post-retirement benefits according
to the provisions of SFAS No. 106.
In 1993, the Company, based on an order from the Commission, created a
regulatory asset and deferred the level of SFAS No. 106 expense in excess
of the previous level of pay-as-you-go expense. Therefore, the adoption of
SFAS No. 106 did not have an effect on results of operations in 1993.
However, in the first quarter of 1994, the Company began recognizing the
excess SFAS No. 106 expense currently, including the amount previously
deferred. See Note 3, Non-Recurring Charges.
The components of the net periodic post-retirement benefit cost as
calculated under SFAS No. 106 are as follows (in thousands of $):
<TABLE>
<CAPTION>
1994 1993
---- ----
<S> <C> <C>
Service cost . . . . . . . . . . . . . . . . $ 621 $ 701
Interest cost. . . . . . . . . . . . . . . . 2,386 2,614
Amortization of transition obligation. . . . 1,337 1,395
----- -----
Post-retirement benefit cost $4,344 $4,710
----- -----
----- -----
</TABLE>
The accumulated post-retirement benefit obligation as calculated under SFAS
No. 106 at December 31, is shown below (in thousands of $):
<TABLE>
<CAPTION>
1994 1993
---- ----
<S> <C> <C>
Retirees . . . . . . . . . . . . . . . . . .$(18,487) $(17,826)
Fully eligible active employees. . . . . . . (1,927) (4,001)
Other active employees . . . . . . . . . . . (9,789) (15,945)
------- -------
Accumulated post-retirement benefit
obligation . . . . . . . . . . . . . . . . . (30,203) (37,772)
Unrecognized net (gain) loss . . . . . . . . (3,275) 4,966
Unrecognized transition obligation . . . . . 24,064 26,508
Previously recognized amount . . . . . . . . - 3,696
------ -------
Accrued post-retirement benefit liability. .$ (9,414) $ (2,602)
------ -------
------ -------
</TABLE>
-33-
<PAGE>
The accumulated post-retirement benefit obligation was determined using an
assumed discount rate of 8.5% for 1994 and 7.5% for 1993. Assumed
compensation increases for projected life insurance benefits for affected
groups was 5% for 1994 and 4.5% for 1993. An assumed health care cost
trend rate of 10.5% was assumed for 1994, gradually decreasing to 5.25% in
ten years and thereafter.
A 1% increase in the assumed health care cost trend rate would increase the
accumulated post-retirement benefit obligation by approximately $1 million
and the annual service and interest cost by approximately $100,000. No
funding has been established by the Company for post-retirement benefits.
POST-EMPLOYMENT BENEFITS. The Company adopted Statement of Financial
Accounting Standards No. 112, EMPLOYERS' ACCOUNTING FOR POST-EMPLOYMENT
BENEFITS (SFAS No. 112) on January 1, 1994, as required. SFAS No. 112
requires the accrual of the expected cost of benefits to former or inactive
employees after employment but before retirement. The cumulative effect of
the accounting change was recorded in the first quarter of 1994 and
decreased net income by $3.4 million.
EARLY RETIREMENT/WORKFORCE REDUCTION. During the last quarter of 1993, the
Company eliminated approximately 350 full-time positions. The cost of the
employee reduction program was approximately $11.5 million, and consisted
primarily of separation payments, enhanced early retirement benefits, and
health care benefits.
In 1992, an early retirement program was made available to all Company
union employees who had reached age 55, or who had 35 years or more of
continuous service regardless of age. The cost of the program was
approximately $7 million and consisted primarily of enhanced early
retirement and health care benefits.
THRIFT SAVINGS PLAN. The Company has a Thrift Savings Plan under
Section 401(k) of the Internal Revenue Code. The plan covers all regular
full-time employees with one year or more of service at the Company. Under
the plan, eligible employees may defer and contribute to the plan a portion
of current compensation in order to provide future retirement benefits.
The Company makes contributions to the plan by matching a portion of
employee contributions according to a formula established by the plan.
These costs were approximately $1,701,000 for 1994, $1,795,000 for 1993,
and $767,000 for 1992. The increase in 1993 401(k) expenses over 1992 is
due to the expansion of the program to the Company's union employees.
-34-
<PAGE>
NOTE 6 - FEDERAL AND STATE INCOME TAXES
Components of income tax expense are shown in the table below (in thousands
of $):
<TABLE>
<CAPTION>
1994 1993 1992
---- ---- ----
<S> <C> <C> <C>
Included in Operating:
Current - Federal. . . . . . . . . . $35,552 $31,082 $20,756
- State. . . . . . . . . . . 9,003 8,920 6,354
Deferred - Federal-net. . . . . . . . (969) 13,185 15,771
- State-net. . . . . . . . . 955 3,933 5,774
Amortization of investment tax credit (4,619) (4,786) (4,815)
------- ------- ------
Total . . . . . . . . . . . $39,922 $52,334 $43,840
------- ------- -------
Included in Other Income and (Deductions):
Current - Federal . . . . . . . . . . $(4,626) $11,009 $(6,971)
- State. . . . . . . . . . . (1,277) 4,034 (3,214)
Deferred - Federal-net. . . . . . . . 19 (8,473) 4,670
- State-net. . . . . . . . . 1 (3,707) 2,696
Deferred investment tax credit. . . . - - 390
Amortization of investment tax credit - (3,035) (608)
------- ------- -------
Total . . . . . . . . . . .$ (5,883) $ (172) $(3,037)
------- ------- -------
Included in Cumulative Effect of a Change in Accounting
for Post-Employment Benefits:
Deferred - Federal. . . . . . . . . .$ (1,814) $ - $ -
- State. . . . . . . . . . . (466) - -
------- ------ ------
Total. . . . . . . . . . . . . .$ (2,280) $ - $ -
------- ------ ------
Total Income Tax Expense. . . . . . . .$ 31,759 $52,162 $40,803
------- ------ ------
------- ------ ------
</TABLE>
Variations in income tax expense are largely attributable to changes in
pre-tax income.
Provisions for deferred income taxes-net consist of the tax effects of the
following temporary differences (in thousands of $):
<TABLE>
<CAPTION>
1994 1993 1992
---- ---- ----
<S> <C> <C> <C>
Depreciation and amortization $12,609 $ (255) $33,839
Alternative minimum tax. . . - 5,387 (5,387)
Pension overfunding. . . . . (4,357) (823) (900)
Accrued liabilities not
currently deductible . . . . (5,343) 1,210 295
Change in accounting principle (2,280) - -
Other . . . . . . . . . . (2,903) (581) 1,064
------ ------ -------
Total . . . . . . . . . . $(2,274) $4,938 $28,911
------ ------ -------
------ ------ -------
</TABLE>
The net provisions for deferred income taxes decreased in 1994 due largely
to recording certain liabilities which are not deductible until such
liabilities are paid. Deferred income taxes attributable to depreciation
and amortization decreased in 1993 because of the reversal of prior years'
accumulated taxes as a result of the sale of a portion of Trimble County
Unit 1. See Note 12, Jointly Owned Electric Utility Plant for a further
discussion of the sale.
-35-
<PAGE>
Net deferred tax liabilities resulting from book-tax temporary differences
are shown below (in thousands of $):
<TABLE>
<CAPTION>
December 31 January 31
1994 1993 1993
---- ---- ----
<S> <C> <C> <C>
Deferred Tax Liabilities:
Depreciation and other
plant related items. . $334,252 $322,544 $326,527
Income taxes due from
customers . . . . . . 10,179 10,233 14,608
Other liabilities . . . 7,977 7,458 5,548
------- ------- -------
$352,408 $340,235 $346,683
------- ------- -------
Deferred Tax Assets:
Investment tax credit . $ 35,833 $ 36,961 $ 42,229
Income taxes due to
customers . . . . . . 13,942 14,361 15,477
Pension overfunding . . 11,145 6,781 5,951
Other assets. . . . . . 15,674 572 5,066
------- ------- -------
$ 76,594 $ 58,675 $ 68,723
------- ------- -------
Net deferred income tax
liability. . . . . . $275,814 $281,560 $277,960
------- ------- -------
------- ------- -------
</TABLE>
The Company's effective income tax rate is computed by dividing the
aggregate of current income taxes, deferred income taxes-net, and the
amortization of investment tax credit, by net income before the deduction
of such taxes. Reconciliation of the statutory Federal income tax rate to
the effective income tax rate is shown in the table below:
<TABLE>
<CAPTION>
1994 1993 1992
---- ---- ----
<S> <C> <C> <C>
Statutory Federal income tax rate . . . 35.0% 35.0% 34.0%
State income taxes net of Federal benefit 5.9 6.0 6.7
Investment tax credits. . . . . . . . . (5.1) (5.5) (4.7)
Other differences-net . . . . . . . . . (.5) 1.1 (.4)
---- ---- ----
Effective Income Tax Rate . . . . . . . 35.3% 36.6% 35.6%
---- ---- ----
---- ---- ----
</TABLE>
NOTE 7 - OTHER INCOME AND (DEDUCTIONS)
Other income and (deductions) consisted of the following at December 31 (in
thousands of $):
<TABLE>
<CAPTION>
1994 1993 1992
---- ---- ----
<S> <C> <C> <C>
Interest and dividend income . . . . . . . . . . $ 4,568 $ 3,112 $ 1,980
Gains (losses) on fixed asset disposal . . . . . 1,427 (3,523) 608
Gain on sale of 12.88% portion of Trimble County - 3,869 -
Donations . . . . . . . . . . . . . . . . . (1,015) (909) (652)
Income taxes and other . . . . . . . . . . . . . (2,529) (636) (4,139)
------ ------ ------
Total . . . . . . . . . . . . . . . . . $ 2,451 $ 1,913 $(2,203)
------ ------ ------
------ ------ ------
</TABLE>
NOTE 8 - FIRST MORTGAGE BONDS
Annual requirements for the sinking funds of the Company's First Mortgage
Bonds (other than the First Mortgage Bonds issued in connection with the
Pollution Control Bonds) are the amounts necessary to redeem 1% of the
highest principal amount of each series of bonds at any time outstanding.
Property additions (166 2/3% of principal amounts of bonds otherwise
-36-
<PAGE>
required to be so redeemed) have been applied in lieu of cash. It is the
intent of the Company to apply property additions to meet 1995 sinking fund
requirements of the First Mortgage Bonds.
The trust indenture securing the First Mortgage Bonds constitutes a direct
first mortgage lien upon substantially all property owned by the Company.
The indenture, as supplemented, provides in substance that, under certain
specified conditions, portions of retained earnings will not be available
for the payment of dividends on common stock. No portion of retained
earnings is presently restricted by this provision.
Pollution Control Bonds (Louisville Gas and Electric Company Projects)
issued by Jefferson and Trimble Counties, Kentucky, are secured by the
assignment of loan payments by the Company to the Counties pursuant to loan
agreements, and further secured by the delivery from time to time of an
equal amount of the Company's First Mortgage Bonds, Pollution Control
Series. First Mortgage Bonds so delivered are summarized in the Statements
of Capitalization. No principal or interest on these First Mortgage Bonds
is payable unless default on the loan agreements occurs. The interest rate
reflected in the Statements of Capitalization applies to the Pollution
Control Bonds.
In March 1993, due to the sale of 12.88% of Trimble County Unit 1, the
Company completed the defeasance of $25 million of its Pollution Control
Bonds ($16.665 million of the 7.625% Series and $8.335 million of the 6.55%
Series).
The Company issued several series of lower interest bearing First Mortgage
and Pollution Control Bonds in 1993 to refinance bonds with higher interest
rates. In August 1993, the Company issued two separate series of Pollution
Control Bonds (a $35.2 million, Variable Rate Series, which had an average
interest rate of 3.740% at December 31, 1994, and 2.586% at December 31,
1993, and a $102 million, 5.625% Series) and redeemed five series of
Pollution Control Bonds totaling $137.2 million with interest rates ranging
from 6.125% to 6.7%. In August 1993, the Company also issued $42.6 million
of 6% First Mortgage Bonds and redeemed two series of First Mortgage Bonds
($19.7 million at 8.25% and $21.362 million at 8.5%). In November 1993,
the Company issued $26 million of Pollution Control Bonds, 5.45% Series and
redeemed the $26 million, 9.75% Series.
The Company entered into an agreement in November 1993 with Goldman, Sachs
& Co. to issue $40 million of tax-exempt Pollution Control Bonds in 1995 at
a rate of 5.9%. The issuance of the bonds in 1995 is subject to certain
conditions. If issued, the proceeds will be used to redeem, in 1995, the
outstanding 9.25% series of Pollution Control Bonds due July 1, 2015.
The Company has outstanding interest rate swap agreements totaling $30
million. Under the agreements, which were entered into in 1992, the
Company pays a fixed rate of 4.35% on $15 million for a five-year period
and 4.74% on $15 million for a seven-year period. In return, the Company
receives a floating rate based on the weighted average JJ Kenny index. The
JJ Kenny index is a tax-exempt municipal bond interest rate index. These
swaps were entered into as a standard hedging device in connection with the
issuance of the Series S Pollution Control Bonds due September 1, 2017.
The swaps are designed to reduce the Company's exposure to interest rate
risk. The Company received interest at composite rates of 2.84%, 2.38%,
and 2.73% in
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<PAGE>
1994, 1993, and 1992, respectively and paid interest at a composite rate of
4.55% pursuant to the swaps.
The Company's First Mortgage Bonds, 5.625% Series of $16 million is
scheduled to mature in 1996 and the 6.75% Series of $20 million is
scheduled to mature in 1998. There are no scheduled maturities of
Pollution Control Bonds for the five years subsequent to December 31, 1994.
The Company has no cash sinking fund requirements.
NOTE 9 - NOTES PAYABLE
The Company had no notes payable at December 31, 1994, or December 31,
1993.
At December 31, 1994, the Company had unused lines of credit of $145
million, for which it pays commitment fees. The credit lines are scheduled
to expire at various periods throughout 1995 and 1996. Management intends
to renegotiate these lines when they expire.
NOTE 10 - COMMITMENTS AND CONTINGENCIES
CONSTRUCTION PROGRAM. The Company had commitments, primarily in connection
with its construction program, aggregating approximately $8 million at
December 31, 1994. Construction expenditures for the calendar years 1995
and 1996 are estimated to total approximately $200 million.
FERC ORDER NO. 636. In 1994, the Company experienced its first full year
operating under Order No. 636. Whereas the Company had previously
purchased natural gas and pipeline transportation services from Texas Gas
Transmission Corporation (Texas Gas), the Company now purchases only
transportation services from Texas Gas and purchases natural gas from other
sources.
Under Order No. 636 pipelines may recover costs associated with the
transition to and implementation of this order from pipeline customers,
including the Company. The Commission issued an order, based on
proceedings that were held to investigate the impact of Order No. 636 on
utilities and ratepayers in Kentucky, providing that transition costs
assessed on utilities by the pipelines, which are clearly identifiable as
being related to the cost of the commodity itself, are appropriate to be
recovered from customers through the gas supply clause. During 1994, the
Company paid and began recovering from its customers approximately $2.8
million in transition costs. It is estimated that $6 million to $8 million
in additional transition costs will be incurred by the Company during 1995,
and these costs are also expected to be recovered from customers. The
Company is a party to proceedings before FERC which will determine a number
of pipeline transition issues. Because of the impact such issues may have
on future costs, management is unable to estimate the level of transition
costs, if any, for years subsequent to 1995.
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<PAGE>
OPERATING LEASE. The Company has an operating lease for its corporate
office building that is scheduled to expire in June 2005. Total expense in
connection with this lease for 1994, 1993, and 1992 was $2,192,000,
$2,436,000, and $2,478,000, respectively. The future minimum annual lease
payments under the lease agreement for years subsequent to December 31,
1994, are as follows (in thousands of $):
1995. . . . . . . . . . . . . $ 2,499
1996. . . . . . . . . . . . . 2,850
1997. . . . . . . . . . . . . 2,850
1998. . . . . . . . . . . . . 2,850
1999. . . . . . . . . . . . . 2,850
Thereafter. . . . . . . . . . 18,960
-------
Total . . . . . . . . . . $ 32,859
-------
-------
ENVIRONMENTAL. The Clean Air Act Amendments of 1990 impose stringent
limits on emissions of sulfur dioxide and nitrogen oxides by electric
utility generating plants. The legislation is extremely complex and its
effect will substantially depend on regulations issued by the U.S.
Environmental Protection Agency (USEPA). The Company is closely monitoring
the continuing rule-making process in order to assess the precise impact of
the legislation on the Company. All of the Company's coal-fired boilers
are equipped with sulfur dioxide "scrubbers" and already achieve the final
sulfur dioxide emission rates required by the year 2000 under the
legislation. However, as part of its ongoing capital construction program,
the Company has spent $10 million to date and anticipates incurring
additional capital expenditures of approximately $29 million through 1996
for remedial measures necessary to meet the Act's requirements for nitrogen
oxides. The overall financial impact of the legislation on the Company is
expected to be minimal. The Company is well-positioned in the market to be
a "clean" power provider without the large capital expenditures that are
expected to be incurred by many other utilities.
In 1992, the Company entered two agreed orders with the Air Pollution
Control District (APCD) of Jefferson County in which the Company committed
to undertake remedial measures to address certain particulate emissions and
alleged excess sulfur dioxide emissions from its Mill Creek electric
generating plant. In May 1994, the Company completed all specified
remedial measures in accordance with the terms of the agreed orders. The
Company has agreed to commence a joint field sampling program with the APCD
to demonstrate the effectiveness of the remedial measures.
In August 1993, 34 persons filed a complaint in Jefferson Circuit Court
against the Company seeking certification of a class consisting of all
persons within 2.5 miles of the Mill Creek plant. The plaintiffs seek
compensation for alleged personal injury and property damage attributable
to emissions from the Mill Creek plant, injunctive relief, a fund to
finance future medical monitoring of area residents, and other relief. In
June 1994, the court denied the plaintiffs' motion for certification of the
class and thus limited the scope of the litigation to the claims of the
individual plaintiffs. The Company intends to vigorously defend itself in
the pending litigation.
In an effort to resolve property damage claims relating to particulate
emissions from the Mill Creek plant, in July 1993, the Company commenced
extensive negotiations and property damage settlements with adjacent
residents who are not parties to the pending litigation. The negotiations
and settlements are continuing and the Company currently estimates that
property
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<PAGE>
damage claims for the particulate emissions should be settled for an
aggregate amount of approximately $15 million. Accordingly, the Company
has recorded an accrual of this amount.
In response to a notification from the APCD that the Company's Cane Run
plant may be the source of a potential exceedance of the National Ambient
Air Quality Standards for sulfur dioxide, the Company submitted a draft
action plan and modeling schedule to the APCD and USEPA. The APCD and
USEPA have approved the submittals, and a Company contractor is currently
conducting additional modeling activities. Although it is expected that
corrective action will be accomplished through capital improvements, until
the modeling activities are complete, the Company cannot determine the
precise impact of this matter.
In March 1994, the APCD adopted a regulation requiring a 15% reduction from
1990 volatile organic compound (VOC) emissions from industrial sources.
There are currently no demonstrated technologies for control of VOC
emissions from coal-fired boilers. Consequently, compliance with the
regulation could require limits on generation at the Mill Creek and Cane
Run plants, unless the APCD adopts a provision for compliance through
utilization of banked emission allowances. The Company is currently
negotiating with the APCD in an effort to demonstrate its eligibility for
an exclusion from the VOC reduction requirements.
The Company owns or formerly owned three primary sites where manufactured
gas plant operations were located. Such manufactured gas plant operations,
conducted in the 1838 to 1960 time period, typically produced coal tar
byproducts and other constituents that may necessitate cleanup measures.
The Company has completed an investigation of the level of contaminants
present at the two company-owned sites, and the Company, along with the
current owner of the third site and another party completed an
investigation of the third site. Investigation and testing at these three
sites has identified the presence of contaminants typical of manufactured
gas operations. A report on the results of the investigation at each site
has been prepared and submitted to the Kentucky Natural Resources and
Environmental Protection Cabinet (KNREPC). The KNREPC will review the
findings submitted by the Company, and through negotiations with the
Company, the level of remediation required at each site will be determined.
Although a precise determination of the costs associated with cleanup
activities at these three sites cannot be made until the required level of
remediation is established, management currently estimates that the total
cost will fall within a range of $3 million to $12 million and has recorded
an accrual of approximately $3 million in the accompanying financial
statements.
In November 1993, the Company was served with a third-party complaint filed
in federal district court in Illinois by three third-party plaintiffs. The
third-party plaintiffs allege that the Company and 31 other parties are
liable under the Comprehensive Environmental Response, Compensation, and
Liability Act as amended (CERCLA) for $1.4 million in costs allegedly
incurred by USEPA in conducting cleanup activities at the M.T. Richards
Site in Crossville, Illinois. A number of de minimis third party
defendants, including the Company, have commenced settlement discussions
with the third-party plaintiffs. In the Company's opinion, the resolution
of this issue will not have a material adverse impact on its financial
position or results of operations.
In June 1992, USEPA identified the Company as a potentially responsible
party (PRP) allegedly liable under CERCLA for $1.6 million in costs
allegedly incurred by USEPA in cleanup of the Sonora Site and Carlie
Middleton Burn Site located in Hardin County, Kentucky. The USEPA
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<PAGE>
has since increased the amount of its demand to $1.8 million to reflect
additional cleanup costs. In September 1994, USEPA filed a CERCLA cost
recovery action in U.S. District Court against the Company and six other
parties. In the Company's opinion, the resolution of this issue will not
have a material adverse impact on its financial position or results of
operations.
In 1987, USEPA identified the Company as one of the numerous PRPs allegedly
liable under CERCLA for the Smith's Farm Site in Bullitt County, Kentucky.
In March 1990, USEPA issued an administrative order requiring the Company
and 35 other PRPs to conduct certain cleanup activities. In February 1992,
four PRPs filed a complaint in federal district court in Kentucky against
the Company and 52 other PRPs. Under the law, each PRP could be held
jointly and severally liable for the cost of site cleanup, but would have
the right to seek contribution from other PRPs. In July 1993, upon motion
of the plaintiffs, the federal court dismissed the Company and a number of
others from the litigation in order to facilitate settlement negotiations
among the parties. Cleanup costs for the site are currently estimated at
approximately $70 million. The Company and several other parties have
shared certain cleanup costs in the interim until a voluntary allocation of
liability can be reached among the parties. It is not possible at this
time to predict the outcome or precise impact of this matter. However,
management believes that this matter should not have a material adverse
impact on the financial position or results of operations of the Company as
other financially viable PRPs appear to have primary liability for the
site.
NOTE 11 - TRIMBLE COUNTY GENERATING PLANT
Trimble County Unit 1 (Trimble County), a 495-megawatt, coal-fired electric
generating unit placed into service in December 1990, is currently the
subject of an administrative proceeding before the Commission. This
proceeding, which originally began in 1988, was initiated by the Commission
to determine the appropriate ratemaking treatment to implement its 1988
decision that the Company should not be allowed to recover 25% of the cost
of the Unit from ratepayers. As a result of a non-unanimous settlement
agreement in the initial 1989 proceedings reached between the Company and
the Commission staff, which was approved by the Kentucky Commission in
October 1989, the Company returned to its customers $11.1 million through
refunds and rate reductions. The Commission's approval of the settlement
agreement was appealed by certain intervenors in the case who had not
joined in the agreement. In April 1993, the Kentucky Court of Appeals held
that the Commission exceeded its authority in approving the agreement, and
ordered the Commission to hold new hearings on the underlying issues.
Pursuant to a Commission procedural order, the Company filed direct
testimony on January 7, 1994, in which the Company recommended that the
Commission allow it to recover the $11.1 million it refunded to customers
under the 1989 settlement agreement. Testimony filed by intervenors
recommended that the Commission order the Company to refund approximately
$183 million, based upon their argument that the Company should refund 25%
of the revenue requirements associated with Trimble County's
construction-work-in-progress (CWIP) collected through rates over the
course of the Trimble County construction project.
On March 25, 1994, the Kentucky Attorney General and the Jefferson County
Attorney filed a motion with the Commission in which they requested that
two of the three members of the Commission and certain unspecified
Commission staff employees be recused from further participation in the
case. The intervenors supported the motion by arguing that past statements
and orders of the Commission in this and other proceedings showed that the
Commissioners had
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<PAGE>
prejudged the issues relevant to the current proceeding. The issues
referred to in the motion centered on the intervenors' claims that the
Company should refund 25% of all revenues associated with Trimble County
CWIP collected through rates during the course of the plant's construction.
On July 8, 1994, the Commission entered an order which denied the
intervenors' motion. In the order, the Commission stated that it had not
prejudged any issues but rather had decided a number of issues in past
proceedings which are binding on it and all other parties. The Commission
also stated that it had never implied in prior orders that the amounts of
Trimble County CWIP included in rate base prior to the issuance of its
July 1, 1988, order in Case No. 10064, a general rate case, would be
subject to later review. The Commission concluded that the scope of the
present case had been limited since at least 1985 when the Commission
issued an order that put the Company on notice that in future rate cases
the continuation of allowing a return on further additions to Trimble
County CWIP would be an issue.
The Company believes that the Commission's July 8 order makes it unlikely
that the Commission will entertain the position that the intervenors have
taken in their previously-filed testimony that the Company refund
approximately $183 million to its customers. The Company believes that
remaining at issue is what amount, if any, of the approximately $30 million
it collected subject to refund under a rate case order issued in 1988
should be returned to ratepayers. As discussed previously, approximately
$11.1 million has already been returned to ratepayers under the 1989
settlement agreement. However, the Company is unable to predict the
outcome of the Commission proceedings, or the amount of additional refunds
or recoveries, if any, that may be ordered.
The Commission has set May 9, 1995, as the formal hearing date in the
Trimble County proceedings. The purpose of the hearing is to determine the
proper ratemaking treatment to exclude 25% of Trimble County from customer
rates for the period from May 1988 to December 31, 1990. The Company's
current rates, which became effective January 1, 1991, reflect the
disallowance of 25% of the plant.
Reference is made to Note 12, Jointly Owned Electric Utility Plant, for a
discussion of the sale of 25% of Trimble County.
NOTE 12 - JOINTLY OWNED ELECTRIC UTILITY PLANT
The Company owns a 75% undivided interest in Trimble County Unit 1.
Accounting for the 75% portion of the Unit, which the Commission has
allowed to be reflected in customer rates, is similar to the Company's
accounting for other wholly owned utility plants.
Of the remaining 25% of the Unit, Illinois Municipal Electric Agency (IMEA)
purchased a 12.12% undivided interest in the Unit on February 28, 1991, and
Indiana Municipal Power Agency (IMPA) purchased a 12.88% undivided interest
on February 1, 1993. Each is responsible for their proportionate ownership
share of operation and maintenance expenses and incremental assets, and for
fuel used.
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<PAGE>
The following data represent shares of the jointly owned property:
<TABLE>
<CAPTION>
Trimble County
----------------------------------
LG&E IMPA IMEA Total
---- ---- ---- -----
<S> <C> <C> <C> <C>
Ownership interest . . . 75% 12.88% 12.12% 100%
Mw capacity. . . . . . . 371.25 63.75 60 495
</TABLE>
NOTE 13 - SEGMENTS OF BUSINESS
The Company is an operating public utility engaged in the generation,
transmission, distribution, and sale of electricity and the transmission,
distribution, and sale of natural gas.
<TABLE>
<CAPTION>
1994 1993 1992
---- ---- ----
(Thousands of $)
<S> <C> <C> <C>
Operating Information
Operating Revenues
Electric. . . . . . . . . . . . $ 558,946 $ 570,210 $ 521,669
Gas . . . . . . . . . . . . . . 200,129 204,915 178,526
------- ------- -------
Total . . . . . . . . . . . . $ 759,075 $ 775,125 $ 700,195
------- ------- -------
------- ------- -------
Pre-tax Operating Income
Electric. . . . . . . . . . . . . $ 139,594 $ 171,016 $ 154,547
Gas . . . . . . . . . . . . . . . 11,368 17,436 15,122
------- ------- -------
Total . . . . . . . . . . . . $ 150,962 $ 188,452 $ 169,669
------- ------- -------
------- ------- -------
Other Information
Depreciation and Amortization
Electric . . . . . . . . . . . . $ 71,882 $ 69,753 $ 67,869
Gas. . . . . . . . . . . . . . . 10,637 9,902 9,034
Non-Jurisdictional . . . . . . . - 232 2,783
------- ------- --------
Total. . . . . . . . . . . . . $ 82,519 $ 79,887 $ 79,686
------- ------- --------
------- ------- --------
Construction Expenditures
Electric. . . . . . . . . . . . . $ 71,592 $ 74,165 $ 75,630
Gas. . . . . . . . . . . . . . . 23,806 24,622 25,545
------- ------- -------
Total. . . . . . . . . . . . . $ 95,398 $ 98,787 $ 101,175
------- ------- -------
------- ------- -------
Investment Information-December 31
Identifiable Assets
Electric. . . . . . . . . . . . $1,514,287 $1,537,387 $1,528,123
Gas . . . . . . . . . . . . . . 252,946 241,930 222,958
--------- --------- ---------
Total . . . . . . . . . . . . 1,767,233 1,779,317 1,751,081
Trimble County (a). . . . . . . . - - 87,794
Other Assets (b). . . . . . . . . 199,357 195,267 121,985
--------- --------- ---------
Total Assets. . . . . . . . . $1,966,590 $1,974,584 $1,960,860
--------- --------- ---------
--------- --------- ---------
<FN>
(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.
</TABLE>
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<PAGE>
REPORT OF MANAGEMENT
The management of Louisville Gas and Electric Company is responsible for the
preparation and integrity of the financial statements and related information
included in this Annual Report. These statements have been prepared in
accordance with generally accepted accounting principles applied on a consistent
basis and, necessarily, include amounts that reflect the best estimates and
judgment of management.
The Company's financial statements have been audited by Arthur Andersen LLP,
independent public accountants. Management has made available to Arthur
Andersen LLP all the Company's financial records and related data as well as the
minutes of shareholders' and directors' meetings.
Management has established and maintains a system of internal controls that
provide reasonable assurance that transactions are completed in accordance with
management's authorization, that assets are safeguarded and that financial
statements are prepared in conformity with generally accepted accounting
principles. Management believes that an adequate system of internal controls is
maintained through the selection and training of personnel, appropriate division
of responsibility, establishment and communication of policies and procedures
and by regular reviews of internal accounting controls by the Company's internal
auditors. Management reviews and modifies its system of internal controls in
light of changes in conditions and operations, as well as in response to
recommendations from the internal auditors. These recommendations for the year
ended December 31, 1994 did not identify any significant deficiencies in the
design and operation of the Company's internal control structure.
The Audit Committee of the Board of Directors is composed entirely of outside
directors. In carrying out its oversight role for the financial reporting and
internal controls of the Company, the Audit Committee meets regularly with the
Company's independent public accountants, internal auditors and management. The
Audit Committee reviews the results of the independent accountants' audit of the
financial statements and their audit procedures, and discusses the adequacy of
internal accounting controls. The Audit Committee also approves the annual
internal auditing program, and reviews the activities and results of the
internal auditing function. Both the independent public accountants and the
internal auditors have access to the Audit Committee at any time.
Louisville Gas and Electric Company maintains and internally communicates a
written code of business conduct that addresses, among other items, potential
conflicts of interest, compliance with laws, including those relating to
financial disclosure, and the confidentiality of proprietary information.
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<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO LOUISVILLE GAS AND ELECTRIC COMPANY:
We have audited the accompanying balance sheets and statements of
capitalization of Louisville Gas and Electric Company (a Kentucky corporation
and a wholly owned subsidiary of LG&E Energy Corp.) as of December 31, 1994 and
1993, and the related statements of income, retained earnings and cash flows for
each of the three years in the period ended December 31, 1994. These financial
statements and the schedule referred to below are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements and schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Louisville Gas and Electric
Company as of December 31, 1994 and 1993, and the results of its operations and
its cash flows for each of the three years in the period ended December 31,
1994, in conformity with generally accepted accounting principles.
As further discussed in Note 11, the potential amount of future rate
refunds that may be required, if any, once the outcome of the legal and
regulatory process is known, is uncertain at this time.
As discussed in Notes 1 and 5 to the financial statements, effective
January 1, 1993, the Company changed its methods of accounting for income taxes
and post-retirement benefits other than pensions, and effective January 1, 1994,
the Company changed its method of accounting for post-employment benefits.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedule listed under Item 14(a)2 is
presented for purposes of complying with the Securities and Exchange
Commission's rules and is not part of the basic financial statements. This
schedule has been subjected to the auditing procedures applied in our audits of
the basic financial statements and, in our opinion, fairly states in all
material respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.
Louisville, Kentucky, Arthur Andersen LLP
January 30, 1995
--------------------------------
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<PAGE>
SELECTED QUARTERLY FINANCIAL DATA (Unaudited)
(Thousands of $)
Selected financial data for the four quarters of 1994 and 1993 are shown
below. Because of seasonal fluctuations in temperature and other factors,
results for quarters may fluctuate throughout the year.
<TABLE>
<CAPTION>
Quarters Ended
-------------------------------------------------
March June September December
----- ---- --------- --------
<S> <C> <C> <C> <C>
1994
Operating Revenues . . . . . $219,679 $173,042 $190,117 $176,237
Net Operating Income . . . . 6,603 29,873 45,913 28,651
Net Income (Loss). . . . . . (16,695) (a) 20,636 35,438 18,941
Net Income (Loss) Available
for Common Stock . . . . . (18,073) (a) 19,256 33,935 17,374
1993
Operating Revenues . . . . . $208,631 $166,906 $200,408 $199,180
Net Operating Income . . . . 32,754 28,395 47,786 27,183
Net Income . . . . . . . 20,786 16,566 36,447 16,736
Net Income Available for
Common Stock . . . . . . . 19,199 14,898 35,099 15,358
<FN>
(a) See Note 3 of Notes to Financial Statements under Item 8.
</TABLE>
-------------------------------------
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
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<PAGE>
PART III
ITEMS 10, 11, 12 AND 13 are omitted pursuant to General Instruction G,
inasmuch as the Company filed copies of a definitive proxy statement with the
Commission on March 16, 1995, pursuant to Regulation 14A under the Securities
Exchange Act of 1934. Such proxy statement is incorporated herein by this
reference. In accordance with General Instruction G of Form 10-K, the
information required by Item 10 relating to executive officers has been included
in Part I of this Form 10-K. The Louisville Gas and Electric Company (LG&E) is
a subsidiary of LG&E Energy Corp. At December 31, 1994, LG&E Energy Corp.
controlled 100% of the common stock of LG&E. There are situations where LG&E
Energy Corp. interacts with its affiliated companies through the use of shared
facilities, common employees, and other business relationships. In these
situations, LG&E receives payment in accordance with regulatory requirements for
the services provided to affiliated companies.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a) 1. Financial Statements (included in Item 8):
Statements of Income for the three years ended December 31,
1994 (page 23).
Statements of Retained Earnings for the three years ended
December 31, 1994
(page 23).
Balance Sheets - December 31, 1994, and 1993 (page 24).
Statements of Cash Flows for the three years ended December
31, 1994 (page 25).
Statements of Capitalization - December 31, 1994, and 1993
(page 26).
Notes to Financial Statements (pages 27-43).
Report of Management (page 44).
Report of Independent Public Accountants (page 45).
Selected Quarterly Financial Data for 1994 and 1993 (page 46).
2. Financial Statement Schedule (included in Part IV):
Schedule II - Valuation and Qualifying Accounts for the three
years ended December 31, 1994 (page 60).
All other schedules have been omitted as not applicable or not required or
because the information required to be shown is included in the Financial
Statements or the accompanying Notes to Financial Statements.
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<PAGE>
3. Exhibits:
Exhibit
No. Description
------- -----------
3.01 Copy of Restated Articles of Incorporation, as amended.
[Filed as Exhibit 3.01 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1993, and
incorporated by reference herein]
3.02 Copy of Amendment to Articles of Incorporation, effective
May 25, 1989. [Filed as Exhibit 3.02 to the Company's Annual
Report on Form 10-K for the year ended December 31, 1993, and
incorporated by reference herein]
3.03 Copy of Amendment to Articles of Incorporation, effective
February 6, 1992. [Filed as Exhibit 3.03 to the Company's
Annual Report on Form 10-K for the year ended December 31,
1993, and incorporated by reference herein]
3.04 Copy of Amendment to Articles of Incorporation, effective
April 8, 1993. [Filed as Exhibit 3.04 to the Company's Annual
Report on Form 10-K for the year ended December 31, 1993, and
incorporated by reference herein]
3.05 Copy of Amendment to Articles of Incorporation, effective
May 19, 1993. [Filed as Exhibit 3.05 to the Company's
Form 10-K for the year ended December 31, 1993, and
incorporated by reference herein]
3.06 Copy of Bylaws, as amended through May 13, 1993. [Filed as
Exhibit 3.01 to the Company's Form 10-Q for the quarter ended
June 30, 1993, and incorporated by reference herein]
4.01 Copy of Trust Indenture dated November 1, 1949, from the
Company to Harris Trust and Savings Bank, Trustee. [Filed as
Exhibit 7.01 to Registration Statement 2-8283 and incorporated
by reference herein]
4.02 Copy of Supplemental Indenture dated February 1, 1952, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 4.05 to Registration Statement 2-9371 and
incorporated by reference herein]
4.03 Copy of Supplemental Indenture dated February 1, 1954, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 4.03 to Registration Statement 2-11923 and
incorporated by reference herein]
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<PAGE>
4.04 Copy of Supplemental Indenture dated September 1, 1957, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 2.04 to Registration Statement 2-17047 and
incorporated by reference herein]
4.05 Copy of Supplemental Indenture dated October 1, 1960, which is
a supplemental instrument to Exhibit 4.01 hereto. [Filed as
Exhibit 2.05 to Registration Statement 2-24920 and
incorporated by reference herein]
4.06 Copy of Supplemental Indenture dated June 1, 1966, which is a
supplemental instrument to Exhibit 4.01 hereto. [Filed as
Exhibit 2.06 to Registration Statement 2-28865 and
incorporated by reference herein]
4.07 Copy of Supplemental Indenture dated June 1, 1968, which is a
supplemental instrument to Exhibit 4.01 hereto. [Filed as
Exhibit 2.07 to Registration Statement 2-37368 and
incorporated by reference herein]
4.08 Copy of Supplemental Indenture dated June 1, 1970, which is a
supplemental instrument to Exhibit 4.01 hereto. [Filed as
Exhibit 2.08 to Registration Statement 2-37368 and
incorporated by reference herein]
4.09 Copy of Supplemental Indenture dated August 1, 1971, which is
a supplemental instrument to Exhibit 4.01 hereto. [Filed as
Exhibit 2.09 to Registration Statement 2-44295 and
incorporated by reference herein]
4.10 Copy of Supplemental Indenture dated June 1, 1972, which is a
supplemental instrument to Exhibit 4.01 hereto. [Filed as
Exhibit 2.10 to Registration Statement 2-52643 and
incorporated by reference herein]
4.11 Copy of Supplemental Indenture dated February 1, 1975, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 2.11 to Registration Statement 2-57252 and
incorporated by reference herein]
4.12 Copy of Supplemental Indenture dated September 1, 1975, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 2.12 to Registration Statement 2-57252 and
incorporated by reference herein]
4.13 Copy of Supplemental Indenture dated September 1, 1976, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 2.13 to Registration Statement 2-57252 and
incorporated by reference herein]
-49-
<PAGE>
4.14 Copy of Supplemental Indenture dated October 1, 1976, which is
a supplemental instrument to Exhibit 4.01 hereto. [Filed as
Exhibit 2.14 to Registration Statement 2-65271 and
incorporated by reference herein]
4.15 Copy of Supplemental Indenture dated June 1, 1978, which is a
supplemental instrument to Exhibit 4.01 hereto. [Filed as
Exhibit 2.15 to Registration Statement 2-65271 and
incorporated by reference herein]
4.16 Copy of Supplemental Indenture dated February 15, 1979, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 2.16 to Registration Statement 2-65271 and
incorporated by reference herein]
4.17 Copy of Supplemental Indenture dated September 1, 1979, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 4.17 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1980, and incorporated by
reference herein]
4.18 Copy of Supplemental Indenture dated September 15, 1979, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 4.18 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1980, and incorporated by
reference herein]
4.19 Copy of Supplemental Indenture dated September 15, 1981, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 4.19 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1981, and incorporated by
reference herein]
4.20 Copy of Supplemental Indenture dated March 1, 1982, which is a
supplemental instrument to Exhibit 4.01 hereto. [Filed as
Exhibit 4.20 to the Company's Annual Report on Form 10-K for
the year ended December 31, 1982, and incorporated by
reference herein]
4.21 Copy of Supplemental Indenture dated March 15, 1982, which is
a supplemental instrument to Exhibit 4.01 hereto. [Filed as
Exhibit 4.21 to the Company's Annual Report on Form 10-K for
the year ended December 31, 1982, and incorporated by
reference herein]
4.22 Copy of Supplemental Indenture dated September 15, 1982, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 4.22 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1982, and incorporated by
reference herein]
-50-
<PAGE>
4.23 Copy of Supplemental Indenture dated February 15, 1984, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 4.23 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1984, and incorporated by
reference herein]
4.24 Copy of Supplemental Indenture dated July 1, 1985, which is a
supplemental instrument to Exhibit 4.01 hereto. [Filed as
Exhibit 4.24 to the Company's Annual Report on Form 10-K for
the year ended December 31, 1985, and incorporated by
reference herein]
4.25 Copy of Supplemental Indenture dated November 15, 1986, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 4.25 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1986, and incorporated by
reference herein]
4.26 Copy of Supplemental Indenture dated November 16, 1986, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 4.26 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1986, and incorporated by
reference herein]
4.27 Copy of Supplemental Indenture dated August 1, 1987, which is
a supplemental instrument to Exhibit 4.01 hereto. [Filed as
Exhibit 4.27 to the Company's Annual Report on Form 10-K for
the year ended December 31, 1987, and incorporated by
reference herein]
4.28 Copy of Supplemental Indenture dated February 1, 1989, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 4.28 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1988, and incorporated by
reference herein]
4.29 Copy of Supplemental Indenture dated February 2, 1989, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 4.29 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1988, and incorporated by
reference herein]
4.30 Copy of Supplemental Indenture dated June 15, 1990, which is a
supplemental instrument to Exhibit 4.01 hereto. [Filed as
Exhibit 4.30 to the Company's Annual Report on Form 10-K for
the year ended December 31, 1990, and incorporated by
reference herein]
4.31 Copy of Supplemental Indenture dated November 1, 1990, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 4.31 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1990, and incorporated by
reference herein]
-51-
<PAGE>
4.32 Copy of Supplemental Indenture dated September 1, 1992, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 4.32 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1992, and incorporated by
reference herein]
4.33 Copy of Supplemental Indenture dated September 2, 1992, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 4.33 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1992, and incorporated by
reference herein]
4.34 Copy of Supplemental Indenture dated August 15, 1993, which is
a supplemental instrument to Exhibit 4.01 hereto. [Filed as
Exhibit 4.34 to the Company's Annual Report on Form 10-K for
the year ended December 31, 1993, and incorporated by
reference herein]
4.35 Copy of Supplemental Indenture dated August 16, 1993, which is
a supplemental instrument to Exhibit 4.01 hereto. [Filed as
Exhibit 4.35 to the Company's Annual Report on Form 10-K for
the year ended December 31, 1993, and incorporated by
reference herein]
4.36 Copy of Supplemental Indenture dated October 15, 1993, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 4.36 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1993, and incorporated by
reference herein]
10.01 Copy of Agreement dated September 1, 1970, between Texas Gas
Transmission Corporation and the Company covering the purchase
of natural gas. [Filed as Exhibit 4.01 to Registration
Statement 2-40985 and incorporated by reference herein]
10.02 Copies of Agreement between Sponsoring Companies re: Project D
of Atomic Energy Commission, dated May 12, 1952, Memorandums
of Understanding between Sponsoring Companies re: Project D of
Atomic Energy Commission, dated September 19, 1952 and
October 28, 1952, and Power Agreement between Ohio Valley
Electric Corporation and Atomic Energy Commission, dated
October 15, 1952. [Filed as Exhibit 13(y) to Registration
Statement 2-9975 and incorporated by reference herein]
10.03 Copy of Modification No. 1 dated July 23, 1953, to the Power
Agreement between Ohio Valley Electric Corporation and Atomic
Energy Commission. [Filed as Exhibit 4.03(b) to Registration
Statement 2-24920 and incorporated by reference herein]
-52-
<PAGE>
10.04 Copy of Modification No. 2 dated March 15, 1964, to the Power
Agreement between Ohio Valley Electric Corporation and Atomic
Energy Commission. [Filed as Exhibit 5.02c to Registration
Statement 2-61607 and incorporated by reference herein]
10.05 Copy of Modification No. 3 and No. 4 dated May 12, 1966 and
January 7, 1967, respectively, to the Power Agreement between
Ohio Valley Electric Corporation and Atomic Energy Commission.
[Filed as Exhibits 4(a)(13) and 4(a)(14) to Registration
Statement 2-26063 and incorporated by reference herein]
10.06 Copy of Modification No. 5 dated August 15, 1967, to the Power
Agreement between Ohio Valley Electric Corporation and Atomic
Energy Commission. [Filed as Exhibit 13(c) to Registration
Statement 2-27316 and incorporated by reference herein]
10.07 Copies of (i) Inter-Company Power Agreement, dated July 10,
1953, between Ohio Valley Electric Corporation and Sponsoring
Companies (which Agreement includes as Exhibit A the Power
Agreement, dated July 10, 1953, between Ohio Valley Electric
Corporation and Indiana-Kentucky Electric Corporation); (ii)
First Supplementary Transmission Agreement, dated July 10,
1953, between Ohio Valley Electric Corporation and Sponsoring
Companies; (iii) Inter-Company Bond Agreement, dated July 10,
1953, between Ohio Valley Electric Corporation and Sponsoring
Companies; (iv) Inter-Company Bank Credit Agreement, dated
July 10, 1953, between Ohio Valley Electric Corporation and
Sponsoring Companies. [Filed as Exhibit 5.02f to Registration
Statement 2-61607 and incorporated by reference herein]
10.08 Copy of Modification No. 1 and No. 2 dated June 3, 1966 and
January 7, 1967, respectively, to Inter-Company Power
Agreement dated July 10, 1953. [Filed as Exhibits 4(a)(8) and
4(a)(10) to Registration Statement 2-26063 and incorporated by
reference herein]
10.09 Copies of Amendments to Agreements (iii) and (iv) referred to
under 10.07 above as follows: (i) Amendment to Inter-Company
Bond Agreement and (ii) Amendment to Inter-Company Bank Credit
Agreement. [Filed as Exhibit 5.02h to Registration Statement
2-61607 and incorporated by reference herein]
10.10 Copy of Modification No. 1, dated August 20, 1958, to First
Supplementary Transmission Agreement, dated July 10, 1953,
among Ohio Valley Electric Corporation and the Sponsoring
Companies. [Filed as Exhibit 5.02i to Registration Statement
2-61607 and incorporated by reference herein]
-53-
<PAGE>
10.11 Copy of Modification No. 2, dated April 1, 1965, to the First
Supplementary Transmission Agreement, dated July 10, 1953,
among Ohio Valley Electric Corporation and the Sponsoring
Companies. [Filed as Exhibit 5.02j to Registration Statement
2-6l607 and incorporated by reference herein]
10.12 Copy of Modification No. 3, dated January 20, 1967, to First
Supplementary Transmission Agreement, dated July 10, 1953,
among Ohio Valley Electric Corporation and the Sponsoring
Companies. [Filed as Exhibit 4(a)(7) to Registration
Statement 2-26063 and incorporated by reference herein]
10.13 Copy of Modification No. 6 dated November 15, 1967, to the
Power Agreement between Ohio Valley Electric Corporation and
Atomic Energy Commission. [Filed as Exhibit 4(g) to
Registration Statement 2-28524 and incorporated by reference
herein]
10.14 Copy of Modification No. 3 dated November 15, 1967, to the
Inter-Company Power Agreement dated July 10, 1953. [Filed as
Exhibit 4.02m to Registration Statement 2-37368 and
incorporated by reference herein]
10.15 Copy of Modification No. 7 dated November 5, 1975, to the
Power Agreement between Ohio Valley Electric Corporation and
Atomic Energy Commission. [Filed as Exhibit 5.02n to
Registration Statement 2-56357 and incorporated by reference
herein]
10.16 Copy of Modification No. 4 dated November 5, 1975, to the
Inter-Company Power Agreement dated July 10, 1953. [Filed as
Exhibit 5.02o to Registration Statement 2-56357 and
incorporated by reference herein]
10.17 Copy of Modification No. 4 dated April 30, 1976, to First
Supplementary Transmission Agreement, dated July 10, 1953,
among Ohio Valley Electric Corporation and the Sponsoring
Companies. [Filed as Exhibit 5.02p to Registration Statement
2-6l607 and incorporated by reference herein]
10.18 Copy of Modification No. 8 dated June 23, 1977, to the Power
Agreement between Ohio Valley Electric Corporation and Atomic
Energy Commission. [Filed as Exhibit 5.02q to Registration
Statement 2-61607 and incorporated by reference herein]
10.19 Copy of Modification No. 9 dated July 1, 1978, to the Power
Agreement between Ohio Valley Electric Corporation and Atomic
Energy Commission. [Filed as Exhibit 5.02r to Registration
Statement 2-63149 and incorporated by reference herein]
-54-
<PAGE>
10.20 Copy of Modification No. 10 dated August 1, 1979, to the Power
Agreement between Ohio Valley Electric Corporation and Atomic
Energy Commission. [Filed as Exhibit 2 to the Company's
Annual Report on Form 10-K for the year ended December 31,
1979, and incorporated by reference herein]
10.21 Copy of Modification No. 11 dated September 1, 1979, to the
Power Agreement between Ohio Valley Electric Corporation and
Atomic Energy Commission. [Filed as Exhibit 3 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1979, and incorporated by reference herein]
10.22 Copy of Modification No. 5 dated September 1, 1979, to
Inter-Company Power Agreement dated July 5, 1953, among Ohio
Valley Electric Corporation and Sponsoring Companies. [Filed
as Exhibit 4 to the Company's Annual Report on Form 10-K for
the year ended December 31, 1979, and incorporated by
reference herein]
10.23 Copy of Modification No. 12 dated August 1, 1981, to the Power
Agreement between Ohio Valley Electric Corporation and Atomic
Energy Commission. [Filed as Exhibit 10.25 to the Company's
Annual Report on Form 10-K for the year ended December 31,
1981, and incorporated by reference herein]
10.24 Copy of Modification No. 6 dated August 1, 1981, to
Inter-Company Power Agreement dated July 5, 1953, among Ohio
Valley Electric Corporation and Sponsoring Companies. [Filed
as Exhibit 10.26 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1981, and incorporated by
reference herein]
10.25 Copy of Diversity Power Agreement dated September 9, 1987,
between East Kentucky Power Cooperative and the Company
covering the purchase and sale of power between the two
companies from 1988 through 1995. [Filed as Exhibit 10.28 to
the Company's Annual Report on Form 10-K for the year ended
December 31, 1987, and incorporated by reference herein]
10.26 Copy of Supplemental Executive Retirement Plan as amended
through January 3, 1990, covering all officers of the Company.
[Filed as Exhibit 10.29 to the Company's Annual Report on Form
10-K for the year ended December 31, 1989, and incorporated by
reference herein]
10.27 Copy of Omnibus Long-Term Incentive Plan effective January 1,
1990, covering officers and key employees of the Company.
[Filed as Exhibit 4.01 to the Company's Registration
Statement 33-38557 and incorporated by reference herein]
-55-
<PAGE>
10.28 Copy of Key Employee Incentive Plan effective January 1, 1990,
covering officers and key employees of the Company. [Filed as
Exhibit 10.33 to the Company's Annual Report on Form 10-K for
the year ended December 31, 1989, and incorporated by
reference herein]
10.29 Copy of LG&E Energy Corp. Deferred Stock Compensation Plan
effective January 1, 1992, covering non-employee directors of
LG&E Energy Corp. and its subsidiaries. [Filed as
Exhibit 10.34 to LG&E Energy Corp.'s Annual Report on Form 10-K
for the year ended December 31, 1991, and incorporated by
reference herein]
10.30 Copy of form of change in control agreement for officers of
Louisville Gas and Electric Company. [Filed as Exhibit 10.38
to the Company's Annual Report on Form 10-K for the year ended
December 31, 1992, and incorporated by reference herein]
10.31 Copy of Supplemental Executive Retirement Plan for Roger W.
Hale, effective June 1, 1989. [Filed as Exhibit 10.40 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1992, and incorporated by reference herein]
10.32 Copy of Nonqualified Savings Plan covering officers of the
Company, effective January 1, 1992. [Filed as Exhibit 10.41 to
the Company's Annual Report on Form 10-K for the year ended
December 31, 1992, and incorporated by reference herein]
10.33 Copy of Modification No. 13 dated September 1, 1989, to the
Power Agreement between Ohio Valley Electric Corporation and
Atomic Energy Commission. [Filed as Exhibit 10.42 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1993, and incorporated by reference herein]
10.34 Copy of Modification No. 14 dated January 15, 1992, to the
Power Agreement between Ohio Valley Electric Corporation and
Atomic Energy Commission. [Filed as Exhibit 10.43 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1993, and incorporated by reference herein]
10.35 Copy of Modification No. 7 dated January 15, 1992, to Inter-
Company Power Agreement dated July 10, 1953, among Ohio Valley
Electric Corporation and Sponsoring Companies. [Filed as
Exhibit 10.44 to the Company's Annual Report on Form 10-K for
the year ended December 31, 1993, and incorporated by reference
herein]
-56-
<PAGE>
10.36 Copy of Modification No. 15 dated February 15, 1993, to the
Power Agreement between Ohio Valley Electric Corporation and
Atomic Energy Commission. [Filed as Exhibit 10.45 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1993, and incorporated by reference herein]
10.37 Firm Transportation Agreement, dated November 1, 1993, between
Texas Gas Transmission Corporation and the Company covering the
transmission of natural gas. [Filed as Exhibit 10.46 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1993, and incorporated by reference herein]
10.38 Firm No Notice Transportation Agreement effective November 1,
1993, between Texas Gas Transmission Corporation and the
Company (8-year term) covering the transmission of natural gas.
[Filed as Exhibit 10.47 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1993, and
incorporated by reference herein]
Firm No Notice Transportation Agreement effective November 1,
1993, between Texas Gas Transmission Corporation and the
Company (2-year term) covering the transmission of natural gas.
[Filed as Exhibit 10.47 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1993, and
incorporated by reference herein]
Firm No Notice Transportation Agreement effective November 1,
1993, between Texas Gas Transmission Corporation and the
Company (5-year term) covering the transmission of natural gas.
[Filed as Exhibit 10.47 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1993, and
incorporated by reference herein]
10.39 Employment Contract between LG&E Energy Corp. and Roger W. Hale
effective November 3, 1993. [Filed as Exhibit 10.50 to LG&E
Energy Corp.'s Annual Report on Form 10-K for the year ended
December 31, 1993, and incorporated by reference herein]
10.40 Copy of LG&E Energy Corp. Stock Option Plan for Non-Employee
Directors. [Filed as Exhibit 10.51 to LG&E Energy Corp.'s
Annual Report on Form 10-K for the year ended December 31,
1993, and incorporated by reference herein]
10.41 Copy of Coal Supply Agreement dated August 9, 1989, between
Shawnee Coal Company, Roberts Brothers Coal Company, and the
Company covering the purchase of coal.
10.42 Copy of Amendment No. 1 dated January 1, 1991, to Coal Supply
Agreement, dated August 9, 1989, between Shawnee Coal
-57-
<PAGE>
Company, Roberts Brothers Coal Company, and the Company
covering the purchase of coal.
10.43 Copy of Amendment No. 2 dated November 27, 1991, to Coal Supply
Agreement, dated August 9, 1989, between Shawnee Coal Company,
Roberts Brothers Coal Company, and the Company covering the
purchase of coal.
10.44 Copy of Amendment No. 3 dated January 1, 1994, to Coal Supply
Agreement, dated August 9, 1989, between Shawnee Coal Company,
Roberts Brothers Coal Company, and the Company covering the
purchase of coal.
10.45 Copy of Amendment No. 4 dated January 1, 1995, to Coal Supply
Agreement, dated August 9, 1989, between Shawnee Coal Company,
Roberts Brothers Coal Company, and the Company covering the
purchase of coal.
10.46 Copy of Coal Supply Agreement dated January 1, 1994, between
Peabody Coalsales Company and the Company covering the purchase
of coal.
12 Computation of Ratio of Earnings to Fixed Charges
23 Consent of Independent Public Accountants
24 Power of Attorney
27 Financial Data Schedule
(b) Executive Compensation Plans and Arrangements:
Supplemental Executive Retirement Plan as amended through
January 3, 1990, covering all officers of the Company. [Filed
as Exhibit 10.29 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1989, and incorporated by
reference herein]
Omnibus Long-Term Incentive Plan effective January 1, 1990,
covering officers and key employees of the Company. [Filed as
Exhibit 4.01 to the Company's Registration Statement 33-38557
and incorporated by reference herein]
Key Employee Incentive Plan effective January 1, 1990, covering
officers and key employees of the Company. [Filed as
Exhibit 10.33 to the Company's Annual Report on Form 10-K for
the year ended December 31, 1989, and incorporated by reference
herein]
-58-
<PAGE>
LG&E Energy Corp. Deferred Stock Compensation Plan effective
January 1, 1992, covering non-employee directors of LG&E Energy
Corp. and its subsidiaries. [Filed as Exhibit 10.34 to LG&E
Energy Corp.'s Annual Report on Form 10-K for the year ended
December 31, 1991, and incorporated by reference herein]
Form of change in control agreement for officers of Louisville
Gas and Electric Company. [Filed as Exhibit 10.38 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1992, and incorporated by reference herein]
Supplemental Executive Retirement Plan for R. W. Hale,
effective June 1, 1989. [Filed as Exhibit 10.40 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1992, and incorporated by reference herein]
Nonqualified Savings Plan covering officers of the Company
effective January 1, 1992. [Filed as Exhibit 10.41 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1992, and incorporated by reference herein]
Employment Contract between LG&E Energy Corp. and Roger W. Hale
effective November 3, 1993. [Filed as Exhibit 10.50 to LG&E
Energy Corp.'s Annual Report on Form 10-K for the year ended
December 31, 1993, and incorporated by reference herein]
LG&E Energy Corp. Stock Option Plan for Non-Employee Directors.
[Filed as Exhibit 10.51 to LG&E Energy Corp.'s Annual Report on
Form 10-K for the year ended December 31, 1993, and
incorporated by reference herein]
(c) Reports on Form 8-K:
The Company was not required to file a Form 8-K report during
the fourth quarter of 1994.
-59-
<PAGE>
SCHEDULE II
LOUISVILLE GAS AND ELECTRIC COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1994
(Thousands of $)
<TABLE>
<CAPTION>
Reserves Deducted from
Assets in Balance Sheet
------------------------------------
Other Accounts
Property Receivable
and (Uncollectible
Investments Accounts)
----------- -------------
<S> <C> <C>
Balance January 1, 1992. . . . . . . $ 2,862 $ 1,413
Additions:
Charged to costs and expenses
Trimble County -
non-jurisdictional
depreciation . . . . . . 2,783
Other. . . . . . . . . . . 2,158
Deductions:
Net charges of nature for which
reserves were created. . . 2,462
----- -----
Balance December 31, 1992. . . . . . 5,645 1,109
Additions:
Charged to costs and expenses
Trimble County -
non-jurisdictional
depreciation . . . . . . 233
Other. . . . . . . . . . . 2,500
Deductions:
Net charges of nature for which
reserves were created. . . 2,135
Other . . . . . . . . . . . 5,815
----- -----
Balance December 31, 1993. . . . . . 63 1,474
Additions:
Charged to costs and expenses 3,100
Deductions:
Net charges of nature for which
reserves were created. . . 3,371
_____ -----
Balance December 31, 1994. . . . . . $ 63 $ 1,203
----- -----
----- -----
</TABLE>
-60-
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
LOUISVILLE GAS AND ELECTRIC COMPANY
Registrant
March 24, 1995 By
- -------------- ------------------------------------------
(Date) M. L. Fowler
Vice President and Controller
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date indicated.
Signature Title Date
--------- ----- ----
ROGER W. HALE Chairman of the Board and
Chief Executive Officer
(Principal Executive Officer);
CHARLES A. MARKEL III Treasurer
(Principal Financial Officer);
M. L. FOWLER Vice President and Controller
(Principal Accounting Officer);
WILLIAM C. BALLARD, JR. Director;
OWSLEY BROWN II Director;
S. GORDON DABNEY Director;
GENE P. GARDNER Director;
J. DAVID GRISSOM Director;
DAVID B. LEWIS Director;
ANNE H. MCNAMARA Director;
T. BALLARD MORTON, JR. Director; and
DR. DONALD C. SWAIN Director.
By__________________________________ March 24, 1995
M. L. FOWLER (Attorney-In-Fact)
-61-
<PAGE>
EXHIBIT 10.41
COAL SUPPLY AGREEMENT
THIS COAL SUPPLY AGREEMENT ("Agreement") entered into this 9th day of
August, 1989 by and between LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky
corporation ("Buyer") and SHAWNEE COAL COMPANY, a Tennessee corporation, and
ROBERTS BROS. COAL CO. INC., a Kentucky corporation (hereafter severally,
collectively and jointly "Seller").
W I T N E S S E T H:
WHEREAS, Buyer is an electric utility company which desires to purchase
steam coal; and
WHEREAS, Seller has access to various sources of such coal and desires to
supply such coal to Buyer.
NOW THEREFORE, in consideration of the mutual covenants contained herein,
Seller agrees to sell and deliver and Buyer agrees to purchase and accept
delivery of coal on the terms and conditions set forth herein.
1. TERM
1.1 TERM. Except for specific effective dates described in specific
sections herein, the term of this Agreement shall commence on March 1, 1989 and
shall continue until and including December 31, 1995. Buyer shall have the
right, but not the obligation, to renew this Agreement for up to three (3)
additional five (5) year periods, such right to be exercised by notice in
writing to Seller no later than sixty (60) days prior to the end of the existing
period. The Base Price upon any such renewal shall be agreed upon by the
parties subject to the provisions of Section 6.2.
<PAGE>
2. QUANTITY
2.1 ANNUAL QUANTITY. This section effective January 1, 1989. Except as
adjusted under Section 2.3, Seller shall sell and deliver and Buyer shall
purchase and accept delivery of the following annual tonnages ("Annual
Quantity").
YEAR ANNUAL QUANTITY (TONS)
1989 364,000
1990 364,000
1991 500,000
1992 750,000
1993 750,000
1994 750,000
1995 750,000
2.2 RATE OF SHIPMENT. The Annual Quantity shall be shipped in accordance
with a reasonable monthly delivery schedule supplied by Buyer to Seller as
further provided in Section 2.3. Time is of the essence with respect to the
schedule so established, and failure by Seller to deliver in timely fashion
shall constitute a default within the meaning of Section 15 of this Agreement.
2.3 NOTIFICATION. By December 1 of each Agreement year, Buyer shall
specify by written notice to Seller the monthly quantities to be delivered in
the following Agreement year. Commencing on January 1, 1991, upon 6 months
notice to Seller, Buyer may change the quantity to be delivered under this
Section within a range of +/- 20% of specified annual tonnage, except that in no
event shall Buyer specify less than 400,000 tons for the 1991 Agreement year,
and 600,000 tons for Agreement years 1992 and following. Further, Buyer shall
have the option to purchase up to an additional 168,000 tons per year for 1989
and 1990.
3. SOURCE AND DELIVERY
2
<PAGE>
3.1 SOURCE. The coal sold hereunder, including coal purchased from third
parties, shall be supplied from Western Kentucky geological seams Nos. 4, 6, 8,
9, 11, 12 and 13 or their equivalent in the opinion of Buyer. The source is
described with particularity in Exhibit A "Coal Property" attached hereto and
made a part hereof (hereafter "Coal Property"). The designated source of coal
of the quality set forth in Section 4.1 (Standard Specifications) are the
following mines: Cardinal Mine, Hopkins County, Kentucky; Oriole Mine, Hopkins
County, Kentucky; Donaldson Creek Mine, Hopkins County, Kentucky; Diamond Mine,
Webster County, Kentucky; Kohl Trust Mine, Hopkins County, Kentucky and such
other reserves as Seller may procure over the life of this Agreement. Seller
may provide coal from any combination of sources provided that the Standard
Specifications under Section 4.1, in Buyer's sole reasonable judgment, are met
or exceeded. Seller shall promptly notify Buyer of any such changes. In the
event Buyer approves any source(s) with such different specifications, the price
for such coal shall be determined as set forth in Section 3.4.
3.2 ASSURANCE OF OPERATION AND RESERVES. Seller represents and warrants
that the Coal Property contains economically recoverable cost of a quality and
in quantities which will be sufficient to satisfy all the requirements of this
Agreement. Seller agrees and warrants that it will have at the Coal Property
adequate machinery, equipment and other facilities to produce, prepare and
deliver coal in the quantity and at the quality required by this Agreement.
Seller further agrees to operate and maintain such machinery, equipment and
facilities in accordance with good mining practices so as to efficiently and
economically produce, prepare and deliver such coal. Seller agrees that Buyer
is not providing any capital for the purchase of such machinery, equipment
and/or facilities and that Seller shall operate and maintain same at its sole
expense, including all required permits and licenses. Seller hereby dedicates
to this Agreement sufficient
3
<PAGE>
reserves of coal meeting the quality specifications hereof and lying on or in
the Coal Property so as to fulfill the quantity requirements hereof.
3.3 NON-DIVERSION OF COAL. Seller agrees and warrants that it will not,
without Buyer's express prior written consent, use or sell coal from the Coal
Property in a way that will reduce the economically recoverable balance of coal
in the Coal Property to an amount less than that required to be supplied to
Buyer hereunder.
3.4 SUBSTITUTE COAL. Notwithstanding the above representations and
warranties, in the event of Seller's inability to produce coal in the quantity
and at the quality required by this Agreement, Seller may, with the express
written consent of Buyer, and subject to any reasonable terms Buyer may require
including, without limitation, the right to share equally in the savings
realized by Seller, supply coal (in all respects of the same or better quality
in Buyer's sole opinion as that provided from the Coal Property) from other
facilities and mines; provided however that the fully evaluated price to Buyer
of any such coal shall not be greater than said fully evaluated price in $/MMBTU
would have been had the coal been supplied from the Coal Property ("fully
evaluated price" as used in this Agreement shall mean the price of coal FOB rail
car or barge, plus transportation, plus or minus, as applicable, quality
adjustments, if any.)
3.5 RAIL DELIVERY. Buyer and Seller hereby select rail transportation on
the Paducah & Louisville (PAL) Railway as the method of shipment for all coal
under this Agreement. Title to and risk of loss of coal will pass to Buyer and
the coal will be considered to be delivered when it is loaded into the railcars
at the Cardinal Mine rail loading facility near Madisonville, Kentucky on the
PAL railway. Buyer or its contractor shall furnish suitable railcars in
accordance with a delivery schedule provided by Buyer to Seller. With Buyer's
prior approval, Seller may deliver the coal to any rail loading facility
("Delivery Point"), provided, however, the total delivered cost
4
<PAGE>
of the coal by train to Buyer's generating stations from any Delivery Point
shall not exceed the total delivered cost of coal by unit train to Buyer's
Generating Station(s) from the Cardinal Mine Delivery Point on the PAL Railway
near Madisonville, Kentucky. Any savings in transportation expenses resulting
from coal loaded at a Delivery Point closer to Buyer's Generating Station(s)
than the Delivery Point of the Cardinal Mine, on the PAL Railway near
Madisonville, Kentucky shall belong to Buyer. Seller shall be responsible for
any pay the cost of repairs for any damages caused by Seller or its producer(s)
to railcars owned or leased by Buyer while such railcars are in Seller's control
or custody. Seller agrees to comply with the provision of PAL Tariff 4000 and
its supplements or other tariffs as applicable.
3.5.1 BARGE DELIVERY. Buyer shall be entitled, upon prior reasonable
notice to Seller, to change the specified mode of delivery for all or a portion
of the Annual Quantity, subject to the availability of a barge loading facility.
Any such change shall be made pursuant to Section 9 of this Agreement. In the
event barge delivery is selected by Buyer for all or a portion of the Annual
Quantity, the following provisions shall apply, effective on the date of
election:
The coal shall be delivered to Buyer F.O.B. barge, title and risk of loss
of coal sold will pass to Buyer and the coal will be considered to be delivered
when barges containing the coal are disengaged by Buyer's barging contractor
from the loading dock. Buyer or its contractor shall furnish suitable barges in
accordance with a delivery schedule provided by Buyer to Seller. Seller may
deliver the coal to any loading facility ("Delivery Point"), provided, however,
the total delivered cost of the coal by barge to Buyer's generating stations
from any Delivery Point shall not exceed the total delivered cost of coal by
barge to Buyer's Generating Station(s) form the Sebree Dock Point at mile point
44.0 on the Green River. Any savings in transportation expenses
5
<PAGE>
resulting from coal loaded at a Delivery Point closer to Buyer's Generating
Station(s) than the Delivery Point of the Sebree Dock shall belong to Buyer.
Seller shall arrange and pay for all costs of transporting the coal from
the mines to the loading docks and loading and trimming the coal into barges to
the property draft and the proper distribution within the barges. Buyer shall
reimburse Seller for such reasonable and actual trucking and transfer charges
and shall arrange for transporting the coal by barge from the loading dock to
its Generating Station(s) and shall pay for the cost of such transportation.
For delays caused by Seller in handling the scheduling of shipments with Buyer's
barging contractor Seller shall be responsible for any demurrage or other
penalties assessed by said barging contractor (or assessed by Buyer relating to
barges furnished by Buyer) which accrue at the Delivery point, including the
demurrage, penalties for loading less than the specified minimum tonnage per
barge, or other penalties assessed for barges not loaded in conformity with
applicable requirements. Buyer shall be responsible to deliver barges in as
clean and dry condition as practicable. Seller shall require of the loading
dock operator that the barges and towboats provided by Buyer or Buyer's barging
contractor be provided convenient and safe berth free of the wharfage, dockage
and port charges; that while the barges are in the are and custody of the
loading dock, all U.S. Coast Guard regulations and other applicable laws,
ordinances, rulings, and regulations shall be complied with, including adequate
mooring and display of warning lights; that any water in the cargo boxes of the
barges be pumped out by the loading dock operator prior to loading; that the
loading operations be performed in a workmanlike manner and in accordance with
the reasonable loading requirements of Buyer and Buyer's barging contractor; and
that the loading dock operator carry landing owners or wharfinger's insurance
with basic coverage of not less than $300,000.00 and total of basic coverage and
excess liability coverage of not less than $1,000,000.00, and
6
<PAGE>
provide evidence thereof to Buyer in the form of a certificate of insurance from
the insurance carrier or an acceptable certificate of self-insurance with
requirement for notification of Buyer in the event of termination of the
insurance.
4. QUALITY
4.1 QUALITY. This section effective March 1, 1989. The coal delivered
hereunder shall conform to the following specifications on an "as received"
basis:
I. Standard Specification
<TABLE>
<CAPTION>
Guaranteed Monthly Rejection Limits
Specification Weighted Average (per shipment)
- -----------------------------------------------------------------------
<S> <C> <C>
BTU/LB. min. 11,700 < 10,850>
MOISTURE max. 7.7 lbs/MMBTU > 11.5
ASH max. 10.0 lbs/MMBU > 12.3
SULFUR max. 3.0 lbs/MMBTU > 3.3
SULFUR min. 1.8 lbs/MMBTU < 1.8>
CHLORINE max. .05 lbs/MMBTU > .07
FLUORINE max. .013 lbs/MMBTU > .013
NITROGEN max. 1.15 lbs/MMBTU > 1.40
ASH/SULFUR RATIO min. 2 < 2>
Size (3" x 0")
Top size (inches) max. 3" > 3"
Fines (% by wgt)
passing 1/4 inch.
screen max. 3" > 35%
% BY WEIGHT:
VOLATILE max. 38 > 38
VOLATILE min. 29 < 29>
FIXED CARBON max. 50 > 50
FIXED CARBON min. 42 < 40>
GRINDABILITY (HGI) min. 55 < 50>
SLAGGING FACTOR* max. 1.6 > 1.9
FOULING FACTOR** max. 0.2 > 0.4
ASH FUSION TEMPERATURE (DEG.F) (ASTM D1857)
- ----------------------------------------
7
<PAGE>
REDUCING ATMOSPHERE
- --------------------
Initial Deformation min. 1940 min. 2000
Softening (H=W) min. 2035 min. 2100
Softening (H=1/2 W) min. 2085 min. 2200
Fluid min. 2190 min. 2300
OXIDIZING ATMOSPHERE
- --------------------
Initial Deformation min. 2300 min. 2350
Softening (H=W) min. 2330 min. 2400
Softening (H=1/2 W) min. 2425 min. 2500
Fluid min. 2490 min. 2525
<FN>
* Slagging Factor (R/s)=(B/A) x (Percent Sulfur by Weight/Dry)
** Fouling Factor (R/f)=(B/A) x (Percent Na/2/0 by Weight/Dry)
</TABLE>
The Base Acid Ratio (B/A) is herein defined as:
BASE ACID RATIO (B/A) = (Fe 0 DIVIDED BY Ca0 + Mg0 + Na 0 + K 0)
--------------------------------------------
2 3 2 2
(Si0 + A1 0 + T10 )
2 2 3 2
All the coal will be of such size that it will pass through a screen having
circular perforations three (3) inches in diameter, but shall not contain more
than thirty percent (30%) by weight of coal that will pass through a screen
having circular perforations one-quarter (1/4) of an inch in diameter.
[Note: As used herein > means greater than; < means less than].
4.2 SHIPMENT. As used herein, a shipment shall mean one barge load, a
barge lot load, or one unit trainload, as the case may be.
4.3 REJECTION.
a. Buyer has the right, but not the obligation, to reject any
shipment or car load(s) which fail(s) to conform to the Rejection Limits set
forth in Section 4.1 or contains
8
<PAGE>
extraneous materials or improperly sized coal. Buyer must reject such coal
within seventy-two (72) hours of receipt of the coal analysis provided for in
Section 5.3 or such right to reject is waived. In the event Buyer rejects such
non-conforming coal, Buyer shall return the coal to Seller or, at Seller's
request, divert such coal to Seller's designee, all at Seller's cost if the coal
is rightfully rejected. Seller shall replace the rejected coal within five (5)
working days with coal conforming to the Rejection Limits set forth in Section
4.1. If Seller fails to replace the rejected coal within such five (5) working
day period or the replacement coal is rightfully rejected, Buyer may purchase an
equivalent amount of coal from another source in order to replace the rejected
coal and Seller shall reimburse Buyer for any amount that the total delivered
cost to Buyer of such coal purchased from another source exceeds the then
current delivered cost of coal sold to Buyer under this Agreement. Seller shall
be responsible to pay or reimburse Buyer for any and all freight or
transportation expenses that have been incurred for rightfully rejected coal.
b. If Seller notifies Buyer prior to receipt of the shipment by
Buyer at the Generating Station(s) that such shipment fails to conform to the
Rejection Limits in Section 4.1, then Buyer has the option to accept or reject
such shipment. If such shipment is not accepted by Buyer it shall not be
considered as a rejection under paragraph a, or subject to the penalty set forth
in paragraph c. If Buyer chooses to accept such non-conforming coal, such
shipment will be considered as a delivery of a part of the quantity Buyer is
obligated to purchase from Seller and shall not be considered as part of the
Monthly Weighted Average specification set forth in Section 4.1, providing Buyer
and Seller have agreed to a price for such non-conforming coal. In the event
the results of the analysis of such shipment do conform to the Rejection Limits
set forth in Section 4.1, Buyer shall pay the price as established under Section
6.
9
<PAGE>
c. If Buyer unloads a shipment of non-conforming coal which it had
the right to reject for failure to meet any or all of the Rejection Limits set
forth in Section 4.1 or because such shipment contained extraneous materials or
improperly sized coal and Seller had not advised prior to unloading that such
shipment is a non-conforming shipment, then such non-conforming coal shall be
deemed accepted by Buyer; however, the price shall be adjusted in accordance
with Section 6 and the quantity Buyer is obligated to purchase from Seller, at
Buyer's sole option, shall be reduced in each calendar year by the amount of
each such non-conforming shipment. Further, for shipments containing extraneous
materials, which include, but are not limited to, slate, rock, wood, corn husks,
mining materials, etc., the estimated weight of such materials shall be deducted
from the weight of that shipment.
4.4 SUSPENSION AND TERMINATION.
a. If the coal sold hereunder fails to meet one or more of the
Monthly Average Guarantees set forth in Section 4.1 for any 3 months in a 6
month period for moisture in a 6 month period for any other specification(s), or
if 9 barge shipments in a 30 day period are rejected or rejectable by Buyer, or
if Buyer receives at Generating Station(s) 2 unapproved rail shipments which are
rejectable under Section 4.3, in any 30 day period, Buyer may upon notice
confirmed in writing, suspend future shipments except shipments already loaded
into barges and/or railcars. Seller shall, within 10 days, provide Buyer with
reasonable assurances that subsequent monthly deliveries of coal shall meet or
exceed the Monthly Average Guarantees set forth in Section 4.1. or that the
source will exceed the rejection limits set forth in Section 4.1. If Seller
fails to provide such assurances within said 10 day period, Buyer may terminate
this Agreement on 5 days notice. A waiver of this right for any one period by
Buyer shall not constitute a waiver for subsequent periods. If Seller provides
such assurances to Buyer's
10
<PAGE>
reasonable satisfaction, shipments hereunder shall resume and any tonnage
deficiencies resulting from suspension may be made up at Buyer's sole option.
Buyer shall not unreasonably withhold its acceptance of Seller's assurances, or
delay the resumption of shipment. If Seller, after such assurances, fails to
meet the Monthly Average Guarantees for moisture or BTU's due to whether for 3
months within the next 6 months or for 1 month within the next 6 months for any
other Monthly Average Guarantee or if 3 barge shipments or 1 rail shipment are
rejected or are rejectable within one month during such six month period, then
Buyer may terminate this Agreement and purchase alternative coal and recover
from Seller as damages the difference between the cost of cover and the contract
price herein, or such other entitlement to damages as may be available to Buyer
at law or in equity.
5. WEIGHTS, SAMPLING AND ANALYSIS
5.1 WEIGHTS. The weight of the coal delivered hereunder shall be
determined on a per shipment basis by Buyer on the basis of scale weights at the
Generating Station(s) unless another method is mutually agreed upon by the
parties. Such scales shall be duly certified by an appropriate testing agency
and maintained in an accurate condition. Seller shall have the right, at
Seller's expense and upon reasonable notice, to have the scales checked for
accuracy at any reasonable time or frequency. If the scales are found to be
inaccurate, over or under the tolerance range allowable for the scale, either
party shall pay to the other any amounts owed due to such inaccuracy for a
period not to exceed thirty (30) days before the time any inaccuracy of scales
is determined.
5.2 SAMPLING AND ANALYSIS. The sampling and analysis of the coal
delivered hereunder shall be performed by Buyer and the results thereof shall be
accepted and used for the quality and characteristics of the coal delivered
under this Agreement. All analyses shall be made in Buyer's
11
<PAGE>
laboratory at Buyer's expense in accordance with A.S.T.M. specifications.
Samples for analyses shall be taken by any reliable and industry accepted
standard, may be composited and shall be taken with a frequency and regularity
sufficient to provide reasonably accurate representative samples of the
deliveries made hereunder. Seller represents that it is familiar with Buyer's
sampling and analysis practices, and finds them to be acceptable. Buyer shall
notify Seller in writing of any significant changes in Buyer's sampling and
analysis practices. Any such changes in Buyer's sampling and analysis practices
shall, except for industry accepted changes in practices, provide for no less
accuracy than the sampling and analysis practices existing at the time of the
execution of this Agreement, unless the Parties otherwise mutually agree.
Each sample taken by Buyer shall be divided into 3 parts and put into
airtight containers, properly labeled and sealed. One part shall be used for
analysis by Buyer, one part shall be used by Buyer as a check sample, if Buyer
in its sole judgment determines it is necessary, and one part ("Referee Sample")
shall be retained by Buyer for a period of 45 days. Seller shall be given
timely and routine copies of all analyses made by Buyer. Seller, on reasonable
notice to Buyer shall have the right to have a representative present to observe
the sampling and analyses performed by Buyer. Unless Seller requests a Referee
Sample analysis, Buyer's analysis shall be used to determine the quality of the
coal delivered hereunder. The Monthly Weighted Averages shall be determined by
utilizing the individual shipment analyses.
If any dispute arises within 30 days of the date of sampling, the Referee
Sample retained by Buyer shall be submitted for analysis to an independent
commercial testing laboratory ("Independent Lab") mutually chosen by Buyer and
Seller. The analysis of the Independent Lab shall control to the extent
provided in this Section. A dispute shall be deemed not to exist and
12
<PAGE>
Buyer's analysis shall prevail if the analysis of a sample made by the
commercial testing laboratory differs from the analysis of Buyer by an amount
equal to or less than:
(i) 0.50% moisture or
(ii) 0.50 ash on a dry basis or
(iii) 100 Btu/lb. on a dry basis, or
(iv) 0.10% sulfur on a dry basis.
The cost of the analysis made by the Independent Lab shall be borne by
Seller if Buyer's analysis prevails and by Buyer if the analysis of the
Independent Lab prevails.
5.3 FREEZE CONDITIONING. At Buyer's request, Seller shall treat (or have
treated) any shipment of coal hereunder with a freeze conditioning agent (No.
8897, supplied by Nalco Chemical Co., or equivalent) in order to prevent
deterioration in coal quality during shipment. If requested by Buyer, Seller
shall also treat (or have treated) any rail cars specified by Buyer with a side
release conditioning agent (No. 8885, supplied by Nalco Chemical Co., or
equivalent).
The prices for such chemical treatment effective on the date of execution
of this Agreement shall be $.47 per ton of coal or $.15 per ton per application
for railcar treatment, as the case may be. Once each year beginning on
September 1, 1989, prices shall be subject to review at the request of either
party for revisions to become effective on October 1. The parties shall
negotiate in good faith to conclude agreement on price revisions, if any. In
the vent of failure to agree within ninety (90) days after commencement of
negotiations, the existing prices shall remain in effect until the next review
period. If after renewing negotiations for an additional ninety (90) days
during the ensuing review the parties are still unable to agree, then either
shall have the right to discontinue performance of freeze conditioning services.
Nothing herein shall require Buyer to contract with Seller for such
services.
Invoicing procedures shall be pursuant to Section 7.3.
13
<PAGE>
6. PRICE
6.1 PRICE. The Base Price of Coal is $.83120/MMBTU, F.O.B. rail car,
effective March 1, 1989, and continuing until December 31, 1989. Thereafter,
the Base Price shall be in accordance with the following schedule:
<TABLE>
<CAPTION>
Year Base Price, FOB Rail* Effective Date
---- --------------------- --------------
<S> <C> <C>
1990 $ .85470 January 1, 1990
1991 $ .89085 January 1, 1991
1992 $ .92410 January 1, 1992
1993 $ .96171 January 1, 1993
1994 $1.00094 January 1, 1994
1995 $1.04017 January 1, 1995
<FN>
* in $/MMBTU
</TABLE>
The Base Price is inclusive of all federal, state, municipal and local taxes,
fees and costs of any kind whether arising from government law, rule, regulation
or otherwise, including, without limitation, all costs of conforming to federal
and state mining and reclamation laws, rules and regulations as of January 1,
1991. In the event any new laws, rules, regulations or ordinances are imposed
subsequent to January 1, 1991, Buyer or Seller, as appropriate, shall compute
and document the effect of such laws, rules, regulations or ordinances on Base
Price and, if the effect is material (as hereafter defined), either party may
propose an increase or decrease as the case may be in Base Price. "Material" as
used herein shall mean increases or decreases in taxes, fees or costs totaling
more than three percent (3%) of the then current Base Price, which are
attributable to any such new laws, rules, regulations or ordinances. Any such
proposal shall be made in writing and shall include such information and data as
is reasonably necessary to substantiate the proposal. The parties shall
thereupon endeavor in good faith to reach an agreement with respect to any
revision in Base Price. If no agreement is concluded within sixty (60) days
after the date of
14
<PAGE>
receipt of any such proposal, the matter shall be submitted for resolution under
Section 14 "Disputes" of this Agreement.
The following additional conditions shall apply to any such proposal:
a. RECORDS AND AUDIT. Seller shall maintain all records relating
directly or indirectly to any proposed revision in Base Price and shall furnish
to Buyer substantiation thereof, in form and detail satisfactory to Buyer.
Buyer shall have the right at all reasonable times to audit and inspect such
records.
b. PRICE REVIEW. Buyer shall have the right of Price Review at any
time under Section 6.2 below.
6.2 PRICE REVIEW. The Base Price and Quality Price Adjustment provisions
in Section 6 of this Agreement shall be subject to review at the request of
either party, for revision(s) to become effective on January 1 of 1991 and on
every fifth anniversary date thereafter if this Agreement is renewed (e.g.,
January 1, 1996; January 1, 2001 etc.). Buyer shall also have the right of
review under this Section at any time during any Agreement Year as a result of
any proposal made by Seller under Section 6.1.
The party requesting such a review shall give written notice of its request
to the other party on or before December 1st of the year prior to the effective
dates. The notice shall describe the proposed adjustment(s) and the reasons
therefor.
For a period of ninety (90) days following receipt of such notice, Buyer
and Seller shall diligently and in good faith endeavor to reach agreement as to
reasonable revision(s) in Base Price or adjustment provisions. If the parties
do not agree within such ninety (90) day period (or any mutually agreed
extension thereof), either party may terminate this Agreement by giving at least
nine (9) months written notice to the other and the then current Base Price
shall remain in effect
15
<PAGE>
until the Agreement is terminated. If neither party gives the aforesaid nine
(9) months notice, the then current Base Price shall remain in effect until the
next price review date or the termination of this Agreement, as the case may be.
6.3 QUALITY PRICE ADJUSTMENTS. This section effective April 1, 1989. The
Base Price is based on coal having the guaranteed "as received" monthly weighted
average specifications as set forth in Section 4.1. Quality Price Adjustments
(bonuses and/or penalties) shall be made to reflect variances from the
Guaranteed Monthly Weighted Averages set forth in Section 4.1 as determined
pursuant to Section 5.2. There shall be no sulfur bonus for coal which has a
sulfur content less than 1.80 lbs/MMBTU.
<TABLE>
<CAPTION>
The penalty and bonus values used are:
PENALTY BONUS
$/MMBTU $/MMBTU
------- -------
<S> <C> <C>
BTU/LB. 0.2604 0.1354
SULFUR 0.1232 0.1084
ASH 0.0083 0.0073
MOISTURE 0.0016 0.0014
</TABLE>
These Bonus and Penalty amounts above are stated in 1988 dollars.
These Bonus and Penalty amounts shall be adjusted annually by the change in
the Producer's Price Index (PPI), and adjusted, for all Commodities, Table 3.
Effective January 1, 1990, each amount shall be revised based on the percentage
change in the PPI from November 1, 1988 through November 1, 1989 as follows:
PPI on 11/1/89 x each Bonus and Penalty Amount = Revised Bonus and Penalty
- -------------- Amount
PPI on 11/1/88 (round to 4 decimal places)
16
<PAGE>
Thereafter, on each January 1, beginning 1991, and continuing throughout the
term of this Agreement, the Bonus and Penalty amounts shall be revised based
upon the percentage change in the PPI for the 12 month period ended on November
1 of the immediately preceding year.
6.4 PAYMENT CALCULATION. Exhibit B attached hereto shows the methodology
for calculating the coal payment and adjustments to Seller for the month
Seller's coal was unloaded by Buyer. If such Adjustments result in a payment to
Buyer, Buyer shall apply credit to amounts owed Seller for the calendar month
the coal was unloaded. If such Adjustments result in a payment to the Seller,
Buyer shall pay Seller at the same time Buyer makes payment to Seller for the
coal unloaded during that calendar month.
7. INVOICES, BILLING AND PAYMENT
7.1 INVOICE PROCEDURES FOR COAL SHIPMENTS. Seller shall invoice Buyer at
the current Base Price for all coal unloaded in a calendar month by the
fifteenth of the following month.
7.2 PAYMENT PROCEDURES FOR COAL SHIPMENTS. Payment for coal unloaded in a
calendar month shall be mailed by the 20th of the month following the month of
unloading. Buyer shall mail all payments to Seller's account at Citizens
Fidelity Bank, Louisville, Kentucky.
7.3 INVOICE AND PAYMENT PROCEDURES FOR FREEZE CONDITIONING. Seller shall
invoice Buyer for freeze conditioning treatments for coal shipments or rail cars
by the 15 of the month following the month in which treatment was provided.
Buyer will make payment by the 20th of such month. Invoices shall be at the
rates established under Section 5.3 and only for treatments actually made.
7.4 WITHHOLDING. Buyer shall have the right to withhold from payment of
any billing or billings the amount of any sums which it is not able in good
faith to verify or which it otherwise in good faith disputes, such right to
withhold to continue for the duration of the dispute or inability
17
<PAGE>
to verify. Buyer shall notify Seller promptly in writing of any such issue,
stating the basis of its claim and the amount it intends to withhold, and the
parties agree to review the matter in detail within ten (10) days after Seller's
receipt of such notice. In the event the parties are not able promptly to agree
to a resolution, the matter shall be resolved under the Disputes provision of
this Agreement. In the event and to the extent that any dispute or verification
issue is resolved in Seller's favor, Seller shall add the unpaid amount to the
next invoice, plus interest at the prime rate of borrowed funds charged by
Manufacturers Hanover Bank as published in the most recently available Wall
Street Journal, for the period between the date on which the amount would
normally be paid and the actual invoice date, and Buyer shall pay such extra
amount in accordance with the procedures hereof. In the event and to the extent
that any dispute or verification issue is resolved in Buyer's favor, Seller
shall promptly issue a credit memorandum covering the amount in question.
Payment by Buyer, whether knowing or inadvertent, of any amount in dispute
shall not be deemed a waiver of any claims or rights by Buyer with respect to
any disputed amounts or payments made.
8. FORCE MAJEURE
8.1 EVENTS OF FORCE MAJEURE. Performance of the obligations of either
party hereto shall be excused to the extent prevented by an event of force
majeure. As used herein, an event of force majeure shall mean an act of God;
strike, lockout or other labor dispute; sabotage; fire; flood; war; riot or
insurrection; explosion; accident; embargo; blockade; inability to secure
supplies, fuel, power, governmental authorization or permit; breakdown of or
damage to machinery, plants or equipment; interruption or shortage of
transportation arrangements or equipment; regulation, rule, law, order, act or
restraint of any civil or military authority; or any
18
<PAGE>
other event, whether of the kind herein enumerated or otherwise, which is beyond
the control and without the fault or negligence of the party affected thereby
and which wholly or partially prevents, interrupt or delays performance
hereunder. An event is beyond the control of a party if it cannot be prevented
or eliminated by the exercise of due diligence or its prevention or elimination
would be accomplished only at an excessive or unreasonable cost.
The party claiming excuse hereunder shall give the other party prompt
notice of such event. Tonnage deficiencies resulting from an event of force
majeure shall be made up by mutual agreement on a reasonable schedule. As used
herein, the term "Seller" shall include any party mining, preparing, hauling,
loading or transporting coal to Seller for resale to Buyer under this Agreement.
8.2 ENVIRONMENTAL FORCE MAJEURE. The parties recognize that, during the
continuance of this Agreement, legislative or regulatory bodies or the courts
may adopt laws, regulations, policies and/or restrictions relating to air
pollution or otherwise which will make it impossible or commercially
impracticable for Buyer to utilize this or like kind and quality coal which
thereafter would be delivered hereunder. If as a result of the adoption of such
laws, regulations, policies, or restrictions, or change in the interpretation or
enforcement thereof, Buyer decides that it will be impossible or commercially
impracticable (uneconomical) for Buyer to utilize such coal, Buyer shall so
notify Seller, and thereupon Buyer and Seller shall promptly consider whether
corrective actions can be taken in the mining and preparation of the coal at
Seller's mine and/or in the handling and utilization of the coal at Buyer's
generating station; and if in Buyer's judgment such actions will not, without
unreasonable expense to Buyer, make it possible and commercially practicable for
Buyer to so utilize coal which thereafter would be delivered hereunder without
violating any applicable law, regulation, policy or order, Buyer shall have the
right, upon the later
19
<PAGE>
of 60 days notice to Seller or the effective date of such restriction, to
terminate this Agreement without further obligation hereunder on the part of
either party. Buyer's decisions and opinions with respect to this Section 8.2
shall be final and not subject to question or dispute by Seller.
9. CHANGES. Buyer may, at any time with Seller's mutual agreement by written
notice pursuant to Section 10 of this Agreement, make changes within the general
scope of this Agreement in any of the following: quality of coal or coal
specifications, quantity of coal, method or time of shipments, place of delivery
(including transfer or title and risk of loss), method(s) of weighing, sampling
or analysis and such other provisions as may affect the suitability and amount
of coal for Buyer's generating stations.
If any such change causes an increase or decrease in the then current Base
Price per ton of coal, or in any other provision of this Agreement, an equitable
adjustment shall be made in: Base Price, whether current or future or both,
and/or in such other provisions of this Agreement as are affected directly or
indirectly by such change, and the Agreement shall thereupon be modified in
writing accordingly.
Any claim by the Seller for adjustment under this Section shall be asserted
within thirty (30) days after the date of Seller's receipt of the written notice
of change, it being understood, however, that Seller shall not be obligated to
proceed under this Agreement as changed until an equitable adjustment has been
mutually agreed upon.
The parties agree to negotiate promptly and in good faith to agree upon the
nature and extent of any equitable adjustment. Failure to agree within one
hundred twenty (120) days after the date of assertion of any claim shall be a
dispute within the meaning of Section 14 "Disputes" of this Agreement, and the
parties shall refer the matter promptly for resolution under said Section 14.
20
<PAGE>
10. NOTICES
10.1 FORM AND PLACE OF NOTICE. Any official notice, request for approval
or other document required to be given under this Agreement shall be in writing,
unless otherwise provided herein, and shall be deemed to have been sufficiently
given if delivered in person, transmitted by telegraph, telex, or telecopier, or
dispatched in the United States mail, postage prepaid, for mailing by first
class, certified, or registered mail, return receipt requested and addressed as
follows:
If to Seller:
Shawnee Coal Company Roberts Bros. Coal Co., Inc.
4205 Hillboro Road Lafoon Trail
Nashville, TN 37215 1223
Madisonville, KY 42431
If to Buyer:
Senior Vice President - Operations
Louisville Gas and Electric Company
311 West Chestnut Street
P.O. Box 32010
Louisville, KY 40232
10.2 CHANGE OF PERSON OR ADDRESS. Either party may change the person or
address specified above upon giving notice to the other party of such change.
10.3 ELECTRONIC DATA TRANSMITTAL. Seller hereby agrees, at Seller's cost,
to electronically transmit shipping notices and/or other data to Buyer in a
format acceptable to and established by Buyer. Buyer shall provide Seller with
the appropriate format and will inform Seller as to the electronic data
requirements at the appropriate time.
11. EARLY TERMINATION. The parties recognize that, conditions not now foreseen
could arise in which either Buyer or Seller, whether for economic or other
compelling reasons, would
21
<PAGE>
desire to terminate this Agreement, in whole or in part, in advance of the
expiration date. Accordingly, it is agreed that for whatever reason, each party
shall have the right of early termination, in whole or in part, of its rights
and obligations under this Agreement, subject to the provisions of this
Agreement.
The party desiring to exercise its rights of early termination shall give
written notice thereof to the other party and pay the price for early
termination as described herein. Notice may be given by either party no later
than three (3) months before the end of any Agreement year, and this Agreement
will be terminated at the end of such year. The price paid for such early
termination shall be 10% of Base Price (not to exceed $2.00/Ton) on the
effective date of termination times the minimum tonnage remaining from the
effective date of the termination until the next price review period, as set
forth in Section 6.2.
12. RIGHT TO RESELL. Buyer shall have the unqualified right to sell all or any
of the coal purchased under this Agreement. In the event Buyer resells any or
all of the coal purchased hereunder that is not unloaded by Buyer, Seller's
weights and analyses shall be used to determine the weights, sampling and
analysis (determined in accordance with ASTM standards) of such coal resold.
13. INDEMNITY
13.1 INDEMNITY. Seller agrees to indemnify and save harmless Buyer, its
officers, directors, employees and representatives from any responsibility and
liability for any and all claims, demands, losses, legal actions for personal
injuries, property damage and pollution (including reasonable attorney's fees)
relating to the barges or railcars provided by Buyer or Buyer's contractor while
such barges or railcars are in the care and custody of the loading dock,
22
<PAGE>
or for any failure of Seller to comply with laws, regulations or ordinances, or
which arise out of the acts or omissions of Seller in the performance of this
Agreement.
13.2 INSURANCE. Seller agrees to carry insurance coverage with minimum
limits as follows:
(1) Commercial General Liability, $1,000,000 single limit liability.
(2) Automobile General Liability, $1,000,000 single limit liability
(3) In addition, Seller shall carry excess liability insurance
covering the foregoing perils in the amount of $3,000,000 for any one
occurrence.
(4) Kentucky Workers Compensation and Employer's Liability with
statutory limits.
(5) If any of the above policies are written on a claims made basis,
then the retroactive date of the policy or policies will be no later than the
effective date of Seller's original contract.
14. DISPUTES. Except as otherwise specifically provided in or permitted by
this Agreement, all disputes, differences of opinion, or controversies arising
in connection with this Agreement shall be resolved first, by the use in good
faith of mutual best efforts to arrive at an agreeable resolution. If, after
negotiating in good faith for a period of ninety (90) days, the parties are
unable to agree, then either shall have the right to terminate this Agreement by
giving ninety (90) days written notice to the other.
15. TERMINATION FOR DEFAULT. In the event of the failure of either party to
comply with any material obligation of this Agreement, either party shall have
the right to terminate this Agreement at any time by giving to the other 120
days' notice in writing of its intention to do so, specifying the default
complained of. At the expiration of said 120 days, unless the party in
23
<PAGE>
default shall have made good such default, the party not in default shall have
the right at its election to terminate this Agreement forthwith.
This right shall be in addition to the rights provided to either party in
other portions of this Agreement and by law, or in equity.
16. CONSTRUCTION OF AGREEMENT
16.1 APPLICABLE LAW. This Agreement shall be construed in accordance with
the laws of the State of Kentucky, and all questions of performance of
obligations hereunder shall be determined in accordance with such laws.
16.2 HEADINGS. The paragraph headings appearing in this Agreement are for
convenience only and shall not affect the meaning or interpretation of the
Agreement.
16.3 WAIVER. The failure of either party to insist on strict performance
of any provision of this Agreement, or to take advantage of any rights
hereunder, shall not be construed as a waiver of such provision or right.
16.4 REMEDIES CUMULATIVE. Remedies provided under this Agreement shall be
cumulative and in addition to other remedies provided by law.
16.5 SEVERABILITY. If any provision of this Agreement is found contrary to
law or unenforceable by any court of law, the remaining provisions shall be
severable and enforceable in accordance with their terms, unless such unlawful
or unenforceable provision is material to the transactions contemplated hereby,
in which case the parties shall negotiate in good faith a substitute provision.
16.6 BINDING EFFECT. This Agreement shall bind and inure to the benefit of
the parties and their successors and assigns.
24
<PAGE>
16.7 ASSIGNMENT. Neither party may assign this Agreement or any rights or
obligations hereunder without the prior written consent of the other party,
which consent shall not be unreasonably withheld or denied; provided, however,
that Buyer shall have the right, without consent of Seller, to assign all or any
part of this Agreement to any company, controlling, controlled by, or under
common control with Buyer.
16.8 ENTIRE AGREEMENT.. This instrument contains the entire Agreement
between the parties as to coal produced and sold from the Coal Property, and
there are no representations, understandings or agreements, oral or written,
which are not included herein.
16.9 AMENDMENTS. Except as otherwise provided herein, this Agreement may
not be amended, supplemented or otherwise modified except by written instrument
signed by parties hereto.
17. AGENCY RELATIONSHIP; SELLER'S LIABILITY
17.1 AGENCY. The relationship between Roberts Bros Coal Co. Inc. and
Shawnee Coal Company, Inc. is that of principal and agent. Any action by
Shawnee Coal Company, Inc. under this Agreement shall be binding on Roberts
Bros. Coal Co. Inc. and vice versa and both Shawnee Coal Company, Inc. and
Roberts Bros. Coal Co. Inc. hereby indemnify and hold Buyer harmless from and
against any and all claims, losses, actions, damages or costs of whatever nature
arising out of or resulting from the agency relationship.
17.2 JOINT AND SEVERAL LIABILITY. The obligations and liabilities of
Seller under this Agreement shall be the joint and several obligations and
liabilities of Roberts Bros. Coal Co. Inc. and Shawnee Coal Company, Inc.
25
<PAGE>
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
executed as of the date first above written.
BUYER:
______________________________ By: _______________________________
Attest
Title: ____________________________
SELLER:
______________________________ By: _______________________________
Attest
Title: ____________________________
SELLER:
______________________________ By: _______________________________
Attest
Title: ____________________________
26
<PAGE>
LEGEND
1. #4 Coal Mason Property 91.8274 AC
Ht. Coal 48" 661,157.28 Tons
2. #8 Coal Mason Property 1,604.2241 AC
Ht. Coal 24" 4,775,206.76 Tons
3. #4 Coal White Plains 56.9330 AC
Ht. Coal 30" 256,198.50 Tons
4. #9 Coal Highway 70 Miracle 11.1843 AC
Coal Ht. 60" 100,658.70 Tons
5. #11 Coal Warrior 3,133.1497 AC
Coal Ht. 66" 31,018,182.03 Tons
6. #9 Coal Warrior 5,178.1451 AC
Coal Ht. 60" 46,603.305.90 Tons
7. #4 Coal Donaldson Creek 509.6419 AC
Coal Ht. 48" 3,669,421.88 Tons
8. #14 Coal T&N Powell 96.6639 AC
Coal Ht. 108" 1,565,955.18 Tons
9. #6 Coal Diamond 1,629.00 AC
Coal Ht. 40" 9,774,000.00 Tons
10. Christian Strip 2,445,200.70 Tons
#13 Coal
#12 Coal (From Donan Reserve Study) 4,087,571.10 Tons
#11 Coal 7,155,174.60 Tons
11. #9 Coal Christian 112.0321 AC
Coal Ht. 60" 1,008,288.90 Tons
12. Charleston Washer Truck and Rail Loading Facility
14. #9 Miracle 77.78 AC
Coal Ht. 60" 700,000.00 Tons
MINES IN PRODUCTION
STRIP RESERVES
UNDERGROUND RESERVES
<PAGE>
TOTAL EVALUATED COAL COSTS FOR P.O. OR CONTRACT NO.:
SECTION I. Base Data
<TABLE>
<CAPTION>
<S> <C> <C>
1) Enter Base F.O.B. price per ton ($/ton) [1] $_______/ton
1a) Enter tons of coal delivered [1a] $_______/tons
2) Enter guaranteed average heat content (BTU/lb) [2] $_______ BTU/LB
2r) Enter as received monthly average heat content (BTU/lb) [2r] $_______ BTU/LB
2a) Enter Energy delivered (in MMBTU), [ (Line 1a) * 2,000 lb/ton * (Line 2r)]*
MMBTU/1,000,000 BTU [ ( ) * 2,000 * ( ) ]/1,000,000 + [2a] $_______ MMBTU
2b) Enter Base F.O.B. price per MMBTU, { [(Line 1) / (Line 2)] * (1 ton/2,000 lb) }
* (1,000,000 BTU/MMBTU) { [ ( ) / ( ) ] / 2,000 } * 1,000,000 = [2b] $_______ MMBTU
3) Enter guaranteed monthly average maximum sulfur [3] $_______ LBS/MMBTU
3r) Enter as received monthly average sulfur [3r] $_______ LBS/MMBTU
4) Enter guaranteed monthly average maximum ash [4] $_______ LBS/MMBTU
4r) Enter as received monthly average ash [4r] $_______ LBS/MMBTU
5) Enter guaranteed monthly average maximum moisture [5] $_______ LBS/MMBTU
5r) Enter as received monthly average moisture [5r] $_______ LBS/MMBTU
</TABLE>
SECTION II. Penalties and Bonuses
Use the appropriate lines under either the Penalty or Bonus section according to
the value of 2r, 3r, 4r and 5r.
<TABLE>
<CAPTION>
- - $/MMBTU
PENALTIES Assign a (-) to all penalties (round to 5 decimal places).
<S> <C> <C>
6p) BTU/LB: If Line 2r is less than Line 2, { 1 - [ ( Line 2r ) / ( Line 2 ) ] } *
$0.2604 / MMBTU { 1 - [ ( ) / ( ) ] } * $0.2604 = [6p] $_______ /MMBTU
7p) Sulfur: If Line 3r is greater than Line 3, [(Line 3r)-(Line 3)] * $0.1232/lb [7p]
sulfur [ ( ) - ( ) ] * 0.1232 = $_______ /MMBTU
8p) Ash: If Line 4r is greater than Line 4, [ (Line 4r) - (Line 4 ] * $0.0083/lb ash
[ ( ) - ( ) ] * $0.0083 = [8p] $_______ /MMBTU
9p) Moisture: I*f Line 5r is greater than Line 5, [ (Line 5r) - (Line 5) ] * $0.0016/lb
moisture [ ( ) - ( ) ] * $0.0016 = [9p] $_______ /MMBTU
BONUSES Assign a (+) to all Bonuses (round to 5 decimal places).
6b) BTU/LB: If Line 2r is greater than Line 2, { [ (Line 2r) / (Line 2) ] - 1 } * \
$0.1354/MMBTU { [ ( ) / ( ) ] - 1} * $0.1354 = [6b] $_______ /MMBTU
7b) Sulfur: If Line 3r is between Line 3 and 1.8 lb/MMBTU, [ (Line 3) - (Line 3r) ] *
$0.1084/lb sulfur (NO BONUS IF LINE 3R IS LESS THAN 1.8)
[ ( ) - ( ) ] * $0.1084 = [7b] $_______ /MMBTU
8b) Ash: If Line 4r is less than Line 4, [ (Line 4) - (Line 4r) ] * $0.0073/lb ash
[ ( ) - ( ) ] * $0.0073 = [8b] $_______ /MMBTU
<PAGE>
9b) Moisture: If Line 5r is less than Line 5, [ (Line 5) - (Line 5r) * $0.0014/lb ]
moisture [ ( ) - ( ) ] * $0.0014 = [9b] $_______ /MMBTU
Determine total Penalty/Bonus adjustment as follows:
Assign a (-) to all Penalties and a (+) to all Bonuses
and enter the number for:
Line 6p or 6b $_______ /MMBTU
Line 7p or 7b $_______ /MMBTU
Line 8p or 8b $_______ /MMBTU
Line 9p or 9b $_______ /MMBTU
10) Total Penalties and/or Bonuses (+/-) ( ) + ( ) + ( ) + ( ) = $_______ /MMBTU
(algebraic summation of the above)
11) Total evaluated coal price = (Line 2b) + (Line 10)
( ) + ( ) = $_______ /MMBTU
12) Total premium/penalties price adjustment for Energy delivered: (Line 2a) * (Line 10) (+/-)
( ) * ( ) = $_______
13) Total base cost of coal (Line 2a) * (Line 2b)
( ) * ( ) = $_______
14) Total coal payment for month (Line 12) + (Line 13)
( ) + ( ) = $_______
(algebraic sum)
</TABLE>
<PAGE>
COAL SUPPLY AGREEMENT
Amendment No. 1
EXHIBIT 10.42
COAL SUPPLY AGREEMENT
THIS AMENDMENT IS entered into, effective as of January 1, 1991, by
and between Louisville Gas and Electric Company (hereinafter referred to
as Buyer), whose address is: 820 W. Broadway, Louisville, Kentucky 40232
and Shawnee Coal Company (herein referred to as "Seller"), whose address
is: 4205 Hillsboro Road, Nashville, Tennessee 73215, and Roberts Bros.
Coal Company (herein referred to as "Seller"), whose address is: Lafoon
Trail, P.O. Box 1223, Madisonville, Kentucky 42431. In consideration of
the agreements herein contained, the parties hereto agree as follows:
1. AMENDMENTS
The Coal Supply Agreement heretofore entered into by the parties,
dated effective August 9, 1989, (hereinafter referred to as "Coal Supply
Agreement"), is hereby amended as follows:
1.1 Article 2.2 set forth to this Coal Supply Agreement is amended
to add the following:
"As of August 31, 1990, a balance of 209,473.50 tons (189,000.00
prescheduled and 20,473.50 deficiency) remained to be delivered
during the 1990 contract year at the 1990 contract base price
($0.85470/MMBTU). Seller shall use its best efforts and full
abilities to insure the delivery of the prescheduled and
deficient tonnage prior to December 31, 1990. However, in the
event the 20,473.50 tons of deficient coal is scheduled by
Buyer, and for reasons other than those which are excusable
under Section 8. FORCE MAJEURE, Seller is unable to meet the
delivery requirements of the contract as amended hereunder by
December 31, 1990, Seller shall delivery the remaining deficient
tonnage during the 1991 Contract year at the 1990 contract
price. The first tonnage delivered by Seller during the 1991
contract year shall be deemed to be the deficient tonnage and
shall be in addition to the contract tonnage requirements for
the 1991 contract year."
1.2 Article 2.3 set forth to this Coal Supply Agreement is amended
to add the following:
"Buyer shall have the option of the first right of refusal to
purchase up to an additional 500,000 tons, if available, per
year for 1991 through 1995 and for any additional renewal
extensions thereafter if exercised by Buyer. Seller shall
notify Buyer in writing whenever additional coal is available.
Buyer must notify Seller, within 30 (thirty) calendar days from
date Seller offers the additional tonnage, of its interest in
exercising this option. After Buyer's notification of interest,
Buyer and Seller shall negotiate in good faith for 30 days to
reach a mutual agreement for the supply of such tonnage. If
Buyer rejects Seller's offer, or the parties are otherwise
unable to reach agreement on price, quality, or other terms and
conditions within the periods indicated above (60 calendar days
from the date of Seller's of first notice), Seller shall have
the right to place the coal on the market for purchase by other
buyers at the price, quality and other terms and conditions
Seller may deemed favorable."
1.3 The Coal Supply Agreement is amended to add the following:
"Section 18 CONFIDENTIAL INFORMATION. Specifications, annual
quantities, pricing and other information obtained by Seller
from Buyer in connection with this Coal Supply Agreement shall
be held in confidence by Seller and shall not be used by Seller
for any purpose other than for the supply of coal or as
authorized in writing by Buyer."
2. PRICING SUMMARY
2.1 The Base Price set forth in the Coal Supply Agreement is hereby
changed as follows to Seller for full and complete performance
by Seller of this Amendment in full compliance with all terms
and conditions of the Coal Supply Agreement:
<TABLE>
<CAPTION>
2.1.1 Original Base Net Adjustment New Total
Price F.O.B. Pursuant to This Base Price Effective
Year Rail Amendment F.O.B. Rail Date
---- ------------- ---------------- ----------- ---------
<S> <C> <C> <C> <C>
1990 $0.85470 $___________ $0.85470 January 1, 1990
<PAGE>
COAL SUPPLY AGREEMENT
Amendment No. 1
1991 $0.89085 $0.01282 $0.90367 January 1, 1991
1992 $0.92410 $0.01282 $0.93692 January 1, 1992
1993 $0.96171 $0.01282 $0.97453 January 1, 1993
1994 $1.00094 $0.01282 $1.01376 January 1, 1994
1995 $1.04017 $0.01282 $1.05299 January 1, 1995
<FN>
*All Prices in $/MMBTU
</TABLE>
3. STATUS OF COAL SUPPLY AGREEMENT
As amended herein, the Coal Supply Agreement shall continue in full
force and effect.
IN WITNESS WHEREOF, the parties hereto have executed this Amendment
on the day and year below written, but effective as of the day and year
first set forth above.
Shawnee Coal Company Louisville Gas and Electric Company
By: ___________________________ By:_________________________________
Title: __________________________ Title:______________________________
Date: ___________ Date: _____________
Roberts Bros. Coal Co., Inc.
By: ___________________________
Title: __________________________
Date: ___________
2
<PAGE>
Shawnee Coal Company
Coal Supply Agreement
Amendment No. 2
EXHIBIT 10.43
AMENDMENT TO CONTRACT
THIS AMENDMENT IS entered into, effective as of November 27, 1991, by and
between Louisville Gas and Electric Company (hereinafter referred to as
"Buyer"), whose address is: 220 W. Main St., Louisville, Kentucky 40232 and
Shawnee Coal Company (herein referred to as "Seller"), whose address is: 4205
Hillsboro Road, Nashville, Tennessee 37215 and Roberts Bros. Coal Company (also
hereinafter referred to as "Seller") whose address is: LaFoon Trail, P.O. Box
1223, Madisonville, Kentucky 42431. In consideration of the agreements herein
contained, the parties hereto agree as follows:
1. AMENDMENTS
The Coal Supply Agreement heretofore entered into by the parties, dated
effective August 9, 1989 and identified by the Contract Number set forth above,
as previously amended by Amendment Number 1 thereto, (hereinafter referred to as
"Agreement"), is hereby further amended as follows:
1.1 Article 2.1 ANNUAL QUANTITY set forth in this Agreement is amended as
follows:
"2.1 ANNUAL QUANTITY. This section effective January 1, 1989.
Except as adjusted under Section 2.3, Seller shall sell and deliver
and buyer shall purchase and accept delivery of the following annual
tonnages ("Annual Quantity").
<TABLE>
<CAPTION>
Additional Coal This
Year This Amendment Quantity (Tons)
---- -------------- ---------------
<S> <C> <C>
1989 ________ 364,000
1990 ________ 364,000
1991 98,000 700,000
1992 400,000 + (20% exiting 1,300,000
base 750,000)
1993 ________ 1,125,000
1994 ________ 1,125,000
1995 ________ 1,125,000
</TABLE>
1.2 Article 2.3 NOTIFICATION set forth in this Agreement is amended to
read as follows:
"2.3 NOTIFICATION. By December 1 of each Agreement year, Buyer shall
specify by written notice to Seller the monthly quantities to be
delivered in the following Agreement year. For 1993 and following
years, upon 6 months notice to Seller, Buyer may change the quantity
to be delivered under this Section within a range of +20% of specified
-
annual tonnage, except that in no event shall Buyer specify less than
900,000 tons.
2. PRICING SUMMARY
2.1 The Base Price set forth in the Coal Supply Agreement is hereby
changed as follows as full compensation to Seller for full and
complete performance by Seller of this Amendment in full compliance
with all terms and conditions of the Coal Supply Agreement:
<PAGE>
Shawnee Coal Company
Coal Supply Agreement
Amendment No. 2
<TABLE>
<CAPTION>
Original Base Net Adjustment Net Adjustment New Total
Price F.O.B. Pursuant to Prior Pursuant to Pursuant to
Year Rail Amendment This Amendment This Amendment
---- -------------- ---------------- -------------- --------------
<S> <C> <C> <C> <C>
1990 $0.85470 $________ $________ $0.85470
1991 $0.89085 $0.01282 $________ $0.90367
1992 $0.92410 $0.01282 ($0.00427) $0.93265
1993 $0.96171 $0.01282 ($0.00427) $0.97026
1994 $1.00094 $0.01282 ($0.00427) $1.00949
1995 $1.04017 $0.01282 ($0.00427) $1.04872
<FN>
* All Prices in $/MMBTU
</TABLE>
3. STATUS OF AGREEMENT
As amended herein, the Agreement shall continue in full force and effect.
IN WITNESS WHEREOF, the parties hereto have executed this Amendment on the
day and year below written, but effective as of the day and year first set forth
above.
Shawnee Coal Company Louisville Gas and Electric Company
By: ___________________________ By: _________________________________
Title: __________________________ Title: ________________________________
Date: ___________ Date: _____________
Roberts Bros. Coal Co., Inc.
By: ___________________________
Title: __________________________
Date: ___________
2
<PAGE>
Shawnee Coal Company
Coal Supply Agreement
Amendment No. 3
EXHIBIT 10.44
AMENDMENT
THIS AMENDMENT IS entered into, effective as of January 1, 1994, by
and between Louisville Gas & Electric Company (hereinafter referred to as
"Buyer"), whose address is: 220 W. Main Street, Louisville, Kentucky
40232 and Shawnee Coal Company (herein referred to as "Seller"), whose
address is: 4205 Hillsboro Road, Nashville, Tennessee 37215 and Roberts
Bros. Coal Company (also hereinafter referred to as "Seller"). Whose
address is: LaFoon Trail, P.O. Box 1223, Madisonville, Kentucky 42431.
In consideration of the agreements herein contained, the parties hereto
agree as follows:
1. AMENDMENTS
The Coal Supply Agreement heretofore entered into by the parties,
dated effective August 9, 1989 and identified as Coal Supply Agreement set
forth above, as previously amended by Amendment Numbers 1 and 2 thereto,
(hereinafter referred to as "Agreement"), is hereby further amended as
follows:
1.1 Article 1.1 TERM set forth in this agreement to the Contract is
amended in its entirety as follows:
"1.1 TERM. Except for specific effective dates described in
specific sections herein, the term of this Agreement shall
commence on March 1, 1989 and shall continue until and including
December 31, 1996. Buyer shall have right, but not the
obligation, to renew this Agreement for up to three (3)
additional five (5) year periods, such right to be exercised by
notice in writing to Seller no later than sixty (60) days prior
to the end of the existing period. The Base Price upon any such
renewal shall be agreed upon by the parties subject to the
provisions of 6.2."
1.2 Article 2.1 ANNUAL QUANTITY set forth in this Agreement is
amended as follows:
"2.1 ANNUAL QUANTITY. This section effective January 1, 1989.
Except as adjusted under Section 2.3, Seller shall sell and
deliver and Buyer shall purchase and accept delivery of the
following annual tonnages ("Annual Quantity").
<TABLE>
<CAPTION>
Additional Coal This
Year This Amendment Quantity (Tons)
---- -------------------- ---------------
<S> <C> <C>
1989 ________ 364,000
1990 ________ 364,000
1991 ________ 700,000
1992 ________ 1,300,000
1993 ________ 1,125,000
1994 90,000 1,215,000
1995 90,000 1,215,000
1996 1,215,000 1,215,000
</TABLE>
1.3 Article 2.3 NOTIFICATION set forth in this Agreement is amended
to read as follows:
"2.3 NOTIFICATION. By December 1 of each Agreement year, Buyer
shall specify by written notice to Seller the monthly quantities
to be delivered in the following Agreement year. Buyer shall
provide Seller with at least 30 days notice prior to the
beginning of each quarter concerning the quantity of optional
tonnage coal that the buyer elects to purchase during the
upcoming quarter. For 1994 and following years, Seller will
supply up to 300,000 additional tons of coal per year if
requested by Buyer. Not more than 150,000 tons of additional
coal is to be supplied in any two consecutive quarters and
Seller is not required to supply more than 150,000 tons
(optional plus base) of additional coal in any given month.
<PAGE>
SHAWNEE COAL COMPANY
COAL SUPPLY AGREEMENT
AMENDMENT NO. 3
1.4 Article 6.2 PRICE REVIEW set forth in this Agreement is amended
in its entirety as follows:
"6.2 PRICE REVIEW. If Buyer exercises its right to renew this
Agreement by giving notice under Article 1.1 hereof, then the
Base Price and Quality Price adjustment provisions in Section 6
of this Agreement shall be subject to review at the request of
either party, for revision(s) to become effective for the
renewal term. Buyer shall also have the right of review under
this Section at any time during any Agreement Year as a result
of any proposal made by Seller under 6.1.
The party requesting such a review shall give written notice of
its request to the other party within 30 days from the date of
Buyer's notice to renew this Agreement. The notice shall
describe the proposed adjustment(s) and the reasons therefor.
For a period of ninety (90) days following receipt of such
notice, Buyer and Seller shall diligently and in good faith
endeavor to reach agreement as to reasonable revision(s) in Base
Price or adjustment provisions. If the parties do not agree
within such ninety (90) day period (or any mutually agreed
extension thereof), either party may terminate this Agreement by
giving at least nine (90) months written notice to the other and
the then current Base Price, quantity, and all other terms and
conditions hereof shall remain in effect until the Agreement is
terminated. If neither party gives the aforesaid nine (90)
months notice, the then current Base Price, quantity, and all
other terms and conditions hereof shall remain in effect until
the next price review date or the termination of this Agreement,
as the case may be."
1.5 Article 6.3 QUALITY PRICE ADJUSTMENTS set forth in this Agree
is amended to add the following at the end:
"6.3 QUALITY PRICE ADJUSTMENTS. Notwithstanding the above, the
Bonus and Penalty amounts shall escalate one additional time
scheduled to take effect 1/1/94, then will remain fixed for the
duration of Contract."
1.6 Article 18 SHAWNEE TERMINATION is added at the end of the
Agreement as follows:
"18 SHAWNEE TERMINATION Notwithstanding any other provision in
this Agreement, with respect to Shawnee Coal Company, Inc. only,
this Agreement will terminate on December 31, 1995. Such
termination will not relieve Shawnee Coal Company, Inc. of any
of its liabilities or obligations to Buyer which accrue
hereunder by December 31, 1995. This Agreement will continue in
full force and effect between Roberts Bros. Coal Company, Inc.
and Buyer through the entire term of this Agreement and any
renewal terms as set forth herein".
2. PRICE SUMMARY
2.1 The Base Price set forth in the Coal Supply Agreement is hereby
changed as follows as full compensation to Seller for full and
complete performance by Seller of this Amendment in full
compliance with all terms and conditions of the Coal Supply
Agreement:
<TABLE>
<CAPTION>
Original Base Net Adjustment Net Adjustment Net Adjustment Few Total Price for
Price F.O.B. Pursuant to Pursuant to Pursuant to Base Price Optional
Year Rail Amendment 1 Amendment 2 Amendment 3 F.O.B. Rail Tonnage
---- ------------- -------------- -------------- -------------- ----------- ---------
<S> <C> <C> <C> <C> <C> <C>
1990 $0.85470 $________ $________ $________ $________ $________
1991 $0.89085 $________ $________ $________ $________ $________
1992 $0.92410 $________ $________ $________ $________ $________
1993 $0.96171 $________ $________ $________ $________ $________
1994 $1.00094 $0.01282 ($0.00427) ($0.00427) $1.00522 $0.96676
1995 $1.04017 $0.01282 ($0.00427) ($0.00427) $1.04445 $1.00599
</TABLE>
2
<PAGE>
Shawnee Coal Company
Coal Supply Agreement
Amendment No. 3
<TABLE>
<S> <C> <C> <C> <C> <C> <C>
1996 $________ $________ $________ $________ $1.08518 $1.04672
<FN>
*All Prices in $/MMBTU
</TABLE>
Any additional tonnage as described in Article 2.3
NOTIFICATION -- shall be .90 cents per ton ($0.03846/MMBTU)
less than established price for that year.
3. STATUS OF AGREEMENT
As amended herein, the Agreement shall continue in full force and
effect.
IN WITNESS WHEREOF, the parties hereto have executed this Amendment
on the day and year below written, but effective as of the day and year
first set forth above.
Shawnee Coal Company Louisville Gas and Electric
Company
By: ___________________________ By:_________________________________
Title: __________________________ Title:______________________________
Date: ___________ Date: _____________
Roberts Bros. Coal Co., Inc.
By: ___________________________
Title: __________________________
Date: ___________
3
<PAGE>
Amendment 4
Page 1 of 11
EXHIBIT 10.45
AMENDMENT TO CONTRACT
THIS AMENDMENT is entered into, effective as of January 1, 1995, by and
between Louisville Gas and Electric Company (hereinafter referred to as
"Buyer"), whose address is: 220 W. Main Street, Louisville, Kentucky 40202 and
Shawnee Coal Company (hereinafter referred to as "Seller"), whose address is:
4205 Hillsboro Road, Nashville, Tennessee 37215 and Roberts Bros. Coal Co., Inc.
(also hereinafter referred to as "Seller") whose address is: 1690 Columbia
School House Road, P.O. Box 1223, Madisonville, Kentucky 42431. In
consideration of the agreements herein contained, the parties hereto agree as
follows:
1.0 RELEASE OF 1994 EARLY TERMINATION RIGHTS
Buyer agrees not to exercise its right to terminate the Agreement as of
December 31, 1994 under Section 11 of the Coal Supply Agreement heretofore
entered into by the parties, dated August 9, 1989, as amended by Amendment Nos.
1, 2 and 3 thereto (hereinafter referred to as the "Agreement").
2.0 AMENDMENTS
The Agreement is hereby further amended as follows:
2.1 Section 1.1 TERM set forth in the Agreement is amended to read in
its entirety as follows:
"1.1 TERM. Except for specific effective dates described in
specific sections herein, the term of this Agreement shall commence on
March 1, 1989 and shall continue until and including December 31,
1996. Prior to October 1, 1996, Buyer and Seller each shall have the
right to propose to the other in writing an extension of the term of
this Agreement or the parties' entry into a new coal supply agreement.
In such case, the parties will negotiate all the terms and conditions
(including, but not limited to, price and quantity) of such extension
or new agreement. If the parties do not reach an agreement in writing
prior to the end of the term of this Agreement, then this Agreement
automatically shall terminate on December 31, 1996. Neither party
will have any obligation to enter into any such extension or new
agreement.
2.2 Article 2.1 ANNUAL QUANTITY set forth in the Agreement is amended
to read in its entirety as follows:
<PAGE>
Amendment 4
Page 2 of 11
"2.1 ANNUAL QUANTITY. Except as adjusted under Section 2.3,
Seller shall sell and deliver and Buyer shall purchase and accept
delivery of the following annual tonnages ("Annual Quantity").
<PAGE>
Amendment 4
Page 3 of 11
Year Reduction in Coal This Amendment Annual Quantity (Tons)
- ---- -------------------------------- ----------------------
1989 ___________ 364,000
1990 ___________ 364,000
1991 ___________ 700,000
1992 ___________ 1,300,000
1993 ___________ 1,125,000
1994 ___________ 1,215,000
1995 115,000 1,100,000
1996 215,000 1,000,000
2.3 Section 2.3 NOTIFICATION is amended to read in its entirety
as follows:
"2.3 NOTIFICATION. By December 1 of each Agreement year,
Buyer shall specify by written notice to Seller the monthly
quantities to be delivered in the following Agreement year."
2.4 Section 4.1 QUALITY set forth in the Agreement is amended to
read in its entirety as follows:
"4.1 QUALITY. The coal delivered hereunder shall conform to
the following specifications on an "as received" basis.
Guaranteed Monthly Rejection Limits
Specification Weighted Average (per shipment)
- --------------------------------------------------------------------------------
BTU/lb. min. 11,500 < 10,850
Moisture max. 8.25 lbs./MMBtu > 12.00 lbs./MMbtu
Ash max. 10.80 lbs./MMBtu > 13.00 lbs./MMbtu
Sulfur max. 2.90 lbs./MMBtu > 3.30 lbs./MMBtu
< 1.80 lbs./MMBtu
Chlorine max. 0.20 lbs./MMBtu > 0.20 lbs./MMBtu
Flourine max. 0.006 lbs./MMBtu > 0.010 lbs./MMBtu
Nitrogen max. 1.20 lbs./MMBtu > 1.50 lbs./MMBtu
Ash/Sulfur Ratio min. 2.6:1 < 2.5:1
Size: (3" x 0"):
Top size (inches)* max. 3" > 3"
Fines (% by wgt)
passing 1/4 inch
screen max. 40% > 45%
<PAGE>
Amendment 4
Page 4 of 11
% by Weight:
Volatile max. 38 > 38
Volatile min. 29 < 29
Fixed Carbon max. 50 > 50
Fixed Carbon min. 30 < 40
Grindability (HGI) min. 55 < 50
Slagging Factor** max. 2 > 2.0
Fouling Factor*** max. 1 > 1.0
ASH FUSION TEMPERATURE (DEG. F) (ASTM D1857)
REDUCING ATMOSPHERE
Initial Deformation min. 2000 min. 1940
Softening (H=W) min. 2100 min. 2035
Softening (H=1/2 W) min. 2200 min. 2085
Fluid min. 2300 min. 2190
OXIDIZING ATMOSPHERE
Initial Deformation min. 2350 min. 2300
Softening (H=W) min. 2400 min. 2330
Softening (H=1/2 W) min. 2500 min. 2425
Fluid min. 2525 min. 2490
* All the coal will be of such size that it will pass through a screen having
circular perforations three (3) inches in diameter, but shall not contain
more than forty per cent (40%) by weight of coal that will pass through a
screen having circular perforations one-quarter (1/4) of an inch in
diameter.
** Slagging Factor (Rs)=(B/A) x (Percent Sulfur by WeightDry)
*** Fouling Factor (Rf)=(B/A) x (Percent Na2O by Weight Dry)
The Base Acid Ration (B/A) is herein defined as:
BASE ACID RATIO (B/A) = (Fe2O3 + CaO + MgO + Na2O + K2O
------------------------------
(SiO2 + Al2O3 + T102)
Note: As used herein > means greater than;
< means less than.
<PAGE>
Amendment 4
Page 5 of 11
2.5 Section 5.3 FREEZE CONDITIONING set forth in the Agreement is
amended to read in its entirety as follows:
"5.3 FREEZE CONDITIONING. At Buyer's request, Seller shall treat
(or have treated) any shipment of coal hereunder with a freeze
conditioning agent approved by Buyer in order to maintain coal
handling characteristics during shipment. If requested by Buyer,
Seller shall also treat (or have treated) any rail cars specified by
Buyer with side release agent approved by Buyer. The price for each
such requested chemical treatment shall be an amount equal to Seller's
cost of materials applied on a per gallon basis for each application
of freeze conditioning agent or side release agent, as the case may
be. Seller shall invoice Buyer for all such treatment which occurred
in a calendar month by the fifteenth of the following month; and
payment shall be mailed by the 20th of such following month or within
five days after receipt of Seller's invoice, whichever is later.
2.6 Section 6.1 PRICE set forth in the Agreement is amended to read
in its entirety as follows:
"6.1 PRICE.
(a) Subject to subsection 6.1(b), the base price ("Base Price")
of the coal to be sold hereunder will be firm and will be $.97000 per
MMBTU.
(b) Notwithstanding the provisions of subsection 6.1(a) above,
the Base Price shall not include any MMBTUs to the extent that the
actual Monthly Weighted Average for BTU/LB exceeds 11,750. For
example, if the Monthly Weighted Average BTU/LB is 11,800 and 100,000
tons of coal were unloaded that month, then the Base Price would be
$2,279,500 (100,000 tons X 2,000 lbs/ton X 11,750 BTU/lb X
$.97/MMBTU).
2.7 Section 6.2 PRICE REVIEW set forth in the Agreement is deleted in
its entirety.
2.8 Section 6.3 QUALITY PRICE ADJUSTMENTS set forth in the Agreement
is amended to read in its entirety as follows:
"6.3 QUALITY PRICE DISCOUNTS. The Base Price is based on coal
meeting or exceeding the Guaranteed Monthly Weighted Average
specifications as set forth in Section 4.1. Quality price discounts
shall be applied for each specification each month to reflect
failures to meet the Guaranteed Monthly Weighted Averages set forth in
Section 4.1 as determined pursuant to Section 5.2, subject to the
provisions set forth below. The discount values used are:
<PAGE>
Amendment 4
Page 6 of 11
DISCOUNT
$/MMBTU
--------
BTU/LB. 0.2604
DISCOUNT
$/LB./MMBTU
-----------
SULFUR 0.1232
ASH 0.0083
MOISTURE 0.0016
Notwithstanding the foregoing, for each specification each month,
there shall be no discount if the actual Monthly Weighted Average
meets the applicable minimum or maximum set forth below. However, if
the actual Monthly Weighted Average fails to meet such applicable
minimum or maximum, then the discount shall apply and shall be
calculated based upon the difference between the actual Monthly
Weighted Average AND THE GUARANTEED MONTHLY WEIGHTED AVERAGE as shown
on Exhibit B attached hereto.
MINIMUM
-------
BTU/LB 11,250
MAXIMUM
--------
LB/MMBTU
SULFUR 3.10
ASH 12.20
MOISTURE 9.56
2.9 Section 6.4 PAYMENT CALCULATION set forth in the Agreement is
amended to read in its entirety as follows:
"6.4 PAYMENT CALCULATION. Exhibit B SAMPLE COAL PAYMENT
CALCULATIONS attached hereto shows the methodology for calculating the
coal payment and quality price discounts for the month Seller's coal
was unloaded by Buyer. If there are any such discounts, Buyer shall
apply credit to amounts owed Seller for the month the coal was
unloaded.
2.10 Section 8.1 FORCE MAJEURE set forth in the Agreement is amended
to read in its entirety as follows:
"8.1 FORCE MAJEURE. If either party hereto is delayed in or
prevented from performing any of its obligations or from utilizing the
coal sold under this
<PAGE>
Amendment 4
Page 7 of 11
Agreement due to acts of God, war, riots, civil insurrection ,acts of
the public enemy, strikes, lockouts, fires, floods or earthquakes, or
other similar occurrences, which are beyond the reasonable control and
without the fault or negligence of the party affected thereby,
notwithstanding their foreseeability, then the obligations of both
parties hereto shall be suspended to the extent made necessary by such
event; provided that the affected party gives written notice to the
other party as early as practicable of the nature and probable
duration of the force majeure event. The party declaring force
majeure shall exercise due diligence to avoid and shorten the force
majeure event and will keep the other party advised as to the
continuance of the force majeure event. During any period in which
Seller's ability to perform hereunder is affected by a force majeure
event, Seller shall not deliver any coal to any other buyers to whom
Seller's ability to supply is similarly affected by such force
majeure event unless contractually committed to do so at the beginning
of the force majeure event; and further shall deliver to Buyer under
this Agreement at least a pro rata portion (on a per ton basis) of its
total contractual commitments to all its buyers to whom Seller's
ability to supply is similarly affected by such force majeure event in
place at the beginning of the force majeure event. An event which
affects the Seller's ability to produce or obtain coal from a mine
other than the Coal Property will not be considered a force majeure
event hereunder.
Tonnage deficiencies resulting from a force majeure event shall
be made up at Buyer's sole option on a reasonable schedule.
2.11 Section 9 CHANGES set forth in the Agreement is amended in part
so that the last sentence thereof is deleted.
2.12 Section 10.1 FORM AND PLACE OF NOTICE set forth in the Agreement
is amended in part so that the Buyer's address is:
Louisville Gas and Electric Company
220 West Main Street
P.O. Box 32010
Louisville, Kentucky 40232
Attention: Manager, Coal Supply
and Roberts Bros. Coal Co., Inc.'s address is:
Roberts Bros. Coal Co., Inc.
1690 Columbia School House Road
P.O. Box 1223
Madisonville, Kentucky 42431
<PAGE>
Amendment 4
Page 8 of 11
2.13 Section 11 EARLY TERMINATION set forth in the Agreement is
amended to read in its entirety as follows:
"Section 11. EARLY TERMINATION. The parties recognize that
conditions not now foreseen could arise in which either Buyer or
Seller, whether for economic or other compelling reasons, would desire
to terminate this Agreement, in whole or in part, in advance of the
expiration date. Accordingly, it is agreed that for whatever reason,
each party shall have the right of early termination, in whole or in
part, of its rights and obligations under this Agreement, subject to
the provisions of this Agreement.
The party desiring to exercise its right of early termination
shall give written notice thereof to the other party and pay the price
for early termination as described herein. Notice may be given by
either party no later than three (3) months before the end of any
Agreement year, and this Agreement will be terminated at the end of
such year. The price paid for such early termination shall be $2.75
times the minimum tonnage remaining from the effective date of
termination until December 31, 1996.
2.14 Section 14 DISPUTES set forth in the Agreement is deleted in its
entirety.
3.0 STATUS OF AGREEMENT
As amended herein, the Agreement shall continue in full force and
effect.
4.0 FORM OF EXECUTION AND DELIVERY
This Amendment may be executed in multiple counterparts, each of which
shall be deemed an original, but all of which together shall constitute one and
the same document. Transmittal by telecopier of an executed copy of this
Amendment shall constitute a valid and binding execution and delivery of this
Amendment.
IN WITNESS WHEREOF, the parties hereto have executed this Amendment on the
day and year below written, but effective as of the day and year first set forth
above.
Shawnee Coal Company Louisville Gas and Electric Company
By: ________________________ By: _________________________
Title: ________________________ Title: _________________________
Date: ________________________ Date: _________________________
<PAGE>
Amendment 4
Page 9 of 11
Roberts Bros. Coal Co., Inc.
By: ________________________
Title: ________________________
Date: ________________________
<PAGE>
Amendment 4
Page 10 of 11
EXHIBIT B
SAMPLE COAL PAYMENT CALCULATIONS
TOTAL EVALUATED COAL COSTS FOR CONTRACT NO. 08901877
FOR CONTRACTS SUPPLIED FROM MULTIPLE "ORIGINS", EACH "ORIGIN" WILL BE CALCULATED
INDIVIDUALLY
SECTION I. BASE DATA
1) Base F.O.B. price per ton: $___22.31____/ton
1a) Tons of coal delivered: ____________tons
2) Guaranteed average heat content: ___11,600____ B.T.U./LB.
2r) As received monthly avg. heat content: _____________B.T.U./LB.
2a) Energy delivered in M.M.B.T.U.: _____________B.T.U./LB.
[(Line 1a)"2,000 lb./ton"(Line 2__)]
*MMBTU/1,000,000 BTU
[( )*2,000 lb./ton*( )]
*MMBTU/1,000,000 BTU
2b) Base F.O.B. price per M.M.B.T.U.: $____________/MMBTU
[((Line 1/(Line 2)]*(1 ton/2,000 lb.))
*1,000,000 BTU/MMBTU
[(( /ton)/( BTU/LB)]*(1 ton/2,000 lb.)]
*1,000,000 BTU/MMBTU
3) Guaranteed monthly avg. max. sulfur __290________ LBS./MMBTU
3r) As received monthly avg. sulfur _____________ LBS./MMBTU
4) Guaranteed monthly avg. max. ash __10.80_______ LBS./MMBTU
4r) As received monthly avg. ash _____________ LBS./MMBTU
5) Guaranteed monthly avg. max. moisture __8.25________ LBS./MMBTU
5r) As received monthly avg. moisture ______________ LBS./MMBTU
SECTION II. DISCOUNTS
Assign a (*) to all discounts to five (5) decimal places)
6d) B.T.U./LB.: If line 2r is less than 11,260 BTU/lb.
{1*[(line 2r)/(line 2)]} * 50.2804/MMBTU
{1*[( )/( )]} * $0.2604 = $____________/MMBTU
7d) SULFUR: If line 3r is greater than 3.1 lbs./MMBTU
[(line 3r)-(Line 3)] * $0.1232/lb sulfur
[( )*( )] * $0.1232 = $____________/MMBTU
<PAGE>
Amendment 4
Page 11 of 11
8d) ASH: If line 4r is greater than 12.20 lbs./MMBTU
[(line 4r)*(line 4)] * $0.0083/lb.ash.
[( )*( )] * $0.0083 = $____________/MMBTU
9d) MOISTURE: If line 6r is greater than 9.58 lbs./MMBTU
[(line 5r)*(line 5)] * $0.0016)lb moisture
[( )*( )] * $0.0018 = $____________/MMBTU
SECTION III. TOTAL PRICE ADJUSTMENTS
Determine total Discounts as follows:
Assign a(-) to all Discounts and enter number for:
Line 6d: $________/MMBTU
Line 7d: $________/MMBTU
Line 8d: $________/MMBTU
Line 9d: $________/MMBTU
10) Total Discounts(-):
Algebraic sum of above: $__________/MMBTU
11) Total evaluated coal price = (line 2b) + (line 10)
$________/MMBTU + $__________/MMBTU = $__________/MMBTU
12) Total discount price adjustment for Energy delivered:
(line 2a)*(line 10)(-)
_________ MMBTU = $__________/MMBTU = $__________
13) Total base cost of coal
(line 2a) * (line 2b)
_________ MMBTU = $___________/MMBTU = $__________
14) Total coal payment for month
(LINE 12)+(LINE 13)
$___________ + $_________ = $__________
<PAGE>
CONTRACT NO. 93-255-026
EXHIBIT 10.46
COAL SUPPLY AGREEMENT
This is a coal supply agreement (the "Agreement") dated January 1, 1994
between LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation, 220 West
Main Street, Louisville, Kentucky 40202 ("Buyer") and PEABODY COALSALES COMPANY,
a Delaware corporation, 1951 Barrett Court, P.O. Box 1996, Henderson, Kentucky
42420 ("Seller").
RECITAL
Peabody Development Company and Buyer entered into a Contract dated
December 18, 1991 (as amended by Amendment 1 dated September 1, 1992) (the
"Original Contract") for the sale of coal by Peabody Development Company to
Buyer. The Original Contract was assigned to Seller by Assignment dated March
1, 1993.
AGREEMENTS
The parties hereto agree as follows:
SECTION 1. GENERAL The Original Contract is hereby terminated as of
December 31, 1993. Thereafter, Seller will sell to Buyer and Buyer will buy
from Seller steam coal under all the terms and conditions of this Agreement.
SECTION 2. TERM Subject to Section 8.2, the term of this Agreement
shall commence on January 1, 1994 and shall continue through December 31, 1999.
Buyer shall have the right, but not the obligation, to renew this Agreement for
up to five (5) additional one year periods, such right to be exercised by notice
in writing to Seller no later than forty-five (45) days prior to the
<PAGE>
beginning of the year in question. Buyer's right to renew this Agreement is
subject to the parties' reaching an agreement on the Base Price for the renewal
period.
SECTION 3. QUANTITY
Section 3.1 BASE QUANTITY. Except as adjusted under Section 3.3, Seller
shall sell and deliver and Buyer shall purchase and accept delivery of the
following annual base quantity of coal ("Base Quantity"):
YEAR BASE QUANTITY (TONS)
---- --------------------
1994 1,100,000
1995 1,100,000
1996 1,100,000
1997 1,100,000
1998 1,100,000
1999 1,100,000
Section 3.2 DELIVERY SCHEDULE. Except as provided in the last sentence of
this Section 3.2, by December 1 of each year, Buyer shall specify in writing to
Seller the quantities to be delivered in each month of the following year.
Subject to Section 3.3, such quantities shall be shipped in accordance with such
schedule. Time is of the essence with respect to the schedule so established;
and failure by Seller to deliver in a timely fashion shall constitute a material
breach within the meaning of Section 16 of this Agreement. This Section 3.2
fully applies to 1994 deliveries except that Buyer
<PAGE>
shall have until ten (10) business days after this Agreement becomes fully
executed to so specify such monthly delivery schedule for 1994.
Section 3.3 ADJUSTMENTS. Buyer shall have the right to change the
monthly delivery schedule and the Base Quantity as follows: Buyer may change
the quantity to be delivered during each calendar month pursuant to the monthly
delivery schedule by giving written notice to Seller 75 days before the
beginning of said month. However, the total quantity for each calendar year may
not be either more than 1,375,000 tons or less than 825,000 tons. Buyer also
has the
option to discuss with Seller quantities greater than 1,375,000 tons subject to
availability and agreement on price.
SECTION 4. SOURCE
Section 4.1 SOURCE. Subject to Section 4.4 hereof, the coal sold
hereunder, including coal purchased from third parties, shall be supplied from
Peabody Coal Company's Lynnville Mine, #5, #6, and #7 seams, Warrick and Spencer
Counties, Indiana. The source is described with particularity in Exhibit A
"Coal Property" attached hereto and made a part hereof (the "Coal Property").
Section 4.2 ASSURANCE OF OPERATION AND RESERVES. Seller represents and
warrants that the Coal Property contains economically recoverable coal of a
quality and in quantities which will be sufficient to satisfy all the
requirements of this Agreement. Seller agrees and warrants that it will cause
to have at the Coal Property adequate machinery, equipment and other facilities
to produce,
3
<PAGE>
prepare and deliver coal in the quantity and of the quality required by this
Agreement. Seller further agrees that it will cause the operation and
maintenance of such machinery, equipment and facilities in accordance with good
mining practices so as to efficiently and economically produce, prepare and
deliver such coal. Seller agrees that Buyer is not providing any capital for
the purchase of such machinery, equipment and/or facilities and that Seller
shall operate and maintain same at its sole expense, including all required
permits and licenses. Seller hereby allocates to this Agreement sufficient
reserves of coal meeting the quality specifications hereof and lying on or in
the Coal Property so as to fulfill the quantity requirements hereof.
Section 4.3 NON-DIVERSION OF COAL. Seller agrees and warrants that it
will not, without Buyer's express prior written consent, use or sell coal from
the Coal Property in a way that will reduce the economically recoverable balance
of coal in the Coal Property to an amount less than that required to be supplied
to Buyer hereunder.
Section 4.4 SUBSTITUTE COAL. Notwithstanding the above representations
and warranties, Seller shall have the right to supply coal hereunder produced
from any of the following mines ("Substitute Coal"):
(1) Peabody Coal Company's Ken Mine, #9, #11, #13 seams, Ohio County,
Kentucky
(2) Peabody Coal Company's Martwick Mine, #9, #11 seams, Muhlenberg
County, Kentucky
(3) Peabody Coal Company's Camp Complex, #9, #11 seams, Union County,
Kentucky
(4) Pyramid Mining Inc.'s Patriot and Goshen Mines (the "Pyramid Mines"),
#9, #11, #12 seams, Henderson and Ohio Counties, Kentucky
4
<PAGE>
subject to the following quantity limitations:
(a) In each six-month period throughout the term of this Agreement (i.e.,
January 1 to June 30 and July 1 to December 31), the Substitute Coal supplied
hereunder shall not exceed 50,000 tons or 10% of the total tonnage delivered
hereunder during such six-month period, whichever is less. For Substitute Coal
delivered hereunder in excess of this quantity limitation (a) ("Excess
Substitute Coal"), the Base Price shall be reduced pursuant to Section 8.1.
(b) In each calendar month throughout the term of this Agreement, the
Substitute Coal produced from the Camp Complex and supplied hereunder shall not
exceed a quantity equivalent to that contained in five (5) individual barge
loads.
(c) The Pyramid Mines may be used as a source of supply during 1994 only
and only with the approval of Buyer.
Buyer shall not be obligated to accept Substitute Coal beyond quantity
limitations (b) and (c) set forth above.
5
<PAGE>
SECTION 5. DELIVERY
5.1 GENERAL. At Buyer's option, the coal shall be delivered either all by
barge, all by rail, or some portion by barge and some portion by rail where such
loading facilities currently exist.
5.2 RAIL DELIVERY. For coal produced from the Coal Property which Buyer
designates to be delivered by rail, such coal shall be delivered F.O.B.
Destination. Title to and risk of loss respecting such coal will pass to Buyer
and the coal will be considered to be delivered when it is unloaded at Buyer's
designated destination point. At Buyer's request, Seller shall treat (or have
treated) any rail shipment of coal hereunder with a freeze conditioning agent
(Shur-Coal No. 615 or equivalent approved by Buyer) in order to maintain coal
handling characteristics during shipment. If requested by Buyer, Seller shall
also treat (or have treated) any rail cars specified by Buyer with a side
release agent (Shur-Coal No. 615 or equivalent approved by Buyer.) The price
for each such requested chemical treatment shall be an amount equal to Seller's
cost of materials on a per gallon basis for each application of freeze
conditioning agent or side release agent, as the case may be. Seller shall
invoice Buyer for all such treatment which occurred in a calendar month by the
fifteenth of the following month; and payment shall be mailed by the 25th of
such following month or within ten days after receipt of Seller's invoice,
whichever is later.
If Seller delivers Substitute Coal under Section 4.4 hereof by rail from
the Pyramid Mines ("Pyramid Rail Coal"), then the coal shall be delivered to
Buyer F.O.B. railcar at the Pyramid rail loading facility at Bixby, Kentucky on
the Paducah & Louisville Railway (the "Pyramid Rail Delivery Point"). Seller
may deliver Pyramid Rail Coal at a location different from the Pyramid
6
<PAGE>
Rail Delivery Point, provided, however, that Seller shall reimburse Buyer for
any resulting increases in the cost of transporting the coal to Buyer's
generating stations. Any resulting savings in such transportation costs shall
be retained by Buyer.
Title to and risk of loss respecting Pyramid Rail Coal will pass to Buyer
and the coal will be considered to be delivered when it is loaded into the
railcars at the rail loading facility. Buyer or its contractor shall furnish
suitable railcars in accordance with a delivery schedule provided by Buyer to
Seller. Seller shall be responsible for and pay the cost of repairs for any
damages caused by Seller to railcars owned or leased by Buyer while such
railcars are in
Seller's control or custody. Seller shall comply with the applicable provisions
of Buyer's rail contractor's tariff.
5.3 BARGE DELIVERY. For coal produced from the Coal Property which Buyer
designates to be delivered by barge, the coal shall be delivered to Buyer F.O.B.
barge at the Yankeetown dock at mile point 772.5 on the Ohio River (the "Barge
Delivery Point"). Seller may deliver coal produced from the Coal Property at a
location different from the Barge Delivery Point, provided, however, that Seller
shall reimburse Buyer for any resulting increases in the cost of transporting
the coal to Buyer's generating stations. Any resulting savings in such
transportation costs shall be retained by Buyer.
Title to and risk of loss of coal sold will pass to Buyer and the coal will
be considered to be delivered when loaded into barges at the loading dock.
Buyer or its contractor shall furnish suitable barges in accordance with a
delivery schedule provided by Buyer to Seller. Seller shall
7
<PAGE>
arrange and pay for all costs of transporting the coal from the mines to the
loading docks and loading and trimming the coal into barges to the proper draft
and the proper distribution within the barges. Buyer shall arrange for
transporting the coal by barge from the loading dock to its generating
station(s) and shall pay for the cost of such transportation. For delays caused
by Seller in handling the scheduling of shipments with Buyer's barging
contractor, Seller shall be responsible for any demurrage or other penalties
assessed by said barging contractor (or assessed by Buyer) which accrue at the
Barge Delivery Point, including the demurrage, penalties for loading less than
normal full-load tonnage for Buyer's barge carrier's individual barge style and
type (an average of approximately 1,500 tons per barge), or other penalties
assessed for barges not loaded in conformity with applicable requirements.
Buyer shall cause Seller to be given notice of such applicable requirements and
reasonable advance notice of any changes in such applicable requirements. Buyer
shall be responsible to deliver barges in as clean and dry condition as
practicable. Seller shall require of the loading dock operator that the barges
and towboats provided by Buyer or buyer's barging contractor be provided
convenient and safe berth free of wharfage, dockage and port charges; that while
the barges are in the care and custody of the loading dock, all U.S. Coast Guard
regulations and other applicable laws, ordinances, rulings, and regulations
shall be complied with, including adequate mooring and display of warning
lights; that any water in the cargo boxes of the barges be pumped out by the
loading dock operator prior to loading; that the loading operations be performed
in a workmanlike manner and in accordance with the reasonable loading
requirements of Buyer and Buyer's barging contractor; and that the
8
<PAGE>
loading dock operator carry landing owners or wharfinger's insurance with basic
coverage of not less than $300,000.00 and total of basic coverage and excess
liability coverage of not less than $1,000,000.00, and provide evidence thereof
to Buyer in the form of a certificate of insurance from the insurance carrier or
an acceptable certificate of self-insurance with requirement for 30 days advance
notification of Buyer in the event of termination of or material reduction in
coverage under the insurance.
If Seller delivers Substitute Coal hereunder pursuant to Section 4.4
hereof, the respective Barge Delivery Points shall be as follows:
MINE NAME LOAD OUT RIVER MILE POINT
--------- -------- ----- ----------
Camp Complex Uniontown Ohio 842.9
Ken Ken Green 97.7
Martwick Gibralter Green 85.9
Pyramid (Patriot) Demao Green 31.5
Pyramid (Goshen) Rockport Green 94.8
and all the provisions set forth in this Section 5.3 hereinabove shall apply.
SECTION 6. QUALITY
Section 6.1 SPECIFICATIONS. The coal produced from the Coal Property and
delivered hereunder shall conform to the following specifications on an "as
received" basis:
LYNNVILLE MINE
Guaranteed Monthly Rejection Limits
Specifications Weighted Average (per shipment)
--------------------------------------------------------------------------
BTU/LB. min. 10,950 < 10,850
------ ------
9
<PAGE>
MOISTURE max. 12.91 lbs/MMBTU > 14.0
----- -----
ASH max. 8.00 lbs/MMBTU > 9.0
----- -----
SULFUR max. 2.90 lbs/MMBTU > 3.3
----- -----
SULFUR min. 1.8 lbs/MMBTU < 1.8
----- -----
CHLORINE max. 0.07 lbs/MMBTU > 0.08
----- -----
FLUORINE max. 0.013 lbs/MMBTU > 0.013
----- -----
NITROGEN max. 1.50 lbs/MMBTU > 1.60
----- -----
ASH/SULFUR RATIO min. 2.5:1 < 2.5:1
----- -----
Size (3" x 0"):
Top size (inches) max. 3"x0" > 3"x0"
----- -----
Fines (% by wgt)
Passing 1/4"
screen max. 40% > 45%
----- -----
% BY WEIGHT:
VOLATILE max. 34.5 > 35.0
----- -----
VOLATILE min. 33.5 < 33.0
----- -----
FIXED CARBON max. 44 > 45
----- -----
FIXED CARBON min. 40 < 40
----- -----
GRINDABILITY (HGI) min. 53 < 50
----- -----
BASE ACID RATIO (B/A)
SLAGGING FACTOR* max. 2.0 > 2.0
----- -----
FOULING FACTOR** max. 0.5 > 0.5
----- -----
ASH FUSION TEMPERATURE (DEG.F) (ASTM D1857)
----------------------------------------
REDUCING ATMOSPHERE
-------------------
Initial Deformation min. 1910 min. 1875
----- -----
Softening (H=W) min. 1930 min. 1900
----- -----
Softening (H=1/2W) min. 1975 min. 1950
----- -----
Fluid min. 2120 min. 2050
----- -----
OXIDIZING ATMOSPHERE
--------------------
Initial Deformation min. 2300 min. 2200
----- -----
Softening (H=W) min. 2325 min. 2300
----- -----
Softening (H=1/2W) min. 2340 min. 2350
----- -----
Fluid min. 2400 min. 2400
----- -----
10
<PAGE>
If Seller delivers Substitute Coal under Section 4.4 hereof, the Substitute
Coal produced from the following mines and delivered hereunder shall conform to
the following specifications on an "as received" basis:
KEN MINE
--------
Guaranteed Monthly Rejection Limits
Specifications Weighted Average (per shipment)
---------------------------------------------------------------------
BTU/LB. min. 11,750 < 11,500
------ ------
MOISTURE max. 8.94 lbs/MMBTU > 11.0
----- ------
ASH max. 6.97 lbs/MMBTU > 8.0
----- ------
SULFUR max. 2.8 lbs/MMBTU > 3.0
----- ------
SULFUR min. 1.8 lbs/MMBTU < 1.8
----- ------
CHLORINE max. 0.03 lbs/MMBTU > 0.05
----- ------
FLUORINE max. 0.013 lbs/MMBTU > 0.013
----- ------
NITROGEN max. 1.40 lbs/MMBTU > 1.60
----- ------
ASH/SULFUR RATIO min. 2.5:1 < 2.5:1
----- ------
Size (3" x 0"):
Top size (inches) max. 3"x0" > 3"
----- -----
Fines (% by wgt)
Passing 1/4" screen max. 40% > 45%
----- -----
% BY WEIGHT:
VOLATILE max. 36.50 > 37
------ -----
VOLATILE min. 34 < 32
------ -----
FIXED CARBON max. 46 > 46.5
------ -----
FIXED CARBON min. 42 < 41
------ ------
GRINDABILITY (HGI) min. 52 < 50
------ ------
BASE ACID RATIO (B/A)
SLAGGING FACTOR* max. 2.0 > 2.0
------ ------
FOULING FACTOR** max. 0.5 > 0.5
------ ------
ASH FUSION TEMPERATURE (DEG.F) (ASTM D1857)
----------------------------------------
11
<PAGE>
REDUCING ATMOSPHERE
-------------------
Initial Deformation min. 1960 min. 1900
----- ------
Softening (H=W) min. 2000 min. 1950
----- ------
Softening (H=1/2W) min. 2050 min. 1975
----- ------
Fluid min. 2190 min. 2100
----- ------
OXIDIZING ATMOSPHERE
--------------------
Initial Deformation min. 2300 min. 2200
------ ------
Softening (H=W) min. 2325 min. 2280
------ ------
Softening (H=1/2W) min. 2340 min. 2300
------ ------
Fluid min. 2400 min. 2375
------ ------
MARTWICK MINE
-------------
Guaranteed Monthly Rejection Limits
Specifications Weighted Average (per shipment)
------------------------------------------------------------------
BTU/LB. min. 11,750 < 11,500
------ ------
MOISTURE max. 9.02 lbs/MMBTU > 11.0
------ ------
ASH max. 7.49 lbs/MMBTU > 9.0
------ ------
SULFUR max. 2.46 lbs/MMBTU > 2.7
------ ------
SULFUR min. 1.8 lbs/MMBTU < 1.8
------ ------
CHLORINE max. 0.04 lbs/MMBTU > 0.05
------ ------
FLUORINE max. 0.013 lbs/MMBTU > 0.013
------ ------
NITROGEN max. 1.45 lbs/MMBTU > 1.50
------ ------
ASH/SULFUR RATIO min. 2.5:1 < 2.5:1
------ ------
Size (3" x 0"):
Top size (inches) max. 3"x0" > 3"x0"
------ ------
Fines (% by wgt)
Passing 1/4" screen max. 45% > 50%
------ ------
% BY WEIGHT:
VOLATILE max. 36 > 36.5
------ ------
VOLATILE min. 34 < 33
------ ------
FIXED CARBON max. 46 > 46.5
------ ------
12
<PAGE>
FIXED CARBON min. 43 < 40
------ ------
GRINDABILITY (HGI) min. 52 < 50
------ ------
BASE ACID RATIO (B/A)
SLAGGING FACTOR* max. 2.0 > 2.0
------ ------
FOULING FACTOR** max. 0.5 > 0.5
------ ------
ASH FUSION TEMPERATURE (DEG.F) (ASTM D1857)
----------------------------------------
REDUCING ATMOSPHERE
-------------------
Initial Deformation min. 2010 min. 1900
------ ------
Softening (H=W) min. 2060 min. 1950
------ ------
Softening (H=1/2W) min. 2120 min. 1975
------ ------
Fluid min. 2355 min. 2100
------ ------
OXIDIZING ATMOSPHERE
--------------------
Initial Deformation min. 2440 min. 2200
----- ------
Softening (H=W) min. 2495 min. 2280
----- ------
Softening (H=1/2W) min. 2425 min. 2300
----- ------
Fluid min. 2575 min. 2375
----- ------
CAMP COMPLEX
------------
Guaranteed Monthly Rejection Limits
Specifications Weighted Average (per shipment)
-------------------------------------------------------------------
BTU/LB. min. 11,400 < 11,300
------ ------
MOISTURE max. 10.53 lbs/MMBTU > 12.0
------ ------
ASH max. 8.65 lbs/MMBTU > 10.0
------ ------
SULFUR max. 2.54 lbs/MMBTU > 2.8
------ ------
SULFUR min. 1.8 lbs/MMBTU < 1.8
------- ------
CHLORINE max. 0.10 lbs/MMBTU > 0.10
------ ------
FLUORINE max. 0.013 lbs/MMBTU > 0.013
------ ------
13
<PAGE>
NITROGEN max. 1.40 lbs/MMBTU > 1.60
------ ------
ASH/SULFUR RATIO min. 2.5:1 < 2.5:1
------ ------
Size (3" x 0"):
Top size (inches) max. 3"x0" > 3"x0"
------ ------
Fines (% by wgt)
Passing 1/4" screen max. 45% > 50%
------ ------
% BY WEIGHT:
VOLATILE max. 36.5 > 37
------ ------
VOLATILE min. 34 < 32
------ ------
FIXED CARBON max. 44 > 45
------ ------
FIXED CARBON min. 42 < 41
------ ------
GRINDABILITY (HGI) min. 52 < 50
------ ------
BASE ACID RATIO (B/A)
SLAGGING FACTOR* max. 2.0 > 2.0
------ -----
FOULING FACTOR** max. 0.5 > 0.5
------ -----
ASH FUSION TEMPERATURE (DEG.F) (ASTM D1857)
----------------------------------------
REDUCING ATMOSPHERE
-------------------
Initial Deformation min. 1900 min. 2200
------ ------
Softening (H=W) min. 1950 min. 2280
------ ------
Softening (H=1/2W) min. 1975 min. 2300
------ ------
Fluid min. 2100 min. 2375
------ ------
OXIDIZING ATMOSPHERE
--------------------
Initial Deformation min. 2300 min. 2275
------ ------
Softening (H=W) min. 2330 min. 2300
------ ------
Softening (H=1/2W) min. 2425 min. 2400
------ ------
Fluid min. 2490 min. 2450
------ ------
PYRAMID MINES
-------------
14
<PAGE>
Guaranteed Monthly Rejection Limits
Specifications Weighted Average (per shipment)
----------------------------------------------------------------
BTU/LB. min. 11,200 < 11,000
------ ------
MOISTURE max. 12.50 lbs/MMBTU > 13.0
------ ------
ASH max. 8.45 lbs/MMBTU > 9.0
------ ------
SULFUR max. 2.50 lbs/MMBTU > 2.6
------ ------
SULFUR min. 1.80 lbs/MMBTU < 1.8
------- ------
CHLORINE max. 0.07 lbs/MMBTU > .09
------ ------
FLUORINE max. 0.013 lbs/MMBTU > 0.013
------ ------
NITROGEN max. 1.40 lbs/MMBTU > 1.80
------ ------
ASH/SULFUR RATIO min. 2.5:1 < 2.5:1
------ ------
Size (3" x 0"):
Top size (inches) max. 3" > 3"
------ ------
Fines (% by wgt)
Passing 1/4" screen max. 40% > 40%
------ ------
% BY WEIGHT:
VOLATILE max. 39 > 40
------ ------
VOLATILE min. 31 < 30
------ ------
FIXED CARBON max. 57 > 58
------ ------
FIXED CARBON min. 33 < 32
------ ------
GRINDABILITY (HGI) min. 48 < 45
------ ------
BASE ACID RATIO (B/A)
SLAGGING FACTOR* max. 2.0 > 2.0
------ ------
FOULING FACTOR** max. 0.5 > 0.5
------ ------
ASH FUSION TEMPERATURE (DEG.F) (ASTM D1857)
----------------------------------------
REDUCING ATMOSPHERE
-------------------
Initial Deformation min. 2100 min. 2000
----- ------
Softening (H=W) min. 2205 min. 2100
----- ------
Softening (H=1/2W) min. 2300 min. 2200
----- ------
Fluid min. 2400 min. 2300
----- ------
15
<PAGE>
OXIDIZING ATMOSPHERE
--------------------
Initial Deformation min. 2450 min. 2350
----- ------
Softening (H=W) min. 2500 min. 2400
----- ------
Softening (H=1/2W) min. 2560 min. 2500
----- ------
Fluid min. 2600 min. 2525
----- ------
* Slagging Factor (R(s))=(B/A) x (Percent Sulfur by Weight(Dry))
** Fouling Factor (R(f))=(B/A) x (Percent Na(2)0 by Weight(Dry))
The Base Acid Ratio (B/A) is herein defined as:
(Fe(2)0(3) + Ca0 + Mg0 + Na(2)0 + K(2)0)
BASE ACID RATIO (B/A) = ------------------------------------------------
(Si0(2) + A1(2)0(3) + T10(2))
Note: As used herein > means greater than:
< means less than.
Section 6.2 DEFINITION OF "SHIPMENT". As used herein, a "shipment"
shall mean one barge load, a barge lot load, or one unit trainload, as the case
may be.
Section 6.3 REJECTION.
Buyer has the right, but not the obligation, to reject any shipment which
fail(s) to conform to the Rejection Limits set forth in Section 6.1 or contains
extraneous materials. Buyer must reject such coal within seventy-two (72) hours
of receipt of the coal analysis provided for in Section 7.2 or such right to
reject is waived. In the event Buyer rejects such non-conforming coal, Buyer
shall return the coal to Seller or, at Seller's request, divert such coal to
Seller's designee, all at Seller's cost. Seller shall replace the rejected coal
within five (5) working days from notice of rejection with coal conforming to
the Rejection Limits set forth in Section 6.1. If Seller fails to replace the
rejected
16
<PAGE>
coal within such five (5) working day period or the replacement coal is
rightfully rejected, Buyer may purchase coal from another source in order to
replace the rejected coal. Seller shall reimburse Buyer for (i) any amount by
which the actual price plus transportation costs to Buyer of such coal purchased
from another source exceeds the price of such coal under this Agreement (as
adjusted under Section 8.3 for coal of the quality actually supplied by the
other source) plus transportation costs to Buyer from the Delivery Point; and
(ii) any and all transportation, storage, handling, or other expenses that have
been incurred by Buyer for rightfully rejected coal. This remedy is in addition
to all of Buyer's other remedies under this Agreement and under applicable law
and in equity for Seller's breach.
If Buyer fails to reject a shipment of non-conforming coal which it had the
right to reject for failure to meet any or all of the Rejection Limits set forth
in Section 6.1 or because such shipment contained extraneous materials, then
such non-conforming coal shall be deemed accepted by Buyer; however, the price
shall be adjusted in accordance with Section 8.3 and the quantity Buyer is
obligated to purchase from Seller, at Buyer's sole option, shall be reduced by
the amount of each such non-conforming shipment. Further, for shipments
containing extraneous materials, which include, but are not limited to, slate,
rock, wood, corn husks, mining materials, etc., the estimated weight of such
materials shall be deducted from the weight of that shipment.
Section 6.4 SUSPENSION AND TERMINATION.
If one or more shipments of the coal sold hereunder fails to meet one or
more of the
17
<PAGE>
rejection limits set forth in Section 6.1 (i.e., are rejectable) in any 2 months
in a 6 month period, or if 9 barge shipments in a 30 day period are rejectable
by Buyer, or if Buyer receives at generating station(s) 2 unapproved rail
shipments which are rejectable in any 30 day period, Buyer may upon notice
confirmed in writing and sent to Seller by certified mail, suspend future
shipments except shipments already loaded into barges and/or railcars. Seller
shall, within 10 days, provide Buyer with reasonable assurances that subsequent
monthly deliveries of coal shall be within the rejection limits set forth in
Section 6.1. If Seller fails to provide such assurances within said 10 day
period, Buyer may terminate this Agreement by giving written notice of such
termination at the end of the 5 day period. A waiver of this right for any one
period by Buyer shall not constitute a waiver for subsequent periods. If Seller
provides such assurances to Buyer's reasonable satisfaction, shipments hereunder
shall resume and any tonnage deficiencies resulting from suspension may be made
up at Buyer's sole option. Buyer shall not unreasonably withhold its acceptance
of Seller's assurances, or delay the resumption of shipment. If Seller, after
such assurances, fails to meet the Guaranteed Monthly Weighted Averages for 1
month within the next 6 months or if 6 individual barge shipments, 2 barge lot
loads, or 2 rail shipments are rejectable within one month during such six month
period, then Buyer may terminate this Agreement and exercise all its other
rights and remedies under applicable law and in equity for Seller's breach.
SECTION 7. WEIGHTS, SAMPLING AND ANALYSIS
Section 7.1 WEIGHTS. The weight of the coal delivered hereunder shall be
determined on a per shipment basis by Buyer on the basis of scale weights at the
generating station(s) unless another
18
<PAGE>
method is mutually agreed upon by the parties. Such scales shall be duly
certified by an appropriate testing agency and maintained in an accurate
condition. Seller shall have the right, at Seller's expense and upon reasonable
notice, to have the scales checked for accuracy at any reasonable time or
frequency. If the scales are found to be inaccurate, over or under the
tolerance range allowable for the scale, either party shall pay to the other any
amounts owed due to such inaccuracy for a period not to exceed thirty (30) days
before the time any inaccuracy of scales is determined.
Section 7.2 SAMPLING AND ANALYSIS. The sampling and analysis of the coal
delivered hereunder shall be performed by Buyer and the results thereof shall be
accepted and used for the quality and characteristics of the coal delivered
under this Agreement. All analyses shall be made in Buyer's laboratory at
Buyer's expense in accordance with A.S.T.M. specifications. Samples for
analyses shall be taken by any reliable and industry accepted standard, mutually
acceptable to both parties, may be composited and shall be taken with a
frequency and regularity sufficient to provide reasonably accurate
representative samples of the deliveries made hereunder. Seller represents that
it is familiar with Buyer's sampling and analysis practices, and finds them to
be acceptable. Buyer shall notify Seller in writing of any significant changes
in Buyer's sampling and analysis practices. Any such changes in Buyer's
sampling and analysis practices shall, except for industry accepted changes in
practices, provide for no less accuracy
than the sampling and analysis practices existing at the time of the execution
of this Agreement, unless the Parties otherwise mutually agree.
19
<PAGE>
Each sample taken by Buyer shall be divided into 4 parts and put into
airtight containers, properly labeled and sealed. One part shall be used by
Seller, one part shall be used for analysis by Buyer, one part shall be used by
Buyer as a check sample, if Buyer in its sole judgment determines it is
necessary, and one part ("Referee Sample") shall be retained by Buyer for a
period of 30 days. Seller shall be given timely and routine copies of all
analyses made by Buyer. Seller, on reasonable notice to Buyer shall have the
right to have a representative present to observe the sampling and analyses
performed by Buyer. Unless Seller requests a Referee Sample analysis, Buyer's
analysis shall be used to determine the quality of the coal delivered hereunder.
The Monthly Weighted Averages shall be determined by utilizing the individual
shipment analyses.
If any dispute arises within 30 days of the date of sampling, the Referee
Sample retained by Buyer shall be submitted for analysis to an independent
commercial testing laboratory ("Independent Lab") mutually chosen by Buyer and
Seller. The analysis of the Independent Lab shall control to the extent
provided in this Section 7.2. A dispute shall be deemed not to exist and
Buyer's analysis shall prevail if the analysis of a sample made by the
Independent Lab differs from the analysis of Buyer by an amount equal to or less
than:
(i) 0.50% moisture or
(ii) 0.50% ash on a dry basis or
(iii) 100 Btu/lb. on a dry basis, or
(iv) 0.10% sulfur on a dry basis.
The cost of the analysis made by the Independent Lab shall be borne by
Seller if Buyer's analysis prevails and by Buyer if the analysis of the
Independent Lab prevails.
20
<PAGE>
SECTION 8. PRICE
Section 8.1 PRICE. Subject to Section 8.2, the base price (the "Base
Price") of the coal produced from the Coal Property to be sold hereunder will be
firm and will be determined by the year in which the coal is delivered in
accordance with the following schedule:
BASE PRICE (IN $/MMBTU)
-----------------------
FOB DESTINATION
YEAR FOB BARGE (BY RAIL)
---- --------- --------------------
1994 .92100 1.01689
1995 .94863 1.04740
1996 .97709 1.07882
1997 1.00640 1.11119
1998 1.03659 1.14452
1999 1.06769 1.17886
The Base Price is inclusive of all federal, state, municipal and local taxes,
fees and costs of any kind whether arising from government law, rule, regulation
or otherwise, including, without limitation, all costs of conforming to federal
and state mining and reclamation laws, rules and regulations and all other
and/or additional mining and operating costs and expenses incurred during the
term of this Agreement. No price adjustment shall be made under this Agreement
for costs occasioned by changes in laws, rules, regulation, or the like or in
any taxes or other governmental imposition(s) enacted or promulgated after the
date of this Agreement. The Base Price shall be firm and not subject to
adjustment except as provided in this Section 8.
21
<PAGE>
For coal produced from the Coal Property and delivered F.O.B. Destination
(by rail), the Base Price is based on current rail transportation costs from the
Coal Property to the destination point. If such rail transportation costs
increase or decrease, then the Base Price shall be adjusted immediately so that
100 percent of the additional costs or the savings, as the case may be,
resulting from such transportation costs increase or decrease, shall be passed
through to the Buyer. Buyer shall have the right to participate in the
negotiations between Seller and the rail transportation company concerning any
relevant rail transportation agreement.
If Seller delivers Substitute Coal hereunder pursuant to Section 4.4 hereof
and within the quantity limitations set forth in Section 4.4, the Base Price
shall be as follows:
BASE PRICE (IN $/MMBTU)
-----------------------
CAMP COMPLEX
PYRAMID MINES
YEAR MARTWICK KEN
---- -------------- ---
1994 .95960 .93750
1995 .98839 .96563
1996 1.01804 .99459
1997 1.04858 1.02443
1998 1.08004 1.05516
1999 1.11244 1.08682
For Excess Substitute Coal (as defined in Section 4.4(a)), the Base Price of
such coal shall be reduced to the Base Price of coal produced from the Coal
Property (F.O.B. Barge) (in $/MMBTU) set forth in this Section 8.1 above; and
Buyer further shall be credited with the amount by which Buyer's cost (in
$/MMBTU) of transporting Excess Substitute Coal from the applicable Delivery
Point to
22
<PAGE>
the destination point exceeds Buyer's cost of transporting coal produced from
the Coal Property from the applicable Barge Delivery Point to the destination
point. The coal quality specifications which shall be applied to determine
quality price adjustments for Excess Substitute Coal shall be the specifications
set forth in Section 6.1 for the mine from which the Excess Substitute Coal was
produced.
Section 8.2 PRICE REVIEW. The Base Price and Quality Price Adjustment
provisions in Section 8 of this Agreement shall be subject to review for any
reason at the request of either party, for revision(s) to become effective on
January 1, 1997.
The party requesting such a review shall give written notice of its request
to the other party on or before October 1, 1996. The parties then shall
negotiate an agreement on new Base Prices between October 1 and December 1. If
the parties do not reach an agreement on new Base Prices by December 1, then
this Agreement will terminate as of December 31, 1996 without liability due to
such termination for either party.
Section 8.3 QUALITY PRICE ADJUSTMENTS. The Base Price is based on coal
having the Guaranteed Monthly Weighted Average specification as set forth in
Section 6.1. Quality price adjustments (discounts and/or premiums) shall be
made to reflect variances from the Guaranteed Monthly Weighted Averages set
forth in Section 6.1 as determined pursuant to Section 7.2.
The discount and premium values used are:
DISCOUNT PREMIUM
$/MMBTU $/MMBTU
------- -------
BTU/LB. 0.2604 0.1354
23
<PAGE>
DISCOUNT PREMIUM
$/LB./MMBTU $/LB./MMBTU
----------- -----------
SULFUR 0.1232 0.1084
ASH 0.0083 0.0073
MOISTURE 0.0016 0.0014
The sulfur premium shall be based on lbs/MMBTU below the Guaranteed Monthly
Weighted Average Maximum. However, there shall be no sulfur premium for coal
with sulfur content below the Guaranteed Monthly Weighted Average minimum
Section 8.4 PAYMENT CALCULATION. Exhibit B attached hereto shows the
methodology for calculating the coal payment and quality price adjustments for
the month Seller's coal was unloaded by Buyer.
SECTION 9. INVOICES, BILLING AND PAYMENT.
Section 9.1 Invoices will be sent to LG&E at the following address:
Louisville Gas & Electric Company
220 West Main Street
P.O. Box 32010
Louisville, KY 40232
Attention: Manager, Coal Supply
With a copy to:
Louisville Gas & Electric Company
820 West Broadway
P. O. Box 32020
Louisville, KY 40232
Attention: Manager, Accounts Payable
24
<PAGE>
Section 9.2 INVOICE PROCEDURES FOR COAL SHIPMENTS. Seller shall invoice
Buyer at the Base Price, as adjusted by the quality price adjustments, for all
coal unloaded in a calendar month by the fifteenth of the following month.
Section 9.3 PAYMENT PROCEDURES FOR COAL SHIPMENTS. Payment for coal
unloaded in a calendar month shall be mailed by the 25th of the month following
the month of unloading or within ten days after receipt of Seller's invoice,
whichever is later. Buyer shall mail all payments to Seller's account at
Peabody COALSALES Company, P.O. Box 503099, St. Louis, MO 63150-30999. To make
wire transfers contact Boatman's Bank, Account ABA 081000032, wire transfer
account 100101223441.
Section 9.4 WITHHOLDING. Buyer shall have the right to withhold from
payment of any billing or billings (i) any sums which it is not able in good
faith to verify or which it otherwise in good faith disputes, (ii) any damages
resulting from or likely to result from any breach of this Agreement by Seller,
and (iii) any amounts owed to Buyer from Seller. Buyer shall notify Seller
promptly in writing of any such issue, stating the basis of its claim and the
amount it intends to withhold.
Payment by Buyer, whether knowing or inadvertent, of any amount in dispute
shall not be deemed a waiver of any claims or rights by Buyer with respect to
any disputed amounts or payments made.
25
<PAGE>
SECTION 10. FORCE MAJEURE
Section 10.1 GENERAL FORCE MAJEURE. If either party hereto is delayed in
or prevented from performing any of its obligations or from utilizing the coal
sold under this Agreement due to acts of God, war, riots, civil insurrection,
acts of the public enemy, strikes, lockouts, fires, floods or earthquakes, which
are beyond the reasonable control and without the fault or negligence of the
party affected thereby, then the obligations of both parties hereto shall be
suspended to the extent made necessary by such event; provided that the affected
party gives written notice to the other party as early as practicable of the
nature and probable duration of the force majeure event. The party declaring
force majeure shall exercise due diligence to avoid and shorten the force
majeure event and will keep the other party advised as to the continuance of the
force majeure event.
During any period in which Seller's ability to perform hereunder is
affected by a force majeure event, Seller shall not deliver any coal to any
other buyers to whom Seller's ability to supply is similarly affected by such
force majeure event unless contractually committed to do so at the beginning of
the force majeure event; and further shall deliver to Buyer under this Agreement
at least a pro-rata portion (on a per ton basis) of its total contractual
commitments to all its buyers to whom Seller's ability to supply is similarly
affected by such force majeure event in place at the beginning of the force
majeure event.
During any period in which Buyer's ability to perform hereunder is affected
by a force majeure event, Buyer shall not purchase any coal from any other
sellers from whom Buyer's ability to purchase is similarly affected by such
force majeure event unless contractually
26
<PAGE>
committed to do so at the beginning of the force majeure event; and further
shall purchase from Seller under this Agreement at least a pro-rata portion (on
a per ton basis) of its total contractual commitments to all sellers from whom
Buyer's ability to purchase is similarly affected by such force majeure event in
place at the beginning of the force majeure event.
Tonnage deficiencies resulting from a force majeure event shall be made up
at Buyer's sole option on a reasonable schedule.
Section 10.2 ENVIRONMENTAL LAW FORCE MAJEURE. The parties recognize that,
during the continuance of this Agreement, legislative or regulatory bodies or
the courts may adopt environmental laws, regulations, policies and/or
restrictions which will make it impossible or commercially impracticable for
Buyer to utilize this or like kind and quality coal which thereafter would be
delivered hereunder. If as a result of the adoption of such laws, regulations,
policies, or restrictions, or change in the interpretation or enforcement
thereof, Buyer decides that it will be impossible or commercially impracticable
(uneconomical) for Buyer to utilize such coal, Buyer shall so notify Seller, and
thereupon Buyer and Seller shall promptly consider whether corrective actions
can be taken in the mining and preparation of the coal at Seller's mine and/or
in the handling and utilization of the coal at Buyer's generating station; and
if in Buyer's sole judgment such actions will not, without unreasonable expense
to Buyer, make it possible and commercially practicable for Buyer to so utilize
coal which thereafter would be delivered hereunder without violating any
applicable law, regulation, policy or order, Buyer shall have the right, upon
the later of 60 days notice to Seller or the effective date of such restriction,
to terminate this Agreement
27
<PAGE>
without further obligation hereunder on the part of either party.
SECTION 11. CHANGES. Buyer may, by mutual agreement with Seller, at any
time by written notice pursuant to Section 12 of this Agreement, make changes
within the general scope of this Agreement in any one or more of the following:
quality of coal or coal specifications, quantity of coal, method or time of
shipments, place of delivery (including transfer of title and risk of loss),
method(s) of weighing, sampling or analysis and such other provision as may
affect the suitability and amount of coal for Buyer's generating stations.
If any such changes makes necessary or appropriate an increase or decrease
in the then current Base Price per ton of coal, or in any other provision of
this Agreement, an equitable adjustment shall be made in: Base Price, whether
current or future or both, and/or in such other provisions of this Agreement as
are affected directly or indirectly by such change, and the Agreement shall
thereupon be modified in writing accordingly.
Any claim by the Seller for adjustment under this Section 11 shall be
asserted within thirty (30) days after the date of Seller's receipt of the
written notice of change, it being understood, however that Seller shall not be
obligated to proceed under this Agreement as changed until an equitable
adjustment has been agreed upon. The parties agree to negotiate promptly and in
good faith to agree upon the nature and extent of any equitable adjustment. In
the event Seller and Buyer are unable to mutually agree on the changes requested
by Buyer under this Section 11, then this Agreement shall continue in full force
and effect without taking into account such requested changes.
28
<PAGE>
SECTION 12. NOTICES
Section 12. FORM AND PLACE OF NOTICE. Any official notice, request for
approval or other document required to be given under this Agreement shall be in
writing, unless otherwise provided herein, and shall be deemed to have been
sufficiently given when delivered in person, transmitted by facsimile or other
electronic media, delivered to an established mail service for same day or
overnight delivery, or dispatched in the United States mail, postage prepaid,
for mailing by first class, certified, or registered mail, return receipt
requested,and addressed as follows:
If to Buyer: Louisville Gas and Electric Company
220 West Main Street
P.O. Box 32010
Louisville, Kentucky 40232
Attn: Manager, Coal Supply
with a copy to: Louisville Gas and Electric Company
820 West Broadway
P.O. Box 32020
Louisville, Kentucky 40232
Attn: Manager, Procurement Services
If to Seller: Peabody COALSALES Company
1951 Barrett Court
Suite 200
P.O. Box 1996
Henderson, Kentucky 42420-1996
Attn: Vice-President, Sales
Section 12.2 CHANGE OF PERSON OR ADDRESS. Either party may change the
person or address specified above upon giving written notice to the other party
of such change.
29
<PAGE>
Section 12.3 ELECTRONIC DATA TRANSMITTAL. Seller hereby agrees, at
Seller's cost, to electronically transmit shipping notices and/or other data to
Buyer in a format acceptable to and established by Buyer upon Buyer's request.
Buyer shall provide Seller with the appropriate format and will inform Seller as
to the electronic data requirements at the appropriate time.
SECTION 13. EARLY TERMINATION. Each party hereto shall have the right
of early termination for any reason or no reason, in whole or in part, of its
rights and obligations under this Agreement as follows: The party desiring to
exercise its right of early termination shall give written notice thereof to the
other party and pay the price for early termination as described herein. Notice
may be given by either party no later than four (4) months before the end of any
calendar year; and this Agreement will be terminated at the end of such year.
The price paid for such early termination shall be $3.50 times the Base Quantity
remaining under this Agreement from the effective date of the early termination
until either the effective date of the next price change which may occur
pursuant to the next price review right set forth in Section 8.2 (i.e., January
1, 1997) or the termination of this Agreement (i.e., January 1, 2000), as
applicable. For example, if Seller terminates this Agreement effective January
1, 1996, then Seller would owe Buyer $3,850,000 under this Section 13. If this
Agreement remains in effect after the price review and Seller then terminates
this Agreement effective January 1, 1998, then Seller would owe Buyer $7,700,000
under this Section 13.
SECTION 14. RIGHT TO RESELL. Buyer shall have the unqualified right to
sell all or any of the coal purchased under this Agreement.
30
<PAGE>
SECTION 15. INDEMNITY AND INSURANCE
Section 15.1 INDEMNITY. Seller agrees to indemnify and save harmless
Buyer, its officers, directors, employees and representatives from any
responsibility and liability for any and all claims, demands, losses, legal
actions for personal injuries, property damage and pollution (including
reasonable attorney's fees) (i) relating to the barges or railcars provided by
Buyer or Buyer's contractor while such barges or railcars are in the care and
custody of the loading dock or loading facility, (ii) due to any failure of
Seller to comply with laws, regulations or ordinances, or (iii) due to the acts
or omissions of Seller in the performance of this Agreement.
Section 15.2 INSURANCE. Seller agrees to maintain insurance coverage with
minimum limits as follows:
(1) Commercial General Liability, including Completed Operations and
Contractual Liability, $1,000,000 single limit liability.
(2) Automobile General Liability, $1,000,000 single limit liability.
(3) In addition, Seller shall carry excess liability insurance
covering the foregoing perils in the amount of $4,000,000 for any one
occurrence.
(4) Workers' Compensation and Employer's Liability with statutory
limits.
If any of the above policies are written on a claims made basis, then the
retroactive date of the policy or policies will be no later than the effective
date of this Agreement. Certificates of Insurance satisfactory in form to the
Buyer and signed by the Seller's insurer shall be supplied by the Seller to the
Buyer evidencing that the above insurance is in force and that not less than 30
31
<PAGE>
calendar days written notice will be given to the Buyer prior to any
cancellation or material reduction in coverage under the policies. The Seller
shall cause its insurer to waive all subrogation rights against the Buyer
respecting all losses or claims arising from performance hereunder. Evidence of
such waiver satisfactory in form and substance to the Buyer shall be exhibited
in the Certificate of Insurance mentioned above. Seller's liability shall not
be limited to its insurance coverage.
SECTION 16. TERMINATION FOR DEFAULT.
Subject to Section 6.4, if either party hereto commits a material breach of
any of its obligations under this Agreement at any time, then the other party
has the right to give written notice describing such breach and stating its
intention to terminate this Agreement no sooner than 30 days after the date of
the notice (the "notice period"). If such material breach is curable and the
breaching party cures such material breach within the notice period, then the
Agreement shall not be terminated due to such material breach. If such material
breach is not curable or the breaching party fails to cure such material breach
within the notice period, then this Agreement shall terminate at the end of the
notice period in addition to all the other rights and remedies available to the
aggrieved party under this Agreement and at law and in equity.
SECTION 17. TAXES, DUTIES AND FEES
Seller shall pay when due, and the price set forth in Section 8 of this
Agreement shall be inclusive of, all taxes, duties, fees and other assessments
of whatever nature imposed by governmental authorities with respect to the
transactions contemplated under this Agreement.
32
<PAGE>
SECTION 18. DOCUMENTATION AND RIGHT OF AUDIT
Seller shall maintain all records and accounts pertaining to payments,
quantities, quality analyses, source, and proposed revisions to the Base Price
of all coal supplied under this Agreement for a period lasting through the term
of this Agreement and for two years thereafter. Buyer shall have the right at
no additional expense to Buyer to audit, copy and inspect such records and
accounts at any reasonable time upon reasonable notice during the term of this
Agreement and for 2 years thereafter.
SECTION 19. EQUAL EMPLOYMENT OPPORTUNITY. To the extent applicable,
Seller shall comply with all of the following provisions which are incorporated
herein by reference: Equal Opportunity regulations set forth in 41 CRF Section
60-1.4(a) and (c) prohibiting discrimination against any employee or applicant
for employment because of race, color, religion, sex, or national origin;
Vietnam Era Veterans Readjustment Assistance Act regulations set forth in 41 CRF
Section 50-250.4 relating to the employment and advancement of disabled veterans
and veterans of the Vietnam Era; Rehabilitation Act regulations set forth in 41
CRF Section 60-741.4 relating to the employment and advancement of qualified
disabled employees and applicants for employment; the clause known as
"Utilization of Small Business Concerns and Small Business Concerns Owned and
Controlled by Socially and Economically Disadvantaged Individuals" set forth in
15 USC Section 637(d)(3); and subcontracting plan requirements set forth in 15
USC Section 637(d).
SECTION 20. COAL PROPERTY INSPECTIONS AND INJURIES TO
REPRESENTATIVES
Upon reasonable notice Buyer reserves the right to have its
representative(s) visit and
33
<PAGE>
inspect all aspects of the Coal Properties including the loading facilities,
scales, sampling system(s), wash plant facilities, and mining equipment at any
time during the term of this Agreement. Seller and Buyer, respectively, assume
full risk for damage or injury to their representatives or employees when such
representatives or employees are on the premises of the other party in
connection with the exercise of any rights or the performance of any obligations
hereunder except where the damage or injury is caused by the negligence of the
other party. Each party agrees that, to the extent permitted by law, it will
indemnify and hold the other party harmless against all loss or liability
resulting from any such damage or injury occurring on the premises of the other
party except where such damage or injury is caused by the negligence of the
other party.
SECTION 21. MISCELLANEOUS
Section 21.1 APPLICABLE LAW. This Agreement shall be construed in
accordance with the laws of the State of Kentucky, and all questions of
performance of obligations hereunder shall be determined in accordance with such
laws.
Section 21.2 HEADINGS. The paragraph headings appearing in this Agreement
are for convenience only and shall not affect the meaning of interpretation of
this Agreement.
Section 21.3 WAIVER. The failure of either party to insist on strict
performance of any provision of this Agreement, or to take advantage of any
rights hereunder, shall not be construed as a waiver of such provision or right.
Section 21.4 REMEDIES CUMULATIVE. Remedies provided under this Agreement
shall be
34
<PAGE>
cumulative and in addition to other remedies provided under this Agreement or by
law or in equity.
Section 21.5 SEVERABILITY. If any provision of this Agreement is found
contrary to law or unenforceable by any court of law, the remaining provisions
shall be severable and enforceable in accordance with their terms, unless such
unlawful or unenforceable provision is material to the transactions contemplated
hereby, in which case the parties shall negotiate in good faith a substitute
provision.
Section 21.6 BINDING EFFECT. This Agreement shall bind and inure to the
benefit of the parties and their successors and assigns.
Section 21.7 ASSIGNMENT. Neither party may assign this Agreement or any
rights or obligations hereunder without the prior written consent of the other
party, which consent shall not be unreasonably withheld or denied; provided,
however, that Buyer shall have the right,
without consent of Seller, to assign all or any part of this Agreement to any
company, controlling, controlled by, or under common control with Buyer.
Section 21.8 ENTIRE AGREEMENT. This Agreement contains the entire
agreement between the parties as to the subject matter hereof, and there are no
representations, understandings or agreements, oral or written, which are not
included herein.
Section 21.9 AMENDMENTS. Except as otherwise provided herein, this
Agreement may not be amended, supplemented or otherwise modified except by
written instrument signed by both parties
35
<PAGE>
hereto.
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
executed as of the date first above written.
LOUISVILLE GAS AND ELECTRIC COMPANY
By: __________________________
Title: __________________________
Date: __________________________
PEABODY COALSALES COMPANY
By: __________________________
Title: __________________________
Date: __________________________
36
<PAGE>
EXHIBIT 12
LOUISVILLE GAS AND ELECTRIC COMPANY
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(Thousands of $)
<TABLE>
<CAPTION>
1994 1993 1992 1991 1990
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Earnings:
Income before cumulative effect of a change
in accounting principle per statements
of income . . . . . . . . . . . . . . . . . . . $ 61,689 $ 90,535 $ 73,793 $ 94,643 $ 83,450
Add:
Federal income taxes - current. . . . . . . . . . 30,926 42,091 13,785 35,490 24,966
State income taxes - current. . . . . . . . . . . 7,726 12,954 3,140 8,425 8,232
Deferred Federal income taxes - net . . . . . . . (950) 4,712 20,441 17,207 13,142
Deferred State income taxes - net . . . . . . . . 956 226 8,470 6,085 4,475
Investment tax credit - net . . . . . . . . . . . (4,619) (7,821) (5,033) (11,472) (1,964)
Fixed charges . . . . . . . . . . . . . . . . . . 44,665 49,640 52,196 55,171 56,061
------- ------- ------- ------- -------
Earnings. . . . . . . . . . . . . . . . . . . . 140,393 192,337 166,792 205,549 188,362
------- ------- ------- ------- -------
Fixed Charges:
Interest Charges per statements of income . . . . 42,856 47,496 49,833 52,680 53,663
Add:
Interest income (1) . . . . . . . . . . . . . . - - 4 98 251
One-third of rentals charged to
operating expense (2). . . . . . . . . . . . . 1,809 2,144 2,359 2,393 2,147
------- ------- ------- ------- -------
Fixed charges . . . . . . . . . . . . . . . . $ 44,665 $ 49,640 $ 52,196 $ 55,171 $ 56,061
------- ------- ------- ------- -------
Ratio of Earnings to Fixed Charges . . . . . . . . . . 3.14 3.87 3.20 3.73 3.36
------- ------- ------- ------- -------
------- ------- ------- ------- -------
<FN>
NOTES:
(1) Interest income earned on pollution control revenue bond proceeds held and invested by trustees--netted against interest
charges above.
(2) In the Company's opinion, one-third of rentals represents a reasonable approximation of the interest factor.
</TABLE>
<PAGE>
EXHIBIT 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
by reference of our report dated January 30, 1995, included in this Form 10-K,
into the Company's previously filed Registration Statement No. 33-13427.
Louisville, Kentucky Arthur Andersen LLP
March 24, 1995
<PAGE>
POWER OF ATTORNEY
WHEREAS, LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation, is to
file with the Securities and Exchange Commission, under the provisions of the
Securities Act of 1934, as amended, its Annual Report on Form 10-K for the year
ended December 31, 1994 (the 1994 Form 10-K); and
WHEREAS, each of the undersigned holds the office or offices in LOUISVILLE
GAS AND ELECTRIC COMPANY set opposite his name;
NOW, THEREFORE, each of the undersigned hereby constitutes and appoints
ROGER W. HALE and M. L. FOWLER, and each of them, individually, his attorney,
with full power to act for him and in his name, place, and stead, to sign his
name in the capacity or capacities set forth below to the 1994 Form 10-K and to
any and all amendments to such 1994 Form 10-K and hereby ratifies and confirms
all that said attorney may or shall lawfully do or cause to be done by virtue
hereof.
IN WITNESS WHEREOF, the undersigned have hereunto set their hands and seals
this 1st day of March 1995.
Roger W. Hale J. David Grissom
- ------------------------------------- ----------------------------------
Roger W. Hale, Principal J. David Grissom, Director
Executive Officer and Director
William C. Ballard, Jr. David B. Lewis
- ------------------------------------ ----------------------------------
William C. Ballard, Jr., Director David B. Lewis, Director
Owsley Brown II Charles A. Markel III
- ------------------------------------ ----------------------------------
Owsley Brown II, Director Charles A. Markel III, Principal
Financial Officer
S. Gordon Dabney Anne H. McNamara
- ------------------------------------ ----------------------------------
S. Gordon Dabney, Director Anne H. McNamara, Director
M. L. Fowler T. Ballard Morton, Jr.
- ------------------------------------ ----------------------------------
M. L. Fowler, Principal T. Ballard Morton, Jr., Director
Accounting Officer
Gene P. Gardner Dr. Donald C. Swain
- ------------------------------------ ----------------------------------
Gene P. Gardner, Director Dr. Donald C. Swain, Director
STATE OF KENTUCKY )
) ss.
COUNTY OF JEFFERSON )
On this 1st day of March 1995, before me, Kathryn M. Carpenter, a Notary
Public, State of Kentucky at Large, personally appeared the above named
directors and officers of LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky
corporation, and known to me to be the persons whose names are subscribed to the
foregoing instrument, and they severally acknowledged to me that they executed
the same as their own free act and deed.
IN WITNESS WHEREOF, I have hereunto set my hand and affixed my official
seal on the date above set forth.
My Commission expires: Kathryn M. Carpenter
----------------------------------
November 2, 1996 Kathryn M. Carpenter, Notary Public
State of Kentucky at Large
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> DEC-31-1994
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,656,034
<OTHER-PROPERTY-AND-INVEST> 50,681
<TOTAL-CURRENT-ASSETS> 207,971
<TOTAL-DEFERRED-CHARGES> 51,904
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 1,966,590
<COMMON> 424,334<F1>
<CAPITAL-SURPLUS-PAID-IN> (1,751)<F2>
<RETAINED-EARNINGS> 193,895
<TOTAL-COMMON-STOCKHOLDERS-EQ> 616,478
0
116,716
<LONG-TERM-DEBT-NET> 662,862
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 0
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 570,534
<TOT-CAPITALIZATION-AND-LIAB> 1,966,590
<GROSS-OPERATING-REVENUE> 759,075
<INCOME-TAX-EXPENSE> 39,922
<OTHER-OPERATING-EXPENSES> 608,113
<TOTAL-OPERATING-EXPENSES> 648,035
<OPERATING-INCOME-LOSS> 111,040
<OTHER-INCOME-NET> (9,864)<F3>
<INCOME-BEFORE-INTEREST-EXPEN> 101,176
<TOTAL-INTEREST-EXPENSE> 42,856
<NET-INCOME> 58,320
5,828
<EARNINGS-AVAILABLE-FOR-COMM> 52,492
<COMMON-STOCK-DIVIDENDS> 53,500
<TOTAL-INTEREST-ON-BONDS> 41,357
<CASH-FLOW-OPERATIONS> 180,881
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
<FN>
<F1>Includes Common Stock Expense of $836.
<F2>Represents Unrealized Loss on Marketable
Securities, Net of Income Taxes.
<F3>Includes ($3,369) for Cumulative Effect of Change
in Accounting for Post-Employment Benefits, Net of
Income Taxes.
</FN>
</TABLE>
