<PAGE>
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
---------------------------
FORM 10-K
[x] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934 (FEE REQUIRED)
For the fiscal year ended DECEMBER 31, 1995
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
Commission File No. 2-26720
--------------------------------------------------------
LOUISVILLE GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
--------------------------------------------------------
KENTUCKY 61-0264150
(State or other jurisdiction of (I.R.S.Employer
incorporation or organization) Identification No.)
220 W. MAIN STREET
P. O. BOX 32010 (502) 627-2000
LOUISVILLE, KENTUCKY 40232 (Registrant's telephone
(Address of principal executive offices) number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Name of each exchange on
Title of each class which registered
------------------- ------------------------
First Mortgage Bonds, New York Stock Exchange
Series due July 1, 2002, 7 1/2%
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
5% Cumulative Preferred Stock, $25 Par Value
$5.875 Cumulative Preferred Stock, Without Par Value
Auction Rate Series A Preferred Stock, Without Par Value
(Title of class)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes /X/ . No .
----- ----
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
---
As of February 29, 1996, the aggregate market value of the registrant's voting
stock held by non-affiliates was $16,882,700 and the number of outstanding
shares of the registrant's common stock, without par value, was 21,294,223 all
of which were held by LG&E Energy Corp.
DOCUMENTS INCORPORATED BY REFERENCE
The proxy statement of Louisville Gas and Electric Company filed with the
Commission on March 13, 1996, is incorporated by reference into Part III of this
Form 10-K.
<PAGE>
TABLE OF CONTENTS
PART I PAGE
Item 1. Business................................................... 1
General.................................................. 1
Electric Operations...................................... 4
Gas Operations........................................... 6
Regulation and Rates..................................... 7
Construction Program and Financing....................... 8
Coal Supply.............................................. 9
Gas Supply............................................... 10
Environmental Matters.................................... 11
Labor Relations.......................................... 11
Employees................................................ 11
Item 2. Properties................................................. 12
Item 3. Legal Proceedings.......................................... 13
Item 4. Submission of Matters to a Vote of Security Holders........ 14
Executive Officers of the Company................................... 14
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters...................................... 16
Item 6. Selected Financial Data.................................... 16
Item 7. Management's Discussion and Analysis of Results of
Operations and Financial Condition....................... 16
Item 8. Financial Statements and Supplementary Data................ 26
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure................................. 49
PART III
Item 10. Directors and Executive Officers of the Registrant (a)..... 50
Item 11. Executive Compensation (a)................................. 50
Item 12. Security Ownership of Certain Beneficial Owners
and Management (a)....................................... 50
Item 13. Certain Relationships and Related Transactions (a)......... 50
PART IV
Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K.................................. 50
Signatures.......................................................... 67
Exhibit 12 - Computation of Ratio of Earnings to Fixed Charges...... 68
Exhibit 23 - Consent of Independent Public Accountants.............. 69
(a) Incorporated by reference.
<PAGE>
PART I
ITEM 1. BUSINESS.
General
Incorporated July 2, 1913, Louisville Gas and Electric Company (the
Company) is an operating public utility that supplies natural gas to
approximately 272,000 customers and electricity to approximately 346,000
customers in Louisville and adjacent areas in Kentucky. The Company's service
area covers approximately 700 square miles in 17 counties and has an estimated
population of 800,000. Included in this area is the Fort Knox Military
Reservation, to which the Company transports gas and provides electric service,
but which maintains its own distribution systems. The Company also provides gas
service in limited additional areas. The Company's coal-fired electric
generating plants, which are all equipped with systems to remove sulfur dioxide,
produce most of the Company's electricity; the remainder is generated by a
hydroelectric power plant and combustion turbines. Underground natural gas
storage fields help the Company provide economical and reliable gas service to
customers.
In August 1990, the Company and LG&E Energy Corp. (Energy Corp.)
implemented a corporate reorganization pursuant to a mandatory share exchange
whereby each share of outstanding common stock of the Company was exchanged on a
share-for-share basis for the common stock of Energy Corp. The reorganization
created a corporate structure that gives the holding company the flexibility to
take advantage of opportunities to expand into other businesses while insulating
the Company's utility customers and senior security holders from any risks
associated with such businesses. The Company's preferred stock and first
mortgage bonds were not exchanged and remained securities of the Company.
The Company's Trimble County Unit 1 (Trimble County or the Unit), a
495-megawatt, coal-fired electric generating unit, which the Company began
constructing in 1979, was placed in commercial operation on December 23, 1990.
The Unit had been subject to numerous reviews by the Public Service Commission
of Kentucky (Kentucky Commission or Commission). On December 8, 1995, the
Commission approved a settlement agreement filed by the Company and all
intervenors in the Trimble County proceedings, including various consumer
interest groups and government agencies, that in effect, resolves all of the
regulatory and legal issues related to the appropriate ratemaking treatment to
exclude 25% of the Trimble County costs from customer rates. The Company has
sold a 25% ownership interest in the Unit. For a more detailed discussion of
the proceedings relating to Trimble County and the sale of 25% of the Unit, see
Electric Operations and Notes 14 and 15 of Notes to Financial Statements under
Item 8.
The Clean Air Act Amendments of 1990 (the Act) impose stringent limits on
emissions of sulfur dioxide and nitrogen oxides by electric utility generating
plants. All of the Company's coal-fired boilers are equipped with sulfur
dioxide "scrubbers" and already achieve the final sulfur dioxide emission rates
required by the year 2000 under the legislation. However, as part of its
ongoing construction program, the Company has spent $22 million to date and
anticipates incurring capital expenditures of approximately $8 million in 1996
for remedial measures necessary to meet the Act's requirements for nitrogen
oxides. The overall financial impact of the legislation on the Company is
expected to be minimal. The Company is well-positioned in the market to be a
"clean" power provider without the large capital expenditures that are expected
to be incurred by many other utilities. For a more detailed discussion of the
Clean Air Act and other environmental issues, see
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Environmental Matters under this Item, Item 3, Item 7, and Note 13 of the Notes
to Financial Statements under Item 8.
The Energy Policy Act of 1992 is designed to give utilities a wider choice
of sources for their electrical supply than previously available, while creating
generating supply options that did not exist under the old law. In passing this
legislation, Congress also anticipated that greater competition among electric
supply options should result in lower consumer rates.
Pursuant to the Energy Policy Act, the Federal Energy Regulatory Commission
(FERC) earlier this year issued a Notice of Proposed Rulemaking on Open Access
Non-discriminatory Transmission Services and a Supplemental Notice of Proposed
Rulemaking on Stranded Investment (collectively, the Mega-NOPR). The Mega-NOPR
is intended, among other things, to create a vigorous wholesale electric market
by requiring transmission providers to offer open access to their transmission
systems. The Company is supportive of proposals to increase competition at all
levels of the electric power market and intends to pursue opportunities created
by a more competitive market.
The Company has taken many steps to prepare for the expected increase in
competition in its industry, including a reduction in the number of employees;
aggressive cost cutting; a write-off of previously deferred expenses; an
increase in focus on commercial and industrial customers; an increase in
employee involvement and training; a major realignment and formation of new
business units, and a modification of its organizational structure.
Effective December 15, 1995, LG&E Energy Corp. modified its organizational
structure. Changes are designed to facilitate decision making, improve response
to customers and better align operating units with the changing competitive
marketplace. Four operating divisions were established:
Distribution Services Division - which includes the distribution
resources of the Company, is responsible for expanding and developing
the distribution businesses and investing in enhanced service offerings
behind the customer's meter.
Gas Marketing Division - primarily consists of the businesses of LG&E
Natural Inc. (a subsidiary of LG&E Energy Corp.), which markets gas
throughout the United States and Canada.
Power Marketing Division - includes LG&E Power Marketing Inc. (LPM), is
responsible for project development and the marketing and sale of
wholesale power throughout the United States.
Power Generation Division - which includes the generation resources of
the Company, LG&E Power Inc. and LG&E International Inc., has
responsibility for all utility and non-utility power plant operations,
asset management, and development functions both domestically and
internationally.
The Company's wholesale power will continue to be marketed and brokered by
LG&E Power Marketing Inc. (LPM), a wholly-owned subsidiary of LG&E Energy Corp.
LPM was among the first utility-affiliated marketers in the country to secure
FERC approval to sell power at market-based rates and engage in wholesale power
marketing activities. During 1995, its first full year of operations, LPM sold
or brokered 1.8 million megawatt-hours of power in 30 states. This
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volume of activity placed LPM among the five largest marketers of wholesale
energy in 1995 and the largest seller affiliated with a regulated electric
utility. LPM is predicting that the market for electric energy will expand and
its revenues and contributions to corporate income will increase in future
years.
The realignment does not affect LG&E Energy Corp.'s legal structure,
regulation of the Company by the Commission or LG&E Energy Corp.'s status as an
exempt holding company.
By using gas storage fields strategically, the Company can buy gas when
prices are low, store it, and retrieve the gas when demand is high. Accessing
least cost gas was made easier in November 1993 when FERC's Order No. 636 went
into effect. Previously, the Company and other utilities purchased most of
their gas services from pipeline companies. The order "unbundled" gas services,
allowing utilities to purchase gas, transportation, and storage services
separately from many different sources. Currently, the Company buys
competitively priced gas from several large producers under contracts of varying
duration. By purchasing from multiple suppliers, and storing any excess gas,
the Company is able to secure favorably priced gas for its customers. Without
storage capacity, the Company would be forced to buy additional gas when
customer demand increases, which is usually when the price is highest. See FERC
Order No. 636 under Item 7 for a further discussion.
During the last quarter of 1995, the Company negotiated a five-year
transportation agreement with Tennessee Gas Pipeline Company (Tennessee) to
become the Company's second natural gas pipeline transporter. The agreement
with Tennessee becomes effective November 1, 1996. For many years, Texas Gas
Transmission Corporation (Texas Gas) has been the sole provider of gas transport
services to the Company. For further discussion, see Gas Supply.
On July 31, 1995, Vantage Consulting, Inc. released its report on the
Kentucky Commission's management audit of the Company. This comprehensive
audit, which began in September 1994, included more than 300 interviews and over
875 requests for information. This was the second management audit of the
Company mandated by the Kentucky Commission, the first being completed in 1986.
The overall audit findings were very favorable and recognized that the Company
has become an innovative industry leader that has implemented many performance
improvements to lower costs, improve efficiency, prepare for increased
competition, and increase its focus on customer satisfaction. For further
discussion, see Regulation and Rates.
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For the year ended December 31, 1995, 75% of total operating revenues was
derived from electric operations and 25% from gas operations. Electric and gas
operating revenues and the percentages by classes of service on a combined basis
for this period were as follows:
<TABLE>
<CAPTION>
(Thousands of $)
--------------------------------------
Electric Gas Combined % Combined
-------- --- -------- ----------
<S> <C> <C> <C> <C>
Residential.......................... $201,357 $107,762 $309,119 44%
Commercial........................... 160,571 38,161 198,732 29
Industrial........................... 110,800 17,430 128,230 18
Public authorities................... 53,861 8,679 62,540 9
-------- -------- -------- ----
Total service revenues............... 526,589 172,032 698,621 100%
Refund - Trimble County Settlement (28,300) (a) - (28,300) ----
-------- -------- -------- ----
Total-ultimate consumers 498,289 172,032 670,321
Sales for resale..................... 37,471 - 37,471
Gas transportation-net............... - 7,821 7,821
Miscellaneous........................ 6,577 1,273 7,850
-------- -------- --------
Total............................. $542,337 $181,126 $723,463
-------- -------- --------
-------- -------- --------
</TABLE>
(a) See Note 14 of Notes to Financial Statements under Item 8.
See Note 16 of Notes to Financial Statements under Item 8 for financial
information concerning segments of business for the three years ended
December 31, 1995.
Electric Operations
The sources of electric operating revenues and the volumes of sales for the
three years ended December 31, 1995, were as follows:
<TABLE>
<CAPTION>
1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
ELECTRIC OPERATING REVENUES
(Thousands of $):
Residential........................... $201,357 $194,145 $195,273
Small commercial and industrial....... 73,074 70,916 70,106
Large commercial...................... 87,497 84,931 84,231
Large industrial...................... 110,800 108,004 104,506
Public authorities.................... 53,861 53,191 52,183
Refund - Trimble County Settlement (28,300) - -
-------- -------- --------
Total-ultimate consumers........... 498,289 511,187 506,299
Sales for resale...................... 37,471 42,720 58,959
Miscellaneous......................... 6,577 5,039 4,952
-------- -------- --------
Total.............................. $542,337 $558,946 $570,210
-------- -------- --------
-------- -------- --------
ELECTRIC SALES (Thousands of kwh):
Residential........................... 3,415,225 3,204,330 3,230,463
Small commercial and industrial....... 1,112,130 1,073,152 1,056,977
Large commercial...................... 1,802,035 1,729,668 1,696,686
Large industrial...................... 3,023,543 2,874,411 2,736,269
Public authorities.................... 1,113,063 1,085,741 1,053,928
---------- ---------- ----------
Total-ultimate consumers........... 10,465,996 9,967,302 9,774,323
Sales for resale...................... 2,000,607 2,315,311 3,299,510
---------- ---------- ----------
Total.......................... 12,466,603 12,282,613 13,073,833
---------- ---------- ----------
---------- ---------- ----------
</TABLE>
At December 31, 1995, the Company had 346,099 electric customers.
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The Company uses efficient coal-fired boilers that are fully equipped with
sulfur dioxide removal systems to generate electricity. The Company's system
wide emission rate for sulfur dioxide in 1995 was approximately .85 lbs./MMBtu
of heat input, which is significantly below the Phase II limit of 1.2 lbs./MMBtu
established by the Clean Air Act Amendments for the year 2000.
On Thursday, August 17, 1995, the Company set a record local peak load
of 2,357 Mw, when the temperature at the time of peak reached 94 DEG. F
(average for the day was 86 DEG. F). The 1994 maximum local peak load of
2,219 Mw occurred on Wednesday, June 15, when the temperature at time of peak
was 95 DEG. F (average for the day was 85 DEG. F). The record system peak of
3,223 Mw (which included purchases from and short-term sales to other
electric utilities) occurred on Thursday, May 30, 1991.
The Company's current reserve margin is 16%. At February 29, 1996, the
Company owned steam and combustion turbine generating facilities with a
capacity of 2,512 Mw and an 80 Mw hydroelectric facility on the Ohio River. See
Item 2, Properties.
The Company is a participating owner with 14 other electric utilities of
Ohio Valley Electric Corporation whose primary customer is the Portsmouth Area
uranium-enrichment complex of the U.S. Department of Energy at Piketon, Ohio.
The Company has direct interconnections with 11 utility companies in the area
and has agreements with each interconnected utility for the purchase and sale of
capacity and energy. The Company also has agreements with an increasing number
of entities throughout the United States for the purchase and/or sale of
capacity and energy and for the utilization of their bulk transmission system.
On February 28, 1991, the Company sold a 12.12% ownership interest in
Trimble County Unit 1 to the Illinois Municipal Electric Agency (IMEA), based in
Springfield, Illinois, which is an agency of 30 municipalities that own and
operate their own electric systems. On February 1, 1993, the Indiana Municipal
Power Agency (IMPA), based in Carmel, Indiana, purchased a 12.88% interest in
the Trimble County Unit. IMPA is composed of 31 municipalities that have joined
together to meet their long-term electric power needs. Both IMEA and IMPA pay
their proportionate share for operation and maintenance expenses of the Unit and
for fuel and reactant used. They are also responsible for their proportionate
share of incremental capital assets acquired.
Electric and magnetic fields (sometimes referred to as EMF) surround
electric wires or conductors of electricity such as electrical tools, household
wiring and appliances, and high voltage electric transmission lines such as
those owned by the Company. Certain studies have suggested a possible
association between electric and magnetic fields and adverse health effects.
The Electric Power Research Institute, of which the Company is a participating
member, has expended approximately $83 million since 1987 in its investigation
and research with regard to possible health effects posed by exposure to
electric and magnetic fields.
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<PAGE>
Gas Operations
The sources of gas operating revenues and the volumes of sales for the
three years ended December 31, 1995, were as follows:
<TABLE>
<CAPTION>
1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
GAS OPERATING REVENUES
(Thousands of $):
Residential........................... $107,762 $110,553 $112,508
Commercial............................ 38,161 40,474 43,568
Industrial............................ 17,430 27,956 28,310
Public authorities.................... 8,679 12,930 13,846
-------- -------- --------
Total-ultimate consumers........... 172,032 191,913 198,232
Gas transportation-net................ 7,821 6,759 5,147
Miscellaneous......................... 1,273 1,457 1,536
-------- -------- --------
Total.............................. $181,126 $200,129 $204,915
-------- -------- --------
-------- -------- --------
GAS SALES (Millions of cu. ft.):
Residential..................... 24,242 22,935 24,330
Commercial...................... 9,885 9,450 10,308
Industrial...................... 5,188 7,505 7,817
Public authorities.............. 2,423 3,268 3,515
-------- -------- --------
Total-ultimate consumers....... 41,738 43,158 45,970
Gas transported................. 12,241 6,854 5,249
-------- -------- --------
Total.......................... 53,979 50,012 51,219
-------- -------- --------
-------- -------- --------
</TABLE>
At December 31, 1995, the Company had 272,135 gas customers.
The Company has underground natural gas storage fields that help provide
economical and reliable gas service to ultimate consumers.
Reflecting the changing nature of the gas business, a number of industrial
customers purchase their natural gas requirements directly from alternate
suppliers for delivery through the Company's distribution system. Generally,
transportation of natural gas for the Company's customers does not have an
adverse effect on earnings because of the offsetting decrease in gas supply
expenses. Transportation rates are designed to make the Company economically
indifferent as to whether gas is sold or merely transported.
The all-time maximum day gas sendout of 545,000 Mcf occurred on Sunday,
January 20, 1985, when the average temperature for the day was -11 DEG. F.
During 1995, the maximum day gas sendout was 454,000 Mcf, occurring on
December 9, when the average temperature for the day was 9 DEG. F. Supply on
that day consisted of 208,000 Mcf from purchases, 199,000 Mcf delivered from
underground storage, and 47,000 Mcf transported for industrial customers.
For further discussion, see Gas Supply.
Under FERC Order No. 636, pipelines may recover costs associated with the
transition to and implementation of this order from pipeline customers,
including the Company. During 1995, the Company paid and began recovering from
its customers approximately $4.8 million in transition costs under Order No.
636. It is estimated that about $1.4 million in additional transition costs
will be incurred by the Company during 1996 and about $1.3 million in 1997, and
these costs are also expected to be recovered from customers. See Note 13 of
Notes to Financial Statements under Item 8 for further discussion of FERC Order
No. 636.
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Regulation and Rates
The Kentucky Commission has regulatory jurisdiction over the rates and
service of the Company and over the issuance of certain of its securities. The
Company is a "public utility" as defined in the Federal Power Act, and is
subject to the jurisdiction of the Department of Energy and the FERC with
respect to the matters covered in such Act, including the sale of electric
energy at wholesale in interstate commerce. In addition, the FERC has sole
jurisdiction over the issuance by the Company of short-term securities.
For a discussion of current regulatory matters, see Rates and Regulation
under Item 7 and Notes 2 and 14 of Notes to Financial Statements under Item 8.
Increases and decreases in the cost of fuel for electric generation are
reflected in the rates charged to all of the Company's electric customers by
means of the Company's fuel adjustment clause. The Kentucky Commission requires
public hearings at six-month intervals to examine past fuel adjustments, and at
two-year intervals for the purpose of additional examination and transfer of the
then current fuel adjustment charge or credit to the base charges. The
Commission also requires that electric utilities, including the Company, file
certain documents relating to fuel procurement and the purchase of power and
energy from other utilities.
The Company's gas rates contain a gas supply clause (GSC), whereby
increases or decreases in the cost of gas supply are reflected in the Company's
rates, subject to approval of the Kentucky Commission. The GSC procedure
prescribed by order of the Commission provides for quarterly rate adjustments to
reflect the expected cost of gas supply in that quarter. In addition, the GSC
contains a mechanism whereby any over- or under-recoveries of gas supply cost
from prior quarters will be refunded to or recovered from customers through the
adjustment factor determined for subsequent quarters.
On December 8, 1995, the Commission approved a settlement agreement filed
by the Company and all intervenors in the Trimble County proceedings, including
various consumer interest groups and government agencies, that, in effect,
resolves all the regulatory and legal issues related to the appropriate
ratemaking treatment to exclude 25% of the Trimble County plant costs from
customer rates. See Note 14 of Notes to Financial Statements under Item 8 for
further discussion of this matter.
On July 31, 1995, Vantage Consulting, Inc. released its report on the
Kentucky Commission's management audit of the Company. This comprehensive
audit, which began in September 1994, included more than 300 interviews and over
875 requests for information. This was the second management audit of the
Company mandated by the Kentucky Commission, the first being completed in 1986.
The overall audit findings were very favorable and recognized that the
Company has become an innovative industry leader that has implemented many
performance improvements to lower costs, improve efficiency, prepare for
increased competition, and increase its focus on customer satisfaction. The
audit report identified additional improvement opportunities and contained a
series of recommendations which should assist the Company with its future plans.
It is estimated that implementation of the audit recommendations could provide
the Company with as much as $11
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million in annual gross savings. However, incremental costs will be incurred to
achieve the full benefits of the recommendations and the ultimate savings will
be realized over the long-term.
On October 7, 1994, the Company filed an application with the Kentucky
Commission in which it requested approval of an environmental cost recovery
surcharge to recover certain costs required to comply with the Federal Clean Air
Act, as amended, and those federal, state, and local environmental requirements
which apply to coal combustion wastes and by-products from facilities utilized
for production of energy from coal. On April 6, 1995, the Commission approved,
with modifications, an environmental cost recovery surcharge that increased
electric revenues by $3.2 million in 1995 and will increase revenues by an
estimated $5.7 million in 1996. The Company, the Kentucky Attorney General, and
the Kentucky Industrial Utility Customers have filed appeals on certain issues
included in the April 6 order. See Rates and Regulation under Item 7 for a
further discussion of the surcharge.
On January 1, 1994, the Company implemented a Commission approved demand
side management (DSM) program. The program contains a rate mechanism that
provides for the recovery of DSM program costs, allows the Company to recover
revenues due to lost sales associated with the DSM programs and provides the
Company an incentive for implementing DSM programs. See Rates and Regulation
under Item 7 for a further discussion of DSM.
As part of the corporate reorganization whereby the Company became the
subsidiary of LG&E Energy Corp., the Company obtained the approval of the
Kentucky Commission. The order of the Kentucky Commission authorizing the
Company to reorganize into a holding company structure contains certain
provisions, which, among other things, ensure the Kentucky Commission access to
books and records of Energy Corp. and its affiliates which relate to
transactions with the Company; require Energy Corp. and its subsidiaries to
employ accounting and other procedures and controls to protect against
subsidization of non-utility activities by the Company's customers; and preclude
the Company from guaranteeing any obligations of Energy Corp. without prior
written consent from the Kentucky Commission. In addition, such order provides
that the Company's Board of Directors has the responsibility to use its dividend
policy consistent with preserving the financial strength of the Company and that
the Kentucky Commission, through its authority over the Company's capital
structure, can protect the Company's ratepayers from the financial effects
resulting from non-utility activities.
Construction Program and Financing
The Company's construction program is designed to assure that there will be
adequate capacity and reliability to meet the electric and gas needs of its
service area. These needs are continually being reassessed and appropriate
revisions are made, when necessary, in construction schedules. The Company's
estimates of its construction expenditures can vary substantially due to
numerous items beyond the Company's control, such as changes in rates, economic
conditions, construction costs, and new environmental or other governmental
laws and regulations.
During the five years ended December 31, 1995, gross property additions
amounted to $476 million. Internally generated funds for the five year period
were sufficient to provide for all of these gross additions. The gross
additions during this period amounted to approximately 18% of total utility
plant at December 31, 1995, and consisted of $356 million for electric
properties and $120
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<PAGE>
million for gas properties. Gross retirements during the same period were $82
million, consisting of $67 million for electric properties and $15 million for
gas properties.
At December 31, 1995, the Company's embedded cost of long-term debt was
6.3% and its ratio of earnings to fixed charges was 3.99. See Exhibit 12. For
a further discussion of construction expenditures and financing, see Liquidity
and Capital Resources under Item 7.
Coal Supply
Over 90% of the Company's present electric generating capacity is
coal-fired, the remainder being made up of a hydroelectric plant and combustion
turbine peaking units fueled by natural gas and oil. Coal will be the
predominant fuel used by the Company in the foreseeable future, with natural gas
and oil being used for peaking capacity and flame stabilization in coal-fired
boilers or in emergencies. The Company has no nuclear generating units and has
no plans to build any in the foreseeable future.
In January 1996, the Company bought out the last year of its three year
contract with Andalex Resources, Inc. at a cost of $3.5 million. The Company
has filed an application with the Kentucky Commission to recover the cost of the
buyout through the fuel adjustment clause. As a result of the buyout of the
coal contract, the Company's customers will realize a net savings in excess of
$1 million.
The Company has entered into coal supply agreements with various suppliers
for coal deliveries for 1996 and beyond. The Company normally augments its coal
supply agreements with spot market purchases which, during 1995, were about 10%
of total purchases. The Company has a coal inventory policy, which is in
compliance with the Kentucky Commission's directives and which the Company
believes provides adequate protection under most contingencies. The Company had
on hand at December 31, 1995, a coal inventory of approximately 600,000 tons, or
a 35 day supply.
The Company expects, for the foreseeable future, to continue purchasing
most of its coal from western Kentucky and southwest Indiana, which has a sulfur
content in the 2%-4.5% range. The abundant supply of this relatively low priced
coal, combined with present and future desulfurization technologies, is expected
to enable the Company to continue to provide adequate electric service in a
manner acceptable under existing environmental laws and regulations.
Coal for the Company's Mill Creek plant is delivered by rail and barge.
Deliveries to the Cane Run and Trimble County plants are by rail and barge,
respectively.
The average delivered cost of coal purchased by the Company, per ton and
per million Btu, for the periods shown were as follows:
<TABLE>
<CAPTION>
1995 1994 1993
------ ------ ------
<S> <C> <C> <C>
Per ton........................... $23.68 $25.27 $26.58
Per million Btu................... 1.04 1.10 1.14
</TABLE>
This downward trend in the delivered cost of coal is expected to continue
through 1996.
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Gas Supply
Prior to the implementation of FERC Order No. 636, the Company had
purchased natural gas and pipeline transportation services from Texas Gas
Transmission Corporation (Texas Gas). The Company now purchases only
transportation services from Texas Gas and purchases natural gas from many other
sources under contracts for varying periods of time. See Management's
Discussion and Analysis, Future Outlook, under Item 7.
Under Order No. 636, pipelines may recover costs associated with the
transition to and implementation of this order from pipeline customers,
including the Company. The Commission issued an order, based on proceedings
that were held to investigate the impact of Order No. 636 on utilities and
ratepayers in Kentucky, providing that transition costs assessed on utilities by
the pipelines, which are clearly identifiable as being related to the cost of
the commodity itself, are appropriate to be recovered from customers through the
gas supply clause. During 1995, the Company paid Texas Gas and began recovering
from its customers approximately $4.8 million in transition costs. It is
estimated that about $1.4 million in additional transition costs will be
incurred by the Company during 1996 and about $1.3 million in 1997, and these
costs are also expected to be recovered from customers. These transition costs
are billed by Texas Gas pursuant to orders issued by FERC in transition cost
regulatory proceedings in which the Company is a party. Pursuant to these FERC
orders, no additional transition costs are expected to be billed after 1997.
During 1995, the Company participated in several regulatory proceedings at
FERC. These proceedings resolved, subject to final FERC approval, issues in
Texas Gas' rate case as well as transition cost issues from the implementation
of Order No. 636 by Texas Gas. The Company does not expect significant
regulatory initiatives by Texas Gas at FERC during 1996.
The Company transports on the Texas Gas System under No-Notice Service
(NNS) and Firm Transportation (FT) rates. In 1995, the Company made two
important modifications to its transportation agreements with Texas Gas. During
the winter months, the Company has 184,900 MMBtu (180,390 mcf) per day in NNS.
During 1995, the Company's summer NNS level was reduced from 135,000 MMBtu
(131,708 Mcf) per day to 111,000 MMBtu (108,293 Mcf), and 24,000 MMBtu (23,415
Mcf) per day was converted to FT service. Each of these NNS and FT agreements
with Texas Gas expire in equal portions in 1998, 2000, and 2001. Each agreement
includes a unilateral five year roll-over provision exercisable at the Company's
option.
The Company also has a transportation agreement with Texas Gas which
provides for 30,000 MMBtu (29,268 Mcf) per day in FT service throughout the
year. The primary term of this FT agreement expired October 31, 1995, subject
to a year-to-year termination by either party. During 1995, the Company
provided the required one year prior written notice to terminate this FT
agreement effective November 1, 1996.
During the last quarter of 1995, the Company negotiated a five year
transportation agreement with Tennessee Gas Pipeline Company (Tennessee) for
30,000 MMBtu (29,268 Mcf) per day in Firm Transportation service under
Tennessee's Rate FT-A. This agreement with Tennessee becomes effective November
1, 1996. For many years, Texas Gas had been the sole provider of gas transport
services to the Company.
The Company also has a portfolio of supply arrangements with various
suppliers in order to meet its firm sales obligations. These gas supply
arrangements include pricing provisions which are
-10-
<PAGE>
market-responsive. These firm supplies, in tandem with pipeline transportation
services, provide the reliability and flexibility necessary to serve the
Company's customers.
The Company operates five underground gas storage fields with a current
working gas capacity of 14.6 million Mcf. Gas is purchased and injected into
storage during the summer season and is then withdrawn to supplement pipeline
supplies to meet the gas-system load requirements during the winter heating
season.
The estimated maximum deliverability from storage during the early part of
the 1994-1995 heating season was approximately 373,000 Mcf per day.
Deliverability decreases during the latter portion of the heating season as the
storage inventory is reduced by seasonal withdrawals.
The average cost per Mcf of natural gas purchased by the Company was $2.62
in 1995, $2.78 in 1994, and $2.91 in 1993.
Environmental Matters
Protection of the environment is a major priority for the Company. The
Company engages in a variety of activities within the jurisdiction of federal,
state, and local regulatory agencies. Those agencies have issued the Company
permits for various activities subject to air quality, water quality, and waste
management laws and regulations. For the five year period ending with 1995,
expenditures for pollution control facilities represented $90 million or 19% of
total construction expenditures. The cost of operating and maintaining
scrubber-related facilities amounted to $21 million in 1995 and $22 million in
1994. The Company's anticipated capital expenditures for 1996 to comply with
environmental laws are approximately $8 million. See Note 13 of Notes to
Financial Statements under Item 8 for a discussion of specific environmental
proceedings affecting the Company.
Labor Relations
On December 8, 1995, members of the International Brotherhood of Electrical
Workers Local 2100 ratified a new three year collective bargaining agreement
with the Company, which covers approximately 1,600 employees. The contract
provides wage and employment protection for employees participating in the
Company's continuous improvement initiative, greater workforce flexibility to
help the Company respond to growing competition, and improved retirement
benefits.
Employees
The Company had 2,594 full-time employees at December 31, 1995.
-11-
<PAGE>
ITEM 2. PROPERTIES.
The Company's power generating system consists of the coal-fired units
operated at its three steam generating stations. Combustion turbines supplement
the system during peak or emergency periods. At February 29, 1996, the Company
owned the following electric generating stations:
<TABLE>
<CAPTION>
Year in
Service Capability Rating (Kw)
------- ----------------------
<S> <C> <C> <C>
Steam Stations:
Mill Creek-Kosmosdale, Ky.
Unit 1........................................... 1972 303,000
Unit 2........................................... 1974 301,000
Unit 3........................................... 1978 386,000
Unit 4........................................... 1982 480,000 1,470,000
-------
Cane Run-near Louisville, Ky.
Unit 4........................................... 1962 155,000
Unit 5........................................... 1966 168,000
Unit 6........................................... 1969 240,000 563,000
-------
Trimble County-Bedford, Ky.
Unit 1........................................... 1990 371,000 (a)
Combustion Turbine Generators (Peaking capability):
Zorn............................................... 1969 16,000
Paddy's Run........................................ 1968 43,000
Cane Run........................................... 1968 16,000
Waterside.......................................... 1964 33,000 108,000
------- ---------
2,512,000
---------
---------
</TABLE>
(a) Amount shown represents the Company's 75% interest in the Unit. See
Note 15 of Notes to Financial Statements, Jointly Owned Electric Utility
Plant, under Item 8 for a discussion of the sale of 25% of the Unit to
IMEA and IMPA. The Company is responsible for operation of the Unit and
is reimbursed by IMEA and IMPA for expenditures related to the Unit
based on their proportionate share of ownership interest.
The Company also owns an 80 Mw hydroelectric generating station located in
Louisville, operated under license issued by the FERC.
At December 31, 1995, the Company's electric transmission system included
21 substations with a total capacity of approximately 11,026,897 Kva and
approximately 651 structure miles of lines. The electric distribution system
included 82 substations with a total capacity of approximately 3,193,127 Kva,
3,507 structure miles of overhead lines, 233 miles of underground conduit, and
5,380 miles of underground conductors.
The Company's gas transmission system includes 177 miles of transmission
mains, and the gas distribution system includes 3,466 miles of distribution
mains.
The Company operates underground gas storage facilities with a current
working gas capacity of approximately 14.6 million Mcf. See Gas Supply under
Item 1.
In 1990, the Company entered into an operating lease for its corporate
office building located in downtown Louisville, Kentucky. The lease is for a
period of 15 years and is scheduled to expire in June 2005.
-12-
<PAGE>
Other properties owned by the Company include office buildings, service
centers, warehouses, garages, and other structures and equipment, the use of
which is common to both the electric and gas departments.
The trust indenture securing the Company's First Mortgage Bonds constitutes
a direct first mortgage lien upon substantially all property owned by the
Company.
ITEM 3. LEGAL PROCEEDINGS.
Rates, Regulatory Matters, and Trimble County Generating Plant
For a discussion of current regulatory matters and a detailed discussion of
the Trimble County Unit 1 settlement agreement, see Rates and Regulation under
Item 7 and Notes 2 and 14 of Notes to Financial Statements under Item 8.
Statewide Power Planning
On March 14, 1995, the Commission staff issued its report on its review of
the Company's 1993 biennial Integrated Resource Plan. The Staff Report
specifically found that the Company's plan contained some of the better analyses
among those filed by the electric utilities under the Commission's jurisdiction,
and presented several suggestions for the Company's consideration when it
develops its next plan. By order issued on March 17, 1995, the Commission
formally closed its proceeding for the review of the Company's plan. On May 5,
1995, the Commission granted the Company's request that the Commission waive the
requirement that the Company file an Integrated Resource Plan during 1995. On
July 21, 1995, the Kentucky Commission amended its Integrated Resource Planning
regulations to replace the biennial filing requirement with a triennial
requirement. The amended regulations also specified that the Company's next
Integrated Resource Plan is to be filed 39 months from the effective date of the
amended regulation, or October 21, 1998.
Environmental
For a complete discussion of the Company's environmental issues concerning
its Mill Creek and Cane Run generating plants, manufactured gas plant sites, and
certain other environmental issues, see Note 13 of Notes to Financial Statements
under Item 8.
Other
In the normal course of business, other lawsuits, claims, environmental
actions, and other governmental proceedings arise against the Company. To the
extent that damages are assessed in any of these lawsuits, the Company believes
that its insurance coverage is adequate. Management, after consultation with
legal counsel, does not anticipate that liabilities arising out of other
currently pending or threatened lawsuits and claims will have a material adverse
effect on the Company's consolidated financial position or results of
operations.
-13-
<PAGE>
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None
--------------------
Executive Officers of the Company.
<TABLE>
<CAPTION>
Effective Date of Election
Name Age Position to Present Position
---- --- -------- --------------------------
<S> <C> <C> <C>
Roger W. Hale 52 Chairman of the Board and
Chief Executive Officer January 1, 1992
Victor A. Staffieri 40 President January 1, 1994
Walter Z. Berger 40 Executive Vice President
and Chief Financial Officer February 5, 1996
John R. McCall 52 Executive Vice President,
General Counsel and
Corporate Secretary July 1, 1994
M. Lee Fowler 59 Vice President and
Controller September 1, 1988
Wendy C. Heck 42 Vice President, Information
Services January 1, 1994
Chris Hermann 48 Vice President and General
Manager, Wholesale
Electric Business January 1, 1993
Rebecca L. Holt 36 Vice President, Gas
Service Business February 15, 1995
Charles A. Markel III 48 Treasurer January 1, 1993
</TABLE>
The present term of office of each of the above executive officers extends
to the meeting of the Board of Directors following the Annual Meeting of
Stockholders, scheduled to be held April 23, 1996.
There are no family relationships between executive officers of the
Company.
Mr. Hale, Mr. Fowler, Ms. Heck, Mr. Hermann, and Mr. Markel have been
employed for more than five years in executive or management positions with the
Company. Prior to election to the position shown in the table, the following
executive officers held other positions with the Company since January 1, 1991:
Mr. Hale was Chairman of the Board, President and Chief Executive Officer; Ms.
Heck was Vice President-Internal Auditing prior to January 1992, Vice
President-Fuels and Operating Services prior to January 1993, and Vice
President-Fuels and
-14-
<PAGE>
Information Services thereafter; Mr. Hermann was General Manager-Power
Production prior to January 1992 and General Manager-Wholesale Electric
thereafter; Mr. Markel was Vice President-Finance and Treasurer prior to January
1992, and Senior Vice President and Chief Financial Officer thereafter.
Effective January 1993, Mr. Markel was named Corporate Vice President-Finance,
and Treasurer of the parent company, LG&E Energy Corp.
Prior to election to his current position, Mr. Staffieri was Senior Vice
President-Public Policy, and General Counsel of the Company, and prior to
November 1992, Senior Vice President, General Counsel and Corporate Secretary.
Prior to March 1992, Mr. Staffieri was employed by Long Island Lighting Company
and held the position of General Counsel and Secretary.
Prior to election to his current position, Mr. Berger was employed by Enron
Oil Trading and Transportation and held the position of Vice President, Finance
and Business Development. Prior to November 1992, Mr. Berger was Controller for
Enron America, Inc., and prior to February 1992, Vice President and Chief
Financial Officer for Baker Hughes, Inc.
Prior to election to his current position, Mr. McCall was Partner and
Litigation Chairman of Brown, Todd & Heyburn, a law firm.
Prior to election to her current position, Ms. Holt was employed by South
Carolina Electric and Gas Company and held the position of General Manager, Gas
Operations from July 1994 to February 1995, Division Manager, Central
Division-Gas Operations prior to July 1994, and General Manager, Northern
Division-Gas Operations prior to February 1992.
-15-
<PAGE>
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
All Louisville Gas and Electric Company common stock, 21,294,223 shares, is
held by LG&E Energy Corp. Therefore, there is no public trading market for the
Company's common stock.
The following table sets forth the cash distributions on common stock paid
to LG&E Energy Corp. for the periods indicated:
<TABLE>
<CAPTION>
1995 1994
---- ----
(Thousands of $)
<S> <C> <C>
First Quarter............. $18,000 $17,500
Second Quarter............ 34,000 17,500
Third Quarter............. 18,000 -
Fourth Quarter............ 18,500 18,000
</TABLE>
ITEM 6. SELECTED FINANCIAL DATA.
<TABLE>
<CAPTION>
Years Ended December 31
(Thousands of $)
---------------------------------------------------------------------------
1995 1994 1993 1992 1991
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Operating Revenues . . . . . . . . . . . $ 723,463 $ 759,075 $ 775,125 $ 700,195 $ 708,706
----------- ----------- ----------- ----------- -----------
Net Operating Income:
Before Unusual Items. . . . . . . . . 138,203 134,393 136,118 125,829 142,730
Trimble County Settlement . . . . . . (16,877) - - - -
Non-Recurring Charges . . . . . . . . - (23,353) - - -
----------- ----------- ----------- ----------- -----------
Total Net Operating Income . . . . 121,326 111,040 136,118 125,829 142,730
----------- ----------- ----------- ----------- -----------
Net Income:
Before Unusual Items. . . . . . . . . 100,061 94,423 90,535 73,793 94,643
Trimble County Settlement . . . . . . (16,877) - - - -
Non-Recurring Charges,
Charitable Foundation, etc.. . . . - (32,734) - - -
Cumulative Effect of
Accounting Change. . . . . . . . . - (3,369) - - -
----------- ----------- ----------- ----------- -----------
Total Net Income . . . . . . . . . 83,184 58,320 90,535 73,793 94,643
----------- ----------- ----------- ----------- -----------
Net Income Available for
Common Stock . . . . . . . . . . . . . 76,873 52,492 84,554 66,620 85,179
----------- ----------- ----------- ----------- -----------
Total Assets . . . . . . . . . . . . . . 1,979,490 1,966,590 1,974,584 1,960,860 1,936,909
Long-Term Obligations (including
amounts due within one year) . . . . . 662,800 662,800 662,800 686,262 687,662
</TABLE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION.
The following discussion and analysis by management focuses on those
factors that had a material effect on the Company's financial results of
operations and financial condition during 1995, 1994 and 1993 and should be read
in connection with the financial statements and notes thereto.
-16-
<PAGE>
Results of Operations
Net Income
The Company's net income increased $24.9 million for 1995 over 1994 in
spite of recording a charge of $28.3 million ($16.9 million after-tax) in 1995
to recognize the effects of the settlement of the long-standing issues
surrounding the Company's Trimble County electric generating plant. (See Note
14 of Notes to Financial Statements, Trimble County Generating Plant, under Item
8). In 1994 net income of $58.3 million included the write-off of certain
non-recurring items ($23.9 million), the expense of establishing a charitable
foundation ($8.9 million), and the adoption of Statement of Financial Accounting
Standards No. 112, EMPLOYERS' ACCOUNTING FOR POST-EMPLOYMENT BENEFITS ($3.4
million). Without consideration of the charges against income in 1995 and 1994
as discussed above, the Company's 1995 net income increased $5.6 million over
1994. This improvement is primarily due to higher retail electric sales during
1995 partially offset by increased purchased power expenses resulting from
unplanned power plant outages this summer.
In 1994 the Company's net income decreased $32.2 million. This decrease
was due to the 1994 write-off of non-recurring items as discussed in the
preceding paragraph totaling $36.2 million. Without consideration of the
non-recurring charges against income discussed above, the Company's 1994 net
income would have increased $3.9 million over 1993. This improvement is
primarily a result of increased sales of electricity to retail customers and
reduced interest on debt due to favorable refinancing activities in 1993.
Rates and Regulation
The Company is subject to the jurisdiction of the Public Service Commission
of Kentucky (Kentucky Commission or Commission) in virtually all matters related
to electric and gas utility regulation, and as such, its accounting is subject
to Statement of Financial Accounting Standards No. 71, ACCOUNTING FOR THE
EFFECTS OF CERTAIN TYPES OF REGULATION (SFAS No. 71). Given the Company's
competitive position in the market and the status of regulation in the state of
Kentucky, the Company has no plans or intentions to discontinue its application
of SFAS No. 71. See Note 2 of Notes to Financial Statements under Item 8.
On December 8, 1995, the Commission approved a settlement agreement filed
by the Company and all intervenors in the Trimble County proceedings, including
various consumer interest groups and government agencies, that, in effect,
resolves all of the regulatory and legal issues related to the appropriate
ratemaking treatment to exclude 25% of the Trimble County plant costs from
customer rates. Under the settlement, ratepayers are to receive $22 million in
refunds, most of which is to be refunded over a five-year period, commencing in
1996, based on a per kilowatt-hour credit. In addition, the Company also agreed
to provide $900,000 annually for five years to fund low-income energy assistance
programs and to revise the decoupling methodology described in this section in a
manner that will reduce revenues collected from residential customers during
1996 and 1997 by a total of approximately $1.8 million.
The overall effect of the settlement, which the Company recognized in its
entirety in the fourth quarter of 1995, was to reduce electric revenues by $28.3
million and net income by $16.9 million. See Note 14 of Notes to Financial
Statements under Item 8 for further discussion.
-17-
<PAGE>
On July 31, 1995, Vantage Consulting, Inc. released its report on the
Kentucky Commission's management audit of the Company. This comprehensive
audit, which began in September 1994, included more than 300 interviews and over
875 requests for information. This was the second management audit of the
Company mandated by the Kentucky Commission, the first being completed in 1986.
The overall audit findings were very favorable and recognized that the
Company has become an innovative industry leader that has implemented many
performance improvements to lower costs, improve efficiency, prepare for
increased competition, and increase its focus on customer satisfaction. The
audit report identified additional improvement opportunities and contained a
series of recommendations which should assist the Company with its future plans.
It is estimated that implementation of the audit recommendations could provide
the Company with as much as $11 million in annual gross savings. However,
incremental costs will be incurred to achieve the full benefits of the
recommendations and the ultimate savings will be realized over the long-term.
On October 7, 1994, the Company filed an application with the Kentucky
Commission in which it requested approval of an environmental cost recovery
surcharge to recover certain costs required to comply with the Federal Clean Air
Act, as amended, and those federal, state, and local environmental requirements
which apply to coal combustion wastes and by-products from facilities utilized
for production of energy from coal. On April 6, 1995, the Commission approved,
with modifications, an environmental cost recovery surcharge that increased
electric revenues by $3.2 million in 1995 and will increase revenues by an
estimated $5.7 million in 1996. The surcharge became effective on May 1, 1995.
The Company, the Kentucky Attorney General (KAG) and the Kentucky Industrial
Utility Customers (KIUC) filed applications for rehearing on certain issues in
the April 6 order. Among other things, the KAG and KIUC requested a reduction
of the amounts recoverable by the Company through the surcharge. The Commission
denied all motions for rehearing, and appeals are currently pending in Franklin
Circuit Court. The amount of refunds that may be ordered, if any, are not
expected to have a material adverse effect on the Company's financial position
or results of operations.
On January 1, 1994, the Company implemented a Commission approved demand
side management (DSM) program that the Company, KAG, the Jefferson County
Attorney, and representatives of several customer-interest groups had filed with
the Commission. Under the agreement, the Company committed up to $3.3 million
over three years (from 1994 through 1996) for initial programs that include a
residential energy conservation and education program and a commercial
conservation audit program. The agreement also provided for a formal
collaborative process to develop future DSM programs. The agreement contains a
rate mechanism that (1) provides the Company concurrent recovery of DSM program
costs, (2) provides an incentive for implementing DSM programs, and (3) allows
the Company to recover revenues from lost sales associated with the DSM
programs.
Revenues from lost sales to residential customers are collected through a
"decoupling mechanism." The Company's residential decoupling mechanism breaks
the link between the level of the Company's residential kilowatt-hour and Mcf
sales and its non-fuel revenues. Under traditional regulation, a utility's
revenue varies with changes in its level of kilowatt-hour or Mcf sales. The
residential decoupling mechanism allows the Company to recover a predetermined
level of revenue per residential customer based on the rate set in the Company's
last rate case, which will not vary with the level of kilowatt-hour or Mcf
sales. Residential revenues will be adjusted to reflect (1) changes in the
number of residential customers and (2) a pre-established annual growth
-18-
<PAGE>
factor in residential revenue per customer. To the extent that actual revenues
are different from the predetermined level of revenues, rates are subsequently
adjusted to correct for any over or under recoveries. Residential revenues
reported in the financial statements for 1994 through 1996 will be determined in
accordance with the predetermined amount per customer plus growth, and recovery
of fuel and gas costs. The difference between the revenues shown in the
financial statements and the amounts billed to customers will be deferred for
future recovery from, or return to, customers.
On December 1, 1995, the Company and the DSM collaborative members filed a
plan which would modify the existing programs and add five new programs. The
proposed filing would increase the Company's commitment to DSM programs by
approximately $4.1 million. The Company expects the Commission to rule on the
filing in the second quarter of 1996.
In 1993, the Federal Energy Regulatory Commission (FERC) gave final
approval for a market-based generation sales tariff and two transmission service
tariffs which were filed by the Company. The market-based tariff enables the
Company to sell up to 75 Mw of firm generation capacity and an unlimited amount
of non-firm power at market-based rates. On July 26, 1995, FERC approved a new
network transmission service and a flexible point-to-point transmission service
which will provide transmission service to other parties comparable to the
transmission service utilized by the Company to serve retail customers.
The Company last filed for a rate increase with the Commission in June 1990
based on the test-year ended April 30, 1990. The Commission issued a final
order in September 1991 that effectively granted the Company an annual increase
in rates of $6.8 million ($6.1 million electric and $.7 million gas). The
Commission's order authorized a rate of return on common equity of 12.5%.
Revenues
A comparison of operating revenues for the years 1995 and 1994, excluding
the Trimble County settlement (which reduced electric revenues by $28.3
million), with the immediately preceding years reflects both increases and
decreases, which have been segregated by the following principal causes (in
thousands of $):
<TABLE>
<CAPTION>
Increase (Decrease) From Prior Period
-------------------------------------
Electric Revenues Gas Revenues
----------------- ------------
Cause 1995 1994 1995 1994
----- ---- ---- ---- ----
<S> <C> <C> <C> <C>
Sales to Ultimate Consumers:
Fuel and gas supply adjustments, etc....... $(10,566) $ (841) $(16,940) $ 1,823
Demand side management/decoupling.......... (4,619) 1,853 479 3,997
Environmental cost recovery surcharge...... 3,205 - - -
Variation in sales volumes................. 27,382 3,876 (3,420) (12,139)
-------- -------- -------- --------
Total................................... 15,402 4,888 (19,881) (6,319)
Sales for resale................................ (5,249) (16,239) - -
Gas transportation-net.......................... - - 1,062 1,612
Other........................................... 1,538 87 (184) (79)
-------- -------- -------- --------
Total................................... $ 11,691 $(11,264) $(19,003) $ (4,786)
-------- -------- -------- --------
-------- -------- -------- --------
</TABLE>
Electric revenues increased in 1995 mainly because of an increase in sales
to ultimate consumers as a result of the warmer summer weather and improved
economic conditions in the
-19-
<PAGE>
Company's service territory. Gas revenues decreased as a result of lower gas
supply adjustment revenues which reflected the lower cost of natural gas in
1995.
The Company's electric revenues decreased in 1994 compared with 1993
primarily because of a decrease in the sales of electricity for resale. Gas
sales to ultimate consumers decreased 6% due primarily to the warmer than normal
weather in the last quarter of 1994.
Expenses
Fuel for electric generation and gas supply expenses comprise a large
segment of the Company's total operating costs. The Company's electric and gas
rates contain a fuel adjustment clause and a gas supply clause, respectively,
whereby increases or decreases in the cost of fuel and gas supply are reflected
in the Company's rates, subject to the approval by the Commission.
Fuel expenses decreased $5.6 million (4%) in 1995 due to a decrease in the
cost of coal burned ($7.5 million) partially offset by increased generation of
2%. Fuel expenses decreased $5.8 million (4%) in 1994 primarily because of a
decrease in the cost of coal burned ($3.9 million) and decreased generation of
3%. The average delivered cost per ton of coal purchased was $23.68 in 1995,
$25.27 in 1994, and $26.58 in 1993. This downward trend in the delivered cost
of coal is expected to continue through 1996.
Power purchased increased $7.1 million in 1995 primarily because of
increased purchases resulting from unplanned outages at the electric generating
plants during the extremely hot summer weather. The decrease of $7.5 million in
1994 was primarily due to less power wheeled for other utilities as a result of
milder weather in the region.
Gas supply expenses decreased $20.8 million (16%) in 1995 because of the
lower cost of net gas supply ($18.7 million) and a decrease in the volume of gas
delivered to the distribution system ($2.1 million). Gas supply expenses
decreased $7.5 million (5%) in 1994 due mainly to a decrease in the volume of
gas delivered to the distribution system ($9.2 million), partially offset by an
increase in net gas supply cost ($1.7 million). The average unit cost per Mcf
of purchased gas was $2.62 in 1995, $2.78 in 1994, and $2.91 in 1993.
Other operation expenses decreased $1.6 million in 1995, as compared to
1994, primarily as a result of a $6 million credit to expense representing a
portion of the proceeds received in a commercial dispute (see the following
paragraph for more discussion) and a decrease in expenses ($1.2 million)
associated with property damage claims. These decreases were partially offset
by an increase in labor related expenses ($3.8 million) and an increase in
various administrative expenses ($1.8 million). Maintenance expense increased
$3.4 million in 1995 primarily as a result of an increase in repairs at the
electric power plants ($4.2 million), partially offset by a decrease in storm
damage expenses ($1 million).
During 1995, the Company received cash proceeds of $8 million in connection
with the settlement of a commercial dispute. Pursuant to a study to determine
the proper amount of income to be recognized, the Company recognized $6 million
as a reduction of operation expenses. The remaining $2 million was recorded as
a reserve for future payments in connection with the dispute.
-20-
<PAGE>
Other operation expenses decreased $.5 million in 1994 mainly as a result
of decreases in various administrative expenses ($1.8 million), partially offset
by increased costs to operate electric generating plants and gas and electric
distribution systems ($.7 million), and an increase in the provision for
uncollectible accounts ($.6 million). Maintenance expenses were up only
slightly over 1993.
Non-recurring charges in 1994 include the Company's write-off of costs in
connection with early retirements and workforce reductions that occurred in 1992
and 1993, costs in connection with property damage claims pertaining to
particulate emissions from the Mill Creek electric generating plant, and certain
costs previously deferred resulting from adoption of Statement of Financial
Accounting Standards No. 106, EMPLOYERS' ACCOUNTING FOR POST-RETIREMENT
BENEFITS OTHER THAN PENSIONS. See Note 3 of Notes to Financial Statements
under Item 8.
Depreciation and amortization increased in both 1995 and 1994 primarily
because of additional depreciable plant in service.
Variations in income tax expenses are largely attributable to changes in
pre-tax income.
Other income and (deductions) increased $1.3 million primarily because of
an increase in dividend and interest income from investments. Other income and
(deductions) increased $.5 million in 1994 partially due to recognition of a
gain on the sale of construction equipment. See Note 9 of Notes to Financial
Statements under Item 8 for further detail.
Contribution to the Company's charitable foundation reflects the expense
associated with establishing a tax-exempt foundation during 1994. Contributions
made from this Foundation are not charged against income, and therefore, do not
affect the Company's net income. See Note 3 of Notes to Financial Statements
under Item 8.
Interest charges for 1995 decreased $.9 million primarily due to a reversal
of an interest expense reserve resulting from a favorable ruling on certain
income tax matters. Interest charges decreased in 1994 because of the lower
composite interest rate on outstanding debt, which reflects the full year effect
of the Company's 1993 aggressive program to refinance approximately $205 million
of outstanding debt at lower interest rates. Since 1993, an immaterial
component of interest expense has been the cost associated with interest rate
swaps. See Note 4, Financial Instruments, under Item 8 for further discussion.
Preferred dividends increased $.5 million in 1995 because of a higher rate
associated with the Auction Rate Series. Preferred dividends in 1994 reflect
the lower dividends that resulted from the Company's refunding of its $25
million, $8.90 Series with a $5.875 Series in May 1993. See Liquidity and
Capital Resources.
The rate of inflation may have a significant impact on the Company's
operations, its ability to control costs, and the need to seek timely and
adequate rate adjustments. However, relatively low rates of inflation in the
past few years have moderated the impact on current operating results.
-21-
<PAGE>
LIQUIDITY AND CAPITAL RESOURCES
The Company's need for capital funds is primarily related to the
construction of plant and equipment necessary to meet the needs of electric and
gas utility customers and protection of the environment.
1995 Capital Requirements
New construction expenditures for 1995 were $93 million compared with $95
million for 1994 and $99 million for 1993.
Past Financing Activities
During 1995, 1994, and 1993, the Company's primary source of capital was
internally generated funds from operating cash flows. Internally generated
funds provided financing for 100% of the Company's construction expenditures for
1995, 1994, and 1993.
Variations in accounts receivable and accounts payable are not generally
significant indicators of the Company's liquidity, as such variations are
primarily attributable to fluctuations in weather in the Company's service
territory, which has a direct effect on sales of electricity and gas. In 1995,
accounts receivable and accounts payable were higher due to colder weather in
the last quarter of the year as compared to 1994.
In December 1995, the Company redeemed the outstanding shares of its 7.45%
Cumulative Preferred Stock with a par value of $25 per share at a redemption
price of $25.75 per share. The Company funded the $22 million redemption with
cash generated internally.
In April 1995, the Company issued $40 million of Jefferson County,
Kentucky, Pollution Control Revenue Bonds, 5.90% Series, due April 15, 2023.
The proceeds of the bonds were used to redeem the outstanding 9.25% Series of
Pollution Control Bonds due July 1, 2015.
Future Capital Requirements
Future financing requirements may be affected in varying degrees by factors
such as load growth, changes in construction expenditure levels, rate increases
allowed by regulatory agencies, new legislation, market entry of competing
electric power generators, changes in environmental regulations and other
regulatory requirements. The Company estimates construction expenditures will
total $220 million for 1996 and 1997. In addition, capital requirements for
1996 include $16 million to retire long-term debt.
Future Sources of Financing
Internally generated funds from operations are expected to fund
substantially all anticipated construction expenditures in 1996 and 1997.
-22-
<PAGE>
At December 31, 1995, the Company had unused lines of credit of $160
million for which it pays commitment fees. These credit facilities are
scheduled to expire during the year 2000. Management expects to renegotiate
them when they expire.
To the extent permanent financings are needed in 1996 and 1997, the Company
expects that it will have ready access to the securities markets to raise needed
funds.
Environmental Matters
The Clean Air Act Amendments of 1990 (the Act) impose stringent limits on
emissions of sulfur dioxide and nitrogen oxides by electric utility generating
plants. All of the Company's coal-fired boilers are equipped with sulfur
dioxide "scrubbers" and already achieve the final sulfur dioxide emission rates
required by the year 2000 under the legislation. However, as part of its
ongoing construction program, the Company has spent $22 million to date and
anticipates incurring capital expenditures of approximately $8 million in 1996
for remedial measures necessary to meet the Act's requirements for nitrogen
oxides. The overall financial impact of the legislation on the Company is
expected to be minimal. The Company is well-positioned in the market to be a
"clean" power provider without the large capital expenditures that are expected
to be incurred by many other utilities.
Reference is made to Note 13, Environmental, under Item 8 for a complete
discussion of the Company's environmental issues concerning its Mill Creek and
Cane Run electric generating plants, manufactured gas plant sites, and certain
other environmental issues.
Energy Policy Act of 1992 and Related Matters
The Energy Policy Act of 1992 is designed to give utilities a wider choice
of sources for their electrical supply than previously available, while creating
generating supply options that did not exist under the old law. In passing this
legislation, Congress also anticipated that greater competition among electric
supply options should result in lower consumer rates.
Pursuant to the Energy Policy Act, the FERC earlier this year issued a
Notice of Proposed Rulemaking on Open Access Non-discriminatory Transmission
Services and a Supplemental Notice of Proposed Rulemaking on Stranded Investment
(collectively, the Mega-NOPR). The Mega-NOPR is intended, among other things,
to create a vigorous wholesale electric market by requiring transmission
providers to offer open access to their transmission systems. The Company is
supportive of proposals to increase competition at all levels of the electric
power market and intends to pursue opportunities created by a more competitive
market.
FERC Order No. 636
Under Order No. 636, pipelines may recover costs associated with the
transition to and implementation of this order from pipeline customers,
including the Company. During 1995, the Company paid and began recovering from
its customers approximately $4.8 million in transition costs under Order No.
636. It is estimated that about $1.4 million in additional transition costs
will be incurred by the Company during 1996 and about $1.3 million in 1997, and
these costs are also
-23-
<PAGE>
expected to be recovered from customers. See FERC Order No. 636 under Note 13
of Notes to Financial Statements under Item 8 for further discussion.
FUTURE OUTLOOK
Business Realignment
Effective December 15, 1995, LG&E Energy Corp. modified its organizational
structure. The changes are designed to facilitate decision making, improve
response to customers and better align operating units with the changing
competitive marketplace. Four operating divisions were established:
Distribution Services Division - which includes the distribution
resources of Louisville Gas and Electric Company (LG&E), is responsible
for expanding and developing the distribution businesses and investing
in enhanced service offerings behind the customer's meter.
Gas Marketing Division - primarily consists of the businesses of LG&E
Natural Inc. (a subsidiary of LG&E Energy Corp.), which markets gas
throughout the United States and Canada.
Power Marketing Division - includes LG&E Power Marketing Inc. (LPM), is
responsible for project development and the marketing and sale of
wholesale power throughout the United States.
Power Generation Division - which includes the generation resources of
LG&E, LG&E Power Inc. and LG&E International Inc., has responsibility
for all utility and non-utility power plant operations, asset
management, and development functions both domestically and
internationally.
Wholesale power will continue to be marketed and brokered by LPM, a
wholly-owned subsidiary of LG&E Energy Corp. LPM was among the first
utility-affiliated marketers in the country to secure FERC approval to sell
power at market-based rates and engage in wholesale power marketing activities.
During 1995, its first full year of operations, LPM sold or brokered 1.8 million
megawatt-hours of power in 30 states. This volume of activity placed LPM among
the five largest marketers of wholesale energy in 1995 and the largest seller
affiliated with a regulated electric utility. LPM is predicting that the market
for electric energy will expand and its revenues will increase in future years.
The realignment does not affect LG&E Energy Corp.'s legal structure,
regulation of the Company by the Commission or LG&E Energy Corp.'s status as an
exempt holding company.
-24-
<PAGE>
Tennessee Gas Pipeline Company
During the last quarter of 1995, the Company negotiated a five-year
transportation agreement with Tennessee Gas Pipeline Company (Tennessee) to
become the Company's second natural gas pipeline transporter. The agreement
with Tennessee becomes effective November 1, 1996. For many years, Texas Gas
Transmission Corporation has been the sole provider of gas transport services to
the Company.
Union Contract
On December 8, 1995, members of the International Brotherhood of Electrical
Workers Local 2100 ratified a new three-year collective bargaining agreement
with the Company, which covers approximately 1,600 employees. The contract
provides wage and employment protection for employees participating in the
Company's continuous improvement initiative, greater workforce flexibility to
help the Company respond to growing competition, and improved retirement
benefits.
Competition
The Company has taken many steps to prepare for the expected increase in
competition in its industry, including a reduction in the number of employees;
aggressive cost cutting; a write-off of previously deferred expenses; an
increase in focus on commercial and industrial customers; an increase in
employee involvement and training; a major realignment and formation of new
business units, and a modification of its organization structure.
-25-
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
LOUISVILLE GAS AND ELECTRIC COMPANY
STATEMENTS OF INCOME
(Thousands of $)
<TABLE>
<CAPTION>
Years Ended December 31
---------------------------------------
1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
Operating Revenues
Electric.............................................. $570,637 $558,946 $570,210
Refund - Trimble County Settlement (Note 14) (28,300) - -
Gas................................................... 181,126 200,129 204,915
-------- -------- --------
Total operating revenues (Note 1)..................... 723,463 759,075 775,125
-------- -------- --------
Operating Expenses
Fuel for electric generation.......................... 138,002 143,602 149,436
Power purchased....................................... 16,830 9,754 17,228
Gas supply expenses................................... 110,738 131,561 139,054
Other operation expenses.............................. 134,655 136,214 136,693
Maintenance........................................... 52,101 48,731 48,414
Non-recurring charges (Note 3)........................ - 38,613 -
Depreciation and amortization......................... 85,759 82,519 79,655
Federal and State income taxes (Note 8)............... 47,524 39,922 52,334
Property and other taxes.............................. 16,528 17,119 16,193
-------- -------- --------
Total operating expenses.............................. 602,137 648,035 639,007
-------- -------- --------
Net Operating Income.................................... 121,326 111,040 136,118
Other Income and (Deductions) (Note 9).................. 3,776 2,451 1,913
Contribution to Charitable Foundation - net (Note 3).... - 8,946 -
Interest Charges........................................ 41,918 42,856 47,496
-------- -------- --------
Income before Cumulative Effect of a Change in
Accounting Principle.................................. 83,184 61,689 90,535
Cumulative Effect of a Change in Accounting for
Post-Employment Benefits, net of income taxes
of $2,280 (Note 7).................................... - (3,369) -
-------- -------- --------
Net Income.............................................. 83,184 58,320 90,535
Preferred Stock Dividends............................... 6,311 5,828 5,981
-------- -------- --------
Net Income Available for Common Stock................... $ 76,873 $ 52,492 $ 84,554
-------- -------- --------
-------- -------- --------
</TABLE>
STATEMENTS OF RETAINED EARNINGS
(Thousands of $)
<TABLE>
<CAPTION>
Years Ended December 31
--------------------------------------
1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
Balance January 1....................................... $193,895 $194,903 $178,667
Add net income.......................................... 83,184 58,320 90,535
-------- -------- --------
277,079 253,223 269,202
-------- -------- --------
Deduct: Cash dividends declared on stock:
5% cumulative preferred........................... 1,075 1,075 1,075
7.45% cumulative preferred........................ 1,527 1,598 1,598
$8.90 cumulative preferred........................ - - 1,113
Auction rate cumulative preferred................. 2,240 1,686 1,322
$5.875 cumulative preferred....................... 1,469 1,469 873
Common............................................ 89,000 53,500 67,500
Preferred stock redemption expense.................. 719 - 818
-------- -------- --------
96,030 59,328 74,299
-------- -------- --------
Balance December 31..................................... $181,049 $193,895 $194,903
-------- -------- --------
-------- -------- --------
</TABLE>
The accompanying notes are an integral part of these financial statements.
-26-
<PAGE>
LOUISVILLE GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Thousands of $)
ASSETS
<TABLE>
<CAPTION>
December 31
--------------------------------
1995 1994
---- ----
<S> <C> <C>
Utility Plant, at original cost
Electric.................................................. $2,123,699 $2,084,334
Gas....................................................... 299,070 280,877
Common.................................................... 128,902 137,662
---------- ----------
2,551,671 2,502,873
Less: Reserve for depreciation........................... 934,942 881,861
---------- ----------
1,616,729 1,621,012
Construction work in progress............................. 47,189 35,022
---------- ----------
1,663,918 1,656,034
---------- ----------
Other Property and Investments - less reserve (Note 6)...... 760 50,681
---------- ----------
Current Assets
Cash and temporary cash investments....................... 58,131 39,138
Marketable securities (Note 6)............................ 20,449 -
Accounts receivable-less reserve of
$1,360 in 1995 and $1,203 in 1994......................... 105,589 86,058
Materials and supplies-at average cost
Fuel (predominantly coal).............................. 14,996 13,869
Gas stored underground................................. 31,714 31,354
Other.................................................. 34,384 37,299
Prepayments............................................... 2,108 253
---------- ----------
267,371 207,971
---------- ----------
Deferred Debits and Other Assets
Unamortized debt expense.................................. 7,710 7,776
Regulatory assets (Note 2)................................ 29,926 31,726
Other..................................................... 9,805 12,402
---------- ----------
47,441 51,904
---------- ----------
$1,979,490 $1,966,590
---------- ----------
---------- ----------
CAPITAL AND LIABILITIES
Capitalization (see Statements of Capitalization)
Common equity............................................. $605,157 $616,478
Cumulative preferred stock................................ 95,328 116,716
Long-term debt............................................ 646,845 662,862
---------- ----------
1,347,330 1,396,056
---------- ----------
Current Liabilities
Long-term debt due within one year........................ 16,000 -
Accounts payable.......................................... 93,706 70,770
Trimble County Settlement (Note 14)....................... 28,300 -
Dividends declared........................................ 19,672 19,567
Accrued taxes............................................. 7,814 8,247
Accrued interest.......................................... 11,064 13,394
Other..................................................... 12,071 10,277
---------- ----------
188,627 122,255
---------- ----------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes (Notes 1 and 8)......... 204,816 193,236
Investment tax credit, in process of amortization......... 84,037 88,779
Accumulated provision for pensions and related benefits... 47,099 49,104
Customers' advances for construction...................... 9,251 8,621
Regulatory liability (Note 2)............................. 88,242 91,492
Other..................................................... 10,088 17,047
---------- ----------
443,533 448,279
---------- ----------
Commitments and Contingencies (Note 13)
$1,979,490 $1,966,590
---------- ----------
---------- ----------
</TABLE>
The accompanying notes are an integral part of these financial statements.
-27-
<PAGE>
LOUISVILLE GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(Thousands of $)
<TABLE>
<CAPTION>
Years Ended December 31
----------------------------------------
1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
Cash Flows from Operating Activities
Net Income........................................................ $ 83,184 $ 58,320 $ 90,535
Items not requiring cash currently:
Depreciation and amortization................................... 85,759 82,519 79,887
Deferred income taxes-net....................................... 7,049 (2,274) 4,938
Investment tax credit-net....................................... (4,742) (4,619) (7,821)
Cumulative effect of change in accounting principle............. - 3,369 -
Non-recurring charges........................................... - 38,613 -
Gain on sale of capital asset................................... - - (3,869)
Other........................................................... 3,958 6,603 5,877
(Increase) decrease in certain net current assets:
Accounts receivable............................................. (19,531) 18,339 (11,678)
Materials and supplies.......................................... 1,428 3,280 10,671
Trimble County Settlement....................................... 28,300 - -
Accounts payable................................................ 22,936 (22,781) 21,099
Accrued taxes................................................... (433) (1,247) 2,343
Accrued interest................................................ (2,330) 530 757
Prepayments and other........................................... (61) (743) (260)
Other............................................................. (6,917) 972 (15,587)
--------- --------- ---------
Net cash provided from operating activities..................... 198,600 180,881 176,892
--------- --------- ---------
Cash Flows from Investing Activities
Purchases of securities........................................... (119,151) (87,896) (38,398)
Proceeds from sales of securities................................. 151,422 56,085 27,301
Construction expenditures......................................... (93,423) (95,398) (98,787)
Sale of capital asset............................................. - - 91,076
--------- --------- ---------
Net cash used for investing activities.......................... (61,152) (127,209) (18,808)
--------- --------- ---------
Cash Flows from Financing Activities
Issuance of preferred stock....................................... - - 24,716
Issuance of first mortgage bonds and pollution control bonds...... 39,914 - 198,918
Redemption of preferred stock..................................... (22,108) - (25,558)
Retirement of first mortgage bonds and pollution control bonds.... (41,055) - (231,876)
Repayment of short-term borrowings................................ - - (8,000)
Payment of dividends.............................................. (95,206) (58,639) (73,125)
--------- --------- ---------
Net cash used for financing activities............................ (118,455) (58,639) (114,925)
--------- --------- ---------
Net Increase (Decrease) in Cash and Temporary Cash Investments...... 18,993 (4,967) 43,159
Cash and Temporary Cash Investments at Beginning of Year............ 39,138 44,105 946
--------- --------- ---------
Cash and Temporary Cash Investments at End of Year.................. $ 58,131 $ 39,138 $ 44,105
--------- --------- ---------
--------- --------- ---------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year for:
Income taxes...................................................... $ 40,049 $ 42,803 $ 54,686
Interest on borrowed money........................................ 42,589 40,827 45,360
</TABLE>
The accompanying notes are an integral part of these financial statements.
-28-
<PAGE>
LOUISVILLE GAS AND ELECTRIC COMPANY
STATEMENTS OF CAPITALIZATION
(Thousands of $)
<TABLE>
<CAPTION>
December 31
-----------------------------
1995 1994
---- ----
<S> <C> <C>
Common Equity
Common stock, without par value -
Authorized 75,000,000 shares, outstanding 21,294,223 shares....... $ 425,170 $ 425,170
Common stock expense................................................ (836) (836)
Unrealized loss on marketable securities, net of income
taxes of $153 in 1995 and $1,434 in 1994 (Note 6)................. (226) (1,751)
Retained earnings................................................... 181,049 193,895
---------- ----------
605,157 616,478
---------- ----------
Cumulative Preferred Stock
Redeemable on 30 days notice by the Company except, $5.875 series
<CAPTION>
Shares Current
Outstanding Redemption Price
----------- ----------------
<S> <C> <C>
$25 par value, 1,720,000 shares authorized -
5% series...................... 860,287 $28.00 21,507 21,507
7.45% series (Note 10)......... - - - 21,453
Without par value, 6,750,000 shares authorized -
Auction Rate................... 500,000 100.00 50,000 50,000
$5.875 series.................. 250,000 Not redeemable 25,000 25,000
Preferred stock expense............................................. (1,179) (1,244)
---------- ----------
95,328 116,716
---------- ----------
Long-Term Debt (Note 11)
First mortgage bonds -
Series due June 1, 1996, 5 5/8%................................... 16,000 16,000
Series due June 1, 1998, 6 3/4%................................... 20,000 20,000
Series due July 1, 2002, 7 1/2%................................... 20,000 20,000
Series due August 15, 2003, 6%.................................... 42,600 42,600
Pollution control series:
J due July 1, 2015, 9 1/4%...................................... - 40,000
K due December 1, 2016, 7 1/4%.................................. 27,500 27,500
L due December 1, 2016, 7 1/4%.................................. 22,500 22,500
N due February 1, 2019, 7 3/4%.................................. 35,000 35,000
O due February 1, 2019, 7 3/4%.................................. 35,000 35,000
P due June 15, 2015, 7.45%...................................... 25,000 25,000
Q due November 1, 2020, 7 5/8%.................................. 83,335 83,335
R due November 1, 2020, 6.55%................................... 41,665 41,665
S due September 1, 2017, variable............................... 31,000 31,000
T due September 1, 2017, variable............................... 60,000 60,000
U due August 15, 2013, variable................................. 35,200 35,200
V due August 15, 2019, 5 5/8%................................... 102,000 102,000
W due October 15, 2020, 5.45%................................... 26,000 26,000
X due April 15, 2023, 5.90%..................................... 40,000 -
---------- ----------
Total bonds outstanding........................................... 662,800 662,800
Less long-term debt due within one year........................... 16,000 -
---------- ----------
Long-term first mortgage bonds.................................... 646,800 662,800
Unamortized premium on bonds........................................ 45 62
---------- ----------
646,845 662,862
---------- ----------
Total Capitalization.................................................. $1,347,330 $1,396,056
---------- ----------
---------- ----------
</TABLE>
The accompanying notes are an integral part of these financial statements.
-29-
<PAGE>
LOUISVILLE GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Louisville Gas and Electric Company (the Company) is the primary subsidiary
of LG&E Energy Corp. The Company is a regulated public utility that is
engaged in the generation, transmission, distribution, and sale of electric
energy and the storage, distribution, and sale of natural gas in Louisville
and adjacent areas in Kentucky. LG&E Energy Corp. is an exempt energy
services holding company with wholly-owned subsidiaries consisting of the
Company, LG&E Energy Systems Inc., and LG&E Gas Systems Inc. All of the
Company's Common Stock is held by LG&E Energy Corp.
Certain reclassification entries have been made to the 1994 financial
statements to conform with the 1995 presentation with no impact on
previously reported income.
UTILITY PLANT. The Company's plant is stated at original cost, which
includes payroll-related costs such as taxes, fringe benefits, and
administrative and general costs. Construction work in progress has been
included in the rate base, and, accordingly, the Company has not recorded
any allowance for funds used during construction.
The cost of plant retired or disposed of in the normal course of business
is deducted from plant accounts and such cost plus removal expense less
salvage value is charged to the reserve for depreciation. When complete
operating units are disposed of, appropriate adjustments are made to the
reserve for depreciation and gains and losses, if any, are recognized.
DEPRECIATION. Depreciation is provided on the straight-line method over
the estimated service lives of depreciable plant. The amounts provided for
1995 were 3.3% (3.2% electric, 3.3% gas, and 6% common); for 1994, 3.3%
(3.2% electric, 3.3% gas, and 5% common); and for 1993, 3.3% (3.2%
electric, 3.2% gas, and 5% common) of average depreciable plant.
CASH AND TEMPORARY CASH INVESTMENTS. The Company considers all highly
liquid debt instruments purchased with a maturity of three months or less
to be cash equivalents. Temporary cash investments are carried at cost,
which approximates fair value.
FINANCIAL INSTRUMENTS. The Company uses over-the-counter interest-rate
swap agreements to hedge its exposure to fluctuations in interest rates it
pays on variable-rate debt, and it uses exchange-traded U.S. Treasury note
and bond futures to hedge its exposure to fluctuations in the value of its
investments in the preferred stocks of other companies.
Gains and losses on interest-rate swaps are reflected in interest charges
monthly. Gains and losses on U.S. Treasury note and bond futures used to
hedge investments in preferred stocks are initially deferred and classified
as unrealized loss on marketable securities in common equity and then
charged or credited to other income and deductions when the securities are
sold. See Note 4, Financial Instruments.
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<PAGE>
DEFERRED INCOME TAXES. Deferred income taxes have been provided for all
book-tax temporary differences.
The Company adopted Statement of Financial Accounting Standards No. 109,
ACCOUNTING FOR INCOME TAXES (SFAS No. 109) January 1, 1993. Regulatory
assets and liabilities have been established to recognize the future
revenue requirement impact from the deferred income taxes which were not
immediately recognized in operating results because of ratemaking
treatment. The adoption of SFAS No. 109 did not have a material impact on
the results of operations or financial position.
INVESTMENT TAX CREDITS. Investment tax credits resulted from provisions
of the tax law that permitted a reduction of the Company's tax liability
based on credits for certain construction expenditures. Investment tax
credits deferred and charged to income in prior years are being amortized
to income over the estimated lives of the related property that gave rise
to the credits.
DEBT PREMIUM AND EXPENSE. Debt premium and expense are amortized over
the lives of the related debt issues, consistent with regulatory practices.
REVENUE RECOGNITION. Revenues are recorded based on service rendered to
customers through month end. The Company accrues an estimate for unbilled
revenues from the date of each meter reading date to the end of the
accounting period. Effective January 1, 1994, under an agreement approved
by the Public Service Commission of Kentucky (Kentucky Commission or
Commission), the Company implemented a demand side management program and a
"decoupling mechanism," which allows the Company to recover a predetermined
level of revenue on electric and gas residential sales. See Management's
Discussion and Analysis, Rates and Regulation, under Item 7 for further
discussion.
FUEL AND GAS COSTS. The cost of fuel for electric generation is charged
to expense as used, and the cost of gas supply is charged to expense as
delivered to the distribution system.
MANAGEMENT'S USE OF ESTIMATES. The preparation of financial statements
in conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting period. Actual
results could differ from those estimates. See Note 13, Commitments and
Contingencies, for further discussion.
NEW ACCOUNTING PRONOUNCEMENT. LONG-LIVED ASSETS - In March 1995, the
Financial Accounting Standards Board issued Statement of Financial
Accounting Standards No. 121, ACCOUNTING FOR THE IMPAIRMENT OF LONG-LIVED
ASSETS AND FOR LONG-LIVED ASSETS TO BE DISPOSED OF (SFAS No. 121),
effective for fiscal years beginning after December 15, 1995. The Company
plans to adopt the provisions of SFAS No. 121 in the first quarter of 1996.
The new standard requires that long-lived assets and certain identified
intangibles be reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be
recoverable. In performing such impairment reviews, companies will be
required to estimate the sum of future cash flows from an asset and compare
such amount to the asset's carrying amount. Any excess of carrying amount
over expected cash flows will result in a possible write-down of an asset
to its fair value. Based on current operating
-31-
<PAGE>
conditions, legal requirements and regulatory environment, the Company does
not expect adoption of SFAS No. 121 to have a material adverse impact on
its financial position or results of operations.
NOTE 2 - RATES AND REGULATORY MATTERS
The Company conforms with generally accepted accounting principles as
applied to regulated public utilities and as prescribed by the Federal
Energy Regulatory Commission (FERC) and the Kentucky Commission. The
Company is subject to Statement of Financial Accounting Standards No. 71,
ACCOUNTING FOR THE EFFECTS OF CERTAIN TYPES OF REGULATION (SFAS No. 71).
Under SFAS No. 71, certain costs that would otherwise be charged to expense
are deferred as regulatory assets based on expected recovery from customers
in future rates. Likewise, certain credits that would otherwise be
reflected as income are deferred as regulatory liabilities based on
expected flowback to customers in future rates. Management's expected
recovery of deferred costs and expected flowback of deferred credits is
generally based on specific ratemaking decisions or precedent for each
item. The following regulatory assets and liabilities were included in the
balance sheets as of December 31 (in thousands of $):
<TABLE>
<CAPTION>
1995 1994
---- ----
<S> <C> <C>
Unamortized loss on bonds................... $ 16,443 $ 15,704
Unamortized extraordinary retirements....... 6,935 9,752
Manufactured gas sites...................... 3,220 3,149
Other....................................... 3,328 3,121
-------- --------
Total regulatory assets..................... 29,926 31,726
Deferred income taxes - net................. (88,242) (91,492)
-------- --------
Regulatory assets and (liabilities) - net... $(58,316) $(59,766)
-------- --------
-------- --------
</TABLE>
Substantially all of the Company's regulatory assets are being recovered
through rates charged to customers. The Company expects to seek regulatory
approval to recover any remaining regulatory assets in its next general
rate case.
ENVIRONMENTAL COST RECOVERY. The Company filed an application with the
Kentucky Commission in October 1994, in which it requested approval of an
environmental cost recovery surcharge to recover certain costs incurred to
comply with federal, state, and local environmental requirements. On April
6, 1995, the Commission approved the surcharge with modifications. The
surcharge became effective on May 1, 1995. The Company recovered $3.2
million in 1995 and expects to recover an additional $5.7 million in 1996
through the surcharge.
An appeal of the Commission's April 6 order by various intervenors in the
proceeding (including the Kentucky Attorney General) is currently pending
in the Franklin Circuit Court of Kentucky. The intervenors are contesting
the validity of the order on several grounds, including the
constitutionality of the Kentucky statute that authorizes the surcharge.
The Company is vigorously contesting the legal challenges to the surcharge,
but cannot predict the outcome of the appeal. The amount of refunds that
may be ordered, if any, are not expected to have a material adverse effect
on the Company's financial position or results of operations. See
Management's Discussion and Analysis, Rates and Regulation, under Item 7
for a further discussion.
-32-
<PAGE>
NOTE 3 - NON-RECURRING CHARGES
As part of a study of LG&E Energy Corp.'s business strategy and realignment
during 1994, the Company re-evaluated its regulatory strategy which
previously had been to seek full recovery of certain costs deferred in
accordance with prior precedents established by the Commission. As a
result of this re-evaluation, the Company wrote off certain expenses that
had previously been deferred amounting to approximately $38.6 million
before taxes. While the Company continues to believe that it could have
reasonably expected to recover these costs in future rate proceedings
before the Commission, the Company decided to deduct these expenses
currently and not seek recovery for such expenses in future rates due to
increasing competitive pressures and the existing and anticipated future
economic conditions. The items written off include costs incurred in
connection with early retirements and workforce reductions that occurred in
1992 and 1993, which consist primarily of separation payments, enhanced
early retirement benefits, and health care benefits; costs associated with
property damage claims pertaining to particulate emissions from its Mill
Creek electric generating plant which primarily consist of spotting on
automobile finish and aluminum siding; and certain costs previously
deferred resulting from adoption in January 1993 of Statement of Financial
Accounting Standards No. 106, EMPLOYERS' ACCOUNTING FOR POST-RETIREMENT
BENEFITS OTHER THAN PENSIONS.
In the first quarter of 1994, the Board of Directors of the Company
approved the formation of a tax-exempt charitable foundation (Foundation)
that makes charitable contributions to qualified persons and entities. In
1994, the Company recorded a pre-tax charge against income and made an
irrevocable payment of $15 million to fund the Foundation. On June 6,
1994, the Internal Revenue Service issued a letter stating that it had
determined the Foundation was exempt from Federal income tax under the
Internal Revenue Code.
NOTE 4 - FINANCIAL INSTRUMENTS
INSTRUMENTS USED IN HEDGING ACTIVITIES. The Company uses exchange-traded
futures and over-the-counter (OTC) swap agreements to hedge its exposure to
changes in the valuation of investments in marketable securities and
changes in interest rates on variable rate debt, respectively. Futures
reduce exposure to fluctuations in pricing of marketable securities as of a
future delivery date. Swaps allow the Company to change certain
index-based interest payment commitments to fixed amounts based on a stated
rate.
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<PAGE>
The following summarizes the Company's use of financial instruments for
hedging purposes at December 31, 1995:
<TABLE>
<CAPTION>
NOTIONAL AMOUNT
CATEGORY /MATURITY PURPOSE
----------------------------- ------------------------------- ------------------------------
<S> <C> <C>
Exchange-traded U.S. Treasury $4.3 million, matures March Reduce exposure to changes in
notes and bond futures 1996 market value of investments in
preferred stock.
OTC interest rate swaps $15 million matures September Convert $30 million of Series S
1997; $15 million matures variable rate Pollution Control
September 1999 Bonds to average composite
rates of 4.55%. Average
variable rate received based on
JJ Kenny index, 3.87%, 2.84%,
and 2.38% in 1995, 1994, and
1993, respectively.
</TABLE>
Initial margin requirements and daily margin calls for exchange-traded
futures are met in cash and all transactions are settled in cash or through
delivery of the underlying security.
FAIR VALUES OF FINANCIAL INSTRUMENTS. The carrying amounts of cash,
accounts receivable, and accounts payable reflected on the balance sheets
approximates the fair value of these instruments due to the short duration
to maturity. The fair value for certain of the Company's investments and
debt are estimated based on quoted market prices for those or similar
instruments. Investments for which there are no quoted market prices are
stated at cost because a reasonable estimate of fair value cannot be made
without incurring excessive costs. The fair value of exchange-traded
financial instruments reflects market prices reported by the exchanges.
Fair values of swaps are based on price quotes obtained from dealers. Fair
value estimates are made at a certain point in time and changes in
assumptions, economic conditions, risk characteristics of various
instruments and other factors could cause significant changes in these
estimates.
The fair value information contained herein does not include an assessment
of assets and liabilities that are not financial instruments, such as
property and equipment or other assets and liabilities. Accordingly, these
fair value disclosures are not intended to present a valuation of the
Company taken as a whole.
-34-
<PAGE>
The cost and estimated fair values of the Company's financial instruments
as of December 31, 1995 and 1994 follow (in thousands of $):
<TABLE>
<CAPTION>
1995 1994
------------------------ -------------------------
Fair Fair
Cost Value Cost Value
-------- --------- --------- --------
<S> <C> <C> <C> <C>
Marketable securities............................. $ 20,828 $ 20,449 $ - $ -
Long-term investments:
Practicable to estimate fair value.............. - - 53,323 50,138
Not practicable................................. 740 740 515 515
Preferred stock subject to mandatory redemption... 25,000 25,000 25,000 22,125
Long-term debt.................................... 662,800 688,977 662,800 648,697
U.S. Treasury note and bond futures............... - (105) (a) - (383)
OTC interest rate swaps........................... - (522) - 965
</TABLE>
(a) Gains and losses realized on the future sale or purchase of marketable
securities will generally offset any net unrealized gains and losses.
See Note 5, Concentrations of Credit and Other Risk, for a discussion of
credit risk as it pertains to certain of the above financial instruments.
NOTE 5 - CONCENTRATIONS OF CREDIT AND OTHER RISK
Credit risk represents the accounting loss that would be recognized at the
reporting date if counterparties (See Note 4, Financial Instruments, for
further discussion) failed completely to perform as contracted.
Concentrations of credit risk (whether on- or off-balance sheet) relate to
groups of customers or counterparties that have similar economic or
industry characteristics that would cause their ability to meet contractual
obligations to be similarly affected by changes in economic or other
conditions. The Company does not have a significant loss exposure to any
individual customer or counterparty.
The Company's customer receivables and gas and electric revenues arise from
deliveries of natural gas to approximately 272,000 customers and
electricity to approximately 346,000 customers in Louisville and adjacent
areas in Kentucky. For the year ended December 31, 1995, 75% of total
revenue was derived from electric operations and 25% from gas operations.
The Company's operation and maintenance employees are members of the
International Brotherhood of Electrical Workers (IBEW) Local 2100 which
represents approximately one-half of the Company's workforce. The
Company's collective bargaining agreement with IBEW employees expires in
November 1998.
NOTE 6 - MARKETABLE SECURITIES
The Company adopted the provisions of Statement of Financial Accounting
Standards No. 115, ACCOUNTING FOR CERTAIN INVESTMENTS IN DEBT AND EQUITY
SECURITIES January 1, 1994. Accordingly, the Company's marketable
securities have been determined to be "available-for-sale" and are stated
at market value in the accompanying balance sheets. The available-for-sale
category of investments results in the classification of unrealized gains
and losses on investments in common equity, net of income taxes, until such
gains and losses are realized, at which time they are recognized in
earnings. Proceeds from sales of available-for-sale securities in 1995
were $151,422,000, which resulted in realized gains of
-35-
<PAGE>
$1,621,000 and losses of $3,440,000, calculated using the specific
identification method. Proceeds from sales of available-for-sale
securities in 1994 were $56,085,000, which resulted in realized gains of
$1,557,000 and losses of $1,538,000. The differences between amortized and
unamortized cost basis of the Company's investments in marketable
securities as of December 31, 1995 and 1994, were immaterial.
Approximate cost, fair value, and other required information about the
Company's available-for-sale securities by major security type as of
December 31, 1995 and 1994, follow (in thousands of $):
<TABLE>
<CAPTION>
1995 1994
------------------------------------- ---------------------------------------
Fixed Fixed
Equity Income Total Equity Income Total
-------- -------- ------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Cost....................... $7,399 $13,429 $20,828 $23,622 $29,701 $53,323
Unrealized gains........... 58 1 59 41 - 41
Unrealized losses.......... (198) (240) (438) (2,399) (827) (3,226)
------ ------- ------- ------- ------- -------
Fair values................ $7,259 $13,190 $20,449 $21,264 $28,874 $50,138
------ ------- ------- ------- ------- -------
------ ------- ------- ------- ------- -------
- -------------------------------------------------------------------------------------------------------------------
Fair Values:
No maturity.............. $6,620 $ - $ 6,620 $20,415 $ - $20,415
Maturities:
Less than one year..... 639 2,710 3,349 849 2,519 3,368
One to five years...... - 8,808 8,808 - 16,968 16,968
Five to ten years...... - 831 831 - 1,958 1,958
Over ten years......... - 164 164 - 3,381 3,381
No single date......... - 677 677 - 4,048 4,048
------ ------- ------- ------- ------- -------
Total Fair Values.......... $7,259 $13,190 $20,449 $21,264 $28,874 $50,138
------ ------- ------- ------- ------- -------
------ ------- ------- ------- ------- -------
</TABLE>
The Company's available-for-sale securities were classified as Marketable
Securities at December 31, 1995. In 1994, available-for-sale securities
were classified as Other Property and Investments in the accompanying
balance sheet.
NOTE 7 - PENSION PLANS AND RETIREMENT BENEFITS
PENSION PLANS. The Company has two non-contributory, defined-benefit
pension plans, covering all eligible employees. Retirement benefits are
based on the employee's years of service, age at retirement and
compensation. The Company's policy is to fund annual actuarial costs, up
to the maximum amount deductible for income tax purposes, as determined
under the frozen entry age actuarial cost method. The assets of the plans
consist primarily of common stocks, corporate bonds and United States
government securities.
The Company also has a supplemental executive retirement plan that covers
officers of the Company. The plan provides retirement benefits based on
average earnings during the final three years prior to retirement, reduced
by social security benefits, any pension benefits received from plans of
prior employers, and by amounts received under the pension plans referred
to in the preceding paragraph.
-36-
<PAGE>
Pension costs were $4,977,000 for 1995, $4,423,000 for 1994, and
$2,669,000 for 1993, of which approximately $761,000, $693,000, and
$425,000, respectively, were charged to construction. The components of
periodic pension expense are shown below (in thousands of $):
<TABLE>
<CAPTION>
1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
Service cost-benefits earned during the period.. $ 4,361 $ 4,813 $ 4,516
Interest cost on projected benefit obligation... 14,328 13,057 12,117
Actual return on plan assets.................... (45,608) (489) (13,602)
Amortization of transition asset................ (1,112) (1,112) (1,112)
Net amortization and deferral................... 33,008 (11,846) 750
-------- -------- --------
Net pension cost................................ $ 4,977 $ 4,423 $ 2,669
-------- -------- --------
-------- -------- --------
</TABLE>
The funded status of the pension plans at December 31 is shown below (in
thousands of $):
<TABLE>
<CAPTION>
1995 1994
---- ----
<S> <C> <C>
Actuarial present value of accumulated plan benefits:
Vested............................................... $166,525 $132,260
Non-Vested........................................... 8,577 14,023
-------- --------
Accumulated benefit obligation....................... 175,102 146,283
Effect of projected future compensation.............. 31,764 18,473
-------- --------
Projected benefit obligation......................... 206,866 164,756
Plan assets at fair value............................ 207,470 159,638
-------- --------
Plan assets in excess of (less than) projected
benefit obligation................................. 604 (5,118)
Unrecognized net transition asset.................... (11,412) (12,524)
Unrecognized prior service cost...................... 28,938 24,257
Unrecognized net gain................................ (43,652) (36,266)
-------- --------
Accrued pension liability.............................. $(25,522) $(29,651)
-------- --------
-------- --------
</TABLE>
The assumptions used in determining the actuarial valuations are as
follows:
<TABLE>
<CAPTION>
1995 1994
---- ----
<S> <C> <C>
Assumed discount rate to determine
projected benefit obligation........... 7.5% 8.5%
Assumed long-term rate of return
on plan assets......................... 8.5% 8.5%
Assumed annual rate of increase in
future compensation levels............. 3.5% - 4% 4.5% - 5%
</TABLE>
POST-RETIREMENT BENEFITS. The Company provides certain health care and
life insurance benefits for eligible retired employees. Post-retirement
health care benefits are subject to a maximum amount payable by the
Company. The Company adopted Statement of Financial Accounting Standards
No. 106, EMPLOYERS' ACCOUNTING FOR POST-RETIREMENT BENEFITS OTHER THAN
PENSIONS (SFAS No. 106) January 1, 1993. SFAS No. 106 requires the
accrual of the expected cost of retiree benefits other than pensions during
the employee's years of service with the Company. The Company is
amortizing the discounted present value of the post-retirement benefit
obligation at the date of adoption over 20 years. Prior to January 1,
-37-
<PAGE>
1993, the cost of retiree health care and life insurance benefits was
generally recognized when paid.
The components of the net periodic post-retirement benefit cost as
calculated under SFAS No. 106 are as follows (in thousands of $):
<TABLE>
<CAPTION>
1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
Service cost ........................... $ 595 $ 621 $ 701
Interest cost........................... 2,706 2,386 2,614
Amortization of transition obligation... 1,337 1,337 1,395
------ ------ ------
Post-retirement benefit cost............ $4,638 $4,344 $4,710
------ ------ ------
------ ------ ------
</TABLE>
The accumulated post-retirement benefit obligation as calculated under SFAS
No. 106 at December 31, is shown below (in thousands of $):
<TABLE>
<CAPTION>
1995 1994
---- ----
<S> <C> <C>
Retirees............................................ $(19,965) $(18,487)
Fully eligible active employees..................... (2,768) (1,927)
Other active employees.............................. (15,082) (9,789)
-------- --------
Accumulated post-retirement benefit obligation...... (37,815) (30,203)
Unrecognized net loss (gain)........................ 3,480 (3,275)
Unrecognized transition obligation.................. 22,727 24,064
-------- --------
Accrued post-retirement benefit liability........... $(11,608) $ (9,414)
-------- --------
-------- --------
</TABLE>
The accumulated post-retirement benefit obligation was determined using an
assumed discount rate of 7.5% for 1995 and 8.5% for 1994. Assumed
compensation increases for projected life insurance benefits for affected
groups was 4% for 1995 and 5% for 1994. An assumed health care cost trend
rate of 10% was assumed for 1995, gradually decreasing to 5% in ten years
and thereafter.
A 1% increase in the assumed health care cost trend rate would increase the
accumulated post-retirement benefit obligation by approximately $1.5
million and the annual service and interest cost by approximately $200,000.
No funding has been established by the Company for post-retirement
benefits.
POST-EMPLOYMENT BENEFITS. The Company adopted Statement of Financial
Accounting Standards No. 112, EMPLOYERS' ACCOUNTING FOR POST-EMPLOYMENT
BENEFITS (SFAS No. 112) January 1, 1994. SFAS No. 112 requires the
accrual of the expected cost of benefits to former or inactive employees
after employment but before retirement. The cumulative effect of the
accounting change was recorded in the first quarter of 1994 and decreased
net income by $3.4 million.
EARLY RETIREMENT/WORKFORCE REDUCTION. During the last quarter of 1993,
the Company eliminated approximately 350 full-time positions. The cost of
the employee reduction program was approximately $11.5 million, and
consisted primarily of separation payments, enhanced early retirement
benefits, and health care benefits. See Note 3, Non-Recurring Charges.
-38-
<PAGE>
THRIFT SAVINGS PLAN. The Company has a Thrift Savings Plan under
Section 401(k) of the Internal Revenue Code. The plan covers all regular
full-time employees with one year or more of service at the Company. Under
the plan, eligible employees may defer and contribute to the plan a portion
of current compensation in order to provide future retirement benefits.
The Company makes contributions to the plan by matching a portion of
employee contributions according to a formula established by the plan.
These costs were approximately $1,750,000 for 1995, $1,701,000 for 1994,
and $1,795,000 for 1993.
NOTE 8 - FEDERAL AND STATE INCOME TAXES
Components of income tax expense are shown in the table below (in thousands
of $):
<TABLE>
<CAPTION>
1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
Included in Operating:
Current - Federal........................ $36,379 $35,552 $31,082
- State.......................... 9,138 9,003 8,920
Deferred - Federal-net.................... 4,021 (969) 13,185
- State-net...................... 2,728 955 3,933
Amortization of investment tax credit..... (4,742) (4,619) (4,786)
------- ------- -------
Total................................. $47,524 $39,922 $52,334
------- ------- -------
Included in Other Income and (Deductions):
Current - Federal........................ $ (555) $(4,626) $11,009
- State.......................... (343) (1,277) 4,034
Deferred - Federal-net.................... 240 19 (8,473)
- State-net...................... 60 1 (3,707)
Amortization of investment tax credit..... - - (3,035)
------- ------- -------
Total................................. $ (598) $(5,883) $ (172)
------- ------- -------
Included in Cumulative Effect of a Change
in Accounting for Post-Employment Benefits:
Deferred - Federal........................ $ - $(1,814) $ -
- State.......................... - (466) -
------- ------- -------
Total................................. $ - $(2,280) $ -
------- ------- -------
Total Income Tax Expense.................... $46,926 $31,759 $52,162
------- ------- -------
------- ------- -------
</TABLE>
Variations in income tax expense are largely attributable to changes in
pre-tax income.
Provisions for deferred income taxes-net consist of the tax effects of the
following temporary differences (in thousands of $):
<TABLE>
<CAPTION>
1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
Depreciation and amortization................. $15,140 $12,609 $ (255)
Alternative minimum tax....................... - - 5,387
Pension overfunding........................... 2,078 (4,357) (823)
Accrued liabilities not currently deductible.. (9,076) (5,343) 1,210
Change in accounting principle................ - (2,280) -
Other........................................ (1,093) (2,903) (581)
------- ------- ------
Total....................................... $ 7,049 $(2,274) $4,938
------- ------- ------
------- ------- ------
</TABLE>
-39-
<PAGE>
The net provisions for deferred income taxes increased in 1995 largely due
to current year funding of one of the Company's defined-benefit pension
plans. Fluctuations in deferred income taxes attributable to liabilities
accrued for financial reporting, which are not currently deductible on the
Company's tax return, occurred in 1995 and 1994 due to the timing of when
such liabilities are paid. Deferred income taxes attributable to
depreciation and amortization in 1993 reflect the reversal of prior years'
accumulated deferred income taxes as a result of the sale of a portion of
Trimble County Unit 1. See Note 15, Jointly Owned Electric Utility Plant,
for a further discussion of the sale.
Net deferred tax liabilities resulting from book-tax temporary differences
are shown below (in thousands of $):
<TABLE>
<CAPTION>
1995 1994
---- ----
<S> <C> <C>
Deferred Tax Liabilities:
Depreciation and other plant related items... $297,929 $281,696
Other liabilities............................ 7,714 7,305
-------- --------
305,643 289,001
-------- --------
Deferred Tax Assets:
Investment tax credit........................ 33,919 35,833
Income taxes due to customers................ 32,363 33,456
Pension overfunding.......................... 9,075 11,145
Other assets................................. 25,470 15,331
-------- --------
100,827 95,765
-------- --------
Net deferred income tax liability.......... $204,816 $193,236
-------- --------
-------- --------
</TABLE>
The Company's effective income tax rate is computed by dividing the
aggregate of current income taxes, deferred income taxes-net, and the
amortization of investment tax credit by net income before the deduction of
such taxes. Reconciliation of the statutory Federal income tax rate to the
effective income tax rate is shown in the table below:
<TABLE>
<CAPTION>
1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
Statutory Federal income tax rate............. 35.0% 35.0% 35.0%
State income taxes net of Federal benefit..... 5.8 5.9 6.0
Amortization of investment tax credit......... (3.6) (5.1) (5.5)
Other differences-net......................... (1.1) (.5) 1.1
---- ---- ----
Effective Income Tax Rate..................... 36.1% 35.3% 36.6%
---- ---- ----
---- ---- ----
</TABLE>
NOTE 9 - OTHER INCOME AND DEDUCTIONS
Other income and deductions consisted of the following at December 31 (in
thousands of $):
<TABLE>
<CAPTION>
1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
Interest and dividend income....................... $ 5,732 $ 4,568 $ 3,112
Gains (losses) on fixed asset disposal............. 1,090 1,427 (3,523)
Gain on sale of 12.88% portion of Trimble County... - - 3,869
Donations.......................................... (144) (1,015) (909)
Income taxes and other............................. (2,902) (2,529) (636)
------- ------- -------
Total other income and deductions.................. $ 3,776 $ 2,451 $ 1,913
------- ------- -------
------- ------- -------
</TABLE>
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<PAGE>
NOTE 10 - PREFERRED STOCK
In December 1995, the Company redeemed the 858,128 outstanding shares of
its 7.45% Cumulative Preferred Stock with a par value of $25 per share at a
redemption price of $25.75 per share.
NOTE 11 - FIRST MORTGAGE BONDS
Annual requirements for the sinking funds of the Company's First Mortgage
Bonds (other than the First Mortgage Bonds issued in connection with the
Pollution Control Bonds) are the amounts necessary to redeem 1% of the
highest principal amount of each series of bonds at any time outstanding.
Property additions (166 2/3% of principal amounts of bonds otherwise
required to be so redeemed) have been applied in lieu of cash. It is the
intent of the Company to apply property additions to meet 1996 sinking fund
requirements of the First Mortgage Bonds.
The trust indenture securing the First Mortgage Bonds constitutes a direct
first mortgage lien upon substantially all property owned by the Company.
The indenture, as supplemented, provides in substance that, under certain
specified conditions, portions of retained earnings will not be available
for the payment of dividends on common stock. No portion of retained
earnings is presently restricted by this provision.
Pollution Control Bonds (Louisville Gas and Electric Company Projects)
issued by Jefferson and Trimble Counties, Kentucky, are secured by the
assignment of loan payments by the Company to the Counties pursuant to loan
agreements, and further secured by the delivery from time to time of an
equal amount of the Company's First Mortgage Bonds, Pollution Control
Series. First Mortgage Bonds so delivered are summarized in the Statements
of Capitalization. No principal or interest on these First Mortgage Bonds
is payable unless default on the loan agreements occurs. The interest rate
reflected in the Statements of Capitalization applies to the Pollution
Control Bonds.
In April 1995, the Company issued $40 million of Jefferson County,
Kentucky, Pollution Control Revenue Bonds, 5.90% Series, due April 15,
2023. The proceeds of the bonds were used to redeem the outstanding 9.25%
Series of Pollution Control Bonds due July 1, 2015.
The Company has outstanding interest rate swap agreements totaling $30
million related to its Pollution Control Revenue Bonds, Variable Rate
Series, due September 1, 2017. See Note 4, Financial Instruments.
The Company's First Mortgage Bonds, 5.625% Series of $16 million is
scheduled to mature June 1, 1996, and the 6.75% Series of $20 million is
scheduled to mature in 1998. There are no scheduled maturities of
Pollution Control Bonds for the five years subsequent to December 31, 1995.
The Company has no cash sinking fund requirements.
NOTE 12 - NOTES PAYABLE
The Company had no notes payable at December 31, 1995, and 1994.
-41-
<PAGE>
At December 31, 1995, the Company had unused lines of credit of $160
million, for which it pays commitment fees. The credit lines are scheduled
to expire during the year 2000. Management expects to renegotiate these
lines when they expire.
NOTE 13 - COMMITMENTS AND CONTINGENCIES
CONSTRUCTION PROGRAM. The Company had commitments in connection with its
construction program aggregating approximately $11 million at December 31,
1995. Construction expenditures for the years 1996 and 1997 are estimated
to total approximately $220 million.
FERC ORDER NO. 636. Prior to the implementation of Order No. 636, the
Company had purchased natural gas and pipeline transportation services from
Texas Gas Transmission Corporation (Texas Gas). The Company now purchases
only transportation services from Texas Gas and purchases natural gas from
many other sources under contracts for varying periods of time. See
Management's Discussion and Analysis, Future Outlook, under Item 7.
Under Order No. 636, pipelines may recover costs associated with the
transition to and implementation of this order from pipeline customers,
including the Company. The Commission issued an order, based on
proceedings that were held to investigate the impact of Order No. 636 on
utilities and ratepayers in Kentucky, providing that transition costs
assessed on utilities by the pipelines, which are clearly identifiable as
being related to the cost of the commodity itself, are appropriate to be
recovered from customers through the gas supply clause. During 1995, the
Company paid Texas Gas and began recovering from its customers
approximately $4.8 million in transition costs. It is estimated that about
$1.4 million in additional transition costs will be incurred by the Company
during 1996 and about $1.3 million in 1997, and these costs are also
expected to be recovered from customers. These transition costs are billed
by Texas Gas pursuant to orders issued by FERC in transition cost
regulatory proceedings in which the Company is a party. Pursuant to these
FERC orders, no additional transition costs are expected to be billed after
1997.
OPERATING LEASE. The Company has an operating lease for its corporate
office building that is scheduled to expire in June 2005. Total expense in
connection with this lease for 1995, 1994, and 1993 was $2,020,000,
$2,192,000, and $2,436,000, respectively. The future minimum annual lease
payments under the lease agreement for years subsequent to December 31,
1995, are as follows (in thousands of $):
<TABLE>
<S> <C>
1996............................. $ 2,850
1997............................. 2,850
1998............................. 2,850
1999............................. 2,850
2000............................. 3,178
Thereafter....................... 15,782
-------
Total......................... $30,360
-------
-------
</TABLE>
ENVIRONMENTAL. The Clean Air Act Amendments of 1990 (the Act) impose
stringent limits on emissions of sulfur dioxide and nitrogen oxides by
electric utility generating plants. The Company is well-positioned in the
market to be a "clean" power provider without the large capital
expenditures that are expected to be incurred by many other utilities. All
of the
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<PAGE>
Company's coal-fired boilers are equipped with sulfur dioxide "scrubbers"
and already achieve the final sulfur dioxide emission rates required by the
year 2000 under the legislation. However, as part of its ongoing capital
construction program, the Company has spent $22 million to date and, based
on engineering estimates from contractors, anticipates incurring additional
capital expenditures of approximately $8 million in 1996 for remedial
measures necessary to meet the Act's requirements for nitrogen oxides. The
overall financial impact of the legislation on the Company is expected to
be minimal.
In May 1994, the Company completed extensive modification at its Mill Creek
plant aimed at controlling certain particulate emissions which have
allegedly damaged metal surfaces on adjacent properties. The Air Pollution
Control District of Jefferson County (APCD) and the Company are currently
conducting a field sampling program to demonstrate the effectiveness of the
plant modifications. In an effort to resolve property damage claims of
adjacent residents, the Company commenced extensive negotiations and
property damage settlements with residents who are not parties to any
pending litigation. Through December 1995, the Company has settled
property damage claims filed by residents at an aggregate cost of
approximately $14.7 million. In management's opinion, settlement of the
limited number of these remaining non-litigated claims should not have a
material adverse impact on the financial position or results of operations
of the Company.
In August 1993, 34 persons filed a complaint in Jefferson Circuit Court
against the Company seeking certification of a class consisting of all
persons within 2.5 miles of the Mill Creek plant who have allegedly
suffered personal injury or property damage as a result of emissions from
the plant. The plaintiffs sought compensation for personal injury and
property damage, injunctive relief, a fund to finance future medical
monitoring of area residents and other relief. In June 1994, the court
denied the plaintiffs' motion for certification of the class and thus
limited the scope of the litigation to the claims of the individual
plaintiffs. In August 1995, the court granted the plaintiffs' motion for
leave to file an amended complaint to bring a total of 537 individual
plaintiffs into the pending litigation. The plaintiffs subsequently filed
a motion to certify a class consisting of all persons within 3.5 miles of
the plant who have allegedly suffered property damage. The court has not
yet ruled on that motion. In January 1996, the plaintiffs waived all
claims for compensation for personal injuries, fear of cancer, emotional
distress, loss of income, injunctive relief, and medical monitoring. The
Company stipulated nuisance as to plaintiffs located within 2.5 miles of
the plant, but reserved the right to assert lack of causation and all
affirmative defenses including statute of limitations. The plaintiffs also
waived claims for punitive damages with respect to all plaintiffs located
within 2.5 miles. The plaintiffs are currently pursuing claims solely for
property damage and annoyance allegedly due to emissions from the plant.
The Company intends to vigorously defend itself in the pending litigation.
In response to a notification from the APCD that the Company's Cane Run
plant may be the source of a potential exceedance of the National Ambient
Air Quality Standards for sulfur dioxide, the Company submitted a draft
action plan and modeling schedule to the APCD and the United States
Environmental Protection Agency (USEPA). The APCD and USEPA have approved
the submittals, and a Company contractor is currently conducting additional
modeling activities. Although it is expected that corrective action will
be accomplished through capital improvements, until the modeling activities
are complete, the Company cannot determine the precise impact of this
matter.
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<PAGE>
In March 1994, the APCD adopted a regulation requiring a 15% reduction
from 1990 volatile organic compound (VOC) emissions from industrial sources
in an effort to ensure compliance with the National Ambient Air Quality
Standards for ozone. There are currently no demonstrated technologies for
control of VOC emissions from coal-fired boilers. Consequently, compliance
with the regulation could require limits on generation at the Mill Creek
and Cane Run plants, unless the APCD adopts a provision for compliance
through utilization of banked emission allowances. The Company is
currently negotiating with the APCD for an exclusion from the VOC reduction
requirements. As an alternative, the APCD is considering additional
nitrogen oxide reduction requirements for the Company. The Company cannot
determine the precise impact of this matter.
The Company owns or formerly owned three primary sites where manufactured
gas plant operations were conducted. Remedial investigations performed at
the three sites have identified coal tar and other contaminants typical of
manufactured gas plant operations. The Company is currently awaiting
regulatory determinations from the Kentucky Natural Resources and
Environmental Protection Cabinet on the level of remediation required for
each site. Until such regulatory determinations are made, the Company is
unable to precisely determine cleanup costs for these sites. However,
based on the results of studies at the three sites, management currently
estimates that total cleanup costs will fall within a range of $3 million
to $12 million and has recorded an accrual of approximately $3 million in
the accompanying financial statements.
The Company, along with a number of other companies, has been identified as
a potentially responsible party (PRP) allegedly liable for cleanup under
the Comprehensive Environmental Response Compensation and Liability Act as
amended at four off-site waste treatment or disposal sites. Under the law,
each PRP potentially could be held jointly and severally liable for the
cost of cleanup, but would have the right to seek contribution from other
PRPs. The sites targeted for cleanup in which the Company has been
identified as a PRP include: the Smith's Farm site located in Bullitt
County, Kentucky, the Sonora and Carlie Middleton Burn sites located in
Hardin County, Kentucky, and the M.T. Richards site located in Crossville,
Illinois. With respect to the Smith's Farm site, USEPA has identified the
Company as a de minimis PRP and is currently pursuing other parties for the
vast majority of the $60 million in cleanup costs as estimated by USEPA.
The Company is participating in settlement discussions in an effort to
resolve any alleged liability which it may have. With respect to the
Sonora Site and Carlie Middleton Burn Site, the Company is involved in
litigation with USEPA and approximately 10 companies in an effort to
resolve liability for approximately $1.8 million in cleanup costs incurred
by USEPA. With respect to the M.T. Richards site, the Company has been
identified as a de minimis party and has reached a tentative settlement for
$7,500, subject to approval by the government and entry by the court.
While it is not possible at this time to predict the exact outcome or
precise impact of these matters, management believes that these matters
should not have a material adverse impact on the financial position or
results of operations of the Company.
NOTE 14 - TRIMBLE COUNTY GENERATING PLANT
Trimble County Unit 1 (Trimble County), a 495-megawatt coal-fired electric
generating unit placed into service in December 1990, has been the subject
of numerous legal and regulatory proceedings to determine the appropriate
ratemaking treatment to implement the Kentucky
-44-
<PAGE>
Public Service Commission's 1988 decision that the Company should not be
allowed to recover 25% of the cost of the Unit from ratepayers.
On July 19, 1995, the Commission issued an order in which it ruled that the
Company refund $33.8 million to its electric customers, including interest.
The Commission stated in its July 19 order that the principal amount to be
refunded represented 25% of the revenues collected by the Company, during
the period May 1988 through December 1990, on Trimble County construction
work in progress (CWIP) included in the Company's rate base in the 1988
rate case. The order also required the Company to file a plan for
implementing the refund.
On December 1, 1995, the Company and the other parties to the proceedings
filed with the Commission a unanimous settlement agreement that was
approved by the Commission on December 8, 1995. Under the agreement, which
resolves all outstanding issues, the Company has agreed to refund
approximately $22 million to current electric customers, the majority of
which will be paid by credits to customers' bills over five years. In
addition, the Company has agreed to pay $900,000 per year for five years to
the Metro Human Needs Alliance, Inc., a not-for-profit Louisville-based
corporation, for the sole purpose of funding low-income energy assistance
programs in the service territory. The Company also agreed to revise the
residential decoupling methodology approved by the Commission in 1994 in a
manner that would reduce revenues collected from residential customers
during 1996 and 1997 by a total of approximately $1.8 million. Finally,
the parties agreed that all appeals currently pending in state courts
regarding the Commission's orders in the Company's most recent general rate
case would be dismissed.
Reference is made to Note 15, Jointly Owned Electric Utility Plant, for a
discussion of the sale of 25% of Trimble County.
NOTE 15 - JOINTLY OWNED ELECTRIC UTILITY PLANT
The Company owns a 75% undivided interest in Trimble County Unit 1.
Accounting for the 75% portion of the Unit, which the Commission has
allowed to be reflected in customer rates, is similar to the Company's
accounting for other wholly-owned utility plants.
Of the remaining 25% of the Unit, Illinois Municipal Electric Agency (IMEA)
purchased a 12.12% undivided interest in the Unit on February 28, 1991, and
Indiana Municipal Power Agency (IMPA) purchased a 12.88% undivided interest
on February 1, 1993. Each is responsible for their proportionate ownership
share of operation and maintenance expenses and incremental assets, and for
fuel used.
The following data represent shares of the jointly owned property:
<TABLE>
<CAPTION>
Trimble County
-------------------------------------
LG&E IMPA IMEA Total
---- ---- ---- -----
<S> <C> <C> <C> <C>
Ownership interest....... 75% 12.88% 12.12% 100%
Mw capacity.............. 371.25 63.75 60 495
</TABLE>
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<PAGE>
NOTE 16 - SEGMENTS OF BUSINESS
The Company is a regulated public utility engaged in the generation,
transmission, distribution, and sale of electricity and the storage,
distribution, and sale of natural gas.
<TABLE>
<CAPTION>
1995 1994 1993
---- ---- ----
(Thousands of $)
<S> <C> <C> <C>
Operating Information
Operating Revenues
Electric........................... $ 542,337(a) $ 558,946 $ 570,210
Gas................................ 181,126 200,129 204,915
---------- ---------- ----------
Total............................ $ 723,463 $ 759,075 $ 775,125
---------- ---------- ----------
---------- ---------- ----------
Pre-tax Operating Income
Electric........................... $ 152,199 $ 139,594 $ 171,016
Gas................................ 16,651 11,368 17,436
---------- ---------- ----------
Total............................ $ 168,850 $ 150,962 $ 188,452
---------- ---------- ----------
---------- ---------- ----------
Other Information
Depreciation and Amortization
Electric........................... $ 74,437 $ 71,882 $ 69,753
Gas................................ 11,322 10,637 9,902
Non-Jurisdictional................. - - 232
---------- ---------- ----------
Total............................ $ 85,759 $ 82,519 $ 79,887
---------- ---------- ----------
---------- ---------- ----------
Construction Expenditures
Electric........................... $ 66,661 $ 71,592 $ 74,165
Gas................................ 26,762 23,806 24,622
---------- ---------- ----------
Total............................ $ 93,423 $ 95,398 $ 98,787
---------- ---------- ----------
---------- ---------- ----------
Investment Information-December 31
Identifiable Assets
Electric........................... $1,501,568 $1,514,287 $1,537,387
Gas................................ 268,840 252,946 241,930
---------- ---------- ----------
Total............................ 1,770,408 1,767,233 1,779,317
Other Assets (b).................... 209,082 199,357 195,267
---------- ---------- ----------
Total Assets..................... $1,979,490 $1,966,590 $1,974,584
---------- ---------- ----------
---------- ---------- ----------
</TABLE>
(a) Net of Refund - Trimble County Settlement of $28.3 million.
(b) Includes cash and temporary cash investments, marketable securities,
accounts receivable, unamortized debt expense, and other property
and investments.
-46-
<PAGE>
REPORT OF MANAGEMENT
The management of Louisville Gas and Electric Company is responsible for the
preparation and integrity of the financial statements and related information
included in this Annual Report. These statements have been prepared in
accordance with generally accepted accounting principles applied on a consistent
basis and, necessarily, include amounts that reflect the best estimates and
judgment of management.
The Company's financial statements have been audited by Arthur Andersen LLP,
independent public accountants. Management has made available to Arthur
Andersen LLP all the Company's financial records and related data as well as the
minutes of shareholders' and directors' meetings.
Management has established and maintains a system of internal controls that
provide reasonable assurance that transactions are completed in accordance with
management's authorization, that assets are safeguarded and that financial
statements are prepared in conformity with generally accepted accounting
principles. Management believes that an adequate system of internal controls is
maintained through the selection and training of personnel, appropriate division
of responsibility, establishment and communication of policies and procedures
and by regular reviews of internal accounting controls by the Company's internal
auditors. Management reviews and modifies its system of internal controls in
light of changes in conditions and operations, as well as in response to
recommendations from the internal auditors. These recommendations for the year
ended December 31, 1995 did not identify any significant deficiencies in the
design and operation of the Company's internal control structure.
The Audit Committee of the Board of Directors is composed entirely of outside
directors. In carrying out its oversight role for the financial reporting and
internal controls of the Company, the Audit Committee meets regularly with the
Company's independent public accountants, internal auditors and management. The
Audit Committee reviews the results of the independent accountants' audit of the
financial statements and their audit procedures, and discusses the adequacy of
internal accounting controls. The Audit Committee also approves the annual
internal auditing program, and reviews the activities and results of the
internal auditing function. Both the independent public accountants and the
internal auditors have access to the Audit Committee at any time.
Louisville Gas and Electric Company maintains and internally communicates a
written code of business conduct that addresses, among other items, potential
conflicts of interest, compliance with laws, including those relating to
financial disclosure, and the confidentiality of proprietary information.
-47-
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO LOUISVILLE GAS AND ELECTRIC COMPANY:
We have audited the accompanying balance sheets and statements of
capitalization of Louisville Gas and Electric Company (a Kentucky corporation
and a wholly owned subsidiary of LG&E Energy Corp.) as of December 31, 1995 and
1994, and the related statements of income, retained earnings and cash flows for
each of the three years in the period ended December 31, 1995. These financial
statements and the schedule referred to below are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements and schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Louisville Gas and Electric
Company as of December 31, 1995 and 1994, and the results of its operations and
its cash flows for each of the three years in the period ended December 31,
1995, in conformity with generally accepted accounting principles.
As discussed in Notes 1 and 7 to the financial statements, effective
January 1, 1993, the Company changed its methods of accounting for income taxes
and post-retirement benefits other than pensions, and effective January 1, 1994,
the Company changed its method of accounting for post-employment benefits.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedule listed under Item 14(a)2 is
presented for purposes of complying with the Securities and Exchange
Commission's rules and is not part of the basic financial statements. This
schedule has been subjected to the auditing procedures applied in our audits of
the basic financial statements and, in our opinion, fairly states in all
material respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.
Louisville, Kentucky Arthur Andersen LLP
January 30, 1996
------------------------------------------
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<PAGE>
SELECTED QUARTERLY FINANCIAL DATA (Unaudited)
(Thousands of $)
Selected financial data for the four quarters of 1995 and 1994 are shown
below. Because of seasonal fluctuations in temperature and other factors,
results for quarters may fluctuate throughout the year.
<TABLE>
<CAPTION>
Quarters Ended
-------------------------------------------------------
March June September December
----- ---- --------- --------
<S> <C> <C> <C> <C>
1995
Operating Revenues.................. $199,517 $167,821 $196,351 $159,774(a)
Net Operating Income................ 32,409 30,015 47,774 11,128
Net Income.......................... 21,839 21,085 38,346 1,914
Net Income Available for
Common Stock...................... 20,222 19,458 36,780 413
1994
Operating Revenues.................. $219,679 $173,042 $190,117 $176,237
Net Operating Income................ 6,603 29,873 45,913 28,651
Net Income (Loss)................... (16,695) 20,636 35,438 18,941
Net Income (Loss) Available for
Common Stock...................... (18,073) 19,256 33,935 17,374
</TABLE>
(a) Net of Refund - Trimble County Settlement of $28.3 million.
----------------------------------
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
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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 13, 1996, pursuant to Regulation 14A under the Securities
Exchange Act of 1934. Such proxy statement is incorporated herein by this
reference. In accordance with General Instruction G of Form 10-K, the
information required by Item 10 relating to executive officers has been included
in Part I of this Form 10-K. The Louisville Gas and Electric Company (LG&E) is
a subsidiary of LG&E Energy Corp. At December 31, 1995, LG&E Energy Corp.
controlled 100% of the common stock of LG&E. There are situations where LG&E
Energy Corp. interacts with its affiliated companies through the use of shared
facilities, common employees, and other business relationships. In these
situations, LG&E receives payment in accordance with regulatory requirements for
the services provided to affiliated companies.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a) 1. Financial Statements (included in Item 8):
Statements of Income for the three years ended December 31, 1995
(page 26).
Statements of Retained Earnings for the three years ended
December 31, 1995 (page 26).
Balance Sheets - December 31, 1995, and 1994 (page 27).
Statements of Cash Flows for the three years ended December 31,
1995 (page 28).
Statements of Capitalization - December 31, 1995, and 1994
(page 29).
Notes to Financial Statements (pages 30-46).
Report of Management (page 47).
Report of Independent Public Accountants (page 48).
Selected Quarterly Financial Data for 1995 and 1994 (page 49).
2. Financial Statement Schedule (included in Part IV):
Schedule II - Valuation and Qualifying Accounts for the three years
ended December 31, 1995 (page 66).
All other schedules have been omitted as not applicable or not required or
because the information required to be shown is included in the Financial
Statements or the accompanying Notes to Financial Statements.
-50-
<PAGE>
3. Exhibits:
Exhibit
No. Description
-------- -----------
3.01 Copy of Restated Articles of Incorporation, as amended. [Filed as
Exhibit 3.01 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1993, and incorporated by reference herein]
3.02 Copy of Amendment to Articles of Incorporation, effective May 25,
1989. [Filed as Exhibit 3.02 to the Company's Annual Report on Form
10-K for the year ended December 31, 1993, and incorporated by
reference herein]
3.03 Copy of Amendment to Articles of Incorporation, effective February
6, 1992. [Filed as Exhibit 3.03 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1993, and incorporated by
reference herein]
3.04 Copy of Amendment to Articles of Incorporation, effective April 8,
1993. [Filed as Exhibit 3.04 to the Company's Annual Report on Form
10-K for the year ended December 31, 1993, and incorporated by
reference herein]
3.05 Copy of Amendment to Articles of Incorporation, effective May 19,
1993. [Filed as Exhibit 3.05 to the Company's Form 10-K for the
year ended December 31, 1993, and incorporated by reference herein]
3.06 Copy of Bylaws, as amended through December 15, 1995.
4.01 Copy of Trust Indenture dated November 1, 1949, from the Company to
Harris Trust and Savings Bank, Trustee. [Filed as Exhibit 7.01 to
Registration Statement 2-8283 and incorporated by reference herein]
4.02 Copy of Supplemental Indenture dated February 1, 1952, which is a
supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit
4.05 to Registration Statement 2-9371 and incorporated by reference
herein]
4.03 Copy of Supplemental Indenture dated February 1, 1954, which is a
supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit
4.03 to Registration Statement 2-11923 and incorporated by reference
herein]
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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]
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<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]
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<PAGE>
4.22 Copy of Supplemental Indenture dated September 15, 1982, which is a
supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit
4.22 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1982, and incorporated by reference herein]
4.23 Copy of Supplemental Indenture dated February 15, 1984, which is a
supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit
4.23 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1984, and incorporated by reference herein]
4.24 Copy of Supplemental Indenture dated July 1, 1985, which is a
supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit
4.24 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1985, and incorporated by reference herein]
4.25 Copy of Supplemental Indenture dated November 15, 1986, which is a
supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit
4.25 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1986, and incorporated by reference herein]
4.26 Copy of Supplemental Indenture dated November 16, 1986, which is a
supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit
4.26 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1986, and incorporated by reference herein]
4.27 Copy of Supplemental Indenture dated August 1, 1987, which is a
supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit
4.27 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1987, and incorporated by reference herein]
4.28 Copy of Supplemental Indenture dated February 1, 1989, which is a
supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit
4.28 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1988, and incorporated by reference herein]
4.29 Copy of Supplemental Indenture dated February 2, 1989, which is a
supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit
4.29 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1988, and incorporated by reference herein]
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<PAGE>
4.30 Copy of Supplemental Indenture dated June 15, 1990, which is a
supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit
4.30 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1990, and incorporated by reference herein]
4.31 Copy of Supplemental Indenture dated November 1, 1990, which is a
supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit
4.31 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1990, and incorporated by reference herein]
4.32 Copy of Supplemental Indenture dated September 1, 1992, which is a
supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit
4.32 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1992, and incorporated by reference herein]
4.33 Copy of Supplemental Indenture dated September 2, 1992, which is a
supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit
4.33 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1992, and incorporated by reference herein]
4.34 Copy of Supplemental Indenture dated August 15, 1993, which is a
supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit
4.34 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1993, and incorporated by reference herein]
4.35 Copy of Supplemental Indenture dated August 16, 1993, which is a
supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit
4.35 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1993, and incorporated by reference herein]
4.36 Copy of Supplemental Indenture dated October 15, 1993, which is a
supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit
4.36 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1993, and incorporated by reference herein]
10.01 Copies of Agreement between Sponsoring Companies re: Project D of
Atomic Energy Commission, dated May 12, 1952, Memorandums of
Understanding between Sponsoring Companies re: Project D of Atomic
Energy Commission, dated September 19, 1952 and October 28, 1952,
and Power Agreement between Ohio Valley Electric Corporation and
Atomic Energy Commission, dated October 15, 1952. [Filed as Exhibit
13(y) to Registration Statement 2-9975 and incorporated by reference
herein]
-55-
<PAGE>
10.02 Copy of Modification No. 1 dated July 23, 1953, to the Power
Agreement between Ohio Valley Electric Corporation and Atomic Energy
Commission. [Filed as Exhibit 4.03(b) to Registration Statement
2-24920 and incorporated by reference herein]
10.03 Copy of Modification No. 2 dated March 15, 1964, to the Power
Agreement between Ohio Valley Electric Corporation and Atomic Energy
Commission. [Filed as Exhibit 5.02(c) to Registration Statement
2-61607 and incorporated by reference herein]
10.04 Copy of Modification No. 3 and No. 4 dated May 12, 1966 and January
7, 1967, respectively, to the Power Agreement between Ohio Valley
Electric Corporation and Atomic Energy Commission. [Filed as
Exhibits 4(a)(13) and 4(a)(14) to Registration Statement 2-26063 and
incorporated by reference herein]
10.05 Copy of Modification No. 5 dated August 15, 1967, to the Power
Agreement between Ohio Valley Electric Corporation and Atomic Energy
Commission. [Filed as Exhibit 13(c) to Registration Statement
2-27316 and incorporated by reference herein]
10.06 Copies of (i) Inter-Company Power Agreement, dated July 10, 1953,
between Ohio Valley Electric Corporation and Sponsoring Companies
(which Agreement includes as Exhibit A the Power Agreement, dated
July 10, 1953, between Ohio Valley Electric Corporation and
Indiana-Kentucky Electric Corporation); (ii) First Supplementary
Transmission Agreement, dated July 10, 1953, between Ohio Valley
Electric Corporation and Sponsoring Companies; (iii) Inter-Company
Bond Agreement, dated July 10, 1953, between Ohio Valley Electric
Corporation and Sponsoring Companies; (iv) Inter-Company Bank Credit
Agreement, dated July 10, 1953, between Ohio Valley Electric
Corporation and Sponsoring Companies. [Filed as Exhibit 5.02(f) to
Registration Statement 2-61607 and incorporated by reference herein]
10.07 Copy of Modification No. 1 and No. 2 dated June 3, 1966 and January
7, 1967, respectively, to Inter-Company Power Agreement dated July
10, 1953. [Filed as Exhibits 4(a)(8) and 4(a)(10) to Registration
Statement 2-26063 and incorporated by reference herein]
10.08 Copies of Amendments to Agreements (iii) and (iv) referred to under
10.07 above as follows: (i) Amendment to Inter-Company Bond
Agreement and (ii) Amendment to Inter-Company Bank Credit Agreement.
[Filed as Exhibit 5.02(h) to Registration Statement 2-61607 and
incorporated by reference herein]
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<PAGE>
10.09 Copy of Modification No. 1, dated August 20, 1958, to the First
Supplementary Transmission Agreement, dated July 10, 1953, among
Ohio Valley Electric Corporation and the Sponsoring Companies.
[Filed as Exhibit 5.02(i) to Registration Statement 2-61607 and
incorporated by reference herein]
10.10 Copy of Modification No. 2, dated April 1, 1965, to the First
Supplementary Transmission Agreement, dated July 10, 1953, among
Ohio Valley Electric Corporation and the Sponsoring Companies.
[Filed as Exhibit 5.02(j) to Registration Statement 2-61607 and
incorporated by reference herein]
10.11 Copy of Modification No. 3, dated January 20, 1967, to the First
Supplementary Transmission Agreement, dated July 10, 1953, among
Ohio Valley Electric Corporation and the Sponsoring Companies.
[Filed as Exhibit 4(a)(7) to Registration Statement 2-26063 and
incorporated by reference herein]
10.12 Copy of Modification No. 6, dated November 15, 1967, to the Power
Agreement between Ohio Valley Electric Corporation and Atomic Energy
Commission. [Filed as Exhibit 4(g) to Registration Statement
2-28524 and incorporated by reference herein]
10.13 Copy of Modification No. 3, dated November 15, 1967, to the
Inter-Company Power Agreement dated July 10, 1953. [Filed as
Exhibit 4.02(m) to Registration Statement 2-37368 and incorporated
by reference herein]
10.14 Copy of Modification No. 7, dated November 5, 1975, to the Power
Agreement between Ohio Valley Electric Corporation and Atomic Energy
Commission. [Filed as Exhibit 5.02(n) to Registration Statement
2-56357 and incorporated by reference herein]
10.15 Copy of Modification No. 4, dated November 5, 1975, to the
Inter-Company Power Agreement dated July 10, 1953. [Filed as
Exhibit 5.02(o) to Registration Statement 2-56357 and incorporated
by reference herein]
10.16 Copy of Modification No. 4, dated April 30, 1976, to the First
Supplementary Transmission Agreement, dated July 10, 1953, among
Ohio Valley Electric Corporation and the Sponsoring Companies.
[Filed as Exhibit 5.02(p) to Registration Statement 2-61607 and
incorporated by reference herein]
-57-
<PAGE>
10.17 Copy of Modification No. 8, dated June 23, 1977, to the Power
Agreement between Ohio Valley Electric Corporation and Atomic Energy
Commission. [Filed as Exhibit 5.02(q) to Registration Statement
2-61607 and incorporated by reference herein]
10.18 Copy of Modification No. 9, dated July 1, 1978, to the Power
Agreement between Ohio Valley Electric Corporation and Atomic Energy
Commission. [Filed as Exhibit 5.02(r) to Registration Statement
2-63149 and incorporated by reference herein]
10.19 Copy of Modification No. 10, dated August 1, 1979, to the Power
Agreement between Ohio Valley Electric Corporation and Atomic Energy
Commission. [Filed as Exhibit 2 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1979, and incorporated by
reference herein]
10.20 Copy of Modification No. 11, dated September 1, 1979, to the Power
Agreement between Ohio Valley Electric Corporation and Atomic Energy
Commission. [Filed as Exhibit 3 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1979, and incorporated by
reference herein]
10.21 Copy of Modification No. 5, dated September 1, 1979, to the
Inter-Company Power Agreement dated July 5, 1953, among Ohio Valley
Electric Corporation and Sponsoring Companies. [Filed as Exhibit 4
to the Company's Annual Report on Form 10-K for the year ended
December 31, 1979, and incorporated by reference herein]
10.22 Copy of Modification No. 12, dated August 1, 1981, to the Power
Agreement between Ohio Valley Electric Corporation and Atomic Energy
Commission. [Filed as Exhibit 10.25 to the Company's Annual Report
on Form 10-K for the year ended December 31, 1981, and incorporated
by reference herein]
10.23 Copy of Modification No. 6, dated August 1, 1981, to the
Inter-Company Power Agreement dated July 5, 1953, among Ohio Valley
Electric Corporation and Sponsoring Companies. [Filed as Exhibit
10.26 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1981, and incorporated by reference herein]
10.24 Copy of Diversity Power Agreement dated September 9, 1987, between
East Kentucky Power Cooperative and the Company covering the
purchase and sale of power between the two companies from 1988
through 1995. [Filed as Exhibit 10.28 to the Company's Annual
Report on Form 10-K for the year ended December 31, 1987, and
incorporated by reference herein]
-58-
<PAGE>
10.25 Copy of Supplemental Executive Retirement Plan as amended through
January 3, 1990, covering all officers of the Company. [Filed as
Exhibit 10.29 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1989, and incorporated by reference herein]
10.26 Copy of LG&E Energy Corp. Deferred Stock Compensation Plan effective
January 1, 1992, covering non-employee directors of LG&E Energy
Corp. and its subsidiaries. [Filed as Exhibit 10.34 to LG&E Energy
Corp.'s Annual Report on Form 10-K for the year ended December 31,
1991, and incorporated by reference herein]
10.27 Copy of form of change in control agreement for officers of
Louisville Gas and Electric Company. [Filed as Exhibit 10.38 to the
Company's Annual Report on Form 10-K for the year ended December 31,
1992, and incorporated by reference herein]
10.28 Copy of Supplemental Executive Retirement Plan for Roger W. Hale,
effective June 1, 1989. [Filed as Exhibit 10.40 to the Company's
Annual Report on Form 10-K for the year ended December 31, 1992, and
incorporated by reference herein]
10.29 Copy of Nonqualified Savings Plan covering officers of the Company,
effective January 1, 1992. [Filed as Exhibit 10.41 to the Company's
Annual Report on Form 10-K for the year ended December 31, 1992, and
incorporated by reference herein]
10.30 Copy of Modification No. 13, dated September 1, 1989, to the Power
Agreement between Ohio Valley Electric Corporation and Atomic Energy
Commission. [Filed as Exhibit 10.42 to the Company's Annual Report
on Form 10-K for the year ended December 31, 1993, and incorporated
by reference herein]
10.31 Copy of Modification No. 14, dated January 15, 1992, to the Power
Agreement between Ohio Valley Electric Corporation and Atomic Energy
Commission. [Filed as Exhibit 10.43 to the Company's Annual Report
on Form 10-K for the year ended December 31, 1993, and incorporated
by reference herein]
10.32 Copy of Modification No. 7, dated January 15, 1992, to the
Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley
Electric Corporation and Sponsoring Companies. [Filed as Exhibit
10.44 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1993, and incorporated by reference herein]
-59-
<PAGE>
10.33 Copy of Modification No. 15, dated February 15, 1993, to the Power
Agreement between Ohio Valley Electric Corporation and Atomic Energy
Commission. [Filed as Exhibit 10.45 to the Company's Annual Report
on Form 10-K for the year ended December 31, 1993, and incorporated
by reference herein]
10.34 Copy of Firm Transportation Agreement, dated November 1, 1993,
between Texas Gas Transmission Corporation and the Company covering
the transmission of natural gas. [Filed as Exhibit 10.46 to the
Company's Annual Report on Form 10-K for the year ended December 31,
1993, and incorporated by reference herein]
10.35 Copy of Firm No-Notice Transportation Agreement effective November
1, 1993, between Texas Gas Transmission Corporation and the Company
(8-year term) covering the transmission of natural gas. [Filed as
Exhibit 10.47 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1993, and incorporated by reference herein]
Copy of Firm No-Notice Transportation Agreement effective November
1, 1993, between Texas Gas Transmission Corporation and the Company
(2-year term) covering the transmission of natural gas. [Filed as
Exhibit 10.47 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1993, and incorporated by reference herein]
Copy of Firm No-Notice Transportation Agreement effective November
1, 1993, between Texas Gas Transmission Corporation and the Company
(5-year term) covering the transmission of natural gas. [Filed as
Exhibit 10.47 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1993, and incorporated by reference herein]
10.36 Copy of Employment Contract between LG&E Energy Corp. and Roger W.
Hale effective November 3, 1993. [Filed as Exhibit 10.50 to LG&E
Energy Corp.'s Annual Report on Form 10-K for the year ended
December 31, 1993, and incorporated by reference herein]
10.37 Copy of LG&E Energy Corp. Stock Option Plan for Non-Employee
Directors. [Filed as Exhibit 10.51 to LG&E Energy Corp.'s Annual
Report on Form 10-K for the year ended December 31, 1993, and
incorporated by reference herein]
-60-
<PAGE>
10.38 Copy of Coal Supply Agreement, dated August 9, 1989, between Shawnee
Coal Company, Roberts Brothers Coal Company, and the Company
covering the purchase of coal. [Filed as Exhibit 10.41 to the
Company's Annual Report on Form 10-K for the year ended December 31,
1994, and incorporated by reference herein]
10.39 Copy of Amendment No. 1, dated January 1, 1991, to the Coal Supply
Agreement, dated August 9, 1989, between Shawnee Coal Company,
Roberts Brothers Coal Company, and the Company covering the purchase
of coal. [Filed as Exhibit 10.42 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1994, and incorporated by
reference herein]
10.40 Copy of Amendment No. 2, dated November 27, 1991, to the Coal Supply
Agreement, dated August 9, 1989, between Shawnee Coal Company,
Roberts Brothers Coal Company, and the Company covering the purchase
of coal. [Filed as Exhibit 10.43 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1994, and incorporated by
reference herein]
10.41 Copy of Amendment No. 3, dated January 1, 1994, to the Coal Supply
Agreement, dated August 9, 1989, between Shawnee Coal Company,
Roberts Brothers Coal Company, and the Company covering the purchase
of coal. [Filed as Exhibit 10.44 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1994, and incorporated by
reference herein]
10.42 Copy of Amendment No. 4, dated January 1, 1995, to the Coal Supply
Agreement, dated August 9, 1989, between Shawnee Coal Company,
Roberts Brothers Coal Company, and the Company covering the purchase
of coal. [Filed as Exhibit 10.45 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1994, and incorporated by
reference herein]
10.43 Copy of Modification No. 8, dated January 19, 1994, to the
Inter-Company Power Agreement, dated July 10, 1953, among Ohio
Valley Electric Corporation and the Sponsoring Companies.
10.44 Copy of Amendment dated March 1, 1995, to Firm No-Notice
Transportation Agreements dated November 1, 1993 (2-Year, 5-Year,
and 8-Year), between Texas Gas Transmission Corporation and the
Company covering the transmission of natural gas.
-61-
<PAGE>
10.45 Copy of Firm Transportation Agreement, dated March 1, 1995, between
Texas Gas Transmission Corporation and the Company (expires October
31, 1998) covering the transportation of natural gas.
Copy of Firm Transportation Agreement, dated March 1, 1995, between
Texas Gas Transmission Corporation and the Company (expires October
31, 2001) covering the transportation of natural gas.
10.46 Copy of Coal Supply Agreement, dated January 1, 1996, between
Lafayette Coal Company, Black Beauty Coal Company and the Company
covering the purchase of coal.
10.47 Copy of Coal Supply agreement, dated January 1, 1996, between Green
Coal Company and the Company covering the purchase of coal.
10.48 Copy of Coal Supply Agreement, dated December 15, 1995, between W.
B. Coal Company, Inc., Windsor Coal Company and the Company covering
the purchase of coal.
10.49 Copy of Coal Supply Agreement dated January 1, 1996, between Peabody
Coalsales Company and the Company covering the purchase of coal.
10.50 Copy of Amended and Restated Omnibus Long-Term Incentive Plan
effective January 1, 1996, covering officers and key employees of
the Company. [Filed as Exhibit 10.52 to LG&E Energy Corp.'s Annual
Report on Form 10-K for the year ended December 31, 1995, and
incorporated by reference herein]
10.51 Copy of Short-Term Incentive Plan effective January 1, 1996,
covering officers and key employees of the Company. [Filed as
Exhibit 10.53 to LG&E Energy Corp.'s Annual Report on Form 10-K for
the year ended December 31, 1995, and incorporated by reference
herein]
10.52 Copy of form of first amendment to change in control agreement for
officers of the Company and key employees. [Filed as Exhibit 10.54
to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended
December 31, 1995, and incorporated by reference herein]
10.53 Copy of Amendment to the Non-Qualified Savings Plan, effective
January 1, 1992. [Filed as Exhibit 10.55 to LG&E Energy Corp.'s
Annual Report on Form 10-K for the year ended December 31, 1995, and
incorporated by reference herein]
-62-
<PAGE>
10.54 Copy of Amendment to the Non-Qualified Savings Plan, effective
January 1, 1995. [Filed as Exhibit 10.56 to LG&E Energy Corp.'s
Annual Report on Form 10-K for the year ended December 31, 1995, and
incorporated by reference herein]
10.55 Copy of Amendment to the Non-Qualified Savings Plan, effective
January 1, 1995. [Filed as Exhibit 10.57 to LG&E Energy Corp.'s
Annual Report on Form 10-K for the year ended December 31, 1995, and
incorporated by reference herein]
10.56 Copy of Amendment to the Supplemental Executive Retirement Plan,
effective January 1, 1992. [Filed as Exhibit 10.58 to LG&E Energy
Corp.'s Annual Report on Form 10-K for the year ended December 31,
1995, and incorporated by reference herein]
10.57 Copy of Amendment to the Supplemental Executive Retirement Plan,
effective January 1, 1993. [Filed as Exhibit 10.59 to LG&E Energy
Corp.'s Annual Report on Form 10-K for the year ended December 31,
1995, and incorporated by reference herein]
10.58 Copy of Amendment to the Supplemental Executive Retirement Plan,
effective January 1, 1995. [Filed as Exhibit 10.60 to LG&E Energy
Corp.'s Annual Report on Form 10-K for the year ended December 31,
1995, and incorporated by reference herein]
10.59 Copy of Amendment to the Supplemental Executive Retirement Plan,
effective May 1, 1995. [Filed as Exhibit 10.61 to LG&E Energy
Corp.'s Annual Report on Form 10-K for the year ended December 31,
1995, and incorporated by reference herein]
12 Computation of Ratio of Earnings to Fixed Charges
23 Consent of Independent Public Accountants
24 Power of Attorney
27 Financial Data Schedule
(b) Executive Compensation Plans and Arrangements:
Supplemental Executive Retirement Plan as amended through January 3,
1990, covering all officers of the Company. [Filed as Exhibit 10.29
to the Company's Annual Report on Form 10-K for the year ended
December 31, 1989, and incorporated by reference herein]
-63-
<PAGE>
LG&E Energy Corp. Deferred Stock Compensation Plan effective January
1, 1992, covering non-employee directors of LG&E Energy Corp. and
its subsidiaries. [Filed as Exhibit 10.34 to LG&E Energy Corp.'s
Annual Report on Form 10-K for the year ended December 31, 1991, and
incorporated by reference herein]
Form of change in control agreement for officers of Louisville Gas
and Electric Company. [Filed as Exhibit 10.38 to the Company's
Annual Report on Form 10-K for the year ended December 31, 1992, and
incorporated by reference herein]
Supplemental Executive Retirement Plan for R. W. Hale, effective
June 1, 1989. [Filed as Exhibit 10.40 to the Company's Annual
Report on Form 10-K for the year ended December 31, 1992, and
incorporated by reference herein]
Nonqualified Savings Plan covering officers of the Company effective
January 1, 1992. [Filed as Exhibit 10.41 to the Company's Annual
Report on Form 10-K for the year ended December 31, 1992, and
incorporated by reference herein]
Employment Contract between LG&E Energy Corp. and Roger W. Hale
effective November 3, 1993. [Filed as Exhibit 10.50 to LG&E Energy
Corp.'s Annual Report on Form 10-K for the year ended December 31,
1993, and incorporated by reference herein]
LG&E Energy Corp. Stock Option Plan for Non-Employee Directors.
[Filed as Exhibit 10.51 to LG&E Energy Corp.'s Annual Report on Form
10-K for the year ended December 31, 1993, and incorporated by
reference herein]
Amended and Restated Omnibus Long-Term Incentive Plan effective
January 1, 1996, covering officers and key employees of the Company.
[Filed as Exhibit 10.52 to LG&E Energy Corp.'s Annual Report on Form
10-K for the year ended December 31, 1995, and incorporated by
reference herein]
Short-Term Incentive Plan effective January 1, 1996, covering
officers and key employees of the Company. [Filed as Exhibit 10.53
to LG&E Energy Corp.'s Annual Report on Form 10-K for the year ended
December 31, 1995, and incorporated by reference herein]
Form of first amendment to change in control agreement for officers
of the Company and key employees. [Filed as Exhibit 10.54 to LG&E
Energy Corp.'s Annual Report on Form 10-K for the year ended
December 31, 1995, and incorporated by reference herein]
-64-
<PAGE>
Amendment to the Non-Qualified Savings Plan, effective January 1,
1992. [Filed as Exhibit 10.55 to LG&E Energy Corp.'s Annual Report
on Form 10-K for the year ended December 31, 1995, and incorporated
by reference herein]
Amendment to the Non-Qualified Savings Plan, effective January 1,
1995. [Filed as Exhibit 10.56 to LG&E Energy Corp.'s Annual Report
on Form 10-K for the year ended December 31, 1995, and incorporated
by reference herein]
Amendment to the Non-Qualified Savings Plan, effective January 1,
1995. [Filed as Exhibit 10.57 to LG&E Energy Corp.'s Annual Report
on Form 10-K for the year ended December 31, 1995, and incorporated
by reference herein]
Amendment to the Supplemental Executive Retirement Plan, effective
January 1, 1992. [Filed as Exhibit 10.58 to LG&E Energy Corp.'s
Annual Report on Form 10-K for the year ended December 31, 1995, and
incorporated by reference herein]
Amendment to the Supplemental Executive Retirement Plan, effective
January 1, 1993. [Filed as Exhibit 10.59 to LG&E Energy Corp.'s
Annual Report on Form 10-K for the year ended December 31, 1995, and
incorporated by reference herein]
Amendment to the Supplemental Executive Retirement Plan, effective
January 1, 1995. [Filed as Exhibit 10.60 to LG&E Energy Corp.'s
Annual Report on Form 10-K for the year ended December 31, 1995, and
incorporated by reference herein]
Amendment to the Supplemental Executive Retirement Plan, effective
May 1, 1995. [Filed as Exhibit 10.61 to LG&E Energy Corp.'s Annual
Report on Form 10-K for the year ended December 31, 1995, and
incorporated by reference herein]
(c) Reports on Form 8-K:
On December 12, 1995, a report on Form 8-K was filed announcing the
Public Service Commission of Kentucky's approval of the Trimble County
power plant settlement agreement.
-65-
<PAGE>
SCHEDULE II
LOUISVILLE GAS AND ELECTRIC COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1995
(Thousands of $)
<TABLE>
<CAPTION>
Reserves Deducted from
Assets in Balance Sheet
---------------------------------
Other Accounts
Property Receivable
and (Uncollectible
Investments Accounts)
----------- --------------
<S> <C> <C>
Balance January 1, 1993..................................... $5,645 $1,109
Additions:
Charged to costs and expenses
Trimble County - non-jurisdictional depreciation...... 233
Other................................................. 2,500
Deductions:
Net charges of nature for which reserves were created...
Other................................................... 5,815 2,135
------ ------
Balance December 31, 1993................................... 63 1,474
Additions:
Charged to costs and expenses........................... 3,100
Deductions:
Net charges of nature for which reserves were created... 3,371
------ ------
Balance December 31, 1994................................... 63 1,203
Additions:
Charged to costs and expenses........................... 3,200
Deductions:
Net charges of nature for which reserves were created... 3,043
------ ------
Balance December 31, 1995................................... $ 63 $1,360
------ ------
------ ------
</TABLE>
-66-
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
LOUISVILLE GAS AND ELECTRIC COMPANY
Registrant
March 27, 1996 By Walter Z. Berger
- -------------- -------------------------------------
(Date) Walter Z. Berger
Executive Vice President and Chief
Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date indicated.
Signature Title Date
--------- ----- ------
ROGER W. HALE Chairman of the Board and
Chief Executive Officer
(Principal Executive Officer);
WALTER Z. BERGER Executive Vice President and
Chief Financial Officer
(Principal Financial and
Accounting Officer);
WILLIAM C. BALLARD, JR. Director;
OWSLEY BROWN II Director;
S. GORDON DABNEY Director;
GENE P. GARDNER Director;
J. DAVID GRISSOM Director;
DAVID B. LEWIS Director;
ANNE H. MCNAMARA Director;
T. BALLARD MORTON, JR. Director; and
DR. DONALD C. SWAIN Director.
By Walter Z. Berger March 27, 1996
-----------------------------------
WALTER Z. BERGER (Attorney-In-Fact)
-67-
<PAGE>
LOUISVILLE GAS AND ELECTRIC COMPANY
By-Laws Adopted November 7, 1956
As Amended Through December 15, 1995
ARTICLE I
MEETINGS OF STOCKHOLDERS
SECTION 1. The Annual Meeting of the stockholders of the Company shall be
held at a location in or out of Kentucky at a time and date to be fixed by the
Board of Directors each year. Notice of the annual meeting shall be mailed to
each stockholder entitled to notice at least ten (10) days before the Annual
Meeting.
SECTION 2. Except as otherwise mandated by Kentucky law and except as
otherwise provided in or fixed by or pursuant to the provisions of Article
Fourth of the Company's Amended Articles of Incorporation relating to the rights
of the holders of any class or series of stock having a preference over the
Company's Common Stock as to dividends or upon liquidation to elect directors
under specified circumstances, special meetings of stockholders may be called
only by the President of the Company or by the Board of Directors pursuant to a
resolution approved by a majority of the entire Board of Directors. For purposes
of these By-Laws, the phrase "Company's Amended Articles of Incorporation" shall
mean the Amended Articles of Incorporation of Louisville Gas and Electric
Company as in effect on February 1, 1987, and as thereafter amended from time to
time.
SECTION 3. A stockholder may vote in person or by proxy, filed with the
Secretary of the Company before or immediately upon the convening of the
meeting.
SECTION 4. Any action required or permitted to be taken by the stockholders
of the Company at a meeting of such holders may be taken without such a meeting
ONLY if a consent in writing setting forth the action so taken shall be signed
by all of the stockholders entitled to vote with respect to the subject matter
thereof.
SECTION 5. At an annual meeting of the stockholders, only such business
shall be conducted as shall have been properly brought before the meeting. To be
properly brought before an annual meeting, business must be (a) specified in the
notice of meeting (or any supplement thereto) given by or at the direction of
the Board of Directors, (b) otherwise properly brought before the meeting by or
at the direction of the Board of Directors, or (c) otherwise properly be
requested to be brought before the meeting by a stockholder. For business to be
properly requested to be brought before an annual meeting by a stockholder, the
stockholder must have given timely notice thereof in writing to the Secretary of
the Company. To be timely, a stockholder's notice must be delivered to or mailed
and received at the principal executive offices of the Company, not less than 90
days prior to the meeting; provided, however, that in the event that the date of
the meeting is not publicly announced by the Company by mail, press release or
otherwise more than 100 days prior to the meeting, notice by the stockholder to
be timely must be delivered to the Secretary of the Company not later than the
close of business on the tenth day following the day on which such announcement
of the date of the
<PAGE>
meeting was communicated to stockholders. A stockholder's notice to the
Secretary shall set forth as to each matter the stockholder proposes to bring
before the annual meeting (a) a brief description of the business desired to be
brought before the annual meeting and the reasons for conducting such business
at the annual meeting, (b) the name and address, as they appear on the Company's
books, of the stockholder proposing such business, (c) the class and number of
shares of the Company which are beneficially owned by the stockholder, and (d)
any material interest of the stockholder in such business. Notwithstanding
anything in the By-Laws to the contrary, no business shall be conducted at an
annual meeting except in accordance with the procedures set forth in this
Section 5. The Chairman of an annual meeting shall, if the facts warrant,
determine and declare to the meeting that business was not properly brought
before the meeting and in accordance with the provisions of this Section 5, and
if he should so determine, he shall so declare to the meeting that any such
business not properly brought before the meeting shall not be transacted.
ARTICLE II
BOARD OF DIRECTORS
SECTION 1. (a) The number of directors of the Company shall be fixed from
time to time by the Board of Directors, but shall be no fewer than nine (9) and
no more than 15. The Board of Directors may elect one of its members as Chairman
of the Board. Regular meetings of the Board of Directors shall be held at such
time and place as may be fixed by the Board of Directors. Except as otherwise
provided in or fixed by or pursuant to the provisions of Article Fourth of the
Company's Amended Articles of Incorporation relating to the rights of the
holders of any class or series of stock having a preference over the Company's
Common Stock as to dividends or upon liquidation to elect directors under
specified circumstances, the directors shall be classified, with respect to the
time for which they severally hold office, into three classes, as nearly equal
in number as possible, as determined by the Board of Directors, one class to be
originally elected for a term expiring at the annual meeting of stockholders to
be held in 1988, another class to be originally elected for a term expiring at
the annual meeting of stockholders to be held in 1989, and another class to be
originally elected for a term expiring at the annual meeting of stockholders to
be held in 1990, with each member of each class to hold office until his
successor is elected and qualified. At each annual meeting of the stockholders
of the Company and except as otherwise provided in or fixed by or pursuant to
the provisions of Article Fourth of the Company's Amended Articles of
Incorporation relating to the rights of the holders of any class or series of
stock having a preference over the Company's Common Stock as to dividends or
upon liquidation to elect directors under specified circumstances, the
successors of the class of directors whose term expires at that meeting shall be
elected to hold office for a term expiring at the annual meeting of stockholders
held in the third year following the year of their election.
(b) Advance notice of stockholder nominations for the election
of directors shall be given in the manner provided in Section 2 of Article IV of
these By-Laws.
2
<PAGE>
(c) Except as otherwise provided in or fixed by or pursuant to
the provisions of Article Fourth of the Company's Amended Articles of
Incorporation relating to the rights of the holders of any class or series of
stock having a preference over the Company's Common Stock as to dividends or
upon liquidation to elect directors under specified circumstances: (i) newly
created directorships resulting from any increase in the number of directors and
any vacancies on the Board of Directors resulting from death, resignation,
disqualification, removal or other cause shall be filled by the affirmative vote
of a majority of the remaining directors then in office, even though less than a
quorum of the Board of Directors; (ii) any director elected in accordance with
the preceding clause (i) shall hold office for the remainder of the full term of
the class of directors in which the new directorship was created or the vacancy
occurred and until such director's successor shall have been elected and
qualified; and (iii) no decrease in the number of directors constituting the
Board of Directors shall shorten the term of any incumbent director.
(d) Except as otherwise provided in or fixed by or pursuant to
the provisions of Article Fourth of the Company's Amended Articles of
Incorporation relating to the rights of the holders of any class or series of
stock having a preference over the Company's Common Stock as to dividends or
upon liquidation to elect directors under specified circumstances, any director
may be removed from office, with or without cause, only by the affirmative vote
of the holders of at least 80% of the combined voting power of the then
outstanding shares of the Company's stock entitled to vote generally (as defined
in Article Eighth of the Company's Amended Articles of Incorporation), voting
together as a single class. Notwithstanding the foregoing provisions of this
Paragraph (d), if at any time any stockholders of the Company have cumulative
voting rights with respect to the election of directors and less than the entire
Board of Directors is to be removed, no director may be removed from office if
the votes cast against his removal would be sufficient to elect him as a
director if then cumulatively voted at an election of the class of directors of
which he is a part.
SECTION 2. Regular Meetings shall be held at such time and place as may be
fixed by the Board of Directors.
SECTION 3. Special Meetings of the Board of Directors shall be held at the
call of the Chairman or of the President, or, in their absence, of a Vice
President, or at the request in writing of not less than three (3) members of
the Board.
SECTION 4. Regular and Special Meetings may be held outside of the State of
Kentucky.
SECTION 5. Notices of Regular and Special Meetings shall be sent to each
director at least one (1) day prior to the meeting.
SECTION 6. The business and affairs of the Company shall be managed by or
under the direction of the Board of Directors, except as may be otherwise
provided by law or by the Company's Amended Articles of Incorporation. Unless
otherwise provided by law, at each meeting of the Board of Directors, the
presence of a majority of the total number of directors shall constitute a
quorum for the transaction of business. Except as provided in Section 1(c) of
this Article II, the vote of a
3
<PAGE>
majority of the directors present at a meeting at which a quorum is present
shall be the act of the Board of Directors. In case at any meeting of the Board
of Directors a quorum shall not be present, the members of the Board of
Directors present may by majority vote adjourn the meeting from time to time
until a quorum shall attend.
SECTION 7. Directors may receive such fees or compensation for their
services as may be authorized by resolution of the Board of Directors. In
addition, expenses of attendance, if any, may be allowed for attendance at each
regular or special meeting.
SECTION 8. The Board of Directors, by resolution adopted by a majority of
the full Board of Directors, may designate from among its members an executive
committee and one or more other committees each of which, to the extent provided
in such resolution, shall have and exercise all the authority of the Board of
Directors, but no such committee shall have the authority to take action that
under Kentucky law can only be taken by a board of directors.
ARTICLE III
OFFICERS
SECTION 1. The officers of the Company shall be a Chief Executive Officer,
President, Chief Financial Officer, one or more Vice Presidents, Secretary,
Treasurer, Controller and such other officers (including, if so directed by a
resolution of the Board of Directors, Chairman of the Board) as the Board may
from time to time elect or appoint. Any two of the offices may be combined in
one person, but no officer shall execute, acknowledge, or verify any instrument
in more than one capacity. Officers are to be elected by the Board of Directors
of the Company at the first meeting of the Board following the annual meeting of
stockholders and, unless otherwise specified by the Board of Directors, shall be
elected to hold office for one year or until their successors are elected and
qualified. Any vacancy shall be filled by the Board of Directors, provided that
the Chief Executive Officer may fill such a vacancy until the Board of Directors
shall elect a successor. Except as provided below, officers shall perform those
duties usually incident to the office or as otherwise required by the Board of
Directors, the Chief Executive Officer, or the officer to whom they report. An
officer may be removed with or without cause and at any time by the Board of
Directors or by the Chief Executive Officer.
CHIEF EXECUTIVE OFFICER
SECTION 2. The Chief Executive Officer of the Company shall have full charge
of all of the affairs of the Company, shall preside at all meetings of the
stockholders and, in the absence of the Chairman of the Board, at meetings of
the Board of Directors.
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PRESIDENT
SECTION 3. The President shall exercise the functions of the Chief Executive
Officer during the absence or disability of the Chief Executive Officer.
CHIEF FINANCIAL OFFICER
SECTION 4. The Chief Financial Officer of the Company shall have full charge
of all of the financial affairs of the Company, including maintaining accurate
books and records, meeting all reporting requirements and controlling Company
funds.
VICE PRESIDENTS
SECTION 5. The Vice President or Vice Presidents may be designated as Vice
President, Senior Vice President or Executive Vice President, as the Board of
Directors or Chief Executive Officer may determine.
SECRETARY
SECTION 6. The Secretary shall be present at and record the proceedings of
all meetings of the Board of Directors and of the stockholders, give notices of
meetings of Directors and stockholders, have custody of the seal of the Company
and affix it to any instrument requiring the same, and shall have the power to
sign certificates for shares of stock of the Company.
TREASURER
SECTION 7. The Treasurer shall have charge of all receipts and disbursements
of the Company and be custodian of the Company's funds.
CONTROLLER
SECTION 8. The Controller shall have charge of the accounting records of the
Company.
CHAIRMAN OF THE BOARD
SECTION 9. In the event the Board of Directors elects a Chairman of the
Board and designates by resolution that the Chairman of the Board shall be an
officer of the corporation, the Chairman of the Board shall preside at all
meetings of the Board of Directors and serve the corporation in an advisory
capacity.
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ARTICLE IV
CAPITAL STOCK CERTIFICATES AND DIRECTOR NOMINATIONS
SECTION 1. The Board of Directors shall approve all stock certificates as to
form. The certificates for the various classes of stock, issued by the Company,
shall be printed or engraved with the facsimile signatures of the President and
Secretary and a facsimile seal of the Company. The Board of Directors shall
appoint transfer agents to issue and transfer certificates of stock, and
registrars to register said certificates.
SECTION 2. Except as otherwise provided in or fixed by or pursuant to the
provisions of Article Fourth of the Company's Amended Articles of Incorporation
relating to the rights of the holders of any class or series of stock having a
preference over the Company's Common Stock as to dividends or upon liquidation
to elect directors under specified circumstances, nominations for the election
of directors may be made by the Board of Directors or a committee appointed by
the Board of Directors or by any stockholder entitled to vote in the election of
directors generally. However, any stockholder entitled to vote in the election
of directors generally may nominate one or more persons for election as director
or directors at a stockholders' meeting only if written notice of such
stockholder's intent to make such nomination or nominations has been given
either by personal delivery or by United States mail, postage prepaid, to the
Secretary of the Company not later than 90 days in advance of such meeting;
provided, however, that in the event the date of the meeting is not publicly
announced by the Company by mail, press release or otherwise more than 100 days
prior to the meeting, notice by the stockholder to be timely must be delivered
not later than the close of business on the tenth day following the date on
which notice of such meeting was first communicated to stockholders. Each such
notice shall set forth (a) the name and address of the stockholder who intends
to make the nomination and of the person or persons to be nominated; (b) a
representation that the stockholder is a holder of record of stock of the
Company entitled to vote at such meeting and intends to appear in person or by
proxy at the meeting to nominate the person or persons specified in the notice;
(c) a description of all arrangements or understandings between the stockholder
and each nominee and any other person or persons (naming such person or persons)
pursuant to which the nomination or nominations are to be made by the
stockholder; (d) such other information regarding each nominee proposed by such
stockholder as would be required to be included in a proxy statement filed
pursuant to the proxy rules of the Securities and Exchange Commission, had the
nominee been nominated, or intended to be nominated, by the Board of Directors;
and (e) the consent of each nominee to serve as a director of the Company if so
elected. The Chairman of the meeting may refuse to acknowledge the nomination of
any person not made in compliance with the foregoing procedure.
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ARTICLE V
LOST STOCK CERTIFICATES
The Board of Directors may, in its discretion, direct that a new
certificate or certificates of stock be issued in place of any certificate or
certificates of stock theretofore issued by the Company, alleged to have been
stolen, lost or destroyed, and the Board of Directors when authorizing the
issuance of such new certificate or certificates may, in its discretion, and as
a condition precedent thereto, require the owner of such stolen, lost or
destroyed certificate or certificates or the legal representatives of such
owner, to give to the Company, its transfer agent or agents, its registrar or
registrars, as may be authorized or required to sign and countersign such new
certificate or certificates, a corporate surety bond in such sum as it may
direct as indemnity against any claim or claims that may be made against the
Company, its transfer agent or agents, its registrar or registrars, for or in
respect to the shares of stock represented by the certificate or certificates
alleged to have been stolen, lost or destroyed.
ARTICLE VI
DIVIDENDS ON PREFERRED STOCK
Dividends upon the 5% Cumulative Preferred Stock, $25 Par value, if
declared, shall be payable on January 15, April 15, July 15 and October 15 of
each year. If the date herein designated for the payment of any dividend shall,
in any year, fall upon a legal holiday, then the dividend payable on such date
shall be paid on the next day not a legal holiday.
Dividends in respect of each share of $8.90 Cumulative Preferred Stock
(without par value) of the Company shall be payable on October 16, 1978, when
and as declared by the Board of Directors of the Company, to holders of record
on September 29, 1978, and shall accrue from the date of original issuance of
said series. Thereafter, such dividends shall be payable on January 15, April
15, July 15, and October 15 in each year (or the next business day thereafter in
each case), when and as declared by the Board of Directors of the Company, for
the quarter-yearly period ending on the last business day of the preceding
month.
Dividends in respect of each share of Preferred Stock, Auction Series A
(without par value), of the Company shall be payable when and as declared by the
Board of Directors of the Company, on the dates and in the manner set forth in
the Amendment to the Articles of Incorporation of the Company setting forth the
terms of such series.
Dividends in respect of each share of $5.875 Cumulative Preferred Stock, of
the Company shall be payable when and as declared by the Board of Directors of
the Company, on the dates and in the manner set forth in the Amendment to the
Articles of Incorporation of the Company setting forth the terms of such series.
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ARTICLE VII
FINANCE
SECTION 1. The Board of Directors shall designate the bank or banks to be
used as depositories of the funds of the Company and shall designate the
officers and employees of the Company who may sign and countersign checks drawn
against the various accounts of the Company. The Board of Directors may
authorize the use of facsimile signatures on checks drawn against certain bank
accounts of the Company.
SECTION 2. Notes shall be signed by the President and either a Vice
President or the Treasurer. In the absence of the President, notes shall be
signed by two Vice Presidents, or a Vice President and the Treasurer.
ARTICLE VIII
SEAL
The seal of this Company shall be in the form of a circular disk, bearing
the following information:
(Louisville Gas and Electric Company)
( Incorporated Under the Laws of )
( Kentucky )
( Seal )
( 1913 )
ARTICLE IX
AMENDMENTS
Subject to the provisions of the Company's Amended Articles of
Incorporation, these By-Laws may be amended or repealed at any regular meeting
of the stockholders (or at any special meeting thereof duly called for that
purpose) by the holders of at least a majority of the voting power of the shares
represented and entitled to vote thereon at such meeting at which a quorum is
present; provided that in the notice of such special meeting notice of such
purpose shall be given. Subject to the laws of the State of Kentucky, the
Company's Amended Articles of Incorporation and these By-Laws, the Board of
Directors may by majority vote of those present at any meeting at which a quorum
is present amend these By-Laws, or adopt such other By-Laws as in their judgment
may be advisable for the regulation of the conduct of the affairs of the
Company.
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ARTICLE X
INDEMNIFICATION
SECTION 1. RIGHT TO INDEMNIFICATION. Each person who was or is a director
of the Company and who was or is made a party or is threatened to be made a
party to or is otherwise involved (including, without limitation, as a witness)
in any action, suit or proceeding, whether civil, criminal, administrative or
investigative (hereinafter a "proceeding"), by reason of the fact that he or she
is or was a director or officer of the Company or is or was serving at the
request of the Company as a director, officer, partner, trustee, employee or
agent of another corporation or of a partnership, joint venture, trust or other
enterprise, including service with respect to an employee benefit plan
(hereinafter an "Indemnified Director"), whether the basis of such proceeding is
alleged action in an official capacity as a director or officer or in any other
capacity while serving as a director or officer, shall be indemnified and held
harmless by the Company to the fullest extent permitted by the Kentucky Business
Corporation Act, as the same exists or may hereafter be amended, against all
expense, liability and loss (including, without limitation, attorneys' fees,
judgments, fines, ERISA excise taxes or penalties and amounts paid in
settlement) reasonably incurred or suffered by such Indemnified Director in
connection therewith and such indemnification shall continue as to an
Indemnified Director who has ceased to be a director or officer and shall inure
to the benefit of the Indemnified Director's heirs, executors and
administrators. Each person who was or is an officer of the Company and not a
director of the Company and who was or is made a party or is threatened to be
made a party to or is otherwise involved (including, without limitation, as a
witness) in any proceeding, by reason of the fact that he or she is or was an
officer of the Company or is or was serving at the request of the Company as a
director, officer, partner, trustee, employee or agent of another corporation or
of a partnership, joint venture, trust or other enterprise, including service
with respect to an employee benefit plan (hereinafter an "Indemnified Officer"),
whether the basis of such proceeding is alleged action in an official capacity
as an officer or in any other capacity while serving as an officer, shall be
indemnified and held harmless by the Company against all expense, liability and
loss (including, without limitation, attorneys' fees, judgments, fines, ERISA
excise taxes or penalties and amounts paid in settlement) reasonably incurred or
suffered by such Indemnified Officer to the same extent and under the same
conditions that the Company must indemnify an Indemnified Director pursuant to
the immediately preceding sentence and to such further extent as is not contrary
to public policy and such indemnification shall continue as to an Indemnified
Officer who has ceased to be an officer and shall inure to the benefit of the
Indemnified Officer's heirs, executors and administrators. Notwithstanding the
foregoing and except as provided in Section 2 of the this Article X with respect
to proceedings to enforce rights to indemnification, the Company shall indemnify
any Indemnified Director or Indemnified Officer in connection with a proceeding
(or part thereof) initiated by such Indemnified Director or Indemnified Officer
only if such proceeding (or part thereof) was authorized by the Board of
Directors of the Company. As hereinafter used in this Article X, the term
"indemnitee" means any Indemnified Director or Indemnified Officer. Any person
who is or was a director or officer of a subsidiary of the Company shall be
deemed to be serving in such capacity at the request of the Company for purposes
of this Article X. The right to
9
<PAGE>
indemnification conferred in this Article shall include the right to be paid by
the Company the expenses incurred in defending any such proceeding in advance of
its final disposition (hereinafter an "advancement of expenses"); provided,
however, that, if the Kentucky Business Corporation Act requires, an advancement
of expenses incurred by an indemnitee who at the time of receiving such advance
is a director of the Company shall be made only upon: (i) delivery to the
Company of an undertaking (hereinafter an "undertaking"), by or on behalf of
such indemnitee, to repay all amounts so advanced if it shall ultimately be
determined by final judicial decision from which there is no further right to
appeal (hereinafter, a "final adjudication") that such indemnitee is not
entitled to be indemnified for such expenses under this Article or otherwise;
(ii) delivery to the Company of a written affirmation of the indemnitee's good
faith belief that he has met the standard of conduct that makes indemnification
by the Company permissible under the Kentucky Business Corporation Act; and
(iii) a determination that the facts then known to those making the
determination would not preclude indemnification under the Kentucky Business
Corporation Act. The right to indemnification and advancement of expenses
incurred in this Section 1 shall be a contract right.
SECTION 2. RIGHT OF INDEMNITEE TO BRING SUIT. If a claim under Section 1 of
this Article X is not paid in full by the Company within sixty days after a
written claim has been received by the Company (except in the case of a claim
for an advancement of expenses, in which case the applicable period shall be
twenty days), the indemnitee may at any time thereafter bring suit against the
Company to recover the unpaid amount of the claim. If successful in whole or in
part to any such suit or in a suit brought by the Company to recover an
advancement of expenses pursuant to the terms of an undertaking, the indemnitee
also shall be entitled to be paid the expense of prosecuting or defending such
suit. In (i) any suit brought by the indemnitee to enforce a right to
indemnification hereunder (other than a suit to enforce a right to an
advancement of expenses brought by an indemnitee who will not be a director of
the Company at the time such advance is made) it shall be a defense that, and in
(ii) any suit by the Company to recover an advancement of expenses pursuant to
the terms of an undertaking the Company shall be entitled to recover such
expenses upon a final adjudication that, the indemnitee has not met the standard
of conduct that makes it permissible hereunder or under the Kentucky Business
Corporation Act (the "applicable standard of conduct") for the Company to
indemnify the indemnitee for the amount claimed. Neither the failure of the
Company (including its Board of Directors, independent legal counsel or its
stockholders) to have made a determination prior to the commencement of such
suit that indemnification of the indemnitee is proper in the circumstances
because the indemnitee has met the applicable standard of conduct, nor an actual
determination by the Company (including its Board of Directors, independent
legal counsel or its stockholders) that the indemnitee has not met the
applicable standard of conduct, shall create a presumption that the indemnitee
has not met the applicable standard of conduct or, in the case of such a suit
brought by the indemnitee, be a defense to such suit. In any suit brought by the
indemnitee to enforce a right to indemnification or to an advancement of
expenses hereunder, or by the Company to recover an advancement of expenses
pursuant to the terms of an undertaking, the burden of proving that the
indemnitee is not entitled to be indemnified or to such advancement of expenses
under this Article X or otherwise shall be on the Company.
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SECTION 3. NON-EXCLUSIVITY OF RIGHTS. The rights to indemnification and to
the advancement of expenses conferred in this Article X shall not be exclusive
of any other right which any person may have or hereafter acquire under any
statute, the Company's Articles of Incorporation, these By-Laws, any agreement,
any vote of stockholders or disinterested directors or otherwise.
SECTION 4. INSURANCE. The Company may maintain insurance, at its expense,
to protect itself and any director, officer, employee or agent of the Company or
another corporation, partnership, joint venture, trust or other enterprise
against any expense, liability or loss, whether or not the Company would have
the power to indemnify such person against such expense, liability or loss under
the Kentucky Business Corporation Act.
SECTION 5. INDEMNIFICATION OF EMPLOYEES AND AGENTS.
The Company may, to the extent authorized from time to time by the Board of
Directors, grant rights to indemnification and to the advancement of expenses to
any employee or agent of the Company and to any person serving at the request of
the Company as an agent or employee of another corporation or of a partnership,
joint venture, trust or other enterprise to the fullest extent of the provisions
of this Article X with respect to the indemnification and advancement of
expenses of directors and officers of the Company.
SECTION 6. REPEAL OR MODIFICATION. Any repeal or modification of any
provision of this Article X shall not adversely affect any rights to
indemnification and to advancement of expenses that any person may have at the
time of such repeal or modification with respect to any acts or omissions
occurring prior to such repeal or modification.
SECTION 7. SEVERABILITY. In case any one or more of the provisions of this
Article X, or any application thereof, shall be invalid, illegal or
unenforceable in any respect, the validity, legality and enforceability of the
remaining provisions of this Article X, and any other application thereof, shall
not in any way be affected or impaired thereby.
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- -------------------------------------------------------------------------------
MODIFICATION NO. 8
TO
INTER-COMPANY POWER AGREEMENT
DATED JULY 10, 1953
AMONG
OHIO VALLEY ELECTRIC CORPORATION,
APPALACHIAN POWER COMPANY,
THE CINCINNATI GAS & ELECTRIC COMPANY,
COLUMBUS SOUTHERN POWER COMPANY (formerly
COLUMBUS AND SOUTHERN OHIO ELECTRIC COMPANY),
THE DAYTON POWER AND LIGHT COMPANY,
INDIANA MICHIGAN POWER COMPANY (formerly
INDIANA & MICHIGAN ELECTRIC COMPANY),
KENTUCKY UTILITIES COMPANY,
LOUISVILLE GAS AND ELECTRIC COMPANY
MONONGAHELA POWER COMPANY,
OHIO EDISON COMPANY,
OHIO POWER COMPANY,
PENNSYLVANIA POWER COMPANY,
THE POTOMAC EDISON COMPANY,
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY,
THE TOLEDO EDISON COMPANY, and
WEST PENN POWER COMPANY.
-----------------------------
Dated as of January 19, 1994
-----------------------------
- -------------------------------------------------------------------------------
<PAGE>
MODIFICATION NO. 8
TO
INTER-COMPANY POWER AGREEMENT
THIS AGREEMENT dated as of the _____ day of __________, 1994, by and among
OHIO VALLEY ELECTRIC CORPORATION (herein called "OVEC" or "Corporation"),
APPALACHIAN POWER COMPANY (herein called "Appalachian"), THE CINCINNATI GAS &
ELECTRIC COMPANY (herein called "Cincinnati"), COLUMBUS SOUTHERN POWER COMPANY
(formerly COLUMBUS AND SOUTHERN OHIO ELECTRIC COMPANY) (herein called
"Columbus"), THE DAYTON POWER AND LIGHT COMPANY (herein called "Dayton"),
INDIANA MICHIGAN POWER COMPANY (formerly INDIANA & MICHIGAN ELECTRIC COMPANY)
(herein called "Indiana"), KENTUCKY UTILITIES COMPANY (herein called
"Kentucky"), LOUISVILLE GAS AND ELECTRIC COMPANY (herein called "Louisville"),
MONONGAHELA POWER COMPANY (herein called "Monongahela"), OHIO EDISON COMPANY
(herein called "Ohio Edison"), OHIO POWER COMPANY (herein called "Ohio Power"),
PENNSYLVANIA POWER COMPANY (herein called "Pennsylvania"), THE POTOMAC EDISON
COMPANY (herein called "Potomac"), SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
(herein called "Southern Indiana"), THE TOLEDO EDISON COMPANY (herein called
"Toledo"), and WEST PENN POWER COMPANY (herein called "West Penn"), all of the
foregoing, other than OVEC, being herein sometimes collectively referred to as
the Sponsoring Companies and individually as a Sponsoring Company.
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W I T N E S S E T H T H A T
WHEREAS, Corporation and the United States of America have heretofore
entered into Contract No. AT-(40-1)-1530 (redesignated Contract No. E-(40-1)-
1530, later redesignated Contract No. EY-76-C-05-1530 and later redesignated
Contract No. DE-AC05-760RO1530), dated October 15, 1952, providing for the
supply by Corporation of electric utility services to the United States Atomic
Energy Commission (hereinafter called "AEC") at AEC's project near Portsmouth,
Ohio (hereinafter called the "Project"), which Contract has heretofore been
modified by Modification No. 1, dated July 23, 1953, Modification No. 2, dated
as of March 15, 1964, Modification No. 3, dated as of May 12, 1966, Modification
No. 4, dated as of January 7, 1967, Modification No. 5, dated as of August 15,
1967, Modification No. 6, dated as of November 15, 1967, Modification No. 7,
dated as of November 5, 1975, Modification No. 8, dated as of June 23, 1977,
Modification No. 9, dated as of July 1, 1978, Modification No. 10, dated as of
August 1, 1979, Modification No. 11, dated as of September 1, 1979, Modification
No. 12, dated as of August 1, 1981, Modification No. 13, dated as of September
1, 1989, Modification No. 14, dated as of January 15, 1992, and Modification No.
15, dated as of February 1, 1993 (said Contract, as so modified, is hereinafter
called the "DOE Power Agreement"); and
WHEREAS, pursuant to the Energy Reorganization Act of 1974, the AEC was
abolished on January 19, 1975 and certain of its functions, including the
procurement of electric utility services for the Project, were transferred to
and vested in the Administrator of Energy Research and Development; and
WHEREAS, pursuant to the Department of Energy Organization Act, on October
1, 1977, all of the functions vested by law in the Administrator of Energy
Research and Development or the
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Energy Research and Development Administration were transferred to, and vested
in, the Secretary of Energy, the statutory head of the Department of Energy
(hereinafter called "DOE"); and
WHEREAS, the parties hereto have entered into a contract, herein called the
"Inter-Company Power Agreement," dated July 10, 1953, governing, among other
things, (a) the supply by the Sponsoring Companies of Supplemental Power in
order to enable Corporation to fulfill its obligations under the DOE Power
Agreement, and (b) the rights of the Sponsoring Companies to receive Surplus
Power (as defined in the Agreement identified in the next clause in this
preamble) as may be available at the Project Generating Stations and the
obligations of the Sponsoring Companies to pay therefor; and
WHEREAS, the Inter-Company Power Agreement has heretofore been amended by
Modification No. 1, dated as of June 3, 1966, Modification No. 2 dated as of
January 7, 1967, Modification No. 3, dated as of November 15, 1967, Modification
No. 4, dated as of November 5, 1975, Modification No. 5, dated as of September
1, 1979, Modification No. 6, dated as of August 1, 1981, and Modification No. 7,
dated as of January 15, 1992 (said contract so amended and as modified and
amended by this Modification No. 8 being herein and therein sometimes called the
"Agreement"); and
WHEREAS, OVEC and the Sponsoring Companies desire to enter into this
Modification No. 8 as more particularly hereinafter provided;
NOW, THEREFORE, the parties hereto agree with each other as follows:
1. Insert after SUBSECTION 1.0122 a new SUBSECTION 1.0123 as follows:
1.0123 "Emergency Power Supply Period" means any period of time
during which, at the request of one or more of the Sponsoring
Companies, OVEC and DOE have agreed to reduce the contract demand
under the DOE Power Agreement in order that one or more of the
Sponsoring Companies will have available additional Surplus
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<PAGE>
Power and Energy to prevent or alleviate an emergency which impairs or
jeopardizes the ability of the Sponsoring Company or Companies to meet
load.
2. Delete SUBSECTION 5.041 and substitute therefor the following:
5.041 Any Sponsoring Company's Surplus Power Reservation, established
as hereinbelow provided, shall remain in effect for a period of not
less than a calendar week except during an Emergency Power Supply
Period. Surplus Power Reservations shall provide the basis for
carrying out settlements between OVEC and Sponsoring Companies.
3. Delete SECTION 6.01 and substitute therefor the following:
6.01 TOTAL MONTHLY CHARGE. The amount to be paid Corporation each
month by he Sponsoring Companies for Surplus Power and Surplus Energy
supplied under this Agreement shall consist of the sum of an energy
charge, a demand charge and, if applicable, an emergency power
surcharge, all determined as set forth in this ARTICLE 6.
4. Delete SUBSECTION 6.035 and substitute therefor the following:
6.035 Determine the difference, if any, between (a) the aggregate of
the costs determined as provided in subsection 6.031 above and (b) the
sum of the demand charge to be charged to DOE determined as provided
in subsection 6.033 above plus the amounts (other than amounts for
fuel expense), if any, payable by DOE pursuant to paragraph 3 of
Section 2.04 of the DOE Power Agreement for billing kwh of
supplemental energy furnished from the Project Generating Stations.
The aggregate demand charge which shall be paid by or credited to all
Sponsoring Companies for such month shall be the amount of such
difference.
The portion thereof payable for such month by each Sponsoring Company
shall be computed by allocating such aggregate demand charge, based on
availability on a kilowatt-hour basis, among the calendar weeks (or
fractions thereof) of such month and shall be the total of the
products obtained by multiplying the respective Surplus power
Reservations of said Sponsoring Company for such weeks (or fraction
thereof) by the respective amounts so allocated.
5. Insert after SUBSECTION 6.035 a new SUBSECTION 6.036 as follows:
6.036 If, during an Emergency Power Supply Period, OVEC requests DOE
to reduce load so that more capacity and energy can be made available
to a Sponsoring Company or Companies affected by such emergency and if
DOE agrees to do so on condition that OVEC reimburse DOE for its
estimated costs of reducing load (emergency power surcharge), the
aggregate demand charge to be paid by each
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<PAGE>
Sponsoring Company shall be adjusted to reflect its agreed share of DOE's
emergency power surcharge paid or credited by OVEC to DOE. Such share shall
be determined based on DOE's estimated cost per kilowatt of reducing an
increment of load during a clock-hour and the amount of capacity reserved
by such Sponsoring Company attributable to such load reduction.
6. This modification No. 8 shall become effective at 12:00 o'clock
Midnight on the day on which Corporation shall advise the other parties to this
Modification No. 8 (to be later confirmed in writing) that all conditions
precedent to the effectiveness of this Modification No. 8 shall have been
satisfied.
7. The Inter-Company Power Agreement, as modified by Modifications Nos.
1, 2, 3, 4, 5, 6 and 7 and as hereinbefore provided, is hereby in all respects
confirmed.
8. This Modification No. 8 may be executed in any number of copies and by
the different parties hereto on separate counterparts, each of which shall be
deemed an original but all of which together shall constitute a single
agreement.
IN WITNESS WHEREOF, the parties hereto have executed this Modification No.
8 as of the day and year first written above.
OHIO VALLEY ELECTRIC CORPORATION
By:
-----------------------------------
APPALACHIAN POWER COMPANY
By:
-----------------------------------
THE CINCINNATI GAS & ELECTRIC COMPANY
By:
-----------------------------------
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<PAGE>
COLUMBUS SOUTHERN POWER COMPANY
By:
-----------------------------------
THE DAYTON POWER AND LIGHT COMPANY
By:
-----------------------------------
INDIANA MICHIGAN POWER COMPANY
By:
-----------------------------------
KENTUCKY UTILITIES COMPANY
By:
-----------------------------------
LOUISVILLE GAS AND ELECTRIC COMPANY
By:
-----------------------------------
MONONGAHELA POWER COMPANY
By:
-----------------------------------
OHIO EDISON COMPANY
By:
-----------------------------------
OHIO POWER COMPANY
By:
-----------------------------------
PENNSYLVANIA POWER COMPANY
By:
-----------------------------------
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THE POTOMAC EDISON COMPANY
By:
-----------------------------------
SOUTHERN INDIANA GAS AND ELECTRIC
COMPANY
By:
-----------------------------------
THE TOLEDO EDISON COMPANY
By:
-----------------------------------
WEST PENN POWER COMPANY
By:
-----------------------------------
8
<PAGE>
Texas Gas Transmission Corporation
3800 Frederica Street
P.O. Box 1160
Owensboro, KY 42302
March 1, 1995
Louisville Gas and Electric Company
820 West Broadway
Louisville, Kentucky 40202
Attention: Mr. J. Clay Murphy
Gentlemen:
Reference is made to the Firm No-Notice Transportation Agreement
(Agreement) dated November 1, 1993, as amended, between Texas Gas Transmission
Corporation (Texas Gas) and Louisville Gas and Electric Company (LG&E),
providing for the transportation of natural gas by Texas Gas for LG&E.
Accordingly, Texas Gas and LG&E hereby desire to amend the Agreement between
them as follows:
A. ARTICLE II, QUANTITY, Sections 2.2, 2.3, and 2.5, for the two-year
agreement shall be deleted in their entirety and replaced with the following:
2.2 The maximum daily quantity of gas which Texas Gas shall be obligated
to transport and redeliver to Customer, and which Customer shall be
obligated to receive, is Customer's applicable Contract Demand expressed on
a seasonal basis as set forth below:
<TABLE>
<CAPTION>
Daily
Contract Demand MMBtu/d
--------------- -------
<S> <C>
Winter 61,633
Summer 37,000
Shoulder Month (April) 49,480
Shoulder Month (October) 56,006
</TABLE>
2.3 The above Contract Demand consists of a Nominated Daily Quantity, for
which Customer is responsible for scheduling the delivery of gas supplies
into Texas Gas's system, and an Unnominated Daily Quantity, which is
automatically delivered from
<PAGE>
storage by Texas Gas to meet Customer's requirements. Those quantities,
expressed on a seasonal basis, are set forth below:
<TABLE>
<CAPTION>
Nominated
Daily Quantity MMBtu/d
-------------- -------
<S> <C>
Winter 49,000
Summer (except October) 37,000
October 41,000
Unnominated
Daily Quantity MMBtu/d
-------------- -------
<S> <C>
Winter 12,633
Shoulder Month (April) 6,316
Shoulder Month (October) 8,843
</TABLE>
2.5 The maximum seasonal quantities of gas which Texas Gas shall be
obligated to transport and deliver to Customer, and which Customer shall be
obligated to receive, are Customer's Seasonal Quantity Entitlements as set
forth below:
<TABLE>
<CAPTION>
Seasonal
Quantity Entitlement MMBtu/d
-------------------- -------
<S> <C>
Winter 8,740,000
Summer 5,314,466
</TABLE>
B. ARTICLE II, QUANTITY, Sections 2.2, 2.3, and 2.5, for the five-year
agreement shall be deleted in their entirety and replaced with the following:
2.2 The maximum daily quantity of gas which Texas Gas shall be obligated
to transport and redeliver to Customer, and which Customer shall be
obligated to receive, is Customer's applicable Contract Demand expressed on
a seasonal basis as set forth below:
<TABLE>
<CAPTION>
Daily
Contract Demand MMBtu/d
--------------- -------
<S> <C>
Winter 61,633
Summer 37,000
Shoulder Month (April) 49,480
Shoulder Month (October) 56,007
</TABLE>
2
<PAGE>
2.3 The above Contract Demand consists of a Nominated Daily
Quantity, for which Customer is responsible for scheduling the
delivery of gas supplies into Texas Gas's system, and an Unnominated
Daily Quantity, which is automatically delivered from storage by Texas
Gas to meet Customer's requirements. Those quantities, expressed on a
seasonal basis, are set forth below:
<TABLE>
<CAPTION>
Nominated
Daily Quantity MMBtu/d
-------------- -------
<S> <C>
Winter 49,000
Summer (except October) 37,000
October 41,000
<CAPTION>
Unnominated
Daily Quantity MMBtu/d
-------------- -------
<S> <C>
Winter 12,633
Shoulder Month (April) 6,317
Shoulder Month (October) 8,843
</TABLE>
2.5 The maximum seasonal quantities of gas which Texas Gas shall be
obligated to transport and deliver to Customer, and which Customer shall be
obligated to receive, are Customer's Seasonal Quantity Entitlements as set
forth below:
<TABLE>
<CAPTION>
Seasonal
Quantity Entitlement MMBtu/d
-------------------- -------
<S> <C>
Winter 8,740,000
Summer 5,314,667
</TABLE>
C. ARTICLE II, QUANTITY, Sections 2.2, 2.3, and 2.5, for the eight-year
agreement shall be deleted in their entirety and replaced with the following:
2.2 The maximum daily quantity of gas which Texas Gas shall be obligated
to transport and redeliver to Customer, and which Customer shall be
obligated to receive, is Customer's applicable Contract Demand expressed on
a seasonal basis as set forth below:
3
<PAGE>
<TABLE>
<CAPTION>
Daily
Contract Demand MMBtu/d
--------------- -------
<S> <C>
Winter 61,633
Summer 37,000
Shoulder Month (April) 49,480
Shoulder Month (October) 56,007
</TABLE>
2.3 The above Contract Demand consists of a Nominated Daily Quantity, for
which Customer is responsible for scheduling the delivery of gas supplies
into Texas Gas's system, and an Unnominated Daily Quantity, which is
automatically delivered from storage by Texas Gas to meet Customer's
requirements. Those quantities, expressed on a seasonal basis, are set
forth below:
<TABLE>
<CAPTION>
Nominated
Daily Quantity MMBtu/d
-------------- -------
<S> <C>
Winter 49,000
Shoulder (except October) 37,000
October 41,000
</TABLE>
<TABLE>
<CAPTION>
Unnominated
Daily Quantity MMBtu/d
-------------- -------
<S> <C>
Winter 12,634
Shoulder Month (April) 6,317
Shoulder Month (October) 8,844
</TABLE>
2.5 The maximum seasonal quantities of gas which Texas Gas shall be
obligated to transport and deliver to Customer, and which Customer shall be
obligated to receive, are Customer's Seasonal Quantity Entitlements as set
forth below:
4
<PAGE>
<TABLE>
<CAPTION>
Seasonal
Quantity Entitlement MMBtu/d
-------------------- -------
<S> <C>
Winter 8,740,000
Summer 5,314,667
</TABLE>
D. ARTICLE XI, SHOULDER MONTH FLEXIBILITY, Section 11.1 shall be deleted
in its entirety and replaced with the following:
11.1 During the Shoulder Months of April and October, Texas Gas will
deliver to Customer at the city-gate the Customer's Shoulder Month Contract
Demand, which shall, unless otherwise agreed, be the sum of Customer's
Summer Contract Demand, Customer's Excess Unnominated Quantity and the
applicable percentage as set forth below of Customer's Unnominated Daily
Quantity for the Winter Season:
<TABLE>
<CAPTION>
Percent of
Unnominated
Shoulder Month Daily Quantity
-------------- --------------
<S> <C>
April 50%
October 70%
</TABLE>
In the event that Customer's Unnominated Seasonal Quantity is
available in quantities sufficient to support additional access to
Customer's Unnominated Daily Quantity the applicable percentage available
to Customer during such Shoulder Month will be as follows:
<TABLE>
<CAPTION>
%of Unnominated % of Unnominated
Seasonal Quantity Daily Quantity
Should Month Withdrawn Available
- ------------ --------- ---------
<S> <C> <C>
April/October 75% 90%
80% 85%
85% 80%
90% 75%
95% 70%
</TABLE>
Although such Shoulder Month Contract Demand shall be available during any
day of the Shoulder Month, it shall only be available for a maximum of fifteen
(15) gas days during such month.
5
<PAGE>
E. EXHIBIT "A", FIRM POINT(S) OF RECEIPT, shall be deleted in its
entirety and replaced with the attached Winter Season - Exhibit "A", FIRM
POINT(S) OF RECEIPT and Summer Season - Exhibit "A", FIRM POINT(S) OF RECEIPT.
F. EXHIBIT"C", SUPPLY LATERAL CAPACITY, shall be deleted in its entirety
and replaced with the attached Winter Season - Exhibit "C", SUPPLY LATERAL
CAPACITY and Summer Season - Exhibit "C", SUPPLY LATERAL CAPACITY.
This amendment shall become effective April 1, 1995, and shall remain in
force for a term to coincide with the term of the Agreement.
The operation of the provisions of this amendment shall be subject to all
applicable governmental statutes and all applicable and lawful orders, rules,
and regulations.
Except as herein amended, the Agreement between the parties hereto shall
remain in full force and effect.
If the foregoing is in accordance with your understanding of our Agreement,
please execute both copies and return to us. We will, in turn, execute them and
return one copy for your records.
Very truly yours,
LOUISVILLE GAS AND ELECTRIC TEXAS GAS TRANSMISSION
COMPANY CORPORATION
By: By:
Title: ATTEST:
AGREED TO AND ACCEPTED this _____ day of _____________, 1995.
6
<PAGE>
Contract No. N0415
Winter Season - Exhibit "A"
Firm Point(s) of Receipt
Louisville Gas And Electric Company
Firm No-Notice Transportation Agreement
<TABLE>
<CAPTION>
Daily Firm
Meter Capacity
Lateral Segment Zone No. Name MMBtu
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
North Louisiana Leg
Carthage-Haughton 1 2102 Champlin 16,715
Sharon-East 1 2632 Dubach 13,455
1 8760 Lonewa 15,000
1 2631 Calhoun Plant 5,000
Southeast Leg
Blk. 8-Morgan City SL 2845 Lake Pagie 3,007
SL 9471 Sohio 5,743
Henry-Lafayette SL 2790 Henry Hub 26,682
Maurice-Freshwater SL 2840 UNOCAL-N Fresh Water Bayou 18,829
Offshore in at Calumet SL 2550 EI293/308/315 11,592
South Leg
Egan-Eunice SL 9003 Egan 19,379
</TABLE>
7
<PAGE>
<TABLE>
<CAPTION>
Daily Firm
Meter Capacity
Lateral Segment Zone No. Name MMBtu
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Offshore in at Egan SL 2770 Vermilion 267F 2,116
SL 2774 Vermilion 256D 951
SL 9342 Vermilion 255/256E 225
SL 2782 Vermilion 267C 1,254
SL 2781 S.S. 247F 3,592
SL 2776 S.S. 248D 4,811
Southwest Leg
Lowry-Eunice SL 9446 NGPL-Lowry 6,161
W.C. 294
Enters at ANR-Eunice SL 9383 WC 293/HI 167/HI 167-166 4,819
HIOS (at ANR-Eunice)
H.I. 247 SL 9135 WC167/HIOS Mainline 3,800
H.I. 555 SL 9887 HIA-555/A-557A/A-556 2,000
H.I. 573 SL 2859 HIA-573B COMPLEX 17,743
Mainline
Bastrop-North 3 2399 ANR-Slaughters (ref. #8082) 20,000
1 9303 Helena #2 10,000
3 9868 U.Cities-Barnsley (ref. #9404) 12,000
Eunice-Zone SL/1 Line SL 8147 Mamou (ref. #8046) 2,092
</TABLE>
8
<PAGE>
<TABLE>
<CAPTION>
Daily Firm
Meter Capacity
Lateral Segment Zone No. Name MMBtu
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Zone SL/1 Line-Bastrop 1 2020 Arkla-Perryville 20,000
1 8063 Pineville (LIG) 20,000
</TABLE>
This exhibit reflects the combined total receipt point capacity held by
Louisville Gas and Electric Company under the 2-year, 5-year and 8-year
agreements for Contract No. NO415. Amendments in contract quantities in either
the 2-year, 5-year or 8-year agreements will result in an amendment of this
exhibit.
9
<PAGE>
Contract No. N0415
Summer Season - Exhibit "A"
Firm Point(s) of Receipt
Louisville Gas And Electric Company
Firm No-Notice Transportation Agreement
<TABLE>
<CAPTION>
Daily Firm
Meter Capacity
Lateral Segment Zone No. Name MMBtu
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
North Louisiana Leg
Carthage-Haughton 1 2102 Champlin 16,715
Sharon-East 1 2631 Calhoun Plant 5,000
1 8760 Lonewa 15,000
1 2632 Dubach 13,455
Southeast Leg
Blk. 8-Morgan City SL 9471 Sohio 5,743
SL 2845 Lake Pagie 3,007
Henry-Lafayette SL 2790 Henry Hub 26,682
Maurice-Freshwater SL 2840 UNOCAL-N Fresh Water Bayou 18,829
Offshore in at Calumet SL 2550 EI293/308/315 11,592
South Leg
Egan-Eunice SL 9003 Egan 19,379
Southwest Leg
Lowry-Eunice SL 9446 NGPL-Lowry 6,161
</TABLE>
10
<PAGE>
<TABLE>
<CAPTION>
Daily Firm
Meter Capacity
Lateral Segment Zone No. Name MMBtu
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
W.C. 294
Enters at ANR-Eunice SL 9383 WC 293/HI 167/HI 167-166 4,819
HIOS (at ANR-Eunice)
H.I. 247 SL 9135 WC167/HIOS Mainline 3,800
H.I. 555 SL 9887 HIA-555/A-557A/A-556 2,000
H.I. 573 SL 2859 HIA-573B COMPLEX 5,440
Mainline
Bastrop-North 3 2399 ANR-Slaughters
(ref. #8082) 20,000
1 9303 Helena #2 10,000
3 9868 U.Cities-Barnsley
(ref. #9404) 12,000
Eunice-Zone SL/1 Line SL 8147 Mamou (ref. #8046) 2,092
Zone SL/1 Line-Bastrop 1 2020 Arkla-Perryville 20,000
1 8063 Pineville (LIG) 20,000
</TABLE>
This exhibit reflects the combined total receipt point capacity held by
Louisville Gas And Electric Company under the 2-year, 5-year, and 8-year
agreements for Contract No. N0415. Amendments in contract quantities in either
the 2-year, S-year, or 8-year agreements will result in an amendment of this
exhibit.
11
<PAGE>
Contract No. NO415
Firm No-Notice Transportation Agreement
Winter Season-Exhibit "C"
Supply Lateral Capacity
Louisville Gas and Electric Company
<TABLE>
<CAPTION>
PREFERENTIAL RIGHTS
SUPPLY LATERAL MMBtu/d
Zone 1 Supply Lateral(s)
- ------------------------
<S> <C>
North Louisiana Leg: 50,170
--------
Total Zone 1: 50,170
Zone SL Supply Lateral(s)
- -------------------------
East Leg: 0
Southeast Leg: 65,853
South Leg: 32,328
Southwest Leg: 22,648
West Leg: 0
WC-294: 4,819
HIOS: 23,543
--------
Total Zone SL: 149,191
--------
Grand Total: 199,361
--------
--------
</TABLE>
This exhibit reflects the combined total supply lateral capacity held by
Louisville Gas and Electric Company under the 2-year, 5-year and 8-year
agreements for Contract No. NO415. Amendments in contract quantities in either
the 2-year, 5-year or 8-year agreements will result in an amendment of this
exhibit.
12
<PAGE>
Contract No. NO415
Firm No-Notice Transportation Agreement
Summer Season-Exhibit "C"
Supply Lateral Capacity
Louisville Gas and Electric Company
<TABLE>
<CAPTION>
PREFERENTIAL RIGHTS
SUPPLY LATERAL MMBtu/d
Zone 1 Supply Lateral(s)
- ------------------------
<S> <C>
North Louisiana Leg: 50,170
--------
Total Zone 1: 50,170
Zone SL Supply Lateral(s)
- -------------------------
East Leg: 0
Southeast Leg: 65,853
South Leg: 19,379
Southwest Leg: 15,351
West Leg: 0
WC-294: 4,819
HIOS: 11,240
--------
Total Zone SL: 116,642
--------
Grand Total: 166,812
--------
--------
</TABLE>
This exhibit reflects the combined total supply lateral capacity held by
Louisville Gas and Electric Company under the 2-year, 5-year and 8-year
agreements for Contract No. NO415. Amendments in contract quantities in either
the 2-year, 5-year or 8-year agreements will result in an amendment of this
exhibit.
13
<PAGE>
T6487
GAS TRANSPORTATION AGREEMENT
BETWEEN
TEXAS GAS TRANSMISSION CORPORATION
AND
LOUISVILLE GAS AND ELECTRIC COMPANY
(TERM THROUGH: OCTOBER 31, 1998)
DATED MARCH 1, 1995
<PAGE>
INDEX
-----
ARTICLE I Definitions 1
ARTICLE II Transportation Service 1
ARTICLE III Scheduling 2
ARTICLE IV Points of Receipt and Delivery 3
ARTICLE V Term of Agreement 3
ARTICLE Vl Point(s) of Measurement 3
ARTICLE VII Facilities 4
ARTICLE VIII Rates and Charges 4
ARTICLE IX Miscellaneous 5
EXHIBIT "A"
FIRM POINT(S) OF RECEIPT
EXHIBIT "A-I"
SECONDARY POINT(S) OF RECEIPT
EXHIBIT "B"
FIRM POINT(S) OF DELIVERY
EXHIBIT "C"
SUPPLY LATERAL CAPACITY
STANDARD FACILITIES KEY
<PAGE>
FIRM TRANSPORTATION AGREEMENT
THIS AGREEMENT, made and entered into this 1st day of March, 1995, by and
between Texas Gas Transmission Corporation, a Delaware corporation, hereinafter
referred to as "Texas Gas," and Louisville Gas and Electric Company, a Kentucky
corporation, hereinafter referred to as "Customer,"
WITNESSETH:
WHEREAS, Customer has natural gas which cannot be moved into its
system/which it desires Texas Gas to move through its existing facilities; and
WHEREAS, Texas Gas has the ability in its pipeline system to move natural
gas for the account of Customer; and
WHEREAS, Customer desires that Texas Gas transport such natural gas for
the account of Customer; and
WHEREAS, Customer and Texas Gas are of the opinion that the transaction
referred to above falls within the provisions of Section 284.223 of Subpart G of
Part 284 of the Federal Energy Regulatory Commission's (Commission) regulations
and the blanket certificate issued to Texas Gas in Docket No. CP88-686-000, and
can be accomplished without the prior approval of the Commission;
NOW, THEREFORE, in consideration of the premises and of the mutual
covenants herein contained, the parties hereto covenant and agree as follows:
ARTICLE I
DEFINITIONS
1.1 Definition of Terms of the General Terms and Conditions of Texas Gas's
FERC Gas Tariff on file with the Commission is hereby incorporated by reference
and made a part of this Agreement.
ARTICLE II
TRANSPORTATION SERVICE
2.1 Subject to the terms and provisions of this Agreement, Customer agrees to
deliver or cause to be delivered to Texas Gas, at the Point(s) of Receipt in
Exhibit "A" hereunder, Gas for Transportation, and Texas Gas agrees to receive,
transport, and redeliver, at the Point(s) of Delivery in Exhibit "B" hereunder,
Equivalent Quantities of Gas to Customer or for the account of Customer, in
accordance with Section 3 of Texas Gas's effective FT Rate Schedule and the
terms and conditions contained herein, up to 0 MMBtu per day during the winter
season, and up to 8,000 MMBtu per day during the summer season, which shall be
Customer's Firm Transportation Contract Demand, and up to 0 MMBtu during the
winter season, and up to 1,712,000 MMBtu during the summer season, which shall
be Customer's Seasonal Quantity Levels.
<PAGE>
2.2 Customer shall reimburse Texas Gas for the Quantity of Gas required for
fuel, company use, and unaccounted for associated with the transportation
service hereunder in accordance with Section 16 of the General Terms and
Conditions of Texas Gas's FERC Gas Tariff. The applicable fuel retention
percentage(s) is shown on Exhibit "A". Texas Gas may adjust the fuel retention
percentage as operating circumstances warrant; however, such change shall not be
retroactive. Texas Gas agrees to give Customer thirty (30) days written notice
before changing such percentage.
2.3 Texas Gas, at its sole option, may, if tendered by Customer, transport
daily quantities in excess of the Transportation Contract Demand.
2.4 In order to protect its system, the delivery of gas to its customers
and/or the safety of its operations, Texas Gas shall have the right to vent
excess natural gas delivered to Texas Gas by Customer or Customer's supplier(s)
in that part of its system utilized to transport gas received hereunder. Prior
to venting excess gas, Texas Gas will use its best efforts to contact Customer
or Customer's supplier(s) in an attempt to correct such excess deliveries to
Texas Gas. Texas Gas may vent such excess gas solely within its reasonable
judgment and discretion without liability to Customer, and a pro rata share of
any gas so vented shall be allocated to Customer. Customer's pro rata share
shall be determined by a fraction, the numerator of which shall be the quantity
of gas delivered to Texas Gas at the Point of Receipt by Customer or Customer's
supplier(s) in excess of Customer's confirmed nomination and the denominator of
which shall be the total quantity of gas in excess of total confirmed
nominations flowing in that part of Texas Gas's system utilized to transport
gas, multiplied by the total quantity of gas vented or lost hereunder.
2.5 Any gas imbalance between receipts and deliveries of gas, less fuel and
PVR adjustments, if applicable, shall be cleared each month in accordance with
Section 17 of the General Terms and Conditions in Texas Gas's FERC Gas Tariff.
Any imbalance remaining at the termination of this Agreement shall also be
cashed-out as provided herein.
ARTICLE III
SCHEDULING
3.1 Customer shall be obligated five (5) working days prior to the end of
each month to furnish Texas Gas with a schedule of the estimated daily
quantity(ies) of gas it desires to be received, transported, and redelivered for
the following month. Such schedules will show the quantity(ies) of gas Texas
Gas will receive from Customer at the Point(s) of Receipt, along with the
identity of the supplier(s) that is delivering or causing to be delivered to
Texas Gas quantities for Customer's account at each Point of Receipt for which a
nomination has been made.
3.2 Customer shall give Texas Gas, after the first of the month, at least
twenty-four (24) hours notice prior to the commencement of any day in which
Customer desires to change the quantity(ies) of gas it has scheduled to be
delivered to Texas Gas at the Point(s) of Receipt. Texas Gas agrees to waive
this 24-hour prior notice and implement nomination changes requested by Customer
to commence in such lesser time frame subject to Texas Gas's being able to
confirm and verify such nomination change at both Receipt and Delivery Points,
and receive PDAs reflecting this nomination change at both Receipt and Delivery
Points. Texas Gas will use its best efforts to make the
2
<PAGE>
nomination change effective at the time requested by Customer; however, if Texas
Gas is unable to do so, the nomination change will be implemented as soon as
confirmation is received.
ARTICLE IV
POINTS OF RECEIPT, DELIVERY AND SUPPLY LATERAL ALLOCATION
4.1 Customer shall deliver or cause to be delivered natural gas to Texas Gas
at the Point(s) of Receipt specified in Exhibit "A" attached hereto and Texas
Gas shall redeliver gas to Customer or for the account of Customer at the
Point(s) of Delivery specified in Exhibit "B" attached hereto in accordance with
Sections 7 and 15 of the General Terms and Conditions of Texas Gas's FERC Gas
Tariff.
4.2 Customer's preferential capacity rights on each of Texas Gas's supply
laterals shall be as set forth in Exhibit "C" attached hereto, in accordance
with Section 34 of the General Terms and Conditions of Texas Gas's FERC Gas
Tariff.
ARTICLE V
TERM OF AGREEMENT
5.1 This Agreement shall become effective upon its execution and remain in
full force and effect with a primary term beginning April 1, 1995, (with the
rates and charges described in Article VIII becoming effective on that date) and
extending through October 31, 1998. At the end of such primary term, or any
subsequent roll-over term of five (5) years, this Agreement shall automatically
be extended for an additional roll-over term of five (5) years, unless Customer
terminates this Agreement at the end of such primary or roll-over term by giving
Texas Gas at least 365 days advance written notice prior to the expiration of
the primary term or any subsequent roll-over term.
ARTICLE VI
POINT(S) OF MEASUREMENT
6.1 The gas shall be delivered by Customer to Texas Gas and redelivered by
Texas Gas to Customer at the Point(s) of Receipt and Delivery hereunder.
6.2 The gas shall be measured or caused to be measured by Customer and/or
Texas Gas at the Point(s) of Measurement which shall be as specified in Exhibits
"A", "A-I", and "B" herein. In the event of a line loss or leak between the
Point of Measurement and the Point of Receipt, the loss shall be determined in
accordance with the methods described contained in Section 3, "Measuring and
Measuring Equipment," contained in the General Terms and Conditions of First
Revised Volume No. 1 of Texas Gas's FERC Gas Tariff.
ARTICLE VII
FACILITIES
3
<PAGE>
7.1 Texas Gas and Customer agree that any facilities required at the Point(s)
of Receipt, Point(s) of Delivery, and Point(s) of Measurement shall be
installed, owned, and operated as specified in Exhibits "A", "A-I", and "B"
herein. Customer may be required to pay or cause Texas Gas to be paid for the
installed cost of any new facilities required as contained in Sections 1.3, 1.4,
and 1.5 of Texas Gas's FT Rate Schedule. Customer shall only be responsible for
the installed cost of any new facilities described in this Section if agreed to
in writing between Texas Gas and Customer.
ARTICLE VIII
RATES AND CHARGES
8.1 Each month, Customer shall pay Texas Gas for the service hereunder an
amount determined in accordance with Section 5 of Texas Gas's FT Rate Schedule
contained in Texas Gas's FERC Gas Tariff, which Rate Schedule is by reference
made a part of this Agreement. The maximum rates for such service consist of a
monthly reservation charge multiplied by Customer's firm transportation demand
as specified in Section 2.1 herein. The reservation charge shall be billed as of
the effective date of this Agreement. In addition to the monthly reservation
charge, Customer agrees to pay Texas Gas each month the maximum commodity charge
up to Customer's Transportation Contract Demand. For any quantities delivered
by Texas Gas in excess of Customer's Transportation Contract Demand, Customer
agrees to pay the maximum FT overrun commodity charge. In addition, Customer
agrees to pay:
(a) Texas Gas's Fuel Retention percentage(s).
(b) The currently effective GRI funding unit, if applicable, the
currently effective FERC Annual Charge Adjustment unit charge
(ACA), the currently effective Take-or-Pay surcharge, or any
other then currently effective surcharges, including but not
limited to Order 636 Transition Costs.
If Texas Gas declares force majeure which renders it unable to perform service
herein, then Customer shall be relieved of its obligation to pay demand charges
for that part of its FT Contract Demand affected by such force majeure event
until the force majeure event is remedied.
Unless otherwise agreed to in writing by Texas Gas and Customer, Texas Gas may,
from time to time, and at any time selectively after negotiation, adjust the
rate(s) applicable to any individual Customer; provided, however, that such
adjusted rate(s) shall not exceed the applicable Maximum Rate(s) nor shall they
be less than the Minimum Rate(s) set forth in the currently effective Sheet No.
10 of this Tariff. if Texas Gas so adjusts any rates to any Customer, Texas Gas
shall file with the Commission any and all required reports respecting such
adjusted rate.
8.2 In the event Customer utilizes a Secondary Point(s) of Receipt or
Delivery for transportation service herein, Customer will continue to pay the
monthly reservation charges as described in Section 8.1 above. In addition,
Customer will pay the maximum commodity charge applicable to the zone in which
gas is received and redelivered up to Customer's Transportation Contract Demand
and the maximum overrun commodity charge for any quantities delivered by Texas
Gas in excess of Customer's winter season or summer season Transportation
Contract Demand. Customer also
4
<PAGE>
agrees to pay the ACA, Take-or-Pay Surcharge, GRI charges, fuel retention
charge, and any other effective surcharges, if applicable, as described in
Section 8.1 above.
8.3 It is further agreed that Texas Gas may seek authorization from the
Commission and/or other appropriate body for such changes to any rate(s) and
terms set forth herein or in Rate Schedule FT, as may be found necessary to
assure Texas Gas just and reasonable rates. Nothing herein contained shall be
construed to deny Customer any rights it may have under the Natural Gas Act, as
amended, including the right to participate fully in rate proceedings by
intervention or otherwise to contest increased rates in whole or in part.
8.4 Customer agrees to fully reimburse Texas Gas for all filing fees, if any,
associated with the service contemplated herein which Texas Gas is required to
pay to the Commission or any agency having or assuming jurisdiction of the
transactions contemplated herein.
8.5 Customer agrees to execute or cause its supplier or processor to execute
a separate agreement with Texas Gas providing for the transportation of any
liquids and/or liquefiables, and agrees to pay or reimburse Texas Gas, or cause
Texas Gas to be paid or reimbursed, for any applicable rates or charges
associated with the transportation of such liquids and/or liquefiables, as
specified in Section 24 of the General Terms and Conditions of Texas Gas's FERC
Gas Tariff.
ARTICLE IX
MISCELLANEOUS
9.1 Texas Gas's Transportation Service hereunder shall be subject to receipt
of all requisite regulatory authorizations from the Commission, or any successor
regulatory authority, and any other necessary governmental authorizations, in a
manner and form acceptable to Texas Gas. The parties agree to furnish each other
with any and all information necessary to comply with any laws, orders, rules,
or regulations.
9.2 Except as may be otherwise provided, any notice, request, demand,
statement, or bill provided for in this Agreement or any notice which a party
may desire to give the other shall be in writing and mailed by regular mail, or
by postpaid registered mail, effective as of the postmark date, to the post
office address of the party intended to receive the same, as the case may be, or
by facsimile transmission, as follows:
TEXAS GAS
---------
Texas Gas Transmission Corporation
3800 Frederica Street
Post Office Box 1160
Owensboro, Kentucky 42302
Attention: Gas Revenue Accounting (Billings and Statements)
Customer Services (Other Matters)
Gas Transportation and Capacity Allocation (Nominations)
Fax (502) 926-8686
5
<PAGE>
CUSTOMER
--------
Louisville Gas and Electric Company
820 West Broadway
Louisville, Kentucky 40202
Attention: Mr. J. Clay Murphy
The address of either party may, from time to time, be changed by a party
mailing, by certified or registered mail, appropriate notice thereof to the
other party. Furthermore, if applicable, certain notices shall be considered
duly delivered when posted to Texas Gas's Electronic Bulletin Board, as
specified in Texas Gas's tariff.
9.3 This Agreement shall be governed by the laws of the State of Kentucky.
9.4 Each party agrees to file timely all statements, notices, and petitions
required under the Commission's Regulations or any other applicable rules or
regulations of any governmental authority having jurisdiction hereunder and to
exercise due diligence to obtain all necessary governmental approvals required
for the implementation of this Transportation Agreement.
9.5 All terms and conditions of Rate Schedule FT and the attached Exhibits
"A", "A-l", "B", and "C" are hereby incorporated to and made a part of this
Agreement.
9.6 This contract shall be binding upon and inure to the benefit of the
successors, assigns, and legal representatives of the parties hereto.
9.7 Neither party hereto shall assign this Agreement or any of its rights or
obligations hereunder without the consent in writing of the other party.
Notwithstanding the foregoing, either party may assign its right, title and
interest in, to and by virtue of this Agreement including any and all
extensions, renewals, amendments, and supplements thereto, to a trustee or
trustees, individual or corporate, as security for bonds or other obligations or
securities, without such trustee or trustees assuming or becoming in any respect
obligated to perform any of the obligations of the assignor and, if any such
trustee be a corporation, without its being required by the parties hereto to
qualify to do business in the state in which the performance of this Agreement
may occur, nothing contained herein shall require consent to transfer this
Agreement by virtue of merger or consolidation of a party hereto or a sale of
all or substantially all of the assets of a party hereto, or any other corporate
reorganization of a party hereto.
9.8 This Agreement insofar as it is affected thereby, is subject to all valid
rules, regulations and orders of all governmental authorities having
jurisdiction.
9.9 No waiver by either party of any one or more defaults by the other in the
performance of any provisions hereunder shall operate or be construed as a
waiver of any future default or defaults whether of a like or a different
character.
6
<PAGE>
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
signed by their respective representatives thereunto duly authorized, on the day
and year first above written.
ATTEST: TEXASGAS TRANSMISSION CORPORATION
- ---------------------------------- By:
------------------------------
WITNESSES: LOUISVILLE GAS AND ELECTRIC COMPANY
By:
- ---------------------------------- ------------------------------
Attest:
- ---------------------------------- ---------------------------
Date of Execution by Customer:
- ----------------------------------
7
<PAGE>
Contract No. T6487
Summer Season - Exhibit "A"
Firm Point(s) of Receipt
Louisville Gas And Electric Company
Firm Transportation Agreement
<TABLE>
<CAPTION>
Daily Firm
Meter Capacity
Lateral Segment Zone No. Name MMBtu
- -------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
South Leg
Offshore in at Egan SL 2770 Vermillion 267F 2,116
SL 2782 Vermillion 267C 1,254
SL 2774 Vermillion 256D 951
SL 9342 Vermillion 255/256E 225
SL 2776 S.S. 248D 4,811
SL 2781 S.S. 247F 3,592
HIOS (at ANR-Eunice)
H.I. 573
SL 2859 HIA-573B COMPLEX 12,303
</TABLE>
This exhibit reflects the combined total receipt point capacity held by
Louisville Gas And Electric Company under the 2-year, 5-year, and 8-year
agreements for Contract No. T6487. Amendments in contract quantities in either
the 2-year, 5-year, or 8-year agreements will result in an amendment of this
exhibit.
8
<PAGE>
EXHIBIT "A-I"
SECONDARY POINT(S) OF RECEIPT
SUPPLY
<TABLE>
<CAPTION>
Meter
Lateral Segment Zone No. Supply Point
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
NORTH LOUISIANA
Carthage-Haughton 1 2102 Champlin
1 9805 Delhi
1 9051 Grigsby
1 9860 Nelson-Greenwood/Waskom
1 8116 Texas Eastern-Sligo
1 9884 Valero-Carthage
Haughton-Sharon 1 8003 Barksdale
1 2455 Beacon
1 9866 Cornerstone-Ada
1 2173 Crystal Oil-West Arcadia
1 2340 F.E. Hargraves-Minden
1 2186 LGI #1
1 2456 McCormick
1 2457 Minden-Hunt
1 2459 Minden Pan-Am #1
1 9819 Nelson-Sibley
1 9461 Olin-McGoldrick
1 2760 Sligo Plant
1 9834 Texaco-Athens
</TABLE>
9
<PAGE>
<TABLE>
<CAPTION>
Meter
Lateral Segment Zone No. Supply Point
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
Sharon 1 2010 Fina Oil-HICO
1 9818 PGC-Bodcaw
1 2757 Texas Eastern-Sharon
Sharon-East 1 2631 Calhoun Plant
1 2632 Dubach
1 2202 Ergon-Monroe
1 8760 Lonewa
1 8020 MRT-Bastrop
1 9302 Munce
1 9812 Par Minerals/Downsville
1 9823 Reliance-Bernice
1 2612 Reliance-West Monroe
1 2634 Southwest-Guthrie
EAST
Bosco-Eunice SL 2015 Amerada Hess
SL 2016 Amerada Hess-South Lewisburg
SL 2385 D.B. McClinton #1
SL 9844 Germany Oil-Church Point
SL 2288 Great Southern-Mowata #2
SL 9804 Great Southern-Mowata #3
SL 2289 Great Southern-South Lewisburg
SL 8142 Ritchie
SL 9119 Sevarg
SL 2740 Superior-Pure
</TABLE>
10
<PAGE>
<TABLE>
<CAPTION>
Meter
Lateral Segment Zone No. Supply Point
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
SOUTHEAST
Blk. 8-Morgan City SL 2198 Bois D'Arc
SL 9142 Bois D'Arc-Pelican Lake
SL 2109 Chevron-Block 8
SL 2638 Coon Point
SL 2845 Lake Pagie
SL 9817 Mustang-Bayou Piquant
SL 2460 Peltex Deep Saline #1
SL 2480 S.S. 41
SL 9471 Sohio
SL 9888 Star Oil & Gas-Bay Junop
SL 9187 Stone-South Timbalier
SL 2755 Texaco-Bay Junop
SL 9836 Texaco-Dog Lake
SL 2463 Toce Oil
SL 2850 Union Oil-N. Lake Pagie
SL 9883 Zeit-Lake Pagie
Henry-Lafayette SL 8190 Faustina-Henry
SL 2790 Henry Hub
Lafayette-Eunice SL 2153 Branch-Cox
SL 2125 California Co.-North Duson
SL 2137 California Co.-South Bosco #1
SL 2138 California Co.-South Bosco #2
</TABLE>
11
<PAGE>
<TABLE>
<CAPTION>
Meter
Lateral Segment Zone No. Supply Point
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
SL 2600 Cayman-Anslem Coulee
SL 9852 CNG-South Rayne
SL 2389 Duson
SL 9837 Excel-Judice
SL 8068 Exch. O&G-No. Maurice
SL 2601 Fina Oil-Anslem Coulee
SL 8040 Florida
SL 2290 Gulf Transport-Church Pt.
SL 2148 Maurice Cox
SL 9906 Quintana-South Bosco
SL 9005 Rayne-Columbia Gulf
SL 2045 Riceland-North Tepetate
SL 8067 South Scott
SL 2810 Tidewater-North Duson
SL 8051 Youngsville
Maurice-Freshwater SL 9822 Cities Service-Nunez
SL 2147 CNG-Hell Hole Bayou
SL 2203 Deck Oil-Perry/Hope
SL 9808 Duhon/Parcperdue
SL 9044 EDC-N. Parcperdue
SL 9160 LLOG-Abbeville
SL 2394 LRC-Theall
SL 9800 May Petroleum
SL 2424 McCain-Maurice
SL 2748 Parc Perdue
</TABLE>
12
<PAGE>
<TABLE>
<CAPTION>
Meter
Lateral Segment Zone No. Supply Point
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
SL 2749 Parc Perdue 2
SL 9830 R&R Res-Abbeville
SL 2706 Sun Ray
SL 9422 UNOCAL-Freshwater Bayou
SL 2840 UNOCAL-N. Freshwater Bayou
Morgan City-Lafayette SL 2064 Amoco-Charenton
SL 9173 ANR-Calumet (Rec.)
SL 9803 Atlantic
SL 9809 B.H. Petroleum-S.E. Avery
SL 2080 Bayou Sale-British Am
SL 9881 Bridgeline-Berwick
SL 2085 British American-Ramos
SL 9425 Charenton
SL 9047 Florida Gas-E.B. Pigeon
SL 2454 FMP/Bayou Postillion
SL 8059 Franklin
SL 2208 Frantzen
SL 9898 Hadson-East Bayou Pigeon
SL 2188 Lamson
SL 9854 Linder Oil-Bayou Penchant
SL 9853 Linder Oil-Garden City
SL 2189 Rutledge Deas
SL 2636 Shell-Bayou Pigeon
SL 9902 Smith Production-Charenton
SL 2035 Southwest-Jeanerette
</TABLE>
13
<PAGE>
<TABLE>
<CAPTION>
Meter
Lateral Segment Zone No. Supply Point
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
SL 9895 Texaco-Bayou Sale
SL 8205 Transco-Myette Point
SL 9829 Trunkline-Centerville
SL 9350 Vulcan
SL 9835 W.T. Burton-Lake Palourde
Offshore Points entering at SL 2583 E.I. 273A
Calumet
SL 2158 E.I. 273A/273A/284B
SL 2584 E.I. 273B
SL 2834 E.I. 276C
SL 2771 E.I. 287D
SL 2151 E.I. 292B
SL 9339 E.I. 292B/286I
SL 9419 E.I. 292B/286I/293
SL 2550 E.I. 293/308/315
SL 2773 E.I. 307E
SL 2154 E.I. 309C
SL 2155 E.I. 309G
SL 2157 E.I. 309H
SL 9886 E.I. 309H/309H/309J
SL 2156 E.I. 314F/309C/314F
SL 2780 SMI 11C
SL 2425 SMI 161
SL 2783 S.S. 204/219
</TABLE>
14
<PAGE>
<TABLE>
<CAPTION>
Meter
Lateral Segment Zone No. Supply Point
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
Thibodaux-Morgan City SL 2250 A. Glassell-Chacahoula
SL 2047 Alliance Exploration
SL 9029 Coastal-Chacahoula
SL 2835 Lake Palourde
SL 9873 Linder Oil-Chacahoula
SL 9175 LLOG-Chacahoula
SL 9847 LRC-Choctaw
SL 2440 Magna-Chacahoula #1
SL 2445 Magna-St. John #2
SL 2470 Patterson-Chacahoula
SL 2135 Simon Pass
SOUTH
Egan-Eunice SL 9851 Booher-Iota
SL 9003 Egan
Offshore Points Entering at SL 9130 E.I. 278/S.S. 247F
Egan
SL 9131 E.I. 278/S.S. 248D
SL 9128 E.I. 299/S.S. 271A
SL 9129 E.I. 299/S.S. 271A/S.S. 271B
SL 9423 E.I. 320/324
SL 9122 E.I. 320/325A
SL 9123 E.I. 342/366A
SL 2793 E.I. 342/372A
SL 9399 E.I. 342/384A
</TABLE>
15
<PAGE>
<TABLE>
<CAPTION>
Meter
Lateral Segment Zone No. Supply Point
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
SL 2767 E.I. 342C
SL 2786 E.I. 343B
SL 9363 E.I. 349/349A
SL 9364 E.I. 349/349A/349B
SL 2788 E.I. 365
SL 9369 E.I. 365A/365A/348
SL 9120 E.I. 372A
SL 2781 S.S. 247F
SL 2776 S.S. 248D
SL 9429 S.S. 248D/248G
SL 2778 S.S. 271A
SL 2785 S.S. 271B/271A/271B
SL 9427 Vermilion 248/255A/255H
SL 9342 Vermilion 255/256E
SL 9424 Vermilion 255/256E/268G
SL 2774 Vermilion 256D
SL 9105 Vermilion 267/275A
SL 9340 Vermilion 267/287A
SL 9341 Vermilion 267/287A/276
SL 9159 Vermilion 267/287A/277
SL 9374 Vermilion 267/289A
SL 2782 Vermilion 267C
SL 2770 Vermilion 267F
SOUTHWEST
East Cameron-Lowry SL 9872 E.C. 9A
</TABLE>
16
<PAGE>
<TABLE>
<CAPTION>
Meter
Lateral Segment Zone No. Supply Point
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
SL 2581 E.C. 14
SL 2860 Lake Arthur
SL 2033 Little Cheniere-Arco
SL 2034 Little Cheniere-Linder
SL 2392 LRC-Grand Cheniere
Lowry-Eunice SL 9843 Mobil-Lowry
SL 9446 NGPL-Lowry
SL 2437 ENOGEX/NGPL Tap Washita
SL 9169 TEX SW/NGPL Washita
SL 9171 Transok/NGPL Inter #2 Beckham
SL 9170 Transok/NGPL Inter #2 Custer
SL 9172 Transok/NGPL Waggs Wheeler
WEST
Iowa-Eunice SL 2091 Caribbean-China #1
SL 2092 Caribbean-China #2
SL 2093 Caribbean-China #3
SL 9038 Coastal/ANR-Iowa
SL 9839 Great Southern-Woodlawn
SL 8170 Iowa
SL 9445 Kilroy Riseden-Woodlawn
SL 9186 Linder Oil-Woodlawn
SL 9890 Source Petroleum-S. Elton #1
SL 9896 Source Petroleum-S. Elton #2
SL 2883 Tree Oil-Woodlawn
</TABLE>
17
<PAGE>
<TABLE>
<CAPTION>
Meter
Lateral Segment Zone No. Supply Point
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
Mallard Bay-Woodlawn SL 2140 California Co.-South Thornwell
SL 2615 Caroline Hunt Sands-S. Thornwell
SL 2170 Cockrell-North Chalkley
SL 9828 Denovo-Lake Arthur
SL 2207 Franks Petroleum-Chalkley
SL 9028 Gas Energy Development-Hayes
SL 2355 Humble-Chalkley
SL 2383 IMC Wintershall-Chalkley
SL 9848 Lamson Onshore-Mallard Bay
SL 8071 LRC-Mallard Bay
SL 2701 Samedan-N. Chalkley
SL 2635 Shell-Chalkley
SL 2266 South Mallard Bay-America1
SL 2822 Superior-S. Thornwell
SL 9879 Total Minatome-Bell City
SL 2885 Union Texas-Welsh
SL 2853 Welsh Field
W.C. 294
Entering at ANR-Eunice SL 9026 W.C. 167/132
SL 9135 W.C. 167/HIOS Mainline
SL 9136 W.C. 167/Near Shore
SL 9396 W.C. 293/H.I. 120/H.I. 120-128
SL 9383 W.C. 293/H.I. 167/H.I. 167-166
SL 2838 W.C. 294
</TABLE>
18
<PAGE>
<TABLE>
<CAPTION>
Meter
Lateral Segment Zone No. Supply Point
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
HIOS
Offshore Points Entering at H.I. 247
ANR-Eunice
SL 2868 H.I. A-247/A-244A/A-231
SL 9176 H.I. A-247/A-245
H.I. 283
SL 9894 H.I. A-283/A-283A
SL 2855 H.I. A-285/A-282
H.I. 303
SL 2858 H.I. A-302A/A-303
H.I. A-345
SL 2863 H.I. 334A/A-335
SL 9327 H.I. A-345/A-325A
H.I. A-498
SL 2867 H.I. A-462
SL 9375 H.I. A-477/A-462/A-486
SL 2534 H.I. A-498/A-489
SL 2533 H.I. A-498/A-489/A-474
SL 2535 H.I. A-498/A-489/A-499
SL 9371 H.I. A-498/A-490
SL 2856 H.I. A-498/A-517
H.I. A-539
SL 2537 H.I. A-539/A-480
SL 9365 H.I. A-539/A-511
SL 9376 H.I. A-539/A-532
</TABLE>
19
<PAGE>
<TABLE>
<CAPTION>
Meter
Lateral Segment Zone No. Supply Point
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
SL 9328 H.I. A-539/A-550
SL 9901 H.I. A-539/A-552/A-551
SL 9889 H.I. A-539/A-552/A-553
SL 2539 H.I. A-539/A-567
SL 9380 H.I. A-539/A-568
H.I. A-555
SL 2857 H.I. A-531A
SL 2861 H.I. A-536C
SL 2862 H.I. A-537B
SL 9127 H.I. A-537B/A-537D/A-556
SL 9308 H.I. A-555
SL 9125 H.I. A-555/A-537D/A-556
SL 9887 H.I. A-555/A-557A/A-556
H.I. A-573
SL 9909 H.I. A-573/A-384/G B 224
SL 2859 H.I. A-573B Complex
SL 2542 H.I. A-595CF Complex
H.I. A-582
SL 9165 H.I. A-582/A-561A
SL 9133 H.I. A-582/E.B. 110
SL 9377 H.I. A-582/E.B. 160/Various
SL 9134 H.I. A-582/E.B. 165
MAINLINE
Bastrop-North 3 8082 ANR-Slaughters
3 2061 Bee-Hunter
</TABLE>
20
<PAGE>
<TABLE>
<CAPTION>
Meter
Lateral Segment Zone No. Supply Point
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
3 2072 Blair
2 8124 Dyersburg
3 2373 Har-Ken/Addison-G #1
3 2352 Har-Ken/Cox
3 2367 Har-Ken/I.C.C. #9
3 2376 Har-Ken/I.C.C. #12
3 2379 Har-Ken/I.C.C. #15
3 2022 Har-Ken/I.C.C. #16
3 2381 Har-Ken/I.C.C. #17
3 9530 Har-Ken/Murray
3 2362 Har-Ken/P. Gannon Est. #1
3 2351 Har-Ken/Qualls
3 2966 Har-Ken/Stearman #1
3 2960 Har-Ken/W. Ky. #1
3 2962 Har-Ken/W. Ky. #2
3 2375 Har-Ken/W. Ky. #6
3 2087 Heathville-Trenton
1 9303 Helena #2
3 9876 Hux Oil-Russellville
4 1715 Lebanon-Columbia
4 1247 Lebanon-Congas
4 1859 Lebanon-Texas Eastern
3 9527 Liberty-South Hill
3 8073 Midwestern-Whitesville
1 3801 Pooling Receipt-Zone 1
3 9525 Pride Energy No. 1
</TABLE>
21
<PAGE>
<TABLE>
<CAPTION>
Meter
Lateral Segment Zone No. Supply Point
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
3 9141 Reynolds-Narge Creek
3 5800 Slaughters-Storage Complex
(Withdraw)
1 2648 Spears
3 9404 United Cities-Barnsley
Eunice-Zone SL/1 Line SL 9035 ANR-Eunice
SL 9084 Bayou Pompey
SL 8107 Evangeline
SL 8046 Mamou
SL 3800 Pooling Receipt-Zone SL
SL 3900 SL Lateral Terminus
Zone SL/1 Line-Bastrop 1 2020 Arkla-Perryville
1 9870 Channel Explo.-Chicksaw Creek
1 9826 Delhi-Ewing
1 2361 Guffey-Millhaven
1 9877 Hadson-Olla/Summerville
1 9814 Hogan-Davis Lake
1 8063 Pineville (LIG)
1 9832 Wintershall-Clarks
</TABLE>
22
<PAGE>
CONTRACT NO. T6487
Contract Demand 8,000 MMBtu/D
EXHIBIT "B"
POINT(S) OF DELIVERY
<TABLE>
<CAPTION>
Meter MAOP MDP*
No. Name/Description Facilities (psig) (psig)
- -------------------------------------------------------------------------------
<C> <S> <C> <C> <C>
1529 Louisville Gas and Electric Company
BARDSTOWN ROAD - Latitude 38-12-0,
Longitude 85-36-0, Jefferson County, KY (1) 674 400
BEDFORD-LG&E-Latitude 38-34-30,
Longitude 85-18-15, Trimble County, KY (1) 810 400
CRESTWOOD-LG&E-Latitude 38-20-0,
Longitude 85-25-15, Oldham County, KY (1) 810 400
DOE RUN-Latitude 37-55-30,
Longitude 86-2-30, Meade County, KY (1) 810 400
ELDER PARK-Latitude 38-22-0,
Longitude 85-25-0, Oldham County, KY (1) 810 400
ELLINGSWORTH LANE-Latitude 38-13-15
Longitude 85-33-0, Jefferson County, KY (1) 810 350
LA GRANGE-Latitude 38-24-0,
Longitude 85-24-15, Oldham County, KY (1) 810 400
PENILE ROAD-Latitude 38-6-0,
Longitude 85-47-0, Jefferson County, KY (1) 674 400
PRESTON STREET ROAD-Latitude 38-9-45,
Longitude 85-41-30, Jefferson County, KY (1) 674 400
</TABLE>
23
<PAGE>
Contract No. T6487
Firm Transportation Agreement
Summer Season-Exhibit "C"
Supply Lateral Capacity
Louisville Gas and Electric Company
<TABLE>
<CAPTION>
PREFERENTIAL RIGHTS
SUPPLY LATERAL MMBTU/D
<S> <C>
Zone 1 Supply Lateral(s)
- ------------------------
North Louisiana Leg: 0
-------
Total Zone 1: 0
Zone SL Supply Lateral(s)
- -------------------------
East Leg: 0
Southeast Leg: 0
South Leg: 12,949
Southwest Leg: 7,297
West Leg: 0
WC-294: 0
HIOS: 12,303
-------
Total Zone SL: 32,549
-------
Grand Total: 32,549
-------
-------
</TABLE>
This exhibit reflects the combined total supply lateral capacity held by
Louisville Gas and Electric Company under the 2-year, 5-year and 8-year
agreements for Contract No. T6487. Amendments in contract quantities in either
the 2-year, 5-year or 8-year agreements will result in an amendment of this
exhibit.
24
<PAGE>
STANDARD FACILITIES KEY
(1) Measurement facilities are owned, operated, and maintained by Texas Gas
Transmission Corporation.
(2) Measurement facilities are owned, operated, and maintained by ANR
Pipeline Company.
(3) Measurement facilities are owned, operated, and maintained by Arkansas
Louisiana Gas Company.
(4) Measurement facilities are owned by Texas Gas Transmission Corporation
and operated and maintained by Kerr-McGee Corporation.
(5) Measurement facilities are owned, operated, and maintained by Koch
Gateway Pipeline Company.
(6) Measurement facilities are owned by Texas Gas Transmission Corporation
and operated and maintained by Delhi Gas Pipeline Corporation.
(7) Measurement facilities are owned, operated, and maintained by Kerr-McGee
Corporation.
(8) Measurement facilities are owned, operated, and maintained by Louisiana
Intrastate Gas Corporation.
(9) Measurement facilities are owned, operated, and maintained by Trunkline
Gas Company.
(10) Measurement facilities are owned, operated, and maintained by Columbia
Gulf Transmission Company.
(11) Measurement facilities are owned by Texas Gas Transmission Corporation
and operated and maintained by Columbia Gulf Transmission Company.
(12) Measurement facilities are owned, operated, and maintained by Florida Gas
Transmission Company.
(13) Measurement facilities are owned by Texas Gas Transmission Corporation
and operated and maintained by ANR Pipeline Company.
(14) Measurement facilities are owned by Champlin Petroleum Company and
operated and maintained by ANR Pipeline Company.
(15) Measurement facilities are owned by Transcontinental Gas Pipe Line
Corporation and operated and maintained by ANR Pipeline Company.
(16) Measurement facilities are jointly owned by others and operated and
maintained by ANR Pipeline Company.
25
<PAGE>
(17) Measurement facilities are owned by Koch Gateway Pipeline Company and
operated and maintained by ANR Pipeline Company.
(18) Measurement facilities are owned by Texas Gas Transmission Corporation
and operated and maintained by Texas Eastern Transmission Corporation.
(19) Measurement facilities are owned by Texas Gas Transmission Corporation
and operated and maintained by Natural Gas Pipeline Company of America.
(20) Measurement facilities are owned by Louisiana Intrastate Gas Corporation
and operated and maintained by Texas Gas Transmission Corporation.
(21) Measurement facilities are owned, operated, and maintained by Texas
Eastern Transmission Corporation.
(22) Measurement facilities are owned by Kerr-McGee Corporation and operated
and maintained by ANR Pipeline Company.
(23) Measurement facilities are operated and maintained by ANR Pipeline
Company.
(24) Measurement facilities are owned, operated, and maintained by
Transcontinental Gas Pipe Line Corporation.
(25) Measurement facilities are owned by Texas Gas Transmission Corporation
and operated and maintained by Tennessee Gas Pipeline Company.
(26) Measurement facilities are owned, operated, and maintained by Northern
Natural Gas Company.
(27) Measurement facilities are owned and maintained by Faustina Pipeline
Company and operated by Texas Gas Transmission Corporation.
(28) Measurement facilities are owned by Samedan and operated and maintained
by ANR Pipeline Company.
(29) Measurement facilities are owned by Texas Gas Transmission Corporation
and operated and maintained by CNG Producing.
(30) Measurement facilities are owned, operated, and maintained by Devon
Energy Corporation.
(31) Measurement facilities are owned by Total Minatome Corporation and
operated and maintained by Texas Gas Transmission Corporation.
(32) Measurement facilities are owned by Texas Gas Transmission Corporation
and operated and maintained by Trunkline Gas Company.
26
<PAGE>
(33) Measurement facilities are owned by Linder Oil Company and operated and
maintained by Texas Gas Transmission Corporation.
(34) Measurement facilities are owned, operated, and maintained by Mississippi
River Transmission Corporation.
(35) Measurement facilities are owned, operated, and maintained by Texaco Inc.
(36) Measurement facilities are owned by Texas Gas Transmission Corporation
and operated and maintained by Louisiana Resources Company.
(37) Measurement facilities are owned, operated, and maintained by Louisiana
Resources Company.
(38) Measurement facilities are owned by Oklahoma Gas Pipeline Company and
operated and maintained by ANR Pipeline Company.
(39) Measurement and interconnecting pipeline facilities are owned and
maintained by Louisiana Resources Company. The measurement facilities are
operated and flow controlled by Texas Gas Transmission Corporation.
(40) Measurement facilities are owned by Hall-Houston and operated and
maintained by ANR Pipeline Company.
(41) Measurement facilities are owned, operated, and maintained as specified
in Exhibit "B".
(42) Measurement facilities are owned by Enron Corporation and operated and
maintained by Texas Gas Transmission Corporation.
(43) Measurement facilities are owned by United Cities Gas Company and
operated and maintained by TXG Engineering, Inc.
(44) Measurement facilities are owned, operated, and maintained by NorAm Gas
Transmission Company.
(45) Measurement facilities are owned by Falcon Seaboard Gas Company and
operated and maintained by Texas Gas Transmission Corporation.
(46) Measurement facilities are owned by ANR Pipeline Company and operated and
maintained by High Island Offshore System.
(47) Measurement facilities are owned by Forest Oil Corporation, et al., and
operated and maintained by Tenneco Gas Transportation Company.
(48) Measurement facilities are owned by PSI, Inc., and operated and
maintained by ANR Pipeline Company.
27
<PAGE>
(49) Measurement facilities are owned, operated, and maintained by Tennessee
Gas Pipeline Company.
(50) Measurement facilities are owned, operated, and maintained by Colorado
Interstate Gas Company.
(51) Measurement facilities are owned by Producer's Gas Company and operated
and maintained by Natural Gas Pipeline Company of America.
(52) Measurement facilities are owned by Zapata Exploration and operated and
maintained by ANR Pipeline Company.
(53) Measurement facilities are jointly owned by Amoco, Mobil, and Union;
operated and maintained by ANR Pipeline Company.
(54) Measurement facilities are owned, operated, and maintained by VHC Gas
Systems, L.P.
(55) Measurement facilities are owned by Walter Oil and Gas and operated and
maintained by Columbia Gulf Transmission Company.
(56) Measurement facilities are operated and maintained by Natural Gas
Pipeline Company of America.
(57) Measurement facilities are operated and maintained by Texas Gas
Transmission Corporation.
(58) Measurement facilities are operated and maintained by Tennessee Gas
Pipeline Company.
(59) Measurement facilities are operated and maintained by Columbia Gulf
Transmission Company.
(60) Measurement facilities are owned, operated, and maintained by Midwestern
Gas Transmission Company.
(61) Measurement facilities are owned, operated, and maintained by Western
Kentucky Gas Company.
28
<PAGE>
CONTRACT #95-348-026
COAL SUPPLY AGREEMENT
This is a coal supply agreement (the "Agreement") dated January 1, 1996
between LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation, 220 West
Main Street, Louisville, Kentucky 40202 ("Buyer") and LAFAYETTE COAL COMPANY, an
Illinois corporation, 200 Frontage Road, Burr Ridge, Illinois 60521 and BLACK
BEAUTY COAL COMPANY, an Indiana corporation, 414 S. Fares Avenue, Evansville,
Indiana 47702 (collectively "Seller").
The parties hereto agree as follows:
SECTION 1. GENERAL. Seller will sell to Buyer and Buyer will buy from
Seller steam coal under all the terms and conditions of this Agreement.
SECTION 2. TERMINATION OF CURRENT AGREEMENT; TERM.
Section 2.1 TERMINATED AGREEMENT. The Coal Supply Agreement dated
August 2, 1989 between the parties, as amended (the "Terminated Agreement"),
shall be terminated effective December 31, 1995.
Section 2.2 TERM. The term of this Agreement shall commence on
January 1, 1996 and shall continue through December 31, 1997. Buyer shall
have the right to extend the term hereof through December 31, 2000 with a
Base Quantity in the amount of 500,000 tons per year, subject to the parties
reaching an agreement on price for the coal sold during such extended term.
<PAGE>
CONTRACT #95-348-026
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)
---- --------------------
1996 560,000
1997 560,000
Section 3.2 DELIVERY SCHEDULE. 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 pursuant to a reasonable schedule. 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.
Section 3.3 ADJUSTMENTS. Buyer may either decrease or increase the Base
Quantity for each year by up to 15% by giving to Seller notice of such
adjustment by December 1 of the previous year, except that (1) the variation in
tonnage between the adjusted Base Quantity and the adjusted Base Quantity from
the preceding year under this Agreement or the Terminated Agreement will not
exceed 15%, and (2) the adjusted Base Quantity shall not exceed 644,000 tons or
be less than 476,000 tons for any year.
2
<PAGE>
CONTRACT #95-348-026
SECTION 4. SOURCE.
Section 4.1 SOURCE. The coal sold hereunder, including coal purchased by
Seller from third parties, shall be supplied from Indiana geological seams 5, 6
and 7, Columbia Mine, Pike County, Indiana and Enterprise Mine, Gibson County,
Indiana (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 have at
the Coal Property adequate machinery, equipment and other facilities to produce,
prepare and deliver coal in the quantity and of 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 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
3
<PAGE>
CONTRACT #95-348-026
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, in the event that Seller is unable to produce or obtain coal
from the Coal Property in the quantity and of the quality required by this
Agreement, and such inability is not caused by a force majeure event as
defined in Section 10, then Buyer will have the option of requiring that
Seller supply substitute coal from other facilities and mines under all the
terms and conditions of this Agreement including, but not limited to, the
price provisions of Section 8, the quality specifications of Section 6.1, and
the provisions of Section 5 concerning reimbursement to Buyer for increased
transportation costs. Seller's delivery of coal not produced from the Coal
Property without having received the express written consent of Buyer shall
constitute a material breach of this Agreement.
SECTION 5. DELIVERY. The coal shall be delivered to Buyer F.O.B. barge at
the Evansville Terminal dock at mile point 784.0 on the Ohio River (the
"Delivery Point"). Seller may deliver the coal at a location different from the
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 barges containing the coal are
disengaged by Buyer's barging
4
<PAGE>
CONTRACT #95-348-026
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 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 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 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 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
5
<PAGE>
CONTRACT #95-348-026
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 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.
SECTION 6. QUALITY.
Section 6.1 SPECIFICATIONS.
(a) If Buyer nominates "Washed Coal" pursuant to Section 6.1(b),
then the coal delivered hereunder shall conform to the following specifications
on an "as received" basis:
WASHED COAL
-----------
<TABLE>
<CAPTION>
Guaranteed Monthly Rejection Limits
Specifications Weighted Average (per shipment)
- ----------------------------------------------------------------------------
<S> <C> <C>
BTU/LB. min. 11,250 LESS THAN10,700
LBS/MMBTU:
---------
MOISTURE max. 12.25 GREATER THAN14.25
ASH max. 8.25 GREATER THAN10.0
SULFUR max. 2.75 GREATER THAN3.2
SULFUR min. 1.7 LESS THAN1.7
CHLORINE max. .03 GREATER THAN.04
NITROGEN max. 1.6 GREATER THAN2.8
ASH/SULFUR RATIO min. 2.2 LESS THAN2.0
Size (3" x 0"):
6
<PAGE>
CONTRACT #95-348-026
Top size (inches)* max. 3.0" GREATER THAN3.0"
Fines (% by wgt)
Passing 1/4" screen max. 32% GREATER THAN35%
% BY WEIGHT:
-----------
VOLATILE max. 34 GREATER THAN35
VOLATILE min. 30 LESS THAN29
FIXED CARBON max. 45 GREATER THAN47
FIXED CARBON min. 42 LESS THAN40
GRINDABILITY (HGI) min. 54 LESS THAN52
BASE ACID RATIO (B/A)
SLAGGING FACTOR** max. 1.9 GREATER THAN2.1
FOULING FACTOR*** max. 0.3 GREATER THAN0.44
ASH FUSION TEMPERATURE (DEG. F) (ASTM D1857)
----------------------------------------
REDUCING ATMOSPHERE
-------------------
Initial Deformation min. 2050 min. 2020
Softening (H=W) min. 2210 min. 2190
Softening (H=1/2W) min. 2400 min. 2290
Fluid min. 2475 min. 2350
OXIDIZING ATMOSPHERE
--------------------
Initial Deformation min. 2500 min. 2480
Softening (H=W) min. 2600 min. 2550
Softening (H=1/2W) min. 2620 min. 2610
Fluid min. 2640 min. 2620
</TABLE>
* 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 (R(s))=(B/A) x (Percent Sulfur by Weight(Dry))
*** Fouling Factor (R(f))=(B/A) x (Percent Na(2)0 by Weight(Dry))
7
<PAGE>
CONTRACT #95-348-026
The Base Acid Ratio (B/A) is herein defined as:
BASE ACID RATIO (B/A) = (FE(2)0(3) + CA0 + MG0 + NA(2)0 + K(2)0)
----------------------------------------
(Si0(2) + A1(2)0(3) + T10(2))
Note: As used herein GREATER THAN means greater than:
LESS THAN means less than.
If Buyer nominates "Blend Coal" pursuant to Section 6.1(b), then the coal
delivered hereunder shall conform to the following specifications on an "as
received" basis:
BLEND COAL
----------
<TABLE>
<CAPTION>
Guaranteed Monthly Rejection Limits
Specifications Weighted Average (per shipment)
- ----------------------------------------------------------------------------
<S> <C> <C>
BTU/LB. min. 11,200 LESS THAN10,700
LBS/MMBTU:
---------
MOISTURE max. 12.00 GREATER THAN14.25
ASH max. 9.00 GREATER THAN11.0
SULFUR max. 3.05 GREATER THAN3.4
SULFUR min. 1.7 LESS THAN1.7
CHLORINE max. .03 GREATER THAN.04
NITROGEN max. 1.6 GREATER THAN2.8
ASH/SULFUR RATIO min. 2.2 LESS THAN2.0
Size (3" x 0"):
Top size (inches)* max. 3.0" GREATER THAN3.0"
Fines (% by wgt)
Passing 1/4" screen max. 32% GREATER THAN35%
% BY WEIGHT:
-----------
VOLATILE max. 34 GREATER THAN35
VOLATILE min. 30 LESS THAN29
FIXED CARBON max. 45 GREATER THAN47
FIXED CARBON min. 42 LESS THAN40
GRINDABILITY (HGI) min. 54 LESS THAN52
8
<PAGE>
CONTRACT #95-348-026
BASE ACID RATIO (B/A)
SLAGGING FACTOR** max. 1.9 GREATER THAN2.1
FOULING FACTOR*** max. 0.3 GREATER THAN0.44
ASH FUSION TEMPERATURE (DEG. F) (ASTM D1857)
----------------------------------------
REDUCING ATMOSPHERE
-------------------
Initial Deformation min. 2050 min. 2020
Softening (H=W) min. 2210 min. 2190
Softening (H=1/2W) min. 2400 min. 2290
Fluid min. 2475 min. 2350
OXIDIZING ATMOSPHERE
--------------------
Initial Deformation min. 2500 min. 2480
Softening (H=W) min. 2600 min. 2550
Softening (H=1/2W) min. 2620 min. 2610
Fluid min. 2640 min. 2620
</TABLE>
* 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 (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:
BASE ACID RATIO (B/A) = (FE(2)0(3) + CA0 + MG0 + NA(2)0 + K(2)0)
----------------------------------------
(Si0(2) + A1(2)0(3) + T10(2))
Note: As used herein GREATER THAN means greater than:
LESS THAN means less than.
9
<PAGE>
CONTRACT #95-348-026
(b) Buyer shall have the right to receive either all Washed Coal
or all Blend Coal or both Washed Coal and Blend Coal in any ratio Buyer desires
hereunder at Buyer's option subject to the pricing provisions set forth in
Section 8.1. Buyer may change such nomination or such ratio at any time by
giving to Seller thirty (30) days prior written notice of such change.
Section 6.2 DEFINITION OF "SHIPMENT". As used herein, a "shipment" shall
mean one barge load or a barge lot load in accordance with Buyer's sampling and
analyzing practices.
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 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 exceed the price of such coal under this Agreement plus
transportation costs to
10
<PAGE>
CONTRACT #95-348-026
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, than such non-conforming coal shall be deemed accepted by Buyer;
however, the quantity Seller is obligated to sell to Buyer under the
Agreement may or may not be reduced by the amount of each such non-conforming
shipment at Buyer's sole option and the Shipment shall nevertheless be
considered "rejectable" under Section 6.4. 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 the coal sold hereunder fails to meet one or more of the Guaranteed
Monthly Weighted Averages set forth in Section 6.1 for any three (3)
consecutive months in a six (6) month period, or if nine (9) barge
shipments in a 30 day period are rejectable by Buyer, Buyer may upon notice
confirmed in writing and sent to Seller by certified mail, suspend future
shipments except shipments already loaded into barges. Seller shall, within
10 days, provide Buyer with reasonable assurances that subsequent monthly
deliveries of coal shall
11
<PAGE>
CONTRACT #95-348-026
meet or exceed the Guaranteed Monthly Weighted Averages set forth in Section
6.1 and that the source will exceed 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 10 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 any of the Guaranteed Monthly
Weighted Averages for any one (1) month within the next six (6) months or if
three (3) barge shipments are rejectable within any one (1) month during such
six (6) 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 method is mutually agreed upon by the
parties. Such scales shall be duly reviewed 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
over
12
<PAGE>
CONTRACT #95-348-026
or under the tolerance range allowable for the scale based on industry accepted
standards, 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 industry-accepted standards. Samples for
analyses shall be taken by any 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.
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 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; one part shall be
retained by Buyer until the 25th of the month following the
13
<PAGE>
CONTRACT #95-348-026
month of unloading (the "Disposal Date") and shall be delivered to Seller for
analysis if Seller so requests before the Disposal Date; and one part ("Referee
Sample") shall be retained by Buyer until the Disposal Date. Seller shall be
given copies of all analyses made by Buyer by the 12th day of the month
following the month of unloading. 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
before the Disposal Date, 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 before the Disposal Date, 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. For
each coal quality specification in question, a dispute shall be deemed not to
exist and Buyer's analysis shall prevail and the analysis of the Independent Lab
shall be disregarded if the analysis of the Independent Lab differs from the
analysis of Buyer by an amount equal to or less than:
(i) 0.50% moisture
(ii) 0.50% ash on a dry basis
(iii) 100 Btu/lb. on a dry basis
(iv) 0.10% sulfur on a dry basis.
For each coal quality specification in question, if the analysis of the
Independent Lab differs from the analysis of Buyer by an amount more than the
amounts listed above, then the analysis of the Independent Lab shall prevail and
Buyer's analysis shall be disregarded.
14
<PAGE>
CONTRACT #95-348-026
The cost of the analysis made by the Independent Lab shall be borne by Seller to
the extent that Buyer's analysis prevails and by Buyer to the extent that the
analysis of the Independent Lab prevails.
SECTION 8. PRICE.
Section BASE PRICE. Subject to Section 8.4, the base price ("Base Price")
of the coal to be sold hereunder will be firm and will be $.79000/MMBTU for
Washed Coal and $.77500/MMBTU for Blend Coal.
Section 8.2 QUALITY PRICE DISCOUNTS.
(a) The Base Price is based on coal meeting or exceeding the Guaranteed
Monthly Weighted Average specifications as set forth in Section 6.1. 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
6.1, as determined pursuant to Section 7.2, subject to the provisions set forth
below. The discount values used are as follows:
DISCOUNT VALUES
---------------
$/MMBTU
-------
BTU/LB. 0.2604
$/LB./MMBTU
-----------
SULFUR 0.1232
ASH 0.0083
MOISTURE 0.0016
(b) Notwithstanding the foregoing, for each specification each month,
there shall be no discount if the actual Monthly Weighted Average meets the
applicable Discount Point set forth below. However, if the actual Monthly
Weighted Average fails to meet such
15
<PAGE>
CONTRACT #95-348-026
applicable Discount Point, then the discount shall apply and shall be calculated
on the basis of the difference between the actual Monthly Weighted Average AND
THE GUARANTEED MONTHLY WEIGHTED AVERAGE pursuant to the methodology shown in
Exhibit A attached hereto.
<TABLE>
<CAPTION>
WASHED COAL
-----------
Guaranteed
Monthly
Weighted Average Discount Point
---------------- --------------
<S> <C> <C>
BTU/LB min. 11,250 11,000
LB/MMBTU:
---------
SULFUR max. 2.75 3.0
ASH max. 8.25 9.5
MOISTURE max. 12.25 13.75
<CAPTION>
BLEND COAL
----------
Guaranteed
Monthly
Weighted Average Discount Point
---------------- --------------
<S> <C> <C>
BTU/LB min. 11,200 10,900
LB/MMBTU:
---------
SULFUR max. 3.05 3.30
ASH max. 9.00 10.50
MOISTURE max. 12.00 13.50
</TABLE>
16
<PAGE>
CONTRACT #95-348-026
For example, for Washed Coal, if the actual Monthly Weighted Average of
sulfur equals 3.05 lb/MMBTU, then the applicable discount would be (3.05 lb. -
2.75 lb.) X $.1232/lb/MMBTU = $.03696/MMBTU.
Section 8.3 PAYMENT CALCULATION. Exhibit A 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.
Section 8.4 GOVERNMENTAL IMPOSITIONS. 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. No price adjustment shall be made for costs
occasioned by any such taxes, fees, costs and the like in effect on the
effective date of this Agreement. In the event of any one enactment,
promulgation or change in any statute, regulation, or the like or of any one
governmental imposition enacted or promulgated after the effective date of this
Agreement, which increases or decreases the Seller's total costs of performance
hereunder by at least $.10 per ton, Seller shall give Buyer prompt written
notice thereof, including the amount of increase or decrease in cost and notice
of proportionate adjustment in Base Price, including the furnishing to Buyer of
all computations, data and information reasonably necessary to substantiate such
notice.
17
<PAGE>
CONTRACT #95-348-026
Buyer shall have the right to audit and inspect Seller's books and records for
the purpose of evaluating such notice. The Base Price shall be adjusted in
accordance with the notice subject to revision based upon an audit by Buyer.
SECTION 9. INVOICES, BILLING AND PAYMENT.
Section 9.1 INVOICING ADDRESS. Invoices will be sent to Buyer at the
following address:
Louisville Gas and Electric Company
220 West Main Street
P.O. Box 32010
Louisville, KY 40232
Attention: Manager, Coal Supply
With a copy to:
Louisville Gas and Electric Company
220 West Main Street
P.O. Box 32010
Louisville, KY 40232
Attention: Manager, Accounts Payable
Section 9.2 INVOICE PROCEDURES FOR COAL SHIPMENTS. Seller shall invoice
Buyer at the Base Price, minus any quality price discounts, 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
Lafayette Coal Company, P.O. Box 95580, Chicago, Illinois 60694.
18
<PAGE>
CONTRACT #95-348-026
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.
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.
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CONTRACT #95-348-026
During any period in which Seller's ability to perform hereunder is
affected by a force majeure event, Seller shall not deliver any coal from the
Coal Property 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.
During any period in which Buyer's ability to perform hereunder is affected
by a force majeure event, Buyer shall not take delivery of any coal from any
other sellers from whom Buyer's ability to take delivery 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 take delivery from
Seller under this Agreement of at least a pro rata portion (on a per ton basis)
of its total contractual commitments to all its sellers from whom Buyer's
ability to take delivery 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 may be made up by
mutual agreement of Buyer and Seller on a reasonable schedule.
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CONTRACT #95-348-026
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 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
21
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CONTRACT #95-348-026
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 price per ton of coal, or in any other provision of this
Agreement, an equitable adjustment shall be made in: 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.
SECTION 12. NOTICES.
Section 12.1 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 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
22
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CONTRACT #95-348-026
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: Lafayette Coal Company
200 Frontage Road
Burr Ridge, Illinois 60521
AND Black Beauty Coal Company
414 S. Fares Avenue
Evansville, Indiana 47702
Attn: Senior Vice President - Marketing
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.
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.
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CONTRACT #95-348-026
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.
If this Agreement is terminated early in whole, then 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 the termination
date of this Agreement as set forth in Section 2. For example, if Seller
terminates this Agreement in whole effective December 31, 1996, then Seller
would owe Buyer $1,960,000 under this Section 13. If this Agreement is
terminated early in part, then the price paid for such early termination shall
be $3.50 times the total tonnage terminated from the effective date of the early
termination until the termination date of this Agreement as set forth in Section
2. For example, if Seller terminates this Agreement in part effective December
31, 1996 by reducing the Base Quantity from 560,000 to 300,000 tons, then Seller
would owe Buyer $910,000 under this Section 13. This provision is not intended
to limit, liquidate, or otherwise affect in any manner damages recoverable for
breach of this Agreement.
SECTION 14. RIGHT TO RESELL. Buyer shall have the unqualified right to
sell all or any of the coal purchased under this Agreement.
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CONTRACT #95-348-026
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 inside and outside attorney's fees) (i) relating to the barges
provided by Buyer or Buyer's contractor while such barges 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 carry 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
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CONTRACT #95-348-026
shall be supplied by the Seller to the Buyer evidencing that the above insurance
is in force and that not less than 30 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.
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CONTRACT #95-348-026
SECTION 17. DOCUMENTATION AND RIGHT OF AUDIT.
Seller shall maintain all records and accounts pertaining to payments,
quantities, quality analyses, and source for 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 18. 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).
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CONTRACT #95-348-026
SECTION 19. COAL PROPERTY INSPECTIONS. Buyer and its representatives,
and others as may be required by applicable laws, ordinances and regulations
shall have the right at all reasonable times and at their own expense to inspect
the Coal Property, including the loading facilities, scales, sampling system(s),
wash plant facilities, and mining equipment for conformance with this Agreement.
Seller shall undertake reasonable care and precautions to prevent personal
injuries to any representatives, agents or employees of Buyer (collectively,
"Visitors") who inspect the Coal Property. Any such Visitors shall make every
reasonable effort to comply with Seller's regulations and rules regarding
conduct on the work site, made known to Visitors prior to entry, as well as
safety measures mandated by state or federal rules, regulations and laws. Buyer
understands that coal mines and related facilities are inherently high-risk
environments. Buyer's failure to inspect the Coal Property or to object to
defects therein at the time Buyer inspects the same shall not relieve Seller of
any of its responsibilities nor be deemed to be a waiver of any of Buyer's
rights hereunder.
SECTION 20. MISCELLANEOUS.
Section 20.1 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 20.2 HEADINGS. The paragraph headings appearing in this Agreement
are for convenience only and shall not affect the meaning or interpretation of
this Agreement.
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CONTRACT #95-348-026
Section 20.3 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 20.4 REMEDIES CUMULATIVE. Remedies provided under this Agreement
shall be cumulative and in addition to other remedies provided under this
Agreement or by law or in equity.
Section 20.5 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 20.6 BINDING EFFECT. This Agreement shall bind and inure to the
benefit of the parties and their successors and assigns.
Section 20.7 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.
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CONTRACT #95-348-026
Section 20.8 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 20.9 AMENDMENTS. Except as otherwise provided herein, this
Agreement may not be amended, supplemented or otherwise modified except by
written instrument signed by both parties hereto.
SECTION 21. JOINT AND SEVERAL LIABILITY. The obligations and
liabilities of Seller under this Agreement shall be joint and several
obligations and liabilities of Lafayette Coal Company and Black Beauty Coal
Company.
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 LAFAYETTE COAL COMPANY
By: By:
--------------------------- ----------------------------
Title: Title:
--------------------------- ----------------------------
Date: Date:
--------------------------- ----------------------------
BLACK BEAUTY COAL COMPANY
By:
----------------------------
Title:
----------------------------
Date:
----------------------------
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CONTRACT #95-361-026
COAL SUPPLY AGREEMENT
THIS IS A COAL SUPPLY AGREEMENT (THE "AGREEMENT") DATED JANUARY 1, 1996
BETWEEN LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation, 220 West
Main Street, Louisville, Kentucky 40202 ("Buyer") and GREEN COAL COMPANY, INC.,
a Kentucky corporation, 6288 Chaney Road, Spottsville, Kentucky 42458-9719
("Seller").
The parties hereto agree as follows:
SECTION 1. GENERAL. Seller will sell to Buyer and Buyer will buy from
Seller steam coal under all the terms and conditions of this Agreement.
SECTION 2. TERMINATION OF CURRENT AGREEMENT; TERM.
Section 2.1 CURRENT AGREEMENT. The Coal Supply Agreement dated November
1, 1994 between the parties shall be terminated effective December 31, 1995.
Section 2.2 TERM. The term of this Agreement shall commence on January 1,
1996 and shall continue through December 31, 1998.
SECTION 3. QUANTITY.
Section 3.1 INITIAL NOMINATION. Within 15 days after this Agreement is
executed by both parties, the Buyer will deliver to Seller the Buyer's
nomination of the initial quantity of coal to be delivered hereunder. Such
quantity shall be no less than 50,000 tons per month and no more than 125,000
tons per month.
Section 3.2 CHANGES IN QUANTITY. At any time during the term of this
Agreement, the Buyer shall have the right either to increase or decrease the
quantity nominated hereunder
<PAGE>
CONTRACT #95-361-026
by up to 25% of the then current quantity. Buyer shall give notice of such
change to Seller at least three months before the effective date of such change.
Buyer may exercise this right repeatedly throughout the term of this Agreement,
except that the quantity nominated may not be either increased or decreased more
than 25% within any 90 day period and for any calendar year, the total quantity
nominated by Buyer shall not be less than 600,000 tons and shall not be more
than 2.5 million tons.
Section 3.3 DELIVERY SCHEDULE. Seller shall deliver quantities of coal in
accordance with Buyer's nominations hereunder. Time is of the essence with
respect to Seller's deliveries; and failure by Seller to deliver in a timely
manner shall constitute a material breach within the meaning of Section 16 of
this Agreement.
SECTION 4. SOURCE.
Section 4.1 SOURCE. The coal sold hereunder, including coal purchased by
Seller from third parties, shall be supplied from geological seam Kentucky #9,
Henderson and Hatchett Mill Mines, Henderson County, Kentucky (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 have at
the Coal Property adequate machinery, equipment and other facilities to produce,
prepare and deliver coal in the quantity and of the quality required by this
Agreement. Seller further agrees to operate and maintain such machinery,
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CONTRACT #95-361-026
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 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, in the event that Seller is unable to produce or obtain coal
from the Coal Property in the quantity and of the quality required by this
Agreement, and such inability is not caused by a force majeure event as defined
in Section 10, then Buyer will have the option of requiring that Seller supply
substitute coal from other facilities and mines under all the terms and
conditions of this Agreement including, but not limited to, the price provisions
of Section 8, the quality specifications of Section 6.1, and the provisions of
Section 5 concerning reimbursement to Buyer for increased transportation costs.
Seller's delivery of coal not produced from the Coal
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CONTRACT #95-361-026
Property without having received the express written consent of Buyer shall
constitute a material breach of this Agreement.
SECTION 5. DELIVERY. The coal shall be delivered to Buyer F.O.B. barge at
the Green Coal dock at mile point 11.5 on the Green River (the "Delivery
Point"). Seller may deliver the coal at a location different from the 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 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 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 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 Delivery Point, including the demurrage, penalties for loading
less than the specified minimum tonnage per barge, or
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CONTRACT #95-361-026
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 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 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.
SECTION 6. QUALITY.
Section 6.1 SPECIFICATIONS. (a) The coal delivered hereunder shall
conform to the following specifications on an "as received" basis:
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CONTRACT #95-361-026
<TABLE>
<CAPTION>
WASHED COAL
Guaranteed Monthly Rejection Limits
Specifications Weighted Average (per shipment)
- -------------------------------------------------------------------------------------
<C> <C> <C>
BTU/LB. min. 11,000 LESS THAN 10,500
MOISTURE max. 12.3 lbs/MMBTU GREATER THAN 14.5 lbs/MMBTU
ASH max. 9.6 lbs/MMBTU GREATER THAN 14.5 lbs/MMBTU
SULFUR max. 2.6 lbs/MMBTU GREATER THAN 3.4 lbs/MMBTU
SULFUR min. 1.8 lbs/MMBTU LESS THAN 1.8 lbs/MMBTU
CHLORINE max. .1 lbs/MMBTU GREATER THAN .2 lbs/MMBTU
FLUORINE max. .004 lbs/MMBTU GREATER THAN .01 lbs/MMBTU
NITROGEN max. 1.3 lbs/MMBTU GREATER THAN 1.5 lbs/MMBTU
ASH/SULFUR RATIO min. 5 LESS THAN 2.5
Size (3" x 0"):
Top size (inches)* max. 3" x 0 " GREATER THAN 3" x 0"
Fines (% by wgt)
Passing 1/4" screen max. 45% GREATER THAN 50%
% BY WEIGHT:
VOLATILE max. 37 GREATER THAN 38
VOLATILE min. 34 LESS THAN 29
FIXED CARBON max. 46 GREATER THAN 48
FIXED CARBON min. 30 LESS THAN 30
GRINDABILITY (HGI) min. 55 LESS THAN 50
BASE ACID RATIO (B/A) max. .466 GREATER THAN .8
SLAGGING FACTOR** max. 1.5 GREATER THAN 2.0
FOULING FACTOR*** max. .32 GREATER THAN 1.0
ASH FUSION TEMPERATURE (DEG.F) (ASTM D1857)
REDUCING ATMOSPHERE
Initial Deformation min. 2000 min. 1900
Softening (H=W) min. 2050 min. 1975
Softening (H=1/2W) min. 2100 min. 2000
Fluid min. 2200 min. 2100
OXIDIZING ATMOSPHERE
Initial Deformation min. 2400 min. 2200
Softening (H=W) min. 2400 min. 2280
Softening (H=1/2W) min. 2425 min. 2300
Fluid min. 2500 min. 2375
</TABLE>
6
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CONTRACT #95-361-026
<TABLE>
<CAPTION>
BLEND COAL
Guaranteed Monthly Rejection Limits
Specifications Weighted Average (per shipment)
- -------------------------------------------------------------------------------------
<S> <C> <C>
BTU/LB. min. 10,600 LESS THAN 10,000
MOISTURE max. 12.7 lbs/MMBTU GREATER THAN 14.5 lbs/MMBTU
ASH max. 13.2 lbs/MMBTU GREATER THAN 15 lbs/MMBTU
SULFUR max. 3.4 lbs/MMBTU GREATER THAN 3.5 lbs/MMBTU
SULFUR min. 1.8 lbs/MMBTU LESS THAN 1.8 lbs/MMBTU
CHLORINE max. .15 lbs/MMBTU GREATER THAN .2 lbs/MMBTU
FLUORINE max. .006 lbs/MMBTU GREATER THAN .01 lbs/MMBTU
NITROGEN max. 1.2 lbs/MMBTU GREATER THAN 1.5 lbs/MMBTU
ASH/SULFUR RATIO min. 4.8 LESS THAN 2.5
Size (3" x 0"):
Top size (inches)* max. 3" x 0" GREATER THAN 3" x 0"
Fines (% by wgt)
Passing 1/4" screen max. 45% GREATER THAN 50%
% BY WEIGHT:
VOLATILE max. 36 GREATER THAN 37
VOLATILE min. 30 LESS THAN 29
FIXED CARBON max. 44 GREATER THAN 46
FIXED CARBON min. 35 LESS THAN 30
GRINDABILITY (HGI) min. 55 LESS THAN 50
BASE ACID RATIO (B/A) max. .54 GREATER THAN .8
SLAGGING FACTOR** max. 1.9 GREATER THAN 2.0
FOULING FACTOR*** max. .4 GREATER THAN 1.0
ASH FUSION TEMPERATURE (DEG.F) (ASTM D1857)
REDUCING ATMOSPHERE
Initial Deformation min. 1940 min. 1900
Softening (H=W) min. 2050 min. 1975
Softening (H=1/2W) min. 2100 min. 2000
Fluid min. 2200 min. 2100
OXIDIZING ATMOSPHERE
Initial Deformation min. 2400 min. 2200
Softening (H=W) min. 2400 min. 2280
Softening (H=1/2W) min. 2425 min. 2300
Fluid min. 2500 min. 2375
</TABLE>
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CONTRACT #95-361-026
<TABLE>
<CAPTION>
RAW COAL
Guaranteed Monthly Rejection Limits
Specifications Weighted Average (per shipment)
- --------------------------------------------------------------------------------
<S> <C> <C>
BTU/LB. min. 10,300 LESS THAN 10,000
MOISTURE max. 13.4 lbs/MMBTU GREATER THAN 14.0 lbs/MMBTU
ASH max. 14.25 lbs/MMBTU GREATER THAN 15.5 lbs/MMBTU
SULFUR max. 4.0 lbs/MMBTU GREATER THAN 4.2 lbs/MMBTU
SULFUR min. 1.8 lbs/MMBTU LESS THAN 1.8 lbs/MMBTU
CHLORINE max. .15 lbs/MMBTU GREATER THAN .2 lbs/MMBTU
FLUORINE max. .006 lbs/MMBTU GREATER THAN .01 lbs/MMBTU
NITROGEN max. 1.2 lbs/MMBTU GREATER THAN 1.5 lbs/MMBTU
ASH/SULFUR RATIO min. 4.8 LESS THAN 2.5
Size (3" x 0"):
Top size (inches)* max. 3" x 0" GREATER THAN 3" x 0"
Fines (% by wgt)
Passing 1/4" screen max. 45% GREATER THAN 50%
% BY WEIGHT:
VOLATILE max. 36 GREATER THAN 37
VOLATILE min. 30 LESS THAN 29
FIXED CARBON max. 44 GREATER THAN 46
FIXED CARBON min. 35 LESS THAN 30
GRINDABILITY (HGI) min. 55 LESS THAN 50
BASE ACID RATIO (B/A) max. .54 GREATER THAN .8
SLAGGING FACTOR** max. 1.9 GREATER THAN 2.0
FOULING FACTOR*** max. .4 GREATER THAN 1.0
ASH FUSION TEMPERATURE (DEG. F) (ASTM D1857)
REDUCING ATMOSPHERE
Initial Deformation min. 1940 min. 1900
Softening (H=W) min. 2050 min. 1975
Softening (H=1/2W) min. 2100 min. 2000
Fluid min. 2200 min. 2100
OXIDIZING ATMOSPHERE
Initial Deformation min. 2400 min. 2200
Softening (H=W) min. 2400 min. 2280
Softening (H=1/2W) min. 2425 min. 2300
Fluid min. 2500 min. 2375
</TABLE>
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CONTRACT #95-361-026
* 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-five per cent (45%) by weight of coal that will pass through a
screen having circular perforations one-quarter (1/4) of an inch in diameter.
** 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:
BASE ACID RATIO (B/A) = (FE(2)0(3) + CA0 + MG0 + NA(2)0 + K(2)0)
------------------------------------------------
(Si0(2) + A1(2)0(3) + T10(2))
Note: As used herein GREATER THAN means greater than:
LESS THAN means less than.
(b) Seller shall deliver either all Blend Coal, all Raw Coal, or Washed
Coal, Blend Coal and Raw Coal in any ratio Buyer desires hereunder at Buyer's
option, subject to the pricing provision set forth in Section 8.1 and subject to
the limitations that Washed Coal shall not constitute more than twenty percent
(20%) of the total quantity to be delivered hereunder during any one month and
Seller shall not be obligated to deliver more than 20,000 tons of Washed Coal in
any one month. Buyer may change such nomination or such ratio at any time by
giving Seller thirty days prior written notice of such change.
Section 6.2 DEFINITION OF "SHIPMENT". As used herein, a "shipment" shall
mean one barge load or a barge lot load in accordance with Buyer's sampling and
analyzing practices.
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CONTRACT #95-361-026
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 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 exceed the price of such coal under this Agreement 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
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CONTRACT #95-361-026
accepted by Buyer; however, the quantity Seller is obligated to sell to Buyer
under the Agreement may or may not be reduced by the amount of each such non-
conforming shipment at Buyer's sole option and the shipment shall nevertheless
be considered "rejectable" under Section 6.4. 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 the coal sold hereunder fails to meet one or more of the Guaranteed
Monthly Weighted Averages set forth in Section 6.1 for any two (2) months in a
six (6) month period, or if nine (9) barge shipments in a 30 day period are
rejectable by Buyer, Buyer may upon notice confirmed in writing and sent to
Seller by certified mail, suspend future shipments except shipments already
loaded into barges. Seller shall, within 10 days, provide Buyer with
reasonable assurances that subsequent monthly deliveries of coal shall meet or
exceed the Guaranteed Monthly Weighted Averages set forth in Section 6.1 and
that the source will exceed 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 10 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.
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CONTRACT #95-361-026
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 any of the Guaranteed Monthly Weighted Averages for any one (1) month
within the next six (6) months or if three (3) barge shipments are rejectable
within any one (1) month during such six (6) 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 method is mutually agreed upon by the
parties. Such scales shall be duly reviewed 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
over or under the tolerance range allowable for the scale based on industry
accepted standards, 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 industry-
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CONTRACT #95-361-026
accepted standards. Samples for analyses shall be taken by any
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.
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 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; one part shall be retained by
Buyer until the 25th of the month following the month of unloading (the
"Disposal Date") and shall be delivered to Seller for analysis if Seller so
requests before the Disposal Date; and one part ("Referee Sample") shall be
retained by Buyer until the Disposal Date. Seller shall be given copies of all
analyses made by Buyer by the 12th day of the month following the month of
unloading. 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 before the Disposal Date,
Buyer's analysis shall be used to determine the quality
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CONTRACT #95-361-026
of the coal delivered hereunder. The Monthly Weighted Averages shall be
determined by utilizing the individual shipment analyses.
If any dispute arises before the Disposal Date, 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. For each
coal quality specification in question, a dispute shall be deemed not to exist
and Buyer's analysis shall prevail and the analysis of the Independent Lab shall
be disregarded if the analysis of the Independent Lab differs from the analysis
of Buyer by an amount equal to or less than:
(i) 0.50% moisture
(ii) 0.50% ash on a dry basis
(iii) 100 Btu/lb. on a dry basis
(iv) 0.10% sulfur on a dry basis.
For each coal quality specification in question, if the analysis of the
Independent Lab differs from the analysis of Buyer by an amount more than the
amounts listed above, then the analysis of the Independent Lab shall prevail and
Buyer's analysis shall be disregarded. The cost of the analysis made by the
Independent Lab shall be borne by Seller to the extent that Buyer's analysis
prevails and by Buyer to the extent that the analysis of the Independent Lab
prevails.
SECTION 8. PRICE.
Section 8.1 BASE PRICE. The base price ("Base Price") of the coal to be
sold hereunder will be firm and will be determined by the type of coal
nominated, the quantity nominated for
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CONTRACT #95-361-026
the applicable calendar year, and the year for which the coal is nominated in
accordance with the following matrix:
<TABLE>
<CAPTION>
Raw Coal Blend Coal Washed Coal
Tonnage Per -------- ---------- -----------
Year 1996 1997/98 1996 1997/98 1996 1997/98
---- ----------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
600,000-1,200,000 .70000 .68000 .73000 .72000 .77000 .76000
1,200,000-1,800,000 .68000 .65000 .70000 .69000 .74000 .72000
GREATER THAN 1,800,000 .61750 .61250 .65000 .65400 .69000 .67000
</TABLE>
(Note: all prices in c/MMBTU).
For pricing purposes, the tonnage per year is based on tonnage nominated by
Buyer in accordance with the terms of this Agreement and is not based on actual
deliveries unless Buyer fails to accept delivery of coal tendered by Seller
without legal excuse. For example, if Buyer duly nominates 1,300,000 tons, but
Seller delivers only 1,100,000 tons for any reason other than Buyer's failure to
accept delivery in breach hereof, then the pricing will be based on 1,300,000
tons. However, if Buyer duly nominates 1,300,000 tons, but Seller delivers only
1,100,000 tons because of Buyer's failure to accept delivery in breach hereof,
the pricing will be based on 1,100,000 tons.
Section 8.2 QUALITY PRICE DISCOUNTS.
(a) The Base Price is based on coal meeting or exceeding the Guaranteed
Monthly Weighted Average specifications as set forth in Section 6.1. Quality
price discounts shall
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CONTRACT #95-361-026
be applied for each specification each month to reflect failures to meet the
Guaranteed Monthly Weighted Averages set forth in Section 6.1, as determined
pursuant to Section 7.2, subject to the provisions set forth below. The
discount values used are as follows:
DISCOUNT VALUES
$/MMBTU
BTU/LB. 0.2604
$/LB./MMBTU
SULFUR 0.1232
ASH 0.0083
MOISTURE 0.0016
(b) Notwithstanding the foregoing, for the BTU/LB specification each
month, there shall be no discount if the actual Monthly Weighted Average meets
the applicable Discount Point set forth below. However, if the actual Monthly
weighted Average fails to meet such applicable Discount Point, then the discount
shall apply and shall be calculated on the basis of the difference between the
actual Monthly Weighted Average AND THE GUARANTEED MONTHLY WEIGHTED AVERAGE
pursuant to the methodology shown in Exhibit A attached hereto.
<TABLE>
<CAPTION>
GUARANTEED
MONTHLY
WEIGHTED AVERAGE DISCOUNT POINT
- -----------------------------------------------------------------------------
BTU/LB WASHED BLEND RAW WASHED BLEND RAW
- -----------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
11,000 10,600 10,300 10,800 10,400 10,100
</TABLE>
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CONTRACT #95-361-026
For example, if the actual Monthly Weighted Average of BTU/LB for Washed
Coal equals 10,700, then the applicable discount would be [1-(10,700/11,000)] X
$.2604 MMBTU = $.00710/MMBTU.
Section 8.3 PAYMENT CALCULATION. Exhibit A 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.
SECTION 9. INVOICES, BILLING AND PAYMENT.
Section 9.1 INVOICING ADDRESS. Invoices will be sent to Buyer at the
following address:
Louisville Gas and Electric Company
220 West Main Street
P.O. Box 32010
Louisville, KY 40232
Attention: Director, Fuels Procurement and Delivery
With a copy to:
Louisville Gas and Electric Company
220 West Main Street
P.O. Box 32010
Louisville, KY 40232
Attention: Manager, Accounts Payable
Section 9.2 INVOICE AND MONTHLY PAYMENT PROCEDURES. For all coal unloaded
in any week (beginning Tuesday and ending Monday), Buyer shall make preliminary
payment by wire transfer by the Tuesday immediately succeeding such week to
National City Bank, Louisville, Kentucky, ABA #083000056, Account #704-3695-7,
Attn: Mike Byers.
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CONTRACT #95-361-026
Preliminary payment shall be in the amount of $12 per ton unloaded during the
previous week. After the end of each calendar month, there will be a true-up as
follows. The amount due for all coal (based on the initial Base Price minus any
Quality Price Discounts) unloaded during any week (beginning Tuesday and ending
Monday) which ended during such calendar month shall be calculated and compared
to the sum of the preliminary payments made for coal unloaded during such weeks.
The difference shall be paid by or paid to the Seller, as applicable, by the
25th of the following month or within ten (10) days after receipt of Seller's
invoice, whichever is later.
Section 9.3 TONNAGE ESTIMATES AND TRUE-UPS. Prior to the beginning of
each calendar year, Buyer shall deliver to Seller Buyer's good faith estimate
(the "Original Estimate") of whether the total tonnage to be nominated for such
calendar year will be between 600,000 and 1,200,000 tons, between 1,200,000 tons
and 1,800,000 tons, or greater than 1,800,000 tons. The Original Estimate and
all revisions thereto shall be used only to determine the Base Price for initial
monthly payment purposes and shall not limit any of Buyer's rights hereunder,
including, but not limited to, Buyer's right to change the quantity as set forth
in Section 3.2. After the end of each calendar quarter, Buyer promptly shall
review its Original Estimate. If Buyer determines in good faith that the
Original Estimate of annual quantity is incorrect, then Buyer promptly will
deliver to Seller notice of a revision to the Original Estimate. With respect
to invoicing and monthly payments which shall have occurred prior to such notice
of revision, there will be a true-up as follows. If there shall have been
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CONTRACT #95-361-026
an underpayment based on the revised estimate, Buyer shall pay to Seller the
amount of the underpayment in a lump sum. If there shall have been an
overpayment based on the revised estimate, then the Seller shall pay to the
Buyer the amount of the overpayment in a lump sum. All invoicing and payments
which occur after the notice of revision to the Original Estimate shall be based
on the revised estimate. In any case, after the end of each calendar year,
there will be a final true-up (if necessary) based on actual nominations under
which the Buyer will pay to the Seller the amount of any underpayment in a lump
sum and the Seller will pay to the Buyer the amount of any overpayment in a lump
sum.
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.
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
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CONTRACT #95-361-026
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. 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.
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CONTRACT #95-361-026
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 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
21
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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 price per ton of coal, or in any other provision of this
Agreement, an equitable adjustment shall be made in: 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.
SECTION 12. NOTICES.
Section 12.1 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 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
22
<PAGE>
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.: Director, Fuels Procurement and Delivery
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: Green Coal Company, Inc.
6288 Chaney Road
Spottsville, Kentucky 42458-9719
Attn: Mike Exline
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.
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 of its rights and obligations
under this Agreement as follows: The party desiring to exercise its right of
early termination shall
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<PAGE>
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 quantity of coal (in tons) nominated under
this Agreement during the calendar year immediately preceding the effective date
of the early termination times the number of years remaining under this
Agreement. For example, if Seller terminates this Agreement effective December
31, 1996 and the quantity of coal nominated under this Agreement during 1996 is
700,000 tons, then Seller would owe Buyer $4,900,000 under this Section 13.
This provision is not intended to limit, liquidate, or otherwise affect in any
manner damages recoverable for breach of this Agreement.
SECTION 14. RIGHT TO RESELL. Buyer shall have the unqualified right to
sell all or any of the coal purchased under this Agreement.
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 inside and outside attorney's fees) (i) relating to the barges
provided by Buyer or Buyer's contractor while such barges are in the care and
custody of the loading dock or loading facility, (ii) due to any failure of
Seller to comply with laws,
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<PAGE>
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 carry 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
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.
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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.
SECTION 18. DOCUMENTATION AND RIGHT OF AUDIT.
Section 18.1 COAL RECORDS. Seller shall maintain all records and accounts
pertaining to payments, quantities, quality analyses, and source for all coal
supplied under this Agreement for a period lasting through the term of this
Agreement and for two years
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<PAGE>
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 18.2 FINANCIAL INFORMATION. Within 30 days after the date
completed, Seller shall deliver to Buyer copies of all of Seller's audited and
unaudited financial statements (including, but not limited to, balance sheets,
profit and loss statements, and cash flow statements) and supporting financing
documents and records.
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).
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SECTION 20. COAL PROPERTY INSPECTIONS. Buyer and its representatives, and
others as may be required by applicable laws, ordinances and regulations shall
have the right at all reasonable times and at their own expense to inspect the
Coal Property, including the loading facilities, scales, sampling system(s),
wash plant facilities, and mining equipment for conformance with this Agreement.
Seller shall undertake reasonable care and precautions to prevent personal
injuries to any representatives, agents or employees of Buyer (collectively,
"Visitors") who inspect the Coal Property. Any such Visitors shall make every
reasonable effort to comply with Seller's regulations and rules regarding
conduct on the work site, made known to Visitors prior to entry, as well as
safety measures mandated by state or federal rules, regulations and laws. Buyer
understands that underground mines and related facilities are inherently
high-risk environments. Buyer's failure to inspect the Coal Property or to
object to defects therein at the time Buyer inspects the same shall not relieve
Seller of any of its responsibilities nor be deemed to be a waiver of any of
Buyer's rights hereunder.
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 or interpretation of
this Agreement.
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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 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; and further provided, however, that any
assignment by Seller in connection with a sale of all or substantially all the
assets of Seller shall trigger the provisions of Section 21.
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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 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 GREEN COAL COMPANY, INC.
By: By:
---------------------------- ---------------------------------
Title: Title:
---------------------------- ---------------------------------
Date: Date:
---------------------------- ---------------------------------
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COAL SUPPLY AGREEMENT
THIS IS A COAL SUPPLY AGREEMENT (THE "AGREEMENT") DATED DECEMBER 15, 1995
BETWEEN LG&E POWER MARKETING INC., a California corporation, 220 West Main
Street, Louisville, Kentucky 40202 ("Buyer") and W.B. COAL COMPANY, INC., an
Ohio corporation, 155 East Broad Street, 23rd floor, Columbus, Ohio 43215, and
WINDSOR COAL COMPANY, a West Virginia corporation, P.O. Box 39, West Liberty,
West Virginia 26074 ("Producer" and collectively with W.B. Coal Company, Inc.
the "Seller").
RECITALS
A. The Buyer entered into a contract with Ohio Edison Company ("Ohio
Edison") under which Buyer shall supply coal for the operation of Ohio Edison's
Burger Plant located in Shady Side, Ohio, Ohio River Mile Point 102.3 and Ohio
Edison's Mansfield Plant, located in Shippingsport, Pennsylvania, Ohio River
Mile Point 33.2 (collectively the "Plant") and under which Ohio Edison will
convert such coal to electric power and deliver such electric power to Buyer
(the "Ohio Edison Agreement").
B. Buyer and Seller wish to enter into this Agreement to enable Buyer to
fulfill all of its coal supply requirements under the Ohio Edison Agreement.
AGREEMENTS
The parties hereto agree as follows:
SECTION 1. GENERAL. Seller will sell to Buyer and Buyer will buy from
Seller steam coal under all the terms and conditions of this Agreement.
<PAGE>
SECTION 2. TERM. The term of this Agreement shall commence on the date
this Agreement is fully executed and shall continue through December 31, 1996.
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 945,000
tons during the term hereof (the "Base Quantity").
Section 3.2 DELIVERY SCHEDULE. During the months of January through
March, Seller shall deliver 75,000 tons per month; and during the months of
April through December, Seller shall deliver 80,000 tons per month. Subject to
Section 3.3 and the timely delivery of barges by Buyer or Buyer's barging
contractor, 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 15 of this Agreement. As used in this Agreement,
all references to a month shall mean a calendar month.
Section 3.3 ADJUSTMENTS. Buyer shall have the right to change the monthly
delivery schedule and the Base Quantity as follows. Upon thirty (30) days prior
written notice to Seller, Buyer shall have the right to increase or decrease the
Base Quantity (80,000 tons) for any months between April and December by up to
20,000 tons so that the minimum quantity for such months will be 60,000 tons and
the maximum quantity for such months will be 100,000 tons.
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SECTION 4. SOURCE.
Section 4.1 SOURCE. The coal sold hereunder shall be supplied from
geological seam Pittsburgh #8, Windsor Mine, Brooke County, West Virginia (the
"Coal Property").
Section 4.2 ASSURANCE OF OPERATION AND RESERVES. Seller represents and
warrants that the Coal Property contains coal of a quality and in quantities
which will be sufficient to satisfy all the requirements of this Agreement.
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 balance of coal in the Coal
Property to an amount less than that required to be supplied to Buyer hereunder.
SECTION 5. DELIVERY. The coal shall be delivered to Buyer F.O.B. barge at
the Windsor dock at mile point 78 on the Ohio River (the "Delivery Point").
Seller may deliver the coal at a location different from the Delivery Point,
provided, however, that Seller shall reimburse Buyer for any resulting increases
in the cost of transporting the coal to the Plant. 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 barges containing the coal are disengaged by
Buyer's barging contractor from the loading dock, subject to Buyer's rejection
rights set forth in Section 6.3. Buyer or its contractor shall furnish suitable
open hopper barges in accordance with a mutually agreeable delivery schedule
provided by Buyer to Seller. Seller shall arrange and pay for all costs of
transporting the coal from the mines to the loading docks and loading and
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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 reasonable penalties assessed by said barging contractor
against 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 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 incidental water in the cargo boxes of the barges be
pumped out as practicable 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 provide evidence thereof to Buyer in the form of a
certificate of
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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.
SECTION 6. QUALITY.
Section 6.1 SPECIFICATIONS. The coal delivered hereunder shall conform to
the following specifications on an "as received" basis:
<TABLE>
<CAPTION>
Rejection Limits
Specifications Weighted Average (per shipment)
- --------------------------------------------------------------------------------
<S> <C> <C>
BTU/LB. min. 12,200 LESS THAN 11,900
LBS/MMBTU:
MOISTURE max. 8.0 GREATER THAN 8.5
ASH max. 9.5 GREATER THAN 9.8
SULFUR (Low Sulfur Months)* max. 3.00 GREATER THAN 3.80
SULFUR (High Sulfur Months)* max. 3.50 GREATER THAN 3.80
SULFUR min. 0.82 LESS THAN 0.82
Size (3" x 0"): max. 3X0 GREATER THAN 3X0
Top size (inches)
Fines (% by wgt)
Passing 1/4" screen max. 45 GREATER THAN 50**
% BY WEIGHT:
VOLATILE min. 37 LESS THAN 36
GRINDABILITY (HGI) min. 50 LESS THAN 50
(HGI)
ASH FUSION TEMPERATURE (DEG. F) (ASTM D1857)***
REDUCING ATMOSPHERE
Initial Deformation min. 2040 min. 1950
Softening (H=W) min. 2090 min. 1980
Softening (H=1/2W) min. 2150 min. 2070
Fluid min. 2340 min. 2340
</TABLE>
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* "Low Sulfur Months" shall mean the months of January, February, and July
through November; and "High Sulfur Months" shall mean the months of March
through June and December.
** 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 fifty per cent (50%) by weight of coal that will pass through a screen
having circular perforations one-quarter (1/4) of an inch in diameter.
*** The Ash Fusion Temperature specifications shall apply only if Ohio
Edison is experiencing an operational problem at the Plant related to ash
fusion.
Note: As used herein GREATER THAN means greater than:
LESS THAN means less than.
Section 6.2 DEFINITION OF "SHIPMENT". As used herein, a "shipment" shall
mean one barge load or a barge lot load in accordance with Buyer's sampling and
analyzing practices.
Section 6.3 REJECTION. For each shipment, Seller will provide to Buyer
approximate "as loaded" coal quality information for weight, moisture, ash,
sulfur, and BTU/lb. by notice sent by telecopier to Buyer prior to the time the
shipment arrives at the Plant. 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
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Seller's receipt of notice of rejection with coal conforming to the Rejection
Limits set forth in Section 6.1. 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 coal of similar quality 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 exceed the price of such coal under this Agreement
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 as provided in Section 21.4.
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 foreign materials or excess
moisture or fines which limit loading and/or handling ability, then such non-
conforming coal shall be deemed accepted by Buyer; however, the quantity Seller
is obligated to sell to Buyer under the Agreement may or may not be reduced by
the amount of each such non-conforming shipment at Buyer's sole option and the
shipment shall nevertheless be considered "rejectable" under Section 6.4.
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.
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Section 6.4 SUSPENSION AND TERMINATION.
If the coal sold hereunder fails to meet one or more of the Guaranteed
Monthly Weighted Averages set forth in Section 6.1 for any two (2) months in a
six (6) month period, or if nine (9) barge shipments in a month are rejectable
by Buyer, Buyer may upon notice confirmed in writing and sent to Seller by
certified mail, suspend future shipments except shipments already loaded into
barges. Seller shall, within 10 business days of Seller's receipt of Buyer's
written notice, provide Buyer with reasonable assurances that subsequent monthly
deliveries of coal shall meet the Guaranteed Monthly Weighted Averages set forth
in Section 6.1 and that the source will not exceed 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 10 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, again fails to meet any of the Guaranteed Monthly Weighted
Averages for any one (1) month within the next six (6) months or if six (6)
barge shipments are rejectable within any one (1) month during such six (6)
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 as
provided in Section 21.4.
8
<PAGE>
Section 6.5 WARRANTY DISCLAIMER. SELLER EXPRESSLY DENIES ANY IMPLIED
WARRANTIES OR EXPRESS WARRANTIES EXCEPT AS SET FORTH HEREIN. SELLER DOES NOT
WARRANT OR REPRESENT THAT THE COAL TO BE SOLD WILL BE FIT FOR ANY PARTICULAR
PURPOSE.
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 Ohio Edison without expense to Seller on
the basis of accurate scale weights at the Plant. Buyer shall exert
commercially reasonable efforts to cause Ohio Edison to operate and maintain its
scales in accordance with industry accepted standards and to allow Seller to be
present and observe such weighing. In the event the scales are determined to be
in error, an appropriate adjustment to price shall be made retroactively for a
period of no more than 30 days.
Section 7.2 SAMPLING AND ANALYSIS. The sampling and analysis of the coal
delivered hereunder shall be performed by Ohio Edison and shall be accepted and
used for the quality and characteristics of the coal delivered under this
Agreement. All analyses shall be made in Ohio Edison's laboratory without
expense to Seller in accordance with industry-accepted standards. If Seller
should at any time question the correctness of either the sampling or the
analyses made by Ohio Edison, Buyer shall exert commercially reasonable efforts
to cause Ohio Edison to allow Seller to challenge the same by written notice.
Thereafter, Buyer shall exert commercially reasonable efforts to cause Ohio
Edison to allow Seller to have a representative observe the sampling and/or to
receive a split of
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the original laboratory sample taken. To meet this requirement, Buyer shall
exert commercially reasonable efforts to cause Ohio Edison to retain the
remaining portion of the sample for a period of forty-five (45) days after the
sample is collected, so that Seller (and/or a mutually agreed upon commercial
laboratory employed by Seller at Seller's cost) may obtain and analyze a portion
of such sample. The results of such commercial testing laboratory's analysis
shall be accepted as the quality and characteristics of such coal if the
difference between Ohio Edison's results and such laboratory's results are
beyond allowable ASTM tolerances.
Section 7.3 REPORTING. Buyer shall either provide the results of Ohio
Edison's weighing, sampling, and analysis of any coal delivered hereunder to
Seller immediately upon Buyer's receipt of the same or have Ohio Edison provide
such results to Seller at the same time Ohio Edison provides such results to
Buyer. Buyer shall exert commercially reasonable efforts to cause the results
of Ohio Edison's weighing, sampling, and analysis of the coal delivered
hereunder to be delivered to Seller within ten (10) days after Ohio Edison's
unloading of such coal.
SECTION 8. PRICE.
Section 8.1 BASE PRICE. The base price ("Base Price") of the coal to be
sold hereunder will be firm and will be $.7730/MMBTU during the Low Sulfur
Months (as defined in Section 6.1) and $.7040/MMBTU during the High Sulfur
Months (as defined in Section 6.1).
10
<PAGE>
Section 8.2 QUALITY PRICE DISCOUNTS.
(a) The Base Price is based on coal meeting the Guaranteed Monthly
Weighted Average specifications for ash, sulfur, and moisture and the Rejection
Limits (per shipment) for BTU/lb as set forth in Section 6.1. Quality price
discounts shall be applied for each specification each month and will be as
follows:
ASH: $0.75/ton for each full 1 lb./MMBTU in excess of 8.5 lb./MMBTU.
SULFUR: $2.75/ton for each 1% or portion thereof in excess of 3% during
the Low Sulfur Months and in excess of 3.7% during the High
Sulfur Months, respectively. This discount will be applied on a
proportionate basis. For example, if, during a Low Sulfur Month,
actual sulfur is 3.2%, the price discount will be $0.55 per ton
(.2x$2.75).
MOISTURE: $0.25/ton for each full 1.00% in excess of 9.0% moisture.
BTU/LB: $0.50/ton for each full 50 BTU/lb below 11,900 BTU/lb applied on
a per shipment basis.
If there are any such discounts, Buyer shall apply credit to amounts owed
Seller for the month the coal was unloaded.
SECTION 9. INVOICES, BILLING AND PAYMENT.
Section 9.1 INVOICING ADDRESS. Invoices will be sent to Buyer at the
following address:
LG&E Power Marketing Inc.
12500 Fair Lakes Circle, Suite 350
Fairfax, Virginia 22033-3804
Attention: President
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<PAGE>
with a copy to:
Louisville Gas and Electric Company
220 West Main Street
P.O. Box 32010
Louisville, KY 40232
Attention: Director, Fuels Procurement and Administration
Section 9.2 INVOICE PROCEDURES FOR COAL SHIPMENTS. Seller shall invoice
Buyer at the Base Price, minus any quality price discounts, for all coal
unloaded in a month by the fifteenth of the following month.
Section 9.3 PAYMENT PROCEDURES FOR COAL SHIPMENTS. Payment for coal
unloaded in a month shall be mailed by overnight mail 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 W.B. Coal
Company, Inc., 155 East Broad Street, 23rd floor, Columbus, Ohio 43215.
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.
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<PAGE>
SECTION 10. 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, earthquakes, or mine roof
falls, or due to force majeures declared by Ohio Edison which affect Ohio
Edison's conversion of coal to electric power under the Ohio Edison Agreement,
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 such force majeure event Seller shall not reduce
deliveries to Buyer and sell coal to any third party to whom it is not
contractually obligated to sell coal at the time of 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.
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Tonnage deficiencies resulting from a force majeure event shall be made up
at Buyer's sole option on a mutually agreeable schedule.
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 the Plant.
If any such changes makes necessary or appropriate an increase or decrease
in the then current price per ton of coal, or in any other provision of this
Agreement, an equitable adjustment shall be made in: 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.
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<PAGE>
SECTION 12. NOTICES.
Section 12.1 FORM AND PLACE OF NOTICE. Unless otherwise specifically
provided herein, 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: LG&E Power Marketing Inc.
12500 Fair Lakes Circle, Suite 350
Fairfax, Virginia 22033-3804
Attention: President
With a copy to: Louisville Gas and Electric Company
220 West Main Street
P.O. Box 32010
Louisville, Kentucky 40232
Attn.: Director, Fuels Procurement and Administration
If to Seller: Windsor Coal Company
c/o American Electric Power Service Corporation
One Memorial Drive
P.O. Box 700
Lancaster, Ohio 43130-0700
Attn.: Senior Vice President Fuel Supply
AND
W.B. Coal Company, Inc.
155 East Broad Street, 23rd floor
Columbus, Ohio 43215
Attn: Wayne Boich
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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.
SECTION 13. RIGHT TO RESELL. Buyer shall have the unqualified right to
sell all or any of the coal purchased under this Agreement to any third party
and for purposes other than the operation of the Plant.
SECTION 14. INDEMNITY AND INSURANCE.
Section 14.1 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, or legal
actions for personal injuries, property damage and pollution (including
reasonable inside and outside attorney's fees) relating to the barges provided
by Buyer or Buyer's contractor while such barges are in the care and custody of
the loading dock or loading facility.
Section 14.2 INSURANCE. Seller agrees to carry insurance coverage or
self-insurance 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.
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(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
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 15. 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
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period in addition to all the other rights and remedies available to the
aggrieved party under this Agreement and at law and in equity, as provided in
Section 21.4.
SECTION 16. 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 sale
of Seller's coal to Buyer hereunder.
SECTION 17. DOCUMENTATION AND RIGHT OF AUDIT.
Seller and Buyer shall maintain all records and accounts pertaining to
payments, quantities, quality analyses, and source for all coal supplied under
this Agreement for a period lasting through the term of this Agreement and for
two years thereafter. Seller and Buyer shall have the right at no additional
expense to the other party 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 18. COAL PROPERTY VISITS. Buyer and its representatives, and
others as may be required by applicable laws, ordinances and regulations shall
have the right at all reasonable times and at their own expense to visit the
Coal Property, including the loading facilities, scales, sampling system(s),
wash plant facilities, and mining equipment for conformance with this Agreement.
Seller shall undertake reasonable care and precautions to prevent personal
injuries to any representatives, agents or employees of Buyer (collectively,
"Visitors") who visit the Coal Property. Any such Visitors shall make every
reasonable effort to comply with Seller's regulations and rules regarding
conduct on
18
<PAGE>
the work site, made known to Visitors prior to entry, as well as safety measures
mandated by state or federal rules, regulations and laws. Buyer understands
that underground mines and related facilities are inherently high-risk
environments. Buyer's failure to visit the Coal Property shall not relieve
Seller of any of its responsibilities nor be deemed to be a waiver of any of
Buyer's rights hereunder.
SECTION 19. JOINT AND SEVERAL LIABILITY. The obligations and liabilities
of Seller under this Agreement shall be the joint and several obligations and
liabilities of W.B. Coal Company, Inc. and Windsor Coal Company.
SECTION 20. CONFIDENTIALITY AND PUBLICITY. Except as required by law or
government regulation, the existence and the provisions of this Agreement shall
be held in confidence by Seller and Buyer and shall not be disclosed by Seller
or Buyer (or any affiliates of Seller or Buyer) to any third party except as
authorized in writing by the other party. Neither party (including its
affiliates) shall issue news releases, generate publicity, or otherwise make
statements to the media concerning the existence or provisions of this Agreement
without first obtaining the written approval 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.
19
<PAGE>
Section 21.2 HEADINGS. The paragraph headings appearing in this Agreement
are for convenience only and shall not affect the meaning or 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. In the event of a breach of this Agreement, the
aggrieved party shall have all the remedies specifically provided in this
Agreement in addition to all other remedies provided by law or in equity.
However, in no event shall either party be liable to the other party for any
special, indirect, or consequential damages, subject to Section 14.1.
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
20
<PAGE>
company, controlling, controlled by, or under common control with Buyer.
However such assignment shall not relieve Buyer of its obligations under the
Agreement.
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 hereto.
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
executed as of the date first above written.
LG&E POWER MARKETING INC. W.B. COAL COMPANY, INC.
By: By:
---------------------------- ---------------------------------
Title: Title:
---------------------------- ---------------------------------
Date: Date:
---------------------------- ---------------------------------
WINDSOR COAL COMPANY
By:
----------------------------
Title:
----------------------------
Date:
----------------------------
21
<PAGE>
CONTRACT NO.: 96-063-026
COAL SUPPLY AGREEMENT
This is a coal supply agreement (the "Agreement") dated January 1, 1996
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").
AGREEMENTS
The parties hereto agree as follows:
SECTION 1. GENERAL
Section 1.1 TERMINATION OF CURRENT AGREEMENT. The Coal Supply Agreement
dated January 1, 1994 between Seller and Buyer is hereby terminated as of
December 31, 1995. Such current agreement shall apply to coal delivered by
December 31, 1995.
Section 1.2 NEW AGREEMENT. Effective January 1, 1996, Seller will sell to
Buyer and Buyer will buy from Seller, steam coal under all the terms and
conditions of this Agreement. This Agreement shall apply to coal delivered on
January 1, 1996 and thereafter.
SECTION 2. TERM Subject to Section 8.2, the term of this Agreement shall
commence on the effective date set forth in Section 1.2 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 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.
<PAGE>
CONTRACT NO.: 96-063-026
SECTION 3. QUANTITY
Section 3.1 ANNUAL QUANTITY. Seller shall sell and deliver and Buyer
shall purchase and accept delivery of the following annual quantity of coal
("Annual Quantity"):
<TABLE>
<CAPTION>
YEAR ANNUAL QUANTITY (TONS)
------ ------------------------
<S> <C>
1996 1,000,000
1997 1,000,000
1998 1,000,000
1999 1,000,000
</TABLE>
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 a reasonable schedule which shows 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 17 of
this Agreement. This Section 3.2 applies to 1996 deliveries which occur after
the execution of this Agreement except that Buyer shall have until ten (10)
business days after this Agreement becomes fully executed to so specify such
monthly delivery schedule for 1996.
Section 3.3 ADJUSTMENTS. 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, subject to
Seller's written consent which shall not be unreasonably
2
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CONTRACT NO.: 96-063-026
withheld or delayed. However, the total quantity for each calendar year shall
be as set forth in Section 3.1.
SECTION 4. SOURCE
Section 4.1 SOURCE. Subject to Section 4.4 hereof, the coal sold
hereunder shall be supplied from Peabody Coal Company's Lynnville Mine, #5, #6,
and #7 seams, Warrick and Spencer Counties, Indiana (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, 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
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CONTRACT NO.: 96-063-026
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, in the event that Seller is unable to produce or obtain coal
from the Coal Property in the quantity and of the quality required by this
Agreement, and such inability is not caused by a force majeure event as defined
in Section 11, then Buyer will have the right to require that Seller supply
substitute coal from other facilities and mines. Seller shall also have the
right to supply substitute coal after having received Buyer's prior written
consent (which shall not be unreasononably withheld). Such substitute coal
shall be provided under all the terms and conditions of this Agreement
including, but not limited to, the price provisions of Section 8, the quality
specifications of Section 6.1, and the provisions of Section 5 concerning
reimbursement to Buyer for increased transportation costs. Seller's delivery of
coal not produced from the Coal Property without having received the express
written consent of Buyer shall constitute a material breach of this Agreement.
SECTION 5. DELIVERY
5.1 RAIL DELIVERY. Subject to Section 9, the coal shall be delivered to
Buyer F.O.B. railcar at the Lynnville or Squaw Creek rail loading facility near
Boonville, Indiana (the "Delivery Point"). Seller may deliver the coal at a
location different from the 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 shared equally by Buyer and Seller.
4
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CONTRACT NO.: 96-063-026
Title to and risk of loss respecting 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.
Section 5.2 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 railcars specified by Buyer with a 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 and applications calculated on a per gallon
basis for each application of freeze conditioning agent and/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.
Section 5.3 BARGE DELIVERY. At any time during the term of this
Agreement, Buyer shall have the right to change the delivery term from F.O.B.
railcar to F.O.B. barge by giving Seller ninety (90) days advance written notice
of such change. If the Buyer so exercises its right to change to barge
deliveries, then the following provisions shall apply:
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CONTRACT NO.: 96-063-026
(a) The Base Price shall be equivalent to the Base Price set forth in
Section 8.1, except that the Base Price for barge deliveries shall be increased
to reflect the difference in Seller's costs to transport coal from the mine to
the Barge Delivery Point (as defined below) and load it into barges and the
Seller's costs to transport coal from the mine to the rail Delivery Point and
load it into railcars.
(b) The coal shall be delivered to Buyer F.O.B. barge at whatever
dock is then available and will result in the lowest delivered cost of coal to
Buyer hereunder (the "Barge Delivery Point").
Title to 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 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 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 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
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CONTRACT NO.: 96-063-026
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 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.
(c) All other provisions of this Agreement shall remain in full force
and effect.
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:
7
<PAGE>
CONTRACT NO.: 96-063-026
<TABLE>
<CAPTION>
Guaranteed Monthly Rejection Limits
Specifications Weighted Average (per shipment)
- --------------------------------------------------------------------------------
<S> <C> <C>
BTU/LB. min. 10,950 LESS THAN 10,750
MOISTURE max. 12.91 lbs/MMBTU GREATER THAN 14.00
ASH max. 8.00 lbs/MMBTU GREATER THAN 9.50
SULFUR max. 2.95 lbs/MMBTU GREATER THAN 3.30
SULFUR min. 1.80 lbs/MMBTU LESS THAN 1.80
CHLORINE max. 0.07 lbs/MMBTU GREATER THAN 0.08
FLUORINE max. 0.013 lbs/MMBTU GREATER THAN 0.013
NITROGEN max. 1.50 lbs/MMBTU GREATER THAN 1.60
ASH/SULFUR RATIO min. 2.5:1 LESS THAN 2.5:1
Size (3" x 0"):
Top size (inches) max. 3"x0" GREATER THAN 3"x0"
Fines (% by wgt)
Passing 1/4" screen max. 40% GREATER THAN 45%
% BY WEIGHT:
VOLATILE max. 34.5 GREATER THAN 35.0
VOLATILE min. 33.5 LESS THAN 33.0
FIXED CARBON max. 44 GREATER THAN 45
FIXED CARBON min. 40 LESS THAN 40
GRINDABILITY (HGI) min. 53 LESS THAN 50
BASE ACID RATIO (B/A)
SLAGGING FACTOR* max. 2.0 GREATER THAN 2.0
FOULING FACTOR** max. 0.5 GREATER THAN 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
</TABLE>
8
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CONTRACT NO.: 96-063-026
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
The Base Acid Ratio (B/A) is herein defined as:
BASE ACID RATIO (B/A) = (Fe(2)0(3) + Ca0 + Mg0 + Na(2)0 + K(2)0)
------------------------------------------------
(Si0(2) + A1(2)0(3) + T10(2))
Note: As used herein GREATER THAN means greater than:
LESS THAN means less than.
Section 6.2 DEFINITION OF "SHIPMENT". As used herein, a "shipment" shall
mean one barge load or a barge lot load, or one unit trainload, in accordance
with Buyer's sampling and analyzing practices.
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 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
9
<PAGE>
CONTRACT NO.: 96-063-026
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 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
10
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CONTRACT NO.: 96-063-026
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 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
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CONTRACT NO.: 96-063-026
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.
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 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; one part shall be retained by
Buyer until the 25th of the month following the month of unloading (the
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CONTRACT NO.: 96-063-026
"Disposal Date") and shall be delivered to Seller for analysis if Seller so
requests before the Disposal Date; and one part ("Referee Sample") shall be
retained by Buyer until the Disposal Date. Seller shall be given copies of all
analyses made by Buyer by the 12th day of the month following the month of
unloading. 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 before the Disposal Date,
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 before the Disposal Date, 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. For each
coal quality specification in question, a dispute shall be deemed not to exist
and Buyer's analysis shall prevail and the analysis of the Independent Lab shall
be disregarded if the analysis of the Independent Lab differs from the analysis
of Buyer by an amount equal to or less than:
(i) 0.50% moisture
(ii) 0.50% ash on a dry basis
(iii) 100 Btu/lb. on a dry basis
(iv) 0.10% sulfur on a dry basis.
For each coal quality specification in question, if the analysis of the
Independent Lab differs from the analysis of Buyer by an amount more than the
amounts listed above, then the analysis of the Independent Lab shall prevail and
Buyer's analysis shall be disregarded. The cost
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CONTRACT NO.: 96-063-026
of the analysis made by the Independent Lab shall be borne by Seller to the
extent that Buyer's analysis prevails and by Buyer to the extent that the
analysis of the Independent Lab prevails.
SECTION 8. PRICE
Section 8.1 PRICE. Subject to Section 9 and Section 8.2, the base price
(the "Base Price") of the coal to be sold hereunder will be firm and will be
$.78767/MMBTU. 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 and
Section 5.
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, 1998.
The party requesting such a review shall give written notice of its request
to the other party on or before October 1, 1997. 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, 1997 without liability due to
such termination for either party.
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CONTRACT NO.: 96-063-026
Section 8.3 QUALITY PRICE DISCOUNTS.
(a) The Base Price is based on coal meeting or exceeding the Guaranteed
Monthly Weighted Average specifications as set forth in Section 6.1. 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
6.1, as determined pursuant to Section 7.2, subject to the provisions set forth
below. The discount values used are as follows:
DISCOUNT VALUES
$/MMBTU
BTU/LB. 0.2604
$/LB./MMBTU
SULFUR 0.1232
ASH 0.0083
MOISTURE 0.0016
(b) Notwithstanding the foregoing, for each specification each month,
there shall be no discount if the actual Monthly Weighted Average meets the
applicable Discount Point set forth below. However, if the actual Monthly
Weighted Average fails to meet such applicable Discount Point, then the discount
shall apply and shall be calculated on the basis of the difference between the
actual Monthly Weighted Average AND THE GUARANTEED MONTHLY WEIGHTED AVERAGE
pursuant to the methodology shown in Exhibit A attached hereto.
15
<PAGE>
CONTRACT NO.: 96-063-026
<TABLE>
<CAPTION>
Guaranteed
Monthly
Weighted Average Discount Point
---------------- --------------
<S> <C> <C>
BTU/LB min. 10,950 10,750
LB/MMBTU:
SULFUR max. 2.95 3.30
ASH max. 8.00 9.50
MOISTURE max. 12.91 14.00
</TABLE>
For example, if the actual Monthly Weighted Average of sulfur equals 3.35
lb/MMBTU, then the applicable discount would be (3.35 lb. - 2.95 lb.) X
$.1232/lb/MMBTU = $.04928/MMBTU.
Section 8.4 PAYMENT CALCULATION. Exhibit A 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. SPECIAL PRICE AND DELIVERY PROVISIONS.
Section 9.1 JAN. 1 - FEB. 4, 1996. Notwithstanding any other provision in
this Agreement, the following provisions shall apply for all coal delivered by
Seller between January 1, 1996 and February 4, 1996:
(a) The coal will be delivered to Buyer F.O.B. barge at the
Yankeetown Dock at Mile Point 772.5 on the Ohio River (the "Yankeetown Dock").
(b) The Base Price will be $.78767/MMBTU plus the costs actually
incurred by the Seller to transport coal from the Coal Property to the
Yankeetown Dock and load such coal
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CONTRACT NO.: 96-063-026
onto barges. Such costs shall be calculated on a per ton basis and shall in no
event exceed $2.60 per ton.
(c) Except as specifically set forth in (a) and (b) above, all the
provisions of this Agreement shall apply.
Section 9.2 FEB. 5 - FEB. 12, 1996. Notwithstanding any other provision
in this Agreement, the following provision shall apply for all coal delivered
F.O.B. barge by Seller between February 5, 1996 and February 12, 1996:
(a) The coal will be delivered to Buyer F.O.B. barge at the
Yankeetown Dock.
(b) The Base Price will be $.78767/MMBTU plus $1.80 per ton.
(c) Except as specifically set forth in (a) and (b) above, all of the
provisions of this Agreement shall apply.
SECTION 10. INVOICES, BILLING AND PAYMENT.
Section 10.1 INVOICING ADDRESS. Invoices will be sent to LG&E at the
following address:
Louisville Gas and Electric Company
220 West Main Street
P.O. Box 32010
Louisville, KY 40232
Attention: Director, Fuels Procurement and Delivery
With a copy to:
Louisville Gas and Electric Company
820 West Broadway
P. O. Box 32020
Louisville, KY 40232
Attention: Manager, Accounts Payable
17
<PAGE>
CONTRACT NO.: 96-063-026
Section 10.2 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 10.3 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 63150-3099. To make
wire transfers contact Boatman's Bank, Account ABA 081000032, wire transfer
account 100101223441.
Section 10.4 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.
SECTION 11. FORCE MAJEURE
Section 11.1 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
18
<PAGE>
CONTRACT NO.: 96-063-026
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 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.
19
<PAGE>
CONTRACT NO.: 96-063-026
Tonnage deficiencies resulting from a force majeure event shall be made up
at Buyer's sole option on a reasonable schedule.
Section 11.2 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 without further obligation hereunder on the part of
either party.
SECTION 12. CHANGES. Buyer may, by mutual agreement with Seller, at any
time by written notice pursuant to Section 13 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
20
<PAGE>
CONTRACT NO.: 96-063-026
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 make 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 12 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 12, then this Agreement shall continue in full force
and effect without taking into account such requested changes.
SECTION 13. NOTICES
Section 13. 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
21
<PAGE>
CONTRACT NO.: 96-063-026
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: Director, Fuels Procurement and Delivery
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 13.2 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.
Section 13.3 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 14. 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
22
<PAGE>
CONTRACT NO.: 96-063-026
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 Annual 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, 1998) or the
termination of this Agreement (i.e., January 1, 2000), as applicable. For
example, if Seller terminates this Agreement effective January 1, 1997, then
Seller would owe Buyer $3,500,000 under this Section 14.
SECTION 15. RIGHT TO RESELL. Buyer shall have the unqualified right to
sell all or any of the coal purchased under this Agreement.
SECTION 16. INDEMNITY AND INSURANCE
Section 16.1 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 16.2 INSURANCE. Seller agrees to maintain insurance coverage with
minimum limits as follows:
23
<PAGE>
CONTRACT NO.: 96-063-026
(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
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 17. 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
24
<PAGE>
CONTRACT NO.: 96-063-026
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 18. 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.
SECTION 19. 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 20. 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 CFR 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
25
<PAGE>
CONTRACT NO.: 96-063-026
in 41 CFR 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 CFR 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 21. COAL PROPERTY INSPECTIONS AND INJURIES TO
REPRESENTATIVES
Buyer and its representatives, and others as may be required by applicable
laws, ordinances and regulations shall have the right at all reasonable times
and at their own expense to inspect the Coal Property, including the loading
facilities, scales, sampling system(s), wash plant facilities, and mining
equipment for conformance with this Agreement. Seller shall undertake
reasonable care and precautions to prevent personal injuries to any
representatives, agents or employees of Buyer (collectively, "Visitors") who
inspect the Coal Property. Any such Visitors shall make every reasonable effort
to comply with Seller's regulations and rules regarding conduct on the work
site, made known to Visitors prior to entry, as well as safety measures mandated
by state or federal rules, regulations and laws. Buyer understands that mines
and related facilities are inherently high-risk environments. Buyer's failure
to inspect the Coal Property or to object to defects therein at the time Buyer
inspects the same shall not relieve Seller of any of its responsibilities nor be
deemed to be a waiver of any of Buyer's rights hereunder.
26
<PAGE>
CONTRACT NO.: 96-063-026
SECTION 22. MISCELLANEOUS
Section 22.1 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 22.2 HEADINGS. The paragraph headings appearing in this Agreement
are for convenience only and shall not affect the meaning of interpretation of
this Agreement.
Section 22.3 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 22.4 REMEDIES CUMULATIVE. Remedies provided under this Agreement
shall be cumulative and in addition to other remedies provided under this
Agreement or by law or in equity.
Section 22.5 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.
27
<PAGE>
CONTRACT NO.: 96-063-026
Section 22.6 BINDING EFFECT. This Agreement shall bind and inure to the
benefit of the parties and their successors and assigns.
Section 22.7 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 22.8 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 22.9 AMENDMENTS. Except as otherwise provided herein, this
Agreement may not be amended, supplemented or otherwise modified except by
written instrument signed by both parties hereto.
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
executed as of the date first above written.
<TABLE>
<S> <C>
LOUISVILLE GAS AND ELECTRIC PEABODY COALSALES COMPANY
COMPANY
By: /s/ Christopher Hermann By: /s/ illegible
---------------------------------- -----------------------------------
Chris Hermann
Vice President and General Manager Title: Vice President Sales & Marketing
Wholesale Electric Business --------------------------------
Date: 2/22/96 Date: 2/21/96
---------------------------------- --------------------------------
</TABLE>
28
<PAGE>
Page 1 of 2
EXHIBIT A
SAMPLE COAL PAYMENT CALCULATIONS
Total Evaluated Coal Costs for Contract No.
- --------------------------------------------------------------------------------
For contracts supplied from multiple "origins", each "origin" will be calculated
individually.
<TABLE>
<CAPTION>
SECTION I BASE DATA
- ------------------------------------------------------------
<S> <C> <C> <C>
1) Base F.O.B. price per ton: $_17.25_ /ton
1a) Tons of coal delivered: ________ tons
2) Guaranteed average heat content: __10,950_ B.T.U./LB.
2r) As received monthly avg. heat content: ________ B.T.U./LB.
2a) Energy delivered in M.M.B.T.U.: ________ MMBTU
[(Line 1a) *2,000 lb./ton *(Line 2r)] *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 _2.95____ LBS./MMBTU
3r) As received monthly avg. sulfur _________ LBS./MMBTU
4) Guaranteed monthly avg. max ash _8.00____ LBS./MMBTU
4r) As received monthly avg. ash _________ LBS./MMBTU
5) Guaranteed monthly avg. max moisture _12.91___ LBS./MMBTU
5r) As received monthly avg. moisture _________ LBS./MMBTU
</TABLE>
<TABLE>
<CAPTION>
SECTION II DISCOUNTS
- ------------------------------------------------------------
Assign a (-) to all discounts (round to five (5) decimal places)
<S> <C> <C> <C>
6d) B.T.U./LB.: If line 2r is less than 10,750 BTU/lb.
{1-[(line 2r)/(line 2)]} *$0.2604/MMBTU
{1-[( )/( )]} *$0.2604 = $________ /MMBTU
7d) SULFUR: If line 3r is greater than 3.3 lbs./MMBTU
[(line 3r)-(line 3)] *$0.1232/lb sulfur
[( )-( )] *$0.1232 = $________ /MMBTU
8d) ASH: If line 4r is greater than 9.50 lbs./MMBTU
[(line 4r)-(line 4)] *$0.0083/lb ash
[( )-( )] $0.0083 = $________ /MMBTU
9d) MOISTURE: If line 5r is greater than 14.00 lbs./MMBTU
[(line 5r)-(line 5)] *$0.00 16/lb moisture
[( )-( )] *$0.0016 = $________ /MMBTU
</TABLE>
<PAGE>
Exhibit A
Page 2 of 2
<TABLE>
<CAPTION>
SECTION III TOTAL PRICE ADJUSTMENTS
- ------------------------------------------------------------
Determine total Discounts as follows:
Assign a (-) to all Discounts and enter number for:
<S> <C> <C>
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)
$________ + $________ = $________
</TABLE>
<PAGE>
EXHIBIT 12
LOUISVILLE GAS AND ELECTRIC COMPANY
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(Thousands of $)
<TABLE>
<CAPTION>
1995 1994 1993 1992 1991
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Earnings:
Income before cumulative effect of a change
in accounting principle per statements
of income.......................................... $ 83,184 $ 61,689 $ 90,535 $ 73,793 $ 94,643
Add:
Federal income taxes - current....................... 35,824 30,926 42,091 13,785 35,490
State income taxes - current......................... 8,795 7,726 12,954 3,140 8,425
Deferred Federal income taxes - net.................. 4,261 (950) 4,712 20,441 17,207
Deferred State income taxes - net.................... 2,788 956 226 8,470 6,085
Investment tax credit - net.......................... (4,742) (4,619) (7,821) (5,033) (11,472)
Fixed charges........................................ 43,550 44,665 49,640 52,196 55,171
-------- -------- -------- -------- --------
Earnings........................................... 173,660 140,393 192,337 166,792 205,549
-------- -------- -------- -------- --------
Fixed Charges:
Interest Charges per statements of income............ 41,918 42,856 47,496 49,833 52,680
Add:
Interest income (1)................................ - - - 4 98
One-third of rentals charged to
operating expense (2).............................. 1,632 1,809 2,144 2,359 2,393
-------- -------- -------- -------- --------
Fixed charges.................................... $ 43,550 $ 44,665 $ 49,640 $ 52,196 $ 55,171
-------- -------- -------- -------- --------
Ratio of Earnings to Fixed Charges..................... 3.99 3.14 3.87 3.20 3.73
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
</TABLE>
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.
-68-
<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, 1996, included in this Form 10-K,
into the Company's previously filed Registration Statement No. 33-13427.
Louisville, Kentucky Arthur Andersen LLP
March 27, 1996
- 69 -
<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, 1995 (the 1995 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 WALTER Z. BERGER, 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 1995 Form
10-K and to any and all amendments to such 1995 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 6th day of March 1996.
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 Anne H. McNamara
- ----------------------------------- ---------------------------------------
Owsley Brown II, Director Anne H. McNamara, Director
S. Gordon Dabney T. Ballard Morton, Jr.
- ----------------------------------- ---------------------------------------
S. Gordon Dabney, Director T. Ballard Morton, Jr., Director
Walter Z. Berger Dr. Donald C. Swain
- ----------------------------------- ---------------------------------------
Walter Z. Berger, Principal Dr. Donald C. Swain, Director
Financial and Accounting Officer
Gene P. Gardner
- -----------------------------------
Gene P. Gardner, Director
STATE OF KENTUCKY )
) ss.
COUNTY OF JEFFERSON)
On this 6th day of March 1996, 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> YEAR
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-01-1995
<PERIOD-END> DEC-31-1995
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,663,918
<OTHER-PROPERTY-AND-INVEST> 760
<TOTAL-CURRENT-ASSETS> 267,371
<TOTAL-DEFERRED-CHARGES> 47,441
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 1,979,490
<COMMON> 424,334<F1>
<CAPITAL-SURPLUS-PAID-IN> (226)<F2>
<RETAINED-EARNINGS> 181,049
<TOTAL-COMMON-STOCKHOLDERS-EQ> 605,157
0
95,328
<LONG-TERM-DEBT-NET> 646,845
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 16,000
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 616,160
<TOT-CAPITALIZATION-AND-LIAB> 1,979,490
<GROSS-OPERATING-REVENUE> 723,463
<INCOME-TAX-EXPENSE> 47,524
<OTHER-OPERATING-EXPENSES> 554,613
<TOTAL-OPERATING-EXPENSES> 602,137
<OPERATING-INCOME-LOSS> 121,326
<OTHER-INCOME-NET> 3,776
<INCOME-BEFORE-INTEREST-EXPEN> 125,102
<TOTAL-INTEREST-EXPENSE> 41,918
<NET-INCOME> 83,184
6,311
<EARNINGS-AVAILABLE-FOR-COMM> 76,873
<COMMON-STOCK-DIVIDENDS> 89,000
<TOTAL-INTEREST-ON-BONDS> 41,259
<CASH-FLOW-OPERATIONS> 198,600
<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.
</FN>
</TABLE>
