<PAGE>
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of
the Securities Exchange Act of 1934
Date of Report: October 16, 1998
----------------
LG&E ENERGY CORP.
-----------------
(Exact name of registrant as specified in its charter)
Kentucky 1-10568 61 - 1174555
-------- ------- ------------
(State or other (Commission (I.R.S. Employer
jurisdiction of File Number) Identification No.)
incorporation)
220 West Main Street
P.O. Box 32030
Louisville, KY 40232
--------------------
(Address of principal executive offices)
(502) 627-2000
--------------
(Registrant's telephone number)
<PAGE>
Item 5. Other Events.
In connection with the May 4, 1997 merger of KU Energy Corporation and LG&E
Energy Corp. (the "Company"), management's discussion and analysis and
consolidated financial statements of the Company as of December 31, 1997 are
filed as Exhibit 99.01 to this report and incorporated herein by reference.
The consolidated financial statements reflect the accounting for the merger
as a pooling of interests and are presented as if the companies were combined
as of the earliest period presented. However the financial information is
not necessarily indicative of the results of operations, financial position
or cash flows that would have occurred had the merger been consummated for
the periods for which it is given effect, nor is it necessarily indicative of
future results of operations, financial position or cash flows. These
statements should be read in conjunction with the Company's Form 10-Q's for
the quarters ended March 31, 1998, and June 30, 1998.
Item 7(c). Exhibits Filed.
<TABLE>
<CAPTION>
Exhibit
Number Description
<S> <C>
27 Financial Data Schedules.
99.01 Consolidated Financial Statements of LG&E Energy Corp. as of
December 31, 1997.
99.02 Consent of Independent Accountants.
</TABLE>
SIGNATURES
----------
Pursuant to the requirements of the Securities and Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
LG&E ENERGY CORP.
- -----------------
Registrant
/s/ John R. McCall
- ------------------
John R. McCall
Executive Vice President, General
Counsel and Corporate Secretary
Date: October 16, 1998
2
<PAGE>
EXHIBIT INDEX
LG&E ENERGY CORP.
Current Report on Form 8-K
Dated October 16, 1998
EXHIBITS
<TABLE>
<CAPTION>
Exhibit No. Description
<S> <C>
27 Financial Data Schedules.
99.01 Consolidated Financial Statements of LG&E Energy Corp. as of
December 31, 1997.
99.02 Consent of Independent Accountants.
</TABLE>
3
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<RESTATED>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-01-1995
<PERIOD-END> DEC-31-1995
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 3,121,980
<OTHER-PROPERTY-AND-INVEST> 179,561
<TOTAL-CURRENT-ASSETS> 699,049
<TOTAL-DEFERRED-CHARGES> 100,936
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 4,101,526
<COMMON> 770,322<F1>
<CAPITAL-SURPLUS-PAID-IN> (573)<F2>
<RETAINED-EARNINGS> 637,996
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,407,745
0
135,328
<LONG-TERM-DEBT-NET> 1,192,825
<SHORT-TERM-NOTES> 228,600
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 16,021
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,121,007
<TOT-CAPITALIZATION-AND-LIAB> 4,101,526
<GROSS-OPERATING-REVENUE> 1,432,680
<INCOME-TAX-EXPENSE> 86,294
<OTHER-OPERATING-EXPENSES> 1,111,582<F3>
<TOTAL-OPERATING-EXPENSES> 1,197,876
<OPERATING-INCOME-LOSS> 234,804
<OTHER-INCOME-NET> 14,577
<INCOME-BEFORE-INTEREST-EXPEN> 249,381
<TOTAL-INTEREST-EXPENSE> 81,931
<NET-INCOME> 167,450
8,567
<EARNINGS-AVAILABLE-FOR-COMM> 158,883
<COMMON-STOCK-DIVIDENDS> 135,787
<TOTAL-INTEREST-ON-BONDS> 77,354
<CASH-FLOW-OPERATIONS> 148,952
<EPS-PRIMARY> 1.23
<EPS-DILUTED> 1.23
<FN>
<F1>Includes common stock expense of $1,523.
<F2>Represents unrealized loss on marketable securities, net of taxes.
<F3>Includes equity in earnings of affiliates of $28,880.
</FN>
</TABLE>
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<RESTATED>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> DEC-31-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 3,163,558
<OTHER-PROPERTY-AND-INVEST> 181,095
<TOTAL-CURRENT-ASSETS> 666,022
<TOTAL-DEFERRED-CHARGES> 121,924
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 4,132,599
<COMMON> 772,615<F1>
<CAPITAL-SURPLUS-PAID-IN> 154<F2>
<RETAINED-EARNINGS> 683,962
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,456,731
0
135,328
<LONG-TERM-DEBT-NET> 1,193,208
<SHORT-TERM-NOTES> 212,200
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 21
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,135,111
<TOT-CAPITALIZATION-AND-LIAB> 4,132,599
<GROSS-OPERATING-REVENUE> 1,560,460
<INCOME-TAX-EXPENSE> 101,322
<OTHER-OPERATING-EXPENSES> 1,185,915<F3>
<TOTAL-OPERATING-EXPENSES> 1,287,237
<OPERATING-INCOME-LOSS> 273,223
<OTHER-INCOME-NET> 7,141
<INCOME-BEFORE-INTEREST-EXPEN> 280,364
<TOTAL-INTEREST-EXPENSE> 87,588
<NET-INCOME> 192,776
6,824
<EARNINGS-AVAILABLE-FOR-COMM> 185,952
<COMMON-STOCK-DIVIDENDS> 139,986
<TOTAL-INTEREST-ON-BONDS> 77,355
<CASH-FLOW-OPERATIONS> 368,386
<EPS-PRIMARY> 1.44
<EPS-DILUTED> 1.44
<FN>
<F1>Includes common stock expense of $1,854.
<F2>Represents unrealized loss on marketable securities, net of taxes.
<F3>Includes equity in earnings of affiliates of $19,727.
</FN>
</TABLE>
<PAGE>
Consolidated Financial Statements
Management's Discussion and Analysis of Results of Operations and
Financial Condition.
RECENT DEVELOPMENTS - MERGER
Effective May 4, 1998, following the receipt of all required state and
federal regulatory approvals, LG&E Energy Corp. (LG&E Energy or the Company)
and KU Energy Corporation (KU Energy) merged, with LG&E Energy as the
surviving corporation. The accompanying consolidated financial statements
reflect the accounting for the merger as a pooling of interests and are
presented as if the companies were combined as of the earliest period
presented. However, the financial information is not necessarily indicative
of the results of operations, financial position or cash flows that would
have occurred had the merger been consummated for the periods for which it is
given effect, nor is it necessarily indicative of future results of
operations, financial position, or cash flows. The financial statements
reflect the conversion of each outstanding share of KU Energy common stock
into 1.67 shares of LG&E Energy common stock. The outstanding preferred stock
of Louisville Gas and Electric Company (LG&E), a subsidiary of LG&E Energy,
and Kentucky Utilities Company (KU), which was a subsidiary of KU Energy
before the Merger, were not affected by the Merger. See Note 2 of the
accompanying Notes to Financial Statements.
DISCONTINUANCE OF MERCHANT ENERGY TRADING AND SALES BUSINESS
Effective June 30, 1998, the Company discontinued its merchant trading and
sales business, primarily due to its current portfolio of energy marketing
contracts, and the impact that recent volatility, instability and rising
prices on the power market have had on these contracts. Exiting the merchant
trading and sales business is intended to enable the Company to focus on
adding and optimizing physical assets, and to eliminate the earnings impact
to continuing operations of extreme market volatility on its current
portfolio of energy marketing contracts. The Company intends to sell or
buyout the long-term contracts that obligate it to buy and sell natural gas
and electric power. It also plans to sell its natural gas gathering and
processing business. The Company, however, intends to maintain sufficient
market knowledge, risk management skills, technical systems and experienced
personnel to maximize the value of power sales from assets it owns or
controls, including LG&E, KU and Big Rivers Electric Corporation (Big Rivers).
As a result of the Company's decision to discontinue its merchant trading and
sales activity, and the decision to sell the associated gas gathering and
processing business, the Company recorded an after-tax loss on disposal of
discontinued operations of $225.0 million in the second quarter of 1998. The
loss on disposal of discontinued operations results primarily from several
fixed-price energy marketing contracts entered in 1996 and early 1997,
including the Company's long-term contract with Oglethorpe Power Corporation
(OPC). Other components of the write-off include costs relating to certain
peaking options, goodwill associated with the Company's 1995 purchase of
these operations and exit costs. Although the Company used what it believes
to be appropriate estimates for future energy prices among other factors to
calculate the fair market value of discontinued operations, there is no
guarantee that higher than anticipated future prices or a lower received
purchase price than estimated for asset sales could not result in additional
losses. As of October 15, 1998, the Company estimates that a $1 change in
electricity prices across all geographic areas and time periods could change
the value of the Company's remaining energy portfolio by approximately $10
million. In addition to price risk, the value of the Company's remaining
energy portfolio is subject to operational and event risks including, among
others, increases in load demand, regulatory changes, and forced outages at
units providing supply for the Company. As of October 15, 1998, the Company
estimates that a 1% change in the forecasted load demand could change the
value of the Company's remaining energy portfolio by $11 million. See Note
18, Commitments and Contingencies, for a discussion of the OPC contract.
The Company restated its financial statements for prior periods to present
the operating results, financial position and cash flows of these businesses
as discontinued operations. See Notes 1 and 3 for more information.
MASTER RESTRUCTURING AGREEMENT
On June 30, 1998, the partnership that owns the Rensselaer cogeneration
facility, along with 14 other independent power producers, participated in
the consummation of a Master Restructuring Agreement (MRA) with Niagara
Mohawk Power Corporation (NIMO), the purchasing utility. The Company
recognized an after-tax gain on the MRA transaction and the settlement of $21
million. See Note 8 of Notes to Financial Statements.
1
<PAGE>
LEASE OF BIG RIVERS FACILITIES
Effective July 15, 1998, the Company closed its transaction to lease the
generating assets of Big Rivers following receipt of necessary regulatory
approvals. This 25-year transaction involves a lease by subsidiaries of the
Company of Big Rivers' approximately 1,700 megawatts of generating capacity.
Under the transaction, Western Kentucky Energy Corp. (WKE), a subsidiary of
the Company, leases and operates Big Rivers' three coal-fired facilities as
an exempt wholesale generator. In addition, an affiliate of WKE operates and
maintains the Station Two generating facility of the City of Henderson,
Kentucky, and another affiliate, LG&E Energy Marketing, Inc. (LEM), purchases
from the City the capacity and energy of Station Two in excess of the City's
needs. In related transactions, LEM supplies power to Big Rivers at fixed
prices to meet the needs of its four member distribution cooperatives and
their retail customers in Western Kentucky, and separately provides power
directly to two of those cooperatives to meet the needs of the aluminum
smelting facilities of Alcan Aluminum Corporation and Southwire Company in
Kentucky. Excess generating capacity, currently estimated to be up to 350
Mwh in the aggregate for this transaction, will remain available for LEM to
market throughout the region. In connection with these transactions, the
Company, through its affiliates, has undertaken to bear certain of the future
capital requirements of those generating assets, certain defined
environmental compliance costs, and other obligations. Big Rivers' personnel
at the plants became employees of WKE upon the commencement of the
transactions. Final Kentucky Public Service Commission approvals in
connection with this transaction were received on July 14, 1998, and final
Federal Energy Regulatory Commission approvals were received on July 8, 1998.
GENERAL
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 1997, 1996, and 1995 and should be read in
connection with the consolidated financial statements and notes thereto. The
Company's financial results and conditions have been largely dependent on the
financial results and conditions of its principal subsidiaries, LG&E, a
regulated electric and gas utility, and KU, a regulated electric utility. As
set forth in the discussion concerning Discontinued Operations above, future
financial results from the Company's operations may continue to reflect the
results from its portfolio of investments in electric generation and gas
distribution in addition to the financial results provided by LG&E and KU.
Some of the following discussion may contain forward-looking statements that
are subject to certain risks, uncertainties and assumptions. Such
forward-looking statements are intended to be identified in this document by
the words "anticipate," "expect," "estimate," "objective," "possible,"
"potential" and similar expressions. Actual results may vary materially.
Factors that could cause actual results to differ materially include: general
economic conditions; business and competitive conditions in the energy
industry; changes in federal or state legislation; unusual weather; actions
by state or federal regulatory agencies, including decisions resulting from
the combination of the Company and KU Energy and other factors described from
time to time in LG&E Energy Corp.'s reports to the Securities and Exchange
Commission, including Exhibit 99.01 to the Company's Annual Report on Form
10-K for the year ended December 31, 1997, and Exhibit 99.1 to its Current
Report on Form 8-K dated May 4, 1998.
RESULTS OF OPERATIONS
Earnings per Share
Earnings per share from continuing operations for 1997 were $1.60, an
increase of $.13 per share from the $1.47 earned from continuing operations
in 1996. Earnings for 1996 included a charge of $.02 resulting from a
write-off associated with non-utility investments. Excluding this charge,
earnings per share from continuing operations for 1996 were $1.49; thus, 1997
earnings from continuing operations increased $.11. The $.11 per share
increase resulted from an increase in core utility business earnings of $.03,
first year earnings related to the acquisition of an interest in two
Argentine gas distribution units of $.04, and an increase in the non-utility
power generation business of $.08, partially offset by an increase in
corporate and other expenses, including interest expense on debt incurred to
acquire non-regulated businesses, of $.04. The $.03 increase in utility
earnings was primarily due to higher contributions from wholesale electric
sales and lower maintenance expenses.
2
<PAGE>
Earnings per share from continuing operations for 1996 of $1.47 increased
$.24 over earnings per share from continuing operations of $1.23 reported for
1995. The 1995 amounts included a one-time charge of $.14 to recognize the
settlement of the long-standing issues surrounding LG&E's Trimble County
electric generating plant. Excluding the Trimble County settlement in 1995
and the charge discussed in the preceding paragraph for 1996, earnings per
share from continuing operations were $1.49 in 1996, or $.12 more than
comparable 1995 earnings from continuing operations of $1.37. The $.12
increase resulted from higher utility earnings of $.15 and an increase in
non-utility earnings of $.03, partially offset by an increase in corporate
and other expenses, including interest expense on debt incurred to acquire
non-regulated businesses, of $.06. The utility increase of $.15 is primarily
the result of a significantly higher level of wholesale electric sales and
increased retail sales of electricity and natural gas, continued economic
growth in KU's service area and the impact of KU's successful marketing
efforts, partially offset by increased operation and maintenance expenses at
LG&E. The increase in non-utility earnings reflects strong performance by
the independent power ventures.
Loss from discontinued operations increased from $.03 in 1996 to $.19 in 1997
due primarily to abnormal weather, price volatility in the energy market and
narrowing margins in the natural gas business. Loss from discontinued
operations increased from zero in 1995 to $.03 in 1996 due to higher trading
volumes and to adopting the mark-to-market method of accounting.
Utility Results
Revenues
A comparison of utility revenues for the years 1997 and 1996 with the
immediately preceding year 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
1997 1996 1997 1996
---- ---- ---- ----
<S> <C> <C> <C> <C>
Sales to ultimate consumers:
Fuel and gas supply adjustments, etc. $ (7,616) $ (9,922) $ 27,192 $ 21,176
Demand side management/decoupling 8,041 5,429 4,348 (1,989)
Environmental cost recovery surcharge 1,002 3,538 - -
Variation in sales volumes 6,538 13,865 (14,891) 14,483
-------- -------- -------- --------
Total 7,965 12,910 16,649 33,670
Wholesale sales 1,210 43,651 - -
Gas transportation-net - - 147 (971)
Other 3,548 4,799 (204) 594
-------- -------- -------- --------
Total $ 12,723 $ 61,360 $ 16,592 $ 33,293
-------- -------- -------- --------
-------- -------- -------- --------
</TABLE>
Electric revenues increased in 1997 due to a higher level of industrial sales
and other revenues, partially offset by lower residential sales in KU's service
area resulting from milder weather. Gas revenues increased primarily
3
<PAGE>
as a result of higher gas supply costs billed to customers through the gas
supply clause, partially offset by decreased gas sales due mainly to warmer
weather.
Electric revenues increased in 1996 compared with 1995 primarily because of
an increase in wholesale sales of electricity which resulted from aggressive
marketing efforts. Increases in industrial and residential sales resulting
from continued economic growth in KU's service area also contributed to the
increase. Gas revenues increased as a result of the higher cost of natural
gas in 1996 and because of increased sales to ultimate consumers (6%) caused
mainly by colder weather experienced in the first quarter of the year.
Expenses
Fuel for electric generation and gas supply expenses comprise a large segment
of the Company's total operating costs. LG&E's and KU's electric rates
contain a fuel adjustment clause and LG&E's gas rates contain a gas supply
clause, whereby increases or decreases in the cost of fuel and gas supply are
reflected in LG&E's and KU's rates, subject to approval by the Public Service
Commission of Kentucky (Kentucky Commission or Commission) and the Virginia
State Corporation Commission (Virginia Commission).
Fuel expenses in 1997 decreased $10.0 million primarily due to a 4% decrease
in MBTU (million British thermal units) consumed at KU which resulted from an
increase in kWh purchases. Fuel expenses increased $20.0 million (6%) in
1996 primarily because of an increase in generation, partially offset by a
decrease in the cost of coal burned. LG&E's average delivered cost per ton
of coal purchased was $21.66 in 1997, $21.73 in 1996, and $23.68 in 1995.
KU's average delivered cost per ton of coal purchased was $27.97 in 1997,
$27.54 in 1996, and $28.45 in 1995.
Purchased power expense increased $10.7 million (13%) in 1997 due to an
increase at KU in kWh purchases associated with increased availability of
surplus power on favorable pricing terms and to a one-time reduction at KU in
demand costs in 1996 of about $4 million under a contract with a neighboring
utility. Purchased power expense decreased $7.2 million (8%) in 1996. The
decline was due to a reduction at KU in kWh purchases and to the one-time
reduction in demand costs.
Gas supply expenses for 1997 increased $18.4 million (13%) because of the
higher cost of net gas supply ($29.3 million), partially offset by a decrease
in the volume of gas delivered to the distribution system ($10.9 million).
Gas supply expenses increased $29.7 million (27%) in 1996 mainly because of
the higher cost of net gas supply ($21.8 million) and an increase in the
volume of gas delivered to the distribution system ($7.9 million). The
average unit cost per Mcf of purchased gas was $3.46 in 1997 and 1996, and
$2.62 in 1995.
Operation and maintenance expenses for 1997 were approximately the same as
1996. Maintenance decreased in 1997 due mainly to decreased repairs at LG&E's
electric generating plants caused by fewer outages and a lower level of storm
damage repairs. These decreases were offset by an increase in costs to
operate LG&E's power plants and a write-off of certain previously deferred
items at LG&E that amounted to approximately $3 million. Items written off
include expenses associated with the hydro-electric plant and a management
audit fee. Even though LG&E believes it could have reasonably expected to
recover these costs in future rate proceedings, it decided not to seek
recovery and expensed these costs because of increasing competitive pressures
in the industry.
Operation and maintenance expenses increased $14.4 million (4%) in 1996 over
1995 primarily because of increased costs to operate LG&E's electric power
plants ($2.9 million) and LG&E's electric and gas transmission and
distribution systems ($1.9 million), increased storm damage expenses at LG&E
($2.2 million) and LG&E's recognition of proceeds in 1995 for the settlement
of a commercial dispute. Pursuant to a study to
4
<PAGE>
determine when the settlement should be recorded, LG&E recognized $6 million
as a reduction of 1995 operation expense and $2 million as a reduction of
1996 operation expense.
Depreciation and amortization increased in both 1997 and 1996 primarily
because of additional plant in service, including a combustion turbine
peaking unit placed into service at KU in May 1996. In addition, 1997
reflects the accelerated write-off of losses on early retirements of
facilities at LG&E.
Other income for 1997 increased by $1.9 million primarily because of interest
income recorded as a result of a favorable tax settlement at LG&E and the
sale of stock options which LG&E had acquired in a commercial transaction.
Other income for 1996 decreased about $2.7 million because of a decrease at
LG&E in income earned from investments and lower gains realized from the sale
of property at LG&E as compared to 1995. See Note 14 of Notes to Financial
Statements.
Interest charges for 1997 decreased $1 million (1%) due to favorable
refinancing activities at LG&E in 1996. Interest charges for 1996 decreased
$2.0 million (3%) primarily because of the retirement of outstanding debt at
LG&E. LG&E's embedded cost of long-term debt at December 31, 1997, was
5.68%; and at December 31, 1996, 6.05%. KU's embedded cost of long-term debt
was 6.98% at December 31, 1997, and December 31, 1996. See Note 16 of Notes
to Financial Statements.
Preferred dividends decreased $1.7 million (28%) in 1996 as compared to 1995
due primarily to the redemption of LG&E's 7.45% Series Cumulative Preferred
Stock in December 1995.
Variations in income tax expenses are largely attributable to changes in
pre-tax income.
The rate of inflation may have a significant impact on the Company's utility
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.
Argentine Gas Distribution and Other
In February 1997, the Company acquired interests in two Argentine gas
distribution companies: Distribuidora de Gas del Centro (Centro) and
Distribuidora de Gas Cuyana (Cuyana). Revenues and operating expenses
increased $127.2 million and $29.3 million, respectively, due to the
incorporation of results from Centro. Equity in earnings of joint ventures
increased by $2.4 million due to the acquisition of an interest in Cuyana.
Interest charges and preferred dividends increased by $10.5 million and
minority interest increased by $9 million due to these acquisitions.
Equity in earnings of joint ventures from the Company's power generation
projects were essentially flat between 1996 and 1997.
The decrease in equity in earnings of joint ventures in 1996 of $9.2 million
compared to 1995 mainly resulted from the sale of power purchase contracts by
two partnerships in June 1995. These sales resulted in gains totaling $9.7
million in 1995. Also, earnings from the three windpower joint ventures
formerly managed by Kenetech Windpower, Inc. (Kenetech) decreased $1.1
million. This was primarily due to an increased level of expense incurred
because of a change in operations management at the ventures during 1996
after Kenetech filed for Chapter 11 bankruptcy protection. The Company now
manages operations at two of the projects, and another venture partner
manages the third. See Notes 8 and 18 of Notes to Financial Statements.
Other income and deductions increased by $9.4 million in 1997 mainly due to
the sale of one-half of the Company's interest in the Rensselaer cogeneration
facility. Other income and deductions decreased by $3.7
5
<PAGE>
million in 1996 compared to 1995 due to lower interest and dividend income
resulting from a decrease in marketable securities. See Notes 8 and 14 of
Notes to Financial Statements.
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 equity investments in connection with independent power
production projects and other energy-related growth or acquisition
opportunities among the non-utility businesses. Capital funds are also
needed for the Company's capital obligations under the Big Rivers lease
arrangements, losses anticipated in connection with the discontinuance of the
merchant sales and trading business, partnership equity contributions in
connection with independent power production projects, information system
enhancements, and other business development opportunities. Fluctuations in
the Company's discontinued energy marketing and trading activities also
affected liquidity throughout the year. Lines of credit are maintained to
fund these temporary capital requirements.
Construction Expenditures and Equity Investments
Utility construction expenditures for 1997 were $205 million compared with
$215 million for 1996 and $218 million for 1995. Non-utility construction
expenditures (other than generating plant expenditures incurred by joint
ventures) were approximately $5 million in 1997, $1 million in 1996, and $2
million in 1995. In 1995, the Company invested equity of $37 million in
several domestic and international power projects and in the redemption of
its interest in the partnership that operated many of its power plants.
Past Financing Activities
During 1997, 1996, and 1995, the Company's primary sources of capital were
internally generated funds from operating cash flows and debt financing.
Internally generated funds provided financing for 100% of the Company's
utility construction expenditures for 1997, 1996, and 1995. The Company
acquired interests in two Argentine natural gas distribution companies in
1997 for $140 million, plus transaction related fees and expenses. It also
acquired Hadson Corporation (Hadson) in 1995 for $143 million, plus
acquisition-related fees and expenses. These acquisitions were financed with
cash and lines of credit. The Company also provided its energy marketing
business with additional cash to meet general working capital needs. The
investment in Hadson and the results of the energy marketing business are
included in discontinued operations.
The Company's combined cash and marketable securities balance increased by
$21.0 million in 1997 and decreased by $15.7 million in 1996. The increase
for 1997 reflects cash flows from operations and an increase in borrowings,
partially offset by capital expenditures and dividends paid. The 1996
decrease reflects capital expenditures, dividends paid, and a net decrease in
borrowings, partially offset by cash flows from operations. In 1995,
combined cash and marketable securities decreased $89.7 million compared to
1994, which primarily resulted from the acquisition of Hadson and related
working capital needs, additional investments in affiliates and dividends
paid; offset by cash flows from operations, an increase in borrowings and
changes in classification of investments from noncurrent to current assets.
The increases in accounts receivable and accounts payable during 1997
resulted primarily from acquiring a controlling interest in Centro in
February 1997. 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 LG&E's
and KU's service territories.
In November 1997, LG&E issued $35 million of Jefferson County, Kentucky and
$35 million of Trimble County, Kentucky, Pollution Control Bonds, Flexible
Rate Series, due November 1, 2027. The interest rates for
6
<PAGE>
these bonds were 3.90% and 3.85%, respectively, at December 31, 1997. The
proceeds from these bonds were used to redeem the outstanding 7.75% Series of
Jefferson County, Kentucky and Trimble County, Kentucky, Pollution Control
Bonds due February 1, 2019.
In October 1996, LG&E issued $22.5 million of Jefferson County, Kentucky and
$27.5 million of Trimble County, Kentucky, Pollution Control Bonds, Flexible
Rate Series, due September 1, 2026. Interest rates for these bonds were
3.79% and 3.82%, respectively, at December 31, 1997. The proceeds from these
bonds were applied in December 1996 to redeem the outstanding 7.25% Series of
Jefferson County, Kentucky and Trimble County, Kentucky, Pollution Control
Bonds due December 1, 2016.
On June 1, 1996, LG&E's First Mortgage Bonds, 5.625% Series of $16 million
matured and were retired by LG&E. The bonds were redeemed with available
funds.
In April 1995, LG&E issued $40 million of Jefferson County, Kentucky,
Pollution Control Bonds, 5.90% Series, due April 15, 2023. The proceeds from
these bonds were used to redeem the outstanding 9.25% Series of Pollution
Control Bonds due July 1, 2015.
In December 1995, LG&E 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. LG&E funded the $22 million redemption with cash
generated internally.
In January 1996, KU issued $36 million of Series S First Mortgage Bonds,
maturing 2006, at a rate of 5.99%. The proceeds were used to redeem $35.5
million of Series K First Mortgage Bonds which carried a rate of 7.375%.
In June 1995, KU issued $50 million of Series R First Mortgage Bonds which
will mature in 2025 and bear interest at 7.55%. The proceeds were used
primarily to pay short-term indebtedness incurred to finance ongoing
construction expenditures and general business requirements.
The Company's equity investments in non-utility projects and non-utility
construction expenditures were financed through internally generated funds
and short-term borrowings. Construction expenditures for new generating
projects were funded through project debt.
The Company had non-utility short-term borrowings outstanding of $360.2
million as of December 31, 1997. These borrowings consisted of commercial
paper which had maturity dates ranging between one and 270 days. Because of
the roll-over of these maturity dates, total short-term borrowings during the
year were approximately $3.9 billion and total repayments of short-term
borrowings during the year were approximately $3.7 billion. Non-utility
short-term borrowings were $158 million as of December 31, 1996, and $173
million as of December 31, 1995. The increase in 1997 was primarily due to
the acquisition of the interests in the Argentine natural gas distribution
companies and the funding of working capital requirements.
At the end of 1997, KU's short-term borrowings were $34 million compared to
$54 million at December 31, 1996. KU has used short-term borrowings to
temporarily finance ongoing construction expenditures and general corporate
requirements. The decrease was due primarily to KU's cash provided by
operations exceeding cash required for investing and financing activities
(exclusive of short-term borrowings).
The Company issued $4 million of new common stock in 1997 and $2 million in
1996, under various employee plans. The Company announced a program on
October 14, 1997, authorizing the repurchase of up to 1,000,000 shares of its
common stock to be used for, among other things, benefit and compensation
plans. See Note 15 of
7
<PAGE>
Notes to Financial Statements.
Future Capital Requirements
Future utility financing requirements may be affected in varying degrees by
factors such as load growth, changes in construction expenditure levels, rate
actions allowed by regulatory agencies, new legislation, market entry of
competing electric power generators, changes in environmental regulations and
other regulatory requirements. The Company estimates that LG&E's
construction expenditures will total $260 million for 1998 and 1999, and that
KU's construction expenditures for the same period will total approximately
$200 million. In addition, LG&E's capital requirements for 1998 include $20
million to retire long-term debt that is scheduled to mature on June 1, 1998,
and KU's capital requirements for 2000 include $61.5 million for scheduled
debt retirements. Capital expenditures for the non-utility businesses are
anticipated to total $23 million for 1998 and 1999. Other future capital
funding requirements are dependent upon the identification of suitable
investment opportunities to enhance shareholder returns and achieve long-term
financial objectives through business acquisitions.
KU forecasts annual growth in sales and peak demand of 2.5% and 2.7%,
respectively, over the next 5 years. KU plans to provide for the future
power needs of its customers primarily through purchased power and the
addition of combustion turbine peaking units. There are no plans for
additional baseload capacity at KU before 2010.
In October 1998, the Company negotiated for the purchase of two gas turbine
peaking units at a total cost of approximately $115 million to be expended in
1998 and 1999.
On July 15, 1998, the Company closed its transaction to lease the generating
assets of Big Rivers Electric Corporation. On July 14, 1998, LG&E Capital
Corp., a subsidiary of the Company, issued $95.1 million of commercial paper
to meet various working capital requirements related to the closing.
In July 1998, following the Company's decision to discontinue its merchant
energy trading and sales business, Standard & Poor's (S&P) downgraded the
credit ratings of the Company and its subsidiaries. The Company's corporate
credit rating was changed from "A+" to "A". Similar action was taken with
respect to the credit ratings of LG&E and KU. LG&E's corporate credit rating
and first mortgage bonds are now rated "A+", its unsecured debt and preferred
stock are now rated "A" and its commercial paper is now rated "A-1". KU's
corporate credit rating and preferred stock are now rated "A+", its first
mortgage bonds are now rated "AA-" and its commercial paper is now rated
"A-1". LG&E Capital's ratings for its corporate credit and unsecured debt
are now "A" and its commercial paper rating remained at "A-1". These ratings
reflect the views of S&P, and an explanation of the significance of these
ratings may be obtained from S&P. A security rating is not a recommendation
to buy, sell or hold securities and is subject to revision or withdrawal at
any time by the rating agency.
Future Sources of Financing
Internally generated funds from operations are expected to fund substantially
all of LG&E's and KU's anticipated construction expenditures in 1998 and
1999. Similarly, the Company anticipates having sufficient internal cash
generation, borrowing capacity and access to securities markets to meet
anticipated equity investments and non-utility capital expenditures in 1998
and 1999.
On September 5, 1997, LG&E Energy Systems Inc. (Energy Systems) and LG&E Gas
Systems Inc. (Gas Systems) merged to form LG&E Capital Corp. (Capital Corp.).
At the same time, Capital Corp. implemented a $600 million commercial paper
facility backed by new lines of credit totaling $700 million. The Company
terminated the previous lines of credit which totaled $460 million.
8
<PAGE>
At December 31, 1997, loan agreements and lines of credit were in place
totaling $960 million ($200 million for LG&E, $60 million for KU, and $700
million for Capital Corp.) for which the companies pay commitment or facility
fees. The LG&E and KU credit facilities provides for short-term borrowing.
The Capital Corp. facilities provide for short-term borrowing, letter of
credit issuance, and support of commercial-paper borrowings. Unused capacity
under these lines totaled $541.7 million after considering the commercial
paper support and approximately $58.1 million in letters of credit securing
on- and off-balance sheet commitments. The credit lines will expire at
various times from 1998 through 2002. Management expects to renegotiate the
lines when they expire.
On February 6, 1998, Capital Corp. issued $150 million of medium-term notes
due in January 2008. The securities were issued pursuant to an unregistered
Rule 144A offering. The stated interest rate on the notes was 6.46%. After
taking into account the effects of an interest rate swap entered into in 1997
to hedge the interest rate on $100 million of such medium-term notes and
other issuance costs, the effective rate will be 6.82%. See Note 6 of Notes
to Financial Statements. The proceeds were used to repay outstanding notes
payable.
The lenders under the credit facilities, commercial paper facility, and the
medium-term notes for Capital Corp. are entitled to the benefits of Support
Agreements with LG&E Energy Corp. See Note 17 of Notes to Financial
Statements.
Year 2000 Computer Software Issue
The Company began its project regarding the year 2000 issue in 1996. The
board of directors approved the general year 2000 plan and receives, along
with management, regular updates. Project teams are continuing to evaluate
risks and to plan and implement appropriate sources of corrective action.
Corrective action, including replacement or modification of certain software
systems, for major applications such as customer information, financial and
trading systems are in process, and in certain cases completed. Regarding
the smaller, more isolated systems, the Company anticipates moving from the
evaluative stage to the corrective stage during 1998. The Company has also
communicated with its suppliers, customers and key business partners
regarding year 2000 compliance and intends to continue monitoring their
progress on this issue.
The amount that has been expensed through December 31, 1997, is approximately
$2 million. Based on studies and progress made to date, the Company expects
to spend approximately $11 million in 1998 and 1999 for significant
modification of its computer information systems to enable proper processing
of transactions relating to the year 2000 and beyond. Accordingly, the
Company does not expect the amounts required to be expensed over the next two
years to have a material effect on its financial position or results of
operations.
LG&E Energy Corp. - KU Energy Corporation Merger
On May 20, 1997, the Company and KU Energy Corporation (KU Energy) entered
into an Agreement and Plan of Merger providing for a merger of LG&E Energy
and KU Energy. Pursuant to the Merger Agreement, LG&E Energy and KU Energy
merged on May 4, 1998, with LG&E Energy as the surviving corporation. For a
more detailed and descriptive discussion of the merger and the additional
approvals needed, see Note 2 of Notes to Financial Statements.
Rates and Regulation
LG&E and KU are subject to the jurisdiction of the Kentucky Commission in
virtually all matters related to electric and gas utility regulation, and as
such, their accounting is subject to Statement of Financial Accounting
Standards No. 71, Accounting for the Effects of Certain Types of Regulation
(SFAS No. 71). Given LG&E's and KU's competitive position in the market and
the status of regulation in the state of Kentucky, neither LG&E
9
<PAGE>
nor KU have plans or intentions to discontinue its application of SFAS No.
71. See Note 5 of Notes to Financial Statements. KU is also subject to the
jurisdiction of the Virginia State Corporation Commission (Virginia
Commission).
On December 8, 1995, the Commission approved a settlement agreement filed by
LG&E and all intervenors in the Trimble County proceedings, including various
consumer interest groups and government agencies, that, in effect, resolved
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 receiving $22 million in refunds,
most of which is being refunded over the five-year period, 1996 through 2000,
based on a per-kilowatt-hour credit. In addition, LG&E is providing $900,000
annually for five years, beginning in 1996, to fund low-income energy
assistance programs. The Company also revised the decoupling methodology in a
manner that reduced 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 increase operating expenses by $1.5 million. Thus, the
settlement reduced 1995 net income by $17.9 million, and earnings per share
by 14CENTS. See Note 19 of Notes to Financial Statements.
In May 1995, LG&E implemented a Commission approved environmental cost
recovery (ECR) 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. As
a result of this surcharge, LG&E's electric revenues increased $3.2 million
in 1995, an additional $2.4 million in 1996 and an additional $.4 million in
1997. The Kentucky Attorney General (KAG), and the Kentucky Industrial
Utility Customers filed an appeal in Franklin Circuit Court on various issues
related to the Commission's order in this proceeding, including the
constitutionality of the Kentucky statute that authorizes the surcharge. In
an order dated April 10, 1996, associated with the first six-month review of
the operation of the surcharge, the Commission stated that all environmental
surcharge revenues collected from the date of the April 10 order will be
subject to refund, pending the outcome of the legal proceedings. LG&E is
contesting the legal challenges but cannot predict the outcome of this
litigation. In a similar proceeding involving appeals from the Commission's
order authorizing an environmental cost recovery surcharge for KU by the same
intervenors, the Kentucky Court of Appeals, in a decision issued on December
5, 1997, upheld the constitutionality of the surcharge statute. The
intervenors have petitioned the Kentucky Supreme Court to review the decision
of the Kentucky Court of Appeals. Any refunds that may ultimately be
ordered, are not expected to have a material adverse effect on LG&E's
financial position or results of operation.
In August 1994, KU implemented an environmental cost recovery mechanism
(surcharge) in Kentucky. Authorized by a 1992 state statute and approved by
the Commission in July 1994, the surcharge is designed to recover certain
environmental compliance costs, including costs to comply with the 1990 Clean
Air Act Amendments, through a surcharge on customers bills.
The Commission's order approving the surcharge and the constitutionality of
the surcharge were challenged in a Franklin County (Kentucky) Circuit Court
(Circuit Court) action brought against KU and the Commission by the Attorney
General of Kentucky and representatives of consumer groups. In July 1995,
the Circuit Court entered a judgment upholding the constitutionality of the
surcharge statute but vacating that part of the Commission's order which the
Circuit Court's judgment described as retroactively applying the surcharge
statute. All parties (including KU and the Commission) appealed the Circuit
Court's judgment to the Kentucky Court of Appeals (Court of Appeals). The
Commission has ordered surcharge revenues collected by KU from February 1,
1995 subject to refund pending final determination of all appeals. The total
surcharge collections
10
<PAGE>
from February 1, 1995 through December 31, 1997 were approximately $56
million.
In December 1997, the Court of Appeals rendered an opinion upholding the
portion of the Circuit Court's judgment regarding the constitutionality of
the surcharge statute but reversing that portion of the Circuit Court's
judgment concerning the claim of retroactive application of the statute. On
June 10, 1998, the Kentucky Supreme Court granted motions for discretionary
review filed by the Kentucky Attorney General and consumer representation in
this matter. Briefs have been filed and oral argument is scheduled for
mid-November 1998.
KU continues to believe that the constitutionality of the surcharge statute
will be upheld. Although KU cannot predict the outcome of the claim of
retroactive application of the statute, it is the position of KU and the
Commission that the July 1994 Commission order did not retroactively apply
the statute. If the Court of Appeals opinion reversing the Circuit Court's
judgment on the claim of retroactivity is overturned and the Circuit Court's
judgment, as entered, is upheld, KU estimates that the amount it could be
required to refund for surcharge collections through December 31, 1997, from
the implementation of the surcharge would be approximately $15 million, and
from February 1, 1995, would be approximately $13 million. At this time, KU
has not recorded any reserve for refund. See to Note 5 of Notes to Financial
Statements.
In January 1994, LG&E implemented a Commission approved demand side
management (DSM) program that LG&E, KAG, the Jefferson County Attorney, and
representatives of several customer-interest groups had filed with the
Commission. The approved program included a formal collaborative process to
develop future DSM programs and also contained a rate mechanism that (1)
provided LG&E concurrent recovery of DSM costs, (2) provided an incentive for
implementing DSM programs, and (3) allowed LG&E to recover revenues from lost
sales associated with the DSM programs.
Subsequent to the original filing, LG&E requested three significant revisions
to the DSM program. In 1996, the Commission approved the addition of five
new programs that increased LG&E's commitment to DSM by approximately $4
million over the next two years. In 1997, LG&E requested a change in the
methodology used in determining revenues from lost sales associated with DSM
programs. This change would have replaced the decoupling mechanism approved
in the original program, with a methodology based on engineering estimates.
Also in 1997, LG&E requested approval to implement a 1998 program budget in
the amount of $2.5 million. On April 27, 1998 the Commission rejected the
proposal to calculate revenues from lost sales associated with DSM programs
based on engineering estimates, and ordered that two programs be terminated
on cost effectiveness grounds. On May 20, 1998, LG&E informed the Commission
that it had determined to terminate the booking of revenues associated with
the decoupling mechanism effective June 1, 1998. LG&E indicated that such a
replacement mechanism would be submitted to the Commission for approval in
the future. LG&E further informed the Commission that this action will not
suspend collection of accrued decoupling revenues recorded as revenues in
1997 and prior years and included in LG&E's currently effective DSM charge,
or the future collection of decoupling revenues booked during 1998 for the
January 1 through May 31 period. The Commission subsequently accepted the
LG&E proposal to terminate these revenues effective June 1, 1998.
On September 30, 1997, the Commission issued an order approving LG&E's
request to implement an experimental performance-based ratemaking mechanism.
This mechanism is related to gas procurement activities and gas off-system
sales only and is approved for a three-year test period effective October 1,
1997. During the three-year experimental period, rate adjustments related to
this mechanism will be determined for each 12-month period beginning November
1 and ending October 31. This mechanism is not expected to have a material
effect on LG&E's financial position or results of operations.
In its September 12, 1997 order approving the merger of LG&E Energy and KU
Energy, the Kentucky Commission ordered LG&E and KU to file by the later of
the consummation of the merger or September 14,
11
<PAGE>
1998, detailed plans to address the future rate regulation of the Company.
The Commission directed LG&E and KU to indicate in its filing whether it
desired to remain under traditional rate of return regulation or commence
non-traditional regulation. On October 12, 1998, pursuant to an extension
granted by the Kentucky Commission, LG&E and KU submitted parallel filings
proposing performance-based ratemaking systems. The performance-based
ratemaking proposal included financial incentives, including penalties, for
LG&E and KU to develop cost-saving means to provide electricity to customers,
who will also share in such savings. Incentives are also included in the
areas of quality of service and reliability. The PBR proposal has five
elements: replacement of the existing fuel adjustment clause with a cap tied
to a regional index; continued flow-through of certain LG&E and KU
joint-dispatch savings to customers; incentives tied to power plant unit
availability compared to past performance; incentives tied to quality,
reliability, satisfaction and safety performance compared to objective
benchmarks; and flexibility to customize rates and services according to
customer needs, subject to an obligation to offer standard tariff service and
subject to the condition that rates must exceed marginal cost. The proposal
remains subject to approval by the Kentucky Commission.
LG&E 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 LG&E an annual increase in rates of
$6.8 million ($6.1 million electric and $.7 million gas).
Environmental Matters
With the passage of the Clean Air Act Amendments of 1990 (the Act), LG&E
already complied with the stringent sulfur dioxide emission limits required
by the year 2000, as it had previously installed scrubbers on all of its
coal-fired generating units. Since 1990, as part of its ongoing construction
program, LG&E has spent $31 million for measures to meet applicable nitrogen
oxide limits. While the overall financial impact of the Act on LG&E has been
minimal, LG&E is closely monitoring several significant regulatory
developments which may potentially impact the Company including regulations
issued by the United States Environmental Protection Agency (USEPA) on
September 24, 1998. These regulations address long-range ozone transport
from Midwest emissions sources that allegedly contribute to ozone problems in
the Northeast. The regulations provide for a reduction in utility nitrogen
oxide emissions of approximately 85% from 1990 levels by 2003. If these
regulations are implemented as promulgated, LG&E, KU, WKEC and the
independent power projects in which the Company has an interest will be
required to incur significant capital expenditures and significantly
increased operation and maintenance costs for remedial measures. Final
implementation methods will be set by the USEPA and state regulatory
authorities.
The Company estimates that these capital costs could potentially exceed $300
million in the aggregate for LG&E, KU and WKEC. These costs would generally
be incurred following the year 2000. The Company believes its costs in this
regard to be comparable to that of similarly-situated utilities with like
generation assets. The Company anticipates that such capital and operating
costs are the type of costs that are eligible for recovery from customers
under its environmental surcharge mechanisms and believes that, in the cases
of LG&E and KU, a significant portion of such costs could be so recovered.
However, Kentucky Commission approval is necessary and there can be no
guarantee of such recovery.
KU met Phase I requirements of the Clean Air Act Amendments of 1990 (which
were effective January 1, 1995) primarily through the addition of a flue gas
desulfurization system (scrubber) on Unit 1 of KU's Ghent Generating Station.
The scrubber began commercial operation in December 1994.
KU's current strategy for Phase II requirements (which will be effective
January 1, 2000) is to use accumulated emission allowances to delay
additional capital expenditures and may also include fuel switching or the
installation of additional scrubbers.
12
<PAGE>
KU's future compliance plans are contingent upon many factors, including
developments in the emission allowance market and fuel markets as well as
regulatory and legislative actions and advances in clean air technology. KU
will continue to review and revise its compliance plans accordingly to ensure
that its environmental obligations are met in the most efficient and
cost-effective manner.
See Note 18 of Notes to Financial Statements for a complete discussion of the
Company's environmental issues concerning the proposed USEPA ozone transport
regulations, LG&E's Cane Run and Mill Creek electric generating plants,
manufactured gas plant sites, and certain other environmental issues.
Public Utility Regulatory Policies Act
Proposals also have been introduced in Congress to repeal all or portions of
the Public Utility Regulatory Policies Act (PURPA). PURPA and its
implementing regulations require, among other things, that electric utilities
purchase electricity generated by qualifying cogeneration facilities at a
price based on the purchasing utility's avoided costs. The Company is the
partial owner of several qualifying cogeneration facilities and it is the
operator of several qualifying cogeneration facilities pursuant to contracts.
While the Company supports the repeal of PURPA, the Company intends to
oppose any efforts to nullify existing contracts between electric utilities
and qualifying cogeneration facilities. The Company is involved in
proceedings before the Federal Energy Regulatory Commission (FERC) regarding
its Southampton cogeneration facility and in litigation with the purchasing
utility of the energy from its Roanoke Valley I cogeneration facility. The
Rensselaer cogeneration facility, in which the Company has a 50% interest
through an indirect subsidiary, is one of a group of 16 independent power
producers which have entered into an agreement with Niagara Mohawk Power
Corporation, as purchasing utility, to negotiate towards restructurings of
their power sales contracts. As proceedings and negotiations concerning
these events are continuing, the Company is currently unable to predict the
outcome of these matters. See Note 18 of Notes to Financial Statements.
Impact of Nonregulated Businesses
The Company expects to continue investing in nonregulated projects, including
domestic and international power production and gas distribution projects, as
described under Future Capital Requirements. The nonregulated projects in
which the Company has invested carry a higher level of risk than LG&E's or
KU's traditional utility businesses. Current investments in nonregulated
projects are subject to competition, operating risks, dependence on certain
suppliers and customers, and domestic and foreign environmental and energy
regulations as well as political and currency risks. In addition,
significant expenses may be incurred for projects pursued by the Company that
do not materialize. The aggregate effect of these factors is to create the
potential for more volatility in the nonregulated component of the Company's
earnings. Accordingly, the historical operating results of the Company's
nonregulated businesses may not necessarily be indicative of future operating
results.
FUTURE OUTLOOK
13
<PAGE>
Competition and Customer Choice
LG&E Energy Corp. has moved aggressively over the past decade to be
positioned for, and to help promote, the energy industry's shift to customer
choice and a competitive market for energy services. Specifically, the
Company has taken many steps to prepare for the expected increase in
competition in its regulated and non-regulated energy services businesses,
including aggressive cost reduction activities; strategic acquisitions and
growth initiatives; write-offs of previously deferred expenses; an increase
in focus on commercial and industrial customers; an increase in employee
training; and necessary corporate and business unit realignments. The
Company continues to be active in the national debate surrounding the
restructuring of the electric industry and the move toward a competitive,
market-based environment. LG&E Energy Corp. has urged Congress and federal
regulatory agencies to set a specific date for a complete transition to a
competitive market, one that will quickly and efficiently bring the benefits
associated with customer choice. LG&E Energy Corp. has repeatedly advocated
the implementation of this transition by January 1, 2001.
The Kentucky Commission has held a series of meetings with representatives of
utilities, consumers, state agencies, state legislators and other groups in
Kentucky to discuss the possible effects of electric industry restructuring
in Kentucky. In December 1997, the Kentucky Commission issued a set of
principles which are intended to serve as its guide in consideration of
issues relating to industry restructuring. Among these principles were:
consumer protection and benefit, system reliability, universal service,
environmental responsibility, cost allocation, stranded costs and codes of
conduct.
At the time of this report, neither the Kentucky General Assembly nor the
Kentucky Commission has adopted or approved a final plan or timetable for
retail electric industry competition in Kentucky. The nature or timing of
future legislative or regulatory actions regarding industry restructuring and
their impact on the Company, which may be significant, cannot be predicted
currently.
14
<PAGE>
LG&E Energy Corp. and Subsidiaries
Consolidated Statements of Income
(Thousands of $ Except Per Share Data)
<TABLE>
<CAPTION>
Years Ended December 31
1997 1996 1995
---- ---- ----
<S> <C> <C> <C>
REVENUES:
Electric utility $1,331,569 $1,318,846 $1,257,486
Refund - Trimble County settlement
(Note 19) - - (28,300)
Gas utility 231,011 214,419 181,126
Argentine gas distribution and other 162,475 27,195 22,368
---------- ---------- ----------
Total revenues (Note 1) 1,725,055 1,560,460 1,432,680
---------- ---------- ----------
COST OF REVENUES:
Fuel and power purchased 427,673 427,011 414,256
Gas supply expenses 158,929 140,482 110,738
Argentine gas distribution and other 85,380 13,559 25,563
---------- ---------- ----------
Total cost of revenues 671,982 581,052 550,557
---------- ---------- ----------
Gross profit 1,053,073 979,408 882,123
OPERATING EXPENSES:
Operation and maintenance:
Utility 415,882 416,597 402,086
Argentine gas distribution and other 54,724 31,101 25,119
Depreciation and amortization 186,549 171,399 162,700
Non-recurring charges (Note 10) - 5,493 -
---------- ---------- ----------
Total operating expenses 657,155 624,590 589,905
---------- ---------- ----------
Equity in earnings of joint ventures
(Note 8) 22,937 19,727 28,880
---------- ---------- ----------
OPERATING INCOME 418,855 374,545 321,098
Other income and (deductions) (Note 14) 20,970 11,575 15,309
Interest charges and preferred dividends 104,427 94,412 90,498
Minority interest 9,035 - -
---------- ---------- ----------
Income before income taxes 326,363 291,708 245,909
Income taxes (Note 13) 119,323 101,322 86,294
---------- ---------- ----------
Income from continuing operations 207,040 190,386 159,615
Loss from discontinued operations,
net of income tax expense (benefit)
of $(15,116), $2,371, and $(179)
(Notes 1 and 3) (24,044) (4,434) (732)
---------- ---------- ----------
NET INCOME $ 182,996 $ 185,952 $ 158,883
---------- ---------- ----------
---------- ---------- ----------
Average common shares outstanding 129,627 129,450 129,261
Earnings per share of common stock -
basic and diluted:
Continuing operations $ 1.60 $ 1.47 $ 1.23
Loss from discontinued operations (.19) (.03) -
---------- ---------- ----------
Total $1.41 $1.44 $1.23
---------- ---------- ----------
---------- ---------- ----------
</TABLE>
The accompanying notes are an integral part of these financial statements.
15
<PAGE>
LG&E Energy Corp. and Subsidiaries
Consolidated Balance Sheets
(Thousands of $)
<TABLE>
<CAPTION>
December 31
1997 1996
---- ----
<S> <C> <C>
ASSETS:
Current assets:
Cash and temporary cash investments $ 111,003 $ 106,463
Marketable securities (Note 11) 22,300 5,815
Accounts receivable - less reserve of
$4,731 in 1997 and $2,143 in 1997 242,942 193,788
Materials and supplies - primarily at average cost:
Fuel (predominantly coal) 45,450 45,471
Gas stored underground 42,104 35,510
Other 55,514 54,083
Net assets of discontinued operations (Notes 1 and 3) 222,784 211,838
Prepayments and other 9,304 13,054
---------- ----------
Total current assets 751,401 666,022
---------- ----------
Utility plant:
At original cost (Note 1) 5,390,868 5,231,456
Less: reserve for depreciation 2,201,124 2,067,898
---------- ----------
Net utility plant 3,189,744 3,163,558
---------- ----------
Other property and investments - less reserve:
Investments in affiliates (Note 8) 177,006 130,844
Non-utility property and plant, net (Notes 1 and 2) 248,119 4,688
Other 53,534 45,563
---------- ----------
Total other property and investments 478,659 181,095
---------- ----------
Deferred debits and other assets:
Regulatory assets (Note 5) 39,672 39,260
Goodwill, net (Notes 1 and 2) 13,675 14,077
Other 89,793 68,587
---------- ----------
Total deferred debits and other assets 143,140 121,924
---------- ----------
Total assets $4,562,944 $4,132,599
---------- ----------
---------- ----------
CAPITAL AND LIABILITIES:
Current liabilities:
Long-term debt due within one year $ 20,021 $ 21
Notes payable (Note 17) 393,784 212,200
Accounts payable 134,714 120,837
Trimble County settlement (Note 19) 13,248 17,511
Other 122,780 98,639
---------- ----------
Total current liabilities 684,547 449,208
---------- ----------
Long-term debt 1,210,690 1,193,208
Deferred credits and other liabilities:
Accumulated deferred income taxes (Notes 1 and 13) 548,477 504,386
Investment tax credit, in process of amortization 101,931 110,207
Accumulated provision for pensions and related benefits 79,547 70,857
Regulatory liability (Note 5) 117,079 134,936
Other 77,141 77,738
---------- ----------
Total deferred credits and other liabilities 924,175 898,124
---------- ----------
Minority interest 105,985 -
Cumulative preferred stock 138,353 135,328
Commitments and contingencies (Note 18)
Common equity 1,499,194 1,456,731
---------- ----------
Total capital and liabilities $4,562,944 $4,132,599
---------- ----------
---------- ----------
</TABLE>
The accompanying notes are an integral part of these financial statements.
16
<PAGE>
LG&E Energy Corp. and Subsidiaries
Consolidated Statements of Cash Flows
(Thousands of $)
<TABLE>
<CAPTION>
Years Ended December 31
1997 1996 1995
---- ---- ----
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 182,996 $ 185,952 $ 158,883
Items not requiring cash currently:
Depreciation and amortization 186,549 171,399 162,700
Deferred income taxes - net 10,316 55,589 30,749
Investment tax credit - net (8,276) (8,010) (8,837)
Undistributed earnings of joint ventures (2,326) (2,102) 16,491
Non-recurring charges - 5,493 -
Loss from discontinued operations (Notes 1 and 3) 24,044 4,434 732
Other 14,213 4,654 2,046
Change in certain net current assets:
Accounts receivable (22,771) (3,976) (31,754)
Materials and supplies (7,514) (1,468) 4,659
Net assets of discontinued operations (Notes 1 and 3) (10,946) 13,539 (224,016)
Trimble County settlement (4,263) (12,289) 29,800
Accounts payable 1,826 (11,396) 12,272
Accrued taxes 7,927 (4,467) (10,164)
Accrued interest (2,068) (542) (1,828)
Prepayments and other 1,981 6,889 (9,919)
Other (52,942) (35,313) 17,138
------------- ------------- -------------
Net cash flows from operating activities 318,746 368,386 148,952
------------- ------------- -------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchases of securities (21,526) (20,625) (204,391)
Proceeds from sales of securities 5,030 44,609 319,731
Construction expenditures (210,131) (215,954) (220,302)
Investment in subsidiaries net of cash and
temporary cash investments acquired (Note 2) (124,593) - -
Investments in affiliates (Note 8) (5,791) (1,490) (37,249)
------------- ------------- -------------
Net cash flows from investing activities (357,011) (193,460) (142,211)
------------- ------------- -------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of bonds 69,776 89,190 89,203
Retirement of bonds (71,714) (103,205) (41,076)
Short-term borrowings 3,871,905 2,784,700 4,170,015
Repayment of short-term borrowings (3,690,321) (2,801,100) (4,049,715)
Issuance of preferred stock 3,025 - -
Redemption of preferred stock - - (22,108)
Issuance of common stock 3,781 2,293 2,711
Payment of common dividends (143,647) (139,282) (135,164)
------------- ------------- -------------
Net cash flows from financing activities 42,805 (167,404) 13,866
------------- ------------- -------------
Change in cash and temporary cash investments 4,540 7,522 20,607
Beginning cash and temporary cash investments 106,463 98,941 78,334
------------- ------------- -------------
Ending cash and temporary cash investments $ 111,003 $ 106,463 $ 98,941
------------- ------------- -------------
------------- ------------- -------------
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Income taxes $ 82,662 $ 67,780 $ 69,278
Interest on borrowed money 93,451 86,045 86,877
</TABLE>
The accompanying notes are an integral part of these financial statements.
17
<PAGE>
LG&E Energy Corp. and Subsidiaries
Consolidated Statements of Capitalization
(Thousands of $)
<TABLE>
<CAPTION>
December 31
1997 1996
---- ----
<S> <C> <C> <C> <C>
COMMON EQUITY:
Common stock, without par value -
Authorized 300,000,000 shares, outstanding 129,682,889
shares in 1997 and 129,497,300 shares in 1996 (Note 15) $ 778,273 $ 774,469
Common stock expense (1,880) (1,854)
Unrealized gain on marketable securities, net of income
taxes of $89 in 1997 and $122 in 1996 (Note 11) 217 154
Retained earnings 722,584 683,962
------------ ------------
Total common equity 1,499,194 1,456,731
------------ ------------
PREFERRED STOCK (Note 15):
$10 nominal value, 302,364 shares authorized and outstanding, variable rate,
redeemable by Inversora de Gas del Centro 3,025 -
Shares Current
Outstanding Redemption Price
----------- ----------------
Cumulative and redeemable on 30 days notice by Louisville Gas and Electric
Company, except $5.875 series:
$25 par value, 1,720,000 shares authorized -
5% series 860,287 $ 28.00 21,507 21,507
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) (1,179)
------------ ------------
Total LG&E preferred stock 95,328 95,328
------------ ------------
Cumulative and redeemable on 30 days notice by Kentucky Utilities Company:
$100 stated value, 200,000 shares authorized -
4 3/4% series 200,000 $101.00 20,000 20,000
$100 stated value, 200,000 shares authorized -
6.53% series 200,000 See Note 15 20,000 20,000
------------ ------------
Total KU preferred stock 40,000 40,000
------------ ------------
Total preferred stock 138,353 135,328
------------ ------------
LONG-TERM DEBT (Note 16):
Louisville Gas and Electric Company:
First mortgage bonds -
Series due June 1, 1998, 6 3/4% - 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:
N due February 1, 2019, 7 3/4% - 35,000
O due February 1, 2019, 7 3/4% - 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 40,000
------------ ------------
Total first mortgage bonds 506,800 596,800
------------ ------------
</TABLE>
The accompanying notes are an integral part of these financial statements.
18
<PAGE>
LG&E Energy Corp. and Subsidiaries
Consolidated Statements of Capitalization (cont.)
(Thousands of $)
<TABLE>
<CAPTION>
December 31
1997 1996
---- ----
<S> <C> <C>
Pollution control bonds (unsecured) -
Jefferson County Series due September 1, 2026, variable 22,500 22,500
Trimble County Series due September 1, 2026, variable 27,500 27,500
Jefferson County Series due November 1, 2027, variable 35,000 -
Trimble County Series due November 1, 2027, variable 35,000 -
----------- -----------
Total unsecured pollution control bonds 120,000 50,000
----------- -----------
Unamortized premium on bonds - 35
----------- -----------
Total LG&E long-term debt 626,800 646,835
----------- -----------
Kentucky Utilities Company:
First mortgage bonds:
5.95% Series Q, due June 15, 2000 61,500 61,500
6.32% Series Q, due June 15, 2003 62,000 62,000
5.99% Series S, due January 15, 2006 36,000 36,000
7.92% Series P, due May 15, 2007 53,000 53,000
7.55% Series R, due June 1, 2025 50,000 50,000
8.55% Series P, due May 15, 2027 33,000 33,000
----------- -----------
Total first mortgage bonds 295,500 295,500
----------- -----------
First Mortgage Bonds, Pollution Control Series:
7 3/8% Pollution Control Series 7, due May 1, 2010 4,000 4,000
7.45% Pollution Control Series 8, due September 15, 2016 96,000 96,000
6 1/4% Pollution Control Series 1B, due February 1, 2018 20,930 20,930
6 1/4% Pollution Control Series 2B, due February 1, 2018 2,400 2,400
6 1/4% Pollution Control Series 3B, due February 1, 2018 7,200 7,200
6 1/4% Pollution Control Series 4B, due February 1, 2018 7,400 7,400
7.60% Pollution Control Series 7, due May 1, 2020 8,900 8,900
5 3/4% Pollution Control Series 9, due December 1, 2023 50,000 50,000
Variable Rate Pollution Control Series 10,
due November 1, 2024 54,000 54,000
----------- -----------
Total first mortgage bonds, pollution control series 250,830 250,830
----------- -----------
8% secured note, due January 5, 1999 (net of current maturity) 21 43
----------- -----------
Total KU long-term debt 546,351 546,373
----------- -----------
Argentine negotiable obligations, due August 2001, 10 1/2% 37,539 -
----------- -----------
Total long-term debt 1,210,690 1,193,208
----------- -----------
Total capitalization $ 2,848,237 $ 2,785,267
----------- -----------
----------- -----------
</TABLE>
The accompanying notes are an integral part of these financial statements.
19
<PAGE>
LG&E Energy Corp. and Subsidiaries
Consolidated Statements of Retained Earnings
(Thousands of $)
<TABLE>
<CAPTION>
Years Ended December 31
1997 1996 1995
---- ---- ----
<S> <C> <C> <C>
Balance January 1 $683,962 $637,996 $615,619
Add net income 182,996 185,952 158,883
Deduct: Cash dividends declared on common stock
($1.11345 per share in 1997, $1.08116 per share in 1996,
and $1.05025 per share in 1995) 144,366 139,986 135,787
Preferred stock redemption expense and other 8 - 719
-------- -------- --------
Balance December 31 $722,584 $683,962 $637,996
-------- -------- --------
-------- -------- --------
</TABLE>
The accompanying notes are an integral part of these financial statements.
NOTES TO FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PRESENTATION.
Effective May 4, 1998, following the receipt of all required state and
federal regulatory approvals, LG&E Energy Corp. (LG&E Energy or the Company)
and KU Energy Corporation (KU Energy) merged, with LG&E Energy as the
surviving corporation. The accompanying consolidated financial statements
reflect the accounting for the merger as a pooling of interests and are
presented as if the companies were combined as of the earliest period
presented. However, the financial information is not necessarily indicative
of the results of operations, financial position or cash flows that would
have occurred had the merger been consummated for the periods for which it is
given effect, nor is it necessarily indicative of future results of
operations, financial position, or cash flows. The financial statements
reflect the conversion of each outstanding share of KU Energy common stock
into 1.67 shares of LG&E Energy common stock. The outstanding preferred stock
of Louisville Gas and Electric Company (LG&E), a subsidiary of LG&E Energy,
and Kentucky Utilities Company (KU), a subsidiary of KU Energy, were not
affected by the Merger.
Effective June 30, 1998, the Company discontinued its merchant trading and
sales business, primarily due to its current portfolio of energy marketing
contracts, and the impact that recent volatility, instability and rising
prices on the power market have had on these contracts. Exiting the merchant
trading and sales business is intended to enable the Company to focus on
adding and optimizing physical assets, and to eliminate the earnings impact
to continuing operations of extreme market volatility on its current
portfolio of energy marketing contracts. The Company intends to sell or
buyout the long-term contracts that obligate it to buy and sell natural gas
and electric power. It also plans to sell its natural gas gathering and
processing business. The Company, however, intends to maintain sufficient
market knowledge, risk management skills, technical systems and experienced
personnel to maximize the value of power sales from assets it owns or
controls, including LG&E, KU and Big Rivers Electric Corporation (Big Rivers).
As a result of the Company's decision to discontinue its merchant trading and
sales activity, and the decision to sell the associated gas gathering and
processing business, the Company recorded an after-tax loss on disposal of
discontinued operations of $225.0 million in the second quarter of 1998. The
loss on disposal of discontinued operations results primarily from several
fixed-price energy marketing contracts entered in 1996 and early 1997,
including the Company's long-term contract with Oglethorpe Power Corporation
(OPC). Other components of the write-off include costs relating to certain
peaking options, goodwill associated with the Company's 1995 purchase of
these operations and exit costs. Although the Company used what it believes
to be appropriate estimates for future energy prices among other factors to
calculate the fair market value of discontinued operations, there is no
guarantee that higher than anticipated future prices or a lower received
purchase price than estimated for asset sales could not result in additional
losses. As of October 15, 1998, the Company estimates that a $1 change in
electricity prices across all geographic areas and time periods could change
the value of the Company's remaining energy portfolio by approximately $10
million. In addition to price risk, the value of the Company's remaining
energy portfolio is subject to operational and event risks including, among
others, increaases in load demand, regulatory changes, and forced outages at
units providing supply for the Company. As of October 15, 1998, the Company
estimates that a 1% change in the forecasted load demand could change the
value of the Company's remaining energy portfolio by $11 million. See Note
18, Commitments and Contingencies, for a discussion of the OPC contract.
The consolidated financial statements include the accounts of LG&E Energy
Corp., Louisville Gas and Electric Company, LG&E Capital Corp. (Capital
Corp.), KU Energy, KU and KU Capital Corporation (KU Capital) and their
respective wholly-owned subsidiaries, collectively referred to herein as the
"Company." KU and KU Capital were subsidiaries of KU Energy before the
merger. On September 5, 1997, LG&E Energy Corp. merged two of its direct
subsidiaries, LG&E Energy Systems Inc. (Energy Systems) and LG&E Gas Systems
Inc. (Gas Systems), and renamed the surviving company LG&E Capital Corp. On
July 24, 1998, KU Capital Corporation was merged into LG&E Capital Corp.,
with the latter as the surviving corporation.
20
<PAGE>
LG&E Energy Corp.'s regulated operations are conducted by LG&E and KU and its
non-regulated operations are conducted by Capital Corp., which has various
subsidiaries referred to in these financial statements including LG&E Energy
Marketing Inc. (LEM), LG&E Power Inc. (LPI), LG&E International Inc. (LII)
and WKE Corp.
All significant intercompany items and transactions have been eliminated from
the consolidated financial statements. The Company is exempt from regulation
as a registered holding company under the Public Utility Holding Company Act
of 1935 (PUHCA).
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.
GAS STORED UNDERGROUND. The costs of natural gas inventories are included in
gas stored underground in the balance sheets as of December 31, 1997, and
1996. Non-utility amounts included in gas inventories were immaterial. LG&E
accounts for gas inventories using the average-cost method.
UTILITY PLANT. LG&E's and KU's utility 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 for determining retail customer rates, and,
accordingly, neither LG&E nor KU has not recorded any significant allowance
for funds used during construction. The cost of utility plant retired or
disposed of in the normal course of business is deducted from utility 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 AND AMORTIZATION. Utility depreciation is provided on the
straight-line method over the estimated service lives of depreciable plant.
The amounts provided for LG&E in 1997 were 3.4% and for 1996 and 1995 were
3.3%. The amounts provided for KU approximated in 3.5% in 1997, 1996 and
1995. Depreciation of non-utility plant and equipment is based on the
straight-line method over periods ranging from 3 to 33 years for domestic
operations. Intangible assets and goodwill have been allocated to the
subsidiaries' lines of business and are being amortized over periods ranging
up to 40 years.
FINANCIAL INSTRUMENTS. The Company uses over-the-counter interest-rate swap
agreements to hedge its exposure to fluctuations in the 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 used to hedge interest rate risk 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 losses on marketable securities in common equity
and then charged or credited to other income and deductions when the
securities are sold. See Note 6, Financial Instruments.
The Company also uses financial instruments associated with its discontinued
energy marketing and trading business. The financial impact of these
transactions is included in discontinued operations.
DEBT EXPENSE. Utility debt expense is amortized over the lives of the
related bond issues, consistent with regulatory practices.
DEFERRED INCOME TAXES. Deferred income taxes have been provided for all
material book-tax temporary differences.
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. Deferred investment tax credits
are being amortized to income over the estimated lives of the related property
that gave
21
<PAGE>
rise to the credits.
COMMON STOCK. Effective April 15, 1996, the outstanding shares of the
Company's common stock were split on a two-for-one basis. The new shares
were issued to shareholders of record on April 1, 1996. On May 4, 1998,
63,155,253 shares were issued to shareholders of KU Energy to effect the
merger, and the KU Energy shares were retired. Prior period shares,
dividends, and earnings per share of common stock have been restated to
reflect the stock split, and to reflect the exchange of KU Energy's shares
for shares of LG&E Energy.
REVENUE RECOGNITION. Utility revenues are recorded based on service rendered
to customers through month-end. LG&E and KU accrue estimates for unbilled
revenues from each meter reading date to the end of the accounting period.
Under an agreement approved by the Public Service Commission of Kentucky,
LG&E has implemented a demand side management program and a "decoupling
mechanism," which allows LG&E to recover a predetermined level of revenue on
electric and gas residential sales. See Management's Discussion and
Analysis, Rates and Regulation, for further discussion. The Company
recognized revenues from non-utility construction activities using the
percentage of completion method of accounting.
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 assets and
liabilities and disclosure of contingent items 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
18, Commitments and Contingencies, for a further discussion.
NEW ACCOUNTING PRONOUNCEMENTS. Effective January 1, 1997, the Company
adopted Statement of Financial Accounting Standards No. 125, Accounting for
Transfers and Servicing of Financial Assets and Extinguishments of
Liabilities (SFAS No. 125). This new standard is effective for all transfers
and servicing of financial assets and extinguishments of liabilities
occurring after December 31, 1996. Adopting SFAS No. 125 had no impact on
the Company's financial position or results of operations.
The Company adopted the provisions of Statement of Position 96-1,
Environmental Remediation Liabilities, effective January 1, 1997. This
statement provides authoritative guidance for recognition, measurement, and
disclosure of environmental remediation liabilities in financial statements.
Due to the Company's previous recognition of this type of liability, adoption
did not have a material impact on the Company's financial position or results
of operation. See Note 18, Commitments and Contingencies, for a further
discussion of the Company's environmental commitments and contingencies.
In February 1997, the Financial Accounting Standards Board issued Statements
of Financial Accounting Standards No. 128, Earnings Per Share (SFAS No. 128),
and No. 129, Disclosure of Information about Capital Structure (SFAS No.
129), effective for periods ending after December 15, 1997. SFAS No. 128
requires that potential additional common stock (e.g., options, warrants,
convertible securities) be included in the calculation of a "dilutive EPS,"
in addition to the "basic EPS" which historically has been included in the
consolidated statements of income. The Company`s EPS as reported is the same
under both calculations. SFAS No. 129 broadens the disclosure requirements
related to an entity's capital structure to include non-public entities, but
requires no change in reporting by the Company.
In June 1997, the Financial Accounting Standards Board issued Statements of
Financial Accounting Standards No. 130, Reporting Comprehensive Income (SFAS
No. 130) and No. 131, Disclosures about Segments of an Enterprise and Related
Information (SFAS No. 131), effective for periods beginning after December
15, 1997.
22
<PAGE>
Pursuant to SFAS No. 130, the Company has presented supplemental information
in the Financial Statements and Notes to Financial Statements that measures
changes in equity that are not required to be measured as a component of net
income. This standard has no impact on the calculation of net income or
earnings per share. The Company anticipates that the Big Rivers Electric
Corporation agreement and other organizational changes will be considered in
determining segment disclosures under SFAS No. 131.
On April 3, 1998, the American Institute of Certified Public Accountants
issued Statement of Position No. 98-5, Reporting on the Costs of Start-Up
Activities, which is effective for fiscal years beginning after December 31,
1998. The statement requires companies to expense the costs of start-up
activities as incurred. The statement also requires certain previously
capitalized costs to be charged to expense at the time of adoption and
reported as the cumulative effect of a change in accounting principle. The
Company is currently analyzing the provisions of the statement and
anticipates that a range of $10 to $20 million of start-up costs could be
affected.
On June 15, 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities. The statement is effective for fiscal
years beginning after June 15, 1999, and establishes accounting and reporting
standards that every derivative instrument be recorded in the balance sheet
as either an asset or liability measured at its fair value. The statement
requires that changes in the derivative's fair value be recognized currently
in earnings unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's gains and losses to
offset related results on the hedged item in the income statement, and
requires that a company must formally document, designate, and assess the
effectiveness of transactions that receive hedge accounting. The Company is
currently analyzing the provisions of the statement and cannot predict the
impact this statement will have on its consolidated operations and financial
position. However, the statement could increase volatility in earnings and
other comprehensive income.
NOTE 2 - MERGERS AND ACQUISITIONS
KU ENERGY CORPORATION. On May 20, 1997, LG&E Energy and KU Energy entered
into an Agreement and Plan of Merger (the Merger Agreement) providing for a
merger of LG&E Energy and KU. Pursuant to the Merger Agreement, LG&E Energy
and KU Energy merged on May 4, 1998, with LG&E Energy as the surviving
corporation.
As a result of the merger, the Company, which is the parent of LG&E, became
the parent company of KU. The operating utility subsidiaries (LG&E and KU)
will maintain their separate corporate identities and will continue to serve
customers in Kentucky and Virginia under their present names. LG&E Energy
has estimated approximately $760 million in gross non-fuel savings over a
ten-year period following the merger. Costs to achieve these synergies of
$103.9 million were recorded in the second quarter of 1998, $38.6 million of
which were deferred pursuant to regulatory orders. The Company, LG&E and KU
expensed the remaining costs associated with the merger in the second quarter
of 1998. In regulatory filings associated with approval of the merger, LG&E
and KU committed not to seek increases in base rates and proposed reductions
in their retail customers' bills in amounts based on one-half of the net
savings over a five-year period. The preferred stock and debt securities of
the operating utility subsidiaries will not be affected by the merger.
Present non-utility operations of KU will be unaffected. The non-utility
subsidiaries of KU Energy have become subsidiaries of LG&E Energy.
Under the terms of the Merger Agreement, each outstanding share of the common
stock, without par value, of KU Energy (KU Common Stock) (other than shares
with respect to which dissenters' rights are perfected under applicable state
law), together with the associated KU Energy stock purchase rights, was
converted into 1.67 shares of common stock of LG&E Energy (LG&E Energy Common
Stock), together with the associated LG&E Energy stock purchase rights.
Immediately preceding the Merger, there were 66,527,636 shares of LG&E Energy
common stock outstanding, and 37,817,517 shares of KU common stock
outstanding. Based on such capitalization, upon consummation of the merger,
51.3% of the outstanding LG&E Energy common stock was
23
<PAGE>
owned by the shareholders of LG&E Energy prior to the merger and 48.7% was
owned by former KU shareholders.
On September 12, 1997, the Public Service Commission of Kentucky (Kentucky
Commission or Commission) approved the merger application substantially as
filed. In the application filed with the Commission, the utilities proposed
that 50% of the net non-fuel cost savings estimated to be achieved from the
merger, less 50% of the costs to achieve such savings (but not in excess of
the originally estimated $77 million costs to achieve), be applied to reduce
customer rates, and the remaining 50% be retained by the companies. The
Commission approved and allocated the customer savings 53% to KU and 47% to
LG&E. The order provides for a surcredit on customers' bills for 50% of the
projected net non-fuel savings in each of the five years following
consummation of the merger. The credit, which will be about 2% of customer
bills in the five-year period, will amount to approximately $55 million in
net non-fuel savings to LG&E customers and approximately $63 million in net
non-fuel savings to KU customers. Any fuel cost savings will be passed to
Kentucky customers through the companies' fuel adjustment clauses. One-half
of the costs to achieve the savings will be charged to expenses as incurred
once the merger is consummated, and the remaining portion (not to exceed
one-half of $77 million for KU and LG&E combined) will be deferred as a
regulatory asset and amortized as an offset to customer savings equally over
five years. It will be up to KU and LG&E to actually realize the estimated
level of net non-fuel savings.
On October 9, 1997, LG&E Energy and KU Energy filed for approval of the
merger with the Federal Energy Regulatory Commission. On October 14, 1997,
in separate meetings, stockholders from each of the companies met and the
holders of over 75% of the outstanding shares of common stock of LG&E Energy
and KU Energy approved the merger. On January 20, 1998, the Virginia State
Corporation Commission approved the merger substantially as filed, with
subsequent approval of a related issue in April 1998.
The Federal Energy Regulatory Commission approved the merger (under the
Federal Power Act) on March 27, 1998. The Federal Trade Commission review
periods (under the Hart-Scott-Rodino Antitrust Improvement Act) expired March
27, 1998. The Securities and Exchange Commission approved the merger (under
the Public Utility Holding Company Act of 1935) on April 30, 1998, allowing
LG&E Energy, as the parent of LG&E and KU, to continue to be an exempt
holding company under the Public Utility Holding Company Act of 1935. The
New York Stock Exchange also approved the listing of LG&E Energy Common Stock
issued in the merger. Management has accounted for the merger as a pooling of
interests and expects the transaction to qualify as a tax-free reorganization
under the Internal Revenue Code.
ARGENTINE GAS DISTRIBUTION COMPANIES. On February 13, 1997, the Company
acquired interests in two Argentine natural gas distribution companies for
$140 million, plus transaction-related costs and expenses. The Company
acquired a controlling interest in Distribuidora de Gas del Centro (Centro),
and a combined 14.4% interest in Distribuidora de Gas Cuyana (Cuyana). The
Company accounted for both acquisitions using the purchase method. The
Company allocated substantially all of the excess of the purchase price over
the underlying equity of Centro and Cuyana to property and equipment. The
Company recognized no goodwill on the acquisition.
24
<PAGE>
The fair values of the net assets acquired follow (in thousands of $):
<TABLE>
<CAPTION>
<S> <C>
Assets $330,215
Liabilities 86,455
Minority interests 103,916
--------
Cash paid, excluding transaction costs 139,844
Cash and cash equivalents acquired 16,453
--------
Net cash paid, excluding transaction costs 123,391
Transaction costs 1,202
--------
Net cash paid $124,593
--------
--------
</TABLE>
Centro's revenues, cost of revenues, and operating expenses since the date of
acquisition are classified as components of Argentine gas distribution and
other in the 1997 Statements of Income. The earnings of Cuyana are included
in Equity in Earnings of Joint Ventures. The Company included Centro's
property and equipment in Non-utility property and plant, net, in its balance
sheet in 1997 and it included its investment in Cuyana in Investments in
affiliates.
Liabilities assumed in the purchase included negotiable obligations issued by
Centro with a face amount of $38 million. The obligations mature in August
2001 and pay interest at 10.5% of face value. The Company classified the
negotiable obligations as long-term debt in its balance sheet in 1997.
NOTE 3 - DISCONTINUED OPERATIONS
Effective June 30, 1998, the Company discontinued its merchant trading and
sales business, primarily due to its current portfolio of energy marketing
contracts, and the impact that recent volatility, instability and rising
prices on the power market have had on these contracts. Exiting the merchant
trading and sales business is intended to enable the Company to focus on
adding and optimizing physical assets, and to eliminate the earnings impact
to continuing operations of extreme market volatility on its current
portfolio of energy marketing contracts. The Company intends to sell or
buyout the long-term contracts that obligate it to buy and sell natural gas
and electric power. It also plans to sell its natural gas gathering and
processing business. The Company, however, intends to maintain sufficient
market knowledge, risk management skills, technical systems and experienced
personnel to maximize the value of power sales from assets it owns or
controls, including LG&E, KU and Big Rivers Electric Corporation (Big Rivers).
As a result of the Company's decision to discontinue its merchant trading and
sales activity, and the decision to sell the associated gas gathering and
processing business, the Company recorded an after-tax loss on disposal of
discontinued operations of $225.0 million in the second quarter of 1998. The
loss on disposal of discontinued operations results primarily from several
fixed-price energy marketing contracts entered in 1996 and early 1997,
including the Company's long-term contract with Oglethorpe Power Corporation
(OPC). Other components of the write-off include costs relating to certain
peaking options, goodwill associated with the Company's 1995 purchase of
these operations and exit costs. Although the Company used what it believes
to be appropriate estimates for future energy prices among other factors to
calculate the fair market value of discontinued operations, there is no
guarantee that higher than anticipated future prices or a lower received
purchase price than estimated for asset sales could not result in additional
losses. As of October 15, 1998, the Company estimates that a $1 change in
electricity prices across all geographic areas and time periods could change
the value of the Company's remaining energy portfolio by approximately $10
million. In addition to price risk, the value of the Company's remaining
energy portfolio is subject to operational and event risks including, among
others, increases in load demand, regulatory changes, and forced outages at
units providing supply for the Company. As of October 15, 1998, the Company
estimates that a 1% change in the forecasted load demand could change the
value of the Company's remaining energy portfolio by $11 million. See Note
18, Commitments and Contingencies, for a discussion of the OPC contract. See
also Note 1.
Operating results for discontinued operations follow.
<TABLE>
<CAPTION>
1997 1996 1995
---------- ---------- --------
<S> <C> <C> <C>
Revenues $3,255,175 $2,740,691 $628,400
Income (loss) before taxes (39,160) (2,063) (911)
Income (loss) from discontinued
operations, net of income taxes $ (24,044) $ (4,434) $ (732)
</TABLE>
Net assets of discontinued operations at December 31 follow.
<TABLE>
<CAPTION>
1997 1996
---------- ----------
<S> <C> <C>
Cash and temporary cash investments $ 15,089 $ 38,476
Accounts receivable 353,162 426,679
Price risk management assets, net 164,581 123,467
Non-utility property and plant, net 176,032 169,492
Accounts payable and accruals (344,265) (436,160)
Price risk management liabilities, net (154,910) (135,884)
Goodwill and other assets and liabilities, net 13,095 25,768
---------- ---------
Net assets of discontinued operations $ 222,784 $ 211,838
---------- ---------
---------- ---------
</TABLE>
ACCOUNTING CHANGE. Effective January 1, 1996, the Company adopted the
mark-to-market method of accounting for its energy marketing and trading
activities. The Company has included these activities in Discontinued
Operations in the accompanying financial statements. Under mark-to-market
accounting, all electric
<PAGE>
power and natural gas contracts which qualify for such accounting treatment,
including both physical transactions and financial instruments, are recorded
at market value, net of future servicing costs and reserves, and are
recognized as price risk management assets and liabilities in the
accompanying balance sheet. To qualify for mark-to-market accounting
treatment, energy marketing and trading contracts generally must include,
among other factors, a firm term, volume and price and allow for settlement
in cash or with another financial instrument. Changes in the value of these
price risk management assets and liabilities resulting from the execution of
new contracts and changes in market factors are recognized as energy
marketing and trading revenues in the period of the change.
Revenues and cost of revenues associated with energy marketing and trading
activities that do not qualify for mark-to-market accounting treatment are
recognized using the accrual method of accounting at the time of delivery of
the underlying commodity. Prior to January 1, 1996, all of the Company's
energy marketing and trading activities were accounted for under the accrual
method. The effect of this change in accounting was immaterial to prior
periods at the time of adoption.
In addition, the Company may enter into transactions to hedge the impact of
market fluctuations in its energy-related assets, liabilities and other
contractual commitments. Changes in the market value of these hedge
transactions are based on the accounting treatment afforded the hedged items
whereby gains and losses are deferred until the gains or losses on the hedged
items are recognized.
TRADING ACTIVITIES. The Company's discontinued operations engage in price
risk management activities related to commodities associated with the energy
industry, predominantly electricity and natural gas. In addition to the
purchase and sale of these physical commodities, the Company's discontinued
operations enter into futures contracts, swap agreements where settlement is
based on the difference between a fixed and index-based price for the
underlying commodity, exchange-traded options, over-the-counter options which
are settled in cash or the physical delivery of the underlying commodity,
exchange-for-physical transactions in which payment for delivery of the
underlying commodity is in the form of futures contracts, tolling and other
contractual arrangements.
The Company's discontinued operations may buy or sell instruments such as
these to manage its exposure to price risk from existing contractual
commitments as well as other energy-related assets and liabilities.
MARKET RISK. The Company's discontinued operations will at times create a
net open position which could result in losses for the Company if prices do
not move in the manner or direction anticipated by the Company. The Company
has established trading policies and limits designed to limit the Company's
exposure to price risk and revalues exposures daily against the stipulated
limits. The Company also continually reviews these policies to ensure they
are responsive to changing business conditions.
The Company's discontinued operations utilize various methodologies which
simulate forward price curves in the energy markets to estimate the size and
probability of changes in market value resulting from price movements. The
use of these methodologies requires a number of key assumptions including
selection of confidence levels, the holding period of the positions, and the
depth and applicability to future periods of historical price information.
As of December 31, 1997, the Company estimates that a $1 change in
electricity prices and a 10-cent change in natural gas prices across all
geographic areas and time periods could have changed the value of the
Company's net price risk management assets by approximately $4.5 million. In
addition to price risk, the value of the Company's entire energy portfolio is
subject to operational and event risks including, among others, regulatory
changes, increases in load demand, and forced outages at units providing
supply for the Company. As of October 15, 1998, the Company estimates that a
$1 change in electricity prices across all geographic areas and time periods
could change the value of the Company's remaining energy portfolio by
approximately $10 million and that a 1% change in the forecasted load demand
could change the value of the Company's remaining energy portfolio by $11
million.
NOTIONAL AMOUNTS AND TERMS. As of December 31, 1997, the Company's
discontinued operations were under contract to pay a fixed price based on
239.1 million MWh's of electricity and 1.07 billion MMBTU's of natural
<PAGE>
gas with a volumetric weighted average period of 2.94 and 0.33 years,
respectively. The Company was also under contract to receive a fixed price
based on 246.4 million MWh's of electricity and 1.025 billion MMBTU's of
natural gas with a volumetric weighted average period of 2.93 and 0.33 years,
respectively. Notional amounts reflect the nominal volume of transactions
included in the Company's net price risk management assets but do not reflect
actual amounts of cash, financial instruments, or quantities of the
underlying commodity which may ultimately be exchanged between the parties.
FAIR VALUES. The fair values of discontinued operations' price risk
management assets and liabilities as of December 31, 1997 and 1996 and the
average fair values during the year by commodity are set forth below (in
thousands of $):
<TABLE>
<CAPTION>
FAIR VALUE AVERAGE FAIR VALUE
---------- ------------------
ASSETS LIABILITIES ASSETS LIABILITIES
-------- ----------- --------- -----------
<S> <C> <C> <C> <C>
1997:
BY COMMODITY:
Electricity $ 69,704 $ 56,308 $ 81,765 $ 31,093
Natural gas 94,252 92,245 55,676 65,414
Other 625 1,119 505 848
-------- ----------- --------- -----------
Total 164,581 149,672 $137,946 $ 97,355
Reserves - 5,238 --------- -----------
-------- ----------- --------- -----------
Net values $164,581 $154,910
-------- -----------
-------- -----------
1996:
BY COMMODITY:
Electricity $ 52,885 $ 27,159 $20,784 $12,736
Natural gas 70,582 101,484 69,156 65,356
Other - - - -
-------- ----------- --------- -----------
Total 123,467 128,643 $89,940 $78,092
Reserves - 7,241 --------- -----------
-------- ----------- --------- -----------
Net values $123,467 $135,884
-------- -----------
-------- -----------
</TABLE>
The fair values above are based on quotes from exchanges and over-the-counter
markets, price volatility factors, the use of established pricing models and
the time value of money. They also reflect management estimates of
counterparty credit risk, location differentials and the potential impact of
liquidating the Company's position in an orderly manner over a reasonable
period of time under present market conditions.
CREDIT RISK. The Company's discontinued operations maintain policies
intended to minimize credit risk and revalues credit exposures daily to
monitor compliance with those policies. As of December 31, 1997, over 97% of
the Company's price risk management assets were with counterparties rated BBB
equivalent or better. As of December 31, 1997, seven counterparties
represented 52% of the Company's price risk management assets.
OTHER CONTRACTS. In addition to the above price risk management assets and
liabilities, the Company's discontinued operations is a party to various
arrangements which commit the Company to the sale or purchase of electricity
or natural gas without a specified firm volume. The Company has also entered
into certain forward transactions and financial instruments which include
futures contracts, fixed swaps and basis swaps, to hedge the price risk
exposure on these transactions. The transactions and related hedges extend
through April 2008, with an estimated volumetric weighted average term of
3.23 years.
<PAGE>
As of December 31, 1997, the notional amount of these hedges was 8.1 million
MWh's of electricity and 10.3 million MMBTU's of natural gas. No gains or
losses have been explicitly deferred with respect to these transactions. The
estimated fair value of the financial instrument hedges was not material as
of December 31,1997.
The Company's discontinued operations is also a party to firm transportation
contracts which require the Company to make specified minimum payments. At
December 31, 1997, the estimated aggregate amount of such payments were $2.3
million, $1.1 million, $.9 million, $.7 million and $.6 million for 1998
through 2002, respectively, and $1.4 million for later years.
25
<PAGE>
NOTE 4 - BIG RIVERS ELECTRIC CORPORATION LEASE
On June 9, 1997, certain subsidiaries of the Company entered into a
Participation Agreement with Big Rivers Electric Corporation (Big Rivers),
setting forth the detailed parameters of the proposed 25-year lease by
Company affiliates of the generation assets of Big Rivers as part of the
confirmation of Big Rivers' Plan of Reorganization by the U.S. Bankruptcy
Court. The Company made initial filings seeking regulatory approvals from
the Kentucky Public Service Commission on June 30, 1997.
On April 30, 1998, the Kentucky Public Service Commission (the "Kentucky
Commission") issued an order approving, in principle, the proposed 25-year
lease by certain subsidiaries of the Company of the generating assets of Big
Rivers as generally set forth in a Participation Agreement dated April 6,
1998 among the parties. In connection with an earlier November 1997 order of
the Kentucky Commission, the Participation Agreement also contains an
agreement by affiliates of the Company to assume, effective with the overall
proposed transaction, responsibility for certain future environmental,
legislative and regulatory costs associated with the Big Rivers generating
facilities and the loads of certain industrial customers. Final Kentucky
Commission approvals were received on July 14, 1998, and final Federal Energy
Regulatory Commission (FERC) approval was received on July 8, 1998.
On July 15, 1998, the Company closed the transaction to lease the generating
assets of Big Rivers. See Management's Discussion and Analysis - Recent
Events, above. Future minimum payments under the lease agreement follow
(amounts in thousands of dollars).
<TABLE>
<CAPTION>
<S> <C>
1998 $ --
1999 --
2000 15,481
2001 30,962
2002 30,962
Thereafter 619,240
---------
Total $696,645
---------
---------
</TABLE>
The Company paid the first two years' rent to Big Rivers at closing. The
above table does not include this payment, which totaled $55.9 million.
26
<PAGE>
See Item 1, Business, of Part I of the Company's Annual Report on Form 10-K
for the year ended December 31, 1997.
NOTE 5 - UTILITY RATES AND REGULATORY MATTERS
Accounting for the regulated utility business 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 and the Virginia Commission. LG&E and KU are 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. LG&E's and KU's current or 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 consolidated balance sheets as of
December 31 (in thousands of $):
<TABLE>
<CAPTION>
1997 1996
---------- -----------
<S> <C>
Unamortized loss on bonds $ 28,454 $ 28,000
Merger costs 7,000 --
Manufactured gas sites 3,263 3,244
Unamortized extraordinary retirements -- 4,087
Other 955 3,929
---------- -----------
Total regulatory assets 39,672 39,260
Deferred income taxes - net (116,406) (131,675)
---------- -----------
Regulatory assets and liabilities - net $ (76,734) $ (92,415)
---------- -----------
---------- -----------
</TABLE>
During 1997, LG&E wrote off certain previously deferred assets that amounted to
approximately $4.2 million. Items written off include expenses associated with
LG&E's hydro-electric plant, a management audit fee, and the accelerated
write-off of losses on early retirement of facilities.
27
<PAGE>
ENVIRONMENTAL COST RECOVERY.
LG&E. In April 1995, in response to an application filed by LG&E, the
Commission approved, with modifications, an environmental cost recovery
surcharge that increased electric revenues by $3.2 million in 1995, an
additional $2.4 million in 1996, and an additional $.4 million in 1997.
An appeal of the Commission's April 1995 order by various intervenors in the
proceeding (including the Kentucky Attorney General) is currently pending in
the Franklin Circuit Court of Kentucky. LG&E is contesting the legal
challenges to the surcharge, but cannot predict the outcome of the appeal.
In a similar proceeding involving appeals from the Commission's order
authorizing an environmental cost recovery surcharge for KU Company by the
same intervenors, the Kentucky Court of Appeals, in a decision issued on
December 5, 1997, upheld the constitutionality of the surcharge statute. The
intervenors have petitioned the Kentucky Supreme Court to review the decision
of the Kentucky Court of Appeals. Any refunds that may be ordered as a
result of these proceedings are not expected to have a material adverse
effect on the Company's financial position or results of operations. See
Rates and Regulation under Management's Discussion and Analysis for a further
discussion.
KU. Since August 1994, KU has been collecting an environmental surcharge
from its Kentucky retail customers under a Kentucky statute which authorizes
electric utilities (including KU) to implement, beginning January 1, 1993, an
environmental surcharge. The surcharge is designed to recover certain
operating and capital costs of compliance with federal, state or local
environmental requirements associated with the production of energy from
coal, including the Federal Clean Air Act as amended. KU's environmental
surcharge was approved by the Commission in July 1994 and was implemented in
August 1994. The total surcharge collections from August 1, 1994 through
December 31, 1997 were approximately $60 million.
The Commission's order approving the surcharge and the constitutionality of
the surcharge statute were challenged in the Franklin County (Kentucky)
Circuit Court (Circuit Court) in an action brought against KU and the
Commission by the Attorney General of Kentucky and joined by representatives
of consumer groups. In July 1995, the Circuit Court entered a judgment
upholding the constitutionality of the surcharge statute, but vacating that
part of the Commission's July 1994 order which the Circuit Court's judgment
described as retroactively applying the surcharge statute. The Circuit Court
further ordered the case remanded to the Commission for a determination in
accordance with the judgment. KU and the Commission argued that the
Commission's July 1994 order did not retroactively apply the statute.
The Kentucky Attorney General and other consumer representatives appealed to
the Kentucky Court of Appeals (Court of Appeals) that part of the Circuit
Court judgment upholding the constitutionality of the surcharge statute. The
Commission and KU appealed that part of the judgment concerning the
retroactive application of the surcharge statute. The Commission has ordered
all surcharge revenues collected by KU from February 1, 1995, subject to
refund pending final determination of all appeals. The total surcharge
collections from February 1, 1995 through December 31, 1997 were
approximately $56 million.
In December 1997, the Court of Appeals rendered an opinion upholding the
portion of the Circuit Court's judgment regarding the constitutionality of
the surcharge statute but reversing that portion of the Circuit Court's
judgment concerning the claim of retroactive application of the statute.
On June 10, 1998, the Kentucky Supreme Court granted motions for
discretionary review filed by the Kentucky Attorney General and consumer
representation in this matter. Briefs have been filed and oral argument is
scheduled for mid-November 1998.
28
<PAGE>
KU continues to believe that the constitutionality of the surcharge statute
will be upheld. Although KU cannot predict the outcome of the claim of
retroactive application of the statute, it is the position of KU and the
Commission that the July 1994 Commission order did not retroactively apply
the statute. If the Court of Appeals opinion reversing the Circuit Court's
judgment on the claim of retroactivity is overturned and the Circuit Court's
judgment, as entered, is upheld, KU estimates that the amount it could be
required to refund for surcharge collections through December 31, 1997, from
the implementation of the surcharge would be approximately $15 million, and
from February 1, 1995, would be approximately $13 million. At this time, KU
has not recorded any reserve for refund.
PERFORMANCE-BASED RATEMAKING. On September 30, 1997, the Commission issued an
order approving LG&E's request to implement an experimental performance-based
ratemaking mechanism. This mechanism, which only applies to gas procurement
activities and gas off-system sales, was approved for a three-year test
period effective October 1, 1997. During the experimental period, rate
adjustments related to this mechanism will be determined for each 12-month
period beginning November 1 and ending October 31. This mechanism is not
expected to have a material effect on LG&E's financial position or results of
operations.
FUTURE RATE REGULATION. In its September 12, 1997 order approving the merger
of LG&E Energy Corp. and KU Energy Corporation, the Commission ordered LG&E
and KU to file by the later of the consummation of the merger or September
14, 1998, detailed plans to address the future rate regulation of the
Company. The Commission directed LG&E and KU to indicate in its filing
whether it desired to remain under traditional rate of return regulation or
commence non-traditional regulation. On October 12, 1998, pursuant to an
extension granted by the Kentucky Commission, LG&E and KU submitted parallel
filings proposing performance-based ratemaking systems. The
performance-based ratemaking proposal included financial incentives for LG&E
and KU to develop cost-saving means to provide electricity to customers, who
will also share in such savings. Incentives are also included in the areas
of quality of service and reliability. The PBR proposal has five elements:
replacement of the existing fuel adjustment clause with a cap tied to a
regional index; continued flow-through of certain LG&E and KU joint-dispatch
savings to customers; incentives tied to power plant unit availability
compared to past performance; incentives tied to quality, reliability,
satisfaction and safety performance compared to objective benchmarks; and
flexibility to customize rates and services according to customer needs,
subject to an obligation to offer standard tariff service and subject to the
condition that rates must exceed marginal cost. The proposal remains subject
to approval by the Kentucky Commission.
KENTUCKY PSC ADMINISTRATIVE CASE FOR AFFILIATE TRANSACTIONS. The Kentucky
Commission has opened Administrative Case No. 369 to lay ground work for
Commission policy addressing cost allocations, affiliate transactions, and
codes of conduct governing the relationship between utilities and their
non-regulated operations and affiliates. The Commission stated in its
December 19, 1997, order it intends to address two major areas in the
proceedings: the tools and conditions needed to prevent cost shifting and
cross-subsidization between regulated and non-regulated operations; and
whether a code of conduct should be established to assure that non-regulated
segments of the holding company are not engaged in practices which result in
unfair competition caused by cost shifting from the non-regulated affiliate
to the utility. Management does not expect the ultimate resolution of this
matter to have a material adverse effect on the Company's financial position
or results of operations.
NOTE 6 - FINANCIAL INSTRUMENTS
At December 31, 1997, the Company held U.S. Treasury note and bond futures
contracts with notional amounts totaling $4.7 million. These contracts are
used to hedge price risk associated with certain marketable securities and
mature in March 1998.
As of December 31, 1997, LG&E had in effect one interest rate swap agreement
to hedge its exposure to tax
29
<PAGE>
exempt rates related to Pollution Control Bonds, Variable Rate Series. The
swap has a notional amount of $15 million and it matures in September 1999.
The Company paid a fixed rate on the swap of 4.74% in 1997, 1996, and 1995
and received a variable rate based on the JJ Kenny Index of 3.66% in 1997,
3.46% in 1996, and 3.87% in 1995. In addition, LG&E had entered into three
other tax exempt interest rate swaps that became effective in February 1998.
The notional amount of each of these is $17 million, and they mature in
February 2001, 2003, and 2005. The swap agreements call for LG&E to pay
fixed rates averaging 4.184%, and to receive a variable rate based on the PSA
Municipal Bond Index.
Capital Corp. had two interest rate swaps at year end 1997 which hedge a
portion of its notes payable. One swap with a notional amount of $25 million
matured on January 30, 1998. The other has a notional amount of $50 million
and matures in June 2002. Both of these require the Company to pay a fixed
rate which averaged 6.28% at December 31, 1997. The Company receives
variable rates based on the three-month London Interbank offered rate which
equaled 5.885% at year end.
Capital Corp. also entered into a forward starting interest-rate swap to
hedge a portion of its initial issuance of medium term notes (see Note 16,
Long-Term Debt). The notional amount of the swap was $100 million, its
effective date was February 3, 1998, and its maturity date was February 2008.
The swap required Capital Corp. to pay a fixed rate of 6.5813%, and Capital
Corp. was to receive the six-month London Interbank offered rate. The swap
was terminated in conjunction with the pricing and sale of the medium term
notes on February 3, 1998.
On April 3, 1998, LG&E entered into a forward-starting interest-rate swap
with a notional amount of $83.3 million. The swap will hedge anticipated
variable-rate borrowing commitments. It will start in August 2000 and mature
in November 2020. LG&E will pay a fixed rate of 5.21% and receive a variable
rate based on the Bond Market Association Municipal Swap Index. Under
certain conditions, the counterparty to the agreement may terminate the swap
at no cost after August 2010.
On September 1998, LG&E entered into two interest-rate swaps with notional
amounts totaling $100 million. The swaps hedge anticipated variable-rate
borrowing commitments. They started in September 1998 and mature in
September 2001. LG&E will pay a fixed rates of 3.66% and 3.56% and receive a
variable rate based on the Bond Market Association Municipal Swap Index.
In October 1998, Capital Corp. entered into two interest-rate swaps with
notional amounts totaling $150 million. The swaps will hedge anticipated
variable-rate borrowing commitments. They will start on October 30, 1998,
and mature in October 2001. Capital Corp. will pay a fixed rate of 5.158% on
the swaps and receive a variable rate based on the three-month London
Interbank offered rate.
In October 1998, Capital Corp. entered into an interest-rate swap with a
notional amount of $50 million. The swaps will hedge outstanding commercial
paper. The swap started on October 1, 1998, and matures in January 2000.
Capital Corp. will pay a fixed rate of 4.78% on the swaps and receive a
variable rate based on the one-month commercial paper - H15 index.
In September 1998, Capital Corp. sold an option for $3.9 million. The option
will hedge synthetic put bonds that Capital Corp. will issue in the fourth
quarter of 1998. The option has a notional amount of $150 million. The
option grants the buyer the right, but not the obligation, to receive a
payment based on the difference between (1) the present value on the exercise
date of a 5% ten-year bond discounted using the then-current yield on a
10-year U.S. Treasury bond and (2) the fair value on the exercise date of a
10-year U.S. Treasury bond. The option expires in October 2001.
The cost and estimated fair values of the Company's non-trading financial
instruments (excluding the fair values of the Company's discontinued
operations financial instruments) as of December 31, 1997 and 1996 follow (in
thousands of $):
<TABLE>
<CAPTION>
1997 1996
---------------------- ---------------------
Fair Fair
Cost Value Cost Value
--------- ---------- --------- ---------
<S> <C> <C> <C> <C>
Marketable securities $ 21,994 $ 22,300 $ 5,539 $ 5,815
Long-term investments:
Not practicable to estimate
fair value 3,983 3,983 4,156 4,156
Preferred stock subject
to mandatory redemption 25,000 26,250 25,000 24,938
Long-term debt 1,210,690 1,266,030 1,193,208 1,249,721
U.S. Treasury note and
bond futures -- (81) -- 10
Interest rate swaps -- (4,328) -- (192)
</TABLE>
All of the above valuations reflect prices quoted by exchanges except for the
swaps and the long-term investments. The fair values of the swaps reflect price
quotes from dealers or amounts calculated using accepted pricing models. The
fair values of the long-term investments reflect cost, since the Company cannot
reasonably estimate fair value.
NOTE 7 - CONCENTRATIONS OF CREDIT AND OTHER RISK
Credit risk represents the accounting loss that would be recognized at the
reporting date if counterparties 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.
30
<PAGE>
LG&E's customer receivables and gas and electric revenues arise from deliveries
of natural gas to approximately 284,000 customers and electricity to
approximately 356,000 customers in Louisville and adjacent areas in Kentucky.
KU's customer receivables and revenues arise from deliveries of electricity to
about 441,200 customers in over 600 communities and adjacent suburban and rural
areas in 77 counties in central, southeastern and western Kentucky and to about
29,000 customers in 5 counties in southwestern Virginia. For the year ended
December 31, 1997, 85% of total utility revenue was derived from electric
operations and 15% from gas operations.
The Argentine natural gas distribution companies serve 675,000 customers in six
provinces in Argentina. The financial position and results of operations of the
domestic joint ventures described in Note 8, Investments in Joint Ventures, and
Note 18, Commitments and Contingencies, are dependent upon the continuation of
long-term power sales contracts with neighboring utilities.
LG&E's operation and maintenance employees are members of the International
Brotherhood of Electrical Workers (IBEW) Local 2100 which represents
approximately 60% of LG&E's workforce. LG&E's collective bargaining agreement
with IBEW employees expires in November 1998. KU had approximately 2,060
employees at December 31, 1997, of which about 300 are covered by union
contracts expiring August 1, 1998.
NOTE 8 - INVESTMENTS IN JOINT VENTURES
The Company's investments in joint ventures reflect interests in domestic and
foreign electric power and steam producing plants and one of the Argentine gas
distribution companies. These investments are accounted for using the equity
method.
The fuel type, ownership percentages and carrying amounts of the joint ventures
as of December 31, 1997 are summarized below (in thousands of $):
<TABLE>
<CAPTION>
CARRYING
FUEL TYPE % OWNED AMOUNT
<S> <C> <C> <C>
LG&E Westmoreland - Southampton Coal 50 $ 16,841
LG&E Westmoreland - Altavista Coal 50 12,734
LG&E Westmoreland - Hopewell Coal 50 11,493
LG&E Westmoreland - Rensselaer (1) Natural Gas 25(1) 4,742
Westmoreland - LG&E Partners Coal 50 28,462
Windpower Partners 1993 Wind 50 22,198
Windpower Partners 1994 Wind 25 4,251
Central Termica San Miguel de Tucuman, S.A. (2) Natural Gas 33(2) 16,536
KW Tarifa, S.A. Wind 46 5,642
Distribuidora de Gas Cuyana - 14 45,377
Tenaska III Partners, Ltd. Gas 15 1,740
Tenaska Washington Partners, L.P. Gas 5 2,676
Tenaska Washington Partners II, L.P. (3) Gas 10 (297)
Tenaska IV Texas Partners, Ltd. Gas 10 4,611
--------
Total $177,006
--------
--------
</TABLE>
(1) As more fully discussed below, this amount reflects the sale of
one-half of the Company's interest in the project as of December
31, 1997. Pursuant to a settlement among the parties, LG&E
reacquired a 50% interest in the project during the second quarter
of 1998.
(2) As discussed below, the Company's interest in this project was
sold in February 1998.
(3) Construction suspended.
31
<PAGE>
The Company's carrying amount exceeded the underlying equity in joint
ventures by $30.4 million and $25.3 million at December 31, 1997, and 1996,
respectively. This difference, which is being amortized, represents
adjustments to reflect the fair value of the underlying net assets acquired
and related goodwill.
With respect to the first seven projects listed above, certain of the Company's
partners (or affiliates of such partners) are in bankruptcy proceedings. Also,
the Tenaska Washington Partners II project is the subject of a breach of
contract claim filed by the Company's partner on the project against the
Bonneville Power Administration. See Note 18, Commitments and Contingencies.
In December 1997, the Company agreed to sell one-half of its interest in the
partnership that owns the Rensselaer facility. The Company recorded a pre-tax
gain of $4.8 million in 1997 related to the agreement, and it retained a 25%
ownership interest in the partnership.
On June 30, 1998, the partnership that owns the facility, along with 14 other
independent power producers, participated in the consummation of a Master
Restructuring Agreement (MRA) with Niagara Mohawk Power Corporation (NIMO), the
purchasing utility. As part of the MRA, the partnership restructured its power
purchase agreement with NIMO and entered into a multi-year agreement with the
utility. Substantial amounts of the gross proceeds received by the partnership
from NIMO were used to repay outstanding project debt and financial obligations
as well as termination payments to the project's steam host, fuel suppliers,
fuel transporters and other service providers.
As a result of a settlement among the parties, the Company will retain a 50%
ownership interest in the partnership. Consequently, the Company received
one-half of the partnership's net receipts related to the MRA, less amounts
retained by the partnership for operating needs and amounts relating to the
terminated sale transaction. The Company recorded an after-tax gain of $21
million in connection with the closing of the MRA transaction. The Company
recognized this gain on the MRA transaction in the second quarter of 1998.
In February 1998, the Company sold its indirect, one-third interest in the
company which owned and operated the San Miguel facility to Pluspetrol Resources
Corporation and ASTRA Compania Argentina de Petroleo S.A. for a price of $16
million. The Company's net book value in the San Miguel project as of December
31, 1997 was approximately $18.8 million.
In June 1995, Babcock-Ultrapower West Enfield and Babcock-Ultrapower Jonesboro,
two partnerships which were 17%-owned by LPI, sold power purchase contracts to
Bangor Hydro-Electric Company. Equity in Earnings of Joint Ventures in the
Company's Statement of Income for 1995 includes $9.7 million representing LPI's
interest in the gains on the sales. In October 1996, the plants were sold to a
third party and the Company's interests in the partnerships were liquidated.
NOTE 9 - LEVERAGED LEASES
KU Capital owns equity interests in several leveraged leases for combustion
turbine units leased to utility companies. The leases expire in 1999. KU
Capital's equity investment represents 75% of the aggregate purchase price of
the leases. The remaining 25% represents the nonrecourse debt provided by
lenders at the inception of the leases in 1974. The lenders have been granted,
as their sole remedy in the event of default by the lessees, an assignment of
rentals due under the leases and a security interest in the leased properties.
32
<PAGE>
The following is a summary of the components of KU Capital's net investment in
leveraged leases at December 31 (in thousands in $):
<TABLE>
<CAPTION>
1997 1996
---- ----
<S> <C> <C>
Rents receivable (net of nonrecourse debt) $ 3,039 $ 3,511
Estimated residual value of leased property 32,707 32,707
Less: unearned and deferred income 7,594 11,568
--------- --------
Investment in leveraged leases 28,152 24,650
Less: accumulated deferred income taxes 5,750 4,219
--------- --------
Net investment in leveraged leases $22,402 $20,431
--------- --------
--------- --------
</TABLE>
The following is a summary of the components of income from leveraged leases
(in thousands of $):
<TABLE>
<CAPTION>
1997 1996 1995
---- ---- ----
<S> <C> <C> <C>
Income before income taxes $3,974 $3,613 $3,306
Income tax expense 1,751 1,890 1,286
------- ------- -------
Income from leveraged leases $2,223 $1,723 $2,020
------- ------- -------
------- ------- -------
</TABLE>
NOTE 10 - NON-RECURRING CHARGES
Under certain agreements with Tenaska, Inc., a developer of domestic gas-fired
cogeneration and independent power generation projects, the Company has been
funding a portion of the costs associated with identifying and pursuing
potential independent power projects in North America. Such funding, which was
expensed as incurred, totaled about $1 million in 1997. In 1996, the Company
wrote off $5.5 million of costs funded during 1994-1996 that was associated with
unsuccessful projects. The Company's remaining funding commitment over the next
several years totals $3.6 million.
NOTE 11 - MARKETABLE SECURITIES
The Company's marketable securities have been determined to be
"available-for-sale" under the provisions of Statement of Financial Accounting
Standards SFAS No. 115, Accounting for Certain Investments in Debt and Equity
Securities. Proceeds from sales of available-for-sale securities in 1997 were
approximately $5 million, which resulted in immaterial realized gains and
losses. Proceeds from sales of available-for-sale securities in 1996 were
approximately $44.6 million, which resulted in realized gains of approximately
$.5 million and losses of approximately $1.4 million, calculated using the
specific identification method.
33
<PAGE>
Approximate cost, fair value, and other required information pertaining to the
Company's available-for-sale securities by major security type as of December
31, 1997 and 1996, follow (in thousands of $):
<TABLE>
<CAPTION>
FIXED
EQUITY INCOME TOTAL
<S> <C> <C> <C>
1997:
Cost $6,379 $15,615 $21,994
Unrealized gains 445 18 463
Unrealized losses (90) (67) (157)
---------- ---------- ---------
Fair values $6,734 $15,566 $22,300
------- ------- -------
------- ------- -------
Fair values:
No maturity $6,734 $ 114 $ 6,848
Contractual maturities:
Less than one year - 8,795 8,795
One to five years - 5,442 5,442
Five to ten years - - -
Over ten years - 1,215 1,215
Not due at a single maturity date - - -
------- ------- -------
Total fair values $6,734 $15,566 $22,300
------- ------- -------
------- ------- -------
1996:
Cost $4,833 $706 $5,539
Unrealized gains 2,109 - 2,109
Unrealized losses (1,789) (44) (1,833)
------- ------- -------
Fair values $5,153 $662 $5,815
------- ------- -------
------- ------- -------
Fair values:
No maturity $4,255 $ - $ 4,255
Contractual maturities:
Less than one year 898 - 898
One to five years - - -
Five to ten years - - -
Over ten years - 662 662
Not due at a single maturity date - - -
------- ------- -------
Total fair values $5,153 $662 $5,815
------- ------- -------
------- ------- -------
</TABLE>
NOTE 12 - PENSION PLANS AND RETIREMENT BENEFITS
PENSION PLANS. The Company has three non-contributory, defined-benefit pension
plans that cover eligible employees of LG&E Energy Corp. corporate staff, LG&E
and KU. Retirement benefits are based on the employee's age at retirement,
years of service, and compensation. The Company's policy is to fund annual
actuarial costs up to the maximum amount deductible for income tax purposes.
The assets of the plans consist primarily of common stocks, corporate bonds,
investments in international mutual funds and United States government
securities.
The Company also has supplemental executive retirement plans that cover eligible
officers of the Company. The plans provide retirement benefits based on average
earnings during the final three or five 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 mentioned in the
preceding paragraph.
On May 20, 1997, KU Energy and LG&E Energy entered into a Merger Agreement. For
information
34
<PAGE>
concerning the agreement, see Note 2. Under the provisions of KU
Energy's supplemental executive retirement plan, the Merger Agreement
constituted a change-in-control which required that a lump sum present value
payment be made to retired employees entitled to retirement benefits on the date
of the Merger Agreement. On May 30, 1997, lump sum payments totaling $4.7
million were made to retired KU Energy employees.
The components of periodic pension expense are shown below (in thousands of $):
<TABLE>
<CAPTION>
1997 1996 1995
----- ------ -----
<S> <C> <C> <C>
Service cost-benefits earned during the period $ 12,675 $ 11,965 $ 10,865
Interest cost on projected benefit obligation 32,927 31,132 28,321
Actual return on plan assets (80,789) (53,048) (73,171)
Amortization of transition asset (1,079) (1,079) (1,079)
Net amortization and deferral 46,765 22,458 47,996
Regulatory effect recorded (261) (1,835) (1,595)
----------- ----------- ----------
Net pension cost $ 10,238 $ 9,593 $ 11,337
----------- ----------- ----------
----------- ----------- ----------
</TABLE>
The funded status of the pension plans at December 31 is shown below (in
thousands of $):
<TABLE>
<CAPTION>
1997 1996
------ -----
<S> <C> <C>
Actuarial present value of
accumulated plan benefits:
Vested $379,598 $329,593
Non-vested 31,638 24,481
-------- ---------
Accumulated benefit obligation 411,236 354,074
Effect of projected future compensation 87,907 78,477
-------- ---------
Projected benefit obligation 499,143 432,551
Plan assets at fair value 501,286 432,511
-------- ---------
Plan assets (less than) in excess of
projected benefit obligation 2,143 (40)
Unrecognized net transition asset (9,009) (10,088)
Unrecognized prior service cost 48,064 49,054
Unrecognized net gain (80,395) (77,457)
Unrecognized net asset (1,350) (1,500)
Regulatory effect recorded 462 201
-------- ---------
Accrued pension liability $(40,085) $(39,830)
-------- ---------
-------- ---------
</TABLE>
The assumptions used in determining the actuarial valuations are as follows:
<TABLE>
<CAPTION>
1997 1996
----- -----
<S> <C> <C>
Assumed discount rate to determine
projected benefit obligation 7.00% 7.75%
Assumed long-term rate of return
on plan assets 8.25% - 8.50% 8.25% - 8.50%
Assumed annual rate of increase in
future compensation levels 2.00% - 4.00% 2.00% - 4.75%
</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, except for KU
Energy employees who retired before 1993. These pre-1993 retirees are not
required to contribute to the plan. The Company accrues for the expected cost
of post-retirement benefits other than
35
<PAGE>pensions during the employee's years of service with the Company. The
discounted present value of the post-retirement benefit obligation is being
amortized over 20 years.
Post-retirement benefit costs are shown below (in thousands of $):
<TABLE>
<CAPTION>
1997 1996 1995
<S> <C> <C> <C>
Service cost $ 2,633 $ 2,662 $ 2,532
Interest cost 7,860 7,745 7,643
Actual return on assets (3,649) (1,633) (1,722)
Amortization of transition obligation 4,682 4,682 4,682
Net amortization and deferral 1,966 435 792
-------- -------- --------
Post-retirement benefit cost $13,492 $13,891 $13,927
-------- -------- --------
-------- -------- --------
</TABLE>
The accumulated post-retirement benefit obligation at December 31 is shown
below (in thousands of $):
<TABLE>
<CAPTION>
1997 1996
----- -----
<S> <C> <C>
Retirees $ (52,572) $ (47,881)
Fully eligible active employees (13,569) (13,515)
Other active employees (49,753) (45,347)
---------- ---------
Accumulated post-retirement benefit obligation (115,894) (106,743)
Plan assets at fair value 22,192 15,619
Unrecognized prior service cost 3,456 3,788
Unrecognized transition obligation 70,229 74,912
Unrecognized net loss (16,729) (19,529)
---------- ---------
Accrued post-retirement benefit liability $ (36,746) $ (31,953)
---------- ---------
---------- ---------
</TABLE>
The accumulated post-retirement benefit obligation was determined using an
assumed discount rate of 7% for 1997 and 7.75% for 1996. Assumed compensation
increases for projected life insurance benefits for affected groups was 4% for
1997 and 4.25%-4.75% for 1996. An assumed health care cost trend rate of 8%-9%
was assumed for 1997, gradually decreasing to 4.25% in nine years and
thereafter.
A 1% increase in the assumed health care cost trend rate would increase the
accumulated post-retirement benefit obligation by approximately $11.5 million
and the annual service and interest cost by approximately $1.9 million. In
1996, the Company (excluding KU Energy) began funding certain liabilities for
post-retirement benefits through a tax-deductible funding vehicle. KU Energy
began similar funding in 1993. The plan assets are being held in two voluntary
employee benefit association (VEBA) trusts and are invested primarily in
short-term United States government securities, mutual funds and cash.
THRIFT SAVINGS PLANS. The Company has Thrift Savings Plans under Section 401(k)
of the Internal Revenue Code. Under these plans, eligible employees may defer
and contribute to the plans a portion of current compensation in order to
provide future retirement benefits. The Company makes contributions to the
plans by matching a portion of employee's contributions. These costs were
approximately $4.7 million for 1997, $4.2 million for 1996, and $4.3 million for
1995.
36
<PAGE>
NOTE 13 - INCOME TAXES
Components of income tax expense are shown in the table below (in thousands
of $):
<TABLE>
<CAPTION>
1997 1996 1995
---- ---- ----
<S> <C> <C> <C>
Included in Income Taxes:
Current - federal $ 88,654 $ 52,018 $56,054
- foreign 9,055 - -
- state 19,574 1,725 8,328
Deferred - federal - net 9,024 36,848 22,507
- state - net 1,292 18,741 8,242
Deferred investment tax credit 102 409 (71)
Amortization of investment tax credit (8,378) (8,419) (8,766)
-------- ------- -------
Total $119,323 $101,322 $86,294
-------- ------- -------
-------- ------- -------
</TABLE>
Net deferred tax liabilities resulting from book-tax temporary differences are
shown below (in thousands of $):
<TABLE>
<CAPTION>
1997 1996
---- ----
<S> <C> <C>
Deferred tax liabilities:
Depreciation and other
plant-related items $670,540 $649,302
Other liabilities 43,199 32,093
-------- --------
713,739 681,395
-------- --------
Deferred tax assets:
Investment tax credit 78,959 82,935
Income taxes due to customers 26,357 31,195
Deferred income 11,878 13,430
Accrued expenses not currently
deductible and other 48,068 49,449
-------- --------
165,262 177,009
-------- --------
Net deferred income tax liability $548,477 $504,386
-------- --------
-------- --------
</TABLE>
Directly related to discontinued operations are $122 million of tax net
operating loss carryforwards at December 31, 1997. These carryforwards, which
expire in 1998 through 2009, are subject to an annual limitation of
approximately $6 million under Sections 382 and 383 of the Internal Revenue
Code, and realization is dependent upon generating sufficient taxable income
prior to their expiration. At both December 31, 1997 and 1996, the Company
recorded valuation allowances of $25.6 million, related to these deferred tax
assets. Unamortized goodwill will be reduced if unrecorded net operation loss
carryforwards are realized.
A reconciliation of differences between the statutory U.S. federal income tax
rate and the Company's effective income tax rate as a percentage of income from
continuing operations before income taxes and preferred dividends follows:
<TABLE>
<CAPTION>
1997 1996 1995
---- ---- ----
<S> <C> <C> <C>
Statutory federal income tax rate 35.0 % 35.0 % 35.0 %
State income taxes net of federal benefit 3.9 4.7 4.9
Effect of foreign operations including foreign tax credit 1.1 - -
Investment and other tax credits (3.1) (3.6) (4.0)
Reduction of taxes provided in prior years (.1) (1.7) (.7)
Other differences - net (1.0) (.5) (1.3)
----- ----- -----
Effective income tax rate 35.8 % 33.9 % 33.9 %
----- ----- -----
----- ----- -----
</TABLE>
37
<PAGE>
NOTE 14 - OTHER INCOME AND DEDUCTIONS
Other income and deductions consisted of the following at December 31
(in thousands of $):
<TABLE>
<CAPTION>
1997 1996 1995
---- ---- ----
<S> <C> <C> <C>
Gains (losses) on securities - net $ 68 $ (950) $ (3,465)
Income from leveraged leases 3,974 3,613 3,306
Interest and dividend income 10,159 8,765 14,309
Gain on sale of investment in Rensselaer joint venture 4,800 - -
Gain on sale of stock options 1,794 - -
Interest on income tax settlement 1,446 - -
Gains (losses) on fixed asset disposals - net 489 51 1,330
Donations (811) (740) (700)
Other (949) 836 529
--------- -------- --------
Total other income and (deductions) $ 20,970 $ 11,575 $ 15,309
--------- -------- --------
--------- -------- --------
</TABLE>
NOTE 15 - CAPITAL STOCK
Changes in shares of common stock outstanding are shown in the table below (in
thousands). The amounts in the table reflect the merger-related exchange of
1.67 share of LG&E Energy common stock for each share of KU Energy common stock.
<TABLE>
<CAPTION>
1997 1996 1995
---- ---- ----
<S> <C> <C> <C>
Outstanding January 1 129,497 129,351 129,188
Issues under the Employee
Common Stock Purchase
Plan (1997, $1,613;
1996, $1,457; 1995, $1,354) 77 77 80
Issues under the Omnibus
Long-Term Incentive Plan
(1997, $2,195; 1996, $1,167;
1995, $1,371) 109 69 83
------- ------- -------
Outstanding December 31 129,683 129,497 129,351
------- ------- -------
------- ------- -------
</TABLE>
The Company's shareholders approved an increase in the Company's authorized
shares of common stock from 125,000,000 to 300,000,000 on October 14, 1997 in
conjunction with the merger with KU Energy. This increase occurred at the time
of consummation of the merger.
The Company has an Omnibus Long-Term Incentive Plan, under which nonqualified
stock options, performance units and stock appreciation rights have been granted
to key personnel. A total of 2,699,250 shares of common stock had been reserved
for issuance under the plan at December 31, 1997. Performance units are paid
out on a three-year rolling basis in 50% stock and 50% cash based on Company
performance. Directors of the Company receive stock options pursuant to the
Stock Option Plan for Non-Employee Directors. A total of 500,000 shares of
common stock had been reserved for issuance under this plan at December 31,
1997. Each option entitles the holder to acquire one share of the Company's
stock no earlier than one year from the date granted. The options are granted
at market value and generally expire 10 years from the date granted. Although
shares are reserved as described above, the Company announced a repurchase
program on October 14, 1997, authorizing the repurchase of up to 1,000,000
shares of its common stock to be used for, among other things,
38
<PAGE>
benefit and compensation plans, including the Omnibus Long-Term Incentive Plan.
A summary of the status of the Company's nonqualified stock options follows:
<TABLE>
<CAPTION>
Outstanding Exercisable
----------- -----------
Weighted Weighted
Average Average
Options Price Options Price
------- ----- ------- -----
<S> <C> <C> <C> <C>
As of December 31, 1994 484,528 $17.34 256,582 $15.78
Options granted and
exercisable 150,690 19.70 137,946 19.27
Options exercised (60,522) 15.48 (60,522) 15.48
Options cancelled (61,146) 19.07 (1,620) 19.30
-------- ------ -------- ------
As of December 31, 1995 513,550 18.04 332,386 17.26
Options granted and
exercisable 415,348 21.24 158,914 19.57
Options exercised (48,226) 17.26 (48,226) 17.26
Options cancelled (16,328) 21.01 - -
-------- ------ -------- ------
As of December 31, 1996 864,344 19.57 443,074 18.09
Options granted and
exercisable 394,945 24.15 352,966 21.22
Options exercised (87,568) 18.97 (87,568) 18.97
Options cancelled (77,100) 23.04 - -
-------- ------ -------- ------
As of December 31, 1997 1,094,621 $21.01 708,472 $19.54
-------- ------ -------- ------
-------- ------ -------- ------
</TABLE>
Common stock equivalents resulting from the options granted under both the
Long-Term Plan and the Directors' Plan would not have a material dilutive
effect on reported earnings per share.
The Company has a Shareholders Rights Plan designed to protect shareholders'
interests in the event the Company is ever confronted with an unfair or
inadequate acquisition proposal. Pursuant to the plan, each share of common
stock has one-third of a "right" entitling the holder to purchase from the
Company one one-hundredth of a share of new preferred stock of the Company
under certain circumstances. The holders of the rights will, under certain
conditions, also be entitled to purchase either shares of common stock of
LG&E Energy Corp. or common stock of the acquirer at a reduced percentage of
market value. The rights will expire in the year 2000.
In December 1997, Inversora de Gas del Centro (Inversora), a subsidiary of
the Company that holds part of the Company's interest in Centro, issued
302,364 shares of preferred stock to unaffiliated parties. The stock has a
nominal value of $10 per share, and a variable dividend consisting of 5% of
Inversora's annual net income. Inversora can redeem the shares at the
nominal value upon shareholder approval.
KU's 6.53% series preferred stock is not redeemable prior to December 1,
2003. After that date, holders can redeem shares at $103.265 through November
30, 2004, decreasing approximately $.33 each twelve months thereafter to $100
on or after December 1, 2013.
39
<PAGE>
NOTE 16 - LONG-TERM DEBT
Annual requirements for the sinking funds of LG&E's First Mortgage Bonds
(other than the First Mortgage Bonds issued in connection with certain
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
LG&E to apply property additions to meet 1998 sinking fund requirements of
the First Mortgage Bonds.
The trust indenture securing LG&E's First Mortgage Bonds constitutes a direct
first mortgage lien upon a substantial portion of all property owned by LG&E.
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 (LG&E Projects) issued by Jefferson and Trimble
Counties, Kentucky, are secured by the assignment of loan payments by LG&E to
the Counties pursuant to loan agreements, and certain series are further
secured by the delivery from time to time of an equal amount of LG&E'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 November 1997, LG&E issued $35 million of Jefferson County, Kentucky and
$35 million of Trimble County, Kentucky, Pollution Control Bonds, Flexible
Rate Series, due November 1, 2027. Interest rates for these bonds were 3.90%
and 3.85%, respectively, at December 31, 1997. The proceeds from these bonds
were used to redeem the outstanding 7.75% Series of Jefferson County,
Kentucky and Trimble County, Kentucky, Pollution Control Bonds due February
1, 2019.
In October 1996, LG&E issued $22.5 million of Jefferson County, Kentucky, and
$27.5 million of Trimble County, Kentucky, Pollution Control Bonds, Flexible
Rate Series, due September 1, 2026. Interest rates for these bonds were
3.79% and 3.82%, respectively, as of December 31, 1997. In December 1996,
the proceeds from the bonds were used to redeem the outstanding 7.25% Series
of Jefferson County and Trimble County Pollution Control Bonds due December
1, 2016.
On June 1, 1996, LG&E's First Mortgage Bonds, 5.625% Series of $16 million
matured and were retired by the Company.
LG&E's First Mortgage Bonds, 6.75% Series of $20 million is scheduled to
mature in June 1998, and the $20 million, 7.5% Series is scheduled for
maturity in 2002. There are no scheduled maturities of Pollution Control
Bonds for the five years subsequent to December 31, 1997. The Company has no
cash sinking fund requirements.
Under the provisions for the KU's variable rate Pollution Control Series 10
Bonds, KU can choose between various interest rate options. The daily
interest rate option was utilized at December 31, 1997. The average annual
interest rate on the bonds during 1997 and 1996 was 3.77% and 3.53%,
respectively. The variable rate bonds are subject to tender for purchase at
the option of the holder and to mandatory tender for purchase upon the
occurrence of certain events. If tendered bonds are not remarketed, KU has
available lines of credit which may be used to repurchase the bonds.
In January 1996, KU issued $36 million of Series S First Mortgage Bonds which
bear interest at 5.99% and will
40
<PAGE>
mature January 15, 2006. The proceeds were used to redeem $35.5 million of
Series K First Mortgage Bonds which carried a rate of 7-3/8%.
Substantially all of KU's utility plant is pledged as security for its first
mortgage bonds.
Capital Corp. has established a $500 million medium-term note program. On
February 6, 1998, Capital Corp. issued $150 million of medium-term notes due
in January 2008. The securities were issued pursuant to an unregistered Rule
144A offering. The stated interest rate on the notes was 6.46%. After
taking into account the effects of an interest-rate swap entered into in 1997
to hedge the interest rate on $100 million (See Note 6, Price Risk Management
and Financial Instruments) and other issuance costs, the effective rate will
be 6.82%. The proceeds were used to repay outstanding notes payable.
Centro maintains a $100 million global note program. As of December 31,
1997, Centro had outstanding $37.5 million in negotiable obligations, net of
issuance costs, as part of this program. The maturity date of the debt is
August 21, 2001. The fixed annual interest rate is 10.5% payable every six
months.
NOTE 17 - NOTES PAYABLE
On September 5, 1997, Energy Systems and Gas Systems merged to form Capital
Corp. At the same time, Capital Corp. implemented a $600 million commercial
paper facility backed by new lines of credit totaling $700 million. The
Company terminated the previous lines of credit which totaled $460 million.
Capital Corp. had outstanding commercial paper of $360.2 million at December
31, 1997, at a weighted average interest rate of 5.79%. On February 6, 1998,
Capital Corp. issued $150 million of medium-term notes (See Note 16,
Long-Term Debt). The net proceeds were used to repay a portion of the
outstanding commercial paper. The outstanding commercial paper following the
repayment totaled $199.3 million. LG&E Energy Corp., LG&E, and Capital Corp.
had no other notes payable at December 31, 1997. Energy Systems and Gas
Systems had notes payable of $158 million at December 31, 1996, at a weighted
average interest rate of 5.83%.
KU's short-term financing requirements are satisfied through the sale of
commercial paper. KU had outstanding commercial paper of $33.6 million at
December 31, 1997, at a weighted average interest rate of 6.79%.
At December 31, 1997, the Company had lines of credit in place totaling $960
million ($200 million for LG&E, $60 million for KU, and $700 million for
Capital Corp.) for which it pays commitment or facility fees. The LG&E and
KU credit facilities provide for short term borrowing and support of variable
rate Pollution Control Bonds. The Capital Corp. facility provides for short
term borrowing, letter of credit issuance, and support of commercial paper
borrowings. Unused capacity under these lines totaled $541.7 million after
considering the commercial paper support and approximately $58.1 million in
letters of credit securing on- and off-balance sheet commitments. The credit
lines will expire at various times from 1998 through 2002. Management
expects to renegotiate the lines when they expire.
The lenders under the credit facilities, commercial paper program, and medium
term notes for Capital Corp. are entitled to the benefits of Support
Agreements with LG&E Energy Corp. The Support Agreements state, in
substance, that LG&E Energy Corp. will provide Capital Corp. with the
necessary funds and financial support to meet their obligations under the
credit facilities, commercial paper program, and medium term notes.
NOTE 18 - COMMITMENTS AND CONTINGENCIES
CONSTRUCTION PROGRAM
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The Company had commitments, primarily in connection with the construction
programs of LG&E and KU, aggregating approximately $7 million at December 31,
1997. LG&E's construction expenditures for the years 1998 and 1999 are
estimated to total approximately $260 million. KU's construction
expenditures for the same period are estimated to total approximately $200
million. Non-utility construction expenditures for 1998 and 1999 are
estimated to be $55 million.
LETTERS OF CREDIT
Capital Corp. has provided letters of credit issued to third parties to
secure certain off-balance sheet obligations (including contingent
obligations) of its subsidiaries. The letters of credit securing such
obligations totaled approximately $38.3 million and $25.2 million at December
31, 1997 and 1996, respectively. These letters of credit are subject to
Support Agreements as more fully described in Note 17, Notes Payable.
Capital Corp. has provided a guarantee of a lease obligation to a third
party. The obligation totaled $10.2 million and $12.8 million at December 31,
1997 and 1996, respectively.
PROJECT CONTINGENCIES
SOUTHAMPTON. The Southampton plant, a 63-megawatt, coal-fired cogeneration
facility in Franklin, Virginia, supplies process steam to a nearby chemical
manufacturer and bulk electric power under contract to Virginia Electric and
Power Company (Virginia Power) as a qualifying facility (QF) under the Public
Utility Regulatory Policies Act (PURPA). The plant began commercial
operation in 1992. In July 1994, FERC denied the request of
LG&E-Westmoreland Southampton (the Partnership) for a waiver of certain QF
requirements. The Partnership subsequently filed a request seeking a
reversal of FERC's order, or, in the alternative, a clarification of FERC's
order stating that, with the exception of rates, the Partnership remains a QF
for 1992 exempt from regulation as a public utility under PUHCA, utility laws
in Virginia and various portions of the Federal Power Act.
In July 1996, the FERC entered an order in the Southampton case which
included a policy statement regarding all QF facilities which fail
temporarily to meet QF standards. The order affirmed the continued
availability to Southampton of exemptions from PUHCA and state law for the
year 1992, supporting the Partnership's request that the ruling on
non-compliance should have no effect on the exemptions from regulations that
would have classified the plant as a public utility. The FERC's decision to
uphold these exemptions eliminates potential issues involving provisions of
PUHCA, Virginia utility law and the non-rate provisions of the Federal Power
Act.
The FERC also concluded that the Partnership should refund a portion of the
rates it received from Virginia Power during 1992. The Company had
anticipated that the Partnership could be required to make a refund to
Virginia Power in the event the QF standards for 1992 were not waived. The
order calls for a refund with interest from the Partnership of the difference
between the amount paid by Virginia Power during the period and the amount
Virginia Power would have paid for energy if it had purchased energy at its
incremental energy rate. The amount of the refund is currently unknown,
pending further FERC review. In August 1996 the Partnership filed a Request
for Clarification to better understand what the Commission intended and filed
a Request for Rehearing on the grounds that the order violated the statutory
standard for just and reasonable rates. In November 1996, the Partnership
requested FERC approval for the contract rates it charged during the period
of non-compliance minus a $500,000 refund offered by the Partnership.
On May 18, 1998, the FERC issued an order addressing certain issues in this
matter. The order reaffirmed certain exemptions granted Southampton as a QF
for the 1992 period. Regarding the rate refund amount, the FERC order
requires VEPCO to compensate Southampton for every hour in 1992 that the unit
was available for dispatch, whether or not actually dispatched, at VEPCO's
hourly economy energy cost, thus reducing
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Southampton's exposure to refund. FERC also denied Southampton's request for
approval of a $500,000 refund and directed the parties to enter into further
FERC-supervised settlement negotiations regarding calculation of the refund
amount in accordance with the clarifications in the FERC order. Initial
negotiations were held on June 12, 1998, and the supervising FERC judge is
expected to file a report on such negotiations in the third quarter of 1998.
In compliance with the FERC order, Southampton has reached a tentative
settlement with VEPCO which requires future payments from Southampton to
VEPCO. The settlement remains subject to FERC approval. If the settlement
is approved, it is not expected to materially adversely effect the financial
condition of the Company. Pending the outcome of such settlement
negotiations and regulatory approval thereof, as well as any further
potential actions, currently unknown, to be taken by Southampton or VEPCO,
the Company cannot predict the ultimate amount of the settlement or refund,
if any. The Company's share of the revenues received by Southampton in 1992
is approximately $9.5 million and any refund is subject to interest charges.
The Company has also been notified that its partners in the Southampton
partnership are disputing their responsibilities for their share of any
refund and are asserting that the Company should bear full responsibility for
any refund. The Company and partners are currently negotiating these matters.
WESTMORELAND BANKRUPTCY. On December 23, 1996, Westmoreland Coal Company and
its four first-tier subsidiaries filed for reorganization under Chapter 11 of
the U.S. Bankruptcy Code. One of these subsidiaries, Westmoreland Energy,
Inc. is the direct parent of the various entities that are partners in
partnerships with LG&E Energy subsidiaries (including the Partnership and
WLP, as defined herein) which own six independent generating facilities.
None of those partnerships and no partner of those partnerships is under
bankruptcy court protection. It is unclear at this time what effect these
filings will have on the value of the partnerships. Although there is no
current default occasioned by the filings, defaults could occur under project
loan agreements if not remedied within the specified time period. If a
default occurred which was not cured within the allowed time, the lenders
would have the right, among other things, to accelerate the outstanding
loans. These loans, which are non-recourse to the Company above the
partnership level, totaled $596.7 million at December 31, 1997.
ROANOKE VALLEY I. The Company owns a 50% interest in Westmoreland-LG&E
Partners (WLP), the sole owner of Roanoke Valley I, a cogeneration facility
selling electric power to Virginia Power and steam energy to Patch Rubber
Company. Under the Power Purchase Agreement (PPA) between WLP and Virginia
Power, WLP is entitled to receive capacity payments based on availability.
From May 1994 through December 1997, Virginia Power withheld approximately
$14.2 million of these capacity payments during periods of forced outages.
To date, the Company has not realized any income on its 50% portion of the
capacity payments being withheld by Virginia Power.
In October 1994, WLP filed a complaint against Virginia Power in the Circuit
Court of the City of Richmond, Virginia seeking damages of at least $5.7
million, contending that Virginia Power breached the PPA in withholding such
payments. In June 1995, the court denied Virginia Power's motion to dismiss
WLP's complaint. In March 1996, Virginia Power filed a motion for summary
judgment which was subsequently granted by the court as to all counts. WLP
filed a petition for appeal with the Virginia Supreme Court in July 1996, and
in June 1997, the Virginia Supreme Court reversed the adverse lower court
ruling and remanded the case for a trial. A new trial date has been set for
October 26, 1998.
In the Company's opinion, WLP is entitled to recover the capacity payments
withheld by Virginia Power and should prevail in this matter ensuring receipt
of future capacity payments during forced outages billable to Virginia Power
during the remaining 21 years of the PPA. However, the Company is unable to
predict the outcome of this proceeding, or the amount of capacity payments,
if any, which Virginia Power may be ordered to pay to WLP. However, the
Company does not expect the ultimate resolution of this matter to have a
material adverse effect on its results of operations or financial condition.
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<PAGE>
RENSSELAER. In July 1997, LG&E Westmoreland - Rensselaer (LWR), in which the
Company has an interest through an indirect subsidiary, executed a master
restructuring agreement with Niagara Mohawk Power Corporation (NIMO) and
other independent power companies (IPPs). LWR is the owner of the Rensselaer
cogeneration facility. On May 7, 1998, LWR committed to proceed with the
restructuring of the Power Purchase Agreement between NIMO and LWR as
contained in the master restructuring agreement at the ultimate closing of
such agreement, if any, according to the terms and conditions of such
agreement, including satisfaction of certain conditions precedent.
On June 30, 1998, LWR, along with the other independent power producers,
participated in the consummation of the master restructuring agreement with
NIMO. See Note 8, Investments in Joint Ventures, for detailed information
regarding the master restructuring transaction, including amounts received by
the Company in connection with the closing of that transaction.
KENETECH BANKRUPTCY. In May 1996, Kenetech Windpower, Inc. (Kenetech) filed
in the United States Bankruptcy Court in the Northern District of California
for protection under Chapter 11 of the United States Bankruptcy Code seeking,
among other things, to restructure certain contractual commitments between
Kenetech and its subsidiaries, on one hand, and various windpower projects
located in the U.S. and abroad, on the other hand. Included in these
projects are the Windpower Partners 1993 (WPP 93), Windpower Partners 1994
(WPP 94) and KW Tarifa, S.A. (Tarifa) wind projects in which the Company has
invested, collectively, approximately $31 million. As part of the bankruptcy
proceeding, Kenetech is also seeking to void certain warranty commitments
made to the owners of those projects with respect to the operation and output
of the facilities, and the repair and replacement of the windpower generation
equipment located there. LPI has been named to the creditors' committee in
the Kenetech bankruptcy on behalf of the three projects, and has been working
with representatives of Kenetech and other secured and unsecured creditors to
ensure that the project owners' interests are equitably treated in the
bankruptcy. On January 31, 1997, the projects filed their respective breach
of contract and other claims against Kenetech in the bankruptcy proceeding.
In September 1996, LG&E Power Services Inc., an affiliate of the Company,
assumed operating control over the WPP 93 and WPP 94 facilities, pursuant to
Facility Operating Agreements with the owners of those facilities. Those
agreements replaced the interim operations and maintenance agreements between
the owners and Kenetech that were implemented at the time of the Kenetech
bankruptcy filing. The owners of the Tarifa windpower project assumed
operating control over that facility shortly after the bankruptcy filing, and
are considering the merits of retaining a third-party contractor to operate
and maintain these facilities. In November 1996, KW Tarifa, S.A., certain of
its shareholders and an affiliate of the Company, LG&E Power Finance Inc.
(LPF), completed separate Settlement Transactions with affiliates of
Kenetech, whereby the equity interests of Kenetech's affiliate in KW Tarifa
S.A. were purchased by the other shareholders, and certain subordinated
indebtedness of KW Tarifa S.A. to another Kenetech affiliate was purchased by
LPF and subsequently retired by KW Tarifa S.A.
The Company is unable to predict the outcome of the bankruptcy proceeding or
the settlement negotiations. However, the Company does not expect the
ultimate resolution of the bankruptcy to have a material adverse effect on
its results of operations or financial condition.
WINDPOWER PARTNERS 1994. WPP 94, in which the Company has a 25% interest
through indirect subsidiaries, did not make semiannual payments, due
September 2, 1997, and March 1, 1998, to John Hancock Mutual Life Insurance
Company (Hancock) under certain Notes issued by WPP 94 to Hancock. The
Company has offered WPP 94 financial support with respect to the appropriate
proportion of its debt obligations, but certain of the three other investor
groups are unable to offer funds to WPP 94 in support of the partnership.
The aggregate indirect investment of the Company in WPP 94 is $4.3 million as
of December 31, 1997. WPP 94 and Hancock are presently engaged in discussions
concerning a possible restructuring of WPP 94's debt obligations and
44
<PAGE>
Hancock has informed WPP 94 that it may declare WPP 94 in default of the
trust indenture relating to the Notes. WPP 94 operates wind power generation
facilities in Texas. Because of the continuing nature of the negotiations,
the Company is not able to predict the outcome of this event. The Company
does not expect the ultimate resolution of this matter to have a material
effect on its results of operations or financial condition.
TENASKA, INC. The Company has agreements with Tenaska, Inc. (a developer of
gas-fired cogeneration and independent power generation projects) and its
affiliates to purchase limited partnership interests in the identification,
development and ownership of certain independent power projects in North
America. Under the agreements, the Company (through its wholly owned
subsidiaries) is a limited partner in three operating cogeneration projects.
The Company also has agreed to participate in funding the costs associated
with identifying and pursuing potential independent power projects in North
America. The remaining funding commitment over the next several years totals
$3.6 million.
The Company also has a limited partnership interest in a gas-fired generation
project which is the subject of a breach of contract claim filed by Tenaska
against the Bonneville Power Administration (BPA). Construction of the
project was suspended in 1995 after BPA notified Tenaska of its intent to
cancel a power purchase agreement under which BPA committed to buy
electricity to be produced by the project. Tenaska has a $650 million claim
for damages against BPA in the United States Court of Federal Claims (Court
of Claims). Arbitration ordered by the Court of Claims began in February
1997. On July 29, 1998, an arbitration panel awarded the partnership $158.2
million in lieu of compensation under the power purchase agreement. The
award remains subject to the approval of the U.S. Department of Justice.
Upon payment of the award, ownership of the facility would be transferred to
the BPA. If the award is approved, it is anticipated the Company would
receive a payment of approximately $8.5 million.
GREGORY. On June 8, 1998, LPI announced that it has entered into a
partnership with Columbia Electric Corporation in the development of a
natural gas-fired cogeneration project in Gregory, Texas, providing
electricity and steam equivalent to 550 Mw. The project's construction is
subject, among other things, to final negotiation of project documents and
completion of financing arrangements. The project will sell steam and a
portion of its electric output to Reynolds Metals Company. It is anticipated
that the remaining electric output will be sold initially under a medium-term
contract. The project is expected to begin commercial operation in the
summer of 2000. Total project cost is anticipated to be approximately $240
million. Non-recourse financing is expected to fund a majority of the costs
and is scheduled to close in the fourth quarter of 1998. The Company's
equity contribution is expected to be approximately $30-35 million in
connection with its 50% interest in the project.
CALGARY
On November 22, 1996, LG&E Natural Canada Inc., a subsidiary of LEM,
initiated action in the Court of the Queens Bench of Alberta, Calgary against
a former employee. That action and an additional action, filed on the same
date in the General Division of the Ontario Court, also named a natural gas
sales and marketing company and the director, president and secretary of that
company (Marketing Company Defendants). The action against such Marketing
Company Defendants was settled on June 6, 1997. An amended statement of
claim was filed in the Calgary action on December 23, 1996, naming additional
parties. These lawsuits were filed as a result of LEM's discovery in the
fourth quarter of 1996 that the former employee had engaged in unauthorized
transactions. Counterclaims have been filed seeking damages of approximately
$40 million for, among other things, defamation and breach of contract. In
the second quarter of 1997, the Company received an insurance settlement of
$7.6 million (net of expenses) related to the losses. The Company does not
expect the ultimate resolution of this matter to have a material adverse
effect on its results of operations or financial condition.
SPRINGFIELD MUNICIPAL CONTRACT
On July 29, 1998, LEM filed suit in the United States District Court for the
Western District of Kentucky in
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<PAGE>
Louisville, against the City of Springfield, Illinois, City Water, Light and
Power Company ("Springfield CWLP"). The action seeks damages for Springfield
CWLP's failure, including in late June 1998, to sell electric energy to LEM
pursuant to a February 1997 Interchange Agreement and transaction
confirmations thereunder, as well as for other related claims. LEM has
estimated that its damages in this matter may be approximately $21.0 million.
OGLETHORPE POWER CONTRACT
In November 1996, the Company, through its LG&E Energy Marketing Inc.
subsidiary (LEM), entered into a 15 year agreement with Oglethorpe Power
Corporation (OPC) to supply approximately one-half of OPC's systemwide power
needs during the term of the agreement and with rights to market OPC's
surplus power. The Company has been in settlement negotiations with OPC over
load projections provided by OPC as an inducement for LEM to enter into the
1996 agreement. Absent an acceptable settlement with OPC, the Company will
pursue legal remedies. See also "Discontinuance of Merchant Energy Trading
and Sales Business" in Management's Discussion and Analysis of Operations and
Financial Condition.
COMBUSTION TURBINE ACQUISITION
In early October 1998, LG&E Capital Corp. entered into a cancelable letter of
intent to purchase two natural gas turbines. The Company anticipates that
the turbines, if purchased, or their electrical output, if purchased and
operated, would be marketed or resold to an affiliated or an unaffiliated
third party. However, there can be no assurance as to when, if at all, such
resale would occur or as to the price of any such resale. The aggregate
purchase price, including costs of installation, for the turbines is
approximately $115 million, which is expected to be largely funded through
additional borrowing or internally available funds.
OPERATING LEASES
The Company leases office space, office equipment, and vehicles. The Company
accounts for these leases as operating leases. Total lease expense for 1997,
1996, and 1995, was $7.5 million, $6.7 million, and $7.8 million,
respectively. The future minimum annual lease payments under lease agreements
for years subsequent to December 31, 1997, are as follows (in thousands of $):
1998 $ 9,461
1999 8,276
2000 8,367
2001 8,120
2002 7,219
Thereafter 10,262
-------
Total $51,705
-------
-------
The above amounts exclude future minimum annual lease payments under the Big
Rivers lease agreement. See Note 4, Big Rivers Electric Corporation Lease.
Future minimum annual lease payments have been reduced by rental payments to
be received from noncancelable subleases of approximately $1.8 million per
year from 1998 through 2000, and $1.3 million in 2001.
ENVIRONMENTAL
With the passage of the Clean Air Act Amendments of 1990 (the Act), LG&E
already complied with the stringent sulfur dioxide emission limits required
by the year 2000 as it had previously installed scrubbers on all of its
coal-fired generating units. Since then, as part of its ongoing construction
program, LG&E has spent $31 million for measures to meet applicable nitrogen
oxide limits. While the overall financial impact of the Act on LG&E has been
minimal, LG&E is closely monitoring several significant regulatory
developments which may
46
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potentially impact the Company including efforts by local officials to
address the "ozone nonattainment" status of Jefferson County, Kentucky and
implementation of new ozone and particulate matter standards adopted by the
United States Environmental Protection Agency (USEPA) in June 1997. Finally,
LG&E is monitoring regulations issued by USEPA on September 24, 1998, that
could require numerous utilities including LG&E to reduce nitrogen oxide
emissions by approximately 85% from 1990 levels. LG&E has already reduced
its nitrogen oxide emissions by approximately 40% and the Company's
independent power projects generally operate at even lower emissions levels.
The regulations provide for a reduction in utility nitrogen oxide emissions
of approximately 85% from 1990 levels by 2003. If these regulations are
implemented as promulgated, LG&E, KU, WKEC and the independent power projects
in which the Company has an interest will be required to incur significant
capital expenditures and significantly increased operation and maintenance
costs for remedial measures. Final implementation methods will be set by the
USEPA and state regulatory authorities. LG&E currently anticipates that a
significant portion of any such capital costs could be recoverable through
rates, although there can be no guarantee of such recovery.
The Company estimates that these capital costs could potentially exceed $300
million in the aggregate for LG&E, KU and WKEC. These costs would generally
be incurred following the year 2000. The Company believes its costs in this
regard to be comparable to that of similarly-situated utilities with like
generation assets. The Company anticipates that such capital and operating
costs are the type of costs that are eligible for recovery from customers
under its environmental surcharge mechanisms and believes that, in the cases
of LG&E and KU, a significant portion of such costs could be so recovered.
However, Kentucky Commission approval is necessary and there can be no
guarantee of such recovery.
KU met Phase I requirements of the Clean Air Act Amendments of 1990 (which
were effective January 1, 1995) primarily through the addition of a flue gas
desulfurization system (scrubber) on Unit 1 of KU's Ghent Generating Station.
The scrubber began commercial operation in December 1994.
KU's current strategy for Phase II requirements (which will be effective
January 1, 2000) is to use accumulated emission allowances to delay
additional capital expenditures and may also include fuel switching or the
installation of additional scrubbers.
KU's future compliance plans are contingent upon many factors, including
developments in the emission allowance market and fuel markets as well as
regulatory and legislative actions and advances in clean air technology. KU
will continue to review and revise its compliance plans accordingly to ensure
that its environmental obligations are met in the most efficient and
cost-effective manner.
LG&E is currently addressing other emissions issues at two of its power
plants. First, LG&E is conducting modeling activities in response to a
notification from the Air Pollution Control District of Jefferson County
(APCD) indicating that the Cane Run plant may be the source of a potential
exceedance of the air quality standards for sulfur dioxide. Depending on the
outcome of the modeling, LG&E may be required to undertake corrective action
that could include significant capital improvements. Secondly, LG&E is
working with the APCD to review the effectiveness of remedial measures aimed
at controlling particulate emissions from the Mill Creek plant which
allegedly damaged metal surfaces on adjacent properties. LG&E had previously
established a claims resolution process which resulted in property damage
settlements with adjacent residents at an aggregate cost of approximately $15
million. In related litigation, in October, 1997, the Jefferson Circuit
Court dismissed all but one of the claims pursued by persons who had not
previously settled with LG&E. In management's opinion, resolution of any
remaining claims should not have a material adverse impact on the financial
position or results of operations of LG&E.
LG&E is also addressing potential liabilities for cleanup of properties where
hazardous substances may have
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been released. LG&E has identified contamination at certain manufactured gas
plant (MGP) sites currently or formerly owned by the Company. One of the
sites was conveyed to a new owner which assumed responsibility for
environmental liabilities and LG&E is negotiating with potentially
responsible parties and state agencies with respect to two other sites.
Until conclusion of such discussions, LG&E is unable to precisely determine
its remaining liability for cleanup costs at MGP sites. However, based on
site studies, management currently estimates total cleanup costs within the
range of $3 million to $8 million and has recorded an accrual of
approximately $3 million in the accompanying financial statements.
LG&E, along with other companies, has also been identified by USEPA as a
potentially responsible party allegedly liable for cleanup costs under the
Comprehensive Environmental Response Compensation and Liability Act (CERCLA)
for certain off-site disposal facilities. LG&E has entered into settlements
for an aggregate of $150,000 for these sites, which settlements are final and
have been entered by the courts.
LPI and its subsidiaries are also subject to extensive federal, state, and
local environmental laws and regulations governing the operation of various
facilities in which they participate as an owner or managing operator. To
the extent that there have been any developments pursuant to environmental
laws and regulations, such developments have not been material, except as
otherwise disclosed herein.
PURCHASED POWER
KU has purchase power arrangements with Owensboro Municipal Utilities (OMU),
Electric Energy, Inc. (EEI), and other parties. Under the OMU agreement,
which expires on January 1, 2020, KU purchases all of the output of a 400-MW
generating station not required by OMU. The amount of purchased power
available to KU during 1998-2002, which is expected to be approximately 8% of
KU's total kWh requirements, is dependent upon a number of factors including
the units' availability, maintenance schedules, fuel costs and OMU
requirements. Payments are based on the total costs of the station allocated
per terms of the OMU agreement, which generally follows delivered kWh.
Included in the total costs is KU's proportionate share of debt service
requirements on $186.6 million of OMU bonds outstanding at December 31, 1997.
The debt service is allocated to KU based on its annual allocated share of
capacity, which averaged approximately 50% in 1997.
KU has a 20% equity ownership in EEI, which is accounted for on the equity
method of accounting. KU's entitlement is 20% of the available capacity of a
1,000-MW station. Payments are based on the total costs of the station
allocated per terms of an agreement among the owners, which generally follows
delivered kWh.
KU has several other contracts for purchased power during 1998-2002 of
various MW capacities and for varying periods with a maximum entitlement at
any time of 282 MW.
The estimated future minimum annual payments under purchased power agreements
for the five years ended December 31, 2002 follow (in thousands of $):
1998 $ 31,300
1999 30,200
2000 29,500
2001 32,300
2002 32,300
--------
Total $155,600
--------
--------
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NOTE 19 - 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 Public Service Commission's
1988 decision that LG&E should not be allowed to recover 25% of the cost of
Trimble County from ratepayers.
In December 1995, the Commission approved a unanimous settlement agreement
that was filed by LG&E and other parties. Under the agreement, which
resolved all outstanding issues, LG&E agreed to refund approximately $22
million to current electric customers, most of which is being refunded by
credits to customers' bills over the five years 1996 through 2000. In
addition, LG&E agreed to pay $900,000 per year for five years beginning in
1996 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. LG&E also agreed to
revise the residential decoupling methodology approved by the Commission in
1994 in a manner that reduced revenues collected from residential customers
by approximately $1.8 million. Finally, the parties agreed to dismiss all
appeals currently pending in state courts regarding the Commission's orders
in LG&E's last general rate case.
NOTE 20 - JOINTLY OWNED ELECTRIC UTILITY PLANT
LG&E 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 LG&E's accounting for other wholly owned
utility plants.
Of the remaining 25% of the Unit, Illinois Municipal Electric Agency (IMEA)
owns a 12.12% undivided interest in the Unit, and Indiana Municipal Power
Agency (IMPA) owns a 12.88% undivided interest. 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>
NOTE 21 - SEGMENTS OF BUSINESS
LG&E Energy Corp. has business operations in both the regulated and
non-regulated energy markets. The regulated business is conducted through
LG&E and KU. LG&E is an electric and gas public utility 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 of Kentucky. KU is an electric utility engaged in producing,
transmitting and selling electric energy to about 441,200 customers in over
600 communities and adjacent suburban and rural areas in 77 counties in
central, southeastern and western Kentucky and to about 29,000 customers in 5
counties in southwestern Virginia.
The non-utility businesses are subsidiaries of LG&E Capital Corp. and include
LG&E Power Inc. (LPI) and LG&E International Inc. (LII). LPI and its
subsidiaries develop, design, own, operate, and maintain power generation
facilities that sell energy to local industries and utilities throughout the
United States. LII develops and owns international power-generation assets
located in Spain and Argentina and acquired interests in two
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natural gas distribution companies located in Argentina in February 1997.
Other primarily relates to non-utility power generation activities and
corporate interest and operating expenses.
<TABLE>
<CAPTION>
(Thousands of $) 1997 1996 1995
---- ---- ----
<S> <C> <C> <C>
Operating information:
Revenues:
Electric $ 1,331,569 $ 1,318,846 $ 1,229,186 (a)
Gas 231,011 214,419 181,126
----------- ----------- -----------
Total utility 1,562,580 1,533,265 1,410,312
Argentine gas distribution 127,182 - -
Other 35,293 27,195 22,368
----------- ----------- -----------
Total $ 1,725,055 $ 1,560,460 $ 1,432,680
----------- ----------- -----------
----------- ----------- -----------
Operating income:
Electric $ 367,958 $ 361,381 $ 305,862
Gas 15,034 18,393 16,651
----------- ----------- -----------
Total utility 382,992 379,774 322,513
Argentine gas distribution 30,173 - -
Other 5,690 (5,229) (1,415)
----------- ----------- -----------
Total $ 418,855 $ 374,545 $ 321,098
----------- ----------- -----------
----------- ----------- -----------
Other information:
Depreciation and amortization:
Electric $ 164,069 $ 157,353 $ 149,517
Gas 13,062 12,073 11,322
----------- ----------- -----------
Total utility 177,131 169,426 160,839
Argentine gas distribution 7,569 - -
Other 1,849 1,973 1,861
----------- ----------- -----------
Total $ 186,549 $ 171,399 $ 162,700
----------- ----------- -----------
----------- ----------- -----------
Construction expenditures:
Electric $ 175,719 $ 186,123 $ 191,448
Gas 29,180 28,338 26,762
----------- ----------- -----------
Total utility (b) 204,899 214,461 218,210
Argentine gas distribution 4,369 - -
Other 863 1,493 2,092
----------- ----------- -----------
Total $ 210,131 $ 215,954 $ 220,302
----------- ----------- -----------
----------- ----------- -----------
Identifiable assets - December 31:
Electric $ 3,197,189 $ 3,178,462 $ 3,161,494
Gas 317,337 300,550 268,840
Other 219,776 186,346 208,517
----------- ----------- -----------
Total utility 3,734,302 3,665,358 3,638,851
Argentine gas distribution 340,144 - -
Net assets of discontinued operations 222,784 211,838 225,377
Other 265,714 255,403 237,298
----------- ----------- -----------
Total $ 4,562,944 $ 4,132,599 $ 4,101,526
----------- ----------- -----------
----------- ----------- -----------
</TABLE>
(a) Net of Refund - Trimble County Settlement of $28.3 million.
(b) Excluding cost of removal and salvage.
50
<PAGE>
NOTE 22 - SELECTED QUARTERLY DATA (UNAUDITED)
Selected financial data for the four quarters of 1997 and 1996 are shown below.
Because of seasonal fluctuations in temperature and other factors, results
for quarters may fluctuate throughout the year.
<TABLE>
<CAPTION>
(Thousands of $ except per share data) Quarters Ended
March June September December
----- ---- --------- --------
<S> <C> <C> <C> <C>
1997
- ----
Revenues $423,073 $388,538 $461,512 $451,932
Operating income 96,090 75,945 143,124 103,696
Net income (loss):
Continuing operations 47,530 32,784 70,869 55,857
Discontinued operations (1,428) 883 (15,123) (8,376)
-------- -------- -------- --------
Total 46,102 33,667 55,746 47,481
Earnings per share of common stock: (1)
Continuing operations .37 .25 .55 .43
Discontinued operations (.01) .01 (.12) (.06)
-------- -------- -------- --------
Total .36 .26 .43 .37
1996
- ----
Revenues $422,641 $353,059 $386,984 $397,776
Operating income 92,886 80,060 116,045 85,554
Net income (loss):
Continuing operations 44,495 39,519 65,614 40,758
Discontinued operations 8,919 376 (1,385) (12,344)
-------- -------- -------- --------
Total 53,414 39,895 64,229 28,414
Earnings per share of common stock: (1)
Continuing operations .34 .31 .51 .31
Discontinued operations .07 - (.01) (.09)
-------- -------- -------- --------
Total .41 .31 .50 .22
</TABLE>
(1) The Company is required to disclose basic and dilutive earnings per
share under the requirements of SFAS No. 128, Earnings Per Share. The
Company has determined that basic and dilutive earnings per share for
the quarters presented are the same.
51
<PAGE>
LG&E Energy Corp.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders of LG&E Energy Corp.:
We have audited the consolidated balance sheets and statements of
capitalization of LG&E Energy Corp. (a Kentucky corporation) and subsidiaries
as of December 31, 1997 and 1996, and the related consolidated statements of
income, retained earnings and cash flows for each of the three years in the
period ended December 31, 1997. These financial statements are the
responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements 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 consolidated financial statements referred to above
present fairly, in all material respects, the financial position of LG&E
Energy Corp. and subsidiaries as of December 31, 1997 and 1996, and the
results of their operations and their cash flows for each of the three years
in the period ended December 31, 1997, in conformity with generally accepted
accounting principles.
As discussed in Note 3 to the consolidated financial statements, effective
January 1, 1996, the Company changed its method of accounting for price risk
management activities.
Louisville, Kentucky
July 29, 1998 (Except with respect
to the matters discussed in the third
paragraph of Note 1, the second
and ninth paragraphs of Note 3, the
twelfth paragraph of Note 5 and the
twenty-fourth, twenty-eighth and
twenty-ninth paragraphs of Note 18, as
to which the date is October 15, 1998.)
52
<PAGE>
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation by
reference of our report dated July 29, 1998 (except with respect to the
matters discussed in the third paragraph of Note 1, the second and ninth
paragraphs of Note 3, the twelfth paragraph of Note 5 and the twenty-fourth,
twenty-eighth and twenty-ninth paragraphs of Note 18, as to which the date is
October 15, 1998) included in LG&E Energy Corp.'s Current Report on Form 8-K
dated October 16, 1998, into its previously filed Registration Statement Nos.
333-43985, 33-13427, 33-56942, 333-05457, 33-33687, 333-05459, 33-38557,
33-56525 and 33-60765.
Louisville, Kentucky
October 16, 1998
