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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
For the fiscal year ended DECEMBER 31, 1998
Commission Registrant, State of Incorporation, IRS Employer
File Number Address, and Telephone Number Identification Number
- ----------- ----------------------------- ----------------------
1-10568 LG&E ENERGY CORP. 61-1174555
(A Kentucky Corporation)
220 West Main Street
P. O. Box 32030
Louisville, Kentucky 40232
(502) 627-2000
2-26720 LOUISVILLE GAS AND ELECTRIC COMPANY 61-0264150
(A Kentucky Corporation)
220 West Main Street
P. O. Box 32010
Louisville, Kentucky 40232
(502) 627-2000
1-3464 KENTUCKY UTILITIES COMPANY 61-0247570
(A Kentucky and Virginia Corporation)
One Quality Street
Lexington, Kentucky 40507-1428
(606) 255-2100
Securities registered pursuant to section 12(b) of the Act:
LG&E ENERGY CORP.
-----------------
Name of each exchange on
Title of each class which registered
------------------- ----------------
Common Stock, without par value New York Stock Exchange
and
Rights to Purchase Series A Preferred Chicago Stock Exchange
Stock, without par value
LOUISVILLE GAS AND ELECTRIC COMPANY
-----------------------------------
Name of each exchange on
Title of each class which registered
------------------- ----------------
First Mortgage Bonds, Series due
July 1, 2002, 7 1/2% New York Stock Exchange
KENTUCKY UTILITIES COMPANY
--------------------------
Name of each exchange on
Title of each class which registered
------------------- ----------------
Preferred Stock, 4 3/4% cumulative, Philadelphia Stock Exchange
tated value $100 per share
Securities registered pursuant to section 12(g) of the Act:
LOUISVILLE GAS AND ELECTRIC COMPANY
-----------------------------------
5% Cumulative Preferred Stock, $25 Par Value
$5.875 Cumulative Preferred Stock, Without Par Value
Auction Rate Series A Preferred Stock, Without Par Value
(Title of class)
KENTUCKY UTILITIES COMPANY
--------------------------
Preferred Stock, cumulative, stated value $100 per share
(Title of class)
Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
As of February 26, 1999, the aggregate market value of LG&E Energy Corp.'s
voting common stock held by non-affiliates totaled $2,915,904,217, and it had
129,677,030 shares of common stock outstanding. As of February 26, 1999, the
aggregate market value of Louisville Gas and Electric Company's voting preferred
stock held by non-affiliates totaled $18,066,027, and it had 21,294,223 shares
of common stock outstanding, all held by LG&E Energy Corp, and 860,287 shares of
voting preferred stock outstanding. As of February 26, 1999, the aggregate
market value of Kentucky Utility Company's voting stock held by non-affiliates
totaled zero, and it had 37,817,878 shares of common stock outstanding, all held
by LG&E Energy Corp.
This combined Form 10-K is separately filed by LG&E Energy Corp., Louisville Gas
and Electric Company and Kentucky Utilities Company. Information contained
herein related to any individual registrant is filed by such registrant on its
own behalf. Each registrant makes no representation as to information relating
to the other registrants. In particular, information contained herein related to
LG&E Energy Corp. or any of its direct or indirect subsidiaries other than
Louisville Gas and Electric Company or Kentucky Utilities Company is provided
solely by LG&E Energy Corp., not Louisville Gas and Electric Company or Kentucky
Utilities Company, and shall be deemed not included in the Form 10-K of
Louisville Gas and Electric Company or the Form 10-K of Kentucky Utilities
Company.
DOCUMENTS INCORPORATED BY REFERENCE
LG&E Energy Corp.'s proxy statement, filed with the Commission on March 26,
1999, and Louisville Gas and Electric Company's proxy statement, filed with the
Commission on March 26, 1999, are incorporated by reference into Part III of
this Form 10-K.
TABLE OF CONTENTS
PART I
Item 1. Business........................................................ 1
Overview of Operations.......................................... 1
Merger with KU Energy Corporation............................... 1
Discontinuance of Merchant Energy Trading and Sales Business.... 1
Louisville Gas and Electric Company
General..................................................... 3
Electric Operations......................................... 4
Gas Operations.............................................. 6
Rates and Regulation........................................ 7
Construction Program and Financing..........................10
Coal Supply.................................................10
Gas Supply..................................................11
Environmental Matters.......................................11
Competition.................................................11
Kentucky Utilities Company
General.....................................................12
Electric Operations.........................................13
Rates and Regulation........................................14
Construction Program and Financing..........................16
Coal Supply.................................................17
Environmental Matters.......................................17
LG&E Capital Corp...............................................18
Independent Power Operations....................................18
Western Kentucky Energy.........................................20
Argentine Gas Distribution Division.............................22
Discontinued Operations.........................................23
Employees and Labor Relations...................................24
Item 2. Properties......................................................25
Item 3. Legal Proceedings...............................................29
Item 4. Submission of Matters to a Vote of Security Holders.............31
Executive Officers of the Company..........................................32
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters......................................39
Item 6. Selected Financial Data.........................................40
Item 7. Management's Discussion and Analysis of Results of
Operations and Financial Condition:
LG&E Energy Corp.........................................44
Louisville Gas and Electric Company......................62
Kentucky Utilities Company...............................73
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk.....................................................83
Item 8. Financial Statements and Supplementary Data:
LG&E Energy Corp.........................................84
Louisville Gas and Electric Company.....................127
Kentucky Utilities Company..............................152
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.....................172
TABLE OF CONTENTS (CONT.)
PART III
Item 10. Directors and Executive Officers of the Registrant (a)........172
Item 11. Executive Compensation (a)....................................172
Item 12. Security Ownership of Certain Beneficial Owners
and Management (a).......................................172
Item 13. Certain Relationships and Related Transactions (a)............172
PART IV
Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K..................................172
Signatures .........................................................198
(a) Incorporated by reference.
PART I.
Item 1. Business.
OVERVIEW OF OPERATIONS
LG&E Energy Corp. (the Company or LG&E Energy), incorporated November 14, 1989,
is a diversified energy-services holding company with three direct subsidiaries:
Louisville Gas and Electric Company (LG&E), Kentucky Utilities Company (KU) and
LG&E Capital Corp. (Capital Corp.). The Company's domestic regulated operations
are conducted by LG&E and KU.
The Company and its subsidiaries currently are exempt from all provisions,
except Section 9(a)(2), of the Public Utility Holding Company Act of 1935 (the
"Holding Company Act") on the basis that the Company, LG&E and KU are
incorporated in the same state and their business is predominately intrastate in
character and carried on substantially in the state of incorporation.
The Company is not a public utility under the laws of the Commonwealth of
Kentucky and is not subject to regulation as such by the Kentucky Public Service
Commission (Kentucky Commission) or the Virginia State Corporation Commission
(Virginia Commission). See LG&E - Rates and Regulation and - Rates and
Regulation for descriptions of the regulation of LG&E and KU by the Kentucky
Commission, and of KU by the Virginia Commission, which includes the ability to
regulate certain intercompany transactions between LG&E, KU and the Company,
including the Company's non-utility subsidiaries.
MERGER WITH KU ENERGY CORPORATION
Effective May 4, 1998, following the receipt of all required state and federal
regulatory approvals, LG&E Energy 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 LG&E and
KU were not affected by the Merger. See Note 2 of LG&E Energy Corp.'s Notes to
Financial Statements under Item 8.
DISCONTINUANCE OF MERCHANT ENERGY TRADING AND SALES BUSINESS
Effective June 30, 1998, the Company discontinued its merchant energy trading
and sales business. This business consisted primarily of a portfolio of energy
marketing contracts entered into in 1996 and early 1997, nationwide deal
origination and some level of speculative trading activities, which were not
directly supported by the Company's physical assets. The Company's decision to
discontinue these operations was primarily based on the impact that volatility
and rising prices in the power market had on its portfolio of energy marketing
contracts. Exiting the merchant energy trading and sales business enables the
Company to focus on optimizing the value of physical assets it owns or controls,
and to reduce the earnings impact on continuing operations of extreme market
volatility in its portfolio of energy marketing contracts. The Company is in the
process of settling commitments that obligate it to buy and sell natural gas and
electric power. It also plans to sell its natural gas gathering and processing
business. If the Company is unable to dispose of these commitments or assets it
will continue to meet its obligations under the contracts. The Company, however,
has maintained sufficient market knowledge, risk management skills, technical
systems and experienced personnel to maximize
1
the value of power sales from physical assets it owns or controls, including
LG&E, KU and the Big Rivers Electric Corporation (Big Rivers).
As a result of the Company's decision to discontinue its merchant energy 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 million in the second quarter of 1998. The loss
on disposal of discontinued operations results primarily from several
fixed-price energy marketing contracts entered into 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
merchant energy trading and sales operations and exit costs, including labor and
related benefits, severance and retention payments, and other general and
administrative expenses. Although the Company used what it believes to be
appropriate estimates for future energy prices among other factors to calculate
the net realizable value of discontinued operations, it also recognizes that
there are inherent limitations in models to accurately predict future events. As
a result, there is no guarantee that higher-than-anticipated future commodity
prices or load demands, lower- than-estimated asset sales prices or other
factors could not result in additional losses. The Company has been successful
in settling portions of its discontinued operations, but significant assets,
operations and obligations remain. As of January 27, 1999, 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 change the value of
the Company's remaining energy portfolio by approximately $8.8 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 January 27, 1999, the Company estimates that a 1% change
in the forecasted load demand could change the value of the Company's remaining
energy portfolio by $9.3 million. See Notes 3 and 18 of LG&E Energy Corp.'s
Notes to Financial Statements under Item 8.
The Company reclassified 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 of LG&E Energy Corp.'s Notes to
Financial Statements under Item 8 for more information.
LEASE OF BIG RIVERS FACILITIES
On July 15, 1998, the Company closed the transaction to lease the generating
assets of Big Rivers following receipt of necessary regulatory approvals. Under
the 25-year operating lease, Western Kentucky Energy Corp. and its affiliates
(WKE) are leasing and operating Big Rivers' three coal-fired facilities. In
addition, WKE operates and maintains the Station Two generating facility of the
City of Henderson (Henderson). The combined generating capacity of these
facilities amounts to approximately 1,700 megawatts (Mw), net of the Henderson's
capacity and energy needs from Station Two. In related transactions, power is
supplied to Big Rivers at contractual prices over the term of the lease to meet
the needs of four member distribution cooperatives and their retail customers,
including major western Kentucky aluminum smelters. Excess generating capacity
is available to WKE to market throughout the region. In connection with these
transactions, WKE 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 completion of the transactions. See Note 4 of
LG&E Energy Corp.'s Notes to Financial Statements under Item 8.
2
LOUISVILLE GAS AND ELECTRIC COMPANY
General
Incorporated on July 2, 1913, LG&E is a regulated public utility that supplies
natural gas to approximately 289,000 customers and electricity to approximately
360,000 customers in Louisville and adjacent areas in Kentucky. LG&E's service
area covers approximately 700 square miles in 17 counties and has an estimated
population of one million. Included in this area is the Fort Knox Military
Reservation, to which LG&E transports gas and provides electric service, but
which maintains its own distribution systems. LG&E also provides gas service in
limited additional areas. LG&E's coal-fired electric generating plants, which
are all equipped with systems to reduce sulfur dioxide emissions, produce most
of LG&E's electricity. The remainder is generated by a hydroelectric power plant
and combustion turbines. Underground natural gas storage fields help LG&E
provide economical and reliable gas service to customers.
LG&E's Trimble County Unit 1 (Trimble County), a 495-Mw, coal-fired electric
generating unit was placed in commercial operation in December 1990. In December
1995, the Commission approved a settlement agreement that excluded 25% of the
Trimble County costs from customer rates. LG&E owns a 75% undivided interest in
Trimble County. See Electric Operations under Item 1, Note 13 of LG&E's Notes to
Financial Statements and Note 19 of LG&E Energy Corp.'s Notes to Financial
Statements under Item 8.
In September 1998, the U.S. Environmental Protection Agency announced its final
regulation requiring significant additional reductions in nitrogen oxide (NOx)
emissions to mitigate alleged ozone transport to the Northeast. While each state
is free to allocate its assigned NOx reductions among various emissions sectors
as it deems appropriate, the regulation may ultimately require utilities to
reduce their NOx emissions to 0.15 lb./mmBtu (million British thermal units) -
an 85% reduction from 1990 levels. Under the regulation, each state must
incorporate the additional NOx reductions in its State Implementation Plan (SIP)
by September 1999 and affected sources must install control measures by May
2003, unless granted extensions. Several states, various labor and industry
groups, and individual companies have appealed the final regulation to the U.S.
Court of Appeals for the D.C. Circuit. Management is currently unable to
determine the outcome or exact impact of this matter until such time as the
states identify specific emissions reductions in their SIPs and the courts rule
on the various legal challenges to the final rule. However, if the 0.15 lb.
target is ultimately imposed, LG&E will be required to incur significant capital
expenditures and increased operation and maintenance costs for additional
controls.
Subject to further study and analysis, LG&E estimates that it may incur capital
costs in the range of $100 million to $200 million. These costs would generally
be incurred beginning in 2000. LG&E believes its costs in this regard to be
comparable to those of similarly situated utilities with like generation assets.
LG&E anticipates that such capital and operating costs are the type of costs
that are eligible for cost recovery from customers under its environmental
surcharge mechanism and believes that a significant portion of such costs could
be recovered. However, Kentucky Commission approval is necessary and there can
be no guarantee of such recovery.
3
For the year ended December 31, 1998, 77% of total operating revenues was
derived from electric operations and 23% from gas operations. Electric and gas
operating revenues and the percentages by classes of service on a combined basis
for this period were as follows:
(Thousands of $)
Electric Gas Combined %Combined
-------- --- -------- ---------
Residential $213,476 $113,430 $326,906 45%
Commercial 170,954 40,888 211,842 29
Industrial 113,372 11,969 125,341 17
Public authorities 55,075 8,884 63,959 9
-------- -------- -------- ---
Total retail 552,877 175,171 728,048 100%
---
---
Wholesale sales 99,340 8,720 108,060
Gas transported - net - 6,926 6,926
Provision for rate refund - ECR (4,500) - (4,500)
Miscellaneous 10,794 728 11,522
-------- -------- --------
Total $658,511 $191,545 $850,056
-------- -------- --------
-------- -------- --------
See Note 14 of LG&E's Notes to Financial Statements and Note 20 of LG&E Energy
Corp.'s Notes to Financial Statements under Item 8 for financial information
concerning segments of business for the three years ended December 31, 1998.
Electric Operations
The sources of LG&E's electric operating revenues and the volumes of sales for
the three years ended December 31, 1998, were as follows:
1998 1997 1996
---- ---- ----
ELECTRIC OPERATING REVENUES
(Thousands of $):
Residential $213,476 $205,137 $202,318
Small commercial and industrial 76,304 72,769 74,034
Large commercial 94,650 90,131 88,993
Large industrial 113,372 110,652 110,914
Public authorities 55,075 53,412 54,318
-------- -------- --------
Total retail 552,877 532,101 530,577
Wholesale sales 99,340 70,942 67,854
Provision for rate refund - ECR (4,500) - -
Miscellaneous 10,794 11,489 8,265
-------- -------- --------
Total $658,511 $614,532 $606,696
-------- -------- --------
-------- -------- --------
ELECTRIC SALES (Thousands of mwh):
Residential 3,534 3,302 3,382
Small commercial and industrial 1,156 1,108 1,131
Large commercial 1,977 1,880 1,850
Large industrial 3,097 3,054 3,059
Public authorities 1,140 1,105 1,122
------ ------ ------
Total retail 10,904 10,449 10,544
Wholesale sales 4,970 3,800 3,589
------ ------ ------
Total 15,874 14,249 14,133
------ ------ ------
------ ------ ------
At December 31, 1998, LG&E had 360,024 electric customers.
4
LG&E uses efficient coal-fired boilers that are fully equipped with sulfur
dioxide removal systems to generate electricity. LG&E's system wide emission
weighted-average rate for sulfur dioxide in 1998 was approximately .97
lbs./MMBtu of heat input, which is significantly below the Phase II limit of 1.2
lbs./MMBtu established by the Clean Air Act Amendments of 1990 for the year
2000.
The 1998 maximum local peak load of 2,427 Mw occurred on Tuesday, August 25,
1998, when the temperature at the time was 94(degree)F. Prior to 1998, the
record local peak load was 2,414 Mw (set on July 21, 1997).
The electric utility business is affected by seasonal weather patterns. As a
result, operating revenues (and associated operating expenses) are not generated
evenly throughout the year. See LG&E's Results of Operations under Item 7.
LG&E's current reserve margin is 14%. At December 31, 1998, LG&E owned steam and
combustion turbine generating facilities with a capacity of 2,512 Mw and an 80
Mw hydroelectric facility on the Ohio River. See Item 2, Properties.
LG&E is a participating owner with 14 other electric utilities of Ohio Valley
Electric Corporation whose primary customer is the Portsmouth Area
uranium-enrichment complex of the U.S. Department of Energy at Piketon, Ohio.
LG&E has direct interconnections with 11 utility companies in the area and has
agreements with each interconnected utility for the purchase and sale of
capacity and energy. LG&E also has agreements with an increasing number of
entities throughout the United States for the purchase and/or sale of capacity
and energy and for the utilization of their bulk transmission system.
The Illinois Municipal Electric Agency (IMEA), based in Springfield, Illinois,
which is an agency of 35 municipalities that own and operate their own electric
systems, has a 12.12% ownership interest in LG&E's Trimble County Unit 1. The
Indiana Municipal Power Agency (IMPA), based in Carmel, Indiana, has a 12.88%
interest in the Trimble County Unit. IMPA is composed of 31 municipalities that
have joined together to meet their long-term electric power needs. Both IMEA and
IMPA pay their proportionate share for operation and maintenance expenses of
Trimble County and for fuel and reactant used. They are also responsible for
their proportionate share of incremental capital assets acquired. See Note 13 of
LG&E's Notes to Financial Statements and Note 19 of LG&E Energy Corp.'s Notes to
Financial Statements under Item 8 for a further discussion.
5
Gas Operations
The sources of LG&E's gas operating revenues and the volumes of sales for the
three years ended December 31, 1998, were as follows:
1998 1997 1996
---- ---- ----
GAS OPERATING REVENUES
(Thousands of $):
Residential $113,430 $139,967 $125,327
Commercial 40,888 52,440 47,415
Industrial 11,969 17,892 21,229
Public authorities 8,884 12,052 11,731
-------- -------- --------
Total retail 175,171 222,351 205,702
Wholesale sales 8,720 - -
Gas transported - net 6,926 6,997 6,850
Miscellaneous 728 1,663 1,867
-------- -------- --------
Total $191,545 $231,011 $214,419
-------- -------- --------
-------- -------- --------
GAS SALES (Millions of cu. ft.):
Residential 20,040 24,038 25,531
Commercial 8,448 10,212 10,656
Industrial 2,860 3,948 5,190
Public authorities 1,967 2,467 2,790
-------- -------- --------
Total retail 33,315 40,665 44,167
Wholesale sales 3,880 - -
Gas transported 13,027 13,452 12,540
-------- -------- --------
Total 50,222 54,117 56,707
-------- -------- --------
-------- -------- --------
At December 31, 1998, LG&E had 288,777 gas customers.
The gas utility business is affected by seasonal weather patterns. As a result,
operating revenues (and associated operating expenses) are not generated evenly
throughout the year. See LG&E's Results of Operations under Item 7.
LG&E has underground natural gas storage fields that help provide economical and
reliable gas service to ultimate consumers.
By using gas storage fields strategically, LG&E can buy gas when prices are low,
store it, and retrieve the gas when demand is high. Accessing least cost gas was
made easier in November 1993 when the Federal Energy Regulatory Commission Order
No. 636 went into effect. Previously, LG&E and other utilities purchased most of
their gas services from pipeline companies. The order "unbundled" gas services,
allowing utilities to purchase gas, transportation, and storage services
separately from many different sources. Currently, LG&E buys competitively
priced gas from several large producers under contracts of varying duration. By
purchasing from multiple suppliers and storing any excess gas, LG&E is able to
secure favorably priced gas for its customers. Without storage capacity, LG&E
would be forced to buy additional gas when customer demand increases, which is
usually when the price is highest.
A number of industrial customers purchase their natural gas requirements
directly from alternate suppliers for delivery through LG&E's distribution
system. Generally, transportation of natural gas for LG&E's customers does not
have an adverse effect on earnings because of the offsetting decrease in gas
supply expenses. Transportation rates are designed to make LG&E economically
indifferent as to whether gas is sold or merely transported.
6
The all-time maximum day gas sendout of 545,000 Mcf occurred on Sunday, January
20, 1985, when the average temperature for the day was -11(degree)F. During
1998, the maximum day gas sendout was 425,000 Mcf, occurring on March 11, when
the average temperature for the day was 20(degree)F. Supply on that day
consisted of 105,000 Mcf from purchases, 263,000 Mcf delivered from underground
storage, and 57,000 Mcf transported for industrial customers.
For a further discussion, see Gas Supply under Item 1.
Rates and Regulation
The Kentucky Commission has regulatory jurisdiction over the rates and service
of LG&E and over the issuance of certain of its securities. The Kentucky
Commission has the ability to examine the rates LG&E charges its retail
customers at any time. LG&E is a "public utility" as defined in the Federal
Power Act, and is subject to the jurisdiction of the Department of Energy and
the FERC with respect to the matters covered in such Act, including the sale of
electric energy at wholesale in interstate commerce. In addition, the FERC has
sole jurisdiction over the issuance by LG&E of short-term securities.
For a discussion of current regulatory matters, see Rates and Regulation for
LG&E and LG&E Energy Corp. under Item 7 and Note 3 of LG&E's Notes to Financial
Statements and Note 5 of LG&E Energy Corp.'s Notes to Financial Statements under
Item 8.
Increases and decreases in the cost of fuel for electric generation are
reflected in the rates charged to all of LG&E's electric customers by means of
LG&E's fuel adjustment clause (FAC). The Kentucky Commission requires public
hearings at six-month intervals to examine past fuel adjustments, and at
two-year intervals to review past operations of the fuel clause and transfer of
the then current fuel adjustment charge or credit to the base charges. The
Commission also requires that electric utilities, including LG&E, file certain
documents relating to fuel procurement and the purchase of power and energy from
other utilities.
As of February 12, 1999, LG&E received orders from the Kentucky Commission
requiring a refund to retail electric customers of approximately $3.9 million
resulting from reviews of the FAC for the period from November 1994 through
April 1998. LG&E estimates up to an additional $1.3 million could be refundable
to retail electric customers for the period from May 1998 through December 1998.
See Note 3 of LG&E's Notes to Financial Statements and Note 5 of LG&E Energy
Corp.'s Notes to Financial Statements under Item 8.
LG&E filed a Petition of Rehearing of all of the orders and a motion to suspend
the refund obligation. On February 25, 1999, the Commission suspended the
obligation to refund pending further direction by the Commission. It also
advised that LG&E may have to pay interest on the refund amounts for the
suspension period. On March 11, 1999 the Commission denied LG&E's Petition for
Rehearing for the period November 1994 through October 1996 and directed LG&E to
reduce future fuel expense by $1.9 million in the first billing month after the
Order. The Company is considering the filing of an Appeal with the Franklin
Circuit Court. In a separate series of Orders on March 11, 1999, the PSC granted
LG&E's Petition for Rehearing for the period November 1996 through April 1998
and established a procedural schedule for LG&E and other parties to submit
evidence and for a hearing before the Commission. In the same Orders the PSC
granted the Petition for Rehearing of the Kentucky Industrial Utility Customers
to determine if interest should be paid on any fuel refunds for this latter
period.
LG&E's gas rates contain a gas supply clause (GSC), whereby increases or
decreases in the cost of gas supply are reflected in LG&E's rates, subject to
approval of the Kentucky Commission. The GSC procedure prescribed by order of
the Commission provides for quarterly rate adjustments to reflect the expected
cost of gas supply in that quarter. In addition, the GSC contains a mechanism
whereby any over- or under-recoveries of gas supply cost from prior quarters
will be refunded to or recovered from customers through the adjustment factor
determined for subsequent quarters.
7
In May 1995, LG&E implemented an environmental cost recovery (ECR) surcharge to
recover certain environmental compliance costs, including costs to comply with
the 1990 Clean Air Act, as amended, and other environmental regulations,
including those applicable to coal combustion wastes and related by-products.
The ECR mechanism was authorized by state statute in 1992 and was first approved
by the Kentucky Commission in a KU case in July 1994.
The Commission's order approving the surcharge in the KU case and the
constitutionality of the surcharge was challenged by certain intervenors,
including the Attorney General of Kentucky, in Franklin Circuit Court. Decisions
of the Circuit Court and the Kentucky Court of Appeals in July 1995 and December
1997, respectively, have upheld the constitutionality of the ECR statute but
differed on a claim of retroactive recovery of certain amounts. The Commission
ordered that certain surcharge revenues collected by LG&E be subject to refund
pending final determination of all appeals.
On December 19, 1998, the Kentucky Supreme Court rendered an opinion upholding
the constitutionality of the surcharge statute. The decision, however, reversed
the ruling of the Court of Appeals on the retroactivity claim, thereby denying
recovery through the ECR of costs associated with pre-1993 environmental
projects. The court remanded the case to the Commission to determine the proper
adjustments to refund amounts collected for such pre-1993 environmental
projects. The parties to the proceeding have notified the Commission that they
have reached agreement as to the terms, proper adjustments and forward
application of the ECR. The settlement agreement is subject to Commission
approval. LG&E recorded a provision for rate refund of $4.5 million in December
1998. See Rates and Regulation for LG&E and LG&E Energy Corp. under Item 7 for a
further discussion.
Integrated resource planning regulations in Kentucky require LG&E and the other
major utilities to make triennial filings with the Kentucky Commission of
various historical and forecasted information relating to forecasted load,
capacity margins and demand-side management techniques.
Pursuant to Kentucky law, the Kentucky Commission has established the boundaries
of the service territory or area of each retail electric supplier in Kentucky
(including LG&E), other than municipal corporations, within which each such
supplier has the exclusive right to render retail electric service.
In January 1994, LG&E implemented a Commission-approved demand side management
(DSM) program that LG&E, the Jefferson County Attorney, and representatives of
several customer interest groups had filed with the Commission. The program
included 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 program
(decoupling). In June 1998, LG&E and customer interest groups requested an end
to the decoupling rate mechanism. On June 1, 1998, LG&E discontinued recording
revenues from lost sales due to DSM. Accrued decoupling revenues recorded for
periods prior to June 1, 1998, will continue to be collected through the DSM
recovery mechanism. In September 1998, the Commission accepted LG&E's modified
tariff reflecting this proposal effective as of June 1, 1998. See Rates and
Regulation for LG&E and LG&E Energy Corp. under Item 7 for a discussion of
Commission approved changes to the original program and requested revisions
pending before the Commission.
In October 1997, LG&E implemented a Commission-approved, experimental
performance-based ratemaking mechanism related to gas procurement activities and
off-system gas sales. During the three-year test period beginning October 1997,
rate adjustments related to this mechanism will be determined for each 12-month
period beginning November 1 and ending October 31. During the first year of
operation of the mechanism LG&E recorded $3.6 million for its share of reduced
gas costs. The $3.6 million will be billed to customers through the gas supply
clause beginning February 1, 1999.
8
In October 1998, LG&E and KU filed separate, but parallel applications with the
Commission for approval of a new method of determining electric rates that
provides financial incentives for LG&E and KU to further reduce customers'
rates. The filing was made pursuant to the September 1997 Commission order
approving the merger of LG&E Energy and KU Energy, wherein the Commission
directed LG&E and KU to indicate whether they desired to remain under
traditional rate of return regulation or commence non-traditional regulation.
The new ratemaking method, known as performance-based ratemaking (PBR), would
include financial incentives for LG&E and KU to reduce fuel costs and increase
generating efficiency, and to share any resulting savings with customers.
Additionally, the PBR provides financial penalties and rewards to assure
continued high quality service and reliability.
The PBR plan proposed by LG&E and KU consists of five components:
The utilities' fuel adjustment clause mechanism will be withdrawn and
replaced with a cap that limits recovery of actual changes in fuel cost to
changes in a fuel price index for a five-state region. If the utilities
outperform the index, benefits will be shared equally between shareholders
and customers. If the utilities' fuel costs exceed the index, the difference
will be absorbed by LG&E Energy's shareholders.
Customers will continue to receive the benefits from the post-merger joint
dispatch of power from LG&E's and KU's generating plants.
Power plant performance will be measured against the best performance
achieved between 1991 and 1997. If the performance exceeds this level,
customers will share equally with LG&E Energy's shareholders in up to $10
million annually of benefits from this performance at each of LG&E and KU.
The utilities will be encouraged to maintain and improve service quality,
reliability, customer satisfaction and safety, which will be measured
against six objective benchmarks. The plan provides for annual rewards or
penalties to LG&E Energy of up to $5 million per year at each of LG&E and
KU.
The plan provides the utilities with greater flexibility to customize rates
and services to meet customer needs. Services will continue to be priced
above marginal cost and customers will continue to have the option to elect
standard tariff service.
These proposals are subject to approval by the Commission. Approval proceedings
commenced in October 1998 and a final decision likely will occur in 1999.
Several intervenors are participating in the case. Some have requested that the
Commission reduce base rates before implementing PBR.
On March 8, 1999, the Kentucky Industrial Utility Customers filed a Complaint
with the Kentucky Commission alleging that LG&E's electric rates are excessive
and should be reduced by an amount between $43 and $90 million and that the
Kentucky Commission establish a proceeding to reduce LG&E's electric rates. LG&E
has asked the Kentucky Commission to dismiss the Complaint.
LG&E is not able to predict the ultimate outcome of these proceedings, however,
should the Commission mandate significant rate reductions at LG&E, through the
PBR proposal or otherwise, such actions could have a material effect on LG&E's
financial condition and results of operations.
As part of the corporate reorganization whereby LG&E became the subsidiary of
LG&E Energy, LG&E obtained the approval of the Kentucky Commission. The order of
the Kentucky Commission authorizing LG&E to reorganize into a holding company
structure contains certain provisions, which, among other things, ensure the
Kentucky Commission access to books and records of LG&E Energy and its
affiliates which relate to transactions with LG&E; requires LG&E Energy and its
subsidiaries to employ accounting and other procedures and controls to
9
protect against subsidization of non-utility activities by LG&E's customers; and
precludes LG&E from guaranteeing any obligations of LG&E Energy without prior
written consent from the Kentucky Commission. In addition, the order provides
that LG&E's Board of Directors has the responsibility to use its dividend policy
consistent with preserving the financial strength of LG&E and that the Kentucky
Commission, through its authority over LG&E's capital structure, can protect
LG&E's ratepayers from the financial effects resulting from non-utility
activities.
Construction Program and Financing
LG&E's construction program is designed to ensure that there will be adequate
capacity and reliability to meet the electric and gas needs of its service area.
These needs are continually being reassessed and appropriate revisions are made,
when necessary, in construction schedules. LG&E's estimates of its construction
expenditures can vary substantially due to numerous items beyond LG&E's control,
such as changes in rates, economic conditions, construction costs, and new
environmental or other governmental laws and regulations.
During the five years ended December 31, 1998, gross property additions amounted
to $546 million. Internally generated funds for the five-year period were
sufficient to provide for all of these gross additions. The gross additions
during this period amounted to approximately 20% of total utility plant at
December 31, 1998, and consisted of $405 million for electric properties and
$141 million for gas properties. Gross retirements during the same period were
$112 million, consisting of $91 million for electric properties and $21 million
for gas properties.
Coal Supply
Over 90% of LG&E's present electric generating capacity is coal-fired, the
remainder being made up of a hydroelectric plant and combustion turbine peaking
units fueled by natural gas and oil. Coal will be the predominant fuel used by
LG&E in the foreseeable future, with natural gas and oil being used for peaking
capacity and flame stabilization in coal-fired boilers or in emergencies. LG&E
has no nuclear generating units and has no plans to build any in the foreseeable
future. LG&E has entered into coal supply agreements with various suppliers for
coal deliveries for 1999 and beyond. LG&E normally augments its coal supply
agreements with spot market purchases which, during 1998, were about 21% of
total purchases. LG&E has a coal inventory policy which it believes provides
adequate protection under most contingencies. LG&E had on hand at December 31,
1998, a coal inventory of approximately 1,015,000 tons, or a 56 day supply.
LG&E expects, for the foreseeable future, to continue purchasing most of its
coal, which has a sulfur content in the 2%-4.5% range, from western Kentucky,
southwest Indiana, West Virginia and Ohio. The abundant supply of this
relatively low priced coal, combined with present and future desulfurization
technologies, is expected to enable LG&E to continue to provide adequate
electric service in a manner acceptable under existing environmental laws and
regulations.
Coal is delivered for LG&E's Mill Creek plant by rail and barge; Trimble County
plant by barge and Cane Run plant by rail. Starting the second half of 2000,
Cane Run is also expected to have the capability for barge delivery of coal.
The average delivered cost of coal purchased by LG&E, per ton and per million
Btu, for the periods shown were as follows:
1998 1997 1996
---- ---- ----
Per ton $22.38 $21.66 $21.73
Per million Btu .98 .94 .97
10
The delivered cost of coal is expected to decrease during 1999.
Gas Supply
LG&E purchases transportation services from Texas Gas Transmission Corporation
(Texas Gas) and Tennessee Gas Pipeline Company (Tennessee). LG&E purchases
natural gas supplies from multiple sources under contracts for varying periods
of time.
During 1997, Texas Gas filed with FERC for a change in its rates as required
under the settlement in its last rate case. LG&E participated in that and other
proceedings, as appropriate. Resolution of that rate case took place in 1998
when the settlement was approved effective December 1. LG&E received a refund of
$1.5 million from Texas Gas in January 1999 which will be refunded to customers
in 1999.
LG&E transports on the Texas Gas system under No-Notice Service (NNS) and Firm
Transportation (FT) rates. During the winter months, LG&E has 184,900 MMBtu per
day in NNS. LG&E's summer NNS levels are 60,000 MMBtu per day and its summer FT
levels are 54,000 MMBtu per day. Each of these NNS and FT agreements with Texas
Gas expire in equal portions in 2000, 2001, and 2003. LG&E also transports on
the Tennessee system under Tennessee's Rate FT-A. LG&E's contract levels with
Tennessee are 51,000 MMBtu per day annually. The FT-A agreement with Tennessee
expires 2002.
LG&E also has a portfolio of supply arrangements with various suppliers in order
to meet its firm sales obligations. These gas supply arrangements include
pricing provisions which are market-responsive. These firm supplies, in tandem
with pipeline transportation services, provide the reliability and flexibility
necessary to serve LG&E's customers.
LG&E operates five underground gas storage fields with a current working gas
capacity of 14.6 million Mcf. Gas is purchased and injected into storage during
the summer season and is then withdrawn to supplement pipeline supplies to meet
the gas-system load requirements during the winter heating season.
The estimated maximum deliverability from storage during the early part of the
1998-1999 heating season was approximately 373,000 Mcf per day. Deliverability
decreases during the latter portion of the heating season as the storage
inventory is reduced by seasonal withdrawals.
The average cost per Mcf of natural gas purchased by LG&E was $3.05 in 1998 and
$3.46 in each of 1997 and 1996.
Environmental Matters
Protection of the environment is a major priority for LG&E. LG&E engages in a
variety of activities within the jurisdiction of federal, state, and local
regulatory agencies. Those agencies have issued LG&E permits for various
activities subject to air quality, water quality, and waste management laws and
regulations. For the five year period ending with 1998, expenditures for
pollution control facilities represented $106 million or 19% of total
construction expenditures. See Note 12 of LG&E's Notes to Financial Statements
and Note 18 of LG&E Energy Corp.'s Notes to Financial Statements under Item 8
for a discussion of specific environmental proceedings affecting LG&E.
Competition
In the last several years, LG&E has taken many steps to prepare for the expected
increase in competition in its industry, including a reduction in the number of
employees; aggressive cost cutting; write-offs of previously deferred expenses;
an increase in focus on not only commercial and industrial customers, but
residential customers
11
as well; an increase in employee involvement and training;
a major realignment and formation of new business units, and continuous
modifications of its organizational structure. LG&E could take additional steps
like these to better position itself for competition in the future.
KENTUCKY UTILITIES COMPANY
General
KU was incorporated in Kentucky in 1912 and incorporated in Virginia in 1991. KU
is a public utility engaged in producing, transmitting and selling electric
energy. KU provides electric service to about 449,000 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. In Virginia, KU operates under the name Old Dominion
Power Company. KU operates under appropriate franchises in substantially all of
the 160 Kentucky incorporated municipalities served. No franchises are required
in unincorporated Kentucky or Virginia communities. The lack of franchises is
not expected to have a material adverse effect on KU's operations. KU also sells
wholesale electric energy to 12 municipalities.
In September, 1998, the U.S. Environmental Protection Agency (USEPA) announced
its final regulation requiring significant additional reductions in nitrogen
oxide (NOx) emissions to mitigate alleged ozone transport to the Northeast.
While each state is free to allocate its assigned NOx reductions among various
emissions sectors as it deems appropriate, the regulation may ultimately require
utilities to reduce their NOx emissions to 0.15 lb./MMBTU - an 85% reduction
from 1990 levels. Under the regulation, each state must incorporate the
additional NOx reductions in its State Implementation Plan (SIP) by September
1999 and affected sources must install control measures by May 2003, unless
granted extensions. Several states, various labor and industry groups, and
individual companies have appealed the final regulation to the U.S. Court of
Appeals for the D.C. Circuit. Management is currently unable to determine the
outcome or exact impact of this matter until such time as the states identify
specific emissions reductions in their SIP and the courts rule on the various
legal challenges to the final rule. However, if the 0.15 lb. target is
ultimately imposed, KU will be required to incur significant capital
expenditures and increased operation and maintenance costs for additional
controls.
Subject to further study and analysis, KU estimates that it may incur capital
costs of approximately $100 to $200 million. These costs would generally be
incurred beginning in 2000. KU believes its costs for these matters to be
comparable to those of similarly situated utilities with like generation assets.
KU anticipates that such capital and operating costs are the type of costs that
are eligible for cost recovery from customers under its environmental surcharge
mechanisms and believes that 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.
12
Electric Operations
The sources of KU's electric operating revenues and the volumes of sales for the
three years ended December 31, 1998, were as follows:
1998 1997 1996
---- ---- ----
ELECTRIC OPERATING REVENUES
(Thousands of $):
Residential $238,898 $231,824 $236,229
Commercial 158,549 150,794 150,640
Industrial 154,662 146,801 136,856
Mine Power 31,697 34,541 34,014
Public authorities 58,814 56,243 56,023
-------- -------- --------
Total - ultimate consumers 642,620 620,203 613,762
Wholesale sales 179,118 87,330 89,208
Provision for rate refund - ECR (21,500) - -
Miscellaneous 9,876 8,904 8,741
-------- -------- --------
Total $810,114 $716,437 $711,711
-------- -------- --------
-------- -------- --------
ELECTRIC SALES (Thousands of mwh):
Residential 5,247 5,061 5,148
Commercial 3,644 3,422 3,411
Industrial 4,747 4,464 4,107
Mine Power 838 926 894
Public authorities 1,424 1,355 1,350
------ ------ ------
Total - ultimate consumers 15,900 15,228 14,910
Wholesale sales 7,224 3,397 3,721
------ ------ ------
Total 23,124 18,625 18,631
------ ------ ------
------ ------ ------
The electric utility business is affected by seasonal weather patterns. As a
result, operating revenues (and associated operating expenses) are not generated
evenly throughout the year. See KU's Results of Operations under Item 7.
At December 31, 1998, KU owned steam and combustion turbine generating
facilities with a capacity of 3,694 Mw and a 24 Mw hydroelectric facility. See
Item 2, Properties. KU obtains power from other utilities under bulk power
purchase and interchange contracts. At December 31, 1998, KU's system
capability, including purchases from others, was 4,235 Mw. On August 25, 1998, a
record local peak load, on a one-hour integrated basis, was set at 3,559 Mw.
Under a contract expiring 2020 with Owensboro Municipal Utilities (OMU), KU has
agreed to purchase from OMU the surplus output of the 150-Mw and 250-Mw
generating units at OMU's Elmer Smith station. Purchases under the contract are
made under a contractual formula which has resulted in costs which were and are
expected to be comparable to the cost of other power purchased or generated by
KU. Such power constituted about 9% of KU's net system output during 1998. See
Note 11 of KU's Notes to Financial Statements and Note 18 of LG&E Energy's Notes
to Financial Statements under Item 8.
KU owns 20% of the common stock of Electric Energy, Inc. (EEI), which owns and
operates a 1,000-Mw generating station in southern Illinois. KU's entitlement is
20% of the available capacity of the station. Purchases from EEI are made under
a contractual formula which has resulted in costs which were and are expected to
be comparable to the cost of other power purchased or generated by KU. Such
power constituted
13
about 8% of KU's net system output in 1998. See Note 11 of KU's Notes to
Financial Statements and Note 18 of LG&E Energy Corp.'s Notes to Financial
Statements under Item 8. See also Item 3, Legal Proceedings.
Rates and Regulation
The Kentucky Commission and the Virginia Commission have regulatory jurisdiction
over KU's retail rates and service, and over the issuance of certain of its
securities. FERC has jurisdiction under the Federal Power Act (FPA) over certain
of the electric utility facilities and operations, wholesale sale of power and
related transactions and accounting practices of KU, and in certain other
respects as provided in the FPA. FERC has classified KU as a "public utility" as
defined in the FPA. By reason of owning and operating a small amount of electric
utility property in one county in Tennessee (having a gross book value of about
$225,000) from which KU serves five customers, KU is subject to the jurisdiction
of the Tennessee Regulatory Authority (TRA). In addition, the FERC has sole
jurisdiction over the issuance by KU of short-term securities.
For a discussion of current regulatory matters, see Rates and Regulation for KU
and LG&E Energy Corp. under Item 7 and under Note 3 of KU's Notes to the
Financial Statements and Note 5 of LG&E Energy Corp.'s Notes to Financial
Statements under Item 8.
KU's fuel adjustment clause (FAC) for Kentucky customers operates to reflect
changes in the cost of fuel in billings to customers, and is designed to conform
with the Kentucky Commission's regulation providing for a uniform monthly fuel
adjustment clause for all electric utilities in Kentucky subject to the
jurisdiction of the Kentucky Commission. The Kentucky Commission's regulation is
based on a formula approved by FERC but with certain modifications, including
the exclusion of excess fuel expense attributable to certain forced outages, the
filing of fuel procurement documentation, a procedure for billing over- and
under-recoveries of fuel cost fluctuations from the base rate level and
provision for periodic public hearings to review past adjustments, to make
allowance for any past adjustments found not justified, to disallow any improper
expenses and to re-index base rates to include current fuel costs. The fuel
adjustment clause mechanism for Virginia customers uses an average fuel cost
factor based primarily on projected fuel costs. The fuel cost factor may be
adjusted annually for over- or under collections of fuel costs from the previous
year.
As of February 12, 1999, the Kentucky Commission ordered KU's affiliate utility,
LG&E, to refund FAC charges to retail electric customers after a review of
LG&E's FAC from November 1994 through April 1998. The Kentucky Commission
subsequently on March 11, 1999, denied LG&E's Petition for Rehearing for the
period November 1994 through October 1996, but granted rehearing for the period
November 1996 through April 1998 on the same issue. KU has not received an order
from the Kentucky Commission but estimates that it may be required to refund to
its retail electric customers up to $3.5 million in FAC charges for the period
November 1994 through October 1998.
Rate regulation in Kentucky allows each electric utility, with the Kentucky
Commission's approved environmental compliance plan and environmental surcharge,
to recover on a current basis the cost of complying with federal, state or local
environmental requirements, including the Federal Clean Air Act as amended,
applicable to coal combustion wastes and byproducts from facilities utilized for
the production of energy from coal. In 1994, the Kentucky Commission approved
KU's environmental surcharge, which is designed to allow KU to recover
compliance related operating expenses and to earn a return on those
compliance-related capital expenditures not already included in existing rates
through the application of the surcharge each month to customers' bills.
Surcharge billings are subject to periodic Kentucky Commission review of the
level of environmental expenditures and reconciliation of previous surcharge
billings with actual costs. For additional information regarding the
environmental surcharge, including information concerning pending legal
proceedings, see Note 3 of KU's Notes to Financial Statements and Note 5 of LG&E
Energy Corp.'s Notes to Financial Statements under Item 8.
14
The Commission's order approving the surcharge in the KU case and the
constitutionality of the surcharge was challenged by certain intervenors,
including the Attorney General of Kentucky, in Franklin Circuit Court. Decisions
of the Circuit Court and the Kentucky Court of Appeals in July 1995 and December
1997, respectively, have upheld the constitutionality of the ECR statute but
differed on a claim of retroactive recovery of certain amounts. The Commission
ordered that certain surcharge revenues collected by KU be subject to refund
pending final determination of all appeals.
On December 19, 1998, the Kentucky Supreme Court rendered an opinion upholding
the constitutionality of the surcharge statute. The decision, however, reversed
the ruling of the Court of Appeals on the retroactivity claim, thereby denying
recovery of costs associated with pre-1993 environmental projects through the
ECR. The court remanded the case to the Commission to determine the proper
adjustments to refund amounts collected for such pre-1993 environmental
projects. The parties to the proceeding have notified the Commission that they
have reached agreement as to the terms, proper adjustments and forward
application of the ECR. The settlement agreement is subject to Commission
approval. KU recorded a provision for rate refund of $21.5 million in December
1998. See Rates and Regulation for KU and LG&E Energy Corp. under Item 7 for a
further discussion.
Integrated resource planning regulations in Kentucky require KU and the other
major utilities to make triennial filings with the Kentucky Commission of
various historical and forecasted information relating to forecasted load,
capacity margins and demand-side management techniques.
Pursuant to Kentucky law, the Kentucky Commission has established the boundaries
of the service territory or area of each retail electric supplier in Kentucky
(including KU), other than municipal corporations, within which each such
supplier has the exclusive right to render retail electric service.
The Virginia Commission requires each Virginia utility to make annual filings of
either a base rate change or an Annual Informational Filing consisting of a set
of standard financial schedules. These filings are subject to review by the
Virginia Commission Staff (Staff). The Staff issues a Staff Report, which
includes any findings or recommendations to the Virginia Commission relating to
the individual utility's financial performance during the historic 12-month
period, including previously accepted adjustments. The Staff Report can lead to
an adjustment in rates.
As a result of its ownership in EEI, KU is considered a holding company under
the Holding Company Act. KU however is presently exempt from all the provisions
of the Holding Company Act, except Section 9(a)(2) thereof (which relates to the
acquisition of securities of public utility companies), by virtue of the
exemption granted by an order of the Securities and Exchange Commission.
For information regarding regulatory matters related to the merger of LG&E
Energy and KU Energy, see Note 2 of KU's Notes to Financial Statements and Note
2 of LG&E Energy Corp.'s Notes to Financial Statements under Item 8.
In October 1998, LG&E and KU filed separate but parallel applications with the
Commission for approval of a new method of determining electric rates that
provides financial incentives for LG&E and KU to further reduce customers'
rates. The filing was made pursuant to the September 1997 Commission order
approving the merger of LG&E Energy and KU Energy, wherein the Commission
directed LG&E and KU to indicate whether they desired to remain under
traditional rate of return regulation or commence non-traditional regulation.
The new ratemaking method, known as performance-based ratemaking (PBR), would
include financial incentives for LG&E and KU to reduce fuel costs and increase
generating efficiency, and to share any resulting savings with customers.
Additionally, the PBR provides financial penalties and rewards to assure
continued high quality service and reliability.
15
The PBR plan proposed by LG&E and KU consists of five components:
The utilities' fuel adjustment clause mechanism will be withdrawn and
replaced with a cap that limits recovery of actual changes in fuel cost to
changes in a fuel price index for a five-state region. If the utilities
outperform the index, benefits will be shared equally between shareholders
and customers. If the utilities' fuel costs exceed the index, the difference
will be absorbed by LG&E Energy's shareholders.
Customers will continue to receive the benefits from the post-merger joint
dispatch of power from LG&E's and KU's generating plants.
Power plant performance will be measured against the best performance
achieved between 1991 and 1997. If the performance exceeds this level,
customers will share equally with LG&E Energy's shareholders in up to $10
million annually of benefits from this performance at each of LG&E and KU.
The utilities will be encouraged to maintain and improve service quality,
reliability, customer satisfaction and safety, which will be measured
against six objective benchmarks. The plan provides for annual rewards or
penalties to LG&E Energy of up to $5 million per year at each of LG&E and
KU.
The plan provides the utilities with greater flexibility to customize rates
and services to meet customer needs. Services will continue to be priced
above marginal cost and customers will continue to have the option to elect
standard tariff service.
These proposals are subject to approval by the Commission. Approval proceedings
commenced in October 1998 and a final decision may occur in 1999. Several
intervenors are participating in the case. Some have requested that the
Commission reduce base rates before implementing PBR.
On March 8, 1999, the Kentucky Industrial Utility Customers filed a Complaint
with the Kentucky Commission alleging that KU's electric rates are excessive and
should be reduced by an amount between $42 and $56 million, and that the
Kentucky Commission establish a proceeding to reduce KU's rates. KU has asked
the Kentucky Commission to dismiss the Complaint.
KU is not able to predict the ultimate outcome of these proceedings, however,
should the Commission mandate significant rate reductions at KU, through the PBR
proposal or otherwise, such actions could have a material effect on KU's
financial condition and results of operations.
Construction Program and Financing
KU's construction program is designed to ensure that there will be adequate
capacity and reliability to meet the electric and gas needs of its service area.
These needs are continually being reassessed and appropriate revisions are made,
when necessary, in construction schedules. KU's estimates of its construction
expenditures can vary substantially due to numerous items beyond KU's control,
such as changes in rates, economic conditions, construction costs, and new
environmental or other governmental laws and regulations.
During the last five years ended December 31, 1998, construction expenditures
aggregated about $609 million, which included four 126-Mw combustion turbine
peaking units. The first peaking unit was placed into commercial operation in
late 1994. The second and third units were placed into commercial operation in
February 1995 and December 1995, respectively. The fourth unit was placed into
commercial operation in May 1996.
16
Coal Supply
Coal-fired generating units provided more than 98% of KU's net kilowatt- hour
generation for 1998. The remainder of KU's net generation for 1998 was provided
by oil and/or natural gas burning units and hydroelectric plants. The average
delivered cost of coal purchased per million BTU (MBTU) and the percentage of
spot coal purchases for the periods indicated were as follows:
1998 1997 1996
---- ---- ----
Per ton $26.97 $27.97 $27.54
Per MBTU - all sources $1.12 $1.15 $1.14
Per MBTU - spot purchases only $1.10 $1.12 $1.08
Spot purchases as % of all sources 42% 34% 33%
The price of coal, due to using low sulfur content coal and transportation costs
are expected to increase slightly during 1998.
KU maintains its fuel inventory at levels estimated to be necessary to avoid
operational disruptions at its coal-fired generating units. Reliability of coal
deliveries can be affected from time to time by a number of factors, including
fluctuations in demand, coal mine labor issues and other supplier or transporter
operating difficulties.
KU believes there are adequate reserves available to supply its existing
base-load generating units with the quantity and quality of coal required for
those units throughout their useful lives. KU intends to meet a substantial
portion of its coal requirements with three-year or shorter contracts. As part
of this strategy, KU will continue to negotiate replacement contracts as
contracts expire. KU does not anticipate any problems negotiating new contracts
for future coal needs. The balance of coal requirements will be met through spot
purchases. KU had on hand at December 31, 1998, a coal inventory of
approximately 866,000 tons, or a 42 day supply.
KU expects, for the foreseeable future, to continue purchasing most of its coal,
which has a sulfur content in the .7% - 3.5% range, from western and eastern
Kentucky, West Virginia, southwest Indiana and Pennsylvania.
Coal for Ghent is delivered by barge. Deliveries to the Tyrone, Green River and
Pineville locations are by
truck. Delivery to E.W. Brown is by rail.
KU has no long-term contracts in place for the purchase of natural gas for its
combustion turbine peaking units. KU has met its gas requirements through spot
purchases and does not anticipate encountering any significant problems
acquiring an adequate supply of fuel necessary to operate its peaking units.
Environmental Matters
Protection of the environment is a major priority for KU. KU engages in a
variety of activities within the jurisdiction of federal, state, and local
regulatory agencies. Those agencies have issued KU permits for various
activities subject to air quality, water quality, and waste management laws and
regulations. For the five year period ending with 1998, expenditures for
pollution control facilities represented $174 million or 29% of total
construction expenditures. See Note 11 of KU's Notes to Financial Statements and
Note 18 of LG&E Energy's Notes to Financial Statements under Item 8.
17
Competition
KU has taken many steps to prepare for the expected increase in competition in
its industry, including a reduction in the number of employees; aggressive cost
cutting; an increase in focus on not only commercial and industrial customers,
but residential customers as well; an increase in employee involvement and
training; and continuous modifications of its organizational structure. KU could
take additional steps like these to better position itself for competition in
the future.
LG&E CAPITAL CORP.
LG&E Capital Corp. (Capital Corp.), the holding company for all non-utility
investments, was formed on September 5, 1997, when the Company merged two of its
former direct subsidiaries, LG&E Energy Systems Inc. and LG&E Gas Systems Inc.,
and renamed the company LG&E Capital Corp. On July 24, 1998, KU Capital
Corporation (KU Capital), a former subsidiary of KU Energy, was merged into
Capital Corp., with the latter as the survivor corporation.
As previously discussed in item 1 under Discontinuance of Merchant Energy
Trading and Sales Business, effective June 30, 1998, the Company discontinued
this business operation. For a more detailed discussion of the discontinuance of
the Company's merchant energy trading and sales business, see Discontinued
Operations under this Item, and Notes 3 and 18 of LG&E Energy's Notes to
Financial Statements under Item 8.
Capital Corp. conducts its operations through three principal business segments:
Independent Power Operations, Western Kentucky Energy and Argentine Gas
Distribution. See Note 20 of LG&E Energy's Notes to Financial Statements under
Item 8.
INDEPENDENT POWER OPERATIONS
General
Capital Corp.'s Independent Power Operations (Power Operations) develop,
operate, maintain and own domestic and international power generation facilities
that sell electric and steam energy to utility and industrial customers. Power
Operations currently has domestic ownership interests in projects capable of
generating nearly 600 Mw of electric power in North Carolina, Virginia,
California, Minnesota, Texas and Washington, and international ownership
interest in a windpower generating facility in Tarifa, Spain. Additionally,
Power Operations owns and / or has ownership interests in eight combustion
turbines. Ownership interests in each of these projects and the revenues from
the sale of electricity and steam are pledged as security to the lenders which
provided the financing. See Item 2, Properties, for a listing of the Power
Operations' projects.
On March 15, 1999, LG&E Westmoreland - Rensselaer, in which Power Operations has
a 50% interest, sold the assets of the Rensselaer cogeneration facility. This
transaction will result in a pre-tax gain for Power Operations of approximately
$14.5 million.
In June 1998, Power Operations entered into a partnership with Columbia Electric
Corporation for the development of a natural gas-fired cogeneration project in
Gregory, Texas, providing electricity and steam equivalent of 550 Mw.
Construction commenced in August 1998 and non-recourse financing for a majority
of the construction and other costs was obtained in November 1998. The project
will sell steam and a portion of its electric output to Reynolds Metals Company.
A medium-term fixed-price contract has also been entered into with a third party
for a portion of the remaining electric output. The project is expected to begin
commercial operation in the summer of 2000. The Company's equity contribution is
expected to be approximately $30 to $35 million in connection with its 50%
interest in the project.
18
In February 1998, Power Operations sold its interest in a 114-Mw natural
gas-fired power plant in North Central Argentina.
Fuel Supply
Power Operations operates five coal fired and three wind plants. See Item 2,
Properties. Coal supply needed by Power Operations is under long-term contracts
expiring at various times from 2008 through 2014. Each contract has two
five-year renewal options. All coal is delivered by rail.
Customer Base
Each project has long-term power purchase agreements with a single power
purchaser, except one of the Tenaska Limited Partnerships which has two. The
power purchasers are Virginia Electric and Power (VEPCO) for Southampton,
Altavista, and Hopewell in Virginia and Roanoke Valley I (ROVA I) and Roanoke
Valley II (ROVA II) in North Carolina; Southern California Edison Co. for
Windpower Partners 1993 (WPP 93) in California; Northern States Power Company
for WPP 93 in Minnesota; Lower Colorado River Authority for Windpower Partners
1994 (WPP 94), Brazos Electric Power Cooperative for Tenaska Limited
Partnerships (TLP), Texas Utilities Electric Company for TLP and Campbell Soup
for TLP in Texas; Puget Sound Power & Light for TLP in Washington; and Compania
Sevillana de Electricidad for K.W. Tarifa in Spain. WPP 94 also sells excess
power to Texas Utilities. See Item 2, Properties, for a listing of Power
Operations projects.
Each of Power Operations combustion turbines are leased to utility companies.
The lessees are Portland General Electric Company (Portland General) in Oregon,
Arkansas Power and Light Company in Arkansas and Puget Sound Power & Light
Company in Washington. The leases expire in 1999. Upon expiration each of the
leases, each of the lessees has the option to extend the lease, purchase the
unit or allow the lease to terminate. Portland General has notified the Company
that it will exercise its rights to purchase the units covered by its leases
when they expire.
Regulatory Environment
Except for its investments in wind power and ROVA I, each of Power Operations'
projects in the United States is a qualifying cogeneration facility (QF) under
the Public Utility Regulatory Policy Act of 1978 (PURPA). See Item 3 and Note 18
of LG&E Energy Corp.'s Notes to Financial Statements under Item 8 for a
discussion of certain issues regarding past operations at certain of these
facilities. Certain partnerships, in which companies in the Power Operations
business segment have ownership interests, are operating wind power facilities
which are qualifying small power production facilities under PURPA. In addition,
Power Operations has obtained exempt wholesale generator (EWG) status for the
entities which own the ROVA I and ROVA II projects in North Carolina and the
Southampton, Altavista and Hopewell projects in Virginia.
Generally, QF status exempts projects from the application of the Holding
Company Act, many provisions of the Federal Power Act, and state laws and
regulations respecting rates and financial or organization regulation of
electric utilities. EWGs also are exempt from application of the Holding Company
Act and many provisions of the Federal Power Act, but once such an entity files
its electric generation rates with FERC, it becomes a jurisdictional public
utility under the Federal Power Act. As a "public utility," an EWG's rates and
some of its corporate activities are subject to FERC regulation. EWGs also are
subject to non-rate regulation under state laws governing electric utilities.
While QF or EWG status entitles Power Operations' projects to certain regulatory
exceptions and benefits under PURPA and the Holding Company Act, each project
must still comply with other federal, state and local laws, including those
regarding siting, construction, operation, licensing and pollution abatement.
19
The foreign power generation facility in which Power Operations has an ownership
interest has obtained foreign utility company (FUCO) status under the Holding
Company Act. Generally, FUCO status exempts this facility from application of
the Holding Company Act.
Commitments & Contingencies
In January 1999, a final order was entered in the bankruptcy proceedings
involving Westmoreland Coal Company and certain of its subsidiaries, including
Westmoreland Energy, Inc., the parent of various entities that are partners in
four of Power Operations' independent generating facilities. However, none of
the partnerships and no partner of the current partnerships has been under
bankruptcy court protection, nor were these partnerships in a default occasioned
under the project loan documents. See Note 18 of LG&E Energy Corp.'s Notes to
Financial Statements under Item 8.
Westmoreland-LG&E Partners (WLP), the partnership that owns the ROVA I and II
facilities, is seeking the recovery of capacity payments withheld by VEPCO. In
November 1998, the Circuit Court for the City of Richmond, Virginia, issued a
decision awarding WLP approximately $19 million, plus interest until paid, and
ruled WLP was entitled to receive future capacity payments for eligible forced
outages during the remainder of the PPA term. In January 1999, VEPCO filed a
notice of appeal regarding the Circuit Court decision. See Note 18 of LG&E
Energy Corp.'s Notes to Financial Statements under Item 8.
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 and various windpower projects located in the U.S. and abroad.
Included in these projects are the WPP 93, WPP 94 and KW Tarifa, S.A. (Tarifa)
wind projects in which Power Operations has invested, collectively,
approximately $31 million. See Note 18 of LG&E Energy Corp.'s Notes to Financial
Statements under Item 8.
WPP 94, in which the Company has a 25% interest through indirect subsidiaries,
did not make its semiannual payments, due September 1997, March 1998, September
1998 and March 1999, to John Hancock Mutual Life Insurance Company (Hancock)
under certain notes issued by WPP94 to Hancock. WPP 94 and Hancock are presently
engaged in discussions concerning a possible restructuring of WPP 94's debt
obligations. 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. During the third quarter of 1998, the
Company wrote off its aggregate remaining investment in WPP94. See Note 18 of
LG&E Energy Corp.'s Notes to Financial Statements under Item 8.
WESTERN KENTUCKY ENERGY
General
In July 1998, following receipt of necessary regulatory approvals, the Company
closed the transaction to lease the generating assets of Big Rivers. Under the
25-year operating lease, Western Kentucky Energy Corp. and its affiliates (WKE)
lease and operate the operating assets of Big Rivers (three coal-fired plants
and one combustion turbine). In addition, WKE operates and maintains the Station
Two generating facility of the City of Henderson (Henderson). The combined
generating capacity of these facilities amounts to approximately 1,700 Mw, net
of Henderson's capacity and energy needs from Station Two. Under the terms of
the lease agreement, WKE paid Big Rivers a total of $55.9 million for the first
two years and will pay $31.0 million for each of the remaining 23 years. In
addition, WKE purchased Big Rivers' inventory, personal property and emission
allowances, and made a one-time payment to Big Rivers of $12.1 million.
20
In related transactions, power is supplied to Big Rivers at contractual prices
over the term of the lease to meet the needs of four member distribution
cooperatives serving approximately 91,000 customers in 22 western Kentucky
counties and two aluminum smelters. The excess generating capacity is available
to WKE to market throughout the region.
Also, as part of the transaction, WKE agreed to provide Big Rivers a $50.0
million note to help it emerge from bankruptcy. The terms of the note are that
WKE will provide $1.7 million per month for the first 12 months beginning August
1998 and $2.5 million per month over the subsequent 12 months. The note will be
repaid over a three-year period, beginning August 2000, with interest at 7.165%.
WKE's business is affected by seasonal weather patterns. As a result, operating
revenues (and associated expenses) are not generated evenly throughout the year.
Construction Program and Financing
In connection with these transactions, WKE has undertaken to bear certain of the
future capital requirements of these generating assets. WKE's estimates of its
construction expenditures can vary substantially due to numerous items beyond
WKE's control, such as economic conditions, construction costs, and new
environmental or other governmental laws and regulations. During 1998 gross
property additions amounted to $11.8 million excluding personal property
acquired from Big Rivers. Internally generated funds and intercompany financing
from Capital Corp. provided 100% of the construction expenditures.
Coal Supply
Coal-fired generating units provided 90% of the electric generating capacity
controlled by WKE, the remainder being made up of a combustion turbine peaking
unit fueled by fuel oil. Coal will be the predominant fuel used by WKE, with
fuel oil being used for peaking capacity. WKE has entered into coal supply
agreements with various suppliers for coal deliveries for 1999 and beyond. WKE
normally augments its coal supply agreements with spot market purchases. At
December 31, 1998, WKE had on hand coal inventory of approximately 1.1 million
tons, or a 75 day supply.
WKE expects, for the foreseeable future, to continue purchasing most of its
coal, which has a sulfur content in the 2%-4.5% range, from western Kentucky and
southwest Indiana. The abundant supply of this relatively low priced coal,
combined with present and future desulfurization technologies, is expected to
enable WKE to continue to provide adequate electric service in a manner
acceptable under existing environmental laws and regulations.
Coal for WKE's operations are delivered by barge and truck.
The average delivered cost per ton of coal purchased by WKE for 1998 was $20.85.
Environmental Matters
In September 1998, the U.S. Environmental Protection Agency announced its final
regulation requiring significant additional reductions in NOx emissions to
mitigate alleged ozone transport to the Northeast. While each state is free to
allocate its assigned NOx reductions among various emissions sectors as it deems
appropriate, the regulation may ultimately require utilities to reduce their NOx
emissions to 0.15 lb./mmBtu (million British thermal units) - an 85% reduction
from 1990 levels. Under the regulation, each state must incorporate the
additional NOx reductions in its State Implementation Plan (SIP) by September
1999 and affected sources must install control measures by May 2003, unless
granted extensions. Several states, various
21
labor and industry groups, and individual companies have appealed the final
regulation to the U.S. Court of Appeals for the D.C. Circuit. Management is
currently unable to determine the outcome or exact impact of this matter until
such time as the states identify specific emissions reductions in their SIP and
the courts rule on the various legal challenges to the final rule. However, if
the 0.15 lb. target is ultimately imposed, WKE will be required to incur
significant capital expenditures and increased operation and maintenance costs
for additional controls. Subject to further study and analysis, WKE estimates
that it may incur capital costs of approximately $100 million. These costs would
generally be incurred beginning in 2000.
WKE engages in a variety of activities within the jurisdiction of federal, state
and local regulatory agencies. Those agencies have issued WKE permits for
various activities subject to air quality, water quality and waste management
laws and regulations. During 1998, expenditures for pollution controlled
facilities represented $.5 million of WKE's construction expenditures. See Note
18 of LG&E Energy's Notes to Financial Statements under Item 8 for a discussion
of specific environmental proceedings.
ARGENTINE GAS DISTRIBUTION
General
In February 1997, the Company acquired interests in two Argentine natural gas
distribution companies. Capital Corp., through a subsidiary, purchased a
controlling interest in Distribuidora de Gas del Centro (Centro) and a minority
interest in Distribuidora de Gas Cuyana (Cuyana). Centro and Cuyana together
serve approximately 706,000 customers in six provinces in Argentina. The
investment in these companies totaled approximately $140 million. Each of these
companies has obtained foreign utility company (FUCO) status under the Holding
Company Act. Generally, FUCO status exempts these facilities from application of
the Holding Company Act.
Gas Operations
Centro's and Cuyana's primary source of gas supply is YPF, S.A., and its primary
source of gas transmission is TGN, S.A. Centro and Cuyana have no underground
storage facilities.
The Argentine federal regulator of gas transmission and distribution, Energas,
has granted Centro a concession that gives Centro the exclusive right to
distribute natural gas in its service territories. The concession ends in 2028.
Centro and Cuyana have been granted exclusive 35-year concessions to provide gas
distribution services to their respective service territories. These
concessions, which originally expire in 2028, also contain the possibility of a
single 10-year extension.
Centro derives approximately 12% of its revenues from electric power plants
located in its service territory. Some of these power plants are state-owned.
Centro sells gas to these plants under contracts ranging from two to 15 years.
Construction Program and Financing
Centro's capital expenditures for 1998 totaled $15 million and were financed
internally. Centro will spend approximately $30 million in 1999 to expand and
maintain its gas distribution network, and it will finance the expenditures
through borrowings and internal sources.
22
DISCONTINUED OPERATIONS
General
Effective June 30, 1998, the Company discontinued its merchant energy trading
and sales business and announced a plan to sell its natural gas gathering and
processing business (Gas Operations). For a more detailed discussion of the
costs incurred see Discontinuance of Merchant Energy Trading and Sales Business
previously discussed in this Item and Notes 3 and 18 of LG&E Energy's Notes to
Financial Statements under Item 8.
Product and Services
The merchant energy trading and sales business consisted primarily of a
portfolio of energy marketing contracts entered into in 1996 and 1997,
nationwide deal origination and some level of speculative trading activities,
which were not directly supported by the Company's physical assets.
Capital Corp.'s Gas Operations, conducted through various subsidiaries, include:
a transportation operation consisting of a 90-mile intrastate pipeline located
in southeast New Mexico (Llano pipeline); gathering and processing operations
consisting of 1,200 miles of pipeline concentrated in southeastern New Mexico
and the Permian Basin of west Texas; and a 6.0 Bcf gas storage facility
connected to the Llano pipeline. For a more detailed explanation of these assets
see Item 2, Properties.
The Llano pipeline has a design capacity of approximately 180,000 Mcf of gas per
day and is capable of delivering gas to three different interstate pipelines.
Capital Corp., through its various subsidiaries, purchases gas from over 50
producers connected to the Llano pipeline and sells the gas directly to end-user
customers or delivers the gas into one of the interstate pipelines for sale.
Also, through its various subsidiaries, Capital Corp. transports natural gas
through the Llano pipeline for third parties and is paid a transportation fee
for such services. An average of approximately 100,000 Mcf of natural gas per
day moved through the Llano pipeline in 1998.
The 11 gathering systems owned (seven 100%, one leased and ownership interests
ranging from 11% to 50% in three others) and operated during 1998 gathered
approximately 205,000 Mcf of natural gas per day during 1998. During 1998,
Capital Corp. divested itself of its three partially owned gathering systems.
Connected to the Llano pipeline are two operating natural gas processing
facilities capable of processing approximately 85,000 MMBtu of natural gas per
day. These facilities extract natural gas liquids, including propane, ethane,
butanes and natural gasoline, from the natural gas stream, at which point the
mixed stream of liquids is sold. Approximately 215,000 gallons per day of
natural gas liquids were extracted and sold from these facilities in 1998.
Also connected to the Llano pipeline is a natural gas storage facility. As noted
above, this facility has current working capacity of approximately 6.0 Bcf.
Capital Corp., through a subsidiary, offers this storage capacity to third
parties on a fee basis. As of December 31, 1998, storage capacity of
approximately 3.0 Bcf was leased to other parties.
Governmental Regulations
The production, transportation and certain sales of natural gas are subject to
federal, state or local regulations which have a significant impact upon Capital
Corp.'s energy products and services businesses. Regulation at the federal level
of domestically produced or transported natural gas is administered primarily by
the FERC
23
pursuant to the Natural Gas Act (NGA) and the Natural Gas Policy Act of 1978
(NGPA). Maximum selling prices of certain categories of gas, whether sold in
interstate or intrastate commerce, previously were regulated pursuant to NGPA.
The NGPA established various categories of gas and provided for graduated
deregulation of price controls of several categories of gas and the deregulation
of sales of certain categories of gas. All price deregulation contemplated under
the NGPA has already taken place. Subsequently, the Natural Gas Wellhead
Decontrol Act of 1989 terminated all NGA and NGPA regulation of "first sales" of
domestic natural gas on January 1, 1993. The sale for resale of certain natural
gas in interstate commerce is regulated, in part, pursuant to the NGA, which
requires certificate and abandonment authority to initiate and terminate such
sales. In addition, natural gas marketed by a Capital Corp. subsidiary is
usually transported by interstate pipeline companies that are subject to the
jurisdiction of the FERC. Similarly, some of the transportation and storage
services provided by Llano are subject to FERC regulation under section 311 of
the NGPA. These services are frequently sold to gas distribution companies that
contract with interstate pipeline companies for transportation from the Llano
facility to their respective service areas. Section 311 permits intrastate
pipelines under certain circumstances to sell gas to, transport gas for, or have
gas transported by, interstate pipeline companies, and assign contract rights to
purchase surplus gas from producers to interstate pipeline companies without
being regulated as interstate pipelines under the NGA. Capital Corp., through a
subsidiary, submitted a rate case for transportation and storage rates to the
FERC in 1998 which was approved without intervention.
Commitments and Contingencies
For discussions of lawsuits filed as a result of the Company's discovery in the
fourth quarter of 1996 that unauthorized transactions had occurred in its gas
trading business, a lawsuit related to the failure to sell electricity to the
Company pursuant to an interchange agreement, and an arbitration proceeding
related to load projections provided as inducement to enter into a power supply
agreement see Note 18 of LG&E Energy Corp.'s Notes to Financial Statements under
Item 8.
EMPLOYEES AND LABOR RELATIONS
LG&E Energy and its subsidiaries had 5,403 full-time employees at December 31,
1998, including 2,315 full-time employees of LG&E and 1,779 full-time employees
of KU. At December 31, 1998, LG&E had 1,385 operating, maintenance, and
construction employees that were members of the International Brotherhood of
Electrical Workers (IBEW) Local 2100. The current three year contract with the
IBEW will expire in November 2001. At December 31, 1998, KU had 233 operating,
maintenance and construction employees who were members of IBEW Local 101 and
United Steelworkers of America (USWA) Local 8686. The current contract will
expire August 1, 1999. At December 31, 1998, WKE had 352 operating, maintenance
and construction employees that were members of the IBEW Local 1701.
The current contract will expire September 14, 2001.
24
ITEM 2. Properties.
LG&E's power generating system consists of the coal-fired units operated at its
three steam generating stations. Combustion turbines supplement the system
during peak or emergency periods. LG&E owns and operates the following electric
generating stations:
Capability
Rating (Kw)
-----------
Steam Stations:
Mill Creek - Kosmosdale, KY.
Unit 1 303,000
Unit 2 301,000
Unit 3 386,000
Unit 4 480,000
----------
Total Mill Creek 1,470,000
Cane Run - near Louisville, KY.
Unit 4 155,000
Unit 5 168,000
Unit 6 240,000
----------
Total Cane Run 563,000
Trimble County - Bedford, KY. (a)
Unit 1 371,000
Combustion Turbine Generators (Peaking capability):
Zorn 16,000
Paddy's Run 43,000
Cane Run 16,000
Waterside 33,000
-----------
Total combustion turbine generators 108,000
-----------
Total capability rating 2,512,000
-----------
-----------
(a) Amount shown represents LG&E's 75% interest in Trimble
County. LG&E is responsible for operation of Unit 1 and is
reimbursed by IMEA and IMPA for expenditures related to
Trimble County based on their proportionate share of
ownership interest. See Note 19 of LG&E Energy Corp.'s
Notes to Financial Statements, Jointly Owned Electric
Utility Plant, under Item 8 for further discussion on
ownership.
LG&E also owns an 80 Mw hydroelectric generating station located in Louisville,
operated under license issued by the FERC.
At December 31, 1998, LG&E's electric transmission system included 21
substations with a total capacity of approximately 11,071,700 Kva and
approximately 652 structure miles of lines. The electric distribution system
included 82 substations with a total capacity of approximately 3,313,730 Kva,
3,659 structure miles of overhead lines, 341 miles of underground conduit, and
5,451 miles of underground conductors.
LG&E's gas transmission system includes 209 miles of transmission mains, and the
gas distribution system includes 3,720 miles of distribution mains.
25
LG&E operates underground gas storage facilities with a current working gas
capacity of approximately 14.6 million Mcf. See Gas Supply under Item 1.
In 1990, LG&E entered into an operating lease for its corporate office building
located in downtown Louisville, Kentucky. The lease is for a period of 15 years
and is scheduled to expire June 2005. LG&E Energy has operating leases for its
corporate office space that expire between 1999 and 2012.
Other properties owned by LG&E include office buildings, service centers,
warehouses, garages, and other structures and equipment, the use of which is
common to both the electric and gas departments.
The trust indenture securing LG&E's First Mortgage Bonds constitutes a direct
first mortgage lien upon much of the property owned by LG&E.
KU's power generating system consists of the coal-fired units operated at its
five steam generating stations. KU owns and operates the following electric
generating stations:
Capability
Rating (kw)
-----------
Steam Stations:
Tyrone - Tyrone, KY.
Unit 1 30,000
Unit 2 33,000
Unit 3 73,000
-----------
Total Tyrone 136,000
Green River - South Carrollton, KY.
Unit 1 29,000
Unit 2 30,000
Unit 3 73,000
Unit 4 107,000
----------
Total Green River 239,000
E.W. Brown - Burgin, KY.
Unit 1 106,000
Unit 2 170,000
Unit 3 441,000
----------
Total E.W. Brown 717,000
Pineville - Four Mile, KY.
Unit 3 34,000
Ghent - Ghent, KY.
Unit 1 487,000
Unit 2 497,000
Unit 3 513,000
Unit 4 500,000
----------
Total Ghent 1,997,000
26
Capability
Rating (kw)
-----------
Combustion Turbine Generators (Peaking capability):
E.W. Brown - Burgin, KY.
Unit 8 135,000
Unit 9 120,000
Unit 10 135,000
Unit 11 122,000
----------
Total E.W. Brown 512,000
Haefling - Lexington, KY.
Unit 1 59,000
-----------
Total capability rating 3,694,000
----------
----------
Substantially all properties are subject to the lien of KU's Mortgage Indenture.
KU also owns a 24 Mw hydroelectric generating station located in Burgin,
Kentucky, operated under license issued by the FERC.
At December 31, 1998, KU's electric transmission system included 107 substations
with a total capacity of approximately 14,538,240 Kva and approximately
4,272,330 structure miles of lines. The electric distribution system included
437 substations with a total capacity of approximately 4,302,120 Kva, 4,272
structure miles of overhead lines.
At December 31, 1998, Power Operations owned the percentage indicated of the
following joint ventures:
Net
Ownership Capability
Name Interest % Fuel Rating (Mw)
------- ---------- ---- -----------
LG&E Westmoreland-Southampton 50 Coal 63
Franklin, Virginia
LG&E Westmoreland-Altavista 50 Coal 63
Altavista, Virginia
LG&E Westmoreland-Hopewell 50 Coal 63
Hopewell, Virginia
Westmoreland-LG&E Partners 50 Coal 165
(Roanoke Valley I)
Weldon, North Carolina
LG&E Westmoreland-Rensselaer 50 Natural 79
Rensselaer, New York (sold March 15, Gas
1999 - see below)
Windpower Partners 1993 L.P. 50 Wind 43
Palm Springs, California
Windpower Partners 1993 L.P. 50 Wind 25
Buffalo Ridge, Minnesota
27
Net
Ownership Capability
Name Interest % Fuel Rating (Mw)
------ ---------- ---- -----------
Windpower Partners 1994 L.P. 25 Wind 25-35
Culberson County, Texas
Westmoreland-LG&E Partners 50 Coal 44
(Roanoke Valley II)
Weldon, North Carolina
K.W. Tarifa, S.A. 46 Wind 30
Tarifa, Spain
Tenaska Limited Partnerships 5-10 Gas 223-258
Power Operations' ownership interests in these projects (except Rensselaer) and
the revenues from the sale of electricity and steam from the projects are
pledged as security to the lenders who provided the financing for the project.
See Note 18 of LG&E Energy Corp.'s Notes to Financial Statements under Item 8
for a discussion of the bankruptcy filing of an affiliate of Power Operations'
partner in the Southampton, Altavista, Hopewell, Rensselaer and Roanoke Valley
joint ventures. Also, see the same note for a discussion of the bankruptcy
filing of an affiliate of Power Operations' partner in the Windpower Partners
1993 and Windpower Partners 1994 joint ventures. See Note 8 of LG&E Energy
Corp.'s Notes to Financial Statements under Item 8.
On March 15, 1999, LG&E Westmoreland - Rensselaer, in which Power Operations has
a 50% interest, sold the assets of the Rensselaer cogeneration facility. This
transaction will result in a pre-tax gain for Power Operations of approximately
$14.5 million.
At December 31, 1998, Power Operations owned equity interests in the following
combustion turbine units which are leased to utility companies. The leases
expire in 1999. Upon expiration of each of the leases, each of the lessees has
the option to extend the lease, purchase the unit or allow the lease to
terminate.
Capacity
Ownership (Mw)
Unit Quantity Fuel Interest % Per Unit
----- -------- ---- ---------- --------
Beaver, OR 2 Gas/Oil 100 59.3
Blytheville, AR 3 Gas 49 64.6
Beaver, OR 2 Gas/Oil 49 59.3
Ferndale, WA 1 Gas 49 56.9
Portland General Electric Company (Portland General) is the lessee of the units
in Beaver, Arkansas Power & Light Company (AP&L) is the lessee of the units in
Blytheville, and Puget Sound Power & Light Company (PSP&L) is the lessee of the
unit in Ferndale.
Portland General has agreed to purchase the four units in Beaver for
approximately $20 million. This transaction is expected to close in the second
half of 1999. AP&L has decided to allow its lease to terminate and not to buy
the turbines in Blytheville. PSP&L has not decided if it will exercise its
option to extend its lease, purchase the unit in Ferndale, or allow its lease to
terminate.
28
Capital Corp., through certain subsidiaries, owns or has an interest in eight
gas gathering systems consisting of 1,200 miles of pipeline (of which it owns
100% of four, leases one, and has ownership interests ranging from 11% to 50% in
the other three). These systems are located in Texas, New Mexico, Louisiana,
Montana and Oklahoma. These gas gathering systems make up part of the Company's
Merchant Energy Trading and Sales Business, which the Company discontinued
effective June 30, 1998. See Discontinued Operations under this Item.
The major gas gathering system is the Llano pipeline, a 90-mile intrastate
pipeline system in southeastern New Mexico with a throughput capacity of 180,000
MCF of gas per day. Capital Corp., through subsidiaries, owns two gas
transmission systems located in Texas which total 76 miles. This system has a
design capacity of 90,000 MCF of gas per day. It also owns, or has interests in,
and operates five natural gas processing plants located in southeastern New
Mexico and western Texas with a total design capacity of 125,000 MCF of gas per
day (owns 100% interests in three of these plants, and a majority of the two
remaining plants). Only three of the five plants are active currently. In
addition, Capital Corp. owns and operates a sour gas treating facility in Texas
and an underground natural gas storage facility adjacent to the Llano pipeline
in southeastern New Mexico with a current working capacity of approximately six
BCF of natural gas. The Llano pipeline makes up part of the Company's Merchant
Energy Trading and Sales Business, which the Company discontinued effective June
30, 1998.
WKE is leasing and operating for 25 years all of the generating assets owned by
Big Rivers, a Henderson, Kentucky-based power generation cooperative with 1,459
Mw of owned net generating capacity. Big Rivers owns three coal-fired plants and
one combustion turbine. In addition, WKE operates a 312 Mw coal-fired facility
owned by the City of Henderson, Kentucky, with contractual rights to any surplus
power generated by such facility, which historically has been about 80% of the
unit's capacity.
Centro's gas transmission and distribution system includes 5,963 miles of
transmission mains and distribution mains located in Cordoba, Argentina, and
neighboring provinces. Cuyana's gas transmission and distribution system
includes approximately 4,800 miles of transmission mains and distribution mains
located in Mendoza Province, Argentina, and neighboring provinces.
ITEM 3. Legal Proceedings.
Rates and Regulatory Matters
For a discussion of current regulatory matters, including a discussion of (a)
rate matters addressed in the Kentucky Commission's order approving the KU
Merger, (b) proceedings before the Kentucky Supreme Court and the Kentucky
Commission regarding environmental cost recovery surcharge refunds, and (c) fuel
adjustment clause proceedings before the Kentucky Commission regarding electric
line loss refunds, see Rates and Regulation under Item 7 and Notes 2, 5 and 18
of LG&E Energy Corp.'s Notes to Financial Statements, Note 3 LG&E's Notes to
Financial Statements and Notes 3 of KU's Notes to Financial Statements under
Item 8.
Performance-Based Ratemaking
In October, 1998, LG&E and KU filed applications with the Kentucky Commission
for appeal of a performance-based method for determining electric rates. The
companies' proposals include financial incentives to reduce fuel costs and
increase generating efficiency, as well as financial penalties and rewards in
other performance areas. The proposals are subject to approval by the Kentucky
Commission, with a decision likely to occur during 1999. Certain intervenors
have requested that the Kentucky Commission significantly reduce base rates
before implementing PBR. See Rates and Regulations under Item 7 and Notes 5 and
22 to LG&E Energy's Notes to Financial Statements, Notes 3 and 16 to LG&E's
Notes to Financial Statements and Notes 3
29
and 13 to KU's Notes to Financial Statements.
Fuel Adjustment Clause Proceedings
Pursuant to Kentucky statute, aspects of the Company's utilities rates are
reviewed through semi-annual fuel adjustment clause (FAC) proceedings at the
Kentucky Commission. Although the proceedings are routine, some items are noted
herein. Certain intervenors have challenged KU's recovery of certain energy
charges for power purchased from Owensboro Municipal Utilities and requested
rate refunds for such amounts. Although the outcome of this proceeding cannot be
predicted, the Company believes that, based upon its review of the legal and
regulatory precedence, its position should prevail and that the PSC should not
disallow any of the energy charges in this category for any part of the four
year period. KU estimates the amount of disputed costs to be approximately $12.8
million through October 31, 1998. See also Note 18 to LG&E Energy's Notes to
Financial Statements and Note 11 to KU's Notes to Financial Statements. See
Rates and Regulatory Matters above regarding electric line loss matters arising
during LG&E's and KU's FAC proceedings.
Environmental
For a discussion of environmental matters concerning (a) currently proposed NOx
and SO2 emission limit decreases, (b) issues at LG&E's Mill Creek and Cane Run
generating plants and LG&E's and KU's manufactured gas plant sites, and (c)
other environmental items affecting LG&E Energy and its subsidiaries, see
Environmental Matters under Item 7 and Note 18 of LG&E Energy's Notes to
Financial Statements, Note 12 of LG&E's Notes to Financial Statements and Note
11 of KU's Notes to Financial Statements under Item 8, respectively.
Southampton
For a discussion of the settlement of certain FERC proceedings involving
LG&E-Westmoreland Southampton, the partnership that owns the Southampton
facility, regarding the Southampton facility status as a qualifying facility for
1992, see Note 18 of LG&E Energy Corp.'s Notes to Financial Statements under
Item 8.
Roanoke Valley I
Westmoreland-LG&E Partners (WLP), the partnership that owns the Roanoke Valley I
and II facilities, is seeking the recovery of capacity payments withheld by
Virginia Electric and Power Company (VEPCO). In November 1998, the Circuit Court
for the City of Richmond, Virginia issued an opinion awarding WLP approximately
$19 million plus interest until paid, and addressed certain other issues. In
January 1999, VEPCO appealed the decision. See Item 1 and Note 18 of LG&E Energy
Corp.'s Notes to Financial Statements under Item 8.
Kenetech Bankruptcy
In May 1996, Kenetech Windpower, Inc. (Kenetech) filed for protection under
Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy
Court in the Northern District of California 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, Windpower Partners 1994 and KW Tarifa, S.A. wind projects. In
January 1999, the Bankruptcy Court approved an initial plan of reorganization.
See Note 18 of LG&E Energy Corp.'s Notes to Financial Statements under Item 8
for a further discussion.
30
Windpower Partners 1994
Windpower Partners 1994 (WPP 94), in which the Company has a 25% interest
through indirect subsidiaries, did not make semiannual payments, due September
1997, March 1998, September 1998 and March 1999 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. See
Note 18 of LG&E Energy Corp.'s Notes to Financial Statements under Item 8 for a
further discussion.
Calgary
On November 22, 1996 LG&E Natural Canada Inc., an indirect subsidiary of LG&E
Energy, initiated action in the Court of the Queens Bench of Alberta, Calgary
against a former employee as a result of the discovery that the former employee
had engaged in unauthorized transactions. See Note 18 to LG&E Energy's Notes to
Financial Statements, under Item 8 for a further discussion.
Springfield Municipal Contract
LG&E Energy Marketing Inc. (LEM), an indirect subsidiary of LG&E Energy, filed
suit against the City of Springfield, Illinois, City Water, Light and Power
Company in the United States District Court for the Western District of
Kentucky. See Note 18 to LG&E Energy's Notes to Financial Statements under Item
8 for a further discussion.
Oglethorpe Power Contract
In October 1998, LEM initiated an arbitration proceeding against Oglethorpe
Power Corporation (OPC) in connection with matters involving LEM's November 1996
power sales agreement with OPC. Selection of arbitrators was completed in
February 1999 and discovery proceedings have commenced in this matter. See Note
18 to LG&E Energy's Notes to Financial Statements under Item 8 for a further
discussion.
Other
In the normal course of business, other lawsuits, claims, environmental actions,
and other governmental proceedings arise against LG&E Energy and its
subsidiaries, including LG&E and KU. To the extent that damages are assessed in
any of these lawsuits, LG&E Energy, LG&E and KU believe that their insurance
coverage is adequate. Management, after consultation with legal counsel, does
not anticipate that liabilities arising out of other currently pending or
threatened lawsuits and claims will have a material adverse effect on LG&E's
Energy's, LG&E's or KU's consolidated financial position or results of
operations, respectively.
ITEM 4. Submission of Matters to a Vote of Security Holders.
None.
31
Executive Officers of LG&E Energy Corp.:
Effective Date of
Election to Present
Name Age Position Position
------ --- -------- --------------------
Roger W. Hale 55 Chairman of the Board August 17, 1990
and Chief Executive
Officer
Victor A. Staffieri 43 President and Chief February 16, 1999
Operating Officer
R. Foster Duncan 45 Executive Vice President February 16, 1999
and Chief Financial Officer
Stephen R. Wood 56 President - Distribution May 15, 1997
Services Division
President - Louisville Gas
and Electric Company
Robert M. Hewett 52 President - Kentucky May 4, 1998
Utilities Company
John R. McCall 55 Executive Vice President, July 1, 1994
General Counsel and
Corporate Secretary
Wayne T. Lucas 51 Executive Vice President - May 4, 1998
Power Generation
George W. Basinger 53 Senior Vice President - May 4, 1998
Independent Power
Operations
Donald F. Santa, Jr. 40 Senior Vice President and October 1, 1998
Deputy General Counsel
Frederick J. Newton III 43 Senior Vice President and January 2, 1999
Chief Administrative
Officer
S. Bradford Rives 40 Senior Vice President - February 16, 1999
Finance and Business
Development
Wendy C. Heck 45 Vice President - Infor- February 3, 1998
mation Technology
Charles A. Markel 51 Vice President - January 1, 1993
Finance and Treasurer
Michael D. Robinson 43 Vice President and February 16, 1999
Controller
32
The present term of office of each of the above executive officers extends to
the meeting of the Board of Directors following the Annual Meeting of
Shareholders, scheduled to be held April 21, 1999.
There are no family relationships between executive officers of the Company or
executive officers of its subsidiaries.
Messrs. Hale, Lucas, Duncan, McCall, Newton, Markel and Robinson are also
executive officers of LG&E and KU. Mr. Hale is Chairman of the Board and Chief
Executive Officer of LG&E and KU; Mr. Lucas is Executive Vice President - Power
Generation of LG&E and KU; Mr. Duncan is Chief Financial Officer of LG&E and KU;
Mr. McCall is Executive Vice President, General Counsel and Corporate Secretary
of LG&E and KU; Mr. Newton is Senior Vice President and Chief Administrative
Officer of LG&E and KU; Mr. Markel is Treasurer of LG&E and KU; and Mr. Robinson
is Vice President and Controller of LG&E and KU. Mr. Wood and Ms. Heck are also
officers of LG&E. Mr. Wood is President of LG&E; and Ms. Heck is Vice President
- - Information Technology of LG&E.
Mr. Hale was President of LG&E Energy from December 1992 to May 1998.
Before he was elected to his current position, Mr. Staffieri was Senior Vice
President, Public Policy and General Counsel of LG&E Energy Corp. and LG&E from
November 1992 to January 1994; President of LG&E from January 1994 to May 1997;
President - Distribution Services of LG&E Energy Corp. from December 1995 to May
1997; Chief Financial Officer of LG&E Energy Corp. and LG&E from May 1997 to
February 1999; and Chief Financial Officer of KU from May 1998 to February 1999.
Before he was elected to his current position, Mr. Duncan was Senior Vice
President, Corporate Finance and Business Development of Freeport-McMoRan
Resource Partners from March 1993 to May 1994; Vice President and Corporate
Treasurer of Freeport-McMoRan, Inc. and Freeport-McMoRan Copper & Gold Inc. and
their affiliates from May 1994 to January 1998; and Executive Vice President -
Planning and Development of LG&E Energy Corp. from January 1998 to February
1999.
Before he was elected to his current position, Mr. Wood was Senior Vice
President and Chief Administrative Officer of LG&E from August 1990 to January
1994, and Executive Vice President and Chief Administrative Officer of LG&E
Energy Corp. from January 1994 to May 1997.
Before he was elected to his current position, Mr. Hewett was Vice President -
Regulation and Economic Planning of KU from January 1982 to April 1997; and
Senior Vice President - Customer Service and Marketing of KU from April 1997 to
May 1998.
Before he was elected to his current position, Mr. McCall was Partner and
Litigation Chairman of Brown, Todd & Heyburn, a law firm.
Before he was elected to his current position, Mr. Lucas was Vice President,
Energy Supply of KU from November 1986 to November 1994; and Senior Vice
President, Energy Supply of KU from November 1994 to June 1998.
Before he was elected to his current position, Mr. Basinger was Partner of
National Power Company prior to November 1993; Vice President of Venture
Management of LG&E Power Inc. from December 1993 to November 1994; Senior Vice
President of Operations of LG&E Power Inc. from November 1994 to August 1996;
and Senior Vice President - Power Operations of LG&E Energy Corp. from August
1996 to May 1998.
Before he was elected to his current position, Mr. Santa was a member of the
Federal Energy Regulatory
33
Commission from May 1993 to August 1997; and Vice President and Deputy General
Counsel of LG&E Energy Corp. from September 1997 to October 1998.
Before he was elected to his current position, Mr. Newton was Director of Human
Resources, Manufacturing and Engineering at Unilever from October 1993 to July
1995; Senior Director, Human Resources, Supply Chain, at Unilever from August
1995 to July 1996; Vice President, Human Resources, at Woolworth Corporation
from August 1996 to July 1997; Senior Vice President, Human Resources, at
Woolworth Corporation's Champs Sports Division from August 1997 to April 1998;
and Senior Vice President - Human Resources and Administration of LG&E Energy
Corp., LG&E and KU from May 1998 to January 1999.
Before he was elected to his current position, Mr. Rives was Associate General
Counsel of LG&E Energy Corp. from January 1994 to June 1994; Vice President and
Treasurer of LG&E Power Inc. from June 1994 to March 1995; Vice President,
Controller and Treasurer of LG&E Power Inc. from March 1995 to December 1995;
Vice President - Finance, Non-Utility Business of LG&E Energy Corp. from January
1996 to March 1996; and Vice President - Finance and Controller of LG&E Energy
Corp. from March 1996 to February 1999.
Before she was elected to her current position, Ms. Heck was Vice President -
Information Services of LG&E from January 1994 to May 1997; and Vice President,
Administration of LG&E Energy Corp. from May 1997 to February 1998.
Before he was elected to his current position, Mr. Robinson was Controller of KU
Energy Corporation from June 1990 to May 1998; Controller of KU from August 1990
to May 1998, and Vice President and Controller of LG&E and KU from May 1998 to
the present.
Executive Officers of LG&E:
Effective Date of
Election to Present
Name Age Position Position
------ --- -------- -------------------
Roger W. Hale 55 Chairman of the Board, January 1, 1992
and Chief Executive
Officer
Stephen R. Wood 56 President May 15, 1997
R. Foster Duncan 45 Executive Vice President February 16, 1999
and Chief Financial Officer
John R. McCall 55 Executive Vice President, July 1, 1994
General Counsel and
Corporate Secretary
Wayne T. Lucas 51 Executive Vice President - May 4, 1998
Power Generation
Frederick J. Newton III 43 Senior Vice President and January 2, 1999
Chief Administrative
Officer
Rebecca L. Farrar 39 Vice President, Gas February 15, 1995
Service Business
34
Effective Date of
Election to Present
Name Age Position Position
---- --- -------- -------------------
Wendy C. Heck 45 Vice President - Infor- February 3, 1998
mation Technology
Chris Hermann 51 Vice President, Power May 4, 1998
Generation and Engineering
Services
Paul W. Thompson 42 Vice President, Retail September 15, 1996
Electric Business
Ronald L. Willhite 52 Vice President - May 4, 1998
Regulatory Affairs
Michael D. Robinson 43 Vice President and May 4, 1998
Controller
Charles A. Markel 51 Treasurer January 1, 1993
The present term of office of each of the above executive officers extends to
the meeting of the Board of Directors following the Annual Meeting of
Shareholders, scheduled to be held April 21, 1999.
There are no family relationships between executive officers of LG&E.
Messrs. Hale, Lucas, Duncan, McCall, Newton, Markel and Robinson are also
executive officers of LG&E Energy Corp. and KU. Mr. Hale is Chairman of the
Board and Chief Executive Officer of LG&E Energy Corp. and KU; Mr. Lucas is
Executive Vice President - Power Generation of LG&E Energy Corp. and KU; Mr.
Duncan is Chief Financial Officer of LG&E Energy Corp. and KU; Mr. McCall is
Executive Vice President, General Counsel and Corporate Secretary of LG&E Energy
Corp. and KU; Mr. Newton is Senior Vice President and Chief Administrative
Officer of LG&E Energy Corp. and KU; Mr. Markel is Vice President - Finance and
Treasurer of LG&E Energy Corp. and Treasurer of KU; and Mr. Robinson is Vice
President and Controller of LG&E Energy Corp. and KU. Mr. Wood and Ms. Heck are
also officers of LG&E Energy Corp. Mr. Wood is President - Distribution Services
of LG&E Energy Corp.; and Ms. Heck is Vice President - Information Technology of
LG&E Energy Corp. Mr. Willhite is also Vice President - Regulatory Affairs of
KU.
Before he was elected to his current position, Mr. Wood was Senior Vice
President and Chief Administrative Officer of LG&E from August 1990 to January
1994, and Executive Vice President and Chief Administrative Officer of LG&E
Energy Corp. from January 1994 to May 1997.
Before he was elected to his current position, Mr. Duncan was Senior Vice
President, Corporate Finance and Business Development of Freeport-McMoRan
Resource Partners from March 1993 to May 1994; Vice President and Corporate
Treasurer of Freeport-McMoRan, Inc. and Freeport-McMoRan Copper & Gold Inc. and
their affiliates from May 1994 to January 1998; and Executive Vice President -
Planning and Development of LG&E Energy Corp. from January 1998 to February
1999.
Before he was elected to his current position, Mr. McCall was Partner and
Litigation Chairman of Brown, Todd & Heyburn, a law firm.
35
Before he was elected to his current position, Mr. Lucas was Vice President,
Energy Supply of KU from November 1986 to November 1994; and Senior Vice
President, Energy Supply of KU from November 1994 to June 1998.
Before he was elected to his current position, Mr. Newton was Director of Human
Resources, Manufacturing and Engineering at Unilever from October 1993 to July
1995; Senior Director, Human Resources, Supply Chain, at Unilever from August
1995 to July 1996; Vice President, Human Resources, at Woolworth Corporation
from August 1996 to July 1997; Senior Vice President, Human Resources, at
Woolworth Corporation's Champs Sports Division from August 1997 to April 1998;
and Senior Vice President - Human Resources and Administration of LG&E Energy
Corp., LG&E and KU from May 1998 to January 1999.
Before she was elected to her current position, Ms. Farrar was Division Manager,
Central Division-Gas Operations of South Carolina Electric and Gas Company from
February 1992 to July 1994; and General Manager, Gas Operations of South
Carolina Electric and Gas Company from July 1994 to February 1995.
Before she was elected to her current position, Ms. Heck was Vice President -
Information Services of LG&E from January 1994 to May 1997; and Vice President,
Administration of LG&E Energy Corp. from May 1997 to February 1998.
Before he was elected to his current position, Mr. Hermann was Vice President
and General Manager, Wholesale Electric Business of LG&E from January 1993 to
June 1997; and Vice President, Business Integration of LG&E from June 1997 to
May 1998.
Before he was elected to his current position, Mr. Thompson was
Director-Business Development for LG&E Energy Corp. prior to December 1993;
General Manager-Gas Operations for LG&E from December 1993 to July 1994; and
Vice President-Business Development for LG&E Energy Corp. from July 1994 to
September 1996.
Before he was elected to his current position, Mr. Willhite was Director of
Regulation for Kentucky Utilities prior to April 1997; and Vice President of
Regulation and Economic Planning for Kentucky Utilities from April 1997 to May
1998.
Before he was elected to his current position, Mr. Robinson was Controller of KU
Energy Corporation from June 1990 to May 1998; and Controller of KU from August
1990 to May 1998.
Executive Officers of KU:
Effective Date of
Election to Present
Name Age Position Position
---- --- -------- -------------------
Roger W. Hale 55 Chairman of the Board, May 4, 1998
and Chief Executive
Officer
Robert M. Hewett 52 President May 4, 1998
Wayne T. Lucas 51 Executive Vice President - May 4, 1998
Power Generation
36
Effective Date of
Election to Present
Name Age Position Position
---- --- -------- -------------------
R. Foster Duncan 45 Executive Vice President February 16, 1999
and Chief Financial Officer
John R. McCall 55 Executive Vice President, May 4, 1998
General Counsel and
Corporate Secretary
Frederick J. Newton III 43 Senior Vice President and January 2, 1999
Chief Administrative
Officer
Gary E. Blake 45 Vice President - Sales May 4, 1998
and Service
James J. Ellington 53 Vice President - Power May 4, 1998
Generation
Ronald L. Willhite 52 Vice President - May 4 1998
Regulatory Affairs
Michael D. Robinson 43 Vice President and August 1, 1990
Controller
Charles A. Markel 51 Treasurer May 4, 1998
The present term of office of each of the above executive officers extends to
the meeting of the Board of Directors following the Annual Meeting of
Shareholders, scheduled to be held April 21, 1999.
There are no family relationships between executive officers of KU.
Messrs. Hale, Lucas, Duncan, McCall, Newton, Markel and Robinson are also
executive officers of LG&E Energy Corp. and LG&E. Mr. Hale is Chairman of the
Board and Chief Executive Officer of LG&E Energy Corp. and LG&E; Mr. Lucas is
Executive Vice President - Power Generation of LG&E Energy Corp. and LG&E; Mr.
Duncan is Chief Financial Officer of LG&E Energy Corp. and LG&E; Mr. McCall is
Executive Vice President, General Counsel and Corporate Secretary of LG&E Energy
Corp. and LG&E; Mr. Newton is Senior Vice President and Chief Administrative
Officer of LG&E Energy Corp. and LG&E; Mr. Markel is Vice President - Finance
and Treasurer of LG&E Energy Corp. and Treasurer of LG&E; and Mr. Robinson is
Vice President and Controller of LG&E Energy Corp. and LG&E. Mr. Willhite is
also Vice President - Regulatory Affairs of LG&E.
Before he was elected to his current position, Mr. Hale was Chairman of the
Board and Chief Executive Officer of LG&E Energy Corp. from August 1990 to the
present and Chairman of the Board and Chief Executive Officer of LG&E from
January 1992 to the present.
Before he was elected to his current position, Mr. Hewett was Vice President -
Regulation and Economic Planning of KU from January 1982 to April 1997; and
Senior Vice President - Customer Service and Marketing of KU from April 1997 to
May 1998.
Before he was elected to his current position, Mr. Lucas was Vice President,
Energy Supply of KU from
37
November 1986 to November 1994; and Senior Vice President, Energy Supply of KU
from November 1994 to June 1998.
Before he was elected to his current position, Mr. Duncan was Senior Vice
President, Corporate Finance and Business Development of Freeport-McMoRan
Resource Partners from March 1993 to May 1994; Vice President and Corporate
Treasurer of Freeport-McMoRan, Inc. and Freeport-McMoRan Copper & Gold Inc. and
their affiliates from May 1994 to January 1998; and Executive Vice President -
Planning and Development of LG&E Energy Corp. from January 1998 to February
1999.
Before he was elected to his current position, Mr. McCall was Partner and
Litigation Chairman of Brown, Todd & Heyburn, a law firm, through June 1994; and
Executive Vice President, General Counsel and Corporate Secretary of LG&E Energy
Corp. and LG&E from July 1994 to the present.
Before he was elected to his current position, Mr. Newton was Director of Human
Resources, Manufacturing and Engineering at Unilever from October 1993 to July
1995; Senior Director, Human Resources, Supply Chain, at Unilever from August
1995 to July 1996; Vice President, Human Resources, at Woolworth Corporation
from August 1996 to July 1997; Senior Vice President, Human Resources, at
Woolworth Corporation's Champs Sports Division from August 1997 to April 1998;
and Senior Vice President - Human Resources and Administration of LG&E Energy
Corp., LG&E and KU from May 1998 to January 1999.
Before he was elected to his current position, Mr. Blake was Vice President -
Retail Marketing of KU from November 1992 to May 1998.
Before he was elected to his current position, Mr. Ellington was Superintendent
of KU's Ghent plant from May 1986 to May 1998.
Before he was elected to his current position, Mr. Willhite was Director of
Regulation for Kentucky Utilities prior to April 1997; and Vice President of
Regulation and Economic Planning for Kentucky Utilities from April 1997 to May
1998.
Before he was elected to his current position, Mr. Robinson was Controller of KU
Energy Corporation from June 1990 to May 1998 and Controller of KU from August
1990 to May 1998.
Before he was elected to his current position, Mr. Markel was Vice President -
Finance and Treasurer of LG&E Energy Corp. and Treasurer of LG&E from January
1993 to the present.
38
PART II.
ITEM 5. Market for the Registrant's Common Equity and Related Stockholder
Matters.
LG&E ENERGY: LG&E Energy 's Common Stock is listed on the New York and
Chicago Stock Exchanges. The ticker symbol is "LGE." The newspaper stock
exchange listings are "LGE Energy" or "LGE EN." The following table gives
information with respect to price ranges, as reported in THE WALL STREET
JOURNAL as New York Stock Exchange Composite Transactions, and dividends paid
for the periods shown (dividends paid have not been restated to reflect the
KU merger).
1998 1997
---- ----
Dividend High Low Dividend High Low
Paid Price Price Paid Price Price
--------- ----- ----- -------- ----- -----
First quarter $.2975 $26.4375 $23.0000 $.2875 $25.8750 $23.5000
Second quarter .2975 27.7500 24.6875 .2875 25.0000 21.8125
Third quarter .2975 27.8750 22.5000 .2875 23.4375 21.2500
Fourth quarter .3075 29.3125 26.0625 .2975 25.0625 21.2500
The number of record holders of Common Stock at December 31, 1998, totaled
50,199. The book value of the Company's Common Stock at December 31, 1998, was
$9.57 per share.
LG&E:
All LG&E common stock, 21,294,223 shares, is held by LG&E Energy. Therefore,
there is no public market for LG&E's common stock.
The following table sets forth LG&E's cash distributions on common stock paid to
LG&E Energy (in thousands of $):
1998 1997
---- ----
First quarter $20,000 $19,000
Second quarter 19,800 -
Third quarter 21,200 19,000
Fourth quarter 22,000 20,000
39
KU:
All KU common stock, 37,817,878 shares, is held by LG&E Energy. Therefore,
there is no public market for KU's common stock.
The following table sets forth KU's cash distributions on common stock paid to
LG&E Energy (in thousands of $):
1998 1997
---- ----
First quarter $17,018 $16,639
Second quarter 23,071 16,640
Third quarter 18,000 16,640
Fourth quarter 18,000 16,640
ITEM 6. Selected Financial Data.
Years Ended December 31
(Thousands of $ Except Per Share Data)
--------------------------------------------------------------------------
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
LG&E ENERGY:
Revenues:
Revenues $2,002,413 $1,725,055 $1,560,460 $1,460,980 $1,467,258
Provision for rate refunds (26,000) -- -- (28,300) --
----------- ----------- ----------- ----------- -----------
Net revenues 1,976,413 1,725,055 1,560,460 1,432,680 1,467,258
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
Operating income:
Before non-recurring items 475,285 418,855 380,038 350,898 335,691
Provision for rate refunds (26,000) -- -- (29,800) --
Merger costs to achieve and
non-recurring charges (65,318) -- (5,493) -- (48,743)
----------- ----------- ----------- ----------- -----------
Operating income 383,967 418,855 374,545 321,098 286,948
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
Net income (loss):
Before non-recurring items 232,216 207,040 192,786 177,467 171,622
Provision for rate refunds (15,556) -- -- (17,852) --
Merger costs to achieve and
non-recurring charges (56,389) -- (2,400) -- (38,696)
----------- ----------- ----------- ----------- -----------
Total continuing
operations 160,271 207,040 190,386 159,615 132,926
Discontinued operations (23,599) (24,044) (4,434) (732) (241)
Gain (loss) on sale of
discontinued operations (225,000) -- -- -- 51,805
Cumulative effect of
accounting change (7,162) -- -- -- (3,369)
----------- ----------- ----------- ----------- -----------
Net income (loss) $ (95,490) $ 182,996 $ 185,952 $ 158,883 $ 181,121
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
Average number of com-
mon shares outstanding 129,679,020 129,626,875 129,449,526 129,261,031 129,137,726
40
Years Ended December 31
(Thousands of $ Except Per Share Data)
--------------------------------------------------------------------------
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
LG&E ENERGY (CONT.):
Earnings (loss) per share of
common stock (basic):
Before non-recurring items $1.79 $1.60 $1.49 $1.37 $1.33
Provision for rate refunds (.12) -- -- (.14) --
Merger costs to achieve and
non-recurring charges (.43) -- (.02) -- (.30)
----------- ----------- ----------- ----------- -----------
Total continuing
operations 1.24 1.60 1.47 1.23 1.03
Discontinued operations (.18) (.19) (.03) -- --
Gain (loss) on sale of
discontinued operations (1.74) -- -- -- .40
Cumulative effect of
accounting change (.06) -- -- -- (.03)
----------- ----------- ----------- ----------- -----------
Earnings (loss) per
share $(.74) $1.41 $1.44 $1.23 $1.40
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
Earnings (loss) per share of
common stock (diluted):
Before non-recurring items $1.79 $1.60 $1.49 $1.37 $1.33
Provision for rate refunds (.12) -- -- (.14) --
Merger costs to achieve and
non-recurring charges (.44) -- (.02) -- (.30)
----------- ----------- ----------- ----------- -----------
Total continuing
operations 1.23 1.60 1.47 1.23 1.03
Discontinued operations (.17) (.19) (.03) -- --
Gain (loss) on sale of
discontinued operations (1.73) -- -- -- .40
Cumulative effect of
accounting change (.06) -- -- -- (.03)
----------- ----------- ----------- ----------- -----------
Earnings (loss) per
share $(.73) $1.41 $1.44 $1.23 $1.40
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
Cash dividends declared per
share of common stock $1.240 $1.113 $1.081 $1.050 $1.021
Payout ratio (from continuing
operations before non-
recurring items) 69.3% 69.7% 72.6% 76.5% 76.8%
Total assets $4,773,268 $4,562,944 $4,132,599 $4,101,526 $3,887,122
Long-term obligations
(including amounts
due within one year) 1,510,775 1,230,711 1,193,229 1,208,846 1,158,895
LG&E Energy Corp.'s Management's Discussion and Analysis of Results of
Operations and Financial Condition and the Notes to Financial
Statements should be read in conjunction with the above information.
41
Years Ended December 31
(Thousands of $)
--------------------------------------------------------------------------
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
LG&E:
Operating revenues:
Revenues $854,556 $845,543 $821,115 $751,763 $759,075
Provision for rate refunds (4,500) -- -- (28,300) --
---------- ---------- ---------- ---------- ----------
Total operating revenues 850,056 845,543 821,115 723,463 759,075
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Net operating income:
Before unusual items 138,207 148,186 147,263 138,203 134,393
Provision for rate refunds (2,684) -- -- (16,877) --
Non-recurring charges -- -- -- -- (23,353)
---------- ---------- ---------- ---------- ----------
Operating income 135,523 148,186 147,263 121,326 111,040
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Net income:
Before unusual items 104,381 113,273 107,941 100,061 94,423
Provision for rate refunds (2,684) -- -- (16,877) --
Merger costs to achieve and
non-recurring charges (23,577) -- -- -- (32,734)
Cumulative effect of
accounting change -- -- -- -- (3,369)
---------- ---------- ---------- ---------- ----------
Net income 78,120 113,273 107,941 83,184 58,320
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Net income available
for common stock 73,552 108,688 103,373 76,873 52,492
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Total assets 2,104,637 2,055,641 2,006,712 1,979,490 1,966,590
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Long-term obligations
(including amounts
due within one year) $626,800 $646,800 $646,800 $662,800 $662,800
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
LG&E's Management's Discussion and Analysis of Results of Operations
and Financial Condition and LG&E's Notes to Financial Statements should
be read in conjunction with the above information.
Years Ended December 31
(Thousands of $)
--------------------------------------------------------------------------
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
KU:
Operating revenues:
Revenues $831,614 $716,437 $711,711 $686,430 $656,013
Provision for rate refund (21,500) -- -- -- (19,385)
---------- ---------- ---------- ---------- ----------
Operating revenues 810,114 716,437 711,711 686,430 636,628
---------- ---------- ---------- ---------- ----------
Net operating income:
Before unusual items 138,263 118,408 117,337 108,544 120,571
Provision for rate refund (12,875) -- -- -- (19,385)
---------- ---------- ---------- ---------- ----------
Operating income 125,388 118,408 117,337 108,544 101,186
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
42
Years Ended December 31
(Thousands of $)
--------------------------------------------------------------------------
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
KU (CONT.):
Net income:
Before unusual items 107,303 85,713 86,163 76,842 96,897
Provision for rate refund (12,875) -- -- -- (19,385)
Merger cost to achieve (21,664) -- -- -- --
---------- ---------- ---------- ---------- ----------
Net income 72,764 85,713 86,163 76,842 77,512
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Net income available
for common stock 70,508 83,457 83,907 74,586 75,128
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Total assets 1,763,797 1,679,880 1,673,055 1,659,988 1,618,100
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Long-term obligations
(including amounts
due within one year) $546,330 $546,351 $546,373 $545,894 $495,916
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
KU's Management's Discussion and Analysis of Results of Operations and
Financial Condition and KU's Notes to Financial Statements should be
read in conjunction with the above information.
43
ITEM 7. Management's Discussion and Analysis of Results of Operations and
Financial Condition.
LG&E ENERGY:
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 1998, 1997 and 1996 and should be read in
connection with the consolidated financial statements and notes thereto. As
set forth in the discussion concerning Discontinued Operations below, future
financial results from the Company's operations will continue to reflect the
results from its portfolio of investments in electric generation and gas
distribution in addition to the financial results provided by the Company's
regulated utilities, Louisville Gas and Electric Company (LG&E) and Kentucky
Utilities Company (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; 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 LG&E Energy Corp.'s report on Form 8-K
filed October 21, 1998.
MERGER
Effective May 4, 1998, following the receipt of all required state and
federal regulatory approvals, LG&E Energy Corp. (LG&E Energy) 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 LG&E and KU was not
affected by the merger. See Note 2 of LG&E Energy's Notes to Financial
Statements under Item 8.
DISCONTINUANCE OF MERCHANT ENERGY TRADING AND SALES BUSINESS
Effective June 30, 1998, the Company discontinued its merchant energy trading
and sales business. This business consisted primarily of a portfolio of
energy marketing contracts entered into in 1996 and early 1997, nationwide
deal origination and some level of speculative trading activities, which were
not directly supported by the Company's physical assets. The Company's
decision to discontinue these operations was primarily based on the impact
that volatility and rising prices in the power market had on its portfolio of
energy marketing contracts. Exiting the merchant energy trading and sales
business enables the Company to focus on optimizing the value of physical
assets it owns or controls, and to reduce the earnings impact on continuing
operations of extreme market volatility in its portfolio of energy marketing
contracts. The Company is in the process of settling commitments that
obligate it to buy and sell natural gas and electric power. It also plans to
sell its natural gas gathering and processing business. If the Company is
unable to dispose of these commitments or assets it will continue to meet its
obligations under the contracts. The Company, however, has maintained
sufficient market knowledge, risk management skills, technical systems and
experienced personnel to maximize
44
LG&E Energy (cont.):
the value of power sales from physical assets it owns or controls, including
LG&E, KU and the Big Rivers Electric Corporation (Big Rivers).
As a result of the Company's decision to discontinue its merchant energy
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 million in the second quarter of
1998. The loss on disposal of discontinued operations results primarily from
several fixed-price energy marketing contracts entered into 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 merchant energy trading and sales operations and exit costs,
including labor and related benefits, severance and retention payments, and
other general and administrative expenses. Although the Company used what it
believes to be appropriate estimates for future energy prices among other
factors to calculate the net realizable value of discontinued operations, it
also recognizes that there are inherent limitations in models to accurately
predict future events. As a result, there is no guarantee that
higher-than-anticipated future commodity prices or load demands, lower-
than-estimated asset sales prices or other factors could not result in
additional losses. The Company has been successful in settling portions of
its discontinued operations, but significant assets, operations and
obligations remain. As of January 27, 1999, 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 change the value of the
Company's remaining energy portfolio by approximately $8.8 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 January 27, 1999, the Company estimates that a
1% change in the forecasted load demand could change the value of the
Company's remaining energy portfolio by $9.3 million. See Notes 3 and 18 of
LG&E Energy's Notes to Financial Statements under Item 8.
The Company reclassified 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 of LG&E Energy's
Notes to Financial Statements under Item 8 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 utility purchasing energy from the
Rensselaer facility. The Company recognized a net after-tax gain on the MRA
transaction and settlement of $21 million. See Note 8 of LG&E Energy's Notes
to Financial Statements under Item 8.
LEASE OF BIG RIVERS FACILITIES
On July 15, 1998, the Company closed the transaction to lease the generating
assets of Big Rivers following receipt of necessary regulatory approvals.
Under the 25-year operating lease, Western Kentucky Energy Corp. and its
affiliates (WKE) are leasing and operating Big Rivers' three coal-fired
facilities. In addition, WKE operates and maintains the Station Two
generating facility of the City of Henderson (Henderson). The combined
generating capacity of these facilities amounts to approximately 1,700
megawatts, net of the Henderson's capacity and energy needs from Station Two.
In related transactions, power is supplied to Big Rivers at contractual
prices over the term of the lease to meet the needs of four member
distribution cooperatives and their retail customers, including major western
Kentucky aluminum smelters. Excess generating capacity is available to WKE to
market throughout the region. In connection with these transactions, WKE has
45
LG&E Energy (cont.):
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 completion of the transactions.
RESULTS OF OPERATIONS
Earnings per Share
Continuing operations for 1998 produced basic earnings per share of $1.24,
before a decrease of 6 cents due to cumulative effect of an accounting
change, a decrease of 36 cents per share from $1.60 earned from continuing
operations in 1997. Earnings for 1998 include non-recurring charges for
merger-related costs and environmental cost recovery refunds of 43 cents and
12 cents, respectively. Excluding these non-recurring charges, earnings per
share from continuing operations for 1998 were $1.79, an increase of 19 cents
over 1997. The 19 cent per share increase resulted from a 10 cent increase in
core domestic utility business and a 16 cent increase in non-utility
business, partially offset by an increase in corporate and other expenses of
7 cents. The 1998 non-utility results included 16 cents relating to the
consummation of the MRA with NIMO, 3 cents for first-year earnings related to
the Big Rivers transactions, 1 cent due to a full year of operations and an
increase in core business of our Argentine operations, partially offset by an
increase in non-utility expenses of 4 cents, primarily related to the loss on
disposition of our gas-fired power plant in San Miguel, Argentina and, the
write-off of our Windpower Partners 1994 investment.
Earnings per share from continuing operations for 1997 were $1.60, an
increase of 13 cents per share from the $1.47 earned from continuing
operations in 1996. Earnings for 1996 included a charge of 2 cents 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 cents. The 11
cent per share increase resulted from an increase in core utility business
earnings of 3 cents, first-year earnings related to the acquisition of
interests in two Argentine gas distribution units of 4 cents, and an increase
in the non-utility power generation business of 8 cents, partially offset by
an increase in corporate and other expenses, including interest expense on
debt incurred to acquire non-utility businesses of 4 cents. The 3 cent
increase in utility earnings was primarily due to higher contributions from
wholesale electric sales and lower maintenance expenses.
Loss from discontinued operations decreased from 19 cents in 1997 to 18 cents
in 1998, due primarily to the Company's decision to exit the merchant energy
trading and sales business effective June 30, 1998. See Note 3 of LG&E
Energy's Notes to Financial Statements under Item 8.
Loss from discontinued operations increased from 3 cents in 1996 to 19 cents
in 1997, due primarily to abnormal weather, price volatility in the energy
market and narrowing margins in the natural gas business.
46
LG&E Energy (cont.):
Electric and Gas Utility Results
Revenues
A comparison of utility revenues for the years 1998 and 1997, excluding the
$26 million provision recorded for refund of environmental costs previously
recovered from customers (ECR refund), with the immediately preceding year
reflects both increases and decreases, which have been segregated by the
following principal causes (in thousands of $):
Increase (Decrease) From Prior Period
Electric Revenues Gas Revenues
1998 1997 1998 1997
---- ---- ---- ----
Sales to ultimate consumers:
Fuel and gas supply adjustments, etc. $ 4,908 $ (7,569) $ (4,393) $ 27,192
Merger surcredit (7,501) -- -- --
Demand side management/decoupling (6,299) 8,041 (369) 4,348
Environmental cost recovery surcharge (807) 1,002 -- --
Variation in sales volumes 52,892 6,491 (42,418) (14,891)
----------- --------- --------- --------
Total retail sales 43,193 7,965 (47,180) 16,649
Wholesale sales 90,386 1,210 8,720 --
Gas transportation-net -- -- (71) 147
Other (324) 3,548 (935) (204)
----------- --------- --------- --------
Total $ 133,255 $ 12,723 $ (39,466) $ 16,592
----------- --------- --------- --------
----------- --------- --------- --------
Electric retail sales increased primarily due to the warmer weather
experienced in 1998 as compared to 1997. Wholesale sales increased due to
larger amounts of power available for off-system sales, and an increase in
the unit price of the sales. Gas retail sales decreased from 1997 due to the
warmer weather in 1998. Gas wholesale sales increased to $8.7 million in 1998
from zero in 1997 due to the implementation of LG&E's performance-based
ratemaking mechanism. See Note 5 of LG&E Energy's Notes to Financial
Statements under Item 8.
Electric revenues increased in 1997 due to a higher level of industrial sales
and other revenues. Gas revenues increased primarily 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.
Expenses
Fuel for electric generation and gas supply expenses comprise a large
component of the Company's total operating costs. LG&E's and KU's electric
rates contain a fuel adjustment clause (FAC) 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
Kentucky Public Service Commission (Kentucky Commission or Commission), the
Virginia State Corporation Commission (Virginia Commission) and the Federal
Energy Regulatory Commission (FERC).
Fuel for electric generation increased $34.1 million in 1998 primarily due to
an increase in generation to support increased electrical sales at KU ($27.3
million) and a higher cost of coal burned at LG&E ($6.6 million). Fuel
expenses incurred in 1997 decreased $10 million primarily due to a decrease
in generation at KU which resulted from an increase in economic power
purchased. LG&E's average delivered cost per ton of coal purchased was $22.38
in 1998, $21.66 in 1997, and $21.73 in 1996. KU's average delivered cost per
ton of coal purchased was
47
LG&E Energy (cont.):
$26.97 in 1998, $27.97 in 1997, and $27.54 in 1996.
Power purchased increased $59.5 million in 1998 to support the increase in
wholesale sales and due to increases in the unit price of purchases.
Purchased power expense increased $10.7 million (13%) in 1997, due to an
increase at KU in kilowatt hour (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.
Gas supply expenses decreased $33 million (21%) in 1998 primarily due to a
decrease in the volume of gas delivered to the distribution system. 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). The
average unit cost per thousand cubic feet (Mcf) of purchased gas was $3.05 in
1998 and $3.46 in 1997 and 1996.
Operation and maintenance expenses increased $14.6 million (3.8%) over 1997
because of increased costs to operate and maintain LG&E's electric generating
plants ($8.8 million), amortization of deferred merger costs ($3.8 million),
and an increase in storm damage expenses ($1.4 million).
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 hydroelectric 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.
Depreciation and amortization increased $2.7 million (1.5%) in 1998 because
of additional utility plant in service. Depreciation and amortization
increased in 1997 primarily because of additional plant in service at both KU
and LG&E. In addition, 1997 reflects the accelerated write-off of losses on
early retirements of facilities at LG&E.
The companies incurred a pre-tax charge in the second quarter of 1998 for
costs associated with the merger of LG&E Energy and KU Energy of $53.9
million (of this amount, $32.1 million was for LG&E, and $21.8 million was
for KU). The amount charged is in excess of the amount permitted to be
deferred as a regulatory asset by the Kentucky Public Service Commission. See
Note 2 of LG&E Energy's Notes to Financial Statements under Item 8.
Interest charges for 1998 decreased $3.9 million (7%) due to the retirement
of LG&E's 6.75% Series First Mortgage Bonds and lower interest rates. LG&E's
embedded cost of long-term debt was 5.57% at December 31, 1998 and 5.68% at
December 31, 1997. KU's embedded cost of long-term debt was 6.99% at December
31, 1998 and 6.98% at December 31, 1997. See Note 16 of LG&E Energy's Notes
to Financial Statements under Item 8.
Variations in income tax expenses are largely attributable to changes in
pre-tax income as well as non-deductible merger expenses.
The rate of inflation may have a significant impact on the Company's utility
operations, its ability to control
48
LG&E Energy (cont.):
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.
LG&E Capital Corp. Results
LG&E Capital Corp. (Capital Corp.), the holding company for all non-utility
investments, conducts its operations through three principal segments:
Independent Power Operations, WKE and Argentine Gas Distribution. Involvement
in these and other non-utility businesses represents the Company's commitment
to understand, respond to, and capitalize on the opportunities presented by
an emerging competitive energy services industry. The Independent Power
Operations develop, operate, maintain and own interests in domestic and
international power generation facilities that sell electric and steam energy
to utility and industrial customers, and own equity interests in combustion
turbines which are leased to others. WKE leases and operates the generating
facilities of Big Rivers. Argentine Gas Distribution owns interests in two
natural gas distribution companies in Argentina. Capital Corp. is also
engaged in commercial and retail initiatives designed to assess the energy
and utility needs of large commercial and industrial entities, provide
maintenance and repair services for customers' major household appliances and
provide third party metering and billing services. See Notes 2, 4, 8, 9, 18
and 20 of LG&E Energy's Notes to Financial Statements under Item 8.
Independent Power Operations
Revenues
Revenues from Independent Power Operations, comprised mainly of contractual
revenues from various power plant operations, were approximately the same in
1998 and 1997. Revenues increased 9% to $19.6 million in 1997 due to the
addition of plant operating contracts at the Windpower Partners 1993 (WPP 93)
California and Minnesota facilities, as well as the Windpower Partners 1994
(WPP 94) Texas facility. See Note 18 of LG&E Energy's Notes to Financial
Statements under Item 8.
Equity in Earnings of unconsolidated ventures includes the Company's share of
earnings from the ventures in which it maintains an equity interest, but does
not consolidate the results of operations. The 247% increase in equity in
earnings in 1998 to $71.3 million was primarily attributable to the closure
of the MRA transaction with NIMO and an arbitration award received by the
Frederickson, Washington, venture, partially offset by a write-off of the
Company's investment in the WPP 94 venture. Equity in Earnings were
approximately the same in 1997 and 1996. See Notes 8 and 18 of LG&E Energy's
Notes to Financial Statements under Item 8.
Expenses
Direct costs of revenues are primarily comprised of labor and related
expenses associated with the Company 's operation of various power plants.
These costs were approximately the same in 1998 and 1997. Expenses increased
9% to $12.2 million in 1997 due to the addition of the operating contracts at
the WPP 93 and WPP 94 facilities.
Operation and maintenance expenses were approximately the same for all
periods presented. Depreciation and amortization increased $3.3 million in
1998 due to the write-off of certain intangible assets and capitalized
interest associated with the sale of the Company's interest in a 114 MW
gas-fired power plant in San Miguel, Argentina and the closure of the MRA
transaction with NIMO. Depreciation and amortization expenses were
approximately the same in 1997 and 1996. See Note 8 of LG&E Energy's Notes to
Financial Statements under Item 8.
49
LG&E Energy (cont.):
Western Kentucky Energy
WKE commenced operations effective July 15, 1998, after closing its lease
transaction with Big Rivers and reported solid performance during its first
partial year of operations with revenues of $128.5 million. WKE's cost of
revenues, primarily composed of fuel and purchased power expenses, amounted
to $73.1 million for the year. Operation and maintenance expenses of $45.4
million include $12.8 million of rent expense associated with the lease of
Big Rivers' operating facilities. WKE incurred interest expense of
approximately $2.6 million associated with borrowings to fund the initial
purchase of certain materials and supplies from Big Rivers and to prepay the
first two years' lease payments of $55.9 million. See Note 4 of LG&E Energy's
Notes to Financial Statements under Item 8.
Argentine Gas Distribution
In February 1997, the Company acquired interests in two Argentine natural gas
distribution companies: Distribuidora de Gas del Centro (Centro) and
Distribuidora de Gas Cuyana (Cuyana). Centro is consolidated within the
Company's results while Cuyana's results are recorded using the equity method
of accounting. Our investments in Argentina continue to contribute to our
non-utility operations, with Centro's revenues increasing by 16% or $21
million due to a full year of operations in 1998 versus 10 1/2 months in
1997, higher per customer consumption and an increase in the customer base.
Centro's operating expenses increased by 8% or $2.4 million due to a full
year of operations in 1998. Equity in earnings of Cuyana were approximately
the same in 1997 and 1998. See Notes 2 and 8 of LG&E Energy's Notes to
Financial Statements under Item 8.
Other
The Company has entered into various commercial and retail initiatives to
position itself for growth in the energy industry. The commercial initiatives
represent new businesses and products designed to leverage the Company's
existing assets and experience, and to gain access to new markets. Our retail
initiatives enhance value for LG&E's and KU's customers and are designed to
help ensure that LG&E and KU remain the utility of choice within their
respective service areas when a fully competitive industry framework takes
shape. These commercial and retail initiatives have not had a significant
impact on the Company's financial position or required significant capital
investment over the last three years. We remain optimistic that these
non-traditional developing ventures will add to our knowledge base as well as
our financial results in the future.
Interest costs increased by $10.4 million, or 62%, from 1997 to 1998
primarily due to the funding of discontinued operations and LG&E Energy's
operating expenses. The increase of $7.5 million, or 80%, from 1996 to 1997
was primarily due to the Argentine gas distribution acquisition. See Notes 2,
3, 6 and 16 of LG&E Energy's Notes to Financial Statements under Item 8.
LIQUIDITY AND CAPITAL RESOURCES
The Company's need for capital funds is largely 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 incurred in connection with the discontinuance of the
merchant energy trading and sales business, 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 and commercial paper programs are
maintained to fund these temporary capital requirements.
50
LG&E Energy (cont.):
Construction Expenditures and Equity Investments
Utility construction expenditures for 1998 were $230 million compared with
$205 million for 1997 and $215 million for 1996. Non-utility construction
expenditures (other than unconsolidated ventures) were approximately $112
million in 1998, $5 million in 1997, and $1 million in 1996. The 1998
increase for non-utility is mainly due to the purchase of two gas turbine
peaking units by Capital Corp., system expansion and refurbishment at Centro,
and generating asset upgrades at WKE.
Past Financing Activities
During 1998, 1997 and 1996, 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 1998, 1997 and 1996. In 1998, the
Company financed $92 million in closing costs related to the WKE lease with
commercial paper. The Company provided its merchant energy trading and sales
business with additional cash to meet obligations and general working capital
needs from funds obtained via Capital Corp.'s borrowings. The results of the
merchant energy trading and sales business are included in discontinued
operations. The Company acquired interests in two Argentine natural gas
distribution companies in 1997 for $140 million, plus transaction related
fees and expenses. This acquisition was financed with cash and lines of
credit.
The Company's combined cash and marketable securities balance decreased by
$3.7million in 1998 and increased by $21 million in 1997. The decrease in
1998 reflects expenses incurred to discontinue our merchant energy trading
and sales business, merger costs and an increase in capital expenditures,
partially offset by increased borrowings and cash flow from continuing
operations. The increase for 1997 reflects cash flows from operations and an
increase in borrowings, partially offset by capital expenditures and
dividends paid. In 1996, combined cash and marketable securities decreased
$15.7 million. This decrease reflects capital expenditures, dividends paid
and a net decrease in borrowings, partially offset by cash flows from
operations.
The increases in accounts receivable and accounts payable during 1998
resulted primarily from the Big Rivers transaction. 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 1998, Capital Corp. issued $150 million of Reset Put Securities
due 2011. The interest rate is set at 5.75% through November 1, 2001. The
securities will be subject to automatic purchase by a remarketing agent, at
which time the interest rate will be reset, or to automatic repurchase by
Capital Corp. on November 1, 2001. After taking into account the net effect
of the derivative instruments entered into in September 1998 to hedge the
interest rate on the notes and other issuance costs, the effective rate
through October 31, 2001 is approximately 5.4%. The proceeds were used to
repay a portion of Capital Corp.'s outstanding commercial paper. See Note 16
of LG&E Energy's Notes to Financial Statements under Item 8.
On June 1, 1998, LG&E's First Mortgage Bonds, 6.75% Series of $20 million
matured and were retired by LG&E. The bonds were redeemed with available
funds.
In February 1998, Capital Corp. issued $150 million of medium-term notes due
January 2008, with a stated interest rate on the notes of 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%. The proceeds were used to
repay outstanding commercial paper. See Note 16 of
51
LG&E Energy (cont.):
LG&E Energy's Notes to Financial Statements under Item 8.
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 these bonds were
3.09% and 3.39%, respectively, at December 31, 1998. 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 September 1997, LG&E Energy Systems Inc. and LG&E Gas Systems Inc. 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.
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 generally funded through project debt.
The Company had non-utility short-term borrowings outstanding of $365.1
million as of December 31, 1998. These borrowings consisted of commercial
paper, which had maturity dates ranging between 1 and 270 days. Because of
the rollover of these maturity dates, total short-term borrowings and
repayments during the year were approximately $6.8 billion. Short-term
borrowings were $360.2 million as of December 31, 1997, and $158 million as
of December 31, 1996. 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.
KU had no short-term borrowings at December 31, 1998. 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 in 1998 from 1997 and 1997 from 1996 was due primarily to KU's cash
provided by operations exceeding cash required for investing and financing
activities (exclusive of short-term borrowings). LG&E had no short-term
borrowings at December 31, 1998 or 1997.
In May 1998, upon closing of the merger with KU Energy, the Company issued
63,149,394 shares of common stock to former KU Energy shareholders. The
Company issued 186,192 shares of new common stock in 1997 and 146,678 shares
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 LG&E Energy's Notes to Financial Statements under Item
8.
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 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 $384 million for 1999 and 2000, and that KU's
construction expenditures for the same period will total approximately $341
million. Both utilities construction estimates include capital expenditures
associated with installation of low nitrogen oxide burner systems as
described in the section titled "Environmental Matters." In addition, 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 $68 million for 1999 and 2000. Other future capital
funding requirements are dependent
52
LG&E Energy (cont.):
upon the identification of suitable investment opportunities to enhance
shareholder returns and achieve long-term financial objectives through
business acquisitions.
In October 1998, the Company negotiated for the purchase of two gas turbine
peaking units at a total cost of approximately $125 million, of which $62
million was expended in 1998.
In July 1998, as part of the deal structure with Big Rivers, WKE agreed to
provide Big Rivers a $50 million note to help it emerge from bankruptcy. WKE
will provide $1.7 million per month for the first 12 months of the note,
beginning August 1998, and $2.5 million per month over the subsequent 12
months. The note will be repaid over a three-year period, beginning August
2000, with interest at 7.165%.
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 while Moody's and Duff &
Phelps (D&P) kept the Company and its subsidiaries at their prior ratings.
The Company's current debt ratings are:
Moody's S&P D&P
------- ------ ------
LG&E
First mortgage bonds Aa2 A+ AA
Unsecured debt Aa3 A AA-
Preferred stock aa3 A- AA-
KU
First mortgage bonds Aa2 AA- AA
Preferred stock aa3 A- AA-
Commercial paper P-1 A-1 D-1+
CAPITAL CORP.
Medium-term notes A1 A A+
Commercial paper P-1 A-1 D-1+
These ratings reflect the views of Moody's, S&P and D&P. An explanation of
the significance of these ratings may be obtained from them. 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 and new debt are expected to fund
LG&E's and KU's anticipated construction expenditures in 1999 and 2000.
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 1999
and 2000.
At December 31, 1998, 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 credit facility provides for short-term borrowing. KU's credit
facilities provide for short-term borrowing and support of commercial paper
borrowings. The Capital Corp. facilities provide for short-term borrowing,
letter of credit issuance, and support of commercial paper borrowings. Unused
capacity
53
LG&E Energy (cont.):
under these lines totaled $536.8 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 1999 through 2002. Management expects to renegotiate the
lines when they expire.
The lenders under the credit facilities, commercial paper facility and the
medium-term notes for Capital Corp. are entitled to the benefits of a Support
Agreement with LG&E Energy Corp. See Note 17 of LG&E Energy's Notes to
Financial Statements under Item 8.
Market Risks
LG&E Energy is exposed to market risks in both its regulated and non-utility
operations. Both operations are exposed to market risks from changes in
interest rates and commodity prices, while the non-utility operations are
also exposed to changes in foreign exchange rates. To mitigate changes in
cash flows attributable to these exposures, the Company has entered into
various derivative financial instruments. Derivative positions are monitored
using techniques that include market value and sensitivity analysis.
Interest Rate Sensitivity
The Company has short-term and long-term variable rate debt obligations
outstanding. At December 31, 1998, the potential change in interest expense
associated with a 1% change in base interest rates of the Company's unswapped
debt is estimated at $4 million.
Interest rate swaps are used to hedge the Company's underlying variable rate
debt obligations. These swaps hedge specific debt issuance and consistent
with management's designation are accorded hedge accounting treatment.
LG&E and Capital Corp. have entered into swaps to reduce the impact of
interest rate changes on their Pollution Control Bonds and commercial paper
program. The swap agreements involve the exchange of floating-rate interest
payments for fixed interest payments over the life of the agreements. As of
December 31, 1998, 40% of the outstanding variable interest rate borrowings
were converted to fixed interest rates through swaps. The potential loss in
fair value from these positions resulting from a hypothetical 1% adverse
movement in base interest rates is estimated at $5.6 million as of December
31, 1998. Changes in the market value of these swaps if held to maturity, as
the Company intends to do, will have no effect on the Company's net income or
cash flow. See Note 6 of LG&E Energy's Notes to Financial Statements under
Item 8.
In April 1998, LG&E entered into a forward starting swap agreement. The
forward swap involves the exchange of floating-rate interest payments for
fixed interest payments over the life of the agreement. The forward swap was
entered into to hedge LG&E's exposure to interest rates for the anticipated
call of its Trimble County, Kentucky, Pollution Control Bonds, 7 5/8% Series,
due November 1, 2020. The potential loss in fair value from this position
resulting from a hypothetical 10% change in the yield curve is estimated at
$7.5 million as of December 31, 1998. See Note 6 of LG&E Energy's Notes to
Financial Statements under Item 8.
Commodity Price Sensitivity
LG&E and KU have limited exposure to market volatility in prices of fuel or
electricity, as long as cost-based regulations exist. To mitigate residual
risks relative to the movements in fuel or electricity prices, LG&E and KU
have entered into primarily fixed-priced contracts for the purchase and sale
of electricity through the wholesale electricity market. WKE is exposed to
changes in fuel prices. To mitigate this risk, WKE has
54
LG&E Energy (cont.):
entered into various fuel supply contracts which expire at various times
through 2001. Realized gains and losses are recognized in the income
statement as incurred. At December 31, 1998, exposure from these activities
was not material to the consolidated financial statements of the Company.
Capital Corp. through its subsidiaries operates and controls the generating
capacity of Big Rivers and the City of Henderson. Some of the excess capacity
generated by Big Rivers and the City is currently being marketed by WKE. To
mitigate residual risks relative to the movements in electricity prices, WKE
has entered into primarily fixed-priced contracts for the purchase and sale
of electricity through the wholesale electricity market. Realized gains and
losses are recognized in the income statement as incurred. At December 31,
1998, exposure from these activities was not material to the consolidated
financial statements of the Company.
The Company's discontinued merchant energy trading and sales business has
exposure to market volatility in prices of electricity. See Discontinuance of
Merchant Energy Trading and Sales Business under Management's Discussion and
Analysis and Note 3 of Notes to Financial Statements.
Exchange Rate Sensitivity
The Company has investments in Argentina and Spain which are not hedged. The
Company relies on the Argentine peso's currency peg to the U.S. dollar to
mitigate currency risk attributable to its Argentine investments and views
its Spanish investment as too small to hedge cost-effectively. A 10% decline
in the December 31, 1998 exchange rate for the Argentine peso and the Spanish
peseta (versus the U.S. dollar) would not have a material effect on income
from continuing operations.
YEAR 2000 COMPUTER SOFTWARE ISSUE
The Company and its subsidiaries use various software, systems and technology
that may be affected by the "Year 2000 Issue." This concerns the ability of
electronic processing equipment (including microprocessors embedded in other
equipment) to properly process the millennium change to the year 2000 and
related issues. A failure to timely correct any such processing problems
could result in material operational and financial risks if significant
systems either cease to function or produce erroneous data. Such risks are
more fully detailed in the sections that follow, but could include an
inability to operate its generating plants, disruptions in the operation of
transmission and distribution systems and an inability to access
interconnections with the systems of neighboring utilities.
The Company began its project regarding the Year 2000 issue in 1996. The
Board of Directors has approved the general Year 2000 plan and receives
regular updates. In addition, monthly reporting procedures have been
established at senior management levels. Since 1996, a single-purpose Year
2000 team has been established in the Information Technology (IT) Department.
This team, which is headed by an officer of the Company, is responsible for
planning, implementing and documenting the Company's Year 2000 process. The
team also provides direct and detailed assistance to the Company's
operational divisions and smaller units, where identified personnel are
responsible for Year 2000 work and remediation in their specific areas. In
many cases, the Company also uses the services of third parties, including
technical consultants, vendor representatives and auditors.
The Company's Year 2000 effort generally follows a three-phase process:
Phase I - inventory and identify potential Year 2000 issues, determine
solutions;
55
LG&E Energy (cont.):
Phase II - survey vendors regarding their Year 2000 readiness, determine
solutions to deal with possible vendor non-compliance, develop work plans
regarding Company and vendors non-compliance issues; and
Phase III - implementation, testing, certification, contingency planning.
The Company has long recognized the complexity of the Year 2000 issue. Work
has progressed concurrently on (a) replacing or modifying IT systems,
including mainframes, client-server, PCs and software applications, (b)
replacing or modifying non-IT systems, including embedded systems such as
mechanical control units and (c) evaluating the readiness of key third
parties, including customers, suppliers, business partners and neighboring
utilities.
State of Readiness
As of January 1999, the Company and its subsidiaries have substantially
completed the internal inventory, vendor survey and compliance assessment
portions (Phases I and II) of their Year 2000 plan for critical mainframe and
PC hardware and software. Remediation efforts (Phase III) in these areas are
approximately 60% complete. With respect to embedded systems, the Company,
LG&E and KU have substantially completed their Phase I and Phase II efforts.
For each entity, Phase III remediation efforts are also in progress for
embedded systems. Testing has commenced and will continue as remediation
efforts are implemented and are expected to run until July 1999.
As a general matter, corrective action for major IT systems, including
customer information, financial and trading systems, are in process or have
been completed. For smaller or more isolated systems, including embedded and
plant operational systems, the Company has completed much of the evaluative
process and is commencing corrective plans. The Company has communicated with
its key suppliers, customers and business partners regarding their Year 2000
progress, particularly in the IT software and embedded component areas, to
determine the areas in which the Company's operations are vulnerable to those
parties' failure to complete their remediation efforts. The Company is
currently evaluating and, in certain cases, initiating follow-up actions
regarding the responses from these parties. The Company regularly attends and
participates in trade group efforts focusing on Year 2000 issues in the
energy industry.
Cost of Year 2000 Issues
The Company's system modification costs related to the Year 2000 issue are
being expensed as incurred, while new system installations are generally
being capitalized pursuant to generally accepted accounting principles. See
Note 1 of LG&E Energy' Notes to Financial Statements under Item 8. Through
December 1998, the Company has incurred approximately $20.2 million in
capital and operating costs in connection with the Year 2000 issue. Based
upon studies and projections to date, the Company expects to spend an
additional $11.9 million to complete its Year 2000 efforts.
It should be noted that these figures include total hardware, software,
embedded systems and consulting costs. In many cases, these costs include
system replacements which were already contemplated or which provided
additional benefits or efficiencies beyond the Year 2000 aspect.
Additionally, many costs are not incremental costs but constitute
redeployment of existing IT and other resources. These costs represent
management's current estimates; however, there can be no assurance that
actual costs associated with the Company's Year 2000 issues will not be
higher.
56
LG&E Energy (cont.):
Risks of Year 2000 Issues
As described above, the Company has made significant progress in the
implementation of its Year 2000 plan. Based upon the information currently
known regarding its internal operations and assuming successful and timely
completion of its remediation plan, the Company does not anticipate material
business disruptions from its internal systems due to the Year 2000 issue.
However, the Company may possibly experience limited interruptions to some
aspects of its activities, whether IT, generation, transmission or
distribution, operational, administrative functions or otherwise, and the
Company is considering such potential occurrences in planning for the most
reasonably likely worst-case scenarios.
Additionally, risk exists regarding the non-compliance of third parties with
key business or operational importance to the Company. Year 2000 problems
affecting key customers, interconnected utilities, fuel suppliers and
transporters, telecommunications providers or financial institutions could
result in lost power or gas sales, reduced power production or transmission
capabilities or internal operational or administrative difficulties on the
part of the Company. The Company is not presently aware of any such
situations; however, severe occurrences of this type could have material
adverse impacts upon the business, operating results or financial condition
of the Company. There can be no assurance that the Company will be able to
identify and correct all aspects of the Year 2000 problem among these third
parties that affect it in sufficient time, that it will develop adequate
contingency plans or that the costs of achieving Year 2000 readiness will not
be material.
Contingency planning is under way for material areas of Year 2000 risk. This
effort will address certain areas, including the most reasonably likely
worst-case scenarios and delays in completion in the Company's remediation
plans, failure or incomplete remediation results and failure of key third
parties to be Year 2000 compliant. Contingency plans will include provisions
for extra staffing, back-up communications, review of unit dispatch and load
shedding procedures, carrying of additional energy reserves and manual energy
accounting procedures. Completion of contingency plan formulation is
scheduled for June 1999.
Forward-Looking Statements
The foregoing discussion regarding the timing, effectiveness, implementation
and cost of the Company's Year 2000 efforts, contains forward-looking
statements, which are based on management's best estimates and assumptions.
These forward-looking statements involve inherent risks and uncertainties,
and actual results could differ materially from those contemplated by such
statements. Factors that might cause material differences include, but are
not limited to, the availability of key Year 2000 personnel, the Company's
ability to locate and correct all relevant computer codes, the readiness of
third parties and the Company's ability to respond to unforeseen Year 2000
complications and other factors described from time to time in the Company's
reports to the Securities and Exchange Commission, including Exhibit 99.01 to
the Form 8-K filed October 21, 1998. Such material differences could result
in, among other things, business disruption, operational problems, financial
loss, legal liability and similar risks.
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). KU is also subject to the jurisdiction of the Virginia
Commission and FERC. Given LG&E's and KU's competitive position in the market
and the status of regulation in the states of Kentucky and Virginia, neither
LG&E nor KU has plans or intentions to discontinue its application of SFAS
No. 71. See Note 5 of LG&E Energy's Notes to
57
LG&E Energy (cont.):
Financial Statements under Item 8.
Since May 1995 and August 1994, respectively, LG&E and KU have implemented an
environmental cost recovery (ECR) surcharge to recover certain environmental
compliance costs. Such costs include compliance with the 1990 Clean Air Act,
as amended, and other environmental regulations, including those applicable
to coal combustion wastes and related by-products. The ECR mechanism was
authorized by state statute in 1992 and was first approved by the Kentucky
Commission in a KU case in July 1994.
The Commission's order approving the surcharge in the KU case and the
constitutionality of the surcharge were challenged by certain intervenors,
including the Attorney General of Kentucky, in Franklin Circuit Court.
Decisions of the Circuit Court and the Kentucky Court of Appeals in July 1995
and December 1997, respectively, have upheld the constitutionality of the ECR
statute but differed on a claim of retroactive recovery of certain amounts.
The Commission ordered that certain surcharge revenues collected by LG&E and
KU be subject to refund pending final determination of all appeals.
On December 19, 1998, the Kentucky Supreme Court rendered an opinion
upholding the constitutionality of the surcharge statute. The decision,
however, reversed the ruling of the Court of Appeals on the retroactivity
claim, thereby denying recovery of costs associated with pre-1993
environmental projects through the ECR. The court remanded the case to the
Commission to determine the proper adjustments to refund amounts collected
for such pre-1993 environmental projects. The parties to the proceeding have
notified the Commission that they have reached agreement as to the terms,
proper adjustments and forward application of the ECR. The settlement
agreement is subject to Commission approval. The Company recorded a provision
for rate refund of $26 million in December 1998.
In January 1994, LG&E implemented a Commission-approved demand side
management (DSM) program that LG&E, the Jefferson County, Kentucky, Attorney
and representatives of several customer interest groups had filed with the
Commission. The program included 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 program (decoupling). In June 1998, LG&E and customer
interest groups requested an end to the decoupling rate mechanism. On June 1,
1998, LG&E discontinued recording revenues from lost sales due to DSM.
Accrued decoupling revenues recorded for periods prior to June 1, 1998, will
continue to be collected through the DSM recovery mechanism. On September 23,
1998, the Commission accepted LG&E's modified tariff reflecting this proposal
effective as of June 1, 1998.
In October 1998, LG&E and KU filed separate but parallel applications with
the Commission for approval of a new method of determining electric rates
that provides financial incentives for LG&E and KU to further reduce
customers' rates. The filing was made pursuant to the September 1997
Commission order approving the merger of LG&E Energy and KU Energy, wherein
the Commission directed LG&E and KU to indicate whether they desired to
remain under traditional rate of return regulation or commence
non-traditional regulation. The new ratemaking method, known as
performance-based ratemaking (PBR), would include financial incentives for
LG&E and KU to reduce fuel costs and increase generating efficiency, and to
share any resulting savings with customers. Additionally, the PBR provides
financial penalties and rewards to assure continued high quality service and
reliability.
The PBR plan proposed by LG&E and KU consists of five components:
The utilities' fuel adjustment clause mechanism will be withdrawn and
replaced with a cap that limits
58
LG&E Energy (cont.):
recovery of actual changes in fuel cost to changes in a fuel price index
for a five-state region. If the utilities outperform the index, benefits
will be shared equally between shareholders and customers. If the
utilities' fuel costs exceed the index, the difference will be absorbed
by the Company's shareholders.
Customers will continue to receive the benefits from the post-merger joint
dispatch of power from LG&E's and KU's generating plants.
Power plant performance will be measured against the best performance
achieved between 1991 and 1997. If the performance exceeds this level,
customers will share in up to $10 million annually of benefits from this
performance at each of LG&E and KU.
The utilities will be encouraged to maintain and improve service quality,
reliability, customer satisfaction and safety, which will be measured
against six objective benchmarks. The plan provides for annual rewards or
penalties to the Company of up to $5 million per year at each of LG&E and
KU.
The plan provides the utilities with greater flexibility to customize rates
and services to meet customer needs. Services will continue to be priced
above marginal cost, and customers will continue to have the option to elect
standard tariff service.
These proposals are subject to approval by the Commission. Approval
proceedings commenced in October 1998 and a final decision likely will occur
in 1999. Several intervenors are participating in the case. Some have
requested that the Commission reduce base rates before implementing PBR.
On March 8, 1999, the Kentucky Industrial Utility Customers filed a Complaint
with the Kentucky Commission alleging that LG&E's and KU's electric rates are
excessive and should be reduced by an amount between $85 and $146 million and
that the Kentucky Commission establish a proceeding to reduce LG&E's and KU's
electric rates. LG&E and KU have asked the Kentucky Commission to dismiss the
Complaint.
The Company is not able to predict the ultimate outcome of these proceedings,
however, should the Commission mandate significant rate reductions at LG&E
and/or KU, through the PBR proposal or otherwise, such actions could have a
material effect on the Company's financial condition and results of
operations.
Since October 1997, LG&E has implemented a Commission-approved, experimental
performance-based ratemaking mechanism related to gas procurement activities
and off-system gas sales only. During the three-year test period beginning
October 1997, rate adjustments related to this mechanism will be determined
for each 12-month period beginning November 1 and ending October 31. During
the first year of the mechanism ended October 31, 1998, LG&E recorded $3.6
million for its share of reduced gas costs. The $3.6 million will be billed
to customers through the gas supply clause beginning February 1, 1999.
In December 1997, the Kentucky Commission opened Administrative Case No. 369
to consider Commission policy regarding cost allocations, affiliate
transactions and codes of conduct governing the relationship between
utilities and their non-utility operations and affiliates. The Commission
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-utility operations; and whether a code of conduct should be
established to assure that non-utility segments of the holding company are
not engaged in practices which result in unfair competition caused by cost
shifting from the non-utility affiliate to the utility. In September 1998,
the Commission issued draft code of conduct and cost allocation guidelines.
In January 1999, the Company, as well as all parties to the proceeding, filed
comments on the Commission draft proposals. Initial hearings are scheduled
for the first
59
LG&E Energy (cont.):
quarter of 1999. 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.
As of February 12, 1999, LG&E received orders from the Kentucky Commission
requiring a refund to retail electric customers of approximately $3.9 million
resulting from reviews of the FAC from November 1994 through April 1998. The
Company estimates up to an additional $4.8 million could be refundable to
LG&E and KU retail electric customers through future Kentucky Commission
orders. See Note 5 of LG&E Energy's Notes to Financial Statements under Item
8.
Environmental Matters
The Clean Air Act Amendments of 1990 (the Act) imposed stringent new sulfur
dioxide (SO2) emission limits. LG&E is currently in compliance with the Phase
II SO2 emission limits required by the year 2000, as it had previously
installed scrubbers on all of its coal-fired generating units. KU met the
Phase I requirements of the Act primarily through the installation of a
scrubber on Unit 1 of the Ghent Generating Station, while WKE utilized fuel
switching and emission allowance strategies. The Company's combined strategy
for Phase II is to use accumulated emissions allowances to delay additional
capital expenditures and may also include fuel switching or the installation
of additional scrubbers. LG&E, KU, and WKE met the nitrogen oxide (NOx)
emission reduction requirements of the Act through installation of low-NOx
burner systems. The Company's compliance plans are subject to many factors
including developments in the emission allowance and fuel markets, future
regulatory and legislative initiatives, and advances in clean air control
technology. The Company will continue to monitor these developments to ensure
that its environmental obligations are met in the most efficient and
cost-effective manner.
In September 1998, the U.S. Environmental Protection Agency announced its
final regulation requiring significant additional reductions in NOx emissions
to mitigate alleged ozone transport to the Northeast. While each state is
free to allocate its assigned NOx reductions among various emissions sectors
as it deems appropriate, the regulation may ultimately require utilities to
reduce their NOx emissions to 0.15 lb./mmBtu (million British thermal
units)-an 85% reduction from 1990 levels. Under the regulation, each state
must incorporate the additional NOx reductions in its State Implementation
Plan (SIP) by September 1999 and affected sources must install control
measures by May 2003, unless granted extensions. Several states, various
labor and industry groups, and individual companies have appealed the final
regulation to the U.S. Court of Appeals for the D.C. Circuit. Management is
currently unable to determine the outcome or exact impact of this matter
until such time as the states identify specific emissions reductions in their
SIPs and the courts rule on the various legal challenges to the final rule.
However, if the 0.15 lb. target is ultimately imposed, LG&E, KU, WKE and the
independent power projects in which the Company has an interest will be
required to incur significant capital expenditures and increased operation
and maintenance costs for additional controls.
Subject to further study and analysis, the Company estimates that it may
incur capital costs in the range of $300 million to $500 million in the
aggregate for LG&E, KU and WKE. These costs would generally be incurred
beginning in 2000. The Company believes its costs in this regard to be
comparable to those of similarly situated utilities with like generation
assets. LG&E and KU anticipate that such capital and operating costs are the
type of costs that are eligible for cost recovery from customers under their
environmental surcharge mechanisms and believe that a significant portion of
such costs could be recovered. However, Kentucky Commission approval is
necessary and there can be no guarantee of recovery.
See Note 18 of LG&E Energy's Notes to Financial Statements under Item 8 for a
complete discussion of the Company's environmental issues concerning
manufactured gas plant sites and certain other environmental
60
LG&E Energy (cont.):
issues.
Public Utilities 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 and contractual operator of several qualifying cogeneration
facilities. 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 has been
involved in proceedings before FERC regarding its Southampton cogeneration
facility and in litigation with the purchasing utility of the energy from its
Roanoke Valley I cogeneration facility. See Note 18 of LG&E Energy's Notes to
Financial Statements under Item 8.
IMPACT OF NON-UTILITY BUSINESSES
The Company expects to continue investing in non-utility projects, including
domestic and international power production and gas distribution projects, as
described under Future Capital Requirements. The non-utility 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 non-utility
projects are subject to competition, operating risks, dependence on certain
suppliers and customers, 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 creates the potential for more volatility
in the non-utility component of the Company's earnings. Accordingly, the
historical operating results of the Company's non-utility businesses may not
necessarily be indicative of future operating results.
FUTURE OUTLOOK
Competition and Customer Choice
LG&E Energy 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-utility energy services businesses, including support for
performance-based ratemaking structures, aggressive cost reduction
activities; strategic acquisitions, dispositions 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 energy
industry and the move toward a competitive, market-based environment. LG&E
Energy has urged Congress 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 has previously
advocated the implementation of this transition by January 1, 2001, and now
recommends adoption of federal legislation specifying a date certain and
appropriate transition regulations implementing deregulation.
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 the issues addressed by these principles are:
consumer protection and benefit, system reliability, universal service,
environmental responsibility, cost allocation, stranded costs and codes of
conduct. During 1998, the Kentucky Commission and a task force of the
61
LG&E Energy (cont.):
Kentucky General Assembly have each initiated proceedings, including meetings
with representatives of utilities, consumers, state agencies and other groups
in Kentucky, to discuss the possible structure and effects of energy industry
restructuring in Kentucky. The purpose of the task force is to make
recommendations to the Kentucky General Assembly for possible legislative
action during its 2000 session.
However, at the time of this report, neither the Kentucky General Assembly
nor the Kentucky Commission has adopted or approved a plan or timetable for
retail electric industry competition in Kentucky. The nature or timing of the
ultimate legislative or regulatory actions regarding industry restructuring
and their impact on the Company, which may be significant, cannot currently
be predicted.
LG&E:
The following discussion and analysis by management focuses on those factors
that had a material effect on LG&E's financial results of operations and
financial condition during 1998, 1997, and 1996 and should be read in
connection with the financial statements and notes thereto.
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; and other factors described from
time to time in Louisville Gas and Electric Company's reports to the
Securities and Exchange Commission, and Exhibit No. 99.01 to LG&E Energy
Corp's report on Form 8-K filed October 21, 1998.
MERGER
Effective May 4, 1998, following the receipt of all required state and
federal regulatory approvals, LG&E Energy Corp. (LG&E Energy) and KU Energy
Corporation (KU Energy) merged, with LG&E Energy as the surviving
corporation. The outstanding preferred stock of Louisville Gas and Electric
Company (LG&E), a subsidiary of LG&E Energy, was not affected by the merger.
See Note 2 of LG&E's Notes to Financial Statements under Item 8.
RESULTS OF OPERATIONS
Net Income
LG&E's net income decreased $35.2 million for 1998, as compared to 1997,
primarily due to non-recurring charges for merger-related expenses and the
Environmental Cost Recovery refund of $23.6 million and $2.7 million, after
tax, respectively. Excluding these non-recurring charges, net income
decreased $8.9 million. This decrease is mainly due to higher operating
expenses at the electric generating stations and lower gas sales, partially
offset by increased electric sales.
Net income increased $5.3 million for 1997 over 1996. This improvement was
mainly due to increased sales of electricity to wholesale customers, a lower
level of maintenance expenses and increased investment and interest income.
These items were partially offset by reduced gas sales volumes due to warmer
winter weather and a write-off of certain expenses deferred in prior periods.
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LG&E (cont.):
Revenues
A comparison of operating revenues for the years 1998 and 1997, excluding the
$4.5 million provision recorded for refund of environmental costs previously
recovered from customers (ECR refund), with the immediately preceding year
reflects both increases and decreases, which have been segregated by the
following principal causes (in thousands of $):
Increase (Decrease) From Prior Period
Electric Revenues Gas Revenues
CAUSE 1998 1997 1998 1997
----- ---- ---- ---- ----
Sales to ultimate consumers:
Fuel and gas supply adjustments, etc. $ 3,750 $ (2,155) $ (4,393) $ 27,192
Merger surcredit (3,466) -- -- --
Demand side management/decoupling (6,299) 8,041 (369) 4,348
Environmental cost recovery surcharge (260) 448 -- --
Variation in sales volumes 27,051 (4,810) (42,418) (14,891)
--------- --------- --------- --------
Total retail sales 20,776 1,524 (47,180) 16,649
Wholesale sales 28,398 3,088 8,720 --
Gas transportation-net -- -- (71) 147
Other (695) 3,224 (935) (204)
--------- --------- --------- --------
Total $ 48,479 $ 7,836 $ (39,466) $ 16,592
--------- --------- --------- --------
--------- --------- --------- --------
Electric retail sales increased primarily due to the warmer weather
experienced in 1998 as compared to 1997. Wholesale sales increased due to
larger amounts of power available for off-system sales, an increase in the
unit price of the sales and sales to Kentucky Utilities (KU) of $11.6 million
due to economic dispatch following the merger in May 1998 of LG&E Energy and
KU Energy. Gas retail sales decreased from 1997 due to the warmer weather in
1998. Gas wholesale sales increased to $8.7 million in 1998 from zero in 1997
due to the implementation of LG&E's gas performance-based ratemaking
mechanism. See Note 3 of LG&E's Notes to Financial Statements under Item 8.
Electric revenues increased in 1997 due to a slightly higher level of
wholesale sales and other revenues. Gas revenues increased primarily 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.
Expenses
Fuel for electric generation and gas supply expenses comprise a large
component of LG&E's total operating costs. LG&E's electric and gas rates
contain a fuel adjustment clause (FAC) and a gas supply clause, respectively,
whereby increases or decreases in the cost of fuel and gas supply are
reflected in LG&E's rates, subject to approval by the Public Service
Commission of Kentucky (Kentucky Commission or Commission).
Fuel for electric generation increased $5.2 million (3.5%) in 1998 because of
higher cost of coal burned ($6.6 million), partially offset by a decrease in
generation ($1.4 million). Fuel expenses incurred in 1997 were approximately
the same as in 1996. The average delivered cost per ton of coal purchased was
$22.38 in 1998, $21.66 in 1997, and $21.73 in 1996.
Power purchased expense increased $32.9 million in 1998 to support the
increase in electric sales and increased purchases from KU of $16 million as
a result of economic dispatch following the merger of the two companies
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LG&E (cont.):
in May 1998. Power purchased expense increased $.6 million (4%) in 1997 due
to an increase in the amount of purchased power needed to support native load
requirements.
Gas supply expenses decreased $33 million (21%) in 1998 primarily due to a
decrease in the volume of gas delivered to the distribution system. 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). The
average unit cost per thousand cubic feet (Mcf) of purchased gas was $3.05 in
1998 and $3.46 in each of 1997 and 1996.
Other operation expenses increased $12.8 million (8.5%) over 1997 because of
increased costs to operate the electric generating plants ($6.6 million),
increased administrative costs ($2.2 million), and amortization of deferred
merger costs ($1.8 million). Other operation expenses increased $7.4 million
(5%) in 1997 primarily because of increased costs to operate the electric
generating plants ($5.1 million) and a write-off of certain previously
deferred items ($3.2 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.
Maintenance expenses increased $5.2 million (11%) in 1998 as compared to 1997
primarily because of an increase in scheduled outages and general repairs at
the electric generating plants ($2.2 million) and an increase in storm damage
expenses ($1.4 million). Maintenance expenses decreased $7.2 million (13%) in
1997 from 1996 due to decreased repairs at the electric generating plants
resulting from fewer scheduled outages ($5 million) and a lower level of
storm damage repairs ($1.8 million).
Depreciation and amortization for 1998 were approximately the same as in
1997. Depreciation and amortization increased $4 million (4.5%) in 1997
because of additional utility plant in service. In addition, 1997 reflects
the accelerated write-off of losses on early retirements of facilities.
Variations in income tax expenses are largely attributable to changes in
pre-tax income.
LG&E incurred a pre-tax charge in the second quarter of 1998 for costs
associated with the merger of LG&E Energy and KU Energy of $32.1 million. The
corresponding tax benefit of $8.5 million is recorded in other income and
(deductions). The amount charged is in excess of the amount permitted to be
deferred as a regulatory asset by the Kentucky Commission. See Note 2 of
LG&E's Notes to Financial Statements under Item 8.
Other income for 1997 increased by $3.4 million primarily because of the
recording in 1997 of interest income due to a favorable tax settlement and
the sale of stock options which LG&E had acquired in a commercial
transaction. See Note 9 of LG&E's Notes to Financial Statements under Item 8.
Interest charges for 1998 decreased $2.9 million (7%) due to the retirement
of LG&E's 6.75% Series First Mortgage Bonds and lower interest rates.
Interest charges for 1997 decreased $1.1 million (3%) due to favorable
refinancing activities in 1996. The embedded cost of long-term debt was 5.57%
at December 31, 1998, and 5.68% at December 31, 1997. See Note 10 of LG&E's
Notes to Financial Statements under Item 8.
The rate of inflation may have a significant impact on LG&E's operations, its
ability to control costs and the need to seek timely and adequate rate
adjustments. However, relatively low rates of inflation in the past few years
have moderated the impact on current operating results.
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LG&E (cont.):
LIQUIDITY AND CAPITAL RESOURCES
LG&E's need for capital funds is largely related to the construction of plant
and equipment necessary to meet the needs of electric and gas utility customers
and protection of the environment.
Construction Expenditures
New construction expenditures for 1998 were $138 million compared with $111
million for 1997 and $108 million for 1996.
Past Financing Activities
During 1998, 1997 and 1996, LG&E's primary source of capital was internally
generated funds from operating cash flows. Internally generated funds
provided financing for 100% of LG&E's construction expenditures for 1998,
1997, and 1996.
LG&E's combined cash and marketable securities balance decreased by $20
million in 1998 and increased $9 million in 1997. The decrease for 1998
reflects retirement of a $20 million first mortgage bond. In 1997, the
increase reflects cash flows from operations, partially offset by
construction expenditures and dividends paid.
Variations in accounts receivable and accounts payable are not generally
significant indicators of LG&E's liquidity, as such variations are primarily
attributable to fluctuations in weather in LG&E's service territory, which
has a direct affect on sales of electricity and natural gas.
On June 1, 1998, LG&E's First Mortgage Bonds, 6.75% Series of $20 million
matured and were retired by LG&E. The bonds were redeemed with available
funds.
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 these bonds were
3.09% and 3.39%, respectively, at December 31, 1998. 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.
Future Capital Requirements
Future financing requirements may be affected in varying degrees by factors
such as load growth, changes in construction expenditure levels, rate actions
by regulatory agencies, new legislation, market entry of competing electric
power generators, changes in environmental regulations and other regulatory
requirements. LG&E estimates construction expenditures will total $384
million for 1999 and 2000. This estimate includes capital expenditures
associated with installation of low nitrogen oxide burner systems as
described in "Environmental Matters."
In July 1998, following LG&E Energy's decision to discontinue its merchant
energy trading and sales business, Standard & Poor's (S&P) downgraded the
credit ratings of LG&E Energy and its subsidiaries while Moody's and Duff &
Phelps (D&P) kept LG&E Energy and its subsidiaries at their prior ratings.
65
LG&E (cont.):
LG&E's current debt ratings are:
Moody's S&P D&P
------- --- ---
First mortgage bonds Aa2 A+ AA
Unsecured debt Aa3 A AA-
Preferred stock aa3 A- AA-
These ratings reflect the views of Moody's, S&P and D&P. An explanation of
the significance of these ratings may be obtained from them. 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 and new debt are expected to fund
substantially all anticipated construction expenditures in 1999 and 2000.
At December 31, 1998, LG&E had unused lines of credit of $200 million for
which it pays commitment fees. These credit facilities provide for short-term
borrowing and are scheduled to expire in 2001. Management expects to
renegotiate them when they expire.
To the extent permanent financings are needed in 1999 and 2000, LG&E expects
that it will have ready access to the securities markets to raise needed
funds.
Market Risks
LG&E is exposed to market risks from changes in interest rates and commodity
prices. To mitigate changes in cash flows attributable to these exposures,
LG&E has entered into various derivative financial instruments. Derivative
positions are monitored using techniques that include market value and
sensitivity analysis.
Interest Rate Sensitivity
LG&E has certain variable rate Pollution Control Bonds outstanding. At
December 31, 1998, the potential change in interest expense associated with a
1% change in base interest rates of LG&E's unswapped debt is estimated at $.8
million.
Interest rate swaps are used to hedge LG&E's underlying variable rate debt
obligations. These swaps hedge specific debt issuance and consistent with
management's designation are accorded hedge accounting treatment.
LG&E has entered into swaps to reduce the impact of interest rate changes on
its Pollution Control Bonds. The swap agreements involve the exchange of
floating-rate interest payments for fixed interest payments over the life of
the agreements. As of December 31, 1998, 67% of the outstanding variable
interest rate borrowings were converted to fixed interest rates through
swaps. The potential loss in fair value from these positions resulting from a
hypothetical 1% adverse movement in base interest rates is estimated at $3.5
million as of December 31, 1998. Changes in the market value of these swaps
if held to maturity, as LG&E intends to do, will have no effect on LG&E's net
income or cash flow. See Note 4 LG&E's of Notes to Financial Statements under
Item 8.
In April 1998, LG&E entered into a forward starting swap agreement. The
forward swap involves the exchange
66
LG&E (cont.):
of floating-rate interest payments for fixed interest payments over the life
of the agreement. The forward swap was entered into to hedge LG&E's exposure
to interest rates for the anticipated call of its Trimble County, Kentucky,
Pollution Control Bonds, 7 5/8% Series, due November 1, 2020. The potential
loss in fair value from this position resulting from a hypothetical 10%
change in the yield curve is estimated at $7.5 million as of December 31,
1998. See Note 4 of LG&E's Notes to Financial Statements under Item 8.
Commodity Price Sensitivity
LG&E has limited exposure to market volatility in prices of fuel or
electricity, as long as cost-based regulations exist. To mitigate residual
risks relative to the movements in fuel or in electricity prices, LG&E has
entered into primarily fixed-priced contracts for the purchase and sale of
electricity through the wholesale electricity market. Realized gains and
losses are recognized in the income statement as incurred. At December 31,
1998, exposure from these activities was not material to the financial
statements of LG&E.
Year 2000 Issue
LG&E uses various software, systems and technology that may be affected by
the "Year 2000 Issue." This concerns the ability of electronic processing
equipment (including microprocessors embedded in other equipment) to properly
process the millennium change to the year 2000 and related issues. A failure
to timely correct any such processing problems could result in material
operational and financial risks if significant systems either cease to
function or produce erroneous data. Such risks are more fully described in
the sections that follow, but could include an inability to operate its
generating plants, disruptions in the operation of transmission and
distribution systems and an inability to access interconnections with the
systems of neighboring utilities.
LG&E began its project regarding the Year 2000 issue in 1996. The Board of
Directors has approved the general Year 2000 plan and receives regular
updates. In addition, monthly reporting procedures have been established at
senior management levels. Since 1996, a single-purpose Year 2000 team has
been established in the Information Technology (IT) Department. This team,
which is headed by an officer of LG&E, is responsible for planning,
implementing, and documenting LG&E's Year 2000 process. The team also
provides direct and detailed assistance to LG&E's operational divisions and
smaller units, where identified personnel are responsible for Year 2000 work
and remediation in their specific areas. In many cases, LG&E also uses the
services of third parties, including technical consultants, vendor
representatives and auditors.
LG&E's Year 2000 effort generally follows a three-phase process:
Phase I - inventory and identify potential Year 2000 issues, determine
solutions;
Phase II - survey vendors regarding their Year 2000 readiness, determine
solutions to deal with possible vendor non-compliance, develop work plans
regarding LG&E and vendors non-compliance issues; and
Phase III - implementation, testing, certification, contingency planning.
LG&E has long recognized the complexity of the Year 2000 issue. Work has
progressed concurrently on (a) replacing or modifying IT systems, including
mainframes, client-server, PCs and software applications, (b) replacing or
modifying non-IT systems, including embedded systems such as mechanical
control units, (c) evaluating the readiness of key third parties, including
customers, suppliers, business partners and neighboring utilities, and (d)
contingency planning.
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LG&E (cont.):
State of Readiness
As of January 1999, LG&E has substantially completed the internal inventory,
vendor survey and compliance assessment portions (Phases I and II) of its
Year 2000 plan for critical mainframe and PC hardware and software, as well
as embedded systems. Remediation efforts (Phase III) in these areas are
approximately 65% complete. Phase III remediation efforts are also in
progress for embedded systems. Testing and contingency planning has commenced
and will continue as remediation efforts are implemented and are expected to
run until July 1999.
As a general matter, corrective action for major IT systems, including
customer information and financial systems, and smaller or more isolated
systems, including embedded and plant operational systems, are in process or
have been completed. LG&E has communicated with its key suppliers, customers
and business partners regarding their Year 2000 progress, particularly in the
IT software and embedded component areas, to determine the areas in which
LG&E's operations are vulnerable to those parties' failure to complete their
remediation efforts. LG&E is currently evaluating and, in certain cases,
initiating follow-up actions regarding the responses from these parties. LG&E
regularly attends and participates in trade group efforts focusing on Year
2000 issues in the energy industry.
Costs of Year 2000 Issues
LG&E's system modification costs related to the Year 2000 issue are being
expensed as incurred, while new system installations are generally being
capitalized pursuant to generally accepted accounting principles. See Note 1
of LG&E's Notes to Financial Statements under Item 8. Through December 1998,
LG&E has incurred approximately $16 million in capital and operating costs in
connection with the Year 2000 issue. Based upon studies and projections to
date, LG&E expects to spend an additional $4.6 million to complete its Year
2000 efforts.
It should be noted that these figures include total hardware, software,
embedded systems and consulting costs. In many cases, these costs include
system replacements which were already contemplated or which provided
additional benefits or efficiencies beyond the Year 2000 aspect.
Additionally, many costs are not incremental costs, but constitute
redeployment of existing IT and other resources. These costs represent
management's current estimates; however, there can be no assurance that
actual costs associated with LG&E's Year 2000 issues will not be higher.
Risks of Year 2000 Issues
As described above, LG&E has made significant progress in the implementation
of its Year 2000 plan. Based upon the information currently known regarding
its internal operations and assuming successful and timely completion of its
remediation plan, LG&E does not anticipate material business disruptions from
its internal systems due to the Year 2000 issue. However, LG&E may possibly
experience limited interruptions to some aspects of its activities, whether
IT, generation, transmission or distribution, operational, administrative
functions or otherwise, and LG&E is considering such potential occurrences in
planning for the most reasonably likely worst-case scenarios.
Additionally, risk exists regarding the non-compliance of third parties with
key business or operational importance to LG&E. Year 2000 problems affecting
key customers, interconnected utilities, fuel suppliers and transporters,
telecommunications providers or financial institutions could result in lost
power or gas sales, reduced power production or transmission capabilities or
internal operational or administrative difficulties on
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LG&E (cont.):
the part of LG&E. LG&E is not presently aware of any such situations;
however, severe occurrences of this type could have material adverse impacts
upon the business, operating results or financial condition of LG&E. There
can be no assurance that LG&E will be able to identify and correct all
aspects of the Year 2000 problem among these third parties that affect it in
sufficient time, that it will develop adequate contingency plans or that the
costs of achieving Year 2000 readiness will not be material.
Contingency planning is under way for material areas of Year 2000 risk. This
effort will address certain areas, including the most reasonably likely
worst-case scenarios and delays in completion in LG&E's remediation plans,
failure or incomplete remediation results and failure of key third parties to
be Year 2000 compliant. Contingency plans will include provisions for extra
staffing, back-up communications, review of unit dispatch and load shedding
procedures, carrying of additional energy reserves and manual energy
accounting procedures. Completion of contingency plan formation is scheduled
for June 1999.
Forward-Looking Statements
The foregoing discussion regarding the timing, effectiveness, implementation
and cost of LG&E's Year 2000 efforts, contains forward-looking statements,
which are based on management's best estimates and assumptions. These
forward-looking statements involve inherent risks and uncertainties, and
actual results could differ materially from those contemplated by such
statements. Factors that might cause material differences include, but are
not limited to, the availability of key Year 2000 personnel, LG&E's ability
to locate and correct all relevant computer codes, the readiness of third
parties and LG&E's ability to respond to unforeseen Year 2000 complications
and other factors described from time to time in LG&E's reports to the
Securities and Exchange Commission, and Exhibit 99.01 to LG&E Energy Corp.'s
Form 8-K filed October 21, 1998. Such material differences could result in,
among other things, business disruption, operational problems, financial
loss, legal liability and similar risks.
Rates and Regulation
LG&E is subject to the jurisdiction of the Kentucky Commission in virtually
all matters related to electric and gas utility regulation, and as such, its
accounting is subject to Statement of Financial Accounting Standards No. 71,
Accounting for the Effects of Certain Types of Regulation (SFAS No. 71).
Given LG&E's competitive position in the market and the status of regulation
in the state of Kentucky, LG&E has no plans or intentions to discontinue its
application of SFAS No. 71. See Note 3 of LG&E's Notes to Financial
Statements under Item 8.
Since May 1995, LG&E implemented an environmental cost recovery (ECR)
surcharge to recover certain environmental compliance costs. Such costs
include compliance with the 1990 Clean Air Act, as amended, and other
environmental regulations, including those applicable to coal combustion
wastes and related by-products. The ECR mechanism was authorized by state
statute in 1992 and was first approved by the Kentucky Commission in a KU
case in July 1994.
The Commission's order approving the surcharge in the KU case and the
constitutionality of the surcharge were challenged by certain intervenors,
including the Attorney General of Kentucky, in Franklin Circuit Court.
Decisions of the Circuit Court and the Kentucky Court of Appeals in July 1995
and December 1997, respectively, have upheld the constitutionality of the ECR
statute but differed on a claim of retroactive recovery of certain amounts.
The Commission ordered that certain surcharge revenues collected by LG&E be
subject to refund pending final determination of all appeals.
On December 19, 1998, the Kentucky Supreme Court rendered an opinion upholding
the constitutionality of the
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LG&E (cont.):
surcharge statute. The decision, however, reversed the ruling of the Court of
Appeals on the retroactivity claim, thereby denying recovery of costs
associated with pre-1993 environmental projects through the ECR. The court
remanded the case to the Commission to determine the proper adjustments to
refund amounts collected for such pre-1993 environmental projects. The
parties to the proceeding have notified the Commission that they have reached
agreement as to the terms, proper adjustments and forward application of the
ECR. The settlement agreement is subject to Commission approval. LG&E
recorded a provision for rate refund of $4.5 million in December 1998.
In January 1994, LG&E implemented a Commission-approved demand side
management (DSM) program that LG&E, the Jefferson County Attorney, and
representatives of several customer interest groups had filed with the
Commission. The program included 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 program (decoupling). In June 1998, LG&E and customer
interest groups requested an end to the decoupling rate mechanism. On June 1,
1998, LG&E discontinued recording revenues from lost sales due to DSM.
Accrued decoupling revenues recorded for periods prior to June 1, 1998, will
continue to be collected through the DSM recovery mechanism. On September 23,
1998, the Commission accepted LG&E's modified tariff reflecting this proposal
effective as of June 1, 1998.
In October 1998, LG&E and KU filed separate, but parallel applications with
the Commission for approval of a new method of determining electric rates
that provides financial incentives for LG&E and KU to further reduce
customers' rates. The filing was made pursuant to the September 1997
Commission order approving the merger of LG&E Energy and KU Energy, wherein
the Commission directed LG&E and KU to indicate whether they desired to
remain under traditional rate of return regulation or commence
non-traditional regulation. The new ratemaking method, known as
performance-based ratemaking (PBR), would include financial incentives for
LG&E and KU to reduce fuel costs and increase generating efficiency, and to
share any resulting savings with customers. Additionally, the PBR provides
financial penalties and rewards to assure continued high quality service and
reliability.
The PBR plan proposed by LG&E and KU consists of five components:
The utilities' fuel adjustment clause mechanism will be withdrawn and
replaced with a cap that limits recovery of actual changes in fuel cost to
changes in a fuel price index for a five-state region. If the utilities
outperform the index, benefits will be shared equally between shareholders
and customers. If the utilities' fuel costs exceed the index, the
difference will be absorbed by LG&E Energy's shareholders.
Customers will continue to receive the benefits from the post-merger joint
dispatch of power from LG&E's and KU's generating plants.
Power plant performance will be measured against the best performance
achieved between 1991 and 1997. If the performance exceeds this level,
customers will share equally with LG&E Energy's shareholders in up to $10
million annually of benefits from this performance at each of LG&E and KU.
The utilities will be encouraged to maintain and improve service quality,
reliability, customer satisfaction and safety, which will be measured
against six objective benchmarks. The plan provides for annual rewards or
penalties to LG&E Energy of up to $5 million per year at each of LG&E and
KU.
The plan provides the utilities with greater flexibility to customize rates
and services to meet customer needs. Services will continue to be priced
above marginal cost and customers will continue to have the
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LG&E (cont.):
option to elect standard tariff service.
These proposals are subject to approval by the Commission. Approval
proceedings commenced in October 1998 and a final decision likely will occur
in 1999. Several intervenors are participating in the case. Some have
requested that the Commission reduce base rates before implementing PBR.
On March 8, 1999, the Kentucky Industrial Utility Customers filed a Complaint
with the Kentucky Commission alleging that LG&E's electric rates are
excessive and should be reduced by an amount between $43 and $90 million and
that the Kentucky Commission establish a proceeding to reduce LG&E's electric
rates. LG&E has asked the Kentucky Commission to dismiss the Complaint.
LG&E is not able to predict the ultimate outcome of these proceedings,
however, should the Commission mandate significant rate reductions at LG&E,
through the PBR proposal or otherwise, such actions could have a material
effect on LG&E's financial condition and results of operations.
Since October 1997, LG&E has implemented a Commission-approved, experimental
performance-based ratemaking mechanism related to gas procurement activities
and off-system gas sales only. During the three-year test period beginning
October 1997, rate adjustments related to this mechanism will be determined
for each 12-month period beginning November 1 and ending October 31. During
the first year of the mechanism ended October 31, 1998, LG&E recorded $3.6
million for its share of reduced gas costs. The $3.6 million will be billed
to customers through the gas supply clause beginning February 1, 1999.
In December 1997, the Kentucky Commission opened Administrative Case No. 369
to consider Commission policy regarding cost allocations, affiliate
transactions and codes of conduct governing the relationship between
utilities and their non-utility operations and affiliates. The Commission
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-utility operations; and whether a code of conduct should be
established to assure that non-utility segments of the holding company are
not engaged in practices which result in unfair competition caused by cost
shifting from the non-utility affiliate to the utility. In September 1998,
the Commission issued draft code of conduct and cost allocation guidelines.
In January 1999, LG&E, as well as all parties to the proceeding, filed
comments on the Commission draft proposals. Initial hearings are scheduled
for the first quarter of 1999. Management does not expect the ultimate
resolution of this matter to have a material adverse effect on LG&E's
financial position or results of operations.
As of February 12, 1999, LG&E received orders from the Kentucky Commission
requiring a refund to retail electric customers of approximately $3.9 million
resulting from reviews of the FAC from November 1994 through April 1998. LG&E
estimates up to an additional $1.3 million could be refundable to retail
electric customers for the period from May 1998 through December 1998. See
Note 3 of LG&E's Notes to Financial Statements under Item 8.
LG&E filed a Petition for Rehearing of all of the orders and a motion to
suspend the refund obligation. On February 25, 1999, the Commission suspended
the obligation to refund pending further direction by the Commission. It also
advised that LG&E may have to pay interest on the refund amounts for the
suspension period. On March 11, 1999 the Commission denied LG&E's Petition
for Rehearing for the period November 1994 through October 1996 and directed
LG&E to reduce future fuel expense by $1.9 million in the first billing month
after the Order. The Company is considering the filing of an Appeal with the
Franklin Circuit Court. In a separate series of Orders on March 11, 1999, the
PSC granted LG&E's Petition for Rehearing for the period November 1996
through April 1998 and established a procedural schedule for LG&E and other
parties to
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LG&E (cont.):
submit evidence and for a hearing before the Commission. In the same Orders
the PSC granted the Petition for Rehearing of the Kentucky Industrial Utility
Customers to determine if interest should be paid on any fuel refunds for
this latter period.
Environmental Matters
The Clean Air Act Amendments of 1990 (the Act) imposed stringent new sulfur
dioxide (SO2) emission limits. LG&E is currently in compliance with the Phase
II SO2 emission limits required by the year 2000, as it had previously
installed scrubbers on all of its coal-fired generating units. LG&E met the
nitrogen oxide (NOx) emission reduction requirements of the Act through
installation of low-NOx burner systems. LG&E's compliance plans are subject
to many factors including developments in the emission allowance and fuel
markets, future regulatory and legislative initiatives, and advances in clean
air control technology. LG&E will continue to monitor these developments to
ensure that its environmental obligations are met in the most efficient and
cost-effective manner.
In September 1998, the U.S. Environmental Protection Agency announced its
final regulation requiring significant additional reductions in NOx emissions
to mitigate alleged ozone transport to the Northeast. While each state is
free to allocate its assigned NOx reductions among various emissions sectors
as it deems appropriate, the regulation may ultimately require utilities to
reduce their NOx emissions to 0.15 lb./mmBtu (million British thermal units)
- - an 85% reduction from 1990 levels. Under the regulation, each state must
incorporate the additional NOx reductions in its State Implementation Plan
(SIP) by September 1999 and affected sources must install control measures by
May 2003, unless granted extensions. Several states, various labor and
industry groups, and individual companies have appealed the final regulation
to the U.S. Court of Appeals for the D.C. Circuit. Management is currently
unable to determine the outcome or exact impact of this matter until such
time as the states identify specific emissions reductions in their SIP and
the courts rule on the various legal challenges to the final rule. However,
if the 0.15 lb. target is ultimately imposed, LG&E will be required to incur
significant capital expenditures and increased operation and maintenance
costs for additional controls.
Subject to further study and analysis, LG&E estimates that it may incur
capital costs in the range of $100 million to $200 million. These costs would
generally be incurred beginning in 2000. LG&E believes its costs in this
regard to be comparable to those of similarly situated utilities with like
generation assets. LG&E anticipates that such capital and operating costs are
the type of costs that are eligible for cost recovery from customers under
its environmental surcharge mechanism and believes that a significant portion
of such costs could be recovered. However, Kentucky Commission approval is
necessary and there can be no guarantee of such recovery.
See Note 12 of LG&E's Notes to Financial Statements under Item 8 for a
complete discussion of LG&E's environmental issues concerning manufactured
gas plant sites and certain other environmental issues.
FUTURE OUTLOOK
Competition and Customer Choice
LG&E Energy 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, LG&E Energy has taken
many steps to prepare for the expected increase in competition in its
regulated and non-utility energy services businesses, including support for
performance-based ratemaking structures; aggressive cost reduction
activities;
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LG&E (cont.):
strategic acquisitions, dispositions 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. LG&E Energy continues to be active
in the national debate surrounding the restructuring of the energy industry
and the move toward a competitive, market-based environment. LG&E Energy has
urged Congress 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 has previously advocated the
implementation of this transition by January 1, 2001, and now recommends that
adoption of federal legislation specifying a date certain and appropriate
transition regulations implementing deregulation.
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 the issues addressed by these principles are:
consumer protection and benefit, system reliability, universal service,
environmental responsibility, cost allocation, stranded costs and codes of
conduct. During 1998, the Kentucky Commission and a task force of the
Kentucky General Assembly have each initiated proceedings, including meetings
with representatives of utilities, consumers, state agencies and other groups
in Kentucky, to discuss the possible structure and effects of energy industry
restructuring in Kentucky. The purpose of the task force is to make
recommendations to the Kentucky General Assembly for possible legislative
action during its 2000 session.
However, at the time of this report, neither the Kentucky General Assembly
nor the Kentucky Commission has adopted or approved a plan or timetable for
retail electric industry competition in Kentucky. The nature or timing of the
ultimate legislative or regulatory actions regarding industry restructuring
and their impact on LG&E, which may be significant, cannot be currently
predicted.
KU
General
The following discussion and analysis by management focuses on those factors
that had a material effect on KU's financial results of operations and
financial condition during 1998, 1997, and 1996 and should be read in
connection with KU's financial statements and notes thereto.
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, and other factors described from
time to time in Kentucky Utilities Company's reports to the Securities and
Exchange Commission, including Exhibit No. 99.01 to LG&E Energy Corp.'s
report on Form 8-K filed October 21, 1998.
Merger
Effective May 4, 1998, following the receipt of all required state and
federal regulatory approvals, LG&E Energy Corp. (LG&E Energy) and KU Energy
Corporation (KU Energy) merged, with LG&E Energy as the surviving
corporation. The outstanding preferred stock of Kentucky Utilities Company
(KU), which was a subsidiary of KU Energy before the merger, was not affected
by the merger. See Note 2 of KU's Notes to Financial Statements under Item 8.
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KU (cont.):
RESULTS OF OPERATIONS
Net Income
KU's net income decreased $12.9 million for 1998 as compared to 1997,
primarily due to non-recurring charges for merger-related expenses and
Environmental Cost Recovery refund of $21.5 million and $12.9 million, after
tax, respectively. Excluding these non-recurring charges, net income
increased $21.5 million. The increase is mainly due to higher residential
sales, commercial sales, industrial sales and sales for resale caused by the
warmer weather and increased marketing efforts. Net income for 1997 as
compared to 1996 was flat.
Revenues
A comparison of KU's revenues for the years 1998 and 1997, excluding the
provision recorded for refund of environmental costs previously recovered
(ECR refund) from customers (which reduced electric revenues by $21.5
million), with the immediately preceding year reflects both increases and
decreases, which have been segregated by the following principal causes (in
thousands of $):
Increase (Decrease)
From Prior Period
CAUSE 1998 1997
----- ---- ----
Sales to ultimate consumers:
Fuel clause adjustments, etc. $ 1,158 $ (5,414)
Merger surcredit (4,035) -
Environmental cost recovery surcharge (547) 554
Variation in sales volumes 25,841 11,301
-------- --------
Total retail sales 22,417 6,441
Sales for resale 91,788 (1,878)
Other 972 163
-------- --------
Total $115,177 $ 4,726
-------- --------
-------- --------
Retail sales increased due to increases in residential and commercial sales
primarily attributable to warmer weather experienced in the second and third
quarters of 1998 as compared to 1997. The increase in sales for resale
(7,224,156 megawatt-hours versus 3,397,423 megawatt-hours) was primarily due
to a more aggressive marketing efforts, increase in the unit price of the
sales, efficiencies achieved from coordinated dispatch of a larger available
pool of generation following completion of the merger, and sales to LG&E of
$16 million due to economic dispatch following the merger in May 1998 of LG&E
Energy and KU Energy.
Total sales for 1997 were flat as compared to 1996. Residential sales
decreased 2% for the year due to milder weather in 1997 compared to 1996.
Industrial sales increased 9% reflecting continued growth in the
manufacturing sector of the service area economy. Sales for resale, which
include wholesale and opportunity sales, declined 9% in 1997; however,
revenues did not decline by a comparable amount due to higher market prices
per megawatt-hour on opportunity sales.
Provision for rate refund reflects a charge in revenues during 1998 of $21.5
million for the refund of environmental costs previously recovered from
customers. See Note 3 of KU's Notes to Financial Statements under Item 8.
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KU (cont.):
Expenses
Fuel for electric generation comprises a large component of KU's total
operating costs. KU's electric rates contain a fuel adjustment clause (FAC),
whereby increases or decreases in the cost of fuel are reflected in KU's
rates, subject to approval by the Public Service Commission of Kentucky
(Kentucky Commission or Commission), Virginia State Corporation Commission
(Virginia Commission), and the Federal Energy Regulatory Commission (FERC).
Fuel for electric generation increased $27.4 million (15%) in 1998 primarily
due to a 12% increase in MBTU (Million British Thermal Units) used. Fuel
expenses increased by $30.3 million (22%) in 1997 primarily due to a 18%
increase in MBTU (Million British Thermal Units) used. The increased
consumption was primarily caused by the previously mentioned increase in
kilowatt-hour sales. KU's average delivered cost per ton of coal purchased
was $26.97 in 1998 , $27.97 in 1997, and $27.54 in 1996.
Power purchased expense increased $54 million (75%) in 1998 because of a 67%
increase in megawatt-hour purchases which was primarily attributable to
increased marketing efforts and purchases from LG&E of $11.6 million as a
result of economic dispatch following the merger of the two companies in May
1998. Power purchased expense increased $10.1 million (16%) in 1997 due to a
19% increase in kWH purchases associated with increased availability of
surplus power on favorable pricing terms and to a one-time reduction in
demand costs in 1996 of about $4 million under a contract with a neighboring
utility.
Depreciation and amortization increased $2.5 million (1.5%) in 1998 because
of additional utility plant in service. Depreciation and amortization
increased in 1997 primarily because of additional plant in service at KU.
KU's embedded cost of long-term debt was 6.99% at December 31, 1998, and
6.98% at December 31, 1997. See Note 10 of KU's Notes to Financial
Statements under Item 8.
Merger costs to achieve reflects the one-time charge during 1998 of $21.7
million (the corresponding tax benefit of $.2 million is recorded in other
income and (deductions) for merger related expenses as discussed in Note 2 of
KU's Notes to Financial Statements under Item 8).
Variations in income tax expense are largely attributable to changes in
pre-tax income.
The rate of inflation may have a significant impact on KU'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.
LIQUIDITY AND CAPITAL RESOURCES
KU's need for capital funds is largely related to the construction of plant
and equipment necessary to meet the needs of electric utility customers and
protection of the environment.
Construction Expenditures
New construction expenditures for 1998 were $92 million compared with $94
million for 1997 and $106.5 million for 1996.
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KU (cont.):
Past Financing Activities
During 1998, 1997, and 1996, KU's primary source of capital was internally
generated funds from operating cash flows and debt financing. Internally
generated funds provided financing for 100% of KU's construction expenditures
for 1998, 1997, and 1996.
Variations in accounts receivable and accounts payable are not generally
significant indicators of KU's liquidity, as such variations are primarily
attributable to fluctuations in weather in KU's service territory, which has
a direct affect on sales of electricity.
KU has no short-term borrowings outstanding at December 31, 1998. 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 in 1997 from 1996 was due primarily to KU's cash provided by
operations exceeding cash required for investing and financing activities
(exclusive of short-term borrowings).
Future Capital Requirements
Future 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. KU estimates construction expenditures will total
$341 million for 1999 and 2000. In addition, KU's capital requirements for
2000 include $61.5 million for scheduled debt retirements.
In July 1998, following LG&E Energy's decision to discontinue its merchant
energy trading and sales business, Standard & Poor's (S&P) downgraded the
credit ratings of LG&E Energy and its subsidiaries while Moody's and Duff &
Phelps (D&P) kept LG&E Energy and its subsidiaries at their prior ratings.
KU's current debt ratings are:
Moody's S&P D&P
------- --- ---
First mortgage bonds Aa2 A+ AA
Preferred stock Aa3 A- AA-
Commercial paper P-1 A-1 D-1+
These ratings reflect the views of Moody's, S&P and D&P. An explanation of
the significance of these ratings may be obtained from them. 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 and new debt are expected to fund
substantially all anticipated construction expenditures in 1999 and 2000.
At December 31, 1998, KU had unused lines of credit of $60 million for which
it pays commitment fees. The KU credit facilities provide for short-term
borrowing and support of commercial-paper borrowings. These credit facilities
are scheduled to expire in 1999. Management expects to renegotiate them when
they expire.
76
KU (cont.):
To the extent permanent financings are needed in 1999 and 2000, KU expects
that it will have ready access to the securities markets to raise needed
funds.
Interest Rate Sensitivity
KU has variable rate debt obligations outstanding. At December 31, 1998, the
potential change in interest expense associated with a 1% change in base
interest rates is immaterial.
Commodity Price Sensitivity
KU has limited exposure to market volatility in prices of fuel or
electricity, as long as cost-based regulations exist. To mitigate residual
risks relative to the movements in fuel or electricity prices, KU entered
into primarily fixed priced contracts for the purchase and sale of
electricity through the wholesale electricity market. Realized gains and
losses are recognized in the income statement as incurred. At December 31,
1998, exposure from these activities was not material to the financial
statements.
Year 2000 Issue
KU uses various software, systems and technology that are affected by the
"Year 2000 Issue." This issue concerns the ability of electronic processing
equipment (including microprocessors embedded in other equipment) to properly
process the millennium change to 2000 and related issues. A failure to timely
correct any such processing problems could result in material operational and
financial risks if significant systems either cease to function or produce
erroneous data. Such risks are described in more detail following, but could
include an inability to operate its generating plants, disruptions in the
operation of transmission and distribution systems, and an inability to
access interconnections with the systems of neighboring utilities.
KU began its project regarding the Year 2000 issue in 1996. The Board of
Directors has approved the general Year 2000 plan and receives regular
updates. In addition, monthly reporting procedures have been established at
senior management levels. Since 1996, a single-purpose Year 2000 team has
been established in the Information Technology (IT) Department. This team,
which is headed by an officer, is responsible for planning, implementing, and
documenting KU's Year 2000 process. The team also provides direct and
detailed assistance to KU's operational divisions and smaller units, where
identified personnel are responsible for Year 2000 work and remediation in
their specific areas. In many cases, KU also uses the services of third
parties, including technical consultants, vendor representatives and auditors.
KU's Year 2000 effort generally follows a three phase process:
Phase I - inventory and identify potential Year 2000 issues, determine
solutions;
Phase II - survey vendors regarding their Year 2000 readiness, determine
solutions to deal with possible vendor non-compliance, develop work plans
regarding KU and vendors non-compliance issues; and
Phase III - implementation, testing, certification, contingency planning.
KU has long recognized the complexity of the Year 2000 issue. Work has
progressed concurrently on (a) replacing or modifying IT systems, including
mainframes, PC's and software applications, (b) replacing or modifying non-IT
systems, including embedded systems such as mechanical control units, (c)
evaluating the readiness of key third parties, including customers,
suppliers, business partners and neighboring utilities, and (d)
77
KU (cont.):
contingency planning.
State of Readiness
As of January 1999, KU has substantially completed the internal inventory,
vendor survey, and compliance assessment portions (Phases I and II) of their
Year 2000 plan for critical mainframe and PC hardware and software, as well
as embedded systems. Remediation efforts (Phase III) in these areas are
approximately 55% complete. Testing and contingency planning has commenced
and will continue as remediation efforts are implemented and are expected to
run until July 1999.
As a general matter, corrective action for major IT systems, including
customer information, financial and trading systems, and smaller or more
isolated systems, including embedded and plant operational systems, are in
process or have been completed. KU has communicated with its key suppliers,
customers and business partners regarding their Year 2000 progress,
particularly in the IT software and embedded component areas, to determine
the areas in which KU's operations are vulnerable to those parties failure to
complete their remediation efforts. KU is currently evaluating and, in
certain cases, initiating follow-up actions regarding the responses from
these parties. KU regularly attends and participates in trade group efforts
focusing on Year 2000 issues in the energy industry context.
Costs of Year 2000 Issues
KU's system modification costs related to the Year 2000 issue are being
expensed as incurred, while new system installations are generally being
capitalized pursuant to generally accepted accounting principles. (See Note 1
of KU's Notes to Financial Statements under Item 8). Through December 1998,
KU has incurred approximately $2.4 million in capital and operating costs in
connection with the Year 2000 issue. Based upon studies and projections to
date, KU expects to spend an additional $4.5 million to complete its Year
2000 efforts.
It should be noted that these figures include total hardware, software,
embedded systems and consulting costs. In many cases, these costs include
system replacements which were already contemplated or which provided
additional benefits or efficiencies beyond the Year 2000 aspect. Additionally
many costs are not incremental costs, but constitute redeployment of existing
IT and other resources. These costs represent management's current estimates;
however, there can be no assurance that actual costs associated with KU's
Year 2000 issues will not be higher.
Risks of Year 2000 Issues
As described above, KU has made significant progress in the implementation of
its Year 2000 plan. Based upon the information currently known regarding its
internal operations and assuming successful and timely completion of its
remediation plan, KU does not anticipate material business disruptions from
its internal systems due to the Year 2000 issue. However, KU may possibly
experience limited interruptions to some aspects of its activities, whether
IT, generation, transmission or distribution, operational, administrative
functions or otherwise, and KU is considering such potential occurrences in
planning for the most reasonably likely worst-case scenarios.
Additionally, risk exists regarding the non-compliance of third parties with
key business or operational importance to KU. Year 2000 problems affecting
key customers, interconnected utilities, fuel suppliers and transporters,
telecommunications providers or financial institutions could result in lost
power or gas sales,
78
KU (cont.):
reduced power production or transmission capabilities or internal operational
or administrative difficulties on the part of the KU. KU is not presently
aware of any such situations; however, severe occurrences of this type could
have material adverse impacts upon the business, operating results or
financial condition of KU. There can be no assurance that KU will be able to
identify and correct all aspects of the Year 2000 problem among these third
parties that affect it in sufficient time, that it will develop adequate
contingency plans or that the costs of achieving Year 2000 readiness will not
be material.
Contingency planning is under way for material areas of Year 2000 risk. This
effort will address certain areas, including the most reasonably likely
worst-case scenarios and delays in completion in KU's remediation plans,
failure or incomplete remediation results and failure of key third parties to
be Year 2000 compliant. Contingency plans will include provisions for extra
staffing, back-up communications, review of unit dispatch and load shedding
procedures, carrying of additional energy reserves and manual energy
accounting procedures. Completion of contingency plan formation is scheduled
for June 1999.
Forward Looking Statements
The foregoing discussion regarding the timing, effectiveness, implementation,
and cost of KU's Year 2000 efforts, contains forward-looking statements,
which are based on management's best estimates and assumptions. These
forward-looking statements involve inherent risks and uncertainties, and
actual results could differ materially from those contemplated by such
statements. Factors that might cause material differences include, but are
not limited to, the availability of key Year 2000 personnel, KU's ability to
locate and correct all relevant computer codes, the readiness of third
parties, and KU's ability to respond to unforeseen Year 2000 complications
and other factors described from time to time in KU's reports to the
Securities and Exchange Commission, including Exhibit 99.01 to LG&E Energy
Corp.'s report on Form 8-K filed October 21, 1998. Such material differences
could result in, among other things, business disruption, operational
problems, financial loss, legal liability and similar risks.
Rates and Regulation
KU is subject to the jurisdiction of the Kentucky Commission in virtually all
matters related to electric 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). KU is also
subject to the jurisdiction of the Virginia Commission and FERC. Given KU's
competitive position in the market and the status of regulation in the states
of Kentucky and Virginia, KU has no plans or intentions to discontinue its
application of SFAS No. 71. See Note 3 of KU's Notes to Financial Statements
under Item 8.
In August 1994, KU implemented an environmental cost recovery (ECR) surcharge
to recover certain environmental compliance costs. Such costs include
compliance with the 1990 Clean Air Act, as amended, as well as other
environmental regulations, including those applicable to coal combustion
wastes and related by-products. The ECR mechanism was authorized by state
statute in 1992 and was first approved by the Kentucky Commission in a KU
case in July 1994.
The Commission's order approving the surcharge in the KU case and the
constitutionality of the surcharge was challenged by certain intervenors,
including the Attorney General of Kentucky, in Franklin Circuit Court.
Decisions of the Circuit Court and the Kentucky Court of Appeals in July 1995
and December 1997, respectively, have upheld the constitutionality of the ECR
statute but differed on a claim of retroactive recovery of certain amounts.
The Commission ordered that certain surcharge revenues collected by KU be
subject to refund pending final determination of all appeals.
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KU (cont.):
On December 19, 1998, the Kentucky Supreme Court rendered an opinion
upholding the constitutionality of the surcharge statute. The decision,
however, reversed the ruling of the Court of Appeals on the retroactivity
claim, thereby denying recovery of costs associated with pre-1993
environmental projects. The court remanded the case to the Commission to
determine the proper adjustments to refund amounts collected for such
pre-1993 environmental projects. The parties to the proceeding have notified
the Commission that they have reached agreement as to the terms, proper
adjustments and forward application of the ECR. The settlement agreement is
subject to Commission approval. KU recorded a provision for rate refund of
$21.5 million in December 1998. See Rates and Regulation in KU's Management's
Discussion and Analysis of Results of Operations and Financial Condition
under Item 7 for a further discussion.
In October 1998, LG&E and KU filed separate but parallel applications with
the Commission for approval of a new method of determining electric rates
that provides financial incentives for LG&E and KU to further reduce
customers' rates. The filing was made pursuant to the September 1997
Commission order approving the merger of LG&E Energy and KU Energy, wherein
the Commission directed LG&E and KU to indicate whether they desired to
remain under traditional rate of return regulation or commence
non-traditional regulation. The new ratemaking method, known as
performance-based ratemaking (PBR), would include financial incentives for
LG&E and KU to reduce fuel costs and increase generating efficiency, and to
share any resulting savings with customers. Additionally, the PBR provides
financial penalties and rewards to assure continued high quality service and
reliability.
The PBR plan proposed by LG&E and KU consists of five components:
The utilities' fuel adjustment clause mechanism will be withdrawn and
replaced with a cap that limits recovery of actual changes in fuel cost to
changes in a fuel price index for a five-state region. If the utilities
outperform the index, benefits will be shared equally between shareholders
and customers. If the utilities' fuel costs exceed the index, the difference
will be absorbed by the LG&E Energy's shareholders.
Customers will continue to receive the benefits from the post-merger joint
dispatch of power from LG&E's and KU's generating plants.
Power plant performance will be measured against the best performance
achieved between 1991 and 1997. If the performance exceeds this level,
customers will share equally with LG&E Energy's shareholders in up to $10
million annually of benefits from this performance at each of LG&E and KU.
The utilities will be encouraged to maintain and improve service quality,
reliability, customer satisfaction and safety, which will be measured
against six objective benchmarks. The plan provides for annual rewards or
penalties to LG&E Energy of up to $5 million per year at each of LG&E and
KU.
The plan provides the utilities with greater flexibility to customize rates
and services to meet customer needs. Services will continue to be priced
above marginal cost and customers will continue to have the option to elect
standard tariff service.
These proposals are subject to approval by the Commission. Approval
proceedings commenced in October 1998 and a final decision may occur in 1999.
Several intervenors are participating in the case. Some have requested that
the Commission reduce base rates before implementing PBR.
In December 1997, the Kentucky Commission opened Administrative Case No. 369
to consider Commission policy regarding cost allocations, affiliate
transactions and codes of conduct governing the relationship between
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KU (cont.):
utilities and their non-utility operations and affiliates. The Commission
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-utility operations; and whether a code of conduct should be
established to assure that non-utility segments of the holding company are
not engaged in practices which result in unfair competition caused by cost
shifting from the non-utility affiliate to the utility. In September 1998,
the Commission issued draft code of conduct and cost allocation guidelines.
In January 1999, KU, as well as all parties to the proceeding, filed comments
on the Commission draft proposals. Initial hearings are scheduled for the
first quarter of 1999. Management does not expect the ultimate resolution of
this matter to have a material adverse effect on KU's financial position or
results of operations.
As of February 12, 1999, the Kentucky Commission ordered KU's affiliate
utility, LG&E, to refund FAC charges to retail electric customers after a
review of LG&E's FAC from November 1994 through April 1998. The Kentucky
Commission subsequently on March 11, 1999, denied LG&E's Petition for
Rehearing for the period November 1994 through October 1996, but granted
rehearing for the period November 1996 through April 1998 on the same issue.
KU has not received an order from the Kentucky Commission but estimates that
it may be required to refund to its retail electric customers approximately
$3.5 million in FAC charges for the period November 1994 through October 1998.
On March 8, 1999, the Kentucky Industrial Utility Customers filed a Complaint
with the Kentucky Commission alleging that KU's electric rates are excessive
and should be reduced by an amount between $42 and $56 million, and that the
Kentucky Commission establish a proceeding to reduce KU's rates. KU has asked
the Kentucky Commission to dismiss the Complaint.
KU is not able to predict the ultimate outcome of these proceedings, however,
should the Commission mandate significant rate reductions at KU, through the
PBR proposal or otherwise, such actions could have a material effect on KU's
financial condition and results of operations.
Environmental Matters
The Clean Air Act Amendments of 1990 (the Act) imposed stringent new sulfur
dioxide (SO2) emission limits. KU met the Phase I requirements of the Act
primarily through the installation of a scrubber on Unit 1 of the Ghent
Generating Station. KU's current strategy for Phase II is to use accumulated
emissions allowances to delay additional capital expenditures and may also
include fuel switching or the installation of additional scrubbers. KU met
the nitrogen oxide (NOx) emission reduction requirements of the Act through
installation of low-NOx burner systems. KU's compliance plans are subject to
many factors including developments in the emission allowance and fuel
markets, future regulatory and legislative initiatives, and advances in clean
air control technology. KU will continue to monitor these developments to
ensure that its environmental obligations are met in the most efficient and
cost-effective manner.
In September 1998, the U.S. Environmental Protection Agency (USEPA) announced
its final regulation requiring significant additional reductions in NOx
emissions to mitigate alleged ozone transport to the Northeast. While each
state is free to allocate its assigned NOx reductions among various emissions
sectors as it deems appropriate, the regulation may ultimately require
utilities to reduce their NOx emissions to 0.15 lb./mmBtu (million British
thermal units) -an 85% reduction from 1990 levels. Under the regulation, each
state must incorporate the additional NOx reductions in its State
Implementation Plan (SIP) by September 1999 and affected sources must install
control measures by May 2003, unless granted extensions. Several states,
various labor and industry groups, and individual companies have appealed the
final regulation to the U.S. Court of Appeals for the D.C. Circuit.
Management is currently unable to determine the outcome or exact impact of
this
81
KU (cont.):
matter until such time as the states identify specific emissions reductions
in their SIP and the courts rule on the various legal challenges to the final
rule. However, if the 0.15 lb. target is ultimately imposed KU will be
required to incur significant capital expenditures and increased operation
and maintenance costs for additional controls. Subject to further study and
analysis, KU estimates that it may incur capital costs in the range of $100
million to $200 million. These costs would generally be incurred beginning in
the year 2000.
KU believes its costs for these matters to be comparable to those of
similarly situated utilities with like generation assets. KU anticipates that
such capital and operating costs are the type of costs that are eligible for
cost recovery from customers under its environmental surcharge mechanism and
believes that 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. See Note 11 of KU's Notes to Financial Statements
under Item 8 for a complete discussion of KU's environmental issues.
In July, 1997, USEPA issued revised National Ambient Air Quality Standards
(NAAQS) for ozone and particulate matter. KU is monitoring USEPA's
implementation of the revised standards. Until USEPA completes additional
implementation steps, including monitoring and nonattainment demonstrations,
management is unable to determine the precise impact of the revised standards.
FUTURE OUTLOOK
Competition and Customer Choice
LG&E Energy 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, LG&E Energy has taken
many steps to prepare for the expected increase in competition in its
regulated and non-utility energy services businesses, including support for
performance-based ratemaking structures, aggressive cost reduction
activities; strategic acquisitions, dispositions, 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. LG&E Energy continues to
be active in the national debate surrounding the restructuring of the energy
industry and the move toward a competitive, market-based environment. LG&E
Energy 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 has previously advocated the implementation of this transition by
January 1, 2001, and now recommends that federal legislation be adopted
specifying a date certain and appropriate transition regulations implementing
deregulation.
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. During 1998, the
Kentucky Commission and a task force of the Kentucky General Assembly have
each initiated proceedings, including meetings with representatives of
utilities, consumers, state agencies, and other groups in Kentucky, to
discuss the possible structure and effects of energy industry restructuring
in Kentucky. The purpose of the task force is to make recommendations to the
Kentucky General Assembly for possible legislative action during its 2000
session.
However, at the time of this report, neither the Kentucky General Assembly
nor the Kentucky Commission has adopted or approved a 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 KU, which may be significant, cannot be predicted currently.
82
KU (cont.):
ITEM 7A. Quantitative and Qualitative Disclosure About Market Risk.
See Management's Discussion and Analysis of Results of Operations and
Financial Condition, Market Risks, under Item 7.
83
ITEM 8. Financial Statements and Supplementary Data.
LG&E Energy Corp. and Subsidiaries
Consolidated Statements of Income
(Thousands of $ Except Per Share Data)
Years Ended December 31
1998 1997 1996
---- ---- ----
REVENUES:
Electric utility........................... $1,464,824 $1,331,569 $1,318,846
Gas utility................................ 191,545 231,011 214,419
International and non-utility.............. 346,044 162,475 27,195
---------- ---------- -----------
Total revenues.......................... 2,002,413 1,725,055 1,560,460
Provision for rate refund (Note 5)......... (26,000) - -
---------- ---------- -----------
Net revenues (Note 1)................... 1,976,413 1,725,055 1,560,460
---------- ---------- -----------
OPERATING EXPENSES:
Operation and maintenance:
Fuel and power purchased................... 640,438 442,949 440,570
Gas supply expenses........................ 207,041 229,033 140,482
Utility operation and maintenance.......... 432,763 415,882 416,597
International and non-utility operation
and maintenance.......................... 123,267 54,724 31,101
Depreciation and amortization.................. 197,417 186,549 171,399
Merger costs to achieve and
non-recurring charges (Notes 2 and 10)..... 65,318 - 5,493
---------- ---------- -----------
Total operating expenses................ 1,666,244 1,329,137 1,205,642
---------- ---------- ----------
Equity in earnings of unconsolidated
ventures (Note 8)............................ 73,798 22,937 19,727
---------- ---------- -----------
OPERATING INCOME............................... 383,967 418,855 374,545
Other income and (deductions) (Note 14)........ 7,451 20,970 11,575
Interest charges and preferred dividends....... 108,871 104,427 94,412
Minority interest.............................. 10,453 9,035 -
---------- ---------- -----------
Income from continuing operations, before
income taxes................................. 272,094 326,363 291,708
Income taxes (Note 13)......................... 111,823 119,323 101,322
---------- ---------- -----------
Income from continuing operations.............. 160,271 207,040 190,386
Loss from discontinued operations,
net of income tax (benefit) expense
of $(14,907), $(15,116) and $2,371
(Notes 1 and 3).............................. (23,599) (24,044) (4,434)
Loss on disposal of discontinued operations,
net of income tax benefit of $125,000
(Note 3) .................................... (225,000) - -
---------- ---------- -----------
Income (loss) before cumulative effect of
change in accounting principle............... (88,328) 182,996 185,952
Cumulative effect of change in accounting
for start-up costs, net of income tax
benefit of $5,061 (Note 1)................... (7,162) - -
---------- ---------- -----------
NET INCOME (LOSS).............................. $ (95,490) $ 182,996 $ 185,952
---------- ---------- -----------
---------- ---------- -----------
The accompanying notes are an integral part of these financial statements.
84
LG&E Energy Corp. and Subsidiaries
Consolidated Statements of Income (cont.)
(Thousands of $ Except Per Share Data)
Years Ended December 31
1998 1997 1996
---- ---- ----
Average common shares outstanding........................... 129,679 129,627 129,450
Earnings (loss) per share of common stock - basic:
Continuing operations....................................... $1.24 $1.60 $1.47
Loss from discontinued operations........................... (.18) (.19) (.03)
Loss on disposal of discontinued operations................. (1.74) - -
Cumulative effect of accounting change...................... (.06) - -
------- -------- --------
Total ..................................................... $ (.74) $1.41 $1.44
------- -------- --------
------- -------- --------
Earnings (loss) per share of common stock - diluted:
Continuing operations....................................... $1.23 $1.60 $1.47
Loss from discontinued operations........................... (.17) (.19) (.03)
Loss on disposal of discontinued operations................. (1.73) - -
Cumulative effect of accounting change...................... (.06) - -
------- -------- ---------
Total ..................................................... $ (.73) $1.41 $1.44
------- -------- ---------
------- -------- ---------
Consolidated Statements of Comprehensive Income
(Thousands of $)
Years Ended December 31
1998 1997 1996
---- ---- ----
Net income (loss)............................................ $(95,490) $182,996 $185,952
Unrealized holding gains (losses) on available-for-sale
securities arising during the period....................... (168) (567) 196
Reclassification adjustment for realized and losses on
available-for-sale securities included in net income..... 123 337 981
------- -------- ---------
Other comprehensive income (loss) before tax................. (45) (230) 1,177
Income tax expense (benefit) related to items of other
comprehensive income..................................... 5 (293) 450
------- -------- ---------
Comprehensive income (loss).................................. $(95,540) $183,059 $186,679
------- -------- ---------
------- -------- ---------
Consolidated Statements of Retained Earnings
(Thousands of $)
Years Ended December 31
1998 1997 1996
---- ---- ----
Balance January 1........................................... $722,584 $683,962 $637,996
Add net income (loss)....................................... (95,490) 182,996 185,952
Deduct: Cash dividends declared on common stock
($1.240 per share in 1998, $1.113 per share
in 1997, and $1.081 per share in 1996)............. (160,815) (144,366) (139,986)
Preferred stock redemption expense and other....... - (8) -
--------- --------- ---------
Balance December 31......................................... $466,279 $722,584 $683,962
--------- --------- ---------
--------- --------- ---------
The accompanying notes are an integral part of these financial statements.
85
LG&E Energy Corp. and Subsidiaries
Consolidated Balance Sheets
(Thousands of $)
December 31
1998 1997
---- ----
ASSETS:
Current assets:
Cash and temporary cash investments............................... $ 108,723 $ 111,003
Marketable securities (Note 11)................................... 20,862 22,300
Accounts receivable - less reserve of $10,532 in 1998 and
$10,187 in 1997.......................................... 285,794 242,942
Materials and supplies - primarily at average cost:
Fuel (predominantly coal)...................................... 78,855 45,450
Gas stored underground......................................... 34,144 42,104
Other.......................................................... 72,457 55,514
Net assets of discontinued operations (Notes 1 and 3)............. 143,651 222,784
Prepayments and other............................................. 37,784 9,304
------------ ------------
Total current assets........................................... 782,270 751,401
------------ ------------
Utility plant:
At original cost (Note 1)......................................... 5,581,667 5,390,868
Less: reserve for depreciation................................... 2,352,306 2,201,124
------------ ------------
Net utility plant.............................................. 3,229,361 3,189,744
------------ ------------
Other property and investments - less reserve:
Investments in unconsolidated ventures (Note 8)................... 167,877 177,006
Non-utility property and plant, net (Notes 1 and 2)............... 285,899 248,119
Other ........................................................... 117,321 53,534
------------ ------------
Total other property and investments........................... 571,097 478,659
------------ ------------
Deferred debits and other assets:
Regulatory assets (Note 5)........................................ 65,871 39,672
Goodwill, net..................................................... 13,273 13,675
Other ........................................................... 111,396 89,793
----------- -------------
Total deferred debits and other assets......................... 190,540 143,140
------------ ------------
Total assets............................................... $4,773,268 $4,562,944
------------ ------------
------------ ------------
CAPITAL AND LIABILITIES:
Current liabilities:
Long-term debt due within one year................................ $ - $ 20,021
Notes payable (Note 17)........................................... 365,135 393,784
Accounts payable.................................................. 237,820 134,714
Taxes and interest accrued........................................ 104,656 45,011
Common dividends declared......................................... 39,876 19,792
Provision for rate refunds........................................ 34,761 13,248
Customer deposits................................................. 17,404 15,795
Other ........................................................... 47,002 42,182
------------ ------------
Total current liabilities...................................... 846,654 684,547
------------ ------------
Long-term debt (Note 16).............................................. 1,510,775 1,210,690
Deferred credits and other liabilities:
Accumulated deferred income taxes (Notes 1 and 13)................ 520,721 548,477
Investment tax credit, in process of amortization................. 93,844 101,931
Accumulated provision for pensions and related benefits........... 120,233 80,217
Regulatory liability (Note 5)..................................... 109,411 117,079
Other ........................................................... 86,047 76,471
------------- ------------
Total deferred credits and other liabilities................... 930,256 924,175
------------- ------------
Minority interest (Note 2)............................................ 107,815 105,985
Cumulative preferred stock............................................ 136,530 138,353
Commitments and contingencies (Note 18)
Common equity........................................................ 1,241,238 1,499,194
------------- ------------
Total capital and liabilities..................................... $4,773,268 $4,562,944
------------- ------------
------------- ------------
The accompanying notes are an integral part of these financial statements.
86
LG&E Energy Corp. and Subsidiaries
Consolidated Statements of Cash Flows
(Thousands of $)
Years Ended December 31
1998 1997 1996
---- ---- ----
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)................................................. $ (95,490) $ 182,996 $ 185,952
Items not requiring cash currently:
Depreciation and amortization.................................. 197,417 186,549 171,399
Deferred income taxes - net.................................... (30,860) 10,316 55,589
Investment tax credit - net.................................... (8,087) (8,276) (8,010)
Undistributed earnings of unconsolidated ventures.............. (18,833) (2,326) (2,102)
Loss from discontinued operations (Notes 1 and 3).............. 23,599 24,044 4,434
Loss on disposal of discontinued
operations (Note 3)........................................ 225,000 - -
Cumulative effect of change in accounting
principle (Note 1)......................................... 7,162 - -
Other.......................................................... 21,838 14,213 10,147
Change in certain net current assets:
Accounts receivable............................................ (42,852) (22,771) (3,976)
Materials and supplies......................................... (42,388) (7,514) (1,468)
Net assets of discontinued operations (Notes 1 and 3).......... (145,867) (10,946) 13,539
Provision for rate refunds..................................... 21,513 (4,263) (12,289)
Accounts payable............................................... 103,106 1,826 (11,396)
Accrued taxes and interest..................................... 59,645 5,859 (5,009)
Customer deposits.............................................. 1,609 2,392 2,867
Prepayments and other.......................................... (23,660) (411) 4,022
Other............................................................. (41,130) (52,942) (35,313)
--------- ----------- -----------
Net cash flows from operating activities....................... 211,722 318,746 368,386
--------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchases of securities........................................... (18,421) (21,526) (20,625)
Proceeds from sales of securities................................. 19,995 5,030 44,609
Construction expenditures......................................... (342,214) (210,131) (215,954)
Investment in subsidiaries net of cash and
temporary cash investments acquired (Note 2)................... - (124,593) -
Investments in unconsolidated ventures (Note 8)................... (1,010) (5,791) (1,490)
Proceeds from sale of investment in affiliate..................... 16,000 - -
--------- ---------- ----------
Net cash flows from investing activities....................... (325,650) (357,011) (193,460)
--------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of medium-term notes..................................... 300,000 - -
Issuance of bonds................................................. - 69,776 89,190
Retirement of bonds............................................... (20,042) (71,714) (103,205)
Short-term borrowings............................................. 6,751,089 3,871,905 2,784,700
Repayment of short-term borrowings................................ (6,776,845) (3,690,321) (2,801,100)
Issuance of preferred stock....................................... - 3,025 -
Redemption of preferred stock..................................... (1,823) - -
Issuance of common stock.......................................... - 3,781 2,293
Payment of common dividends....................................... (140,731) (143,647) (139,282)
--------- ----------- ----------
Net cash flows from financing activities....................... 111,648 42,805 (167,404)
--------- ----------- ----------
Change in cash and temporary cash investments....................... (2,280) 4,540 7,522
Beginning cash and temporary cash investments....................... 111,003 106,463 98,941
---------- ---------- ----------
Ending cash and temporary cash investments.......................... $ 108,723 $ 111,003 $ 106,463
--------- ---------- ----------
--------- ---------- ----------
Supplemental disclosures of cash flow information: Cash paid
during the year for:
Income taxes................................................. $ 55,513 $ 82,662 $ 67,780
Interest on borrowed money................................... 96,356 93,451 86,045
The accompanying notes are an integral part of these financial statements.
87
LG&E Energy Corp. and Subsidiaries
Consolidated Statements of Capitalization
(Thousands of $)
December 31
1998 1997
---- ----
COMMON EQUITY:
Common stock, without par value -
Authorized 300,000,000 shares, outstanding 129,677,030
shares in 1998 and 129,682,889 shares in 1997 (Note 15)...................... $ 778,273 $ 778,273
Common stock expense............................................................ (3,481) (1,880)
Unrealized gain on marketable securities, net of income
taxes of $94 in 1998 and $89 in 1997 (Note 11)............................... 167 217
Retained earnings............................................................... 466,279 722,584
------------ ------------
Total common equity.......................................................... 1,241,238 1,499,194
------------ ------------
PREFERRED STOCK (Note 15):
Shares Current
Outstanding Redemption Price
----------- ----------------
Cumulative and redeemable on 30 days notice by
Louisville Gas and Electric Company:
$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................................. 250,000 105.875 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 Not redeemable 20,000 20,000
------------ -----------
Total KU preferred stock..................................................... 40,000 40,000
------------ -----------
$10 nominal value, 102,089 and 302,364 shares authorized and outstanding,
(net of shares owned by affiliates) for 1998 and 1997, respectively,
variable rate and redeemable by Inversora de Gas del Centro.................. 1,202 3,025
------------- ------------
Total preferred stock........................................................... 136,530 138,353
------------- ------------
LONG-TERM DEBT (Note 16):
Louisville Gas and Electric Company:
First mortgage bonds -
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:
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............................................ 506,800 506,800
------------- -------------
The accompanying notes are an integral part of these financial statements.
88
LG&E Energy Corp. and Subsidiaries
Consolidated Statements of Capitalization (cont.)
(Thousands of $)
December 31
1998 1997
---- ----
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 35,000
Trimble County Series due November 1, 2027, variable......................... 35,000 35,000
------------- ------------
Total unsecured pollution control bonds.................................. 120,000 120,000
------------- ------------
Total LG&E long-term debt............................................. 626,800 626,800
------------ ------------
Kentucky Utilities Company:
First mortgage bonds:
Series Q, due June 15, 2000, 5.95%........................................... 61,500 61,500
Series Q, due June 15, 2003, 6.32%........................................... 62,000 62,000
Series S, due January 15, 2006, 5.99%........................................ 36,000 36,000
Series P, due May 15, 2007, 7.92%............................................ 53,000 53,000
Series R, due June 1, 2025, 7.55%............................................ 50,000 50,000
Series P, due May 15, 2027, 8.55%............................................ 33,000 33,000
Pollution Control Series:
Series 7, due May 1, 2010, 7 3/8%........................................ 4,000 4,000
Series 8, due September 15, 2016, 7.45%.................................. 96,000 96,000
Series 1B, due February 1, 2018, 6 1/4%.................................. 20,930 20,930
Series 2B, due February 1, 2018, 6 1/4%.................................. 2,400 2,400
Series 3B, due February 1, 2018, 6 1/4%.................................. 7,200 7,200
Series 4B, due February 1, 2018, 6 1/4%.................................. 7,400 7,400
Series 7, due May 1, 2020, 7.60%......................................... 8,900 8,900
Series 9, due December 1, 2023, 5 3/4%................................... 50,000 50,000
Series 10, due November 1, 2024, variable................................ 54,000 54,000
------------ -----------
Total first mortgage bonds............................................ 546,330 546,330
Other ................................................................... - 21
------------ -----------
Total KU long-term debt...................................................... 546,330 546,351
------------ -----------
LG&E Capital Corp.:
Argentine negotiable obligations, due August 2001, 10 1/2%...................... 37,645 37,539
Medium term notes, due January 15, 2008, 6.46% (Note 16)........................ 150,000 -
Medium term notes, due November 1, 2011, 5.75% (Note 16)........................ 150,000 -
------------ -----------
Total Capital Corp. long-term debt........................................... 337,645 37,539
------------ -----------
Total long-term debt............................................................ 1,510,775 1,210,690
------------ -----------
Total capitalization............................................................ $ 2,888,543 $ 2,848,237
------------ -----------
------------ -----------
The accompanying notes are an integral part of these financial statements.
89
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 energy trading
and sales business and announced its plans to sell its natural gas gathering
and processing business. As a result of this decision, the Company recorded
an after-tax loss on disposal of discontinued operations of $225 million in
the second quarter of 1998. See Note 3, Discontinued Operations.
The consolidated financial statements include the accounts of LG&E Energy, LG&E,
LG&E Capital Corp. (Capital Corp.), KU and their respective wholly owned
subsidiaries, collectively referred to herein as the Company. KU and KU Capital
Corporation (KU Capital) were subsidiaries of KU Energy before the merger. On
September 5, 1997, LG&E Energy 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. In July 1998, KU Capital
was merged into Capital Corp. with the latter as the surviving corporation.
LG&E Energy's regulated operations are conducted by LG&E and KU. Its non-utility
operations are conducted by Capital Corp., which has various subsidiaries
referred to in these financial statements, including LG&E Power Inc. (LPI), LG&E
Energy Marketing (LEM), LG&E International Inc. (LII) and Western Kentucky
Energy Corp. (with its affiliates, WKE).
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 utility natural gas inventories are
included in gas stored underground in the balance sheets as of December 31, 1998
and 1997. Utility gas inventories were $33 million and $41 million at December
31, 1998 and 1997, respectively. LG&E accounts for gas inventories using the
average-cost method. Non-utility gas inventories are included in net assets or
liabilities of discontinued operations.
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. Neither LG&E
nor KU has recorded any significant
90
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 1998 and 1997 were 3.4% and for 1996 were 3.3%. The
amounts provided for KU were 3.5% in 1998, 1997 and 1996.
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.
In connection with the Company's marketing of power from owned or controlled
generation assets, exchange traded futures are used to hedge its exposure to
price risk. The Company also uses financial instruments associated with its
discontinued merchant energy trading and sales business, the financial impact of
which is included in discontinued operations. See Note 3, 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 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, 63,149,394 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 (Kentucky
Commission or Commission) in 1995, LG&E implemented a demand-side management
program, including a
91
"decoupling mechanism" which allowed LG&E to recover a predetermined level of
revenue on electric and gas residential sales. In 1998, the decoupling
mechanism was suspended. See Note 5, Utility Rates and Regulatory Matters.
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. LG&E implemented a Commission approved experimental
performance-based ratemaking mechanism related to gas procurement and off-system
gas sales activity. See Note 5, Utility Rates and Regulatory Matters.
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. During 1998, the Company adopted the
following accounting pronouncements:
Statements of Financial Accounting Standards No. 132, Employers' Disclosures
about Pensions and Other Postretirement Benefits (SFAS No. 132), No. 131,
Disclosures about Segments of an Enterprise and Related Information (SFAS No.
131) and No. 130, Reporting Comprehensive Income (SFAS No. 130). Pursuant to
SFAS No. 132, the Company has disclosed additional information on changes in
benefit obligations and fair values of plan assets and eliminated certain
disclosures that are no longer relevant. This standard does not change the
measurement or financial statement recognition of the plans (see Note 12,
Pension Plans and Retirement Benefits). Under SFAS No. 131, the Company has
provided information about its various business segments that is intended to
allow readers to view certain financial information as if "through the eyes
of management" (see Note 20, Segments of Business and Related Information
Disclosures). Pursuant to SFAS No. 130, the Company has presented
information in the Consolidated Statements of Comprehensive Income that
measures changes in equity that are not required to be recorded as a
component of net income. These standards had no impact on the calculation of
net income or earnings per share presented in the Consolidated Statements of
Income.
Statement of Position Nos. 98-5, Reporting on the Costs of Start-Up Activities
(SOP 98-5) and 98-1, Accounting for the Costs of Computer Software Developed or
Obtained for Internal Use (SOP 98-1). SOP 98-5, adopted as of January 1, 1998,
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 as a cumulative effect of a change in accounting
principle. The Company had previously capitalized start-up costs related to its
investments in various unconsolidated ventures and other non-utility businesses.
The cumulative effect of adoption resulted in a $7.2 million after-tax charge.
The effect of this change on 1998 income before cumulative effect of changes in
accounting principles was not significant. SOP 98-1, adopted as of January 1,
1998, clarifies the criteria for capital or expense treatment of costs incurred
by an enterprise to develop or obtain computer software to be used in its
internal operations. The statement does not change treatment of costs incurred
in connection with correcting computer programs to properly process the
millennium change to the Year 2000, which must be expensed as incurred. Adoption
of SOP 98-1 did not have a material effect on the Company's financial
statements. The following accounting pronouncements have been issued but are not
yet effective:
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
92
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 use 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. The
effect of this statement will be recorded in cumulative effect of change in
accounting when adopted.
Emerging Issues Task Force Issue No. 98-10, Accounting for Energy Trading and
Risk Management Activities (EITF No. 98-10). This pronouncement is effective for
fiscal years beginning after December 15, 1998. The task force concluded that
energy trading contracts should be recorded at mark to market on the balance
sheet, with the gains and losses shown net in the income statement. EITF No.
98-10 more broadly defines what represents energy trading to include economic
activities related to physical assets which were not previously marked to market
by established industry practice. The effects of adopting EITF No. 98-10, if
applicable, will be reported as a cumulative effect of a change in accounting
principle with no prior period restatement. The Company does not expect the
adoption of EITF No. 98-10 to have a material adverse impact on its consolidated
operations and financial position.
NOTE 2 - MERGERS AND ACQUISITIONS
KU ENERGY CORPORATION. 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) have continued to maintain their
separate corporate identities and 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 savings of $103.9 million were recorded in the second quarter of
1998, $38.6 million of which were initially deferred and are being amortized
over a five-year period pursuant to regulatory orders. Primary components of the
merger costs were separation benefits, relocation costs, and transaction fees,
the majority of which were paid by December 31, 1998. 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 existing base rates and proposed reductions
in their retail customers' bills in amounts based on one-half of the savings,
net of the deferred and amortized amount, over a five-year period. The preferred
stock and debt securities of the operating utility subsidiaries were not
affected by the merger. The non-utility subsidiaries of KU Energy have become
subsidiaries of Capital Corp.
Under the terms of the Agreement and Plan of Merger dated May 20, 1997 (the
Merger Agreement), each outstanding share of the common stock, without par
value, of KU Energy (KU Energy Common Stock) 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
Energy common stock outstanding. Based on such capitalization, immediately
following the merger, 51.3% of the outstanding LG&E Energy common stock was
owned by the shareholders of LG&E Energy prior to the merger and 48.7% was owned
by former KU Energy shareholders.
Regulatory and administrative approvals were obtained from the Federal Energy
Regulatory Commission (FERC), the Federal Trade Commission, the Securities and
Exchange Commission, the Virginia State Corporation Commission and the
stockholders of LG&E Energy and KU Energy prior to the effective date of the
merger. LG&E Energy, as the parent of LG&E and KU, continues to be an exempt
holding company under
93
the Public Utility Holding Company Act of 1935. Management has accounted for
the merger as a pooling of interests and as a tax-free reorganization under
the Internal Revenue Code.
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
$38.6 million or 50% of the originally estimated costs to achieve such savings,
be applied to reduce customer rates through a surcredit on customers' bills and
the remaining 50% be retained by the companies. The Commission approved the
surcredit and allocated the customer savings 53% to KU and 47% to LG&E. The
surcredit will be about 2% of customer bills over the next five years and 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 are passed to Kentucky customers through the companies' fuel
adjustment clauses.
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.
The fair values of the net assets acquired follow (in thousands of $):
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
--------
--------
Centro's revenues, cost of revenues and operating expenses since the date of
acquisition are classified as components of international and non-utility in
these Statements of Income. The earnings of Cuyana are included in Equity in
Earnings of Unconsolidated Ventures. The Company includes Centro's property and
equipment in Non-utility property and plant, net, in its balance sheet, and it
includes its investment in Cuyana in Investments in Unconsolidated Ventures.
Portions of Centro not owned directly or indirectly by the Company are reported
as minority interests in the financial statements.
Liabilities assumed in the purchase included negotiable obligations issued by
Centro with a face amount of $38 million. The obligations mature in August 2001,
pay interest at 10.5% of face value and are classified as long-term debt.
NOTE 3 - DISCONTINUED OPERATIONS
Effective June 30, 1998, the Company discontinued its merchant energy trading
and sales business. This business consisted primarily of a portfolio of energy
marketing contracts entered into in 1996 and early 1997, nationwide deal
origination and some level of speculative trading activities, which were not
directly supported by the Company's physical assets. The Company's decision to
discontinue these operations was primarily based on the impact that volatility
and rising prices in the power market had on its portfolio of energy marketing
contracts. Exiting the merchant energy trading and sales business enables the
Company to focus on optimizing the value of physical assets it owns or controls,
and to reduce the earnings impact on continuing operations of
94
extreme market volatility in its portfolio of energy marketing contracts. The
Company is in the process of settling commitments that obligate it to buy and
sell natural gas and electric power. It also plans to sell its natural gas
gathering and processing business. If the Company is unable to dispose of
these commitments or assets it will continue to meet its obligations under
the contracts. The Company, however, has maintained sufficient market
knowledge, risk management skills, technical systems and experienced
personnel to maximize the value of power sales from physical assets it owns
or controls, including LG&E, KU and the Big Rivers Electric Corporation (Big
Rivers).
As a result of the Company's decision to discontinue its merchant energy 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 million in the second quarter of 1998. The loss
on disposal of discontinued operations results primarily from several
fixed-price energy marketing contracts entered into 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
merchant energy trading and sales operations and exit costs, including labor and
related benefits, severance and retention payments, and other general and
administrative expenses. Although the Company used what it believes to be
appropriate estimates for future energy prices among other factors to calculate
the net realizable value of discontinued operations, it also recognizes that
there are inherent limitations in models to accurately predict future events. As
a result, there is no guarantee that higher-than-anticipated future commodity
prices or load demands, lower-than-estimated asset sales prices or other factors
could not result in additional losses. The Company has been successful in
settling portions of its discontinued operations, but significant assets,
operations and obligations remain. As of January 27, 1999, the Company estimates
that a $1 change in electricity prices and a 10 cents change in natural gas
prices across all geographic areas and time periods could change the value of
the Company's remaining energy portfolio by approximately $8.8 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 January 27, 1999, the Company estimates that a 1% change
in the forecasted load demand could change the value of the Company's remaining
energy portfolio by $9.3 million. See Note 18, Commitments and Contingencies,
for a discussion of the OPC contract. See also Note 1, Summary of Significant
Accounting Policies.
Operating results for discontinued operations follow (in thousands of $):
1998 1997 1996
---- ---- ----
Revenues $ 3,865,020 $ 3,255,175 $ 2,740,691
Loss before taxes (173,423) (39,160) (2,063)
Loss from discontinued operations,
net of income taxes $ (113,273) $ (24,044) $ (4,434)
95
Net assets of discontinued operations at December 31 follow (in thousands of $):
1998 1997
---- ----
Cash and temporary cash investments $ 1,674 $ 15,089
Accounts receivable 78,200 353,162
Price risk management assets, net 98,885 164,581
Non-utility property and plant, net 163,510 176,032
Accounts payable and accruals (71,265) (344,265)
Price risk management liabilities, net (32,693) (154,910)
Goodwill and other assets and liabilities, net 24,721 13,095
--------- ----------
Net assets before accrued loss on disposal of dis-
continued operations 263,032 222,784
Accrued loss on disposal of discontinued operations,
net of income tax benefit of $74,297 119,381 -
--------- ----------
Net assets of discontinued operations $ 143,651 $ 222,784
--------- ----------
--------- ----------
ACCOUNTING TREATMENT. Effective January 1, 1996, the Company adopted the mark to
market method of accounting for most of its merchant energy trading and sales
activities. The Company has included these activities in Discontinued Operations
in the accompanying financial statements. Under mark to market accounting, all
electric power and natural gas contracts which qualify for such accounting
treatment, including both physical transactions and financial instruments, were
recorded at market value, net of future servicing costs and reserves, and were
recognized as price risk management assets and liabilities in the balance sheet.
To qualify for mark to market accounting treatment, merchant energy trading and
sales 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 were
recognized as merchant energy trading and sales revenues in the period of the
change.
Revenues and cost of revenues associated with merchant energy trading and sales
activities that did not qualify for mark to market accounting treatment were
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 merchant
energy trading and sales 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 entered 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 were
afforded hedge accounting treatment whereby gains and losses were deferred until
the gains or losses on the hedged items were recognized or the instrument was
terminated.
As a result of the Company's decision to discontinue its merchant energy trading
and sales activity, all transactions are recorded using discontinued operations
accounting. Most transactions previously recorded using the mark to market
method of accounting have now been settled. The effects of the previously
adopted mark to market method of accounting for the remaining unsettled
transactions are applied against the reserve for discontinued operations.
Total charges against the reserve through December 31, 1998 include $77.3
million for commitments prior to disposal, $51.2 million for transaction
settlements, $11.1 million for goodwill, and $16.7 million for other exit
96
costs. The reserve as of December 31, 1998, represents management's best
estimate of the loss from remaining discontinued operations until disposal
and the costs of disposing of these operations.
MARKET RISK. The primary market risk inherent in the Company's discontinued
operations relates to commodity price risk principally associated with
fluctuations in the supply and demand of electricity and natural gas. The
Company's price risk management strategy involved using various derivative
instruments to hedge the impact of market fluctuations in its energy-related
assets, liabilities and other contractual commitments. Derivative instruments
utilized as hedges include futures contracts; swap agreements, where settlement
is based on the difference between a fixed and index-based price;
exchange-traded options; over-the-counter options, which are settled in cash or
the physical delivery of the commodity; exchange-for-physical transactions, in
which payment for delivery of the underlying commodity is in the form of futures
contracts; and tolling arrangements. The changes in the market value of these
instruments correspond to the price changes in the underlying commodities.
The Company has reduced its price risk by settling contracts or entering into
back-to-back agreements with third parties to act on its behalf as the purchaser
or seller for specified transactions. For all other transactions, the Company is
actively attempting to mitigate its risk and no new overall positions are being
taken. The remaining net open positions on these transactions could result in
additional losses to the Company if prices do not move in the manner or
direction anticipated.
The Company has established trading policies and limits designed to minimize its
exposure to price risk and regularly revalues exposures 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. 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.
NOTIONAL AMOUNTS. As of December 31, 1998, the Company's discontinued operations
were under various contracts to buy and sell power and gas with net notional
amounts of 30.6 million MWh's of power and 22.7 million MMBTU's of natural gas
with a volumetric weighted-average period of approximately 45 and 16 months,
respectively. These notional amounts are based on estimated loads since various
commitments do not include specified firm volumes. The Company is also under
contract to buy or sell immaterial amounts of coal and SO2 allowances in support
of its power contracts. Notional amounts reflect the nominal volume of
transactions included in the Company's price risk management commitments, but do
not reflect actual amounts of cash, financial instruments, or quantities of the
underlying commodity which may ultimately be exchanged between the parties.
97
FAIR VALUES. The fair values of discontinued operations' price risk management
assets and liabilities recorded on a mark to market basis as of December 31,
1998 and 1997, and the average fair values during the year by commodity are set
forth below (in thousands of $):
Fair Value Average Fair Value
--------------------------- ----------------------------
Assets Liabilities Assets Liabilities
--------- ----------- --------- -----------
1998:
By Commodity:
-------------
Electricity $ 98,823 $ 31,950 $ 230,816 $ 194,233
Natural gas 62 - 69,972 61,701
Other - - 265 -
--------- --------- --------- ---------
Total 98,885 31,950 $ 301,053 $ 255,934
Reserves - 743 --------- ---------
--------- --------- --------- ---------
Net values $ 98,885 $ 32,693
--------- ---------
--------- ---------
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
--------- ---------
--------- ---------
The table above does not include the fair value of various transactions not
previously recorded using mark to market accounting since these transactions
commit the Company to the sale or purchase of electricity or natural gas without
specified firm volumes.
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. The increase in values from 1997 to 1998 results from
volatility and risk management actions taken in connection with discontinuing
the merchant energy trading and sales business.
If the Company is unable to dispose of its remaining commitments, it will
continue to meet its obligations through the terms of the contracts. The net
fair value of these commitments as of December 31, 1998 are currently estimated
to be approximately $24.6 million in 1999, $19.6 million to $36.6 million each
year in 2000 through 2004, and $5.4 million for later years.
CREDIT RISK. The Company's discontinued operations maintain policies intended to
minimize credit risk and revalue credit exposures daily to monitor compliance
with those policies. As of December 31, 1998, over 90% of the Company's price
risk management commitments were with counterparties rated BBB equivalent or
better. As of December 31, 1998, seven counterparties represented 86% of the
Company's price risk management commitments.
98
NOTE 4 - BIG RIVERS ELECTRIC CORPORATION LEASE
On July 15, 1998, the Company closed the transaction to lease the generating
assets of Big Rivers Electric Corporation (Big Rivers). Under the 25-year
operating lease, WKE is leasing and operating Big Rivers' three coal-fired
facilities. In addition, WKE operates and maintains the Station Two generating
facility of the City of Henderson (Henderson). The combined generating capacity
of these facilities amounts to approximately 1,700 megawatts, net of the
Henderson's capacity and energy needs from Station Two. WKE prepaid $55.9
million for its first two years of lease payments. Lease expense for 1998 was
$12.8 million. See Note 18, Commitments and Contingencies, for a further
discussion.
In related transactions, power is supplied to Big Rivers at contractual prices
over the term of the lease to meet the needs of four-member distribution
cooperatives and their retail customers, including major western Kentucky
aluminum smelters. Excess generating capacity is available to WKE to market
throughout the region. In connection with these transactions, WKE has undertaken
to bear certain of the future capital requirements of those generating assets,
certain defined environmental compliance costs and other obligations.
In July 1998, as part of the deal structure with Big Rivers, WKE agreed to
provide Big Rivers a $50 million note to help it emerge from bankruptcy. WKE
will provide $1.7 million per month for the first 12 months of the note,
beginning August 1998, and $2.5 million per month over the subsequent 12 months.
The note will be repaid over a three-year period, beginning August 2000, with
interest at 7.165%.
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 FERC, 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 $):
1998 1997
---- ----
Unamortized loss on bonds $ 26,302 $ 28,454
Merger costs 34,749 7,000
Manufactured gas sites 3,684 3,263
Other 1,136 955
---------- ----------
Total regulatory assets 65,871 39,672
Deferred income taxes - net (109,411) (117,079)
---------- ----------
Regulatory assets and liabilities - net $ (43,540) $ (77,407)
---------- ----------
---------- ----------
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.
ENVIRONMENTAL COST RECOVERY. Since May 1995 and August 1994, respectively, LG&E
and KU have implemented an environmental cost recovery (ECR) surcharge to
recover certain environmental compliance costs, including costs to comply with
the 1990 Clean Air Act, as amended, as well as other environmental
99
regulations, including those applicable to coal combustion wastes and related
by-products. The ECR mechanism was authorized by state statute in 1992 and
was first approved by the Kentucky Commission in KU's Case No. 93-465 in July
1994.
The Commission's order approving the surcharge in the KU case and the
constitutionality of the surcharge was challenged by certain intervenors,
including the Attorney General of Kentucky, in Franklin Circuit Court. Decisions
of the Circuit Court and the Kentucky Court of Appeals in July 1995 and December
1997, respectively, have upheld the constitutionality of the ECR statute but
differed on a claim of retroactive recovery of certain amounts. The Commission
ordered that certain surcharge revenues collected by LG&E and KU be subject to
refund pending final determination of all appeals.
On December 19, 1998 the Kentucky Supreme Court rendered an opinion upholding
the constitutionality of the surcharge statute. The decision, however, reversed
the ruling of the Court of Appeals on the retroactivity claim, thereby denying
recovery of costs associated with pre-1993 environmental projects through the
ECR. The court remanded the case to the Commission to determine the proper
adjustments to refund amounts collected for such pre-1993 environmental
projects. The parties to the proceeding have notified the Commission that they
have reached agreement as to the terms, refund amounts, refund procedure and
forward application of the ECR. The settlement agreement is subject to
Commission approval. The Company recorded a provision for rate refund of $26
million in December 1998.
OTHER RATE MATTERS. In January 1994, LG&E implemented a Commission-approved
demand side management (DSM) program that LG&E, the Jefferson County, Kentucky,
Attorney and representatives of several customer interest groups had filed with
the Commission. The program included 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 program (decoupling). In June 1998, LG&E and customer interest
groups requested an end to the decoupling rate mechanism. On June 1, 1998, LG&E
discontinued recording revenues from lost sales due to DSM. Accrued decoupling
revenues recorded for periods prior to June 1, 1998, will continue to be
collected through the DSM recovery mechanism. On September 23, 1998, the
Commission accepted LG&E's modified tariff reflecting this proposal effective as
of June 1, 1998.
Since October 1997, LG&E has implemented a Commission-approved, experimental
performance-based ratemaking mechanism related to gas procurement activities and
off-system gas sales only. During the three-year test period beginning October
1997, rate adjustments related to this mechanism will be determined for each
12-month period beginning November 1 and ending October 31. During the first
year of the mechanism ended October 31, 1998, LG&E recorded $3.6 million for its
share of reduced gas costs. The $3.6 million will be billed to customers through
the gas supply clause beginning February 1, 1999.
LG&E and KU employ a fuel adjustment clause (FAC) mechanism, which under
Kentucky law allows the companies to recover from customers, the actual fuel
costs associated with retail electric sales. As of February 12, 1999, LG&E
received orders from the Kentucky Commission requiring a refund to retail
electric customers of approximately $3.9 million resulting from reviews of the
FAC from November 1994 through April 1998. The orders changed the Company's
method of computing fuel costs associated with electric line losses on
off-system sales appropriate for recovery through the FAC. The orders require
these amounts to be refunded to customers during first quarter 1999.
The Kentucky Commission has not issued LG&E an order for the review period May
1998 through October 1998, nor have they issued orders pertaining to KU's FAC
for review periods after November 1994. However, following the methods set forth
in the LG&E orders, the Company estimates up to an additional $4.8 million could
be refundable to LG&E and KU retail electric customers for open review periods
through December
100
1998. Management intends to file a request for rehearing on the Kentucky
Commission's rulings. Management does not believe final resolution of these
proceedings will have a material adverse effect on the Company's financial
position or results of operations.
FUTURE RATE REGULATION. In October 1998, LG&E and KU filed separate but parallel
applications with the Commission for approval of a new method of determining
electric rates that provides financial incentives for LG&E and KU to further
reduce customers' rates. The filing was made pursuant to the September 1997
Commission order approving the merger of LG&E Energy and KU Energy, wherein the
Commission directed LG&E and KU to indicate whether they desired to remain under
traditional rate of return regulation or commence non-traditional regulation.
The new ratemaking method, known as performance-based ratemaking (PBR), would
include financial incentives for LG&E and KU to reduce fuel costs and increase
generating efficiency, and to share any resulting savings with customers.
Additionally, the PBR provides financial penalties and rewards to assure
continued high quality service and reliability.
The PBR plan proposed by LG&E and KU consists of five components:
The utilities' fuel adjustment clause mechanism will be withdrawn and
replaced with a cap that limits recovery of actual changes in fuel cost to
changes in a fuel price index for a five-state region. If the utility
outperform the index, benefits will be shared equally between shareholders
and customers. If the utility's fuel costs exceed the index, the difference
will be absorbed by the Company's shareholders.
Customers will continue to receive the benefits from the post-merger joint
dispatch of power from LG&E's and KU's generating plants.
Power plant performance will be measured against the best performance
achieved between 1991 and 1997. If the performance exceeds this level,
customers will share in up to $10 million annually of benefits from this
performance at each of LG&E and KU.
The utilities will be encouraged to maintain and improve service quality,
reliability, customer satisfaction and safety, which will be measured
against six objective benchmarks. The plan provides for annual rewards or
penalties to the Company of up to $5 million per year at each of LG&E and
KU.
The plan provides the utilities with greater flexibility to customize rates
and services to meet customer needs. Services will continue to be priced
above marginal cost and customers will continue to have the option to elect
standard tariff service.
These proposals are subject to approval by the Commission. Approval proceedings
commenced in October 1998 and a final decision likely will occur in 1999.
Several intervenors are participating in the case. Some have requested that the
Commission reduce base rates before implementing PBR. The Company is not able to
predict the ultimate outcome of these proceedings, however, should the
Commission mandate significant rate reductions at LG&E or KU, through the PBR
proposal or otherwise, such actions could have a material effect on the
Company's financial condition and results of operations.
KENTUCKY PSC ADMINISTRATIVE CASE FOR AFFILIATE TRANSACTIONS. In December 1997,
the Kentucky Commission opened Administrative Case No. 369 to consider
Commission policy regarding cost allocations, affiliate transactions and codes
of conduct governing the relationship between utilities and their non-utility
operations and affiliates. The Commission 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-utility operations;
101
and whether a code of conduct should be established to assure that
non-utility segments of the holding company are not engaged in practices
which result in unfair competition caused by cost shifting from the
non-utility affiliate to the utility. In September 1998, the Commission
issued draft code of conduct and cost allocation guidelines. In January 1999,
the Company, as well as all parties to the proceeding, filed comments on the
Commission draft proposals. Initial hearings are scheduled for the first
quarter of 1999. 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, 1998, the Company held U.S. Treasury note and bond futures
contracts with notional amounts totaling $4.9 million. These contracts are used
to hedge price risk associated with certain marketable securities and mature in
March 1999.
As of December 31, 1998, LG&E had in effect six interest-rate swap agreements to
hedge its exposure to tax exempt rates related to Pollution Control Bonds,
Variable Rate Series. The swaps have notional amounts totaling $166 million and
mature at various times from 1999 to 2005. LG&E pays a weighted-average fixed
rate on the swaps of 3.89% and receives a variable rate based on the JJ Kenny
Index (in the case of one of the swaps) or the Bond Market Association Municipal
Swap Index. The indices averaged 3.48% in 1998.
In April 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.
Capital Corp. had two interest rate swaps outstanding at December 31, 1998,
which hedge a portion of its notes payable. One swap has a notional amount of
$50 million and matures in June 2002. Capital Corp. receives a variable rate
based on the three-month London Interbank Offered Rate which equaled 5.24% at
year end and pays a fixed rate of 6.49%. The second swap has a notional amount
of $50 million and matures in January 2000. The Company receives a variable rate
based on a one-month commercial paper rate index and pays a fixed rate of 4.78%.
The index for December 1998 was 5.23%.
The cost and estimated fair values of the Company's non-trading financial
instruments (excluding the fair values of the Company's price risk management
assets and liabilities) as of December 31, 1998 and 1997 follow (in thousands of
$):
1998 1997
---- ----
Fair Fair
Cost Value Cost Value
----------- ----------- ----------- -----------
Marketable securities $ 20,592 $ 20,862 $ 21,994 $ 22,300
Long-term investments -
Not practicable to estimate
fair value 1,721 1,721 3,983 3,983
Preferred stock subject
to mandatory redemption 25,000 26,413 25,000 26,250
Long-term debt 1,510,795 1,576,502 1,210,690 1,266,030
U.S. Treasury note and
bond futures - (87) - (81)
Interest rate swaps - (9,527) - (4,328)
102
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.
LG&E's customer receivables and gas and electric revenues arise from deliveries
of natural gas to approximately 289,000 customers and electricity to
approximately 360,000 customers in Louisville and adjacent areas in Kentucky.
KU's customer receivables and revenues arise from deliveries of electricity to
about 449,000 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 five counties in southwestern Virginia. For the year ended
December 31, 1998, 90% of total utility revenue was derived from electric
operations and 10% from gas operations.
The financial position and results of operations of the domestic unconsolidated
ventures are substantially dependent upon the continuation of long-term power
sales contracts with purchasing utilities. The Argentine natural gas
distribution companies serve approximately 706,000 customers in six provinces in
Argentina. WKE's customer receivables and revenues arise from the deliveries of
electricity and generating capacity to Big Rivers for distribution to its four
members distribution cooperatives, as well as to other major wholesale
customers.
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. On December 10, 1998, LG&E and IBEW
employees entered into a three-year collective bargaining agreement following a
vote by IBEW members which ratified the contract providing for certain wage and
benefit improvements, and opportunities for early retirement. KU's operation and
maintenance employees are members of the IBEW Local 101 and United Steelworkers
of America (USWA) Local 8686. KU has approximately 15% of its workforce covered
by union contracts expiring August 1, 1999. In September 1998, WKE and
approximately 350 WKE employees entered into a three-year collective bargaining
agreement providing for, among other things, annual wage increases and fixed
pension benefits.
NOTE 8 - INVESTMENTS IN UNCONSOLIDATED VENTURES
The Company's investments in unconsolidated 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.
103
The fuel type, ownership percentages and carrying amounts of the unconsolidated
ventures as of December 31, 1998 are summarized as follows (in thousands of $):
Carrying
Fuel Type % Owned Amount
--------- ------- --------
LG&E Westmoreland - Southampton Coal 50 $ 13,784
LG&E Westmoreland - Altavista Coal 50 12,669
LG&E Westmoreland - Hopewell Coal 50 11,330
LG&E Westmoreland - Rensselaer Natural Gas 50 23,023
Westmoreland - LG&E Partners Coal 50 25,141
Windpower Partners 1993 Wind 50 21,345
Windpower Partners 1994 Wind 25 -
KW Tarifa, S.A. Wind 46 5,999
Distribuidora de Gas Cuyana - 14 44,531
Tenaska Limited Partnerships Gas 5-10 7,899
Electric Energy, Inc. (Note 18) Coal 20 2,156
--------
Total $167,877
--------
--------
The Company's carrying amount exceeded the underlying equity in unconsolidated
ventures by $33.3 million and $32.9 million at December 31, 1998 and 1997,
respectively. This difference, which is being amortized, represents adjustments
to reflect the fair value of the underlying net assets acquired and related
goodwill.
In January 1999, a final order was entered in the bankruptcy proceedings
involving Westmoreland Coal Company and certain of its subsidiaries, including
Westmoreland Energy, Inc., the parent of various entities that are partners with
company subsidiaries in five of the independent generating facilities. However,
none of the partnerships and no partner of the current partnerships has been
under bankruptcy court protection, nor were these partnerships in a default
occasioned under the project loan documents.
With respect to the Windpower Partners 1993 and Windpower Partners 1994 (WPP94)
projects listed above, certain of the Company's partners (or affiliates of such
partners) are in bankruptcy proceedings. During the third quarter of 1998, the
Company wrote off its aggregate remaining investment in WPP94 of $3.8 million.
See Note 18, Commitments and Contingencies.
In November 1998, the Company received approximately $8.5 million in connection
with an arbitration proceeding concerning a former Power Purchase Agreement
between Tenaska Washington Partners II, L.P. and the Bonneville Power
Administration (BPA). The Company has a 10% interest in this partnership, which
owned a partially constructed facility in Frederickson, Washington. This
facility was transferred to the BPA following payment of the award.
In June 1998, the partnership that owns the Rensselaer facility, along with 14
other independent power producers, participated in the consummation of a Master
Restructuring Agreement (MRA) with Niagara Mohawk Power Corporation (NIMO). As
part of the MRA, the partnership restructured its power purchase agreement with
NIMO and entered into a new multi-year agreement with the utility. Concurrent
with the MRA, the Company reached a settlement with other parties to retain a
50% ownership in the Rensselaer facility. As a result of these transactions, the
Company recorded a $21 million, net after-tax gain in 1998. See Note 18,
Commitments and Contingencies.
In February 1998, the Company sold its indirect, one-third interest in the
company which owned and operated the San Miguel, Argentina generating facility
for a price of $16 million. The sale resulted in a $2.8 million pre-
104
tax charge to 1998 earnings.
NOTE 9 - LEVERAGED LEASES
Capital Corp. owns equity interests in several leveraged leases for combustion
turbine units leased to utility companies. The leases expire in 1999 at which
time the Company will release, sell or reacquire these assets. Capital Corp.'s
equity investment represents 75% of the aggregate purchase price of the leases.
The remaining 25% represents the non-recourse 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.
The following is a summary of the components of Capital Corp.'s net investment
in leveraged leases at December 31 (in thousands of $):
1998 1997
---- ----
Rents receivable (net of nonrecourse debt) $ 1,556 $ 3,039
Estimated residual value of leased property 32,707 32,707
Less: unearned and deferred income 3,319 7,594
-------- --------
Investment in leveraged leases 30,944 28,152
Less: accumulated deferred income taxes 7,301 5,750
-------- --------
Net investment in leveraged leases $23,643 $22,402
-------- --------
-------- --------
See Note 14, Other Income and Deductions for income from leveraged leases.
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. As of December 31, 1998, the Company has no remaining
funding commitment.
105
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 1998 were
approximately $20 million, which resulted in realized gains of approximately $.2
million and losses of approximately $.7 million, calculated using the specific
identification method. Proceeds from sales of available-for-sale securities in
1997 were approximately $5 million, which resulted in immaterial realized gains
and losses.
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, 1998 and 1997, follow (in thousands of $):
Fixed
Equity Income Total
------ ------ -----
1998:
-----
Cost $6,467 $14,134 $20,601
Unrealized gains 545 40 585
Unrealized losses (196) (128) (324)
------ ------- -------
Fair values $6,816 $14,046 $20,862
------ ------- -------
------ ------- -------
Fair values:
No maturity $6,816 $ 178 $ 6,994
Contractual maturities:
Less than one year - 8,301 8,301
One to five years - 3,861 3,861
Five to ten years - - -
Over ten years - 1,706 1,706
Not due at a single maturity date - - -
------ ------- -------
Total fair values $6,816 $14,046 $20,862
------ ------- -------
------ ------- -------
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
------ ------- -------
------ ------- -------
NOTE 12 - PENSION PLANS AND RETIREMENT BENEFITS
PENSION PLANS AND RETIREMENT BENEFITS. LG&E Energy Corp. sponsors several
qualified and non-qualified pension plans and other postretirement benefit plans
for its employees. The following tables provide a reconciliation of the changes
in the plans' benefit obligations and fair value of assets over the three-year
period
106
ending December 31, 1998 and a statement of the funded status as of December
31 for each of the last three years (in thousands of $):
1998 1997 1996
---- ---- ----
Pension Plans:
--------------
Change in benefit obligation
Benefit obligation at beginning of year $499,143 $432,551 $397,155
Service cost 14,242 12,675 11,965
Interest cost 35,715 32,927 31,132
Plan amendments 6,377 3,143 19,186
Acquisitions/divestitures (2,243) - -
Curtailment (gain) or loss (364) - -
Special termination benefits 23,965 - -
Benefits paid (23,823) (22,114) (16,811)
Actuarial (gain) or loss 5,629 39,961 (10,076)
-------- -------- --------
Benefit obligation at end of year $558,641 $499,143 $432,551
-------- -------- --------
-------- -------- --------
Change in plan assets
Fair value of plan assets at beginning of year $501,361 $432,612 $389,303
Actual return on plan assets 70,631 81,645 53,713
Employer contributions 2,638 10,101 7,139
Benefits paid (23,823) (22,114) (16,811)
Administrative expenses (96) (883) (732)
-------- -------- --------
Fair value of plan assets at end of year $550,711 $501,361 $432,612
-------- -------- --------
-------- -------- --------
Reconciliation of funded status
Funded status $ (7,930) $ 2,218 $ 61
Unrecognized actuarial (gain) or loss (96,368) (79,891) (77,495)
Unrecognized transition (asset) or obligation (9,059) (10,358) (11,587)
Unrecognized prior service cost 47,286 48,064 49,054
-------- -------- --------
Net amount recognized at year-end $(66,071) $(39,967) $ (39,967)
-------- -------- --------
-------- -------- --------
Other Benefits:
---------------
Change in benefit obligation
Benefit obligation at beginning of year $115,894 $106,743 $101,667
Service cost 2,870 2,633 2,661
Interest cost 8,255 7,860 7,746
Plan amendments 613 - 4,120
Acquisitions/divestitures 2,283 - -
Curtailment (gain) or loss 3,584 - -
Special termination benefits 2,855 - -
Benefits paid (5,260) (6,648) (6,535)
Actuarial (gain) or loss (3,501) 5,306 (2,917)
-------- -------- --------
Benefit obligation at end of year $127,593 $115,894 $106,742
-------- -------- --------
-------- -------- --------
Change in plan assets
Fair value of plan assets at beginning of year $ 22,192 $ 15,568 $ 10,427
Actual return on plan assets 5,313 3,649 1,582
Employer contributions 7,056 7,577 6,037
Benefits paid (4,077) (4,602) (2,478)
Administrative expenses - - -
-------- -------- --------
Fair value of plan assets at end of year $ 30,484 $ 22,192 $ 15,568
-------- -------- --------
-------- -------- --------
107
1998 1997 1996
---- ---- ----
Reconciliation of funded status
Funded status $(97,109) $(93,702) $(91,175)
Unrecognized actuarial (gain) or loss (20,115) (16,730) (19,477)
Unrecognized transition (asset) or obligation 63,834 70,230 74,912
Unrecognized prior service cost 3,572 3,456 3,787
-------- -------- --------
Net amount recognized at year-end $(49,818) $(36,746) $(31,953)
-------- -------- --------
-------- -------- --------
There are no plan assets in the nonqualified plan due to the nature of the plan.
The following tables provide the amounts recognized in the statement of
financial position and information for plans with benefit obligations in excess
of plan assets as of December 31, 1998, 1997 and 1996 (in thousands of $):
1998 1997 1996
---- ---- ----
Pension Plans:
--------------
Amounts recognized in the balance sheet consisted of:
Accrued benefit liability $(67,126) $(40,296) $(40,032)
Intangible asset 426 281 65
Other 706 710 -
-------- -------- --------
Net amount recognized at year-end $(65,994) $(39,305) $(39,967)
-------- -------- --------
-------- -------- --------
Additional year-end information for plans with benefit
obligations in excess of plan assets:
Projected benefit obligation (1) $163,722 $138,492 $120,254
Accumulated benefit obligation (2) 142,941 11,879 14,656
Fair value of plan assets (1) 111,914 102,775 84,555
(1) All years include LG&E's non-union plan, Energy Corp.'s plan and all of the Company's unfunded
Supplemental Executive Retirement Plans (SERPs).
(2) 1998 includes LG&E's non-union plan, Energy Corp.'s plan and all SERPs. 1997 and 1996 include
SERPs only.
Other Benefits:
---------------
Amounts recognized in the balance sheet consisted of:
Accrued benefit liability $(49,818) $(36,746) $(31,953)
Intangible asset - - -
Other (4,421) (4,166) -
-------- -------- --------
Net amount recognized at year-end $(54,239) $(40,912) $(31,953)
-------- -------- --------
-------- -------- --------
Additional year-end information for plans with benefit
obligations in excess of plan assets:
Projected benefit obligation $127,593 $115,894 $106,743
Fair value of plan assets 30,484 22,192 15,568
108
The following table provides the components of net periodic benefit cost for the
plans for 1998, 1997 and 1996 (in thousands of $):
1998 1997 1996
---- ---- ----
Pension Plans:
--------------
Components of net periodic benefit cost
Service cost $ 14,242 $ 12,675 $ 11,965
Interest cost 35,715 32,927 31,132
Expected return on plan assets (42,278) (35,511) (32,320)
Amortization of prior service cost 4,421 4,133 3,911
Amortization of transition (asset) or obligation (1,224) (1,229) (1,229)
Recognized actuarial (gain) or loss (2,248) (2,854) (2,031)
---------- --------- ---------
Net periodic benefit cost $ 8,628 $ 10,141 $ 11,428
---------- --------- ---------
---------- --------- ---------
FAS88 special charges
Curtailment (gain)/loss $ (2,204) $ - $ -
Prior service cost recognized 2,015 - -
Special termination benefits 23,965 - -
---------- --------- ---------
Total FAS88 charges $ 23,776 $ - $ -
---------- --------- ---------
---------- --------- ---------
Other Benefits:
---------------
Components of net periodic benefit cost
Service cost $ 2,870 $ 2,633 $ 2,662
Interest cost 8,255 7,860 7,746
Expected return on plan assets (1,722) (1,204) (827)
Amortization of prior service cost 373 332 332
Amortization of transition (asset) or obligation 4,621 4,682 4,682
Recognized actuarial (gain) or loss (467) (810) (704)
---------- --------- ---------
Net periodic benefit cost $ 13,930 $ 13,493 $ 13,891
---------- --------- ---------
---------- --------- ---------
FAS88 special charges
Curtailment (gain)/loss $ 2,243 $ - $ -
Special termination benefits 2,855 - -
---------- --------- ---------
Total FAS88 charges $ 5,098 $ - $ -
---------- --------- ---------
---------- --------- ---------
On May 4, 1998, LG&E Energy and KU Energy merged, with LG&E Energy as the
surviving corporation. At the time of the merger KU Energy had both qualified
and nonqualified pension plans. During 1998, the Company invested approximately
$24.0 million in special termination benefits as a result of its early
retirement program offered to eligible employees post-merger. On May 30, 1997,
$4.7 million in lump sum payments were made to retired employees of KU Energy
due to a change-in-control provision in the provisions of the Supplemental
Security Plan of the Merger Agreement.
109
The assumptions used in the measurement of the Company's pension benefit
obligation are shown in the following table:
1998 1997 1996
---- ---- ----
Weighted-average assumptions as of December 31
Discount rate 7.00% 7.00% 7.75%
Expected long-term rate of return on plan assets (1) 8.25%-8.50% 8.25%-8.50% 8.25%-8.50%
Rate of compensation increase (2) 3.50%-4.00% 2.00%-4.00% 2.00%-4.75%
(1) All plans used 8.50% except KU's.
(2) All plans used 4.00% except LG&E's union plan which used 3.50% for
1998 and 2.00% for 1997. Rate of compensation increase for 1996
was 2.00% for LG&E's union plan, 4.25% for LG&E and 4.75% for KU.
For measurement purposes, a 7% annual increase in the per capita cost of covered
health care benefits was assumed for 1999. The rate was assumed to decrease
gradually to 4.25% for 2005 and remain at that level thereafter.
Assumed health care cost trend rates have a significant effect on the amounts
reported for the health care plans. A 1% change in assumed health care cost
trend rates would have the following effects:
1% Change
Effect on total of service and interest cost components for 1998 $ (1,214)
Effect on year-end 1998 postretirement benefit obligations (11,752)
Effect on total of service and interest cost components for 1998 1,544
Effect on year-end 1998 postretirement benefit obligations 15,197
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 the employee's contributions. The costs were
approximately $6.0 million, $4.7 million and $4.2 million for 1998, 1997 and
1996, respectively.
NOTE 13 - INCOME TAXES
Components of income tax expense are shown in the table below (in thousands of
$):
1998 1997 1996
---- ---- ----
Included in Income Taxes:
Current - federal $114,741 $ 88,654 $ 52,018
- foreign 12,208 9,055 -
- state 23,821 19,574 1,725
Deferred - federal - net (25,605) 9,024 36,848
- state - net (5,255) 1,292 18,741
Deferred investment tax credit - 102 409
Amortization of investment tax credit (8,087) (8,378) (8,419)
-------- -------- --------
Total $111,823 $119,323 $101,322
-------- -------- --------
-------- -------- --------
110
Net deferred tax liabilities resulting from book-tax temporary differences are
shown below (in thousands of $):
1998 1997
---- ----
Deferred tax liabilities:
Depreciation and other
plant-related items $632,593 $670,540
Other liabilities 39,966 43,199
-------- --------
672,559 713,739
-------- --------
Deferred tax assets:
Investment tax credit 37,878 41,142
Income taxes due to customers 43,021 45,574
Deferred income 11,626 11,878
Accrued expenses not currently
deductible and other 59,313 66,668
-------- --------
151,838 165,262
-------- --------
Net deferred income tax liability $520,721 $548,477
-------- --------
-------- --------
At December 31, 1998, there were $116 million of net operating loss
carryforwards related to discontinued operations. These carryforwards, which
expire in years 2000 through 2009, are subject to an annual limitation of
approximately $6 million under provisions of the Internal Revenue Code, and
realization is dependent upon generating sufficient taxable income prior to
their expiration. At both December 31, 1998 and 1997, the Company recorded
valuation allowances of $25.6 million, related to these deferred tax assets.
Unamortized goodwill will be reduced if unrecorded net operating 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:
1998 1997 1996
---- ---- ----
Statutory federal income tax rate 35.0% 35.0% 35.0%
State income taxes net of federal benefit 4.4 3.9 4.7
Effect of foreign operations including foreign tax credit 1.8 1.1 -
Investment and other tax credits (3.6) (3.1) (3.6)
Nondeductible merger expenses 4.7 - -
Other differences - net (2.2) (1.1) (2.2)
---- ---- -----
Effective income tax rate 40.1% 35.8% 33.9%
---- ---- -----
---- ---- -----
111
NOTE 14 - OTHER INCOME AND DEDUCTIONS
Other income and deductions consisted of the following at December 31 (in
thousands of $):
1998 1997 1996
---- ---- ----
Income from leveraged leases $ 4,273 $ 3,974 $ 3,613
Interest and dividend income 10,552 11,605 8,765
Gains (losses) on disposals - net (4,942) 7,083 51
Other (2,432) (1,692) (854)
-------- -------- --------
Total other income and (deductions) $ 7,451 $ 20,970 $ 11,575
-------- -------- --------
-------- -------- --------
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
shares of LG&E Energy common stock for each share of KU Energy common stock.
1998 1997 1996
---- ---- ----
Outstanding January 1 129,683 129,497 129,350
Issues under the Employee
Common Stock Purchase
Plan (1997, $1,613;
1996, $1,457) - 77 78
Issues under the Omnibus
Long-Term Incentive Plan
(1997, $2,195; 1996, $1,167) - 109 69
Merger-related buy-back of
fractional shares (6) - -
------- ------- -------
Outstanding December 31 129,677 129,683 129,497
------- ------- -------
------- ------- -------
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 proposed merger with KU Energy. This increase was
effective at the consummation of the merger on May 4, 1998.
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 3,000,000 shares of common stock have been reserved
for issuance under the plan. 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 have been
reserved for issuance under this plan. 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, benefit and compensation plans, including the Omnibus Long-Term
Incentive Plan.
112
A summary of the status of the Company's nonqualified stock options follows:
Outstanding Exercisable
----------- -----------
Weighted- Weighted-
Average Average
Options Price Options Price
------- --------- ------- ---------
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
Options granted and
exercisable 901,588 24.19 437,373 24.19
Options exercised (153,456) 20.42 (153,456) 20.42
Options cancelled (100,284) 23.05 - -
--------- ------ ------- ------
As of December 31, 1998 1,742,469 $22.60 992,389 $21.46
--------- ------ ------- ------
--------- ------ ------- ------
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 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. During 1998 Inversora redeemed 200,275 shares of preferred
stock.
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 1999 sinking fund requirements of the First Mortgage Bonds.
113
The trust indenture securing the 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.
On June 1, 1998, LG&E's First Mortgage Bonds, 6.75% Series of $20 million
matured and were retired by the Company.
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 3.09% and
3.39%, respectively, at December 31, 1998. 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.
LG&E's First Mortgage Bonds, 7.5% Series of $20 million is scheduled to mature
in 2002, and the $42.6 million, 6% Series is scheduled for maturity in 2003.
There are no scheduled maturities of Pollution Control Bonds for the five years
subsequent to December 31, 1998. The Company has no cash sinking fund
requirements.
Under the provisions for the KU's variable rate Pollution Control Bonds Series
10, KU can choose between various interest rate options. The daily interest rate
option was utilized at December 31, 1998. The average annual interest rate on
the bonds during 1998 and 1997 was 3.54% and 3.77%, 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.
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
November 3, 1998, Capital Corp. issued $150 million of Reset Put Securities due
2011. The interest rate is set at 5.75% through November 1, 2001. The securities
will be subject to automatic purchase by a remarketing agent, at which time the
interest rate will be reset, or to automatic repurchase by Capital Corp., on
November 1, 2001. After taking into account the net effect of the derivative
instruments entered into in September 1998 to hedge the interest rate on the
notes and other issuance costs, the effective rate through October 31, 2001, is
approximately 5.4%. The proceeds were used to repay a portion of Capital Corp.'s
outstanding commercial paper. In February 1998, Capital Corp. issued $150
million of medium-term notes due in January 2008, with a stated interest rate on
the notes of 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, Financial Instruments) and other issuance costs, the effective rate will be
6.82%. The proceeds were used to repay outstanding commercial paper.
114
Centro maintains a $100 million global note program. As of December 31, 1998 and
1997, Centro had outstanding $37.6 million in negotiable obligations, net of
issuance costs as part of this program. The maturity date of the debt is August
21, 2001. Interest is paid semi-annually based upon a fixed rate of 10.5%.
NOTE 17 - NOTES PAYABLE
Capital Corp. had outstanding commercial paper of $365.1 million at December
31, 1998, at a weighted-average interest rate of 5.19%. The Company had no
other notes payable at December 31, 1998. Capital Corp. had notes payable of
$360.2 million at December 31, 1997, at a weighted-average interest rate of
5.79%.
KU's short-term financing requirements are satisfied through the sale of
commercial paper. KU had no short-term borrowings at December 31, 1998. 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, 1998, 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 the Companies pays commitment or facility fees. The LG&E credit
facility provides for short-term borrowing. KU credit facilities provide for
short-term borrowing and support of commercial paper borrowing. 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 $536.8 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 1999
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 a Support
Agreement with LG&E Energy. The Support Agreement states, in substance, that
LG&E Energy 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.
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.
NOTE 18 - COMMITMENTS AND CONTINGENCIES
CONSTRUCTION PROGRAM
The Company had commitments, primarily in connection with the construction
program of LG&E and KU, aggregating approximately $15 million at December 31,
1998. LG&E's construction expenditures for the years 1999 and 2000 are estimated
to total approximately $384 million. KU's construction expenditures for the same
period are estimated to total approximately $341 million. Non-utility
construction expenditures for the same two-year period are estimated to be $68
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 $30.7 million and $38.3 million at December 31, 1998 and 1997,
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 $7.6 million
115
and $10.2 million at December 31, 1998 and 1997, respectively.
PROJECT CONTINGENCIES
SOUTHAMPTON. In October 1998, LG&E-Westmoreland Southampton and Virginia
Electric and Power Company (VEPCO) entered into a settlement agreement which
resolved issues pending before the FERC regarding the status of the Southampton
cogeneration facility (Southampton) as a qualifying facility (QF) under the
Public Utility Regulatory Policies Act for the year 1992, including the possible
payment of FERC-ordered refunds by Southampton of capacity payments previously
received from VEPCO for such year. The settlement, which has been approved by
the FERC, provides for, among other items, payments by Southampton to VEPCO of
$1 million annually for the years 1999-2001, followed by a reduction in capacity
payments from VEPCO to Southampton by $500,000 annually for the years 2002-2008.
Following 2008, VEPCO may elect to terminate its power purchases from
Southampton or continue to receive the annual reduction in capacity payments for
the remainder of the power purchase agreement. The Company has also been
notified that its partners in the Southampton partnership are disputing their
responsibilities for their share of the refunds and are asserting that the
Company should bear full responsibility for such amounts. The Company and its
partners are currently negotiating these matters. The Company does not believe
that the disputes with its partners will have a material adverse effect on its
results of operations or financial condition.
ROANOKE VALLEY I. The Company owns a 50% interest in Westmoreland-LG&E Partners
(WLP), the owner of the Roanoke Valley I facility which sells electric power to
VEPCO pursuant to a long-term power purchase agreement (PPA). From May 1994
through December 1998, VEPCO withheld approximately $14.8 million of capacity
payments during periods of forced outages. In October 1994, WLP filed a
complaint against VEPCO seeking damages related to the withholding of such
payments. In June 1997, the Virginia Supreme Court reversed a lower court ruling
granting summary judgment in favor of VEPCO and remanded the case for a trial
which occurred in October 1998. In November 1998, the Circuit Court for the City
of Richmond, Virginia issued a decision awarding WLP approximately $19 million,
plus interest until paid, and ruled WLP was entitled to receive future capacity
payments for eligible forced outages during the remainder of the PPA term.
In January 1999, VEPCO filed a notice of appeal regarding the Circuit Court
decision. Pending resolution of all appeals by VEPCO, the Company has not
recognized any income on its 50% portion of the capacity payments being withheld
by VEPCO. In the Company's opinion, WLP is entitled to recover the withheld
capacity payments, as well as the future capacity payments during forced
outages. 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.
RENSSELAER. In November 1998, LG&E Westmoreland-Rensselaer (LWR), in which the
Company has a 50% interest, entered into a non-binding letter of intent for the
sale of the assets of the Rensselaer cogeneration facility. The proposed sale is
subject to a number of contingencies, including satisfactory completion of
certain due diligence, corporate approvals by buyer and seller parties, receipt
of all necessary regulatory and third party approvals and consents and other
matters. Should all conditions precedent be satisfied or waived, a sale is
scheduled for early 1999.
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, and various windpower projects located in the U.S. and
abroad. 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
116
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. In January 1997, the projects filed their respective breach of
contract and other claims against Kenetech in the bankruptcy proceeding. In
January 1999, the Bankruptcy Court approved an initial plan of
reorganization. The Plan is subject to a number of filed objections, the
resolution of which and satisfaction of other conditions precedent are
required prior to initial distributions currently planned for the first
quarter 1999.
The projects are discussing with their creditors the allocation of any such
distributions. The Company is unable to predict the outcome of these
proceedings. 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 is a windpower generation facility in Texas, in
which the Company has a 25% interest. WPP 94 did not make its semiannual
payments, due September 1997, March 1998 and September 1998 to John Hancock
Mutual Life Insurance Company (Hancock) under certain Notes issued by WPP 94 to
Hancock. WPP 94 and Hancock are presently engaged in discussions concerning a
possible restructuring of WPP 94's debt obligations. 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.
GREGORY. In June 1998, LPI entered into a partnership with Columbia Electric
Corporation for the development of a natural gas-fired cogeneration project in
Gregory, Texas, providing electricity and steam equivalent of 550 MW. Initial
construction commenced in August 1998 and non-recourse financing for a majority
of the construction and other costs was obtained in November 1998. The project
will sell steam and a portion of its electric output to Reynolds Metals Company.
A medium-term fixed-price contract has also been entered into with a third party
for a portion of the remaining electric output. The project is expected to begin
commercial operation in the summer of 2000 at an anticipated total project cost
of approximately $240 million. The Company's equity contribution is expected to
be approximately $30 to $35 million in connection with its 50% interest in the
project.
CALGARY. In November 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. An amended statement of claim was filed in the Calgary action
in December 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.
Discovery proceedings in this action have occurred in 1998. 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. In July 1998, LEM filed suit in the United
States District Court for the Western District of Kentucky in 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 million. The parties have commenced discovery
which is scheduled to continue into late 1999.
OGLETHORPE POWER CONTRACT. In November 1996, the Company, through LEM, entered
into a 15-year agreement with 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 negotia-
117
tions with OPC over load projections provided by OPC as an inducement for LEM
to enter into the 1996 agreement. In October 1998, LEM initiated an
arbitration proceeding against OPC related to these load projections. Final
selection of the arbitration panel is expected to occur in the first quarter
of 1999. See also Discontinuance of Merchant Energy Trading and Sales
Business in Management's Discussion and Analysis of Operations and Financial
Condition.
OPERATING LEASES
The Company leases office space, office equipment and vehicles. See also Note 4
for discussion of the Big Rivers Electric Corporation operating lease. The
Company accounts for these leases as operating leases. Total lease expense for
1998, 1997 and 1996, was $21.7 million, $6.7 million and $7.8 million,
respectively. The future minimum annual lease payments under lease agreements
for years subsequent to December 31, 1998 are as follows (in thousands of $):
1999 $ 5,650
2000 19,926
2001 36,669
2002 37,072
2003 36,574
Thereafter 627,073
--------
Total $762,964
--------
--------
Future minimum annual lease payments have been reduced by rental payments to be
received from noncancelable subleases of approximately $1.8 million per year
through 1999 and 2000, and $1.3 million in 2001.
ENVIRONMENTAL
In September 1998, the U.S. Environmental Protection Agency (USEPA) announced
its final regulation requiring significant additional reductions in NOx
emissions to mitigate alleged ozone transport to the Northeast. While each state
is free to allocate its assigned NOx reductions among various emissions sectors
as it deems appropriate, the regulation may ultimately require utilities to
reduce their NOx emissions to 0.15 lb./mmBtu-an 85% reduction from 1990 levels.
Under the regulation, each state must incorporate the additional NOx reductions
in its State Implementation Plan (SIP) by September 1999 and affected sources
must install control measures by May 2003, unless granted extensions. Several
states, various labor and industry groups, and individual companies have
appealed the final regulation to the U.S. Court of Appeals for the D.C. Circuit.
Management is currently unable to determine the outcome or exact impact of this
matter until such time as the states identify specific emissions reductions in
their SIPs and the courts rule on the various legal challenges to the final
rule. However, if the 0.15 lb. target is ultimately imposed, LG&E, KU, WKE and
the independent power projects in which the Company has an interest will be
required to incur significant capital expenditures and increased operation and
maintenance costs for additional controls.
Subject to further study and analysis, the Company estimates that it may incur
capital costs in the range of $300 million to $500 million in the aggregate for
LG&E, KU, and WKE. These costs would generally be incurred beginning in 2000.
The Company believes its costs in this regard to be comparable to those 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 cost 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.
The Company is also addressing other air quality issues. First, the Company is
monitoring USEPA's
118
implementation of the revised National Ambient Air Quality Standards (NAAQS)
for ozone and particulate matter. Until USEPA completes additional
implementation steps, including monitoring and nonattainment designations,
management is unable to determine the precise impact of the revised
standards. Second, the Company is conducting modeling activities at LG&E's
Cane Run Station and WKE's Coleman Station in response to notifications from
regulatory agencies that those plants may be the source of potential
exceedances of the NAAQS for SO2. Depending on future regulatory
determinations, the Company may be required to undertake corrective action
that could include significant capital expenditures or emissions limitations.
Third, the Company is working with regulatory authorities to review the
effectiveness of remedial measures aimed at controlling particulate emissions
from LG&E's Mill Creek Station. The Company previously settled a number of
property damage claims from adjacent residents and completed significant
plant modifications as part of its ongoing capital construction program. The
Company is currently awaiting a final regulatory determination regarding
remedial measures. In management's opinion, resolution of any remaining
property damage claims from adjacent residents should not have a material
adverse impact on the financial position or results of operations of the
Company.
The Company is addressing potential liabilities for the cleanup of properties
where hazardous substances may have been released. The Company has identified
contamination at certain manufactured gas plant (MGP) sites currently or
formerly owned by the Company. A cleanup has been completed at a site owned by
KU and the Company is negotiating with state agencies with respect to cleanup of
a site owned by LG&E. In addition, several other former MGP sites have been
conveyed to other parties over a substantial period of time. In agreements
reached in 1996 and 1998 with the current owners of two sites formerly owned by
LG&E, the current owners of those sites have expressly agreed to assume
responsibility for environmental liabilities in return for an aggregate payment
of $400,000. Until conclusion of discussions with state agencies regarding the
site currently owned by LG&E and the receipt of additional information on sites
no longer owned by the Company, management is unable to precisely determine
remaining liability for cleanup costs at MGP sites. However, management
estimates total cleanup costs to be approximately $3 million. Accordingly, an
accrual of $3 million has been recorded in the accompanying financial
statements.
LG&E and KU along with other companies have been identified by USEPA as
potentially responsible parties allegedly liable for cleanup of certain off-site
disposal facilities under the Comprehensive Environmental Response Compensation
and Liability Act. LG&E has entered into final settlements for an aggregate of
$150,000 resolving liability in two cases, while KU is currently participating
as a de minimis party in an additional case.
WKE and LPI and 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 1999-2003, which is expected to be approximately 9% 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 $180 million of OMU
bonds outstanding at December 31, 1998. The debt service is allocated to KU
based on its annual allocated share of capacity, which averaged approximately
49% in 1998.
119
KU has a 20% equity ownership in EEI, which is accounted for on the equity
method of accounting. See Note 8. 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 1999-2003 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, 2003, are as follows (in thousands of $):
1999 $ 34,291
2000 26,712
2001 29,621
2002 29,561
2003 29,670
--------
Total $149,855
--------
--------
NOTE 19 - 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, and Indiana Municipal Power Agency (IMPA) owns a
12.88% undivided interest. Each is responsible for its proportionate ownership
share of fuel cost, operation and maintenance expenses, and incremental assets.
The following data represents shares of the jointly owned property:
Trimble County
LG&E IMPA IMEA TOTAL
---- ---- ---- -----
Ownership interest 75% 12.88% 12.12% 100%
Mw capacity 371.25 63.75 60 495
NOTE 20 - SEGMENTS OF BUSINESS AND RELATED INFORMATION
Effective December 31, 1998, the Company adopted Statements of Financial
Accounting Standards No. 131, Disclosure About Segments of an Enterprise and
Related Information. The Company's principal business segments consist of LG&E's
regulated electric and gas utility operations, KU's regulated electric utility
operations and Capital Corp.'s non-utility operations. Capital Corp.'s principal
business segments include its independent power operations, WKE and Argentine
gas distribution subsidiaries.
120
The All Other category consists of elimination entries, adjustments and other
corporate. The Company does not allocate all expenses from corporate to
reportable segments. International long-lived assets consist of the long-lived
assets of the Argentine gas distribution companies, the Company's investment in
the San Miguel project in Argentina, and its investment in the Tarifa project in
Spain. The Company acquired its interests in the Argentine gas distribution
companies in February 1997, and it sold its interest in the San Miguel project
in February 1998. Financial data for business segments, revenues by product, and
long-lived assets by geographic area follow (in thousands of $):
LG&E CAPITAL CORP.
-------------------------------------------
Inde- Argentine
pendent Western Gas Other
LG&E LG&E KU Power Kentucky Distri- Capital All Consol-
Year Electric Gas Electric Operations Energy Bution Corp. Other (1) idated
- ---- -------- --- -------- ---------- ------ ------ ----- --------- ------
1998
- ----
Revenues $ 658,510 $191,545 $ 810,114 $ 19,884 $128,519 $148,162 $49,479 $(29,800) $1,976,413
Depreciation and
amortization 79,867 13,312 86,657 4,633 1,345 8,973 1,759 871 197,417
Interest income 3,672 679 1,811 5,025 18 2,313 14,734 (17,700) 10,552
Interest expense 34,221 6,668 40,896 6 2,631 12,581 27,176 (15,308) 108,871
Equity in unconsolidated
ventures - - - 71,297 - 2,501 - - 73,798
Merger costs to achieve 32,073 - 21,830 - - - - 11,415 65,318
Income taxes 48,415 (152) 49,444 24,432 2,442 10,030 (5,321) (17,467) 111,823
Income from continuing
operations 71,536 2,016 70,508 41,608 3,592 5,752 (8,203) (26,538) 160,271
Total assets 1,734,221 332,789 1,751,048 163,663 176,166 346,305 120,972 148,104 4,773,268
Construction expenditures 105,837 32,509 91,992 4,242 17,549 14,977 69,478 5,630 342,214
(1) This column includes eliminations, adjustments and corporate.
LG&E CAPITAL CORP.
-------------------------------------------
Inde- Argentine
pendent Western Gas Other
LG&E LG&E KU Power Kentucky Distri- Capital All Consol-
Year Electric Gas Electric Operations Energy Bution Corp. Other (1) idated
- ---- -------- --- -------- ---------- ------ ------ ----- --------- ------
1997
- ----
Revenues $ 615,159 $231,011 $ 716,410 $ 19,622 $ - $127,182$ 15,671 $ - $1,725,055
Depreciation and
amortization 79,958 13,062 84,111 1,287 - 7,569 84 478 186,549
Interest income 5,400 953 1,673 2,321 - 1,697 7,836 (9,721) 10,159
Interest expense 37,236 6,539 41,955 - - 10,472 16,819 (8,594) 104,427
Equity in unconsolidated
ventures - - - 20,526 - 2,411 - - 22,937
Income taxes 61,426 4,667 47,789 10,154 - 7,264 (893) (11,084) 119,323
Income from continuing
operations 104,349 4,339 83,457 17,795 - 4,860 (1,461) (6,299) 207,040
Total assets 1,728,761 325,864 1,679,676 214,952 - 340,144 15,801 257,746 4,562,944
Construction expenditures 81,713 29,180 94,006 45 - 4,369 147 671 210,131
(1) This column includes eliminations, adjustments and corporate.
121
LG&E CAPITAL CORP.
-------------------------------------------
Inde- Argentine
pendent Western Gas Other
LG&E LG&E KU Power Kentucky Distri- Capital All Consol-
Year Electric Gas Electric Operations Energy Bution Corp. Other (1) idated
- ---- -------- --- -------- ---------- ------ ------ ----- --------- ------
1996
- ----
Revenues $ 607,160 $214,419 $ 711,711 $ 17,956 $ - $ - $ 9,239 $ (25) $1,560,460
Depreciation and
amortization 76,929 12,073 80,424 1,308 - - 250 415 171,399
Interest income 3,521 576 2,800 127 - - 1,134 607 8,765
Interest expense 38,488 6,322 41,873 (1,281) - - 9,337 (327) 94,412
Equity in unconsolidated
ventures - - - 19,727 - - - - 19,727
Non-recurring charges - - - 5,493 - - - - 5,493
Income taxes 58,854 4,812 47,206 4,522 - - (6,146) (7,926) 101,322
Income from continuing
operations 96,197 7,176 83,907 10,337 - - (963) (6,268) 190,386
Total assets 1,709,942 294,444 1,672,954 214,421 - - 21,122 219,716 4,132,599
Construction expenditures 79,541 28,338 106,582 1,080 - - 74 339 215,954
(1) This column includes eliminations, adjustments and corporate.
Revenue By Product:
Asset-Based
Retail Retail Energy
Year Electric Gas Marketing Other Totals
1998 $1,189,185 $339,707 $390,567 $56,954 $1,976,413
1997 1,173,275 358,193 158,294 35,293 1,725,055
1996 1,153,039 214,419 165,832 27,170 1,560,460
Long-Lived Assets By Geographic Area:
Inter-
Year Domestic national Totals
1998 $3,691,554 $299,444 $3,990,998
1997 3,451,437 360,106 3,811,543
1996 3,441,488 25,089 3,466,577
122
NOTE 21 - SELECTED QUARTERLY DATA (UNAUDITED)
Selected financial data for the four quarters of 1998 and 1997 are shown below.
Because of seasonal fluctuations in temperature and other factors, results for
quarters may fluctuate throughout the year.
(Thousands of $ except per share data) Quarters Ended
March June September December
----- ---- --------- --------
1998
- ----
Revenues $ 450,724 $ 441,137 $ 603,855 $ 480,697
Operating income 94,850 73,650 158,583 56,884
Net income (loss):
Continuing operations 46,674 13,294 (a) 79,512 20,791(b)
Discontinued operations (3,506) (20,093) - -
Loss on disposal of discon-
tinued operations - (225,000) - -
Cumulative effect of account-
ing change (7,162) - - -
-------- --------- --------- ---------
Total 36,006 (231,799) 79,512 20,791
Earnings per share of common
stock (basic and diluted):
Continuing operations .36 .10 .61 .16
Discontinued operations (.02) (.15) - -
Loss on disposal of discon-
tinued operations - (1.74) - -
Cumulative effect of account-
ing change (.06) - - -
-------- --------- --------- ---------
Total .28 (1.79) .61 .16
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 (basic and diluted):
Continuing operations .37 .25 .55 .43
Discontinued operations (.01) .01 (.12) (.06)
----- --- ----- -----
Total .36 .26 .43 .37
(a) The decrease of $20.4 million compared to June 1997 was due to an
after-tax charge of $56.4 million from merger-related expenses, offset by an
increase in our core utility business of approximately $13.0 million and the
consummation of the MRA with NIMO resulting in a $21.0 million gain.
(b) The decrease of $26.7 million compared to December 1997 was due to an
after-tax charge of $15.6 million related to refunds of certain amounts
collected under the environmental cost recovery surcharge, warmer weather and
higher utility operating expenses.
123
NOTE 22 - SUBSEQUENT EVENT
On March 8, 1999, the Kentucky Industrial Utility Customers (KIUC) filed a
separate complaints with the Kentucky Commission alleging that LG&E's and KU's
electric rates are excessive and should be reduced by an amount between $85 and
$146 million and that the Kentucky Commission establish a proceeding to reduce
LG&E's and KU's electric rates. LG&E and KU have asked the Kentucky Commission
to dismiss the complaint. The Company is not able to predict the ultimate
outcome of these proceedings, however, should the Commission mandate significant
rate reductions at LG&E and KU, through the PBR proposal or otherwise, such
actions could have a material effect on LG&E's and KU's financial condition and
results of operations.
On March 11, 1999, the Commission denied LG&E's Petition for Rehearing for the
period November 1994 through October 1996 and directed LG&E to reduce future
fuel expense by $1.9 million in the first billing month after the Order. The
Company is considering the filing of an Appeal with the Franklin Circuit Court.
In a separate series of Orders on March 11,1999, the PSC granted LG&E's Petition
for Rehearing for the period November 1996 through April 1998 and established a
procedural schedule for LG&E and other parties to submit evidence and for a
hearing before the Commission. In the same Orders the PSC granted the Petition
for Rehearing of the KIUC to determine if interest should be paid on any fuel
refunds for this latter period.
On March 15, 1999, LG&E Westmoreland - Rensselaer, in which the Company has a
50% interest, sold the assets of the Rensselaer cogeneration facility. This
transaction will result in a pre-tax gain for the Company of approximately $14.5
million.
124
LG&E Energy Corp.
REPORT OF MANAGEMENT
The management of LG&E Energy Corp. and subsidiaries is responsible for the
preparation and integrity of the consolidated financial statements and related
information included in this Annual Report. These statements have been prepared
in accordance with generally accepted accounting principles applied on a
consistent basis and, necessarily, include amounts that reflect the best
estimates and judgment of management.
The Company's financial statements have been audited by Arthur Andersen LLP,
independent public accountants. Management has made available to Arthur Andersen
LLP all the Company's financial records and related data as well as the minutes
of shareholders' and directors' meetings. Management has established and
maintains a system of internal controls that provides reasonable assurance that
transactions are completed in accordance with management's authorization, that
assets are safeguarded and that financial statements are prepared in conformity
with generally accepted accounting principles. Management believes that an
adequate system of internal controls is maintained through the selection and
training of personnel, appropriate division of responsibility, establishment and
communication of policies and procedures and by regular reviews of internal
accounting controls by the Company's internal auditors. Management reviews and
modifies its system of internal controls in light of changes in conditions and
operations, as well as in response to recommendations from the internal
auditors. These recommendations for the year ended December 31, 1998, did not
identify any material weaknesses in the design and operation of the Company's
internal control structure.
The Audit Committee of the Board of Directors is composed entirely of outside
directors. In carrying out its oversight role for the financial reporting and
internal controls of the Company, the Audit Committee meets regularly with the
Company's independent public accountants, internal auditors and management. The
Audit Committee reviews the results of the independent accountants' audit of the
consolidated financial statements and their audit procedures, and discusses the
adequacy of internal accounting controls. The Audit Committee also approves the
annual internal auditing program and reviews the activities and results of the
internal auditing function. Both the independent public accountants and the
internal auditors have access to the Audit Committee at any time.
LG&E Energy Corp. and subsidiaries maintain and internally communicate a written
code of business conduct that addresses, among other items, potential conflicts
of interest, compliance with laws, including those relating to financial
disclosure and the confidentiality of proprietary information.
125
LG&E Energy Corp.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders of LG&E Energy Corp.:
We have audited the accompanying consolidated balance sheets and statements of
capitalization of LG&E Energy Corp. (a Kentucky corporation) and subsidiaries as
of December 31, 1998 and 1997, and the related consolidated statements of
income, retained earnings, cash flows and comprehensive income for each of the
three years in the period ended December 31, 1998. 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, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted accounting principles.
As explained in Notes 1 and 3 to the consolidated financial statements,
effective January 1, 1998, the Company changed its method of accounting for
start-up costs and effective January 1, 1996, the Company changed its method of
accounting for price risk management activities.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedule listed under Item 14(a)2 is
presented for purposes of complying with the Securities and Exchange
Commission's rules and is not part of the basic financial statements. This
schedule has been subjected to the auditing procedures applied in the audit of
the basic financial statements and, in our opinion, fairly states in all
material respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.
Louisville, Kentucky Arthur Andersen LLP
January 27, 1999 (Except with respect
to the matters discussed in the
eighth and ninth paragraphs of Note
5, as to which the date is February
12, 1999, and Note 22, as to which
the date is March 15, 1999.)
126
Louisville Gas and Electric Company
Statements of Income
(Thousands of $)
Years Ended December 31
1998 1997 1996
---- ---- ----
OPERATING REVENUES:
Electric.......................................................... $ 663,011 $ 614,532 $ 606,696
Gas............................................................... 191,545 231,011 214,419
--------- --------- ---------
Total operating revenues....................................... 854,556 845,543 821,115
Provision for rate refund (Note 3)................................ (4,500) - -
--------- --------- ---------
Net operating revenues (Note 1)................................ 850,056 845,543 821,115
--------- --------- ---------
OPERATING EXPENSES:
Fuel for electric generation...................................... 154,683 149,463 149,697
Power purchased................................................... 50,176 17,229 16,626
Gas supply expenses............................................... 125,894 158,929 140,482
Other operation expenses.......................................... 163,584 150,750 143,338
Maintenance....................................................... 52,786 47,586 54,790
Depreciation and amortization..................................... 93,178 93,020 89,002
Federal and state income taxes (Note 8)........................... 56,307 64,081 63,259
Property and other taxes.......................................... 17,925 16,299 16,658
--------- --------- ---------
Total operating expenses....................................... 714,533 697,357 673,852
--------- --------- ---------
Net operating income.................................................. 135,523 148,186 147,263
Merger costs to achieve (Note 2)...................................... 32,072 - -
Other income and (deductions) (Note 9)................................ 10,991 4,277 920
Interest charges...................................................... 36,322 39,190 40,242
--------- --------- ---------
Net income............................................................ 78,120 113,273 107,941
Preferred stock dividends............................................. 4,568 4,585 4,568
--------- --------- ---------
Net income available for common stock................................. $ 73,552 $ 108,688 $ 103,373
--------- --------- ---------
--------- --------- ---------
Statements of Retained Earnings
(Thousands of $)
Years Ended December 31
1998 1997 1996
---- ---- ----
Balance January 1..................................................... $258,910 $209,222 $181,049
Add net income........................................................ 78,120 113,273 107,941
-------- -------- --------
337,030 322,495 288,990
Deduct: Cash dividends declared on stock:
5% cumulative preferred.................................. 1,075 1,075 1,075
Auction rate cumulative preferred........................ 2,024 2,041 2,024
$5.875 cumulative preferred.............................. 1,469 1,469 1,469
Common................................................... 85,000 59,000 75,200
-------- -------- --------
89,568 63,585 79,768
-------- -------- --------
Balance December 31................................................... $247,462 $258,910 $209,222
-------- -------- --------
-------- -------- --------
The accompanying notes are an integral part of these financial statements.
127
Louisville Gas and Electric Company
Statements of Comprehensive Income
(Thousands of $)
Years Ended December 31
1998 1997 1996
---- ---- ----
Net income available for common stock................................. $ 73,552 $108,688 $103,373
Unrealized holding gains (losses) on available-for-sale securities
arising during the period......................................... (14) (426) 169
Reclassification adjustment for realized and losses on
available-for-sale securities included in net income.............. - 188 547
-------- -------- --------
Other comprehensive income (loss) before tax.......................... (14) (238) 716
Income tax expense (benefit) related to items of other
comprehensive income.............................................. 18 (119) 289
-------- -------- --------
Comprehensive income.................................................. $ 73,520 $108,569 $103,800
-------- -------- --------
-------- -------- --------
The accompanying notes are an integral part of these financial statements.
128
Louisville Gas and Electric Company
Balance Sheets
(Thousands of $)
December 31
1998 1997
---- ----
ASSETS:
Utility plant, at original cost:
Electric.................................................................... $2,268,860 $2,242,980
Gas ..................................................................... 339,647 337,619
Common ..................................................................... 131,271 137,496
---------- ----------
2,739,778 2,718,095
Less: reserve for depreciation............................................. 1,144,123 1,072,842
---------- ----------
1,595,655 1,645,253
Construction work in progress............................................... 156,361 61,139
---------- ----------
1,752,016 1,706,392
---------- ----------
Other property and investments - less reserve................................... 1,154 1,365
Current assets:
Cash and temporary cash investments......................................... 31,730 50,472
Marketable securities (Note 6).............................................. 17,851 19,311
Accounts receivable - less reserve of $1,399 in 1998 and $1,295 in 1997..... 142,580 124,872
Materials and supplies - at average cost:
Fuel (predominantly coal)................................................ 23,993 17,651
Gas stored underground................................................... 33,485 41,487
Other.................................................................... 33,103 31,866
Prepayments................................................................. 2,285 2,627
---------- ----------
285,027 288,286
---------- ----------
Deferred debits and other assets:
Unamortized debt expense.................................................... 5,919 6,074
Regulatory assets (Note 3).................................................. 37,643 24,899
Other ..................................................................... 22,878 28,625
---------- ----------
66,440 59,598
---------- ----------
$2,104,637 $2,055,641
---------- ----------
---------- ----------
CAPITAL AND LIABILITIES:
Capitalization (see statements of capitalization):
Common equity............................................................... $ 671,846 $ 683,326
Cumulative preferred stock.................................................. 95,328 95,328
Long-term debt (Note 10).................................................... 626,800 626,800
---------- ----------
1,393,974 1,405,454
---------- ----------
Current liabilities:
Long-term debt due within one year.......................................... - 20,000
Accounts payable............................................................ 133,673 98,894
Provision for rate refunds.................................................. 13,261 13,248
Dividends declared.......................................................... 23,168 21,152
Accrued taxes............................................................... 31,929 18,723
Accrued interest............................................................ 8,038 8,016
Other ..................................................................... 15,242 14,608
---------- ----------
225,311 194,641
---------- ----------
Deferred credits and other liabilities:
Accumulated deferred income taxes (Notes 1 and 8)........................... 254,589 249,851
Investment tax credit, in process of amortization........................... 71,542 75,800
Accumulated provision for pensions and related benefits (Note 7)............ 59,529 33,872
Customers' advances for construction........................................ 10,848 10,385
Regulatory liability (Note 3)............................................... 63,529 65,502
Other ..................................................................... 25,315 20,136
---------- ----------
485,352 455,546
---------- ----------
Commitments and contingencies (Note 12)
$2,104,637 $2,055,641
---------- ----------
---------- ----------
The accompanying notes are an integral part of these financial statements.
129
Louisville Gas and Electric Company
Statements of Cash Flows
(Thousands of $)
Years Ended December 31
1998 1997 1996
---- ---- ----
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income........................................................ $ 78,120 $ 113,273 $ 107,941
Items not requiring cash currently:
Depreciation and amortization.................................. 93,178 93,020 89,002
Deferred income taxes - net.................................... 2,747 (3,495) 26,055
Investment tax credit - net.................................... (4,258) (4,240) (3,997)
Other.......................................................... 5,534 4,640 3,911
Change in certain net current assets:
Accounts receivable............................................ (17,708) (9,728) (9,555)
Materials and supplies......................................... 423 (8,492) (1,418)
Accounts payable............................................... 34,779 1,416 3,772
Provision for rate refunds..................................... 13 (4,263) (10,789)
Accrued taxes.................................................. 13,206 6,741 4,168
Accrued interest............................................... 22 (1,978) (1,070)
Prepayments and other.......................................... 976 1,333 685
Other............................................................. 18,679 (3,188) (23,153)
--------- ---------- ----------
Net cash flows from operating activities....................... 225,711 185,039 185,552
--------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchases of securities........................................... (17,397) (18,529) (11,039)
Proceeds from sales of securities................................. 18,841 2,544 28,605
Construction expenditures......................................... (138,345) (110,893) (107,879)
--------- ---------- ----------
Net cash flows from investing activities....................... (136,901) (126,878) (90,313)
--------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of first mortgage bonds and pollution control bonds...... - 69,776 49,745
Retirement of first mortgage bonds and pollution control bonds.... (20,000) (71,693) (67,013)
Payment of dividends.............................................. (87,552) (62,564) (79,310)
--------- ---------- ----------
Net cash flows from financing activities....................... (107,552) (64,481) (96,578)
--------- ---------- ----------
Change in cash and temporary cash investments......................... (18,742) (6,320) (1,339)
Cash and temporary cash investments at beginning of year.............. 50,472 56,792 58,131
--------- ---------- ----------
Cash and temporary cash investments at end of year.................... $ 31,730 $ 50,472 $ 56,792
--------- ---------- ----------
--------- ---------- ----------
Supplemental disclosures of cash flow information: Cash paid during the year
for:
Income taxes................................................... $ 40,334 $ 63,421 $ 41,508
Interest on borrowed money..................................... 34,245 39,582 40,334
The accompanying notes are an integral part of these financial statements.
130
Louisville Gas and Electric Company
Statements of Capitalization
(Thousands of $)
December 31
1998 1997
---- ----
COMMON EQUITY:
Common stock, without par value -
Authorized 75,000,000 shares, outstanding 21,294,223 shares.................. $ 425,170 $ 425,170
Common stock expense............................................................ (836) (836)
Unrealized gain on marketable securities, net of income
taxes $34 in 1998 and $16 in 1997 (Note 6)................................... 50 82
Retained earnings............................................................... 247,462 258,910
---------- ----------
671,846 683,326
---------- ----------
CUMULATIVE PREFERRED STOCK:
Redeemable on 30 days notice by LG&E
Shares Current
Outstanding Redemption Price
----------- ----------------
$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................................. 250,000 105.875 25,000 25,000
Preferred stock expense......................................................... (1,179) (1,179)
---------- ----------
95,328 95,328
---------- ----------
LONG-TERM DEBT (Note 10):
First mortgage bonds -
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:
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............................................ 506,800 506,800
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 35,000
Trimble County Series due November 1, 2027, variable......................... 35,000 35,000
---------- ----------
Total unsecured pollution control bonds.................................. 120,000 120,000
---------- ----------
Total long-term bonds................................................. 626,800 626,800
---------- ----------
Total capitalization......................................................... $1,393,974 $1,405,454
---------- ----------
---------- ----------
The accompanying notes are an integral part of these financial statements.
131
Louisville Gas and Electric Company
Notes to Financial Statements
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Louisville Gas and Electric Company (LG&E) is a subsidiary of LG&E Energy Corp.
(LG&E Energy). LG&E is a regulated public utility that is engaged in the
generation, transmission, distribution, and sale of electric energy and the
storage, distribution, and sale of natural gas in Louisville and adjacent areas
in Kentucky. LG&E Energy is an exempt energy services holding company with
wholly-owned subsidiaries consisting of LG&E, Kentucky Utilities Company (KU),
and LG&E Capital Corp. (Capital Corp.). All of the LG&E's Common Stock is held
by LG&E Energy.
UTILITY PLANT. LG&E's plant is stated at original cost, which includes
payroll-related costs such as taxes, fringe benefits, and administrative and
general costs. Construction work in progress has been included in the rate base
for determining retail customer rates. LG&E has not recorded any allowance for
funds used during construction.
The cost of plant retired or disposed of in the normal course of business is
deducted from plant accounts and such cost, plus removal expense less salvage
value, is charged to the reserve for depreciation. When complete operating units
are disposed of, appropriate adjustments are made to the reserve for
depreciation and gains and losses, if any, are recognized.
DEPRECIATION. Depreciation is provided on the straight-line method over the
estimated service lives of depreciable plant. The amounts provided for 1998 were
3.4% (3.2% electric, 3.4% gas, and 7.4% common); for 1997 were 3.4% (3.2%
electric, 3.3% gas, and 6% common); and for 1996 were 3.3% (3.2% electric, 3.3%
gas, and 6% common) of average depreciable plant.
CASH AND TEMPORARY CASH INVESTMENTS. LG&E 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. Gas inventories of $33 million and $41 million at
December 31, 1998 and 1997, respectively, are included in gas stored underground
in the balance sheet. The inventory is accounted for using the average-cost
method.
FINANCIAL INSTRUMENTS. LG&E 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 gains or losses on marketable securities in common equity and then
charged or credited to other income and deductions when the securities are sold.
See Note 4, Financial Instruments.
In connection with the LG&E's marketing of power from owned generation assets,
exchange traded futures are used to hedge market risk associated with price
fluctuations for commitments to sell or purchase electricity. Gains and losses
on these futures contracts are reflected in other income and deductions, but are
immaterial to the LG&E's results of operations. At December 31, 1998, the value
of these futures contracts was not material to the LG&E's financial position.
DEBT EXPENSE. Debt expense is amortized over the lives of the related bond
issues, consistent with regulatory
132
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 LG&E'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
rise to the credits.
REVENUE RECOGNITION. Revenues are recorded based on service rendered to
customers through month-end. LG&E accrues an estimate 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 (Kentucky Commission or
Commission) in 1994, LG&E implemented a demand side management program,
including a "decoupling mechanism" which allowed LG&E to recover a predetermined
level of revenue on electric and gas residential sales. In 1998, the decoupling
mechanism was suspended. See Note 3, Rates and Regulatory Matters.
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. LG&E implemented a Commission-approved experimental
performance-based ratemaking mechanism related to gas procurement and off-system
gas sales activity. See Note 3, Rates and Regulatory Matters.
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 12, Commitments and
Contingencies, for a further discussion.
NEW ACCOUNTING PRONOUNCEMENTS. During 1998, LG&E adopted the following
accounting pronouncements:
Statements of Financial Accounting Standards No. 132, Employers' Disclosures
about Pensions and Other Postretirement Benefits (SFAS No. 132), No. 130,
Reporting Comprehensive Income (SFAS No. 130), and No. 131, Disclosures about
Segments of an Enterprise and Related Information (SFAS No. 131). Pursuant
to SFAS No. 132, LG&E has disclosed additional information on changes in
benefit obligations and fair values of plan assets and eliminated certain
disclosures that are no longer relevant. This standard does not change the
measurement or financial statement recognition of the plans. See Note 7,
Pension Plans and Retirement Benefits. Under SFAS No. 131, LG&E has provided
information about its various business segments that is intended to allow
readers to view certain financial information as if "through the eyes of
management". See Note 14, Segments of Business and Related Information.
Pursuant to SFAS No. 130, LG&E has presented information in the Statements of
Comprehensive Income that measures changes in equity that are not required to
be recorded as a component of net income. These standards had no impact on
the calculation of net income presented in the Statements of Income.
Statement of Position No. 98-1, Accounting for the Costs of Computer Software
Developed or Obtained for Internal Use (SOP 98-1). SOP 98-1, adopted as of
January 1, 1998, clarifies the criteria for capital or expense treatment of
costs incurred by an enterprise to develop or obtain computer software to be
used in its internal operations. The statement does not change treatment of
costs incurred in connection with correcting computer programs to properly
process the millennium change to the Year 2000, which must be expensed as
incurred. Adoption of SOP 98-1 did not have a material effect on LG&E's
financial statements.
133
The following accounting pronouncements have been issued but are not yet
effective:
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 use hedge accounting. LG&E is currently analyzing the provisions of the
statement and cannot predict the impact this statement will have on its results
of operations and financial position, however, the statement could increase
volatility in earnings and other comprehensive income. The effect of this
statement will be recorded in cumulative effect of change in accounting when
adopted.
Emerging Issues Task Force Issue No. 98-10, Accounting for Energy Trading and
Risk Management Activities (EITF No. 98-10). This pronouncement is effective for
fiscal years beginning after December 15, 1998. The task force concluded that
energy trading contracts should be recorded at mark to market on the balance
sheet, with the gains and losses shown net in the income statement. EITF No.
98-10 more broadly defines what represents energy trading to include economic
activities related to physical assets which were not previously marked to market
by established industry practice. The effects of adopting EITF No. 98-10, if
applicable, will be reported as a cumulative effect of a change in accounting
principle with no prior period restatement. LG&E does not expect the adoption of
EITF No. 98-10 to have a material adverse impact on its operations and financial
position.
NOTE 2 - MERGER
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, LG&E Energy, which is the
parent of LG&E, became the parent company of Kentucky Utilities Company (KU).
LG&E and KU have continued to maintain their separate corporate identities and
serve customers 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 savings for LG&E of $50.2 million
were recorded in the second quarter of 1998, $18.1 million of which were
initially deferred and are being amortized over a five-year period pursuant to
regulatory orders. Primary components of the merger costs were separation
benefits, relocation costs, and transaction fees, the majority of which were
paid by December 31, 1998. LG&E 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 committed not to seek increases in existing base
rates and proposed reductions in their retail customers' bills in amounts based
on one-half of the savings, net of the deferred and amortized amount, over a
five-year period. The common stock, preferred stock and debt securities of LG&E
were not affected by the merger.
Regulatory and administrative approvals were obtained from the Federal Energy
Regulatory Commission, (FERC), the Federal Trade Commission, the Securities and
Exchange Commission, the Public Service Commission of Kentucky (Kentucky
Commission or Commission), the Virginia State Corporation Commission and the
stockholders of LG&E Energy and KU Energy prior to the effective date of the
merger. LG&E Energy, as the parent of LG&E and KU, continues to be an exempt
holding company under the Public Utility Holding Company Act of 1935. Management
has accounted for the merger as a pooling of interests and as a tax-free
reorganization under the Internal Revenue Code.
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 $18.1 million or 50% of the originally estimated costs to achieve
134
such savings by LG&E, be applied to reduce customer rates through a surcredit
on customers' bills and the remaining 50% be retained by the companies. The
Commission approved the surcredit and allocated the customer savings 53% to
KU and 47% to LG&E. The surcredit will be about 2% of customer bills over the
next five years and will amount to approximately $55 million in net non-fuel
savings to LG&E's customers. Any fuel cost savings are passed to customers
through LG&E's fuel adjustment clause.
NOTE 3 - RATES AND REGULATORY MATTERS
LG&E conforms with generally accepted accounting principles as applied to
regulated public utilities and as prescribed by FERC and the Kentucky
Commission. LG&E is subject to Statement of Financial Accounting Standards No.
71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71).
Under SFAS No. 71, certain costs that would otherwise be charged to expense are
deferred as regulatory assets based on expected recovery from customers in
future rates. Likewise, certain credits that would otherwise be reflected as
income are deferred as regulatory liabilities based on expected flowback to
customers in future rates. LG&E'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 balance sheets as of December 31 (in
thousands of $):
1998 1997
---- ----
Unamortized loss on bonds $ 17,627 $ 18,698
Merger costs 16,332 2,938
Manufactured gas sites 3,684 3,263
-------- --------
Total regulatory assets 37,643 24,899
Deferred income taxes - net (63,529) (65,502)
-------- --------
Regulatory assets and (liabilities) - net $(25,886) $(40,603)
-------- --------
-------- --------
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.
ENVIRONMENTAL COST RECOVERY. Since May 1995, LG&E implemented an environmental
cost recovery (ECR) surcharge to recover certain environmental compliance costs,
including costs to comply with the 1990 Clean Air Act, as amended, as well as
other environmental regulations, including those applicable to coal combustion
wastes and related by-products. The ECR mechanism was authorized by state
statute in 1992 and was first approved by the Kentucky Commission in a KU case
in July 1994.
The Commission's order approving the surcharge in the KU case and the
constitutionality of the surcharge was challenged by certain intervenors,
including the Attorney General of Kentucky, in Franklin Circuit Court. Decisions
of the Circuit Court and the Kentucky Court of Appeals in July 1995 and December
1997, respectively, have upheld the constitutionality of the ECR statute but
differed on a claim of retroactive recovery of certain amounts. The Commission
ordered that certain surcharge revenues collected by LG&E be subject to refund
pending final determination of all appeals.
On December 19, 1998, the Kentucky Supreme Court rendered an opinion upholding
the constitutionality of the surcharge statute. The decision, however, reversed
the ruling of the Court of Appeals on the retroactivity claim, thereby denying
recovery of costs associated with pre-1993 environmental projects through the
ECR. The court remanded the case to the Commission to determine the proper
adjustments to refund amounts collected for such pre-1993 environmental
projects. The parties to the proceeding have notified the Commission that they
have reached agreement as to the terms, refund amounts, refund procedure and
forward application of the ECR. The
135
settlement agreement is subject to Commission approval. LG&E recorded a
provision for rate refund of $4.5 million in December 1998.
DEMAND SIDE MANAGEMENT. In January 1994, LG&E implemented a Commission-approved
demand side management (DSM) program that LG&E, the Jefferson County Attorney,
and representatives of several customer interest groups had filed with the
Commission. The program included 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 program (decoupling). In June 1998, LG&E and customer interest
groups requested an end to the decoupling rate mechanism. On June 1, 1998, LG&E
discontinued recording revenues from lost sales due to DSM. Accrued decoupling
revenues recorded for periods prior to June 1, 1998, will continue to be
collected through the DSM recovery mechanism. On September 23, 1998, the
Commission accepted LG&E's modified tariff reflecting this proposal effective as
of June 1, 1998.
PERFORMANCE-BASED RATEMAKING. Since October 1997, LG&E has implemented a
Commission-approved, experimental performance-based ratemaking mechanism related
to gas procurement activities and off-system gas sales. During the three-year
test period beginning October 1997, rate adjustments related to this mechanism
will be determined for each 12-month period beginning November 1 and ending
October 31. During the first year of the mechanism ended October 31, 1998, LG&E
recorded $3.6 million for its share of reduced gas costs. The $3.6 million will
be billed to customers through the gas supply clause beginning February 1, 1999.
FUEL ADJUSTMENT CLAUSE. LG&E has a fuel adjustment clause (FAC) mechanism, which
under Kentucky law allows LG&E to recover from customers, the actual fuel costs
associated with retail electric sales. As of February 12, 1999, LG&E received
orders from the Kentucky Commission requiring a refund to retail electric
customers of approximately $3.9 million resulting from reviews of the FAC from
November 1994 through April 1998. The orders changed LG&E's method of assigning
fuel costs associated with electric line losses on off-system sales through the
FAC. The orders require these amounts to be refunded to customers during 1999
and to include in the FAC calculation the cost of fuel associated with line
losses incurred in making off-system sales.
The Kentucky Commission has not issued LG&E an order for the review period May
1998 through October 1998, however, following the methods set forth in the
previous orders, LG&E estimates up to an additional $1.3 million could be
refundable to retail electric customers for open review periods through December
1998. LG&E filed a request for rehearing on the Kentucky Commission's rulings.
LG&E does not believe final resolution of these proceedings will have a material
adverse effect on LG&E's financial position or results of operations.
The Kentucky Commission granted LG&E's motion to suspend the refund obligation
until further direction by the Commission. The Commission advised that LG&E may
have to pay interest on the refund amounts for the suspension period. LG&E is
awaiting a Commission response to a motion to revoke the orders, or in the
alternative, grant a rehearing.
FUTURE RATE REGULATION. In October 1998, LG&E and KU filed separate, but
parallel applications with the Commission for approval of a new method of
determining electric rates that provides financial incentives for LG&E and KU to
further reduce customers' rates. The filing was made pursuant to the September
1997 Commission order approving the merger of LG&E Energy and KU Energy, wherein
the Commission directed LG&E and KU to indicate whether they desired to remain
under traditional rate of return regulation or commence non-traditional
regulation. The new ratemaking method, known as performance-based ratemaking
(PBR), would include financial incentives for LG&E and KU to reduce fuel costs
and increase generating efficiency, and to share any resulting savings with
customers. Additionally, the PBR provides financial
136
penalties and rewards to assure continued high quality service and
reliability.
The PBR plan proposed by LG&E and KU consists of five components:
The utilities' fuel adjustment clause mechanism will be withdrawn and
replaced with a cap that limits recovery of actual changes in fuel cost to
changes in a fuel price index for a five-state region. If the utilities
outperform the index, benefits will be shared equally between shareholders
and customers. If the utilities' fuel costs exceed the index, the difference
will be absorbed by LG&E Energy's shareholders.
Customers will continue to receive the benefits from the post-merger joint
dispatch of power from LG&E's and KU's generating plants.
Power plant performance will be measured against the best performance
achieved between 1991 and 1997. If the performance exceeds this level,
customers will share equally with LG&E Energy's shareholders in up to $10
million annually of benefits from this performance at each of LG&E and KU.
The utilities will be encouraged to maintain and improve service quality,
reliability, customer satisfaction and safety, which will be measured
against six objective benchmarks. The plan provides for annual rewards or
penalties to LG&E Energy of up to $5 million per year at each of LG&E and
KU.
The plan provides the utilities with greater flexibility to customize rates
and services to meet customer needs. Services will continue to be priced
above marginal cost and customers will continue to have the option to elect
standard tariff service.
These proposals are subject to approval by the Commission. Approval proceedings
commenced in October 1998 and a final decision likely will occur in 1999.
Several intervenors are participating in the case. Some have requested that the
Commission reduce base rates before implementing PBR. LG&E is not able to
predict the ultimate outcome of these proceedings, however, should the
Commission mandate significant rate reductions at LG&E, through the PBR proposal
or otherwise, such actions could have a material effect on LG&E's financial
condition and results of operations.
KENTUCKY PSC ADMINISTRATIVE CASE FOR AFFILIATE TRANSACTIONS. In December 1997,
the Kentucky Commission opened Administrative Case No. 369 to consider
Commission policy regarding cost allocations, affiliate transactions and codes
of conduct governing the relationship between utilities and their non-utility
operations and affiliates. The Commission 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-utility operations; and whether a
code of conduct should be established to assure that non-utility segments of the
holding company are not engaged in practices which result in unfair competition
caused by cost shifting from the non-utility affiliate to the utility. In
September 1998, the Commission issued draft code of conduct and cost allocation
guidelines. In January 1999, LG&E, as well as all parties to the proceeding,
filed comments on the Commission draft proposals. Initial hearings are scheduled
for the first quarter of 1999. Management does not expect the ultimate
resolution of this matter to have a material adverse effect on LG&E's financial
position or results of operations.
NOTE 4 - FINANCIAL INSTRUMENTS
At December 31, 1998, LG&E held U.S. Treasury note and bond futures contracts
with notional amounts totaling $2.8 million. These contracts are used to hedge
price risk associated with certain marketable securities and mature in March
1999.
137
As of December 31, 1998, LG&E had in effect six interest-rate swap agreements
to hedge its exposure to tax exempt rates related to Pollution Control Bonds,
Variable Rate Series. The swaps have notional amounts totaling $166 million
and mature at various times from 1999 to 2005. LG&E pays a weighted-average
fixed rate on the swaps of 3.89% and receives a variable rate based on the JJ
Kenny Index (in the case of one of the swaps) or the Bond Market Association
Municipal Swap Index. The indices averaged 3.48% in 1998.
In April 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.
The cost and estimated fair values of LG&E's non-trading financial
instruments as of December 31, 1998 and 1997 follow (in thousands of $):
1998 1997
---- ----
Fair Fair
Cost Value Cost Value
---- ----- ---- -----
Marketable securities $ 17,767 $ 17,851 $ 19,213 $ 19,311
Long-term investments -
Not practicable to estimate
fair value 748 748 747 747
Preferred stock subject
to mandatory redemption 25,000 26,413 25,000 26,250
Long-term debt 626,800 648,603 626,800 649,491
U.S. Treasury note and
bond futures - (50) - (37)
Interest-rate swaps - (7,378) - (248)
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 LG&E
cannot reasonably estimate fair value.
NOTE 5 - 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.
LG&E's customer receivables and gas and electric revenues arise from
deliveries of natural gas to approximately 289,000 customers and electricity
to approximately 360,000 customers in Louisville and adjacent areas in
Kentucky. For the year ended December 31, 1998, 77% of total revenue was
derived from electric operations and 23% from gas operations.
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. On December 10, 1998, LG&E and IBEW
employees entered into a three-year collective bargaining agreement following
a vote by IBEW members which ratified the contract providing for certain wage
and benefit improvements, and opportunities for early retirement.
138
NOTE 6 - MARKETABLE SECURITIES
LG&E'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 1998 were
approximately $18.8 million, which resulted in immaterial realized gains and
losses. Proceeds from sales of available-for-sale securities in 1997 were
approximately $2.5 million, which resulted in immaterial realized gains and
losses, calculated using the specific identification method.
Approximate cost, fair value, and other required information pertaining to
LG&E's available-for-sale securities by major security type, as of December
31, 1998 and 1997, follow (in thousands of $):
Fixed
Equity Income Total
------ ------ -----
1998:
Cost $3,798 $13,969 $17,767
Unrealized gains 276 31 307
Unrealized losses (95) (128) (223)
-------- ---------- ----------
Fair values $3,979 $13,872 $17,851
-------- ---------- ----------
-------- ---------- ----------
Fair values:
No maturity $3,979 $ 178 $ 4,157
Contractual maturities:
Less than one year - 8,301 8,301
One to five years - 3,861 3,861
Five to ten years - - -
Over ten years - 1,532 1,532
Not due at a single maturity date - - -
-------- ---------- ----------
Total fair values $3,979 $13,872 $17,851
-------- ---------- ----------
-------- ---------- ----------
1997:
Cost $3,763 $15,450 $19,213
Unrealized gains 192 13 205
Unrealized losses (40) (67) (107)
-------- ----------- ----------
Fair values $3,915 $15,396 $19,311
-------- ---------- ----------
-------- ---------- ----------
Fair values:
No maturity $3,915 $ 114 $ 4,029
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 - 1,045 1,045
Not due at a single maturity date - - -
---------- ------------- -------------
Total fair values $3,915 $15,396 $19,311
-------- ---------- ----------
-------- ---------- ----------
139
NOTE 7 - PENSION PLANS AND RETIREMENT BENEFITS
PENSION PLANS. LG&E sponsors several qualified and non-qualified pension
plans and other postretirement benefit plans for its employees. The following
tables provide a reconciliation of the changes in the plans' benefit
obligations and fair value of assets over the three-year period ending
December 31, 1998 and a statement of the funded status as of December 31 for
each of the last three years (in thousands of $):
1998 1997 1996
---- ---- ----
Pension Plans:
--------------
Change in benefit obligation
Benefit obligation at beginning of year $274,095 $229,349 $206,866
Service cost 6,333 5,214 4,989
Interest cost 19,873 17,629 16,697
Plan amendments 3,724 3,085 18,694
Curtailment (gain) or loss (2,218) - -
Special termination benefits 18,295 - -
Benefits paid (10,866) (8,735) (7,745)
Actuarial (gain) or loss 2,699 27,553 (10,152)
--------- --------- ----------
Benefit obligation at end of year $311,935 $274,095 $229,349
--------- --------- ----------
--------- --------- ----------
Change in plan assets
Fair value of plan assets at beginning of year $280,238 $238,026 $207,471
Actual return on plan assets 38,913 46,078 31,921
Employer contributions 375 4,869 6,379
Benefits paid (10,866) (8,735) (7,745)
--------- --------- ----------
Fair value of plan assets at end of year $308,660 $280,238 $238,026
--------- --------- ----------
--------- --------- ----------
Reconciliation of funded status
Funded status $ (3,275) $ 6,143 $ 8,677
Unrecognized actuarial (gain) or loss (72,037) (61,720) (65,850)
Unrecognized transition (asset) or obligation (8,076) (9,188) (10,300)
Unrecognized prior service cost 41,447 43,518 44,141
--------- --------- ----------
Net amount recognized at end of year $ (41,941) $ (21,247) $ (23,332)
--------- --------- ----------
--------- --------- ----------
Other Benefits:
--------------
Change in benefit obligation
Benefit obligation at beginning of year $43,373 $39,951 $37,815
Service cost 761 746 773
Interest cost 2,946 2,942 2,976
Plan amendments 599 - 4,066
Curtailment (gain) or loss 344 - -
Special termination benefits 2,855 - -
Benefits paid (2,634) (2,604) (2,678)
Actuarial (gain) or loss (3,280) 2,338 (3,001)
--------- --------- ----------
Benefit obligation at end of year $44,964 $43,373 $39,951
--------- --------- ----------
--------- --------- ----------
Change in plan assets
Fair value of plan assets at beginning of year $ 4,384 $ 2,284 $ -
Actual return on plan assets 199 80 -
Employer contributions 3,207 3,696 2,284
Benefits paid (1,728) (1,676) -
--------- --------- ----------
Fair value of plan assets at end of year $ 6,062 $ 4,384 $ 2,284
--------- --------- ----------
--------- --------- ----------
140
1998 1997 1996
---- ---- ----
Reconciliation of funded status
Funded status $ (38,902) $ (38,989) $ (37,667)
Unrecognized actuarial (gain) or loss (285) 2,901 493
Unrecognized transition (asset) or obligation 18,080 20,053 21,390
Unrecognized prior service cost 3,519 3,410 3,738
----------- ----------- -----------
Net amount recognized at end of year $ (17,588) $ (12,625) $ (12,046)
----------- ----------- -----------
----------- ----------- -----------
There are no plan assets in the nonqualified plan due to the nature of the plan.
The following tables provide the amounts recognized in the statement of
financial position and information for plans with benefit obligations in excess
of plan assets as of December 31, 1998, 1997 and 1996 (in thousands of $):
1998 1997 1996
---- ---- ----
Pension Plans:
--------------
Amounts recognized in the balance sheet consisted of:
Accrued benefit liability $ (41,977) $ (21,317) $ (23,372)
Intangible asset 36 70 40
----------- ----------- -----------
Net amount recognized at year-end $ (41,941) $ (21,247) $ (23,332)
----------- ----------- -----------
----------- ----------- -----------
Additional year-end information for plans with
benefit obligations in excess of plan assets:
Projected benefit obligation (1) $148,005 $121,902 $101,260
Accumulated benefit obligation (2) 131,430 4,179 3,634
Fair value of plan assets (1) 107,988 99,151 81,848
(1) All years include LG&E's non-union plan and unfunded Supplemental Executive Retirement Plans (SERPs).
(2) 1998 includes LG&E's non-union plan and SERPs. 1997 and 1996 include SERPs only.
Other Benefits:
---------------
Amounts recognized in the balance sheet consisted of:
Accrued benefit liability $ (17,588) $ (12,625) $ (12,046)
----------- ----------- -----------
----------- ----------- -----------
Additional year-end information for plans with benefit obligations in
excess of plan assets:
Projected benefit obligation $44,964 $43,373 $39,951
Fair value of plan assets 6,062 4,384 2,284
141
The following table provides the components of net periodic benefit cost for the
plans for 1998, 1997 and 1996 (in thousands of $):
1998 1997 1996
---- ---- ----
Pension Plans:
--------------
Components of net periodic benefit cost
Service cost $ 6,333 $ 5,214 $ 4,989
Interest cost 19,873 17,629 16,697
Expected return on plan assets (23,701) (19,849) (17,706)
Amortization of prior service cost 3,882 3,708 3,491
Amortization of transition (asset) or obligation (1,112) (1,112) (1,112)
Recognized actuarial (gain) or loss (2,248) (2,866) (2,047)
--------- --------- ---------
Net periodic benefit cost $ 3,027 $ 2,724 $ 4,312
--------- --------- ---------
--------- --------- ---------
FAS88 special charges
Curtailment (gain)/loss $ (2,168) $ - $ -
Prior service cost recognized 1,914 - -
Special termination benefits 18,295 - -
--------- --------- ---------
Total FAS88 charges $ 18,041 $ - $ -
--------- --------- ---------
--------- --------- ---------
Other Benefits:
---------------
Components of net periodic benefit cost
Service cost $ 761 $ 746 $ 773
Interest cost 2,946 2,942 2,976
Expected return on plan assets (296) (151) -
Amortization of prior service cost 367 328 328
Amortization of transition (asset) or obligation 1,315 1,337 1,337
--------- --------- ---------
Net periodic benefit cost $ 5,093 $ 5,202 $ 5,414
--------- --------- ---------
--------- --------- ---------
FAS88 special charges
Curtailment (gain)/loss $ 1,005 $ - $ -
Prior service cost recognized 124 - -
Special termination benefits 2,855 - -
--------- --------- ---------
Total FAS88 charges $ 3,984 $ - $ -
--------- --------- ---------
--------- --------- ---------
On May 4, 1998, LG&E Energy and KU Energy merged, with LG&E Energy as the
surviving corporation. During 1998, LG&E incurred approximately $18 million in
special termination pension benefits as a result of its early retirement program
offered to eligible employees post-merger.
The assumptions used in the measurement of LG&E's pension benefit obligation are
shown in the following table:
1998 1997 1996
---- ---- ----
Weighted-average assumptions as of December 31:
Discount rate 7.00% 7.00% 7.75%
Expected long-term rate of return on plan assets 8.50% 8.50% 8.50%
Rate of compensation increase 3.50%-4.00% 2.00%-4.00% 2.00%-4.25%
For measurement purposes, a 7% annual increase in the per capita cost of covered
health care benefits was assumed for 1999. The rate was assumed to decrease each
year to 4.25% for 2005 and remain at that level thereafter.
142
Assumed health care cost trend rates have a significant effect on the amounts
reported for the health care plans. A 1% change in assumed health care cost
trend rates would have the following effects (in thousands of $):
1% Decrease 1% Increase
----------- -----------
Effect on total of service and interest cost components for 1998 $ 122 $ 146
Effect on year-end 1998 postretirement benefit obligations 1,188 1,971
THRIFT SAVINGS PLANS. LG&E has a thrift savings plan under section 401(k) of the
Internal Revenue Code. Under the plan, eligible employees may defer and
contribute to the plan a portion of current compensation in order to provide
future retirement benefits. LG&E makes contributions to the plan by matching a
portion of the employee contributions. The costs were approximately $2.4 million
for 1998 and $1.8 million for each of 1997 and 1996.
NOTE 8 - INCOME TAXES
Components of income tax expense are shown in the table below (in thousands
of $):
1998 1997 1996
---- ---- ----
Included in operating expenses:
Current - federal $45,716 $57,590 $33,823
- state 11,895 14,593 7,685
Deferred - federal - net 2,276 (4,565) 19,161
- state - net 678 703 6,587
Deferred investment tax credit 55 102 409
Amortization of investment tax credit (4,313) (4,342) (4,406)
-------- -------- --------
Total 56,307 64,081 63,259
Included in other income and (deductions):
Current - federal 660 1,484 196
- federal - merger costs (6,758) - -
- state 6 161 (96)
- state - merger costs (1,737) - -
Deferred - federal - net (165) 292 246
- state - net (42) 75 61
-------- -------- --------
Total (8,036) 2,012 407
-------- -------- --------
Total income tax expense $48,271 $66,093 $63,666
-------- -------- --------
-------- -------- --------
143
Net deferred tax liabilities resulting from book-tax temporary differences are
shown below (in thousands of $):
1998 1997
---- ----
Deferred tax liabilities:
Depreciation and other
plant-related items $323,869 $321,442
Other liabilities 9,644 6,702
--------- ---------
333,513 328,144
--------- ---------
Deferred tax assets:
Investment tax credit 28,876 30,595
Income taxes due to customers 25,447 26,357
Pension overfunding 2,099 7,265
Accrued liabilities not currently
deductible and other 22,502 14,076
--------- ---------
78,924 78,293
--------- ---------
Net deferred income tax liability $254,589 $249,851
--------- ---------
--------- ---------
A reconciliation of differences between the statutory U.S. federal income tax
rate and LG&E's effective income tax rate follows:
1998 1997 1996
---- ---- ----
Statutory federal income tax rate 35.0% 35.0% 35.0%
State income taxes net of federal benefit 5.5 5.7 5.4
Amortization of investment tax credit (3.4) (2.4) (2.6)
Nondeductible merger expenses 2.4 - -
Other differences - net (1.3) (1.5) (.7)
----- ----- -----
Effective income tax rate 38.2% 36.8% 37.1%
----- ----- -----
----- ----- -----
NOTE 9 - OTHER INCOME AND DEDUCTIONS
Other income and deductions consisted of the following at December 31 (in
thousands of $):
1998 1997 1996
---- ---- ----
Interest and dividend income $ 4,245 $ 4,786 $ 4,096
Interest on income tax settlement - 1,446 -
Gain on sale of stock options - 1,794 -
Gains (losses) on fixed asset disposal 530 77 (36)
Donations (168) (147) (150)
Income taxes and other (2,111) (3,679) (2,990)
Income tax benefit on merger costs to achieve 8,495 - -
--------- --------- ---------
Total other income and deductions $ 10,991 $ 4,277 $ 920
--------- --------- ---------
--------- --------- ---------
NOTE 10 - FIRST MORTGAGE BONDS AND POLLUTION CONTROL BONDS
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
144
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
1999 sinking fund requirements of the First Mortgage Bonds.
The trust indenture securing the 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 (Louisville Gas and Electric Company 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.
On June 1, 1998, LG&E's First Mortgage Bonds, 6.75% Series of $20 million
matured and were retired by LG&E.
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 3.09%
and 3.39%, respectively, at December 31, 1998. 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.
LG&E's First Mortgage Bonds, 7.5% Series of $20 million is scheduled to
mature in 2002, and the $42.6 million, 6% Series is scheduled for maturity in
2003. There are no scheduled maturities of Pollution Control Bonds for the
five years subsequent to December 31, 1998. LG&E has no cash sinking fund
requirements.
NOTE 11 - NOTES PAYABLE
LG&E had no notes payable at December 31, 1998, and 1997.
At December 31, 1998, LG&E had unused lines of credit of $200 million, for
which it pays commitment fees. The credit facility provides for short-term
borrowings and support of variable rate Pollution Control Bonds. The credit
lines are scheduled to expire in 2001. Management expects to renegotiate
these lines when they expire.
NOTE 12 - COMMITMENTS AND CONTINGENCIES
CONSTRUCTION PROGRAM. LG&E had commitments in connection with its
construction program aggregating approximately $8 million at December 31,
1998. Construction expenditures for the years 1999 and 2000 are estimated to
total approximately $384 million.
145
OPERATING LEASE. LG&E leases office space and accounts for all of its office
space leases as operating leases. Total lease expense for 1998, 1997, and
1996, less amounts contributed by the parent company, was $1.6 million, $1.8
million, and $1.9 million, respectively. The future minimum annual lease
payments under lease agreements for years subsequent to December 31, 1998,
are as follows (in thousands of $):
1999 $ 3,055
2000 3,321
2001 3,654
2002 3,594
2003 3,507
Thereafter 5,260
---------
Total $22,391
---------
---------
ENVIRONMENTAL. In September 1998, the U.S. Environmental Protection Agency
(USEPA) announced its final regulation requiring significant additional
reductions in nitrogen oxide (NOx) emissions to mitigate alleged ozone
transport to the Northeast. While each state is free to allocate its assigned
NOx reductions among various emissions sectors as it deems appropriate, the
regulation may ultimately require utilities to reduce their NOx emissions to
0.15 lb./mmBtu (million British thermal units ) - an 85% reduction from 1990
levels. Under the regulation, each state must incorporate the additional NOx
reductions in its State Implementation Plan (SIP) by September 1999 and
affected sources must install control measures by May 2003, unless granted
extensions. Several states, various labor and industry groups, and individual
companies have appealed the final regulation to the U.S. Court of Appeals for
the D.C. Circuit. Management is currently unable to determine the outcome or
exact impact of this matter until such time as the states identify specific
emissions reductions in their SIP and the courts rule on the various legal
challenges to the final rule. However, if the 0.15 lb. target is ultimately
imposed, LG&E will be required to incur significant capital expenditures and
increased operation and maintenance costs for additional controls.
Subject to further study and analysis, LG&E estimates that it may incur
capital costs in the range of $100 million to $200 million. These costs would
generally be incurred beginning in 2000. LG&E believes its costs in this
regard to be comparable to those of similarly situated utilities with like
generation assets. LG&E anticipates that such capital and operating costs are
the type of costs that are eligible for cost recovery from customers under
its environmental surcharge mechanism and believes that 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.
LG&E is also addressing other air quality issues. First, LG&E is monitoring
USEPA's implementation of the revised National Ambient Air Quality Standards
(NAAQS) for ozone and particulate matter. Until USEPA completes additional
implementation steps, including monitoring and nonattainment designations,
management is unable to determine the precise impact of the revised
standards. Second, LG&E is conducting modeling activities at its Cane Run
Station in response to notifications from regulatory agencies that the plant
may be the source of potential exceedances of the NAAQS for sulfur dioxide
(SO2). Depending on future regulatory determinations, LG&E may be required to
undertake corrective action that could include significant capital
expenditures or emissions limitations. Third, LG&E is working with regulatory
authorities to review the effectiveness of remedial measures aimed at
controlling particulate emissions from its Mill Creek Station. LG&E
previously settled a number of property damage claims from adjacent residents
and completed significant plant modifications as part of its ongoing capital
construction program. LG&E is currently awaiting a final regulatory
determination regarding remedial measures. In management's opinion,
resolution of any remaining property damage claims from adjacent residents
should not have a material adverse impact on the financial position or
results of operations of LG&E.
147
LG&E is addressing potential liabilities for the cleanup of properties where
hazardous substances may have been released. LG&E has identified
contamination at certain manufactured gas plant (MGP) sites currently or
formerly owned by LG&E. LG&E is negotiating with state agencies with respect
to cleanup of a site owned by LG&E. In agreements reached in 1996 and 1998
with the current owners of two sites formerly owned by LG&E, the current
owners of those sites have expressly agreed to assume responsibility for
environmental liabilities in return for an aggregate payment of $400,000.
Until conclusion of discussions with state agencies regarding the site
currently owned by LG&E, management is unable to precisely determine
remaining liability for cleanup costs at MGP sites. However, management
estimates total cleanup costs to be $3 million. Accordingly, an accrual of $3
million has been recorded in the accompanying financial statements.
LG&E, along with other companies, has been identified by USEPA as potentially
responsible parties allegedly liable for cleanup of certain off-site disposal
facilities under the Comprehensive Environmental Response Compensation and
Liability Act. LG&E has entered into final settlements for an aggregate of
$150,000 resolving liability in these matters.
NOTE 13 - 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 and Indiana Municipal Power Agency (IMPA)
owns a 12.88% undivided interest. Each is responsible for their proportionate
ownership share of fuel cost, operation and maintenance expenses, and
incremental assets.
The following data represent shares of the jointly owned property:
Trimble County
LG&E IMPA IMEA TOTAL
---- ---- ---- -----
Ownership interest 75% 12.88% 12.12% 100%
Mw capacity 371.25 63.75 60 495
147
NOTE 14 - SEGMENTS OF BUSINESS AND RELATED INFORMATION
Effective December 31, 1998, LG&E adopted Statements of Financial Accounting
Standards No. 131, Disclosure About Segments of an Enterprise and Related
Information. LG&E is a regulated public utility engaged in the generation,
transmission, distribution, and sale of electricity and the storage,
distribution, and sale of natural gas. Financial data for business segments,
follow (in thousands of $):
Electric Gas Total
1998
Operating revenues $ 658,511(a) $191,545 $ 850,056
Depreciation and amortization 79,866 13,312 93,178
Interest income 3,566 679 4,245
Interest expense 30,389 5,933 36,322
Merger costs to achieve 32,072 - 32,072
Income taxes 56,401 (94) 56,307
Net income 75,368 2,752 78,120
Total assets 1,727,463 377,174 2,104,637
Construction expenditures 105,836 32,509 138,345
1997
Operating revenues $ 614,532 $231,011 $ 845,543
Depreciation and amortization 79,958 13,062 93,020
Interest income 5,279 953 6,232
Interest expense 33,349 5,841 39,190
Income taxes 59,415 4,666 64,081
Net income 108,236 5,037 113,273
Total assets 1,677,278 378,363 2,055,641
Construction expenditures 81,713 29,180 110,893
1996
Operating revenues $ 606,696 $214,419 $ 821,115
Depreciation and amortization 76,929 12,073 89,002
Interest income 3,520 576 4,096
Interest expense 34,566 5,676 40,242
Income taxes 58,448 4,811 63,259
Net income 100,119 7,822 107,941
Total assets 1,673,857 332,855 2,006,712
Construction expenditures 79,541 28,338 107,879
(a) Net of provision for rate refund of $4.5 million.
148
NOTE 15 - SELECTED QUARTERLY DATA (UNAUDITED)
Selected financial data for the four quarters of 1998 and 1997 are shown below.
Because of seasonal fluctuations in temperature and other factors, results for
quarters may fluctuate throughout the year.
Quarters Ended
March June September December
----- ---- --------- --------
(Thousands of $)
1998
Operating revenues $233,344 $201,389 $229,885 $185,438
Net operating income 32,326 33,629 53,420 16,148
Net income 23,399 21 44,861 9,839
Net income (loss) available
for common stock 22,276 (1,122) (a) 43,726 8,672(b)
1997
Operating revenues $225,399 $180,276 $208,435 $231,433
Net operating income 32,895 30,422 46,562 38,307
Net income 23,967 21,487 37,223 30,596
Net income (loss) available
for common stock 22,840 20,326 36,077 29,445
(a) The decrease of $21.5 million compared to June 1997 was due to a
non-recurring after-tax charge of $23.6 million from
merger-related expenses offset by increased electric sales caused
by warmer weather.
(b) The decrease of $20.8 million compared to December 1997 was due to
a non-recurring charge to refund certain amounts collected under
the Environmental Cost Recovery surcharge, decreased gas sales due
to warmer weather and higher operating expenses at the electric
generating stations.
NOTE 16 - SUBSEQUENT EVENT
On March 8,1999, the Kentucky Industrial Utility Customers (KIUC) filed a
complaint with the Kentucky Commission alleging that LG&E's electric rates are
excessive and should be reduced by an amount between $43 and $90 million and
that the Kentucky Commission establish a proceeding to reduce LG&E's electric
rates. LG&E has asked the Kentucky Commission to dismiss the complaint. LG&E is
not able to predict the ultimate outcome of these proceedings, however, should
the Commission mandate significant rate reductions at LG&E, through the PBR
proposal or otherwise, such actions could have a material effect on LG&E's
financial condition and results of operations.
On March 11, 1999, the Commission denied LG&E's Petition for Rehearing for the
period November 1994 through October 1996 and directed LG&E to reduce future
fuel expense by $1.9 million in the first billing month after the Order. The
Company is considering the filing of an Appeal with the Franklin Circuit Court.
In a separate series of Orders on March 11,1999, the PSC granted LG&E's Petition
for Rehearing for the period November 1996 through April 1998 and established a
procedural schedule for LG&E and other parties to submit evidence and for a
hearing before the Commission. In the same Orders the PSC granted the Petition
for Rehearing of the KIUC to determine if interest should be paid on any fuel
refunds for this latter period.
149
Louisville Gas and Electric Company
REPORT OF MANAGEMENT
The management of Louisville Gas and Electric Company is responsible for the
preparation and integrity of the financial statements and related information
included in this Annual Report. These statements have been prepared in
accordance with generally accepted accounting principles applied on a
consistent basis and, necessarily, include amounts that reflect the best
estimates and judgment of management.
LG&E's financial statements have been audited by Arthur Andersen LLP,
independent public accountants. Management has made available to Arthur
Andersen LLP all LG&E's financial records and related data as well as the
minutes of shareholders' and directors' meetings. Management has established
and maintains a system of internal controls that provides reasonable
assurance that transactions are completed in accordance with management's
authorization, that assets are safeguarded and that financial statements are
prepared in conformity with generally accepted accounting principles.
Management believes that an adequate system of internal controls is
maintained through the selection and training of personnel, appropriate
division of responsibility, establishment and communication of policies and
procedures and by regular reviews of internal accounting controls by LG&E's
internal auditors. Management reviews and modifies its system of internal
controls in light of changes in conditions and operations, as well as in
response to recommendations from the internal auditors. These recommendations
for the year ended December 31, 1998, did not identify any material
weaknesses in the design and operation of LG&E's internal control structure.
The Audit Committee of the Board of Directors is composed entirely of outside
directors. In carrying out its oversight role for the financial reporting and
internal controls of LG&E, the Audit Committee meets regularly with LG&E's
independent public accountants, internal auditors and management. The Audit
Committee reviews the results of the independent accountants' audit of the
financial statements and their audit procedures, and discusses the adequacy
of internal accounting controls. The Audit Committee also approves the annual
internal auditing program and reviews the activities and results of the
internal auditing function. Both the independent public accountants and the
internal auditors have access to the Audit Committee at any time.
Louisville Gas and Electric Company maintains and internally communicates a
written code of business conduct that addresses, among other items, potential
conflicts of interest, compliance with laws, including those relating to
financial disclosure and the confidentiality of proprietary information.
150
Louisville Gas and Electric Company
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders of Louisville Gas and Electric Company:
We have audited the accompanying balance sheets and statements of
capitalization of Louisville Gas and Electric Company (a Kentucky corporation
and a wholly-owned subsidiary of LG&E Energy Corp.) as of December 31, 1998
and 1997, and the related statements of income, retained earnings, cash flows
and comprehensive income for each of the three years in the period ended
December 31, 1998. These financial statements are the responsibility of
LG&E'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 financial statements referred to above present fairly, in
all material respects, the financial position of Louisville Gas and Electric
Company as of December 31, 1998 and 1997, and the results of its operations
and its cash flows for each of the three years in the period ended December
31, 1998, in conformity with generally accepted accounting principles.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedule listed under Item 14(a)2
is presented for purposes of complying with the Securities and Exchange
Commission's rules and is not part of the basic financial statements. This
schedule has been subjected to the auditing procedures applied in the audit
of the basic financial statements and, in our opinion, fairly states in all
material respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.
Louisville, Kentucky Arthur Andersen LLP
January 27, 1999 (Except with respect
to the matters discussed in the eighth
and ninth paragraphs of Note 3, as to
which the date is February 12, 1999,
and Note 16, as to which the date is
March 11, 1999.)
151
Kentucky Utilities Company
Statements of Income
(Thousands of $)
Years Ended December 31
1998 1997 1996
---- ---- ----
OPERATING REVENUES:
Electric.......................................................... $ 831,614 $ 716,437 $ 711,711
Provision for rate refund (Note 3)................................ (21,500) - -
--------- --------- ---------
Total operating revenues (Note 1).............................. 810,114 716,437 711,711
--------- --------- ---------
OPERATING EXPENSES:
Fuel, principally coal, used in generation........................ 217,401 188,439 198,198
Power purchased................................................... 126,584 72,542 62,490
Other operation expenses.......................................... 121,275 120,951 122,872
Maintenance....................................................... 63,608 64,990 64,161
Depreciation and amortization..................................... 86,657 84,111 80,424
Federal and state income taxes (Note 7)........................... 53,256 51,690 51,452
Property and other taxes.......................................... 15,945 15,306 14,777
--------- --------- ---------
Total operating expenses....................................... 684,726 598,029 594,374
--------- --------- ---------
Net operating income.................................................. 125,388 118,408 117,337
Merger costs to achieve (Note 2)...................................... 21,830 - -
Interest and dividend income.......................................... 1,811 1,673 1,733
Other income and (deductions) (Note 8)................................ 6,035 5,330 6,710
Interest charges...................................................... 38,640 39,698 39,617
--------- --------- ---------
Net income............................................................ 72,764 85,713 86,163
Preferred stock dividends............................................. 2,256 2,256 2,256
--------- --------- ---------
Net income available for common stock................................. $ 70,508 $ 83,457 $ 83,907
--------- --------- ---------
--------- --------- ---------
Statements of Retained Earnings
(Thousands of $)
Years Ended December 31
1998 1997 1996
---- ---- ----
Balance January 1..................................................... $304,750 $287,852 $268,992
Add net income........................................................ 72,764 85,713 86,163
-------- -------- --------
377,514 373,565 355,155
Deduct: Cash dividends declared on stock:
4.75% cumulative preferred............................... 950 950 950
6.53% cumulative preferred............................... 1,306 1,306 1,306
Common................................................... 76,091 66,559 65,047
-------- -------- --------
78,347 68,815 67,303
-------- -------- --------
Balance December 31................................................... $299,167 $304,750 $287,852
-------- -------- --------
-------- -------- --------
The accompanying notes are an integral part of these financial statements.
152
Kentucky Utilities Company
Balance Sheets
(Thousands of $)
December 31
1998 1997
---- ----
ASSETS:
Utility plant, at original cost................................................. $2,602,167 $2,552,695
Less: reserve for depreciation................................................. 1,208,183 1,128,282
---------- ----------
1,393,984 1,424,413
Construction work in progress................................................... 83,361 58,939
---------- ----------
1,477,345 1,483,352
---------- ----------
Other property and investments - less reserve................................... 14,238 12,808
Current assets:
Cash and temporary cash investments......................................... 59,071 5,453
Accounts receivable - less reserve of $520 in 1998 and 1997................. 106,003 74,524
Materials and supplies - at average cost:
Fuel (predominantly coal)................................................ 23,927 27,799
Other.................................................................... 24,877 24,466
Prepayments and other....................................................... 5,022 4,951
---------- ----------
218,900 137,193
---------- ----------
Deferred debits and other assets:
Unamortized debt expense.................................................... 5,227 5,628
Regulatory assets (Note 3).................................................. 28,228 14,771
Other ..................................................................... 19,859 26,128
---------- ----------
53,314 46,527
---------- ----------
$1,763,797 $1,679,880
---------- ----------
---------- ----------
CAPITAL AND LIABILITIES:
Capitalization (see statements of capitalization):
Common equity............................................................... $ 606,713 $ 612,295
Cumulative preferred stock.................................................. 40,000 40,000
Long-term debt.............................................................. 546,330 546,351
---------- ----------
1,193,043 1,198,646
---------- ----------
Current liabilities:
Long-term debt due within one year.......................................... - 21
Notes payable............................................................... - 33,600
Accounts payable............................................................ 100,012 33,386
Provision for rate refund................................................... 21,500 -
Dividends declared.......................................................... 18,188 188
Accrued taxes............................................................... 16,733 7,473
Accrued interest............................................................ 8,110 8,283
Other ..................................................................... 31,226 26,216
---------- ----------
195,769 109,167
---------- ----------
Deferred credits and other liabilities:
Accumulated deferred income taxes (Note 7).................................. 247,088 245,150
Investment tax credit, in process of amortization........................... 22,302 26,131
Accumulated provision for pensions and related benefits..................... 50,044 41,334
Customers' advances for construction........................................ 1,265 1,464
Regulatory liability (Note 3)............................................... 45,882 51,576
Other ..................................................................... 8,404 6,412
---------- ----------
374,985 372,067
---------- ----------
Commitments and contingencies (Note 11)
$1,763,797 $1,679,880
---------- ----------
---------- ----------
The accompanying notes are an integral part of these financial statements.
153
Kentucky Utilities Company
Statements of Cash Flows
(Thousands of $)
Years Ended December 31
1998 1997 1996
---- ---- ----
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income........................................................ $ 72,764 $ 85,713 $ 86,163
Items not requiring cash currently:
Depreciation and amortization.................................. 86,657 84,111 80,424
Deferred income taxes - net.................................... (2,437) 4,606 3,750
Investment tax credit - net.................................... (3,829) (4,036) (4,013)
Deferred merger-related costs.................................. (14,322) (4,062) -
Change in certain net current assets and liabilities:
Accounts receivable............................................ (31,479) 297 2,551
Fuel inventory................................................. 3,872 3,095 (1,456)
Materials and supplies......................................... (411) (1,755) 1,764
Accounts payable............................................... 66,626 4,426 (9,040)
Provision for rate refund...................................... 21,500 - -
Accrued taxes.................................................. 9,260 2,090 182
Accrued interest............................................... (173) 235 492
Prepayments and other.......................................... 71 (1,481) 278
Other............................................................. 49,321 5,667 10,702
---------- ---------- ----------
Net cash flows from operating activities....................... 257,420 178,906 171,797
---------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds form insurance reimbursement............................. 179 4,270 257
Construction expenditures......................................... (91,992) (94,006) (106,503)
Other............................................................. - - (79)
---------- ---------- ----------
Net cash flows from investing activities....................... (91,813) (89,736) (106,325)
---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term borrowings............................................. 381,500 2,645,500 2,570,200
Repayments of short-term borrowings............................... (415,100) (2,666,100) (2,571,600)
Issuance of first mortgage bonds.................................. - - 39,445
Repayment of first mortgage bonds................................. (42) (21) (36,192)
Payment of dividends.............................................. (78,347) (68,815) (67,303)
---------- ---------- ----------
Net cash flows from financing activities....................... (111,989) (89,436) (65,450)
---------- ---------- ----------
Change in cash and temporary cash investments......................... 53,618 (266) 22
Cash and temporary cash investments at beginning of year.............. 5,453 5,719 5,697
---------- ---------- ----------
Cash and temporary cash investments at end of year.................... $ 59,071 $ 5,453 $ 5,719
---------- ---------- ----------
---------- ---------- ----------
Supplemental disclosures of cash flow information: Cash paid during the year
for:
Income taxes................................................... $ 46,490 $ 44,857 $ 47,539
Interest on borrowed money..................................... 36,008 37,053 36,729
The accompanying notes are an integral part of these financial statements.
154
Kentucky Utilities Company
Statements of Capitalization
(Thousands of $)
December 31
1998 1997
---- ----
COMMON EQUITY:
Common stock, without par value -
outstanding 37,817,878 shares, respectively.................................. $ 308,140 $ 308,140
Retained earnings............................................................... 299,168 304,750
Other........................................................................... (595) (595)
---------- ----------
606,713 612,295
---------- ----------
CUMULATIVE PREFERRED STOCK:
Redeemable on 30 days notice by KU, except 6.53% series
Shares Current
Outstanding Redemption Price
----------- ----------------
Without par value, 5,300,000 shares authorized -
4.75% series.................................. 200,000 100.00 20,000 20,000
6.53% series.................................. 200,000 Not redeemable 20,000 20,000
---------- ----------
40,000 40,000
---------- ----------
LONG-TERM DEBT (Note 10):
First mortgage bonds -
Q due June 15, 2000, 5.95%................................................... 61,500 61,500
Q due June 15, 2003, 6.32%................................................... 62,000 62,000
S due January 15, 2006, 5.99%................................................ 36,000 36,000
P due May 15, 2007, 7.92%.................................................... 53,000 53,000
R due June 1, 2025, 7.55%.................................................... 50,000 50,000
P due May 15, 2027, 8.55%.................................................... 33,000 33,000
Pollution control series:
1B due February 1, 2018, 6.25%........................................... 20,930 20,930
2B due February 1, 2018, 6.25%........................................... 2,400 2,400
3B due February 1, 2018, 6.25%........................................... 7,200 7,200
4B due February 1, 2018, 6.25%........................................... 7,400 7,400
7, due May 1, 2010, 7.38%................................................ 4,000 4,000
7, due May 1, 2020, 7.60%................................................ 8,900 8,900
8, due September 15, 2016, 7.45%......................................... 96,000 96,000
9, due December 1, 2023, 5.75%........................................... 50,000 50,000
10, due November 1, 2024, variable....................................... 54,000 54,000
---------- ----------
Total first mortgage bonds............................................ 546,330 546,330
8% secured note, due January 5, 1999 (net of current maturity).................. - 21
---------- ----------
Total long-term bonds........................................................ 546,330 546,351
---------- ----------
Total capitalization......................................................... $1,193,043 $1,198,646
---------- ----------
---------- ----------
The accompanying notes are an integral part of these financial statements.
155
Kentucky Utilities Company
Notes to Financial Statements
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Kentucky Utilities Company (KU) is a subsidiary of LG&E Energy Corp. KU is a
regulated public utility that is engaged in the generation, transmission,
distribution, and sale of electric energy. Effective May 4, 1998, following
the receipt of all required state and federal regulatory approvals, LG&E
Energy Corp. (LG&E Energy) and KU Energy Corporation (KU Energy) merged, with
LG&E Energy as the surviving corporation. LG&E Energy is an exempt energy
services holding company with wholly-owned subsidiaries consisting of KU,
Louisville Gas and Electric Company (LG&E) and LG&E Capital Corp (Capital
Corp.) All of KU's Common Stock is held by LG&E Energy.
Certain reclassifications have been made to the 1997 and 1996 financial
statements to conform to the 1998 presentation with no impact on previously
reported income.
UTILITY PLANT. 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. 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. Depreciation is provided on the straight-line method over the
estimated service lives of depreciable plant. The amounts provided for KU
approximated 3.5% in 1998, 1997 and 1996.
CASH AND TEMPORARY CASH INVESTMENTS. KU 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.
DEBT EXPENSE. 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 KU'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 rise to the credits.
REVENUE RECOGNITION. Revenues are recorded based on service rendered to
customers through month-end. KU accrues an estimate for unbilled revenues
from each meter reading date to the end of the accounting period.
FUEL COSTS. The cost of fuel for electric generation is charged to expense
as used.
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
156
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
11, Commitments and Contingencies, for a further discussion.
NEW ACCOUNTING PRONOUNCEMENTS. During 1998, KU adopted the following
accounting pronouncements:
Statements of Financial Accounting Standards No. 132, Employers' Disclosures
about Pensions and Other Post retirement Benefits (SFAS No. 132), effective
for periods beginning after December 15, 1997. Pursuant to SFAS No. 132, KU
has disclosed additional information on changes in benefit obligations and
fair values of plan assets and eliminated certain disclosures that are no
longer relevant. This standard does not change the measurement or financial
statement recognition of the plans (See Note 6, Pension Plans and Retirement
Benefits).
Statement of Position No 98-1, Accounting for the Costs of Computer Software
Developed or Obtained for Internal Use (SOP 98-1), adopted January 1, 1998.
SOP 98-1 clarifies the criteria for capital or expense treatment of costs
incurred by an enterprise to develop or obtain computer software to be used
in its internal operations. The statement does not change treatment of costs
incurred in connection with correcting computer programs to properly process
the millennium change to the Year 2000, which must be expensed as incurred.
Adoption of SOP 98-1 did not have a material effect on KU's financial
statements.
The following accounting pronouncements have been issued but are not yet
effective:
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 use hedge accounting. KU is currently
analyzing the provisions of the statement and cannot predict the impact this
statement will have on its operations and financial position; however, the
statement could increase volatility in earnings. The effect of this statement
will be recorded in cumulative effect of change in accounting when adopted.
The Emerging Issues Task Force issue No. 98-10, Accounting for Energy Trading
and Risk Management Activities (EITF No. 98-10), which is effective for
fiscal years beginning after December 15, 1998. The task force concluded that
energy trading contracts should be recorded at mark to market on the balance
sheet, with the gains and losses shown net in the income statement. EITF
98-10 more broadly defines what represents energy trading to include economic
activities related to physical assets which were not previously recorded at
mark to market by established industry practice. The effects of adopting EITF
No. 98-10, if applicable, will be reported as a cumulative effect of a change
in accounting principle with no prior period restatement. KU does not expect
the adoption of EITF No. 98-10 to have a material adverse impact on its
operations and financial position.
NOTE 2 - LG&E - KENTUCKY UTILITIES MERGER
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, LG&E Energy, which is the
parent of LG&E, became the parent company of KU. The operating utility
subsidiaries (LG&E and KU) have continued to maintain their separate corporate
identities and serve customers in Kentucky and Virginia under their present
names. LG&E Energy has estimated approxi-
157
mately $760 million in gross non-fuel savings over a ten-year period
following the merger. Costs to achieve these savings of $42.3 million were
recorded in the second quarter of 1998, $20.5 million of which were initially
deferred and are being amortized over a five-year period pursuant to
regulatory orders. Primary components of the merger costs were separation
benefits, relocation costs, and transaction fees, the majority of which were
paid by December 31, 1998. KU expensed the remaining costs associated with
the merger in the second quarter of 1998. In regulatory filings associated
with approval of the merger, KU committed not to seek increases in existing
base rates and proposed reductions in their retail customers' bills in
amounts based on one-half of the net savings, net of the deferred and
amortized amount, over a five-year period. The preferred stock and debt
securities of the operating utility subsidiaries were not affected by the
merger. The non-utility subsidiaries of KU Energy have become subsidiaries of
Capital Corp.
Under the terms of the Agreement and Plan of Merger dated May 20, 1997 (the
Merger Agreement) each outstanding share of the common stock, without par
value, of KU Energy (KU Common Stock) 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 Energy common stock outstanding. Based on such capitalization,
immediately following the merger, 51.3% of the outstanding LG&E Energy common
stock was owned by the shareholders of LG&E Energy prior to the merger and
48.7% was owned by former KU Energy shareholders.
Regulatory and administrative approvals were obtained from the Federal Energy
Regulatory Commission (FERC), the Federal Trade Commission, the Securities
and Exchange Commission, the Virginia State Corporation Commission and the
stockholders of LG&E Energy and KU Energy prior to the effective date of the
merger. LG&E Energy, as the parent of LG&E and KU, continues to be an exempt
holding company under the Public Utility Holding Company Act of 1935.
Management has accounted for the merger as a pooling of interests and as a
tax-free reorganization under the Internal Revenue Code.
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 $38.6 million or 50% of the originally estimated costs to achieve such
savings, be applied to reduce customer rates through a surcredit on
customers' bills and the remaining 50% be retained by the companies. The
Commission approved the surcredit and allocated the customer savings 53% to
KU and 47% to LG&E. The surcredit will be about 2% of customer bills over the
next five years and will amount to approximately $63 million in net non-fuel
savings to KU customers. Any fuel cost savings are passed to Kentucky
customers through KU's fuel adjustment clause.
158
NOTE 3 - 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 FERC, the Kentucky Commission and the Virginia
Commission. KU is subject to Statement of Financial Accounting Standards No.
71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71).
Under SFAS No. 71, certain costs that would otherwise be charged to expense
are deferred as regulatory assets based on expected recovery from customers
in future rates. Likewise, certain credits that would otherwise be reflected
as income are deferred as regulatory liabilities based on expected flowback
to customers in future rates. 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 on the balance sheet as of
December 31 (in thousands of $):
1998 1997
---- ----
Unamortized loss on bonds $ 8,675 $ 9,756
Merger costs 18,417 4,062
Other 1,136 953
--------- ---------
Total regulatory assets 28,228 14,771
Deferred income taxes - net (45,882) (51,576)
Other regulatory liability (670) (673)
--------- ---------
Regulatory assets and (liabilities) - net $(18,324) $(37,478)
--------- ---------
--------- ---------
ENVIRONMENTAL COST RECOVERY. In August 1994, KU implemented an environmental
cost recovery (ECR) surcharge to recover certain environmental compliance
costs, including costs to comply with the 1990 Clean Air Act, as amended, as
well as, other environmental regulations, including those applicable to coal
combustion wastes and related by-products. The ECR mechanism was authorized
by state statute in 1992 and was first approved by the Kentucky Commission in
July 1994.
The Commission's order approving the surcharge in the KU case and the
constitutionality of the surcharge was challenged by certain intervenors,
including the Attorney General of Kentucky, in Franklin Circuit Court.
Decisions of the Circuit Court and the Kentucky Court of Appeals in July 1995
and December 1997, respectively, have upheld the constitutionality of the ECR
statute but differed on a claim of retroactive recovery of certain amounts.
The Commission ordered that certain surcharge revenues collected by KU be
subject to refund pending final determination of all appeals.
On December 19, 1998, the Kentucky Supreme Court rendered an opinion
upholding the constitutionality of the surcharge statute. The decision,
however, reversed the ruling of the Court of Appeals on the retroactivity
claim, thereby denying recovery of costs associated with pre-1993
environmental projects through the ECR. The court remanded the case to the
Commission to determine the proper adjustments to refund amounts collected
for such pre-1993 environmental projects. The parties to the proceeding have
notified the Commission that they have reached agreement as to the terms,
refund amounts, refund procedure and forward application of the ECR. The
settlement agreement is subject to Commission approval. KU recorded a
provision for rate refund of $21.5 million in December 1998.
FUEL ADJUSTMENT CLAUSE. KU employs a fuel adjustment clause (FAC) mechanism,
which under Kentucky law allows the company to recover from customers, the
actual fuel costs associated with retail electric sales. As of February 12,
1999, LG&E, a subsidiary of LG&E Energy Corp., received orders from the
Kentucky Commission requiring a refund to retail electric customers which
resulted from reviews of the FAC from November 1994 through April 1998. The
orders changed the method of assigning fuel costs associated with electric
line losses on off-system sales appropriate for recovery through the FAC. The
orders require these
159
amounts to be refunded to customers during first quarter 1999 and to include
in the FAC calculation the cost of fuel associated with line losses incurred
in making off-system sales. KU has not received an order from the Kentucky
Commission but anticipates that it will be required to refund to retail
electric customers of approximately $3.5 million for the review period
November 1994 through December 1998. Management does not believe final
resolution of these proceedings will have a material adverse effect on KU's
financial position or results of operations.
FUTURE RATE REGULATION. In October 1998, LG&E and KU filed separate but
parallel with the Commission for approval of a new method of determining
electric rates that provides financial incentives for LG&E and KU to further
reduce customers' rates. The filing was made pursuant to the September 1997
Commission order approving the merger of LG&E Energy and KU Energy, wherein
the Commission directed LG&E and KU to indicate whether it desired to remain
under traditional rate of return regulation or commence non-traditional
regulation. The new ratemaking method, known as performance-based ratemaking
(PBR), would include financial incentives for LG&E and KU to reduce fuel
costs and increase generating efficiency, and to share any resulting savings
with customers. Additionally, the PBR provides financial penalties and
rewards to assure continued high quality service and reliability.
The PBR plan proposed by LG&E and KU consists of five components:
1) The utilities' fuel adjustment clause mechanism will be withdrawn and
replaced with a cap that limits recovery of actual changes in fuel cost
to changes in a fuel price index for a five-state region. If the
utilities outperform the index, benefits will be shared equally between
shareholders and customers. If the utilities' fuel costs exceed the
index, the difference will be absorbed by LG&E Energy's shareholders.
2) Customers will continue to receive the benefits from the post-merger
joint dispatch of power from LG&E's and KU's generating plants.
3) Power plant performance will be measured against the best performance
achieved between 1991 and 1997. If the performance exceeds this level,
customers will share equally with LG&E Energy's shareholders in up to
$10 million annually of benefits from this performance at each of LG&E
and KU.
4) The utilities will be encouraged to maintain and improve service
quality, reliability, customer satisfaction and safety, which will be
measured against six objective benchmarks. The plan provides for annual
rewards or penalties to LG&E Energy of up to $5 million per year at
each of LG&E and KU.
5) The plan provides KU with greater flexibility to customize rates and
services to meet customer needs. Services will continue to be priced
above marginal cost and customers will continue to have the option to
elect standard tariff service.
These proposals are subject to approval by the Commission. Approval
proceedings commenced in October 1998 and a final decision likely will occur
in 1999. Several intervenors are participating in the case. Some have
requested the Commission to reduce base rates before implementing PBR. KU is
not able to predict the ultimate outcome of these proceedings, however,
should the Commission mandate significant rate reductions at KU, through the
PBR proposal or otherwise, such actions could have a material effect on KU's
financial condition and result of operations.
KENTUCKY PSC ADMINISTRATIVE CASE FOR AFFILIATE TRANSACTIONS. In December
1997, the Kentucky Commission opened Administrative Case No. 369 to consider
Commission policy regarding cost allocations, affiliate transactions and
codes of conduct governing the relationship between utilities and their
non-utility
160
operations and affiliates. The Commission 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-utility operations; and
whether a code of conduct should be established to assure that non-utility
segments of the holding company are not engaged in practices which result in
unfair competition caused by cost shifting from the non-utility affiliate to
the utility. In September 1998, the Commission issued draft code of conduct
and cost allocation guidelines. In January 1999, KU, as well as all parties
to the proceeding, issued comments on the Commission draft proposals. Initial
hearings are scheduled for the first quarter of 1999. Management does not
expect the ultimate resolution of this matter to have a material adverse
effect on KU's financial position or results of operations.
NOTE 4 - FINANCIAL INSTRUMENTS
The cost and estimated fair values of the KU's non-trading financial
instruments as of December 31, 1998 and 1997 follow (in thousands of $):
1998 1997
---- ----
Fair Fair
Cost Value Cost Value
---- ----- ---- -----
Long-term debt $546,330 $587,245 $546,351 $578,835
-------- -------- -------- --------
-------- -------- -------- --------
The above valuations reflect prices quoted by exchanges.
NOTE 5 - 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.
KU's customer receivables and electric revenues arise from deliveries of
electricity to about 449,000 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 five counties in southwestern
Virginia. For the year ended December 31, 1998, 100% of total utility revenue
was derived from electric operations.
KU's operation and maintenance employees are members of the International
Brotherhood of Electrical Workers (IBEW) Local 101 and United Steelworkers of
America (USWA) Local 8686. KU has approximately 15% of its workforce covered
by union contracts expiring August 1, 1999.
161
NOTE 6 - PENSION PLANS AND RETIREMENT BENEFITS
PENSION PLANS. KU sponsors a qualified and non-qualified pension plans and
other postretirement benefit plans for its employees. The following tables
provide a reconciliation of the changes in the plans' benefit obligations and
fair value of assets over the three-year period ending December 31, 1998 and
a statement of the funded status as of December 31 of the three years (in
thousands of $):
1998 1997 1996
---- ---- ----
PENSION PLANS:
Change in benefit obligation
Benefit obligation at beginning of year $214,657 $194,874 $183,795
Service cost 6,702 6,728 6,399
Interest cost 14,939 14,680 13,856
Acquisitions/divestitures (2,243) -- --
Curtailment (gain) or loss 1,901 -- --
Special termination benefits 5,427 -- --
Benefits paid (12,762) (13,313) (9,001)
Actuarial (gain) or loss 2,367 11,688 (175)
-------- -------- --------
Benefit obligation at end of year $230,988 $214,657 $194,874
-------- -------- --------
-------- -------- --------
Change in plan assets
Fair value of plan assets at beginning of year $217,500 $191,879 $179,371
Actual return on plan assets 31,209 35,066 21,463
Employer contributions 2,273 4,750 777
Benefits paid (12,762) (13,314) (9,001)
Administrative expenses (96) (882) (731)
-------- -------- --------
Fair value of plan assets at end of year $238,124 $217,499 $191,879
-------- -------- --------
-------- -------- --------
Reconciliation of funded status
Funded status $ 7,135 $ 2,843 $ (2,995)
Unrecognized actuarial (gain) or loss (26,487) (19,552) (12,549)
Unrecognized transition (asset) or obligation (1,128) (1,350) (1,500)
Unrecognized prior service cost 2,831 3,635 3,990
-------- -------- --------
Net amount recognized at year-end $(17,649) $(14,424) $(13,054)
-------- -------- --------
-------- -------- --------
OTHER BENEFITS:
Change in benefit obligation
Benefit obligation at beginning of year $ 72,139 $66,519 $63,656
Service cost 2,012 1,853 1,859
Interest cost 5,207 4,895 4,751
Curtailment (gain) or loss 3,240 -- --
Special termination benefits - (4,038) (3,857)
Benefits paid (2,617) -- --
Actuarial (gain) or loss (331) 2,910 110
-------- -------- --------
Benefit obligation at end of year $ 79,650 $ 72,139 $66,519
-------- -------- --------
-------- -------- --------
Change in plan assets
Fair value of plan assets at beginning of year $ 17,763 $ 13,270 $ 10,427
Actual return on plan assets 5,117 3,569 1,581
Employer contributions 3,805 3,848 3,740
Benefits paid (2,348) (2,924) (2,478)
-------- -------- --------
Fair value of plan assets at end of year $ 24,337 $ 17,763 $ 13,270
-------- -------- --------
-------- -------- --------
162
1998 1997 1996
---- ---- ----
Reconciliation of funded status
Funded status $(55,313) $(54,376) $ (53,249)
Unrecognized actuarial (gain) or loss (19,944) (19,697) (19,977)
Unrecognized transition (asset) or obligation 45,701 50,118 53,460
-------- -------- --------
Net amount recognized at year-end $(29,556) $(23,955) $ (19,766)
-------- -------- --------
-------- -------- --------
There are no plan assets in the nonqualified plan due to the nature of the plan.
The following tables provide the amounts recognized in the statement of
financial position and information for plans with benefit obligations in excess
of plan assets as of December 31, 1998, 1997 and 1996 (in thousands of $):
1998 1997 1996
---- ---- ----
PENSION PLANS:
Amounts recognized in the statement
financial position consisted of:
Accrued benefit liability $(17,649) $ (14,424) $ (13,054)
Other (22) -- --
-------- -------- --------
Accrued benefit liability $(17,671) $ (14,424) $ (13,054)
-------- -------- --------
-------- -------- --------
Additional year-end information for plans with benefit obligations in
excess of plan assets:
Projected benefit obligation $ 2,300 $ 6,199 $ 10,667
Accumulated benefit obligation 99 3,975 8,235
OTHER BENEFITS:
Amounts recognized in the statement
financial position consisted of:
Accrued benefit liability $ (29,556) $ (23,955) $ (19,766)
Other (2,817) (2,955) --
-------- -------- --------
Net amount recognized at year-end $ (32,373) $ (26,910) $ (19,766)
-------- -------- --------
-------- -------- --------
Additional year-end information for plans with benefit obligations in
excess of plan assets:
Projected benefit obligation $ 79,650 $ 72,139 $ 66,519
Fair value of plan assets 24,337 17,763 13,270
163
The following table provides the components of net periodic benefit cost for
the plans for fiscal years 1998, 1997 and 1996 (in thousands of $):
1998 1997 1996
---- ---- ----
PENSION PLANS:
Components of net periodic benefit cost
Service cost $ 6,703 $ 6,728 $ 6,399
Interest cost 14,939 14,680 13,856
Expected return on plan assets (18,264) (15,427) (14,410)
Amortization of transition (asset) or obligation 321 354 354
Amortization of prior service cost (146) (150) (150)
Amortization of net (gain) loss (151) (26) (24)
---------- ---------- ----------
Net periodic benefit cost $ 3,402 $ 6,159 $ 6,025
---------- ---------- ----------
---------- ---------- ----------
FAS88 special charges
Prior service cost recognized $ 67 $ -- $ --
Special termination benefits 5,427 -- --
---------- ---------- ----------
Total FAS88 charges $ 5,494 $ -- $ --
---------- ---------- ----------
---------- ---------- ----------
OTHER BENEFITS:
Components of net periodic benefit cost
Service cost $ 2,012 $ 1,853 $ 1,859
Interest cost 5,207 4,895 4,751
Expected return on plan assets (1,424) (1,051) (827)
Amortization of transition (asset) or obligation 3,303 3,341 3,341
Amortization of net (gain) loss (536) (812) (703)
---------- ---------- ----------
Net periodic benefit cost $ 8,562 $ 8,226 $ 8,421
---------- ---------- ----------
---------- ---------- ----------
FAS88 special charges
Curtailment (gain)/loss $ 1,114 $ -- $ --
---------- ---------- ----------
---------- ---------- ----------
On May 4, 1998 LG&E Energy and KU Energy merged, with LG&E Energy as the
surviving corporation. At the time of the merger KU had both qualified and
nonqualified pension plans. Under the provisions of the Supplemental Security
Plan (SERP), the Merger Agreement constituted a change-in-control which required
that a lump sum present value payment be made out of KU's SERP to retired
employees entitled to retirement benefits on the date of the Merger Agreement.
On May 30, 1997, $4.7 million in lump sum payments were made to these retired
employees.
Effective May 4, 1998, due to the change in control, the present value balance
of KU's SERP of $4.9 million was transferred and allocated between LG&E Energy
Corp's Nonqualified Savings Plan and KU's Nonqualified Savings plan of $2.2
million and $2.7 million, respectively. The plan is an unfunded, pretax deferred
compensation program which provides officers and senior managers of KU the
opportunity to defer earnings above the qualified savings plan limits. As an
"Unfunded" plan the money is not specifically invested or secured and future
distributions will be made from the general assets of KU. Currently interest is
credited at a rate equal to the average yield on five-year Treasury notes.
During 1998, KU invested approximately $6.6 million in special termination
benefits as a result of its early retirement program offered to eligible
employees post-merger.
KU provides nonpension post retirement benefits for eligible retired employees.
164
The assumptions used in the measurement of the KU's benefit obligation are shown
in the following table:
1998 1997 1996
---- ---- ----
Weighted-average assumptions as of December 31:
Discount rate 7.00% 7.75% 7.75%
Expected long-term rate of return on plan assets 8.25% 8.25% 8.25%
Rate of compensation increase 4.00% 4.75% 4.75%
For measurement purposes, a 7.00% annual increase in the per capita cost of
covered health care benefits was assumed for 1999. The rate was assumed to
decrease gradually to 4.25% for 2005 and remain at that level thereafter.
Assumed health care cost trend rates have a significant effect on the amounts
reported for the health care plans. A 1% change in assumed health care cost
trend rates would have the following effects:
1% INCREASE
-----------
Effect on total of service and interest cost components for 1998 $ (1,071)
Effect on year-end 1998 postretirement benefit obligation (10,219)
Effect on total of service and interest cost components for 1998 1,373
Effect on year-end 1998 postretirement benefit obligation 12,815
THRIFT SAVINGS PLANS. KU has a thrift savings plan under section 401(k) of the
Internal Revenue Code. Under the plan, eligible employees may defer and
contribute to the plan a portion of current compensation in order to provide
future retirement benefits. KU makes contributions to the plan by matching a
portion of the employee contributions. The costs were approximately $2.2 million
for each of 1998 and 1997, and $2.1 million for 1996.
NOTE 7 - INCOME TAXES
Components of income tax expense are shown in the table below (in thousands of
$):
1998 1997 1996
---- ---- ----
Included in operating expenses:
Current - federal $46,321 $39,353 $35,656
- state - net 10,245 8,964 7,387
Deferred - federal - net (3,186) 1,996 5,510
- state - net (124) 1,377 2,899
--------- --------- --------
Total 53,256 51,690 51,452
Included in other income and (deductions):
Current - federal (617) (853) 3,565
- state (237) (246) 861
Deferred - federal - net 694 975 (3,665)
- state - net 178 258 (994)
Amortization of investment tax credit (3,829) (4,036) (4,013)
--------- ---------- ----------
Total (3,811) (3,902) (4,246)
--------- ---------- ----------
Total income tax expense $49,445 $47,788 $47,206
--------- ---------- ----------
--------- ---------- ----------
165
Net deferred tax liabilities resulting from book-tax temporary differences are
shown below (in thousands of $):
1998 1997
---- ----
Deferred tax liabilities:
Depreciation and other
plant-related items $289,147 $285,034
Other liabilities 5,598 5,389
--------- ---------
294,745 290,423
--------- ---------
Deferred tax assets:
Investment tax credit 9,001 10,547
Income taxes due to customers 17,574 19,217
Accrued liabilities not currently
deductible and other 23,677 18,750
Less: amounts included in
current assets 2,595 3,241
--------- ---------
47,657 45,273
--------- ---------
Net deferred income tax liability $247,088 $245,150
--------- ---------
--------- ---------
A reconciliation of differences between the statutory U.S. federal income tax
rate and KU's effective income tax rate follows:
1998 1997 1996
---- ---- ----
Statutory federal income tax rate 35.0% 35.0% 35.0%
State income taxes net of federal benefit 5.4 5.0 4.9
Amortization of investment tax credit (3.1) (3.0) (3.0)
Nondeductible merger expenses 6.4 -- --
Other differences - net (2.2) (1.2) (1.5)
----- ----- -----
Effective income tax rate 41.5% 35.8% 35.4%
----- ----- -----
----- ----- -----
NOTE 8 - OTHER INCOME AND DEDUCTIONS
Other income and deductions consisted of the following at December 31 (in
thousands of $):
1998 1997 1996
---- ---- ----
Equity in earnings - subsidiary company $ 2,167 $ 2,480 $ 2,436
Interest and dividend income 1,811 1,673 1,733
Gains (losses) on fixed asset disposal 272 412 87
Donations (453) (388) (379)
Income taxes and other 4,049 2,826 4,566
-------- -------- --------
Total other income and deductions $ 7,846 $ 7,003 $ 8,443
-------- -------- --------
-------- -------- --------
NOTE 9 - FIRST MORTGAGE BONDS AND POLLUTION CONTROL BONDS
Under the provisions for the KU's variable rate Pollution Control Bonds Series
10, KU can choose between various interest rate options. The daily interest rate
option was utilized at December 31, 1998. The average annual interest rate on
the bonds during 1998 and 1997 was 3.54% and 3.77%, respectively. The variable
rate
166
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.
Substantially all of KU's utility plant is pledged as security for its first
mortgage bonds.
NOTE 10 - NOTES PAYABLE
KU's short-term financing requirements are satisfied through the sale of
commercial paper, KU had no short-term borrowings at December 31, 1998. 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, 1998, KU had lines of credit in place totaling $60 million, all
of which remained unused at December 31, 1998. In support of these lines of
credit, KU pays commitment or facility fees. The KU credit facilities provide
for short-term borrowing and support of commercial paper borrowings. The credit
lines will expire in December 1999. Management expects to renegotiate these
lines when they expire.
NOTE 11 - COMMITMENTS AND CONTINGENCIES
CONSTRUCTION PROGRAM. KU had $6.5 million of commitments in connection with its
construction program at December 31, 1998. Construction expenditures for the
years 1999 and 2000 are estimated to total approximately $341 million.
OPERATING LEASES. KU leases office space, office equipment, and vehicles. KU
accounts for these leases as operating leases. Total lease expense for 1998,
1997, and 1996, was $1.9 million, $1.8 million, and $1.7 million, respectively.
The future minimum annual lease payments under lease agreements for years
subsequent to December 31, 1998, are as follows (in thousands of $):
1999 $ 1,059
2000 983
2001 927
2002 862
2003 811
--------
Total $ 4,642
--------
--------
ENVIRONMENTAL. In September, 1998, the U.S. Environmental Protection Agency
(USEPA) announced its final regulation requiring significant additional
reductions in nitrogen oxide (NOx) emissions to mitigate alleged ozone transport
to the Northeast. While each state is free to allocate its assigned NOx
reductions among various emissions sectors as it deems appropriate, the
regulation may ultimately require utilities to reduce their NOx emissions to
0.15 lb./mmBtu (million British thermal units) - an 85% reduction from 1990
levels. Under the regulation, each state must incorporate the additional NOx
reductions in its State Implementation Plan (SIP) by September 1999 and affected
sources must install control measures by May 2003, unless granted extensions.
Several states, various labor and industry groups, and individual companies have
appealed the final regulation to the U.S. Court of Appeals for the D.C. Circuit.
Management is currently unable to determine the outcome or exact impact of this
matter until such time as the states identify specific emissions reductions in
their SIP and the courts rule on the various legal challenges to the final rule.
However, if the 0.15 lb. target is ultimately imposed, KU will be required to
incur significant capital expenditures and increased operation and maintenance
costs for additional controls. Subject to further study and analysis, KU
estimates that it may incur capital costs of approximately $100 to $200 million
for KU. These costs would generally be incurred beginning in 2000.
167
KU believes its costs for these matters to be comparable to those of similarly
situated utilities with like generation assets. KU anticipates that such capital
and operating costs are the type of costs that are eligible for cost recovery
from customers under its environmental surcharge mechanisms and believes that,
in the case of 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.
In July, 1997, USEPA issued revised National Ambient Air Quality Standards
(NAAQS) for ozone and particulate matter. KU is monitoring USEPA's
implementation of the revised standards. Until USEPA completes additional
implementation steps, including monitoring and nonattainment demonstrations,
management is unable to determine the precise impact of the revised standards.
KU is addressing potential liabilities for the cleanup of properties where
hazardous substances may have been released. KU along with other companies has
been identified by USEPA as a potentially responsible party allegedly liable for
cleanup of off-site disposal facilities under the Comprehensive Environmental
Response Compensation and Liability Act. KU is currently participating as a de
minimis party in one such matter. In addition, KU has conducted various
voluntary cleanups of KU owned properties, including cleanup of a former
manufactured gas plant site.
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 1999-2003, which is expected to be approximately 9% 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 $180 million
of OMU bonds outstanding at December 31, 1998. The debt service is allocated to
KU based on its annual allocated share of capacity, which averaged approximately
49% in 1998.
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 1999-2003 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, 2003 follow (in thousands of $):
1999 $ 34,291
2000 26,712
2001 29,621
2002 29,561
2003 29,670
----------
Total $ 149,855
----------
----------
168
NOTE 12 - SELECTED QUARTERLY DATA (UNAUDITED)
Selected financial data for the four quarters of 1998 and 1997 are shown below.
Because of seasonal fluctuations in temperature and other factors, results for
quarters may fluctuate throughout the year.
Quarters Ended
March June September December
------------ ----------- ------------- ------------
(Thousands of $)
1998
Revenues $183,219 $193,079 $246,117 $187,699
Operating income 33,035 28,144 44,677 19,531
Net income (loss) 25,049 (1,119) 36,980 11,854
Net income (loss) available
for common stock 24,485 (1,683) (a) 36,416 (b) 11,290(c)
1997
Revenues $178,914 $162,868 $192,102 $182,553
Operating income 33,424 19,742 35,343 29,889
Net income 24,961 12,088 26,924 21,740
Net income available
for common stock 24,397 11,524 26,360 21,176
(a) The decrease of $13.2 million compared to June 1997 was due to a
non-recurring after-tax charge of $21.5 million from
merger-related expenses, offset by an increase of $8.3 million due
to increased sales caused by warmer weather and lower maintenance
expenses.
(b) The increase of $10.1 million compared to September 1997 was due
to increased sales caused by warmer weather and an increase in
wholesale sales.
(c) The decrease of $9.9 million compared to December 1997 was due to
an after-tax charge of $12.9 million related to refunds of certain
amounts collected under the Environmental Cost Recovery surcharge,
partially offset by higher wholesale sales.
NOTE 13 - SUBSEQUENT EVENT
On March 8, 1999, the Kentucky Industrial Utility Customers filed a complaint
with the Kentucky Commission alleging that KU's electric rates are excessive and
should be reduced by an amount between $42 and $56 million, and that the
Kentucky Commission establish a proceeding to reduce KU's rates. KU has asked
the Kentucky Commission to dismiss the complaint. KU is not able to predict the
ultimate outcome of these proceedings, however, should the Commission mandate
significant rate reductions at KU, through the PBR proposal or otherwise, such
actions could have a material effect on KU's financial condition and results of
operations.
169
Kentucky Utilities Company
REPORT OF MANAGEMENT
The management of Kentucky Utilities Company is responsible for the preparation
and integrity of the financial statements and related information included in
this Annual Report. These statements have been prepared in accordance with
generally accepted accounting principles applied on a consistent basis and,
necessarily, include amounts that reflect the best estimates and judgment of
management.
KU's financial statements have been audited by Arthur Andersen LLP, independent
public accountants. Management has made available to Arthur Andersen LLP all
KU's financial records and related data as well as the minutes of shareholders'
and directors' meetings.
Management has established and maintains a system of internal controls that
provide reasonable assurance that transactions are completed in accordance with
management's authorization, that assets are safeguarded and that financial
statements are prepared in conformity with generally accepted accounting
principles. Management believes that an adequate system of internal controls is
maintained through the selection and training of personnel, appropriate division
of responsibility, establishment and communication of policies and procedures
and by regular reviews of internal accounting controls by KU's internal
auditors. Management reviews and modifies its system of internal controls in
light of changes in conditions and operations, as well as in response to
recommendations from the internal auditors. These recommendations for the year
ended December 31, 1998, did not identify any material weaknesses in the design
and operation of KU's internal control structure.
The Audit Committee of the Board of Directors is composed entirely of outside
directors. In carrying out its oversight role for the financial reporting and
internal controls of KU, the Audit Committee meets regularly with KU's
independent public accountants, internal auditors and management. The Audit
Committee reviews the results of the independent accountants' audit of the
financial statements and their audit procedures, and discusses the adequacy of
internal accounting controls. The Audit Committee also approves the annual
internal auditing program, and reviews the activities and results of the
internal auditing function. Both the independent public accountants and the
internal auditors have access to the Audit Committee at any time.
Kentucky Utilities Company maintains and internally communicates a written code
of business conduct that addresses, among other items, potential conflicts of
interest, compliance with laws, including those relating to financial
disclosure, and the confidentiality of proprietary information.
170
Kentucky Utilities Company
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders of Kentucky Utilities Company:
We have audited the accompanying balance sheets and statements of
capitalization of Kentucky Utilities Company (a Kentucky and Virginia
corporation and a wholly-owned subsidiary of LG&E Energy Corp.) as of
December 31, 1998 and 1997, and the related statements of income, retained
earnings and cash flows for each of the three years in the period ended
December 31, 1998. These financial statements are the responsibility of KU'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 financial statements referred to above present fairly, in
all material respects, the financial position of Kentucky Utilities Company as
of December 31, 1998 and 1997, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 1998, in
conformity with generally accepted accounting principles.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedule listed under Item 14(a)2 is
presented for purposes of complying with the Securities and Exchange
Commission's rules and is not part of the basic financial statements. This
schedule has been subjected to the auditing procedures applied in the audit of
the basic financial statements and, in our opinion, fairly states in all
material respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.
Louisville, Kentucky Arthur Andersen LLP
January 27, 1999 (Except with respect
to the matters discussed in the fifth paragraph of Note 3, as to which the date
is February 12, 1999, and Note 13, as to which the date is March 8, 1999.)
171
ITEM 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
PART III
ITEMS 10, 11, 12 and 13 are omitted pursuant to General Instruction G, inasmuch
as LG&E Energy and LG&E filed copies of their definitive proxy statements with
the Commission on March 26, 1999, respectively, pursuant to Regulation 14A under
the Securities Exchange Act of 1934. Such proxy and information statements are
incorporated herein by this reference. In accordance with General Instruction G
of Form 10-K, the information required by Item 10 relating to executive officers
has been included in Part I of this Form 10-K. The information required by ITEMS
10, 11, 12 and 13 for KU is incorporated herein by reference to the material
appearing in Exhibit 99.03, which is filed herewith. In accordance with General
Instruction G of Form 10-K, the information required by Item 10 relating to
executive officers of KU has been included in Part I of this Form 10-K.
PART IV
ITEM 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) 1. Financial Statements (included in Item 8):
LG&E ENERGY:
Consolidated statements of income for the three years ended
December 31, 1998 (page 84).
Consolidated statements of retained earnings for the three years
ended December 31, 1998 (page 85).
Consolidated statements of comprehensive income for the three years
ended December 31, 1998 (page 85)
Consolidated balance sheets - December 31, 1998, and 1997 (page 86).
Consolidated statements of cash flows for the
three years ended December 31, 1998 (page 87).
Consolidated statements of capitalization - December 31, 1998, and
1997 (page 88).
Notes to consolidated financial statements (pages 90-123).
Report of management (page 125).
Report of independent public accountants (page 126).
LG&E:
Statements of income for the three years ended December 31, 1998
(page 127).
Statements of retained earnings for the three years ended
December 31, 1998 (page 127).
Statements of comprehensive income for the three years ended
December 31, 1998 (page 128).
Balance sheets - December 31, 1998, and 1997 (page 129).
Statements of cash flows for the three years ended December 31, 1998
(page 130).
Statements of capitalization - December 31, 1998, and 1997
(page 131).
Notes to financial statements (pages 132-149).
Report of management (page 150).
Report of independent public accountants (page 151).
172
(a) 1. Financial Statements (included in Item 8) (continued):
KU:
Statements of income for the three years ended December 31, 1998
(page 152).
Statements of retained earnings for the three years ended
December 31, 1998 (page 152).
Balance sheets - December 31, 1998, and 1997 (page 153).
Statements of cash flows for the three years ended December 31, 1998
(page 154).
Statements of capitalization - December 31, 1998, and 1997
(page 155).
Notes to financial statements (pages 156-169).
Report of management (page 170).
Report of independent public accountants (page 170).
2. Financial Statement Schedules (included in Part IV):
Schedule II Valuation and Qualifying Accounts for the
three years ended December 31, 1998, for LG&E
Energy (page 195), LG&E (page 196), and
KU (page 197).
All other schedules have been omitted as not applicable or not
required or because the information required to be shown is included
in the Financial Statements or the accompanying Notes to Financial
Statements.
3. Exhibits:
Applicable
to Form 10-K of
Exhibit LG&E
No. Energy LG&E KU Description
- ------- ---------- ---------- ---------- -------------
2.01 x x x Copy of Agreement and Plan of Merger, dated as of May 20,
1997, by and between LG&E Energy and KU Energy, including
certain exhibits thereto. [Filed as Exhibit 2 to LG&E
Energy's Current Report on Form 8-K filed May 30, 1997 and
incorporated by reference herein]
3.01 x Copy of LG&E Energy's Amended and Restated Articles of
Incorporation dated May 4, 1998. [Filed as Exhibit 4.1 to
LG&E Energy's Current Report on Form 8-K dated May 4,
1998, and incorporated by reference herein]
3.02 x Copy of Restated Articles of Incorporation of LG&E, dated
November 6, 1996. [Filed as Exhibit 3.06 to LG&E's
Quarterly Report on Form 10-Q for the quarter ended
September 30, 1996, and incorporated by reference herein]
3.03 x Copy of Bylaws of LG&E Energy, as amended through May 4,
1998. [Filed as Exhibit 4.2 to LG&E Energy's Current
Report on Form 8-K dated May 4, 1998, and incorporated by
reference herein]
173
Applicable
to Form 10-K of
Exhibit LG&E
No. Energy LG&E KU Description
- ------- ---------- ---------- ---------- -------------
3.04 x Copy of By-Laws of LG&E, as amended through May 4, 1998.
3.05 x Amended and Restated Articles of Incorporation of Kentucky
Utilities Company [Filed as Exhibits 4.03 and 4.04 to
Form 8-K Current Report of KU, dated December 10, 1993,
and incorporated by reference herein]
3.06 x By-laws of Kentucky Utilities Company dated April 28, 1998.
4.01 x x Copy of Trust Indenture dated November 1, 1949, from LG&E
to Harris Trust and Savings Bank, Trustee. [Filed as
Exhibit 7.01 to LG&E's Registration Statement 2-8283 and
incorporated by reference herein]
4.02 x x Copy of Supplemental Indenture dated February 1, 1952,
which is a supplemental instrument to Exhibit 4.01
hereto. [Filed as Exhibit 4.05 to LG&E's Registration
Statement 2-9371 and incorporated by reference herein]
4.03 x x Copy of Supplemental Indenture dated February 1, 1954,
which is a supplemental instrument to Exhibit 4.01
hereto. [Filed as Exhibit 4.03 to LG&E's Registration
Statement 2-11923 and incorporated by reference herein]
4.04 x x Copy of Supplemental Indenture dated September 1, 1957,
which is a supplemental instrument to Exhibit 4.01
hereto. [Filed as Exhibit 2.04 to LG&E's Registration
Statement 2-17047 and incorporated by reference herein]
4.05 x x Copy of Supplemental Indenture dated October 1, 1960,
which is a supplemental instrument to Exhibit 4.01
hereto. [Filed as Exhibit 2.05 to LG&E's Registration
Statement 2-24920 and incorporated by reference herein]
4.06 x x Copy of Supplemental Indenture dated June 1, 1966, which
is a supplemental instrument to Exhibit 4.01 hereto.
[Filed as Exhibit 2.06 to LG&E's Registration Statement
2-28865 and incorporated by reference herein]
4.07 x x Copy of Supplemental Indenture dated June 1, 1968, which
is a supplemental instrument to Exhibit 4.01 hereto.
[Filed as Exhibit 2.07 to LG&E's Registration Statement
2-37368 and incorporated by reference herein]
4.08 x x Copy of Supplemental Indenture dated June 1, 1970, which
is a
174
Applicable
to Form 10-K of
Exhibit LG&E
No. Energy LG&E KU Description
- ------- ---------- ---------- ---------- -------------
supplemental instrument to Exhibit 4.01 hereto.
[Filed as Exhibit 2.08 to LG&E's Registration Statement
2-37368 and incorporated by reference herein]
4.09 x x Copy of Supplemental Indenture dated August 1, 1971, which
is a supplemental instrument to Exhibit 4.01 hereto.
[Filed as Exhibit 2.09 to LG&E's Registration Statement
2-44295 and incorporated by reference herein]
4.10 x x Copy of Supplemental Indenture dated June 1, 1972, which
is a supplemental instrument to Exhibit 4.01 hereto.
[Filed as Exhibit 2.10 to LG&E's Registration Statement
2-52643 and incorporated by reference herein]
4.11 x x Copy of Supplemental Indenture dated February 1, 1975,
which is a supplemental instrument to exhibit 4.01
hereto. [Filed as Exhibit 2.11 to LG&E's Registration
Statement 2-57252 and incorporated by reference herein]
4.12 x x Copy of Supplemental Indenture dated September 1, 1975,
which is a supplemental instrument to Exhibit 4.01
hereto. [Filed as Exhibit 2.12 to LG&E's Registration
Statement 2-57252 and incorporated by reference herein]
4.13 x x Copy of Supplemental Indenture dated September 1, 1976,
which is a supplemental instrument to Exhibit 4.01
hereto. [Filed as Exhibit 2.13 to LG&E's Registration
Statement 2-57252 and incorporated by reference herein]
4.14 x x Copy of Supplemental Indenture dated October 1, 1976,
which is a supplemental instrument to Exhibit 4.01
hereto. [Filed as Exhibit 2.14 to LG&E's Registration
Statement 2-65271 and incorporated by reference herein]
4.15 x x Copy of Supplemental Indenture dated June 1, 1978, which
is a supplemental instrument to Exhibit 4.01 hereto.
[Filed as Exhibit 2.15 to LG&E's Registration Statement
2-65271 and incorporated by reference herein]
4.16 x x Copy of Supplemental Indenture dated February 15, 1979,
which
175
Applicable
to Form 10-K of
Exhibit LG&E
No. Energy LG&E KU Description
- ------- ---------- ---------- ---------- -------------
is a supplemental instrument to Exhibit 4.01
hereto. [Filed as Exhibit 2.16 to LG&E's Registration
Statement 2-65271 and incorporated by reference herein]
4.17 x x Copy of Supplemental Indenture dated September 1, 1979,
which is a supplemental instrument to Exhibit 4.01
hereto. [Filed as Exhibit 4.17 to LG&E's Annual Report on
Form 10-K for the year ended December 31, 1980, and
incorporated by reference herein]
4.18 x x Copy of Supplemental Indenture dated September 15, 1979,
which is a supplemental instrument to Exhibit 4.01
hereto. [Filed as Exhibit 4.18 to LG&E's Annual Report on
Form 10-K for the year ended December 31, 1980, and
incorporated by reference herein]
4.19 x x Copy of Supplemental Indenture dated September 15, 1981,
which is a supplemental instrument to Exhibit 4.01
hereto. [Filed as Exhibit 4.19 to LG&E's Annual Report on
Form 10-K for the year ended December 31, 1981, and
incorporated by reference herein]
4.20 x x Copy of Supplemental Indenture dated March 1, 1982, which
is a supplemental instrument to Exhibit 4.01 hereto.
[Filed as Exhibit 4.20 to LG&E's Annual Report on Form
10-K for the year ended December 31, 1982, and
incorporated by reference herein]
4.21 x x Copy of Supplemental Indenture dated March 15, 1982, which
is a supplemental instrument to Exhibit 4.01 hereto.
[Filed as Exhibit 4.21 to LG&E's Annual Report on Form
10-K for the year ended December 31, 1982, and
incorporated by reference herein]
4.22 x x Copy of Supplemental Indenture dated September 15, 1982,
which is a supplemental instrument to Exhibit 4.01
hereto. [Filed as Exhibit 4.22 to LG&E's Annual Report on
Form 10-K for the year ended December 31, 1982, and
incorporated by reference herein]
4.23 x x Copy of Supplemental Indenture dated February 15, 1984,
which is a supplemental instrument to Exhibit 4.01
hereto. [Filed as Exhibit 4.23 to LG&E's Annual Report on
Form 10-K for the year ended December 31, 1984, and
incorporated by reference herein]
4.24 x x Copy of Supplemental Indenture dated July 1, 1985, which
is a supplemental instrument to Exhibit 4.01 hereto.
[Filed as Exhibit 4.24 to LG&E's Annual Report on Form
10-K for the year ended December 31, 1985, and
incorporated by reference herein]
4.25 x x Copy of Supplemental Indenture dated November 15, 1986,
176
Applicable
to Form 10-K of
Exhibit LG&E
No. Energy LG&E KU Description
- ------- ---------- ---------- ---------- -------------
which is a supplemental instrument to Exhibit 4.01
hereto. [Filed as Exhibit 4.25 to LG&E's Annual Report on
Form 10-K for the year ended December 31, 1986, and
incorporated by reference herein]
4.26 x x Copy of Supplemental Indenture dated November 16, 1986,
which is a supplemental instrument to Exhibit 4.01
hereto. [Filed as Exhibit 4.26 to LG&E's Annual Report on
Form 10-K for the year ended December 31, 1986, and
incorporated by reference herein]
4.27 x x Copy of Supplemental Indenture dated August 1, 1987, which
is a supplemental instrument to Exhibit 4.01 hereto.
[Filed as Exhibit 4.27 to LG&E's Annual Report on Form
10-K for the year ended December 31, 1987, and
incorporated by reference herein]
4.28 x x Copy of Supplemental Indenture dated February 1, 1989,
which is a supplemental instrument to Exhibit 4.01
hereto. [Filed as Exhibit 4.28 to LG&E's Annual Report on
Form 10-K for the year ended December 31, 1988, and
incorporated by reference herein]
4.29 x x Copy of Supplemental Indenture dated February 2, 1989,
which is a supplemental instrument to Exhibit 4.01
hereto. [Filed as Exhibit 4.29 to LG&E's Annual Report on
Form 10-K for the year ended December 31, 1988, and
incorporated by reference herein]
4.30 x x Copy of Supplemental Indenture dated June 15, 1990, which
is a supplemental instrument to Exhibit 4.01 hereto.
[Filed as Exhibit 4.30 to LG&E's Annual Report on Form
10-K for the year ended December 31, 1990, and
incorporated by reference herein]
4.31 x x Copy of Supplemental Indenture dated November 1, 1990,
which is a supplemental instrument to Exhibit 4.01
hereto. [Filed as Exhibit 4.31 to LG&E's Annual Report on
Form 10-K for the year ended December 31, 1990, and
incorporated by reference herein]
4.32 x x Copy of Supplemental Indenture dated September 1, 1992,
which is a supplemental instrument to Exhibit 4.01
hereto. [Filed as Exhibit 4.32 to LG&E's Annual Report on
Form 10-K for the year ended December 31, 1992, and
incorporated by reference herein]
177
Applicable
to Form 10-K of
Exhibit LG&E
No. Energy LG&E KU Description
- ------- ---------- ---------- ---------- -------------
4.33 x x Copy of Supplemental Indenture dated September 2, 1992,
which is a supplemental instrument to Exhibit 4.01
hereto. [Filed as Exhibit 4.33 to LG&E's Annual Report on
Form 10-K for the year ended December 31, 1992, and
incorporated by reference herein]
4.34 x x Copy of Supplemental Indenture dated August 15, 1993,
which is a supplemental instrument to Exhibit 4.01
hereto. [Filed as Exhibit 4.34 to LG&E's Annual Report on
Form 10-K for the year ended December 31, 1993, and
incorporated by reference herein]
4.35 x x Copy of Supplemental Indenture dated August 16, 1993,
which is a supplemental instrument to Exhibit 4.01
hereto. [Filed as Exhibit 4.35 to LG&E's Annual Report on
Form 10-K for the year ended December 31, 1993, and
incorporated by reference herein]
4.36 x x Copy of Supplemental Indenture dated October 15, 1993,
which is a supplemental instrument to Exhibit 4.01
hereto. [Filed as Exhibit 4.36 to LG&E's Annual Report on
Form 10-K for the year ended December 31, 1993, and
incorporated by reference herein]
4.37 x x Indenture of Mortgage or Deed of Trust dated May 1, 1947,
between Kentucky Utilities Company and First Trust
National Association (successor Trustee) and a successor
individual co-trustee, as Trustees (the Trustees) (Amended
Exhibit 7(a) in File No. 2-7061), and Supplemental
Indentures thereto dated, respectively, January 1, 1949
(Second Amended Exhibit 7.02 in File No. 2-7802), July 1,
1950 (Amended Exhibit 7.02 in File No. 2-8499), June 15,
1951 (Exhibit 7.02(a) in File No. 2-8499), June 1, 1952
(Amended Exhibit 4.02 in File No. 2-9658), April 1, 1953
(Amended Exhibit 4.02 in File No. 2-10120), April 1, 1955
(Amended Exhibit 4.02 in File No. 2-11476), April 1, 1956
(Amended Exhibit 2.02 in File No. 2-12322), May 1, 1969
(Amended Exhibit 2.02 in File No. 2-32602), April 1, 1970
(Amended Exhibit 2.02 in File No. 2-36410), September 1,
1971 (Amended Exhibit 2.02 in File No. 2-41467), December
1, 1972 (Amended Exhibit 2.02 in File No. 2-46161), April
1, 1974 (Amended Exhibit 2.02 in File No. 2-50344),
September 1, 1974 (Exhibit 2.04 in File No. 2-59328), July
1, 1975 (Exhibit 2.05 in File No. 2-59328), May 15, 1976
(Amended Exhibit 2.02 in File No. 2-56126), April 15, 1977
(Exhibit 2.06 in File No. 2-59328), August 1, 1979
(Exhibit 2.04 in File No. 2-64969), May 1, 1980
178
Applicable
to Form 10-K of
Exhibit LG&E
No. Energy LG&E KU Description
- ------- ---------- ---------- ---------- -------------
(Exhibit 2 to Form 10-Q Quarterly Report of KU for the quarter
ended June 30, 1980), September 15, 1982 (Exhibit 4.04 in File
No. 2-79891), August 1, 1984 (Exhibit 4B to Form 10-K
Annual Report of KU for the year ended December 31, 1984),
June 1, 1985 (Exhibit 4 to Form 10-Q Quarterly Report of
KU for the quarter ended June 30, 1985), May 1, 1990
(Exhibit 4 to Form 10-Q Quarterly Report of KU for the
quarter ended June 30, 1990), May 1, 1991 (Exhibit 4 to
Form 10-Q Quarterly Report of KU for the quarter ended
June 30, 1991), May 15, 1992 (Exhibit 4.02 to Form 8-K of
KU dated May 14, 1992), August 1, 1992 (Exhibit 4 to Form
10-Q Quarterly Report of KU for the quarter ended
September 30, 1992), June 15, 1993 (Exhibit 4.02 to Form
8-K of KU dated June 15, 1993) and December 1, 1993
(Exhibit 4.01 to Form 8-K of KU dated December 10, 1993),
November 1, 1994 (Exhibit 4.C to Form 10-K Annual Report
of KU for the year ended December 31, 1994), June 1, 1995
(Exhibit 4 to Form 10-Q Quarterly Report of KU for the
quarter ended June 30, 1995) and January 15, 1996 (Exhibit
4.E to Form 10-K Annual Report of KU for the year ended
December 31, 1995). Incorporated by reference.
4.38 x x Supplemental Indenture dated March 1, 1992 between
Kentucky Utilities Company and the Trustees, providing for
the conveyance of properties formerly held by Old Dominion
Power Company [Filed as Exhibit 4B to Form 10-K Annual
Report of KU for the year ended December 31, 1992, and
incorporated by reference herein]
10.01 x x Copies of Agreement between Sponsoring Companies re:
Project D of Atomic Energy Commission, dated May 12, 1952,
Memorandums of Understanding between Sponsoring Companies
re: Project D of Atomic Energy Commission, dated
September 19, 1952 and October 28, 1952, and Power
Agreement between Ohio Valley Electric Corporation and
Atomic Energy Commission, dated October 15, 1952. [Filed
as Exhibit 13(y) to LG&E's Registration Statement 2-9975
and incorporated by reference herein]
10.02 x x Copy of Modification No. 1 dated July 23, 1953, to the
Power Agreement between Ohio Valley Electric Corporation
and Atomic Energy Commission. [Filed as Exhibit 4.03(b)
to LG&E's Registration Statement 2-24920 and incorporated
by reference herein]
10.03 x x Copy of Modification No. 2 dated March 15, 1964, to the
Power
179
Applicable
to Form 10-K of
Exhibit LG&E
No. Energy LG&E KU Description
- ------- ---------- ---------- ---------- -------------
Agreement between Ohio Valley Electric Corporation
and Atomic Energy Commission. [Filed as Exhibit 5.02c to
LG&E's Registration Statement 2-61607 and incorporated by
reference herein]
10.04 x x Copy of Modification No. 3 and No. 4 dated May 12, 1966
and January 7, 1967, respectively, to the Power Agreement
between Ohio Valley Electric Corporation and Atomic Energy
Commission. [Filed as Exhibits 4(a)(13) and 4(a)(14) to
LG&E's Registration Statement 2-26063 and incorporated by
reference herein]
10.05 x x Copy of Modification No. 5 dated August 15, 1967, to the
Power Agreement between Ohio Valley Electric Corporation
and Atomic Energy Commission. [Filed as Exhibit 13(c) to
LG&E's Registration Statement 2-27316 and incorporated by
reference herein]
10.06 x x Copies of (i) Inter-Company Power Agreement, dated July
10, 1953, between Ohio Valley Electric Corporation and
Sponsoring Companies (which Agreement includes as Exhibit
A the Power Agreement, dated July 10, 1953, between Ohio
Valley Electric Corporation and Indiana-Kentucky Electric
Corporation); (ii) First Supplementary Transmission
Agreement, dated July 10, 1953, between Ohio Valley
Electric Corporation and Sponsoring Companies; (iii)
Inter-Company Bond Agreement, dated July 10, 1953, between
Ohio Valley Electric Corporation and Sponsoring Companies;
(iv) Inter-Company Bank Credit Agreement, dated July 10,
1953, between Ohio Valley Electric Corporation and
Sponsoring Companies. [Filed as Exhibit 5.02f to LG&E's
Registration Statement 2-61607 and incorporated by
reference herein]
10.07 x x Copy of Modification No. 1 and No. 2 dated June 3, 1966
and January 7, 1967, respectively, to Inter-Company Power
Agreement dated July 10, 1953. [Filed as Exhibits 4(a)(8)
and 4(a)(10) to LG&E's Registration Statement 2-26063 and
incorporated by reference herein]
10.08 x x Copies of Amendments to Agreements (iii) and (iv) referred
to under 10.06 above as follows: (i) Amendment to
Inter-Company Bond Agreement and (ii) Amendment to
Inter-Company Bank Credit Agreement. [Filed as Exhibit
5.02h to LG&E's Registration Statement 2-61607 and
incorporated by reference herein]
10.09 x x Copy of Modification No. 1, dated August 20, 1958, to
First
180
Applicable
to Form 10-K of
Exhibit LG&E
No. Energy LG&E KU Description
- ------- ---------- ---------- ---------- -------------
Supplementary Transmission Agreement, dated July 10,
1953, among Ohio Valley Electric Corporation and the
Sponsoring Companies. [Filed as Exhibit 5.02i to LG&E's
Registration Statement 2-61607 and incorporated by
reference herein]
10.10 x x Copy of Modification No. 2, dated April 1, 1965, to the
First Supplementary Transmission Agreement, dated July 10,
1953, among Ohio Valley Electric Corporation and the
Sponsoring Companies. [Filed as Exhibit 5.02j to LG&E's
Registration Statement 2-61607 and incorporated by
reference herein]
10.11 x x Copy of Modification No. 3, dated January 20, 1967, to
First Supplementary Transmission Agreement, dated July 10,
1953, among Ohio Valley Electric Corporation and the
Sponsoring Companies. [Filed as Exhibit 4(a)(7) to LG&E's
Registration Statement 2-26063 and incorporated by
reference herein]
10.12 x x Copy of Modification No. 6 dated November 15, 1967, to the
Power Agreement between Ohio Valley Electric Corporation
and Atomic Energy Commission. [Filed as Exhibit 4(g) to
LG&E's Registration Statement 2-28524 and incorporated by
reference herein]
10.13 x x Copy of Modification No. 3 dated November 15, 1967, to the
Inter-Company Power Agreement dated July 10, 1953. [Filed
as Exhibit 4.02m to LG&E's Registration Statement 2-37368
and incorporated by reference herein]
10.14 x x Copy of Modification No. 7 dated November 5, 1975, to the
Power Agreement between Ohio Valley Electric Corporation
and Atomic Energy Commission. [Filed as Exhibit 5.02n to
LG&E's Registration Statement 2-56357 and incorporated by
reference herein]
10.15 x x Copy of Modification No. 4 dated November 5, 1975, to the
Inter-Company Power Agreement dated July 10, 1953. [Filed
as Exhibit 5.02o to LG&E's Registration Statement 2-56357
and incorporated by reference herein]
10.16 x x Copy of Modification No. 4 dated April 30, 1976, to First
Supplementary Transmission Agreement, dated July 10, 1953,
among Ohio Valley Electric Corporation and the Sponsoring
Companies. [Filed as Exhibit 5.02p to LG&E's Registration
Statement 2-61607 and incorporated by reference herein]
181
Applicable
to Form 10-K of
Exhibit LG&E
No. Energy LG&E KU Description
- ------- ---------- ---------- ---------- -------------
10.17 x x Copy of Modification No. 8 dated June 23, 1977, to the
Power Agreement between Ohio Valley Electric Corporation
and Atomic Energy Commission. [Filed as Exhibit 5.02q to
LG&E's Registration Statement 2-61607 and incorporated by
reference herein]
10.18 x x Copy of Modification No. 9 dated July 1, 1978, to the
Power Agreement between Ohio Valley Electric Corporation
and Atomic Energy Commission. [Filed as Exhibit 5.02r to
LG&E's Registration Statement 2-63149 and incorporated by
reference herein]
10.19 x x Copy of Modification No. 10 dated August 1, 1979, to the
Power Agreement between Ohio Valley Electric Corporation and Atomic
Energy Commission. [Filed as Exhibit 2 to LG&E's
Annual Report on Form 10-K for the year ended December 31, 1979, and
incorporated by reference herein]
10.20 x x Copy of Modification No. 11 dated September 1, 1979, to
the Power Agreement between Ohio Valley Electric
Corporation and Atomic Energy Commission. [Filed as
Exhibit 3 to LG&E's Annual Report on Form 10-K for the
year ended December 31, 1979, and incorporated by
reference herein]
10.21 x x Copy of Modification No. 5 dated September 1, 1979, to
Inter-Company Power Agreement dated July 5, 1953, among
Ohio Valley Electric Corporation and Sponsoring
Companies. [Filed as Exhibit 4 to LG&E's Annual Report on
Form 10-K for the year ended December 31, 1979, and
incorporated by reference herein]
10.22 x x Copy of Modification No. 12 dated August 1, 1981, to the
Power Agreement between Ohio Valley Electric
Corporation and Atomic Energy Commission. [Filed
as Exhibit 10.25 to LG&E's Annual Report on
Form 10-K for the year ended December 31, 1981,
and incorporated by reference herein]
10.23 x x Copy of Modification No. 6 dated August 1, 1981, to
Inter-Company Power Agreement dated July 5, 1953, among
Ohio Valley Electric Corporation and Sponsoring
Companies. [Filed as Exhibit 10.26 to LG&E's Annual
Report on Form 10-K for the year ended December 31, 1981,
and incorporated by reference herein]
10.24 x x * Copy of LG&E Energy Corp. Deferred Stock Compensation
182
Applicable
to Form 10-K of
Exhibit LG&E
No. Energy LG&E KU Description
- ------- ---------- ---------- ---------- -------------
Plan effective January 1, 1992, covering non-employee
directors of the Company and its subsidiaries. [Filed as
Exhibit 10.34 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1991, and incorporated by
reference herein]
10.25 x x * Copy of Supplemental Executive Retirement Plan for R.
W. Hale, effective June 1, 1989. [Filed as Exhibit 10.42
to the Company's Annual Report on Form 10-K for the year
ended December 31, 1992, and incorporated by reference
herein]
10.26 x x * Copy of Nonqualified Savings Plan covering officers of
the Company, effective January 1, 1992. [Filed as Exhibit
10.43 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1992, and incorporated by
reference herein]
10.27 x x Copy of Modification No. 13 dated September 1, 1989, to
the Power Agreement between Ohio Valley Electric
Corporation and Atomic Energy Commission. [Filed as
Exhibit 10.42 to LG&E's Annual Report on Form 10-K for the
year ended December 31, 1993, and incorporated by
reference herein]
10.28 x x Copy of Modification No. 14 dated January 15, 1992, to the
Power Agreement between Ohio Valley Electric Corporation and
Atomic Energy Commission. [Filed as Exhibit 10.43 to LG&E's
Annual Report on Form 10-K for the year ended December 31,
1993, and incorporated by reference herein]
10.29 x x Copy of Modification No. 7 dated January 15, 1992, to
Inter-Company Power Agreement dated July 10, 1953, among
Ohio Valley Electric Corporation and Sponsoring
Companies. [Filed as Exhibit 10.44 to LG&E's Annual
Report on Form 10-K for the year ended December 31, 1993,
and incorporated by reference herein]
10.30 x x Copy of Modification No. 15 dated February 15, 1993, to
the Power Agreement between Ohio Valley Electric
Corporation and Atomic Energy Commission. [Filed as
Exhibit 10.45 to LG&E's Annual Report on Form 10-K for the
year ended December 31, 1993, and incorporated by
reference herein]
10.31 x x Copy of Firm No Notice Transportation Agreement effective
November 1, 1993, between Texas Gas Transmission
Corporation and LG&E (expires October 31, 2001) covering
the transmission of natural gas.
183
Applicable
to Form 10-K of
Exhibit LG&E
No. Energy LG&E KU Description
- ------- ---------- ---------- ---------- -------------
Copy of Firm No Notice Transportation Agreement
effective November 1, 1993, between Texas Gas
Transmission Corporation and LG&E (expires October
31, 2000) covering the transmission of natural gas.
Copy of Firm No Notice Transportation Agreement
effective November 1, 1993, between Texas Gas
Transmission Corporation and LG&E (expires October
31, 2003) covering the transmission of natural gas.
[Filed as Exhibit 10.47 to LG&E's Annual Report
on Form 10-K for the year ended December 31, 1993,
and incorporated by reference herein]
10.32 x x x * Copy of LG&E Energy Corp. Stock Option Plan for
Non-Employee Directors. [Filed as Exhibit 10.51 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1993, and incorporated by reference herein]
10.33 x x Copy of Modification No. 8 dated January 19, 1994, to
Intercompany Power Agreement, dated July 10, 1953, among
Ohio Valley Electric Corporation and the Sponsoring
Companies. [Filed as Exhibit 10.43 to LG&E's Annual Report
on Form 10-K for the year ended December 31, 1995, and
incorporated by reference herein]
10.34 x x Copy of Amendment dated March 1 1995, to Firm No-Notice
Transportation Agreements dated November 1, 1993 (2-Year,
5-Year and 8-Year), between Texas Gas Transmission
Corporation and LG&E covering the transmission of natural
gas. [Filed as Exhibit 10.44 of LG&E's Annual Report on
Form 10-K for the year ended December 31, 1995, and
incorporated by reference herein]
10.35 x x Copy of Modification No. 9, dated August 17, 1995, to the
Inter-Company Power Agreement dated July 10, 1953, among
Ohio Valley Electric Corporation and the Sponsoring
Companies. [Filed as Exhibit 10.39 to LG&E's Annual
Report on Form 10-K for the year ended December 31, 1996,
and incorporated by reference herein]
10.36 x x Copy of Agreement and Plan of Merger, dated February 10,
1995, between LG&E Natural Inc., formerly known as Hadson
Corporation, Carousel Acquisition Corporation and the
Company. [Filed as Exhibit 2 of Schedule 13D by the
Company on
184
Applicable
to Form 10-K of
Exhibit LG&E
No. Energy LG&E KU Description
- ------- ---------- ---------- ---------- -------------
February 21, 1995, and incorporated by reference herein]
10.37 x x Copy of Firm Transportation Agreement, dated March 1,
1995, between Texas Gas Transmission Corporation and LG&E
(expires October 31, 2003) covering the transportation of
natural gas.
Copy of Firm Transportation Agreement,
dated March 1, 1995, between Texas Gas
Transmission Corporation and LG&E (expires October
31, 2001) covering the transportation of natural
gas. [Filed as Exhibit 10.45 to LG&E's Annual
Report on Form 10-K for the year ended December
31, 1995, and incorporated by reference herein]
10.38 x x Copy of Firm Transportation Agreement, dated March 1,
1995, between Texas Gas Transmission Corporation and LG&E
(expires October 31, 2000) covering the transportation of
natural gas [Filed as Exhibit 10.41 to LG&E's Annual
Report on Form 10-K for the year ended December 31, 1996,
and incorporated by reference herein]
10.39 x x x * Copy of Amended and Restated Omnibus Long-Term
Incentive Plan effective January 1, 1996, covering
officers and key employees of the Company. [Filed as
Exhibit 10.52 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1995, and incorporated by
reference herein]
10.40 x x x * Copy of Short-Term Incentive Plan effective January 1,
1996, covering officers and key employees of the Company.
[Filed as Exhibit 10.53 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1995, and
incorporated by reference herein]
10.41 x x * Copy of Amendment to the Non-Qualified Savings Plan,
effective January 1, 1992. [Filed as Exhibit 10.55 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1995, and incorporated by reference herein]
10.42 x x * Copy of Amendment to the Non-Qualified Savings Plan,
effective January 1, 1995. [Filed as Exhibit 10.56 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1995, and incorporated by reference herein]
10.43 x x * Copy of Amendment to the Non-Qualified Savings Plan,
effective January 1, 1995. [Filed as Exhibit 10.57 to the
Company's
185
Applicable
to Form 10-K of
Exhibit LG&E
No. Energy LG&E KU Description
- ------- ---------- ---------- ---------- -------------
Annual Report on Form 10-K for the year ended
December 31, 1995, and incorporated by reference herein]
10.44 x x Copy of Form of Master Gas Purchase Agreement, dated
December 14, 1993, among Santa Fe, SFEOP and AGPC. [Filed
as Exhibit 10.23 to LG&E Natural Inc.'s, formerly known as
Hadson Corporation, Registration Statement on Form S-4,
File No. 33-68224, and incorporated by reference herein]
10.45 x x Copy of Credit Agreement, dated as of December 18, 1995,
among LG&E, as Borrower, the Banks named therein, PNC
Bank, Kentucky, Inc. as Agent and Bank of Montreal as
Co-Agent. [Filed as Exhibit 10.01 to the LG&E's Quarterly
Report on Form 10-Q/A for the quarter ended March 31,
1996, and incorporated by reference herein]
10.46 x x Copy of Firm Transportation Agreement, dated November 1,
1996, between LG&E and Tennessee Gas Pipeline Company for
30,000 MMBtu per day in Firm Transportation Service under
Tennessee's Rate FT-A (expires October 31, 2001). [Filed
as Exhibit 10.42 to LG&E's Annual Report on Form 10-K for
the year ended December 31, 1996, and incorporated by
reference herein]
10.47 x x Copy of Amendment No. 1, dated as of November 5, 1996, to
Credit Agreement dated as of December 18, 1995, by and
among Louisville Gas and Electric Company, the Banks party
thereto, and PNC Bank, Kentucky, Inc. as Agent and Bank of
Montreal as Co-Agent. [Filed as Exhibit 10.59 to LG&E's
Annual Report on Form 10-K for the year ended December 31,
1996, and incorporated by reference herein]
10.48 x x Copy of Power Purchase and Sale Agreement, dated as of
November 19, 1996, among the Company, LG&E Power Marketing
Inc., and Oglethorpe Power Corporation. [Filed as Exhibit
10.66 to LG&E Energy's Annual Report on Form 10-K for the
year ended December 31, 1996, and incorporated by
reference herein] [Certain portions of this exhibit have
been omitted pursuant to a confidential treatment request
filed with the Securities and Exchange Commission]
10.49 x x Copy of Power Purchase and Sale Agreement, dated as of
January 1, 1997, among LG&E Power Marketing Inc., LG&E
Power Inc., and Oglethorpe Power Corporation. [Filed as
Exhibit 10.67 to LG&E Energy's Annual Report on Form 10-K
for
186
Applicable
to Form 10-K of
Exhibit LG&E
No. Energy LG&E KU Description
- ------- ---------- ---------- ---------- -------------
the year ended December 31, 1996, and incorporated by
reference herein] [Certain portions of this exhibit have
been omitted pursuant to a confidential treatment request
filed with the Securities and Exchange Commission]
10.50 x Copy of U.S. $500,000,000 Credit Agreement, dated as of
September 5, 1997, among LG&E Capital Corp., as Borrower,
and the Banks named therein, as Lenders, and Chase
Securities Inc., as Syndication Agent, Bank of Montreal,
as Administrative Agent, and Morgan Guaranty Trust Company
of New York, PNC Bank, Kentucky, Inc., The Bank of New
York, The First National Bank of Chicago and Wachovia
Bank, N.A., as Co-Agents. [Filed as Exhibit 10.01 to LG&E
Energy's Quarterly Report on Form 10-Q for the quarter
ended September 30, 1997, and incorporated by reference
herein]
10.51 x Copy of U.S. $ 200,000,000 Credit Agreement, dated as of
September 5, 1997, among LG&E Capital Corp., as Borrower,
and the Banks named therein, as Lenders, and Chase
Securities Inc., as Syndication Agent, Bank of Montreal,
as Administrative Agent, and Morgan Guaranty Trust Company
of New York, PNC Bank, Kentucky, Inc., The Bank of New
York, The First National Bank of Chicago and Wachovia
Bank, N.A., as Co-Agents. [Filed as Exhibit 10.02 to LG&E
Energy's Quarterly Report on Form 10-Q for the quarter
ended September 30, 1997, and incorporated by reference
herein]
10.52 x Copy of Support Agreement, dated as of September 5, 1997,
between LG&E Energy Corp. and LG&E Capital Corp. [Filed
as Exhibit 10.03 to LG&E Energy's Quarterly Report on Form
10-Q for the quarter ended September 30, 1997, and
incorporated by reference herein]
10.53 x KU Energy Stock Option Agreement, dated as of May 20,
1997, by and between KU Energy and LG&E Energy. [Filed as
Exhibit 99.1 to the Company's Current Report on Form 8-K
filed May 30, 1997 and incorporated by reference herein]
10.54 x Copy of LG&E Energy Stock Option Agreement, dated as of
May 20, 1997, by and between KU Energy and LG&E Energy.
[Filed as Exhibit 99.2 to the Company's Current Report on
Form 8-K filed May 30, 1997 and incorporated by reference
herein]
10.55 x x x * Copy of Employment Agreement between LG&E Energy and
Roger W. Hale dated May 20, 1997, effective May 4, 1998.
187
Applicable
to Form 10-K of
Exhibit LG&E
No. Energy LG&E KU Description
- ------- ---------- ---------- ---------- -------------
[Filed as Annex D to Exhibit 2.01 of LG&E Energy's Annual
Report on Form 10-K for the year ended December 31, 1997,
and incorporated by reference herein]
10.56 x x * Copy of LG&E Energy Corp. and Louisville Gas and
Electric Company Non-Officer Senior Management Pension
Restoration Plan, effective May 1, 1996. [Filed as
Exhibit 10.69 to LG&E Energy's Annual Report on Form 10-K
for the year ended December 31, 1996, and incorporated by
reference herein]
10.57 x Copy of Indenture between LG&E Capital Corp. and the Bank
of New York as Trustee dated as of January 15, 1998.
[Filed as Exhibit 10.72 to LG&E Energy's Annual Report on
Form 10-K for the year ended December 31, 1997, and
incorporated by reference herein]
10.58 x Copy of First Supplemental Indenture between LG&E Capital
Corp. and The Bank of New York as Trustee dated as of
January 15, 1998. [Filed as Exhibit 10.73 to LG&E
Energy's Annual Report on Form 10-K for the year ended
December 31, 1997, and incorporated by reference herein]
10.59 x x x * Copy of Supplemental Executive Retirement Plan as
amended through January 1, 1998, covering
officers of LG&E Energy. [Filed as Exhibit 10.74
to LG&E Energy's Annual Report on Form 10-K for
the year ended December 31, 1997, and
incorporated by reference herein]
10.60 x x x * Copy of form of Change in Control Agreement for
officers of LG&E Energy Corp. [Filed as Exhibit 10.75 to
LG&E Energy's Annual Report on Form 10-K for the year
ended December 31, 1997, and incorporated by reference
herein]
10.61 x x Copy of Coal Supply Agreement between LG&E and Kindill
Mining, Inc., dated July 1, 1997. [Filed as Exhibit 10.76
to LG&E Energy's Annual Report on Form 10-K for the year
ended December 31, 1997, and incorporated by reference
herein]
10.62 x x Copy of Coal Supply Agreement between LG&E and Warrior
Coal Corp. dated January 1, 1997, and Amendments #1 and #2
dated May 1, 1997, and December 1, 1997, thereto. [Filed
as Exhibit 10.79 to LG&E Energy's Annual Report on Form
10-K for the year ended December 31, 1997, and
incorporated by reference herein]
188
Applicable
to Form 10-K of
Exhibit LG&E
No. Energy LG&E KU Description
- ------- ---------- ---------- ---------- -------------
10.63 x x Copies of Amendments dated September 23, 1997, to Firm
No-Notice Transportation Agreements dated November 1,
1993, between Texas Gas Transmission Corporation and LG&E,
as amended. [Filed as Exhibit 10.81 to LG&E Energy's
Annual Report on Form 10-K for the year ended December 31,
1997, and incorporated by reference herein]
10.64 x x Copies of Amendments dated September 23, 1997, to Firm
Transportation Agreements dated March 1, 1995, between
Texas Gas Transmission Corporation and LG&E, as amended.
[Filed as Exhibit 10.82 to LG&E Energy's Annual Report on
Form 10-K for the year ended December 31, 1997, and
incorporated by reference herein]
10.65 x x Copy of Gas Transportation Agreement dated November 1,
1996, between Tennessee Gas Pipeline Company and LG&E and
amendments dated February 4, 1997, thereto. [Filed as
Exhibit 10.83 to LG&E Energy's Annual Report on Form 10-K
for the year ended December 31, 1997, and incorporated by
reference herein] [Certain portions of this exhibit have
been omitted pursuant to a confidential treatment request
filed with the Securities and Exchange Commission]
10.66 x x * KU's Amended and Restated Performance Share Plan
[Filed as Exhibit 10.A to Form 10-Q Quarterly Report of KU
for the quarter ended June 30, 1993, and incorporated by
reference herein]
10.67 x x * KU's Annual Performance Incentive Plan [Filed as
Exhibit 10B to Form 10-K Annual Report of KU for the year
ended December 31, 1990, and incorporated by reference
herein]
10.68 x x * Amendment No. 1 to KU's Performance Share Plan [Filed
as Exhibit 10.03 to Form 10-K Annual Report for KU for the
year ended December 31, 1996, and incorporated by
reference herein]
10.69 x x * Amendment No. 1 to KU's Annual Performance Incentive
Plan [Filed as Exhibit 10D to Form 10-K Annual Report of
KU for the year ended December 31, 1991, and incorporated
by reference herein]
10.70 x x * Amendment No. 2 to KU's Annual Performance Incentive
Plan [Filed as Exhibit 10.H to Form 10-K Annual Report of
KU for the year ended December 31, 1993, and incorporated
by reference herein]
189
Applicable
to Form 10-K of
Exhibit LG&E
No. Energy LG&E KU Description
- ------- ---------- ---------- ---------- -------------
10.71 x x * Amendment No. 3 to KU's Annual Performance Incentive
Plan [Filed as Exhibit 10.I to Form 10-K Annual Report of
KU for the year ended December 31, 1993, and incorporated
by reference herein]
10.72 x x * Amendment No. 4 to KU's Annual Performance Incentive
Plan [Filed as Exhibit 10.07 to Form 10-K Annual Report
for KU for the year ended December 31, 1996, and
incorporated by reference herein]
10.73 x x * KU's Executive Optional Deferred Compensation Plan
[Filed as Exhibit 10.08 to Form 10-K Annual Report for KU
for the year ended December 31, 1996, and incorporated by
reference herein]
10.74 x x * KU Energy's Long-Term Incentive Plan [Filed as Exhibit
10.27 to Form 10-K Annual Report of KU Energy for the year
ended December 31, 1996, and incorporated by reference
herein]
10.75 x * Employment Agreement by and between KU Energy
Corporation and Michael R. Whitley [Filed as Exhibit
(2)-5 to S-4 Registration Statement File No. 333-34219;
Annex E to Form DEFM14A Joint Proxy Statement of LG&E
Energy Corp. and KU Energy Corporation dated August 22,
1997, and incorporated by reference herein]
10.76 x x Copy of Amended and Restated Coal Supply Agreement dated
April 1, 1998 between LG&E and Hopkins County Coal LLC.
10.77 x x Copy of Coal Supply Agreement dated January 1, 1999
between LG&E and Peabody COALSALES Company.
10.78 x x Copy of Coal Supply Agreement dated December 31, 1997
between KU and Leslie Resources, Inc.
10.79 x x Copy of Amendment No. One to Contract dated November 16,
1998 between KU, Leslie Resources, Inc., AEI Coal Sales
Company, Inc. and AEI Holding Company, Inc. regarding Coal
Supply Agreement dated December 31, 1997.
10.80 x x Copy of Assignment and Assumption Agreement dated November
16, 1998 between KU, Leslie Resources, Inc. and AEI Coal
Sales Company, Inc. regarding Coal Supply Agreement dated
December 31, 1997.
190
Applicable
to Form 10-K of
Exhibit LG&E
No. Energy LG&E KU Description
- ------- ---------- ---------- ---------- -------------
10.81 x x Copy of Coal Supply Agreement dated April 1, 1995 between
KU and Consolidation Coal Company, Quarto Mining Company,
McElroy Coal Company, Consol Pennsylvania Coal Company,
Greenon Coal Company and Nineveh Coal Company.
10.82 x x Copy of Amendment to Coal Supply Agreement dated October
1, 1996 between KU and Consolidation Coal Company, Quarto
Mining Company, McElroy Coal Company, Consol Pennsylvania
Coal Company, Greenon Coal Company and Nineveh Coal
Company regarding Coal Supply Agreement dated April 1,
1995.
10.83 x Copy of New Participation Agreement dated April 6, 1998
among Big Rivers Electric Corporation. LG&E Energy Marketing
Inc., Western Kentucky Leasing Corp., WKE Station Two Inc.
and Western Kentucky Energy Corp. [Certain portions of this
exhibit have been omitted pursuant to a confidential treatment
request filed with the Securities and Exchange Commission.]
10.84 x Copy of Letter Agreement from WKE Station Two Inc. to Big
Rivers Electric Corporation dated April 6, 1998 amending
New Participation Agreement dated April 6, 1998 among Big
Rivers Electric Corporation. LG&E Energy Marketing Inc.,
Western Kentucky Leasing Corp., WKE Station Two Inc. and
Western Kentucky Energy Corp. [Certain portions of this
exhibit have been omitted pursuant to a confidential
treatment request filed with the Securities and Exchange
Commission.]
10.85 x Copy of Second Amendment dated June 15, 1998 to New
Participation Agreement dated April 6, 1998 among Big
Rivers Electric Corporation. LG&E Energy Marketing Inc.,
Western Kentucky Leasing Corp., WKE Station Two Inc. and
Western Kentucky Energy Corp. [Certain portions of this
exhibit have been omitted pursuant to a confidential
treatment request filed with the Securities and Exchange
Commission.]
10.86 x Copy of Third Amendment dated July 15, 1998 to New
Participation Agreement dated April 6, 1998 among Big
Rivers Electric Corporation. LG&E Energy Marketing Inc.,
Western Kentucky Leasing Corp., WKE Station Two Inc. and
Western Kentucky Energy Corp. [Certain portions of this
exhibit have been omitted pursuant to a confidential
treatment request filed with the Securities and Exchange
Commission.]
10.87 x Copy of Form of Lease and Operating Agreement Between
Western Kentucky Energy Corp. and Big Rivers Electric
Corporation
191
Applicable
to Form 10-K of
Exhibit LG&E
No. Energy LG&E KU Description
- ------- ---------- ---------- ---------- -------------
dated July 15, 1998. [Certain portions of this
exhibit have been omitted pursuant to a confidential
treatment request filed with the Securities and Exchange
Commission.]
10.88 x Copy of Power Purchase Agreement Between Big Rivers
Electric Corporation and LG&E Energy Marketing Inc. dated
July 15, 1998. [Certain portions of this exhibit have
been omitted pursuant to a confidential treatment request
filed with the Securities and Exchange Commission.]
10.89 x Copy of Agreement and Amendments to Agreements By and
Among City of Henderson, Kentucky, City of Henderson
Utility Commission, Big Rivers Electric Corporation, WKE
Station Two Inc., LG&E Energy Marketing Inc., and Western
Kentucky Energy Corp. dated July 15, 1998.
10.90 x x x * Copy of Amendment to LG&E Energy's Supplemental
Executive Retirement Plan, effective September 2, 1998.
10.91 x x x * Copy of Amendment effective September 2, 1998 to
Supplemental Executive Retirement Plan for R. W. Hale
effective June 1, 1989.
10.92 x Copy of Terms Agreement among LG&E Capital Corp., LG&E
Energy Corp., Morgan Stanley & Co. Incorporated, Chase
Securities Inc., Merrill Lynch, Pierce, Fenner & Smith
Incorporated and J.P. Morgan Securities Inc. dated October
29, 1998.
12 x x Computation of Ratio of Earnings to Fixed Charges for LG&E
and KU.
21 x x x Subsidiaries of the Registrant.
23.01 x Consent of Independent Public Accountants for LG&E Energy
Corp.
23.02 x Consent of Independent Public Accountants for LG&E.
23.03 x Consent of Independent Public Accountants for KU.
24 x x x Power of Attorney.
27 x x x Financial Data Schedules for LG&E Energy Corp., LG&E and
KU.
192
Applicable
to Form 10-K of
Exhibit LG&E
No. Energy LG&E KU Description
- ------- ---------- ---------- ---------- -------------
99.01 x x x Cautionary Statement for purposes of the "Safe Harbor"
provisions of the Private Securities Litigation Reform Act
of 1995.
99.02 x Description of Common Stock.
99.03 x Director and Officer Information.
(b) Executive Compensation Plans and Arrangements:
Exhibits preceded by an asterisk ("*") above are management contracts,
compensation plans or arrangements required to be filed as an exhibit
pursuant to Item 14(c) of Form 10-K.
(c) Reports on Form 8-K:
On October 2, 1998, the Company filed a report on Form 8-K announcing
that Michael R. Whitley, Vice Chairman of the Board of Directors,
President and Chief Operating Officer of LG&E Energy Corp. announced his
retirement, effective November 1, 1998. Mr. Whitley also retired from the
positions of Vice Chairman of the Board of Directors and Chief Operating
Officer of Louisville Gas and Electric Company and Kentucky Utilities
Company, two public utility subsidiaries of the Company.
On October 21, 1998, the Company filed a report on Form 8-K containing
management's discussion and analysis and consolidated financial
statements of the Company as of December 31, 1997. The Company filed this
report in connection with the May 4, 1998, merger of KU Energy
Corporation and LG&E Energy Corp.
On December 21, 1998, the Company filed a report on Form 8-K announcing
that LG&E Energy Corp. noted the recent decision of the Kentucky Supreme
Court regarding the environmental cost recovery mechanism allowing its
subsidiaries, Kentucky Utilities Company and Louisville Gas and Electric
Company, to recover certain costs associated with environmental
compliance and requiring certain refunds.
On February 11, 1999, the Company filed a report on Form 8-K announcing
that it had realigned its management structure to support its strategy of
aggressively growing the company as the energy services industry moves
toward deregulation.
On March 23, 1999, the Company filed a report on Form 8-K announcing that
on March 15, 1999, LG&E-Westmoreland Rensselaer, a California general
partnership in which LG&E Energy owns a 50% interest, completed the sale
of substantially all the assets and major contracts of its 79 MW
gas-fired cogeneration facility in Rensselaer, New York to Fulton
Cogeneration Associates, L.P., an affiliate of The Coastal Corporation.
(d) The following instruments defining the rights of holders of certain long-
term debt of KU have not been filed with the Securities and Exchange
Commission but will be furnished to the Commission upon request.
193
1. Loan Agreement dated as of May 1, 1990 between KU and the County of
Mercer, Kentucky, in connection with $12,900,000 County of Mercer,
Kentucky, Collateralized Solid Waste Disposal Facility Revenue Bonds
(KU Project) 1990 Series A, due May 1, 2010 and May 1, 2020.
2. Loan Agreement dated as of May 1, 1991 between KU and the County of
Carroll, Kentucky, in connection with $96,000,000 County of Carroll,
Kentucky, Collateralized Pollution Control Revenue Bonds (KU Project)
1992 Series A, due September 15, 2016.
3. Loan Agreement dated as of August 1, 1992 between KU and the County
of Carroll, Kentucky, in connection with $2,400,000 County of
Carroll, Kentucky, Collateralized Pollution Control Revenue Bonds (KU
Project) 1992 Series C, due February 1, 2018.
4. Loan Agreement dated as of August 1, 1992 between KU and the County
of Muhlenberg, Kentucky, in connection with $7,200,000 County of
Muhlenberg, Kentucky, Collateralized Pollution Control Revenue Bonds
(KU Project) 1992 Series A, due February 1, 2018.
5. Loan Agreement dated as of August 1, 1992 between KU and the County
of Mercer, Kentucky, in connection with $7,400,000 County of Mercer,
Kentucky, Collateralized Pollution Control Revenue Bonds (KU Project)
1992 Series A, due February 1, 2018.
6. Loan Agreement dated as of August 1, 1992 between KU and the County
of Carroll, Kentucky, in connection with $20,930,000 County of
Carroll, Kentucky, Collateralized Pollution Control Revenue Bonds (KU
Project) 1992 Series B, due February 1, 2018.
7. Loan Agreement dated as of December 1, 1993, between KU and the
County of Carroll, Kentucky, in connection with $50,000,000 County of
Carroll, Kentucky, Collateralized Solid Waste Disposal Facilities
Revenue Bonds (KU Project) 1993 Series A, due December 1, 2023.
8. Loan Agreement dated as of November 1, 1994, between KU and the
County of Carroll, Kentucky, in connection with $54,000,000 County of
Carroll, Kentucky, Collateralized Solid Waste Disposal Facilities
Revenue Bonds (KU Project) 1994 Series A, due November 1, 2024.
194
Schedule II
LG&E Energy Corp. and Subsidiaries
Schedule II - Valuation and Qualifying Accounts
For the Three Years Ended December 31, 1998
(Thousands of $)
(b)
(a) Accumulated
Other Accounts Discon- Deferred
Property Receivable tinued Income Taxes
and (Uncollectible Operations (NOL Carry-
Investments Accounts) Reserve Forwards)
----------- -------------- ---------- ------------
Balance December 31, 1995 $ 8,785 $ 6,724 $ - $29,501
Additions:
Charged to costs and expenses 11,019 4,840 - -
Other additions 641 616 - -
Deductions:
Net charges of nature for which
reserves were created - 5,059 - -
Other deductions 1,479 - - 3,900
--------- --------- ---------- --------
Balance December 31, 1996 18,966 7,121 - 25,601
Additions:
Charged to costs and expenses 11,875 5,356 - -
Other additions 7,570 1,997 - -
Deductions:
Net charges of nature for which
reserves were created 354 4,212 - -
Other deductions - 75 - -
--------- --------- ---------- --------
Balance December 31, 1997 38,057 10,187 - 25,601
Additions:
Charged to costs and expenses 23,791 4,770 225,000 -
Other additions 1,750 248 - -
Deductions:
Net charges of nature for which
reserves were created 11,399 4,648 105,619 -
Other deductions 108 25 -
--------- --------- ---------- --------
Balance December 31, 1998 $52,091 $10,532 $119,381 $25,601
--------- --------- ---------- --------
--------- --------- ---------- --------
(a) Amounts presented are after tax.
(b) Partially offsets a deferred tax debit included in net assets of
discontinued operations. The debit represents net operating loss
carryforwards available from a previous acquisition.
195
Schedule II
Louisville Gas and Electric Company
Schedule II - Valuation and Qualifying Accounts
For the Three Years Ended December 31, 1998
(Thousands of $)
Other Accounts
Property Receivable
and (Uncollectible
Investments Accounts)
----------- --------------
Balance December 31, 1995 $ 63 $ 1,360
Additions:
Charged to costs and expenses - 2,600
Deductions:
Net charges of nature for which
reserves were created - 2,490
-------- --------
Balance December 31, 1996 63 1,470
Additions:
Charged to costs and expenses - 2,300
Deductions:
Net charges of nature for which
reserves were created - 2,475
-------- --------
Balance December 31, 1997 63 1,295
Additions:
Charged to costs and expenses - 2,300
Deductions:
Net charges of nature for which
reserves were created - 2,196
-------- --------
Balance December 31, 1998 $ 63 $ 1,399
-------- --------
-------- --------
196
Schedule II
Kentucky Utilities Company
Schedule II - Valuation and Qualifying Accounts
For the Three Years Ended December 31, 1998
(Thousands of $)
Other Accounts
Property Receivable
and (Uncollectible
Investments Accounts)
----------- --------------
Balance December 31, 1995 $ 178 $ 455
Additions:
Charged to costs and expenses 85 1,900
Deductions:
Net charges of nature for which
reserves were created - 1,835
------- -------
Balance December 31, 1996 263 520
Additions:
Charged to costs and expenses 82 1,374
Deductions:
Net charges of nature for which
reserves were created - 1,374
------- -------
Balance December 31, 1997 345 520
Additions:
Charged to costs and expenses 231 1,308
Deductions:
Net charges of nature for which
reserves were created - 1,308
------- -------
Balance December 31, 1998 $ 576 $ 520
------- -------
------- -------
197
SIGNATURES - LG&E ENERGY CORP.
(First of Two Pages)
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
LG&E ENERGY CORP.
Registrant
March 31, 1999 /s/ R. Foster Duncan
- -------------- ------------------------------
(Date) R. Foster Duncan
Executive Vice President and
Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the date indicated.
Signature Title Date
- --------- ----- ----
Roger W. Hale Chairman of the Board,
and Chief Executive
Officer (Principal
Executive Officer);
R. Foster Duncan Executive Vice President and
Chief Financial Officer
(Principal Financial Officer);
Michael D. Robinson Vice President and Controller
(Principal Accounting Officer);
Mira S. Ball Director;
William C. Ballard, Jr. Director;
Owsley Brown, II Director;
Carol M. Gatton Director;
Jeffery T. Grade Director;
J. David Grissom Director;
David B. Lewis Director;
Anne H. McNamara Director;
By /s/ R. Foster Duncan March 31, 1999
--------------------
R. Foster Duncan
(Attorney-In-Fact)
198
SIGNATURES - LG&E ENERGY CORP.
(Second of Two Pages)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the date indicated.
Signature Title Date
- --------- ----- ----
T. Ballard Morton, Jr. Director;
Frank V. Ramsey, Jr. Director;
William L. Rouse, Jr. Director;
Charles L. Shearer, Ph.D. Director; and
Lee T. Todd, Jr., Ph.D. Director.
By /s/ R. Foster Duncan March 31, 1999
--------------------
R. Foster Duncan
(Attorney-In-Fact)
199
SIGNATURES - LOUISVILLE GAS AND ELECTRIC COMPANY
(First of Two Pages)
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
LOUISVILLE GAS AND ELECTRIC COMPANY
Registrant
March 31, 1999 /s/ R. Foster Duncan
- -------------- --------------------
(Date) R. Foster Duncan
Executive Vice President and
Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the date indicated.
Signature Title Date
- --------- ----- ----
Roger W. Hale Chairman of the Board
and Chief Executive
Officer (Principal
Executive Officer);
R. Foster Duncan Executive Vice President and
Chief Financial Officer
(Principal Financial Officer);
Michael D. Robinson Vice President and Controller
(Principal Accounting Officer);
Mira S. Ball Director;
William C. Ballard, Jr. Director;
Owsley Brown, II Director;
Gene P. Gardner Director;
Carol M. Gatton Director;
Jeffery T. Grade Director;
J. David Grissom Director;
David B. Lewis Director;
By /s/ R. Foster Duncan March 31, 1999
--------------------
R. Foster Duncan
(Attorney-In-Fact)
200
SIGNATURES - LOUISVILLE GAS AND ELECTRIC COMPANY
(Second of Two Pages)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the date indicated.
Signature Title Date
- --------- ----- ----
Anne H. McNamara Director;
T. Ballard Morton, Jr. Director;
Frank V. Ramsey, Jr. Director;
William L. Rouse, Jr. Director;
Charles L. Shearer, Ph.D. Director;
Dr. Donald C. Swain Director; and
Lee T. Todd, Jr., Ph.D. Director.
By /s/ R. Foster Duncan March 31, 1999
--------------------
R. Foster Duncan
(Attorney-In-Fact)
201
SIGNATURES - KENTUCKY UTILITIES COMPANY
(First of Two Pages)
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
KENTUCKY UTILITIES COMPANY
Registrant
March 31, 1999 /s/ R. Foster Duncan
- -------------- --------------------
(Date) R. Foster Duncan
Executive Vice President and
Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the date indicated.
Signature Title Date
- --------- ----- ----
Roger W. Hale Chairman of the Board
and Chief Executive
Officer (Principal
Executive Officer);
R. Foster Duncan Executive Vice President and
Chief Financial Officer
(Principal Financial Officer);
Michael D. Robinson Vice President and Controller
(Principal Accounting Officer);
Mira S. Ball Director;
William C. Ballard, Jr. Director;
Owsley Brown, II Director;
Carol M. Gatton Director;
Jeffery T. Grade Director;
J. David Grissom Director;
David B. Lewis Director;
Anne H. McNamara Director;
By /s/ R. Foster Duncan March 31, 1999
--------------------
R. Foster Duncan
(Attorney-In-Fact)
202
SIGNATURES - KENTUCKY UTILITIES COMPANY
(Second of Two Pages)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the date indicated.
Signature Title Date
- --------- ----- ----
T. Ballard Morton, Jr. Director;
Frank V. Ramsey, Jr. Director;
William L. Rouse, Jr. Director;
Charles L. Shearer, Ph.D. Director; and
Lee T. Todd, Jr., Ph.D. Director.
By /s/ R. Foster Duncan March 31, 1999
--------------------
R. Foster Duncan
(Attorney-In-Fact)
203