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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