UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington,
D.C.D. C. 20549FormFORM 10-K
X ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (Fee Required) For the fiscal year ended December 31, 1994 TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (No Fee Required) For the transition period from to Commission file number 1-3464 KENTUCKY UTILITIES COMPANY (Exact name of Registrant as specified in its charter) Kentucky and Virginia 61-0247570 (State of Incorporation) (I.R.S. Employer Identification No.) One Quality Street Lexington, Kentucky 40507 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: 606-255-2100 Securities registered pursuant to Section 12(b) of the Act: Name of Each Exchange on Title of Each Class Which Registered Preferred Stock, 4 3/4% cumulative, Philadelphia Stock Exchange, Inc. stated value $100 per share Securities registered pursuant to Section 12(g) of the Act: Preferred stock, cumulative, stated value $100 per share (Title of Class)
(Mark One)
ý
ANNUAL 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, 2002
OR
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
Commission
File NumberRegistrant, State of Incorporation,
Address, and Telephone NumberIRS Employer
Identification Number2-26720
Louisville Gas and Electric Company
61-0264150
(A Kentucky Corporation)
220 West Main Street
P. O. Box 32010
Louisville, Kentucky 40232
(502) 627-20001-3464
Kentucky Utilities Company
61-0247570
(A Kentucky and Virginia Corporation)
One Quality Street
Lexington, Kentucky 40507-1428
(859) 255-2100
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, 6.53% cumulative, stated value $100 per share
Preferred Stock, 4.75% cumulative, stated value $100 per share(Title of class)
Indicate by check mark whether the
Registrantregistrants (1)hashave 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 theRegistrant wasregistrants were required to file such reports), and (2)hashave been subject to such filing requirements for the past 90 days. YesXý No oIndicate 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'sregistrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.( X ) AggregateýIndicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes o No ý
As of June 28, 2002, the aggregate market value of the
votingcommon stockheld by nonaffiliatesofthe Registrant: None Numbereach ofshares of Common Stock outstanding at March 9, 1995: 37,817,878 shares (owned by the parent - KU Energy Corporation). Documents Incorporated by Reference: None Exhibit Index appears on page 42. -1-KENTUCKY UTILITIES COMPANY Form 10-K Annual Report to the SecuritiesLouisville Gas andExchange Commission For the Year Ended December 31, 1994 _____________ TABLE OF CONTENTS Item Page PART I 1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . 9 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . 10 4. Submission of Matters to a Vote of Security Holders . . . . . . 10 Executive Officers of the Registrant . . . . . . . . . . . . . 11 PART II 5. Market for Registrant's Common EquityElectric Company andRelated Stockholder Matters . . . . . . . . . . . . . . . . . . . . . 13 6. Selected Financial Data . . . . . . . . . . . . . . . . . . . . 14 7. Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . . . . 16 8. Financial Statements and Supplementary Data . . . . . . . . . . 24 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . . . . . . . . . . . . . 40 PART III 10. Directors and Executive Officers of the Registrant . . . . . . 40 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . 40 12. Security Ownership of Certain Beneficial Owners and Management 40 13. Certain Relationships and Related Transactions . . . . . . . . 40 PART IV 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 41 Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . 42 Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . 47 -2-PART I Item 1. Business GeneralKentucky Utilities Company(Kentucky Utilities)held by non-affiliates was $0. As of February 28, 2003, Louisville Gas and Electric Company had 21,294,223 shares of common stock outstanding, all held by LG&E Energy Corp. Kentucky Utilities Company 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 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.
DOCUMENTS INCORPORATED BY REFERENCE
Not applicable.
TABLE OF CONTENTS
(a) Incorporated by reference.
INDEX OF ABBREVIATIONS
Capital Corp.
LG&E Capital Corp.
Clean Air Act
The Clean Air Act, as amended in 1990
CCN
Certificate of Public Convenience and Necessity
CT
Combustion Turbines
DSM
Demand Side Management
ECR
Environmental Cost Recovery
EEI
Electric Energy, Inc.
EITF
Emerging Issues Task Force Issue
E.ON
E.ON AG
EPA
U.S. Environmental Protection Agency
ESM
Earnings Sharing Mechanism
F
Fahrenheit
FAC
Fuel Adjustment Clause
FERC
Federal Energy Regulatory Commission
FPA
Federal Power Act
FT and FT-A
Firm Transportation
GSC
Gas Supply Clause
IBEW
International Brotherhood of Electrical Workers
IMEA
Illinois Municipal Electric Agency
IMPA
Indiana Municipal Power Agency
Kentucky Commission
Kentucky Public Service Commission
KIUC
Kentucky Industrial Utility Consumers, Inc.
KU
Kentucky Utilities Company
KU Energy
KU Energy Corporation
KU R
KU Receivables LLC
kV
Kilovolts
Kva
Kilovolt-ampere
KW
Kilowatts
Kwh
Kilowatt hours
LEM
LG&E Energy Marketing Inc.
LG&E
Louisville Gas and Electric Company
LG&E Energy
LG&E Energy Corp.
LG&E R
LG&E Receivables LLC
LG&E Services
LG&E Energy Services Inc.
Mcf
Thousand Cubic Feet
MGP
Manufactured Gas Plant
MISO
Midwest Independent System Operator
Mmbtu
Million British thermal units
Moody’s
Moody’s Investor Services, Inc.
Mw
Megawatts
Mwh
Megawatt hours
NNS
No-Notice Service
NOPR
Notice of Proposed Rulemaking
NOx
Nitrogen Oxide
OATT
Open Access Transmission Tariff
OMU
Owensboro Municipal Utilities
OVEC
Ohio Valley Electric Corporation
PBR
Performance-Based Ratemaking
PJM
Pennsylvania, New Jersey, Maryland Interconnection
Powergen
Powergen Limited (formerly Powergen plc)
PUHCA
Public Utility Holding Company Act of 1935
ROE
Return on Equity
RTO
Regional Transmission Organization
S&P
Standard & Poor’s Rating Services
SCR
Selective Catalytic Reduction
SEC
Securities and Exchange Commission
SERP
Supplemental Employee Retirement Plan
SFAS
Statement of Financial Accounting Standards
SIP
State Implementation Plan
SMD
Standard Market Design
SO2
Sulfur Dioxide
Tennessee Gas
Tennessee Gas Pipeline Company
Texas Gas
Texas Gas Transmission Corporation
TRA
Tennessee Regulatory Authority
Trimble County
LG&E’s Trimble County Unit 1
USWA
United Steelworkers of America
Utility Operations
Operations of LG&E and KU
VDT
Value Delivery Team Process
Virginia Commission
Virginia State Corporation Commission
Virginia Staff
Virginia State Corporation Commission Staff
LG&E and KU are each subsidiaries of LG&E Energy. On December 11, 2000, LG&E Energy was acquired by Powergen plc, now known as Powergen Limited, for cash of approximately $3.2 billion or $24.85 per share and the assumption of all of LG&E Energy’s debt. As a result of the acquisition, among other things, LG&E Energy became a wholly owned subsidiary of Powergen and, as a result, LG&E and KU became indirect subsidiaries of Powergen. The utility operations (LG&E and KU) of LG&E Energy
Corporation (KU Energy).have continued their separate identities and continue to serve customers in Kentucky,UtilitiesVirginia and Tennessee under their existing names. The preferred stock and debt securities of the utility operations were not affected by this transaction resulting in the utility operations’ obligations to continue to file SEC reports. Following the acquisition, Powergen became a registered holding company under PUHCA, and LG&E and KU, as subsidiaries of a registered holding company, became subject to additional regulation under PUHCA.As a result of the Powergen acquisition and in order to comply with PUHCA, LG&E Services was formed as a subsidiary of LG&E Energy effective on January 1, 2001. LG&E Services provides certain services to affiliated entities, including LG&E and KU, at cost as required under PUHCA. On January 1, 2001, approximately 1,000 employees, mainly from LG&E Energy, LG&E and KU, were moved to LG&E Services.
On July 1, 2002, E.ON, a German company, completed its acquisition of Powergen following receipt of all necessary regulatory approvals. E.ON had announced its pre-conditional cash offer of £5.1 billion ($7.3 billion) for Powergen on April 9, 2001.
LOUISVILLE GAS AND ELECTRIC COMPANY
Incorporated in 1913 in Kentucky, LG&E is a regulated public utility that supplies natural gas to approximately 310,000 customers and electricity to approximately 382,000 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, 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. See Item 2, Properties.
LG&E has one wholly owned consolidated subsidiary, LG&E R. LG&E R is a special purpose entity formed in September 2000 to enter into accounts receivable securitization transactions with LG&E. LG&E R started operations in 2001. LG&E is considering unwinding its accounts receivable securitization arrangements involving LG&E R during 2003.
6
For the year ended December 31, 2002, 74% of total operating revenues were derived from electric operations and 26% from gas operations. Electric and gas operating revenues and the percentages by class of service on a combined basis for this period were as follows:
(Thousands of $)
Electric
Gas
Combined
% Combined
Residential
$
232,285
$
160,733
$
393,018
47
%
Commercial
185,112
61,036
246,148
30
%
Industrial
111,871
10,232
122,103
15
%
Public authorities
57,703
11,197
68,900
8
%
Total retail
586,971
243,198
830,169
100
%
Wholesale sales
143,002
16,384
159,386
Gas transported – net
—
6,232
6,232
Provision for rate collections
12,267
—
12,267
Miscellaneous
16,251
1,879
18,130
Total
$
758,491
$
267,693
$
1,026,184
See Note 13 of LG&E’s Notes to Financial Statements under Item 8 for financial information concerning segments of business for the three years ended December 31, 2002.
The sources of LG&E’s electric operating revenues and the volumes of sales for the three years ended December 31, 2002, were as follows:
2002
2001
2000
ELECTRIC OPERATING REVENUES
(Thousands of $)
Residential
$
232,285
$
205,926
$
205,105
Commercial
185,112
171,540
171,414
Industrial
111,871
104,438
104,738
Public authorities
57,703
53,725
54,270
Total retail
586,971
535,629
535,527
Wholesale sales
143,002
159,406
165,080
Provision for rate collections (refunds)
12,267
(720
)
(2,500
)
Miscellaneous
16,251
11,610
12,851
Total
$
758,491
$
705,925
$
710,958
ELECTRIC SALES (Thousands of Mwh):
Residential
4,036
3,782
3,722
Commercial
3,493
3,395
3,350
Industrial
3,028
2,976
3,043
Public authorities
1,253
1,224
1,214
Total retail
11,810
11,377
11,329
Wholesale sales
7,262
6,957
6,834
Total
19,072
18,334
18,163
LG&E uses efficient coal-fired boilers, fully equipped with sulfur dioxide removal systems, to generate most of its
7
electricity. LG&E’s weighted-average system-wide emission rate for sulfur dioxide in 2002 was approximately 0.55 lbs./Mmbtu of heat input, with every generating unit below its emission limit established by the Kentucky Division for Air Quality.
LG&E set a record local peak load of 2,623 Mw on Monday, August 5, 2002, when the peak daily temperature was 100 degrees F.
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 currently maintains a 13 – 15% reserve margin range. At December 31, 2002, LG&E owned steam and combustion turbine generating facilities with a net summer capability of 2,882 Mw and an 80 Mw nameplate rated hydroelectric facility on the Ohio River with a summer capability rate of 48 Mw. At December 31, 2002, LG&E’s system net summer capability, including purchases from others and excluding the hydroelectric facility, was 3,037 Mw. See Item 2, Properties.
LG&E and 11 other electric utilities are participating owners of OVEC located in Piketon, Ohio. OVEC owns and operates two power plants that burn coal to generate electricity, Kyger Creek Station in Ohio and Clifty Creek Station in Indiana. LG&E’s share is 7%, representing approximately 155 Mw’s of generation capacity. LG&E also has agreements with a number of entities throughout the United States for the purchase and/or sale of capacity and energy and for the utilization of their bulk transmission system.
On February 1, 2002, LG&E (along with KU) turned over operational control of its high voltage transmission facilities (100kV and above) to MISO. LG&E (along with KU) is a founding member of MISO. Such membership was obtained in 1998 in response to and consistent with federal policy initiatives. MISO operates a single OATT over the facilities under its control. Currently MISO controls over 100,000 miles of transmission over 1.1 million square miles located in the northern Midwest between Manitoba, Canada and Kentucky. On September 18, 2002, FERC granted a 12.88% ROE on transmission facilities for LG&E, KU and the rest of the MISO owners. This ROE includes a 50 basis point increase because of operational independence.
MISO plans to implement a Congestion Management System in December 2003, in compliance with FERC Order 2000. This system will be similar to the Locational Marginal Pricing (LMP) system currently used by the PJM RTO and contemplated in FERC’s SMD NOPR, currently being discussed. MISO filed with FERC a mechanism for recovery of costs for the Congestion Management System, designated Schedule 16 and Schedule 17. The MISO transmission owners, including LG&E and KU, and others have objected to the allocation of costs between market participants and retail native load. This case is currently in a hearing at FERC.
In October 2001, the FERC issued an order requiring that the bundled retail load and grandfathered wholesale load of each member transmission owner (including LG&E) be included in the current calculation of MISO’s “cost-adder,” a charge designed to recover MISO’s costs of operation, including start-up capital (debt) costs. LG&E, along with several other transmission owners, opposed the FERC’s ruling in this regard, which opposition the FERC rejected in an order on rehearing issued in 2002. Later that year, MISO’s transmission owners, including LG&E, appealed the FERC’s decision to the United States Court of Appeals for the District of Columbia Circuit. In response, by petition filed November 25, 2002, the FERC requested that the Court issue a partial remand of its challenged orders to allow the FERC to revisit certain issues raised therein, and further requested that the case be held in abeyance pending the agency’s resolution of such issues. The Court granted the FERC’s petition by order dated December 6, 2002. On February 24, 2003, FERC issued an order
8
reaffirming its position concerning the calculation of the “cost-adder”.
As a separate matter, MISO, its transmission owners and other interested industry segments reached a settlement in mid-2002 regarding the levelof cost responsibility properly borne by bundled and grandfathered load under these FERC rulings (such settlement expressly not prejudicing the transmission owners’ and LG&E’s right to challenge the FERC’s ruling imposing cost responsibility on bundled loads in the first instance). On February 24, 2003, FERC accepted a partial settlement between MISO and the transmission owners. FERC did not accept the only contested section of the settlement, which would have allowed the transmission owners to immediately treat unrecoverable Schedule 10 charges as regulatory assets. FERC will consider allowing regulatory asset treatment of unrecoverable Schedule 10 charges on a case-by-case basis.
The sources of LG&E’s gas operating revenues and the volumes of sales for the three years ended December 31, 2002, were as follows:
2002
2001
2000
GAS OPERATING REVENUES
(Thousands of $)
Residential
$
160,733
$
177,387
$
159,670
Commercial
61,036
70,296
61,888
Industrial
10,232
15,750
15,898
Public authorities
11,197
13,223
9,193
Total retail
243,198
276,656
246,649
Wholesale sales
16,384
5,702
17,344
Gas transported – net
6,232
6,042
6,922
Miscellaneous
1,879
2,375
1,574
Total
$
267,693
$
290,775
$
272,489
GAS SALES (Millions of cu. ft.):
Residential
22,124
20,429
24,274
Commercial
9,074
8,587
10,132
Industrial
1,783
2,160
3,089
Public authorities
1,747
1,681
1,576
Total retail
34,728
32,857
39,071
Wholesale sales
5,345
1,882
5,115
Gas transported
13,939
13,108
14,729
Total
54,012
47,847
58,915
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 five underground natural gas storage fields that help provide economical and reliable gas service to ultimate consumers. By using gas storage facilities, LG&E avoids the costs associated with typically more expensive pipeline transportation capacity to serve peak winter space-heating loads. LG&E stores gas in the summer season for withdrawal in the subsequent winter heating season. Without its storage capacity, LG&E would be forced to buy additional gas and pipeline transportation services when customer demand increases, likely to be when the price for those items are typically at their highest. Currently, LG&E buys competitively
9
priced gas from several large suppliers under contracts of varying duration. LG&E’s underground storage facilities, in combination with its purchasing practices, enable it to offer gas sales service at rates lower than state and national averages. At December 31, 2002, LG&E had an inventory balance of gas stored underground of 12.6 million Mcf valued at $50.3 million.
A number of industrial customers purchase their natural gas requirements directly from alternate suppliers for delivery through LG&E’s distribution system. These large industrial customers account for about one-fourth of LG&E’s annual throughput.
The all-time maximum day gas sendout of 545,000 Mcf occurred on Sunday, January 20, 1985, when the average temperature for the day was -11 degrees F. During 2002, maximum day gas sendout was approximately 418,000 Mcf, occurring on February 27, 2002, when the average temperature for the day was 21 degrees F. Supply on that day consisted of approximately 130,000 Mcf from purchases, approximately 221,000 Mcf delivered from underground storage, and approximately 67,000 Mcf transported for industrial customers. For a further discussion, see Gas Supply under Item 1.
Following the purchase of Powergen by E.ON, E.ON became a registered holding company under PUHCA. As a result, E.ON, its utility subsidiaries, including LG&E, and certain of its non-utility subsidiaries are subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales of securities, acquisitions and sales of certain utility properties, and intra-system sales of certain goods and services. In addition, PUHCA generally limits the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company. LG&E believes that it has adequate authority (including financing authority) under existing SEC orders and regulations to conduct its business. LG&E will seek additional authorization when necessary.
No costs associated with the E.ON purchase of Powergen or the Powergen purchase of LG&E Energy nor any effects of purchase accounting have been reflected in the financial statements of LG&E.
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 FPA, and is subject to the jurisdiction of the Department of Energy and FERC with respect to the matters covered in the FPA, including the sale of electric energy at wholesale in interstate commerce.
For a discussion of current regulatory matters, see Rates and Regulation for LG&E under Item 7 and Note 3 of LG&E’s Notes to Financial Statements under Item 8.
LG&E’s retail electric rates contain a FAC, whereby increases and decreases in the cost of fuel for electric generation are reflected in the rates charged to retail electric customers. 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 Kentucky 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.
LG&E’s retail electric rates are subject to an ESM. The ESM, initially in place for three years beginning in 2000, sets an upper and lower point for rate of return on equity, whereby if LG&E’s rate of return for the calendar year
10
falls within the range of 10.5% to 12.5%, no action is necessary. If earnings are above the upper limit, the excess earnings are shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, the earnings deficiency is recovered 40% from ratepayers and 60% from shareholders. By order of the Kentucky Commission, rate changes prompted by the ESM filing go into effect in April of each year subject to a balancing adjustment in successive periods. LG&E made its second ESM filing on March 1, 2002, for the calendar year 2001 reporting period. LG&E is in the process of refunding $441,000 to customers for the 2001 reporting period. LG&E estimated that the rate of return will fall below the lower limit, subject to Kentucky Commission approval, for the year ended December 31, 2002. The 2002 financial statements include an accrual to reflect the earnings deficiency of $12.5 million to be recovered from customers commencing in April 2003.
On November 27, 2002, LG&E filed a revised ESM tariff which proposed continuance of the existing ESM through 2005. The Kentucky Commission issued an Order suspending the ESM tariff one day making the effective date January 2, 2003. In addition, the Kentucky Commission is conducting a management audit to review the ESM plan and reassess its reasonableness in 2003. LG&E and interested parties will have the opportunity to provide recommendations for modification and continuance of the ESM or other forms of alternative or incentive regulation.
LG&E’s retail rates contain an ECR surcharge which recovers certain costs incurred by LG&E that are required to comply with the Clean Air Act and other environmental regulations. See Note 3 of LG&E’s Notes to Financial Statements under Item 8.
LG&E’s gas rates contain a GSC, whereby increases or decreases in the cost of gas supply are reflected in LG&E’s rates, subject to approval by the Kentucky Commission. The GSC procedure prescribed by order of the Kentucky 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.
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 load, capacity margins and demand-side management techniques. LG&E filed its most recent integrated resource plan on October 1, 2002.
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 this service territory each such supplier has the exclusive right to render retail electric service.
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, 2002, gross property additions amounted to approximately $950 million. Internally generated funds and external financings for the five-year period were utilized to provide for these gross additions. The gross additions during this period amounted to approximately 26% of total utility plant at
11
December 31, 2002, and consisted of $798 million for electric properties and $152 million for gas properties. Gross retirements during the same period were $106 million, consisting of $74 million for electric properties and $32 million for gas properties.
Coal-fired generating units provided over 97% of LG&E’s net kilowatt-hour generation for 2002. The remaining net generation was provided by a natural gas and oil fueled combustion turbine peaking units and a hydroelectric plant. 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 2003 and beyond. LG&E normally augments its coal supply agreements with spot market purchases. LG&E has a coal inventory policy which it believes provides adequate protection under most contingencies. LG&E had a coal inventory of approximately 1.5 million tons, or a74-day supply, on hand at December 31, 2002.
LG&E expects to continue purchasing most of its coal, with sulfur content in the 2%-4.5% range, from western Kentucky, southwest Indiana, and West Virginia for the foreseeable future. This supply is relatively low priced coal, and in combination with its sulfur dioxide removal systems is expected to enable LG&E to continue to provide electric service in compliance with existing environmental laws and regulations.
Coal is delivered to LG&E’s Mill Creek plant by rail and barge, Trimble County plant by barge and Cane Run plant by rail.
The historical average delivered costs of coal purchased and the percentage of spot coal purchases were as follows:
2002
2001
2000
Per ton
$
25.30
$
21.27
$
20.96
Per Mmbtu
$
1.11
$
.93
$
.92
Spot purchases as % of all sources
2
%
3
%
1
%
The delivered cost of coal is expected to remain relatively flat during 2003. Slight increases in the cost of coal in multi-year contracts signed for 2002 are expected to be offset by lower prices negotiated in contracts signed for 2003.
LG&E purchases natural gas supplies from multiple sources under contracts for varying periods of time, while transportation services are purchased from Texas Gas and Tennessee Gas.
On April 28, 2000, Texas Gas filed with FERC in Docket RP00-260 for an increase in its base rates effective June 1, 2000. This filing is part of a rate case Texas Gas was required to file pursuant to the settlement in its last rate case. On May 31, 2000, FERC issued an Order suspending the effectiveness of Texas Gas’s proposed rates, subject to refund, until November 1, 2000, and establishing a hearing and settlement procedures. As the result of reaching various FERC-approved settlements, Texas Gas’s higher motion rates were not billed after July 31, 2002, and its lower prospective rates went into effect on August 1, 2002. Refunds covering the period from November 1, 2000, through July 31, 2002, were received on September 17, 2002, and are currently being
12
refunded to customers through the GSC. LG&E participates in rate and other proceedings affecting its regulated interstate pipeline services, as appropriate.
LG&E transports on the Texas Gas system under NNS and FT rate schedules. During the winter months, LG&E has 184,900 Mmbtu/day in NNS service and 18,000 Mmbtu/day (increasing to 36,000 Mmbtu/day effective November 1, 2003) in FT service. LG&E’s summer NNS levels are 60,000 Mmbtu/day and its summer FT levels are 54,000 Mmbtu/day. Each of these NNS and FT agreements with Texas Gas are subject to termination by LG&E in equal portions during 2005, 2006, and 2008. LG&E also transports on the Tennessee system under Tennessee’s FT-A rate schedule. LG&E’s contract levels with Tennessee are 51,000 Mmbtu/day throughout the year. The FT-A agreement with Tennessee, which was subject to termination by LG&E during 2002, has been successfully renegotiated for a minimum additional term of five years at a lower price.
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 that are market-responsive. These firm gas supplies, in tandem with pipeline transportation services, provide the reliability and flexibility necessary to serve LG&E’s customers.
LG&E owns and operates five underground gas storage fields with a current working gas capacity of about 15.1 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. See Gas Operations under Item 1.
The estimated maximum deliverability from storage during the early part of the heating season is typically about 373,000 Mcf/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 $4.19 in 2002, $5.27 in 2001 and $5.08 in 2000. Although natural gas prices in the unregulated wholesale market increased significantly throughout 2000 and early 2001, these prices decreased dramatically in early 2002 and then began to increase again. These increases in natural gas prices, caused in part by decreased natural gas production, decreased liquidity in the marketplace, increases in the price of oil, and increased reliance on natural gas as a fuel for electric generation were mitigated in part by higher national storage inventory levels, and decreased demand associated with a less robust economy.
Protection of the environment is a major priority for LG&E. Federal, state, and local regulatory 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 2002, expenditures for pollution control facilities represented $253.8 million or 27% of total construction expenditures. LG&E estimates that construction expenditures for the installation of NOx control equipment from 2003 through 2004 will be approximately $32 million. For a discussion of environmental matters, see Rates and Regulation for LG&E under Item 7 and Note 11 of LG&E’s Notes to Financial Statements under Item 8.
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
13
deferred expenses; an increase in focus on commercial, industrial and residential customers; 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 will continue to take additional steps to better position itself for competition in the future.
KU, incorporated in Kentucky in 1912 and incorporated in Virginia in 1991, is a regulated public utility engaged in producing, transmitting and selling electric energy.
Kentucky UtilitiesKU provides electric service toabout 418,100approximately 477,000 customers in over 600 communities and adjacent suburban and rural areas in 77 counties in central, southeastern and western Kentucky,andtoabout 28,300approximately 30,000 customers in 5counties in southwesternVirginia.Virginia and to less than 10 customers in Tennessee. In Virginia,Kentucky UtilitiesKU operates under the name Old Dominion Power Company.OfKU operates under appropriate franchises in substantially all of theKentucky communities,160areKentucky incorporated municipalitiesserved under unexpired municipal franchises and the rest are unincorporated communities where noserved. No franchises arerequired. Service has been providedrequired in unincorporated Kentucky or Virginiawithout franchises for a number of years. Thiscommunities. The lack ofVirginiafranchises is not expected to have a material adverse effect onKentucky Utilities' operations. Kentucky UtilitiesKU’s operations. KU also sells wholesale electric energyat wholesale for resaleto 12 municipalities.KU has one wholly owned consolidated subsidiary, KU R. KU R is a special purpose entity formed in
12 municipalities. The territory served by Kentucky Utilities has an aggregate population estimated at about 1,000,000. The largest city servedSeptember 2000 to enter into accounts receivable securitization transactions with KU. KU R began operations in 2001. KU isLexington, Kentucky.considering unwinding its accounts receivable securitization arrangements involving KU R during 2003.14
The
population of the metropolitan Lexington area is estimated at about 225,000. The populations of the next 10 largest cities served at retail range from about 21,000 to 9,000. The territory served includes most of the Blue Grass Region of central Kentucky and parts of the coal mining areas in southeastern and western Kentucky and southwestern Virginia. Lexington is the center of the Blue Grass Region, in which thoroughbred horse, burley tobacco and bourbon whiskey distilling industries are located. Among the principal industries in the territory served are coal mining, automotive and related industries, the manufacture of paper and paper products and of electrical and other machinery and primary metals processing. Revenues Kentucky Utilities'sources of KU’s electric operating revenues and therespective percentagesvolumes oftotal revenuessales for the three years1992-1994ended December 31, 2002, were as follows:degrees F.
Year Ended December 31, 1994 1993 1992 Amount % Amount % Amount % (dollars in thousands)Residential $ 213,574 34 $210,759 35 $ 194,817 34 Commercial 142,207 22 138,271 23 133,519 23 Industrial 120,043 19 111,857 18 102,808 18 Mine Power 36,498 6 34,977 6 36,696 7 Public Authorities 49,869 8 48,142 8 45,570 8 Other Electric Utilities 89,665 14 62,463 10 58,979 10 Miscellaneous Revenues 4,181 - 3,428 - 3,432 - Provision for Refund - Litigation Settlement (19,385) (3) (3,309) - - - Total $ 636,652 100 $606,588 100 $ 575,821
2002
2001
2000
ELECTRIC OPERATING REVENUES
(Thousands of $):
Residential
$
275,869
$
244,004
$
241,783
Commercial
179,157
165,389
161,291
Industrial
163,206
146,968
153,017
Mine power
29,453
28,196
27,089
Public authorities
62,649
58,770
57,979
Total retail
710,334
643,327
641,159
Wholesale sales
143,807
203,181
198,073
Provision for rate collections (refunds)
13,027
(954
)
—
Miscellaneous
21,051
13,918
12,709
Total
$
888,219
$
859,472
$
851,941
ELECTRIC SALES (Thousands of Mwh):
Residential
6,198
5,678
5,714
Commercial
4,161
3,990
3,954
Industrial
4,975
4,716
5,044
Mine power
766
771
767
Public authorities
1,533
1,481
1,495
Total retail
17,633
16,636
16,974
Wholesale sales
5,780
7,713
7,573
Total
23,413
24,349
24,547
KU’s weighted-average system-wide emission rate for sulfur dioxide in 2002 was approximately1.24lbs./Mmbtuof heat input, with every generating unit below its emission limit established by the Kentucky Division for Air Quality.
KU set a record local peak load of 3,899 Mw on Monday, August 5, 2002, when the peak daily temperature was 100
The electric utility business is affected by
varyingseasonal weather patterns. As a result, operating revenues (and associated operating expenses) are not generated evenly throughout the year. SeeItem 7, Management's Discussion and Analysis of Financial Condition andKU’s Results-3-of Operations - Sales and Revenues for information related to revenues from sales to Other Electric Utilities. -4-Operations Kentucky Utilities' net generating capability was 3,265 megawatts atunder Item 7.KU currently maintains a 13-15% reserve margin range. At December 31,
1994. An additional 110-megawatt2002, KU owned steam and combustion turbinepeaking unit was placed into commercial operation in February 1995. Thegenerating facilities with a netgeneratingsummer capabilityavailable for operation at any time may be lower becauseofperiodic outages4,111 Mw and a hydroelectric facility with a summer capability ofgenerating units due to inspection, maintenance, fuel restrictions, or modifications required by regulatory agencies. Kentucky Utilities24 Mw. See Item 2, Properties. KU obtains power from other utilities under bulk power purchase and interchange contracts. At December 31,1994, Kentucky Utilities'2002, KU’s system net summer capability, including purchases from others and excluding the hydroelectric facility, was3,805 megawatts. The all-time system peak demand, on a one-hour integrated basis, occurred on July 28, 1993 and was 3,176 megawatts. The percentage of Kentucky Utilities' system output which was internally generated and purchased for the periods indicated was as follows: 1994 1993 1992 Internally Generated 83% 89% 87% Purchased 17% 11% 13% Kentucky Utilities is one of 28 members of the East Central Area Reliability Coordination Agreement, the purpose of which is to augment the reliability of the members' bulk power supply through coordination of planning and operation of generation and transmission facilities. The members are engaged in the generation, transmission and sale of electric power and energy in the east central area of the United States, which covers all or portions of Michigan, Indiana, Ohio, Kentucky, Pennsylvania, Virginia, West Virginia and Maryland. Kentucky Utilities also has interconnections and contractually established operating arrangements with neighboring utilities and cooperatives.4,630 Mw.Under a contract expiring in 2020 with
Owensboro Municipal Utilities (OMU), Kentucky UtilitiesOMU, KU has agreed to purchase from OMU the surplus output of the150- megawatt150-Mw and250-megawatt250-Mw generating units atOMU'sOMU’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 byKentucky Utilities.KU. Such powerconstituted aboutequated to approximately 8% ofKentucky Utilities'KU’s net15
generation system output during
1994.2002. See Note411 oftheKU’s Notes to FinancialStatements. Kentucky UtilitiesStatements under Item 8.KU owns 20% of the common stock of
Electric Energy, Inc. (EEI),EEI, which owns and operates a1,000-megawatt1,000-Mw generating station in southern Illinois.Kentucky Utilities' entitlementKU is entitled to take 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 powerconstituted about 8%equated to approximately 9% ofKentucky Utilities'KU’s net generation system output in1994.2002. See Note411 oftheKU’s Notes to FinancialStatements.Statements under Item 8.KU and 11 other electric utilities are participating owners of OVEC located in Piketon, Ohio. OVEC owns and operates two power plants that burn coal to generate electricity, Kyger Creek Station in Ohio and Clifty Creek Station in Indiana. KU’s share is 2.5%, approximately 55 Mws of generation capacity. KU also has agreements with a 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 systems.
On February 1, 2002, KU (along with LG&E) turned over operational control of its high voltage transmission facilities (100kV and above) to MISO. KU (along with LG&E) is a founding member of MISO. Such membership was obtained in 1998 in response to and consistent with federal policy initiatives. MISO operates a single OATT over the facilities under its control. Currently MISO controls over 100,000 miles of transmission over 1.1 million square miles located in the northern Midwest between Manitoba, Canada and Kentucky. On September 18, 2002, FERC granted a 12.88% ROE on transmission facilities for LG&E, KU and the rest of the MISO owners. This ROE includes a 50 basis point increase because of operational independence.
MISO plans to implement a Congestion Management System in December 2003, in compliance with FERC Order 2000. This system will be similar to the Locational Marginal Pricing (LMP) system currently used by the PJM RTO and contemplated in FERC’s SMD NOPR currently being discussed. MISO filed with FERC a mechanism for recovery of costs for the Congestion Management System, designated Schedule 16 and Schedule 17. MISO transmission owners, including LG&E and KU, and others have objected to the allocation of costs between market participants and retail native load. This case is currently in a hearing at FERC.
In October 2001, the FERC issued an order requiring that the bundled retail load and grandfathered wholesale load of each member transmission owner (including KU) be included in the current calculation of MISO’s “cost-adder,” a charge designed to recover MISO’s costs of operation, including start-up capital (debt) costs. KU, along with several other transmission owners, opposed the FERC’s ruling in this regard, which opposition the FERC rejected in an order on rehearing issued in 2002. Later that year, MISO’s transmission owners, including KU, appealed the FERC’s decision to the United States Court of Appeals for the District of Columbia Circuit. In response, by petition filed November 25, 2002, FERC requested that the Court issue a partial remand of its challenged orders to allow the FERC to revisit certain issues raised therein, and further requested that the case be held in abeyance pending the agency’s resolution of such issues. The Court granted the FERC’s petition by order dated December 6, 2002. On February 24, 2003, FERC issued an order reaffirming its position concerning the calculation of the “cost-adder”.
As a separate matter, MISO, its transmission owners and other interested industry segments reached a settlement in mid-2002 regarding the levelof cost responsibility properly borne by bundled and grandfathered load under these FERC rulings (such settlement expressly not prejudicing the transmission owners’ and KU’s right to challenge the FERC’s ruling imposing cost responsibility on bundled loads in the first instance). On February 24, 2003, FERC accepted a partial settlement between MISO and the transmission owners. FERC did not accept the only contested section of the settlement, which would have allowed the transmission owners to immediately treat unrecoverable Schedule 10 charges as regulatory assets. FERC will consider allowing
16
regulatory asset treatment of unrecoverable Schedule 10 charges on a case-by-case basis.
Following the purchase of Powergen by E.ON, E.ON became a registered holding company under PUHCA. As a result, E.ON, its utility subsidiaries, including KU, and certain of its non-utility subsidiaries are subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales of securities, acquisitions and sales of certain utility properties, and intra-system sales of certain goods and services. In addition, PUHCA generally limits the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company. KU believes that it has adequate authority (including financing authority) under existing SEC orders and regulations to conduct its business. KU will seek additional authorization when necessary.
No costs associated with the E.ON purchase of Powergen or the Powergen purchase of LG&E Energy nor any effects of purchase accounting have been reflected in the financial statements of KU.
The Kentucky
Utilities hadCommission and the Virginia Commission have regulatory jurisdiction over KU’s retail rates and service, and over the issuance of certain of its securities. By reason of owning and operating a small amount of electric utility property in one county in Tennessee (having a gross book value of approximately2,240 employees$225,000) from which KU served five customers at December 31,1994,2002, KU is subject to the jurisdiction of the TRA. FERC has classified KU as a “public utility” as defined in the FPA. FERC has jurisdiction under the 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.For a discussion of current regulatory matters, see Rates and Regulation for KU under Item 7 and Note 3 of KU’s Notes to the Financial Statements under Item 8.
KU’s Kentucky retail electric rates contain a FAC, whereby increases and decreases in the cost of fuel for electric generation are reflected in the rates charged to retail electric customers. 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 Kentucky Commission also requires that electric utilities, including KU, file certain documents relating to fuel procurement and the purchase of power and energy from other utilities. The FAC 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.
KU’s Kentucky retail electric rates are subject to an ESM. The ESM, initially in place for three years beginning in 2000, sets an upper and lower point for rate of return on equity, whereby if KU’s rate of return for the calendar year falls within the range of 10.5% to 12.5%, no action is necessary. If earnings are above the upper limit, the excess earnings are shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, the earnings deficiency is recovered 40% from ratepayers and 60% from shareholders. By order of the Kentucky Commission, rate changes prompted by the ESM filing go into effect in April of each year subject to a balancing adjustment in successive periods. KU made its second ESM filing on March 1, 2002 for the calendar year 2001 reporting period. KU is in the process of refunding $1 million to customers for the 2001 reporting period. KU estimated that the rate of return will fall below the lower limit for the year ended December 31, 2002. The 2002 financial statements include an accrual to reflect the earnings, subject to Kentucky Commission approval, deficiency of $13.5 million to be recovered from customers commencing in April 2003.
17
On November 27, 2002, KU filed a revised ESM tariff which
about 300proposed continuance of the existing ESM through 2005. The Kentucky Commission issued an Order suspending the ESM tariff one day making the effective date January 2, 2003. In addition, the Kentucky Commission is conducting a management audit to review the ESM plan and reassess its reasonableness in 2003. KU and interested parties will have the opportunity to provide recommendations for modification and continuance of the ESM or other forms of alternative or incentive regulation.KU’s Kentucky retail rates contain an ECR surcharge which recovers certain costs incurred by KU that are
covered by union contracts expiring August 1995. -5-Fuel Matters Coal-burningrequired to comply with the Clean Air Act and other environmental regulations. See Note 3 of KU’s Notes to Financial Statements under Item 8.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 load, capacity margins and demand-side management techniques. KU filed its most recent integrated resource plan on October 1, 2002.
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 this service territory each such supplier has the exclusive right to render retail electric service.
The state of Virginia passed the Virginia Electric Utility Restructuring Act in 1999. This act gives Virginia customers a choice for energy services. The change will be phased in gradually between January 2002 and January 2004. KU filed unbundled rates that became effective January 1, 2002. Rates are capped at current levels through June 2007. The Virginia Commission will continue to require 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. The Virginia Staff will issue a Staff Report regarding the individual utility’s financial performance during the historic 12-month period. The Staff Report can lead to an adjustment in rates, but through June 2007 will be limited to decreases. KU was granted a waiver from the Virginia Commission on October 29, 2002, exempting KU from retail choice through December 31, 2004. KU is also seeking a permanent legislative exemption from the Virginia Electric Utility Restructuring Act. The outcome of this legislative initiative is not expected be known until mid-2003.
Construction Program and Financing
KU’s construction program is designed to ensure that there will be adequate capacity and reliability to meet the electric 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 five years ended December 31, 2002, gross property additions amounted to approximately $754 million. Internally generated funds and external financings for the five-year period were utilized to provide for these gross additions. The gross additions during this period amounted to approximately 23% of total utility plant at December 31, 2002. Gross retirements during the same period were $82 million.
Coal-fired generating units provided
more than 99%over 97% ofKentucky Utilities'KU’s net kilowatt-hour generation for1994.2002. Theremainder of Kentucky Utilities'remaining18
net generation for
19942002 was provided byhydroelectric plants, oil and/ornatural gasburning units. The average delivered cost of coal purchased, per tonandper million BTU (MBTU),oil fueled combustion turbine peaking units and hydroelectric plants. Coal will be thepercentage of spot coal purchasespredominant fuel used by KU in the foreseeable future, with natural gas and oil being used for capacity and flame stabilization in coal-fired boilers or in emergencies. KU has no nuclear generating units and has no plans to build any in theperiods indicated were as follows: 1994 1993 1992 Per ton - all sources $ 28.91 $ 27.92 $ 27.94 Per MBTU - all sources $ 1.19 $ 1.15 $ 1.16 Per ton - spot purchases only $ 28.33 $ 26.23 $ 25.32 Per MBTU - spot purchases only $ 1.16 $ 1.08 $ 1.07 Spot purchases as % of all sources 46 % 44 % 42 % Kentucky Utilitiesforeseeable future.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
strikesissues and other supplier or transporter operating difficulties.Kentucky UtilitiesKU 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.
Kentucky UtilitiesKU intends to meet asubstantialportion of its coal requirements with5 yearthree-year or shorter contracts.Kentucky Utilities anticipates that coal supplied under such agreements will represent about two-thirds of the requirements over the next several years.As part of this strategy,Kentucky Utilities is currently andKU will continue to negotiate replacement contracts as contracts expire.Kentucky UtilitiesKU does not anticipate any problems negotiating new contracts for future coal needs. The balance of coal requirements will be met through spot purchases.SeeKU had a coal inventory of approximately 1.4 million tons, or a 67-day supply, on hand at December 31, 2002.KU expects to continue purchasing most of its coal, which has a sulfur content in the 0.7% - 3.5% range, from western and eastern Kentucky, West Virginia, southwest Indiana, Wyoming and Pennsylvania for the foreseeable future.
Coal for Ghent is delivered by barge. Deliveries to the Tyrone and Green River locations are by truck. Delivery to E.W. Brown is by rail.
The historical average delivered cost of coal purchased and the percentage of spot coal purchases were as follows:
2002
2001
2000
Per ton
$
31.44
$
27.84
$
25.63
Per Mmbtu
$
1.35
$
1.20
$
1.07
Spot purchases as % of all sources
18
%
44
%
51
%
KU’s historical average cost of coal purchased is higher than LG&E’s due to the lower sulfur content of the coal KU purchases for use at its Ghent plant and higher cost to transport coal to the E.W. Brown plant. The delivered cost of coal is expected to increase during 2003.
Protection of the environment is a major priority for KU. Federal, state, and local regulatory 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 2002, expenditures for pollution control facilities represented $63.5 million or 11% of total construction expenditures. KU estimates that construction expenditures for the installation of NOx control equipment from 2003 through 2004 will be approximately $178 million. For a discussion of environmental matters, see Rates and Regulation for KU under Item 7 and Note
411 oftheKU’s Notes to Financial Statements under Item 8.In the last several years, KU has taken many steps to prepare for the
estimated obligations under fuel contractsexpected increase in competition in its19
industry, including a reduction in the number of employees; aggressive cost cutting; an increase in focus on commercial, industrial and residential customers; an increase in employee involvement and training; a major realignment and formation of new business units; and continuous modifications of its organizational structure. KU will continue to take additional steps to better position itself for
eachcompetition in the future.LG&E had 891 full-time regular employees and KU had 946 full-time regular employees at December 31, 2002. Of the LG&E total, 628 operating, maintenance, and construction employees were represented by IBEW Local 2100. LG&E and employees represented by IBEW Local 2100 signed a four-year collective bargaining agreement in November 2001. Of the KU total, 162 operating, maintenance, and construction employees were represented by IBEW Local 2100 and USWA Local 9447-01. In August 2001, KU and employees represented by IBEW Local 2100 entered into a two-year collective bargaining agreement. KU and employees represented by USWA Local 9447-01 entered into a three-year collective bargaining agreement effective August 2002 and expiring August 2005.
As a result of the
years 1995 through 1999. Kentucky Utilities has no long-term contracts in place for the purchase of natural gas for its combustion turbine peaking units. Kentucky Utilities does not anticipate encountering any significant problems acquiring an adequate supply of fuel necessary to operate its new peaking units. See "Construction" for a discussion of Kentucky Utilities' plans to add peaking capacity. Environmental Matters FederalPowergen acquisition andstate agencies have adopted environmental protection standards which apply to the electric operations of Kentucky Utilities. Capital expenditures to comply with these standards amounted to about $185 million during the 1990-1994 time period. Kentucky Utilities' generating units are operated in compliance with the Kentucky Natural Resources and Environmental Protection Cabinet's (the "Cabinet") State Implementation Plan (the "KYSIP") and New Source Performance Standards developed under the Clean Air Act. The KYSIP is a federally-approved plan for the attainment of the national ambient air quality standards. The KYSIP contains standards relating to the emissions of various pollutants (sulfur dioxide, particulates and -6-nitrogen oxides) from Kentucky Utilities' fossil-fuel fired steam electric generating units. These emission standards are of varying stringencies and compliance with these standards is attained through a variety of air pollution control technologies (scrubbers, electrostatic precipitators, and low NOx burners) and the use of low sulfur coal. Kentucky Utilities' operations are in substantial compliance with current emission standards. The acid rain control provisions of the 1990 Clean Air Act Amendments, which are effective in two phases, require Kentucky Utilities to further decrease the emissions of sulfur dioxide and nitrogen oxides from its fossil-fuel fired steam electric generating units. Ghent Unit 1, E. W. Brown Units 1, 2 and 3, and Green River Unit 4 have been designated as Phase I affected units which are required to comply with sulfur dioxide emission reduction obligations beginning January 1, 1995. In order to comply with these sulfur dioxide emission limitations, Kentucky Utilities has installed a scrubber and related facilities on Ghent Unit 1 (which was declared commercial December 20, 1994) and switched to lower sulfur coal on some other Phase I affected units. In addition, the retrofit of low NOx burners on these units is requiredin order to comply withnitrogen oxide limitations and is expected to be complete in the Spring of 1995, which is in compliance with applicable requirements of the United States Environmental Protection Agency (EPA). The EPA issued final acid rain permits for each of Kentucky Utilities' Phase I affected units. The EPA's approval of Kentucky Utilities acid rain compliance planPUHCA, LG&E Services wasaccompanied by bonus allowances awarded for the installation of the scrubberformed effective onGhent Unit 1 and an extension of the Phase I effective date toJanuary 1,1997, for2001. LG&E Services provides certainportions ofservices to affiliated entities, including LG&E and KU, at cost as required under thesulfur dioxide emission limitations. Kentucky Utilities' current emission allowance strategy is to bank unused sulfur dioxide emission allowances. These unused allowances result from the bonus allowances received from the EPA and the expected reduced sulfur dioxide emissions from the installation of the Ghent Unit 1 scrubber. These banked allowances are expected to allow Kentucky Utilities to delay capital expenditures associated with Kentucky Utilities' Phase II acid rain compliance obligations, which are effectiveHolding Company Act. On January 1,2000. Kentucky Utilities' Phase II compliance strategy,2001, approximately 1,000 employees, mainly from LG&E Energy, LG&E and KU, were moved to LG&E Services.See Note 3 of LG&E’s Notes to Financial Statements and Note 3 of KU’s Notes to Financial Statements under Item 8 for workforce separation program in
addition to utilizing banked allowances, may include additional fuel switching or the installationeffect for 2001.20
Executive Officers of
additional scrubbers. However, Kentucky Utilities will continue to reassess its options for complying with Phase II emission reduction requirements to determine an overall least cost strategy. See Item 7, Management's DiscussionLG&E andAnalysisKU at December 31, 2002:
Name
Age
Position
Effective Date of
Election to Present
PositionVictor A. Staffieri
47
Chairman of the Board,
President and Chief
Executive OfficerMay 1, 2001
Richard Aitken-Davies
53
Chief Financial Officer
January 31, 2001
John R. McCall
59
Executive Vice President,
General Counsel and
Corporate SecretaryJuly 1, 1994
S. Bradford Rives
44
Senior Vice President -
Finance and ControllerDecember 11, 2000
Paul W. Thompson
45
Senior Vice President -
Energy ServicesJune 7, 2000
Chris Hermann
55
Senior Vice President -
Distribution OperationsDecember 11, 2000
Wendy C. Welsh
48
Senior Vice President -
Information TechnologyDecember 11, 2000
Martyn Gallus
38
Senior Vice President -
Energy MarketingDecember 11, 2000
A. Roger Smith
49
Senior Vice President
Project EngineeringDecember 11, 2000
David A. Vogel
36
Vice President – Retail
ServicesDecember 11, 2000
Daniel K. Arbough
41
Treasurer
December 11, 2000
Bruce D. Hamilton
47
Vice President
Independent Power OperationsDecember 11, 2000
Robert E. Henriques
61
Vice President
Regulated GenerationSeptember 30, 2001
Michael S. Beer
44
Vice President-Rates
and RegulatoryFebruary 1, 2001
George R. Siemens
53
Vice President-External
AffairsJanuary 11, 2001
Paula H. Pottinger
45
Vice President -
Human ResourcesJune 1, 2002
D. Ralph Bowling
45
Vice President -
Power Operations WKEAugust 1, 2002
R. W. Chip Keeling
46
Vice President -
CommunicationsMarch 18, 2002
21
The present term of
Financial Condition and Resultsoffice ofOperations - Construction Requirements and - Environmental Matters for additional discussion. During 1990, each of Kentucky Utilities' five fossil-fuel fired steam electric generating stations was re-issued a wastewater discharge permit by the Cabinet under the Clean Water Act's National Pollutant Discharge Elimination System. These 5-year permits place water quality-based effluent limitations (i.e., thermal and chemical limits) oneach of thepower plant's discharges. Kentucky Utilities' operationsabove executive officers extends to the meeting of the Board of Directors following the 2003 Annual Meeting of Shareholders.There are
in substantial compliance withno family relationships between or among executive officers of LG&E and KU. The above tables indicate officers serving as executive officers of both LG&E and KU at December 31, 2002. Each of theconditionsabove officers serves in thepermits.same capacity for LG&E and KU.Before he was elected to his current positions, Mr. Staffieri was President, Distribution Services Division of LG&E Energy Corp. from December 1995 to May 1997; Chief Financial Officer of LG&E Energy Corp. and LG&E from May 1997 to February 1999, (including Chief Financial Officer of KU from May 1998 to February 1999); President and Chief Operating Officer of LG&E Energy Corp. from March 1999 to April 2001 (including President of LG&E and KU from June 2000 to April 2001); Chairman, President and CEO of LG&E Energy Corp., LG&E and KU from May 2001 to present.
Before he was elected to his current positions, Mr. Aitken-Davies was Group Performance Director at Powergen from April 1998 to March 2000; Director - LG&E Transition Team at Powergen from March 2000 to January 2001.
Mr. McCall has been Executive Vice President, General Counsel and Corporate Secretary of LG&E Energy Corp. and LG&E since July 1994. He became Executive Vice President, General Counsel and Corporate Secretary of KU in May 1998.
Before he was elected to his current positions, Mr. Rives was Vice President – Finance and Controller of LG&E Energy Corp. from March 1996 to February 1999; and Senior Vice President – Finance and Business Development from February 1999 to December 2000.
Before he was elected to his current positions, Mr. Thompson was Vice President – Business Development for LG&E Energy Corp. from July 1994 to September 1996; Vice President, Retail Electric Business for LG&E from September 1996 to June 1998; Group Vice President for LG&E Energy Marketing, Inc. from June 1998 to August 1999; Vice President, Retail Electric Business for LG&E from December 1998 to August 1999; and Senior Vice President – Energy Services for LG&E Energy Corp. from August 1999 to June 2000.
Before he was elected to his current positions, Mr. Hermann was Vice President and General Manager, Wholesale Electric Business of LG&E from January 1993 to June 1997; Vice President, Business Integration of LG&E from June 1997 to May 1998; Vice President, Power Generation and Engineering Services, of LG&E from May 1998 to December 1999; and Vice President Supply Chain and Operating Services from December 1999 to December 2000.
Before she was elected to her current positions, Ms. Welsh was Vice President - Information Services of LG&E from January 1994 to May 1997; Vice President, Administration of LG&E Energy Corp. from May 1997 to February 1998; and Vice President-Information Technology from February 1998 to December 2000.
22
Before he was elected to his current positions, Mr. Gallus was Director, Trading and Risk Management from January 1996 to September 1996; Director, Product Development from September 1996 to April 1997; Vice President, Structured Products from April 1997 to May 1998; Senior Vice President, Trading, from May 1998 to August 1998 for LG&E Energy Marketing Inc.; and Vice President, Energy Marketing from August 1998 to December 2000 for LG&E Energy Corp.
Before he was elected to his current positions, Mr. Smith was Head of Construction Projects - Powergen from January 1996 to May 1999; Director of Projects - Powergen from May 1999 to December 1999; and Director of Engineering Projects for Powergen International from January 2000 to December 2000.
Before he was elected to his current positions, Mr. Vogel served in management positions within the Distribution organization of LG&E and KU prior to December 2000. In his position prior to his current role he was responsible for statewide outage management and restoration of distribution network.
Before he was elected to his current positions, Mr. Arbough was Manager, Corporate Finance of LG&E Energy Corp., and LG&E from August 1996 to May 1998; and he has held the position of Director, Corporate Finance of LG&E Energy Corp., LG&E and KU from May 1998 to present.
Before he was elected to his current positions, Mr. Hamilton was Venture Manager from May 1992 to December 1995; Senior Venture Manager from December 1995 to September 1997, and Vice President, Asset Management from September 1997 to December 2000.
Before he was elected to his current positions, Mr. Henriques was Senior Venture Manager for LG&E Power Inc. from May 1993 to September 1995, and Vice President-Plant Operations from September 1995 to September 2001.
Before he was elected to his current positions, Mr. Beer was Director, Federal Regulatory Affairs, for Illinois Power Company in Decatur, Illinois, from February of 1997 to January of 1998; Senior Corporate Attorney from February 1998 to February 2000; and Senior Counsel Specialist, Regulatory from February 2000 to February 2001.
Before he was elected to his current positions, Mr. Siemens held the position of Director of External Affairs for LG&E from August 1982 to January 2001.
Before she was elected to her current positions as Vice President-Human Resources, Ms. Pottinger was Manager, Human Resources Development from May 1994 to May 1997; and Director, Human Resources from June 1997 to June 2002.
Before he was elected to his current positions, Mr. Bowling was Plant General Manager at Western Kentucky
UtilitiesEnergy Corp. from July 1998 to December 2001; and General Manager Black Fossil Operations for Powergen in the United Kingdom from January 2002 to August 2002.Before he was elected to his current positions, Mr. Keeling was General Manager, Marketing Communications for General Electric Company from January 1998 to January 1999. He joined LG&E Energy Corp. and held the title Manager, Media Relations from January 1999 to February 2000; and Director, Corporate Communications for LG&E Energy from February 2000 to March 2002.
23
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:
Summer Capability
Rating (Kw)Steam Stations:
Mill Creek - Kosmosdale, KY
Unit 1
308,000
Unit 2
306,000
Unit 3
391,000
Unit 4
480,000
Total Mill Creek
1,485,000
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
386,000
Combustion Turbine Generators (Peaking capability):
Zorn
14,000
Paddy’s Run(b)
119,000
Cane Run
14,000
Waterside
22,000
E.W. Brown – Burgin, KY(c)
189,000
Trimble County – Bedford, KY(d)
90,000
Total combustion turbine generators
448,000
Total capability rating
2,882,000
(a)
Amount shown represents LG&E’s 75% interest in Trimble County 1. See Notes 11 and 12 of LG&E’s Notes to Financial Statements under Item 8 for further discussion on ownership.
(b)
Amount shown represents LG&E’s 53% interest in Paddy’s Run Unit 13 and 100% ownership of two other Paddy’s Run CTs. See Notes 11 and 12 of LG&E’s Notes to Financial Statement, under Item 8 for further discussion on ownership.
(c)
Amount shown represents LG&E’s 53% interest in Unit 5 and 38% interest in Units 6 and 7 at E.W. Brown. See Notes 11 and 12 of LG&E’s Notes to Financial Statements, under Item 8 for further discussion on ownership. KU operates the units on behalf of LG&E.
(d)
Amount shown represents LG&E’s 29% interest in Units 5 and 6 at Trimble County. See Notes 11 and 12 of LG&E’s Notes to Financial Statements, under Item 8 for further discussion on ownership.
LG&E also owns an 80 Mw nameplate rated hydroelectric generating station located in Louisville, with a summer capability rating of 48 Mw, operated under a license issued by the FERC.
At December 31, 2002, LG&E’s electric transmission system included 21 substations with a total capacity of
24
approximately 11,519,700 Kva and approximately 656 structure miles of lines. The electric distribution system included 84 substations with a total capacity of approximately 3,448,730 Kva, 3,761 structure miles of overhead lines and 379 miles of underground conduit.
LG&E’s gas transmission system includes 212 miles of transmission mains, and the gas distribution system includes 4,066 miles of distribution mains.
LG&E operates underground gas storage facilities with a current working gas capacity of approximately15.1million 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 was renegotiated in 2002 and is scheduled to expire July 31, 2015.
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.
25
KU’s power generating system consists of the coal-fired units operated at its four steam generating stations. Combustion turbines supplement the system during peak or emergency periods. KU owns and operates the following electric generating stations:
Summer Capability
Rating (Kw)Steam Stations:
Tyrone - Tyrone, KY
Unit 1
27,000
Unit 2
31,000
Unit 3
71,000
Total Tyrone
129,000
Green River – South Carrollton, KY
Unit 1
22,000
Unit 2
22,000
Unit 3
68,000
Unit 4
100,000
Total Green River
212,000
E.W. Brown – Burgin, KY
Unit 1
104,000
Unit 2
168,000
Unit 3
429,000
Total E.W. Brown
701,000
Ghent – Ghent, KY
Unit 1
509,000
Unit 2
494,000
Unit 3
496,000
Unit 4
467,000
Total Ghent
1,966,000
Combustion Turbine Generators (Peaking capability):
E.W. Brown – Burgin, KY (Units 5-11)(a)
773,000
Haefling – Lexington, KY
36,000
Paddy’s Run – Louisville, KY(b)
74,000
Trimble County-Bedford, KY(c)
220,000
Total combustion turbine generators
1,103,000
Total capability rating
4,111,000
(a)
Amount shown represents KU’s 47% interest in Unit 5, 62% interest in Units 6 and 7 and 100% of four other units at E.W. Brown. See Notes 11 and 12 of KU’s Notes to Financial Statements, under Item 8 for further discussion on ownership.
(b)
Amount shown represents KU’s 47% interest in Unit 13 at Paddy’s Run. See Notes 11 and 12 of KU’s Notes to Financial Statements, under Item 8 for further discussion on ownership. LG&E operates this unit on behalf of KU.
(c)
Amount shown represents KU’s 71% interest in Units 5 and 6 at Trimble County. See Notes 11 and 12 of KU’s Notes to Financial Statements, under Item 8 for further discussion on ownership. LG&E operates these units on behalf of KU.
KU also owns a 24 Mw hydroelectric generating station located in Burgin, Kentucky (Dix Dam), operated under a license issued by the FERC.
At December 31, 2002, KU’s electric transmission system included 112 substations with a total capacity of approximately 14,855,396 Kva and approximately 4,229 structure miles of lines. The electric distribution system included 464 substations with a total capacity of approximately 5,046,335 Kva and 15,036 structure
26
miles of lines.
Other properties owned by KU include office buildings, service centers, warehouses, garages, and other structures and equipment.
Substantially all properties are subject to the lien of KU’s Mortgage Indenture.
Rates and Regulatory Matters
For a discussion of current rate and regulatory matters, including (a) environmental surcharge and cost recovery proceedings, (b) fuel adjustment and gas supply clause proceedings, (c) earnings sharing mechanism extension proceedings, (d) merger surcredit proceedings and (e) other rate or regulatory matters affecting LG&E and KU, see Rates and Regulation under Item 7 and Note 3 of LG&E’s Notes to Financial Statements and Note 3 of KU’s Notes to Financial Statements under Item 8.
Environmental
For a discussion of environmental matters including (a) currently proposed reductions in NOx emission limits, (b) items regarding LG&E’s Mill Creek generating plant, KU’s E.W. Brown plant, KU-related Tindall property and LG&E’s and KU’s manufactured gas plant sites and (c) other environmental items affecting LG&E and KU, see Environmental Matters under Item 7 and Note 11 of LG&E’s Notes to Financial Statements and Note 11 of KU’s Notes to Financial Statements under Item 8, respectively.
LG&E Employment Discrimination Case
In October 2001 approximately 30 employees or former employees filed a complaint against LG&E claiming past and current instances of employment discrimination against LG&E. LG&E has removed the case to the U.S. District Court for the Western District of Kentucky and filed an answer denying all plaintiff’s claims. Discovery has commenced in the matter. The court has ordered mediation and certain plaintiffs have settled for non-material amounts as a result of that process. In addition, certain plaintiffs have sought administrative review before the U.S. Equal Employment Opportunity Commission which has, to date, declined to proceed to litigation on any claims reviewed. Amended pleadings have also reduced the size of the plaintiff and defendant groups and eliminated certain prior demands. The amended complaints included a reduced claimed damage amount of $100 million as well as requests for injunctive relief. LG&E intends to defend itself vigorously in the action and management does not anticipate
any difficulties in renewing the required permits which are expiring in 1995. Pursuant to the Resource Conservation and Recovery Act, utility wastes (fly ash, bottom ash and scrubber sludge) have been categorized as special wastes (i.e., wastes of large volume, but low environmental hazard). The EPA has concludedthat thedisposal of coal combustion by- products by practices common to the utility industry are adequate for the protection of human health and the environment. The Cabinet also regulates utility wastes as special wastes under its waste management -7-program. Under the Toxic Substances Control Act, the EPA regulates the use, servicing, repair, storage and disposal of electrical equipment containing polychlorinated biphenyls (PCB). To comply with these regulations, Kentucky Utilities has implemented procedures to be followed in the handling, storage and disposal of PCBs. In addition, Kentucky Utilities has completed the mandated phase out of all of its pole-class PCB capacitors and has no vault-type PCB transformers in use, in or near commercial buildings. On February 13, 1990, Kentucky Utilities received a letter from the EPA identifying Kentucky Utilities and others as potentially responsible parties under the Comprehensive Environmental Response Compensation and Liability Act (CERCLA or "Superfund") for a disposal site in Daviess County, Kentucky. The letter also asked Kentucky Utilities, and the other persons or entities named, to proceed voluntarily with a remediation program at the site. Under Superfund, a responsible party may be liable for all or a portion of all monies expended by the government to take corrective action at the site. The EPA has turned over responsibility for investigation of the site and development of a remediation plan to a group (not including Kentucky Utilities) originally named as potentially responsible parties. Kentucky Utilities has entered into an agreement with the group as to the portion of the investigation and development costs to be borne by Kentucky Utilities in connection with the site. The agreement does not cover costs which may be incurred in connection with any remediation plan. Any remediation plan would be subject to approval of the EPA. Although a final plan has yet to be developed or approved, Kentucky Utilities does not believe that any liability with respect to the siteoutcome will have a material impact onitsLG&E’s operations or financial condition.Combustion Turbine Litigation
In September 2002, LG&E and KU, or their affiliates, filed further amended complaints in litigation in the U.S. District Court for the Eastern District of Kentucky against Alstom Power, Inc. (formerly ABB Power Generation, Inc.) (“Alstom”) regarding two combustion turbines supplied by Alstom in 1999. These units are installed at KU’s E.W. Brown generating plant and are jointly owned by LG&E and KU. The original purchase price for the turbines was approximately $91.8 million. The suit presents warranty, negligence, misrepresentation, fraud and other claims relating to numerous operational defects or deficiencies in connection therewith. LG&E and KU have requested rescission of the contract and recovery of all expenditures relating to the
27
turbines. As an alternative to rescission, LG&E and KU have requested relief for amounts incurred or expended to date in connection with operational repairs, cover damages or liquidated damages and other costs, with possible further damages and interest to be proven at trial. The matter is currently in discovery with a trial presently scheduled for the third quarter of 2003.
Preferred Stock Delisting
On April 16, 2002, the LG&E 5% Cumulative Preferred class of stock was delisted from the NASDAQ Small Capitalization Market. On June 3, 2002, the KU 4.75% Cumulative Preferred class of stock was delisted from the Philadelphia Stock Exchange. Delisting will enable the Companies to realize certain administrative and corporate governance efficiencies.
Other
In the normal course of business, other lawsuits, claims, environmental actions, and other governmental proceedings arise against LG&E and KU. To the extent that damages are assessed in any of these lawsuits, LG&E and KU believe that their insurance coverage is adequate. Management, after consultation with legal counsel, does not anticipate that liabilities arising out of other currently pending or threatened lawsuits and claims will have a material adverse effect on LG&E’s or KU’s consolidated financial position or results of
operations. Regulation Kentucky Utilities is subjectoperations, respectively.28
ITEM 4. Submission of Matters to a Vote of Security Holders.
a) LG&E’s and KU’s Annual Meetings of Shareholders were held on December 19, 2002.
b) Not applicable.
c) The matters voted upon and the
jurisdictionresults of theKentucky Public Service Commission (PSC)voting at the Annual Meetings are set forth below:1. LG&E
i)
The shareholders voted to elect LG&E’s nominees for election to the Board of Directors, as follows:
Michael Söhlke - 21,294,223 common shares and 114,107 preferred shares cast in favor of election and 1,979 preferred shares withheld.
Victor A. Staffieri - 21,294,223 common shares and 113,207 preferred shares cast in favor of election and 2,879 preferred shares withheld.
Edmund A. Wallis - 21,294,223 common shares and 114,246 preferred shares cast in favor of election and 1,840 preferred shares withheld.
No holders of common or preferred shares abstained from voting on this matter.
ii)
The shareholders voted 21,294,223 common shares and 113,801 preferred shares in favor of and 331 preferred shares against the approval of PricewaterhouseCoopers LLP as independent accountants for 2002. Holders of 1,954 preferred shares abstained from voting on this matter.
2. KU
i)
The sole shareholder voted to elect KU’s nominees for election to the Board of Directors, as follows:
37,817,878 common shares cast in favor of election and no shares withheld for each of Michael Söhlke, Victor A. Staffieri and Edmund A. Wallis, respectively.
ii)
The sole shareholder voted 37,817,878 common shares in favor of and no shares withheld for approval of PricewaterhouseCoopers LLP as independent accountants for 2002.
No holders of common shares abstained from voting on these matters.
d) Not applicable.
LG&E:
All LG&E common stock, 21,294,223 shares, is held by LG&E Energy. Therefore, there is no public market
29
for LG&E’s common stock.
The following table sets forth LG&E’s cash distributions on common stock paid to
rates, service, accounts, issuanceLG&E Energy (in thousands ofsecurities$):
2002
2001
First quarter
$
0
$
0
Second quarter
23,000
0
Third quarter
23,000
0
Fourth quarter
23,000
23,000
KU:
All KU common stock, 37,817,878 shares, is held by LG&E Energy. Therefore, there is no public market for KU’s common stock.
The following table sets forth KU’s cash distributions on common stock paid to LG&E Energy (in thousands of $):
2002
2001
First quarter
$
0
$
0
Second quarter
0
0
Third quarter
0
0
Fourth quarter
0
30,500
30
ITEM 6. Selected Financial Data.
The Consolidated Financial Statements for 1998 through 2000 for LG&E and
in other respects. 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 $212,000), Kentucky Utilities may also be subject to the jurisdictionKU were audited by Arthur Andersen LLP (Andersen) who has ceased operations. A copy of theTennessee Public Service Commission as to rates, accounts, issuance of securities and in other respects. Since 1992, utilities in Kentucky have been allowed to use either a historical test period or a forward-looking test period in rate filings. Kentucky Utilities' fuel adjustment clause for Kentucky customers, which operates to reflect changes in the cost of fuel in billings to customers, is designed to conform to a general regulation providing for a uniform monthly fuel adjustment clause for all electric utilities in Kentucky subject to the jurisdiction of the PSC. The clause is basedreport previously issued by Andersen ona formula approved by the Federal Energy Regulatory Commission (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, which is -8-adjusted annually, uses an average fuel cost factor based primarily on projected test year fuel costs. The fuel cost factor is adjustedour financial statements for theover or under collection of fuel costs from the previous year. Rate regulationyear ended December 31, 2000, is included elsewhere inKentucky allows each utility, with a PSC-approved environmental compliance plan and environmental surcharge rider, to recover on a current basis the cost of complying with federal, state or local environmental requirements, including the 1990 Clean Air Act Amendments, which apply to coal combustion wastes and by-products from facilities utilized for the production of energy from coal. During 1994, the PSC approved Kentucky Utilities' environmental surcharge, which is designed to allow Kentucky Utilities to recover any compliance related operating expenses and to earn a return on compliance related capital expenditures on coststhis report. Such report has notalready included in existing rates through the application of the surcharge each month to customers' bills. Surcharge billings are subject to periodic PSC review of the level of environmental expenditures and reconciliation of previous surcharge billings with actual costs. For additional information regarding the environmental surcharge, see Item 3, Legal Proceedings. Integrated resource planning regulations in Kentucky require Kentucky Utilities and the other major utilities to make biennial filings with the PSC, of various historical and forecasted information relating to forecasted load, capacity margins and demand-side management techniques. Pursuant to Kentucky law, the PSC has established the boundaries of the service territory or area of each supplier of retail electric service in Kentucky (including Kentucky Utilities), other than municipal corporations, within which each such supplier shall have the exclusive right to render retail electric service. The SCC 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 reviewbeen reissued bythe SCC Staff. The SCC issues a Staff Report, which includes any findings or recommendations to the SCC relating to the individual utility's financial performance during the historic 12 month period, including previously accepted adjustments. The FERC has jurisdiction under the Federal Power Act over certain of the electric utility facilities and operations and accounting practices of Kentucky Utilities, and in certain other respects as provided in the Act. The FERC has classified Kentucky Utilities as a "public utility" as defined in the Act. Kentucky Utilities is presently exempt from all the provisions of the Public Utility Holding Company Act of 1935, 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 dated April 19, 1949 and, absent further action by the Commission, by virtue of annual exemption statements filed by Kentucky Utilities with the Commission pursuant to Rule 2 prescribed under the Act. National Energy Policy Act See Item 7, Management'sAndersen.
Years Ended December 31
(Thousands of $)
2002
2001
2000
1999
1998
LG&E:
Operating revenues:
Revenues
$
1,013,917
$
997,420
$
985,947
$
969,984
$
854,556
Provision for rate collections (refunds)
12,267
(720
)
(2,500
)
(1,735
)
(4,500
)
Total operating revenues
1,026,184
996,700
983,447
968,249
850,056
Net operating income
117,914
141,773
148,870
140,091
135,523
Net income
88,929
106,781
110,573
106,270
78,120
Net income available for common stock
84,683
102,042
105,363
101,769
73,552
Total assets
2,561,078
2,448,354
2,226,084
2,171,452
2,104,637
Long-term obligations (including amounts due within one year)
$
616,904
$
616,904
$
606,800
$
626,800
$
626,800
LG&E’s Management’s Discussion and Analysis of Financial Condition and Results of Operation
- Utility Issues - Competition. -9-Transmission ServicesandPower Services Tariffs On September 30, 1994, Kentucky Utilities filed an application with the FERC for approval to sell power on a wholesale basis at market-based rates under a proposed Power Services (PS) Tariff. In connection with the PS Tariff filing, Kentucky Utilities also filed a Transmission Service Tariff (TS) under which it would provide firm and nonfirm transmission services to eligible customers. Kentucky Utilities would offer the TS Tariff to customers seeking access to KU's transmission lines, and would use the TS Tariff for its own transmission needs when it makes opportunity sales. On November 30, 1994, the FERC accepted for filing the Transmission Services Tariff and permitted the tariff to be placed in effect, subject to refund, on December 1, 1994. A procedural schedule was also established, with hearings scheduled for July, 1995. In the same Order, the FERC rejected Kentucky Utilities' proposed market-based PS Tariff, without prejudice, thereby permitting Kentucky Utilities to correct identified deficiencies. On December 13, 1994, Kentucky Utilities filed a response to the FERC's Order seeking clarification of certain aspects of the Order and included in its response certain supplemental information which the FERC deemed necessary for approval of the PS Tariff. Item 2. Properties
Kentucky Utilities owns and operates the following electric generating stations:Nameplate Effective Rating (KW) Capability (KW)Steam: Ghent Ghent, Ky 2,226,060 2,000,000 Green River South Carrollton, Ky 263,636 241,000 E. W. Brown Burgin, Ky 739,534 661,000 Tyrone Tyrone, Ky 137,500 135,000 Pineville Four Mile, Ky 37,500 35,000 Hydro: Dix Dam & Lock #7 Burgin, Ky 30,297 24,000 Gas/Oil Peaking: Haefling Lexington, Ky 62,100 59,000 E.W. Brown Burgin, Ky 119,000 110,000 3,615,627 3,265,000Substantially all properties are subject to the lien of Kentucky Utilities' Mortgage Indenture. Construction Construction on two 110-MW combustion turbine peaking units was substantially completed in 1994. The first peaking unit was placed into commercial operation in 1994 and the second unit was placed into commercial operation in February 1995. The total construction expenditures of Kentucky Utilities for the years 1995 through 1999 are estimated at $521 million. Such expenditures include an estimated $182 million for generating facilities, $66 million for transmission facilities and $273 million for distribution and general facilities. Included in total construction expenditures for the 1995-1999 period are $120 million for 440-MW of peak generating capacity, in addition to the units mentioned above, to be added during 1995-1999 (110-MW in each year 1995-1998) and $23 million for environmental compliance (of which $18 million is for compliance with the 1990 Clean Air Act Amendments). -10-All necessary permits and approvals for the units to go on line in 1995 and 1996 have been obtained. Kentucky Utilities has no plans to install base load generating capacity before 2010. Construction expenditures for the years 1990 through 1994 aggregated about $581 million. See Note 4 of theLG&E’s Notes to Financial Statementsforshould be read in conjunction with theestimated amounts of construction expenditures for each of the years 1995 through 1999. Kentucky Utilities frequently reviews its construction program and construction expenditures, which may be affected by numerous factors, including the rate of load growth, changes in construction costs, changes in environmental regulations, least cost planning, the adequacy of rate relief and Kentucky Utilities' ability to raise necessary capital (See Item 7. Management'sabove information.31
Years Ended December 31
(Thousands of $)
2002
2001
2000
1999
1998
KU:
Operating revenues:
Revenues
$
875,192
$
860,426
$
851,941
$
943,210
$
831,614
Provision for rate collections (refunds)
13,027
(954
)
—
(5,900
)
(21,500
)
Total operating revenues
888,219
859,472
851,941
937,310
810,114
Net operating income
108,643
121,370
128,136
136,016
125,388
Net income
93,384
96,414
95,524
106,558
72,764
Net income available for common stock
91,128
94,158
93,268
104,302
70,508
Total assets
1,998,383
1,826,902
1,739,518
1,785,090
1,761,201
Long-term obligations (including amounts due within one year)
$
500,492
$
488,506
$
484,830
$
546,330
$
546,330
KU’s Management’s Discussion and Analysis of Financial Condition and Results of
Operations). Kentucky Utilities' planned additions to its electric generating capacity are based on future load projections using estimated load growth rates. Consideration is also given to projections by neighboring utilities of their future loadsOperation andcapacity. However, forecasts of future loads are subject to numerous uncertainties, including economic conditions and effectiveness of energy conservation measures. Item 3. Legal Proceedings By order of July 19, 1994, the PSC approved Kentucky Utilities' plan for environmental surcharge adjustments to customer billings beginning in August 1994. The surcharge, authorized by a Kentucky statute enacted in 1992, is designed to recover certain ongoing operating and capital costs, not already included in existing rates, related to compliance with federal, state or local environmental requirements associated with the production of energy from coal, including the 1990 Clean Air Act Amendments. Surcharge billings are subject to periodic PSC review of the level of environmental expenditures and reconciliation of previous surcharge billings with actual costs. On September 9, 1994, the Attorney General of the Commonwealth of Kentucky (Attorney General) filed an action in the Franklin County (KY) Circuit Court challenging the constitutionality of the Kentucky surcharge statute and seeking to vacate the PSC order of July 19, 1994 on the ground, among others, that the environmental surcharge approved by the PSC will deprive Kentucky Utilities' customers of their property without due process of law. The Attorney General has been joined by interveners asserting similar claims on behalf of ratepayer groups. In December 1994, the Circuit Court denied a motion by the Attorney General and two interveners seeking to have surcharge collections deposited with the court pending the outcome of the litigation. Management believes that, based on its review of the circumstances, the surcharge statute is constitutional and that the PSC order of July 19, 1994 approving the surcharge will be upheld. In the remote occurrence that the statute is declared unconstitutional, amounts collected pursuant to the PSC order may be subject to refund. Item 4. Submission of Matters to a Vote of Security Holders None. -11-Executive Officers of the Registrant Current Positions Held During at Least the Name and Age Positions Held Last 5 Years John T. Newton Chairman and Chairman of the Board of Kentucky Age 64 Director Utilities since November 1987, and President from January 1987 to November 1994. Director of Kentucky Utilities since December 1974. Michael R. Whitley President and President of Kentucky Utilities Age 51 Director since November 1994, and Director since March 1992. Senior Vice- President of Kentucky Utilities from March 1987 to November 1994. Secretary of Kentucky Utilities from July 1978 to November 1992. James M. Allison Senior Vice- Senior Vice-President of Kentucky Age 41 President Utilities since November 1994. Vice-President of Kentucky Utilities from February 1993 to November 1994. President and Chief Operating Officer of Wheeling Power Company from October 1989 to January 1993. O. M. Goodlett Senior Vice- Senior Vice-President of Kentucky Age 47 President Utilities since November 1992. Vice-President of Kentucky Utilities from April 1982 to November 1992. Wayne T. Lucas Senior Vice- Senior Vice-President of Kentucky Age 47 President Utilities since November 1994. Vice President of Kentucky Utilities from November 1986 to November 1994. George S. Brooks II General Corporate Secretary of Kentucky Age 44 Counsel and Utilities since November 1992, and Corporate General Counsel since January Secretary 1988. Gary E. Blake Vice-President Vice-President of Kentucky Age 41 Utilities since November 1992. Western Division Manager of Kentucky Utilities from October 1991 to November 1992. Assistant Western Division Manager of Kentucky Utilities from March 1990 to October 1991. Field Operations Coordinator for Kentucky Utilities from April 1986 to March 1990. William E. Casebier Vice-President Vice-President of Kentucky Age 52 Utilities since May 1988. -12-Executive Officers of the Registrant (continued) Current Positions Held During at Least the Name and Age Positions Held Last 5 Years Linda M. DiMascio Vice-President Vice-President of Kentucky Age 40 Utilities since February 1995. Director of Human Resources of Tucker Housewares from September 1994 to February 1995. Senior Area Coordinator for U.S. Manufacturing Department of Mobil Oil Corporation from April 1992 to September 1994. Assistant Employee Relations Manager, Torrance Refinery of Mobil Oil Corporation from October 1989 to April 1992. Robert M. Hewett Vice-President Vice-President of Kentucky Age 47 Utilities since January 1982. Ronald L. Whitmer Vice-President Vice-President of Kentucky Age 62 Utilities since November 1992. Director of Production and Generation Construction of Kentucky Utilities from May 1985 to November 1992. William N. English Treasurer Treasurer of Kentucky Utilities Age 44 since April 1982. Michael D. Robinson Controller Controller of Kentucky Utilities Age 39 since August 1990. Assistant Controller of Kentucky Utilities from August 1983 to August 1990. John J. Maloy, Jr. Assistant Assistant Treasurer of Kentucky Age 40 Treasurer Utilities since August 1984. (Not an Executive Officer) Note: Officers are elected annually by the Board of Directors. There is no family relationship between any executive officer and any other executive officer or any director. -13-PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters All of the outstanding common stock of Kentucky Utilities is held by KU Energy. The following table sets forth the cash distributions (in thousands of dollars) on common stock paid by Kentucky Utilities for the periods indicated: 1994 1993 First Quarter $ 15,411 $ 15,127 Second Quarter $ 15,411 $ 15,127 Third Quarter $ 15,411 $ 15,127 Fourth Quarter $ 15,411 $ 15,127 See Note 5 of theKU’s Notes to FinancialStatements. -14-
Item 6. Selected Financial DataYear ended December 31, 1994 1993 1992 1991 1990 (in thousands) Operating Revenues:Residential $213,574 $ 210,759 $194,817 $ 202,885 $187,100 Commercial 142,207 138,271 133,519 137,653 131,990 Industrial 120,043 111,857 102,808 98,595 96,524 Mine power 36,498 34,977 36,696 37,093 37,877 Public authorities 49,869 48,142 45,570 46,332 43,125 Total sales to ultimate consumers 562,191 544,006 513,410 522,558 496,616 Other electric utilities 89,665 62,463 58,979 61,542 53,295 Miscellaneous revenues and other 4,181 3,428 3,432 3,560 3,870 Provision for refund - litigation settlement (19,385) (3,309) - - - Total operating revenues 636,652 606,588 575,821 587,660 553,781 Operating Expenses: Fuel used in generation (1) 170,654 178,910 168,470 183,167 175,439 Electric power purchased 61,442 34,711 32,753 26,744 27,521 Other operating expenses 112,712 104,930 93,915 91,779 85,111 Maintenance 66,134 59,451 61,118 58,590 52,606 Depreciation 65,259 60,800 58,849 57,337 56,173 Federal and state income taxes 44,683 48,178 41,489 46,569 42,331 Other taxes 14,582 14,347 13,359 12,858 12,384 Total operating expenses 535,466 501,327 469,953 477,044 451,565 Net Operating Income 101,186 105,261 105,868 110,616 102,216 Other Income and Deductions 9,299 8,331 11,226 12,062 15,102 Income Before Interest Charges and AFUDC 110,485 113,592 117,094 122,678 117,318 Interest Charges: Interest on long-term debt 32,147 31,650 39,571 36,559 36,132 Other interest 2,411 1,249 1,394 1,626 1,219 Total interest charges 34,558 32,899 40,965 38,185 37,351 AFUDC 1,585 593 169 262 146 Net Income $ 77,512 $ 81,286 $ 76,298 $ 84,755 $ 80,113 Preferred Stock Dividend Requirements 2,384 2,558 2,518 3,031 5,513 Net Income Applicable to Common Stock $ 75,128 $ 78,728 $ 73,780 $ 81,724 $ 74,600 Common Dividends $ 61,644 $ 60,509 $108,996 $ 56,727 $ 55,214 (1) Amounts for 1994 and 1993 reflect reductions of $23.1 million and $4.1 million, respectively, associated with refunds to customers related to a litigation settlement with a former coal supplier.-15-
Item 6. Selected Financial Data (continued)1994 1993 1992 1991 1990Assets (in thousands) $1,618,100 $1,523,274 $1,408,453 $1,412,961 $1,416,487 Capitalization: (in thousands) Bonds $ 495,830 $ 441,830 $ 443,330 $ 407,330 $ 408,070 Notes 86 107 128 149 171 Unamortized premium on long-term debt 96 108 519 713 772 Preferred stock 40,000 40,000 40,000 40,000 40,000 Preferred stock with mandatory redemption - - - - - Common stock equity 565,201 552,106 534,073 569,289 546,477 Total capitalization $1,101,213 $1,034,151 $1,018,050 $1,017,481 $ 995,490 % Total Capitalization Represented by: Long-term debt 45.1 42.7 43.6 40.1 41.1 Preferred stock 3.6 3.9 3.9 3.9 4.0 Common stock equity 51.3 53.4 52.5 56.0 54.9 Kilowatt-hours Generated, Purchased and Sold: (in thousands) Power generated 15,524,844 14,934,839 13,700,313 14,183,713 13,024,722 Power purchased 3,066,917 1,926,299 2,032,110 1,464,812 1,425,899 Power interchanged - net 2,638 1,556 3,393 (10,725) 14,934 Total 18,594,399 16,862,694 15,735,816 15,637,800 14,465,555 Less - losses and company use 998,010 1,066,251 876,862 906,468 878,337 Remainder - kilowatt-hours sold 17,596,389 15,796,443 14,858,954 14,731,332 13,587,218 Sales classified: Residential 4,706,058 4,702,697 4,278,098 4,385,670 4,012,324 Commercial 3,272,370 3,217,504 3,080,045 3,122,156 2,968,049 Industrial 3,641,469 3,409,213 3,093,113 2,874,016 2,791,304 Mine power 974,233 933,317 977,032 955,410 983,778 Public authorities 1,225,668 1,199,893 1,123,494 1,133,176 1,048,483 Total sales to ultimate consumers 13,819,798 13,462,624 12,551,782 12,470,428 11,803,938 Other electric utilities 3,776,591 2,333,819 2,307,172 2,260,904 1,783,280 Total 17,596,389 15,796,443 14,858,954 14,731,332 13,587,218 Average Number of Customers 440,590 432,636 425,403 419,340 413,843 Residential Sales (per customer): Average kilowatt-hours 12,781 12,995 12,007 12,471 11,546 Average revenue $ 580.05 $ 582.41 $ 546.80 $ 576.93 $ 538.43 System Capability - Megawatts: Kentucky Utilities' plants 3,265 3,164 3,163 3,162 3,150 Purchased contracts 540 365 293 254 251 Total system capability 3,805 3,529 3,456 3,416 3,401 Net System Maximum Demand - Megawatts 3,127 3,176 2,845 2,894 2,835 Load Factor (%) 59.8 57.7 59.4 58.4 56.5 Heat Rate (BTU per KWH) (1) 10,306 10,367 10,344 10,350 10,449 Fuel - Average Cost per Ton(1) $ 28.84 $ 28.31 $ 27.88 $ 29.67 $ 30.74 Average Cost per Million BTU(1) $ 1.19 $ 1.17 $ 1.18 $ 1.24 $ 1.28 (1) Based on coal consumed-16-ItemStatements should be read in conjunction with the above information.LG&E:
GENERAL
The following discussion and analysis by management focuses on those factors that had a material effect on LG&E’s financial results of operations and financial condition during 2002,
an electric utility, is2001, and 2000 and should be read in connection with the financial statements and notes thereto.Some of the following discussion may contain forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “expect,” “estimate,” “objective,” “possible,” “potential” and similar expressions. Actual results may materially vary. Factors that could cause actual results to materially differ include; general economic conditions; business and competitive conditions in the energy industry; changes in federal or state legislation; unusual weather; actions by state or federal regulatory agencies; actions by credit rating agencies; and other factors described from time to time in LG&E’s reports to the SEC, including Exhibit No. 99.01 to this report on Form 10-K.
MERGERS and ACQUISITIONS
On December 11, 2000, LG&E Energy was acquired by Powergen for cash of approximately $3.2 billion or $24.85 per share and the assumption of all of LG&E Energy’s debt. As a result of the acquisition, LG&E Energy became a wholly owned subsidiary of Powergen and, as a result, LG&E became an indirect subsidiary of Powergen. LG&E has continued its separate identity and serves customers in Kentucky under its existing
32
name. The preferred stock and debt securities of LG&E were not affected by this transaction and LG&E continues to file SEC reports. Following the acquisition, Powergen became a registered holding company under PUHCA, and LG&E, as a subsidiary of a registered holding company, became subject to additional regulation under PUHCA. See “Rates and Regulation” under Item 1.
On July 1, 2002, E.ON, a German company, completed its acquisition of Powergen plc (now Powergen Limited). As a result, LG&E and KU became indirect subsidiaries of E.ON. E.ON had announced its pre-conditional cash offer of £5.1 billion ($7.3 billion) for Powergen on April 9, 2001. Following the acquisition, E.ON became a registered holding company under PUHCA.
As contemplated in their regulatory filings in connection with the E.ON acquisition, E.ON, Powergen and LG&E Energy
Corporation (KU Energy).completed an administrative reorganization to move the LG&E Energy group from an indirect Powergen subsidiary to an indirect E.ON subsidiary. This reorganization was effective in March 2003.RESULTS OF OPERATIONS
1994 Compared to 1993Net Income
Applicable to Common Stock NetLG&E’s net income
applicable to common stockin1994 was $75.12002 decreased $17.9 million as compared to$78.7 million in 1993.2001. Thedecline reflects increases indecrease resulted primarily from higher transmission operating expenses, an increase in amortization of VDT regulatory asset, and increased property insurance and pension expense, partially offset by an increase in electric sales to retail customers and lower interest expenses.LG&E’s net income decreased $3.8 million for 2001, as compared to 2000. This decrease is mainly due to higher pension related expenses and amortization of VDT regulatory asset, partially offset by increased electric and gas net revenues (operating revenues less fuel for electric generation, power purchased and gas supply expenses) and decreased interest expenses.
33
Revenues
A comparison of operating revenues for the years 2002 and 2001, excluding the provisions recorded for rate collections (refunds), with the immediately preceding year reflects both increases and decreases, which have been segregated by the following principal causes (in thousands of $):
Increase (Decrease) From Prior Period
Electric Revenues
Gas Revenues
Cause
2002
2001
2002
2001
Retail sales:
Fuel and gas supply adjustments
$
19,449
$
(394
)
$
(58,003
)
$
79,627
LG&E/KU Merger surcredit
(2,825
)
(2,456
)
—
—
Performance based rate
—
1,962
—
—
Environmental cost recovery surcharge
9,694
1,246
—
—
Demand side management
1,381
—
938
—
Electric rate reduction
—
(3,671
)
—
—
VDT surcredit
(1,177
)
(1,014
)
(285
)
(68
)
Gas rate increase
—
—
—
15,265
Weather normalization
—
—
2,234
—
Variation in sales volumes and other
24,819
4,429
21,658
(64,817
)
Total retail sales
51,341
102
(33,458
)
30,007
Wholesale sales
(16,404
)
(5,674
)
10,683
(11,642
)
Gas transportation-net
—
—
189
(880
)
Other
4,642
(1,241
)
(496
)
801
Total
$
39,579
$
(6,813
)
$
(23,082
)
$
18,286
Electric revenues increased in 2002 primarily
relateddue topurchased power. The benefits ofan increase in retail sales due to warmer summer weather, an increase in thefirst halfrecovery of1994 werefuel costs passed through the FAC, partially offset bythe impact of milder weathera decrease in wholesale sales due to lower market prices as compared to 2001. Cooling degree days increased 20% compared to 2001. Electric revenues decreased in 2001 primarily due to a decrease in brokered activity in thethirdwholesale electric sales market, an electric rate reduction ordered by the Kentucky Commission andfourth quartersthe effects of theyear. Net income applicable to common stock for 1994 includes a one-time recoveryLG&E/KU merger surcredit (See Note 2 ofabout $1.9 million associated with the resolution of a coal contract dispute. For additional detail concerning the refunds resulting from resolution of the dispute, refer to Note 1 of theLG&E’s Notes to Financial Statements"Operating Revenuesunder Item 8) partially offset by an increase in electric retail sales. In January 2000, the Kentucky Commission ordered an electric rate reduction andFuel Costs".
Sales and Revenues Increase (Decrease) From Prior Years1994 1993 kWh Revenues kWh Revenues (%) (000's) (%) (000's)Residential - $ 2,815 10 $15,942 Commercial 2 3,936 4 4,752 Industrial 7 8,186 10 9,049 Mine Power & Public Authorities 3 3,248 2 853 Total Retail Sales 3 18,185 7 30,596 Other Electric Utilities 62 27,202 1 3,484 Miscellaneous Revenues and Other - 753 - (4) Total Before Refund 11 46,140 6 34,076 Provision for Refund - Litigation Settlement - (16,076) - (3,309) Total 11 $ 30,064 6 $30,767Kilowatt-hour (kWh)the termination of LG&E’s proposed electric PBR mechanism.Gas revenues in 2002 decreased due to a lower gas supply cost billed to customers through the gas supply clause offset partially by increased gas retail sales due to cooler winter weather and an increase in wholesale sales volume. Heating degree days increased 17% as compared to 2001. Gas revenues in 2001 increased primarily as a result of higher gas supply costs billed to customers through the gas supply clause and the effects of a gas rate increase ordered by the Kentucky Commission in September 2000. The gas revenue increase was partially offset by a decrease in retail and wholesale gas sales in
1994 were 11% above sales2001 due to warmer weather. Heating degree days decreased 10.2% compared to 2000.Expenses
Fuel for electric generation and gas supply expenses comprise a large component of LG&E’s total operating costs. The retail electric rates contain a FAC and gas rates contain a GSC, whereby increases or decreases in
1993. The increase wasthe34
cost of fuel and gas supply are reflected in the FAC and GSC factors, subject to approval by the Kentucky Commission, and passed through to LG&E’s retail customers.
Fuel for electric generation increased $35.7 million (22.4%) in 2002 due to increased generation ($5.4 million) and higher cost of coal burned ($30.3 million). Fuel for electric generation decreased $0.2 million (.1%) in 2001 primarily due to
greater sales to neighboring utilities and increased sales to industrial customers. Sales to other electric utilities rose 62% in 1994 due to increased demand for power from neighboring utilities. While management believes the level of sales to other utilities was unusually high in 1994, KU will aggressively pursue future opportunities in the bulk power market. Industrial sales rose 7% in 1994 reflecting a continued trend of growth in the manufacturing sector of KU's service area. About 42% of the industrial sales increase for 1994 was due to greater sales to Toyota Motor Manufacturing, USA, Inc. (TMM), KU's largest customer. In March 1994, TMM completed an $800 million assembly plant expansion. Residential sales were flatdecreased generation as-17-compared to 1993. Asa result ofrefundsdecreased electric sales ($2.2 million) partially offset by a higher cost of coal burned ($2.0 million). The average delivered cost per ton of coal purchased was $25.30 in 2002, $21.27 in 2001 and $20.96 in 2000.Power purchased increased $2.9 million (3.5%) in 2002 due to
customersan increase in purchases to meet requirements for native load and off-system sales partially offset by decreased brokered sales activity in the wholesale electric market. Power purchased decreased $15.4 million (15.9%) in 2001 primarily due to decreased brokered sales activity in the wholesale electric market and a lower unit cost offuelthe purchases partially offset by an increase in purchases to meet requirements for native load and off-system sales.Gas supply expenses decreased $24.1 million (11.7%) in 2002 due to a decrease in cost of net gas supply ($36.6 million), partially offset by an increase in the volume of gas delivered to the distribution system ($12.5 million). Gas supply expenses increased $9.3 million (4.7%) in 2001 primarily due to an increase in cost of net gas supply ($36.2 million), partially offset by a decrease in the volume of gas delivered to the distribution system ($26.9 million). The average unit cost per Mcf of purchased gas was $4.19 in 2002, $5.27 in 2001 and $5.08 in 2000.
Other operation expenses increased $40.5 million (24.1%) in 2002 primarily due to a full year amortization in 2002 of a regulatory asset created as a result of the workforce reduction costs
savingsassociated with LG&E’s VDT ($17.0 million), higher costs for electric transmission primarily resulting from increased MISO costs ($13.9 million), an increase in property and other insurance costs ($3.9 million), an increase in pension costs due to change in pension assumptions to reflect current market conditions and change in market value of theresolutionplan assets at the measurement date ($3.7 million), and an increase in steam production costs ($3.4 million). Other operation expenses increased $31.9 million (23.4%) in 2001 primarily due to amortization of acoal contract dispute, operating revenuesregulatory asset resulting from workforce reduction costs associated with LG&E’s VDT ($13.0 million), an increase in1994 were reducedpension expense ($10.3 million) and an increase in outside services ($8.5 million). Outside services increased in part due to the reclassification of expenses as a result of the formation of LG&E Services, as required byabout $19.4the SEC to comply with PUHCA.Maintenance expenses for 2002 increased $1.5 million (2.6%) primarily due to gas distribution expenses for main remediation work ($2.2 million). Maintenance expenses for 2001 decreased $5.0 million (7.9%) primarily due to decreases in scheduled outages ($2.8 million), and
fuel expensea decrease in software and communication equipment maintenance ($2.8 million).Depreciation and amortization increased $5.5 million (5.5%) in 2002 and $2.1 million (2.1%) in 2001 because of additional utility plant in service. The 2001 increase was
reducedoffset byabout $23.1a decrease in depreciation rates resulting from a settlement order in December 2001 from the Kentucky Commission. Depreciation expenses decreased $5.6 million(refer to Note 1as a result of the settlement order.Variations in income tax expenses are largely attributable to changes in pre-tax income. LG&E’s 2002 effective income tax rate increased to 37.2% from the 36.5% rate in 2001. See Note 7 of LG&E’s Notes to Financial Statements
"Operating Revenuesunder Item 8.35
Property and
Fuel Costs"). Excluding the impact of the refund to customers, revenues in 1994 increased $46.1other taxes decreased $0.3 million(8%) over 1993 as a result of increased kWh sales. 1994 Kilowatt-Hour Sales by Classification Year Ended December 31, 1994 Residential 27% Commercial 19% Industrial 21% Mine Power 5% Public Authorities 7% Other Electric Utilities 21% Total 100% Fuel Expense Excluding the effect of the above referenced refunds to customers, fuel expense increased $10.7 million (6%(1.6%) in1994. This increase was due to a 3% increase in annual coal consumption attributable to greater kWh generation2002. Property andto a 2% increase in the average price per ton of coal consumed. Purchased Power Expense Purchased power expense increased $26.7other taxes decreased $1.2 million(77%(6.5%) in1994 due to higher demand costs ($13.8 million) and increased kWh purchases ($12.9 million). The higher demand costs are related to KU's decision to increase purchased power commitments as part of its strategy to obtain the most economical sources of energy supply, which allows KU to delay the need for additional baseload capacity. Effective January 1, 1994, KU elected to increase from 5% to 20% its entitlement to the available capacity of a 1,000-megawatt generating station owned by Electric Energy, Inc. (EEI). KU is a 20% owner of EEI. The increase in power purchases was2001 primarilyfrom EEI. Maintenance Expense Maintenance expense for 1994 was $6.7 million (11%) above 1993. The increase was primarily due to damage from two severe ice storms in the first quarter of 1994 and to scheduled maintenance at KU's generating stations. 1993 Compared to 1992 Net Income Applicable to Common Stock -18-Net income applicable to common stock was $78.7 million in 1993 compared to $73.8 million in 1992. The increase in 1993 was largely due to weather-related growth in sales and lower interest charges attributable to debt refinancings and redemptions. Earnings in 1993 were negatively impacted by an increase in other operating expenses and a decline in interest and dividend income. Sales and Revenues Sales in 1993 were 6% above 1992. The increase was the result of greater sales to residential and industrial customers. The increase in residential sales was largely weather-related. KU's customers set an all-time record peak demand for electricity of 3,176 megawatts in July 1993 during a period of unusually warm weather. The increase in industrial sales for 1993 reflected the general strength of the service area economy as well as an increase in the number of industrial customers. Excluding the effect of refunds to customers associated with the resolution of a coal contract dispute (refer to Note 1 of the Notes to Financial Statements, "Operating Revenues and Fuel Costs"), revenues increased $34.1 million (6%) in 1993. This increase was primarily a result of greater kWh sales. Fuel and Purchased Power Expenses Fuel expense, excluding the effect of the above referenced refunds to customers, increased 9% in 1993. The increase was primarily due to a 7% increase in coal consumption attributable to greater kWh generation. Purchased power expense for 1993 was $2.0 million (6%) above 1992. The increase reflected greater demand charges associated with a new short- term capacity contract with a neighboring utility, partially offset by a 5% decrease in power purchases. The decline in power purchases wasdue to a reduction in payroll taxes related to fewer employees as a result of workforce reductions and transfers to LG&E Services.Other income – net decreased $2.1 million (72.0%) in 2002 primarily due to increased costs for non-utility areas, $1.3 million and decreases in the
availabilitygain on sale ofOwensboro Municipal Utilities' (OMU)property $0.8 million. Other income – net decreased $2.0 million (40.5%) in 2001 primarily due to lower interest and dividend income.Interest charges for 2002 decreased $8.1 million (21.4%) primarily due to lower interest rates on variable rate debt ($5.6 million) a decrease in debt to associated companies ($0.8 million) and an decrease in interest associated with LG&E’s accounts receivable securitization program ($1.5 million). Interest charges for 2001 decreased $5.3 million (12.2%) primarily due to lower interest rates on variable rate debt ($2.2 million) and the retirement of short-term borrowings ($8.1 million) partially offset by an increase in debt to associated companies ($2.5 million) and an increase in interest associated with LG&E’s accounts receivable securitization program ($2.5 million). See Note 9 of LG&E’s Notes to Financial Statements under Item 8.
LG&E’s weighted average cost of long-term debt, including amortization of debt expense and interest rate swaps, was 3.87% at December 31, 2002 compared to 4.17% at December 31, 2001. See Note 9 of LG&E’s Notes to Financial Statements under Item 8.
The rate of inflation may have a significant impact on LG&E’s operations, its ability to control costs and the need to seek timely and adequate rate adjustments. However, relatively low rates of inflation in the past few years have moderated the impact on current operating results.
CRITICAL ACCOUNTING POLICIES/ESTIMATES
Preparation of financial statements and related disclosures in compliance with generally accepted accounting principles requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including legal and regulatory challenges and anticipated recovery of costs. These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment also may have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies applied has not changed. Specific risks for these critical accounting policies are described in the following paragraphs. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Events rarely develop exactly as forecast and the best estimates routinely require adjustment. See also Note 1 of LG&E’s Notes to Financial Statements under Item 8.
36
Unbilled Revenue – At each month end LG&E prepares a financial estimate that projects electric and gas usage that has been used by customers, but not billed. The estimated usage is based on known weather and days not billed. At December 31, 2002, a 10% change in these estimated quantities would cause revenue and accounts receivable to change by approximately $5.0 million, including $2.3 million for electric usage and $2.7 million for gas usage. See also Note 1 of LG&E’s Notes to Financial Statements under Item 8.
Benefit Plan Accounting - Judgments and uncertainties in benefit plan accounting include future rate of returns on pension plan assets, interest rates used in valuing benefit obligation, healthcare cost trend rates, and other actuarial assumptions.
LG&E’s costs of providing defined-benefit pension retirement plans is dependent upon a number of factors, such as the rates of return on plan assets, discount rate, and contributions made to the plan. The market value of LG&E plan assets has been affected by declines in the equity market since the beginning of the fiscal year. As a result, at December 31, 2002, LG&E was required to recognize an additional minimum liability as prescribed by SFAS No. 87 Employers’ Accounting for Pensions. The liability was recorded as a reduction to other comprehensive income, and did not affect net income for 2002. The amount of the liability depended upon the asset returns experienced in 2002 and contributions made by LG&E to the plan during 2002. Also, pension cost and cash contributions to the plan could increase in future years without a substantial recovery in the equity market. If the fair value of the plan assets exceeds the accumulated benefit obligation, the recorded liability will be reduced and other comprehensive income will be restored in the consolidated balance sheet.
The combination of poor market performance and a decrease in short-term corporate bond interest rates has created a divergence in the potential value of the pension liability and the actual value of the pension assets. These conditions could result in an increase in LG&E’s funded accumulated benefit obligation and future pension expense. The primary assumptions that drive the value of the unfunded accumulated benefit obligation are the discount rate and expected return on plan assets.
LG&E made a contribution to the pension plan of $83.1 million in January 2003.
A 1% increase or decrease in the assumed discount rate could have an approximate $37.0 million positive or negative impact to the accumulated benefit obligation of LG&E.
See also Note 6 of LG&E’s Notes to Financial Statements under Item 8.
Regulatory Mechanisms – Judgments and uncertainties include future regulatory decisions, impact of deregulation and competition on ratemaking process, and external regulator decisions.
Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates based upon Kentucky Commission orders. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections based upon orders by the Kentucky Commission. Management believes, based on orders, the existing regulatory assets and liabilities are probable of recovery. This determination reflects the current regulatory climate in the state. If future recovery of costs ceases to be probable the assets would be required to be recognized in current period earnings.
LG&E has accrued in the financial statements an estimate of $12.5 million for 2002 ESM, with collection from
37
customer commencing in April 2003. The ESM is subject to Kentucky Commission approval.
See also Note 3 of LG&E’s Notes to Financial Statements under Item 8.
NEW ACCOUNTING PRONOUNCEMENTS
The following accounting pronouncements were issued that affected LG&E in 2002:
SFAS No. 143, Accounting for Asset Retirement Obligations was issued in 2001. SFAS No. 143 establishes accounting and reporting standards for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.
The effective implementation date for SFAS No. 143 is January 1, 2003. Management has calculated the impact of SFAS No. 143 and the recently released FERC NOPR No. RM02-7, Accounting, Financial Reporting, and Rate Filing Requirements for Asset Retirement Obligations. As of January 1, 2003, LG&E recorded asset retirement obligation (ARO) assets in the amount of $4.6 million and liabilities in the amount of $9.3 million. LG&E also recorded a cumulative effect adjustment in the amount of $5.3 million to reflect the accumulated depreciation and accretion of ARO assets at the transition date less amounts previously accrued under regulatory depreciation. LG&E recorded offsetting regulatory assets of $5.3 million, pursuant to regulatory treatment prescribed under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. Also pursuant to SFAS No. 71, LG&E recorded regulatory liabilities in the amount of $60,000 offsetting removal costs previously accrued under regulatory accounting in excess of amounts allowed under SFAS No. 143.
LG&E also expects to record ARO accretion expense of approximately $617,000, ARO depreciation expense of approximately $117,000 and an offsetting regulatory credit in the income statement of approximately $734,000 in 2003, pursuant to regulatory treatment prescribed under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. The accretion, depreciation and regulatory credit will be annual adjustments. SFAS No. 143 will have no impact on the results of the operation of LG&E.
LG&E’s asset retirement obligations are primarily related to the final retirement of generating
unitsunits. LG&E transmission and distribution lines largely operate under perpetual property easement agreements which do not generally require restoration upon removal of the property. Therefore, under SFAS No. 143, no material asset retirement obligations will be recorded for transmission and distribution assets.LG&E adopted EITF No. 98-10, Accounting for Energy Trading and Risk Management Activities, effective January 1, 1999. This pronouncement required that energy trading contracts be marked to market on the balance sheet, with the gains and losses shown net in the income statement. In October 2002, the Emerging Issues Task Force reached a consensus to rescind EITF 98-10. The effective date for the full rescission is for fiscal periods beginning after December 15, 2002. With the rescission of EITF No. 98-10, energy trading contracts that do not also meet the definition of a derivative under SFAS No. 133 must be accounted for as executory contracts. Contracts previously recorded at fair value under EITF No. 98-10 that are not also derivatives under SFAS No. 133 must be restated to historical cost through a cumulative effect adjustment. LG&E does not expect the rescission of this standard to have a material impact on financial position or results of operations.
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In January 2003, the Financial Accounting Standards Board issued Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51 (FIN 46). FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 is effective immediately for all new variable interest entities created or acquired after January 31, 2003. For variable interest entities created or acquired prior to February 1, 2003, the provisions of FIN 46 must be applied for the first interim or annual period beginning after June 15, 2003. LG&E does not expect the adoption of this standard to have any impact on the financial position or results of operations.
LIQUIDITY AND CAPITAL RESOURCES
LG&E uses net cash generated from its operations and external financing to fund construction of plant and equipment and the payment of dividends. LG&E believes that such sources of funds will be sufficient to meet the needs of its business in the foreseeable future.
Operating Activities
Cash provided by operations was $212.4 million, $287.1 million and $156.2 million in 2002, 2001, and 2000, respectively. The 2002 decrease compared to 2001 of $74.7 million resulted primarily from the change in accounts receivable balances, including the sale of accounts receivable through the accounts receivable securitization program and a decrease in accounts payable and accrued taxes. The 2001 increase of $130.9 million resulted primarily from an increase in accounts receivable, and a decrease in accrued taxes. See Note 1 of LG&E’s Notes to Financial Statements under Item 8 for a discussion of accounts receivable securitization.
Investing Activities
LG&E’s primary use of funds for investing activities continues to be for capital expenditures. Capital expenditures were $220.4 million, $253.0 million and $144.2 million in 2002, 2001, and 2000, respectively. LG&E expects its capital expenditures for 2003 and 2004 to total approximately $340.0 million, which consists primarily of construction estimates associated with installation of NOx equipment as described in the section titled “Environmental Matters,” purchase of jointly owned CTs with KU and on-going construction for the distribution systems.
Net cash used for investment activities decreased $28.7 million in 2002 compared to 2001 primarily due to the level of construction expenditures. CT expenditures were approximately $35.9 million in 2002 and $57.8 million in 2001. The $107.9 million increase in net cash used in 2001 as compared to 2000 was due to NOx expenditures and the purchase of CTs.
Financing Activities
Net cash inflows for financing activities were $22.5 million in 2002 and outflows of $38.7 million and $67.7 million in 2001 and 2000, respectively. In 2002, short-term borrowings increased $98.9 million which were used in part for dividend payments of $73.3 million. During 2001, short-term borrowings decreased $20.4 million from 2000 and LG&E paid $28.0 million in dividends.
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During 2001, LG&E issued $10.1 million of pollution control bonds resulting in net proceeds of $9.7 million after issuance costs.
On March 6, 2002, LG&E refinanced its $22.5 million and $27.5 million unsecured pollution control bonds, both due September 1, 2026. The replacement bonds, due September 1, 2026, are variable rate bonds and are secured by first mortgage bonds.
On March 22, 2002, LG&E refinanced its two $35 million unsecured pollution control bonds due November 1, 2027. The replacement variable rate bonds are secured by first mortgage bonds and will mature November 1, 2027.
In October 2002, LG&E issued $41.7 million variable rate pollution bonds due October 1, 2032, and exercised its call option on $41.7 million, 6.55% pollution control bonds due November 1, 2020.
Under the provisions for LG&E’s variable-rate pollution control bonds totaling $246.2 million, the bonds are subject to tender for purchase at the option of the holder and to mandatory tender for purchase upon the occurrence of certain events, causing the bonds to be classified as current portion of long-term debt.
Future Capital Requirements
Future capital requirements may be affected in varying degrees by factors such as load growth, changes in construction expenditure levels, rate actions by regulatory agencies, new legislation, market entry of competing electric power generators, changes in environmental regulations and other regulatory requirements. LG&E anticipates funding future capital requirements through operating cash flow, debt, and/or infusions of capital from its parent.
LG&E’s debt ratings as of December 31, 2002, were:
Moody’s
S&P
Fitch
First mortgage bonds
A1
A
A+
Preferred stock
Baa1
BBB
A-
Commercial paper
P-1
A-2
F-1
These ratings reflect the views of Moody’s, S&P and Fitch. A security rating is not a recommendation to buy, sell or hold securities and is subject to revision or withdrawal at any time by the rating agency.
Contractual Obligations
The following is provided to summarize LG&E’s contractual cash obligations for periods after December 31, 2002 (in thousands of $):
Payments Due by Period
Contractual cash
Obligations
2003
2004-
2005
2006-
2007
After
2007
Total
Short-term debt(a)
$
193,053
$
—
$
—
$
—
$
193,053
Long-term debt(b)
288,800
—
—
328,104
616,904
Operating lease(c)
3,371
6,866
7,143
29,794
47,174
Unconditional purchase obligations(d)
10,773
20,268
21,632
184,544
237,217
Other long-term obligations(e)
28,401
95,151
—
—
123,552
Total contractual cash obligations(f)
$
524,398
$
122,285
$
28,775
$
542,442
$
1,217,900
(a) Represents borrowings from parent company due within one year.
(b) Includes long-term debt of $246.2 million classified as current liabilities because these bonds are subject to tender for purchase at the option of the holder and to mandatory tender for purchase upon the occurrence of certain events. Maturity dates for these bonds range from 2017 to 2027.
(c) Operating lease represents the lease of LG&E’s administrative office building.
(d) Represents future minimum payments under purchased power agreements through 2020.
(e) Represents construction commitments.
(f) LG&E does not expect to pay the $246.2 million of long-term debt classified as a current liability in the consolidated balance sheets in 2003 as explained in (b) above. LG&E anticipates cash from operations and external financing will be sufficient to fund future obligations. LG&E anticipates refinancing a portion of its short-term debt with long-term debt in 2003.
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Market Risks
LG&E is exposed to market risks from changes in interest rates and commodity prices. To mitigate changes in cash flows attributable to these exposures, LG&E uses various financial instruments including derivatives. Derivative positions are monitored using techniques that include market value and sensitivity analysis.
See Note 1 and 4 of LG&E’s Notes to Financial Statements under Item 8.
Interest Rate Sensitivity
LG&E has short-term and long-term variable rate debt obligations outstanding. At December 31, 2002, the potential change in interest expense associated with a 1% change in base interest rates of LG&E’s unhedged debt is estimated at $5.5 million after impact of interest rate swaps.
Interest rate swaps are used to hedge LG&E’s underlying variable-rate debt obligations. These swaps hedge specific debt issuances and, consistent with management’s designation, are accorded hedge accounting treatment. See Note 4 of LG&E’s Notes to Financial Statements under Item 8.
As of December 31, 2002, LG&E had swaps with a combined notional value of $117.3 million. The swaps exchange floating-rate interest payments for fixed rate interest payments to reduce the impact of interest rate changes on LG&E’s Pollution Control Bonds. The potential loss in fair value resulting from a hypothetical 1% adverse movement in base interest rates is estimated at $10.8 million as of December 31, 2002. This estimate is derived from third party valuations. Changes in the market value of these swaps if held to maturity, as LG&E intends to do, will have no effect on LG&E’s net income or cash flow. See Note 4 of LG&E’s Notes to Financial Statements under Item 8.
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Commodity Price Sensitivity
LG&E has limited exposure to market price volatility in prices of fuel and electricity, since its retail tariffs include the FAC and GSC commodity price pass-through mechanisms. LG&E is exposed to market price volatility of fuel and electricity in its wholesale activities.
Energy Trading & Risk Management Activities
LG&E conducts energy trading and risk management activities to maximize the value of power sales from physical assets it owns, in addition to the wholesale sale of excess asset capacity. Certain energy trading activities are accounted for on a mark-to-market basis in accordance with EITF 98-10 Accounting for Contracts Involved in Energy Trading and Risk Management Activities, SFAS No. 133 Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138 Accounting for Certain Derivative Instruments and Certain Hedging Activities. Wholesale sales of excess asset capacity and wholesale purchases are treated as normal sales and purchases under SFAS No. 133 and SFAS No. 138 and are not marked-to-market.
The rescission of EITF 98-10, effective for fiscal periods ending after December 15, 2002, will have no impact on LG&E’s energy trading and risk management reporting as all contracts marked to market under EITF 98-10 are also within the scope of SFAS No. 133.
The table below summarizes LG&E’s energy trading and risk management activities for 2002 and 2001 (in thousands of $).
2002
2001
Fair value of contracts at beginning of period, net liability
$
(186
)
$
(17
)
Fair value of contracts when entered into during the period
(65
)
3,441
Contracts realized or otherwise settled during the period
448
(2,894
)
Changes in fair values due to changes in assumptions
(353
)
(716
)
Fair value of contracts at end of period, net liability
$
(156
)
$
(186
)
No changes to valuation techniques for energy trading and risk management activities occurred during
scheduled maintenance2002. Changes in market pricing, interest rate and volatility assumptions were made during both years. All contracts outstanding at December 31, 2002, have a maturity of less than one year and are valued using prices actively quoted for proposed or executed transactions or quoted by brokers.LG&E maintains policies intended to minimize credit risk and revalues credit exposures daily to monitor compliance with those
unitspolicies. At December 31, 2002, 86% of the trading and risk management commitments were with counterparties rated BBB- equivalent or better.Accounts Receivable Securitization
On February 6, 2001, LG&E implemented an accounts receivable securitization program. The purpose of this program is to enable LG&E to accelerate the receipt of cash from the collection of retail accounts receivable, thereby reducing dependence upon more costly sources of working capital. The securitization program allows for a percentage of eligible receivables to be sold. Eligible receivables are generally all receivables associated with retail sales that have standard terms and are not past due. LG&E is able to terminate the program at any time without penalty. If there is a significant deterioration in the payment record of the receivables by the retail
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customers or if LG&E fails to meet certain covenants regarding the program, the program may terminate at the election of the financial institutions. In this case, payments from retail customers would first be used to repay the financial institutions participating in the program, and would then be available for use by LG&E.
As part of the program, LG&E sold retail accounts receivables to a wholly owned subsidiary, LG&E R. Simultaneously, LG&E R entered into two separate three-year accounts receivable securitization facilities with two financial institutions and their affiliates whereby LG&E R can sell, on a revolving basis, an undivided interest in certain of its receivables and receive up to $75 million from an unrelated third party purchaser. The effective cost of the receivables programs is comparable to LG&E’s lowest cost source of capital, and is based on prime rated commercial paper. LG&E retains servicing rights of the sold receivables through two separate servicing agreements with the third party purchaser. LG&E has obtained an opinion from independent legal counsel indicating these transactions qualify as a true sale of receivables. As of December 31, 2002, the outstanding program balance was $63.2 million. LG&E is considering unwinding its accounts receivable securitization arrangements involving LG&E R during 2003.
The allowance for doubtful accounts associated with the eligible securitized receivables was $2.1 million at December 31, 2002. This allowance is based on historical experience of LG&E. Each securitization facility contains a fully funded reserve for uncollectible receivables.
RATES AND REGULATION
Following the purchase of Powergen by E.ON, E.ON became a registered holding company under PUHCA. As a result, E.ON, its utility subsidiaries, including LG&E, and certain of its non-utility subsidiaries are subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales of securities, acquisitions and sales of certain utility properties, and intra-system sales of certain goods and services. In addition, PUHCA generally limits the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company. LG&E believes that it has adequate authority (including financing authority) under existing SEC orders and regulations to conduct its business. LG&E will seek additional authorization when necessary.
LG&E is subject to the jurisdiction of the Kentucky Commission in virtually all matters related to electric and gas utility regulation, and as such, its accounting is subject to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. Given LG&E’s competitive position in the marketplace and the status of regulation in the state of Kentucky, LG&E has no plans or intentions to discontinue its application of SFAS No. 71. See Note 3 of LG&E’s Notes to Financial Statements under Item 8.
Kentucky Commission Settlement Order - VDT Costs, ESM and Depreciation
During the first quarter 2001, LG&E recorded a $144 million charge for a workforce reduction program. Primary components of the charge were separation benefits, enhanced early retirement benefits, and health care benefits. The result of this workforce reduction was the elimination of approximately 700 positions, accomplished primarily through a voluntary enhanced severance program.
On June 1, 2001, LG&E filed an application (VDT case) with the Kentucky Commission to create a regulatory asset relating to these first quarter 2001 charges. The application requested permission to amortize these costs over a four-year period. The Kentucky Commission also opened a case to review a new depreciation study and
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resulting depreciation rates implemented in 2001.
LG&E reached a settlement in the VDT case as well as the other cases involving depreciation rates and ESM with all intervening parties. The settlement agreement was approved by Kentucky Commission Order on December 3, 2001. The order allowed LG&E to set up a regulatory asset of $141 million for the workforce reduction costs and begin amortizing these costs over a five year period starting in April 2001. The first quarter 2001 charge of $144 million represented all employees who had accepted a voluntary enhanced severance program. Some employees rescinded their participation in the voluntary enhanced severance program, thereby decreasing the original charge from $144 million to $141 million. The settlement will also reduce revenues approximately $26 million through a surcredit on future bills to customers over the same five year period. The surcredit represents stipulated net savings LG&E is expected to realize from implementation of best practices through the VDT. The agreement also established LG&E’s new depreciation rates in effect December 2001, retroactive to January 1, 2001. The new depreciation rates decreased depreciation expense by $5.6 million in 2001.
Environmental Cost Recovery
In June 2000, the Kentucky Commission approved LG&E’s application for a CCN to construct up to three SCR NOx reduction facilities. The construction and subsequent operation of the SCRs is intended to reduce NOx emission levels to meet the EPA’s mandated NOx emission level of 0.15 lbs./ Mmbtu by May 2004. In its order, the Kentucky Commission ruled that LG&E’s proposed plan for construction was “reasonable, cost-effective and will not result in the wasteful duplication of facilities.” In October 2000, LG&E filed an application with the Kentucky Commission to amend its Environmental Compliance Plan to reflect the addition of the proposed NOx reduction technology projects and to amend its Environmental Cost Recovery Tariff to include an overall rate of return on capital investments. Approval of LG&E’s application in April 2001 allowed LG&E to begin to recover the costs associated with these new projects, subject to Kentucky Commission oversight during normal six-month and two-year reviews.
In May 2002, the Kentucky Commission initiated a periodic two year review of LG&E’s environmental surcharge. The review included the operation of the surcharge mechanism, determination of the appropriateness of costs included in the surcharge mechanism, recalculation of the cost of debt to reflect actual costs for the period under review, final determination of the amount of environmental revenues over-collected from customers, and a final determination of the amount of environmental costs and revenues to be “rolled-in” to base rates. A final order was issued on October 22, 2002, in which LG&E was ordered to refund $325,000 to customers over the four month period beginning November 2002 and ending February 2003. Additionally, LG&E was ordered to roll $4.1 million into base rates and make corresponding adjustments to the monthly environmental surcharge filings to reflect that portion of environmental rate base now included in base rates on a going-forward basis.
In August 2002, LG&E filed an application with the Kentucky Commission to amend its compliance plan to allow recovery of the cost of new and additional environmental compliance facilities. The estimated capital cost of the additional facilities is $71.1 million. The Kentucky Commission conducted a public hearing on the case on December 20, 2002, final briefs were filed on January 15, 2003, and a final order was issued February 11, 2003. The final order approved recovery of four new environmental compliance facilities totaling $43.1 million. A fifth project, expansion of the land fill facility at the Mill Creek Station, was denied without prejudice with an invitation to reapply for recovery when required construction permits are approved. Cost
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recovery through the environmental surcharge of the four approved projects will begin with the bills rendered in April 2003.
ESM
LG&E’s electric rates are subject to an ESM. The ESM, initially in place for three years beginning in 2000, sets an upper and lower point for rate of return on equity, whereby if LG&E’s rate of return for the calendar year falls within the range of 10.5% to 12.5%, no action is necessary. If earnings are above the upper limit, the excess earnings are shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, the earnings deficiency is recovered 40% from ratepayers and 60% from shareholders. By order of the Kentucky Commission, rate changes prompted by the ESM filing go into effect in April of each year subject to a balancing adjustment in successive periods. LG&E made its second ESM filing on March 1, 2002, for the calendar year 2001 reporting period. LG&E is in the process of refunding $441,000 to customers for the 2001 reporting period. LG&E estimated that the rate of return will fall below the lower limit, subject to Kentucky Commission approval, for the year ended December 31, 2002. The 2002 financial statements include an accrual to reflect the earnings deficiency of $12.5 million to be recovered from customers commencing in April 2003.
On November 27, 2002, LG&E filed a revised ESM tariff which proposed continuance of the existing ESM through December 2005. The Kentucky Commission issued an Order suspending the ESM tariff one day making the effective date January 2, 2003. In addition, the Kentucky Commission is conducting a management audit to review the ESM plan and reassess its reasonableness in 2003. LG&E and interested parties will have the opportunity to provide recommendations for modification and continuance of the ESM or other forms of alternative or incentive regulation.
DSM
LG&E’s rates contain a DSM provision. The provision includes a rate mechanism that provides concurrent recovery of DSM costs and provides an incentive for implementing DSM programs. This program had allowed LG&E to recover revenues from lost sales associated with the DSM program. In May 2001, the Kentucky Commission approved LG&E’s plan to continue DSM programs. This filing called for the expansion of the DSM programs into the service territory served by KU and proposed a mechanism to recover revenues from lost sales associated with DSM programs based on program planning engineering estimates and post-implementation evaluation.
Gas PBR
Since November 1, 1997, LG&E has operated under an experimental PBR mechanism related to its gas procurement activities. For each of the last five years, LG&E’s rates have been adjusted to recover its portion of the savings (or expenses) incurred during each of the five 12-month periods beginning November 1 and ending October 31. Since its implementation on November 1, 1997, through October 31, 2002, LG&E has achieved $38.1 million in savings. Of the total savings, LG&E has retained $16.5 million, and the remaining portion of $21.6 million has been distributed to customers. In December 2000, LG&E filed an application reporting on the operation of the experimental PBR and requested the Kentucky Commission to extend the PBR as a result of the benefits provided to both LG&E and its customers during the experimental period. Following the discovery and hearing process, the Kentucky Commission issued an order effective November 1, 2001, extending the experimental PBR program for an additional four years, and making other modifications,
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including changes to the sharing levels applicable to savings or expenses incurred under the PBR. Specifically, the Kentucky Commission modified the sharing mechanism to a 25%/75% Company/Customer sharing for all savings (and expenses) up to 4.5% of the benchmarked gas costs. Savings (and expenses) in excess of 4.5% of the benchmarked gas costs are shared at a 50%/50% level.
FAC
Prior to implementation of the electric PBR in July 1999, and following its termination in March 2000, LG&E employed an FAC mechanism, which under Kentucky law allowed LG&E to recover from customers the actual fuel costs associated with retail electric sales. In February 1999, LG&E received orders from the Kentucky Commission requiring a refund to retail electric customers of approximately $3.9 million resulting from reviews of the FAC from November 1994, through April 1998. While legal challenges to the Kentucky Commission order were pending a comprehensive settlement was reached by all parties and approved by the Kentucky Commission on May 17, 2002. Thereunder, LG&E agreed to credit its fuel clause in the amount of $720,000 (such credit provided over the course of June and July 2002), and the parties agreed on a prospective interpretation of the state’s fuel adjustment clause regulation to ensure consistent and mutually acceptable application on a going-forward basis.
In December 2002, the Kentucky Commission initiated a two year review of the operation of LG&E’s FAC for the period November 2000 through October 2002. Testimony in the review case was filed on January 20, 2003 and a public hearing was held February 18, 2003. Issues addressed at that time included the establishment of the current base fuel factor to be included in LG&E’s base rates, verification of proper treatment of purchased power costs during unit outages, and compliance with fuel procurement policies and practices.
Gas Rate Case
In March 2000, LG&E filed an application with the Kentucky Commission requesting an adjustment in LG&E’s gas rates. In September 2000, the Kentucky Commission granted LG&E an annual increase in its base gas revenues of $20.2 million effective September 28, 2000. The Kentucky Commission authorized a return on equity of 11.25%. The Kentucky Commission approved LG&E’s proposal for a weather normalization billing adjustment mechanism that will normalize the effect of weather on base gas revenues from gas sales.
Wholesale Natural Gas Prices
On September 12, 2000, the Kentucky Commission issued an order establishing Administrative Case No. 384 – “An Investigation of Increasing Wholesale Natural Gas Prices and the Impacts of such Increase on the Retail Customers Served by Kentucky’s Jurisdictional Natural Gas Distribution Companies”. The impetus for this administrative proceeding was the escalation of wholesale natural gas prices during the summer of 2000.
The Kentucky Commission directed Kentucky’s natural gas distribution companies, including LG&E, to file selected information regarding the individual companies’ natural gas purchasing practices, expectations for the then-approaching winter heating season of 2000-2001, and potential actions which these companies might take to mitigate price volatility. On July 17, 2001, the Kentucky Commission issued an order encouraging the natural gas distribution companies in Kentucky to take various actions, among them to propose a natural gas hedge plan, consider performance-based ratemaking mechanisms, and to increase the use of storage.
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In April 2002, in Case No. 2002-00136, LG&E proposed a hedging plan for the 2002/2003 winter heating season with three alternatives, the first two using a combination of storage and financial hedge instruments and the third relying upon storage alone. LG&E and the Attorney General, who represents Kentucky consumers, entered into a settlement which selected the third option. In August 2002, the Kentucky Commission approved the plan contemplated in the settlement. The Kentucky Commission validated the effectiveness of storage to mitigate potentially high winter gas prices by approving this natural gas hedging plan.
The Kentucky Commission also decided in Administrative Case No. 384 to engage a consultant to conduct a forward-looking audit of the gas procurement and supply procedures of Kentucky’s largest natural gas distribution companies. The Kentucky Commission completed its audit in late 2002. The audit recognized LG&E as ”efficient and effective [in the] procurement and management of significant quantities of natural gas supplies.” The auditors also recognized that “the Company’s residential gas prices have long been below averages for the U. S. and for the Commonwealth of Kentucky” which “demonstrates [LG&E’s] effectiveness in [the] procurement and management of natural gas supplies.” The audit also stated that the ”Company’s very impressive record in keeping its rates down provides sound evidence on the excellent job done in the area of gas supply procurement and management.”
Kentucky Commission Administrative Case for Affiliate Transactions
In December 1997, the Kentucky Commission opened Administrative Case No. 369 to consider Kentucky Commission policy regarding cost allocations, affiliate transactions and codes of conduct governing the relationship between utilities and their non-utility operations and affiliates. The Kentucky Commission intended to address two major areas in the proceedings: the tools and conditions needed to prevent cost shifting and cross-subsidization between regulated and non-utility operations; and whether a code of conduct should be established to assure that non-utility segments of the holding company are not engaged in practices that could result in unfair competition caused by cost shifting from the non-utility affiliate to the utility. During the period September 1998 to February 2000, the Kentucky Commission issued draft codes of conduct and cost allocation guidelines. In early 2000, the Kentucky General Assembly enacted legislation, House Bill 897, which authorized the Kentucky Commission to require utilities who provide nonregulated activities to keep separate accounts and allocate costs in accordance with procedures established by the Kentucky Commission. In the same bill, the General Assembly set forth provisions to govern a utility’s activities related to the sharing of information, databases, and resources between its employees or an affiliate involved in the marketing or the provision of nonregulated activities and its employees or an affiliate involved in the provision of regulated services. The legislation became law in July 2000 and LG&E has been operating pursuant thereto since that time. On February 14, 2001, the Kentucky Commission published notice of their intent to promulgate new administrative regulations under the auspices of the new law. This effort is still on going.
Kentucky Commission Administrative Case for System Adequacy
On June 19, 2001, Kentucky Governor Paul E. Patton issued Executive Order 2001-771, which directed the Kentucky Commission to review and study issues relating to the need for and development of new electric generating capacity in Kentucky. The issues to be considered included the impact of new power plants on the electric supply grid, facility citing issues, and economic development matters, with the goal of ensuring a continued, reliable source of supply of electricity for the citizens of Kentucky and the continued environmental and economic vitality of Kentucky and its communities. In response to that Executive Order, in July 2001 the
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Kentucky Commission opened Administrative Case No. 387 to review the adequacy of Kentucky’s generation capacity and transmission system. Specifically, the items reviewed were the appropriate level of reliance on purchased power, the appropriate reserve margins to meet existing and future electric demand, the impact of spikes in natural gas prices on electric utility planning strategies, and the adequacy of Kentucky’s electric transmission facilities. LG&E, as a party to this proceeding, filed written testimony and responded to two requests for information. Public hearings were held and in October 2001, LG&E filed a final brief in the case. In December 2001, the Kentucky Commission issued an order in which it noted that LG&E is responsibly addressing the long-term supply needs of native load customers and that current reserve margins are appropriate. However, due to the rapid pace of change in the industry, the order also requires LG&E to provide an annual assessment of supply resources, future demand, reserve margin, and the need for new resources.
Regarding the transmission system, the Kentucky Commission concluded that the transmission system within Kentucky can reliably serve native load and a significant portion of the proposed new unregulated power plants. However, it will not be able to handle the volume of transactions envisioned by FERC without future upgrades, the costs of which should be borne by those for whom the upgrades are required.
The Kentucky Commission pledged to continue to monitor all relevant issues and advocate Kentucky’s interests at all opportunities.
FERC SMD NOPR
On July 31, 2002, FERC issued a NOPR in Docket No. RM01-12-000 which would substantially alter the regulations governing the nation’s wholesale electricity markets by establishing a common set of rules — SMD. The SMD NOPR would require each public utility that owns, operates, or controls interstate transmission facilities to become an Independent Transmission Provider (ITP), belong to an RTO that is an ITP, or contract with an ITP for operation of its transmission assets. It would also establish a standardized congestion management system, real-time and day-ahead energy markets, and a single transmission service for network and point-to-point transmission customers. Review of the proposed rulemaking is underway and a final rule is expected during 2003. While it is expected that the SMD final rule will affect LG&E revenues and expenses, the specific impact of the rulemaking is not known at this time.
MISO
LG&E is a member of the MISO, which began commercial operations on February 1, 2002. MISO now has operational control over LG&E’s high-voltage transmission facilities (100 kV and greater), while LG&E continues to control and operate the lower voltage transmission subject to the terms and conditions of the MISO OATT. As a transmission-owning member of MISO, LG&E also incurs administrative costs of MISO pursuant to Schedule 10 of the MISO OATT.
MISO also proposed to implement a congestion management system. FERC directed the MISO to coordinate its efforts with FERC’s Rulemaking on SMD. On September 24, 2002, the MISO filed new rate schedules designated as Schedules 16 and 17, which provide for the collection of costs incurred by the MISO to establish day-ahead and real-time energy markets. The MISO proposed to recover these costs under Schedules 16 and 17 once service commences. If approved by FERC, these schedules will cause LG&E to incur additional costs. LG&E opposes the establishment of Schedules 16 and 17. This effort is still on-going and the ultimate impact of the two schedules, if approved, is not known at this time.
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Merger Surcredit
As part of the LG&E Energy merger with KU Energy in 1998, LG&E Energy estimated non-fuel savings over a ten–year period following the merger. Costs to achieve these savings for LG&E of $50.2 million were recorded in the second quarter of
1993. A contract between KU and OMU allows KU to purchase, on an economic basis, surplus power from a 400-megawatt generating station owned by OMU. Other Operating Expenses Other operating expenses for 1993 increased $11.0 million (12%), $6.31998, $18.1 million of whichresulted from the adoption ofwas deferred and amortized over anew accounting standard. (Referfive-year period pursuant toNote 3regulatory orders. Primary components of theNotes to Financial Statements, "Other Postretirement Benefits"). Other Incomemerger costs were separation benefits, relocation costs, andDeductions Other income and deductionstransaction fees, the majority of which were paid by December 31, 1998. LG&E expensed the remaining costs associated with the merger ($32.1 million) in1993 declined $2.6 million. A reduction in interest and dividend income wastheresult of lower levels of cash investments. Interest Charges Interest charges decreased $8.2 million (20%) in 1993. The decline resulted from the redemption of two debt issues near the beginning of the -19-second quarter of 19931998.In approving the merger, the Kentucky Commission adopted LG&E’s proposal to reduce its retail customers’ bills based on one-half of the estimated merger-related savings, net of deferred and amortized amounts, over a five-year period. The surcredit mechanism provides that 50% of the
refinancing of several debt issues duringnet non-fuel cost savings estimated to be achieved from thesecond half of 1992merger be provided to ratepayers through a monthly bill credit, andearly in50% be retained by thethird quarter of 1993 at significantly lower interest rates. LIQUIDITY AND CAPITAL RESOURCES Financial ConditionCompanies, over a five-year period. The surcredit was allocated 53% to KUcontinuesand 47% tomaintain a strong financial position. AtLG&E. In that same order, the Commission required LG&E and KU, after the end of1994, common stock equity represented 51.3% of total capitalization while long-term debt was 45.1%, and preferred stock was 3.6%. KU's financial strength is reflected in excellent credit ratings. Rating agencies are applying stricter standardsthe five-year period, toutility credits in light of increasing competition inpresent a plan for sharing with customers theutility industry. This has resulted in credit downgrades for some utilities. Despite the more stringent standards, KU has maintained high quality bond ratings of AA (Duff & Phelps), Aa2 (Moody's) and AA- (Standard & Poor's).
Total CapitalizationAs of December 31, 1994 1993 1992 1991 1990Capitalization (in millions) $1,101 $1,034 $1,018 $1,017 $ 995 Long-Term Debt 45.1% 42.7% 43.6% 40.1% 41.1% Preferred Stock 3.6% 3.9% 3.9% 3.9% 4.0% Common Stock Equity 51.3% 53.4% 52.5% 56.0% 54.9%Cash from operations accounted for 55% of cash requirements in 1994 as compared to 67% in 1993 and 68% for 1992. Cash requirements in the above percentages exclude optional debt refinancings and redemptions and optional preferred stock redemptions. Financing On behalf of KU, $54 million of Variable Rate Collateralized Solid Waste Disposal Facility Revenue Bonds was issued in 1994, and $50 million of 5 3/4% Collateralized Solid Waste Disposal Facility Revenue Bonds was issued in 1993. Proceeds from the sale of these tax exempt issues were used to fund a portion of the costs of certain environmental compliance facilities at KU's Ghent Generating Station. To provide working capital for operations, KU issued commercial paper in 1994. At the end of 1994, KU had $76.3 million outstanding under its commercial paper program. Taking advantage of favorable market conditions in 1993, KU refinanced $120 million of first mortgage bonds at significantly lower interest rates. KU had refinanced about $180 million of higher cost debt in 1992. These refinancings reduced annual interest expense by about $5.4 million. -20-KU also issued $20 million of 6.53% preferred stock in December 1993. Proceeds from the sale of this issue were used to redeem KU's 7.84% preferred stock in February 1994. -21-Through refinancing activities, KU has lowered its embedded costs of long-term debt and preferred stock as shown below.
Embedded CostAs of December 31, 1994 1993 1992 Long-Term Debt 7.06% 7.23% 8.00% Preferred Stock 5.64% 6.37% 6.30%Construction Requirements Construction expenditures were $193 million in 1994. Of that amount, about $62 million related to compliancethen-projected non-fuel savings associated with the1990 Clean Air Act Amendments, $21 millionmerger. The Companies submitted this filing on January 13, 2003, proposing toother environmental compliance measures and $38 millioncontinue toconstructionshare with customers, on a 50%/50% basis, the estimated fifth-year gross level ofcombustion turbine generating units (peaking units). Projected construction expenditures for the 1995-1999 period are $521 million. Included in this amount is $120 million for peaking units. Also included in the 1995-1999 construction total is $23 million for environmental compliance measures of which $18 million is for compliancenon-fuel savings associated with the1990 Clean Air Act Amendments. KU expectsmerger. The filing is currently under review.Any fuel cost savings are passed to
provide about 93% of its 1995-1999 construction requirementsKentucky customers throughinternal sources of funds withthebalance primarily from long-term debt and/or preferred stock.
Construction Expenditures by Function - Actual 1994 and Estimated 1995-1999 Actual Estimated(in millions of dollars) 1994 1995 1996 1997 1998 1999Total Construction Expenditures $ 193 $ 123 $ 117 $ 106 $ 100 $ 75 Environmental Compliance 42.7% 8.1% 6.3% 5.6% -% -% Generation 25.4% 33.1% 36.8% 31.3% 31.1% 15.1% Distribution 23.0% 36.5% 36.8% 42.9% 47.6% 67.9% Transmission and Other 8.9% 22.3% 20.1% 20.2% 21.3% 17.0%UTILITY ISSUES Competition Increasing competitive pressures continue to challenge the utility industry. Set in motion by the National Energy Policy Act of 1992 (NEPA), these pressures are moving the utility industry to a less regulated and more competitive operating environment. Under NEPA, the Federal Energy Regulatory Commission (FERC) was given authority to order utilities to open their transmission lines to third parties. NEPA also removed long-standing constraints on the development of wholesale power generation by establishing a new class of independent power producers which are generally exempt from traditional utility regulation. -22-While NEPA prohibits the FERC from ordering utilities to provide transmission access to retail customers (so-called retail wheeling), several states are considering proposals that would allow retail wheeling. To date, competition from independent power producers has not been a factor in KU's service area largely due to KU's low rates. There are no pending proposals for retail wheeling in Kentucky or Virginia. However, the final impact of NEPA on the utility industry is yet to be determined. KU believes that competition will become more intense and that customers will demand and be given more energy options. With utility rates that are among the lowest in the nation, KU believes it is well-positioned for an increasingly competitive environment. In September 1994, KU filed for FERC approval of a Power Services Tariff which would allow KU to leverage its low-cost position by selling power at competitive market-based rates. In connection with the Power Services Tariff filing, KU also filed a Transmission Service Tariff. KU would offer the Transmission Service Tariff to customers seeking access to its transmission lines, and would use the transmission tariff for its own transmission needs when it makes opportunity sales. The Transmission Service Tariff became effective, subject to refund, on December 1, 1994, according to a November 1994 FERC order. In the same order, the FERC rejected, without prejudice, KU's proposed Power Services Tariff. KU has subsequently filed a response seeking clarification of certain aspects of the order. KU's filing included supplemental information which the FERC deemed necessary for approval of the Power Services Tariff. In addition, KU has launched a series of innovative marketing programs designed to increase market share. KU has also developed strategic initiatives to increase off-system sales and to expand its market through economic development. KU's strong competitive position was confirmed in 1994 by the findings of a management and operations audit by the Kentucky Public Service Commission (PSC). Management Audit In August 1994, the PSC released the findings of a comprehensive management and operations audit that found KU to be "one of the better managed electric utilities in the country". The audit, which began in November 1993, was a part of the PSC's ongoing management audit program. Vantage Consulting, Inc., selected by the PSC to perform the audit, found that "...KU is one of the most cost-effective utilities in the country." The audit findings cited KU's low embedded cost of generation, lean staff ratios, good corporate citizenship and favorable ratings from customers, employees and the financial community. Included in the audit report was a list of recommendations, accepted by KU, designed to maintain KU's strong position in the future. Most of these are strategic considerations that help position KU as an even stronger energy provider in the increasingly competitive electric utility industry. -23-ENVIRONMENTAL MATTERS Clean Air Actfuel adjustment clause. See FAC above.Environmental Matters
The Clean Air Act
Amendmentsimposed stringent new SO2 and NOx emission limits on electric generating units. LG&E previously had installed scrubbers on all of1990 require KU to reduce sulfur dioxide and nitrogen oxide emissions in two phases.its generating units. LG&E’s strategy for PhaseI requirements,II SO2 reductions, whichwere effectivecommenced January 1,1995, were2000, is to increase scrubber removal efficiency to delay additional capital expenditures and may also include fuel switching or upgrading scrubbers. LG&E metprimarilythe NOx emission requirements of the Act throughtheinstallation ofa flue gas desulfurization system (scrubber) on Unit 1 of KU's Ghent Generating Station. The scrubber became operational in December 1994. KU estimates capital costs for the scrubber and other equipment modifications relatedlow-NOx burner systems. LG&E’s compliance plans are subject toClean Air Act compliance to be $151 million through the year 1999. About $133 million of this amount had been spent through the end of 1994. The flexible design of the Ghent Unit 1 scrubber provides an option of installing an additional scrubber on Ghent Unit 2 at a favorable cost. This option, which is not includedmany factors including developments in theabove capital costs, may be considered if it is cost beneficial to the KU system to meet Phase II requirements, which become effective January 1, 2000. KU has purchased 12,900 Phase I emission allowances and has been awarded about 114,000 additional allowances through the Environmental Protection Agency's (EPA) Phase I Extension Plan Program. KU's currentemission allowancestrategy is to bank unused sulfur dioxide emission allowances. Under the current strategy, allowances accumulated (from the additional allowances received from the EPAandexpected reduced emissions from the installation of the scrubber) will begin to be consumed when Phase II requirements become effective. KUfuel markets, future regulatory and legislative initiatives, and advances in clean air control technology. LG&E will continue toreview and revise its compliance plans accordingly,monitor these developments to ensure that its environmental obligations are met in the most efficient and cost-effective manner.In September 1998, the EPA announced its final “NOx SIP Call” rule requiring states to impose significant additional reductions in NOx emissions by May 2003, in order to mitigate alleged ozone transport impacts on the Northeast region. The Commonwealth of Kentucky is currently in the process of revising its SIP to require reductions in NOx emissions from coal-fired generating units to the 0.15 lb./Mmbtu level on a system-wide basis. In related proceedings in response to petitions filed by various Northeast states, in December 1999, EPA issued a final rule pursuant to Section 126 of the Clean Air Act directing similar NOx reductions from a number of specifically targeted generating units including all LG&E units. As a result of appeals to both rules, the compliance date was extended to May 2004. All LG&E generating units are subject to the May 2004 compliance date under these NOx emissions reduction rules.
LG&E is currently implementing a plan for adding significant additional NOx controls to its generating units. Installation of additional NOx controls will proceed on a phased basis, with installation of controls commencing
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in late 2000 and continuing through the final compliance date. LG&E estimates that it will incur total capital costs of approximately $178 million to reduce its NOx emissions to the 0.15 lb./Mmbtu level on a company-wide basis. In addition, LG&E will incur additional operating and maintenance costs in operating new NOx controls. LG&E believes its costs in this regard to be comparable to those of similarly situated utilities with like generation assets. LG&E had anticipated that such capital and operating costs are the type of costs that are eligible for recovery from customers under its environmental surcharge mechanism and believed that a significant portion of such costs could be recovered. In April 2001, the Kentucky Commission granted recovery of these costs for LG&E.
LG&E is also monitoring several other air quality issues which may potentially impact coal-fired power plants, including the appeal of the D.C. Circuit’s remand of the EPA’s revised air quality standards for ozone and particulate matter, measures to implement EPA’s regional haze rule, and EPA’s December 2000 determination to regulate mercury emissions from power plants. In addition, LG&E is currently working with local regulatory authorities to review the effectiveness of remedial measures aimed at controlling particulate matter emissions from its Mill Creek Station. LG&E previously settled a number of property damage claims from adjacent residents and completed significant remedial measures as part of its ongoing capital construction program. LG&E is in the process of converting the Mill Creek Station to wet stack operation in an effort to resolve all outstanding issues related to particulate matter emissions.
LG&E owns or formerly owned three properties which are the location of past MGP operations. Various contaminants are typically found at such former MGP sites and environmental remediation measures are frequently required. With respect to the sites, LG&E has completed cleanups, obtained regulatory approval of site management plans, or reached agreements for other parties to assume responsibility for cleanup. Based on currently available information, management estimates that it will incur additional costs of $400,000. Accordingly, an accrual of $400,000 has been recorded in the accompanying financial statements at December 31, 2002 and 2001.
See Note 11 of LG&E’s Notes to Financial Statements under Item 8 for an additional discussion of environmental issues.
Deferred Income Taxes
LG&E expects to have adequate levels of taxable income to realize its recorded deferred tax assets. At December 31, 2002, deferred tax assets totaled $98.2 million and were principally related to expenses attributable to LG&E’s pension plans and post retirement benefit obligations.
FUTURE OUTLOOK
Competition and Customer Choice
LG&E has moved aggressively over the past decade to be positioned for the energy industry’s shift to customer choice and a competitive market for energy services. Specifically, LG&E has taken many steps to prepare for the expected increase in competition in its business, including support for PBR structures; aggressive cost reduction activities; strategic acquisitions, dispositions and growth initiatives; write-offs of previously deferred expenses; an increase in focus on commercial and industrial customers; an increase in employee training; and necessary corporate and business unit realignments.
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In December 1997, the Kentucky Commission issued a set of principles which was intended to serve as its guide in consideration of issues relating to industry restructuring. Among the issues addressed by these principles are: consumer protection and benefit, system reliability, universal service, environmental responsibility, cost allocation, stranded costs and codes of conduct. During 1998, the Kentucky Commission and a task force of the Kentucky General Assembly had each initiated proceedings, including meetings with representatives of utilities, consumers, state agencies and other groups in Kentucky, to discuss the possible structure and effects of energy industry restructuring in Kentucky.
In November 1999, the task force issued a report to the Governor of Kentucky and a legislative agency recommending no general electric industry restructuring actions during the 2000 legislative session. No general restructuring actions have been taken to date by the legislature.
Thus, at the time of this report, neither the Kentucky General Assembly nor the Kentucky Commission has adopted or approved a plan or timetable for retail electric industry competition in Kentucky. The nature or timing of the ultimate legislative or regulatory actions regarding industry restructuring and their impact on LG&E, which may be significant, cannot currently be predicted.
While many states have moved forward in providing retail choice, many others have not. Some are reconsidering their initiatives and have even delayed implementation.
GENERAL
The following discussion and analysis by management focuses on those factors that had a material effect on KU’s financial results of operations and financial condition during 2002, 2001, and 2000 and should be read in connection with the financial statements and notes thereto.
Some of the following discussion may contain forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “expect,” “estimate,” “objective,” “possible,” “potential” and similar expressions. Actual results may materially vary. Factors that could cause actual results to materially differ include: general economic conditions; business and competitive conditions in the energy industry; changes in federal or state legislation; unusual weather; actions by state or federal regulatory agencies; actions by credit rating agencies; and other factors described from time to time in KU’s reports to the SEC, including Exhibit No. 99.01 to this report on Form 10-K.
MERGERS and ACQUISITIONS
On December 11, 2000, LG&E Energy was acquired by Powergen for cash of approximately $3.2 billion or $24.85 per share and the assumption of all of LG&E Energy’s debt. As a result of the acquisition, LG&E Energy became a wholly owned subsidiary of Powergen and, as a result, KU became an indirect subsidiary of Powergen. KU has continued its separate identity and serves customers in Kentucky, Virginia and Tennessee under its existing name. The preferred stock and debt securities of KU were not affected by this transaction and KU continued to file SEC reports. Following the acquisition, Powergen became a registered holding company under PUHCA and KU, as a subsidiary of a registered holding company, became subject to additional
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regulation under PUHCA. See “Rates and Regulation” under Item 1.
On July 1, 2002, E.ON, a German company, completed its acquisition of Powergen plc (now Powergen Limited). As a result, LG&E and KU became indirect subsidiaries of E.ON. E.ON had announced its pre-conditional cash offer of £5.1 billion ($7.3 billion) for Powergen on April 9, 2001. Following the acquisition, E.ON became a registered holding company under PUHCA.
As contemplated in their regulatory filings in connection with the E.ON acquisition, E.ON, Powergen and LG&E Energy completed an administrative reorganization to move the LG&E Energy group from an indirect Powergen subsidiary to an indirect E.ON subsidiary. This reorganization was effective in March 2003.
RESULTS OF OPERATIONS
Net Income
KU’s net income in 2002 decreased $3.0 million compared to 2001. The decrease resulted primarily from higher transmission operating expenses, an increase in amortization of regulatory assets, and increased property insurance, partially offset by an increase in sales to retail customers and lower interest expenses.
KU’s net income in 2001 was relatively flat as compared to 2000 with an increase of $.9 million. The increase resulted primarily from decreased depreciation, interest expenses and property and other taxes, partially offset by higher pension related expenses and amortization of regulatory assets.
Revenues
A comparison of operating revenues for the years 2002 and 2001, excluding the provision for rate collections (refunds), with the immediately preceding year reflects both increases and decreases which have been segregated by the following principal causes (in thousands of $):
Increase (Decrease)
From Prior Period
Cause
2002
2001
Retail sales:
Fuel clause adjustments
$
18,223
$
10,220
KU/LG&E Merger surcredit
(2,641
)
(3,856
)
Environmental cost recovery surcharge
3,781
1,458
Demand side management
1,570
—
Performance based rate
—
1,747
Electric rate reduction
—
(5,395
)
VDT surcredit
(527
)
(372
)
Variation in sales volumes, and other
46,601
(1,627
)
Total retail sales
67,007
2,175
Wholesale sales
(59,373
)
5,108
Other
7,132
1,202
Total
$
14,766
$
8,485
Electric revenues increased in 2002 primarily due to an increase in retail sales due to warmer weather and an increase in the recovery of fuel costs passed through the FAC. Cooling degree days for 2002 increased 26% over 2001. The increase in retail sales was partially offset by a decrease in wholesale sales volumes. The
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decrease in wholesale sales was due in large part to fewer megawatts available due to increased retail sales. Electric revenues increased in 2001 primarily due to an increase in the recovery of fuel costs passed through the FAC and an increase in wholesale activity partially offset by a rate reduction ordered by Kentucky Commission in 2000 and lower sales volumes.
Expenses
Fuel for electric generation comprises a large component of KU’s total operating expenses. KU’s Kentucky jurisdictional electric rates are subject to a FAC whereby increases or decreases are reflected in the FAC factor, subject to the approval of the Kentucky Commission. KU’s wholesale and Virginia jurisdictional electric rates contain a fuel adjustment clause whereby increases or decreases in the cost of fuel are reflected in rates, subject to the approval of FERC and the Virginia Commission, respectively.
Fuel for electric generation increased $13.1 million (5.5%) in 2002 because of an increase in the cost of coal burned ($29.7 million), partially offset by a decrease in generation ($16.5 million). Fuel for electric generation increased $17.1 million (7.8%) in 2001 because of an increase in the cost of coal burned ($21.8 million), partially offset by a decrease in generation ($4.7 million). The average delivered cost per ton of coal purchased was $31.44 in 2002, $27.84 in 2001 and $25.63 in 2000.
Power purchased expense in 2002 increased slightly over 2001, $.8 million (.5%) primarily due to an increase in purchases to meet requirements for native load and off-system sales partially offset by a decrease in purchase price. Power purchased expense decreased $9.8 million (5.9%) in 2001 primarily due to decreased brokered sales activity in the wholesale electric market and a lower unit cost of the purchases partially offset by an increase in purchases to meet requirements for native load and off-system sales.
Other operation expenses increased $25.8 million (21.8%) in 2002. The primary cause for the increase was the full year amortization in 2002 of a regulatory asset created as a result of the workforce reduction associated with KU’s VDT of $6.5 million, higher costs for electric transmission primarily resulting from increased MISO costs of $7.4 million, an increase in property insurance costs of $2.8 million, an increase in employee benefit costs due to changes in pension assumptions to reflect current market conditions and changes in market value of plan assets at the measurement date of $1.7 million, and an increase in outside services of $4.9 million. Other operation expenses increased $10.3 million (9.5%) in 2001. The primary cause for the increase was the amortization of a regulatory asset as a result of the workforce reduction associated with KU’s VDT of $5.0 million and an increase in pension expense of $5.5 million.
Maintenance expenses increased $5.9 million (10.3%) in 2002 primarily due to increases in steam maintenance of $6.1 million related to annual outages at the Ghent, Green River, and Tyrone steam facilities. Maintenance expenses for 2001 decreased $4.6 million (7.5%) primarily due to decreased repairs to steam facilities ($6.5 million).
Depreciation and amortization increased $5.2 million (5.7%) in 2002 primarily due to an increase in plant in service. Depreciation and amortization decreased $8.0 million (8.1%) in 2001 primarily due to a reduction in depreciation rates as a result of a settlement order in December 2001 from the Kentucky Commission. Depreciation expenses decreased by $6.0 million as a result of the settlement order.
Variations in income tax expense are largely attributable to changes in pre-tax income. The 2002 effective income tax rate decreased to 34.9% from the 35.9% rate in 2001. See Note 7 of KU’s Notes to Financial Statements under Item 8.
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Property and other taxes increased $1.1 million (7.6%) in 2002 due to higher property taxes and payroll taxes. Property and other taxes decreased $3.1 million (18.2%) in 2001 due to decreases in payroll taxes related to fewer employees as a result of workforce reductions and transfers to LG&E Energy Services Company.
Other income-net increased $1.5 million (16.8%) in 2002 primarily due to a non-recurring increase in earnings from KU’s equity earnings in a minority interest of $5.2 million, partially offset by a gain on disposition of property in 2001, $1.8 million, lower interest and dividend income from investments, $0.7 million, and higher benefit and other costs, $1.4 million. The increased equity earnings in 2002 are due to the gain on the sale of emissions allowances. Other income-net increased $2.1 million (30.5%) in 2001 due to an increase in the gain on sale of assets.
Interest charges decreased $8.3 million (24.5%) in 2002 as compared to 2001 due to lower interest rates on variable rate debt and refinancing of long term debt with lower interest rates, $8.0 million. Interest charges decreased $5.4 million (13.7%) in 2001 from 2000 due to lower interest rates on variable rate debt, $4.6 million, the retirement of short-term borrowings, $1.6 million, lower interest on debt to parent company, $1.2 million, partially offset by an increase in interest associated with KU’s accounts receivable securitization program, $1.8 million.
KU’s weighted average cost of long-term debt, including amortization of debt expense and interest rate swaps, was 3.30% at December 31, 2002 compared to 4.91% at December 31, 2001. See Note 9 of KU’s Notes to Financial Statements under Item 8.
The rate of inflation may have a significant impact on KU’s operations, its ability to control costs and the need to seek timely and adequate rate adjustments. However, relatively low rates of inflation in the past few years have moderated the impact on current operating results.
CRITICAL ACCOUNTING POLICIES/ESTIMATES
Preparation of financial statements and related disclosures in compliance with generally accepted accounting principles requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including legal and regulatory challenges and anticipated recovery of costs. These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment also may have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies applied has not changed. Specific risks for these critical accounting policies are described in the following paragraphs. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Events rarely develop exactly as forecast and the best estimates routinely require adjustment. See also Note 1 of KU’s Notes to Financial Statements under Item 8.
Unbilled Revenue – At each month end KU prepares a financial estimate that projects electric usage that has been used by customers, but not billed. The estimated usage is based on known weather and days not billed. At December 31, 2002, a 10% change in these estimated quantities would cause revenue and accounts receivable to change by approximately $4.2 million. See also Note 1 of KU’s Notes to Financial Statements under Item 8.
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Benefit Plan Accounting - Judgments and uncertainties in benefit plan accounting include future rate of returns on pension plan assets, interest rates used in valuing benefit obligation, healthcare cost trend rates and other actuarial assumptions.
KU’s costs of providing defined-benefit pension retirement plans is dependent upon a number of factors, such as the rates of return on plan assets, discount rate, and contributions made to the plan. The market value of KU plan assets has been affected by declines in the equity market since the beginning of the fiscal year. As a result, at December 31, 2002, KU was required to recognize an additional minimum liability as prescribed by SFAS No. 87 Employers’ Accounting for Pensions. The liability was recorded as a reduction to other comprehensive income, and did not affect net income for 2002. The amount of the liability depended upon the asset returns experienced in 2002 and contributions made by KU to the plan during 2002. Also, pension cost and cash contributions to the plan could increase in future years without a substantial recovery in the equity market. If the fair value of the plan assets exceeds the accumulated benefit obligation, the recorded liability will be reduced and other comprehensive income will be restored in the consolidated balance sheet.
The combination of poor market performance and a decrease in short-term corporate bond interest rates has created a divergence in the potential value of the pension liability and the actual value of the pension assets. These conditions could result in an increase in KU’s funded accumulated benefit obligation and future pension expense. The primary assumptions that drive the value of the unfunded accumulated benefit obligation are the discount rate and expected return on plan assets.
KU made a contribution to the pension plan of $3.5 million in January 2003.
A 1% increase or decrease in the assumed discount rate could have an approximate $26.0 million positive or negative impact to the accumulated benefit obligation of KU.
See also Note 6 of KU’s Notes to Financial Statements under Item 8.
Regulatory Mechanisms – Judgments and uncertainties include future regulatory decisions, the impact of deregulation and competition on the ratemaking process and external regulator decisions.
Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates based upon Kentucky Commission orders. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections based upon orders by the Kentucky Commission. Management believes, based on orders, the existing regulatory assets and liabilities are probable of recovery. This determination reflects the current regulatory climate in the state. If future recovery of costs ceases to be probable the assets would be required to be recognized in current period earnings.
KU has accrued in the financial statements, an estimate of $13.5 million for 2002 ESM, with collection from customers commencing in April 2003. The ESM is subject to Kentucky Commission approval.
See also Note 3 of KU’s Notes to Financial Statements under Item 8.
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NEW ACCOUNTING PRONOUNCEMENTS
The following accounting pronouncements were issued that affected KU in 2002:
SFAS No. 143, Accounting for Asset Retirement Obligations was issued in 2001. SFAS No. 143 establishes accounting and reporting standards for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.
The effective implementation date for SFAS No. 143 is January 1, 2003. Management has calculated the impact of SFAS No. 143 and the recently released FERC NOPR No. RM02-7, Accounting, Financial Reporting, and Rate Filing Requirements for Asset Retirement Obligations. As of January 1, 2003, KU recorded asset retirement obligation (ARO) assets in the amount of $8.6 million and liabilities in the amount of $18.5 million. KU also recorded a cumulative effect adjustment in the amount of $9.9 million to reflect the accumulated depreciation and accretion of ARO assets at the transition date less amounts previously accrued under regulatory depreciation. KU recorded offsetting regulatory assets of $9.9 million, pursuant to regulatory treatment prescribed under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. Also pursuant to SFAS No. 71, KU recorded regulatory liabilities in the amount of $888,000 offsetting removal costs previously accrued under regulatory accounting in excess of amounts allowed under SFAS No. 143.
KU also expects to record ARO accretion expense of approximately $1.2 million, ARO depreciation expense of approximately $176,000 and an offsetting regulatory credit in the income statement of approximately $1.4 million in 2003, pursuant to regulatory treatment prescribed under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. The accretion, depreciation and regulatory credit will be annual adjustments. SFAS No. 143 will have no impact on the results of the operation of KU.
KU’s asset retirement obligations are primarily related to the final retirement of generating units. KU transmission and distribution lines largely operate under perpetual property easement agreements which do not generally require restoration upon removal of the property. Therefore, under SFAS No. 143, no material asset retirement obligations will be recorded for transmission and distribution assets.
KU adopted EITF No. 98-10, Accounting for Energy Trading and Risk Management Activities, effective January 1, 1999. This pronouncement required that energy trading contracts be marked to market on the balance sheet, with the gains and losses shown net in the income statement. In October 2002, the Emerging Issues Task Force reached a consensus to rescind EITF 98-10. The effective date for the full rescission is for fiscal periods beginning after December 15, 2002. With the rescission of EITF No. 98-10, energy trading contracts that do not also meet the definition of a derivative under SFAS No. 133 must be accounted for as executory contracts. Contracts previously recorded at fair value under EITF No. 98-10 that are not also derivatives under SFAS No. 133 must be restated to historical cost through a cumulative effect adjustment. KU does not expect the rescission of this standard to have a material impact on financial position or results of operations.
In January 2003, the Financial Accounting Standards Board issued Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51 (FIN 46). FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 is effective immediately for all new variable interest entities created or acquired after January 31, 2003. For variable interest entities created or acquired prior to February 1, 2003, the provisions of FIN 46 must be applied for the first interim or annual period beginning after June 15, 2003. KU
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does not expect the adoption of this standard to have any impact on the financial position or results of operations.
LIQUIDITY AND CAPITAL RESOURCES
KU uses net cash generated from its operations and external financing to fund construction of plant and equipment and the payment of dividends. KU believes that such sources of funds will be sufficient to meet the needs of its business in the foreseeable future.
Operating Activities
Cash provided by operations was $175.8 million, $188.1 million and $176.3 million in 2002, 2001 and 2000, respectively. The 2002 decrease from 2001 of $12.3 million was primarily the result of a decrease in accrued taxes and changes in accounts receivable. The 2001 increase resulted from sale of accounts receivable through a securitization program. See Note 1 of KU’s Notes to Financial Statements under Item 8 for a discussion of accounts receivable securitization.
Investing Activities
KU’s primary use of funds for investing activities continues to be for capital expenditures. Capital expenditures were $237.9 million, $142.4 million and $100.3 million in 2002, 2001 and 2000, respectively. KU expects its capital expenditures for 2003 and 2004 will total approximately $550.0 million, which consists primarily of construction costs associated with installation of NOx equipment as described in the section titled “Environmental Matters,” purchase of jointly owned CTs with LG&E and on going construction for the distribution system.
Net cash used for investment activities increased $99.0 million in 2002 compared to 2001 and $38.6 million in 2001 compared to 2000 primarily due to the level of construction expenditures. NOx expenditures increased $50.6 million and CT expenditures increased $27.0 million in 2002.
Financing Activities
Net cash inflows from financing activities were $64.2 million in 2002 and outflows of $46.2 million and $82.4 million in 2001 and 2000, respectively. In 2002, short-term debt increased $72.0 million from 2001. In 2001, short-term debt decreased $13.4 million from 2000 and KU paid $32.8 million in dividends.
In May 2002, KU issued $37.93 million variable rate pollution control Series 12, 13, 14 and 15 due February 1, 2032, and exercised its call option on $37.93 million, 6.25% pollution control Series 1B, 2B, 3B, and 4B due February 1, 2018.
In September 2002, KU issued $96 million variable rate pollution control Series 16 due October 1, 2032, and exercised its call option on $96 million, 7.45% pollution control Series 8 due September 15, 2016.
Future Capital Requirements
Future capital requirements may be affected in varying degrees by factors such as load growth, changes in construction expenditure levels, rate actions by regulatory agencies, new legislation, market entry of competing
57
electric power generators, changes in environmental regulations and other regulatory requirements. KU anticipates funding future capital requirements through operating cash flow, debt, and/or infusion of capital from its parent.
KU’s debt ratings as of December 31, 2002, were:
Moody’s
S&P
Fitch
First mortgage bonds
A1
A
A+
Preferred stock
Baa1
BBB
A-
Commercial paper
P-1
A-2
F-1
These ratings reflect the views of Moody’s, S&P and Fitch. A security rating is not a recommendation to buy, sell or hold securities and is subject to revision or withdrawal at any time by the rating agency.
Contractual Obligations
The following is provided to summarize KU’s contractual cash obligations for periods after December 31, 2002 (in thousands of $):
Payments Due by Period
Contractual cash
Obligations
2003
2004-
2005
2006-
2007
After
2007
Total
Short-term debt(a)
$
119,490
$
—
$
—
$
—
$
119,490
Long-term debt(b)
153,930
—
89,000
257,562
500,492
Unconditional purchase obligations(c)
34,317
79,306
79,878
643,946
837,447
Other long-term obligations(d)
128,199
201,249
—
—
329,448
Total contractual cash obligations(e)
$
435,936
$
280,555
$
168,878
$
901,508
$
1,786,877
(a) Represents borrowings from parent company due within one year.
(b) Includes long-term debt of $91.9 million is classified as a current liability because the bonds are subject to tender for purchase at the option of the holder and to mandatory tender for purchase upon the occurrence of certain events. Maturity dates for the bonds range from 2024 to 2032.
(c) Represents future minimum payments under purchased power agreements through 2020.
(d) Represents construction commitments.
(e) KU does not expect to pay the $91.9 million of long-term debt classified as a current liability in the consolidated balance sheets in 2003 as explained in (b) above. KU anticipates cash from operations and external financing will be sufficient to fund future obligations. KU anticipates refinancing a portion of its short-term debt with long-term debt in 2003.
Market Risks
KU is exposed to market risks from changes in interest rates and commodity prices. To mitigate changes in
58
cash flows attributable to these exposures, KU uses various financial instruments including derivatives. Derivative positions are monitored using techniques that include market value and sensitivity analysis. See Notes 1 and 4 of KU’s Notes to Financial Statements under Item 8.
Interest Rate Sensitivity
KU has short-term and long-term variable rate debt obligations outstanding. At December 31, 2002, the potential change in interest expense associated with a 1% change in base interest rates of KU’s variable rate debt is estimated at $5.2 million after impact of interest rate swaps.
Interest rate swaps are used to hedge KU’s underlying debt obligations. These swaps hedge specific debt issuances and, consistent with management’s designation, are accorded hedge accounting treatment.
As of December 31, 2002, KU has swaps with a combined notional value of $153 million. The swaps exchange fixed-rate interest payments for floating rate interest payments on KU’s Series P, R, and PCS-9 Bonds. The potential loss in fair value resulting from a hypothetical 1% adverse movement in base interest rates is estimated at $6.9 million as of December 31, 2002. This estimate is derived from third party valuations. Changes in the market value of these swaps if held to maturity, as KU intends to do, will have no effect on KU’s net income or cash flow. See Note 4 of KU’s Notes to Financial Statements under Item 8.
Commodity Price Sensitivity
KU has limited exposure to market price volatility in prices of fuel and electricity, since its retail tariffs include the FAC commodity price pass-through mechanism. KU is exposed to market price volatility of fuel and electricity in its wholesale activities.
Energy Trading & Risk Management Activities
KU conducts energy trading and risk management activities to maximize the value of power sales from physical assets it owns, in addition to the wholesale sale of excess asset capacity. Certain energy trading activities are accounted for on a mark-to-market basis in accordance with EITF 98-10 Accounting for Contracts Involved in Energy Trading and Risk Management Activities, SFAS No. 133 Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138 Accounting for Certain Derivative Instruments and Certain Hedging Activities. Wholesale sales of excess asset capacity and wholesale purchases are treated as normal sales and purchases under SFAS No. 133 and SFAS No. 138 and are not marked-to-market.
The rescission of EITF 98-10, effective for fiscal years ending after December 15, 2002, will have no impact on KU’s energy trading and risk management reporting as all contracts marked to market under EITF 98-10 are also within the scope of SFAS No. 133.
The table below summarizes KU’s energy trading and risk management activities for 2002 and 2001(in thousands of $).
2002
2001
Fair value of contracts at beginning of period, net liability
$
(186
)
$
(17
)
Fair value of contracts when entered into during the period
(65
)
3,441
Contracts realized or otherwise settled during the period
448
(2,894
)
Changes in fair values due to changes in assumptions
(353
)
(716
)
Fair value of contracts at end of period, net liability
$
(156
)
$
(186
)
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No changes to valuation techniques for energy trading and risk management activities occurred during 2002. Changes in market pricing, interest rate and volatility assumptions were made during both years. All contracts outstanding at December 31, 2002 have a maturity of less than one year and are valued using prices actively quoted for proposed or executed transactions or quoted by brokers.
KU maintains policies intended to minimize credit risk and revalues credit exposures daily to monitor compliance with those policies. At December 31, 2002, 86% of the trading and risk management commitments were with counterparties rated BBB- equivalent or better.
Accounts Receivable Securitization
On February 6, 2001, KU implemented an accounts receivable securitization program. The purpose of this program is to enable KU to accelerate the receipt of cash from the collection of retail accounts receivable, thereby reducing dependence upon more costly sources of working capital. The securitization program allows for a percentage of eligible receivables to be sold. Eligible receivables are generally all receivables associated with retail sales that have standard terms and are not past due. KU is able to terminate this program at any time without penalty. If there is a significant deterioration in the payment record of the receivables by the retail customers or if KU fails to meet certain covenants regarding the program, the program may terminate at the election of the financial institutions. In this case, payments from retail customers would first be used to repay the financial institutions participating in the program, and would then be available for use by KU.
As part of the program, KU sold retail accounts receivables to a wholly owned subsidiary KU R. Simultaneously, KU R entered into two separate three-year accounts receivable securitization facilities with two financial institutions and their affiliates whereby KU R can sell, on a revolving basis, an undivided interest in certain of their receivables and receive up to $50 million from an unrelated third party purchaser. The effective cost of the receivables programs is comparable to KU’s lowest cost source of capital, and is based on prime rated commercial paper. KU retains servicing rights of the sold receivables through two separate servicing agreements with the third party purchaser. KU has obtained an opinion from independent legal counsel indicating these transactions qualify as a true sale of receivables. As of December 31, 2002, the outstanding program balance was $49.3 million. KU is considering unwinding the accounts receivable securitization arrangements involving KU R during 2003.
The allowance for doubtful accounts associated with the eligible securitized receivables was $520,000 at December 31, 2002. This allowance is based on historical experience of KU. Each securitization facility contains a fully funded reserve for uncollectible receivables.
RATES AND REGULATION
Following the purchase of Powergen by E.ON, E.ON became a registered holding company under PUHCA. As a result, E.ON, its utility subsidiaries, including KU, and certain of its non-utility subsidiaries are subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales of securities, acquisitions and sales of certain utility properties, and intra-system sales of certain goods and services. In addition, PUHCA generally limits the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company. KU believes that it has
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adequate authority (including financing authority) under existing SEC orders and regulations to conduct its business. KU will seek additional authorization when necessary.
KU is subject to the jurisdiction of the Kentucky Commission, the Virginia Commission and FERC in virtually all matters related to electric utility regulation, and as such, its accounting is subject to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. Given KU’s competitive position in the market and the status of regulation in the states of Kentucky and Virginia, KU has no plans or intentions to discontinue its application of SFAS No. 71. See Note 3 of KU’s Notes to Financial Statements under Item 8.
Kentucky Commission Settlement Order - VDT Costs, ESM and Depreciation
During the first quarter 2001, KU recorded a $64 million charge for a workforce reduction program. Primary components of the charge were separation benefits, enhanced early retirement benefits, and health care benefits. The result of this workforce reduction was the elimination of approximately 300 positions, accomplished primarily through a voluntary enhanced severance program.
On June 1, 2001, KU filed an application (VDT case) with the Kentucky Commission to create a regulatory asset relating to these first quarter 2001 charges. The application requested permission to amortize these costs over a four-year period. The Kentucky Commission also opened a case to review the new depreciation study and resulting depreciation rates implemented in 2001.
KU reached a settlement in the VDT case as well as the other cases involving depreciation rates and ESM with all intervening parties. The settlement agreement was approved by the Kentucky Commission on December 3, 2001. The order allowed KU to set up a regulatory asset of $54 million for the workforce reduction costs and begin amortizing these costs over a five year period starting in April 2001. The first quarter 2001 charge of $64 million represented all employees who had accepted a voluntary enhanced severance program. Some employees rescinded their participation in the voluntary enhanced severance program and, along with the non-recurring charge of $6.9 million for FERC and Virginia jurisdictions, thereby decreasing the original charge of the regulatory asset from $64 million to $54 million. The settlement will also reduce revenues approximately $11 million through a surcredit on future bills to customers over the same five year period. The surcredit represents stipulated net savings KU is expected to realize from implementation of best practices through the VDT. The agreement also established KU’s new depreciation rates in effect December 2001, retroactive to January 1, 2001. The new depreciation rates decreased depreciation expense by $6.0 million in 2001.
Environmental Cost Recovery
In June 2000, the Kentucky Commission approved KU’s application for a CCN to construct up to four SCR NOx reduction facilities. The construction and subsequent operation of the SCRs is intended to reduce NOx emission levels to meet the EPA’s mandated NOx emission level of 0.15 lbs./ Mmbtu by May 2004. In its order, the Kentucky Commission ruled that KU’s proposed plan for construction was “reasonable, cost-effective and will not result in the wasteful duplication of facilities”. In October 2000, KU filed an application with the Kentucky Commission to amend its Environmental Compliance Plan to reflect the addition of the proposed NOx reduction technology projects and to amend its Environmental Cost Recovery
In July 1994, the PSC approved KU's January 1994Tariff to include an overall rate of return on capital investments. Approval of KU’s application in April 2001, allowed KU toimplement an environmental surcharge. The surcharge, authorized by a Kentucky statute enacted in 1992, is designedbegin to recovercertain operatingthe costs associated with these new projects, subject to Kentucky Commission oversight during normal six-month and two-year reviews.61
In August 2002, KU filed an application with the Kentucky Commission to amend its compliance plan to allow recovery of the cost of a new and additional environmental compliance facility. The estimated capital cost of the additional facilities is $17.3 million. The Kentucky Commission conducted a public hearing on the case on December 20, 2002, final briefs were filed on January 15, 2003, and a final order was issued February 11, 2003. The final order approved recovery of the new environmental compliance facility totaling $17.3 million. Cost recovery through the environmental surcharge of the approved project will begin with bills rendered in April 2003.
ESM
KU’s electric rates are subject to an ESM. The ESM, initially in place for three years beginning in 2000, sets an upper and lower point for rate of return on equity, whereby if KU’s rate of return for the calendar year falls within the range of 10.5% to 12.5%, no action is necessary. If earnings are above the upper limit, the excess earnings are shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, the earnings deficiency is recovered 40% from ratepayers and 60% from shareholders. By order of the Kentucky Commission, rate changes prompted by the ESM filing go into effect in April of each year subject to a balancing adjustment in successive periods. KU made its second ESM filing on March 1, 2002 for the calendar year 2001 reporting period. KU is in the process of refunding $1 million to customers for the 2001 reporting period. KU estimated that the rate of return will fall below the lower limit, subject to Kentucky Commission approval, for the year ended December 31, 2002. The 2002 financial statements include an accrual to reflect the earnings deficiency of $13.5 million to be recovered from customers commencing in April 2003.
On November 27, 2002, KU filed a revised ESM tariff which proposed continuance of the existing ESM through December 2005. The Kentucky Commission issued an Order suspending the ESM tariff one day making the effective date January 2, 2003. In addition, the Kentucky Commission is conducting a management audit to review the ESM plan and reassess its reasonableness in 2003. KU and interested parties will have the opportunity to provide recommendations for modification and continuance of the ESM or other forms of alternative or incentive regulation.
DSM
In May 2001, the Kentucky Commission approved a plan that would expand LG&E’s current DSM programs into the service territory served by KU. The filing included a rate mechanism that provided for concurrent recovery of DSM costs,
related to compliance with federal, state or local environmental requirementsprovided an incentive for implementing DSM programs, and recovered revenues from lost sales associated with theproductionDSM program based on program planning engineering estimates and post-implementation evaluations.FAC
KU employs an FAC mechanism, which allows KU to recover from customers the actual fuel costs associated with retail electric sales. In July 1999, the Kentucky Commission issued a series of orders requiring KU to refund approximately $10.1 million resulting from reviews of the FAC from November 1994 to October 1998. In August 1999, after a rehearing request by KU, the Kentucky Commission issued a final order that reduced the refund obligation to $ 6.7 million ($5.8 million on Kentucky jurisdictional basis) from the original order amount of $10.1 million. KU implemented the refund from October 1999 through September 2000. Both KU and the KIUC appealed the order. Pending a decision on this appeal, a comprehensive settlement was reached by all parties and approved by the Kentucky Commission on May 17, 2002. Thereunder, KU agreed to credit
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its fuel clause in the amount of $954,000 (refund made in June and July 2002), and the parties agreed on a prospective interpretation of the state’s fuel adjustment clause regulation to ensure consistent and mutually acceptable application on a going-forward basis.
In December 2002, the Kentucky Commission initiated a two year review of the operation of KU’s fuel adjustment clause for the period November 2000 through October 2002. Testimony in the review case was filed on January 20, 2003 and a public hearing was held February 18, 2003. Issues addressed at that time included the establishment of the current base fuel factor to be included in KU’s base rates, verification of proper treatment of purchased power costs during unit outages, and compliance with fuel procurement policies and practices.
In January 2003, the Kentucky Commission reviewed the FAC of KU for the six month period ended October 31, 2001. The Kentucky Commission ordered KU to reduce its fuel costs for purposes of calculating its FAC by $673,000. At issue was the purchase of approximately 102,000 tons of coal from Western Kentucky Energy Corporation, a non-regulated affiliate, for use at KU’s Ghent Facility. The Kentucky Commission further ordered that an independent audit be conducted to examine operational and management aspects of KU’s fuel procurement functions.
Kentucky Commission Administrative Case for Affiliate Transactions
In December 1997, the Kentucky Commission opened Administrative Case No. 369 to consider Kentucky Commission policy regarding cost allocations, affiliate transactions and codes of conduct governing the relationship between utilities and their non-utility operations and affiliates. The Kentucky Commission intended to address two major areas in the proceedings: the tools and conditions needed to prevent cost shifting and cross-subsidization between regulated and non-utility operations; and whether a code of conduct should be established to assure that non-utility segments of the holding company are not engaged in practices that could result in unfair competition caused by cost shifting from the non-utility affiliate to the utility. During the period September 1998 to February 2000, the Kentucky Commission issued draft codes of conduct and cost allocation guidelines. In early 2000, the Kentucky General Assembly enacted legislation, House Bill 897, which authorized the Kentucky Commission to require utilities that provide nonregulated activities to keep separate accounts and allocate costs in accordance with procedures established by the Kentucky Commission. In the same bill, the General Assembly set forth provisions to govern a utility’s activities related to the sharing of information, databases, and resources between its employees or an affiliate involved in the marketing or the provision of nonregulated activities and its employees or an affiliate involved in the provision of regulated services. The legislation became law in July 2000 and KU has been operating pursuant thereto since that time. On February 14, 2001, the Kentucky Commission published notice of their intent to promulgate new administrative regulation under the auspices of the new law. This effort is still on going.
Kentucky Commission Administrative Case for System Adequacy
On June 19, 2001, Kentucky Governor Paul E. Patton issued Executive Order 2001-771, which directed the Kentucky Commission to review and study issues relating to the need for and development of new electric generating capacity in Kentucky. The issues to be considered included the impact of new power plants on the electric supply grid, facility siting issues, and economic development matters, with the goal of ensuring a continued, reliable source of supply of electricity for the citizens of Kentucky and the continued environmental and economic vitality of Kentucky and its communities. In response to that Executive Order, in July 2001 the Kentucky Commission opened Administrative Case No. 387 to review the adequacy of Kentucky’s generation
63
capacity and transmission system. Specifically, the items reviewed were the appropriate level of reliance on purchased power, the appropriate reserve margins to meet existing and future electric demand, the impact of spikes in natural gas prices on electric utility planning strategies, and the adequacy of Kentucky’s electric transmission facilities. KU, as a party to this proceeding, filed written testimony and responded to two requests for information. Public hearings were held and in October 2001, KU filed a final brief in the case. In December 2001, the Kentucky Commission issued an order in which it noted that KU is responsibly addressing the long-term supply needs of native load customers and that current reserve margins are appropriate. However, due to the rapid pace of change in the industry, the order also requires KU to provide an annual assessment of supply resources, future demand, reserve margin, and the need for new resources.
Regarding the transmission system, the Kentucky Commission concluded that the transmission system within Kentucky can reliably serve native load and a significant portion of the proposed new unregulated power plants. However, it will not be able to handle the volume of transactions envisioned by FERC without future upgrades, the costs of which should be borne by those for whom the upgrades are required.
The Kentucky Commission pledged to continue to monitor all relevant issues and advocate Kentucky’s interests at all opportunities.
FERC SMD NOPR
On July 31, 2002, the FERC issued a NOPR in Docket No. RM01-12-000 which would substantially alter the regulations governing the nation’s wholesale electricity markets by establishing a common set of rules — SMD. The SMD NOPR would require each public utility that owns, operates, or controls interstate transmission facilities to become an Independent Transmission Provider (ITP), belong to an RTO that is an ITP, or contract with an ITP for operation of its transmission assets. It would also establish a standardized congestion management system, real-time and day-ahead energy markets, and a single transmission service for network and point-to-point transmission customers. Review of the proposed rulemaking is underway and a final rule is expected during 2003. While it is expected that the SMD final rule will affect KU revenues and expenses, the specific impact of the rulemaking is not known at this time.
MISO
KU is a member of the MISO, which began commercial operations on February 1, 2002. MISO now has operational control over KU’s high-voltage transmission facilities (100 kV and greater), while KU continues to control and operate the lower voltage transmission subject to the terms and conditions of the MISO OATT. As a transmission-owning member of MISO, KU also incurs administrative costs of MISO pursuant to Schedule 10 of the MISO OATT.
MISO also proposed to implement a congestion management system. FERC directed the MISO to coordinate its efforts with FERC’s Rulemaking on SMD. On September 24, 2002, the MISO filed new rate schedules designated as Schedules 16 and 17, which provide for the collection of costs incurred by the MISO to establish day-ahead and real-time energy markets. The MISO proposed to recover these costs under Schedules 16 and 17 once service commences. If approved by FERC, these schedules will cause KU to incur additional costs. KU opposes the establishment of Schedules 16 and 17. This effort is still on-going and the ultimate impact of the two schedules, if approved, is not known at this time.
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Merger Surcredit
As part of the LG&E Energy merger with KU Energy in 1998, LG&E Energy estimated non-fuel savings over a ten–year period following the merger. Costs to achieve these savings for KU of $42.3 million were recorded in the second quarter of 1998, $20.5 million of which was deferred and amortized over a five-year period pursuant to regulatory orders. Primary components of the merger costs were separation benefits, relocation costs, and transaction fees, the majority of which were paid by December 31, 1998. KU expensed the remaining costs associated with the merger ($21.8 million) in the second quarter of 1998.
In approving the merger, the Kentucky Commission adopted KU’s proposal to reduce its retail customers’ bills based on one-half of the estimated merger-related savings, net of deferred and amortized amounts, over a five-year period. The surcredit mechanism provides that 50% of the net non-fuel cost savings estimated to be achieved from
coal, includingthe1990merger be provided to ratepayers through a monthly bill credit, and 50% be retained by the Companies, over a five-year period. The surcredit was allocated 53% to KU and 47% to LG&E. In that same order, the Commission required LG&E and KU, after the end of the five-year period, to present a plan for sharing with customers the then-projected non-fuel savings associated with the merger. The Companies submitted this filing on January 13, 2003, proposing to continue to share with customers, on a 50%/50% basis, the estimated fifth-year gross level of non-fuel savings associated with the merger. The filing is currently under review.Any fuel cost savings are passed to Kentucky customers through the fuel adjustment clause. See FAC above.
Environmental Matters
The Clean Air Act
Amendments. KU'simposed stringent new SO2 and NOx emission limits on electric generating units. KU met its Phase I SO2 requirements primarily through installation of a scrubber on Ghent Unit 1. KU’s strategy for Phase II SO2 reductions, which commenced January 1, 2000, is to use accumulated emissions allowances to delay additional capital expenditures and may also include fuel switching or the installation of additional scrubbers. KU met the NOx emission requirements of the Act through installation of low-NOx burner systems. KU’s compliance plans are subject to many factors including developments in the emission allowance and fuel markets, future regulatory and legislative initiatives, and advances in clean air control technology. KU will continue to monitor these developments to ensure that its environmentalsurchargeobligations are met in the most efficient and cost-effective manner.In September 1998, the EPA announced its final “NOx SIP Call” rule requiring states to impose significant additional reductions in NOx emissions by May 2003, in order to mitigate alleged ozone transport impacts on the Northeast region. The Commonwealth of Kentucky is currently in the process of revising its SIP to require reductions in NOx emissions from coal-fired generating units to the 0.15 lb./Mmbtu level on a system-wide basis. In related proceedings in response to petitions filed by various Northeast states, in December 1999, EPA issued a final rule pursuant to Section 126 of the Clean Air Act directing similar NOx reductions from a number of specifically targeted generating units including all KU units in the eastern half of Kentucky. Additional petitions currently pending before EPA may potentially result in rules encompassing KU’s remaining generating units. As a result of appeals to both rules, the compliance date was
implementedextended to May 2004. All KU generating units are subject to the May 2004 compliance date under these NOx emissions reduction rules.KU is currently implementing a plan for adding significant additional NOx controls to its generating units. Installation of additional NOx controls will proceed on a phased basis, with installation of controls commencing in
August 1994.late 2000 and continuing through the final compliance date. KU estimates that it willresultincur total capital costs65
of approximately $232 million to reduce its NOx emissions to the 0.15 lb./Mmbtu level on a company-wide basis. In addition, KU will incur additional operating and maintenance costs in operating new NOx controls. KU believes its costs in this regard to be comparable to those of similarly situated utilities with like generation assets. KU had anticipated that such capital and operating costs are the type of costs that are eligible for recovery from customers under its environmental surcharge mechanism and believed that a significant portion of such costs could be recovered. In April 2001, the Kentucky Commission granted recovery of these costs for KU.
KU is also monitoring several other air quality issues which may potentially impact coal-fired power plants, including the appeal of the D.C. Circuit’s remand of the EPA’s revised air quality standards for ozone and particulate matter, measures to implement EPA’s regional haze rule, and EPA’s December 2000 determination to regulate mercury emissions from power plants.
KU owns or formerly owned several properties that contained past MGP operations. Various contaminants are typically found at such former MGP sites and environmental remediation measures are frequently required. KU has completed the cleanup of a site owned by KU. With respect to other former MGP sites no longer owned by KU, KU is unaware of what, if any, additional exposure or liability it may have.
In October 1999, approximately 38,000 gallons of diesel fuel leaked from a cracked valve in an
average increaseunderground pipeline at KU’s E.W. Brown Station. Under the oversight ofabout 4%EPA and state officials, KU commenced immediate spill containment and recovery measures which prevented the spill from reaching the Kentucky River. KU ultimately recovered approximately 34,000 gallons of diesel fuel. In November 1999, the Kentucky Division of Water issued a notice of violation for the incident. KU is currently negotiating with the state in an effort to reach acustomer's monthly bill, leaving KU's rates very competitive. The constitutionalitycomplete resolution of this matter. KU incurred costs of approximately $1.8 million and received insurance reimbursement of $1.2 million. In December 2002, the Department of Justice (DOJ) sent correspondence to KU regarding a potential per-day fine for failure to timely submit a spill control plan and a per-gallon fine for the amount of oil discharged. KU and the DOJ have commenced settlement discussions using existing DOJ settlement guidelines on this matter.In April 2002, the EPA sent correspondence to KU regarding potential exposure in connection with $1.5 million in completed remediation costs associated with a transformer scrap-yard. KU believes it is one of the
surcharge is being challenged in the Franklin County (Kentucky) Circuit Court. Management believes that, based on its reviewmore remote among a number ofthe circumstances, the surcharge statute is constitutional and the PSC approval of July 1994 will be upheld. Other In 1990, KU received a letter from the EPA identifying KU and others aspotentially responsible partiesunder the Comprehensive Environmental Response CompensationandLiability Act of 1980 for a disposal site in Daviess County, Kentucky. The EPA has turned over responsibility for investigation of the site and development of a remediation plan to a group (not including KU) originally named as potentially responsible parties. KUhas entered intoan agreementsettlement discussions with thegroupEPA on this matter.See Note 11 of KU’s Notes to Financial Statements under Item 8 for an additional discussion of environmental issues.
Deferred Income Taxes
KU expects to have adequate levels of taxable income to realize its recorded deferred tax assets. At December 31, 2002, deferred tax assets totaled $61 million and were principally related to expenses attributable to KU’s pension plans and post retirement benefit obligations.
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FUTURE OUTLOOK
Competition and Customer Choice
KU has moved aggressively over the past decade to be positioned for the energy industry’s shift to customer choice and a competitive market for energy services. Specifically, KU has taken many steps to prepare for the expected increase in competition in its business, including support for PBR structures, aggressive cost reduction activities; strategic acquisitions, dispositions and growth initiatives; write-offs of previously deferred expenses; an increase in focus on commercial and industrial customers; an increase in employee training; and necessary corporate and business unit realignments.
In December 1997, the Kentucky Commission issued a set of principles which was intended to serve as its guide in consideration of issues relating to industry restructuring. Among the issues addressed by these principles are: consumer protection and benefit, system reliability, universal service, environmental responsibility, cost allocation, stranded costs and codes of conduct. During 1998, the Kentucky Commission and a task force of the Kentucky General Assembly each initiated proceedings, including meetings with representatives of utilities, consumers, state agencies and other groups in Kentucky, to discuss the possible structure and effects of energy industry restructuring in Kentucky.
In November 1999, the task force issued a report to the
portionGovernor of Kentucky and a legislative agency recommending no general electric industry restructuring actions during the 2000 legislative session. No general industry restructuring actions have been taken to date by the legislature.Thus, at the time of this report, neither the Kentucky General Assembly nor the Kentucky Commission has adopted or approved a plan or timetable for retail electric industry competition in Kentucky. The nature or timing of the
investigationultimate legislative or regulatory actions regarding industry restructuring anddevelopmenttheir impact on KU, which may be significant, cannot currently be predicted.While many states have moved forward in providing retail choice, many others have not. Some are reconsidering their initiatives and have even delayed implementation.
Virginia has enacted a phase-in of customer choice through the Virginia Electric Restructuring Act. The Virginia Commission is promulgating regulations to govern the various activities required by the Act. KU filed unbundled rates that became effective January 1, 2002. KU was granted a waiver from the Virginia Commission on October 29, 2002, exempting KU from retail choice through December 31, 2004. KU is also seeking a permanent legislative exemption to the Virginia Electric Restructuring Act. The outcome of such legislative initiatives will not be known until mid-2003.
ITEM 7A. Quantitative and Qualitative Disclosure About Market Risk.
See LG&E’s and KU’s Management’s Discussion and Analysis of Results of Operations and Financial Condition, Market Risks, under Item 7.
ITEM 8. Financial Statements and Supplementary Data.
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INDEX OF ABBREVIATIONS
Capital Corp.
LG&E Capital Corp.
Clean Air Act
The Clean Air Act, as amended in 1990
CCN
Certificate of Public Convenience and Necessity
CT
Combustion Turbines
DSM
Demand Side Management
ECR
Environmental Cost Recovery
EEI
Electric Energy, Inc.
EITF
Emerging Issues Task Force Issue
E.ON
E.ON AG
EPA
U.S. Environmental Protection Agency
ESM
Earnings Sharing Mechanism
F
Fahrenheit
FAC
Fuel Adjustment Clause
FERC
Federal Energy Regulatory Commission
FPA
Federal Power Act
FT and FT-A
Firm Transportation
GSC
Gas Supply Clause
IBEW
International Brotherhood of Electrical Workers
IMEA
Illinois Municipal Electric Agency
IMPA
Indiana Municipal Power Agency
Kentucky Commission
Kentucky Public Service Commission
KIUC
Kentucky Industrial Utility Consumers, Inc.
KU
Kentucky Utilities Company
KU Energy
KU Energy Corporation
KU R
KU Receivables LLC
kV
Kilovolts
Kva
Kilovolt-ampere
KW
Kilowatts
Kwh
Kilowatt hours
LEM
LG&E Energy Marketing Inc.
LG&E
Louisville Gas and Electric Company
LG&E Energy
LG&E Energy Corp.
LG&E R
LG&E Receivables LLC
LG&E Services
LG&E Energy Services Inc.
Mcf
Thousand Cubic Feet
MGP
Manufactured Gas Plant
MISO
Midwest Independent System Operator
Mmbtu
Million British thermal units
Moody’s
Moody’s Investor Services, Inc.
Mw
Megawatts
Mwh
Megawatt hours
NNS
No-Notice Service
NOPR
Notice of Proposed Rulemaking
NOx
Nitrogen Oxide
OATT
Open Access Transmission Tariff
OMU
Owensboro Municipal Utilities
OVEC
Ohio Valley Electric Corporation
PBR
Performance-Based Ratemaking
PJM
Pennsylvania, New Jersey, Maryland Interconnection
Powergen
Powergen Limited (formerly Powergen plc)
PUHCA
Public Utility Holding Company Act of 1935
ROE
Return on Equity
RTO
Regional Transmission Organization
S&P
Standard & Poor’s Rating Services
SCR
Selective Catalytic Reduction
68
SEC
Securities and Exchange Commission
SERP
Supplemental Employee Retirement Plan
SFAS
Statement of Financial Accounting Standards
SIP
State Implementation Plan
SMD
Standard Market Design
SO2
Sulfur Dioxide
Tennessee Gas
Tennessee Gas Pipeline Company
Texas Gas
Texas Gas Transmission Corporation
TRA
Tennessee Regulatory Authority
Trimble County
LG&E’s Trimble County Unit 1
USWA
United Steelworkers of America
Utility Operations
Operations of LG&E and KU
VDT
Value Delivery Team Process
Virginia Commission
Virginia State Corporation Commission
Virginia Staff
Virginia State Corporation Commission Staff
69
Louisville Gas and Electric Company and Subsidiary
Consolidated Statements of Income
(Thousands of $)
Years Ended December 31
2002
2001
2000
OPERATING REVENUES:
Electric
$
746,224
$
706,645
$
713,458
Gas
267,693
290,775
272,489
Provision for rate collections (refunds) (Note 3)
12,267
(720
)
(2,500
)
Total operating revenues (Note 1)
1,026,184
996,700
983,447
OPERATING EXPENSES:
Fuel for electric generation
194,900
159,231
159,418
Power purchased
84,330
81,475
96,894
Gas supply expenses
182,108
206,165
196,912
Other operation expenses
208,322
167,818
135,943
Maintenance
60,210
58,687
63,709
Depreciation and amortization (Note 1)
105,906
100,356
98,291
Federal and state income taxes (Note 7)
55,035
63,452
64,425
Property and other taxes
17,459
17,743
18,985
Total operating expenses
908,270
854,927
834,577
Net operating income
117,914
141,773
148,870
Other income - net (Note 8)
820
2,930
4,921
Interest charges
29,805
37,922
43,218
Net income
88,929
106,781
110,573
Preferred stock dividends
4,246
4,739
5,210
Net income available for common stock
$
84,683
$
102,042
$
105,363
Consolidated Statements of Retained Earnings
(Thousands of $)
Years Ended December 31
2002
2001
2000
Balance January 1
$
393,636
$
314,594
$
259,231
Add net income
88,929
106,781
110,573
482,565
421,375
369,804
Deduct: Cash dividends declared on stock:
5% cumulative preferred
1,075
1,075
1,075
Auction rate cumulative preferred
1,702
2,195
2,666
$5.875 cumulative preferred
1,469
1,469
1,469
Common
69,000
23,000
50,000
73,246
27,739
55,210
Balance December 31
$
409,319
$
393,636
$
314,594
The accompanying notes are an integral part of these consolidated financial statements.
70
Louisville Gas and Electric Company and Subsidiary
Consolidated Statements of Comprehensive Income
(Thousands of $)
Years Ended December 31
2002
2001
2000
Net income
$
88,929
$
106,781
$
110,573
Cumulative effect of change in accounting principle – Accounting for derivative instruments and hedging activities
—
(5,998
)
—
Losses on derivative instruments and hedging activities (Note 1)
(8,511
)
(2,606
)
—
Additional minimum pension liability adjustment (Note 6)
(25,999
)
(24,712
)
—
Income tax benefit related to items of other comprehensive income
13,898
13,416
—
Other comprehensive loss, net of tax
(20,612
)
(19,900
)
—
Comprehensive income
$
68,317
$
86,881
$
110,573
The accompanying notes are an integral part of these consolidated financial statements.
71
Louisville Gas and Electric Company and Subsidiary
Consolidated Balance Sheets
(Thousands of $)
December 31
2002
2001
ASSETS:
Utility plant, at original cost (Note 1):
Electric
$
2,717,187
$
2,598,152
Gas
435,235
409,994
Common
169,577
159,817
3,321,999
3,167,963
Less: reserve for depreciation
1,463,674
1,381,874
1,858,325
1,786,089
Construction work in progress
300,986
255,074
2,159,311
2,041,163
Other property and investments – less reserve of $63 in 2002 and 2001
764
1,176
Current assets:
Cash
17,015
2,112
Accounts receivable - less reserve of $2,125 in 2002 and $1,575 in 2001
68,440
85,667
Materials and supplies - at average cost:
Fuel (predominantly coal) (Note 1)
36,600
22,024
Gas stored underground (Note 1)
50,266
46,395
Other
25,651
29,050
Prepayments and other
5,298
4,688
203,270
189,936
Deferred debits and other assets:
Unamortized debt expense (Note 1)
6,532
5,921
Regulatory assets (Note 3)
153,446
197,142
Other
37,755
13,016
197,733
216,079
$
2,561,078
$
2,448,354
CAPITAL AND LIABILITIES:
Capitalization (see statements of capitalization):
Common equity
$
833,141
$
838,070
Cumulative preferred stock
95,140
95,140
Long-term debt (Note 9)
328,104
370,704
1,256,385
1,303,914
Current liabilities:
Current portion of long-term debt (Note 9)
288,800
246,200
Notes payable (Note 10)
193,053
94,197
Accounts payable
122,771
149,070
Accrued taxes
1,450
20,257
Other
19,536
18,658
625,610
528,382
Deferred credits and other liabilities:
Accumulated deferred income taxes (Notes 1 and 7)
313,225
298,143
Investment tax credit, in process of amortization
54,536
58,689
Accumulated provision for pensions and related benefits (Note 6)
224,703
167,526
Regulatory liabilities (Note 3)
52,424
65,349
Other
34,195
26,351
679,083
616,058
Commitments and contingencies (Note 11)
.
$
2,561,078
$
2,448,354
The accompanying notes are an integral part of these consolidated financial statements.
72
Louisville Gas and Electric Company and Subsidiary
Consolidated Statements of Cash Flows
(Thousands of $)
Years Ended December 31
2002
2001
2000
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income
$
88,929
$
106,781
$
110,573
Items not requiring cash currently:
Depreciation and amortization
105,906
100,356
98,291
Deferred income taxes - net
11,915
3,021
31,020
Investment tax credit - net
(4,153
)
(4,290
)
(4,274
)
Other
37,260
(528
)
8,481
Change in certain net current assets:
Accounts receivable
(3,973
)
43,185
(56,993
)
Materials and supplies
(15,048
)
(2,018
)
(4,311
)
Accounts payable
(26,299
)
14,678
21,384
Accrued taxes
(18,807
)
12,184
(15,686
)
Prepayments and other
321
(10,500
)
(7,816
)
Sale of accounts receivable (Note 1)
21,200
42,000
—
Other
15,130
(17,806
)
(24,431
)
Net cash flows from operating activities
212,381
287,063
156,238
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchases of securities
—
—
(708
)
Proceeds from sales of securities
412
4,237
4,089
Construction expenditures
(220,416
)
(252,958
)
(144,216
)
Net cash flows from investing activities
(220,004
)
(248,721
)
(140,835
)
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term borrowings and repayments
98,856
(20,392
)
(5,508
)
Issuance of pollution control bonds
158,635
9,662
106,545
Retirement of first mortgage bonds and pollution control bonds
(161,665
)
—
(130,627
)
Additional paid-in capital
—
—
40,000
Payment of dividends
(73,300
)
(27,995
)
(78,079
)
Net cash flows from financing activities
22,526
(38,725
)
(67,669
)
Change in cash and temporary cash investments
14,903
(383
)
(52,266
)
Cash and temporary cash investments at beginning of year
2,112
2,495
54,761
Cash and temporary cash investments at end of year
$
17,015
$
2,112
$
2,495
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Income taxes
$
51,540
$
35,546
$
46,562
Interest on borrowed money
25,673
30,989
42,958
The accompanying notes are an integral part of these consolidated financial statements.
73
Louisville Gas and Electric Company and Subsidiary
Consolidated Statements of Capitalization
(Thousands of $)
December 31
2002
2001
COMMON EQUITY:
Common stock, without par value -
Authorized 75,000,000 shares, outstanding 21,294,223 shares
$
425,170
$
425,170
Common stock expense
(836
)
(836
)
Additional paid-in capital
40,000
40,000
Accumulated other comprehensive income
(40,512
)
(19,900
)
Retained earnings
409,319
393,636
833,141
838,070
CUMULATIVE PREFERRED STOCK:
Redeemable on 30 days notice by LG&E
Shares
Outstanding
Current
Redemption Price
$25 par value, 1,720,000 shares authorized -
5% series
860,287
$
28.00
21,507
21,507
Without par value, 6,750,000 shares authorized -
Auction rate
500,000
100.00
50,000
50,000
$5.875 series
250,000
101.18
25,000
25,000
Preferred stock expense
(1,367
)
(1,367
)
95,140
95,140
LONG-TERM DEBT (Note 9):
First mortgage bonds -
Series due August 15, 2003, 6%
42,600
42,600
Pollution control series:
R due November 1, 2020, 6.55%
—
41,665
S due September 1, 2017, variable%
31,000
31,000
T due September 1, 2017, variable%
60,000
60,000
U due August 15, 2013, variable%
35,200
35,200
V due August 15, 2019, 5.625%
102,000
102,000
W due October 15, 2020, 5.45%
26,000
26,000
X due April 15, 2023, 5.90%
40,000
40,000
Y due May 1, 2027, variable%
25,000
25,000
Z due August 1, 2030, variable%
83,335
83,335
AA due September 1, 2027, variable%
10,104
10,104
BB due September 1, 2026, variable%
22,500
—
CC due September 1, 2026, variable%
27,500
—
DD due November 1, 2027, variable%
35,000
—
EE due November 1, 2027, variable%
35,000
—
FF due October 1, 2032, variable%
41,665
—
Total first mortgage bonds
616,904
496,904
Pollution control bonds (unsecured) -
Series due September 1, 2026, variable%
—
22,500
Series due September 1, 2026, variable%
—
27,500
Series due November 1, 2027, variable%
—
35,000
Series due November 1, 2027, variable%
—
35,000
Total unsecured pollution control bonds
—
120,000
Total bonds outstanding
616,904
616,904
Less current portion of long-term debt
288,800
246,200
Long-term debt
328,104
370,704
Total capitalization
$
1,256,385
$
1,303,914
The accompanying notes are an integral part of these consolidated financial statements.
74
Louisville Gas and Electric Company and Subsidiary
Notes to Consolidated Financial StatementsNote 1 - Summary of Significant Accounting Policies
LG&E, a subsidiary of LG&E Energy and an indirect subsidiary of Powergen and E.ON, is a regulated public utility engaged in the generation, transmission, distribution, and sale of electric energy and the storage, distribution, and sale of natural gas in Louisville and adjacent areas in Kentucky. LG&E Energy is an exempt public utility holding company with wholly owned subsidiaries including LG&E, KU, Capital Corp., LEM, and LG&E Services. All of the LG&E’s Common Stock is held by LG&E Energy. LG&E has one wholly owned consolidated subsidiary, LG&E R.
On December 11, 2000, LG&E Energy was acquired by Powergen. On July 1, 2002, E.ON, a German company, completed its acquisition of Powergen plc (now Powergen Limited). E.ON had announced its pre-conditional cash offer of £5.1 billion ($7.3 billion) for Powergen on April 9, 2001. E.ON and Powergen are registered public utility holding companies under PUHCA. No costs associated with these acquisitions nor any of the effects of purchase accounting have been reflected in the financial statements of LG&E.
Certain reclassification entries have been made to the previous year’s financial statements to conform to the 2002 presentation with no impact on the balance sheet totals or previously reported income.
Utility Plant. LG&E’s utility plant is stated at original cost, which includes payroll-related costs such as taxes, fringe benefits, and administrative and general costs. Construction work in progress has been included in the rate base for determining retail customer rates. LG&E has not recorded any allowance for funds used during construction.
The cost of plant retired or disposed of in the normal course of business is deducted from plant accounts and such cost, plus removal expense less salvage value, is charged to the reserve for depreciation. When complete operating units are disposed of, appropriate adjustments are made to the reserve for depreciation and gains and losses, if any, are recognized.
Depreciation and Amortization. Depreciation is provided on the straight-line method over the estimated service lives of depreciable plant. Pursuant to a final order of the Kentucky Commission dated December 3, 2001, LG&E implemented new depreciation rates effective January 1, 2001. The amounts provided were approximately 3.1% in 2002 (2.9% electric, 2.8% gas and 6.6% common); 3.0% for 2001 (2.9% electric, 2.9% gas and 5.7% common); and 3.6% for 2000 (3.3% electric, 3.8% gas and 7.3% common), of average depreciable plant. Of the amount provided for depreciation, at December 31, 2002, 2001 and 2000, respectively, approximately 0.4 % electric, 0.9 % gas and 0.04% common were related to the retirement, removal and disposal costs of long lived assets.
Fuel Inventory. Fuel inventories of $36.6 million and $22.0 million at December 31, 2002, and 2001, respectively, are included in Fuel in the balance sheet. The inventory is accounted for using the average-cost method.
Gas Stored Underground. Gas inventories of $50.3 million and $46.4 million at December 31, 2002, and 2001, respectively, are included in gas stored underground in the balance sheet. The inventory is accounted for using the average-cost method.
Financial Instruments. LG&E uses over-the-counter interest-rate swap agreements to hedge its exposure to fluctuations in the interest rates it pays on variable-rate debt. Gains and losses on interest-rate swaps used to hedge interest rate risk are reflected in other comprehensive income. In 2000, LG&E used exchange traded U.S.
75
Treasury note and bond futures to hedge its exposure to fluctuations in the value of its investments in the preferred stocks of other companies. Gains and losses on U.S. Treasury note and bond futures were charged or credited to other income-net. See Note 4 - Financial Instruments.
Unamortized Debt Expense. Debt expense is capitalized in deferred debits and amortized over the lives of the related bond issues, consistent with regulatory practices.
Deferred Income Taxes. Deferred income taxes are recognized at currently enacted tax rates for all material temporary differences between the financial reporting and income tax basis of assets and liabilities.
Investment Tax Credits. Investment tax credits resulted from provisions of the tax law that permitted a reduction of LG&E’s tax liability based on credits for certain construction expenditures. Deferred investment tax credits are being amortized to income over the estimated lives of the related property that gave rise to the credits.
Revenue Recognition. Revenues are recorded based on service rendered to customers through month-end. LG&E accrues an estimate for unbilled revenues from each meter reading date to the end of the accounting period. The unbilled revenue estimates included in accounts receivable were approximately $40.7 million and $37.3 million, at December 31, 2002 and 2001, respectively. See Note 3, Rates and Regulatory Matters. LG&E recorded electric revenues that resulted from sales to a related party, KU, of $46.5 million, $28.5 million and $20.9 million for years ended December 31, 2002, 2001 and 2000, respectively.
Fuel and Gas Costs. The cost of fuel for electric generation is charged to expense as used, and the cost of gas supply is charged to expense as delivered to the distribution system. LG&E implemented a Kentucky Commission-approved performance-based ratemaking mechanism related to gas procurement and off-system gas sales activity. See Note 3, Rates and Regulatory Matters.
Management’s Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported assets and liabilities and disclosure of contingent items at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. See Note 11, Commitments and Contingencies, for a further discussion.
Accounts Receivable Securitization. SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, revises the standards for accounting for securitizations and other transfers of financial assets and collateral and requires certain disclosures, and provides accounting and reporting standards for transfers and servicing of financial assets and extinguishments of liabilities. SFAS No. 140 was adopted in the first quarter of 2001, when LG&E entered into an accounts receivable securitization transaction.
On February 6, 2001, LG&E implemented an accounts receivable securitization program. The purpose of this program is to enable LG&E to accelerate the receipt of cash from the collection of retail accounts receivable, thereby reducing dependence upon more costly sources of working capital. The securitization program allows for a percentage of eligible receivables to be
bornesold. Eligible receivables are generally all receivables associated with retail sales that have standard terms and are not past due. LG&E is able to terminate this program at any time without penalty. If there is a significant deterioration in the payment record of the receivables byKUthe retail customers or if LG&E fails to meet certain covenants regarding the program, the program may terminate at the election of the financial institutions. In this case, payments from retail customers would first be used to repay the financial institutions participating inconnectionthe program, and would then be available for use by LG&E.As part of the program, LG&E sold retail accounts receivables to a wholly owned subsidiary, LG&E R.
76
Simultaneously, LG&E R entered into two separate three-year accounts receivable securitization facilities with two financial institutions and their affiliates whereby LG&E R can sell, on a revolving basis, an undivided interest in certain of its receivables and receive up to $75 million from an unrelated third party purchaser. The effective cost of the receivables programs is comparable to LG&E’s lowest cost source of capital, and is based on prime rated commercial paper. LG&E retains servicing rights of the sold receivables through two separate servicing agreements with the
site. Any remediation plan wouldthird party purchaser. LG&E has obtained an opinion from independent legal counsel indicating these transactions qualify as true sale of receivables. As of December 31, 2002, the outstanding program balance was $63.2 million. LG&E is considering unwinding its accounts receivable securitization arrangements involving LG&E R during 2003.The allowance for doubtful accounts associated with the eligible securitized receivables was $2.125 million at December 31, 2002. This allowance is based on historical experience of LG&E. Each securitization facility contains a fully funded reserve for uncollectible receivables.
New Accounting Pronouncements. The following accounting pronouncements were issued that affected LG&E in 2002:
SFAS No. 143, Accounting for Asset Retirement Obligations was issued in 2001. SFAS No. 143 establishes accounting and reporting standards for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.
The effective implementation date for SFAS No. 143 is January 1, 2003. Management has calculated the impact of SFAS No. 143 and the recently released FERC NOPR No. RM02-7, Accounting, Financial Reporting, and Rate Filing Requirements for Asset Retirement Obligations. As of January 1, 2003, LG&E recorded asset retirement obligation (ARO) assets in the amount of $4.6 million and liabilities in the amount of $9.3 million. LG&E also recorded a cumulative effect adjustment in the amount of $5.3 million to reflect the accumulated depreciation and accretion of ARO assets at the transition date less amounts previously accrued under regulatory depreciation. LG&E recorded offsetting regulatory assets of $5.3 million, pursuant to regulatory treatment prescribed under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. Also pursuant to SFAS No. 71, LG&E recorded regulatory liabilities in the amount of $60,000 offsetting removal costs previously accrued under regulatory accounting in excess of amounts allowed under SFAS No. 143.
LG&E also expects to record ARO accretion expense of approximately $617,000, ARO depreciation expense of approximately $117,000 and an offsetting regulatory credit in the income statement of approximately $734,000 in 2003, pursuant to regulatory treatment prescribed under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. The accretion, depreciation and regulatory credit will be
subject to approvalannual adjustments. SFAS No. 143 will have no impact on the results of theEPA. Althoughoperation of LG&E.LG&E asset retirement obligations are primarily related to the final retirement of generating units. LG&E transmission and distribution lines largely operate under perpetual property easement agreements which do not generally require restoration upon removal of the property. Therefore, under SFAS No. 143, no material asset retirement obligations will be recorded for transmission and distribution assets.
LG&E adopted EITF No. 98-10, Accounting for Energy Trading and Risk Management Activities, effective January 1, 1999. This pronouncement required that energy trading contracts be marked to market on the balance sheet, with the gains and losses shown net in the income statement. In October 2002, the Emerging Issues Task Force reached a
final, approved plan has yetconsensus to rescind EITF 98-10. The effective date for the full rescission is for fiscal periods beginning after December 15, 2002. With the recession of EITF No. 98-10, energy trading contracts that do not also meet the definition of a derivative under SFAS No. 133 must bedeveloped, KUaccounted for as executory contracts. Contracts previously recorded at fair value under EITF No. 98-10 that are not also77
derivatives under SFAS No. 133 must be restated to historical cost through a cumulative effect adjustment. LG&E does not
believe that any liability with respectexpect the rescission of this standard tothe -24-site willhave a material impact onitsfinancial position or results of operations.PROVIDING FOR CUSTOMER GROWTH KU's forecast indicates annual growth in sales and peak demandIn January 2003, the Financial Accounting Standards Board issued Financial Accounting Standards Board Interpretation No. 46, Consolidation of
2.1% and 1.7%Variable Interest Entities,respectively, overan Interpretation of ARB No. 51 (FIN 46). FIN 46 requires certain variable interest entities to be consolidated by thenext 15 years. KU plans to provide for customer growthprimary beneficiary of the entity if the equity investors in the'90s through purchased power,entity do not have theadditioncharacteristics ofcombustion turbine peaking unitsa controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 is effective immediately for all new variable interest entities created or acquired after January 31, 2003. For variable interest entities created or acquired prior to February 1, 2003, the provisions of FIN 46 must be applied for the first interim or annual period beginning after June 15, 2003. LG&E does not expect the adoption of this standard to have any impact on the financial position or results of operations.Note 2 – Mergers and
demand-side management. There are no plansAcquisitionsOn July 1, 2002, E.ON completed its acquisition of Powergen, including LG&E Energy, for approximately £5.1 billion ($7.3 billion). As a result of the acquisition, LG&E Energy became a wholly owned subsidiary (through Powergen) of E.ON and, as a result, LG&E also became an indirect subsidiary of E.ON. LG&E has continued its separate identity and serves customers in Kentucky under its existing name. The preferred stock and debt securities of LG&E were not affected by this transaction and the utilities continue to file SEC reports. Following the acquisition, E.ON became, and Powergen remained, a registered holding company under PUHCA. LG&E, as a subsidiary of a registered holding company, is subject to additional
coal-fired baseload capacity before 2010. INFLATION KU's rates are designedregulations under PUHCA. As contemplated in their regulatory filings in connection with the E.ON acquisition, E.ON, Powergen and LG&E Energy completed an administrative reorganization torecover operatingmove the LG&E Energy group from an indirect Powergen subsidiary to an indirect E.ON subsidiary. This reorganization was effective in March 2003.LG&E Energy and
historical plant costs. Financial statements, which are preparedKU Energy merged on May 4, 1998, with LG&E Energy as the surviving corporation. Management accounted for the merger as a pooling of interests and as a tax-free reorganization under the Internal Revenue Code. Following the acquisition, LG&E has continued to maintain its separate corporate identity and serve customers inaccordanceKentucky under its present name.Note 3 - Rates and Regulatory Matters
Accounting for the regulated utility business conforms with generally accepted accounting principles
report operating resultsas applied to regulated public utilities and as prescribed by FERC and the Kentucky Commission. LG&E is subject to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, under which certain costs that would otherwise be charged to expense are deferred as regulatory assets based on expected recovery from customers intermsfuture rates. Likewise, certain credits that would otherwise be reflected as income are deferred as regulatory liabilities based on expected return to customers in future rates. LG&E’s current or expected recovery ofhistoricdeferred costs anddo not evaluate the impactexpected return ofinflation. Inflation affects KU's construction costs, operating expensesdeferred credits is generally based on specific ratemaking decisions or precedent for each item. The following regulatory assets andinterest charges. Inflation can also impact KU's financial performance if rate relief is not granted on a timely basis for increased operating costs. -25-Item 8. Financial Statements and Supplementary Data REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To Kentucky Utilities Company: We have audited the accompanyingliabilities were included in LG&E’s balance sheetsand statements of capitalization of Kentucky Utilities Company (a Kentucky and Virginia corporation)as of December 31 (in thousands of $):
2002
2001
VDT Costs
$
98,044
$
127,529
Gas supply adjustments due from customers
13,714
30,135
Unamortized loss on bonds
18,843
17,902
ESM provision
12,500
—
LGE/KU merger costs
1,815
5,444
Manufactured gas sites
1,757
2,062
One utility costs
954
3,643
Other
5,819
10,427
Total regulatory assets
153,446
197,142
Deferred income taxes - net
(45,536
)
(48,703
)
Gas supply adjustments due to customers
(3,154
)
(15,702
)
Other
(3,734
)
(944
)
Total regulatory liabilities
(52,424
)
(65,349
)
Regulatory assets – net
$
101,022
$
131,793
78
Kentucky Commission Settlement - VDT Costs. During the first quarter 2001, LG&E recorded a $144 million charge for a workforce reduction program. Primary components of the charge were separation benefits, enhanced early retirement benefits, and health care benefits. The result of this workforce reduction was the elimination of approximately 700 positions, accomplished primarily through a voluntary enhanced severance program.
On June 1, 2001, LG&E filed an application (VDT case) with the Kentucky Commission to create a regulatory asset relating to these first quarter 2001 charges. The application requested permission to amortize these costs over a four-year period. The Kentucky Commission also opened a case to review a new depreciation study and resulting depreciation rates implemented in 2001.
LG&E reached a settlement in the VDT case as well as the other cases involving depreciation rates and ESM with all intervening parties. The settlement agreement was approved by the Kentucky Commission on December 3, 2001. The order allowed LG&E to set up a regulatory asset of $141 million for the workforce reduction costs and begin amortizing these costs over a five year period starting in April 2001. The first quarter 2001 charge of $144 million represented all employees who had accepted a voluntary enhanced severance program. Some employees rescinded their participation in the voluntary enhanced severance program, thereby decreasing the original charge from $144 million to $141 million. The settlement will also reduce revenues approximately $26 million through a surcredit on future bills to customers over the same five year period. The surcredit represents net savings stipulated by LG&E. The agreement also established LG&E’s new depreciation rates in effect December 2001, retroactive to January 1, 2001. The new depreciation rates decreased depreciation expense by $5.6 million in 2001.
PUHCA. LG&E Energy was purchased by Powergen on December 11, 2000. Effective July 1, 2002, Powergen was acquired by E.ON, which became a registered holding company under PUHCA. As a result, E.ON, its utility subsidiaries, including LG&E, and certain of its non-utility subsidiaries are subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales of securities, acquisitions and sales of certain utility properties, and intra-system sales of certain goods and services. In addition, PUHCA generally limits the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company. LG&E believes that it has adequate authority (including financing authority) under existing SEC orders and regulations to conduct its business. LG&E will seek additional authorization when necessary.
Environmental Cost Recovery. In June 2000, the Kentucky Commission approved LG&E’s application for a CCN to construct up to three SCR NOx reduction facilities. The construction and subsequent operation of the SCRs is intended to reduce NOx emission levels to meet the EPA’s mandated NOx emission level of 0.15 lbs./ Mmbtu by May 2004. In its order, the Kentucky Commission ruled that LG&E’s proposed plan for construction was “reasonable, cost-effective and will not result in the wasteful duplication of facilities.” In October 2000,
79
LG&E filed an application with the Kentucky Commission to amend its Environmental Compliance Plan to reflect the addition of the proposed NOx reduction technology projects and to amend its ECR Tariff to include an overall rate of return on capital investments. Approval of LG&E’s application in April 2001 allowed LG&E to begin to recover the costs associated with these new projects, subject to Kentucky Commission oversight during normal six-month and two-year reviews.
In August 2002, LG&E filed an application with the Kentucky Commission to amend its compliance plan to allow recovery of the cost of new and additional environmental compliance facilities. The estimated capital cost of the additional facilities is $71.1 million. The Kentucky Commission conducted a public hearing on the case on December 20, 2002, final briefs were filed on January 15, 2003, and a final order was issued February 11, 2003. The final order approved recovery of four new environmental compliance facilities totaling $43.1 million. A fifth project, expansion of the land fill facility at the Mill Creek Station, was denied without prejudice with an invitation to reapply for recovery when required construction permits are approved. Cost recovery through the environmental surcharge of the four approved projects will begin with the bills rendered in April 2003.
ESM.LG&E’s electric rates are subject to an ESM. The ESM, initially in place for three years beginning in 2000, sets an upper and lower point for rate of return on equity, whereby if LG&E’s rate of return for the calendar year falls within the range of 10.5% to 12.5%, no action is necessary. If earnings are above the upper limit, the excess earnings are shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, the earnings deficiency is recovered 40% from ratepayers and 60% from shareholders. By order of the Kentucky Commission, rate changes prompted by the ESM filing go into effect in April of each year subject to a balancing adjustment in successive periods. LG&E made its second ESM filing on March 1, 2002 for the calendar year 2001 reporting period. LG&E is in the process of refunding $441,000 to customers for the 2001 reporting period. LG&E estimated that the rate of return will fall below the lower limit, subject to Kentucky Commission approval, for the year ended December 31, 2002. The 2002 financial statements include an accrual to reflect the earnings deficiency of $12.5 million to be recovered from customers commencing in April 2003.
On November 27, 2002, LG&E filed a revised ESM tariff which proposed continuance of the existing ESM through December 2005. The Kentucky Commission issued an Order suspending the ESM tariff one day making the effective date January 2, 2003. In addition, the Kentucky Commission is conducting a management audit to review the ESM plan and reassess its reasonableness in 2003. LG&E and interested parties will have the opportunity to provide recommendations for modification and continuance of the ESM or other forms of alternative or incentive regulation.
DSM. LG&E’s rates contain a DSM provision. The provision includes a rate mechanism that provides concurrent recovery of DSM costs and provides an incentive for implementing DSM programs. This program had allowed LG&E to recover revenues from lost sales associated with the DSM program. In May 2001, the Kentucky Commission approved LG&E’s plan to continue DSM programs. This filing called for the expansion of the DSM programs into the service territory served by KU and proposed a mechanism to recover revenues from lost sales associated with DSM programs based on program planning engineering estimates and post-implementation evaluation.
Gas PBR. Since November 1, 1997, LG&E has operated under an experimental PBR mechanism related to its gas procurement activities. For each of the last five years, LG&E’s rates have been adjusted to recover its portion of the savings (or expenses) incurred during each of the five 12-month periods beginning November 1 and ending October 31. Since its implementation on November 1, 1997, through October 31, 2001, LG&E has achieved $38.1 million in savings. Of the total savings, LG&E has retained $16.5 million, and the remaining portion of $21.6 million has been distributed to customers. In December 2000, LG&E filed an application reporting on the operation of the experimental PBR and requested the Kentucky Commission to extend the PBR
80
as a result of the benefits provided to both LG&E and its customers during the experimental period. Following the discovery and hearing process, the Kentucky Commission issued an order effective November 1, 2001, extending the experimental PBR program for an additional four years, and making other modifications, including changes to the sharing levels applicable to savings or expenses incurred under the PBR. Specifically, the Kentucky Commission modified the savings mechanism to a 25%/75% Company/Customer sharing for all savings (and expenses) up to 4.5% of the benchmarked gas costs. Savings (and expenses) in excess of 4.5% of the benchmarked gas costs are shared at a 50%/50% level.
FAC. Prior to implementation of the electric PBR in July 1999, and following its termination in March 2000, LG&E employed an FAC mechanism, which under Kentucky law allowed LG&E to recover from customers the actual fuel costs associated with retail electric sales. In February 1999, LG&E received orders from the Kentucky Commission requiring a refund to retail electric customers of approximately $3.9 million resulting from reviews of the FAC from November 1994, through April 1998. While legal challenges to the Kentucky Commission order were pending, a comprehensive settlement was reached by all parties and
1993,approved by the Kentucky Commission on May 17, 2002. Thereunder, LG&E agreed to credit its fuel clause in the amount of $720,000 (such credit provided over the course of June and July 2002), and the parties agreed on a prospective interpretation of the state’s FAC regulation to ensure consistent and mutually acceptable application on a going-forward basis.In December 2002, the Kentucky Commission initiated a two year review of the operation of LG&E’s FAC for the period November 2000 through October 2002. Testimony in the review case was filed on January 20, 2003 and a public hearing was held February 18, 2003. Issues addressed at that time included the establishment of the current base fuel factor to be included in LG&E’s base rates, verification of proper treatment of purchased power costs during unit outages, and compliance with fuel procurement policies and practices.
Gas Rate Case. In March 2000, LG&E filed an application with the Kentucky Commission requesting an adjustment in LG&E’s gas rates. In September 2000, the Kentucky Commission granted LG&E an annual increase in its base gas revenues of $20.2 million effective September 28, 2000. The Kentucky Commission authorized a return on equity of 11.25%. The Kentucky Commission approved LG&E’s proposal for a weather normalization billing adjustment mechanism that will normalize the effect of weather on base gas revenues from gas sales.
Wholesale Natural Gas Prices. On September 12, 2000, the Kentucky Commission issued an order establishing Administrative Case No. 384 – “An Investigation of Increasing Wholesale Natural Gas Prices and the Impacts of such Increase on the Retail Customers Served by Kentucky’s Jurisdictional Natural Gas Distribution Companies”. The impetus for this administrative proceeding was the escalation of wholesale natural gas prices during the summer of 2000.
The Kentucky Commission directed Kentucky’s natural gas distribution companies, including LG&E, to file selected information regarding the individual companies’ natural gas purchasing practices, expectations for the then-approaching winter heating season of 2000-2001, and potential actions which these companies might take to mitigate price volatility. On July 17, 2001, the Kentucky Commission issued an order encouraging the natural gas distribution companies in Kentucky to take various actions, among them to propose a natural gas hedge plan, consider performance-based ratemaking mechanisms, and to increase the use of storage.
In April 2002, in Case No. 2002-00136, LG&E proposed a hedging plan for the 2002/2003 winter heating season with three alternatives, the first two using a combination of storage and financial hedge instruments and the third relying upon storage alone. LG&E and the Attorney General, who represents Kentucky consumers, entered into a settlement which selected the third option. In August 2002, the Kentucky Commission approved the plan contemplated in the settlement. The Kentucky Commission validated the effectiveness of storage to
81
mitigate potentially high winter gas prices by approving this natural gas hedging plan.
The Kentucky Commission also decided in Administrative Case No. 384 to engage a consultant to conduct a forward-looking audit of the gas procurement and supply procedures of Kentucky’s largest natural gas distribution companies. The Kentucky Commission completed its audit in late 2002. The audit recognized LG&E as “efficient and effective [in the] procurement and management of significant quantities of natural gas supplies.” The auditors also recognized that “the Company’s residential gas prices have long been below averages for the U. S. and for the Commonwealth of Kentucky” which “demonstrates [LG&E’s] effectiveness in [the] procurement and management of natural gas supplies.” The audit also stated that the “Company’s very impressive record in keeping its rates down provides sound evidence on the excellent job done in the area of gas supply procurement and management.”
Kentucky Commission Administrative Case for Affiliate Transactions. In December 1997, the Kentucky Commission opened Administrative Case No. 369 to consider Kentucky Commission policy regarding cost allocations, affiliate transactions and codes of conduct governing the relationship between utilities and their non-utility operations and affiliates. The Kentucky Commission intended to address two major areas in the proceedings: the tools and conditions needed to prevent cost shifting and cross-subsidization between regulated and non-utility operations; and whether a code of conduct should be established to assure that non-utility segments of the holding company are not engaged in practices that could result in unfair competition caused by cost shifting from the non-utility affiliate to the utility. During the period September 1998 to February 2000, the Kentucky Commission issued draft codes of conduct and cost allocation guidelines. In early 2000, the Kentucky General Assembly enacted legislation, House Bill 897, which authorized the Kentucky Commission to require utilities that provide nonregulated activities to keep separate accounts and allocate costs in accordance with procedures established by the Kentucky Commission. In the same bill, the General Assembly set forth provisions to govern a utility’s activities related to the sharing of information, databases, and resources between its employees or an affiliate involved in the marketing or the provision of nonregulated activities and its employees or an affiliate involved in the provision of regulated services. The legislation became law in July 2000 and LG&E has been operating pursuant thereto since that time. On February 14, 2001, the Kentucky Commission published notice of its intent to promulgate new administrative regulations under the auspices of this new law. This effort is still on going.
Kentucky Commission Administrative Case for System Adequacy. On June 19, 2001, Kentucky Governor Paul E. Patton issued Executive Order 2001-771, which directed the Kentucky Commission to review and study issues relating to the need for and development of new electric generating capacity in Kentucky. The issues to be considered included the impact of new power plants on the electric supply grid, facility citing issues, and economic development matters, with the goal of ensuring a continued, reliable source of supply of electricity for the citizens of Kentucky and the continued environmental and economic vitality of Kentucky and its communities. In response to that Executive Order, in July 2001 the Kentucky Commission opened Administrative Case No. 387 to review the adequacy of Kentucky’s generation capacity and transmission system. Specifically, the items reviewed were the appropriate level of reliance on purchased power, the appropriate reserve margins to meet existing and future electric demand, the impact of spikes in natural gas prices on electric utility planning strategies, and the adequacy of Kentucky’s electric transmission facilities. LG&E, as a party to this proceeding, filed written testimony and responded to two requests for information. Public hearings were held and in October 2001, LG&E filed a final brief in the case. In December 2001, the Kentucky Commission issued an order in which it noted that LG&E is responsibly addressing the long-term supply needs of native load customers and that current reserve margins are appropriate. However, due to the rapid pace of change in the industry, the order also requires LG&E to provide an annual assessment of supply resources, future demand, reserve margin, and the need for new resources.
Regarding the transmission system, the Kentucky Commission concluded that the transmission system within
82
Kentucky can reliably serve native load and a significant portion of the proposed new unregulated power plants. However, it will not be able to handle the volume of transactions envisioned by FERC without future upgrades, the costs of which should be borne by those for whom the upgrades are required.
The Kentucky Commission pledged to continue to monitor all relevant issues and advocate Kentucky’s interests at all opportunities.
FERC SMD NOPR. On July 31, 2002, FERC issued a NOPR in Docket No. RM01-12-000 which would substantially alter the regulations governing the nation’s wholesale electricity markets by establishing a common set of rules — SMD. The SMD NOPR would require each public utility that owns, operates, or controls interstate transmission facilities to become an Independent Transmission Provider (ITP), belong to an RTO that is an ITP, or contract with an ITP for operation of its transmission assets. It would also establish a standardized congestion management system, real-time and day-ahead energy markets, and a single transmission service for network and point-to-point transmission customers. Review of the proposed rulemaking is underway and a final rule is expected during 2003. While it is expected that the SMD final rule will affect LG&E revenues and expenses, the specific impact of the rulemaking is not known at this time.
MISO. LG&E is a member of the MISO, which began commercial operations on February 1, 2002. MISO now has operational control over LG&E’s high-voltage transmission facilities (100 kV and greater), while LG&E continues to control and operate the lower voltage transmission subject to the terms and conditions of the MISO OATT. As a transmission-owning member of MISO, LG&E also incurs administrative costs of MISO pursuant to Schedule 10 of the MISO OATT.
MISO also proposed to implement a congestion management system. FERC directed the MISO to coordinate its efforts with FERC’s Rulemaking on SMD. On September 24, 2002, the MISO filed new rate schedules designated as Schedules 16 and 17, which provide for the collection of costs incurred by the MISO to establish day-ahead and real-time energy markets. The MISO proposed to recover these costs under Schedules 16 and 17 once service commences. If approved by FERC, these schedules will cause LG&E to incur additional costs. LG&E opposes the establishment of Schedules 16 and 17. This effort is still on-going and the ultimate impact of the two schedules, if approved, is not known at this time.
ARO. In 2003, LG&E expects to record approximately $6.0 million in regulatory assets and approximately $60,000 in regulatory liabilities related to SFAS No. 143, Accounting for Asset Retirement Obligations.
Merger Surcredit. As part of the LG&E Energy merger with KU Energy in 1998, LG&E Energy estimated non-fuel savings over a ten–year period following the merger. Costs to achieve these savings for LG&E of $50.2 million were recorded in the second quarter of 1998, $18.1 million of which was deferred and amortized over a five-year period pursuant to regulatory orders. Primary components of the merger costs were separation benefits, relocation costs, and transaction fees, the majority of which were paid by December 31, 1998. LG&E expensed the remaining costs associated with the merger ($32.1 million) in the second quarter of 1998.
In approving the merger, the Kentucky Commission adopted LG&E’s proposal to reduce its retail customers’ bills based on one-half of the estimated merger-related savings, net of deferred and amortized amounts, over a five-year period. The surcredit mechanism provides that 50% of the net non-fuel cost savings estimated to be achieved from the merger be provided to ratepayers through a monthly bill credit, and 50% be retained by the Companies, over a five-year period. The surcredit was allocated 53% to KU and 47% to LG&E. In that same order, the Commission required LG&E and KU, after the end of the five-year period, to present a plan for sharing with customers the then-projected non-fuel savings associated with the merger. The Companies submitted this filing on January 13, 2003, proposing to continue to share with customers, on a 50%/50% basis, the estimated fifth-year gross level of non-fuel savings associated with the merger. The filing is currently under
83
review.
Any fuel cost savings are passed to Kentucky customers through the fuel adjustment clause. See FAC above.
Note 4 - Financial Instruments
The cost and estimated fair values of LG&E’s non-trading financial instruments as of December 31, 2002, and 2001 follow (in thousands of $):
2002
2001
Cost
Fair
Value
Cost
Fair
Value
Preferred stock subject to mandatory redemption
$
25,000
$
25,188
$
25,000
$
25,125
Long-term debt (including current portion)
616,904
623,325
616,904
620,504
Interest-rate swaps
—
(17,115
)
—
(8,604
)
All of the above valuations reflect prices quoted by exchanges except for the swaps. The fair values of the swaps reflect price quotes from dealers or amounts calculated using accepted pricing models.
Interest Rate Swaps. LG&E uses interest rate swaps to hedge exposure to market fluctuations in certain of its debt instruments. Pursuant to policy, use of these financial instruments is intended to mitigate risk and earnings volatility and is not speculative in nature. Management has designated all of the interest rate swaps as hedge instruments. Financial instruments designated as cash flow hedges have resulting gains and losses recorded within other comprehensive income and stockholders’ equity. To the extent a financial instrument or the underlying item being hedged is prematurely terminated or the hedge becomes ineffective, the resulting gains or losses are reclassified from other comprehensive income to net income. Financial instruments designated as fair value hedges are periodically marked to market with the resulting gains and losses recorded directly into net income to correspond with income or expense recognized from changes in market value of the items being hedged.
As of December 31, 2002 and 2001, LG&E was party to various interest rate swap agreements with aggregate notional amounts of $117.3 million. Under these swap agreements, LG&E paid fixed rates averaging 5.13% and received variable rates based on the Bond Market Association’s municipal swap index averaging 1.52% and 1.61% at December 31, 2002 and 2001, respectively. The swap agreements in effect at December 31, 2002 have been designated as cash flow hedges and mature on dates ranging from 2003 to 2020. The hedges have been deemed to be fully effective resulting in a pretax loss of $8.5 million for 2002, recorded in other comprehensive income. Upon expiration of these hedges, the amount recorded in other comprehensive income will be reclassified into earnings. The amounts expected to be reclassified from other comprehensive income to earnings in the next twelve months is immaterial.
Energy Trading & Risk Management Activities. LG&E conducts energy trading and risk management activities to maximize the value of power sales from physical assets it owns, in addition to the wholesale sale of excess asset capacity. Certain energy trading activities are accounted for on a mark-to-market basis in accordance with EITF 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities. Wholesale sales of excess asset capacity and wholesale purchases are treated as normal sales and purchases under SFAS No. 133 and SFAS No. 138 and are not marked-to-market.
84
The rescission of EITF 98-10, effective for fiscal years after December 15, 2002, will have no impact on LG&E’s energy trading and risk management reporting as all contracts marked to market under EITF 98-10 are also within the scope of SFAS No. 133.
The table below summarizes LG&E’s energy trading and risk management activities for 2002 and 2001 (in thousands of $).
2002
2001
Fair value of contracts at beginning of period, net liability
$
(186
)
$
(17
)
Fair value of contracts when entered into during the period
(65
)
3,441
Contracts realized or otherwise settled during the period
448
(2,894
)
Changes in fair values due to changes in assumptions
(353
)
(716
)
Fair value of contracts at end of period, net liability
$
(156
)
$
(186
)
No changes to valuation techniques for energy trading and risk management activities occurred during 2002. Changes in market pricing, interest rate and volatility assumptions were made during both years. All contracts outstanding at December 31, 2002, have a maturity of less than one year and are valued using prices actively quoted for proposed or executed transactions or quoted by brokers.
LG&E maintains policies intended to minimize credit risk and revalues credit exposures daily to monitor compliance with those policies. At December 31, 2002, 86% of the trading and risk management commitments were with counterparties rated BBB- equivalent or better.
Note 5 - Concentrations of Credit and Other Risk
Credit risk represents the accounting loss that would be recognized at the reporting date if counterparties failed to perform as contracted. Concentrations of credit risk (whether on- or off-balance sheet) relate to groups of customers or counterparties that have similar economic or industry characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in economic or other conditions.
LG&E’s customer receivables and gas and electric revenues arise from deliveries of natural gas to approximately 310,000 customers and electricity to approximately 382,000 customers in Louisville and adjacent areas in Kentucky. For the year ended December 31, 2002, 74% of total revenue was derived from electric operations and 26% from gas operations.
In November 2001, LG&E and IBEW Local 2100 employees, which represent approximately 70% of LG&E’s workforce, entered into a four-year collective bargaining agreement.
85
Note 6 - Pension Plans and Retirement Benefits
LG&E sponsors several qualified and non-qualified pension plans and other postretirement benefit plans for its employees. The following tables provide a reconciliation of the changes in the plans’ benefit obligations and fair value of assets over the three-year period ending December 31, 2002, and a statement of the funded status as of December 31 for each of the last three years (in thousands of $):
2002
2001
2000
Pension Plans:
Change in benefit obligation
Benefit obligation at beginning of year
$
356,293
$
310,822
$
283,267
Service cost
1,484
1,311
3,408
Interest cost
24,512
25,361
22,698
Plan amendments
576
1,550
17,042
Curtailment loss
—
24,563
—
Special termination benefits
—
53,610
—
Benefits paid
(34,823
)
(53,292
)
(16,656
)
Actuarial (gain) or loss and other
16,752
(7,632
)
1,063
Benefit obligation at end of year
$
364,794
$
356,293
$
310,822
Change in plan assets
Fair value of plan assets at beginning of year
$
233,944
$
333,378
$
360,095
Actual return on plan assets
(15,648
)
(27,589
)
(6,150
)
Employer contributions and plan transfers
14,150
(17,134
)
(1,804
)
Benefits paid
(34,824
)
(53,292
)
(16,656
)
Administrative expenses
(1,308
)
(1,419
)
(2,107
)
Fair value of plan assets at end of year
$
196,314
$
233,944
$
333,378
Reconciliation of funded status
Funded status
$
(168,480
)
$
(122,349
)
$
22,556
Unrecognized actuarial (gain) or loss
60,313
18,800
(74,086
)
Unrecognized transition (asset) or obligation
(3,199
)
(4,215
)
(5,853
)
Unrecognized prior service cost
32,265
35,435
47,984
Net amount recognized at end of year
$
(79,101
)
$
(72,329
)
$
(9,399
)
Other Benefits:
Change in benefit obligation
Benefit obligation at beginning of year
$
89,946
$
56,981
$
44,997
Service cost
444
358
822
Interest cost
5,956
5,865
4,225
Plan amendments
—
1,487
5,826
Curtailment loss
—
8,645
—
Special termination benefits
—
18,089
—
Benefits paid
(4,988
)
(4,877
)
(4,889
)
Actuarial (gain) or loss
1,875
3,398
6,000
Benefit obligation at end of year
$
93,233
$
89,946
$
56,981
Change in plan assets
Fair value of plan assets at beginning of year
$
2,802
$
7,166
$
10,526
Actual return on plan assets
(533
)
(765
)
(92
)
Employer contributions and plan transfers
4,213
1,282
1,621
Benefits paid
(5,004
)
(4,881
)
(4,889
)
Fair value of plan assets at end of year
$
1,478
$
2,802
$
7,166
Reconciliation of funded status
Funded status
$
(91,755
)
$
(87,144
)
$
(49,815
)
Unrecognized actuarial (gain) or loss
16,971
15,947
5,623
Unrecognized transition (asset) or obligation
6,697
7,346
13,374
Unrecognized prior service cost
5,995
5,302
8,960
Net amount recognized at end of year
$
(62,092
)
$
(58,549
)
$
(21,858
)
86
There are no plan assets in the nonqualified plans due to the nature of the plans.
LG&E made a contribution to the pension plan of $83.1 million in January 2003.
The following tables provide the amounts recognized in the balance sheet and information for plans with benefit obligations in excess of plan assets as of December 31, 2002, 2001 and 2000 (in thousands of $):
2002
2001
2000
Pension Plans:
Amounts recognized in the balance sheet consisted of:
Prepaid benefits cost
$
—
$
—
$
18,880
Accrued benefit liability
(162,611
)
(108,977
)
(28,279
)
Intangible asset
32,799
11,936
—
Accumulated other comprehensive income
50,711
24,712
—
Net amount recognized at year-end
$
(79,101
)
$
(72,329
)
$
(9,399
)
Additional year-end information for plans with accumulated benefit obligations in excess of plan assets (1):
Projected benefit obligation
$
364,794
$
356,293
$
4,088
Accumulated benefit obligation
358,956
352,477
3,501
Fair value of plan assets
196,314
233,944
—
(1) 2002 and 2001 includes all plans. 2000 includes SERPs only.
Other Benefits:
Amounts recognized in the balance sheet consisted of:
Accrued benefit liability
$
(62,092
)
$
(58,549
)
$
(21,858
)
Additional year-end information for plans with benefit obligations in excess of plan assets:
Projected benefit obligation
$
93,233
$
89,946
$
56,981
Fair value of plan assets
1,478
2,802
7,166
87
The following table provides the components of net periodic benefit cost for the plans for 2002, 2001 and 2000 (in thousands of $):
2002
2001
2000
Pension Plans:
Components of net periodic benefit cost
Service cost
$
1,484
$
1,311
$
3,408
Interest cost
24,512
25,361
22,698
Expected return on plan assets
(21,639
)
(26,360
)
(33,025
)
Amortization of prior service cost
3,777
3,861
4,646
Amortization of transition (asset) or obligation
(1,016
)
(1,000
)
(1,112
)
Recognized actuarial (gain) or loss
21
(777
)
(6,856
)
Net periodic benefit cost
$
7,139
$
2,396
$
(10,241
)
Special charges
Prior service cost recognized
$
—
$
10,237
$
—
Special termination benefits
—
53,610
—
Settlement loss
—
(2,244
)
—
Total charges
$
—
$
61,603
$
—
Other Benefits:
Components of net periodic benefit cost
Service cost
$
444
$
358
$
822
Interest cost
5,956
5,865
4,225
Expected return on plan assets
(204
)
(420
)
(683
)
Amortization of prior service cost
920
951
1,158
Amortization of transition (asset) or obligation
650
719
1,114
Recognized actuarial (gain) or loss
116
(32
)
(485
)
Net periodic benefit cost
$
7,882
$
7,441
$
6,151
Special charges
Curtailment loss
$
—
$
6,671
$
—
Prior service cost recognized
—
2,391
—
Transition obligation recognized
—
4,743
—
Special termination benefits
—
18,089
—
Total charges
$
—
$
31,894
$
—
The assumptions used in the measurement of LG&E’s pension benefit obligation are shown in the following table:
2002
2001
2000
Weighted-average assumptions as of December 31:
Discount rate
6.75
%
7.25
%
7.75
%
Expected long-term rate of return on plan assets
9.00
%
9.50
%
9.50
%
Rate of compensation increase
3.75
%
4.25
%
4.75
%
For measurement purposes, a 12.00% annual increase in the per capita cost of covered health care benefits was assumed for 2003. The rate was assumed to decrease gradually to 5.00% for 2014 and remain at that level thereafter.
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A 1% change in assumed health care cost trend rates would have the following effects (in thousands of $):
88
1% Decrease
1% Increase
Effect on total of service and interest cost components for 2002
(201
)
227
Effect on year-end 2002 postretirement benefit obligations
(3,001
)
3,347
Thrift Savings Plans.LG&E has a thrift savings plan under section 401(k) of the Internal Revenue Code. Under the plan, eligible employees may defer and contribute to the plan a portion of current compensation in order to provide future retirement benefits. LG&E makes contributions to the plan by matching a portion of the employee contributions. The costs of this matching were approximately $1.7 million for 2002, $1.2 million for 2001 and $2.7 million for 2000.
Note 7 - Income Taxes
Components of income tax expense are shown in the table below (in thousands of $):
2002
2001
2000
Included in operating expenses:
Current - federal
$
26,231
$
42,997
$
32,612
- state
8,083
8,668
5,018
Deferred - federal – net
20,464
12,310
24,272
- state – net
4,410
3,767
6,797
Amortization of investment tax credit
(4,153
)
(4,290
)
(4,274
)
Total
55,035
63,452
64,425
Included in other income - net:
Current - federal
(1,667
)
(1,870
)
(2,187
)
- state
(430
)
(483
)
(568
)
Deferred - federal – net
(206
)
285
(39
)
- state – net
(53
)
73
(10
)
Total
(2,356
)
(1,995
)
(2,804
)
Total income tax expense
$
52,679
$
61,457
$
61,621
Components of net deferred tax liabilities included in the balance sheet are shown below (in thousands of $):
2002
2001
Deferred tax liabilities:
Depreciation and other plant-related items
$
346,737
$
334,914
Other liabilities
64,734
77,611
411,471
412,525
Deferred tax assets:
Investment tax credit
22,012
23,713
Income taxes due to customers
18,431
19,709
Pensions
21,056
6,621
Accrued liabilities not currently deductible and other
36,747
64,339
98,246
114,382
Net deferred income tax liability
$
313,225
$
298,143
A reconciliation of differences between the statutory U.S. federal income tax rate and LG&E’s effective income
89
tax rate follows:
2002
2001
2000
Statutory federal income tax rate
35.0
%
35.0
%
35.0
%
State income taxes, net of federal benefit
5.6
4.7
4.3
Amortization of investment tax credit
(2.9
)
(2.6
)
(2.6
)
Other differences – net
(0.5
)
(0.6
)
(0.9
)
Effective income tax rate
37.2
%
36.5
%
35.8
%
Note 8 - Other Income - net
Other income – net consisted of the following at December 31 (in thousands of $):
2002
2001
2000
Interest and dividend income
$
457
$
748
$
3,103
Gains on fixed asset disposals
421
1,217
1,014
Income taxes and other
(58
)
965
804
Other income – net
$
820
$
2,930
$
4,921
Note 9 - First Mortgage Bonds and Pollution Control Bonds
Long-term debt and the current portion of long-term debt, summarized below (in thousands of $), consists primarily of first mortgage bonds and pollution control bonds. Interest rates and maturities in the table below are for the amounts outstanding at December 31, 2002.
Stated
Interest Rates
Weighted
Average
Interest
Rate
Maturities
Principal
Amounts
Noncurrent portion
Variable - 5.90
%
3.53
%
2019-2032
$
328,104
Current portion
Variable - 6.00
%
2.08
%
2003-2027
288,800
Under the provisions for some of LG&E’s variable-rate pollution control bonds, the bonds are subject to tender for purchase at the option of the holder and to mandatory tender for purchase upon the occurrence of certain events, causing the bonds to be classified as current portion of long-term debt in the consolidated balance sheets. The average annualized interest rate for these bonds during 2002 was 1.61%.
LG&E’s First Mortgage Bond, 6% Series of $42.6 million is scheduled to mature in 2003. There are no other scheduled maturities of pollution control bonds for the five years subsequent to December 31,2002.
In October 2002, LG&E issued $41.7 million variable rate pollution bonds due October 1, 2032, and exercised its call option on $41.7 million, 6.55% pollution control bonds due November 1, 2020.
In March 2002, LG&E refinanced four unsecured pollution control bonds with an aggregate principal balance of $120 million and replaced them with secured pollution control bonds. The new bonds and the previous bonds were all variable rate bonds, and the maturity dates remained unchanged.
In September 2001, LG&E issued $10.1 million variable rate tax-exempt environmental facility revenue bonds due September 1, 2027.
90
In January 2000, LG&E exercised its call option on its $20 million 7.50% First Mortgage Bonds due July 1, 2002. The bonds were redeemed utilizing proceeds from issuance of commercial paper.
In May 2000, LG&E issued $25 million variable rate pollution control bonds due May 1, 2027 and exercised its call option on $25 million, 7.45%, pollution control bonds due June 15, 2015. In August 2000, LG&E issued $83 million in variable rate pollution control bonds due August 1, 2030 and exercised its call option on its $83 million, 7.625%, pollution control bonds due November 1, 2020.
Annual requirements for the sinking funds of LG&E’s First Mortgage Bonds (other than the First Mortgage Bonds issued in connection with certain Pollution Control Bonds) are the amounts necessary to redeem 1% of the highest principal amount of each series of bonds at any time outstanding. Property additions (166 2/3% of principal amounts of bonds otherwise required to be so redeemed) have been applied in lieu of cash.
Substantially all of LG&E’s utility plants are pledged as security for its first mortgage bonds. LG&E’s indenture, as supplemented, provides that portions of retained earnings will not be available for the payment of dividends on common stock, under certain specified conditions. No portion of retained earnings is restricted by this provision as of December 31, 2002.
Note 10 - Notes Payable
LG&E participates in an intercompany money pool agreement wherein LG&E Energy can make funds available to LG&E at market based rates up to $400 million. The balance of the money pool loan from LG&E Energy was $193.1 million at a rate of 1.61% and $64.2 million at an average rate of 2.37%, at December 31, 2002 and 2001, respectively. LG&E also had outstanding commercial paper of $30 million at an average rate of 2.54% at December 31, 2001. The remaining money pool availability at December 31, 2002, was $206.9 million. LG&E Energy maintains facilities of $450 million with affiliates to ensure funding availability for the money pool. The outstanding balance under these facilities as of December 31, 2002 was $230 million, and availability of $220 million remained.
Note 11 - - Commitments and Contingencies
Construction Program.LG&E had approximately $15.1 million of commitments in connection with its construction program at December 31, 2002. Construction expenditures for the years 2003 and 2004 are estimated to total approximately $340.0 million, although all of this amount is not currently committed, including the purchase of four jointly owned CTs, $89.0 million, and construction of NOx equipment, $34.0 million.
Operating Lease.LG&E leases office space and accounts for its office space lease as an operating lease. Total lease expense for 2002, 2001, and 2000, less amounts contributed by the parent company, was $1.6 million, $1.1 million, and $0.9 million, respectively. The future minimum annual lease payments under this lease agreement for years subsequent to December 31, 2002, are as follows (in thousands of $):
2003
$
3,371
2004
3,399
2005
3,467
2006
3,536
2007
3,607
Thereafter
29,794
Total
$
47,174
91
In December 1999, LG&E and KU entered into an 18-year cross-border lease of its two jointly owned combustion turbines recently installed at KU’s Brown facility (Units 6 and 7). LG&E’s obligation was defeased upon consummation of the cross-border lease. The transaction produced a pre-tax gain of approximately $1.2 million which was recorded in other income on the income statement in 2000, pursuant to a Kentucky Commission order.
Environmental. The Clean Air Act imposed stringent new SO2 and NOx emission limits on electric generating units. LG&E previously had installed scrubbers on all of its generating units. LG&E’s strategy for Phase II SO2 reductions, which commenced January 1, 2000, is to increase scrubber removal efficiency to delay additional capital expenditures and may also include fuel switching or upgrading scrubbers. LG&E met the NOx emission requirements of the Act through installation of low-NOx burner systems. LG&E’s compliance plans are subject to many factors including developments in the emission allowance and fuel markets, future regulatory and legislative initiatives, and advances in clean air control technology. LG&E will continue to monitor these developments to ensure that its environmental obligations are met in the most efficient and cost-effective manner.
In September 1998, the EPA announced its final “NOx SIP Call” rule requiring states to impose significant additional reductions in NOx emissions by May 2003, in order to mitigate alleged ozone transport impacts on the Northeast region. The Commonwealth of Kentucky is currently in the process of revising its SIP to require reductions in NOx emissions from coal-fired generating units to the 0.15 lb./Mmbtu level on a system-wide basis. In related proceedings in response to petitions filed by various Northeast states, in December 1999, EPA issued a final rule pursuant to Section 126 of the Clean Air Act directing similar NOx reductions from a number of specifically targeted generating units including all LG&E units. As a result of appeals to both rules, the compliance date was extended to May 2004. All LG&E generating units are subject to the May 2004 compliance date under these NOx emissions reduction rules.
LG&E is currently implementing a plan for adding significant additional NOx controls to its generating units. Installation of additional NOx controls will proceed on a phased basis, with installation of controls commencing in late 2000 and continuing through the final compliance date. In addition, LG&E will incur additional operation and maintenance costs in operating new NOx controls. LG&E believes its costs in this regard to be comparable to those of similarly situated utilities with like generation assets. LG&E had anticipated that such capital and operating costs are the type of costs that are eligible for recovery from customers under its environmental surcharge mechanism and believed that a significant portion of such costs could be recovered. In April 2001, the Kentucky Commission granted recovery of these costs for LG&E.
LG&E is also monitoring several other air quality issues which may potentially impact coal-fired power plants, including the appeal of the D.C. Circuit’s remand of the EPA’s revised air quality standards for ozone and particulate matter, measures to implement EPA’s regional haze rule, and EPA’s December 2000 determination to regulate mercury emissions from power plants. In addition, LG&E is currently working with local regulatory authorities to review the effectiveness of remedial measures aimed at controlling particulate matter emissions from its Mill Creek Station. LG&E previously settled a number of property damage claims from adjacent residents and completed significant remedial measures as part of its ongoing capital construction program. LG&E is in the process of converting the Mill Creek Station to wet stack operation in an effort to resolve all outstanding issues related to particulate matter emissions.
LG&E owns or formerly owned three properties which are the location of past MGP operations. Various contaminants are typically found at such former MGP sites and environmental remediation measures are frequently required. With respect to the sites, LG&E has completed cleanups, obtained regulatory approval of site management plans, or reached agreements for other parties to assume responsibility for cleanup. Based on
92
currently available information, management estimates that it will incur additional costs of $400,000. Accordingly, an accrual of $400,000 has been recorded in the accompanying financial statements at December 31, 2002 and 2001.
Purchased Power. LG&E has a contract for purchased power with OVEC for various Mw capacities. The estimated future minimum annual payments under purchased power agreements for the years subsequent to December 31, 2002, are as follows (in thousands of $):
2003
$
10,773
2004
10,116
2005
10,152
2006
10,816
2007
10,816
Thereafter
184,544
Total
$
237,217
Note 12 - - Jointly Owned Electric Utility Plant
LG&E owns a 75% undivided interest in Trimble County Unit 1 which the Kentucky Commission has allowed to be reflected in customer rates.
Of the remaining 25% of the Unit, IMEA owns a 12.12% undivided interest, and IMPA owns a 12.88% undivided interest. Each company is responsible for its proportionate ownership share of fuel cost, operation and maintenance expenses, and incremental assets.
The following data represent shares of the jointly owned property:
Trimble County
LG&E
IMPA
IMEA
Total
Ownership interest
75
%
12.88
%
12.12
%
100
%
Mw capacity
386.2
66.4
62.4
515.0
LG&E’s 75% ownership (in thousands of $):
Cost
$
595,747
Accumulated depreciation
182,711
Net book value
$
413,036
Construction work in progress
(included above)
$
12,867
93
LG&E and KU jointly own the following combustion turbines (in thousands of $):
LG&E
KU
Total
Paddy’s Run 13
Ownership %
53
%
47
%
100
%
Mw capacity
84
74
158
Cost
$
33,919
$
29,973
$
63,892
Depreciation
1,711
1,499
3,210
Net book value
$
32,208
$
28,474
$
60,682
E.W. Brown 5
Ownership %
53
%
47
%
100
%
Mw capacity
71
63
134
Cost
$
23,973
$
21,106
$
45,079
Depreciation
1,206
1,052
2,258
Net book value
$
22,767
$
20,054
$
42,821
E.W. Brown 6
Ownership %
38
%
62
%
100
%
Mw capacity
59
95
154
Cost
$
23,696
$
36,957
$
60,653
Depreciation
1,770
4,201
5,971
Net book value
$
21,926
$
32,756
$
54,682
E.W. Brown 7
Ownership %
38
%
62
%
100
%
Mw capacity
59
95
154
Cost
$
23,607
$
44,792
$
68,399
Depreciation
4,054
4,502
8,556
Net book value
$
19,553
$
40,290
$
59,843
Trimble 5
Ownership %
29
%
71
%
100
%
Mw capacity
45
110
155
Cost
$
15,970
$
39,045
$
55,015
Depreciation
251
614
865
Net book value
$
15,719
$
38,431
$
54,150
Trimble 6
Ownership %
29
%
71
%
100
%
Mw capacity
45
110
155
Cost
$
15,961
$
39,025
$
54,986
Depreciation
251
614
865
Net book value
$
15,710
$
38,411
$
54,121
Trimble CT Pipeline
Ownership %
29
%
71
%
100
%
Cost
$
1,835
$
4,475
$
6,310
Depreciation
39
96
135
Net book value
$
1,796
$
4,379
$
6,175
See also Note 11, Construction Program, for LG&E’s planned purchase of four jointly owned CTs in 2004.
Note 13 - - Segments of Business and Related Information
Effective December 31, 1998, LG&E adopted SFAS No. 131, Disclosure About Segments of an Enterprise and Related Information. LG&E is a regulated public utility engaged in the generation, transmission, distribution, and sale of electricity and the storage, distribution, and sale of natural gas. Financial data for business segments, follow (in thousands of $):
94
Electric
Gas
Total
2002
Operating revenues
$
758,491
(a)
$
267,693
$
1,026,184
Depreciation and amortization
90,248
15,658
105,906
Interest income
381
76
457
Interest expense
24,837
4,968
29,805
Operating income taxes
49,010
6,025
55,035
Net income
79,246
9,683
88,929
Total assets
2,105,956
455,122
2,561,078
Construction expenditures
195,662
24,754
220,416
2001
Operating revenues
$
705,925
(b)
$
290,775
$
996,700
Depreciation and amortization
85,572
14,784
100,356
Interest income
616
132
748
Interest expense
31,295
6,627
37,922
Operating income taxes
55,527
7,925
63,452
Net income
95,103
11,768
106,781
Total assets
1,985,252
463,102
2,448,354
Construction expenditures
227,107
25,851
252,958
2000
Operating revenues
$
710,958
(c)
$
272,489
$
983,447
Depreciation and amortization
84,761
13,530
98,291
Interest income
2,551
552
3,103
Interest expense
35,604
7,614
43,218
Operating income taxes
57,869
6,556
64,425
Net income
100,395
10,178
110,573
Total assets
1,760,305
465,779
2,226,084
Construction expenditures
109,798
34,418
144,216
(a) Net of provision for rate collections of $12.3 million.
(b) Net of provision for rate refunds of $.7 million.
(c) Net of provision for rate refunds of $2.5 million.
95
Note 14 - - Selected Quarterly Data (Unaudited)
Selected financial data for the four quarters of 2002 and 2001 are shown below. Because of seasonal fluctuations in temperature and other factors, results for quarters may fluctuate throughout the year.
Quarters Ended
March
June
September
December
(Thousands of $)
2002
Operating revenues
$
283,365
$
222,751
$
245,817
$
274,251
Net operating income
28,748
22,410
41,652
25,104
Net income
20,943
15,256
34,204
18,526
Net income available for common stock
19,878
14,207
33,129
17,469
2001
Operating revenues
$
313,271
$
228,841
$
231,885
$
222,703
Net operating income (loss)(a)
(43,732
)
37,624
49,092
98,789
Net income (loss)(a)
(54,115
)
28,467
40,270
92,159
Net income (loss) available for common stock(a)
(55,413
)
27,247
39,160
91,048
(a) Loss resulted from the VDT pre-tax charge of $144.0 million in March 2001, which was reversed in December 2001. See Note 3.
Note 15 - - Subsequent Events
LG&E made a contribution to the pension plan of $83.1 million in January 2003.
On March 18, 2003, the Kentucky Commission approved LG&E and KU's joint application for the acquisition of four CTs from an unregulated affiliate, LG&E Capital Corp. The total projected construction cost for the turbines, expected to be available for June 2004 in-service, is $227.4 million. The requested ownership share of the turbines is 63% for KU and 37% for LG&E.
96
Louisville Gas and Electric Company
REPORT OF MANAGEMENTThe management of Louisville Gas and Electric Company is responsible for the preparation and integrity of the financial statements and related information included in this Annual Report. These statements have been prepared in accordance with accounting principles generally accepted in the United States applied on a consistent basis and, necessarily, include amounts that reflect the best estimates and judgment of management.
LG&E’s 2002 and 2001 financial statements have been audited by PricewaterhouseCoopers LLP, independent accountants, and the 2000 financial statements were audited by Arthur Andersen LLP. Management made available to PricewaterhouseCoopers LLP and Arthur Andersen LLP (in prior years) all LG&E’s financial records and related data as well as the minutes of shareholders’ and directors’ meetings.
Management has established and maintains a system of internal controls that provides reasonable assurance that transactions are completed in accordance with management’s authorization, that assets are safeguarded and that financial statements are prepared in conformity with generally accepted accounting principles. Management believes that an adequate system of internal controls is maintained through the selection and training of personnel, appropriate division of responsibility, establishment and communication of policies and procedures and by regular reviews of internal accounting controls by LG&E’s internal auditors. Management reviews and modifies its system of internal controls in light of changes in conditions and operations, as well as in response to recommendations from the internal and external auditors. These recommendations for the year ended December 31, 2002, did not identify any material weaknesses in the design and operation of LG&E’s internal control structure.
In carrying out its oversight role for the financial reporting and internal controls of LG&E, the Board of Directors meets regularly with LG&E’s independent public accountants, internal auditors and management. The Board of Directors reviews the results of the independent accountants’ audit of the financial statements and their audit procedures, and discusses the adequacy of internal accounting controls. The Board of Directors also approves the annual internal auditing program and reviews the activities and results of the internal auditing function. Both the independent public accountants and the internal auditors have access to the Board of Directors at any time.
Louisville Gas and Electric Company maintains and internally communicates a written code of business conduct that addresses, among other items, potential conflicts of interest, compliance with laws, including those relating to financial disclosure, and the confidentiality of proprietary information.
S. Bradford Rives
Senior Vice President-Finance and Controller
Louisville Gas and Electric Company
Louisville, Kentucky
97
Louisville Gas and Electric Company and Subsidiary
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders of Louisville Gas and Electric Company and Subsidiary:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of capitalization, income,
andretained earnings, cash flows and comprehensive income present fairly, in all material respects, the financial position of Louisville Gas and Electric Company and Subsidiary (the “Company”), a wholly-owned subsidiary of LG&E Energy Corp., at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of thethreetwo years in the period ended December 31,1994.2002, in conformity with accounting principles generally accepted in the United States of America. These financial statementsand the schedule referred to beloware the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
January 21, 2003
Louisville, Kentucky98
Louisville Gas and Electric Company
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTSTo the Shareholders of Louisville Gas and Electric Company:
We have audited the accompanying balance sheet and statement of capitalization of Louisville Gas and Electric Company (a Kentucky
Utilities'corporation and a wholly-owned subsidiary of LG&E Energy Corp.) as of December 31, 2000, and the related statements of income, retained earnings, cash flows and comprehensive income for each of the two years in the period ended December 31, 2000. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statementsand schedulebased on our audits.We conducted our audits in accordance with auditing standards generally accepted
auditing standards.in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of
Kentucky UtilitiesLouisville Gas and Electric Company as of December 31,1994 and 1993,2000, and the results of its operations and its cash flows for each of thethreetwo years in the period ended December 31,1994,2000, in conformity with accounting principles generally acceptedaccounting principles. As explainedinNotes 2 and 3 tothefinancial statements, effective January 1, 1993, Kentucky Utilities Company changed its method of accounting for income taxes and postretirement benefits other than pensions.United States.Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed
inunder Item14(A)(2)14(a)2 is presented for purposes of complying with the Securities and ExchangeCommission'sCommission’s rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in theauditsaudit of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole./s/
Louisville, Kentucky
January 26, 2001Arthur Andersen LLP
THIS IS A COPY OF A PREVIOUSLY ISSUED REPORT OF ARTHUR ANDERSEN LLP
Arthur Andersen LLP Chicago, Illinois January 30, 1995 -26-(“ANDERSEN”) RELATING TO A PRIOR PERIOD FOR WHICH ANDERSEN WAS ENGAGED AS INDEPENDENT PUBLIC ACCOUNTANTS. THE REPORT HAS NOT BEEN REISSUED BY ANDERSEN. 99
INDEX OF ABBREVIATIONS
StatementsCapital Corp.
LG&E Capital Corp.
Clean Air Act
The Clean Air Act, as amended in 1990
CCN
Certificate of
IncomePublic Convenience andRetainedNecessityCT
Combustion Turbines
DSM
Demand Side Management
ECR
Environmental Cost Recovery
EEI
Electric Energy, Inc.
EITF
Emerging Issues Task Force Issue
E.ON
E.ON AG
EPA
U.S. Environmental Protection Agency
ESM
Earnings Sharing Mechanism
F
Fahrenheit
FAC
Fuel Adjustment Clause
FERC
Federal Energy Regulatory Commission
FPA
Federal Power Act
FT and FT-A
Firm Transportation
GSC
Gas Supply Clause
IBEW
International Brotherhood of Electrical Workers
IMEA
Illinois Municipal Electric Agency
IMPA
Indiana Municipal Power Agency
Kentucky Commission
Kentucky Public Service Commission
KIUC
Kentucky Industrial Utility Consumers, Inc.
KU
Kentucky Utilities Company
Year Ended December 31, (in thousandsKU Energy
KU Energy Corporation
KU R
KU Receivables LLC
kV
Kilovolts
Kva
Kilovolt-ampere
KW
Kilowatts
Kwh
Kilowatt hours
LEM
LG&E Energy Marketing Inc.
LG&E
Louisville Gas and Electric Company
LG&E Energy
LG&E Energy Corp.
LG&E R
LG&E Receivables LLC
LG&E Services
LG&E Energy Services Inc.
Mcf
Thousand Cubic Feet
MGP
Manufactured Gas Plant
MISO
Midwest Independent System Operator
Mmbtu
Million British thermal units
Moody’s
Moody’s Investor Services, Inc.
Mw
Megawatts
Mwh
Megawatt hours
NNS
No-Notice Service
NOPR
Notice of
dollars) 1994 1993 1992Operating Revenues (See Note 1) $ 636,652 $ 606,588 $ 575,821 Operating Expenses: Fuel, principally coal, used in generation (See Note 1) 170,654 178,910 168,470Proposed RulemakingNOx
Nitrogen Oxide
OATT
Open Access Transmission Tariff
OMU
Owensboro Municipal Utilities
OVEC
Ohio Valley Electric
power purchased 61,442 34,711 32,753 Other operating expenses 112,712 104,930 93,915 Maintenance 66,134 59,451 61,118 Depreciation 65,259 60,800 58,849 FederalCorporationPBR
Performance-Based Ratemaking
PJM
Pennsylvania, New Jersey, Maryland Interconnection
Powergen
Powergen Limited (formerly Powergen plc)
PUHCA
Public Utility Holding Company Act of 1935
ROE
Return on Equity
RTO
Regional Transmission Organization
S&P
Standard & Poor’s Rating Services
SCR
Selective Catalytic Reduction
SEC
Securities and
state income taxes 44,683 48,178 41,489 Other taxes 14,582 14,347 13,359 Total Operating Expenses 535,466 501,327 469,953 Net Operating Income 101,186 105,261 105,868 Other IncomeExchange Commission100
SERP
Supplemental Employee Retirement Plan
SFAS
Statement of Financial Accounting Standards
SIP
State Implementation Plan
SMD
Standard Market Design
SO2
Sulfur Dioxide
Tennessee Gas
Tennessee Gas Pipeline Company
Texas Gas
Texas Gas Transmission Corporation
TRA
Tennessee Regulatory Authority
Trimble County
LG&E’s Trimble County Unit 1
USWA
United Steelworkers of America
Utility Operations
Operations of LG&E and
Deductions: Interest and dividend income 4,295 2,813 6,611 Other income and deductions - net 6,098 5,926 4,734 Total Other Income and Deductions 10,393 8,739 11,345 Income Before Interest Charges 111,579 114,000 117,213 Interest Charges: Interest on long-term debt 32,147 31,650 39,571 Other interest charges 1,920 1,064 1,344 Total Interest Charges 34,067 32,714 40,915 Net Income 77,512 81,286 76,298 Preferred Stock Dividend Requirements 2,384 2,558 2,518 Net Income Applicable to Common Stock $ 75,128 $ 78,728 $ 73,780 Retained Earnings Beginning of Year $ 244,429 $ 226,210 $ 261,426 Add Net Income 77,512 81,286 76,298 321,941 307,496 337,724 Deduct: Dividends on preferred stock 2,384 2,558 2,518 Dividends on common stock 61,644 60,509 108,996 Preferred stock redemption expense 257 - - 64,285 63,067 111,514 Retained Earnings End of Year $ 257,656 $ 244,429 $ 226,210 The accompanying Notes to Financial Statements are an integral part of these statements.KUVDT
Value Delivery Team Process
Virginia Commission
Virginia State Corporation Commission
Virginia Staff
Virginia State Corporation Commission Staff
-27-
Statements of Cash Flows Kentucky Utilities CompanyYear Ended December 31, (in thousands of dollars) 1994 1993 1992 Cash Flows from Operating Activities:Net income $ 77,512 $ 81,286 $ 76,298 Items not requiring (providing) cash currently: Depreciation 65,259 60,800 58,849 Deferred income taxes (1,559) 5,725 3,974 Investment tax credit deferred (4,110) (4,131) (4,149) Changes in current assets and liabilities: Change in fuel inventory (4,579) 7,694 (642) Change in accounts receivable (203) (9,331) 7,338 Change in accounts payable 5,511 22,768 (1,819) Change in liability to ratepayers (29,958) 36,867 - Change in escrow funds 30,841 (37,752) - Other - net 2,555 724 (4,049) Net Cash Provided by Operating Activities 141,269 164,650 135,800 Cash Flows from Investing Activities: Construction expenditures - utility (193,344) (177,069) (86,077) Nonutility property (465) (4,956) - Other 836 380 801 Net Cash Used by Investing Activities (192,973) (181,645) (85,276) Cash Flows from Financing Activities: Short-term borrowings - net 76,300 - - Issuance of long-term debt 54,000 173,500 219,930 Funds deposited with trustee - net 95 (18,268) 528 Retirement of long-term debt, including premiums (21) (180,677) (190,756) Retirement of preferred stock, including premium (20,302) - - Issuance of preferred stock - 20,000 - Payment of dividends (64,089) (63,027) (111,514) Net Cash Provided (Used) by Financing Activities 45,983 (68,472) (81,812) Net Decrease in Cash and Cash Equivalents (5,721) (85,467) (31,288) Cash and Cash Equivalents Beginning of Year 8,832 94,299 125,587 Cash and Cash Equivalents End of Year $ 3,111 $ 8,832 $ 94,299 Supplemental Disclosures Cash paid for: Interest on long-term debt $ 30,594 $ 33,860 $ 41,912 Federal and state income taxes $ 45,270 $ 42,483 $ 39,091 The accompanying Notes to Financial Statements are an integral part of these statements.-28-
Balance Sheets Kentucky Utilities CompanyAs of December 31, (in thousands of dollars) 1994 1993 Assets Utility Plant:Plant in service, at cost $ 2,238,926 $ 2,004,688 Less: Accumulated depreciation 933,394 879,960 1,305,532 1,124,728 Construction work in progress 104,385 158,829 Total Utility Plant 1,409,917 1,283,557 Current Assets: Cash and cash equivalents 3,111 8,832 Escrow funds - coal contract litigation 6,911 37,752 Construction funds held by trustee 18,553 18,268 Accounts receivable, net of allowance for doubtful accounts 41,660 41,457 Accrued utility revenues 24,227 25,575 Fuel, principally coal, at average cost 35,652 31,073 Plant materials and operating supplies, at average cost 20,081 17,261 Other 10,616 7,804 Total Current Assets 160,811 188,022 Investments, Deferred Charges and Other Assets: Unamortized loss on reacquired debt 12,324 13,295 Other 35,048 38,400 Total Investments, Deferred Charges and Other Assets 47,372 51,695 Total Assets $ 1,618,100 $ 1,523,274 Capitalization and Liabilities Capitalization: (See Statements of Capitalization) Common stock equity $ 565,201 $ 552,106 Preferred stock 40,000 40,000 Long-term debt 496,012 442,045 Total Capitalization 1,101,213 1,034,151 Current Liabilities: Preferred stock and long-term debt due within one year 21 20,021 Short-term borrowings 76,300 - Accounts payable 49,517 44,006 Accrued interest 7,328 7,302 Accrued taxes 9,422 4,660 Customers' deposits 6,423 10,803 Accrued payroll and vacations 8,207 7,709 Liability to ratepayers - coal contract litigation 6,909 36,867 Other 6,275 6,434 Total Current Liabilities 170,402 137,802 Deferred Credits and Other Liabilities: Accumulated deferred income taxes 214,892 212,325 Accumulated deferred investment tax credits 38,275 42,385 Regulatory tax liability 60,788 64,086 Other 32,530 32,525 Total Deferred Credits and Other Liabilities 346,485 351,321 Total Capitalization and Liabilities $ 1,618,100 $ 1,523,274 The accompanying Notes to Financial Statements are an integral part of these statements.-29-
Statements of Capitalization Kentucky Utilities CompanyAs of December 31, (in thousands of dollars) 1994 1993 Common Stock Equity: Common stock, without par value,outstanding 37,817,878 shares $ 308,140 $ 308,140 Capital stock expense and other (595) (463) Retained earnings 257,656 244,429 Total Common Stock Equity 565,201 552,106 Preferred Stock, cumulative, without par value,$100 stated value 4 3/4%, outstanding 200,000 shares 20,000 20,000 6.53%, outstanding 200,000 shares 20,000 20,000 7.84%, outstanding 200,000 shares - 20,000 Less: Amounts to be redeemed within one year - 20,000 Total Preferred Stock 40,000 40,000 Long-Term Debt: First Mortgage Bonds: 5.95% Series Q, due June 15, 2000 61,500 61,500 7 3/8% Series K, due December 1, 2002 35,500 35,500 6.32% Series Q, due June 15, 2003 62,000 62,000 7.92% Series P, due May 15, 2007 53,000 53,000 8.55% Series P, due May 15, 2027 33,000 33,000 245,000 245,000 First Mortgage Bonds, Pollution Control Series: 7 3/8% Pollution Control Series 7, due May 1, 2010 4,000 4,000 7.45% Pollution Control Series 8, due September 15, 2016 96,000 96,000 6 1/4% Pollution Control Series 1B, due February 1, 2018 20,930 20,930 6 1/4% Pollution Control Series 2B, due February 1, 2018 2,400 2,400 6 1/4% Pollution Control Series 3B, due February 1, 2018 7,200 7,200 6 1/4% Pollution Control Series 4B, due February 1, 2018 7,400 7,400 7.60% Pollution Control Series 7, due May 1, 2020 8,900 8,900 5 3/4% Pollution Control Series 9, due December 1, 2023 50,000 31,900 5 3/4% County of Carroll, Kentucky, Collateralized Solid Waste Disposal Facility Revenue Bonds, due December 1, 2023 - 18,100 Variable Rate Pollution Control Series 10, due November 1, 2024 35,700 - Variable Rate County of Carroll, Kentucky, Collateralized Solid Waste Disposal Facility Revenue Bonds, due November 1, 2024 18,300 - 250,830 196,830 Total First Mortgage Bonds 495,830 441,830 Unamortized premium 96 108 8% secured note, due January 5, 1999(net of current maturity) 86 107 Total Long-Term Debt 496,012 442,045 Total Capitalization $ 1,101,213 $ 1,034,151 The accompanying Notes to Financial Statements are an integral part of these statements.-30-Notes to Financial Statements101
Kentucky Utilities Company
1.and SubsidiaryConsolidated Statements of Income
(Thousands of $)
Years Ended December 31
2002
2001
2000
OPERATING REVENUES:
Electric (Note 1)
$
875,192
$
860,426
$
851,941
Provision for rate collections (refunds) (Note 3)
13,027
(954
)
—
Total operating revenues
888,219
859,472
851,941
OPERATING EXPENSES:
Fuel for electric generation
250,117
236,985
219,923
Power purchased
157,955
157,161
166,918
Other operation expenses
144,118
118,359
108,072
Non-recurring charge (Note 3)
—
6,867
—
Maintenance
62,909
57,021
61,643
Depreciation and amortization (Note 1)
95,462
90,299
98,256
Federal and state income taxes (Note 7)
54,032
57,482
51,963
Property and other taxes
14,983
13,928
17,030
Total operating expenses
779,576
738,102
723,805
Net operating income
108,643
121,370
128,136
Other income – net (Note 8)
10,429
8,932
6,843
Interest charges
25,688
34,024
39,455
Net income before cumulative effect of a change in accounting principle
93,384
96,278
95,524
Cumulative effect of a change in accounting principle-accounting for
Derivative instruments and hedging activities, net of tax
—
136
—
Net income
93,384
96,414
95,524
Preferred stock dividends
2,256
2,256
2,256
Net income available for common stock
$
91,128
$
94,158
$
93,268
Consolidated Statements of Retained Earnings
(Thousands of $)
Years Ended December 31
2002
2001
2000
Balance January 1
$
410,896
$
347,238
$
329,470
Add net income
93,384
96,414
95,524
504,280
443,652
424,994
Deduct: Cash dividends declared on stock:
4.75% cumulative preferred
950
950
950
6.53% cumulative preferred
1,306
1,306
1,306
Common
—
30,500
75,500
2,256
32,756
77,756
Balance December 31
$
502,024
$
410,896
$
347,238
The accompanying notes are an integral part of these consolidated financial statements.
102
Kentucky Utilities Company and Subsidiary
Consolidated Statements of Comprehensive Income
(Thousands of $)
Years Ended December 31
2002
2001
2000
Net income
$
93,384
$
96,414
$
95,524
Cumulative effect of change in accounting principle – Accounting for derivative instruments and hedging activities
—
2,647
—
Losses on derivative instruments and hedging activities
(2,647
)
—
—
Additional minimum pension liability adjustment (Note 6)
(17,543
)
—
—
Income tax benefit (expense) related to items of other comprehensive income
8,140
(1,059
)
—
Other comprehensive (loss) income, net of tax
(12,050
)
1,588
—
Comprehensive income
$
81,334
$
98,002
$
95,524
The accompanying notes are an integral part of these consolidated financial statements.
103
Kentucky Utilities Company and Subsidiary
Consolidated Balance Sheets
(Thousands of $)
December 31
2002
2001
ASSETS:
Utility plant, at original cost (Note 1)
$
3,089,529
$
2,960,818
Less: reserve for depreciation
1,536,658
1,457,754
1,552,871
1,503,064
Construction work in progress
191,233
103,402
1,744,104
1,606,466
Other property and investments - less reserve of $130 in 2002 and 2001
14,358
9,629
Current assets:
Cash and temporary cash investments (Note 1)
5,391
3,295
Accounts receivable-less reserve of $800 in 2002 and 2001
49,588
45,291
Materials and supplies - at average cost:
Fuel (predominantly coal) (Note 1)
46,090
43,382
Other
26,408
26,188
Prepayments and other
6,584
4,942
134,061
123,098
Deferred debits and other assets:
Unamortized debt expense (Note 1)
4,991
4,316
Regulatory assets (Note 3)
65,404
66,467
Other
35,465
16,926
105,860
87,709
$
1,998,383
$
1,826,902
CAPITAL AND LIABILITIES:
Capitalization (see statements of capitalization):
Common equity
$
814,107
$
735,029
Cumulative preferred stock
40,000
40,000
Long-term debt (Note 9)
346,562
434,506
1,200,669
1,209,535
Current liabilities:
Current portion of long-term debt (Note 9)
153,930
54,000
Notes payable to parent (Note 10)
119,490
47,790
Accounts payable
95,374
85,149
Accrued taxes
4,955
20,520
Other
21,442
22,150
395,191
229,609
Deferred credits and other liabilities:
Accumulated deferred income taxes (Notes 1 and 7)
241,184
239,204
Investment tax credit, in process of amortization
8,500
11,455
Accumulated provision for pensions and related benefits (Note 6)
110,927
91,235
Regulatory liabilities (Note 3)
29,876
33,889
Other
12,036
11,975
402,523
387,758
Commitments and contingencies (Note 11)
$
1,998,383
$
1,826,902
The accompanying notes are an integral part of these consolidated financial statements.
104
Kentucky Utilities Company and Subsidiary
Consolidated Statements of Cash Flows
(Thousands of $)
Years Ended December 31
2002
2001
2000
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income
$
93,384
$
96,414
$
95,524
Items not requiring cash currently:
Depreciation and amortization
95,462
90,299
98,256
Deferred income taxes - net
(2,038
)
(12,088
)
(2,449
)
Investment tax credit - net
(2,955
)
(3,446
)
(3,674
)
Other
(1,267
)
11,776
(8,136
)
Change in certain net current assets:
Accounts receivable
(8,497
)
28
(1,870
)
Materials and supplies
(2,928
)
(31,263
)
18,131
Accounts payable
10,225
8,810
(60,774
)
Accrued taxes
(15,565
)
898
9,120
Prepayments and other
(2,350
)
(6,033
)
850
Sale of accounts receivable (Note 1)
4,200
45,100
—
Other
8,086
(12,364
)
31,272
Net cash flows from operating activities
175,757
188,131
176,250
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sales of securities
—
3,480
—
Construction expenditures
(237,909
)
(142,425
)
(100,328
)
Net cash flows from investing activities
(237,909
)
(138,945
)
(100,328
)
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term borrowings and repayments
71,700
(13,449
)
61,239
Retirement of long-term debt
(133,930
)
—
(74,784
)
Issuance of long-term debt
128,734
—
12,900
Additional paid-in capital
—
—
15,000
Payment of dividends
(2,256
)
(32,756
)
(96,756
)
Net cash flows used for financing activities
64,248
(46,205
)
(82,401
)
Change in cash and temporary cash investments
2,096
2,981
(6,479
)
Cash and temporary cash investments at beginning of year
3,295
314
6,793
Cash and temporary cash investments at end of year
$
5,391
$
3,295
$
314
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Income taxes
$
59,580
$
72,432
$
49,871
Interest on borrowed money
37,866
39,829
35,196
The accompanying notes are an integral part of these consolidated financial statements.
105
Kentucky Utilities Company and Subsidiary
Consolidated Statements of Capitalization
(Thousands of $)
December 31
2002
2001
COMMON EQUITY:
Common stock, without par value -
authorized 80,000,000 shares, outstanding 37,817,878 shares
$
308,140
$
308,140
Additional paid-in-capital
15,000
15,000
Accumulated other comprehensive income
(10,462
)
1,588
Other
(595
)
(595
)
Retained earnings
502,024
410,896
814,107
735,029
CUMULATIVE PREFERRED STOCK:
Shares
Outstanding
Current
Redemption Price
Without par value, 5,300,000 shares authorized -
4.75% series, $100 stated value
Redeemable on 30 days notice by KU
200,000
$
101.00
20,000
20,000
6.53% series, $100 stated value
200,000
Not redeemable
20,000
20,000
40,000
40,000
LONG-TERM DEBT (Note 9);
First mortgage bonds -
Q due June 15, 2003, 6.32%
62,000
62,000
S due January 15, 2006, 5.99%
36,000
36,000
P due May 15, 2007, 7.92%
53,000
53,000
R due June 1, 2025, 7.55%
50,000
50,000
P due May 15, 2027, 8.55%
33,000
33,000
Pollution control series:
1B due February 1, 2018, 6.25%
—
20,930
2B due February 1, 2018, 6.25%
—
2,400
3B due February 1, 2018, 6.25%
—
7,200
4B due February 1, 2018, 6.25%
—
7,400
8, due September 15, 2016, 7.45%
—
96,000
9, due December 1, 2023, 5.75%
50,000
50,000
10, due November 1, 2024, variable%
54,000
54,000
11, due May 1, 2023, variable%
12,900
12,900
12, due February 1, 2032, variable%
20,930
—
13, due February 1, 2032, variable%
2,400
—
14, due February 1, 2032, variable%
7,400
—
15, due February 1, 2032, variable%
7,200
—
16, due October 1, 2032, variable%
96,000
—
Long-term debt marked to market (Note 4)
15,662
3,676
Total bonds outstanding
500,492
488,506
Less current portion of long-term debt
153,930
54,000
Long-term debt
346,562
434,506
Total capitalization
$
1,200,669
$
1,209,535
The accompanying notes are an integral part of these consolidated financial statements.
106
Kentucky Utilities Company and Subsidiary
Notes to Consolidated Financial StatementsNote 1 - Summary of Significant Accounting Policies
General Kentucky Utilities Company (Kentucky Utilities) is the principalKU, a subsidiary of
KULG&E EnergyCorporation. Certain amounts from prior periods have been reclassified to conform with the current year presentation. Regulation Kentucky Utilitiesand an indirect subsidiary of Powergen and E.ON, is a regulated public utilitysubject to regulationengaged in the generation, transmission, distribution, and sale of electric energy. LG&E Energy is an exempt public utility holding company with wholly owned subsidiaries including LG&E, KU, Capital Corp., LEM, and LG&E Services. All of the KU’s Common Stock is held bythe Kentucky Public Service Commission (PSC), the Virginia State Corporation Commission (SCC)LG&E Energy. KU has one wholly owned consolidated subsidiary, KU R.On December 11, 2000, LG&E Energy was acquired by Powergen. On July 1, 2002, E.ON, a German company, completed its acquisition of Powergen plc (now Powergen Limited). E.ON had announced its pre-conditional cash offer of £5.1 billion ($7.3 billion) for Powergen on April 9, 2001. Powergen and
the Federal Energy Regulatory Commission (FERC). With respect to accounting matters, Kentucky Utilities maintains its accounts in accordanceE.ON are registered public utility holding companies under PUHCA. No costs associated withthe Uniform Systemthese acquisitions nor any ofAccounts as defined by these agencies. Its accounting policies conform to generally accepted accounting principles applicable to rate regulated enterprises and reflectthe effects of purchase accounting have been reflected in theratemaking process. Other thanfinancial statements of KU.Certain reclassification entries have been made to the
unamortized lossprevious year’s financial statements to conform to the 2002 presentation with no impact onreacquired debt, Kentucky Utilities' regulatory assets are insignificant.the balance sheet totals or previously reported income.Utility
Plant UtilityPlant. KU’s utility plant is stated attheoriginal cost,ofwhich includes payroll-related costs such as taxes, fringe benefits, and administrative and general costs. Construction work in progress has been included in the rate base for determining retail customer rates. KU has not recorded any significant allowance for funds used during construction.The cost of
repairsplant retired or disposed of in the normal course of business is deducted from plant accounts andminor renewalssuch cost, plus removal expense less salvage value, is charged tomaintenance expense as incurred. Property unit replacementsthe reserve for depreciation. When complete operating units arecapitalized anddisposed of, appropriate adjustments are made to thedepreciationreserveis charged with the cost, less net salvage, of units retired. Depreciation Provisionfor depreciation and gains and losses, if any, are recognized.Depreciation and Amortization. Depreciation is provided on the straight-line method over the estimated service lives of
utility plant is based on straight-line compositedepreciable plant. Pursuant to a final order of the Kentucky Commission dated December 3, 2001, KU implemented new deprecation ratesappliedeffective January 1, 2001. The amounts provided were approximately 3.1% in 2002, 3.1% in 2001 and 3.5% in 2000, of average depreciable plant. Of the amount provided for depreciation at December 31, 2002, 2001 and 2000, respectively, approximately 0.7% was related to thecostretirement, removal and disposal costs ofdepreciable property. The rates approximated 3.4% in 1994, and 3.3% in 1993 and 1992.long lived assets.Cash and Temporary Cash
Equivalents For purposes of reporting cash flows, Kentucky UtilitiesInvestments. KU considers all highly liquidinvestmentsdebt instruments purchased with a maturity of three months or lessfrom the date of purchaseto be cash equivalents.Kentucky Utilities utilizes aTemporary cashmanagement mechanism that funds certain bank accounts for checks as theyinvestments arepresented to those banks. Kentucky Utilities classified checks written but not presented to those banks,carried at cost, whichamounted to $11.5approximates fair value.Fuel Inventories. Fuel inventories of $46.1 million and
$9.9$43.4 million at December 31,19942002 and1993,2001, respectively, are included inaccounts payable.Fuel in the balance sheet. The inventory is accounted for using the average-cost method.Financial
Instruments Kentucky Utilities' temporary cash investmentsInstruments. KU uses over-the-counter interest-rate swap agreements to hedge its exposure to interest rates. Gains and losses on interest-rate swaps used to hedge interest rate risk areclassified as held-to- maturityreflected in interest charges monthly. See Note 4 - Financial Instruments.107
Unamortized Debt Expense. Debt expense is capitalized in deferred debits and
are reported under the caption "Cash and cash equivalents" on the Balance Sheet. -31-Notes to Financial Statements Kentucky Utilities Company Unamortized Loss on Reacquired Debt Kentucky Utilities defers costs (primarily call premiums) arising from the reacquisition or retirement of long-term debt. Costs related to refinanced debt areamortized over the lives of thenew debt issues. Costsrelatedto retired debt not refinancedbond issues, consistent with regulatory practices.Deferred Income Taxes. Deferred income taxes are
amortized over the period to the scheduled maturity of the retired debt. Operating Revenues and Fuel Costs Revenues are recorded based on services rendered to customers. Kentucky Utilities accrues an estimate of revenuesrecognized at currently enacted tax rates forelectric service furnished from the meter reading dates to the end of each accounting period. Cost of fuel used in electric generation is charged to expense as the fuel is consumed. The cost of fuel for 1992 included an amortization of buyout costs associated with the termination of a coal supply contract. A fuel adjustment clause adjusts operating revenues for changes in the level of fuel costs charged to expense. An environmental surcharge, implemented in August 1994, permits the utility to recover certain ongoing operating and capital costs of compliance with federal, state or local environmental requirements associated with the production of energy from coal, including the 1990 Clean Air Act Amendments. Pursuant to regulatory orders, Kentucky Utilities has been refunding fuel cost savings related to the resolution of a coal contract dispute. Refunds to Kentucky retail customers commenced in July 1994. Refunds were made to Virginia retail customers during the period August 1993 through June 1994. Refunds were made to wholesale customers under the jurisdiction of the Federal Energy Regulatory Commission in lump sum payments in September 1993. Operating revenues and fuel expense for the respective periods were reduced by the following amounts resulting from the above-mentioned refunds:
Year Ended December 31, (in thousands of dollars) 1994 1993Operating Revenues $ 19,385 $ 3,309 Fuel, principally coal, used in generation $ 23,082 $ 4,095The differenceall material temporary differences between thereduction in Operating Revenuesfinancial reporting andthe reduction in Fuel Expense is attributed to incurred litigation costs, fuel costs savings related to off-system sales and costs incurred to administer the refund plan. These amounts were allowed to be retained by Kentucky Utilities pursuant to regulatory orders. Income Taxes Kentucky Utilities establishes deferredincome tax basis of assets andliabilities, as appropriate, for all temporary differences, and adjusts deferred tax balances to reflect changes in tax rates expected to be in effect during the periods the temporary differences reverse.liabilities.Investment Tax Credits. Investment tax credits resulted from provisions of the tax law
whichthat permitted a reduction of-32-Notes to Financial Statements Kentucky Utilities Company Kentucky Utilities'KU’s tax liability based on credits for certain construction expenditures.SuchDeferred investment tax creditshave been deferred in the accounts andare being amortizedas reductions into incometax expenseover thelifeestimated lives of the relatedproperty. Becauseproperty that gave rise to the credits.Revenue Recognition. Revenues are recorded based on service rendered to customers through month-end. KU accrues an estimate for unbilled revenues from each meter reading date to the end of
rate regulation, changesthe accounting period. The unbilled revenue estimates included intax ratesaccounts receivable were approximately $36.4 million and $33.4 million at December 31, 2002, and 2001, respectively. KU recorded electric revenues that resulted from sales to a related party, LG&E, of $34.6 million, $31.1 million and $22.1 million for years ended December 31, 2002, 2001 and 2000, respectively. See Note 3, Rates and Regulatory Matters.Fuel Costs. The cost of fuel for electric generation is charged to expense as used.
Management’s Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported assets and liabilities and disclosure of contingent items at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. See Note 11, Commitments and Contingencies, for a further discussion.
Accounts Receivable Securitization. SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, revises the standards for accounting for securitizations and other transfers of financial assets and collateral and requires certain disclosures, and provides accounting and reporting standards for transfers and servicing of financial assets and extinguishments of liabilities. SFAS No. 140 was adopted in the first quarter of 2001, when KU entered into an accounts receivable securitization transaction.
On February 6, 2001, KU implemented an accounts receivable securitization program. The purpose of this program is to enable KU to accelerate the receipt of cash from the collection of retail accounts receivable, thereby reducing dependence upon more costly sources of working capital. The securitization program allows for a percentage of eligible receivables to be sold. Eligible receivables are
deferredgenerally all receivables associated with retail sales that have standard terms andamortizedare not past due. KU is able to terminate this program at any time without penalty. If there is a significant deterioration in the payment record of the receivables by the retail customers or if KU fails to meet certain covenants regarding the program, the program may terminate at the election of the financial institutions. In this case, payments from retail customers would first be used to repay the financial institutions participating in the program, and would then be available for use by KU.As part of the program, KU sold retail accounts receivables to a wholly owned subsidiary, KU R. Simultaneously, KU R entered into two separate three-year accounts receivable securitization facilities with two financial institutions and their affiliates whereby KU R can sell, on a revolving basis, an undivided interest in certain of its receivables and receive up to $50 million from an unrelated third party purchaser. The effective cost of the receivables programs is comparable to KU’s lowest cost source of capital, and is based on prime rated commercial paper. KU retains servicing rights of the sold receivables through two separate servicing agreements with the third party purchaser. KU has obtained an opinion from independent legal counsel
108
indicating these transactions qualify as a true sale of receivables. As of December 31, 2002, the
temporary differences reverse. 2. Income Taxes Effectiveoutstanding program balance was $49.3 million. KU is considering unwinding its accounts receivable securitization arrangements involving KU R during 2003.The allowance for doubtful accounts associated with the eligible securitized receivables was $520,000 at December 31, 2002. This allowance is based on historical experience of KU. Each securitization facility contains a fully funded reserve for uncollectible receivables.
New Accounting Pronouncements. The following accounting pronouncements were issued that affected KU in 2002:
SFAS No. 143, Accounting for Asset Retirement Obligations was issued in 2001. SFAS No. 143 establishes accounting and reporting standards for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.
The effective implementation date for SFAS No. 143 is January 1,
1993, Kentucky Utilities adopted Statement2003. Management has calculated the impact of SFAS No. 143 and the recently released FERC NOPR No. RM02-7, Accounting, Financial Reporting, and Rate Filing Requirements for Asset Retirement Obligations. As of January 1, 2003, KU recorded asset retirement obligation (ARO) assets in the amount of $8.6 million and liabilities in the amount of $18.5 million. KU also recorded a cumulative effect adjustment in the amount of $9.9 million to reflect the accumulated depreciation and accretion of ARO assets at the transition date less the amounts previously accrued under reglatory depreciation. KU recorded offsetting regulatory assets of $9.9 million, pursuant to regulatory treatment prescribed under SFAS No. 71, AccountingStandardsfor the Effects of Certain Types of Regulation. Also pursuant to SFAS No.109, "Accounting71, KU recorded regulatory liabilities in the amount of $888,000 offsetting removal costs previously accrued under regulatory accounting in excess of amounts allowed under SFAS No. 143.KU also expects to record ARO accretion expense of approximately $1.2 million, ARO depreciation expense of approximately $176,000 and an offsetting regulatory credit in the income statement of approximately $1.4 million in 2003, pursuant to regulatory treatment prescribed under SFAS No. 71, Accounting for
Income Taxes"the Effects of Certain Types of Regulation. Theadoptionaccretion, depreciation and regulatory credit will be annual adjustments. SFAS No. 143 will have no impact on the results of the operation of KU.KU’s asset retirement obligations are primarily related to the final retirement of generating units. KU transmission and distribution lines largely operate under perpetual property easement agreements which do not generally require restoration upon removal of the property. Therefore, under SFAS No. 143, no material asset retirement obligations will be recorded for transmission and distribution assets.
KU adopted EITF No. 98-10, Accounting for Energy Trading and Risk Management Activities, effective January 1, 1999. This pronouncement required that energy trading contracts be marked to market on the balance sheet, with the gains and losses shown net in the income statement. In October 2002, the Emerging Issues Task Force reached a consensus to rescind EITF 98-10. The effective date for the full rescission will be for fiscal periods beginning after December 15, 2002. With the recession of EITF No. 98-10, energy trading contracts that do not also meet the definition of a derivative under SFAS No. 133 must be accounted for as executory contracts. Contracts previously recorded at fair value under EITF No. 98-10 that are not also derivatives under SFAS No. 133 must be restated to historical cost through a cumulative effect adjustment. KU does not expect the rescission of this standard
did notto have a material impact on financial position or results ofoperation, cash flows or financial position. Kentucky Utilities is included inoperations.In January 2003, the
consolidated federal tax return of its parent company, KU Energy. Income taxes are allocated to the individual companies, including Kentucky Utilities, based on their respective taxable income or loss. The accumulated deferred income taxes as set forth below and in the Balance Sheet arise from the following temporary differences:
As of December 31, (in thousands of dollars) 1994 1993 Deferred Tax Assets: Unamortized investment tax credit and other propertyrelated differences $ 31,805 $ 28,529 Other 17,363 13,146 Less: Amounts included in current assets 6,726 5,897 42,442 35,778 Deferred Tax Liabilities: Accelerated depreciation and other property related differences 251,282 241,893 Other 6,052 6,210 257,334 248,103 Net accumulated deferred income tax liability $ 214,892 $ 212,325-33-Notes to Financial Statements Kentucky Utilities Company
The components of income tax expense are as follows:Year Ended December 31, (in thousands of dollars) 1994 1993 1992 Income taxes charged to Operating Income:Current - federal $ 37,058 $ 35,893 $ 30,838 - state 8,812 9,484 7,951 45,870 45,377 38,789 Deferred - federal (1,114) 2,837 2,269 - state 13 71 561 (1,101) 2,908 2,830 Deferred investment tax credit (86) (107) (130) 44,683 48,178 41,489 Income taxes charged to Other Income and Deductions: Current - federal 1,537 (2,056) (7) - state 344 (560) (217) 1,881 (2,616) (224) Deferred - federal (365) 2,261 909 - state (93) 556 235 (458) 2,817 1,144 Amortization of deferred investment tax credit (4,024) (4,024) (4,019) (2,601) (3,823) (3,099) Total income tax expense $ 42,082 $ 44,355 $ 38,390The provision for deferred income taxes in 1992 primarily related to accelerated depreciation and other property related differences. Kentucky Utilities' effective income tax rate, determined by dividing income taxes by the sum of such taxes and net income, was 35.2% in 1994, 35.3% in 1993 and 33.5% in 1992. The difference between the effective rate and the statutory federal income tax rate is attributable to the following factors:
Year Ended December 31, (in thousands of dollars) 1994 1993 1992 Federal income tax computedat 35%, 35% and 34%, respectively $ 41,858 $ 43,974 $ 38,994 Add (Deduct): State income taxes, net of federal income tax benefit 5,899 6,208 5,630 Amortization of deferred investment tax credit (4,110) (4,131) (4,140) Other, net (1,565) (1,696) (2,094) Total income tax expense $ 42,082 $ 44,355 $ 38,3903. Retirement Benefits Pensions Kentucky Utilities has a noncontributory defined benefit pension plan covering substantially all of its employees. Benefits under this plan are based on years of service, final average base pay and age at -34-Notes to Financial Statements Kentucky Utilities Company retirement. Kentucky Utilities' funding policy is to make such contributions as are necessary to finance the benefits provided under the plan. Kentucky Utilities' contributions meet the funding standards set forth in the Employee Retirement Income Security Act of 1974. The plan assets consist primarily of equity and fixed income investments. Kentucky Utilities also has a Supplemental Security Plan for certain management personnel. Retirement benefits under this plan are based on years of service, earnings and age at retirement. The plan has no advance funding. Benefit payments are made to retired employees or their beneficiaries from the general assets of Kentucky Utilities.
The reconciliation of the funded status of the retirement plans and the pension liability recorded by Kentucky Utilities is as follows:As of December 31, (in thousands of dollars) 1994 1993Fair value of plan assets $ 154,314 $ 157,137 Projected benefit obligation (169,599) (169,309) Plan assets less than projected benefit obligation (15,285) (12,172) Unrecognized net loss from past experience different than that assumed 5,246 6,361 Unrecognized prior service cost 4,705 4,966 Unrecognized net asset (1,799) (1,949) Regulatory effect recorded (3,229) (5,146) Pension liability $ (10,362) $ (7,940) Accumulated benefit obligation (including vested benefits of $124,094 and $128,779, respectively) $ 126,146 $ 130,758
Components of Net Pension Cost:Year Ended December 31, (in thousands of dollars) 1994 1993 1992 Service cost (benefits earned during theperiod) $ 6,017 $ 5,036 $ 4,774 Interest cost on projected benefit obligation 12,366 12,311 11,482 Actual return on plan assets (3,723) (13,229) (11,384) Net amortization and deferral (8,765) 1,785 350 Regulatory effect recorded (1,916) 56 705 Net pension cost $ 3,979 $ 5,959 $ 5,927
Assumptions Used in Determining Actuarial Valuations:1994 1993 1992Weighted average discount rate used to determine the projected benefit obligation 8 1/4 % 7 1/2% 8 3/4% Rate of increase for compensation levels (1) 5 1/2 % 4 3/4% 6% Weighted average expected long-term rate of return on assets 8 1/4 % 8 1/4% 8 3/4% (1) 6%, 5 1/4% and 6 1/2%, respectively, used for the Supplemental Security Plan valuation.-35-Notes to Financial Statements Kentucky Utilities Company Other Postretirement Benefits Effective January 1, 1993, Kentucky Utilities adopted Statement ofFinancial Accounting Standards Board issued Financial Accounting Standards Board109
Interpretation No.
106, "Employers'46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51 (FIN 46). FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 is effective immediately for all new variable interest entities created or acquired after January 31, 2003. For variable interest entities created or acquired prior to February 1, 2003, the provisions of FIN 46 must be applied for the first interim or annual period beginning after June 15, 2003. KU does not expect the adoption of this standard to have any impact on the financial position or results of operations.Note 2 – Mergers and Acquisitions
On July 1, 2002, E.ON completed its acquisition of Powergen, including LG&E Energy, for approximately £5.1 billion ($7.3 billion). As a result of the acquisition, LG&E Energy became a wholly owned subsidiary (through Powergen) of E.ON and, as a result, KU also became an indirect subsidiary of E.ON. KU has continued its separate identity and serves customers in Kentucky, Virginia and Tennessee under its existing names. The preferred stock and debt securities of KU were not affected by this transaction and the utilities continue to file SEC reports. Following the acquisition, E.ON became, and Powergen remained, a registered holding company under PUHCA. KU, as a subsidiary of a registered holding company, is subject to additional regulations under PUHCA. As contemplated in their regulatory filings in connection with the E.ON acquisition, E.ON, Powergen and LG&E Energy completed an administrative reorganization to move the LG&E Energy group from an indirect Powergen subsidiary to an indirect E.ON subsidiary. This reorganization was effective in March 2003.
LG&E Energy and KU Energy merged on May 4, 1998, with LG&E Energy as the surviving corporation. Management accounted for the merger as a pooling of interests and as a tax-free reorganization under the Internal Revenue Code. Following these acquisitions, KU has continued to maintain its separate identity and serve customers under its present name.
Note 3 - Rates and Regulatory Matters
Accounting for
Postretirement Benefits Other Than Pensions." This standard providesthe regulated utility business conforms with generally accepted accounting principles as applied to regulated public utilities anddisclosure requirementsas prescribed by FERC, the Kentucky Commission and the Virginia Commission. KU is subject to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, under which certain costs that would otherwise be charged to expense are deferred as regulatory assets based on expected recovery from customers in future rates. Likewise, certain credits that would otherwise be reflected as income are deferred as regulatory liabilities based on expected return to customers in future rates. KU’s current or expected recovery of deferred costs and expected return of deferred credits is generally based on specific ratemaking decisions or precedent for each item. The following regulatory assets and liabilities were included in KU’s balance sheets as of December 31 (in thousands of $):
2002
2001
VDT costs
$
38,375
$
48,811
Unamortized loss on bonds
9,456
6,142
LG&E/KU merger costs
2,046
6,139
One utility costs
873
4,365
ESM provision
13,500
—
Other
1,154
1,010
Total regulatory assets
65,404
66,467
Deferred income taxes - net
(28,854
)
(32,872
)
Other
(1,022
)
(1,017
)
Total regulatory liabilities
(29,876
)
(33,889
)
Regulatory assets - net
$
35,528
$
32,578
110
Kentucky Commission Settlement Order - VDT Costs. During the first quarter 2001, KU recorded a $64 million charge for a workforce reduction program. Primary components of the charge were separation benefits, enhanced early retirement benefits, and health care benefits. The result of this workforce reduction was the elimination of approximately 300 positions, accomplished primarily through a voluntary enhanced severance program.
On June 1, 2001, KU filed an application (VDT case) with the Kentucky Commission to create a regulatory asset relating to these first quarter 2001 charges. The application requested permission to amortize these costs over a four-year period. The Kentucky Commission also opened a case to review a new depreciation study and resulting depreciation rates implemented in 2001.
KU reached a settlement in the VDT case as well as the other cases involving depreciation rates and ESM with all intervening parties. The settlement agreement was approved by the Kentucky Commission on December 3, 2001. The order allowed KU to set up a regulatory asset of $54 million for the workforce reduction costs and begin amortizing these costs over a five year period starting in April 2001. The first quarter 2001 charge of $64 million represented all employees who had accepted a voluntary enhanced severance program. Some employees rescinded their participation in the voluntary enhanced severance program and, along with the non-recurring charge of $6.9 million for FERC and Virginia jurisdictions, thereby decreasing the original charge of the regulatory asset from $64 million to $54 million. The settlement will also reduce revenues approximately $11 million through a surcredit on future bills to customers over the same five year period. The surcredit represents net savings stipulated by KU. The agreement also established KU’s new depreciation rates in effect December 2001, retroactive to January 1, 2001. The new depreciation rates decreased depreciation expense by $6.0 million in 2001.
PUHCA. LG&E Energy was purchased by Powergen on December 11, 2000. Effective July 1, 2002, Powergen was acquired by E.ON, which became a registered holding company under PUHCA. As a result, E.ON, its utility subsidiaries, including KU, and certain of its non-utility subsidiaries are subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales of securities, acquisitions and sales of certain utility properties, and intra-system sales of certain goods and services. In addition, PUHCA generally limits the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company. KU believes that it has adequate authority (including financing authority) under existing SEC orders and regulations to conduct its business. KU will seek additional authorization when necessary.
Environmental Cost Recovery. In June 2000, the Kentucky Commission approved KU’s application for a CCN to construct up to four SCR NOx reduction facilities. The construction and subsequent operation of the SCRs is intended to reduce NOx emission levels to meet the EPA’s mandated NOx emission level of 0.15 lbs./ Mmbtu by May 2004. In its order, the Kentucky Commission ruled that KU’s proposed plan for construction was “reasonable, cost-effective and will not result in the wasteful duplication of facilities.” In October 2000, KU filed an application with the Kentucky Commission to amend its Environmental Compliance Plan to reflect the addition of the proposed NOx reduction technology projects and to amend its ECR Tariff to include an overall rate of return on capital investments. Approval of KU’s application in April 2001 allowed KU to begin to recover the costs associated with these new projects, subject to Kentucky
Utilities' obligationCommission oversight during normal six-month and two-year reviews.111
In August 2002, KU filed an application with the Kentucky Commission to
provide postretirement benefits other than pensionsamend its compliance plan topresentallow recovery of the cost of a new andfuture retirees. In accordanceadditional environmental compliance facility. The estimated capital cost of the additional facilities is $17.3 million. The Kentucky Commission conducted a public hearing on the case on December 20, 2002, final briefs were filed on January 15, 2003, and a final order was issued February 11, 2003. The final order approved recovery of the new environmental compliance facility totaling $17.3 million. Cost recovery through the environmental surcharge of the approved project will begin withthis standard,bills rendered in April 2003.ESM.KU’s electric rates are subject to an ESM. The ESM, initially in place for three years beginning in 2000, sets an upper and lower point for rate of return on equity, whereby if KU’s rate of return for the calendar year falls within the range of 10.5% to 12.5%, no action is necessary. If earnings are above the upper limit, the excess earnings are shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, the earnings deficiency is recovered 40% from ratepayers and 60% from shareholders. By order of the Kentucky
Utilities accrues, duringCommission, rate changes prompted by theyearsESM filing go into effect in April of each year subject to a balancing adjustment in successive periods. KU made its second ESM filing on March 1, 2002 for the calendar year 2001 reporting period. KU is in the process of refunding $1 million to customers for the 2001 reporting period. KU estimated that theemployee renders service,rate of return will fall below theexpected cost of providing these benefits for retired employees, their beneficiaries and covered dependents. The impact on results of operations was an increase in pre-tax expenselower limit, subject to Kentucky Commission approval, for the year ended December 31,19932002. The 2002 financial statements include an accrual to reflect the earnings deficiency of$6.3$13.5 million(netto be recovered from customers commencing in April 2003.On November 27, 2002, KU filed a revised ESM tariff which proposed continuance of
capitalized payroll benefits).the existing ESM through December 2005. The KentuckyUtilities, priorCommission issued an order suspending the ESM tariff one day making the effective date January 2, 2003. In addition, the Kentucky Commission is conducting a management audit to1993, recognizedreview the ESM plan and reassess its reasonableness in 2003. KU and interested parties will have the opportunity to provide recommendations for modification and continuance of the ESM or other forms of alternative or incentive regulation.DSM. In May 2001, the Kentucky Commission approved a plan that would expand LG&E’s current DSM programs into the service territory served by KU. The filing included a rate mechanism that provided for concurrent recovery of DSM costs, provided an incentive for implementing DSM programs, and recovered revenues from lost sales associated with the DSM program based on program planning engineering estimates and post-implementation evaluation.
FAC. KU employs a FAC mechanism which allows KU to recover from customers’ fuel costs associated with retail electric sales. In July 1999, the Kentucky Commission issued a series of orders requiring KU to refund approximately $10.1 million resulting from reviews of the FAC from November 1994 to October 1998. In August 1999, after a rehearing request by KU, the Kentucky Commission issued a final order that reduced the refund obligation to $6.7 million ($5.8 million on a Kentucky jurisdictional basis) from the original order amount of $10.1 million. KU implemented the refund from October 1999 through September 2000. Both KU and the KIUC appealed the order. Pending a decision on this appeal, a comprehensive settlement was reached by all parties and approved by the Kentucky Commission on May 17, 2002. Thereunder, KU agreed to credit its fuel clause in the amount of $954,000 (refund made in June and July 2002), and the parties agreed on a prospective interpretation of the state’s FAC regulation to ensure consistent and mutually acceptable application on a going-forward basis.
In December 2002, the Kentucky Commission initiated a two year review of the operation of KU’s FAC for the period November 2000 through October 2002. Testimony in the review case was filed on January 20, 2003 and a public hearing was held February 18, 2003. Issues addressed at that time included the establishment of the
112
current base fuel factor to be included in KU’s base rates, verification of proper treatment of purchased power costs during unit outages, and compliance with fuel procurement policies and practices.
Kentucky Commission Administrative Case for Affiliate Transactions. In December 1997, the Kentucky Commission opened Administrative Case No. 369 to consider Kentucky Commission policy regarding cost allocations, affiliate transactions and codes of conduct governing the relationship between utilities and their non-utility operations and affiliates. The Kentucky Commission intended to address two major areas in the proceedings: the tools and conditions needed to prevent cost shifting and cross-subsidization between regulated and non-utility operations; and whether a code of conduct should be established to assure that non-utility segments of the holding company are not engaged in practices that could result in unfair competition caused by cost shifting from the non-utility affiliate to the utility. During the period September 1998 to February 2000, the Kentucky Commission issued draft codes of conduct and cost allocation guidelines. In early 2000, the Kentucky General Assembly enacted legislation, House Bill 897, which authorized the Kentucky Commission to require utilities that provide nonregulated activities to keep separate accounts and allocate costs in accordance with procedures established by the Kentucky Commission. In the same Bill, the General Assembly set forth provisions to govern a utility’s activities related to the sharing of information, databases, and resources between its employees or an affiliate involved in the marketing or the provision of nonregulated activities and its employees or an affiliate involved in the provision of regulated services. The legislation became law in July 2000 and KU has been operating pursuant thereto since that time. On February 14, 2001, the Kentucky Commission published notice of their intent to promulgate new administrative regulations under the auspices of this new law. This effort is still on-going.
Kentucky Commission Administrative Case for System Adequacy. On June 19, 2001, Kentucky Governor Paul E. Patton issued Executive Order 2001-771, which directed the Kentucky Commission to review and study issues relating to the need for and development of new electric generating capacity in Kentucky. The issues to be considered included the impact of new power plants on the electric supply grid, facility citing issues, and economic development matters, with the goal of ensuring a continued, reliable source of supply of electricity for the citizens of Kentucky and the continued environmental and economic vitality of Kentucky and its communities. In response to that Executive Order, in July 2001 the Kentucky Commission opened Administrative Case No. 387 to review the adequacy of Kentucky’s generation capacity and transmission system. Specifically, the items reviewed were the appropriate level of reliance on purchased power, the appropriate reserve margins to meet existing and future electric demand, the impact of spikes in natural gas prices on electric utility planning strategies, and the adequacy of Kentucky’s electric transmission facilities. KU, as a party to this proceeding, filed written testimony and responded to two requests for information. Public hearings were held October 2001 and KU filed a final brief in the case. In December 2001, the Kentucky Commission issued an order in which it noted that KU is responsibly addressing the long-term supply needs of native load customers and that current reserve margins are appropriate. However, due to the rapid pace of change in the industry, the order also requires KU to provide an annual assessment of supply resources, future demand, reserve margin, and the need for new resources.
Regarding the transmission system, the Kentucky Commission concluded that the transmission system within Kentucky can reliably serve native load and a significant portion of the proposed new unregulated power plants. However, it will not be able to handle the volume of transactions envisioned by FERC without future upgrades, the costs of which should be borne by those for whom the upgrades are required.
The Kentucky Commission pledged to continue to monitor all relevant issues and advocate Kentucky’s interests at all opportunities.
FERC SMD NOPR. On July 31, 2002, the FERC issued a NOPR in Docket No. RM01-12-000 which would
113
substantially alter the regulations governing the nation’s wholesale electricity markets by establishing a common set of rules — SMD. The SMD NOPR would require each public utility that owns, operates, or controls interstate transmission facilities to become an Independent Transmission Provider (ITP), belong to an RTO that is an ITP, or contract with an ITP for operation of its transmission assets. It would also establish a standardized congestion management system, real-time and day-ahead energy markets, and a single transmission service for network and point-to-point transmission customers. Review of the proposed rulemaking is underway and a final rule is expected during 2003. While it is expected that the SMD final rule will affect KU revenues and expenses, the specific impact of the rulemaking is not known at this time.
MISO. KU is a member of the MISO, which began commercial operations on February 1, 2002. MISO now has operational control over KU’s high-voltage transmission facilities (100 kV and greater), while KU continues to control and operate the lower voltage transmission subject to the terms and conditions of the MISO OATT. As a transmission-owning member of MISO, KU also incurs administrative costs of MISO pursuant to Schedule 10 of the MISO OATT.
MISO also proposed to implement a congestion management system. FERC directed the MISO to coordinate its efforts with FERC’s Rulemaking on SMD. On September 24, 2002, the MISO filed new rate schedules designated as Schedules 16 and 17, which provide for the collection of costs incurred by the MISO to establish day-ahead and real-time energy markets. The MISO proposed to recover these costs under Schedules 16 and 17 once service commences. If approved by FERC, these schedules will cause KU to incur additional costs. KU opposes the establishment of Schedules 16 and 17. This effort is still on-going and the ultimate impact of the two schedules, if approved, is not known at this time.
ARO. In 2003, KU expects to record approximately $11.3 million in regulatory assets and approximately $888,000 in regulatory liabilities related to SFAS No. 143, Accounting for Asset Retirement Obligations.
Merger Surcredit. As part of the LG&E Energy merger with KU Energy, KU estimated non-fuel savings over a ten—year period following the merger. Costs to achieve these savings for KU of $42.3 million were recorded in the second quarter of 1998, $20.5 million of which was deferred and amortized over a five-year period pursuant to regulatory orders. Primary components of the merger costs were separation benefits, relocation costs, and transaction fees, the majority of which were paid by December 31, 1998. KU expensed the remaining costs associated with the merger ($21.8 million) in the second quarter of 1998.
In approving the merger, the Kentucky Commission adopted KU’s proposal to reduce its retail customers’ bills based on one-half of the estimated merger-related savings, net of deferred and amortized amounts, over a five year period. The surcredit mechanism provides that 50% of the net non-fuel cost savings estimated to be achieved from the merger would be provided to ratepayers through a monthly bill credit, and 50% retained by the Companies, over a five-year period. The surcredit was allocated 53% to KU and 47% to LG&E. In that same order, the Commission required LG&E and KU, after the end of the five-year period, to present a plan for sharing with customers the then-projected non-fuel savings associated with the merger. The Companies submitted this filing on January 13, 2003, proposing to continue to share with customers, on a
pay-as-you-go (cash) basis. Amounts paid for retirees for 1992 amounted50%/50% basis, the estimated fifth-year gross level of non-fuel savings associated with the merger. The filing is currently under review.Any fuel cost savings are passed to
$2.3 million.KentuckyUtilities provides certain health carecustomers through the fuel adjustment clauses. See FAC above.114
Note 4 - Financial Instruments
The cost and
life insurance benefits to eligible retired employees and their dependents. The postretirement health care plan is contributory for employees who retired afterestimated fair values of the KU’s non-trading financial instruments as of December 31,1992, with retiree contributions indexed annually based upon2002, and 2001 follow (in thousands of $):
2002
2001
Cost
Fair
Value
Cost
Fair
Value
Long-term debt (including current portion)
$
484,830
$
503,194
$
484,830
$
499,618
Interest-rate swaps
—
16,928
—
6,906
All of the
experience of retiree medical expensesabove valuations reflect prices quoted by exchanges except for thepreceding year. Pre-1993 retirees are not requiredswaps. The fair values of the swaps reflect price quotes from dealers or amounts calculated using accepted pricing models.Interest Rate Swaps. KU uses interest rate swaps to
contributehedge exposure tothe plan. Kentucky Utilities' employees become eligible for retiree medical benefits after 15 yearsmarket fluctuations in certain ofserviceits debt instruments. Pursuant to policy, use of these financial instruments is intended to mitigate risk andattainment of age 55. The life insurance plan is noncontributoryearnings volatility and is not speculative in nature. Management has designated all of the interest rate swaps as hedge instruments. Financial instruments designated as fair value hedges are periodically marked to market with the resulting gains and losses recorded directly into net income to correspond with income or expense recognized from changes in market value of the items being hedged.As of December 31, 2002 and 2001, KU was party to various interest rate swap agreements with aggregate notional amounts of $153 million in 2002 and 2001. Under these swap agreements, KU paid variable rates based on
compensation levels prioreither LIBOR or the Bond Market Association’s municipal swap index averaging 2.36% and 2.54%, and received fixed rates averaging 7.13% and 7.13% at December 31, 2002 and 2001, respectively. The swap agreements in effect at December 31, 2002 have been designated as fair value hedges and mature on dates ranging from 2007 toretirement. In 1993, Kentucky Utilities began funding,2025. For 2002, the effect of marking these financial instruments and the underlying debt to market resulted in immaterial pretax gains recorded in interest expense.Interest rate swaps hedge interest rate risk on the underlying debt under SFAS 133, in addition to
current requirementsswaps being marked to market, the item being hedged must also be marked to market, consequently at December 31, 2002, KU’s debt reflects a $15.7 million mark to market adjustment.Energy Trading & Risk Management Activities. KU conducts energy trading and risk management activities to maximize the value of power sales from physical assets it owns, in addition to the wholesale sale of excess asset capacity. Certain energy trading activities are accounted for
benefit payments,on a mark-to-market basis in accordance with EITF 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities. Wholesale sales of excess asset capacity and wholesale purchases are treated as normal sales and purchases under SFAS No. 133 and SFAS No. 138 and are not marked-to-market.The rescission of EITF 98-10, effective for fiscal years after December 15, 2002, will have no impact on KU’s energy trading and risk management reporting as all contracts marked to market under EITF 98-10 are also within the
maximum tax-favored amount allowed through certain tax deductible funding vehicles.scope of SFAS No. 133.The table below summarizes KU’s energy trading and risk management activities for 2002 and 2001 (in thousands of $).
115
2002
2001
Fair value of contracts at beginning of period, net liability
$
(186
)
$
(17
)
Fair value of contracts when entered into during the period
(65
)
3,441
Contracts realized or otherwise settled during the period
448
(2,894
)
Changes in fair values due to changes in assumptions
(353
)
(716
)
Fair value of contracts at end of period, net liability
$
(156
)
$
(186
)
No changes to valuation techniques for energy trading and risk management activities occurred during 2002. Changes in market pricing, interest rate and volatility assumptions were made during both years. All contracts outstanding at December 31, 2002, have a maturity of less than one year and are valued using prices actively quoted for proposed or executed transactions or quoted by brokers.
KU maintains policies intended to minimize credit risk and revalues credit exposures daily to monitor compliance with those policies. At December 31, 2002, 86% of the trading and risk management commitments were with counterparties rated BBB- equivalent or better.
Note 5 - Concentrations of Credit and Other Risk
Credit risk represents the accounting loss that would be recognized at the reporting date if counterparties failed to perform as contracted. Concentrations of credit risk (whether on- or off-balance sheet) relate to groups of customers or counterparties that have similar economic or industry characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in economic or other conditions.
KU’s customer receivables and revenues arise from deliveries of electricity to approximately 477,000 customers in over 600 communities and adjacent suburban and rural areas in 77 counties in central, southeastern and western Kentucky,
Utilities anticipates making similar funding decisionsto approximately 30,000 customers infuture years, but will considerfive counties in southwestern Virginia andmake such funding decisions onless than ten customers in Tennessee. For thebasisyear ended December 31, 2002, 100% oftax, regulatorytotal utility revenue was derived from electric operations.In August 2001, KU and its employees represented by IBEW Local 2100 entered into a two-year collective bargaining agreement. KU and its employees represented by USWA Local 9447-01 entered into a three-year collective bargaining agreement effective August 2002 and expiring August 2005. The employees represented by these two bargaining units comprise approximately 17% of KU’s workforce.
Note 6 - Pension Plans and Retirement Benefits
KU sponsors qualified and non-qualified pension plans and other
relevant conditionspostretirement benefit plans for its employees. The following tables provide a reconciliation of the changes ineffect at such times. Thethe plans’ benefit obligations and fair value of assets over the three-year period ending December 31, 2002, and a statement of the funded status as of December 31 for each of the last three years (in thousands of $):
2002
2001
2000
Pension Plans:
Change in benefit obligation
Benefit obligation at beginning of year
$
244,472
$
233,034
$
219,628
Service cost
2,637
2,761
4,312
Interest cost
16,598
17,534
17,205
Plan amendment
28
4
11,757
Change due to transfers
—
(16,827
)
—
Curtailment loss
—
1,400
—
Special termination benefits
—
24,274
—
Benefits paid
(23,291
)
(29,166
)
(16,512
)
Actuarial (gain) or loss and other
7,283
11,458
(3,356
)
Benefit obligation at end of year
$
247,727
$
244,472
$
233,034
Change in plan assets
Fair value of plans assets at beginning of year
$
216,947
$
244,677
$
274,109
Actual return on plan assets
(13,767
)
18,155
(10,943
)
Employer contributions and plan transfers
(99
)
(15,300
)
(994
)
Benefits paid
(23,291
)
(29,166
)
(16,512
)
Administrative expenses
(1,256
)
(1,419
)
(983
)
Fair value of plan assets at end of year
$
178,534
$
216,947
$
244,677
Reconciliation of funded status
Funded status
$
(69,193
)
$
(27,525
)
$
11,643
Unrecognized actuarial (gain) or loss
36,233
(20,581
)
(36,435
)
Unrecognized transition (asset) or obligation
(532
)
(664
)
(847
)
Unrecognized prior service cost
10,106
11,027
14,176
Net amount recognized at end of year
$
(23,386
)
$
(37,743
)
$
(11,463
)
Other Benefits:
Change in benefit obligation
Benefit obligation at beginning of year
$
83,223
$
64,213
$
54,201
Service cost
610
495
757
Interest cost
6,379
5,433
4,781
Plan amendments
—
—
7,127
Curtailment loss
—
6,381
—
Special termination benefits
—
3,824
—
Benefits paid net of retiree contributions
(4,640
)
(5,446
)
(4,318
)
Actuarial (gain) or loss
19,030
8,323
1,665
Benefit obligation at end of year
$
104,602
$
83,223
$
64,213
Change in plan assets
Fair value of plan assets at beginning of year
$
14,330
$
23,762
$
28,720
Actual return on plan assets
(2,698
)
(4,404
)
(1,162
)
Employer contributions and plan transfers
1,648
473
522
Benefits paid net of retiree contributions
(5,337
)
(5,501
)
(4,318
)
Fair value of plan assets at end of year
$
7,943
$
14,330
$
23,762
Reconciliation of funded status
Funded status
$
(96,659
)
$
(68,893
)
$
(40,451
)
Unrecognized actuarial (gain) or loss
22,667
(437
)
(23,561
)
Unrecognized transition (asset) or obligation
11,209
12,290
21,871
Unrecognized prior service cost
2,891
3,548
6,109
Net amount recognized at end of year
$
(59,892
)
$
(53,492
)
$
(36,032
)
116
There are no plan assets
consist primarilyin the non-qualified plan due to the nature ofequity investments.
The reconciliation of the funded status of the plans and the postretirement benefit liability recorded by Kentucky Utilities is as follows:As of December 31, (in thousands of dollars) 1994 1993 Accumulated postretirement benefit obligation:Retirees $ (31,992) $ (38,331) Fully eligible active plan participants (8,287) (8,448) Other active plan participants (25,578) (28,813) (65,857) (75,592) Plan assets at fair value 5,341 2,440 Accumulated postretirement benefit obligation in excess of plan assets (60,516) (73,152) Unrecognized net (gain)/loss from past experience different from that assumed (11,353) 3,230 Unrecognized transition obligation 60,142 63,483 Regulatory effect recorded - 689 Accrued postretirement benefit liability $ (11,727) $ (5,750)-36-Notesthe plan.KU made a contribution to
Financial Statements Kentucky Utilities Company
Components of the net periodic postretirement benefit cost are as follows:Year Ended December 31, (in thousands of dollars) 1994 1993 Service cost (benefits attributed to serviceduring the period) $ 2,105 $ 2,048 Interest cost on accumulated postretirement benefit obligation 4,926 5,730 Actual return on plan assets (80) - Net amortization and deferral (118) - Amortization of transition obligation 3,341 3,341 Regulatory effect recorded 689 (689) Net periodic postretirement benefit cost $ 10,863 $ 10,430-37-Notes to Financial Statements Kentucky Utilities Companythe pension plan of $3.5 million in January 2003.
Assumptions Used in Determining Actuarial Valuations: 1994 1993 Weighted average discount rate used todetermine the projected benefit obligation 8 1/4% 7 1/2% Rate of increase for compensation levels 5 1/2% 4 3/4% Weighted average expected long-term rate of return on assets 8 1/4% -The following tables provide the amounts recognized in the balance sheet and information for plans with benefit obligations in excess of plan assets as of December 31, 2002, 2001 and 2000 (in thousands of $):
2002
2001
2000
Pension Plans:
Amounts recognized in the balance sheet consisted of:
Accrued benefit liability
$
(51,035
)
$
(37,743
)
$
(11,463
)
Intangible asset
10,106
—
—
Accumulated other comprehensive income
17,543
—
—
Net amount recognized at year-end
$
(23,386
)
$
(37,743
)
$
(11,463
)
Additional year-end information for plans with accumulated benefit obligations in excess of plan assets (1):
Projected benefit obligation
$
247,727
$
244,472
$
1,505
Accumulated benefit obligation
229,569
224,261
336
Fair value of plan assets
178,534
216,947
—
(1) 2002 and 2001 includes all plans. 2000 includes SERPs only.
Other Benefits:
Amounts recognized in the balance sheet consisted of:
Accrued benefit liability
$
(59,892
)
$
(53,492
)
$
(36,032
)
Additional year-end information for plans with benefit obligations in excess of plan assets:
Projected benefit obligation
$
104,602
$
83,223
$
64,213
Fair value of plan assets
7,943
14,330
23,762
117
The following table provides the components of net periodic benefit cost for the plans for 2002, 2001 and 2000 (in thousands of $):
2002
2001
2000
Pension Plans:
Components of net periodic benefit cost
Service cost
$
2,637
$
2,761
$
4,312
Interest cost
16,598
17,534
17,205
Expected return on plan assets
(18,406
)
(19,829
)
(25,170
)
Amortization of transition (asset) or obligation
(133
)
(136
)
(141
)
Amortization of prior service cost
956
962
1,145
Recognized actuarial (gain) or loss
1
(120
)
(3,410
)
Net periodic benefit cost
$
1,653
$
1,172
$
(6,059
)
Special charges
Prior service cost recognized
$
—
$
1,238
$
—
Special termination benefits
—
24,274
—
Total charges
$
—
$
25,512
$
—
Other Benefits:
Components of net periodic benefit cost
Service cost
$
610
$
495
$
757
Interest cost
6,379
5,433
4,781
Expected return on plan assets
(1,022
)
(1,313
)
(1,768
)
Amortization of prior service cost
691
740
1,018
Amortization of transition (asset) or obligation
1,081
1,193
1,823
Recognized actuarial (gain) or loss
343
(40
)
(820
)
Net periodic benefit cost
$
8,082
$
6,508
$
5,791
Special charges
Transition obligation recognized
$
—
$
7,638
$
—
Prior service cost recognized
—
1,613
—
Special termination benefits
—
3,824
—
Total charges
$
—
$
13,075
$
—
The assumptions used in the measurement of KU’s pension benefit obligation are shown in the following table:
2002
2001
2000
Weighted-average assumptions as of December 31:
Discount rate
6.75
%
7.25
%
7.75
%
Expected long-term rate of return on plan assets
9.00
%
9.50
%
9.50
%
Rate of compensation increase
3.75
%
4.25
%
4.75
%
For measurement purposes, a
9%12.00% annualrate ofincrease in the per capita cost of covered health care benefitsiswas assumed for1995.2003. Thehealth care cost trendrateiswas assumed to decrease gradually to5.5% through 20035.00% for 2014 and remain at that levelthereafter overthereafter.Assumed health care cost trend rates have a significant effect on the
projected payout period ofamounts reported for thebenefits. Increasing thehealth care plans. A 1% change in assumed health care cost trend rates would have the following effects (in thousands of $):118
1% Decrease
1% Increase
Effect on total of service and interest cost components for 2002
(422
)
479
Effect on year-end 2002 postretirement benefit obligations
(7,010
)
7,972
Thrift Savings Plans. KU has a thrift savings plan under section 401(k) of the Internal Revenue Code. Under the plan, eligible employees may defer and contribute to the plan a portion of current compensation in order to provide future retirement benefits. KU makes contributions to the plan by matching a portion of the employee contributions. The costs of this matching were approximately $1.5 million for 2002, $1.4 million for 2001 and $2.5 million for 2000.
Note 7 - Income Taxes
Components of income tax expense are shown in the table below (in thousands of $):
2002
2001
2000
Included in operating expenses:
Current - federal
$
38,524
$
58,337
$
44,927
- state
10,494
13,465
9,333
Deferred - federal – net
3,467
(12,980
)
(3,254
)
- state – net
1,547
(1,340
)
957
Total
54,032
57,482
51,963
Included in other income - net:
Current - federal
(685
)
(948
)
349
- state
15
(268
)
67
Deferred - federal – net
(195
)
863
(122
)
- state – net
(88
)
222
(30
)
Amortization of investment tax credit
(2,955
)
(3,446
)
(3,674
)
Total
(3,908
)
(3,577
)
(3,410
)
Total income tax expense
$
50,124
$
53,905
$
48,553
Components of net deferred tax liabilities included in the balance sheet are shown below (in thousands of $):
2002
2001
Deferred tax liabilities:
Depreciation and other plant-related items
$
271,792
$
269,752
Other liabilities
30,378
33,376
302,170
303,128
Deferred tax assets:
Investment tax credit
3,431
4,623
Income taxes due to customers
11,609
13,263
Pensions
15,861
4,595
Accrued liabilities not currently deductible and other
30,085
41,443
60,986
63,924
Net deferred income tax liability
$
241,184
$
239,204
A reconciliation of differences between the statutory U.S. federal income tax rate and KU’s effective income tax
119
rate follows:
2002
2001
2000
Statutory federal income tax rate
35.0
%
35.0
%
35.0
%
State income taxes, net of federal benefit
5.5
5.4
4.9
Amortization of investment tax credit
(2.4
)
(2.3
)
(2.6
)
Other differences – net
(3.2
)
(2.2
)
(3.6
)
Effective income tax rate
34.9
%
35.9
%
33.7
%
The change in other differences is due to increased non-taxable earnings from an unconsolidated KU investment.
Note 8 - Other Income - net
Other income – net consisted of the following at December 31 (in thousands of $):
2002
2001
2000
Equity in earnings - subsidiary company
$
6,697
$
1,803
$
2,242
Interest and dividend income
641
1,368
1,206
Gains on fixed asset disposals
157
1,844
5
Income taxes and other
2,934
3,917
3,390
Other income – net
$
10,429
$
8,932
$
6,843
Note 9 - First Mortgage Bonds and Pollution Control Bonds
Long-term debt and the current portion of long-term debt, summarized below (in thousands of $), consists primarily of first mortgage bonds and pollution control bonds. Interest rates and maturities in the table below are for the amounts outstanding at December 31, 2002.
Stated
Interest Rates
Weighted
Average
Interest
Rate
Maturities
Principal
Amounts
Noncurrent portion
Variable - 8.55%
5.21
%
2006-2032
$
346,562
Current portion
Variable - 6.32%
3.58
%
2003-2032
$
153,930
Under the provisions for KU’s variable-rate pollution control bonds Series PCS 10, 12, 13, 14, and 15, the bonds are subject to tender for purchase at the option of the holder and to mandatory tender for purchase upon the occurrence of certain events, causing the bonds to be classified as current portion of long-term debt in the consolidated balance sheets. The average annualized interest rate for these bonds during 2002 was 1.58%.
In September 2002, KU issued $96 million variable rate pollution control Series 16 due October 1,
percentage point2032, and exercised its call option on $96 million, 7.45% pollution control Series 8 due September 15, 2016.In May 2002, KU issued $37.9 million variable rate pollution control Series 12, 13, 14 and 15 due February 1, 2032, and exercised its call option on $37.9 million, 6.25% pollution control Series 1B, 2B, 3B, and 4B due
120
February 1, 2018.
In May 2000, KU issued the Mercer County Solid Waste Disposal Facility Revenue Bonds, 2000 Series A variable rate debt, for $12.9 million. These proceeds were used to redeem $4 million PCB Series 7, 7.38% bonds and $8.9 million of PCB Series 7, 7.6% bonds. In June 2000, $61.5 million Series Q, 5.95% First Mortgage Bond matured and was paid in
each year would increasefull.KU’s First Mortgage Bond, 6.32% Series Q of $62 million is scheduled to mature in June 2003, KU’s First Mortgage Bond, 5.99% Series S of $36 million matures in 2006, and KU’s First Mortgage Bond, 7.92% Series P of $53 million matures in 2007. There are no scheduled maturities of Pollution Control Bonds for the
accumulated postretirement benefit obligationfive years subsequent to December 31, 2002.Substantially all of KU’s utility plant is pledged as security for its First Mortgage Bonds.
Note 10 - - Notes Payable to Parent
KU participates in an intercompany money pool agreement wherein LG&E Energy can make funds available to KU at market based rates up to $400 million. The balance of the money pool loan from LG&E Energy was $119.5 million at a rate of 1.61% and $47.8 million at an average rate of 2.37% at December 31, 2002 and 2001, respectively. The remaining money pool availability at December 31, 2002, was $280.5 million. LG&E Energy maintains facilities of $450 million with affiliates to ensure funding availability for the money pool. The outstanding balance under these facilities as of December 31,
1994, by $112002 was $230 million,(17%)andthe aggregateavailability ofthe service and interest cost components of the net periodic postretirement benefit cost for the year by $1.5$220 million(21%). 4.remained.Note 11 - Commitments and Contingencies
The effects of certain commitments made by Kentucky Utilities are estimated below:(in thousands of dollars) 1995 1996 1997 1998 1999 1995-1999 Estimated ConstructionExpenditures $122,900 $117,400 $105,600 $100,200 $ 75,000 $521,100 Estimated Contract Obligations: Fuel 136,400 79,700 66,100 29,100 20,800 332,100 Purchased power 24,800 26,100 27,100 26,700 26,400 131,100 Operating leases 3,100 3,100 3,000 3,000 3,000 15,200 Sinking Fund Requirements: First mortgage bonds $ 376 $ 376 $ 376 $ 376 $ 376 $ 1,880Construction
Program Kentucky Utilities frequently reviewsProgram. KU had approximately $6.2 million of commitments in connection with its construction program at December 31, 2002. Construction expenditures for the years 2003 andmay revise its projections2004 are estimated to total approximately $550.0 million; although all ofrelated expenditures based on revisions to its estimated load growththis is not currently committed, including the purchase of four jointly owned CTs, $152.0 million, andprojectionsconstruction of NOx equipment, $177.0 million.Operating Leases. KU leases office space, office equipment, and vehicles. KU accounts for these leases as operating leases. Total lease expense for 2002, 2001, and 2000, was $2.6 million, $2.8 million and $2.3 million, respectively.
In December 1999, LG&E and KU entered into an 18-year cross-border lease of its
future load. See Management's Discussiontwo jointly owned combustion turbines recently installed at KU’s Brown facility (units 6 andAnalysis7). KU’s obligation was defeased upon consummation ofFinancial Condition and Resultsthe cross-border lease. The transaction produced a pre-tax gain ofOperations - Construction Requirements forapproximately $1.9 million which was recorded in other income on the income statement in 2000, pursuant to adiscussion of future expenditures relating to construction of peaking units and compliance with the 1990Kentucky Commission order.Environmental. The Clean Air Act
Amendments. Coal Supply Obligations under Kentucky Utilities' coal purchase contracts are stated at prices effectiveimposed stringent new SO2 and NOx emission limits on electric generating units. KU met its Phase I SO2 requirements primarily through installation of a scrubber on Ghent Unit 1. KU’s strategy for Phase II SO2 reductions, which commenced January 1,1995,2000, is to use accumulated emissions allowances to delay additional capital expenditures and may also include fuel switching or the installation of additional scrubbers. KU met the NOx emission requirements of the Act through installation of low-NOx burner systems. KU’s compliance plans are subject tochanges as definedmany factors including developments in the emission allowance and fuel markets, future regulatory and legislative initiatives, and advances in clean air control121
technology. KU will continue to monitor these developments to ensure that its environmental obligations are met in the most efficient and cost-effective manner.
In September 1998, the EPA announced its final “NOx SIP Call” rule requiring states to impose significant additional reductions in NOx emissions by May 2003, in order to mitigate alleged ozone transport impacts on the
termsNortheast region. The Commonwealth of Kentucky is currently in the process of revising its SIP to require reductions in NOx emissions from coal-fired generating units to the 0.15 lb./Mmbtu level on a system-wide basis. In related proceedings in response to petitions filed by various Northeast states, in December 1999, EPA issued a final rule pursuant to Section 126 of thecontracts.Clean Air Act directing similar NOx reductions from a number of specifically targeted generating units including all KU units in the eastern half of Kentucky. Additional petitions currently pending before EPA may potentially result in rules encompassing KU’s remaining generating units. As a result of appeals to both rules, the compliance date was extended to May 2004. All KU generating units are subject to the May 2004 compliance date under these NOx emissions reduction rules.KU is currently implementing a plan for adding significant additional NOx controls to its generating units. Installation of additional NOx controls will proceed on a phased basis, with installation of controls commencing in late 2000 and continuing through the final compliance date. In addition, KU will incur additional operation and maintenance costs in operating new NOx controls. KU believes its costs in this regard to be comparable to those of similarly situated utilities with like generation assets. KU had anticipated that such capital and operating costs are the type of costs that are eligible for recovery from customers under its environmental surcharge mechanism and believed that a significant portion of such costs could be recovered. In April 2001, the Kentucky Commission granted recovery of these costs for KU.
KU is also monitoring several other air quality issues which may potentially impact coal-fired power plants, including the appeal of the D.C. Circuit’s remand of the EPA’s revised air quality standards for ozone and particulate matter, measures to implement EPA’s regional haze rule, and EPA’s December 2000 determination to regulate mercury emissions from power plants.
KU owns or formerly owned several properties that contained past MGP operations. Various contaminants are typically found at such former MGP sites and environmental remediation measures are frequently required. KU has completed the cleanup of a site owned by KU. With respect to other former MGP sites no longer owned by KU, KU is unaware of what, if any, additional exposure or liability it may have.
In October 1999, approximately 38,000 gallons of diesel fuel leaked from a cracked valve in an underground pipeline at KU’s E.W. Brown Station. Under the oversight of EPA and state officials, KU commenced immediate spill containment and recovery measures which prevented the spill from reaching the Kentucky River. KU ultimately recovered approximately 34,000 gallons of diesel fuel. In November 1999, the Kentucky Division of Water issued a notice of violation for the incident. KU is currently negotiating with the state in an effort to reach a complete resolution of this matter. KU incurred costs of approximately $1.8 million and received insurance reimbursement of $1.2 million. In December 2002, the Department of Justice (DOJ) sent correspondence to KU regarding a potential per-day fine for failure to timely submit a spill control plan and a per-gallon fine for the amount of oil discharged. KU and the DOJ have commenced settlement discussions using existing DOJ settlement guidelines on this matter.
In April 2002, the EPA sent correspondence to KU regarding potential exposure in connection with $1.5 million in completed remediation costs associated with a transformer scrap-yard. KU believes it is one of the more remote among a number of potentially responsible parties and has entered into settlement discussions with the EPA on this matter.
122
Purchased
Power Agreements -38-KU has purchase power arrangements with Notes to Financial Statements Kentucky Utilities Company Kentucky UtilitiesPower.Owensboro Municipal Utilities (OMU)OMU, EEI andElectric Energy, Inc. (EEI).other parties. Under the OMU agreement, which expires on January 1, 2020,Kentucky UtilitiesKU purchaseson an economic basis,all of the output of a400-MW400-Mw generating station not required by OMU. The amount of purchased power available toKentucky UtilitiesKU during1995-1999,2003-2007, which is expected to be approximately9%8% ofKentucky Utilities'KU’s total kWh native load energy requirements, is dependent upon a number of factors including theunits'units’ availability, maintenance schedules, fuel costs and OMU requirements. Payments are based on the total costs of the station allocated per terms of the OMU agreement, which generallyfollowsfollow delivered kWh. Included in the total costs isKentucky Utilities'KU’s proportionate share of debt service requirements on$27.3$149.6 million of OMU bonds outstanding at December 31,1994.2002. The debt service is allocated toKentucky UtilitiesKU based on its annual allocated share of capacity, which averaged approximately51%50% in1994. In 1995, Kentucky Utilities' total costs will increase to include its proportionate share of debt service requirements on approximately $176.9 million of additional OMU bonds issued to finance capital improvements designed to enable OMU to comply with the 1990 Clean Air Act Amendments. Kentucky Utilities2002.KU has a 20% equity ownership in EEI, which is accounted for on the equity method of accounting.
Kentucky Utilities'KU’s entitlementbeginning January 1, 1994,is 20% of the available capacity of a1,000-MW1,000 Mw station. Payments are based on the total costs of the station allocated per terms of an agreement among the owners, which generallyfollowsfollow delivered kWh.Sinking Fund Requirements Annual sinking fund requirementsKU has several other contracts for purchased power of various Mw capacities.
The estimated future minimum annual payments under purchased power agreements for the years subsequent to December 31, 2002, are as follows (in thousands of $):
2003
$
34,317
2004
39,653
2005
39,653
2006
39,884
2007
39,994
Thereafter
643,946
Total
$
837,447
Note 12 – Jointly Owned Electric Utility Plant
LG&E and KU jointly own the following combustion turbines (in thousands of $):
LG&E
KU
Total
Paddy’s Run 13
Ownership%
53
%
47
%
100
%
Mw capacity
84
74
158
Cost
$
33,919
$
29,973
$
63,892
Depreciation
1,711
1,499
3,210
Net book value
$
32,208
$
28,474
$
60,682
E.W. Brown 5
Ownership%
53
%
47
%
100
%
Mw capacity
71
63
134
Cost
$
23,973
$
21,106
$
45,079
Depreciation
1,206
1,052
2,258
Net book value
$
22,767
$
20,054
$
42,821
E.W. Brown 6
Ownership%
38
%
62
%
100
%
Mw capacity
59
95
154
Cost
$
23,696
$
36,957
$
60,653
Depreciation
1,770
4,201
5,971
Net book value
$
21,926
$
32,756
$
54,682
E.W. Brown 7
Ownership%
38
%
62
%
100
%
Mw capacity
59
95
154
Cost
$
23,607
$
44,792
$
68,399
Depreciation
4,054
4,502
8,556
Net book value
$
19,553
$
40,290
$
59,843
Trimble 5
Ownership%
29
%
71
%
100
%
Mw capacity
45
110
155
Cost
$
15,970
$
39,045
$
55,015
Depreciation
251
614
865
Net book value
$
15,719
$
38,431
$
54,150
Trimble 6
Ownership%
29
%
71
%
100
%
Mw capacity
45
110
155
Cost
$
15,961
$
39,025
$
54,986
Depreciation
251
614
865
Net book value
$
15,710
$
38,411
$
54,121
Trimble CT Pipeline
Ownership%
29
%
71
%
100
%
Cost
$
1,835
$
4,475
$
6,310
Depreciation
39
96
135
Net book value
$
1,796
$
4,379
$
6,175
123
See also Note 11, Construction Program, for KU’s planned purchase of four jointly owned CTs in 2004.
Note 13 - - Selected Quarterly Data (Unaudited)
Selected financial data for the four quarters of 2002 and 2001 are shown below. Because of seasonal fluctuations in temperature and other factors, results for quarters may fluctuate throughout the year.
Quarters Ended
March
June
September
December
(Thousands of $)
2002
Revenues
$
215,168
$
203,555
$
239,020
$
230,476
Net operating income
28,200
20,047
31,028
29,368
Net income
24,357
12,752
31,085
25,190
Net income available for common stock
23,793
12,188
30,521
24,626
2001
Revenues
$
211,793
$
219,360
$
216,370
$
211,949
Net operating income (loss)(a)
(344
)
28,422
30,253
63,039
Net income (loss)(a)
(7,995
)
22,080
26,340
55,989
Net income (loss) available for common stock(a)
(8,559
)
21,516
25,776
55,425
(a) Loss resulted from the VDT pre-tax charge of $64.0 million in March 2001, which $57.1 million was reversed in
124
December 2001. See Note 3.
Note 14 – Subsequent Events
In January 2003, the Kentucky
Utilities' first mortgage bondsCommission reviewed the FAC of KU for the six month period ended October 31, 2001. The Kentucky Commission ordered KU to reduce its fuel costs for purposes of calculating its FAC by $673,000. At issue was the purchase of approximately 102,000 tons of coal from Western Kentucky Energy Corporation, a non-regulated affiliate, for use at KU’s Ghent Facility. The Kentucky Commission further ordered that an independent audit be conducted to examine operational and management aspects of KU’s fuel procurement functions.On February 15, 2003, KU experienced a severe ice storm in Lexington, Kentucky, and surrounding service area causing over 140,000 customers to lose power. KU is still in the process of accumulating the costs of the storm. Costs relate to repair of transmission and distribution system, property damage, and significant labor costs, including contractor costs. A portion of the costs may be
metoffset by insurance proceeds.On March 18, 2003, the Kentucky Commission approved LG&E and KU's joint application for the acquisition of four CTs from an unregulated affiliate, LG&E Capital Corp. The total projected construction cost for the turbines, expected to be available for June 2004 in-service, is $227.4 million. The requested ownership share of the turbines is 63% for KU and 37% for LG&E.
125
Kentucky Utilities Company
REPORT OF MANAGEMENT
The management of Kentucky Utilities Company is responsible for the preparation and integrity of the financial statements and related information included in this Annual Report. These statements have been prepared in accordance with
cash or expenditures for bondable property as providedaccounting principles generally accepted in theMortgage Indenture.United States applied on a consistent basis and, necessarily, include amounts that reflect the best estimates and judgment of management.KU’s 2002 and 2001 financial statements have been audited by PricewaterhouseCoopers LLP, independent accountants and the 2000 financial statements were audited by Arthur Andersen LLP. Management made available to PricewaterhouseCoopers LLP and to Arthur Andersen LLP (in prior years) all KU’s financial records and related data as well as the minutes of shareholders’ and directors’ meetings.
Management has established and maintains a system of internal controls that provide reasonable assurance that transactions are completed in accordance with management’s authorization, that assets are safeguarded and that financial statements are prepared in conformity with generally accepted accounting principles. Management believes that an adequate system of internal controls is maintained through the selection and training of personnel, appropriate division of responsibility, establishment and communication of policies and procedures and by regular reviews of internal accounting controls by KU’s internal auditors. Management reviews and modifies its system of internal controls in light of changes in conditions and operations, as well as in response to recommendations from the internal and external auditors. These recommendations for the year ended December 31, 2002, did not identify any material weaknesses in the design and operation of KU’s internal control structure.
In carrying out its oversight role for the financial reporting and internal controls of KU, the Board of Directors meets regularly with KU’s independent public accountants, internal auditors and management. The Board of Directors reviews the results of the independent accountants’ audit of the financial statements and their audit procedures, and discusses the adequacy of internal accounting controls. The Board of Directors also approves the annual internal auditing program, and reviews the activities and results of the internal auditing function. Both the independent public accountants and the internal auditors have access to the Board of Directors at any time.
Kentucky Utilities
intendsCompany maintains and internally communicates a written code of business conduct that addresses, among other items, potential conflicts of interest, compliance with laws, including those relating tomeetfinancial disclosure, and the1995 sinking fund requirements with expenditures for bondable property. Linesconfidentiality ofCreditproprietary information.S. Bradford Rives
Senior Vice President-Finance and Controller
Kentucky Utilities
has aggregate bank linesCompanyLouisville, Kentucky
126
Kentucky Utilities Company and Subsidiary
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders of
creditKentucky Utilities Company and Subsidiary:In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of
$90 million,capitalization, income, retained earnings, cash flows and comprehensive income present fairly, in all material respects, the financial position ofwhich remained unusedKentucky Utilities Company and Subsidiary (the “Company”), a wholly-owned subsidiary of LG&E Energy Corp., at December 31,1994. A portion2002 and 2001, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of thesecredit lines ($30 million) expiresstatements inSeptember, 1995accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform thebalance ($60 million) expiresaudits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures inDecember, 1997. In support of these lines of credit,the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
January 21, 2003
Louisville, Kentucky
127
Kentucky Utilities
compensatesCompanyREPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the
banks by paying a commitment fee. 5. Common StockShareholders of Kentucky Utilitiesis subject to restrictions applicable to all corporations underCompany:We have audited the accompanying balance sheet and statement of capitalization of Kentucky Utilities Company (a Kentucky and Virginia
law oncorporation and a wholly-owned subsidiary of LG&E Energy Corp.) as of December 31, 2000, and theuserelated statements of income, retained earnings and cash flows forcash dividendseach of the two years in the period ended December 31, 2000. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion oncommon stock,these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as
those containedevaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, the financial statements referred to above present fairly, in
its Mortgage Indenture and Articlesall material respects, the financial position ofIncorporation. At December 31, 1994, there were no restricted retained earnings. 6. Preferred Stock -39-Notes to Financial StatementsKentucky Utilities CompanyIn December 1993, Kentucky Utilities issued 200,000 shares of 6.53% preferred stock. The proceeds were used to redeem 200,000 shares of 7.84% preferred stock on February 1, 1994.
Each series of preferred stock is redeemable at the option of Kentucky Utilities upon 30 days' written noticeasfollows:Redemption Price per Share Series (plus accrued and unpaid dividends, if any)4 3/4% $101.00 6.53% (Not redeemable prior to December 1, 2003.) $103.265 through November 30, 2004, decreasing approximately $.33 each twelve months thereafter to $100 on or after December 1, 2013.Asof December 31,1994, there2000, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States.Our audits were
5.3 million sharesmade for the purpose ofKentucky Utilities preferred stock, having a maximum aggregate stated value of $200 million, authorized for issuance. 7. Short-Term and Long-Term Debt Kentucky Utilities' short-term financing requirements are satisfied through the sale of commercial paper. The weighted average interest rateforming an opinion on theyear-end balance was 6.07%basic financial statements taken as a whole. The schedule listed under Item 14(a)2 is presented for1994. In 1993, Kentucky Utilities entered into a loan agreementpurposes of complying with theCounty of Carroll, Kentucky to finance the construction of solid waste disposal facilities. The County of Carroll issued $50 million of revenue bonds, with the proceeds held in a construction fund by a trustee. In 1994, Kentucky Utilities completed the draw downSecurities and Exchange Commission’s rules and is not part of theremaining $18.1 million revenue bond proceeds. In 1994, Kentucky Utilities entered into a loan agreement withbasic financial statements. This schedule has been subjected to theCounty of Carroll, Kentucky to financeauditing procedures applied in theconstruction of solid waste disposal facilities. The County of Carroll issued $54 million of variable rate revenue bonds, with the proceeds held in a construction fund. In 1994, Kentucky Utilities drew down $35.7 million relating to these bonds. Kentucky Utilities Pollution Control Series 10 Bonds are issued under Kentucky Utilities' Mortgage Indenture. Under the provisions for the variable rate revenue bonds, Kentucky Utilities can choose between various interest rate options. Currently, the daily interest rate mode is being utilized. The average annual interest rate on the bonds during 1994 was 4.10%. The variable rate bonds are subject to tender for purchase at the optionaudit of theholderbasic financial statements and, in our opinion, fairly states in all material respects the financial data required tomandatory tender for purchase uponbe set forth therein in relation to theoccurrence of certain events. If tendered bonds are not remarketed,basic financial statements taken as a whole.Arthur Andersen LLP
Louisville, Kentucky
Utilities has available lines of credit which may be used to repurchase the bonds. Substantially all of Kentucky Utilities' utility plant is pledged as security for the First Mortgage Bonds. -40-Notes to Financial Statements Kentucky Utilities Company 8. Financial Instruments The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value: Cash and cash equivalents, escrow funds, construction funds, short-term borrowings and customers' deposits carrying values approximate fair value because of the short maturity of these amounts. Long-term debt fair values are based on quoted market prices for Kentucky Utilities' first mortgage bonds and on current rates available to Kentucky Utilities for debt of the same remaining maturities for Kentucky Utilities' pollution control bonds and promissory note. Kentucky Utilities has an interest rate swap agreement with a notional amount of $70 million. Fair value of this instrument is the estimated amount the counter-party would pay to Kentucky Utilities to terminate the swap at the date of measurement. This agreement expires in 1996. Kentucky Utilities has no downside interest rate risk associated with this agreement.
The estimated fair values of Kentucky Utilities' financial instruments at December 31 are as follows: 1994 1993Carrying Estimated Carrying Estimated (in thousands of dollars) Amount Fair Value Amount Fair ValueInterest rate swap $ - $ 1,550 $ - $ 2,550 Long-term debt $ 496,033 $ 475,976 $ 442,066 $ 489,042If the difference between fair value and carrying value of Kentucky Utilities' long-term debt was settled at amounts approximating those above, the anticipated regulatory treatment would require return of or allow recovery of these amounts in rates over a prescribed amortization period. Accordingly, any settlement would not have a significant impact on Kentucky Utilities' financial position or results of operations. -41-Supplementary Quarterly Financial Information (Unaudited) Kentucky Utilities Company Quarterly financial results for 1994 and 1993 are summarized below. Generally, quarterly results may fluctuate due to seasonal variations, changes in fuel costs and other factors. Operating revenues for the third quarter of 1994 were reduced by $17.5 million related to refunds to customers of fuel cost savings associated with the resolution of a coal contract dispute. Operating revenues for other quarters were insignificantly impacted by the refunds. Refer to Note 1 of the Notes to Financial Statements for additional information.
Quarter 4th 3rd 2nd 1st (in thousands of dollars) 1994Operating Revenues $ 159,586 $ 156,512 $ 154,026 $ 166,528 Net Operating Income 20,835 29,737 20,034 30,580 Net Income 14,053 23,642 14,473 25,344 Net Income Applicable to Common Stock 13,489 23,078 13,909 24,652 1993 Operating Revenues $ 151,828 $ 160,615 $ 139,909 $ 154,236 Net Operating Income 21,257 30,640 22,209 31,155 Net Income 15,526 24,790 16,422 24,548 Net Income Applicable to Common Stock 14,856 24,161 15,792 23,919 These quarterly amounts reflect, in Kentucky Utilities' opinion, all adjustments (including only normal recurring adjustments) necessary for a fair presentation.-42-ItemJanuary 26, 2001
THIS IS A COPY OF A PREVIOUSLY ISSUED REPORT OF ARTHUR ANDERSEN LLP (“ANDERSEN”) RELATING TO A PRIOR PERIOD FOR WHICH ANDERSEN WAS ENGAGED AS INDEPENDENT PUBLIC ACCOUNTANTS. THE REPORT HAS NOT BEEN REISSUED BY ANDERSEN.
128
Not applicable.
ITEMS 10, 11, 12 and
Executive Officers13 are omitted pursuant to General Instruction G of Form 10-K. The information required by ITEMS 10, 11, 12 and 13 for LG&E and KU are set forth in Exhibit 99.2 filed herewith and incorporated herein by reference. Additionally, in accordance with General Instruction G, theRegistrant Referinformation required by ITEM 10 relating to executive officers of LG&E and KUEnergy's definitive proxy statement (the "Proxy Statement") filed withhas been included in Part I of this Form 10-K.ITEM 14. Controls and Procedures
LG&E and KU maintain a system of disclosure controls and procedures designed to ensure that information required to be disclosed by the companies in reports they file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission
in connection with its 1995 Annual Shareholder Meetingrules and forms. During the 90 day period preceding the filing of this report, LG&E and KU conducted an evaluation of such controls and procedures under thecaption "Electionsupervision and the participation ofDirectors--General" fortheinformation required by this item pertainingcompanies’ Management, including the Chairman, President and Chief Executive Officer (“CEO”) and the Chief Financial Officer (“CFO”). Based upon that evaluation, the CEO and CFO are of the conclusion that the companies’ disclosure controls and procedures are effective. With respect todirectors. Such information is incorporated herein by referenceLG&E’s andis also filed herewith as Exhibit 99B. Information required by this item relatingKU’s internal controls, there have been no significant changes in internal controls or in other factors that could significantly affect these controls subsequent toexecutive officersthe date ofKentucky Utilities is set forth under a separate caption in Part I hereof. Item 11. Executive Compensation Refertheir most recent evaluation, including any corrective actions with regard toKU Energy's Proxy Statement under the caption "Election of Directors -- Directors' Compensation,significant deficiencies and-- Executive Compensation" (but excluding any information contained under the subheadings -- "Report of Compensation Committee on Executive Compensation", and -- "Performance Graph") for the information required by this item. Such information is incorporated herein by reference and is also filed herewith as Exhibit 99B. Item 12. Security Ownership of Certain Beneficial Owners and Management Refer to KU Energy's Proxy Statement under the caption "Election of Directors--Voting Securities Beneficially Owned by Directors, Nominees and Executive Officers; Other Information" for the information required by this item. Such information is incorporated herein by reference and is also filed herewith as Exhibit 99B. Item 13. Certain Relationships and Related Transactions None. -43-PART IV Item 14.material weaknesses.ITEM 15. Exhibits, Financial Statement Schedules, and Reports on Form
8-K (A) The following (1) financial statements, (2)8-K.
(a)
1.
Financial Statements (included in Item 8):
LG&E:
Consolidated statements of income for the three years ended December 31, 2002 (page 70).
Consolidated statements of retained earnings for the three years ended December 31, 2002 (page 70).
Consolidated statements of comprehensive income for the three years ended December 31, 2002 (page 71).
Consolidated balance sheets-December 31, 2002, and 2001 (page 72).
Consolidated statements of cash flows for the three years ended December 31, 2002 (page 73).
Consolidated statements of capitalization-December 31, 2002, and 2001 (page 74).
Notes to consolidated financial statements (pages 75-96).
Report of management (page 97).
Reports of independent accountants (pages 98-99).
KU:
Consolidated statements of income for the three years ended December 31, 2002 (page 102).
Consolidated statements of retained earnings for the three years ended December 31, 2002 (page 102).
Consolidated statements of comprehensive income for the three years ended December 31, 2002 (page 103).
129
Consolidated balance sheets-December 31, 2002, and 2001 (page 104).
Consolidated statements of cash flows for the three years ended December 31, 2002 (page 105).
Consolidated statements of capitalization-December 31, 2002, and 2001 (page 106).
Notes to consolidated financial statements (pages 107-125).
Report of management (page 126).
Reports of independent accountants (pages 127-128).
2.
Financial Statement Schedules (included in Part IV):
Schedule II
Valuation and Qualifying Accounts for the three years ended December 31, 2002, for LG&E (page 150), and KU (page 152).
All other schedules have been omitted as not applicable or not required or because the information required to be shown is included in the Financial Statements or the accompanying Notes to Financial Statements.
3. Exhibits:
Exhibit
No.Applicable to Form
10-K ofDescription
LG&E
KU
2.01
ý
ý
Copy of Agreement and Plan of Merger, dated as of February 27, 2000, by and among Powergen plc, LG&E Energy Corp., US Subholdco2 and Merger Sub, including certain exhibits thereto. [Filed as Exhibit 1 to LG&E’s and KU’s Current Report on Form 8-K filed February 29, 2000 and incorporated by reference herein]
2.02
ý
ý
Amendment No. 1 to Agreement and Plan of Merger, dated as of December 8, 2000, among LG&E Energy Corp., Powergen plc, Powergen US Investments Corp. and Powergen Acquisition Corp. [Filed as Exhibit 2.01 to LG&E’s and KU’s Current Report on Form 8-K filed December 11, 2000 and incorporated by reference herein]
2.03
ý
ý
Copy of Agreement and Plan of Merger, dated as of May 20, 1997, by and between LG&E Energy and KU Energy, including certain exhibits thereto. [Filed as Exhibit 2 to LG&E’s and KU’s Current Report on Form 8-K filed May 30, 1997 and incorporated by reference herein]
3.01
ý
Copy of Restated Articles of Incorporation of LG&E, dated November 6, 1996. [Filed as Exhibit 3.06 to LG&E Quarterly Report on Form 10-Q for the quarter ended September 30, 1996, and incorporated by reference herein]
3.02
ý
Copy of By-Laws of LG&E, as amended through June 2, 1999 [Filed as Exhibit 3.02 to LG&E’s Annual Report on Form 10-K for the year ended
130
Applicable to Form
10-K ofExhibit
No.LG&E
KU
Description
December 31, 1999, and incorporated by reference herein]
3.03
ý
Copy of Amended and Restated Articles of Incorporation of KU [Filed as Exhibits 4.03 and 4.04 to Form 8-K Current Report of KU, dated December 10, 1993, and incorporated by reference herein]
3.04
ý
Copy of By-Laws of KU, as amended through June 2, 1999. [Filed as Exhibit 3.04 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated by reference herein]
4.01
ý
Copy of Trust Indenture dated November 1, 1949, from LG&E to Harris Trust and Savings Bank, Trustee. [Filed as Exhibit 7.01 to LG&E’s Registration Statement 2-8283 and incorporated by reference herein]
4.02
ý
Copy of Supplemental Indenture dated February 1, 1952, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.05 to LG&E’s Registration Statement 2-9371 and incorporated by reference herein]
4.03
ý
Copy of Supplemental Indenture dated February 1, 1954, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.03 to LG&E’s Registration Statement 2-11923 and incorporated by reference herein]
4.04
ý
Copy of Supplemental Indenture dated September 1, 1957, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.04 to LG&E’s Registration Statement 2-17047 and incorporated by reference herein]
4.05
ý
Copy of Supplemental Indenture dated October 1, 1960, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.05 to LG&E’s Registration Statement 2-24920 and incorporated by reference herein]
4.06
ý
Copy of Supplemental Indenture dated June 1, 1966, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.06 to LG&E’s Registration Statement 2-28865 and incorporated by reference herein]
4.07
ý
Copy of Supplemental Indenture dated June 1, 1968, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.07 to LG&E’s Registration Statement 2-37368 and incorporated by reference herein]
131
Applicable to Form
10-K ofExhibit
No.LG&E
KU
Description
4.08
ý
Copy of Supplemental Indenture dated June 1, 1970, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.08 to LG&E’s Registration Statement 2-37368 and incorporated by reference herein]
4.09
ý
Copy of Supplemental Indenture dated August 1, 1971, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.09 to LG&E’s Registration Statement 2-44295 and incorporated by reference herein]
4.10
ý
Copy of Supplemental Indenture dated June 1, 1972, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.10 to LG&E’s Registration Statement 2-52643 and incorporated by reference herein]
4.11
ý
Copy of Supplemental Indenture dated February 1, 1975, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.11 to LG&E’s Registration Statement 2-57252 and incorporated by reference herein]
4.12
ý
Copy of Supplemental Indenture dated September 1, 1975, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.12 to LG&E’s Registration Statement 2-57252 and incorporated by reference herein]
4.13
ý
Copy of Supplemental Indenture dated September 1, 1976, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.13 to LG&E’s Registration Statement 2-57252 and incorporated by reference herein]
4.14
ý
Copy of Supplemental Indenture dated October 1, 1976, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.14 to LG&E’s Registration Statement 2-65271 and incorporated by reference herein]
4.15
ý
Copy of Supplemental Indenture dated June 1, 1978, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.15 to LG&E’s Registration Statement 2-65271 and incorporated by reference herein]
4.16
ý
Copy of Supplemental Indenture dated February 15, 1979, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.16 to
132
Applicable to Form
10-K ofExhibit
No.LG&E
KU
Description
LG&E’s Registration Statement 2-65271 and incorporated by reference herein]
4.17
ý
Copy of Supplemental Indenture dated September 1, 1979, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.17 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1980, and incorporated by reference herein]
4.18
ý
Copy of Supplemental Indenture dated September 15, 1979, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.18 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1980, and incorporated by reference herein]
4.19
ý
Copy of Supplemental Indenture dated September 15, 1981, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.19 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1981, and incorporated by reference herein]
4.20
ý
Copy of Supplemental Indenture dated March 1, 1982, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.20 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1982, and incorporated by reference herein]
4.21
ý
Copy of Supplemental Indenture dated March 15, 1982, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.21 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1982, and incorporated by reference herein]
4.22
ý
Copy of Supplemental Indenture dated September 15, 1982, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.22 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1982, and incorporated by reference herein]
4.23
ý
Copy of Supplemental Indenture dated February 15, 1984, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.23 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1984, and incorporated by reference herein]
4.24
ý
Copy of Supplemental Indenture dated July 1, 1985, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.24 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1985, and incorporated by reference herein]
133
Applicable to Form
10-K ofExhibit
No.LG&E
KU
Description
4.25
ý
Copy of Supplemental Indenture dated November 15, 1986, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.25 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1986, and incorporated by reference herein]
4.26
ý
Copy of Supplemental Indenture dated November 16, 1986, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.26 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1986, and incorporated by reference herein]
4.27
ý
Copy of Supplemental Indenture dated August 1, 1987, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.27 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1987, and incorporated by reference herein]
4.28
ý
Copy of Supplemental Indenture dated February 1, 1989, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.28 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1988, and incorporated by reference herein]
4.29
ý
Copy of Supplemental Indenture dated February 2, 1989, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.29 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1988, and incorporated by reference herein]
4.30
ý
Copy of Supplemental Indenture dated June 15, 1990, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.30 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1990, and incorporated by reference herein]
4.31
ý
Copy of Supplemental Indenture dated November 1, 1990, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.31 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1990, and incorporated by reference herein]
4.32
ý
Copy of Supplemental Indenture dated September 1, 1992, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.32 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein]
4.33
ý
Copy of Supplemental Indenture dated September 2, 1992, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.33 to LG&E’s Annual Report on Form 10-K for the year ended December 31,
134
Applicable to Form
10-K ofExhibit
No.LG&E
KU
Description
1992, and incorporated by reference herein]
4.34
ý
Copy of Supplemental Indenture dated August 15, 1993, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.34 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
4.35
ý
Copy of Supplemental Indenture dated August 16, 1993, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.35 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
4.36
ý
Copy of Supplemental Indenture dated October 15, 1993, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.36 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
4.37
ý
Copy of Supplemental Indenture dated May 1, 2000, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.37 to LG&E’s Annual Report on Form 10-K/A for the year ended December 31, 2000, and incorporated by reference herein]
4.38
ý
Copy of Supplemental Indenture dated August 1, 2000, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.38 to LG&E’s Annual report on Form 10-K/A for the year ended December 31, 2000, and incorporated by reference herein]
4.39
ý
Copy of Supplemental Indenture dated March 1, 2002, which is a supplemental instrument to Exhibit 4.01 hereto.
4.40
ý
Copy of Supplemental Indenture dated March 15, 2002, which is a supplemental instrument to Exhibit 4.01 hereto.
4.41
ý
Copy of Supplemental Indenture dated October 1, 2002, which is a supplemental instrument to Exhibit 4.01 hereto.
4.42
ý
Indenture of Mortgage or Deed of Trust dated May 1, 1947, between KU and First Trust National Association (successor Trustee) and a successor individual co-trustee, as Trustees (the Trustees) (Amended Exhibit 7(a) in File No. 2-7061), and Supplemental Indentures thereto dated, respectively, January 1, 1949 (Second Amended Exhibit 7.02 in File No. 2-7802), July 1, 1950 (Amended Exhibit 7.02 in File No. 2-8499), June 15, 1951 (Exhibit 7.02(a) in File No. 2-8499), June 1, 1952 (Amended
135
Applicable to Form
10-K ofExhibit
No.LG&E
KU
Description
Exhibit 4.02 in File No. 2-9658), April 1, 1953 (Amended Exhibit 4.02 in File No. 2-10120), April 1, 1955 (Amended Exhibit 4.02 in File No. 2-11476), April 1, 1956 (Amended Exhibit 2.02 in File No. 2-12322), May 1, 1969 (Amended Exhibit 2.02 in File No. 2-32602), April 1, 1970 (Amended Exhibit 2.02 in File No. 2-36410), September 1, 1971 (Amended Exhibit 2.02 in File No. 2-41467), December 1, 1972 (Amended Exhibit 2.02 in File No. 2-46161), April 1, 1974 (Amended Exhibit 2.02 in File No. 2-50344), September 1, 1974 (Exhibit 2.04 in File No. 2-59328), July 1, 1975 (Exhibit 2.05 in File No. 2-59328), May 15, 1976 (Amended Exhibit 2.02 in File No. 2-56126), April 15, 1977 (Exhibit 2.06 in File No. 2-59328), August 1, 1979 (Exhibit 2.04 in File No. 2-64969), May 1, 1980 (Exhibit 2 to Form 10-Q Quarterly Report of KU for the quarter ended June 30, 1980), September 15, 1982 (Exhibit 4.04 in File No. 2-79891), August 1, 1984 (Exhibit 4B to Form 10-K Annual Report of KU for the year ended December 31, 1984), June 1, 1985 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended June 30, 1985), May 1, 1990 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended June 30, 1990), May 1, 1991 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended June 30, 1991), May 15, 1992 (Exhibit 4.02 to Form 8-K of KU dated May 14, 1992), August 1, 1992 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended September 30, 1992), June 15, 1993 (Exhibit 4.02 to Form 8-K of KU dated June 15, 1993) and December 1, 1993 (Exhibit 4.01 to Form 8-K of KU dated December 10, 1993), November 1, 1994 (Exhibit 4.C to Form 10-K Annual Report of KU for the year ended December 31, 1994), June 1, 1995 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended June 30, 1995) and January 15, 1996 [Filed as Exhibit 4.E to Form 10-K Annual Report of KU for the year ended December 31, 1995, and incorporated by reference herein]
4.43
ý
Copy of Supplemental Indenture dated March 1, 1992 between KU and the Trustees, providing for the conveyance of properties formerly held by Old Dominion Power Company [Filed as Exhibit 4B to Form 10-K Annual Report of KU for the year ended December 31, 1992, and incorporated by reference herein]
4.44
ý
Copy of Supplemental Indenture dated May 1, 2000, which is a supplemental instrument to Exhibit 4.42 hereto. [Filed as Exhibit 4.41 to KU’s Annual Report on Form 10-K for the year ended December 31, 2000, and incorporated by reference herein]
4.45
ý
Copy of Supplemental Indenture dated September 1, 2001, which is a supplemental instrument to Exhibit 4.42 hereto. [Filed as Exhibit 4.42 to
136
Applicable to Form
10-K ofExhibit
No.LG&E
KU
Description
KU’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
4.46
ý
Receivables Purchase Agreement dated as of February 6, 2001 among KU Receivables LLC, Kentucky Utilities Company as Servicer, the Various Purchaser Groups From Time to Time Party Hereto and PNC Bank, National Association, as Administrator. [Filed as Exhibit 4.43 to KU’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
4.47
ý
Purchase and Sale Agreement dated as of February 6, 2001 between KU Receivables LLC and Kentucky Utilities Company. [Filed as Exhibit 4.44 to KU’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
4.48
ý
Receivables Purchase Agreement dated as of February 6, 2001 among LG&E Receivables LLC, Louisville Gas and Electric Company as Servicer, the Various Purchaser Groups From Time to Time Party Hereto and PNC Bank, National Association, as Administrator. [Filed as Exhibit 4.45 to KU’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
4.49
ý
Purchase and Sale Agreement dated as of February 6, 2001 between LG&E Receivables LLC and Louisville Gas and Electric Company. [Filed as Exhibit 4.46 to KU’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
4.50
ý
Copy of Supplemental Indenture dated May 1, 2002, which is a supplemental instrument to Exhibit 4.42 hereto.
4.51
ý
Copy of Supplemental Indenture dated September 1, 2002, which is a supplemental instrument to Exhibit 4.42 hereto.
10.01
ý
Copies of Agreement between Sponsoring Companies re: Project D of Atomic Energy Commission, dated May 12, 1952, Memorandums of Understanding between Sponsoring Companies re: Project D of Atomic Energy Commission, dated September 19, 1952 and October 28, 1952, and Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission, dated October 15, 1952. [Filed as Exhibit 13(y) to LG&E’s Registration Statement 2-9975 and incorporated by reference herein]
10.02
ý
Copy of Modification No. 1 dated July 23, 1953, to the Power Agreement
137
Applicable to Form
10-K ofExhibit
No.LG&E
KU
Description
between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 4.03(b) to LG&E’s Registration Statement 2-24920 and incorporated by reference herein]
10.03
ý
Copy of Modification No. 2 dated March 15, 1964, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 5.02c to LG&E’s Registration Statement 2-61607 and incorporated by reference herein]
10.04
ý
Copy of Modification No. 3 and No. 4 dated May 12, 1966 and January 7, 1967, respectively, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibits 4(a)(13) and 4(a)(14) to LG&E’s Registration Statement 2-26063 and incorporated by reference herein]
10.05
ý
Copy of Modification No. 5 dated August 15, 1967, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 13(c) to LG&E’s Registration Statement 2-27316 and incorporated by reference herein]
10.06
ý
ý
Copies of (i) Inter-Company Power Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies (which Agreement includes as Exhibit A the Power Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation); (ii) First Supplementary Transmission Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies; (iii) Inter-Company Bond Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies; (iv) Inter-Company Bank Credit Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 5.02f to LG&E’s Registration Statement 2-61607 and incorporated by reference herein]
10.07
ý
ý
Copy of Modification No. 1 and No. 2 dated June 3, 1966 and January 7, 1967, respectively, to Inter-Company Power Agreement dated July 10, 1953. [Filed as Exhibits 4(a)(8) and 4(a)(10) to LG&E’s Registration Statement 2-26063 and incorporated by reference herein]
10.08
ý
Copies of Amendments to Agreements (iii) and (iv) referred to under 10.06 above as follows: (i) Amendment to Inter-Company Bond Agreement and (ii) Amendment to Inter-Company Bank Credit Agreement. [Filed as Exhibit 5.02h to LG&E’s Registration Statement 2-61607 and incorporated by reference herein]
138
Applicable to Form
10-K ofExhibit
No.LG&E
KU
Description
10.09
ý
Copy of Modification No. 1, dated August 20, 1958, to First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 5.02i to LG&E’s Registration Statement 2-61607 and incorporated by reference herein]
10.10
ý
Copy of Modification No. 2, dated April 1, 1965, to the First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 5.02j to LG&E’s Registration Statement 2-61607 and incorporated by reference herein]
10.11
ý
Copy of Modification No. 3, dated January 20, 1967, to First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 4(a)(7) to LG&E’s Registration Statement 2-26063 and incorporated by reference herein]
10.12
ý
Copy of Modification No. 6 dated November 15, 1967, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 4(g) to LG&E’s Registration Statement 2-28524 and incorporated by reference herein]
10.13
ý
ý
Copy of Modification No. 3 dated November 15, 1967, to the Inter-Company Power Agreement dated July 10, 1953. [Filed as Exhibit 4.02m to LG&E’s Registration Statement 2-37368 and incorporated by reference herein]
10.14
ý
Copy of Modification No. 7 dated November 5, 1975, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 5.02n to LG&E’s Registration Statement 2-56357 and incorporated by reference herein]
10.15
ý
ý
Copy of Modification No. 4 dated November 5, 1975, to the Inter-Company Power Agreement dated July 10, 1953. [Filed as Exhibit 5.02o to LG&E’s Registration Statement 2-56357 and incorporated by reference herein]
10.16
ý
Copy of Modification No. 4 dated April 30, 1976, to First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 5.02p to LG&E’s Registration Statement 2-61607 and incorporated by
139
Applicable to Form
10-K ofExhibit
No.LG&E
KU
Description
reference herein]
10.17
ý
Copy of Modification No. 8 dated June 23, 1977, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 5.02q to LG&E’s Registration Statement 2-61607 and incorporated by reference herein]
10.18
ý
Copy of Modification No. 9 dated July 1, 1978, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 5.02r to LG&E’s Registration Statement 2-63149 and incorporated by reference herein]
10.19
ý
Copy of Modification No. 10 dated August 1, 1979, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 2 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1979, and incorporated by reference herein]
10.20
ý
Copy of Modification No. 11 dated September 1, 1979, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 3 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1979, and incorporated by reference herein]
10.21
ý
ý
Copy of Modification No. 5 dated September 1, 1979, to Inter-Company Power Agreement dated July 5, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 4 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1979, and incorporated by reference herein]
10.22
ý
Copy of Modification No. 12 dated August 1, 1981, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 10.25 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1981, and incorporated by reference herein]
10.23
ý
ý
Copy of Modification No. 6 dated August 1, 1981, to Inter-Company Power Agreement dated July 5, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 10.26 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1981, and incorporated by reference herein]
10.24
ý
* Copy of Non-Qualified Savings Plan covering officers of the Company,
140
Applicable to Form
10-K ofExhibit
No.LG&E
KU
Description
effective January 1, 1992. [Filed as Exhibit 10.43 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein]
10.25
ý
Copy of Modification No. 13 dated September 1, 1989, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 10.42 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.26
ý
Copy of Modification No. 14 dated January 15, 1992, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 10.43 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.27
ý
ý
Copy of Modification No. 7 dated January 15, 1992, to Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 10.44 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.28
ý
Copy of Modification No. 15 dated February 15, 1993, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 10.45 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.29
ý
Copies of Firm No-Notice Transportation Agreements each effective November 1, 1993, between Texas Gas Transmission Corporation and LG&E (expiring October 31, 2000, 2001 and 2003) covering the transmission of natural gas. [All filed as Exhibit 10.47 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.30
ý
ý
Copy of Modification No. 8 dated January 19, 1994, to Inter-Company Power Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 10.43 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.31
ý
Copy of Amendment dated March 1, 1995, to Firm No-Notice Transportation Agreements dated November 1, 1993 (2-Year, 5-Year and 8-Year),
141
Applicable to Form
10-K ofExhibit
No.LG&E
KU
Description
between Texas Gas Transmission Corporation and LG&E covering the transmission of natural gas. [Filed as Exhibit 10.44 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.32
ý
ý
Copy of Modification No. 9, dated August 17, 1995, to the Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 10.39 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1996, and incorporated by reference herein]
10.34
ý
Copies of Firm Transportation Agreements, each dated March 1, 1995, between Texas Gas Transmission Corporation and LG&E (expiring October 31, 2001 and 2003) covering the transportation of natural gas. [Both filed as Exhibit 10.45 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.35
ý
Copy of Firm Transportation Agreement, dated March 1, 1995, between Texas Gas Transmission Corporation and LG&E (expires October 31, 2000) covering the transportation of natural gas. [Filed as Exhibit 10.41 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1996, and incorporated by reference herein]
10.36
ý
* Copy of Amendment to the Non-Qualified Savings Plan, effective January 1, 1992. [Filed as Exhibit 10.55 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.37
ý
* Copy of Amendment to the Non-Qualified Savings Plan, effective January 1, 1995. [Filed as Exhibit 10.56 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.38
ý
* Copy of Amendment to the Non-Qualified Savings Plan, effective January 1, 1995. [Filed as Exhibit 10.57 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.39
ý
ý
* Copy of Supplemental Executive Retirement Plan as amended through January 1, 1998, covering officers of LG&E Energy. [Filed as Exhibit 10.74 to LG&E Energy’s Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated by reference herein]
142
Applicable to Form
10-K ofExhibit
No.LG&E
KU
Description
10.40
ý
Copy of Coal Supply Agreement between LG&E and Kindill Mining, Inc., dated July 1, 1997. [Filed as Exhibit 10.76 to LG&E Energy’s Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated by reference herein]
10.41
ý
Copies of Amendments dated September 23, 1997, to Firm No-Notice Transportation Agreements dated November 1, 1993, between Texas Gas Transmission Corporation and LG&E, as amended. [Filed as Exhibit 10.81 to LG&E Energy’s Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated by reference herein]
10.42
ý
Copies of Amendments dated September 23, 1997, to Firm Transportation Agreements dated March 1, 1995, between Texas Gas Transmission Corporation and LG&E, as amended. [Filed as Exhibit 10.82 to LG&E Energy’s Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated by reference herein]
10.43
ý
ý
Copy of Coal Supply Agreement between LG&E and KU and Black Beauty Coal Company, dated as of January 1, 2002, covering the purchase of coal. [Filed as Exhibit 10.51 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
10.44
ý
ý
Copy of Coal Supply Agreement between LG&E and KU and McElroy Coal Company, Consolidation Coal Company, Consol Pennsylvania Coal Company, Greenon Coal Company, Nineveh Coal Company, Eighty Four Mining Company and Island Creek Coal Company, dated as of January 1, 2000, and Amendment No. 1 dated as of January 1, 2002, for the purchase of coal. [Filed as Exhibit 10.52 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
10.45
ý
Copy of Coal Supply Agreement between KU and Arch Coal Sales Company, Inc., as agent for the independent operating subsidiaries of Arch Coal, Inc., dated as of July 22, 2001, for the purchase of coal. [Filed as Exhibit 10.53 to KU’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
10.46
ý
Copy of Coal Supply Agreement between LG&E and Hopkins County Coal, LLC and Alliance Coal Sales, a division of Alliance Coal, LLC, dated as of January 1, 2002, for the purchase of coal. [Filed as Exhibit 10.54 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
143
Applicable to Form
10-K ofExhibit
No.LG&E
KU
Description
10.47
ý
Copy of Coal Supply Agreement between KU and Arch Coal Sales Company, Inc., as agent for the independent operating subsidiaries of Arch Coal, Inc., dated as of August 12, 2001, for the purchase of coal. [Filed as Exhibit 10.55 to KU’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
10.48
ý
Copy of Purchase Order dated December 26, 2000, by and between Kentucky Utilities Company and AEI Coal Sales Company, Inc., for the purchase of coal, commencing January 1, 2001. [Filed as Exhibit 10.56 to KU’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
10.49
ý
Copy of Amendment dated November 6, 2000, to Firm Transportation Agreement between LG&E and Texas Gas Transmission Corporation covering the transmission of natural gas (expires October 31, 2006). [Filed as Exhibit 10.57 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
10.50
ý
Copy of Amendment dated November 6, 2000, to Firm Transportation Agreement between LG&E and Texas Gas Transmission Corporation covering the transmission of natural gas (expires October 31, 2008). [Filed as Exhibit 10.58 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
10.51
ý
Copy of Amendment dated November 6, 2000, to Firm No-Notice Transportation Agreement between LG&E and Texas Gas Transmission Corporation covering the transmission of natural gas (expires October 31, 2006). [Filed as Exhibit 10.59 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
10.52
ý
Copy of Amendment dated September 15, 1999, to Firm Transportation Agreement between LG&E and Texas Gas Transmission Corporation covering the transmission of natural gas (expires October 31, 2006). [Filed as Exhibit 10.60 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
10.53
ý
ý
* Copy of Amendment to LG&E Energy’s Supplemental Executive Retirement Plan, effective September 2, 1998. [Filed as Exhibit 10.90 to LG&E Energy’s Annual Report on Form 10-K for the year ended December 31, 1998 and incorporated by reference herein]
144
Applicable to Form
10-K ofExhibit
No.LG&E
KU
Description
10.54
ý
ý
* Copy of Employment and Severance Agreement, dated as of February 25, 2000, by and among LG&E Energy, Powergen plc and an executive officer of the Company.
10.55
ý
ý
* Copy of Amendment, effective October 1, 1999, to LG&E Energy’s Non-Qualified Savings Plan. [Filed as Exhibit 10.96 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated by reference herein]
10.56
ý
ý
* Copy of Amendment, effective December 1, 1999, to LG&E Energy’s Non-Qualified Savings Plan. [Filed as Exhibit 10.97 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated by reference herein]
10.57
ý
ý
Copy of Modification No. 10, dated January 1, 1998, to the Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 10.102 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated by reference herein]
10.58
ý
ý
Copy of Modification No. 11, dated April 1, 1999, to the Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 10.103 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated by reference herein]
10.59
ý
Copy of Letter Amendment, dated September 15, 1999, to Transportation Agreement, dated November 1, 1993, between LG&E and Texas Gas Transmission Corporation. [Filed as Exhibit 10.106 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated by reference herein]
10.60
ý
ý
* Copy of Powergen Short-Term Incentive Plan, effective January 1, 2001, applicable to certain employees of LG&E Energy Corp. and its subsidiaries. [Filed as Exhibit 10.109 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2000, and incorporated herein by reference]
10.61
ý
ý
* Copy of two forms of Change-In-Control Agreement applicable to certain employees of LG&E Energy Corp. and its subsidiaries. [Filed as
145
Applicable to Form
10-K ofExhibit
No.LG&E
KU
Description
Exhibit 10.110 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2000, and incorporated by reference herein]
10.62
ý
ý
* Copy of Employment and Severance Agreement, dated as of February 25, 2000, and amendments thereto dated December 8, 2000 and April 30, 2001, by and among LG&E Energy, Powergen plc and Victor A. Staffieri. [Filed as Exhibit 10.74 to LG&E’s and KU’s Annual Report on Form 10-K/A for the year ended December 31, 2001, and incorporated by reference herein]
10.63
ý
ý
* Copy of Amendment, dated as of December 8, 2000, to Employment and Severance Agreement dated as of February 25, 2000, by and among LG&E Energy, Powergen plc and an executive officer of the Company.
10.64
ý
Copy of Amendment dated June 5, 2002, to Firm No-Notice Transportation Agreement dated November 1, 1993, between LG&E and Texas Gas Transmission Corporation covering the transmission of natural gas (expires October 31, 2008).
10.65
ý
Copy of Firm Transportation Service Agreement dated November 1, 2002, between LG&E and Tennessee Gas Pipeline Company covering the transmission of natural gas (expires October 31, 2012).
10.66
ý
Copy of Amendment No. 1 dated January 1, 2001, to Coal Supply Agreement dated July 1, 1997, between LG&E and Kindill Mining, Inc.
10.67
ý
Copy of Amendment No. 2 dated January 1, 2002, to Coal Supply Agreement dated July 1, 1997, between LG&E and Kindill Mining, Inc.
10.68
ý
ý
Copy of Amendment No. 2 dated January 1, 2003, to Coal Supply Agreement dated January 1, 2000, between LG&E and KU and McElroy Coal Company, Consolidation Coal Company, Consol Pennsylvania Coal Company, Greenon Coal Company, Nineveh Coal Company, Eighty Four Mining Company and Island Creek Coal Company.
10.69
ý
Copy of Coal Supply Agreement dated January 1, 2003, between LG&E and Peabody Coalsales Company.
10.70
ý
Copy of Coal Supply Agreement dated January 1, 2002, between LG&E and Peabody Coalsales Company.
146
Applicable to Form
10-K ofExhibit
No.LG&E
KU
Description
10.71
ý
Copy of Amendment No. 1 dated June 1, 2002, to Coal Supply Agreement dated January 1, 2002, between LG&E and Peabody Coalsales Company.
10.72
ý
Copy of Amendment No. 2 dated January 1, 2003, to Coal Supply Agreement dated January 1, 2002, between LG&E and Peabody Coalsales Company.
10.73
ý
Copy of Coal Supply Agreement dated January 1, 2002, between KU and Massey Coal Sales Company, Inc.
10.74
ý
ý
*Copy of Third Amendment, dated July 1, 2002, to Employment and Severance Agreement dated as of February 25, 2000 by and among E.ON AG, LG&E Energy, Powergen and Victor A. Staffieri.
10.75
ý
ý
*Copy of form of Retention and Severance Agreement dated April/May, 2002 by and among LG&E Energy, E.ON AG and certain executive officers of the Companies.
10.76
ý
ý
*Copy of Second Amendment, dated May 20, 2002, to Employment and Severance Agreement, dated February 25, 2000, by and among E.ON AG, LG&E Energy Corp., Powergen plc and an executive of the Companies.
10.77
ý
ý
*Copies of Contract of Employment, dated June 22, 1999, Terms of Condition of Assignment, dated December 19, 2000, and Amendment to the Terms and Conditions of Assignment, dated June 27, 2002, by and among, as applicable, Powergen UK plc, Powergen plc, LG&E Energy Corp. and an executive officer of the Companies.
10.78
ý
ý
*Copy of Powergen UK Long Term Incentive Plan, November 2002, applicable to certain executive officers of the Companies.
10.79
ý
ý
*Copy of Terms and Conditions for Stock Options Issued as part of E.ON Group's Stock Option Programs, applicable to certain executive officers of the Companies.
12
ý
ý
Computation of Ratio of Earnings to Fixed Charges for LG&E and KU.
21
ý
ý
Subsidiaries of the Registrants.
23.01
ý
Consents of Independent Accountants for LG&E.
23.02
ý
Consents of Independent Accountants for KU.
24
ý
ý
Powers of Attorney.
99.01
ý
ý
Cautionary Statement for purposes of the “Safe Harbor” provisions of the Private Securities Litigation Reform Act of 1995.
99.02
ý
ý
LG&E and KU Director and Officer Information.
(b) Executive Compensation Plans and
(3) exhibits, are filed as a part of this Annual Report. (1) Financial Statements Report of Independent Public Accountants, Statements of Income and Retained Earnings for the three years ended December 31, 1994, Statements of Cash Flows for the three years ended December 31, 1994, Balance Sheets as of December 31, 1994 and 1993, Statements of Capitalization as of December 31, 1994 and 1993, and Notes to Financial Statements. (2) Schedules Schedule II Valuation and qualifying accounts. The following Schedules are omitted as not applicable or not required under Regulation S-X: I, III, IV, V. -44-(3)Arrangements:Exhibits
Number Description Page 3.A Amended and Restated Articles of Incorporation of Kentucky Utilities Company. (Exhibits 4.03 and 4.04 to Form 8-K Current Report of Kentucky Utilities Company, dated December 10, 1993). Incorporatedpreceded byreference. - 3.B By-laws of Kentucky Utilities Company dated December 14, 1992. (Exhibit 3B to Form 10-K Annual Report of Kentucky Utilities Company for the year ended December 31, 1992). Incorporated by reference. - 4.A Indenture of Mortgage or Deed of Trust dated May 1, 1947 between Kentucky Utilities Company and Continental Illinois National Bank and Trust Company of Chicago and Edmond B. Stofft, as Trustees (Amended Exhibit 7(a) in File No. 2-7061), and Supplemental Indentures thereto dated, respectively, January 1, 1949 (Second Amended Exhibit 7.02 in File No. 2-7802), July 1, 1950 (Amended Exhibit 7.02 in File No. 2-8499), June 15, 1951 (Exhibit 7.02(a) in File No. 2-8499), June 1, 1952 (Amended Exhibit 4.02 in File No. 2-9658), April 1, 1953 (Amended Exhibit 4.02 in File No. 2-10120), April 1, 1955 (Amended Exhibit 4.02 in File No. 2-11476), April 1, 1956 (Amended Exhibit 2.02 in File No. 2-12322), May 1, 1969 (Amended Exhibit 2.02 in File No. 2- 32602), April 1, 1970 (Amended Exhibit 2.02 in File No. 2-36410), September 1, 1971 (Amended Exhibit 2.02 in File No. 2-41467), December 1, 1972 (Amended Exhibit 2.02 in File No. 2-46161), April 1, 1974 (Amended Exhibit 2.02 in File No. 2-50344), September 1, 1974 (Exhibit 2.04 in File No. 2-59328), July 1, 1975 (Exhibit 2.05 in File No. 2-59328), May 15, 1976 (Amended Exhibit 2.02 in File No. 2- 56126), April 15, 1977 (Exhibit 2.06 in File No. 2- 59328), August 1, 1979 (Exhibit 2.04 in File No. 2- 64969), May 1, 1980 (Exhibit 2 to Form 10-Q Quarterly Report of Kentucky Utilities for the quarter ended June 30, 1980), September 15, 1982 (Exhibit 4.04 in File No. 2-79891), August 1, 1984 (Exhibit 4B to Form 10-K Annual Report of Kentucky Utilities Company for the year ended December 31, 1984), June 1, 1985 (Exhibit 4 to Form 10-Q Quarterly Report of Kentucky Utilities Company for the quarter ended June 30, 1985), May 1, 1990 (Exhibit 4 to Form 10-Q Quarterly Report of Kentucky Utilities Company for the quarter ended June 30, 1990), May 1, 1991 (Exhibit 4 to Form 10-Q Quarterly Report of Kentucky Utilities Company for the quarter ended June 30, 1991), May 15, 1992 (Exhibit 4.02 to Form 8-K of Kentucky Utilities -45-Number Description Page 4.A Company dated May 14, 1992), August 1, 1992 (Exhibit (cont.an asterisk (“*”)4 to Form 10-Q Quarterly Report of Kentucky Utilities Company for the quarter ended September 30, 1992), June 15, 1993 (Exhibit 4.02 to Form 8-K of Kentucky Utilities Company dated June 15, 1993) and December 1, 1993 (Exhibit 4.01 to Form 8-K of Kentucky Utilities Company dated December 10, 1993). Incorporated by reference. - 4.B Supplemental Indenture dated March 1, 1992 between Kentucky Utilities and Continental Bank, National Association and M. J. Kruger, as Trustees, providing for the conveyance of properties formerly held by Old Dominion Power Company. (Exhibit 4B to Form 10-K Annual Report of Kentucky Utilities Company for the year ended December 31, 1992). Incorporated by reference. - 4.C Supplemental Indenture dated November 1, 1994 between Kentucky Utilities Company and Bank of America Illinois, as Trustee. 48-65 10.A Kentucky Utilities' Amended and Restated Performance Share Plan (Exhibit 10A to Form 10-Q Quarterly Report of Kentucky Utilities Company for the quarter ended June 30, 1993). Incorporated by reference. - 10.B Kentucky Utilities' Annual Performance Incentive Plan (Exhibit 10B to Form 10-K Annual Report of Kentucky Utilities Company for the year ended December 31, 1990). Incorporated by reference. - 10.C Amendment No. 1 to Kentucky Utilities' Annual Performance Incentive Plan (Exhibit 10D to Form 10-K Annual Report of Kentucky Utilities Company for the year ended December 31, 1991). Incorporated by reference. - 10.D Amendment No. 2 to Kentucky Utilities' Annual Performance Incentive Plan (Exhibit 10H to Form 10-K Annual Report of Kentucky Utilities Company for the year ended December 31, 1993). Incorporated by reference. - 10.E Amendment No. 3 to Kentucky Utilities' Annual Performance Incentive Plan (Exhibit 10I to Form 10-K Annual Report of Kentucky Utilities Company for the year ended December 31, 1993). Incorporated by reference. - 10.F Kentucky Utilities' Executive Optional Deferred Compensation Plan (Exhibit 10C to Form 10-K Annual Report of Kentucky Utilities Company for the year ended December 31, 1990). Incorporated by reference. - 10.G Amendment No. 1 to Kentucky Utilities' Executive Optional Deferred Compensation Plan (Exhibit 10F to Form 10-K Annual Report of Kentucky Utilities Company for the year ended December 31, 1991). Incorporated by reference. - -46-Number Description Page 10.H Amendment No. 2 to Kentucky Utilities' Executive Optional Deferred Compensation Plan (Exhibit 10J to Form 10-K Annual Report of Kentucky Utilities Company for the year ended December 31, 1993). Incorporated by reference. - 10.I Kentucky Utilities' Supplemental Security Plan (Exhibit 10I to Form 10-K Annual Report of Kentucky Utilities Company for the year ended December 31, 1991). Incorporated by reference. - 10.J Amendment No. 1 to Kentucky Utilities' Supplemental Security Plan. 66-67 10.K Amendment No. 2 to Kentucky Utilities' Supplemental Security Plan. 68-70 10.L Kentucky Utilities' Director Retirement Retainer Program, and Amendment No. 1 (Exhibit 10G to Form 10-K Annual Report of Kentucky Utilities Company for the year ended December 31, 1991). Incorporated by reference. - 10.M Kentucky Utilities' Amended and Restated Director Deferred Compensation Plan 71-87 12 Computation of Ratio of Earnings to Fixed Charges 88 21 List of Subsidiaries 89 23 Consent of Independent Public Accountants 90 27 Financial Data Schedule (required for electronic filing only in accordance with Item 601(c)(1) of Regulation S-K). - 99.A Description of Common Stock 91-92 99.B Director and Executive Officer Information 93-101 Note - Exhibit numbers 10.A through 10.Mabove are management contracts,or compensatorycompensation plans or arrangements required to be filed asexhibitsan exhibit pursuant tothisItem 14(c) of Form 10-K.-47-(c) Reports on Form 8-K:
147
On November 14, 2002, LG&E and KU filed a current report on Form 8-K, submitting certifications of the Chairman, President, and Chief Executive Officer and the Chief Financial Officer of each company, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 regarding the companies’ Quarterly Reports on Form 10-Q for the period ended September 30, 2002.
(d) The following instruments defining the rights of holders of certain long- term debt of
Kentucky Utilities CompanyKU have not been filed with the Securities and Exchange Commission but will be furnished to the Commission upon request.1. Loan Agreement dated as of May 1, 1990, between
Kentucky Utili- tiesKU and the County of Mercer, Kentucky, in connection with $12,900,000 County of Mercer, Kentucky, Collateralized Solid Waste Disposal Facility Revenue Bonds(Kentucky Utilities Company(KU Project) 1990 Series A, due May 1, 2010 and May 1, 2020.2. Loan Agreement dated as of May 1, 1991, between
Kentucky Utili- tiesKU and the County of Carroll, Kentucky, in connection with $96,000,000 County of Carroll, Kentucky, Collateralized Pollution Control Revenue Bonds(Kentucky Utilities Company(KU Project) 1992 Series A, due September 15, 2016.3. Loan Agreement dated as of August 1, 1992, between
Kentucky UtilitiesKU and the County of Carroll, Kentucky, in connection with $2,400,000 County of Carroll, Kentucky, Collateralized Pollution Control Revenue Bonds(Kentucky Utilities Company(KU Project) 1992 Series C, due February 1, 2018.4. Loan Agreement dated as of August 1, 1992, between
Kentucky UtilitiesKU and the County of Muhlenberg, Kentucky, in connection with $7,200,000 County of Muhlenberg, Kentucky, Collateralized Pollution Control Revenue Bonds(Kentucky Utilities Company(KU Project) 1992 Series A, due February 1, 2018.5. Loan Agreement dated as of August 1, 1992, between
Kentucky UtilitiesKU and the County of Mercer, Kentucky, in connection with $7,400,000 County of Mercer, Kentucky, Collateralized Pollution Control Revenue Bonds(Kentucky Utilities Company(KU Project) 1992 Series A, due February 1, 2018.6. Loan Agreement dated as of August 1, 1992, between
Kentucky UtilitiesKU and the County of Carroll, Kentucky, in connection with $20,930,000 County of Carroll, Kentucky, Collateralized Pollution Control Revenue Bonds(Kentucky Utilities Company(KU Project) 1992 Series B, due February 1, 2018.7. Loan Agreement dated as of December 1, 1993, between
Kentucky UtilitiesKU and the County of Carroll, Kentucky, in connection with $50,000,000 County of Carroll, Kentucky, Collateralized Solid Waste Disposal Facilities Revenue Bonds(Kentucky Utilities Company(KU Project) 1993 Series A, due December 1, 2023.8. Loan Agreement dated as of November 1, 1994, between
Kentucky UtilitiesKU and the County of Carroll, Kentucky, in connection with $54,000,000 County of Carroll, Kentucky, Collateralized Solid Waste Disposal Facilities Revenue Bonds(Kentucky Utilities Company(KU Project) 1994 Series A, due November 1, 2024.(B) No reports148
Report of Independent Accountants
on Financial Statement SchedulesTo the Shareholders of Louisville Gas and Electric Company and Subsidiary:
Our audits of the consolidated financial statements of Louisville Gas and Electric Company and Subsidiary as of December 31, 2002 and for each of the two years in the period ended December 31, 2002, referred to in our report dated January 21, 2003 also included an audit of the financial statement schedule listed in Item 14(a)2 of this Form
8-K were filed by10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein as of December 31, 2002 and for the year then ended when read in conjunction with the related consolidated financial statements./s/ PricewaterhouseCoopers LLP
January 21, 2003
Louisville, Kentucky
149
Schedule II
Louisville Gas and Electric Company
Schedule II - Valuation and Qualifying Accounts
For the Three Years Ended December 31, 2002
(Thousands of $)
Other
Property
and
Investments
Accounts
Receivable
(Uncollectible
Accounts)
Balance December 31, 1999
$
63
$
1,233
Additions:
Charged to costs and expenses
—
2,803
Deductions:
Net charges of nature for which reserves were created
—
2,750
Balance December 31, 2000
63
1,286
Additions:
Charged to costs and expenses
—
4,953
Deductions:
Net charges of nature for which reserves were created
—
4,664
Balance December 31, 2001
63
1,575
Additions:
Charged to costs and expenses
—
4,459
Deductions:
Net charges of nature for which reserves were created
—
3,909
Balance December 31, 2002
$
63
$
2,125
150
Report of Independent Accountants
on Financial Statement SchedulesTo the Shareholders of Kentucky Utilities
duringCompany and Subsidiary:Our audits of the
last quarterconsolidated financial statements of1994. -48-
SCHEDULE II KENTUCKY UTILITIES COMPANY VALUATION AND QUALIFYING ACCOUNTSYear Ended December 31, 1994 1993 1992 (in thousands) Accumulated Provision for Uncollectible Accounts ReceivableBalance at beginning of year $ 923 $ 1,033 $ 1,132 Balance at end of year $ 457 $ 923 $ 1,033Note-Other valuationKentucky Utilities Company andqualifying accounts are not significant. -49-Subsidiary as of December 31, 2002 and for each of the two years in the period ended December 31, 2002, referred to in our report dated January 21, 2003 also included an audit of the financial statement schedule listed in Item 14(a)2 of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein as of December 31, 2002 and for the year then ended when read in conjunction with the related consolidated financial statements. /s/ PricewaterhouseCoopers LLP
January 21, 2003
Louisville, Kentucky
151
Schedule II
Kentucky Utilities Company
Schedule II - Valuation and Qualifying Accounts
For the Three Years Ended December 31, 2002
(Thousands of $)
Other
Property
and
Investments
Accounts
Receivable
(Uncollectible
Accounts)
Balance December 31, 1999
$
687
$
800
Additions:
Charged to costs and expenses
64
1,430
Deductions:
Net charges of nature for which reserves were created
—
1,430
Balance December 31, 2000
751
800
Additions:
Charged to costs and expenses
9
1,528
Deductions:
Net charges of nature for which reserves were created
630
1,528
Balance December 31, 2001
130
800
Additions:
Charged to costs and expenses
—
1,314
Deductions:
Net charges of nature for which reserves were created
—
1,314
Balance December 31, 2002
$
130
$
800
152
SIGNATURES – LOUISVILLE GAS AND ELECTRIC COMPANY
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly
authorized, on March 9, 1995. KENTUCKY UTILITIES COMPANY /s/ John T. Newton John T. Newton Chairmanauthorized.
LOUISVILLE GAS AND ELECTRIC COMPANY
Registrant
March 25, 2003
/s/ S. Bradford Rives
(Date)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
Signature Title /s/ John T. Newton John T. Newton
Signature
Title
Date
Victor A. Staffieri
Chairman of the Board,
President and Chief Executive
Officer (Principal Executive Officer);Richard Aitken-Davies
Chief Financial Officer
(Principal Financial Officer);S. Bradford Rives
Senior Vice President –
Finance and Controller
(Principal Accounting Officer);Michael Söhlke
Director;
Edmund A. Wallis
Director.
By
/s/ S. Bradford Rives
March 25, 2003
(Attorney-In-Fact)
153
SIGNATURES – KENTUCKY UTILITIES COMPANY
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
KENTUCKY UTILITIES COMPANY
Registrant
March 25, 2003
/s/ S. Bradford Rives
(Date)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
Signature
Title
Date
Victor A. Staffieri
Chairman of the Board,
President and Chief Executive
Officer (Principal Executive Officer);Richard Aitken-Davies
Chief Financial Officer
(Principal Financial Officer);S. Bradford Rives
Senior Vice President –
Finance and Controller
(Principal Accounting Officer);Michael Söhlke
Director;
Edmund A. Wallis
Director.
By
/s/ S. Bradford Rives
March 25, 2003
(Attorney-In-Fact)
154
CERTIFICATIONS
Louisville Gas and Electric Company
I, Victor A. Staffieri, Chairman
and Director (Principal Executive Officer) /s/ Michael R. Whitley Michael R. Whitleyof the Board, President andDirector /s/ O. M. Goodlett O. M. Goodlett Senior Vice-President (PrincipalChief Executive Officer, certify that:1. I have reviewed this annual report on Form 10-K of Louisville Gas and Electric Company;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and
6. The registrant’s other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 25, 2003
/s/ Victor A. Staffieri
Victor A. Staffieri
Chairman of the Board, President and Chief Executive Officer
155
Louisville Gas and Electric Company
I, Richard Aitken-Davies, Chief Financial
Officer) /s/ Michael D. Robinson Michael D. Robinson Controller (Principal Accounting Officer) /s/ Mira S. Ball Mira S. Ball Director /s/ W. B. Bechanan W. B. Bechanan Director /s/ Harry M Hoe Harry M. Hoe Director /s/ Milton W. Hudson Milton W. Hudson Director /s/ Frank V. Ramsey, Jr. Frank V. Ramsey, Jr. Director /s/ Warren W. Rosenthal Warren W. Rosenthal Director /s/ William L. Rouse, Jr. William L. Rouse, Jr. Director /s/ Charles L. Shearer Charles L. Shearer DirectorOfficer, certify that:1. I have reviewed this annual report on Form 10-K of Louisville Gas and Electric Company;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and
6. The registrant’s other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March
9, 1995 -50-25, 2003
/s/ Richard Aitken-Davies
Richard Aitken-Davies
Chief Financial Officer
156
Kentucky Utilities Company
I, Victor A. Staffieri, Chairman of the Board, President and Chief Executive Officer, certify that:
1. I have reviewed this annual report on Form 10-K of Kentucky Utilities Company;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and
6. The registrant’s other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 25, 2003
/s/ Victor A. Staffieri
Victor A. Staffieri
Chairman of the Board, President and Chief Executive Officer
157
Kentucky Utilities Company
I, Richard Aitken-Davies, Chief Financial Officer, certify that:
1. I have reviewed this annual report on Form 10-K of Kentucky Utilities Company;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and
6. The registrant’s other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 25, 2003
/s/ Richard Aitken-Davies
Richard Aitken-Davies
Chief Financial Officer
158