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Kentucky Utilities

Filed: 30 Mar 06, 12:00am

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

 

FORM 10-K

 

(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, 2005

 

 

 

OR

 

 

 

o

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

 

 

SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)

 

Commission

 

Registrant, State of Incorporation,

 

IRS Employer

File Number

 

Address, and Telephone Number

 

Identification Number

 

 

 

 

 

1-2893

 

Louisville Gas and Electric Company

 

61-0264150

 

 

(A Kentucky Corporation)

 

 

 

 

220 West Main Street

 

 

 

 

P. O. Box 32010

 

 

 

 

Louisville, Kentucky 40232

 

 

 

 

(502) 627-2000

 

 

 

 

 

 

 

1-3464

 

Kentucky Utilities Company

 

61-0247570

 

 

(A Kentucky and Virginia Corporation)

 

 

 

 

One Quality Street

 

 

 

 

Lexington, Kentucky 40507-1428

 

 

 

 

(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

 

Kentucky Utilities Company

none

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  o    No  ý

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes  o    No  ý

 

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes  ý    No  o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12-b2 of the Exchange Act. (Check one):

 

Large accelerated filer  o

Accelerated filer  o

Non-accelerated filer   ý

 

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes  o    No  ý

 

As of June 30, 2005, the aggregate market value of the common stock of each of Louisville Gas and Electric Company and Kentucky Utilities Company held by non-affiliates was $0. As of February 28, 2006, Louisville Gas and Electric Company had 21,294,223 shares of common stock outstanding, all held by E.ON U.S. LLC. Kentucky Utilities Company had 37,817,878 shares of common stock outstanding, all held by E.ON U.S. LLC.

 

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 registrant.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Not applicable.

 

 



 

TABLE OF CONTENTS

 

PART I

 

 

 

 

Item 1.

Business

 

 

Louisville Gas and Electric Company

 

 

General

 

 

Electric Operations

 

 

Gas Operations

 

 

Rates and Regulation

 

 

Construction Program and Financing

 

 

Coal Supply

 

 

Gas Supply

 

 

Environmental Matters

 

 

Competition

 

 

Kentucky Utilities Company

 

 

General

 

 

Electric Operations

 

 

Rates and Regulation

 

 

Construction Program and Financing

 

 

Coal Supply

 

 

Environmental Matters

 

 

Competition

 

 

Employees and Labor Relations

 

 

Executive Officers of the Companies

 

Item 1A.

Risk Factors

 

Item 1B.

Unresolved Staff Comments

 

Item 2.

Properties

 

Item 3.

Legal Proceedings

 

Item 4.

Submission of Matters to a Vote of Security Holders

 

 

 

 

PART II

 

 

 

 

Item 5.

Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 

Item 6.

Selected Financial Data

 

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

 

Louisville Gas and Electric Company

 

 

Kentucky Utilities Company

 

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

 

Item 8.

Financial Statements and Supplementary Data

 

 

Louisville Gas and Electric Company

 

 

Kentucky Utilities Company

 

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

Item 9A.

Controls and Procedures

 

Item 9B.

Other Information

 

 

 

 

PART III

 

 

 

 

Item 10.

Directors and Executive Officers of LG&E and KU

 

Item 11.

Executive Compensation

 

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 

Item 13.

Certain Relationships and Related Transactions

 

Item 14.

Principal Accountant Fees and Services

 

 

 

 

PART IV

 

 

 

 

Item 15.

Exhibits and Financial Statement Schedules

 

Signatures

 

 



 

INDEX OF ABBREVIATIONS

 

AEP

 

American Electric Power Company, Inc.

AFUDC

 

Allowance for Funds Used During Construction

AG

 

Attorney General of Kentucky

APBO

 

Accumulated Postretirement Benefit Obligation

ARO

 

Asset Retirement Obligation

CAIR

 

Clean Air Interstate Rule

CAMR

 

Clean Air Mercury Rule

Capital Corp.

 

E.ON U.S. Capital Corp. (formerly LG&E Capital Corp.)

CAVR

 

Clean Air Visibility Rule

Clean Air Act

 

The Clean Air Act, as amended in 1990

CCN

 

Certificate of Public Convenience and Necessity

CO2

 

Carbon Dioxide

Company

 

LG&E or KU, as applicable

Companies

 

LG&E and KU

CT

 

Combustion Turbines

CWIP

 

Construction Work in Progress

DOE

 

Department of Energy

DOJ

 

Department of Justice

DSM

 

Demand Side Management

ECAR

 

East Central Area Reliability Region

ECR

 

Environmental Cost Recovery

EEI

 

Electric Energy, Inc.

EITF

 

Emerging Issues Task Force Issue

E.ON

 

E.ON AG

E.ON U.S.

 

E.ON U.S. LLC. (formerly LG&E Energy LLC and LG&E Energy Corp.)

E.ON U.S. Services

 

E.ON U.S. Services Inc. (formerly LG&E Energy Services Inc.)

EPA

 

U.S. Environmental Protection Agency

EPAct 2005

 

Energy Policy Act of 2005

ERISA

 

Employee Retirement Income Security Act of 1974, as amended

ESM

 

Earnings Sharing Mechanism

Fidelia

 

Fidelia Corporation (an E.ON affiliate)

FAC

 

Fuel Adjustment Clause

FASB

 

Financial Accounting Standards Board

FERC

 

Federal Energy Regulatory Commission

FGD

 

Flue Gas Desulfurization

FIN

 

FASB Interpretation

FPA

 

Federal Power Act

FGD

 

Flue Gas Desulfurization

FIN

 

FASB Interpretation

FPA

 

Federal Power Act

FSP

 

FASB Staff Position

FT and FT-A

 

Firm Transportation

FTR

 

Financial Transmission Right

GSC

 

Gas Supply Clause

GFA

 

Grandfathered Transmission Agreement

IBEW

 

International Brotherhood of Electrical Workers

IMEA

 

Illinois Municipal Electric Agency

IMPA

 

Indiana Municipal Power Agency

IRC

 

Internal Revenue Code of 1986, as amended

IRP

 

Integrated Resource Plan

ITP

 

Independent Transmission Provider

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

Kw

 

Kilowatts

Kwh

 

Kilowatt hours

LEM

 

LG&E Energy Marketing Inc.

LG&E

 

Louisville Gas and Electric Company

 



 

LG&E Energy

 

LG&E Energy LLC (now E.ON U.S. LLC)

LG&E R

 

LG&E Receivables LLC

LG&E Services

 

LG&E Energy Services Inc. (now E.ON U.S. Services Inc.)

LMP

 

Locational Marginal Pricing

LNG

 

Liquefied Natural Gas

Mcf

 

Thousand Cubic Feet

MGP

 

Manufactured Gas Plant

MISO

 

Midwest Independent Transmission System Operator, Inc.

MMBtu

 

Million British thermal units

Moody’s

 

Moody’s Investor Services, Inc.

Mva

 

Megavolt-ampere

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 1935

 

Public Utility Holding Company Act of 1935

PUHCA 2005

 

Public Utility Holding Company Act of 2005

ROE

 

Return on Equity

RTO

 

Regional Transmission Organization

RTOR

 

Regional Through and Out Rates

S&P

 

Standard & Poor’s Rating Services

SCR

 

Selective Catalytic Reduction

SEC

 

Securities and Exchange Commission

SERP

 

Supplemental Executive Retirement Plan

SFAS

 

Statement of Financial Accounting Standards

SIP

 

State Implementation Plan

SMD

 

Standard Market Design

SO2

 

Sulfur Dioxide

SPP

 

Southwest Power Pool, Inc.

TEMT

 

Transmission and Energy Markets Tariff

Tennessee Gas

 

Tennessee Gas Pipeline Company

Texas Gas

 

Texas Gas Transmission LLC

Trimble County

 

LG&E’s Trimble County Unit 1

TVA

 

Tennessee Valley Authority

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

WNA

 

Weather Normalization Adjustment

 



 

PART I

 

Item 1. Business.

 

LG&E and KU are each subsidiaries of E.ON U.S. LLC (E.ON U.S.). Prior to December 1, 2005, E.ON U.S. LLC was known as LG&E Energy LLC. Previously, effective December 30, 2003, LG&E Energy LLC had become the successor, by assignment and subsequent merger, to all the assets and liabilities of LG&E Energy Corp. E.ON U.S. is a subsidiary of E.ON AG (E.ON), a German corporation. E.ON acquired LG&E Energy through its July 1, 2002 acquisition of Powergen plc, now Powergen Limited (Powergen), a United Kingdom company and holding company for E.ON UK plc, E.ON’s United Kingdom market unit operating parent. As contemplated in their regulatory filings in connection with the E.ON acquisition, E.ON, Powergen and E.ON U.S. completed an administrative reorganization to move the E.ON U.S. group from an indirect Powergen subsidiary to an indirect E.ON subsidiary. This reorganization was effective in March 2003. In early 2004, E.ON U.S. began direct reporting arrangements to E.ON.

 

LG&E and KU are now indirect subsidiaries of E.ON. As a result of these acquisitions and otherwise, E.ON and E.ON U.S. anticipate registering as holding companies under PUHCA 2005 and were formerly registered holding companies under PUHCA 1935.

 

In order to comply with PUHCA 1935, E.ON U.S. Services (formerly LG&E Energy Services), which was formed as a subsidiary service company of E.ON U. S., provides services to affiliated entities, including LG&E and KU, at cost as permitted under PUHCA 1935 and PUHCA 2005.

 

E.ON, its utility subsidiaries, including LG&E and KU, and certain of its non-utility subsidiaries are subject to certain regulation by the FERC under the FPA, PUHCA 2005 and the EPAct 2005, including with respect to record-keeping and reporting, acquisitions and sales of utility securities and properties, financial matters, and intra-system sales of goods and services. LG&E and KU believe that they have adequate authority (including financing authority) under existing FERC orders and regulations to conduct their business. LG&E and KU will seek additional authorization when necessary.

 

The utility operations (LG&E and KU) of E.ON U.S. have continued their separate identities as LG&E and KU. The preferred stock and debt securities of LG&E and KU were not affected by these transactions.

 

1



 

LOUISVILLE GAS AND ELECTRIC COMPANY

 

General

 

LG&E, incorporated in 1913 in Kentucky, is a regulated public utility that supplies natural gas to approximately 321,000 customers and electricity to approximately 394,000 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 natural gas and provides electric service, but does not provide any distribution services. LG&E also provides natural gas service in limited additional areas. LG&E’s coal-fired electric generating plants, all equipped with systems to reduce SO2 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 natural gas service to customers. See Item 2, Properties.

 

Operating Revenues

 

For the year ended December 31, 2005, 69% of total operating revenues were derived from electric operations and 31% from natural gas operations. Electric and gas operating revenues and the percentages by class of service on a combined basis for this period were as follows:

 

(in millions)

 

Electric

 

Gas

 

Combined

 

% Combined

 

Residential

 

$

276

 

$

265

 

$

541

 

49

%

Commercial

 

221

 

108

 

329

 

30

%

Industrial

 

128

 

19

 

147

 

13

%

Public authorities

 

66

 

19

 

85

 

8

%

Total retail

 

691

 

411

 

1,102

 

100

%

Wholesale sales

 

259

 

19

 

278

 

 

 

Gas transported

 

 

5

 

5

 

 

 

Miscellaneous

 

37

 

2

 

39

 

 

 

Total

 

$

987

 

$

437

 

$

1,424

 

 

 

 

See Note 12 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, 2005.

 

Electric Operations

 

The sources of LG&E’s electric operating revenues and the volumes of sales for the three years ended December 31, 2005, were as follows:

 

(in millions)

 

2005

 

2004

 

2003

 

ELECTRIC OPERATING REVENUES

 

 

 

 

 

 

 

Residential

 

$

276

 

$

241

 

$

223

 

Commercial

 

221

 

202

 

188

 

Industrial

 

128

 

120

 

112

 

Public authorities

 

66

 

62

 

58

 

Total retail

 

691

 

625

 

581

 

Wholesale sales

 

259

 

185

 

170

 

Provision for rate collections (refunds)

 

 

(11

)

(1

)

Miscellaneous

 

37

 

17

 

18

 

Total

 

$

987

 

$

816

 

$

768

 

 

2



 

(Thousands of Mwh)

 

 

 

 

 

 

 

ELECTRIC SALES

 

 

 

 

 

 

 

Residential

 

4,265

 

3,923

 

3,835

 

Commercial

 

3,682

 

3,534

 

3,482

 

Industrial

 

3,077

 

3,019

 

2,936

 

Public authorities

 

1,268

 

1,248

 

1,251

 

Total retail

 

12,292

 

11,724

 

11,504

 

Wholesale sales

 

8,704

 

7,819

 

7,678

 

Total

 

20,996

 

19,543

 

19,182

 

 

LG&E set an annual peak load of 2,754 Mw on July 25, 2005, when the temperature reached 98 degrees Fahrenheit in Louisville. This was the highest hourly customer demand in LG&E’s history.

 

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 and KU currently maintain a 12% - 14% reserve margin range. At December 31, 2005, LG&E owned steam and combustion turbine generating facilities with a net summer capability of 3,105 Mw and an 80 Mw nameplate-rated hydroelectric facility on the Ohio River with a net summer capability of 48 Mw. See Item 2, Properties. LG&E also obtains power from other utilities under bulk power purchase and interchange contracts. At December 31, 2005, LG&E’s system net summer capability, including purchases from others and excluding the hydroelectric facility, was 3,259 Mw.

 

LG&E uses efficient coal-fired boilers, fully equipped with SO2 removal systems, to generate most of its electricity. LG&E’s weighted-average system-wide emission rate for SO2 in 2005 was approximately 0.54 lbs./MMBtu of heat input, with every generating unit below its emission limit established by the Kentucky Division for Air Quality.

 

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 owns 5.63% of OVEC’s common stock. Through March 2006, LG&E is entitled to receive 7% of OVEC’s output, and thereafter is entitled to receive 5.63%, representing approximately 124 Mw. In April 2004, OVEC and its shareholders, including LG&E and KU, entered into an Amended and Restated Inter-Company Power Agreement, to be effective beginning March 2006, upon the expiration of the current power contract among the parties. The parties received SEC approval under PUHCA 1935 of the Amended and Restated Inter-Company Power Agreement in February 2005.

 

LG&E is a member of the MISO, a non-profit independent transmission system operator that serves the electrical transmission needs of much of the Midwest. Membership was obtained when the MISO was formed in 1998 in response to and consistent with federal energy policy initiatives at that time. The MISO began commercial operations in February 2002. As a result, LG&E turned over operational control of its 100 Kv and above transmission facilities, but continues to control and operate the lower voltage transmission system subject to the terms and conditions of the MISO. As a transmission-owning member of the MISO, LG&E incurs costs under the MISO OATT. In April 2005, the MISO implemented its day-ahead real-time market (MISO Day 2), including a congestion management system. At the present time, LG&E is involved in regulatory proceedings at the Kentucky Commission and the FERC seeking authority to exit the MISO. On March 17, 2006, the FERC issued an order conditionally approving the request of LG&E and KU to exit the MISO. For further discussion, see Note 16 of LG&E’s Notes to Financial Statements under Item 8.

 

3



 

Gas Operations

 

The sources of LG&E’s gas operating revenues and the volumes of sales for the three years ended December 31, 2005, were as follows:

 

(in millions)

 

2005

 

2004

 

2003

 

GAS OPERATING REVENUES

 

 

 

 

 

 

 

Residential

 

$

265

 

$

223

 

$

199

 

Commercial

 

108

 

89

 

78

 

Industrial

 

19

 

15

 

14

 

Public authorities

 

19

 

15

 

14

 

Total retail

 

411

 

342

 

305

 

Wholesale sales

 

19

 

7

 

12

 

Gas transported

 

5

 

6

 

6

 

Miscellaneous

 

2

 

2

 

2

 

Total

 

$

437

 

$

357

 

$

325

 

 

 

 

 

 

 

 

 

(Millions of cu. ft.)

 

 

 

 

 

 

 

GAS SALES

 

 

 

 

 

 

 

Residential

 

20,801

 

21,402

 

23,192

 

Commercial

 

9,131

 

9,144

 

9,652

 

Industrial

 

1,711

 

1,736

 

1,880

 

Public authorities

 

1,574

 

1,646

 

1,746

 

Total retail

 

33,217

 

33,928

 

36,470

 

Wholesale sales

 

2,652

 

1,221

 

2,119

 

Gas transported

 

12,549

 

13,692

 

13,683

 

Total

 

48,418

 

48,841

 

52,272

 

 

The natural 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. While natural gas usage patterns are seasonal, LG&E received approval from the Kentucky Commission for a WNA mechanism. The WNA mechanism adjusts the distribution cost recovery component of the natural gas billings of residential and commercial customers to normal temperatures during the heating season months of November through April, somewhat mitigating the effect of weather extremes. LG&E requested, and the Kentucky Commission approved, an extension of the current WNA mechanism through April 30, 2006. LG&E expects to file for another extension of the WNA before the next heating season begins in November 2006. 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 natural gas service to ultimate consumers. By using natural 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 natural 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 natural gas and pipeline transportation services during the winter months when customer demand increases and when the prices for natural gas supply and transportation services are typically at their highest. Currently, LG&E buys competitively priced natural 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 natural gas sales service at rates generally lower than state and national averages. At December 31, 2005, LG&E had an inventory balance of gas stored underground of approximately 12.1 million Mcf of working gas valued at approximately $124.9 million.

 

4



 

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 approximately one-fourth of LG&E’s annual throughput.

 

During 2005, the maximum daily gas sendout was approximately 444,000 Mcf, occurring on January 17, 2005, when the average temperature for the day was 16 degrees Fahrenheit. Supply on that day consisted of approximately 221,000 Mcf from purchases, approximately 166,000 Mcf delivered from underground storage, and approximately 57,000 Mcf transported for industrial customers. For a further discussion, see Gas Supply under Item 1.

 

Rates and Regulation

 

Historically, E.ON, LG&E’s ultimate parent, has been a registered holding company under PUHCA 1935, and anticipates registering under PUHCA 2005. As a registered holding company, E.ON, its utility subsidiaries, including LG&E, and certain of its non-utility subsidiaries have been subject to extensive regulation by the SEC and the FERC with respect to numerous matters, including: electric utility facilities and operations, wholesale sales of power and related transactions, accounting practices, issuances and sales of securities, acquisitions and sales of utility properties, payments of dividends out of capital and surplus, financial matters and inter-system sales of non-power goods and services. In addition, PUHCA 2005 generally limited 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 FERC orders and regulations to conduct its business and will seek additional authorization when necessary.

 

In August 2005, President Bush signed into law the EPAct 2005, significantly changing many federal statutes, repealing PUHCA 1935 as of February 8, 2006 and enacting PUHCA 2005. As part of the repeal of PUHCA 1935, the FERC was given more authority over the merger and acquisition of public utilities and more authority over the books and records of public utilities. Despite these increases in the FERC’s authority, LG&E believes that the repeal of PUHCA 1935 will lessen its regulatory burdens and provide more flexibility in the event of expansion.

 

Besides repealing PUHCA 1935, the EPAct 2005 is also expected to have substantial long-term effects on energy markets, energy investment and regulation of public utilities and holding company systems by the FERC and the DOE. The FERC and the DOE are in various stages of rulemaking in implementing the EPAct 2005. The precise impact of these rulemakings cannot be determined at this time.

 

The Kentucky Commission has regulatory jurisdiction over LG&E’s retail rates and service, 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.

 

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.

 

5



 

LG&E’s retail electric rates contain an 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 documents relating to fuel procurement and the purchase of power and energy from other utilities.

 

Prior to 2004, LG&E’s retail electric rates were subject to an ESM. LG&E and the Kentucky Commission agreed to a termination of the ESM relating to all periods after 2003. The ESM, initially in place for three years beginning in 2000, set an upper (12.5%) and lower (10.5%) limit for rate of return on equity. If earnings were above the upper limit, the excess earnings were shared 40% with ratepayers and 60% with shareholders; if earnings were below the lower limit, the earnings deficiency was recovered 40% from ratepayers and 60% from shareholders. By order of the Kentucky Commission, rate changes prompted by the ESM filing went into effect in April of each year subject to a balancing adjustment in successive periods. For discussion of current ESM matters, see Note 3 of LG&E’s Notes to Financial Statements under Item 8.

 

In June 2001, LG&E filed an application (“VDT case”) with the Kentucky Commission to create a regulatory asset relating to first quarter 2001 charges for a workforce reduction program. In December 2001, the Kentucky Commission approved a settlement in the VDT case and 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 settlement reduced revenues by approximately $26 million through a surcredit on bills to ratepayers over the same five-year period. The surcredit represented net savings stipulated by LG&E. For discussion of current VDT matters, see Note 3 and Note 16 of LG&E’s Notes to Financial Statements under Item 8.

 

LG&E’s retail rates contain an ECR surcharge which recovers 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 natural gas rates contain a GSC, whereby increases or decreases in the cost of natural 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 natural gas supply in that quarter. In addition, the GSC contains a mechanism whereby any over- or under-recoveries of natural gas supply cost from prior quarters is to be refunded to or recovered from customers through the adjustment factor determined for subsequent quarters. In late 2005, as wholesale natural gas prices began to decrease, a monthly adjustment in the GSC was requested by LG&E and approved by the Kentucky Commission to pass the lower natural gas costs to the customers on a more timely basis.

 

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 IRP in April 2005. The AG and KIUC were granted intervention in the IRP proceeding. The Kentucky Commission issued its staff report on February 15, 2006, with no substantive issues noted and closed the case by Order dated February 24, 2006.

 

In December 2003, LG&E filed an application with the Kentucky Commission requesting adjustments in LG&E’s electric and natural gas rates. LG&E asked for general adjustments in electric and natural gas rates based on the twelve month test period ended September 30, 2003. The revenue increases requested were

 

6



 

approximately $64 million for electric and $19 million for gas. In June 2004, the Kentucky Commission issued an order approving increases in LG&E’s annual electric base rates of approximately $43 million (7.7%) and annual gas base rates of approximately $12 million (3.4%). The rate increases took effect on July 1, 2004.

 

Subsequently during 2004 and 2005, the AG conducted an investigation regarding the proceedings resulting in the rate increases. The AG requested information from LG&E and the Kentucky Commission and its staff regarding alleged improper communications between LG&E and the Kentucky Commission related to the rate proceedings. The AG also requested rehearing of the rate increase orders on the basis of these allegations, as well as calculational aspects of the increased rates. In February 2005, the AG submitted a confidential report on its investigation with the Kentucky Commission and filed a motion summarizing the report as containing evidence of improper communications and record-keeping errors by LG&E in respect of its activities with state governmental agencies, including the Kentucky Commission.

 

In December 2005, the Kentucky Commission issued an order noting completion of its inquiry, including review of the AG’s investigative report. The order concluded that no improper communications occurred during the rate proceedings. The order further established a procedural schedule through the first quarter of 2006 for considering the sole issue for which rehearing was granted: state income tax rates used in calculating the granted rate increases. This issue is estimated at less than $1 million annually. Upon resolution of this issue on rehearing, the initial rate increase orders could be subject to judicial appeal.

 

For a further discussion of regulatory matters, see Note 3 of LG&E’s Notes to Financial Statements under Item 8.

 

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 natural 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 interest rates, economic conditions, construction costs, and new environmental or other governmental laws and regulations.

 

During the five years ended December 31, 2005, gross property additions amounted to approximately $1 billion. 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 24% of total utility plant at December 31, 2005, and consisted of $807 million for electric properties and $164 million for natural gas properties. Gross retirements during the same period were $108 million, consisting of $81 million for electric properties and $27 million for natural gas properties.

 

Capital expenditures during the three years ending December 31, 2008, are estimated to be approximately $530 million. The major expenditures during this period relate to the development and construction of Trimble County Unit 2, of which LG&E’s portion totals approximately $120 million, and approximately $26 million for the redevelopment of the Ohio Falls hydro facility.

 

Coal Supply

 

Coal-fired generating units provided approximately 97% of LG&E’s net kilowatt-hour generation for 2005.

 

7



 

The remaining net generation for 2005 was provided by natural gas and oil-fueled combustion turbine peaking units  and a hydroelectric plant. Coal is expected to 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 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 production issues and other supplier or transporter operating difficulties.

 

LG&E has entered into coal supply agreements with various suppliers for coal deliveries for 2006 and beyond and 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. It had a coal inventory of approximately 1.1 million tons, or a 50-day supply, on hand at December 31, 2005.

 

LG&E expects to continue purchasing most of its coal, which has a sulfur content in the 2% - 4.5% range, from western Kentucky, southern Indiana, southern Illinois, Ohio 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 cost of coal purchased and the percentage of spot coal purchases were as follows:

 

 

 

2005

 

2004

 

2003

 

Per ton

 

$

30.37

 

$

26.25

 

$

25.56

 

Per MMBtu

 

$

1.32

 

$

1.15

 

$

1.12

 

Spot purchases as % of all sources

 

14

%

7

%

1

%

 

The delivered cost of coal is expected to increase in 2006 due to the start of new contracts for 2006 and market conditions. LG&E increased spot purchases in 2005 and 2004 due to supply and transportation issues in the market.

 

Gas Supply

 

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.

 

LG&E transports natural gas on the Texas Gas system under Rate Schedules NNS and FT service. Effective November 1, 2005, LG&E’s winter season NNS levels are 184,900 MMBtu/day and its winter season FT levels are 36,000 MMBtu/day. LG&E’s summer season NNS levels are 60,000 MMBtu/day and its summer season FT levels are 36,000 MMBtu/day. LG&E provided Texas Gas with notice to terminate a portion of its FT agreement in the amount of 8,000 MMBtu/day effective November 1, 2006. As a result, LG&E will have FT service in the amount of 28,000 MMBtu/day, effective November 1, 2006. Each of the NNS agreements with Texas Gas is subject to termination by LG&E in equal portions during 2008, 2010 and 2011. Each of the FT

 

8



 

agreements with Texas Gas is subject to termination by LG&E during 2008 and 2011. LG&E also transports on the Tennessee Gas system under Tennessee Gas’ Rate Schedule FT-A. LG&E’s contract levels with Tennessee Gas are 51,000 MMBtu/day throughout the year. The FT-A agreement with Tennessee Gas is subject to termination by LG&E during 2007.

 

LG&E participates in rate and other proceedings affecting the regulated interstate natural gas pipelines that provide service to LG&E. Both Texas Gas and Tennessee Gas have several active proceedings in which LG&E is participating at the FERC. One of those proceedings is an application filed by Texas Gas with the FERC to increase its base rates. LG&E is participating in this proceeding with other interested parties. The rates of Texas Gas are, therefore, being billed subject to refund, and LG&E will refund to its customers any amounts which may be refunded to it as the result of the resolution of this proceeding before the FERC. The rates of Tennessee Gas are not being billed subject to refund.

 

LG&E also has a portfolio of supply arrangements of various terms with a number of suppliers designed to meet its firm sales obligations. These natural gas supply arrangements include pricing provisions that are market-responsive. These firm natural gas supplies, in tandem with pipeline transportation services, provide the reliability and flexibility necessary to serve LG&E’s natural gas customers.

 

LG&E owns and operates five underground natural gas storage fields with a current working gas capacity of approximately 15.1 million Mcf. Natural gas is purchased and injected into storage during the summer season when natural gas prices are typically lower, 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 expected to be in excess of 370,000 Mcf/day. Under mid-winter design conditions, LG&E expects to be able to withdraw in excess of 350,000 Mcf/day from its storage facilities. The deliverability of natural gas from LG&E’s storage facilities decreases as storage inventory levels are reduced by seasonal withdrawals.

 

LG&E relies upon its significant underground storage to mitigate the price volatility to which customers might otherwise be exposed. In 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”. Subsequent to this investigation, the Kentucky Commission issued an order on July 17, 2001, encouraging the natural gas distribution companies in Kentucky to take various actions, among them to propose a natural gas hedge plan. LG&E currently operates under a hedge plan proposed by LG&E beginning with the 2004/2005 winter heating season. This hedge plan relies upon LG&E’s underground natural gas storage to mitigate customer exposure to price volatility. In 2004, the Kentucky Commission approved LG&E’s proposed hedge plan, validating the effectiveness of storage to mitigate potential volatility associated with high winter natural gas prices by approving this natural gas hedge plan. The Kentucky Commission also ordered that LG&E need not file hedge plans in the future unless it intended to utilize financial hedging instruments.

 

The average cost per Mcf of natural gas purchased by LG&E was $10.23 in 2005, $7.18 in 2004, and $6.30 in 2003. Natural gas prices in the unregulated wholesale market generally have increased significantly over the last few years beginning in 2000. For further discussion of wholesale natural gas prices, see Note 3 of LG&E’s Notes to Financial Statements under Item 8.

 

9



 

Environmental Matters

 

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 2005, expenditures for pollution control facilities represented $233 million or 24% of total construction expenditures. LG&E estimates that construction expenditures for environmental protection equipment from 2006 through 2008 will be approximately $40 million. For a discussion of environmental matters, see Note 10 of LG&E’s Notes to Financial Statements under Item 8.

 

Competition

 

At this time, 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. Some states that have already deregulated have begun discussions that could lead to re-regulation.

 

In February 2005, Kentucky’s Governor signed an executive order directing the Kentucky Commission, in conjunction with the Commerce Cabinet and the Environmental and Public Protection Cabinet, to ‘develop a Strategic Blueprint for the continued use and development of electric energy.’ This Strategic Blueprint is designed to promote future investment in electric infrastructure for the Commonwealth of Kentucky, to protect Kentucky’s low-cost electric advantage, to maintain affordable rates for all Kentuckians, and to preserve Kentucky’s commitment to environmental protection. In March 2005, the Kentucky Commission established Administrative Case No. 2005-00090 to collect information from all jurisdictional utilities in Kentucky, including LG&E, pertaining to Kentucky electric generation, transmission and distribution systems. LG&E responded to the Kentucky Commission’s first set of data requests at the end of March 2005 and to a second set of data requests in May 2005. The Commission held a Technical Conference in June 2005, in which all parties participated in a panel discussion. A final report was provided in August 2005 from the Kentucky Commission to the Governor. The Kentucky Commission issued an order and closed this proceeding on September 15, 2005. Some of the key findings from the report are:

 

                  Kentucky’s electric utilities currently have adequate infrastructure as well as adequate planning to serve the needs of customers through 2025;

                  Kentucky will need 7,000 megawatts of additional generating capacity by 2025;

                  Kentucky’s electric transmission is reliable but intrastate power transfers are limited;

                  Additional incentives to use renewable energy and educate the public on the benefits of renewables are needed;

                  Financial incentives should be available for coal purification and other clean air technologies;

                  A cautious approach should be taken toward deregulation; and

                  Kentucky must be involved in federal decisions that impact its status as a low cost energy provider.

 

Over the last several years, LG&E has taken many steps to keep its rates low while maintaining high levels of customer satisfaction, including: an increase in focus on commercial, industrial and residential customers; an increase in employee involvement and training; and continuous modifications of its organizational structure. LG&E also strives to control costs through competitive bidding and process improvements. LG&E’s performance in national customer satisfaction surveys continues to be high.

 

10



 

KENTUCKY UTILITIES COMPANY

 

General

 

KU, incorporated in Kentucky in 1912 and incorporated in Virginia in 1991, is a regulated public utility that provides electricity to approximately 495,000 customers in over 600 communities and adjacent suburban and rural areas in 77 counties in central, southeastern and western Kentucky, to approximately 30,000 customers in 5 counties in southwestern Virginia and 5 customers in Tennessee. KU’s coal-fired electric generating plants produce most of KU’s electricity, the remainder is generated by hydroelectric power plants and combustion turbines. In Virginia, KU operates under the name Old Dominion Power Company. KU operates under appropriate franchises in substantially all of the 160 Kentucky incorporated municipalities served. No franchises are required in unincorporated Kentucky or Virginia communities. The lack of franchises is not expected to have a material adverse effect on KU’s operations. KU also sells wholesale electric energy to 12 municipalities. See Item 2, Properties.

 

Electric Operations

 

The sources of KU’s electric operating revenues and the volumes of sales for the three years ended December 31, 2005, were as follows:

 

(in millions)

 

2005

 

2004

 

2003

 

ELECTRIC OPERATING REVENUES

 

 

 

 

 

 

 

Residential

 

$

364

 

$

304

 

$

278

 

Commercial

 

241

 

207

 

189

 

Industrial

 

220

 

190

 

176

 

Mine power

 

38

 

32

 

30

 

Public authorities

 

83

 

72

 

66

 

Total retail

 

946

 

805

 

739

 

Wholesale sales

 

210

 

160

 

138

 

Provision for rate collections (refunds)

 

 

5

 

(8

)

Miscellaneous

 

51

 

25

 

23

 

Total

 

$

1,207

 

$

995

 

$

892

 

 

(Thousands of Mwh)

 

 

 

 

 

 

 

ELECTRIC SALES

 

 

 

 

 

 

 

Residential

 

6,599

 

6,160

 

6,001

 

Commercial

 

4,466

 

4,323

 

4,210

 

Industrial

 

5,459

 

5,400

 

5,110

 

Mine power

 

803

 

732

 

722

 

Public authorities

 

1,649

 

1,597

 

1,551

 

Total retail

 

18,976

 

18,212

 

17,594

 

Wholesale sales

 

5,781

 

5,707

 

5,591

 

Total

 

24,757

 

23,919

 

23,185

 

 

KU set an annual peak load of 4,079 Mw on July 25, 2005, when the temperature reached 94 degrees Fahrenheit. This was the highest hourly customer demand in KU’s history.

 

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The electric utility business is affected by seasonal weather patterns. As a result, operating revenues (and associated operating expenses) are not generated evenly throughout the year. See KU’s Results of Operations under Item 7.

 

KU and LG&E currently maintain a 12% - 14% reserve margin range. At December 31, 2005, KU owned steam and combustion turbine generating facilities with a net summer capability of 4,433 Mw and a 28 Mw nameplate-rated hydroelectric facility with a summer capability of 24 Mw. See Item 2, Properties. KU also obtains power from other utilities under bulk power purchase and interchange contracts. At December 31, 2005, KU’s system net summer capability, including purchases from others and excluding the hydroelectric facility, was 4,678 Mw.

 

KU’s weighted-average system-wide emission rate for SO2 in 2005 was approximately 1.25 lbs./MMBtu of heat input, with every generating unit below its emission limit established by the Kentucky Division for Air Quality.

 

Under a contract expiring in 2020 with OMU, KU has agreed to purchase from OMU the surplus output of the 142-Mw and 265-Mw generating units at OMU’s Elmer Smith station. Purchases under the contract are made under a contractual formula resulting in costs which are expected to be comparable to the cost of other power purchased or generated by KU. Such power equated to approximately 8% of KU’s net generation system output during 2005. See Note 10 of KU’s Notes to Financial Statements under Item 8.

 

KU owns 20% of the common stock of EEI, which owns and operates a 1,000-Mw generating station in southern Illinois. Previously, KU was entitled to take 20% of the available capacity of the station under a pricing formula comparable to the cost of other power generated by KU. Such power equated to approximately 9% of KU’s net generation system output in 2005. The contract governing the purchases from EEI terminated on December 31, 2005. Subsequent to December 31, 2005, EEI has sold power under general market-based pricing and terms. KU has not contracted with EEI for power under the new arrangements, but maintains its 20% ownership in the common stock of EEI. Replacement power for the EEI capacity has been largely provided by KU generation.

 

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 owns 2.5% of OVEC’s common stock. KU’s share of OVEC’s output is 2.5%, approximately 55 Mw of generation capacity. In April 2004, OVEC and its shareholders, including KU and LG&E, entered into an Amended and Restated Inter-Company Power Agreement, to be effective beginning March 2006, upon the expiration of the current power contract among the parties. The parties received SEC approval under PUHCA 1935 of the Amended and Restated Inter-Company Power Agreement in February 2005.

 

KU is a member of the MISO, a non-profit independent transmission system operator that serves the electrical transmission needs of much of the Midwest. Membership was obtained when the MISO was formed in 1998 in response to and consistent with federal energy policy initiatives at that time. The MISO began commercial operations in February 2002. As a result, KU turned over operational control of its 100 Kv and above transmission facilities, but continues to control and operate the lower voltage transmission system subject to the terms and conditions of the MISO. As a transmission-owning member of the MISO, KU incurs costs under the MISO OATT. In April 2005, the MISO implemented its day-ahead real-time market (MISO Day 2), including a congestion management system. At the present time, KU is involved in regulatory proceedings at the Kentucky Commission and the FERC seeking authority to exit the MISO. On March 17, 2006, the FERC issued an order conditionally approving the request of KU and LG&E to exit the MISO. For further discussion, see

 

12



 

Note 15 of KU’s Notes to Financial Statements under Item 8.

 

Rates and Regulation

 

Historically, E.ON, KU’s ultimate parent, has been a registered holding company under PUHCA 1935, and anticipates registering under PUHCA 2005. As a registered holding company, E.ON, its utility subsidiaries, including KU, and certain of its non-utility subsidiaries have been subject to extensive regulation by the SEC and the FERC with respect to numerous matters, including: electric utility facilities and operations, wholesale sales of power and related transactions, accounting practices, issuances and sales of securities, acquisitions and sales of utility properties, payments of dividends out of capital and surplus, financial matters and inter-system sales of non-power goods and services. In addition, PUHCA 1935 generally limited 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 FERC orders and regulations to conduct its business and will seek additional authorization when necessary.

 

In August 2005, President Bush signed into law the EPAct 2005, significantly changing many federal statutes, repealing PUHCA 1935 as of February 8, 2006 and enacting PUHCA 2005. As part of the repeal of PUHCA 1935, the FERC was given more authority over the merger and acquisition of public utilities and more authority over the books and records of public utilities. Despite these increases in the FERC’s authority, KU believes that the repeal of PUHCA 1935 will lessen its regulatory burdens and provide more flexibility in the event of expansion.

 

Besides repealing PUHCA 1935, the EPAct 2005 is also expected to have substantial long-term effects on energy markets, energy investment and regulation of public utilities and holding company systems by the FERC and the DOE. The FERC and the DOE are in various stages of rulemaking in implementing the EPAct 2005. While the precise impact of these rulemakings cannot be determined at this time, KU generally views the EPAct 2005 as legislation that will enhance the utility industry going forward.

 

The Kentucky Commission and the Virginia Commission have regulatory jurisdiction over KU’s retail rates and service, and over the issuance of certain of its securities. By reason of owning and operating a small amount of electric utility property in one county in Tennessee (having a gross book value of approximately $0.3 million) from which KU served 5 customers at December 31, 2005, KU is subject to the jurisdiction of the Tennessee Regulatory Authority. The Kentucky Commission, the Virginia Commission and the Tennessee Regulatory Authority have the ability to examine the rates KU charges its retail customers at any time.

 

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.

 

KU’s Kentucky retail electric rates contain an 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

 

13



 

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 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.

 

Prior to 2004, KU’s Kentucky retail electric rates were subject to an ESM. KU and the Kentucky Commission agreed to a termination of the ESM relating to all periods after 2003. The ESM, initially in place for three years beginning in 2000, set an upper (12.5%) and lower (10.5%) limit for rate of return on equity. If earnings were above the upper limit, the excess earnings were shared 40% with ratepayers and 60% with shareholders; if earnings were below the lower limit, the earnings deficiency was recovered 40% from ratepayers and 60% from shareholders. By order of the Kentucky Commission, rate changes prompted by the ESM filing went into effect in April of each year subject to a balancing adjustment in successive periods. There is no ESM for Virginia retail electric rates. For discussion of current ESM matters, see Note 3 of KU’s Notes to Financial Statements under Item 8.

 

In June 2001, KU filed an application (“VDT case”) with the Kentucky Commission to create a regulatory asset relating to first quarter 2001 charges for a workforce reduction program. In December 2001, the Kentucky Commission approved a settlement in the VDT and 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 settlement reduced revenues by approximately $11 million through a surcredit on bills to ratepayers over the same five-year period. The surcredit represented net savings stipulated by KU. For discussion of current VDT matters, see Note 3 and Note 15 of KU’s Notes to Financial Statements under Item 8.

 

KU’s Kentucky retail rates contain an ECR surcharge which recovers costs incurred by KU that are required 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 IRP in April 2005. The AG and KIUC were granted intervention in the IRP proceeding. The Kentucky Commission issued its staff report on February 15, 2006, with no substantive issues noted and closed the case by Order dated February 24, 2006.

 

The Commonwealth of Virginia passed the Virginia Electric Utility Restructuring Act in 1999. This act gave Virginia customers the ability to choose their electric supplier. Rates are capped at current levels through December 2010. 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 December 2010 rates are subject to the capped rate period and essentially “frozen”. However, KU may petition the Virginia Commission for a one-time adjustment in rates during the capped rate period. Effective July 1, 2003, the General Assembly of Virginia amended and reenacted Section 56-580 of the Code of Virginia with language that effectively exempts all KU Virginia service territory from retail choice until such time as retail choice is offered to customers in KU’s other service territories.

 

14



 

In December 2003, KU filed an application with the Kentucky Commission requesting an adjustment in KU’s electric rates. KU asked for a general adjustment in electric rates based on the twelve month test period ended September 30, 2003. The revenue increase requested was approximately $58 million. In June 2004, the Kentucky Commission issued an order approving an increase in KU’s annual electric base rates of approximately $46 million (6.8%). The rate increase took effect on July 1, 2004.

 

Subsequently during 2004 and 2005, the AG conducted an investigation regarding the proceedings resulting in the rate increase. The AG requested information from KU and the Kentucky Commission and its staff regarding alleged improper communications between KU and the Kentucky Commission related to the rate proceeding. The AG also requested rehearing of the rate increase order on the basis of these allegations, as well as calculational aspects of the increased rates. In February, 2005 the AG submitted a confidential report on its investigation with the Kentucky Commission and filed a motion summarizing the report as containing evidence of improper communications and record-keeping errors by KU in respect of its activities with state governmental agencies, including the Kentucky Commission.

 

In December 2005, the Kentucky Commission issued an order noting completion of its inquiry, including review of the AG’s investigative report. The order concluded that no improper communications occurred during the rate proceedings. The order further established a procedural schedule through the first quarter of 2006 for considering the sole issue for which rehearing was granted: state income tax rates used in calculating the granted rate increase. This issue is estimated at less than $1 million annually. Upon resolution of this issue on rehearing, the initial rate increase order could be subject to judicial appeal.

 

For a further discussion of regulatory matters, see Note 3 of KU’s Notes to the Financial Statements under Item 8.

 

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 interest rates, economic conditions, construction costs, and new environmental or other governmental laws and regulations.

 

During the five years ended December 31, 2005, gross property additions amounted to approximately $1 billion. 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 December 31, 2005. Gross retirements during the same period were $106 million.

 

Capital expenditures during the three years ending December 31, 2008 are estimated to be approximately $1.5 billion. The major expenditures during this period relate to the development and construction of Trimble County Unit 2, of which KU’s portion totals approximately $510 million, and the installation of FGDs on Ghent and Brown units, totaling approximately $560 million.

 

Coal Supply

 

Coal-fired generating units provided approximately 97% of KU’s net kilowatt-hour generation for 2005. The remaining net generation for 2005 was provided by natural gas and oil-fueled combustion turbine peaking units

 

15



 

and hydroelectric plants. Coal is expected to be the predominant fuel used by KU in the foreseeable future, with natural gas and oil being used for peaking 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 the foreseeable 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 production issues and other supplier or transporter operating difficulties.

 

KU has entered into coal supply agreements with various suppliers for coal deliveries for 2006 and beyond and normally augments its coal supply agreements with spot market purchases. KU has a coal inventory policy which it believes provides adequate protection under most contingencies. It had a coal inventory of approximately 1.1 million tons, or a 51-day supply, on hand at December 31, 2005.

 

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, southern Indiana, southern Illinois, Ohio, Wyoming and Colorado for the foreseeable future.

 

Coal is delivered to KU’s Ghent plant by barge, Tyrone and Green River plants by truck, and E.W. Brown plant by rail and truck.

 

The historical average delivered cost of coal purchased and the percentage of spot coal purchases were as follows:

 

 

 

2005

 

2004

 

2003

 

 

 

 

 

 

 

 

 

Per ton

 

$

42.45

 

$

37.69

 

$

34.57

 

Per MMBtu

 

$

1.78

 

$

1.56

 

$

1.47

 

Spot purchases as % of all sources

 

15

%

14

%

11

%

 

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 for 2006 is expected to increase due to the start of new contracts and market conditions.

 

Environmental Matters

 

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 2005, expenditures for pollution control facilities represented $269 million or 26% of total construction expenditures. KU estimates that construction expenditures for environmental control equipment from 2006 through 2008, will be approximately $680 million, of which approximately $560 million is related to the installation of FGDs at Ghent and Brown. For a discussion of environmental matters, see Note 10 of KU’s Notes to Financial Statements under Item 8.

 

Competition

 

At this time, 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

 

16



 

legislative or regulatory actions regarding industry restructuring and their impact on KU, which may be significant, cannot currently be predicted. Some states that have already deregulated have begun discussions that could lead to re-regulation.

 

In February 2005, Kentucky’s Governor signed an executive order directing the Kentucky Commission, in conjunction with the Commerce Cabinet and the Environmental and Public Protection Cabinet, to ‘develop a Strategic Blueprint for the continued use and development of electric energy.’ This Strategic Blueprint is designed to promote future investment in electric infrastructure for the Commonwealth of Kentucky, to protect Kentucky’s low-cost electric advantage, to maintain affordable rates for all Kentuckians, and to preserve Kentucky’s commitment to environmental protection. In March 2005, the Kentucky Commission established Administrative Case No. 2005-00090 to collect information from all jurisdictional utilities in Kentucky, including KU, pertaining to Kentucky electric generation, transmission and distribution systems. KU responded to the Kentucky Commission’s first set of data requests at the end of March 2005 and to a second set of data requests in May 2005. The Commission held a Technical Conference in June 2005, in which all parties participated in a panel discussion. A final report was provided in August 2005 from the Kentucky Commission to the Governor. The Kentucky Commission issued an order and closed this proceeding on September 15, 2005. Some of the key findings from the report are:

 

                  Kentucky’s electric utilities currently have adequate infrastructure as well as adequate planning to serve the needs of customers through 2025;

                  Kentucky will need 7,000 megawatts of additional generating capacity by 2025;

                  Kentucky’s electric transmission is reliable but intrastate power transfers are limited;

                  Additional incentives to use renewable energy and educate the public on the benefits of renewables are needed;

                  Financial incentives should be available for coal purification and other clean air technologies;

                  A cautious approach should be taken toward deregulation; and

                  Kentucky must be involved in federal decisions that impact its status as a low cost energy provider.

 

Virginia has enacted a phase-in of customer choice through the Virginia Electric Restructuring Act, however, KU’s service territory has been effectively exempted from retail choice until such time as retail choice is offered to customers in KU’s other service territories.

 

Over the last several years, KU has taken many steps to keep its rates low while maintaining high levels of customer satisfaction, including: an increase in focus on commercial, industrial and residential customers; an increase in employee involvement and training; and continuous modifications of its organizational structure. KU also strives to control costs through competitive bidding and process improvements. KU’s performance in national customer satisfaction surveys continues to be high.

 

17



 

EMPLOYEES AND LABOR RELATIONS

 

LG&E had approximately 895 full-time regular employees and KU had approximately 925 full-time regular employees at February 28, 2006. Of the LG&E total, 621 operating, maintenance, and construction employees were represented by IBEW Local 2100. LG&E and employees represented by IBEW Local 2100 signed a three-year collective bargaining agreement in November 2005 with annual benefits re-openers. Of the KU total, approximately 150 operating, maintenance, and construction employees were represented by IBEW Local 2100 and USWA Local 9447-01. In August 2003, KU and employees represented by IBEW Local 2100 entered into a three-year collective bargaining agreement. KU and employees represented by USWA Local 9447-01 entered into a three-year collective bargaining agreement in August 2005 with authorized annual wage re-openers.

 

E.ON U.S. Services provides services to affiliated entities, including LG&E and KU, at cost as permitted under PUHCA 2005. On February 28, 2006, approximately 1,022 employees worked for E.ON U.S. Services.

 

18



 

Executive Officers of LG&E and KU at February 28, 2006:

 

 

 

 

 

 

 

Effective Date of

 

 

 

 

 

 

 

Election to Present

 

Name

 

Age

 

Position

 

Position

 

 

 

 

 

 

 

 

 

Victor A. Staffieri

 

50

 

Chairman of the Board,

 

May 1, 2001

 

 

 

 

 

President and Chief

 

 

 

 

 

 

 

Executive Officer

 

 

 

 

 

 

 

 

 

 

 

John R. McCall

 

62

 

Executive Vice President,

 

July 1, 1994

 

 

 

 

 

General Counsel and

 

 

 

 

 

 

 

Corporate Secretary

 

 

 

 

 

 

 

 

 

 

 

S. Bradford Rives

 

47

 

Chief Financial Officer

 

September 15, 2003

 

 

 

 

 

 

 

 

 

Paul W. Thompson

 

49

 

Senior Vice President -

 

June 7, 2000

 

 

 

 

 

Energy Services

 

 

 

 

 

 

 

 

 

 

 

Chris Hermann

 

58

 

Senior Vice President -

 

February 14, 2003

 

 

 

 

 

Energy Delivery

 

 

 

 

 

 

 

 

 

 

 

Wendy C. Welsh

 

52

 

Senior Vice President -

 

December 11, 2000

 

 

 

 

 

Information Technology

 

 

 

 

 

 

 

 

 

 

 

Martyn Gallus

 

41

 

Senior Vice President -

 

December 11, 2000

 

 

 

 

 

Energy Marketing

 

 

 

 

 

 

 

 

 

 

 

Paula H. Pottinger

 

49

 

Senior Vice President -

 

January 2, 2006

 

 

 

 

 

Human Resources

 

 

 

 

Other Officers of LG&E and KU at February 28, 2006:

 

David A. Vogel

 

40

 

Vice President - Retail

 

March 1, 2003

 

 

 

 

 

and Gas Storage Operations

 

 

 

 

 

 

 

 

 

 

 

Daniel K. Arbough

 

44

 

Treasurer

 

December 11, 2000

 

 

 

 

 

 

 

 

 

Michael S. Beer

 

47

 

Vice President

 

September 27, 2004

 

 

 

 

 

Federal Regulation and Policy

 

 

 

 

 

 

 

 

 

 

 

George R. Siemens

 

56

 

Vice President - External

 

January 11, 2001

 

 

 

 

 

Affairs

 

 

 

 

 

 

 

 

 

 

 

D. Ralph Bowling

 

48

 

Vice President -

 

August 1, 2002

 

 

 

 

 

Power Operations WKE

 

 

 

 

 

 

 

 

 

 

 

R. W. Chip Keeling

 

49

 

Vice President -

 

March 18, 2002

 

 

 

 

 

Communications

 

 

 

 

 

 

 

 

 

 

 

John N. Voyles, Jr.

 

51

 

Vice President -

 

June 16, 2003

 

 

 

 

 

Regulated Generation

 

 

 

 

 

 

 

 

 

 

 

Valerie L. Scott

 

49

 

Controller

 

January 1, 2005

 

 

19



 

The present term of office of each of the above executive and other officers extends to the meeting of the Board of Directors following the 2006 Annual Meeting of Shareholders.

 

There are no family relationships between or among executive and other officers of LG&E and KU. The above tables indicate officers serving as executive officers of both LG&E and KU at February 28, 2006. Each of the above officers serves in the same capacity for LG&E and KU.

 

Before he was elected to his current positions, Mr. Staffieri was Chief Financial Officer of LG&E Energy (now E.ON U.S.) and LG&E from May 1997 to February 1999 (including Chief Financial Officer of KU from May 1998 to February 1999) and President and Chief Operating Officer of LG&E Energy (now E.ON U.S.) from March 1999 to April 2001 (including President of LG&E and KU from June 2000 to April 2001).

 

Mr. McCall has been Executive Vice President, General Counsel and Corporate Secretary of LG&E Energy (now E.ON U.S.) 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 Senior Vice President - Finance and Business Development from February 1999 to December 2000 and Senior Vice President - Finance and Controller of LG&E Energy (now E.ON U.S.), LG&E and KU from December 2000 to September 2003.

 

Before he was elected to his current positions, Mr. Thompson was 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 (now E.ON U.S.) from August 1999 to June 2000.

 

Before he was elected to his current positions, Mr. Hermann was Vice President, Power Generation and Engineering Services, of LG&E from May 1998 to December 1999; Vice President Supply Chain and Operating Services from December 1999 to December 2000; and Senior Vice President - Distribution Operations, from December 2000 to February 2003.

 

Before she was elected to her current positions, Ms. Welsh was Vice President - Information Technology from February 1998 to December 2000 for LG&E Energy (now E.ON U.S.).

 

Before he was elected to his current positions, Mr. Gallus was Vice President, Energy Marketing from August 1998 to December 2000 for LG&E Energy (now E.ON U.S.).

 

Before she was elected to her current positions, Ms. Pottinger was Director, Human Resources from June 1997 to June 2002; and Vice President - Human Resources from June 2002 to January 2006.

 

Before he was elected to his current positions, Mr. Vogel was Vice President - Retail Services from December 2000 to March 2003.

 

In addition to being elected to his current positions, Mr. Arbough has held the positions of Director, Corporate Finance of LG&E Energy (now E.ON U.S.), LG&E and KU from May 1998 to present.

 

20



 

Before he was elected to his current positions, Mr. Beer was Senior Counsel Specialist, Regulatory from February 2000 to February 2001, and Vice President – Rates and Regulatory from February 2001 to September 2004.

 

Before he was elected to his current positions, Mr. Siemens held the position of Director of External Affairs for LG&E Energy (now E.ON U.S.) from August 1982 to January 2001.

 

Before he was elected to his current positions, Mr. Bowling was Plant General Manager at Western Kentucky Energy from July 1998 to December 2001; and General Manager Black Fossil Operations for E.ON U.K. in the United Kingdom from January 2002 to August 2002.

 

Before he was elected to his current positions, Mr. Keeling was Director, Corporate Communications for LG&E Energy (now E.ON U.S.) from February 2000 to March 2002.

 

Before he was elected to his current positions, Mr. Voyles was General Manager, Cane Run, Ohio Falls and Combustion Turbines, November 1998 to February 2003; and Director, Generation Services, February 2003 to June 2003.

 

Before she was elected to her current positions, Ms. Scott was Director, Trading Controls and Energy Marketing Accounting from February 1999 to September 2002, and Director, Financial Planning and Accounting – Utility Operations from September 2002 to December 2004.

 

Item 1A. Risk Factors

 

In addition to the other information in this Form 10-K and other documents furnished to or filed by LG&E and KU with the SEC from time to time, the following factors should be carefully considered in evaluating the Companies. Such factors could affect actual results and cause results to differ materially from those expressed in any forward-looking statements made by, or on behalf of, the Companies. Some or all of these factors may apply to LG&E or KU or both.

 

The electric and gas rates that LG&E and KU charge customers, as well as other aspects of the business, are subject to significant state and FERC regulation.

 

The rates that the Companies are allowed to charge for their services are a primary item influencing the results of operations, financial position, and liquidity of the Companies. The regulation of the rates that are collected from customers is determined, in large part, by governmental organizations outside the Companies’ control, including the Kentucky Commission, and for KU, the Virginia Commission and the Tennessee Regulatory Authority. These commissions regulate many aspects of utility operations, including financial and capital structure matters, siting and construction of facilities, terms and conditions of service, safety and operations, accounting and cost allocation methodologies and other matters. While rate regulation is premised on recovery of prudently incurred costs and reasonable rate of return on capital, such cannot be assured. Regulatory proceedings regarding all matters of operations can thus significantly affect the earnings, liquidity and business activities of the Companies.

 

Base rate increases of LG&E and KU approved during 2004 and currently being collected by the Companies in Kentucky remain the subject of continuing proceedings by the Kentucky Commission and the Attorney General. Proceedings regarding the expiration of VDT charges formerly included in the Companies’ rates in Kentucky

 

21



 

are also the subject of on-going proceedings.

 

Transmission and interstate market activities of LG&E and KU, as well as other aspects of the business, are subject to significant FERC regulation.

 

The Companies’ businesses are subject to regulation under the FERC covering matters including rates charged to transmission users and wholesale customers, interstate market structure and design, construction and operation of transmission facilities, acquisition and disposal of utility assets and securities, standards of conduct, cost allocations and financial matters. Existing FERC regulation, changes thereto or issuance of new rules in these areas, can affect the earnings, operations and other activities of the Companies.

 

LG&E’s and KU’s continued participation in the MISO, as well as changes in transmission and wholesale power market structures, could increase costs or reduce revenues.

 

LG&E and KU are members of the MISO and have transferred functional control of their transmission systems to the MISO. The Companies must incur MISO membership-related costs and charges established by the MISO and can be required to incur other expenses or make transmission and generation operating decisions as directed by the MISO. The MISO Day 2 markets, which began operation in April 2005, have represented a significant change in the wholesale power market structure and operation. Until the market matures, the effects on results of operations, financial position, or liquidity will remain difficult to predict.

 

LG&E and KU have commenced proceedings at the Kentucky Commission and the FERC seeking authority to exit the MISO. On March 17, 2006, the FERC issued an order conditionally approving the request of KU and LG&E to exit the MISO. For further discussion see Note 16 of LG&E’s Notes to Financial Statements and Note 15 of KU's Notes to Financial Statements under Item 8.

 

LG&E and KU undertake significant capital projects and are subject to unforeseen costs, delays or failures in such projects, as well as risk of full recovery of such costs.

 

In the ordinary course of business, the Companies are continually developing, permitting and constructing new generation and transmission facilities, as well as maintaining and improving existing facilities. The completion of these facilities without delays or cost overruns is subject to risks in many areas, including approval and licensing, permitting, construction problems or delays, contractor performance, weather and geological issues, and political, labor and regulatory developments. Delays, additional costs or unsatisfactory regulatory treatment can result in reduced earnings. Further, if construction projects are not completed according to specifications, the Companies may incur reduced plant efficiency, higher operating costs or continued capital costs.

 

Projects underway at LG&E and KU include plans to construct a new base-load generating plant, Trimble County Unit 2, and associated transmission facilities; the upgrade or construction of other transmission facilities; and the installation of significant on-going emissions reduction equipment. These projects are in varying stages of construction, planning or regulatory approval.

 

22



 

LG&E’s and KU’s costs of compliance with environmental laws are significant and are subject to continuing changes.

 

LG&E and KU are subject to extensive federal, state and local environmental requirements which, among other things, regulate air emissions, water discharges and the management of hazardous and solid waste in order to adequately protect the environment. Compliance by the Companies requires significant expenditures for installation of pollution control equipment, environmental monitoring, emission fees and permits at all of their facilities. If the Companies fail to comply with environmental laws and regulations, even if caused by factors beyond their control, civil or criminal penalties and fines can result. Revised or additional laws and regulations could result in significant additional expense and operating restrictions on LG&E’s or KU’s facilities or increased compliance costs which may not be fully recoverable from customers. The cost impact of such changes would depend upon the specific requirements enacted and cannot be determined at this time.

 

LG&E and KU are undertaking significant emissions construction projects relating to upcoming compliance with the Clean Air Act, CAIR and CAMR standards, among others. Rate recovery and other regulatory proceedings regarding these matters occur periodically and will continue for some time.

 

LG&E’s and KU’s operating results are affected by weather conditions, including storms and seasonal temperature variations, as well as by significant man-made or accidental disturbances.

 

Customer demand for electricity and natural gas is seasonal and can cause extreme variability in load due to higher or lower than normal temperatures. Generally, demand for electricity peaks during the summer and demand for natural gas peaks during the winter. As a result, LG&E’s and KU’s overall operating results can fluctuate substantially on a seasonal basis. LG&E and KU maintain adequate generating and natural gas supply resources to accommodate system demands for electricity and natural gas. In addition, the Companies have generally sold less electricity or natural gas, as applicable, and consequently earned lower revenues, when weather conditions have been milder. However, the natural gas rates contain a WNA mechanism which adjusts the distribution cost recovery component of the natural gas billings of residential and commercial customers to normal temperatures during the heating season months of November through April, somewhat mitigating the effect of weather extremes. Severe weather, such as tornadoes, ice storms, thunderstorms, high wind or floods could also significantly affect the Companies’ operations by causing power outages, damaging infrastructure and requiring significant repair costs. Terrorism, explosions or fires pose similar risks. LG&E and KU maintain a comprehensive storm management plan for efficient and timely restoration of service to customers after major storm events.

 

LG&E’s and KU’s businesses are concentrated in the Midwest United States, specifically Kentucky.

 

The operations of the Companies are concentrated in Kentucky and are therefore impacted by changes in the Midwest United States economy in general, and the Kentucky economy in particular. General economic conditions, such as population growth, industrial growth or expansion and economic development, as well as the operational or financial performance of major industries or customers in the Companies’ service territories can affect the demand for electricity and natural gas.

 

LG&E and KU are subject to operational risks relating to their generating plants, transmission facilities and distribution equipment.

 

Operation of power plants, transmission and distribution facilities subject LG&E and KU to many risks, including the breakdown or failure of equipment, accidents, labor disputes, delivery/transportation problems, disruptions of fuel supply and performance below expected levels. Because LG&E’s and KU’s transmission facilities are interconnected with those of third parties, the operation of their facilities may be

 

23



 

adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties. Operation of the Companies’ power plants below expected capacity levels could result in lost revenues or increased expenses, including higher maintenance costs that may not be recovered from customers. Unplanned outages may result in significant replacement power costs. While LG&E and KU believe appropriate prevention or mitigation measures are in place, where possible, with respect to these potential business disruptions, no assurances can be given that such events will not occur in the future or will not negatively affect their financial condition or results of operations.

 

LG&E and KU could be negatively affected by downgrades to credit ratings or other negative developments in their ability to access capital markets.

 

In the ordinary course of business, the Companies have significant long-term and short-term financing requirements to fund their capital expenditures, debt interest or maturities and operating needs. If rating agencies were to downgrade the Companies’ credit ratings, particularly below investment grade, or withdraw such ratings, it could significantly limit access to the capital market and the Companies’ borrowing costs could increase. In addition, the Companies’ financing costs can also be affected by financial matters involving their parent holding company, including its overall credit rating, its provision of intra-company financing and the terms and rates of such financing.

 

LG&E and KU are subject to commodity price risk, credit risk, counterparty risk and other risks associated with the energy business.

 

LG&E and KU are exposed to purchase and sales market operating and financial risks common to utility operations. Although the Companies operate largely in regulated markets, increases in the cost of power and fuel, such as coal or natural gas, as well as other major inputs and supplies, can affect their margins because authorized rate structures and pass-through cost mechanisms may include timing lags or regulatory discretion which do not lead to full cost recovery. Changes in the wholesale market price for electricity can impact LG&E’s and KU’s financial results by altering the revenues from off-system sales of excess power from period to period. LG&E and KU are also exposed to risk that counterparties could fail to perform their obligations to provide energy, fuel, goods, services or payments resulting in potential increased costs to the Companies.

 

LG&E and KU are subject to risks associated with defined benefit retirement plans, health care plans, wages and other employee-related benefits.

 

The Companies’ funding obligations concerning defined benefit and postretirement plans are subject to risks relating to developments in future costs, returns on investments, interest rates and other actuarial matters which may differ from assumptions currently in effect for the plans and may lead to higher required funding outlays. Further, higher wage levels, whether related to collective bargaining agreements or employment market conditions, and costs of providing health care benefits to employee may adversely affect LG&E’s and KU’s results of operations, financial position or liquidity.

 

Item 1B. Unresolved Staff Comments.

 

None.

 

24



 

ITEM 2. Properties.

 

LG&E’s power generating system consists of the coal-fired units operated at its three steam generating stations. Combustion turbines supplement the system during peak or emergency periods. LG&E owns and operates the following electric generating stations unless otherwise stated:

 

 

 

Summer Capability
Rating (Kw)

 

Steam Stations:

 

 

 

Mill Creek – Jefferson County, KY

 

 

 

Unit 1

 

303,000

 

Unit 2

 

301,000

 

Unit 3

 

391,000

 

Unit 4

 

477,000

 

Total Mill Creek

 

1,472,000

 

 

 

 

 

Cane Run – Jefferson County, KY

 

 

 

Unit 4

 

155,000

 

Unit 5

 

168,000

 

Unit 6

 

240,000

 

Total Cane Run

 

563,000

 

 

 

 

 

Trimble County – Trimble County, KY (a)

 

 

 

Unit 1

 

383,000

 

 

 

 

 

Combustion Turbine Generators (Peaking capability):

 

 

 

Zorn Run – Jefferson County, KY

 

14,000

 

Paddy’s Run – Jefferson County, KY (b)

 

119,000

 

Cane Run – Jefferson County, KY

 

14,000

 

Waterside – Jefferson County, KY

 

22,000

 

E.W. Brown – Mercer County, KY (Units 5,6,7) (c)

 

190,000

 

Trimble County – Trimble County, KY (d)

 

328,000

 

Total combustion turbine generators

 

687,000

 

 

 

 

 

Total capability rating

 

3,105,000

 

 


(a)          Amount shown represents LG&E’s 75% interest in Trimble County 1. See Notes 10 and 11 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 Paddy’s Run Units 11 and 12. See Notes 10 and 11 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, 38% interest in Units 6 and 7 at E.W. Brown and 10% of the Inlet Air Cooling system, attributable to Brown Unit 5. See Notes 10 and 11 of LG&E’s Notes to Financial Statements, under Item 8 for further discussion on ownership. KU operates these units on behalf of LG&E.

(d)         Amount shown represents LG&E’s 29% interest in Units 5 and 6 and LG&E’s 37% interest in Units 7, 8, 9 and 10 at Trimble County. See Notes 10 and 11 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 Jefferson County, Kentucky (Ohio Falls), with an expected summer capability rating of 48 Mw, operated under a license issued by the FERC.

 

25



 

At December 31, 2005, LG&E’s electric transmission system included 21 substations dedicated solely to transmission and an additional 20 substations shared with the distribution system with a total capacity of approximately 12,000 Mva and approximately 899 miles of lines. The electric distribution system included 93 substations (20 of which are shared by the transmission system) with a total capacity of approximately 4,865 Mva, 3,934 miles of overhead lines and 2,035 miles of underground conduit.

 

LG&E’s natural gas transmission system includes 257 miles of transmission mains, and the natural gas distribution system includes 4,133 miles of distribution mains.

 

LG&E operates underground natural gas storage facilities with a current working gas capacity of approximately 15.1 million Mcf. See Gas Supply under Item 1.

 

In 1990, LG&E entered into an operating lease for its corporate office building located in downtown Louisville, Kentucky. The lease 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. In addition, Fidelia has a second secured lien on the property subject to the first mortgage bond lien.

 

26



 

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 unless otherwise stated:

 

 

 

Summer Capability
Rating (Kw)

 

Steam Stations:

 

 

 

Tyrone – Woodford County, KY

 

 

 

Unit 1

 

27,000

 

Unit 2

 

31,000

 

Unit 3

 

71,000

 

Total Tyrone

 

129,000

 

 

 

 

 

Green River – Muhlenberg County, KY

 

 

 

Unit 3

 

68,000

 

Unit 4

 

95,000

 

Total Green River

 

163,000

 

 

 

 

 

E.W. Brown – Mercer County, KY

 

 

 

Unit 1

 

101,000

 

Unit 2

 

167,000

 

Unit 3

 

429,000

 

Total E.W. Brown

 

697,000

 

 

 

 

 

Ghent – Carroll County, KY

 

 

 

Unit 1

 

475,000

 

Unit 2

 

484,000

 

Unit 3

 

493,000

 

Unit 4

 

493,000

 

Total Ghent

 

1,945,000

 

 

 

 

 

Combustion Turbine Generators (Peaking capability):

 

 

 

E.W. Brown – Mercer County, KY (Units 5-11) (a)

 

757,000

 

Haefling – Fayette County, KY

 

36,000

 

Paddy’s Run – Jefferson County, KY (b)

 

74,000

 

Trimble County – Trimble County, KY (c)

 

632,000

 

Total combustion turbine generators

 

1,499,000

 

 

 

 

 

Total capability rating

 

4,433,000

 

 


(a)          Amount shown represents KU’s 47% interest in Unit 5, 62% interest in Units 6 and 7, 100% of units 8-11 at E.W. Brown and 90% of the Inlet Air Cooling system, attributable to E.W. Brown CT Unit 5 and Units 8 to 11. See Notes 10 and 11 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 10 and 11 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 and KU’s 63% interest in Units 7, 8, 9 and 10 at Trimble County. See Notes 10 and 11 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 28 Mw nameplate-rated hydroelectric generating station located in Mercer County, Kentucky (Dix Dam), with an expected summer capability rating of 24 Mw, operated under a license issued by the FERC.

 

At December 31, 2005, KU’s electric transmission system included 110 substations with a total capacity of

 

27



 

approximately 16,978 Mva and approximately 4,031 miles of lines. The electric distribution system included 492 substations with a total capacity of approximately 6,322 Mva, 13,746 miles of overhead lines and 1,704 miles of underground conduit.

 

Other properties owned by KU include office buildings, service centers, warehouses, garages and other structures and equipment.

 

The trust indenture securing KU’s first mortgage bonds constitutes a direct first mortgage lien upon much of the property owned by KU. In addition, Fidelia has a second secured lien on the property subject to the first mortgage bond lien.

 

ITEM 3. Legal Proceedings.

 

Rates and Regulatory Matters

 

For a discussion of current rate and regulatory matters, including electric and natural gas base rate increase proceedings, the Kentucky attorney general investigation, VDT proceedings, Trimble County Unit 2 proceedings,  Kentucky Commission, FERC and MISO proceedings, and other rate or regulatory matters affecting LG&E and KU, see Rates and Regulation for LG&E and KU under Item 1 and Note 3 of LG&E’s and KU’s Notes to Financial Statements under Item 8.

 

Environmental

 

For a discussion of environmental matters including additional reductions in SO2, NOx and other emissions mandated by recent regulations; items regarding LG&E’s Mill Creek generating plant, KU’s E.W. Brown plant and LG&E’s and KU’s manufactured gas plant sites; and other environmental items affecting LG&E and KU, see Executive Summary (Environmental Matters) and Note 10 of LG&E’s and KU’s Notes to Financial Statements under Item 8.

 

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 plaintiffs’ claims. To date, the U.S. Equal Employment Opportunity Commission has declined to proceed to litigation on any claims reviewed. Through continuing mediation, settlements have been reached with the majority of plaintiffs, including the lead plaintiff. Negotiations continue with six plaintiffs. The complaint contains a claimed damage amount of $100 million as well as requests for injunctive relief, however, all prior settlements have been for non-material amounts and LG&E does not anticipate that the remaining outcome will have a material impact on its operations or financial condition.

 

Owensboro Contract Litigation

 

In May 2004, the City of Owensboro, Kentucky and Owensboro Municipal Utilities (collectively “OMU”), commenced a suit now removed to the U.S. District Court for the Western District of Kentucky, against KU concerning a long-term power supply contract (the “OMU Agreement”) with KU. The dispute involves interpretational differences regarding issues under the OMU Agreement, including various payments or charges

 

28



 

between KU and OMU and rights concerning excess power, termination and emissions allowances, respectively. The complaint seeks approximately $6 million in damages for periods prior to 2004 and OMU is expected to claim further amounts for later-occurring periods. OMU has additionally requested injunctive and other relief, including a declaration that KU is in material breach of the contract. KU has filed an answer in that court denying the OMU claims and presenting counterclaims. During 2005, the FERC declined KU’s application to exercise exclusive jurisdiction on matters. In July 2005, the district court resolved a summary judgment motion of KU in OMU’s favor, ruling that a contractual provision grants OMU the ability to terminate the contract without cause upon four years’ prior notice, which ruling is not yet final. At this time, the district court case is in the discovery stage and a trial schedule has not yet been established.

 

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 financial position or results of operations, respectively.

 

ITEM 4. Submission of Matters to a Vote of Security Holders.

 

None.

 

PART II.

 

ITEM 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

 

LG&E:

 

All LG&E common stock, 21,294,223 shares, is held by E.ON U.S. Therefore, there is no public market for LG&E’s common stock.

 

The following table sets forth LG&E’s cash distributions on common stock paid to E.ON U.S. during 2005:

 

(in millions)

 

 

 

First quarter

 

$

29

 

Second quarter

 

10

 

Third quarter

 

 

Fourth quarter

 

 

 

LG&E paid cash distributions on common stock to E.ON U.S. in the amount of $57 million in 2004 and $0 in 2003.

 

KU:

 

All KU common stock, 37,817,878 shares, is held by E.ON U.S. 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 E.ON U.S. during 2005:

 

29



 

(in millions)

 

 

 

First quarter

 

$

30

 

Second quarter

 

10

 

Third quarter

 

10

 

Fourth quarter

 

 

 

KU paid cash distributions on common stock to E.ON U.S. in the amount of $63 million in 2004 and $0 in 2003.

 

30



 

ITEM 6. Selected Financial Data.

 

 

 

Years Ended December 31

 

(in millions)

 

2005

 

2004

 

2003

 

2002

 

2001

 

 

 

 

 

 

 

 

 

 

 

 

 

LG&E:

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

 

$

1,424

 

$

1,173

 

$

1,094

 

$

1,004

 

$

965

 

 

 

 

 

 

 

 

 

 

 

 

 

Net operating income

 

$

230

 

$

185

 

$

179

 

$

173

 

$

205

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

$

129

 

$

96

 

$

91

 

$

89

 

$

107

 

 

 

 

 

 

 

 

 

 

 

 

 

Total assets

 

$

3,146

 

$

2,967

 

$

2,882

 

$

2,769

 

$

2,448

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term obligations (including amounts due within one year)

 

$

821

 

$

872

 

$

798

 

$

617

 

$

617

 

 

LG&E’s Management’s Discussion and Analysis of Financial Condition and Results of Operation and LG&E’s Notes to Financial Statements should be read in conjunction with the above information.

 

 

 

Years Ended December 31

 

(in millions)

 

2005

 

2004

 

2003

 

2002

 

2001

 

 

 

 

 

 

 

 

 

 

 

 

 

KU:

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

 

$

1,207

 

$

995

 

$

892

 

$

862

 

$

821

 

 

 

 

 

 

 

 

 

 

 

 

 

Net operating income

 

$

202

 

$

228

 

$

162

 

$

163

 

$

179

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

$

112

 

$

134

 

$

91

 

$

93

 

$

96

 

 

 

 

 

 

 

 

 

 

 

 

 

Total assets

 

$

2,756

 

$

2,610

 

$

2,505

 

$

2,252

 

$

1,827

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term obligations (including amounts due within one year)

 

$

747

 

$

726

 

$

688

 

$

501

 

$

489

 

 

KU’s Management’s Discussion and Analysis of Financial Condition and Results of Operation and KU’s Notes to Financial Statements should be read in conjunction with the above information.

 

31



 

ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

GENERAL

 

The following discussion and analysis by management focuses on those factors that had a material effect on LG&E and KU’s financial results of operations and financial condition during 2005, 2004 and 2003 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 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 and KU’s reports to the SEC, including Risk Factors in Item 1A of this report on Form 10-K and in Exhibit No. 99.01 to this report on Form 10-K.

 

EXECUTIVE SUMMARY

 

Our Business

 

LG&E and KU are each subsidiaries of E.ON U.S., which is an indirect subsidiary of E.ON, a German company. LG&E and KU maintain separate corporate identities and serve customers in Kentucky, Virginia and Tennessee under their respective names.

 

LG&E, incorporated in 1913 in Kentucky, is a regulated public utility that supplies natural gas to approximately 321,000 customers and electricity to approximately 394,000 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. LG&E also provides natural gas service in limited additional areas. LG&E’s coal-fired electric generating plants, all equipped with systems to reduce SO2 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 natural gas service to customers.

 

KU, incorporated in Kentucky in 1912 and incorporated in Virginia in 1991, is a regulated public utility that provides electricity to approximately 495,000 customers in over 600 communities and adjacent suburban and rural areas in 77 counties in central, southeastern and western Kentucky, to approximately 30,000 customers in 5 counties in southwestern Virginia and 5 customers in Tennessee. KU’s coal-fired electric generating plants produce most of KU’s electricity, the remainder is generated by hydroelectric power plants and combustion turbines. In Virginia, KU operates under the name Old Dominion Power Company. KU also sells wholesale electric energy to 12 municipalities.

 

32



 

Our Customers

 

The following table provides statistics regarding LG&E and KU retail customers:

 

Customers (in thousands)

 

 

 

LG&E

 

KU

 

2005% Retail Revenues

 

 

 

Electric

 

Gas

 

Electric

 

LG&E

 

KU

 

Retail Customer Data

 

2005

 

2004

 

2003

 

2005

 

2004

 

2003

 

2005

 

2004

 

2003

 

Electric

 

Gas

 

Electric

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

 

347

 

343

 

337

 

296

 

293

 

287

 

433

 

426

 

421

 

40

%

64

%

38

%

Industrial & Commercial

 

41

 

41

 

41

 

24

 

24

 

24

 

82

 

82

 

82

 

50

%

31

%

49

%

Other

 

6

 

6

 

6

 

1

 

1

 

1

 

10

 

10

 

9

 

10

%

5

%

13

%

Total Retail

 

394

 

390

 

384

 

321

 

318

 

312

 

525

 

518

 

512

 

100

%

100

%

100

%

 

Our Mission

 

The mission of LG&E and KU is to build on our tradition and achieve world-class status providing reliable, low-cost energy services and superior customer satisfaction; and to promote safety, financial success and quality of life for our employees, communities and other stakeholders.

 

Our Strategy

 

LG&E’s and KU’s strategy focuses on the following:

 

                  Achieve scale as an integrated U.S. electric and gas business through organic growth;

                  Maintain excellent customer satisfaction;

                  Maintain best-in-class cost position versus U.S. utility companies;

                  Develop and transfer best practices throughout the company;

                  Invest in infrastructure to meet expanding load and comply with increasing environmental requirements;

                  Achieve appropriate regulated returns on all investment;

                  Attract, retain and develop the best people; and

                  Act with a commitment to corporate social responsibility that enhances the well being of our employees, demonstrates environmental stewardship, promotes quality of life in our communities and reflects the diversity of the society we serve.

 

Low Rates

 

LG&E and KU believe they are well positioned in the regulated Kentucky market. LG&E and KU continue to sustain high customer satisfaction, ranking first among all large Midwest utilities for the 6th time in 7 years in the J.D. Power and Associates 2005 survey of residential electric customers. This excellent performance is balanced with cost control. The customer benefits of the LG&E and KU culture of cost management are evident in rate comparisons among U.S. utilities. The following chart compares the total residential average rate per thousand Kwh of U.S. investor-owned utilities as of July 1, 2005:

 

33



 

 

Source: Edison Electric Institute, Summer 2005 Typical Bills and Average Rates Report; Residential rates in effect July 1, 2005, based on 1,000 kWh monthly usage.

 

LG&E and KU must continue to address new cost pressures. The Kentucky Commission accepted the settlement agreements reached by the majority of the parties in the rate cases filed by LG&E and KU in December 2003. New rates, implemented in July 2004, produced approximately $55 million of revenue for LG&E and approximately $46 million of revenue for KU for a full year. Under the settlement agreements, the LG&E utility base electric rates have increased approximately $43 million (7.7%) and base natural gas rates have increased approximately $12 million (3.4%) annually. Base electric rates at KU have increased approximately 6.8% annually. The 2004 increases were the first increases in electric base rates for LG&E and KU in 13 and 20 years, respectively; the last natural gas rate increase for the LG&E natural gas utility took effect in September 2000. Competitors also face these same cost pressures that caused LG&E and KU to initiate rate cases (e.g., pensions, benefits and reliability expenditures) and many other utility companies already have rate cases in process. Despite these increases, LG&E and KU rates remain significantly lower than the national average.

 

Commodity Prices: Fuel and Electricity

 

Natural gas prices have risen dramatically in 2005, averaging over $8/MMBtu and spiking as high as $15/MMBtu in late September following the hurricanes that interrupted natural gas production activities in the Gulf of Mexico. Although the supply problems created by the hurricanes have improved significantly, the underlying and fundamental U.S. supply-demand imbalance shows no sign of easing. While U.S. natural gas reserves are in structural decline, natural gas demand is increasing. The natural gas outlook is projected to maintain this pattern until significant new supply, in the form of LNG or new discoveries, enters the marketplace.

 

Coal price increases continued during 2005, up nearly 60% overall since the beginning of 2004, with modest increases projected over the near term. The rise in oil and natural gas prices, combined with the supply of coal not keeping pace with demand, have resulted in substantially higher coal prices over the last two years.

 

34



 

The graph displays the LG&E, KU and combined utility average utility natural gas and coal purchase prices.

 

 

 

Actual natural gas costs are recovered from customers through the GSC. The GSC also contains an incentive component, the PBR component, which is determined for each 12-month period ending October 31.

 

Actual fuel costs associated with retail electric sales are recovered from customers through the FAC. The Utilities’ base rates contain an embedded fuel cost component. The FAC reconciles the difference between this fuel cost component and the actual fuel cost, including transportation costs. Refunds to customers occur if the actual costs are below the embedded cost component. Additional charges to customers occur if the actual costs exceed the embedded cost component.

 

With respect to wholesale electricity prices, generation over-capacity in the Midwest United States is forecasted to persist, with reserve margins over 23% for ECAR in 2006. However, the over-capacity results largely from the construction of natural gas-fired units. High natural gas prices have supported higher wholesale electricity prices, providing advantages to coal-fired generation. While the regional reserve margin is expected to decline over time as new capacity construction slows and demand grows, natural gas-fired generation is expected to set prices, particularly during times of higher loads. This expectation, combined with the expectation that natural gas prices will remain high, indicates that peak electricity prices are expected to remain high.

 

Generation Reliability

 

Generation reliability also remains a key aspect to meeting the Companies’ strategy. LG&E and KU believe that they have maintained good performance and reliability in the key area of utility generation operation. While maintaining low cost levels, LG&E and KU have also been able to generate increasing volumes and expect to continue high levels of availability and low outage levels. This performance is also important to maintaining margins from off-system sales.

 

Generation Capacity

 

The installation of Trimble County Units 7-10, completed in 2004, increased total system capability by 9%. However, the IRP submitted by LG&E and KU to the Kentucky Commission in 2005, outlining the least cost alternative to meet Kentucky’s needs, indicated the requirement for additional base-load capacity by 2010. Consequently, LG&E and KU have begun development efforts for another base-load coal-fired unit at the Trimble County site. LG&E and KU believe this is the least cost alternative to meet the future needs of

 

35



 

customers. Trimble County Unit 2, with a 750 MW capacity rating, is expected to be jointly owned by LG&E and KU (75% owners of the unit) and IMEA and IMPA (25% owners). Trimble County Unit 2 is expected to cost $1.1 billion and be completed by 2010. LG&E’s and KU’s aggregate 75% share of the total Trimble County Unit 2 capital cost is approximately $885 million and is estimated to be approximately $120 million and $510 million, respectively, through 2008.

 

An application for a construction CCN was filed with the Kentucky Commission in December 2004 and initial CCN applications for three transmission lines were filed in early 2005, with further applications submitted in December 2005. The proposed air permit was filed with the Kentucky Division for Air Quality in December 2004. In November 2005, the Kentucky Commission approved the application of LG&E and KU to expand the Trimble County generating plant. Kentucky Commission approval for one transmission line CCN was granted in September 2005 and a ruling that a second transmission line was not subject to the CCN process was received in February 2006. LG&E and KU hope to obtain approval for the remaining transmission line CCN during 2006. The transmission lines are also subject to routine regulatory filings and the right-of-way acquisition process. In November 2005, the Kentucky Division for Air Quality issued the final air permit, which was challenged in December 2005 by an environmental advocacy group. Administrative proceedings with respect to the challenge are expected to commence during the first quarter of 2006.

 

In October 2005, LG&E received from the FERC a new license to upgrade, operate and maintain the Ohio Falls Hydroelectric Project. The license is for a period of 40 years, effective November 2005. LG&E intends to spend approximately $76 million to refurbish the facility and add approximately 20 Mw of generating capacity over the next seven years.

 

Environmental Matters

 

In addition to the Trimble County Unit 2 project, the second major area of utility investment is environmental expenditures. LG&E and KU are subject to SO2 and NOx emission limits on their electric generating units pursuant to the Clean Air Act. LG&E and KU placed into operation significant NOx controls for their generating units prior to the 2004 summer ozone season. As of December 31, 2005, LG&E and KU have incurred total capital costs of approximately $188 million and $217 million, respectively, since 2000 to reduce their NOx emissions below required levels. In addition, LG&E and KU have incurred additional operating and maintenance costs in operating the new NOx controls.

 

In March 2005, the EPA issued the final CAIR which requires substantial additional reductions in SO2 and NOx emissions from electric generating units. The CAIR provides for a two-phased reduction program with Phase I reductions in NOx and SO2 emissions in 2009 and 2010, respectively, and Phase II reductions in 2015. On March 15, 2005, the EPA issued a related regulation, the final CAMR, which requires substantial mercury reductions from electric generating units. CAMR also provides for a two-phased reduction, with the Phase I target in 2010 achieved as a “co-benefit” of the controls installed to meet CAIR. Additional control measures will be required to meet the Phase II target in 2018. Both CAIR and CAMR establish a cap and trade framework, in which limits are set on total emissions and allowances can be bought or sold on the open market, to be used for compliance, unless the state chooses another approach.

 

In order to meet these new regulatory requirements, KU has implemented a plan for adding significant additional SO2 controls to its generating units. Installation of additional SO2 controls will proceed on a phased basis, with construction of controls (i.e., FGDs) having commenced in September 2005, and continuing through the final installation and operation in 2009. KU estimates that it will incur approximately $560 million in capital costs related to the construction of the FGDs over the next three years to achieve compliance with current emission limits on a company-wide basis. In addition, KU will incur additional operating and maintenance costs

 

36



 

in operating the new SO2 controls. LG&E currently has FGDs on all its units but will continue to evaluate improvements to further reduce SO2 emissions.

 

Kentucky law permits LG&E and KU to recover the costs of complying with the Federal Clean Air Act, including a return of operating expenses, and a return of and on capital invested, through the ECR mechanism. Approximately 80% of the applicable environmental costs, including investment and operating costs, are recoverable through the ECR. The remaining 20%, attributable to off-system and non-Kentucky jurisdictional sales, are not recoverable through the ECR.

 

COMPANY STRUCTURE

 

As contemplated in their regulatory filings in connection with the E.ON acquisition of Powergen in 2002, E.ON, Powergen and E.ON U.S. completed an administrative reorganization to move the LG&E Energy Corp. group from an indirect Powergen subsidiary to an indirect E.ON subsidiary. This reorganization was effective in March 2003. In early 2004, E.ON U.S. began direct reporting arrangements to E.ON.

 

Effective December 30, 2003, LG&E Energy LLC became the successor, by assignment and subsequent merger, to all the assets and liabilities of LG&E Energy Corp.

 

Effective December 1, 2005, LG&E Energy LLC was renamed E.ON U.S. LLC.

 

The utility operations of E.ON U.S. have continued their separate identities as LG&E and KU. The preferred stock and debt securities of LG&E and KU were not affected by these transactions.

 

37



 

RESULTS OF OPERATIONS

 

LG&E

 

Net Income

 

LG&E’s net income in 2005 increased $33.3 million (34.8%) compared to 2004. The increase resulted primarily from higher electric revenues due to increased retail sales volumes resulting from warmer summer weather and increased base rates implemented for service rendered on and after July 1, 2004. Wholesale revenues also increased due to higher volumes and higher prices. These increases were partially offset by increased fuel and power purchased costs largely due to MISO Day 2 costs.

 

LG&E’s net income in 2005 related to the electric business increased $32.2 million (36.9%) compared to 2004. Electric operating revenues increased $171.7 million (21.0%), partially offset by higher fuel for electric generation and power purchased of $122.6 million (40.8%). Income tax and depreciation expense increased $11.7 million (24.2%) and $6.2 million (6.2%), respectively.

 

LG&E’s net income in 2005 related to the natural gas business increased $1.1 million (13.1%) compared to 2004. Natural gas operating revenues increased $79.8 million (22.3%) offset by higher natural gas supply expenses of $73.4 million (27.6%). Other natural gas operations and maintenance expenses increased $3.6 million (7.2%) and depreciation expense increased $1.3 million (7.8%).

 

During 2005, LG&E made out-of-period adjustments for estimated over/under collection of ECR revenues to be billed in subsequent periods. The adjustments related to the reporting periods of March 2003 through December 2004. As a result, LG&E revenues for 2005 increased by $5.3 million and net income for 2005 increased by $3.2 million. LG&E revenues for 2004 and 2003 were understated by $2.4 million and $2.9 million, respectively, and net income was understated by $1.4 million and $1.8 million, respectively.

 

LG&E’s net income in 2004 increased $4.8 million (5.3%) compared to 2003. The increase resulted primarily from higher electric revenues due to increased base rates implemented for service rendered on and after July 1, 2004, following the electric rate case order and higher wholesale revenues, somewhat offset by higher maintenance expenses related to storm restoration costs. Operating expenses for 2004 reflect $12.7 million in expenses related to severe May and July storms.

 

LG&E’s net income in 2004 related to the electric business increased $6.6 million (8.2%) compared to 2003. Electric operating revenues increased $47.5 million (6.2%), offset by higher fuel for electric generation and power purchased of $22.8 million (8.2%). Other electric operations and maintenance expenses increased $11.1 million (4.9%). Electric depreciation expense increased $3.5 million (3.6%). Interest expense increased $1.6 million (6.2%).

 

LG&E’s net income in 2004 related to the natural gas business decreased $1.8 million (17.6%) compared to 2003. Natural gas operating revenues increased $31.8 million (9.8%) offset by higher natural gas supply expenses of $32.4 million (13.9%). Other natural gas operations and maintenance expenses increased $2.0 million (4.2%).

 

38



 

Revenues

 

The following table presents a comparison of operating revenues for the years 2005 and 2004 with the immediately preceding year.

 

(in millions)

 

 

 

 

 

 

 

 

 

Increase (Decrease) From Prior Period

 

 

 

Electric Revenues

 

Gas Revenues

 

Cause

 

2005

 

2004

 

2005

 

2004

 

Retail sales:

 

 

 

 

 

 

 

 

 

Fuel and gas supply adjustments

 

$

23.3

 

$

5.8

 

$

66.6

 

$

33.6

 

LG&E/KU Merger surcredit

 

(1.0

)

(2.3

)

 

 

Environmental cost recovery surcharge

 

10.0

 

7.3

 

 

 

Earnings sharing mechanism

 

(5.6

)

(5.8

)

 

 

Demand side management

 

(0.3

)

0.4

 

 

(0.6

)

VDT surcredit

 

(0.9

)

(1.1

)

(0.6

)

0.1

 

Weather normalization adjustment

 

 

 

(2.7

)

3.2

 

Rate changes

 

24.8

 

16.8

 

4.9

 

7.0

 

Variation in sales volumes and other

 

27.5

 

11.8

 

(0.1

)

(5.8

)

Total retail sales

 

77.8

 

32.9

 

68.1

 

37.5

 

Wholesale

 

73.7

 

15.8

 

11.8

 

(5.1

)

MISO Day 2

 

18.2

 

 

 

 

Gas transportation-net

 

 

 

(0.7

)

0.1

 

Other

 

2.0

 

(1.2

)

0.6

 

(0.7

)

Total

 

$

171.7

 

$

47.5

 

$

79.8

 

$

31.8

 

 

Electric revenues increased in 2005 primarily due to higher wholesale sales and MISO related revenues, higher fuel costs billed to the customer through the fuel adjustment clause and new rates implemented in July 2004. These increases were partially offset by the discontinuation of the ESM in the second quarter of 2005. Retail revenues increased 5.4% due to higher sales volume, primarily due to warmer summer weather than experienced in 2004. Cooling degree days increased 13% compared to 2004 and were 14% higher than the 20-year average. Wholesale revenues increased due to the combination of a 29% increase in prices and 11% higher volumes. The price increase was largely due to higher fuel prices and the volume increase was primarily due to increased demand for LG&E generation in the region.

 

Electric revenues increased in 2004 primarily due to new rates implemented in July 2004. Retail revenues increased 2.0% due to higher sales volume, primarily due to warmer summer weather than 2003. Cooling degree days increased 21% compared to 2003 and were 2% higher than the 20-year average.

 

Natural gas revenues in 2005 increased due to higher gas supply cost billed to customers through the gas supply clause and increased natural gas rates. New natural gas rates took effect in July 2004 increasing revenues by 1.3% in 2005. Despite remaining 1% lower than the 20-year average, the number of heating degree days in 2005 increased 6% as compared to 2004. This increase in heating degree days was offset by the effect of higher natural gas prices which curtailed natural gas usage and resulted in slightly lower natural gas sales volumes.

 

Natural gas revenues in 2004 increased due to higher gas supply cost billed to customers through the gas supply clause and increased gas rates. New natural gas rates took effect in July 2004 increasing revenues by 2.3% in 2004. These increases were partially offset by lower retail sales due to warmer winter weather and lower wholesale sales. Heating degree days decreased 8% as compared to 2003 and were 8% lower than the 20-year average.

 

39



 

Expenses

 

Fuel for electric generation and natural gas supply expenses comprise a large component of LG&E’s total operating costs. The retail electric rates contain an FAC and natural gas rates contain a GSC, whereby increases or decreases in the cost of fuel and natural 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 $74.1 million (35.6%) in 2005 primarily due to:

      Increased cost of fuel burned ($61.8 million) due to the MISO’s dispatch of natural gas-fired units and higher coal and natural gas prices

      Increased generation ($12.3 million) due to increased demand and the dispatch of units for MISO Day 2

 

Fuel for electric generation increased $10.3 million (5.2%) in 2004 primarily due to:

      Increased cost of fuel burned ($6.4 million) due to higher fuel prices

      Increased generation ($3.7 million) due to increased demand

 

Power purchased increased $48.5 million (52.7%) in 2005 primarily due to:

      Increased unit cost per Mwh of purchases ($40.7 million) due to higher fuel prices

      Increased volumes purchased ($7.7 million) due to increased demand and unit outages

                  Purchased power costs from the MISO due to unit outages totaled $9.8 million

 

Power purchased increased $12.5 million (15.7%) in 2004 primarily due to:

      Increased unit cost per Mwh of purchases ($9.0 million) due to higher fuel prices

      Increased volumes purchased ($3.4 million) due to increased demand and unit outages

 

Gas supply expenses increased $73.4 million (27.6%) in 2005 primarily due to:

      Increased cost of net gas supply ($61.7 million) due to the increase in natural gas prices in 2005

      Increased volumes of natural gas delivered to the distribution system ($11.7 million)

 

Gas supply expenses increased $32.4 million (13.9%) in 2004 primarily due to:

      Increased cost of net gas supply ($52.2 million) due to the increase in natural gas prices in 2004

      Decreased volumes of natural gas delivered to the distribution system ($19.8 million)

 

Other operation and maintenance expenses increased $3.1 million (1.0%) in 2005 primarily due to higher other operation expense ($10.6 million) and higher property taxes ($1.7 million), partially offset by lower maintenance expense ($9.2 million).

 

Other operation expenses increased $10.6 million (4.9%) in 2005 primarily due to:

      Increased other power supply costs ($17.2 million) due largely to MISO Day 2 costs ($18.2 million) for administrative and allocated charges from the MISO for Day 2 operations

      Increased steam generation expenses ($3.5 million) primarily for scrubber reactant and waste disposal

      Increased employee benefit costs ($3.3 million)

      Increased customer service and collection expenses ($2.0 million)

      Decreased transmission costs ($10.5 million), due largely to MISO Day 2 ($13.4 million). Prior to the MISO Day 2 market, most bilateral transactions required the purchase of transmission; however, with the Day 2 market, most transactions are handled directly with the MISO and no additional transmission is necessary

      Decreased distribution operating costs ($5.0 million) due to fewer storms in 2005

 

40



 

Maintenance expenses decreased $9.2 million (12.7%) in 2005 primarily due to:

      Decreased distribution maintenance ($8.5 million) due to fewer storms in 2005

      Decreased steam generation expense ($2.1 million)

      Increased administrative and general maintenance expenses ($1.3 million)

 

Other operation and maintenance expenses increased $14.6 million (5.0%) in 2004 primarily due to higher maintenance expenses ($15.6 million) and higher property and other taxes ($1.6 million), partially offset by lower operation expenses ($2.5 million).

 

Maintenance expenses increased $15.6 million (27.3%) in 2004 primarily due to:

      Increased distribution maintenance expense ($10.0 million) primarily due to restoration costs related to severe May and July storms

      Increased natural gas system maintenance and administrative and general expenses ($2.6 million)

      Increased steam generation expense due to timing of scheduled maintenance ($1.4 million)

      Increased combustion turbine and hydro generation maintenance ($1.6 million)

 

Other operation expenses decreased $2.5 million (1.2%) in 2004 primarily due to:

      The KU/LG&E merger costs and the One Utility initiative costs were fully amortized in 2003, resulting in $2.8 million lower expense in 2004

      Decreased benefits expense ($1.7 million), primarily due to lower pension expense ($2.1 million) as a result of the $34.5 million pension funding in January 2004, partially offset by higher medical insurance expense

      Decreased steam generation expense ($1.2 million)

      Increased operations expense due to storm restoration costs related to severe storms in May and July 2004 ($3.1 million)

 

Depreciation and amortization increased $7.5 million (6.4%) in 2005 and $3.3 million (2.9%) in 2004 due to additional plant in service.

 

Other income (expense) - net increased $4.0 million (121.2%) in 2005 primarily due to:

      Increased non-operating income ($2.3 million)

      Decreased income deductions ($1.3 million)

      Increased interest income ($0.3 million)

 

Other income (expense) - net increased $3.9 million (54.2%) in 2004 primarily due to:

      Decreased income deductions ($3.0 million) primarily for 2003 write-offs of terminated projects

      Increased other income ($0.9 million)

 

Interest expense increased $4.0 million (12.2%) in 2005 primarily due to:

      Increased interest rates on variable-rate debt ($6.4 million)

      Increased borrowing from the money pool ($1.5 million)

      Decreased cost of interest rate swaps ($3.2 million)

      Decreased costs due to refinancing fixed rate debt with variable rate debt ($0.8 million)

 

Interest expense increased $2.1 million (6.8%) in 2004 primarily due to:

      Increased borrowing from Fidelia ($6.9 million)

 

41



 

      Increased cost of interest rate swaps ($3.0 million)

      Increased cost of variable-rate debt ($0.8 million)

      Decreased cost due to lower first mortgage debt ($7.2 million)

      Decreased borrowing from the money pool ($1.4 million)

 

Details of LG&E’s exposure to variable interest rates on long-term debt are shown in the table below:

 

 

 

2005

 

2004

 

2003

 

Unswapped variable rate debt ($ in millions)

 

$

363.0

 

$

306.0

 

$

306.0

 

Percentage of unswapped variable rate debt to total long-term debt

 

44.2

%

35.1

%

38.3

%

Weighted average interest rate on variable rate debt for the year

 

2.49

%

1.28

%

1.10

%

Weighted average interest rate on total long-term debt at year-end, including expense amortization and interest rate swaps

 

4.13

%

3.92

%

3.58

%

 

See Note 8 of LG&E’s Notes to the Financial Statements under Item 8.

 

Variations in income tax expenses are largely attributable to changes in pre-tax income. LG&E’s 2005 effective income tax rate decreased to 33.5% from the 35.8% rate in 2004 primarily due to the reduction in tax accruals after the conclusion of IRS audits. See Note 7 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 forecasted and the best estimates routinely require adjustment. See also Note 1 of LG&E’s Notes to Financial Statements under Item 8.

 

Unbilled Revenue – At each month end LG&E prepares a financial estimate that projects electric and natural gas usage by customers that has not been billed. The estimated usage is based on allocating the daily system net deliveries between billed volumes and unbilled volumes. The allocation is based on a daily ratio of the number of meter reading cycles remaining in the month to the total number of meter reading cycles in each month. Each day’s ratio is then multiplied by each day’s system net deliveries to determine an estimated billed and unbilled volume for each day of the accounting period. At December 31, 2005, a 10% change in these estimated quantities would cause revenue and accounts receivable to change by approximately $8.2 million, including $3.2 million for electric usage and $5.0 million for natural gas usage. See also Note 1 of LG&E’s Notes to Financial Statements under Item 8.

 

42



 

Allowance for Doubtful Accounts – At December 31, 2005 and 2004, the LG&E allowance for doubtful accounts was $1.1 million and $0.8 million, respectively. The allowance is based on the ratio of the amounts charged-off during the last twelve months to the retail revenues billed over the same period multiplied by the retail revenues billed over the last four months. Accounts with no payment activity are charged-off after four months, although collection efforts continue thereafter.

 

Pension and Post-retirement Benefits – LG&E has both funded and unfunded non-contributory defined benefit pension and post-retirement benefit plans that together cover substantially all of its employees. The plans are accounted for under SFAS No. 87, Employers’ Accounting for Pensions, and SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other than Pensions.

 

The pension and other post-retirement benefit plan costs and liabilities are determined on an actuarial basis and are dependent upon numerous economic assumptions, such as discount rates, rates of compensation increases, estimates of the expected return on plan assets and health care cost trend rates and demographic and economic assumptions. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower health care costs or turnover, or longer or shorter life spans of participants. These differences may result in a significant impact on the amount of expenses recorded in future periods. The underlying assumptions and estimates related to the pension and post-retirement benefit plan costs and liabilities are reviewed annually.

 

The assumed discount rate, expected return on assets and rate of compensation increases generally have the most significant impact on the pension costs and liabilities. The discount rate is used to calculate the actuarial present value of the benefits provided by the plans. LG&E bases its discount rate assumption on Moody’s Aa Corporate Bond Rate rounded to the nearest 25 basis points, which has a duration comparable to the weighted average duration of the plans.

 

The expected long-term rate of return on assets is used to calculate the net periodic pension costs for the plans. To develop the expected long-term rate of return on assets assumption, consideration is given to the current level of expected returns on risk free investments (primarily government bonds), the historical performance of the asset managers versus their respective benchmarks, the historical level of the risk premium associated with the other asset classes in which the portfolio is invested and the expectations for future returns of each asset class. The expected return for each asset class is then weighted based on a target asset allocation. For 2005, the actual return on pension assets was comparable to the assumed expected rate of return.

 

The following describes the effects on pension benefits by changing the major actuarial assumptions discussed above:

 

                  A 1% change in the assumed discount rate could have an approximate $48.8 million positive or negative impact to the 2005 accumulated benefit obligation of LG&E.

                  A 25 basis point change in the expected rate of return on assets would have an approximate $0.8 million positive or negative impact on 2005 pension expense.

 

Compensation rate increases are used to calculate service costs and the projected benefit obligation. Such rates are based on a review of LG&E’s actual historical salaries, promotion and bonus increases. For 2005 net periodic pension benefit costs, LG&E used an assumption of 4.50%. Based on plan experience, the rate was increased to 5.25% for the projected benefit obligation at December 31, 2005.

 

43



 

When the plan experience differs from the actuarial assumptions, a portion of the difference may be deferred and is subject to amortization at rates based on the estimated average years of participants’ future service. LG&E’s deferred losses on these assumptions were $24.4 million (35%) higher in 2005 than 2004 and $14.0 million (25%) higher in 2004 than 2003, primarily due to declining discount rate assumptions during these years.

 

The assumptions related to the discount rate, retirement, turnover and healthcare cost trends, which represent expected rates of increase in health care claim payments, generally have the most significant impact on LG&E’s post-retirement benefit plan costs and liabilities. Unlike pensions, however, assumptions about per capita claims cost by age and participation rates also significantly impact post-retirement liability computations. A 1% change in the healthcare cost trend rates could have a positive or negative impact on the 2005 post-retirement benefit obligation and post-retirement expense of approximately $3.0 million and $0.3 million, respectively.

 

Additionally, demographic and other economic assumptions affect the pension and post-retirement computations. Beginning with the December 31, 2005 liability, LG&E replaced the 1983 Group Annuity Mortality tables for males and females with the RP 2000 combined tables for males and females projected to 2006. These updated healthy mortality tables will be used for the 2006 expense.

 

The benefit obligation is compared with the plan asset values to determine a net position. Asset values are increased primarily by actual rates of return on plan assets and by employer contributions. For explanation of the investment policy including targeted asset allocations, see Note 6 of LG&E’s Notes to Financial Statements under Item 8.

 

The pension plans are funded in accordance with all applicable requirements of the ERISA and the IRC. In accordance with the ERISA guidelines, LG&E made discretionary contributions to the pension plans of $89.1 million in 2003 and $34.5 million in 2004. No contributions were made in 2005. LG&E made a discretionary contribution of $17.5 million during 2006 and anticipates making additional contributions as deemed necessary. Additionally, LG&E made a contribution of $0.7 million to the post-retirement plan in 2005, representing the maximum employer contribution under IRC Section 401(h) requirements for all plan years through 2004. LG&E may continue to make subsequent contributions in accordance with the maximum funding limitation governed by tax laws.

 

As prescribed by SFAS No. 87, LG&E was required to recognize an additional minimum pension liability of $19.2 million and $10.2 million during 2005 and 2004, respectively, since the fair value of the plan assets was less than the accumulated benefit obligation at that time. This additional minimum pension liability was recorded as a reduction to other comprehensive income and did not affect net income. Historically low corporate bond rates, used to determine the discount rate, significantly increased the potential value of the pension liabilities above the actual value of the plan assets. 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 balance sheet. In 2003, LG&E recognized a reduction of the minimum pension liability of $3.1 million.

 

Should poor market conditions return or should interest rates decline further, LG&E’s unfunded accumulated benefit obligations and future pension expense could increase. The Company believes that such increases are recoverable in whole or in part under future rate proceedings or mechanisms.

 

See also Note 6 and Note 14 of LG&E’s Notes to Financial Statements under Item 8.

 

44



 

Regulatory Mechanisms – Judgments and uncertainties include future regulatory decisions, the impact of deregulation and competition on ratemaking process, and external regulatory 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 and liabilities would be required to be recognized in current period earnings.

 

See also Note 3 of LG&E’s Notes to Financial Statements under Item 8.

 

Income Taxes - Income taxes are accounted for under SFAS No. 109, Accounting for Income Taxes.  In accordance with this statement, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, as measured by enacted tax rates that are expected to be in effect in the periods when the deferred tax assets and liabilities are expected to be settled or realized. Significant judgment is required in determining the provision for income taxes, and there are transactions for which the ultimate tax outcome is uncertain.

 

To provide for these uncertainties or exposures, an allowance is maintained for tax contingencies based on management’s best estimate of probable loss. Tax contingencies are analyzed periodically and adjustments are made when events occur to warrant a change. On September 19, 2005, LG&E received notice from the Congressional Joint Committee on Taxation approving the Internal Revenue Service’s audit of LG&E’s income tax returns for the periods December 1999 through December 2003. As a result of resolving numerous tax matters during these periods, LG&E reduced income tax accruals by $3.8 million during 2005.

 

H. R. 4520, known as the “American Jobs Creation Act of 2004” allows electric utilities to take a deduction of up to 3% of their qualified production activities income in 2005. This deduction reduced LG&E’s effective tax rate by less than 1% for 2005.

 

Kentucky House Bill 272, also known as “Kentucky’s Tax Modernization Plan,” was signed into law in March 2005. This bill contains a number of changes in Kentucky’s tax system, including the reduction of the Corporate income tax rate from 8.25% to 7% effective January 1, 2005, and a further reduction to 6% effective January 1, 2007. As a result of the income tax rate change, LG&E’s deferred tax reserve amount will exceed its actual deferred tax liability attributable to existing temporary differences since the new statutory rates are lower than the rates were when the deferred tax liability originated. This excess amount is referred to as excess deferred income taxes. In June 2005, LG&E received approval from the Kentucky Commission to establish and amortize a regulatory liability ($16.3 million) for its net excess deferred income tax balances. Under this accounting treatment, LG&E will amortize its depreciation-related excess deferred income tax balances under the average rate assumption method. The average rate assumption method matches the amortization of the excess deferred income taxes with the life of the timing differences to which it relates. Excess deferred income tax balances related to non-depreciation timing differences will be expensed in the current year due to their immaterial amount.

 

LG&E expects to have adequate levels of taxable income to realize its recorded deferred taxes.

 

For further discussion of income tax issues, see Note 1 and Note 7 of LG&E’s Notes to Financial Statements

 

45



 

under Item 8.

 

NEW ACCOUNTING PRONOUNCEMENTS

 

The following recent accounting pronouncements affected LG&E in 2005 and 2004:

 

FIN 47

 

LG&E adopted Financial Accounting Standards Board Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143 (FIN 47) effective December 31, 2005. FIN 47 expands the term “conditional asset retirement obligation” as used in SFAS No. 143, Accounting for Asset Retirement Obligations, to refer to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. An entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred; generally, upon acquisition, construction, or development and through the normal operation of the asset.

 

As a result of the implementation of FIN 47, LG&E recorded additional ARO net assets and liabilities during the fourth quarter of 2005 in the amount of $1.0 million and $15.7 million, respectively. LG&E also recorded a cumulative effect adjustment in the amount of $12.3 million to reflect the accumulated depreciation and accretion of ARO assets at the transition date less amounts previously accrued under regulatory depreciation. A $2.4 million reduction in the accumulated cost of removal regulatory liability was also recorded for this previously accrued cost of removal. LG&E recorded offsetting regulatory assets of $12.3 million, pursuant to regulatory treatment prescribed under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, as the costs of removal are allowed under Kentucky Commission ratemaking.

 

Had FIN 47 been in effect at the beginning of the 2004 reporting period, LG&E would have established asset retirement obligations as described in the following table (in millions):

 

 

 

2005

 

2004

 

Provision at beginning of the year

 

$

14.8

 

$

14.0

 

Accretion expense

 

0.9

 

0.8

 

Provision at end of the year

 

$

15.7

 

$

14.8

 

 

See Note 1 of LG&E’s Notes to Financial Statements under Item 8 for further discussion of FIN 47.

 

LIQUIDITY AND CAPITAL RESOURCES

 

LG&E uses net cash generated from its operations and external financing (including financing from affiliates) 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.

 

As of December 31, 2005, LG&E is in a negative working capital position in part because of the classification of certain variable-rate pollution control bonds totaling $246.2 million that are subject to tender for purchase at the option of the holder as current portion of long-term debt. Backup credit facilities totaling $185 million are in place to fund such tenders if necessary. LG&E has never needed to access these facilities. LG&E expects to cover any working capital deficiencies with cash flow from operations, money pool borrowings and borrowings

 

46



 

from Fidelia.

 

Operating Activities

 

Cash provided by operations was $150.4 million, $171.6 million and $163.3 million in 2005, 2004 and 2003, respectively.

 

The 2005 decrease of $21.2 million was primarily the result of changes in:

                  Inventory ($60.6 million) largely the result of increased coal and gas prices

                  Deferred income taxes ($19.8 million)

                  Accounts receivable ($18.1 million) primarily due to colder December weather

                  Gas supply recovery ($13.5 million) primarily due to higher natural gas prices

                  Prepayments and other ($9.3 million)

                  ESM recovery ($8.1 million) due to termination of the ESM program

These decreases were partially offset by changes in:

                  Accounts payable ($48.8 million) primarily from the increase in natural gas prices

                  Earnings ($33.3 million)

                  Pension funding ($24.7 million)

 

The 2004 increase of $8.3 million was primarily the result of changes in:

                  Pension funding ($54.6 million)

                  Gas supply cost recovery ($15.0 million)

                  ESM ($10.1 million)

                  Prepayments and other ($5.9 million)

                  Receipt of a litigation settlement ($7.0 million)

These increases were partially offset by changes in:

                  Accounts receivable ($66.3 million) including the termination of the accounts receivable securitization program

                  Accrued income taxes ($22.4 million)

 

See Note 4 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 $138.9 million, $148.3 million and $213.0 million in 2005, 2004 and 2003, respectively. LG&E expects its capital expenditures for the three-year period ending December 31, 2008, to total approximately $530 million, which consists primarily of construction estimates associated with the redevelopment of the Ohio Falls hydro facility totaling approximately $26 million, construction of Trimble County Unit 2 totaling approximately $120 million and on-going construction related to generation and distribution assets.

 

Net cash used for investing activities decreased $21.1 million in 2005 compared to 2004 and $53.7 million in 2004 compared to 2003, primarily due to the level of construction expenditures.

 

47



 

Financing Activities

 

Net cash inflows (outflows) for financing activities were $(12.1) million, $(7.4) million and $34.2 million in 2005, 2004 and 2003, respectively.

 

Redemptions and maturities of long-term debt for 2005, 2004 and 2003 are summarized below:

 

($ in millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year

 

Description

 

Principal
Amount

 

Rate

 

Secured/
Unsecured

 

Maturity

 

 

 

 

 

 

 

 

 

 

 

 

 

2005

 

Pollution control bonds

 

$

40.0

 

5.90

%

Secured

 

Apr 2023

 

2005

 

Due to Fidelia

 

$

50.0

 

1.53

%

Secured

 

Jan 2005

 

2005

 

Mandatorily Redeemable Preferred Stock

 

$

1.3

 

5.875

%

Unsecured

 

Jul 2005

 

2004

 

Due to Fidelia

 

$

50.0

 

1.53

%

Secured

 

Jan 2005

 

2004

 

Mandatorily Redeemable Preferred Stock

 

$

1.3

 

5.875

%

Unsecured

 

Jul 2004

 

2003

 

Pollution control bonds

 

$

102.0

 

5.625

%

Secured

 

Aug 2019

 

2003

 

Pollution control bonds

 

$

26.0

 

5.45

%

Secured

 

Oct 2020

 

2003

 

First Mortgage Bonds

 

$

42.6

 

6.00

%

Secured

 

Aug 2003

 

2003

 

Mandatorily Redeemable Preferred Stock

 

$

1.3

 

5.875

%

Unsecured

 

Jul 2003

 

 

Issuances of long-term debt for 2005, 2004 and 2003 are summarized below:

 

($ in millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year

 

Description

 

Principal
Amount

 

Rate

 

Secured/
Unsecured

 

Maturity

 

 

 

 

 

 

 

 

 

 

 

 

 

2005

 

Pollution control bonds

 

$

40.0

 

Variable

 

Secured

 

Feb 2035

 

2004

 

Due to Fidelia

 

$

25.0

 

4.33

%

Secured

 

Jan 2012

 

2004

 

Due to Fidelia

 

$

100.0

 

1.53

%

Secured

 

Jan 2005

 

2003

 

Pollution control bonds

 

$

128.0

 

Variable

 

Secured

 

Oct 2033

 

2003

 

Due to Fidelia

 

$

100.0

 

4.55

%

Unsecured

 

Apr 2013

 

2003

 

Due to Fidelia

 

$

100.0

 

5.31

%

Secured

 

Aug 2013

 

 

Future Capital Requirements

 

Future capital requirements may be affected in varying degrees by factors such as electric energy demand 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 has a variety of funding alternatives available to meet its capital requirements. LG&E maintains a series of bilateral credit facilities with banks totaling $185 million. Several intercompany financing arrangements are also available. LG&E participates in an intercompany money pool agreement wherein E.ON U.S. and/or KU make funds available to LG&E at market-based rates up to $400 million. Fidelia also provides long-term intercompany funding to LG&E. See Note 9 of LG&E’s Notes to Financial Statements under Item 8.

 

Regulatory approvals are required for LG&E to incur additional debt. The FERC authorizes the issuance of short-term debt while the Kentucky Commission authorizes issuance of long-term debt. In February 2006,

 

48



 

LG&E received a two-year authorization from the FERC to borrow up to $400 million in short-term funds.

 

LG&E’s debt ratings as of December 31, 2005, were:

 

 

 

Moody’s

 

S&P

 

 

 

 

 

 

 

First mortgage bonds

 

A1

 

A-

 

Preferred stock

 

Baa1

 

BBB-

 

Commercial paper

 

P-1

 

A-2

 

 

These ratings reflect the views of Moody’s and S&P. A security rating is not a recommendation to buy, sell or hold securities and is subject to revision or withdrawal at any time by the rating agency.

 

Contractual Obligations

 

The following is provided to summarize LG&E’s contractual cash obligations for periods after December 31, 2005. LG&E anticipates cash from operations and external financing will be sufficient to fund future obligations. Future interest obligations cannot be quantified because most of LG&E’s debt is variable rate. (See LG&E’s Statements of Capitalization)

 

(in millions)

 

 

 

Payments Due by Period

 

Contractual Cash Obligations

 

2006

 

2007

 

2008

 

2009

 

2010

 

Thereafter

 

Total

 

Short-term debt (a)

 

$

141.2

 

$

 

$

 

$

 

$

 

$

 

$

141.2

 

Long-term debt

 

1.3

 

1.3

 

18.7

 

 

 

799.3

(b)

820.6

 

Operating lease (c)

 

3.5

 

3.6

 

3.7

 

3.8

 

3.8

 

18.5

 

36.9

 

Unconditional power purchase obligations (d)

 

11.1

 

10.9

 

11.0

 

11.3

 

11.5

 

215.1

 

270.9

 

Coal and gas purchase obligations (e)

 

248.0

 

197.6

 

201.2

 

174.2

 

188.6

 

199.8

 

1,209.4

 

Retirement obligations (f)

 

36.7

 

36.3

 

35.7

 

35.0

 

34.3

 

166.1

 

344.1

 

Other obligations (g)

 

23.0

 

 

 

 

 

 

23.0

 

Total contractual cash obligations

 

$

464.8

 

$

249.7

 

$

270.3

 

$

224.3

 

$

238.2

 

$

1,398.8

 

$

2,846.1

 

 


(a)          Represents borrowings from affiliated 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 2013 to 2027. LG&E does not expect to pay these amounts in 2006.

(c)          Operating lease represents the lease of LG&E’s administrative office building.

(d)         Represents future minimum payments under OVEC purchased power agreements through 2024.

(e)          Represents contracts to purchase coal and natural gas.

(f)            Represents currently projected cash flows for pension plans and other post-employment benefits as calculated by the actuary.

(g)         Represents construction commitments.

 

Off-Balance Sheet Arrangements

 

In the ordinary course of business LG&E has operating leases for various vehicles, equipment and real estate. See Note 10 of LG&E’s Notes to Financial Statements under Item 8 for further discussion of leases.

 

49



 

Sale and Leaseback Transaction

 

LG&E is a participant in a sale and leaseback transaction involving its 38% interest in two jointly-owned CTs at KU’s E.W. Brown generating station (Units 6 and 7). Commencing in December 1999, LG&E and KU entered into a tax-efficient, 18-year lease of the CTs. LG&E and KU have provided funds to fully defease the lease, and have executed an irrevocable notice to exercise an early purchase option contained in the lease after 15.5 years. The financial statement treatment of this transaction is no different than if LG&E had retained its ownership. The leasing transaction was entered into following receipt of required state and federal regulatory approvals.

 

In case of default under the lease, LG&E is obligated to pay to the lessor its share of certain fees or amounts. Primary events of default include loss or destruction of the CTs, failure to insure or maintain the CTs and unwinding of the transaction due to governmental actions. No events of default currently exist with respect to the lease. Upon any termination of the lease, whether by default or expiration of its term, title to the CTs reverts jointly to LG&E and KU.

 

At December 31, 2005, the maximum aggregate amount of default fees or amounts, which decrease over the term of the lease, was $8.2 million, of which LG&E would be responsible for $3.1 million (38%). LG&E has made arrangements with E.ON U.S., via guarantee and regulatory commitment, for E.ON U.S. to pay LG&E’s full portion of any default fees or amounts.

 

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 Note 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, 2005, the potential change in interest expense associated with a 1% change in base interest rates of LG&E’s unhedged debt is estimated at $3.6 million.

 

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, 2005, LG&E had swaps with a combined notional value of $211.3 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 approximately $17.6 million as of December 31, 2005. 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.

 

In February 2005, an LG&E interest rate swap with a notional amount of $17.0 million matured. The swap was fully effective upon expiration. As a result, the impact on earnings and other comprehensive income from the swap maturity was less than $0.1 million.

 

50



 

Commodity Price Sensitivity

 

LG&E is exposed to the market price volatility of coal, natural gas and oil (the fuels used to generate electricity) in its wholesale activities. It has limited exposure to such market price volatility as the result of its retail FAC and GSC commodity price pass-through mechanisms.

 

Energy & Risk Management Activities

 

LG&E conducts energy trading and risk management activities to maximize the value of power sales from physical assets it owns. Certain energy trading activities are accounted for on a mark-to-market basis in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Wholesale sales of excess asset capacity are treated as normal sales under SFAS No. 133, as amended, and are not marked to market.

 

Since the inception of the MISO Day 2 market in April 2005, LG&E has been eligible to receive FTRs from the MISO. FTRs are assigned by the MISO to market participants for a twelve-month period of time beginning June 1, 2006, for off-peak and peak periods based on each market participant’s share of generation. FTRs are utilized to manage price risk associated with transmission congestion. The value of FTRs is determined by the transmission congestion charges that arise when the transmission grid is congested in the day-ahead market. FTRs are obtained through an allocation from the MISO at zero cost, however, they can also be bought and sold. FTRs are derivatives and their fair value is insignificant due to the lack of liquidity in the forward market.

 

The fair value of LG&E’s energy trading and risk management contracts as of December 31, 2005 and 2004, was less than $1.0 million. No changes to valuation techniques for energy trading and risk management activities occurred during 2005 or 2004. Changes in market pricing, interest rate and volatility assumptions were made during both years. The outstanding mark-to-market value is sensitive to changes in prices, price volatilities, and interest rates. The Company estimates that a movement in prices of $1 and a change in interest and volatilities of 1% would result in a change of less than $0.1 million. All contracts outstanding at December 31, 2005, 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, 2005, 100% of the trading and risk management commitments were with counterparties rated BBB-/Baa3 equivalent or better.

 

Accounts Receivable Securitization

 

LG&E terminated its accounts receivable securitization program in January 2004, and in May 2004, dissolved its inactive accounts receivable securitization-related subsidiary, LG&E R. No material pre-tax gains or losses resulted from the sale of the receivables in 2004 and 2003. LG&E’s net cash flows from LG&E R were reduced by $58.1 million and $6.2 million for 2004 and 2003, respectively. The allowance for doubtful accounts associated with the eligible securitized receivables at December 31, 2003 was $1.4 million. This allowance was based on historical experience of LG&E. Each securitization facility contained a fully funded reserve for

 

51



 

uncollectible receivables.

 

RATES AND REGULATION

 

LG&E is subject to the jurisdiction of the Kentucky Commission in virtually all matters related to electric and natural gas utility regulation, and as such, its accounting is subject to SFAS No. 71. Given LG&E’s competitive position in the marketplace and the status of regulation in Kentucky, LG&E has no plans or intentions to discontinue its application of SFAS No. 71. See Note 3 and Note 10 of LG&E’s Notes to Financial Statements under Item 8 for a discussion of rates and regulation.

 

FUTURE OUTLOOK

 

Competition and Customer Choice

 

At this time, 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. Some states that have already deregulated have begun discussions that could lead to re-regulation.

 

In February 2005, Kentucky’s Governor signed an executive order directing the Kentucky Commission, in conjunction with the Commerce Cabinet and the Environmental and Public Protection Cabinet, to ‘develop a Strategic Blueprint for the continued use and development of electric energy.’ This Strategic Blueprint is designed to promote future investment in electric infrastructure for the Commonwealth of Kentucky, to protect Kentucky’s low-cost electric advantage, to maintain affordable rates for all Kentuckians, and to preserve Kentucky’s commitment to environmental protection.

 

Over the last several years, LG&E has taken many steps to keep its rates low while maintaining high levels of customer satisfaction, including: an increase in focus on commercial, industrial and residential customers; an increase in employee involvement and training; and continuous modifications of its organizational structure. LG&E also strives to control costs through competitive bidding and process improvements. LG&E’s performance in national customer satisfaction surveys continues to be high.

 

52



 

RESULTS OF OPERATIONS

 

KU

 

Net Income

 

KU’s net income in 2005 decreased $21.4 million (16.0%) compared to 2004. The decrease resulted primarily from higher fuel, power purchased and other operation and maintenance expenses. These cost increases were largely due to MISO Day 2 requirements and KU operating unit outages during the year. The increases in costs were partially offset by increased retail revenues resulting from increased electricity demand and increased base rates, effective July 1, 2004. Wholesale revenues also increased due to higher volumes and higher prices.

 

During 2005, KU made out-of-period adjustments for estimated over/under collection of ECR revenues to be billed in subsequent periods. The adjustments were related to the reporting periods of May 2003 through December 2004. As a result, 2005 revenues for KU were reduced by $2.9 million and net income was reduced by $1.7 million. KU revenues and net income for 2004 were overstated by $3.2 million and $1.9 million, respectively, and KU revenues and net income for 2003 were understated by $0.3 million and $0.2 million, respectively.

 

KU’s net income in 2004 increased $42.1 million (46.1%) compared to 2003. The increase resulted primarily from higher revenues, primarily in the retail sector, due to increased base rates resulting from the rate case order and higher volumes due to a warmer summer. Operating expenses of $2.7 million related to severe May and July storms in 2004 partially offset the increase.

 

Revenues

 

The following table presents a comparison of operating revenues for the years 2005 and 2004 with the immediately preceding year.

 

(in millions)

 

 

 

 

 

 

 

 

 

Increase (Decrease) From Prior Period

 

Cause

 

2005

 

2004

 

Retail sales:

 

 

 

 

 

Fuel clause adjustments

 

$

90.3

 

$

15.3

 

KU/LG&E Merger surcredit

 

(1.6

)

(2.6

)

Environmental cost recovery surcharge

 

0.7

 

20.6

 

Earnings sharing mechanism

 

(9.0

)

(1.0

)

Demand side management

 

(0.6

)

1.0

 

VDT surcredit

 

(0.7

)

(0.5

)

Rate and rate structure

 

24.1

 

21.7

 

Variation in sales volumes and other

 

33.2

 

24.6

 

Total retail sales

 

136.4

 

79.1

 

Wholesale sales

 

49.9

 

22.0

 

MISO Day 2

 

24.9

 

 

Other

 

 

2.5

 

Total

 

$

211.2

 

$

103.6

 

 

Electric revenues increased in 2005 primarily due to higher fuel costs cost billed to customers through the fuel adjustment clause, an increase in wholesale sales and MISO related revenue, higher rates and a change in the rate structure. New rates implemented in July 2004 and the elimination of a volume dependent step rate structure, increased revenues by 3.0% in 2005. These increases were partially offset by the elimination of the

 

53



 

ESM in the second quarter of 2005. Retail volumes increased 4.7% due to weather. The KU service area experienced a warmer summer in 2005, with cooling degree days for 2005 46% above 2004 and 18% above the 20-year average while heating degree days were 3% above 2004 and 1% below the 20-year average. Wholesale revenues increased due to a 31% increase in prices.

 

Electric revenues increased in 2004 primarily due to an increase in rates and a change in the rate structure. New rates, implemented in July 2004 and the elimination of a volume dependent step rate structure, increased revenues by 3.1% in 2004. Retail volumes increased 3.3% due to a 1.4% increase in the customer base and 2.6% increase in demand due to weather. The KU service area experienced a warmer summer in 2004, partially offset by a milder winter. Cooling degree days for 2004 increased 2.9% from 2003 and were 20% below the 20-year average while heating degree days decreased 6.8% from 2003 and were 4% below the 20-year average. Wholesale revenues increased due to a combination of a 14.2% increase in prices and 1.7% higher volumes. The price increase was largely due to higher fuel prices and the volume increase was primarily due to increased electricity demand in the region.

 

Expenses

 

Fuel for electric generation comprises a large component of KU’s total operating expenses. KU’s Kentucky jurisdictional electric rates are subject to an FAC whereby increases or decreases are reflected in the FAC factor, subject to the approval of the Kentucky Commission and passed through to KU’s retail customers. KU’s municipal 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 the FERC and the Virginia Commission, respectively.

 

Fuel for electric generation increased $91.6 million (31.3%) in 2005 primarily due to:

                  Increased cost of fuel burned ($87.4 million) due to the MISO’s dispatch of natural gas-fired units and higher coal and natural gas prices

                  Increased generation ($4.2 million) due to increased demand and the dispatch of units for MISO Day 2

 

Fuel for electric generation increased $26.1 million (9.8%) in 2004 primarily due to:

                  Increased cost of fuel burned ($16.8 million) due to higher fuel prices

                  Increased generation ($9.3 million) due to increased demand

 

Power purchased expense increased $74.7 million (51.8%) in 2005 primarily due to:

                  Increased unit cost of purchases ($61.3 million) due to higher fuel prices

                  Increased volumes purchased ($13.4 million) due to increased demand and unit outages

                  Purchased power costs from the MISO due to unit outages totaled $22.0 million

 

Power purchased expense increased $4.1 million (2.9%) in 2004 primarily due to:

                  Increased volumes purchased ($5.1 million) due to increased demand and unit outages

                  Decreased unit cost of purchases ($0.9 million)

 

Other operation and maintenance expenses increased $64.7 million (29.1%) in 2005 primarily due to higher other operation expenses ($53.8 million) and higher maintenance expenses ($11.4 million), partially offset by lower property and other taxes ($0.5 million).

 

54



 

Other operation expenses increased $53.8 million (37.0%) in 2005 primarily due to:

      Increased other power supply expenses primarily due to MISO Day 2 costs ($43.1 million) for administrative and allocated charges from the MISO for Day 2 operations

      Increased employee welfare expenses ($4.3 million)

      Increased transmission expenses ($2.5 million) primarily due to increased costs associated with MISO Day 1. The increase was partially offset by lower transmission costs resulting from MISO Day 2 ($2.9 million). Prior to the MISO Day 2 market, most bilateral transactions required the purchase of transmission; however, with the Day 2 market, most transactions are handled directly with the MISO and no additional transmission is necessary

      Increased customer service and collections expense ($2.1 million)

      Increased distribution costs ($1.5 million)

 

Maintenance expenses increased $11.4 million (18.7%) in 2005 primarily due to:

      Increased steam generation expenses ($5.9 million) primarily due to unit outages

      Increased distribution maintenance ($3.9 million) due to increased line repairs and tree trimming costs

      Increased administrative and general maintenance ($1.1 million)

      Increased transmission line maintenance ($0.3 million)

 

Other operation and maintenance expenses increased $0.8 million (0.4%) in 2004 primarily due to higher property and other taxes ($0.8 million) and higher maintenance expenses ($0.6 million), partially offset by lower other operation expenses ($0.4 million).

 

Maintenance expenses increased $0.6 million (1.0%) in 2004 primarily due to:

      Increased maintenance expense due to storm restoration costs related to severe May and July storms ($2.2 million)

      Increased combustion turbine maintenance ($2.3 million)

      Decreased expense due to reclassification of maintenance expense to a regulatory asset ($4.0 million) of costs related to the 2003 ice storm based on an order from the Kentucky Commission, to be amortized through June 2009. KU earns a return of these amortized costs, which are included in KU’s jurisdictional operating expenses.

 

Other operation expenses decreased $0.4 million (0.3%) in 2004 primarily due to:

      Decreased benefits expense ($3.7 million), primarily due to lower pension expense

      The KU/LG&E merger costs and the One Utility initiative costs were fully amortized in 2003, resulting in $2.9 million lower expense in 2004

      Increased emission allowance expense ($4.5 million)

      Increased combustion turbine operations expense ($0.9 million)

      Increased operations expense due to storm restoration costs related to severe storms in May and July 2004 ($0.5 million)

 

Depreciation and amortization increased $6.0 million (5.5%) in 2005 and $6.9 million (6.8%) in 2004 primarily due to additional plant in service.

 

Other income - net decreased $2.5 million (33.3%) in 2005 primarily due to:

      Increased income deductions ($3.7 million)

      Decreased AFUDC equity ($1.1 million)

      Decreased gain on disposition of property ($0.5 million)

 

55



 

      Increased miscellaneous non-operating income ($2.9 million)

 

Other income - net increased $3.0 million (66.7%) in 2004 primarily due to:

      Decreased income deductions ($3.1 million)

      Increased miscellaneous non-operating income ($0.6 million)

      Increased gain on disposition of property ($0.4 million)

      Decreased equity in earnings – subsidiary company ($1.1 million)

 

Interest expense increased $5.5 million (21.6%) in 2005 primarily due to:

      Increased cost of interest rate swaps ($2.9 million)

      Increased cost of variable-rate debt ($2.4 million)

      Increased marked to market of interest rate swaps ($1.6 million)

      Decreased cost from refinancing fixed rate bonds with variable rate bonds ($1.5 million)

 

Interest expense increased $0.3 million (1.2%) in 2004 primarily due to:

      Increased borrowing from Fidelia ($9.0 million)

      Decreased cost from retired first mortgage debt ($4.4 million)

      Decreased cost of interest rate swaps ($3.5 million)

      Decreased borrowing from the money pool ($0.8 million)

 

Details of KU’s exposure to variable interest rates on long-term debt are shown in the table below:

 

 

 

2005

 

2004

 

2003

 

Variable rate debt, including fixed rate debt swapped to variable rate debt ($ in millions)

 

$

325.6

 

$

349.0

 

$

368.6

 

Percentage of variable rate debt to total long-term debt, including fixed rate debt swapped to variable rate debt

 

43.7

%

48.6

%

53.6

%

Weighted average interest rate on variable rate debt for the year

 

2.52

%

1.32

%

1.07

%

Weighted average interest rate on total long-term debt at year-end, including expense amortization and interest rate swaps

 

4.50

%

3.43

%

2.96

%

 

See Note 8 of KU’s Notes to the Financial Statements under Item 8.

 

Variations in income tax expense are largely attributable to changes in pre-tax income. KU’s 2005 effective income tax rate was 36.3%, a slight decrease from 36.4% in 2004. See Note 7 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

 

56



 

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 forecasted 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 by customers that has not been billed. The estimated usage is based on allocating the daily system net deliveries between billed volumes and unbilled volumes. The allocation is based on a daily ratio of the number of meter reading cycles remaining in the month to the total number of meter reading cycles in each month. Each day’s ratio is then multiplied by each day’s system net deliveries to determine an estimated billed and unbilled volume for each day of the accounting period. At December 31, 2005, a 10% change in these estimated quantities would cause revenue and accounts receivable to change by approximately $4.4 million. See also Note 1 of KU’s Notes to Financial Statements under Item 8.

 

Allowance for Doubtful Accounts – At December 31, 2005 and 2004, the KU allowance for doubtful accounts was $1.5 million and $0.6 million, respectively. The allowance is based on the ratio of the amounts charged-off during the last twelve months to the retail revenues billed over the same period multiplied by the retail revenues billed over the last four months. Accounts with no payment activity are charged-off after four months, although collection efforts continue thereafter.

 

Pension and Post-retirement Benefits – KU has both funded and unfunded non-contributory defined benefit pension and post-retirement benefit plans that together cover substantially all of its employees. The plans are accounted for under SFAS No. 87 and SFAS No. 106.

 

The pension and other post-retirement benefit plan costs and liabilities are determined on an actuarial basis and are dependent upon numerous economic assumptions, such as discount rates, rates of compensation increases, estimates of the expected return on plan assets and health care cost trend rates and demographic and economic assumptions. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower health care costs or turnover, or longer or shorter life spans of participants. These differences may result in a significant impact on the amount of expenses recorded in future periods. The underlying assumptions and estimates related to the pension and post-retirement benefit plan costs and liabilities are reviewed annually.

 

The assumed discount rate, expected return on assets and rate of compensation increases generally have the most significant impact on the pension costs and liabilities. The discount rate is used to calculate the actuarial present value of the benefits provided by the plans. KU bases its discount rate assumption on Moody’s Aa Corporate Bond Rate rounded to the nearest 25 basis points, which has a duration comparable to the weighted average duration of the plans.

 

The expected long-term rate of return on assets is used to calculate the net periodic pension costs for the plans. To develop the expected long-term rate of return on assets assumption, consideration is given to the current level of expected returns on risk free investments (primarily government bonds), the historical performance of the asset managers versus their respective benchmarks, the historical level of the risk premium associated with the other asset classes in which the portfolio is invested and the expectations for future returns of each asset class. The expected return for each asset class is then weighted based on a target asset allocation. For 2005, the actual return on pension assets was comparable to the assumed expected rate of return.

 

57



 

The following describes the effects on pension benefits by changing the major actuarial assumptions discussed above:

 

                  A 1% change in the assumed discount rate could have an approximate $32.6 million positive or negative impact to the 2005 accumulated benefit obligation of KU.

                  A 25 basis point change in the expected rate of return on assets would have an approximate $0.6 million positive or negative impact on 2005 pension expense.

 

Compensation rate increases are used to calculate service costs and the projected benefit obligation. Such rates are based on a review of KU’s historical salaries, promotion and bonus increases. For 2005 net periodic pension benefit costs, KU used an assumption of 4.50%. Based on plan experience, the rate was increased to 5.25% for the projected benefit obligation at December 31, 2005.

 

When the plan experience differs from the actuarial assumptions, a portion of the difference may be deferred and is subject to amortization at rates based on the estimated average years of participants’ future service. KU’s deferred losses on these assumptions were $24.6 million (44%) higher in 2005 than 2004 and $28.3 million (101%) higher in 2004 than 2003, primarily due to declining discount rate assumptions during these years.

 

The assumptions related to the discount rate, retirement, turnover and healthcare cost trends, which represent expected rates of increase in health care claim payments, generally have the most significant impact on post-retirement benefit plan costs and liabilities. Unlike pensions, however, assumptions about per capita claims cost by age and participation rates also significantly impact post-retirement liability computations. A 1% change in the healthcare cost trend rates could have a positive or negative impact on the 2005 post-retirement benefit obligation and post-retirement expense of approximately $6.0 million and $0.4 million, respectively.

 

Additionally, demographic and other economic assumptions affect the pension and post-retirement computations. Beginning with the December 31, 2005 liability, KU replaced the 1983 Group Annuity Mortality tables for males and females with the RP 2000 combined tables for males and females projected to 2006. These updated healthy mortality tables will be used for the 2006 expense.

 

The benefit obligation is compared with the plan asset values to determine a net position. Asset values are increased primarily by actual rates of return on plan assets and by employer contributions. For explanation of the investment policy including targeted asset allocations, see Note 6 of KU’s Notes to Financial Statements under Item 8.

 

The pension plans are funded in accordance with all applicable requirements of the ERISA and the IRC. In accordance with the ERISA guidelines, KU made discretionary contributions to the pension plans of $10.2 million in 2003 and $43.4 million in 2004. No contributions were made in 2005. KU anticipates making additional contributions as deemed necessary. Additionally, KU made a contribution of $3.0 million to the post-retirement plan in 2005, representing the maximum employer contribution under IRC Section 401(h) requirements for all plan years through 2004. KU may continue to make subsequent contributions in accordance with the maximum funding limitation governed by tax laws.

 

As prescribed by SFAS No. 87, KU was required to recognize an additional minimum pension liability of $9.5 million and $12.4 million during 2005 and 2004, respectively, since the fair value of the plan assets was less than the accumulated benefit obligation at that time. This additional minimum pension liability was recorded as a

 

58



 

reduction to other comprehensive income and did not affect net income. Historically low corporate bond rates, used to determine the discount rate, significantly increased the potential value of the pension liabilities above the actual value of the plan assets. 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 balance sheet. In 2003, KU recognized a reduction of the minimum pension liability of $7.7 million.

 

Should poor market conditions return or should interest rates decline further, KU’s unfunded accumulated benefit obligations and future pension expense could increase. The Company believes that such increases are recoverable in whole or in part under future rate proceedings or mechanisms.  See also Note 6 and Note 13 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 regulatory decisions. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates based upon Kentucky Commission, Virginia Commission and FERC orders. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections based upon orders by the Kentucky Commission, Virginia Commission and FERC. 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 and liabilities would be required to be recognized in current period earnings.  See also Note 3 of KU’s Notes to Financial Statements under Item 8.

 

Income Taxes – Income taxes are accounted for under SFAS No. 109.  In accordance with this statement, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, as measured by enacted tax rates that are expected to be in effect in the periods when the deferred tax assets and liabilities are expected to be settled or realized. Significant judgment is required in determining the provision for income taxes, and there are transactions for which the ultimate tax outcome is uncertain.

 

To provide for these uncertainties or exposures, an allowance is maintained for tax contingencies based on management’s best estimate of probable loss. Tax contingencies are analyzed periodically and adjustments are made when events occur to warrant a change. On September 19, 2005, KU received notice from the Congressional Joint Committee on Taxation approving the Internal Revenue Service’s audit of KU’s income tax returns for the periods December 1999 through December 2003. As a result of resolving numerous tax matters during these periods, KU reduced income tax accruals by $4.6 million during 2005.

 

The company recognized additional deferred income tax expense in the third quarter of 2005 ($3.1 million) related to the undistributed earnings of its EEI unconsolidated investment. Recent EEI management decisions regarding changes in the distribution of EEI’s earnings led to the decision to provide deferred taxes for all book and tax temporary differences related to this investment.

 

H. R. 4520, known as the “American Jobs Creation Act of 2004” allows electric utilities to take a deduction of up to 3% of their qualified production activities income in 2005. This deduction reduced KU’s effective tax rate by less than 1% for 2005.

 

59



 

Kentucky House Bill 272, also known as “Kentucky’s Tax Modernization Plan,” was signed into law in March 2005. This bill contains a number of changes in Kentucky’s tax system, including the reduction of the Corporate income tax rate from 8.25% to 7% effective January 1, 2005, and a further reduction to 6% effective January 1, 2007. As a result of the income tax rate change, KU’s deferred tax reserve amount will exceed its actual deferred tax liability attributable to existing temporary differences since the new statutory rates are lower than the rates were when the deferred tax liability originated. This excess amount is referred to as excess deferred income taxes. In June 2005, KU received approval from the Kentucky Commission to establish and amortize a regulatory liability ($11.0 million) for its net excess deferred income tax balances. Under this accounting treatment, KU will amortize its depreciation-related excess deferred income tax balances under the average rate assumption method. The average rate assumption method matches the amortization of the excess deferred income taxes with the life of the timing differences to which it relates. Excess deferred income tax balances related to non-depreciation timing differences will be expensed in the current year due to their immaterial amount.

 

KU expects to have adequate levels of taxable income to realize its recorded deferred taxes.

 

For further discussion of income tax issues, see Note 1 and Note 7 of KU’s Notes to Financial Statements under Item 8.

 

NEW ACCOUNTING PRONOUNCEMENTS

 

The following recent accounting pronouncements affected KU in 2005 and 2004:

 

FIN 47

 

KU adopted FIN 47 effective December 31, 2005. FIN 47 expands the term “conditional asset retirement obligation” as used in SFAS No. 143 to refer to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. An entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred; generally, upon acquisition, construction, or development and through the normal operation of the asset.

 

As a result of the implementation of FIN 47, KU recorded additional ARO net assets and liabilities during the fourth quarter of 2005 in the amount of $0.5 million and $4.6 million, respectively. KU also recorded a cumulative effect adjustment in the amount of $4.1 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 $4.1 million, pursuant to regulatory treatment prescribed under SFAS No. 71, as the costs of removal are allowed under Kentucky Commission ratemaking.

 

Had FIN 47 been in effect at the beginning of the 2004 reporting period, KU would have established asset retirement obligations as described in the following table (in millions):

 

 

 

2005

 

2004

 

Provision at beginning of the year

 

$

4.3

 

$

4.1

 

Accretion expense

 

0.3

 

0.2

 

Provision at end of the year

 

$

4.6

 

$

4.3

 

 

60



 

See Note 1 of KU’s Notes to Financial Statements under Item 8 for a further discussion of FIN 47.

 

LIQUIDITY AND CAPITAL RESOURCES

 

KU uses net cash generated from its operations and external financing (including financing from affiliates) 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.

 

As of December 31, 2005, KU is in a negative working capital position in part because of the classification of certain variable-rate pollution control bonds totaling $87.1 million that are subject to tender for purchase at the option of the holder as current portion of long-term debt. KU expects to cover any working capital deficiencies with cash flow from operations, money pool borrowings and borrowings from Fidelia.

 

Operating Activities

 

Cash provided by operations was $220.7 million, $185.9 million and $233.4 million in 2005, 2004 and 2003, respectively.

 

The 2005 increase of $34.8 million was primarily the result of changes in:

                  Pension funding ($35.9 million)

                  Accounts payable ($16.2 million) largely due to the increase in power purchased resulting from increased fuel costs

                  Accounts receivable ($8.9 million)

These increases were partially offset by:

                  Lower earnings ($21.4 million)

 

The 2004 decrease of $47.5 million was primarily due to the change in:

                  Accounts receivable ($63.0 million), including the termination of the accounts receivable securitization program

                  Additional pension funding ($33.2 million)

                  Lower environmental cost recovery ($14.2 million)

These decreases were partially offset by:

                  Higher earnings ($42.1 million)

                  Higher accounts payable ($13.3 million)

                  Receipt of a litigation settlement ($11.4 million)

 

See Note 4 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 $140.0 million, $157.6 million and $341.8 million in 2005, 2004 and 2003, respectively. KU expects its capital expenditures for the three-year period ending December 2008, to total approximately $1.5 billion, which consists primarily of construction estimates associated with installation of FGDs on Ghent and Brown units totaling approximately $560 million, as described in the section titled “Environmental Matters,” the construction of Trimble County Unit 2 totaling approximately $510 million and on-going construction on generation and

 

61



 

distribution assets.

 

Net cash used for investing activities increased $4.0 million in 2005 compared to 2004 primarily due to the increase in restricted cash in 2005, partially offset by lower capital expenditures. Restricted cash is the escrowed proceeds of the Pollution Control Bonds issued in 2005 which will be disbursed as qualifying costs are incurred. Net cash used for investing activities decreased $184.1 million in 2004 compared to 2003 primarily due to the level of construction expenditures. NOx expenditures were zero in 2005 and approximately $45.0 million in 2004, while CT expenditures were approximately $8.1 million in 2005 and $13.7 million in 2004.

 

Financing Activities

 

Net cash inflows (outflows) from financing activities were $(57.0) million, $(28.6) million and $107.8 million in 2005, 2004 and 2003, respectively.

 

Redemptions and maturities of long-term debt for 2005, 2004 and 2003 are summarized below:

 

($ in millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year

 

Description

 

Principal
Amount

 

Rate

 

Secured/
Unsecured

 

Maturity

 

2005

 

First mortgage bonds

 

$

50.0

 

7.55

%

Secured

 

Jun 2025

 

2005

 

Due to Fidelia

 

$

75.0

 

2.29

%

Secured

 

Dec 2005

 

2004

 

Pollution control bonds

 

$

4.8

 

Variable

 

Secured

 

Feb 2032

 

2004

 

Pollution control bonds

 

$

50.0

 

5.75

%

Secured

 

Dec 2023

 

2003

 

First mortgage bonds

 

$

62.0

 

6.32

%

Secured

 

Jun 2003

 

2003

 

First mortgage bonds

 

$

33.0

 

8.55

%

Secured

 

May 2027

 

 

Issuances of long-term debt for 2005, 2004 and 2003 are summarized below:

 

($ in millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year

 

Description

 

Principal
Amount

 

Rate

 

Secured/
Unsecured

 

Maturity

 

2005

 

Pollution control bonds

 

$

13.3

 

Variable

 

Secured

 

Jun 2035

 

2005

 

Pollution control bonds

 

$

13.3

 

Variable

 

Secured

 

Jun 2035

 

2005

 

Due to Fidelia

 

$

50.0

 

4.735

%

Unsecured

 

Jul 2015

 

2005

 

Due to Fidelia

 

$

75.0

 

5.36

%

Unsecured

 

Dec 2015

 

2004

 

Due to Fidelia

 

$

50.0

 

4.39

%

Unsecured

 

Jan 2012

 

2004

 

Pollution control bonds

 

$

50.0

 

Variable

 

Secured

 

Oct 2034

 

2003

 

Due to Fidelia

 

$

100.0

 

4.55

%

Unsecured

 

Apr 2013

 

2003

 

Due to Fidelia

 

$

75.0

 

5.31

%

Secured

 

Aug 2013

 

2003

 

Due to Fidelia

 

$

33.0

 

4.24

%

Secured

 

Nov 2010

 

2003

 

Due to Fidelia

 

$

75.0

 

2.29

%

Secured

 

Dec 2005

 

 

In May 2005, KU repaid a $26.7 million loan against the cash surrender value of life insurance policies.

 

In October 2005, KU redeemed all of its outstanding shares of preferred stock for $40.8 million. KU paid $101 per share for the 4.75% Series and $102.939 per share for the 6.53% Series.

 

62



 

Future Capital Requirements

 

Future capital requirements may be affected in varying degrees by factors such as electric energy demand 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. KU anticipates funding future capital requirements through operating cash flow, debt, and/or infusion of capital from its parent.

 

KU has a variety of intercompany funding alternatives available to meet its capital requirements. KU participates in an intercompany money pool agreement wherein E.ON U.S. and/or LG&E make funds available to KU at market-based rates up to $400 million. Fidelia also provides long-term intercompany funding to KU. See Note 9 of KU’s Notes to Financial Statements under Item 8.

 

Regulatory approvals are required for KU to incur additional debt. The Virginia Commission and the FERC authorize the issuance of short-term debt while the Kentucky Commission, the Virginia Commission and the Tennessee Regulatory Authority authorize the issuance of long-term debt. In February 2006, KU received approvals from the Virginia Commission and from the FERC to borrow up to $400 million in short-term funds.

 

KU’s debt ratings as of December 31, 2005, were:

 

 

 

Moody’s

 

S&P

 

 

 

 

 

 

 

First mortgage bonds

 

A1

 

A

 

Preferred stock

 

Baa1

 

BBB-

 

Commercial paper

 

P-1

 

A-2

 

 

These ratings reflect the views of Moody’s and S&P. A security rating is not a recommendation to buy, sell or hold securities and is subject to revision or withdrawal at any time by the rating agency.

 

Contractual Obligations

 

The following is provided to summarize KU’s contractual cash obligations for periods after December 31, 2005. KU anticipates cash from operations and external financing will be sufficient to fund future obligations. Future interest obligations cannot be quantified because most of KU’s debt is variable rate. (See KU’s Statements of Capitalization)

 

(in millions)

 

 

 

 

 

 

 

 

 

Payments Due by Period

 

Contractual Cash Obligations

 

2006

 

2007

 

2008

 

2009

 

2010

 

Thereafter

 

Total

 

Short-term debt (a)

 

$

69.7

 

$

 

$

 

$

 

$

 

$

 

$

69.7

 

Long-term debt

 

36.0

 

55.0

 

 

 

33.0

 

622.6 (b

)

746.6

 

Unconditional power purchase obligations (c)

 

24.2

 

24.5

 

23.3

 

24.7

 

24.9

 

358.2

 

479.8

 

Coal purchase obligations (d)

 

307.6

 

203.7

 

109.4

 

6.4

 

 

 

627.1

 

Retirement obligations (e)

 

26.1

 

26.0

 

25.6

 

25.4

 

25.2

 

126.7

 

255.0

 

Other obligations (f)

 

120.2

 

 

 

 

 

 

120.2

 

Total contractual cash obligations

 

$

583.8

 

$

309.2

 

$

158.3

 

$

56.5

 

$

83.1

 

$

1,107.5

 

$

2,298.4

 

 


(a)          Represents borrowings from affiliated company due within one year.

(b)         Includes long-term debt of $87.1 million classified as current liabilities because these bonds are subject to tender for

 

63



 

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 2024 to 2032. KU does not expect to pay these amounts in 2006.

(c)          Represents future minimum payments under OVEC and OMU purchased power agreements through 2024.

(d)         Represents contracts to purchase coal.

(e)          Represents currently projected cash flows for pension plans and other post-employment benefits as calculated by the actuary.

(f)            Represents construction commitments.

 

Off-Balance Sheet Arrangements

 

In the ordinary course of business KU has operating leases for various vehicles, equipment and real estate. See Note 10 of KU’s Notes to Financial Statements under Item 8 for further discussion of leases. 

 

Sale and Leaseback Transaction

 

KU is a participant in a sale and leaseback transaction involving its 62% interest in two jointly-owned CTs at KU’s E.W. Brown generating station (Units 6 and 7). Commencing in December 1999, LG&E and KU entered into a tax-efficient, 18-year lease of the CTs. KU and LG&E have provided funds to fully defease the lease, and have executed an irrevocable notice to exercise an early purchase option contained in the lease after 15.5 years. The financial statement treatment of this transaction is no different than if KU had retained its ownership. The leasing transaction was entered into following receipt of required state and federal regulatory approvals.

 

In case of default under the lease, KU is obligated to pay to the lessor its share of certain fees or amounts. Primary events of default include loss or destruction of the CTs, failure to insure or maintain the CTs and unwinding of the transaction due to governmental actions. No events of default currently exist with respect to the lease. Upon any termination of the lease, whether by default or expiration of its term, title to the CTs reverts jointly to KU and LG&E.

 

At December 31, 2005, the maximum aggregate amount of default fees or amounts, which decrease over the term of the lease, was $8.2 million, of which KU would be responsible for $5.1 million (62%). KU has made arrangements with E.ON U.S., via guarantee and regulatory commitment, for E.ON U.S. to pay KU’s full portion of any default fees or amounts.

 

MARKET RISKS

 

KU is exposed to market risks from changes in interest rates and commodity prices. To mitigate changes in 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 Note 1 and Note 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, 2005, the potential change in interest expense associated with a 1% change in base interest rates of KU’s variable-rate debt is estimated at $3.3 million.

 

An interest rate swap is used to hedge KU’s underlying debt obligations. The swap hedges specific debt issuances and, consistent with management’s designation, are accorded hedge accounting treatment. See Note 4

 

64



 

of KU’s Notes to Financial Statements under Item 8.

 

As of December 31, 2005, KU has a swap with a notional value of $53.0 million. The swap exchanged fixed-rate interest payments for floating rate interest payments on KU’s Series P first mortgage bonds. The potential loss in fair value resulting from a hypothetical 1% adverse movement in base interest rates is estimated at $0.6 million as of December 31, 2005. This estimate is derived from third-party valuations. Changes in the market value of these swaps, if held to maturity, 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.

 

In June 2005, a KU interest rate swap with a notional amount of $50.0 million was terminated by the counterparty pursuant to the terms of the swap agreement. KU received a payment of $1.9 million in consideration for the termination of the agreement. KU also called the underlying debt (First Mortgage Bond Series R) and paid a call premium of $1.9 million. The swap was fully effective upon termination. No impact on earnings occurred as a result of the bond call and related swap termination.

 

In February 2004, KU terminated the swaps it had in place at December 31, 2003, related to the Series 9 pollution control bonds. The notional amount of the terminated swap was $50.0 million and KU received a payment of $2.0 million as part of the termination. The swap was terminated because it was no longer an effective hedge of the underlying bond.

 

Commodity Price Sensitivity

 

KU is exposed to the market price volatility of coal, natural gas and oil (the fuels used to generate electricity) in its wholesale activities. It has limited exposure to such market price volatility as the result of its retail FAC commodity price pass-through mechanism.

 

Energy & Risk Management Activities

 

KU conducts energy trading and risk management activities to maximize the value of power sales from physical assets it owns. Certain energy trading activities are accounted for on a mark-to-market basis in accordance with SFAS No. 133, as amended. Wholesale sales of excess asset capacity are treated as normal sales under SFAS No. 133, as amended, and are not marked to market.

 

Since the inception of the MISO Day 2 market in April 2005, KU has been eligible to receive FTRs from the MISO. FTRs are assigned by the MISO to market participants for a twelve-month period of time beginning June 1, 2006, for off-peak and peak periods based on each market participant’s share of generation. FTRs are utilized to manage price risk associated with transmission congestion. The value of FTRs is determined by the transmission congestion charges that arise when the transmission grid is congested in the day-ahead market. FTRs are obtained through an allocation from the MISO at zero cost, however, they can also be bought and sold. FTRs are derivatives and their fair value is insignificant due to the lack of liquidity in the forward market.

 

The fair value of KU’s energy trading and risk management contracts as of December 31, 2005 and 2004, was less than $1.0 million. No changes to valuation techniques for energy trading and risk management activities

 

65



 

occurred during 2005. Changes in market pricing, interest rate and volatility assumptions were made during both years. The outstanding mark-to-market value is sensitive to changes in prices, price volatilities, and interest rates. The Company estimates that a movement in prices of $1 and a change in interest and volatilities of 1% would result in a change of less than $0.1 million. All contracts outstanding at December 31, 2005 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, 2005, 100% of the trading and risk management commitments were with counterparties rated BBB-/Baa3 equivalent or better.

 

Accounts Receivable Securitization

 

KU terminated its accounts receivable securitization program in January 2004, and in May 2004, dissolved its inactive accounts receivable securitization-related subsidiary, KU R. No material pre-tax gains or losses resulted from the sale of the receivables in 2004 and 2003. KU’s net cash flows from KU R were reduced by $50.1 million and $0.1 million for 2004 and 2003, respectively. The allowance for doubtful accounts associated with the eligible securitized receivables at December 31, 2003 was $0.5 million. This allowance was based on historical experience of KU. Each securitization facility contained a fully funded reserve for uncollectible receivables.

 

RATES AND REGULATION

 

KU is subject to the jurisdiction of the Kentucky Commission, the Virginia Commission, the Tennessee Regulatory Authority and the FERC in virtually all matters related to electric utility regulation, and as such, its accounting is subject to SFAS No. 71. Given KU’s competitive position in the marketplace and the status of regulation in Kentucky and Virginia, KU has no plans or intentions to discontinue its application of SFAS No. 71. See Note 3 and Note 10 of KU’s Notes to Financial Statements under Item 8.

 

FUTURE OUTLOOK

 

Competition and Customer Choice

 

At this time, 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 KU, which may be significant, cannot currently be predicted. Some states that have already deregulated have begun discussions that could lead to re-regulation.

 

In February 2005, Kentucky’s Governor signed an executive order directing the Kentucky Commission, in conjunction with the Commerce Cabinet and the Environmental and Public Protection Cabinet, to ‘develop a Strategic Blueprint for the continued use and development of electric energy.’ This Strategic Blueprint is designed to promote future investment in electric infrastructure for the Commonwealth of Kentucky, to protect Kentucky’s low-cost electric advantage, to maintain affordable rates for all Kentuckians, and to preserve Kentucky’s commitment to environmental protection.

 

Virginia has enacted a phase-in of customer choice through the Virginia Electric Restructuring Act, however,

 

66



 

KU’s service territory has been effectively exempted from retail choice until such time as retail choice is offered to customers in KU’s other service territories.

 

Over the last several years, KU has taken many steps to keep its rates low while maintaining high levels of customer satisfaction, including: an increase in focus on commercial, industrial and residential customers; an increase in employee involvement and training; and continuous modifications of its organizational structure. KU also strives to control costs through competitive bidding and process improvements. KU’s performance in national customer satisfaction surveys continues to be high.

 

ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk.

 

See LG&E’s and KU’s Management’s Discussion and Analysis of Financial Condition and Results of Operations, Market Risks, under Item 7.

 

67



 

ITEM 8. Financial Statements and Supplementary Data.

 

INDEX OF ABBREVIATIONS

 

AEP

 

American Electric Power Company, Inc.

AFUDC

 

Allowance for Funds Used During Construction

AG

 

Attorney General of Kentucky

APBO

 

Accumulated Postretirement Benefit Obligation

ARO

 

Asset Retirement Obligation

CAIR

 

Clean Air Interstate Rule

CAMR

 

Clean Air Mercury Rule

Capital Corp.

 

E.ON U.S. Capital Corp. (formerly LG&E Capital Corp.)

CAVR

 

Clean Air Visibility Rule

Clean Air Act

 

The Clean Air Act, as amended in 1990

CCN

 

Certificate of Public Convenience and Necessity

Company

 

LG&E or KU, as applicable

Companies

 

LG&E and KU

CO2

 

Carbon Dioxide

CT

 

Combustion Turbines

CWIP

 

Construction Work in Progress

DOE

 

Department of Energy

DOJ

 

Department of Justice

DSM

 

Demand Side Management

ECAR

 

East Central Area Reliability Region

ECR

 

Environmental Cost Recovery

EEI

 

Electric Energy, Inc.

EITF

 

Emerging Issues Task Force Issue

E.ON

 

E.ON AG

E.ON U.S.

 

E.ON U.S. LLC (formerly LG&E Energy LLC and LG&E Energy Corp.)

E.ON U.S. Services

 

E.ON U.S. Services Inc. (formerly LG&E Energy Services Inc.)

EPA

 

U.S. Environmental Protection Agency

EPAct 2005

 

Energy Policy Act of 2005

ERISA

 

Employee Retirement Income Security Act of 1974, as amended

ESM

 

Earnings Sharing Mechanism

Fidelia

 

Fidelia Corporation (an E.ON affiliate)

FAC

 

Fuel Adjustment Clause

FASB

 

Financial Accounting Standards Board

FERC

 

Federal Energy Regulatory Commission

FGD

 

Flue Gas Desulfurization

FIN

 

FASB Interpretation

FPA

 

Federal Power Act

FSP

 

FASB Staff Position

FT and FT-A

 

Firm Transportation

FTR

 

Financial Transmission Right

GSC

 

Gas Supply Clause

GFA

 

Grandfathered Transmission Agreement

IBEW

 

International Brotherhood of Electrical Workers

IMEA

 

Illinois Municipal Electric Agency

IMPA

 

Indiana Municipal Power Agency

IRC

 

Internal Revenue Code of 1986, as amended

IRP

 

Integrated Resource Plan

ITP

 

Independent Transmission Provider

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

 

68



 

Kv

 

Kilovolts

Kw

 

Kilowatts

Kwh

 

Kilowatt hours

LEM

 

LG&E Energy Marketing Inc.

LG&E

 

Louisville Gas and Electric Company

LG&E Energy

 

LG&E Energy LLC (now E.ON U.S. LLC)

LG&E R

 

LG&E Receivables LLC

LG&E Services

 

LG&E Energy Services Inc. (now E.ON U.S. Services)

LMP

 

Locational Marginal Pricing

LNG

 

Liquefied Natural Gas

Mcf

 

Thousand Cubic Feet

MGP

 

Manufactured Gas Plant

MISO

 

Midwest Independent Transmission System Operator, Inc.

MMBtu

 

Million British thermal units

Moody’s

 

Moody’s Investor Services, Inc.

Mva

 

Megavolt-ampere

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 1935

 

Public Utility Holding Company Act of 1935

PUHCA 2005

 

Public Utility Holding Company Act of 2005

ROE

 

Return on Equity

RTO

 

Regional Transmission Organization

RTOR

 

Regional Through and Out Rates

S&P

 

Standard & Poor’s Rating Services

SCR

 

Selective Catalytic Reduction

SEC

 

Securities and Exchange Commission

SERP

 

Supplemental Executive Retirement Plan

SFAS

 

Statement of Financial Accounting Standards

SIP

 

State Implementation Plan

SMD

 

Standard Market Design

SO2

 

Sulfur Dioxide

SPP

 

Southwest Power Pool, Inc.

TEMT

 

Transmission and Energy Markets Tariff

Tennessee Gas

 

Tennessee Gas Pipeline Company

Texas Gas

 

Texas Gas Transmission LLC

Trimble County

 

LG&E’s Trimble County Unit 1

TVA

 

Tennessee Valley Authority

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

WNA

 

Weather Normalization Adjustment

 

69



 

Louisville Gas and Electric Company

Statements of Income

(Millions of $)

 

 

 

Years Ended December 31

 

 

 

2005

 

2004

 

2003

 

OPERATING REVENUES:

 

 

 

 

 

 

 

Electric (Note 13)

 

$

987.4

 

$

815.7

 

$

768.2

 

Gas

 

436.9

 

357.1

 

325.3

 

Total operating revenues

 

1,424.3

 

1,172.8

 

1,093.5

 

 

 

 

 

 

 

 

 

OPERATING EXPENSES:

 

 

 

 

 

 

 

Fuel for electric generation

 

282.4

 

208.3

 

198.0

 

Power purchased (Notes 10 and 13)

 

140.6

 

92.1

 

79.6

 

Gas supply expenses

 

339.4

 

266.0

 

233.6

 

Other operation and maintenance expenses

 

307.9

 

304.8

 

290.2

 

Depreciation and amortization (Note 1)

 

124.1

 

116.6

 

113.3

 

Total operating expenses

 

1,194.4

 

987.8

 

914.7

 

 

 

 

 

 

 

 

 

Net operating income

 

229.9

 

185.0

 

178.8

 

 

 

 

 

 

 

 

 

Other (income) expense - net

 

(0.7

)

3.3

 

7.2

 

Interest expense (Notes 8 and 9)

 

24.1

 

20.6

 

23.9

 

Interest expense to affiliated companies (Note 13)

 

12.7

 

12.2

 

6.8

 

 

 

 

 

 

 

 

 

Income before income taxes

 

193.8

 

148.9

 

140.9

 

 

 

 

 

 

 

 

 

Federal and state income taxes (Note 7)

 

64.9

 

53.3

 

50.1

 

 

 

 

 

 

 

 

 

Net income

 

$

128.9

 

$

95.6

 

$

90.8

 

 

The accompanying notes are an integral part of these financial statements.

 

Statements of Retained Earnings

(Millions of $)

 

 

 

Years Ended December 31

 

 

 

2005

 

2004

 

2003

 

 

 

 

 

 

 

 

 

Balance January 1

 

$

534.0

 

$

497.4

 

$

409.3

 

Add net income

 

128.9

 

95.6

 

90.8

 

 

 

 

 

 

 

 

 

 

 

662.9

 

593.0

 

500.1

 

Deduct:      Cash dividends declared on stock:

 

 

 

 

 

 

 

5% cumulative preferred

 

1.1

 

1.1

 

1.1

 

Auction rate cumulative preferred

 

1.8

 

0.9

 

0.9

 

$5.875 cumulative preferred

 

 

 

0.7

 

Common

 

39.0

 

57.0

 

 

 

 

 

 

 

 

 

 

 

 

41.9

 

59.0

 

2.7

 

 

 

 

 

 

 

 

 

Balance December 31

 

$

621.0

 

$

534.0

 

$

497.4

 

 

The accompanying notes are an integral part of these financial statements.

 

70



 

Louisville Gas and Electric Company

Statements of Comprehensive Income

(Millions of $)

 

 

 

Years Ended December 31

 

 

 

2005

 

2004

 

2003

 

Net income

 

$

128.9

 

$

95.6

 

$

90.8

 

 

 

 

 

 

 

 

 

Gain (loss) on derivative instruments and hedging activities, net of tax benefit (expense) of $0, $0.9 and $(0.4) for 2005, 2004 and 2003, respectively (Notes 1 and 4)

 

(0.1

)

(1.4

)

0.5

 

 

 

 

 

 

 

 

 

Additional minimum pension liability adjustment, net of tax benefit (expense) of $6.7, $4.1 and $(1.2) for 2005, 2004 and 2003, respectively (Note 6)

 

(12.5

)

(6.1

)

1.9

 

 

 

 

 

 

 

 

 

Other comprehensive income (loss), net of tax (Note 14)

 

(12.6

)

(7.5

)

2.4

 

 

 

 

 

 

 

 

 

Comprehensive income

 

$

116.3

 

$

88.1

 

$

93.2

 

 

The accompanying notes are an integral part of these financial statements.

 

71



 

Louisville Gas and Electric Company

Balance Sheets

(Millions of $)

 

 

 

December 31

 

 

 

2005

 

2004

 

 

 

 

 

 

 

ASSETS:

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents (Note 1)

 

$

7.1

 

$

6.8

 

Accounts receivable - less reserve of $1.1 million in 2005 and $0.8 million in 2004 (Note 4)

 

267.5

 

167.0

 

Materials and supplies (Note 1):

 

 

 

 

 

Fuel (predominantly coal)

 

38.7

 

21.8

 

Gas stored underground

 

124.9

 

77.5

 

Other materials and supplies

 

27.7

 

26.1

 

Prepayments and other current assets

 

5.8

 

3.9

 

Total current assets

 

471.7

 

303.1

 

 

 

 

 

 

 

Other property and investments – less reserve of $0.1 million in 2005 and 2004 (Note 1)

 

0.7

 

0.5

 

 

 

 

 

 

 

Utility plant, at original cost (Note 1):

 

 

 

 

 

Electric

 

3,179.9

 

3,113.7

 

Gas

 

511.6

 

487.8

 

Common

 

198.8

 

177.5

 

Total utility plant, at original cost

 

3,890.3

 

3,779.0

 

 

 

 

 

 

 

Less: reserve for depreciation

 

1,508.7

 

1,396.3

 

Total utility plant, net

 

2,381.6

 

2,382.7

 

 

 

 

 

 

 

Construction work in progress

 

158.8

 

136.8

 

Total utility plant and construction work in progress

 

2,540.4

 

2,519.5

 

 

 

 

 

 

 

Deferred debits and other assets:

 

 

 

 

 

Restricted cash (Note 1)

 

9.8

 

10.9

 

Unamortized debt expense (Note 1)

 

8.6

 

8.4

 

Regulatory assets (Note 3)

 

84.5

 

91.9

 

Other assets

 

30.7

 

32.2

 

Total deferred debits and other assets

 

133.6

 

143.4

 

 

 

 

 

 

 

Total Assets

 

$

3,146.4

 

$

2,966.5

 

 

The accompanying notes are an integral part of these financial statements.

 

72



 

Louisville Gas and Electric Company

Balance Sheets (continued)

(Millions of $)

 

 

 

December 31

 

 

 

2005

 

2004

 

 

 

 

 

 

 

LIABILITIES AND EQUITY:

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Current portion of long-term debt:

 

 

 

 

 

Long-term bonds (Note 8)

 

$

247.5

 

$

247.4

 

Long-term notes to affiliated company (Note 8)

 

 

50.0

 

Total current portion of long term debt

 

247.5

 

297.4

 

 

 

 

 

 

 

Notes payable to affiliated company (Notes 9 and 13)

 

141.2

 

58.2

 

Accounts payable

 

140.5

 

106.1

 

Accounts payable to affiliated companies (Note 13)

 

52.4

 

31.7

 

Accrued income taxes

 

6.2

 

6.2

 

Customer deposits

 

16.7

 

14.0

 

Other current liabilities

 

15.2

 

18.6

 

Total current liabilities

 

619.7

 

532.2

 

 

 

 

 

 

 

Long-term debt:

 

 

 

 

 

Long-term bonds (Note 8)

 

328.1

 

328.1

 

Long-term notes to affiliated company (Note 8)

 

225.0

 

225.0

 

Mandatorily redeemable preferred stock (Note 8)

 

20.0

 

21.3

 

Total long term debt

 

573.1

 

574.4

 

 

 

 

 

 

 

Deferred credits and other liabilities:

 

 

 

 

 

Accumulated deferred income taxes (Note 7)

 

321.7

 

347.2

 

Investment tax credit, in process of amortization

 

42.1

 

46.2

 

Accumulated provision for pensions and related benefits (Note 6)

 

143.5

 

120.6

 

Asset retirement obligations

 

26.6

 

10.3

 

Regulatory liabilities (Note 3):

 

 

 

 

 

Accumulated cost of removal of utility plant

 

218.9

 

220.2

 

Regulatory liability deferred income taxes

 

41.7

 

37.2

 

Other regulatory liabilities

 

20.2

 

14.9

 

Other liabilities

 

41.3

 

40.1

 

Total deferred credits and other liabilities

 

856.0

 

836.7

 

 

 

 

 

 

 

Commitments and contingencies (Note 10)

 

 

 

 

 

 

 

 

 

 

 

Cumulative preferred stock

 

70.4

 

70.4

 

 

 

 

 

 

 

COMMON EQUITY:

 

 

 

 

 

Common stock, without par value - Authorized 75,000,000 shares, outstanding 21,294,223 shares

 

424.4

 

424.4

 

Additional paid-in capital

 

40.0

 

40.0

 

Accumulated other comprehensive income (Note 14)

 

(58.2

)

(45.6

)

Retained earnings

 

621.0

 

534.0

 

Total common equity

 

1,027.2

 

952.8

 

 

 

 

 

 

 

Total Liabilities and Equity

 

$

3,146.4

 

$

2,966.5

 

 

The accompanying notes are an integral part of these financial statements.

 

73



 

Louisville Gas and Electric Company

Statements of Cash Flows

(Millions of $)

 

 

 

Years Ended December 31

 

 

 

2005

 

2004

 

2003

 

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

 

 

Net income

 

$

128.9

 

$

95.6

 

$

90.8

 

Items not requiring cash currently:

 

 

 

 

 

 

 

Depreciation and amortization

 

119.3

 

116.6

 

113.3

 

Deferred income taxes - net

 

(14.3

)

5.5

 

20.1

 

Investment tax credit - net

 

(4.1

)

(4.1

)

(4.2

)

VDT amortization

 

30.2

 

30.1

 

30.4

 

Unrealized gain (loss) on derivatives

 

 

2.6

 

(1.1

)

Other

 

7.8

 

(2.0

)

10.8

 

Change in certain current assets and liabilities:

 

 

 

 

 

 

 

Accounts receivable

 

(100.5

)

(82.4

)

(16.1

)

Materials and supplies

 

(65.9

)

(5.3

)

(7.6

)

Accounts payable

 

55.1

 

6.3

 

8.7

 

Accrued income taxes

 

 

(5.3

)

17.2

 

Prepayments and other

 

(2.5

)

6.8

 

0.9

 

Pension funding

 

(9.8

)

(34.5

)

(89.1

)

Gas supply clause receivable, net

 

(3.2

)

10.3

 

(4.7

)

Litigation settlement

 

 

7.0

 

 

Earnings sharing mechanism receivable

 

2.1

 

10.2

 

0.1

 

Other

 

7.3

 

14.2

 

(6.2

)

Net cash provided by operating activities

 

150.4

 

171.6

 

163.3

 

 

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

 

 

Construction expenditures

 

(138.9

)

(148.3

)

(213.0

)

Change in restricted cash

 

1.1

 

(10.9

)

 

Other

 

(0.2

)

0.1

 

0.2

 

Net cash used for investing activities

 

(138.0

)

(159.1

)

(212.8

)

 

 

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

 

 

Long-term borrowings from affiliated company

 

 

125.0

 

200.0

 

Repayment of long-term borrowings from affiliated company

 

(50.0

)

(50.0

)

 

Short-term borrowings from affiliated company

 

788.6

 

552.8

 

602.7

 

Repayment of short-term borrowings from affiliated company

 

(705.6

)

(574.9

)

(715.4

)

Retirement of first mortgage bonds

 

 

 

(42.6

)

Issuance of pollution control bonds

 

40.0

 

 

128.0

 

Issuance expense on pollution control bonds

 

(1.9

)

(0.1

)

(5.9

)

Retirement of pollution control bonds

 

(40.0

)

 

(128.0

)

Retirement of mandatorily redeemable preferred stock

 

(1.3

)

(1.3

)

(1.3

)

Payment of dividends

 

(41.9

)

(58.9

)

(3.3

)

Net cash (used for) provided by financing activities

 

(12.1

)

(7.4

)

34.2

 

 

 

 

 

 

 

 

 

Change in cash and cash equivalents

 

0.3

 

5.1

 

(15.3

)

 

 

 

 

 

 

 

 

Cash and cash equivalents at beginning of year

 

6.8

 

1.7

 

17.0

 

 

 

 

 

 

 

 

 

Cash and cash equivalents at end of year

 

$

7.1

 

$

6.8

 

$

1.7

 

 

 

 

 

 

 

 

 

Supplemental disclosures of cash flow information:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash paid during the year for:

 

 

 

 

 

 

 

Income taxes

 

$

83.3

 

$

52.1

 

$

24.9

 

Interest on borrowed money

 

20.9

 

18.1

 

23.8

 

Interest to affiliated companies on borrowed money

 

12.7

 

11.3

 

4.2

 

 

The accompanying notes are an integral part of these financial statements.

 

74



 

Louisville Gas and Electric Company

Statements of Capitalization

(Millions of $)

 

 

 

December 31

 

 

 

2005

 

2004

 

 

 

 

 

 

 

LONG-TERM DEBT (Note 8):

 

 

 

 

 

Pollution control series:

 

 

 

 

 

S due September 1, 2017, variable %

 

$

31.0

 

$

31.0

 

T due September 1, 2017, variable %

 

60.0

 

60.0

 

U due August 15, 2013, variable %

 

35.2

 

35.2

 

X due April 15, 2023, 5.90%

 

 

40.0

 

Y due May 1, 2027, variable %

 

25.0

 

25.0

 

Z due August 1, 2030, variable %

 

83.3

 

83.3

 

AA due September 1, 2027, variable %

 

10.1

 

10.1

 

BB due September 1, 2026, variable %

 

22.5

 

22.5

 

CC due September 1, 2026, variable %

 

27.5

 

27.5

 

DD due November 1, 2027, variable %

 

35.0

 

35.0

 

EE due November 1, 2027, variable %

 

35.0

 

35.0

 

FF due October 1, 2032, variable %

 

41.7

 

41.7

 

GG due October 1, 2033, variable %

 

128.0

 

128.0

 

HH due February 1, 2035, variable %

 

40.0

 

 

Notes payable to Fidelia:

 

 

 

 

 

Due January 6, 2005, 1.53%, secured

 

 

50.0

 

Due January 16, 2012, 4.33%, secured

 

25.0

 

25.0

 

Due April 30, 2013, 4.55%, unsecured

 

100.0

 

100.0

 

Due August 15, 2013, 5.31%, secured

 

100.0

 

100.0

 

Mandatorily redeemable preferred stock:

 

 

 

 

 

$5.875 series, outstanding shares of 212,500 in 2005 and 225,000 in 2004

 

21.3

 

22.5

 

 

 

 

 

 

 

Total long-term debt outstanding

 

820.6

 

871.8

 

 

 

 

 

 

 

Less current portion of long-term debt

 

247.5

 

297.4

 

 

 

 

 

 

 

Long-term debt

 

573.1

 

574.4

 

 

CUMULATIVE PREFERRED STOCK:

 

 

 

Shares

 

Current

 

 

 

 

 

 

 

Outstanding

 

Redemption Price

 

 

 

 

 

$25 par value, 1,720,000 shares authorized - 5% series

 

860,287

 

$

28.00

 

21.5

 

21.5

 

Without par value, 6,750,000 shares authorized - Auction rate

 

500,000

 

$

100.00

 

50.0

 

50.0

 

Preferred stock expense, net

 

 

 

 

 

(1.1

)

(1.1

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

70.4

 

70.4

 

 

COMMON EQUITY:

 

Common stock, without par value - Authorized 75,000,000 shares, outstanding 21,294,223 shares

 

425.2

 

425.2

 

Common stock expense

 

(0.8

)

(0.8

)

Additional paid-in capital

 

40.0

 

40.0

 

Accumulated other comprehensive income (Note 14)

 

(58.2

)

(45.6

)

Retained earnings

 

621.0

 

534.0

 

Total common equity

 

1,027.2

 

952.8

 

Total capitalization

 

$

1,670.7

 

$

1,597.6

 

 

The accompanying notes are an integral part of these financial statements.

 

75



 

Louisville Gas and Electric Company

Notes to Financial Statements

 

Note 1 - Summary of Significant Accounting Policies

 

LG&E, a subsidiary of E.ON U.S. (formerly LG&E Energy) and an indirect subsidiary of 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. E.ON U.S. is a public utility holding company with wholly owned subsidiaries including LG&E, KU, Capital Corp., LEM and E.ON U.S. Services. All of LG&E’s common stock is held by E.ON U.S. In May 2004, LG&E dissolved its accounts receivable securitization-related subsidiary, LG&E R. Prior to May 2004, the consolidated financial statements included the accounts of LG&E and LG&E R with the elimination of intercompany accounts and transactions.

 

Effective December 30, 2003, LG&E Energy LLC became the successor, by assignment and subsequent merger, to all assets and liabilities of LG&E Energy Corp. Effective December 1, 2005, LG&E Energy LLC was renamed E.ON U.S. LLC.

 

Certain reclassification entries have been made to the previous years’ financial statements to conform to the 2005 presentation with no impact on net assets, liabilities and capitalization or previously reported net income and cash flows.

 

During 2005, LG&E made out-of-period adjustments for estimated over/under collection of ECR revenues to be billed in subsequent periods. The adjustments were related to the reporting periods of March 2003 through December 2004. As a result, LG&E revenues for 2005 were increased $5.3 million and net income for 2005 was increased $3.2 million. LG&E revenues for 2004 and 2003 were understated by $2.4 million and $2.9 million, respectively, and net income was understated by $1.4 million and $1.8 million, respectively.

 

Regulatory Accounting. LG&E is subject to SFAS No. 71 under which costs that would otherwise be charged to expense are deferred as regulatory assets based on expected recovery from customers in future rates. Likewise, 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 of deferred costs and expected return of deferred credits is based on specific ratemaking decisions or precedent for each item as prescribed by the FERC or the Kentucky Commission. See Note 3, Rates and Regulatory Matters, for additional detail regarding regulatory assets and liabilities.

 

Cash and Cash Equivalents. LG&E considers all debt instruments purchased with an original maturity of three months or less to be cash equivalents.

 

Allowance for Doubtful Accounts. The allowance for doubtful accounts is based on the ratio of the amounts charged-off during the last twelve months to the retail revenues billed over the same period multiplied by the retail revenues billed over the last four months. Accounts with no payment activity are charged-off after four months, although collection efforts continue thereafter.

 

Materials and Supplies. Fuel, gas stored underground and other materials and supplies inventories are accounted for using the average-cost method. Emission allowances are included in inventory at cost and are not currently traded by LG&E. At December 31, 2005 and 2004, the emission allowances inventory was less than $0.1 million.

 

Other Property and Investments. Other property and investments on the balance sheet consists of LG&E’s investment in OVEC and non-utility plant. 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

 

76



 

electricity, Kyger Creek Station in Ohio and Clifty Creek Station in Indiana. Through March 2006, LG&E is entitled to receive 7% of OVEC’s output, and thereafter is entitled to receive 5.63%, representing approximately 124 Mw.

 

As of December 31, 2005 and 2004, LG&E’s investment in OVEC totaled $0.6 and $0.5 million, respectively. LG&E is not the primary beneficiary of OVEC, and, therefore, it is not consolidated into the financial statements of LG&E and is accounted for under the cost method of accounting. LG&E’s maximum exposure to loss as a result of its involvement with OVEC is limited to the value of its investment. In the event of the inability of OVEC to fulfill its power provision requirements, LG&E would substitute such power supply with either owned generation or market purchases and would generally recover associated incremental costs through regulatory rate mechanisms. See Note 10, Commitments and Contingencies, for further discussion of developments regarding LG&E’s ownership interest and power purchase rights.

 

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, in accordance with Kentucky Commission regulations.

 

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. The amounts provided were approximately 3.2% in 2005 (3.0% electric, 2.4% gas, and 8.0% common); 3.1% in 2004 (2.9% electric, 2.8% gas and 7.6% common); and 3.3% for 2003 (2.9% electric, 2.8% gas and 9.4% common), of average depreciable plant. Of the amount provided for depreciation, at December 31, 2005, approximately 0.4% electric, 0.8% gas and 0.02% common were related to the retirement, removal and disposal costs of long lived assets.  Of the amount provided for depreciation, at December 31, 2004, approximately 0.4% electric, 0.9% gas and 0.04% common were related to the retirement, removal and disposal costs of long lived assets.

 

Restricted Cash. A deposit in the amount of $9.8 million, used as collateral for an $83.3 million interest rate swap expiring in 2020, is classified as restricted cash on LG&E’s balance sheet.

 

Unamortized Debt Expense. Debt expense is capitalized in deferred debits and amortized over the lives of the related bond issues.

 

Income Taxes. Income taxes are accounted for under SFAS No.109. In accordance with this statement,

 

77



 

deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, as measured by enacted tax rates that are expected to be in effect in the periods when the deferred tax assets and liabilities are expected to be settled or realized. Significant judgment is required in determining the provision for income taxes, and there are transactions for which the ultimate tax outcome is uncertain. To provide for these uncertainties or exposures, an allowance is maintained for tax contingencies based on management’s best estimate of probable loss. Tax contingencies are analyzed periodically and adjustments are made when events occur to warrant a change. See Note 7, Income Taxes.

 

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 bases 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 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 based on allocating the daily system net deliveries between billed volumes and unbilled volumes. The allocation is based on a daily ratio of the number of meter reading cycles remaining in the month to the total number of meter reading cycles in each month. Each day’s ratio is then multiplied by each day’s system net deliveries to determine an estimated billed and unbilled volume for each day of the accounting period. The unbilled revenue estimates included in accounts receivable were approximately $81.8 million and $63.0 million at December 31, 2005 and 2004, respectively.

 

Fuel and Gas Costs. The cost of fuel for electric generation is charged to expense as used, and the cost of natural 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 natural gas procurement 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. Accrued liabilities, including legal and environmental, are recorded when they are probable and estimable. Actual results could differ from those estimates.

 

New Accounting Pronouncements. The following accounting pronouncement was issued that affected LG&E in 2005:

 

FIN 47

 

LG&E adopted FIN 47,  effective December 31, 2005. FIN 47 expands the term “conditional asset retirement obligation” as used in SFAS No. 143, to refer to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. An entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when

 

78



 

incurred; generally, upon acquisition, construction or development and through the normal operation of the asset.

 

As a result of the implementation of FIN 47, LG&E recorded additional ARO net assets and liabilities during the fourth quarter of 2005 in the amount of $1.0 million and $15.7 million, respectively. LG&E also recorded a cumulative effect adjustment in the amount of $12.3 million to reflect the accumulated depreciation and accretion of ARO assets at the transition date less amounts previously accrued under regulatory depreciation. A $2.4 million reduction in the accumulated cost of removal regulatory liability was also recorded for this previously accrued cost of removal. LG&E recorded offsetting regulatory assets of $12.3 million, pursuant to regulatory treatment prescribed under SFAS No. 71 as the costs of removal are allowed under Kentucky Commission ratemaking.

 

Had FIN 47 been in effect at the beginning of the 2004 reporting period, LG&E would have established asset retirement obligations as described in the following table (in millions):

 

 

 

2005

 

2004

 

Provision at beginning of the year

 

$

14.8

 

$

14.0

 

Accretion expense

 

0.9

 

0.8

 

Provision at end of the year

 

$

15.7

 

$

14.8

 

 

Note 2 – Company Structure

 

On July 1, 2002, E.ON completed its acquisition of Powergen, including E.ON U.S. (formerly LG&E Energy), for approximately £5.1 billion ($7.3 billion). As a result of the acquisition, E.ON U.S. became a wholly owned subsidiary 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 Company continues to file SEC reports.

 

Note 3 - Rates and Regulatory Matters

 

Electric and Gas Rate Cases

 

In December 2003, LG&E filed an application with the Kentucky Commission requesting adjustments in LG&E’s electric and natural gas rates. LG&E asked for general adjustments in electric and natural gas rates based on the twelve month test period ended September 30, 2003. The revenue increases requested were $63.8 million for electric and $19.1 million for natural gas. In June 2004, the Kentucky Commission issued an order approving increases in LG&E’s annual electric base rates of approximately $43.4 million (7.7%) and annual natural gas base rates of approximately $11.9 million (3.4%). The rate increases took effect on July 1, 2004.

 

During 2004 and 2005, the AG conducted an investigation of LG&E, as well as of the Kentucky Commission and its staff, requesting information regarding allegedly improper communications between LG&E and the Kentucky Commission, particularly during the period covered by the rate cases. Concurrently, the AG had filed pleadings with the Kentucky Commission requesting rehearing of the rate cases on computational components of the increased rates, including income taxes, cost of removal and depreciation amounts. In August 2004, the Kentucky Commission denied the AG’s rehearing request on the cost of removal and depreciation issues and granted rehearing on the income tax component. The Kentucky Commission further agreed to hold in abeyance further proceedings in the rate case, until the AG filed its investigative report regarding the allegations of improper communication.

 

In January 2005 and February 2005, the AG filed a motion summarizing its investigative report as containing evidence of improper communications and record-keeping errors by LG&E in its conduct of activities before

 

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the Kentucky Commission or other state governmental entities and forwarded such report to the Kentucky Commission under continued confidential treatment to allow it to consider the report, including its impact, if any, on completing its investigation and any remaining steps in the rate case. To date, LG&E has neither seen nor requested copies of the report or its contents.

 

In December 2005, the Kentucky Commission issued an order noting completion if its inquiry, including review of the AG’s investigative report. The order concludes no improper communications occurred during the rate proceedings. The order further established a procedural schedule through the first quarter of 2006 for considering the sole issue for which rehearing was granted: state income tax rates used in calculating the granted rate increases. This issue is estimated at less than $1 million annually. Upon resolution of this issue on rehearing, the initial rate increase order could be subject to judicial appeal.

 

LG&E believes no improprieties have occurred in its communications with the Kentucky Commission and has cooperated with the proceedings before the AG and the Kentucky Commission. LG&E is currently unable to determine the ultimate impact, if any, of, or any possible future actions of the AG or the Kentucky Commission arising out of, the AG’s report and investigation, including whether there will be further actions to appeal, review or otherwise challenge the granted increases in rates.

 

Regulatory Assets and Liabilities

 

The following regulatory assets and liabilities were included in LG&E’s Balance Sheets as of December 31:

 

(in millions)

 

2005

 

2004

 

 

 

 

 

 

 

VDT Costs

 

$

7.5

 

$

37.7

 

Unamortized loss on bonds

 

20.6

 

20.3

 

ARO

 

20.0

 

6.9

 

Gas supply adjustments

 

25.4

 

13.3

 

Merger surcredit

 

3.5

 

4.8

 

Other

 

7.5

 

8.9

 

Total regulatory assets

 

$

84.5

 

$

91.9

 

 

 

 

 

 

 

Accumulated cost of removal of utility plant

 

$

218.9

 

$

220.2

 

Deferred income taxes - net

 

41.7

 

37.2

 

Gas supply adjustments

 

17.3

 

8.4

 

ECR

 

 

4.0

 

Other

 

2.9

 

2.5

 

Total regulatory liabilities

 

$

280.8

 

$

272.3

 

 

LG&E currently earns a return on all regulatory assets except for gas supply adjustments, FAC, gas performance based ratemaking and DSM, all of which are separate rate mechanisms with recovery within twelve months. Additionally, no current return is earned on the ARO regulatory asset. This regulatory asset will be offset against the associated regulatory liability, ARO asset, and ARO liability at the time the underlying asset is retired. See Note 1, Summary of Significant Accounting Policies.

 

VDT. During the first quarter of 2001, LG&E recorded a $144.0 million charge for a workforce reduction program. Primary components of the charge were separation benefits, enhanced early retirement benefits and healthcare benefits. The result of this workforce reduction was the elimination of approximately 700 positions, accomplished primarily through a voluntary enhanced severance program.

 

In December 2001, the Kentucky Commission issued an order approving a settlement agreement allowing LG&E to set up a regulatory asset of $141.0 million for the workforce reduction costs and begin amortizing

 

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these costs over a five-year period starting in April 2001. Some employees rescinded their participation in the voluntary enhanced severance program, which thereby decreased the charge to the regulatory asset from $144.0 million to $141.0 million. The order reduced revenues by approximately $26.0 million through a surcredit on bills to ratepayers over the same five-year period. The surcredit represents savings, net of the amortization of the costs, stipulated by LG&E and shared 40% with ratepayers and with LG&E retaining 60% of the net savings.

 

The five-year VDT amortization period is scheduled to expire in March 2006. As part of the settlement agreements in the electric and natural gas rate cases, LG&E was required to file, and did file on September 30, 2005, with the Kentucky Commission a plan for the future ratemaking treatment of the VDT surcredit and costs. The surcredit will remain in effect until the Commission enters an order on the future disposition of VDT-related issues.

 

On February 27, 2006, the AG, KIUC, LG&E and KU reached a settlement agreement on the future ratemaking treatment of the VDT surcredits and costs and subsequently submitted a joint motion to the Kentucky Commission to approve the unanimous settlement agreement. Under the terms of the settlement agreement, the VDT surcredit will continue at the current level until such time as LG&E files for a change in electric or gas base rates. The Kentucky Commission held a public hearing in the proceeding on March 21, 2006 and issued an order thereafter approving the settlement agreement.

 

Unamortized Loss on Bonds. The costs of early extinguishment of debt, including call premiums, legal and other expenses, and any unamortized balance of debt expense are amortized over the life of either replacement debt (in the case of re-financing) or the original life of the extinguished debt.

 

ARO. A summary of LG&E’s net ARO assets, regulatory assets, liabilities and cost of removal established under FIN 47 and SFAS No. 143 follows:

 

 

 

ARO Net

 

ARO

 

Regulatory

 

Regulatory

 

Accumulated

 

Cost of Removal

 

(in millions)

 

Assets

 

Liabilities

 

Assets

 

Liabilities

 

Cost of Removal

 

Depreciation

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2003

 

$

3.5

 

$

(9.7

)

$

6.0

 

$

(0.1

)

$

0.5

 

$

 

ARO accretion

 

 

(0.7

)

0.7

 

 

 

 

ARO depreciation

 

(0.2

)

 

0.2

 

 

 

 

Removal cost incurred

 

 

0.1

 

 

 

 

 

Cost of removal depreciation

 

 

 

 

 

 

 

As of December 31, 2004

 

3.3

 

(10.3

)

6.9

 

(0.1

)

0.5

 

 

FIN 47 net asset additions

 

1.0

 

(15.7

)

12.3

 

 

2.4

 

 

ARO accretion

 

 

(0.7

)

0.7

 

 

 

 

ARO depreciation

 

(0.1

)

 

0.1

 

 

 

 

Removal cost incurred

 

 

0.1

 

 

 

 

 

Cost of removal depreciation

 

 

 

 

(0.1

)

 

0.1

 

As of December 31, 2005

 

$

4.2

 

$

(26.6

)

$

20.0

 

$

(0.2

)

$

2.9

 

$

0.1

 

 

Pursuant to regulatory treatment prescribed under SFAS No. 71, an offsetting regulatory credit was recorded in Depreciation and amortization in the income statement of $0.8 million in 2005 and $0.9 million in 2004 for the ARO accretion and depreciation expense. LG&E AROs are primarily related to the final retirement of assets associated with generating units and natural gas wells. For assets associated with AROs, the removal cost accrued through depreciation under regulatory accounting is established as a regulatory asset or liability pursuant to regulatory treatment prescribed under SFAS No. 71. For the years ended December 31, 2005 and 2004, LG&E recorded less than $0.1 million of depreciation expense related to the cost of removal of ARO related assets. An offsetting regulatory liability was established pursuant to regulatory treatment prescribed under SFAS No. 71.

 

LG&E transmission and distribution lines largely operate under perpetual property easement agreements which

 

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do not generally require restoration upon removal of the property. Therefore, under SFAS No. 143, no material asset retirement obligations are recorded for transmission and distribution assets.

 

Merger Surcredit. As part of the LG&E Energy merger with KU Energy in 1998, LG&E estimated non-fuel savings over a ten-year period following the merger. Costs to achieve these savings were deferred and amortized over a five-year period pursuant to regulatory orders. 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 LG&E and KU, 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 ratepayers the then-projected non-fuel savings associated with the merger. The Companies submitted this filing in January 2003, proposing to continue to share with ratepayers, on a 50%/50% basis, the estimated fifth-year gross level of non-fuel savings associated with the merger. In October 2003, the Kentucky Commission issued an order approving a settlement agreement reached with the parties in the case. LG&E’s merger surcredit will remain in place for another five-year term beginning July 1, 2003 and the merger savings will continue to be shared 50% with ratepayers and 50% with shareholders.

 

ESM. Prior to 2004, LG&E’s retail electric rates were subject to an ESM. The ESM, initially in place for three years beginning in 2000, set an upper (12.5%) and lower (10.5%) limit for rate of return on equity. If earnings were above the upper limit, the excess earnings were shared 40% with ratepayers and 60% with shareholders; if earnings were below the lower limit, the earnings deficiency was recovered 40% from ratepayers and 60% from shareholders. By order of the Kentucky Commission, rate changes prompted by the ESM filing went into effect in April of each year subject to a balancing adjustment in successive periods.

 

In November 2002, LG&E filed a revised ESM tariff which proposed continuance of the existing ESM through December 2005. In addition, the Kentucky Commission initiated a focused management audit to review the ESM plan and reassess its reasonableness. LG&E filed its final 2003 ESM calculations with the Kentucky Commission on March 1, 2004, and applied for recovery of $13.0 million. Based upon estimates, LG&E previously accrued $8.9 million for the 2003 ESM as of December 31, 2003. In June 2004, the Kentucky Commission issued an order largely accepting proposed settlement agreements by LG&E and all intervenors regarding the ESM. Under the ESM settlements, LG&E continued to collect approximately $13.0 million of previously requested 2003 ESM revenue amounts through March 2005. As part of the settlement, the parties agreed to a termination of the ESM mechanism relating to all periods after 2003.

 

FAC. LG&E’s retail electric rates contain an FAC, whereby increases and decreases in the cost of fuel for electric generation are reflected in the rates charged to retail electric customers. In January 2003, the Kentucky Commission reviewed KU’s FAC and, as part of the order in that case, required that an independent audit be conducted to examine operational and management aspects of both LG&E’s and KU’s fuel procurement functions. The final report was issued in February 2004. The report’s recommendations related to documentation and process improvements. Management Audit Action Plans were agreed upon by LG&E and the Kentucky Commission Staff in the second quarter of 2004. LG&E filed its first Audit Progress Report with the Kentucky Commission Staff in November 2004. A second Audit Progress Report was filed May 2005. The third Audit Progress Report was filed in December 2005. In January 2006, the Kentucky Commission staff informed LG&E and KU that reporting on all of the original recommendations, but one, has been concluded. LG&E and KU are to file another Audit Progress Report on the remaining open recommendation on August 15, 2006.

 

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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. No significant issues have been identified as a result of these reviews.

 

In December 2004, the Kentucky Commission initiated a two-year review of LG&E’s past operations of the fuel clause and transfer of fuel costs from the fuel adjustment clause to base rates. A public hearing on the matter was held on March 17, 2005. An order by the Kentucky Commission was issued in May 2005 approving LG&E’s base fuel component of 13.49 mills/kwh as filed. Revised tariff schedules for LG&E were filed to reflect the change in the base fuel component.

 

On July 7, 2005, the Kentucky Commission initiated the six-month review of the LG&E fuel adjustment clause for the period of November 2004 through April 2005. During November 2005, the Kentucky Commission approved the charges and credits billed and the fuel procurement practices of LG&E.

 

On December 27, 2005, the Kentucky Commission initiated the six-month review of the LG&E fuel adjustment clause for the period of May 2005 through October 2005. Initial discovery was completed on January 17, 2006, and a hearing was held on March 16, 2006. LG&E anticipates Kentucky Commission approval of the charges and credits billed and the fuel procurement practices of LG&E during the second quarter of 2006.

 

DSM. LG&E’s rates contain a DSM provision. The provision includes a rate mechanism that provides for concurrent recovery of DSM costs and provides an incentive for implementing DSM programs. The provision allows LG&E to recover revenues from lost sales associated with the DSM programs based on program plan engineering estimates and post-implementation evaluations.

 

Gas Supply Adjustments.  Since November 1, 1997, LG&E has operated under an experimental PBR mechanism related to its natural gas procurement activities. LG&E’s rates are adjusted annually to recover (or refund) its portion of the savings (or expenses) incurred during each PBR year (12 months ending October 31). During the PBR year ending in 2005, LG&E achieved $10.8 million in savings. Of that total savings amount, LG&E’s portion was $2.7 million and the ratepayers’ portion was $8.1 million. Pursuant to the extension of LG&E’s natural gas supply cost PBR mechanism effective November 1, 2001, the sharing mechanism under the PBR requires savings (and expenses) to be shared 25% with shareholders and 75% with ratepayers up to 4.5% of the benchmarked natural gas costs. Savings (and expenses) in excess of 4.5% of the benchmarked natural gas costs are shared 50% with shareholders and 50% with ratepayers. LG&E filed a report and assessment with the Kentucky Commission in December 2004, seeking modification and extension of the mechanism. Following a review by the Kentucky Commission, the current natural gas supply cost PBR mechanism was extended through 2010 without further modification.

 

Accumulated Cost of Removal of Utility Plant. As of December 31, 2005 and 2004, LG&E has segregated the cost of removal, embedded in accumulated depreciation, of $218.9 million and $220.2 million, respectively, in accordance with FERC Order No. 631. For reporting purposes in the balance sheets, LG&E has presented this cost of removal as a regulatory liability pursuant to SFAS No. 71.

 

Deferred Income Taxes – Net. Deferred income taxes represent the future income tax effects of recognizing the regulatory assets and liabilities in the income statement. Deferred income taxes are recognized at currently enacted tax rates for all material temporary differences between the financial reporting and income tax bases of assets and liabilities.

 

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ECR. LG&E’s retail rates contain an ECR surcharge which recovers costs incurred by LG&E that are required to comply with the Clean Air Act and other environmental regulations.  In January 2003, the Kentucky Commission initiated a six-month review of LG&E’s environmental surcharge. A final order was issued in April 2003, in which LG&E was ordered to refund $2.9 million it had previously over-collected from customers. In July 2003, the Kentucky Commission initiated a two-year review of LG&E’s environmental surcharge. A final order was issued in December 2003 in which LG&E was ordered to roll $15.2 million of environmental assets 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 going forward. Additionally, LG&E was ordered to collect $0.2 million to correct for amounts under-collected from customers. The rates of return for LG&E’s 1995 and post-1995 plans were reset to 3.32% and 10.92%, respectively.

 

In June 2004, the Kentucky Commission issued an order approving a settlement agreement that, among other things, revised the rate of return for LG&E’s post-1995 plan to 10.72%, with an 11% return on common equity. The order also approved the elimination of LG&E’s 1995 plan from its ECR billing mechanism, with all remaining costs associated with that plan to be included in their entirety in base rates.

 

In December 2004, LG&E filed an application with the Kentucky Commission to amend its compliance plan to allow recovery of costs associated with new and additional environmental compliance facilities, including the expansion of the landfill facility at the Mill Creek station. The estimated capital cost of the additional facilities for the next three years is approximately $40.0 million. LG&E requested an overall rate of return of 10.72%, including an 11% return on common equity. Hearings in these cases occurred during May 2005 and final orders were issued in June 2005, granting approval of the amendments to LG&E’s compliance plans.

 

Other Regulatory Matters

 

MISO. The MISO is a non-profit independent transmission system operator that controls approximately 97,000 miles of transmission lines over 947,000 square miles in 15 northern Midwest states and one Canadian province. The MISO operates the regional power grid and wholesale electricity market in an effort to optimize efficiency and safeguard reliability in accordance with federal energy policy.

 

LG&E is now involved in proceedings with the Kentucky Commission and the FERC seeking the authority to exit the MISO. A timeline of events regarding the MISO and various proceedings is as follows:

 

                  September 1998 – The FERC granted conditional approval for the formation of the MISO. LG&E was a founding member.

 

                  October 2001 – The FERC ordered that all bundled retail loads and grandfathered wholesale loads of each member transmission owner be included in the calculation of the MISO “cost adder,” the Schedule 10 charges designed to recover the MISO’s cost of operation, including start-up capital (debt) costs. LG&E and several owners opposed the FERC order and filed suit with the United States Court of Appeals.

 

                  February 2002 – The MISO began commercial operations.

 

                  February 2003 – The FERC reaffirmed its position on the Schedule 10 charges and the order was subsequently upheld by the U.S. Court of Appeals.

 

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                  July 2003 – The Kentucky Commission opened an investigation into LG&E’s MISO membership. Testimony was filed by LG&E that supported an exit from the MISO, under certain conditions. This proceeding remains open.

 

                  August 2004 – The MISO filed its FERC-required TEMT. LG&E and other owners filed opposition to certain conditions of the TEMT and sought to delay the implementation. Such opposition was denied by the FERC.

 

                  December 2004 – LG&E provided the MISO its required one-year notice of intent to exit the grid.

 

                  April 2005 – The MISO implemented its day-ahead and real-time market (MISO Day 2), including a congestion management system.

 

                  October 2005 – LG&E filed documents with the FERC seeking authority to exit the MISO. This proceeding remains open.

 

                  November 2005 – LG&E requested a Kentucky Commission order authorizing the transfer of functional control of its transmission facilities from the MISO to LG&E, for the purpose of exiting the MISO. The request stated that the TVA would have control to the extent necessary to act as LG&E’s Reliability Coordinator and for the SPP to perform its function as LG&E’s Independent Transmission Organization. This proceeding remains open.

 

Based on various financial analyses performed internally, in response to the July 2003 Kentucky Commission investigation into MISO membership, and particularly in light of the financial impacts following MISO’s implementation of the new day-ahead and real-time markets, LG&E determined that the costs of MISO membership, both now and in the future, outweigh the benefits.

 

Should LG&E be allowed to exit the MISO, an aggregate exit fee of up to $41.0 million (approximately $16.0 million for LG&E and approximately $25.0 million for KU) could be imposed, depending on the timing and circumstances of the actual exit. LG&E estimates that, over time, such fee could be more than offset by savings resulting from exit from the MISO. Conversely, should LG&E be ordered to remain in the MISO, costs are expected to continue to exceed benefits, currently without mechanisms for immediate recovery.

 

On March 17, 2006, the FERC issued an order conditionally approving the request of LG&E and KU to exit the MISO. For further discussion, see Note 16, Subsequent Events.

 

Market-Based Rate Authority. Since April 2004, the FERC has initiated proceedings to modify its methods which assess generation market power and has established more stringent interim market screen tests. During 2005, in connection with LG&E’s and KU’s tri-annual market-based rate tariff renewals, although disputed by LG&E and KU, the FERC continued to contend that LG&E and KU failed such market screens in certain regions. In January 2006, in order to resolve the matter, LG&E and KU submitted proposed tariff schedules to the FERC containing a mitigation mechanism with respect to applicable power sales into an adjacent western Kentucky control area where a non-utility affiliate company is active. Prices for such sales will be capped at a relevant MISO power pool index price. Should LG&E and KU exit the MISO, they could additionally be deemed to have market power in their own joint control area, potentially requiring a similar mitigation mechanism for power sales into such region. LG&E and KU cannot predict the ultimate impact of the current or potential mitigation mechanisms on their future wholesale power revenues.

 

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IRP. In April 2005, LG&E and KU filed their 2005 Joint IRP with the Kentucky Commission. The IRP provides historical and projected demand, resource and financial data, and other operating performance and system information. The AG and the KIUC were granted intervention in the IRP proceeding. The Kentucky Commission issued its staff report on February 15, 2006, with no substantive issues noted and closed the case by Order dated February 24, 2006.

 

Kentucky Commission Administrative Case for System Adequacy. In June 2001, Kentucky’s Governor 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. 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. 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 the 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.

 

EPAct 2005. The EPAct 2005 was enacted on August 8, 2005. Among other matters, this comprehensive legislation contains provisions mandating improved electric reliability standards and performance; providing economic and other incentives relating to transmission, pollution control and renewable generation assets; increasing funding for clean coal generation incentives; repealing PUHCA 1935; enacting PUHCA 2005 and expanding FERC jurisdiction over public utility holding companies and related matters via the FPA and PUHCA 2005.

 

The FERC was directed by the EPAct 2005 to adopt rules to address many areas previously regulated by the other agencies under other statutes, including PUHCA 1935. The FERC is in various stages of rulemaking on these issues and LG&E is monitoring these rulemaking activities and actively participating in these and other rulemaking proceedings. LG&E is still evaluating the potential impacts of the EPAct 2005 and the associated rulemakings and cannot predict what impact the EPAct 2005, and any such rulemakings, will have on its operations or financial position.

 

Kentucky Commission Strategic Blueprint. In February 2005, Kentucky’s Governor signed an executive order directing the Kentucky Commission, in conjunction with the Commerce Cabinet and the Environmental and Public Protection Cabinet, to ‘develop a Strategic Blueprint for the continued use and development of electric energy.’ This Strategic Blueprint is designed to promote future investment in electric infrastructure for the Commonwealth of Kentucky, to protect Kentucky’s low-cost electric advantage, to maintain affordable rates for all Kentuckians and to preserve Kentucky’s commitment to environmental protection. In March 2005, the Kentucky Commission established Administrative Case No. 2005-00090 to collect information from all

 

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jurisdictional utilities in Kentucky, including LG&E, pertaining to Kentucky electric generation, transmission and distribution systems. LG&E responded to the Kentucky Commission’s first set of data requests at the end of March 2005 and to a second set of data requests in May 2005. The Commission held a Technical Conference on June 14, 2005, in which all parties participated in a panel discussion. A final report was provided on August 22, 2005 from the Kentucky Commission to the Governor. The Kentucky Commission issued an order and closed this proceeding on September 15, 2005. Some of the key findings from the report are:

 

                  Kentucky’s electric utilities currently have adequate infrastructure as well as adequate planning to serve the needs of customers through 2025;

 

                  Kentucky will need 7,000 megawatts of additional generating capacity by 2025;

 

                  Kentucky’s electric transmission is reliable but intrastate power transfers are limited;

 

                  Additional incentives to use renewable energy and educate the public on the benefits of renewables are needed;

 

                  Financial incentives should be available for coal purification and other clean air technologies;

 

                  A cautious approach should be taken toward deregulation; and

 

                  Kentucky must be involved in federal decisions that impact its status as a low cost energy provider.

 

Note 4 - Financial Instruments

 

The cost and estimated fair values of LG&E’s non-trading financial instruments as of December 31, 2005, and 2004 follow:

 

 

 

2005

 

2004

 

 

 

Carrying

 

Fair

 

Carrying

 

Fair

 

(in millions)

 

Value

 

Value

 

Value

 

Value

 

Preferred stock subject to mandatory redemption

 

$

21.3

 

$

21.4

 

$

22.5

 

$

22.8

 

Long-term debt (including current portion)

 

$

574.3

 

$

574.3

 

$

574.3

 

$

575.4

 

Long-term debt from affiliate

 

$

225.0

 

$

224.8

 

$

275.0

 

$

280.7

 

Interest-rate swaps - liability

 

$

(18.6

)

$

(18.6

)

$

(18.5

)

$

(18.5

)

 

All of the above valuations reflect prices quoted by exchanges except for the swaps and intercompany loans. The fair values of the swaps and intercompany loans reflect price quotes from dealers or amounts calculated using accepted pricing models. The fair values of cash and cash equivalents, accounts receivable, accounts payable and notes payable are substantially the same as their carrying values.

 

Interest Rate Swaps. LG&E uses over-the-counter interest rate swaps to hedge exposure to market fluctuations in certain of its debt instruments. Pursuant to Company policy, use of these financial instruments is intended to mitigate risk, earnings and cash flow 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. See Note 14, Accumulated Other Comprehensive Income. Financial instruments designated as fair value hedges and the underlying hedged items are periodically marked to market with the resulting net gains and losses recorded directly into net income.  Upon termination of any fair value hedge, the resulting gain or loss is recorded into net income.

 

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LG&E was party to various interest rate swap agreements with aggregate notional amounts of $211.3 million and $228.3 million as of December 31, 2005 and 2004. Under these swap agreements, LG&E paid fixed rates averaging 4.38% and received variable rates based on LIBOR or the Bond Market Association’s municipal swap index averaging 3.15% and 1.74% at December 31, 2005 and 2004, respectively. The swap agreements in effect at December 31, 2005 have been designated as cash flow hedges and mature on dates ranging from 2020 to 2033. The cash flow designation was assigned because the underlying variable rate debt has variable future cash flows. The hedges have been deemed to be fully effective resulting in a pretax loss of $0.1 million for 2005 and $2.3 million in 2004, recorded in other comprehensive income. Upon expiration of these hedges, the amount recorded in other comprehensive income will be reclassified into earnings. The amount expected to be reclassified from other comprehensive income to earnings in the next twelve months is less than $0.1 million. A deposit in the amount of $9.8 million, used as collateral for one of the interest rate swaps, is classified as restricted cash on LG&E’s Balance Sheet. The amount of the deposit required is tied to the market value of the swap.

 

Energy Risk Management Activities. LG&E conducts energy trading and risk management activities to maximize the value of power sales from physical assets it owns. Certain energy trading activities are accounted for on a mark-to-market basis in accordance with SFAS No. 133, as amended. Wholesale sales of excess asset capacity are treated as normal sales under SFAS No. 133, as amended and are not marked to market.

 

No changes to valuation techniques for energy trading and risk management activities occurred during 2005 and 2004. Changes in market pricing, interest rate and volatility assumptions were made during both years. All contracts outstanding at December 31, 2005, 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, 2005, 100% of the trading and risk management commitments were with counterparties rated BBB-/Baa3 equivalent or better.

 

LG&E hedges the price volatility of its forecasted electric off-system sales with the sales of market-traded electric forward contracts for periods of less than one year. These electric forward sales have been designated as cash flow hedges and are not speculative in nature. Gains or losses on these instruments, to the extent that the hedging relationship has been effective, are deferred in other comprehensive income. Gains and losses resulting from ineffectiveness are shown in LG&E’s Statements of Income in other (income) expense – net. Upon completion of the underlying hedge transaction, the amount recorded in other comprehensive income is recorded in earnings. No material pre-tax gains and losses resulted from these cash flow hedges in 2005, 2004 and 2003.  See Note 14, Accumulated Other Comprehensive Income.

 

Accounts Receivable Securitization. LG&E terminated its accounts receivable securitization program in January 2004, and in May 2004, LG&E dissolved its inactive accounts receivable securitization-related subsidiary, LG&E R. No material pre-tax gains and losses resulted from the sale of the receivables in 2004 and 2003. LG&E’s net cash flows from LG&E R were reduced by $58.1 million and $6.2 million for 2004 and 2003, respectively. The allowance for doubtful accounts associated with the eligible securitized receivables at December 31, 2003, was $1.4 million. This allowance was based on historical experience of LG&E. Each securitization facility contained a fully funded reserve for uncollectible receivables. LG&E was able to terminate this program at any time without penalty.

 

88



 

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 321,000 customers and electricity to approximately 394,000 customers in Louisville and adjacent areas in Kentucky. For the year ended December 31, 2005, 69% of total revenue was derived from electric operations and 31% from natural gas operations. For the year ended December 31, 2004, 70% of total revenue was derived from electric operations and 30% from natural gas operations.

 

In November 2005, LG&E and IBEW Local 2100 employees, that represent approximately 69% of LG&E’s workforce, entered into a three-year collective bargaining agreement with annual benefits re-openers.

 

Note 6 - Pension and Other Post Retirement Benefit Plans

 

LG&E has both funded and unfunded non-contributory defined benefit pension plans and other post-retirement benefit plans that together cover substantially all of its employees. The healthcare plans are contributory with participants’ contributions adjusted annually. LG&E uses December 31 as the measurement date for its plans.

 

Obligations and Funded Status. The following tables provide a reconciliation of the changes in the plan’s benefit obligations and fair value of assets over the three-year period ending December 31, 2005, and a statement of the funded status as of December 31, 2005, 2004 and 2003 for LG&E’s sponsored defined benefit plan:

 

(in millions)

 

2005

 

2004

 

2003

 

Pension Plans:

 

 

 

 

 

 

 

Change in projected benefit obligation

 

 

 

 

 

 

 

Projected benefit obligation at beginning of year

 

$

402.4

 

$

378.7

 

$

364.8

 

Service cost

 

3.7

 

2.8

 

1.7

 

Interest cost

 

22.3

 

22.7

 

23.2

 

Plan amendments

 

3.2

 

3.3

 

4.0

 

Change due to transfers

 

0.3

 

(1.1

)

(2.8

)

Benefits paid

 

(29.9

)

(30.5

)

(33.5

)

Actuarial (gain) or loss and other

 

24.7

 

26.5

 

21.3

 

Projected benefit obligation at end of year

 

$

426.7

 

$

402.4

 

$

378.7

 

 

 

 

 

 

 

 

 

Change in plan assets

 

 

 

 

 

 

 

Fair value of plan assets at beginning of year

 

$

338.2

 

$

297.8

 

$

196.3

 

Actual return on plan assets

 

26.6

 

39.3

 

47.2

 

Employer contributions

 

 

34.5

 

89.1

 

Change due to transfers

 

 

(1.1

)

0.2

 

Benefits paid

 

(29.9

)

(30.5

)

(33.5

)

Administrative expenses

 

(1.8

)

(1.8

)

(1.5

)

Fair value of plan assets at end of year

 

$

333.1

 

$

338.2

 

$

297.8

 

 

 

 

 

 

 

 

 

Reconciliation of funded status

 

 

 

 

 

 

 

Funded status

 

$

(93.6

)

$

(64.2

)

$

(80.9

)

Unrecognized actuarial (gain) or loss

 

94.7

 

70.3

 

56.2

 

Unrecognized transition (asset) or obligation

 

(0.7

)

(1.5

)

(2.2

)

Unrecognized prior service cost

 

30.4

 

31.5

 

32.3

 

Net amount recognized at end of year

 

$

30.8

 

$

36.1

 

$

5.4

 

 

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Other Benefits:

 

 

 

 

 

 

 

Change in benefit obligation

 

 

 

 

 

 

 

Benefit obligation at beginning of year

 

$

113.0

 

$

108.0

 

$

93.2

 

Service cost

 

1.0

 

0.9

 

0.6

 

Interest cost

 

5.6

 

6.5

 

6.9

 

Plan amendments

 

2.2

 

0.4

 

7.4

 

Benefits paid

 

(8.1

)

(7.1

)

(9.3

)

Actuarial (gain) or loss

 

(7.5

)

4.3

 

9.2

 

Benefit obligation at end of year

 

$

106.2

 

$

113.0

 

$

108.0

 

 

 

 

 

 

 

 

 

Change in plan assets

 

 

 

 

 

 

 

Fair value of plan assets at beginning of year

 

$

0.8

 

$

0.7

 

$

1.5

 

Actual return on plan assets

 

0.2

 

(2.0

)

2.1

 

Employer contributions

 

9.8

 

9.3

 

6.4

 

Change due to transfers

 

 

(0.1

)

 

Benefits paid

 

(8.1

)

(7.1

)

(9.3

)

Fair value of plan assets at end of year

 

$

2.7

 

$

0.8

 

$

0.7

 

 

 

 

 

 

 

 

 

Reconciliation of funded status

 

 

 

 

 

 

 

Funded status

 

$

(103.5

)

$

(112.2

)

$

(107.3

)

Unrecognized actuarial (gain) or loss

 

21.5

 

29.4

 

23.7

 

Unrecognized transition (asset) or obligation

 

4.7

 

5.4

 

6.0

 

Unrecognized prior service cost

 

10.4

 

10.0

 

11.5

 

Net amount recognized at end of year

 

$

(66.9

)

$

(67.4

)

$

(66.1

)

 

Amounts Recognized in Statement of Financial Position. 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, 2005, 2004 and 2003:

 

(in millions)

 

2005

 

2004

 

2003

 

Pension Plans:

 

 

 

 

 

 

 

Amounts recognized in the balance sheet consisted of:

 

 

 

 

 

 

 

Accrued benefit liability

 

$

(76.6

)

$

(53.2

)

$

(74.5

)

Intangible asset

 

30.4

 

31.5

 

32.3

 

Accumulated other comprehensive income

 

77.0

 

57.8

 

47.6

 

Net amount recognized at year-end

 

$

30.8

 

$

36.1

 

$

5.4

 

 

 

 

 

 

 

 

 

 

 

 

Increase (decrease) in minimum liability included in other comprehensive income

 

$

19.2

 

$

10.2

 

$

(3.1

)

 

 

 

 

 

 

 

 

Additional year-end information for plans with accumulated benefit obligations in excess of plan assets:

 

 

 

 

 

 

 

Projected benefit obligation

 

$

426.7

 

$

402.4

 

$

378.7

 

Accumulated benefit obligation

 

409.7

 

391.4

 

372.3

 

Fair value of plan assets

 

333.1

 

338.2

 

297.8

 

 

 

 

 

 

 

 

 

Other Benefits:

 

 

 

 

 

 

 

Amounts recognized in the balance sheet consisted of:

 

 

 

 

 

 

 

Accrued benefit liability

 

$

(66.9

)

$

(67.4

)

$

(66.1

)

 

 

 

 

 

 

 

 

Additional year-end information for plans with benefit obligations in excess of plan assets:

 

 

 

 

 

 

 

Benefit obligation

 

$

106.2

 

$

113.0

 

$

108.0

 

Fair value of plan assets

 

2.7

 

0.8

 

0.7

 

 

Components of Net Periodic Benefit Cost. The following table provides the components of net periodic

 

90



 

benefit cost for the plans for 2005, 2004 and 2003:

 

(in millions)

 

2005

 

2004

 

2003

 

Pension Plans:

 

 

 

 

 

 

 

Components of net periodic benefit cost

 

 

 

 

 

 

 

Service cost

 

$

3.7

 

$

2.8

 

$

1.8

 

Interest cost

 

22.3

 

22.7

 

23.2

 

Expected return on plan assets

 

(26.5

)

(27.0

)

(22.8

)

Amortization of prior service cost

 

4.3

 

4.1

 

3.8

 

Amortization of transition (asset) or obligation

 

(0.7

)

(0.7

)

(1.0

)

Amortization of actuarial (gain) or loss

 

2.3

 

1.9

 

2.2

 

Net periodic benefit cost

 

$

5.4

 

$

3.8

 

$

7.2

 

 

 

 

 

 

 

 

 

Other Benefits:

 

 

 

 

 

 

 

Components of net periodic benefit cost

 

 

 

 

 

 

 

Service cost

 

$

1.0

 

$

0.9

 

$

0.6

 

Interest cost

 

5.6

 

6.5

 

6.9

 

Expected return on plan assets

 

 

 

(0.1

)

Amortization of prior service cost

 

1.8

 

1.8

 

1.8

 

Amortization of transition (asset) or obligation

 

0.7

 

0.7

 

0.7

 

Amortization of actuarial (gain) or loss

 

0.3

 

0.7

 

0.5

 

Net periodic benefit cost

 

$

9.4

 

$

10.6

 

$

10.4

 

 

The assumptions used in the measurement of LG&E’s pension benefit obligation are shown in the following table:

 

 

 

2005

 

2004

 

2003

 

 

 

 

 

 

 

 

 

Weighted-average assumptions as of December 31:

 

 

 

 

 

 

 

Discount rate

 

5.50

%

5.75

%

6.25

%

Rate of compensation increase

 

5.25

%

4.50

%

3.00

%

 

The assumptions used in the measurement of LG&E’s net periodic benefit cost are shown in the following table:

 

 

 

2005

 

2004

 

2003

 

 

 

 

 

 

 

 

 

Discount rate

 

5.75

%

6.25

%

6.75

%

Expected long-term return on plan assets

 

8.25

%

8.50

%

9.00

%

Rate of compensation increase

 

4.50

%

3.50

%

3.75

%

 

To develop the expected long-term rate of return on assets assumption, LG&E considered the current level of expected returns on risk free investments (primarily government bonds), the historical level of the risk premium associated with the other asset classes in which the portfolio is invested and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based on the target asset allocation to develop the expected long-term rate of return on assets assumption for the portfolio.

 

Assumed Healthcare Cost Trend Rates. For measurement purposes, an 11.0% annual increase in the per capita cost of covered healthcare benefits was assumed for 2005. The rate was assumed to decrease gradually to 5.0% by 2015 and remain at that level thereafter.

 

Assumed healthcare cost trend rates have a significant effect on the amounts reported for the healthcare plans. A 1% change in assumed healthcare cost trend rates would have the following effects:

 

91



 

(in millions)

 

1% Decrease

 

1% Increase

 

Effect on total of service and interest cost components for 2005

 

$

(0.2

)

$

0.3

 

Effect on year-end 2005 postretirement benefit obligations

 

$

(2.8

)

$

3.1

 

 

Expected Future Benefit Payments. The following list provides the amount of expected future benefit payments, which reflect expected future service, as appropriate:

 

 

 

Pension

 

Other

 

(in millions)

 

Plans

 

Benefits

 

2006

 

$

29.0

 

$

7.7

 

2007

 

$

28.3

 

$

8.0

 

2008

 

$

27.6

 

$

8.1

 

2009

 

$

26.7

 

$

8.3

 

2010

 

$

25.9

 

$

8.4

 

2011-2015

 

$

123.4

 

$

42.7

 

 

Plan Assets. The following table shows LG&E’s weighted-average asset allocation by asset category at December 31:

 

 

 

Target Range

 

2005

 

2004

 

2003

 

Pension Plans:

 

 

 

 

 

 

 

 

 

Equity securities

 

45% - 75

%

57

%

66

%

66

%

Debt securities

 

30% - 50

%

42

%

33

%

33

%

Other

 

0% - 10

%

1

%

1

%

1

%

Totals

 

 

 

100

%

100

%

100

%

 

 

 

 

 

 

 

 

 

 

Other Benefits:

 

 

 

 

 

 

 

 

 

Equity securities

 

%

%

%

%

Debt securities

 

100

%

100

%

100

%

100

%

 

 

100

%

100

%

100

%

100

%

 

The investment policy of the pension plans was developed in conjunction with financial consultants, investment advisors and legal counsel. The goal of the investment policy is to preserve the capital of the fund and maximize investment earnings. The return objective is to exceed the benchmark return for the policy index comprised of the following:  Russell 3000 Index, MSCI-EAFE Index, Lehman Aggregate, and Lehman Long Duration Gov/Corporate Bond Index in proportions equal to the targeted asset allocation.

 

Evaluation of performance focuses on a long-term investment time horizon of at least three to five years or a complete market cycle. The assets of the pension plans are broadly diversified within different asset classes (equities, fixed income securities and cash equivalents).

 

To minimize the risk of large losses in a single asset class, no more than 5% of the portfolio will be invested in the securities of any one issuer with the exclusion of the U.S. government and its agencies. The equity portion of the fund is diversified among the market’s various subsections to diversify risk, maximize returns and avoid undue exposure to any single economic sector, industry group or individual security. The equity subsectors include, but are not limited to, growth, value, small capitalization and international.

 

In addition, the overall fixed income portfolio holdings may have an average weighted duration, or interest rate sensitivity which is within +/- 20% of the duration of the overall fixed income benchmark. Foreign bonds in the aggregate shall not exceed 10% of the total fund. The portfolio may include a limited investment of up to 20% in below investment grade securities provided that the overall average portfolio quality remains “AA” or better. The below investment grade securities include, but are not limited to, medium-term notes, corporate debt, non-dollar and emerging market debt and asset backed securities. The cash investments should be in securities that

 

92



 

either are of short maturities (not to exceed 180 days) or readily marketable with modest risk.

 

Derivative securities are permitted only to improve the portfolio’s risk/return profile, modify the portfolio’s duration or to reduce transaction costs and must be used in conjunction with underlying physical assets in the portfolio. Derivative securities that involve speculation, leverage, interest rate anticipation, or any undue risk whatsoever are not deemed appropriate investments.

 

The investment objective for the post retirement benefit plan is to provide current income consistent with stability of principal and liquidity while maintaining a stable net asset value of $1.00 per share. The post retirement funds are invested in a prime cash money market fund that invests primarily in a portfolio of short-term, high-quality fixed income securities issued by banks, corporations and the U.S. government.

 

Contributions. LG&E made discretionary contributions to the pension plan of $89.1 million during 2003 and $34.5 million in January 2004. LG&E made a discretionary contribution to the pension plan for $17.5 million in January 2006. There were no contributions during 2005.

 

FSP 106-2. FSP 106-2, which provided guidance on accounting for subsidies provided under the Medicare Act, was effective for the first interim or annual period beginning after June 15, 2004. The following table reflects the impact of the subsidy in 2004:

 

(in millions)

 

 

 

Reduction in APBO

 

$

3.2

 

 

 

Effect of the subsidy on the measurement of the net periodic postretirement benefit cost:

 

 

 

Amortization of the actuarial experience gain/(loss)

 

$

0.2

 

Reduction in service cost due to the subsidy

 

 

Resulting reduction in interest cost on the APBO

 

0.2

 

Total

 

$

0.4

 

 

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 $1.3 million for 2005, $1.4 million for 2004 and $1.8 million for 2003.

 

Note 7 - Income Taxes

 

Components of income tax expense are shown in the table below:

 

(in millions)

 

2005

 

2004

 

2003

 

 

 

 

 

 

 

 

 

Current   - federal

 

$

73.2

 

$

33.9

 

$

25.8

 

- state

 

10.1

 

13.0

 

10.0

 

Deferred - federal – net

 

(12.6

)

11.4

 

16.8

 

- state – net

 

(1.7

)

(0.8

)

1.7

 

Amortization of investment tax credit

 

(4.1

)

(4.2

)

(4.2

)

Total income tax expense

 

$

64.9

 

$

53.3

 

$

50.1

 

 

Deferred federal income tax expense during 2003 and 2004 included significant deductions attributable to federal bonus depreciation that ended after December 2004.

 

93



 

Components of net deferred tax liabilities included in the balance sheet are shown below:

 

(in millions)

 

2005

 

2004

 

Deferred tax liabilities:

 

 

 

 

 

Depreciation and other plant-related items

 

$

390.9

 

$

397.8

 

Regulatory assets and other

 

22.5

 

33.3

 

Total deferred tax liabilities

 

413.4

 

431.1

 

 

 

 

 

 

 

Deferred tax assets:

 

 

 

 

 

Investment tax credit

 

16.6

 

18.6

 

Income taxes due to customers

 

16.5

 

15.0

 

Pensions and related benefits

 

39.2

 

32.2

 

Liabilities and other

 

19.4

 

18.1

 

Total deferred tax assets

 

91.7

 

83.9

 

 

 

 

 

 

 

Net deferred income tax liability

 

$

321.7

 

$

347.2

 

 

A reconciliation of differences between the statutory U.S. federal income tax rate and LG&E’s effective income tax rate follows:

 

 

 

2005

 

2004

 

2003

 

Statutory federal income tax rate

 

35.0

%

35.0

%

35.0

%

State income taxes, net of federal benefit

 

4.1

 

5.3

 

5.4

 

Reduction of income tax accruals

 

(1.9

)

(0.7

)

(0.4

)

Investment and other credits

 

(2.1

)

(3.6

)

(3.0

)

Other differences

 

(1.6

)

(0.2

)

(1.5

)

Effective income tax rate

 

33.5

%

35.8

%

35.5

%

 

On September 19, 2005, LG&E received notice from the Congressional Joint Committee on Taxation approving the Internal Revenue Service’s audit of LG&E’s income tax returns for the periods December 1999 through December 2003. As a result of resolving numerous tax matters during these periods, LG&E reduced income tax accruals by $3.8 million during 2005.

 

Kentucky House Bill 272, also known as “Kentucky’s Tax Modernization Plan”, was signed into law in March 2005. This bill contains a number of changes in Kentucky’s tax system, including the reduction of the Corporate income tax rate from 8.25% to 7% effective January 1, 2005, and a further reduction to 6% effective January 1, 2007. As a result of the income tax rate change, LG&E’s deferred tax reserve amount will exceed its actual deferred tax liability attributable to existing temporary differences since the new statutory rates are lower than the rates were when the deferred tax liability originated. This excess amount is referred to as excess deferred income taxes. In June 2005, LG&E received approval from the Kentucky Commission to establish and amortize a regulatory liability ($16.3 million) for its net excess deferred income tax balances. Under the accounting treatment, LG&E will amortize its depreciation-related excess deferred income tax balances under the average rate assumption method. The average rate assumption method matches the amortization of the excess deferred income taxes with the life of the timing differences to which they relate. Excess deferred income tax balances related to non-depreciation timing differences will be expensed in the current year due to their immaterial amount.

 

LG&E expects to have adequate levels of taxable income to realize its recorded deferred taxes.

 

94



 

Note 8 - Long-Term Debt

 

As of December 31, 2005, long-term debt and the current portion of long-term debt consist primarily of pollution control bonds and long-term loans from affiliated companies as summarized below.

 

(in millions)

 

Stated
Interest Rates

 

Maturities

 

Principal
Amounts

 

Outstanding at December 31, 2005:

 

 

 

 

 

 

 

Noncurrent portion

 

Variable - 5.90%

 

2008-2035

 

$

573.1

 

Current portion

 

Variable

 

2006-2027

 

247.5

 

 

 

 

 

 

 

 

 

Outstanding at December 31, 2004:

 

 

 

 

 

 

 

Noncurrent portion

 

Variable - 5.90%

 

2008-2033

 

$

574.4

 

Current portion

 

Variable

 

2005-2027

 

297.4

 

 

Under the provisions for LG&E’s variable-rate pollution control bonds, Series S, T, U, BB, CC, DD and EE, 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 balance sheets. The average annualized interest rate for these bonds during 2005 and 2004 was 2.50% and 1.29%, respectively.

 

Pollution control series bonds are first mortgage bonds that have been issued by LG&E in connection with tax-exempt pollution control revenue bonds issued by various governmental entities, principally counties in Kentucky. A loan agreement obligates LG&E to make debt service payments to the county that equate to the debt service due from the county on the related pollution control revenue bonds. The county’s debt is also secured by an equal amount of LG&E’s first mortgage bonds (the pollution control series bonds) that are pledged to the trustee for the pollution control revenue bonds, and that match the terms and conditions of the county’s debt, but require no payment of principal and interest unless LG&E defaults on the loan agreement.

 

Substantially all of LG&E’s utility assets are pledged as security for its first mortgage bonds. LG&E’s first mortgage bond 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 was restricted by this provision as of either December 31, 2005 or 2004.

 

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. 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.  As of December 31, 2005 and 2004, LG&E had swaps with a combined notional value of $211.3 million and $228.3 million, respectively. See Note 4, Financial Instruments.

 

Redemptions and maturities of long-term debt for 2005, 2004 and 2003 are summarized below:

 

($ in millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Principal

 

 

 

Secured/

 

 

 

Year

 

Description

 

Amount

 

Rate

 

Unsecured

 

Maturity

 

2005

 

Pollution control bonds

 

$

40.0

 

5.90

%

Secured

 

Apr 2023

 

2005

 

Due to Fidelia

 

$

50.0

 

1.53

%

Secured

 

Jan 2005

 

2005

 

Mandatorily Redeemable Preferred Stock

 

$

1.3

 

5.875

%

Unsecured

 

Jul 2005

 

2004

 

Due to Fidelia

 

$

50.0

 

1.53

%

Secured

 

Jan 2005

 

2004

 

Mandatorily Redeemable Preferred Stock

 

$

1.3

 

5.875

%

Unsecured

 

Jul 2004

 

2003

 

Pollution control bonds

 

$

102.0

 

5.625

%

Secured

 

Aug 2019

 

2003

 

Pollution control bonds

 

$

26.0

 

5.45

%

Secured

 

Oct 2020

 

2003

 

First mortgage bonds

 

$

42.6

 

6.00

%

Secured

 

Aug 2003

 

2003

 

Mandatorily Redeemable Preferred Stock

 

$

1.3

 

5.875

%

Unsecured

 

Jul 2