Loading...
Docoh

Kentucky Utilities

Filed: 30 Mar 05, 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, 2004

 

OR

 

o

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)

 

Commission
File Number

 

Registrant, State of Incorporation,
Address, and Telephone Number

 

IRS Employer
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

(Title of class)

 

Kentucky Utilities Company

Preferred Stock, 6.53% cumulative, stated value $100 per share

Preferred Stock, 4.75% cumulative, stated value $100 per share

(Title of class)

 

Indicate by check mark whether the 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 an accelerated filer (as defined in Exchange Act Rule 12b-2).  Yes  o   No  ý

 

As of June 30, 2004, 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, 2005, Louisville Gas and Electric Company had 21,294,223 shares of common stock outstanding, all held by LG&E Energy LLC.  Kentucky Utilities Company had 37,817,878 shares of common stock outstanding, all held by LG&E Energy 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

 

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 the Registrant (a)

 

Item 11.

Executive Compensation. (a)

 

Item 12.

Security Ownership of Certain Beneficial Owners and Management and related Stockholder Matters (a)

 

Item 13.

Certain Relationships and Related Transactions (a)

 

Item 14.

Principal Accountant Fees and Services

 

 

 

PART IV

 

 

 

Item 15.

Exhibits and Financial Statement Schedules

 

Signatures

 

 


(a) Incorporate by reference

 

2



 

INDEX OF ABBREVIATIONS

 

AFUDC

 

Allowance for Funds Used During Construction

ARO

 

Asset Retirement Obligation

Capital Corp.

 

LG&E Capital Corp.

Clean Air Act

 

The Clean Air Act, as amended in 1990

CCN

 

Certificate of Public Convenience and Necessity

CO2

 

Carbon Dioxide

CT

 

Combustion Turbines

CWIP

 

Construction Work in Progress

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

EPA

 

U.S. Environmental Protection Agency

ESM

 

Earnings Sharing Mechanism

F

 

Fahrenheit

FAC

 

Fuel Adjustment Clause

FERC

 

Federal Energy Regulatory Commission

FGD

 

Flue Gas Desulfurization

FPA

 

Federal Power Act

FT and FT-A

 

Firm Transportation

GSC

 

Gas Supply Clause

IBEW

 

International Brotherhood of Electrical Workers

IMEA

 

Illinois Municipal Electric Agency

IMPA

 

Indiana Municipal Power Agency

IRP

 

Integrated Resource Plan

Kentucky Commission

 

Kentucky Public Service Commission

KIUC

 

Kentucky Industrial Utility Consumers, Inc.

KU

 

Kentucky Utilities Company

KU Energy

 

KU Energy Corporation

KU R

 

KU Receivables LLC

kV

 

Kilovolts

Kva

 

Kilovolt-ampere

KW

 

Kilowatts

Kwh

 

Kilowatt hours

LEM

 

LG&E Energy Marketing Inc.

LG&E

 

Louisville Gas and Electric Company

LG&E Energy

 

LG&E Energy LLC (as successor to LG&E Energy Corp.)

LG&E R

 

LG&E Receivables LLC

LG&E Services

 

LG&E Energy Services Inc.

LNG

 

Liquefied Natural Gas

Mcf

 

Thousand Cubic Feet

MGP

 

Manufactured Gas Plant

MISO

 

Midwest Independent Transmission System Operator

MMBtu

 

Million British thermal units

Moody’s

 

Moody’s Investor Services, Inc.

Mw

 

Megawatts

Mwh

 

Megawatt hours

NNS

 

No-Notice Service

NOPR

 

Notice of Proposed Rulemaking

NOx

 

Nitrogen Oxide

OATT

 

Open Access Transmission Tariff

OMU

 

Owensboro Municipal Utilities

OVEC

 

Ohio Valley Electric Corporation

PBR

 

Performance-Based Ratemaking

PJM

 

Pennsylvania, New Jersey, Maryland Interconnection

Powergen

 

Powergen Limited (formerly Powergen plc)

 

3



 

PUHCA

 

Public Utility Holding Company Act of 1935

ROE

 

Return on Equity

RTO

 

Regional Transmission Organization

S&P

 

Standard & Poor’s Rating Services

SCR

 

Selective Catalytic Reduction

SEC

 

Securities and Exchange Commission

SERP

 

Supplemental Executive Retirement Plan

SFAS

 

Statement of Financial Accounting Standards

SIP

 

State Implementation Plan

SMD

 

Standard Market Design

SO2

 

Sulfur Dioxide

Tennessee Gas

 

Tennessee Gas Pipeline Company

Texas Gas

 

Texas Gas Transmission LLC

Trimble County

 

LG&E’s Trimble County Unit 1

USWA

 

United Steelworkers of America

Utility Operations

 

Operations of LG&E and KU

VDT

 

Value Delivery Team Process

Virginia Commission

 

Virginia State Corporation Commission

Virginia Staff

 

Virginia State Corporation Commission Staff

WNA

 

Weather Normalization Adjustment

 

4



 

PART I

 

Item 1.  Business.

 

LG&E and KU are each subsidiaries of LG&E Energy.  LG&E Energy is a subsidiary of E.ON AG, a German corporation.  E.ON acquired LG&E Energy through its July 1, 2002 acquisition of Powergen plc, now Powergen Limited, a United Kingdom company.  LG&E and KU are now indirect subsidiaries of E.ON.  As a result of these acquisitions and otherwise, E.ON and LG&E Energy are registered as holding companies under PUHCA.

 

In order to comply with PUHCA, LG&E Services was formed as a subsidiary of LG&E Energy.  LG&E Services provides certain services to affiliated entities, including LG&E and KU, at cost as required under PUHCA.  Approximately 1,000 employees, mainly from LG&E Energy, LG&E and KU, were moved to LG&E Services upon its formation.

 

E.ON, its utility subsidiaries, including LG&E and KU, and certain of its non-utility subsidiaries are subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales of securities, acquisitions and sales of certain utility properties, and intra-system sales of certain goods and services.  In addition, PUHCA generally limits the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company.  LG&E and KU believe that they have adequate authority (including financing authority) under existing SEC orders and regulations to conduct their business.  LG&E and KU will seek additional authorization when necessary.  E.ON’s general financing approval order under PUHCA (including certain LG&E and KU components) expires in May 2005 and an application has been submitted to the SEC for renewed or modified financing authorizations for an additional three year period.  LG&E and KU anticipate receiving a timely approval from the SEC, but such approval cannot be assured.

 

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

 

The utility operations (LG&E and KU) of LG&E Energy 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.

 

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.

 

5



 

LOUISVILLE GAS AND ELECTRIC COMPANY

 

General

 

LG&E, incorporated in 1913 in Kentucky, is a regulated public utility that supplies natural gas to approximately 318,000 customers and electricity to approximately 390,000 customers in Louisville and adjacent areas in Kentucky.  LG&E’s service area covers approximately 700 square miles in 17 counties and has an estimated population of one million.  Included in this area is the Fort Knox Military Reservation, to which LG&E transports gas and provides electric service, but does not provide any distribution services.  LG&E also provides gas service in limited additional areas. LG&E’s coal-fired electric generating plants, all equipped with systems to reduce sulfur dioxide emissions, produce most of LG&E’s electricity.  The remainder is generated by a hydroelectric power plant and combustion turbines.  Underground natural gas storage fields help LG&E provide economical and reliable gas service to customers.  See Item 2, Properties.

 

For the year ended December 31, 2004, 70% of total operating revenues were derived from electric operations and 30% from gas operations.  Electric and gas operating revenues and the percentages by class of service on a combined basis for this period were as follows:

 

(in thousands)

 

Electric

 

Gas

 

Combined

 

% Combined

 

Residential

 

$

240,779

 

$

222,574

 

$

463,353

 

48

%

Commercial

 

202,025

 

88,774

 

290,799

 

30

%

Industrial

 

119,758

 

15,277

 

135,035

 

14

%

Public authorities

 

62,266

 

15,533

 

77,799

 

8

%

Total retail

 

624,828

 

342,158

 

966,986

 

100

%

Wholesale sales

 

185,563

 

7,195

 

192,758

 

 

 

Gas transported – net

 

 

6,140

 

6,140

 

 

 

Provision for rate collections

 

(11,418

)

 

(11,418

)

 

 

Miscellaneous

 

16,724

 

1,578

 

18,302

 

 

 

Total

 

$

815,697

 

$

357,071

 

$

1,172,768

 

 

 

 

See Note 13 of LG&E’s Notes to Financial Statements under Item 8 for financial information concerning segments of business for the three years ended December 31, 2004.

 

Electric Operations

 

The sources of LG&E’s electric operating revenues and the volumes of sales for the three years ended December 31, 2004, were as follows:

 

(in thousands)

 

2004

 

2003

 

2002

 

ELECTRIC OPERATING REVENUES

 

 

 

 

 

 

 

Residential

 

$

240,779

 

$

223,404

 

$

232,527

 

Commercial

 

202,025

 

187,500

 

185,306

 

Industrial

 

119,758

 

111,535

 

111,988

 

Public authorities

 

62,266

 

58,493

 

57,762

 

Total retail

 

624,828

 

580,932

 

587,583

 

Wholesale sales

 

185,563

 

169,782

 

120,552

 

Provision for rate collections (refunds)

 

(11,418

)

(412

)

11,656

 

Miscellaneous

 

16,724

 

17,886

 

16,251

 

  Total

 

$

815,697

 

$

768,188

 

$

736,042

 

 

(Thousands of Mwh)

 

 

 

 

 

 

 

ELECTRIC SALES

 

 

 

 

 

 

 

Residential

 

3,923

 

3,835

 

4,036

 

Commercial

 

3,534

 

3,482

 

3,493

 

Industrial

 

3,019

 

2,936

 

3,028

 

Public authorities

 

1,248

 

1,251

 

1,253

 

Total retail

 

11,724

 

11,504

 

11,810

 

Wholesale sales

 

7,819

 

7,678

 

6,387

 

Total

 

19,543

 

19,182

 

18,197

 

 

6



 

LG&E uses efficient coal-fired boilers, fully equipped with sulfur dioxide removal systems, to generate most of its electricity.  LG&E’s weighted-average system-wide emission rate for sulfur dioxide in 2004 was approximately 0.56 lbs./MMBtu of heat input, with every generating unit below its emission limit established by the Kentucky Division for Air Quality.

 

LG&E set an annual peak load of 2,485 Mw on July 13, 2004, when the temperature reached 88 degrees F in Louisville.

 

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

 

LG&E currently maintains a 13% – 15% reserve margin range.  At December 31, 2004, 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 summer capability rate 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, 2004, LG&E’s system net summer capability, including purchases from others and excluding the hydroelectric facility, was 3,260 Mw.  See Item 2, Properties.

 

LG&E and 11 other electric utilities are participating owners of OVEC located in Piketon, Ohio.

 

In March 2005, LG&E purchased from American Electric Power Company Inc. (“AEP”) an additional 0.73% interest in OVEC for a purchase price of approximately $0.1 million, which resulted in an increase in LG&E ownership in OVEC from 4.9% to 5.63%.  OVEC owns and operates two power plants that burn coal to generate electricity, Kyger Creek Station in Ohio and Clifty Creek Station in Indiana.  LG&E’s share is 7%, representing approximately 155 Mw of generation capacity.

 

LG&E is a member of the MISO and therefore has turned over operational control of transmission facilities  100 kV and above, but continues to control and operate the lower voltage transmission subject to the terms and conditions of the MISO.  The MISO currently controls over 100,000 miles of transmission lines over 1.1 million square miles located in the northern Midwest between Manitoba, Canada and Kentucky.  As a transmission-owning member of the MISO, LG&E also incurs costs under the MISO Open Access Transmission Tariff, including the Schedule 10 adder which recovers the operational and capital costs incurred by the MISO.  For discussion of current MISO matters, see Rates and Regulation for LG&E under Item 7 and Note 3 of LG&E’s Notes to Financial Statements under Item 8.

 

Gas Operations

 

The sources of LG&E’s gas operating revenues and the volumes of sales for the three years ended December 31, 2004, were as follows:

 

7



 

(in thousands)

 

2004

 

2003

 

2002

 

GAS OPERATING REVENUES

 

 

 

 

 

 

 

Residential

 

$

222,574

 

$

198,881

 

$

160,733

 

Commercial

 

88,774

 

78,280

 

61,036

 

Industrial

 

15,277

 

13,812

 

10,232

 

Public authorities

 

15,533

 

13,745

 

11,197

 

Total retail

 

342,158

 

304,718

 

243,198

 

Wholesale sales

 

7,195

 

12,278

 

16,384

 

Gas transported – net

 

6,140

 

6,046

 

6,232

 

Miscellaneous

 

1,578

 

2,291

 

1,879

 

Total

 

$

357,071

 

$

325,333

 

$

267,693

 

 

(Millions of cu. ft.)

 

 

 

 

 

 

 

GAS SALES

 

 

 

 

 

 

 

Residential

 

21,402

 

23,192

 

22,124

 

Commercial

 

9,144

 

9,652

 

9,074

 

Industrial

 

1,736

 

1,880

 

1,783

 

Public authorities

 

1,646

 

1,746

 

1,747

 

Total retail

 

33,928

 

36,470

 

34,728

 

Wholesale sales

 

1,221

 

2,119

 

5,345

 

Gas transported

 

13,692

 

13,683

 

13,939

 

Total

 

48,841

 

52,272

 

54,012

 

 

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

 

LG&E has five underground natural gas storage fields that help provide economical and reliable gas service to ultimate consumers.  By using gas storage facilities, LG&E avoids the costs associated with typically more expensive pipeline transportation capacity to serve peak winter space-heating loads.  LG&E stores gas in the summer season for withdrawal in the subsequent winter heating season.  Without its storage capacity, LG&E would be forced to buy additional gas and pipeline transportation services during the winter months when customer demand increases and when the prices for gas supply and transportation services are typically at their highest.  Currently, LG&E buys competitively priced gas from several large suppliers under contracts of varying duration.  LG&E’s underground storage facilities, in combination with its purchasing practices, enable it to offer gas sales service at rates lower than state and national averages.  At December 31, 2004, LG&E had an inventory balance of gas stored underground of approximately 12.2 million Mcf of working gas valued at approximately $77.5 million.

 

A number of industrial customers purchase their natural gas requirements directly from alternate suppliers for delivery through LG&E’s distribution system.  These large industrial customers account for approximately one-fourth of LG&E’s annual throughput.

 

During 2004, the maximum day gas sendout was approximately 491,000 Mcf, occurring on January 30, 2004, when the average temperature for the day was 7 degrees F.  Supply on that day consisted of approximately 235,000 Mcf from purchases, approximately 180,000 Mcf delivered from underground storage, and approximately 76,000 Mcf transported for industrial customers.  For a further discussion, see Gas Supply under Item 1.

 

Rates and Regulation

 

As a subsidiary of a registered holding company under PUHCA, LG&E is subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales of securities, acquisitions and sales of certain utility properties, and intra-system sales of certain goods and services.  In addition, PUHCA generally limits the ability

 

8



 

of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company.  LG&E believes that it has adequate authority (including financing authority) under existing SEC orders and regulations to conduct its business.  LG&E will seek additional authorization when necessary.  E.ON’s general financing approval order under PUHCA (including certain LG&E components) expires in May 2005 and an application has been submitted to the SEC for renewed or modified financing authorizations for an additional three year period.  LG&E anticipates receiving a timely approval from the SEC, but such approval cannot be assured.

 

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.  FERC has classified LG&E as a “public utility” as defined in the FPA.  The Department of Energy and FERC have jurisdiction under the FPA over certain electric utility facilities and operations, wholesale sale of power and related transactions, accounting practices of LG&E, and in certain other respects as provided in the FPA.

 

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.

 

LG&E’s retail electric rates contain a FAC, whereby increases and decreases in the cost of fuel for electric generation are reflected in the rates charged to retail electric customers.  The Kentucky Commission requires public hearings at six-month intervals to examine past fuel adjustments, and at two-year intervals to review past operations of the fuel clause and transfer of the then current fuel adjustment charge or credit to the base charges.  The Kentucky Commission also requires that electric utilities, including LG&E, file certain documents relating to fuel procurement and the purchase of power and energy from other utilities.

 

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 and lower point for rate of return on equity, whereby if LG&E’s rate of return for the calendar year fell within the range of 10.5% to 12.5%, no action was necessary.  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 Rates and Regulation for LG&E under Item 7 and Note 3 of LG&E’s Notes to Financial Statements under Item 8.

 

LG&E’s retail rates contain an ECR surcharge which recovers certain costs incurred by LG&E that are required to comply with the Clean Air Act and other environmental regulations.  See Rates and Regulation for LG&E under Item 7 and Note 3 of LG&E’s Notes to Financial Statements under Item 8.

 

LG&E’s gas rates contain a GSC, whereby increases or decreases in the cost of gas supply are reflected in LG&E’s rates, subject to approval by the Kentucky Commission.  The GSC procedure prescribed by order of the Kentucky Commission provides for quarterly rate adjustments to reflect the expected cost of gas supply in that quarter.  In addition, the GSC contains a mechanism whereby any over- or under-recoveries of gas supply cost from prior quarters will be refunded to or recovered from customers through the adjustment factor determined for subsequent quarters.

 

Integrated resource planning regulations in Kentucky require LG&E and the other major utilities to make triennial filings with the Kentucky Commission of various historical and forecasted information relating to load,

 

9



 

capacity margins and demand-side management techniques.  LG&E filed its most recent IRP in October 2002.  The Kentucky Commission issued its Staff Report and ordered the case closed in December 2003 with no significant findings.  The next IRP is due April 2005, and will incorporate the recommendations from the Staff Report regarding the 2002 IRP.

 

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

 

During July 2004, the Attorney General of Kentucky (“AG”) served subpoenas on LG&E, as well as on 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 case.  The Kentucky Commission has procedurally reopened the rate cases for the limited purpose of taking evidence, if any, as to the communication issues.

 

LG&E believes no improprieties have occurred in its communications with the Kentucky Commission and is cooperating 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 base rates.

 

For a further discussion of regulatory matters, see Rates and Regulation for LG&E under Item 7 and Note 3 of LG&E’s Notes to Financial Statements under Item 8.

 

Construction Program and Financing

 

LG&E’s construction program is designed to ensure that there will be adequate capacity and reliability to meet the electric and gas needs of its service area.  These needs are continually being reassessed and appropriate revisions are made, when necessary, in construction schedules.  LG&E’s estimates of its construction expenditures can vary substantially due to numerous items beyond LG&E’s control, such as changes in interest rates, economic conditions, construction costs, and new environmental or other governmental laws and regulations.

 

During the five years ended December 31, 2004, 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 25% of total utility plant at December 31, 2004, and consisted of $821 million for electric properties and $156 million for gas properties.  Gross retirements during the same period were $126 million, consisting of $92 million for electric properties and $34 million for gas properties.

 

Capital expenditures during the five years ending December 31, 2009 are estimated to be approximately $843 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 $158 million, contingent upon approval of the Company’s application for a CCN by the Kentucky Commission, and the redevelopment of the Ohio Falls hydro facility ($46 million).

 

10



 

Coal Supply

 

Coal-fired generating units provided over 98.2% of LG&E’s net kilowatt-hour generation for 2004.  The remaining net generation for 2004 was provided by natural gas and oil-fueled combustion turbine peaking units (0.5%) and a hydroelectric plant (1.3%).  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 2005 and beyond.  The Company 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 0.7 million tons, or a 36-day supply, on hand at December 31, 2004.

 

LG&E expects to continue purchasing most of its coal, with sulfur content in the 2%-4.5% range, from western Kentucky, southern Indiana, and West Virginia for the foreseeable future.  This supply is relatively low-priced coal, and in combination with its sulfur dioxide removal systems is expected to enable LG&E to continue to provide electric service in compliance with existing environmental laws and regulations.

 

Coal is delivered to LG&E’s Mill Creek plant by rail and barge, Trimble County plant by barge and Cane Run plant by rail.

 

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

 

 

 

2004

 

2003

 

2002

 

Per ton

 

$

26.25

 

$

25.56

 

$

25.30

 

Per MMBtu

 

$

1.15

 

$

1.12

 

$

1.11

 

Spot purchases as % of all sources

 

7

%

1

%

2

%

 

The delivered cost of coal is expected to increase in 2005 due to market conditions.

 

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 participates in rate and other proceedings affecting the regulated interstate natural gas pipelines that provide service to LG&E. Although both Texas Gas and Tennessee Gas have several active proceedings in which LG&E is participating at the FERC, neither interstate natural gas pipeline has filed an application at FERC to increase the pipeline’s base rates.  Additionally, the rates of these pipelines are not being billed subject to refund, and LG&E has refunded to its customers any amounts which have been refunded to it as the result of the settlement of any FERC proceedings.  Texas Gas is obligated to file a general rate case at FERC to be effective no later than November 1, 2005.  Tennessee Gas is under no such obligation.

 

LG&E transports on the Texas Gas system under Rate Schedules NNS and FT service.  During the winter

 

11



 

months, LG&E has 184,900 MMBtu/day in NNS and 36,000 MMBtu/day in FT service.  LG&E’s summer NNS levels are 60,000 MMBtu/day and its summer FT levels are 54,000 MMBtu/day.  Each of these NNS and FT agreements with Texas Gas are subject to termination by LG&E in equal portions during 2005, 2006, and 2008.  LG&E has provided Texas Gas with notice to terminate a portion of the summer-only FT agreement in the amount of 18,000 MMBtu/day effective November 1, 2005.  After that date, LG&E will have FT service during the summer in the amount of 36,000 MMBtu/day.  For January 2005 only, LG&E contracted for short-term firm transportation service from Texas Gas under Rate Schedule STF in the amount of 15,000 MMBtu/day.  LG&E also transports on the Tennessee Gas system under Tennessee Gas’s 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 also has a portfolio of supply arrangements of various terms with a number of suppliers designed to meet its firm sales obligations.  These gas supply arrangements include pricing provisions that are market-responsive.  These firm gas supplies, in tandem with pipeline transportation services, provide the reliability and flexibility necessary to serve LG&E’s gas customers.

 

LG&E owns and operates five underground gas storage fields with a current working gas capacity of approximately 15.1 million Mcf.  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 approximately 373,000 Mcf/day.  Deliverability decreases during the latter portion of the heating season as the storage inventory is reduced by seasonal withdrawals.

 

The average cost per Mcf of natural gas purchased by LG&E was $7.18 in 2004, $6.30 in 2003, and $4.19 in 2002.  Natural gas prices in the unregulated wholesale market generally have increased significantly over the last few years beginning in 2000.  These increases in natural gas prices, caused in part by decreased natural gas production, decreased liquidity in the marketplace, and increased demand for natural gas as a fuel for electric generation have been significantly affected by changing national gas storage inventory levels.  LG&E relies upon storage to mitigate the price volatility to which customers might otherwise be exposed.

 

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 2004, expenditures for pollution control facilities represented $247 million or 25% of total construction expenditures.  LG&E estimates that construction expenditures for environmental protection equipment from 2005 through 2009 will be approximately $56 million.  For a discussion of environmental matters, see Rates and Regulation for LG&E under Item 7 and Note 11 of LG&E’s Notes to Financial Statements under Item 8.

 

Competition

 

In the last several years, LG&E has taken many steps to keep its rates low while maintaining high levels of customer satisfaction, including a reduction in the number of employees; aggressive cost cutting; an increase in focus on commercial, industrial and residential customers; an increase in employee involvement and training; and continuous modifications of its organizational structure.  LG&E will take additional steps to better position itself should retail competition come to Kentucky.

 

12



 

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 will be 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.  The KPSC must provide its Strategic Blueprint to the Governor in early August 2005.  LG&E must respond to the Kentucky Commission’s first set of data requests by the end of March 2005.

 

13



 

KENTUCKY UTILITIES COMPANY

 

General

 

KU, incorporated in Kentucky in 1912 and incorporated in Virginia in 1991, is a regulated public utility engaged in producing, transmitting and selling electric energy.  KU provides electric service to approximately 488,000 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 to less than 10 customers in Tennessee.  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 operationsKU also sells wholesale electric energy to 12 municipalities.

 

Electric Operations

 

The sources of KU’s electric operating revenues and the volumes of sales for the three years ended December 31, 2004, were as follows:

 

(in thousands)

 

2004

 

2003

 

2002

 

ELECTRIC OPERATING REVENUES

 

 

 

 

 

 

 

Residential

 

$

303,635

 

$

278,461

 

$

274,660

 

Commercial

 

206,931

 

189,113

 

178,694

 

Industrial

 

190,560

 

175,601

 

163,372

 

Mine power

 

31,703

 

29,584

 

28,664

 

Public authorities

 

72,158

 

66,452

 

62,490

 

Total retail

 

804,987

 

739,211

 

707,880

 

Wholesale sales

 

160,002

 

138,003

 

117,252

 

Provision for rate collections (refunds)

 

4,751

 

(8,534

)

15,481

 

Miscellaneous

 

25,622

 

23,098

 

21,051

 

Total

 

$

995,362

 

$

891,778

 

$

861,664

 

 

(Thousands of Mwh)

 

 

 

 

 

 

 

ELECTRIC SALES

 

 

 

 

 

 

 

Residential

 

6,160

 

6,001

 

6,198

 

Commercial

 

4,323

 

4,210

 

4,161

 

Industrial

 

5,400

 

5,110

 

4,975

 

Mine power

 

732

 

722

 

766

 

Public authorities

 

1,597

 

1,551

 

1,533

 

Total retail

 

18,212

 

17,594

 

17,633

 

Wholesale sales

 

5,707

 

5,591

 

4,794

 

Total

 

23,919

 

23,185

 

22,427

 

 

KU’s weighted-average system-wide emission rate for sulfur dioxide in 2004 was approximately 1.4 lbs./MMBtu of heat input, with every generating unit below its emission limit established by the Kentucky Division for Air Quality.

 

KU set an annual peak load of 3,768 Mw on January 7, 2004, when the temperature was 13 degrees F.  On January 18, 2005, KU achieved the highest hourly customer demand in KU’s history, with a peak load of 4,065 Mw.

 

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

 

14



 

under Item 7.

 

KU currently maintains a 13% -15% reserve margin range.  At December 31, 2004, 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 obtains power from other utilities under bulk power purchase and interchange contracts.  At December 31, 2004, KU’s system net summer capability, including purchases from others and excluding the hydroelectric facility, was 4,934 Mw.

 

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 9% of KU’s net generation system output during 2004.  See Note 11 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.  KU is entitled to take 20% of the available capacity of the station.  Purchases from EEI are made under a contractual formula which has resulted in costs which were and are expected to be comparable to the cost of other power generated by KU.  This contract governing the purchases from EEI will terminate on December 31, 2005.  Such power equated to approximately 10% of KU’s net generation system output in 2004.  See Note 11 of KU’s Notes to Financial Statements under Item 8.

 

KU and 11 other electric utilities are participating owners of OVEC, located in Piketon, Ohio.  KU’s investment in OVEC is the equivalent of 2.5% of OVEC’s common stock.  OVEC owns and operates two power plants that burn coal to generate electricity, Kyger Creek Station in Ohio and Clifty Creek Station in Indiana.  KU’s share is 2.5%, approximately 55 Mw of generation capacity.

 

KU is a member of the MISO and therefore has turned over operational control of transmission facilities 100 kV and above, but continues to control and operate the lower voltage transmission subject to the terms and conditions of the MISO.  The MISO currently controls over 100,000 miles of transmission over 1.1 million square miles located in the northern Midwest between Manitoba, Canada and Kentucky.  As a transmission-owning member of the MISO, KU also incurs costs under the MISO Open Access Transmission Tariff, including the Schedule 10 adder which recovers the operational and capital costs incurred by the MISO.  For discussion of current MISO matters, see Rates and Regulation for KU under Item 7 and Note 3 of KU’s Notes to Financial Statements under Item 8.

 

Rates and Regulation

 

As a subsidiary of a registered holding company under PUHCA, KU is subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales of securities, acquisitions and sales of certain utility properties, and intra-system sales of certain goods and services.  In addition, PUHCA generally limits the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company.  KU believes that it has adequate authority (including financing authority) under existing SEC orders and regulations to conduct its business.  KU will seek additional authorization when necessary.  E.ON’s general financing approval order under PUHCA (including certain KU components) expires in May 2005 and an application has been submitted to the SEC for renewed or modified financing authorizations for an additional three year period.  KU anticipates receiving a timely approval from the SEC, but such approval cannot be assured.

 

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

 

15



 

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, 2004, KU is subject to the jurisdiction of the Tennessee Regulatory Authority.  FERC has classified KU as a “public utility” as defined in the FPA.  The Department of Energy and FERC have jurisdiction under the FPA over certain of the electric utility facilities and operations, wholesale sale of power and related transactions, accounting practices of KU, and in certain other respects as provided in the FPA.

 

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 a FAC, whereby increases and decreases in the cost of fuel for electric generation are reflected in the rates charged to retail electric customers.  The Kentucky Commission requires public hearings at six-month intervals to examine past fuel adjustments, and at two-year intervals to review past operations of the fuel clause and transfer of the then current fuel adjustment charge or credit to the base charges.  The Kentucky Commission also requires that electric utilities, including KU, file certain documents relating to fuel procurement and the purchase of power and energy from other utilities.  The FAC mechanism for Virginia customers uses an average fuel cost factor based primarily on projected fuel costs.  The fuel cost factor may be adjusted annually for over or under collections of fuel costs from the previous year.

 

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 and lower point for rate of return on equity, whereby if KU’s rate of return for the calendar year fell within the range of 10.5% to 12.5%, no action was necessary.  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 shareholdersBy 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 Rates and Regulation for KU under Item 7 and Note 3 of KU’s Notes to Financial Statements under Item 8.

 

KU’s Kentucky retail rates contain an ECR surcharge which recovers certain costs incurred by KU that are required to comply with the Clean Air Act and other environmental regulations.  See Rates and Regulation for KU under Item 7 and 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 October 2002.  The Kentucky Commission issued its Staff Report and ordered the case closed in December 2003 with no significant findings.  The next IRP is due April 2005, and will incorporate the recommendations from the Staff Report regarding the 2002 IRP.

 

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

 

16



 

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.

 

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 year ended September 30, 2003.  The revenue increase requested was $58.3 million.  In June 2004, the Kentucky Commission issued an order approving an increase in KU’s annual electric base rates of approximately $46.1 million (6.8%). The rate increase took effect on July 1, 2004.

 

During July 2004, the AG served subpoenas on KU, as well as on the Kentucky Commission and its staff, requesting information regarding allegedly improper communications between KU and the Kentucky Commission, particularly during the period covered by the rate case.  The Kentucky Commission has procedurally reopened the rate cases for the limited purpose of taking evidence, if any, as to the communication issues.

 

KU believes no improprieties have occurred in its communications with the Kentucky Commission and is cooperating with the proceedings before the AG and the Kentucky Commission.  KU 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 base rates.

 

For a further discussion of regulatory matters, see Rates and Regulation for KU under Item 7 and Note 3 of KU’s Notes to the Financial Statements under Item 8.

 

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, 2004, 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, 2004.  Gross retirements during the same period were $114 million.

 

Capital expenditures during the five years ending December 31, 2009 are estimated to be approximately $1.9 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 $672 million, and the installation of FGDs on Ghent and Brown units, totaling approximately $678 million.  Expenditures for Trimble County Unit 2 and the FGDs are contingent upon approval of the Company’s application for CCNs by the Kentucky Commission.

 

Coal Supply

 

Coal-fired generating units provided over 98.7% of KU’s net kilowatt-hour generation for 2004.  The remaining net generation for 2004 was provided by natural gas and oil-fueled combustion turbine peaking units (0.7%) and

 

17



 

hydroelectric plants (0.6%).  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 2005 and beyond.  The Company 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 1.0 million tons, or a 49-day supply, on hand at December 31, 2004.

 

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, Wyoming and Colorado for the foreseeable future.

 

Coal for Ghent is delivered by barge.  Deliveries to the Tyrone and Green River locations are by truck.  Delivery to E.W. Brown is by rail and truck.

 

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

 

 

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Per ton

 

$

37.69

 

$

34.57

 

$

31.44

 

Per MMBtu

 

$

1.56

 

$

1.47

 

$

1.35

 

Spot purchases as % of all sources

 

14

%

11

%

18

%

 

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 2005 is expected to increase due to 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 2004, expenditures for pollution control facilities represented $246 million or 25% of total construction expenditures.  KU estimates that construction expenditures for environmental control equipment from 2005 through 2009, primarily related to the installation of FGDs on three Ghent units, will be approximately $719 million.  For a discussion of environmental matters, see Rates and Regulation for KU under Item 7 and Note 11 of KU’s Notes to Financial Statements under Item 8.

 

Competition

 

In the last several years, KU has taken many steps to keep its rates low while maintaining high levels of customer satisfaction, including a reduction in the number of employees; aggressive cost cutting; an increase in focus on commercial, industrial and residential customers; an increase in employee involvement and training; and

 

18



 

continuous modifications of its organizational structure.  KU will take additional steps to better position itself should retail competition come to Kentucky.

 

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 will be 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.  The KPSC must provide its Strategic Blueprint to the Governor in early August 2005.  KU must respond to the Kentucky Commission’s first set of data requests by the end of March 2005.

 

Virginia has enacted a phase-in of customer choice through the Virginia Electric Restructuring Act.  The Virginia Commission is promulgating regulations to govern the various activities required by the Act.  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.

 

EMPLOYEES AND LABOR RELATIONS

 

LG&E had approximately 887 full-time regular employees and KU had approximately 934 full-time regular employees at February 28, 2005. Of the LG&E total, 643 operating, maintenance, and construction employees were represented by IBEW Local 2100.  LG&E and employees represented by IBEW Local 2100 signed a four-year collective bargaining agreement in November 2001 and completed wage and benefits re-opener negotiations in October 2003.  New wage and benefit rates went into effect in November 2003.  Of the KU total, approximately 158 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 effective August 2002 and expiring August 2005.

 

LG&E Services provides certain services to affiliated entities, including LG&E and KU, at cost as required under PUHCA.  On February 28, 2005 approximately 965 employees worked for LG&E Services.

 

See Note 3 of LG&E’s Notes to Financial Statements and Note 3 of KU’s Notes to Financial Statements under Item 8 for the workforce separation program in effect for 2001.

 

19



 

Executive Officers of LG&E and KU at February 28, 2005:

 

Name

 

Age

 

Position

 

Effective Date of
Election to Present
Position

 

 

 

 

 

 

 

Victor A. Staffieri

 

49

 

Chairman of the Board,
President and Chief
Executive Officer

 

May 1, 2001

 

 

 

 

 

 

 

John R. McCall

 

61

 

Executive Vice President,
General Counsel and
Corporate Secretary

 

July 1, 1994

 

 

 

 

 

 

 

S. Bradford Rives

 

46

 

Chief Financial Officer

 

September 15, 2003

 

 

 

 

 

 

 

Paul W. Thompson

 

48

 

Senior Vice President -
Energy Services

 

June 7, 2000

 

 

 

 

 

 

 

Chris Hermann

 

57

 

Senior Vice President -
Energy Delivery

 

February 14, 2003

 

 

 

 

 

 

 

Wendy C. Welsh

 

51

 

Senior Vice President -
Information Technology

 

December 11, 2000

 

 

 

 

 

 

 

Martyn Gallus

 

40

 

Senior Vice President -
Energy Marketing

 

December 11, 2000

 

Other Officers of LG&E and KU at February 28, 2005:

 

David A. Vogel

 

39

 

Vice President - Retail
and Gas Storage Operations

 

March 1, 2003

 

 

 

 

 

 

 

Daniel K. Arbough

 

43

 

Treasurer

 

December 11, 2000

 

 

 

 

 

 

 

Michael S. Beer

 

46

 

Vice President
Federal Regulation and Policy

 

September 27, 2004

 

 

 

 

 

 

 

George R. Siemens

 

55

 

Vice President - External
Affairs

 

January 11, 2001

 

 

 

 

 

 

 

Paula H. Pottinger

 

48

 

Vice President -
Human Resources

 

June 1, 2002

 

 

 

 

 

 

 

D. Ralph Bowling

 

47

 

Vice President -
Power Operations WKE

 

August 1, 2002

 

 

 

 

 

 

 

R. W. Chip Keeling

 

48

 

Vice President -
Communications

 

March 18, 2002

 

 

 

 

 

 

 

John N. Voyles, Jr.

 

50

 

Vice President -
Regulated Generation

 

June 16, 2003

 

 

 

 

 

 

 

Valerie L. Scott

 

48

 

Controller

 

January 1, 2005

 

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 2005 Annual Meeting of Shareholders.

 

20



 

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, 2005.  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 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 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 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, 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 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.

 

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.

 

Before he was elected to his current positions, Mr. Vogel served in management positions within the Distribution organization of LG&E and KU from November 1994 to December 2000, and 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, LG&E and KU from May 1998 to present.

 

Before he was elected to his current positions, Mr. Beer was Senior Corporate Attorney from February 1998 to February 2000; 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 from August 1982 to January 2001.

 

Before she was elected to her current positions, Ms. Pottinger was Manager, Human Resources Development

 

21



 

from May 1994 to May 1997; and Director, Human Resources from June 1997 to June 2002.

 

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

 

Before he was elected to his current positions, Mr. Keeling was General Manager, Marketing Communications for General Electric Company from January 1988 to January 1999.  He joined LG&E Energy and held the title Manager, Media Relations from January 1999 to February 2000; and Director, Corporate Communications for LG&E Energy from February 2000 to March 2002.

 

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.

 

22



 

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 - Kosmosdale, 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 - near Louisville, KY

 

 

 

Unit 4

 

155,000

 

Unit 5

 

168,000

 

Unit 6

 

240,000

 

Total Cane Run

 

563,000

 

 

 

 

 

Trimble County - Bedford, KY (a)

 

 

 

Unit 1

 

383,000

 

 

 

 

 

Combustion Turbine Generators (Peaking capability):

 

 

 

Zorn

 

14,000

 

Paddy’s Run (b)

 

119,000

 

Cane Run

 

14,000

 

Waterside

 

22,000

 

E.W. Brown – Burgin, KY (c)

 

190,000

 

Trimble County – Bedford, 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 11 and 12 of LG&E’s Notes to Financial Statements under Item 8 for further discussion on ownership.

(b)         Amount shown represents LG&E’s 53% interest in Paddy’s Run Unit 13 and 100% ownership of Paddy’s Run Units 11 and 12.  See Notes 11 and 12 of LG&E’s Notes to Financial Statement, under Item 8 for further discussion on ownership.

(c)          Amount shown represents LG&E’s 53% interest in Unit 5, 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 11 and 12 of LG&E’s Notes to Financial Statements, under Item 8 for further discussion on ownership.  KU operates the units on behalf of LG&E.

(d)         Amount shown represents LG&E’s 29% interest in Units 5 and 6 and LG&E’s 37% interest in Units 7, 8, 9 and 10 at Trimble County.  See Notes 11 and 12 of LG&E’s Notes to Financial Statements, under Item 8 for further discussion on ownership.

 

LG&E also owns an 80 Mw nameplate-rated hydroelectric generating station located in Louisville (Ohio Falls), with an expected summer capability rating of 48 Mw, operated under a license issued by the FERC.

 

At December 31, 2004, 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 11,878,000 Kva and approximately 670 structure miles of lines.  The electric distribution system

 

23



 

included 93 substations (20 of which are shared by the transmission system) with a total capacity of approximately 4,860,500 Kva, 3,923 structure miles of overhead lines and 1,859 miles of underground conduit.

 

LG&E’s gas transmission system includes 255 miles of transmission mains, and the gas distribution system includes 4,026 miles of distribution mains.

 

LG&E operates underground 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 Corporation, a financing subsidiary of E.ON, has a second lien on the property subject to the first mortgage bond lien.  The second lien secures loans provided by Fidelia.

 

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 - Tyrone, KY

 

 

 

Unit 1

 

27,000

 

Unit 2

 

31,000

 

Unit 3

 

71,000

 

Total Tyrone

 

129,000

 

 

 

 

 

Green River – South Carrollton, KY

 

 

 

Unit 3

 

68,000

 

Unit 4

 

95,000

 

Total Green River

 

163,000

 

 

 

 

 

E.W. Brown – Burgin, KY

 

 

 

Unit 1

 

101,000

 

Unit 2

 

167,000

 

Unit 3

 

429,000

 

Total E.W. Brown

 

697,000

 

 

 

 

 

Ghent – Ghent, 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 – Burgin, KY (Units 5-11) (a)

 

757,000

 

Haefling – Lexington, KY

 

36,000

 

Paddy’s Run – Louisville, KY (b)

 

74,000

 

Trimble County – Bedford, KY (c)

 

632,000

 

 

 

 

 

Total combustion turbine generators

 

1,499,000

 

 

 

 

 

Total capability rating

 

4,433,000

 

 

24



 


(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 11 and 12 of KU’s Notes to Financial Statements, under Item 8 for further discussion on ownership.

(b)         Amount shown represents KU’s 47% interest in Unit 13 at Paddy’s Run.  See Notes 11 and 12 of KU’s Notes to Financial Statements, under Item 8 for further discussion on ownership.  LG&E operates this unit on behalf of KU.

(c)          Amount shown represents KU’s 71% interest in Units 5 and 6 and KU’s 63% interest in Units 7, 8, 9 and 10 at Trimble County.  See Notes 11 and 12 of KU’s Notes to Financial Statements, under Item 8 for further discussion on ownership.  LG&E operates these units on behalf of KU.

 

KU also owns a 28 Mw nameplate-rated hydroelectric generating station located in Burgin, Kentucky (Dix Dam), with an expected summer capability rating of 24 Mw, operated under a license issued by the FERC.

 

At December 31, 2004, KU’s electric transmission system included 108 substations with a total capacity of approximately 16,978,000 Kva and approximately 4,239 structure miles of lines.  The electric distribution system included 491 substations with a total capacity of approximately 6,220,400 Kva and 15,182 structure miles of lines.

 

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 lien on the property subject to the first mortgage bond lien.  The second lien secures loans provided by Fidelia.

 

ITEM 3.  Legal Proceedings.

 

Rates and Regulatory Matters

 

For a discussion of current rate and regulatory matters, including electric and gas base rate increase proceedings, the Kentucky attorney general investigation, ESM proceedings, FERC or 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 Item 7, and Note 3 of LG&E’s Notes to Financial Statements and Note 3 of KU’s Notes to Financial Statements under Item 8.

 

Environmental

 

For a discussion of environmental matters including currently proposed reductions in SO2 and NOx emission limits; 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 Pressures) and Rates and Regulations for LG&E and KU (Environmental Matters) under Item 7 and Note 11 of LG&E’s Notes to Financial Statements and Note 11 of KU’s Notes to Financial Statements under Item 8, respectively.

 

25



 

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.  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 eight plaintiffs.  The complaint contains a claimed damage amount of $100 million as well as requests for injunctive relief.  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”), filed suit in Davies County, Kentucky District Court against KU concerning a long-term power supply contract (the “OMU Agreement”) with KU.  The dispute involves interpretational differences regarding certain issues under the OMU Agreement, including various payments or charges between KU and OMU and rights concerning excess power, termination and emissions allowances, respectively.  The complaint seeks approximately $6 million in damages for historical periods, as well as injunctive and other relief, including a declaration that KU is in material breach.  KU has removed this litigation to the U.S. District Court for the Western District of Kentucky, filed an answer in that court denying the OMU claims and presenting certain counterclaims and commenced a FERC proceeding to request FERC jurisdiction on certain issues.  In October 2004, FERC declined to exercise exclusive jurisdiction regarding the issues in dispute, which ruling KU has appealed.  In December 2004, KU filed in federal court for summary judgment on certain issues.

 

OVEC Power Agreement and Share Purchase

 

On April 30, 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.  Under the new contract, which has a 20-year term from its effective date, LG&E and KU have purchase rights for 5.63% and 2.5%, respectively, of OVEC power at marginal cost-based rates.  LG&E and KU are entitled to 7% and 2.5% of OVEC power, respectively, under the current contract.  In addition, LG&E has purchased from AEP an additional 0.73% interest in OVEC for a purchase price of approximately $0.1 million, resulting in an increase in LG&E ownership in OVEC from 4.9% to 5.63%.  The parties received SEC approval under PUHCA of the Amended and Restated Inter-Company Power Agreement during February 2005 and completed the share purchase transaction during March 2005.

 

Other

 

In the normal course of business, other lawsuits, claims, environmental actions, and other governmental proceedings arise against LG&E and KU.  To the extent that damages are assessed in any of these lawsuits, LG&E and KU believe that their insurance coverage is adequate.  Management, after consultation with legal counsel, does not anticipate that liabilities arising out of other currently pending or threatened lawsuits and claims will have a material adverse effect on LG&E’s or KU’s consolidated financial position or results of operations, respectively.

 

26



 

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 LG&E Energy.  Therefore, there is no public market for LG&E’s common stock.

 

The following table sets forth LG&E’s cash distributions on common stock paid to LG&E Energy during 2004.

 

(in thousands)

 

 

 

First quarter

 

$

 

Second quarter

 

21,000

 

Third quarter

 

21,000

 

Fourth quarter

 

15,000

 

 

LG&E had no cash distributions on common stock paid to LG&E Energy in 2003. In 2002, LG&E paid $69 million in cash distribution on common stock to LG&E Energy.

 

KU:

All KU common stock, 37,817,878 shares, is held by LG&E Energy.  Therefore, there is no public market for KU’s common stock.

 

The following table sets forth KU’s cash distributions on common stock paid to LG&E Energy during 2004.

 

(in thousands)

 

 

 

First quarter

 

$

 

Second quarter

 

21,000

 

Third quarter

 

21,000

 

Fourth quarter

 

21,000

 

��

KU paid no cash distributions on common stock to LG&E Energy in 2003 or 2002.

 

27



 

ITEM 6.  Selected Financial Data.

 

The 2000 consolidated financial data were derived from financial statements audited by Arthur Andersen LLP, independent accountants, who expressed an unqualified opinion on those financial statements in their report dated January 26, 2001, before the revisions required by EITF 02-03 and the reclassification of income taxes.  Arthur Andersen LLP has ceased operations.  The amounts shown below for such period, reclassified pursuant to the adoption of EITF 02-03 and reclassified due to the change in presentation of income taxes, are unaudited.

 

 

 

Years Ended December 31

 

(in thousands)

 

2004

 

2003

 

2002

 

2001

 

2000

 

LG&E:

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

 

$

1,172,768

 

$

1,093,521

 

$

1,003,735

 

$

964,547

 

$

931,704

 

 

 

 

 

 

 

 

 

 

 

 

 

Net operating income

 

$

185,031

 

$

178,752

 

$

172,949

 

$

205,225

 

$

213,295

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

$

95,618

 

$

90,839

 

$

88,929

 

$

106,781

 

$

110,573

 

 

 

 

 

 

 

 

 

 

 

 

 

Total assets

 

$

2,966,552

 

$

2,882,082

 

$

2,768,930

 

$

2,448,354

 

$

2,226,084

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

$

871,804

 

$

798,054

 

$

616,904

 

$

616,904

 

$

606,800

 

 

 

 

 

 

 

 

 

 

 

 

 

Dividends declared per common share

 

$

2.68

 

$

 

$

3.24

 

$

1.08

 

$

2.35

 

 

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 thousands)

 

2004

 

2003

 

2002

 

2001

 

2000

 

KU:

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

 

$

995,362

 

$

891,778

 

$

861,664

 

$

820,721

 

$

793,409

 

 

 

 

 

 

 

 

 

 

 

 

 

Net operating income

 

$

227,847

 

$

162,210

 

$

162,675

 

$

178,852

 

$

180,099

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

$

133,471

 

$

91,402

 

$

93,384

 

$

96,414

 

$

95,524

 

 

 

 

 

 

 

 

 

 

 

 

 

Total assets

 

$

2,610,439

 

$

2,505,094

 

$

2,251,638

 

$

1,826,902

 

$

1,739,518

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

$

726,211

 

$

687,576

 

$

500,492

 

$

488,506

 

$

484,830

 

 

 

 

 

 

 

 

 

 

 

 

 

Dividends declared per common share

 

$

1.67

 

$

 

$

 

$

0.81

 

$

2.00

 

 

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.

 

28



 

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 2004, 2003, and 2002 and should be read in connection with the financial statements and notes thereto.

 

Some of the following discussion may contain forward-looking statements that are subject to certain risks, uncertainties and assumptions.  Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “expect,” “estimate,” “objective,” “possible,” “potential” and similar expressions.  Actual results may materially vary.  Factors that could cause actual results to materially differ include: general economic conditions; business and competitive conditions in the energy industry; changes in federal or state legislation; unusual weather; actions by state or federal regulatory agencies; actions by credit rating agencies; and other factors described from time to time in LG&E’s and KU’s reports to the SEC, including Exhibit No. 99.01 to this report on Form 10-K.

 

EXECUTIVE SUMMARY

 

Our Business

 

LG&E and KU are each subsidiaries of LG&E Energy LLC, 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 318,000 customers and electricity to approximately 390,000 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 gas service in limited additional areas.  LG&E’s coal-fired electric generating plants, all equipped with systems to reduce sulfur dioxide emissions, produce most of LG&E’s electricity.  The remainder is generated by a hydroelectric power plant and combustion turbines.  Underground natural gas storage fields help LG&E provide economical and reliable gas service to customers.

 

KU, incorporated in Kentucky in 1912 and incorporated in Virginia in 1991, is a regulated public utility engaged in producing, transmitting and selling electric energy.  KU provides electric service to approximately 488,000 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 to less than 10 customers in Tennessee.  In Virginia, KU operates under the name Old Dominion Power Company.  KU also sells wholesale electric energy to 12 municipalities.

 

29



Our Customers

 

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

 

 

 

LG&E

 

KU

 

2004 % Retail Revenues

 

Customers (000s)

 

Electric

 

Gas

 

Electric

 

LG&E

 

KU

 

 

 

2004

 

2003

 

2004

 

2003

 

2004

 

2003

 

Electric

 

Gas

 

Electric

 

Retail Customer Data

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

 

343

 

337

 

293

 

287

 

426

 

421

 

39

%

65

%

38

%

Industrial & Commercial

 

41

 

41

 

24

 

24

 

82

 

82

 

51

%

30

%

53

%

Other

 

6

 

6

 

1

 

1

 

10

 

9

 

10

%

5

%

9

%

Total Retail

 

390

 

384

 

318

 

312

 

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 and KU’s strategy focuses on the following:

 

                  Execute all our business processes to secure a world-class competitive advantage

                  Develop and transfer best practices in generation, customer service, distribution and supply

                  Operate our commercial hub to enhance margins and manage risks across the company

                  Pursue flexible asset portfolio management

                  Attract, retain and develop the best people

 

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 top amongst large electric utilities in the Midwest for the 5th time in six years in the J.D. Power and Associates 2004 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 rates per thousand Kwh of U.S. investor-owned utilities as of July 1, 2004:

 

 

Source: Edison Electric Institute, Summer 2004 Typical Bills and Average Rates Report; Residential rates in effect July 1, 2004, based on 1,000 Kwh monthly usage.

 

30



 

The company 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, produce $55.3 million of revenue for LG&E and $46.1 million of revenue for KU for a full year.  Under the ruling, the LG&E utility base electric rates have increased $43.4 million (7.7%) and base gas rates have increased $11.9 million (3.4%), on an annual basis.  Base electric rates at KU have increased $46.1 million (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 gas rate increase for the LG&E 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

 

Wholesale natural gas prices stayed around the $6/MMBtu level during summer 2004.  The U.S. supply-demand imbalance problem has continued, with U.S. reserves in decline and gas demand for electric generation continuing to increase.

 

Coal prices, which moderated after increases in 2001-2002, rose in late 2003 and maintained strength during 2004.  Coal production in the U.S. has not kept pace with demand, and mining companies are exercising market discipline in their production decisions.  Lower sulfur Central Appalachian coal led the price increases.  Prices for Powder River Basin (“PRB”) low sulfur coal from the western U.S. have risen much less than eastern coals, largely due to transportation constraints between the mines and eastern markets.  However, LG&E and KU generation plants are limited in the amount of PRB coal that can be burned.

 

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

 

 

Actual 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.

 

31



 

With respect to wholesale electricity prices, generation overcapacity in the Midwest is forecasted to persist, with reserve margins still topping 25% for ECAR in 2005. However, the overcapacity resulted largely from the construction of high-cost simple cycle gas-fired units.  Therefore, high gas prices have supported higher wholesale electricity prices, advantaging coal-fired generation.  While the regional reserve margin is expected to decline over time as new capacity construction slows and demand grows, gas-fired generation is expected to set prices, particularly during times of higher loads. This expectation, combined with the expectation that gas prices will remain high, indicates that on-peak electricity prices are expected to remain high.

 

Generation Reliability

 

Generation reliability also remains a key aspect to meeting our 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

 

With the recent installation of four combustion turbines at Trimble County, near-term regulated load growth in Kentucky is expected to be satisfied. The installation of Trimble County Units 7-10 increased total system capability by 9%. However, the IRP submitted by LG&E and KU to the Kentucky Commission in 2002, outlining the least cost alternative to meet Kentucky’s needs, indicated the requirement for additional base-load capacity in the longer-term.   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 customers.  Trimble County Unit 2, with a 732 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).   An application for a construction CCN was filed with the Kentucky Commission in December 2004, and the proposed air permit was filed with the Kentucky Department of Air Quality in December 2004.  LG&E’s and KU’s share of the total capital cost of $885 million for Trimble County Unit 2 is estimated to be $168 million and $717 million, respectively, through 2010.

 

Environmental Pressures

 

In addition to the Trimble County Unit 2 project, the second major utility investment area is environmental expenditures.  The need for additional FGD units is continuously assessed based on the expected changes in SO2 allowance prices, coal cost, and environmental legislation.  The analysis supports building additional FGD units to mitigate the declining SO2 allowance bank at KU over the next several years.  The LG&E utility fleet is fully scrubbed.  SO2 allowance prices have risen significantly and, coupled with the high price of low sulfur coal, indicate the need for FGDs on three of KU’s Ghent units and at E.W. Brown.  In December 2004, KU filed with the Kentucky Commission an application for a CCN to construct four FGDs; a decision is expected by late June 2005.

 

LG&E and KU completed the NOx SCR projects before the May 2004 deadline.  Expenditures on NOx investments, totaling approximately $186 million at LG&E and $219 million at KU, are being recovered currently through the companies’ ECR mechanism (see “Rates and Regulation”).

 

Additional environmental regulations are probable in the areas of New Source Review (a preconstruction permitting program established as part of the Clean Air Act), mercury and CO2. The mercury standard will most likely be achieved through the operation of conventional air pollution control equipment (FGDs). The

 

32



 

Companies believe that CO2 regulation is a longer-term issue as there is no current nationwide consensus to adopt Kyoto-like restrictions.

 

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. The mechanism permits LG&E and KU to earn a reasonable return on these capital investments outside of base rates.  Related operation and maintenance expenses are also recoverable.  Approximately 80% of the applicable environmental costs, including investment and operating costs, are recoverable through ECR. The remaining 20%, attributable to off-system and FERC-jurisdictional sales, are not recoverable through the ECR, but can be included in the determination of base rate cases.

 

Weather

 

The utility business is affected by various weather patterns.  Seasonal weather patterns can cause extreme variability in load due to higher or lower temperatures than normal.  The Companies maintain generation reserve margins and natural gas storage fields to accommodate higher than normal loads.  Lower than normal loads can impact the profitability of the Companies due to lower revenues.  A WNA mechanism, effective November through April, adjusts for the over- and under-recovery of costs associated with natural gas in periods of abnormal winter usage.

 

Severe snow and ice storms, thunderstorms, tornadoes and flooding can result in extensive damage to the infrastructure of the Companies’ transmission and distribution systems.  The Companies maintain a comprehensive storm management plan for efficient and timely restoration of service to customers after major storm events.

 

Business Disruption Risks

 

LG&E and KU face certain operational risks common to the electric and gas utility industries, as applicable.  These include, without limitation, the risk of disruptions or outages relating to major operating or delivery facilities, such as generating units, transmission or distribution assets and information technology or data processing components, whether due to terrorist or other attack, civil unrest or labor action, break-down or mechanical failure, severe weather or other acts of God.

 

While LG&E and KU believe they have appropriate prevention or mitigation measures 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 the Companies’ financial condition or results of operations.

 

MERGERS AND ACQUISITIONS

 

LG&E and KU are each subsidiaries of LG&E Energy.  On December 11, 2000, LG&E Energy Corp., now LG&E Energy LLC, was acquired by Powergen plc, now known as Powergen Limited, for cash of approximately $3.2 billion and the assumption of all of LG&E Energy’s debt.  As a result of the acquisition, LG&E Energy became a wholly owned subsidiary of Powergen and, as a result, LG&E and KU became indirect subsidiaries of Powergen.

 

On July 1, 2002, E.ON, a German company, completed its acquisition of Powergen plc (now Powergen Limited).  As a result, LG&E and KU became indirect subsidiaries of E.ON.  E.ON had announced its pre-conditional cash offer of £5.1 billion ($7.3 billion) for Powergen on April 9, 2001.

 

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

 

The utility operations of LG&E Energy 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.

 

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.

 

33



 

RESULTS OF OPERATIONS

 

LG&E

 

Net Income

 

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 $22.6 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 (6.3%).

 

LG&E’s net income in 2004 related to the gas business decreased $1.9 million (18.2%) compared to 2003.  Gas operating revenues increased $31.7 million (9.8%) offset by higher gas supply expenses of $32.4 million (13.9%).  Other gas operations and maintenance expenses increased $2.0 million (4.2%).

 

LG&E’s net income in 2003 increased $1.9 million (2.1%) as compared to 2002.  The increase resulted primarily from increased electric sales.

 

LG&E’s net income in 2003 related to the electric business increased $1.4 million (1.8%) compared to 2002.  Electric operating revenues increased $32.1 million (4.4%), offset by higher fuel for electric generation and power purchased of $19.8 million (7.8%).  Other electric operations expense increased $2.2 million (1.3%).  Electric depreciation expense increased $6.2 million (7.0%).  Other income decreased $1.6 million (126.6%) and interest expense increased $0.9 million (3.5%).

 

LG&E’s net income in 2003 related to the gas business increased $0.5 million (5.7%) compared to 2002.  Gas operating revenues increased $57.6 million (21.6%) offset by higher gas supply expenses of $51.5 million (28.3%).  Other gas operations expense increased $3.1 million (8.4%) and maintenance expense increased $0.3 million (4.4%).  Gas depreciation increased $1.1 million (7.3%).  Other income decreased $0.5 million (112.4%).

 

Revenues

 

The following table presents a comparison of operating revenues for the years 2004 and 2003 with the immediately preceding year.

 

34



 

 

 

Increase (Decrease) From Prior Period

 

(in thousands)

 

Electric Revenues

 

Gas Revenues

 

Cause

 

2004

 

2003

 

2004

 

2003

 

Retail sales:

 

 

 

 

 

 

 

 

 

Fuel and gas supply adjustments

 

$

1,093

 

$

6,620

 

$

33,546

 

$

50,972

 

LG&E/KU Merger surcredit

 

(2,329

)

(2,288

)

 

 

Environmental cost recovery surcharge

 

12,747

 

(269

)

 

 

Earnings sharing mechanism

 

4,489

 

9,768

 

 

 

Demand side management

 

403

 

1,362

 

(555

)

267

 

VDT surcredit

 

(1,140

)

(3,394

)

87

 

(1,283

)

Weather normalization

 

 

 

3,188

 

(506

)

Rate changes

 

16,824

 

 

6,947

 

 

Variation in sales volumes and other

 

11,809

 

(18,451

)

(5,773

)

12,070

 

Provision for Rate Collections (Refunds)

 

(11,006

)

(12,067

)

 

 

Total retail sales

 

32,890

 

(18,719

)

37,440

 

61,520

 

Wholesale

 

15,781

 

49,230

 

(5,083

)

(4,106

)

Gas transportation-net

 

 

 

95

 

(186

)

Other

 

(1,162

)

1,635

 

(714

)

412

 

Total

 

$

47,509

 

$

32,146

 

$

31,738

 

$

57,640

 

 

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.  Electric revenues increased in 2003 primarily due to an increase in wholesale sales due to both higher market prices and higher sales volume as compared to 2002.  Retail revenues decreased due to 2.6% lower sales volume, primarily in the residential sector due to milder summer weather than 2002.  Cooling degree days decreased 33% compared to 2002 and were 14% below the 20-year average.

 

Gas revenues in 2004 increased due to higher gas supply cost billed to customers through the gas supply clause and increased gas rates. New 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. Gas revenues in 2003 increased compared to 2002, due to higher gas supply cost billed to customers through the gas supply clause and increased gas retail sales due to cooler winter weather, offset by lower off-system gas sales.  Heating degree days increased 5% as compared to 2002 and were the same as the 20-year average.

 

The decrease in the provision for rate collections (refunds) in 2004 from 2003 ($11.0 million) results primarily from a decrease in the ESM accrual ($12.7 million) and a decrease in 2004 ECR accruals ($5.4 million), partially offset by an increase in fuel accruals ($7.1 million). The decrease in the provision for rate collections (refunds) in 2003 from 2002 ($12.1 million) results primarily from ESM revenues billed to customers during 2003 ($10.0 million), a decrease in the ESM accrual ($2.4 million) and a decrease in fuel accruals ($2.6 million), partially offset by an increase in ECR accruals ($2.9 million).

 

Expenses

 

Fuel for electric generation and gas supply expenses comprise a large component of LG&E’s total operating costs. The retail electric rates contain a FAC and gas rates contain a GSC, whereby increases or decreases in the cost of fuel and gas supply are reflected in the FAC and GSC factors, subject to approval by the Kentucky Commission, and passed through to LG&E’s retail customers.

 

Fuel for electric generation increased $10.1 million (5.1%) in 2004 due to increased generation ($3.7 million) and higher cost of fuel burned ($6.4 million).   Fuel for electric generation increased $2.1 million (1.1%) in

 

35



 

2003 due to increased generation ($5.8 million) offset by lower cost of fuel burned ($3.7 million), primarily due to greater percentage of steam generation vs. combustion turbine generation in 2003.  The average delivered cost per MMBtu of coal purchased was $1.15 in 2004, $1.12 in 2003 and $1.11 in 2002.

 

Power purchased increased $12.4 million (15.6%) in 2004 due to a 4% increase in purchases to meet off-system sales requirements ($3.4 million), and an 11% higher unit cost of purchases ($9.0 million).   Power purchased expenses increased $17.7 million (28.7%) in 2003 due to an increase in purchases to meet off-system sales requirements ($9.0 million), and a 12% higher unit cost of purchases ($8.7 million).

 

Gas supply expenses increased $32.4 million (13.9%) in 2004 due to an increase in cost of net gas supply ($52.2 million) offset by a decrease in the volume of gas delivered to the distribution system ($19.8 million). Gas supply expenses increased $51.5 million (28.3%) in 2003 due to an increase in cost of net gas supply ($50.2 million) and an increase in the volume of gas delivered to the distribution system ($4.1 million), partially offset by lower cost of purchases for wholesale sales ($2.8 million).

 

Other operations and maintenance expenses increased $14.7 million (5.1%) in 2004.

 

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 steam generation expense ($1.2 million).

                  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.

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

 

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

                  Increased maintenance expense due to storm restoration costs related to severe May and July storms ($9.3 million).

                  Increased distribution maintenance, excluding the storm restoration costs ($0.7 million).

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

                  Increased combustion turbine maintenance ($1.1 million).

                  Increased hydro generation maintenance, primarily due to Ohio Falls rehabilitation ($0.5 million).

 

Property and other taxes increased $1.6 million (10.2%) in 2004 primarily due to:

                  Increased property taxes ($1.2 million).

                  Increased payroll taxes ($0.4 million).

 

Other operations and maintenance increased $5.3 million (1.9%) in 2003.

 

Other operation expenses increased $8.7 million (4.2%) in 2003 primarily due to:

                  Increased electric transmission and distribution expense ($5.4 million).

                  Increased employee benefits costs ($4.0 million).

                  Increased demand side management program expenses ($2.5 million).

                  Increased uncollectible customer accounts ($1.6 million).

                  Decreased amortization of regulatory assets ($3.5 million).

                  Decreased injury and damage liabilities ($2.1 million).

 

Maintenance expenses for 2003 decreased $3.0 million (5.0%) primarily due to:

 

36



 

                  Decreased maintenance of electric distribution ($1.1 million) and gas distribution ($0.8 million).

                  Decreased communications maintenance expenses ($0.9 million).

 

Property and other taxes decreased $0.4 million (2.3%) in 2003 primarily due to:

                  Reduced property taxes due to a $1.2 million coal credit ($1.1 million).

                  Increased payroll taxes ($0.7 million).

 

Depreciation and amortization increased $3.3 million (2.9%) in 2004 and $7.4 million (7.0%) in 2003 due to additional utility plant in service.

 

Other income (expense) - net increased $3.9 million (53.7%) in 2004.  In 2003, write-offs of $3.0 million decreased other income (see below).  Other income (expense) - net decreased $5.7 million (367.2%) in 2003 due primarily to the write-off of amounts from CWIP for a terminated plant project ($2.4 million) and a terminated software project ($0.6 million) partially offset by a decrease in benefit costs ($1.7 million).

 

Total interest expense for 2004 increased $2.1 million (7.0%) due to increased borrowing from Fidelia ($6.9 million), higher cost of the interest rate swaps ($3.0 million) resulting from the first full year of an additional $128 million of swaps and higher interest rates on variable-rate debt ($0.8 million), partially offset by savings from retired first mortgage debt ($7.2 million) and reduced borrowing from the money pool ($1.4 million).

 

Interest charges for 2003 increased $0.8 million (2.8%) due to new fixed-rate debt with Fidelia ($5.0 million) offset by a decrease in average outstanding balances borrowed from the money pool ($0.4 million) and savings from lower average interest rates on variable-rate long-term bonds ($3.7 million).

 

The weighted average interest rate on variable-rate long-term bonds for 2004, 2003 and 2002 was 1.28%, 1.10% and 1.54%, respectively.  At December 31, 2004, 2003 and 2002, LG&E’s percentage of long-term bonds having a variable-rate, including the impact of interest rate swaps,  was 35.1% at $306.0 million, 38.3% at $306.0 million and 46.8% at $289.0 million, respectively.  LG&E’s weighted average cost of long-term debt, including amortization of debt expense and interest rate swaps, was 3.92%, 3.58%, and 3.87% at December 31, 2004, 2003 and 2002, respectively.  See Note 9 of LG&E’s Notes to Financial Statements under Item 8.

 

Variations in income tax expenses are largely attributable to changes in pre-tax income. LG&E’s 2004 effective income tax rate increased to 35.8% from the 35.5% rate in 2003.   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

 

37



 

applied has not changed.  Specific risks for these critical accounting policies are described in the following paragraphs.  Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions.  Events rarely develop exactly as forecast and the best estimates routinely require adjustment.  See also Note 1 of LG&E’s Notes to Financial Statements under Item 8.

 

Financial Instruments - LG&E uses over-the-counter interest-rate swap agreements to hedge its exposure to fluctuations in the interest rates it pays on variable-rate debt.  Gains and losses on interest-rate swaps used to hedge interest rate risk are reflected in other comprehensive income.  LG&E uses sales of market-traded electric forward contracts for periods less than one year to hedge the price volatility of its forecasted peak electric off-system sales.  Gains and losses resulting from ineffectiveness are shown in other income (expense) and to the extent that the hedging relationship has been effective, gains and losses are reflected in other comprehensive income.  Wholesale sales of excess asset capacity and wholesale purchases to be used to serve native load are treated as normal sales and purchases under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities and SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, and are not marked-to-market.  See Note 4 and Note 15 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 gas usage that has been used by customers, but not 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, 2004, a 10% change in these estimated quantities would cause revenue and accounts receivable to change by approximately $6.3 million, including $2.7 million for electric usage and $3.6 million for gas usage.  See also Note 1 of LG&E’s Notes to Financial Statements under Item 8.

 

Allowance for Doubtful Accounts – At December 31, 2004 and 2003, the LG&E allowance for doubtful accounts was $0.8 million and $3.5 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.

 

Benefit Plan Accounting – LG&E’s costs of providing defined-benefit pension retirement plans is dependent upon a number of factors, such as the rates of return on plan assets, healthcare cost trend rates, discount rate, contributions made to the plan, and other actuarial assumptions used to value benefit obligations.  In 2002, LG&E was required to recognize an additional minimum liability of $26.0 million as prescribed by SFAS No. 87 Employers’ Accounting for Pensions since the fair value of the plan assets was less than the accumulated benefit obligation at that time.  During 2002, the combination of poor market performance and historically low corporate bond rates created a divergence in the potential value of the pension liabilities and the actual value of the pension assets.  The liability was recorded as a reduction to other comprehensive income, and did not affect net income.  In 2003, LG&E recognized a reduction of the minimum pension liability of $3.1 million.  During 2004 LG&E recognized an additional minimum pension liability of $10.2 million.  If the fair value of the plan assets exceeds the accumulated benefit obligation, the recorded liability will be reduced and other comprehensive income will be restored in the consolidated balance sheet.

 

Should poor market conditions return, these conditions could result in an increase in LG&E’s unfunded accumulated benefit obligations and future pension expense.  The primary assumptions that drive the value of the unfunded accumulated benefit obligations are the discount rate and expected return on plan assets.

 

38



 

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

 

 

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Discount rate

 

6.25

%

6.75

%

7.25

%

Expected long-term return on plan assets

 

8.50

%

9.00

%

9.50

%

Rate of compensation increase

 

3.50

%

3.75

%

4.25

%

 

LG&E made contributions to the pension plan of $34.5 million in January 2004 and $89.1 million during 2003.

 

A 1% increase or decrease in the assumed discount rate could have an approximate $39.9 million positive or negative impact to the accumulated benefit obligation of LG&E.

 

See also Note 6 and Note 15 of LG&E’s Notes to Financial Statements under Item 8.

 

Regulatory Mechanisms – Judgments and uncertainties include future regulatory decisions, the impact of deregulation and competition on ratemaking process, and external regulator decisions.

 

Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates based upon Kentucky Commission orders.  Regulatory liabilities generally represent obligations to make refunds to customers for previous collections based upon orders by the Kentucky Commission.  Management believes, based on orders, the existing regulatory assets and liabilities are probable of recovery.   This determination reflects the current regulatory climate in the state.  If future recovery of costs ceases to be probable the assets would be required to be recognized in current period earnings.

 

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 many transactions for which the ultimate tax outcome is uncertain.

 

To provide for these uncertainties or exposures, an allowance is maintained for tax contingencies, the balance of which management believes is adequate.  Tax contingencies are analyzed periodically and adjustments are made when events occur to warrant a change.  The company is currently in the examination phase of IRS audits for the years 1999 to 2003 and expects some or all of these audits to be completed within the next 12 months.  The results of audit assessments by taxing authorities are not anticipated to have a material adverse effect on cash flows or results of operations.

 

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 generation taxable income in 2005. On a stand-alone basis, LG&E expects to generate a deduction in 2005 which will reduce LG&E’s effective tax rate by less than 1%.

 

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.  The impact of these reduced rates is expected to decrease LG&E’s income tax expense in future periods.  Furthermore, these reduced rates will result in the reversal of accumulated temporary differences at lower rates than originally provided.  LG&E is presently evaluating the impact of this and other changes to the Kentucky tax system, however, no material adverse impacts on cash flows or results of operations are expected.

 

LG&E is subject to periodic changes in state tax law, regulation or interpretation, as well as enforcement proceedings.  LG&E is currently undergoing a routine Kentucky sales tax audit for the period October 1997 through 2001.  The possible assessment or amount at issue is not known at this time, but is not expected to have a material adverse effect on cashflows or results of operations.

 

See Note 1 and Note 7 of LG&E’s Notes to Financial Statements under Item 8.

 

Deferred Income Taxes - LG&E expects to have adequate levels of taxable income to realize its recorded deferred tax assets.  See Note 7 of LG&E’s Notes to Financial Statements under Item 8 for a breakdown of deferred tax assets.

 

NEW ACCOUNTING PRONOUNCEMENTS

 

The following recent accounting pronouncements affected LG&E in 2004 and 2003:

 

SFAS No. 143

 

SFAS No. 143, Accounting for Asset Retirement Obligations was issued in 2001.  SFAS No. 143 establishes accounting and reporting standards for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.

 

The effective implementation date for SFAS No. 143 was January 1, 2003.  Management has calculated the impact of SFAS No. 143 and FERC Final Order No. 631 issued in Docket No. RM02-7, Accounting, Financial Reporting, and Rate Filing Requirements for Asset Retirement Obligations.  As of January 1, 2003, LG&E recorded ARO assets in the amount of $4.6 million and liabilities in the amount of $9.3 million.  LG&E also recorded a cumulative effect adjustment in the amount of $5.3 million to reflect the accumulated depreciation and accretion of ARO assets at the transition date less amounts previously accrued under regulatory depreciation.  LG&E recorded offsetting regulatory assets of $5.3 million, pursuant to regulatory treatment prescribed under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.  Also pursuant to SFAS No. 71, LG&E recorded regulatory liabilities in the amount of $0.1 million offsetting removal costs previously accrued under regulatory accounting in excess of amounts allowed under SFAS No. 143.

 

39



 

Had SFAS No. 143 been in effect for the 2002 reporting period, LG&E would have established asset retirement obligations as described in the following table:

 

(in thousands)

 

 

 

Provision at January 1, 2002

 

$

8,752

 

Accretion expense

 

578

 

Provision at December 31, 2002

 

$

9,330

 

 

As of December 31, 2004, LG&E had ARO assets, net of accumulated depreciation, of $3.3 million and liabilities of $10.3 million.  As of December 31, 2003, LG&E had ARO assets, net of accumulated depreciation, of $3.5 million and liabilities of $9.7 million.  LG&E recorded offsetting regulatory assets of $6.9 million and $6.0 million and regulatory liabilities of $0.1 million as of both December 31, 2004 and 2003, respectively.

 

For the year ended December 31, 2004, LG&E recorded ARO accretion expense of approximately $0.7 million, ARO depreciation expense of $0.2 million and an offsetting regulatory credit in the income statement of $0.9 million, pursuant to regulatory treatment prescribed under SFAS No. 71.  For the year ended December 31, 2003, LG&E recorded ARO accretion expense of approximately $0.6 million, ARO depreciation expense of $0.1 million and an offsetting regulatory credit in the income statement of $0.7 million.  Removal costs incurred and charged against the ARO liability during 2004 and 2003 were $0.1 million and $0.2 million, respectively.  SFAS No. 143 has no impact on the results of operations of LG&E.

 

LG&E AROs are primarily related to final retirement of assets associated with generating units.  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, 2004 and 2003, LG&E recorded immaterial amounts (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 also continues to include a cost of removal component in depreciation for assets that do not have a legal ARO.  As of December 31, 2004 and 2003, LG&E has segregated this cost of removal, embedded in accumulated depreciation, of $220.2 million and $216.5 million, respectively, in accordance with FERC Order No. 631. For reporting purposes in its Consolidated Balance Sheets included in Item 8, LG&E has presented this cost of removal as a regulatory liability pursuant to SFAS No. 71.

 

LG&E transmission and distribution lines largely operate under perpetual property easement agreements which do not generally require restoration upon removal of the property.  Therefore, under SFAS No. 143, no material asset retirement obligations are recorded for transmission and distribution assets.

 

EITF No. 02-03

 

LG&E adopted EITF No. 98-10, Accounting for Energy Trading and Risk Management Activities, effective January 1, 1999.  This pronouncement required that energy trading contracts be marked to market on the balance sheet, with the gains and losses shown net in the income statement.  Effective January 1, 2003, LG&E adopted EITF No. 02-03, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.  EITF No. 02-03 established the following:

 

                  Rescinded EITF No. 98-10,

 

40



 

                  Contracts that do not meet the definition of a derivative under SFAS No. 133 should not be marked to fair market value, and

                  Revenues should be shown in the income statement net of costs associated with trading activities, whether or not the trades are physically settled.

 

With the rescission of EITF No. 98-10, energy trading contracts that do not also meet the definition of a derivative under SFAS No. 133 must be accounted for as executory contracts.  Contracts previously recorded at fair value under EITF No. 98-10 that are not also derivatives under SFAS No. 133 must be restated to historical cost through a cumulative effect adjustment.  The rescission of this standard had no impact on financial position or results of operations of LG&E since all forward and option contracts marked to market under EITF No. 98-10 were also within the scope of SFAS No. 133.

 

As a result of EITF No. 02-03, LG&E has netted the power purchased expense for trading activities against electric operating revenue to reflect this accounting change.  LG&E applied this guidance to previously reported 2002 balances as shown below. The reclassifications had no impact on previously reported net income or common equity.

 

(in thousands)

 

 

 

Gross electric operating revenues as previously reported

 

$

1,026,184

 

Less costs reclassified from power purchased

 

22,449

 

Net electric operating revenues

 

$

1,003,735

 

 

 

 

 

Gross power purchased as previously reported

 

$

84,330

 

Less costs reclassified to revenues

 

22,449

 

Net power purchased

 

$

61,881

 

 

SFAS No. 150

 

In May 2003, the Financial Accounting Standards Board issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.  SFAS No. 150 was effective immediately for financial instruments entered into or modified after May 31, 2003, and otherwise was effective for interim reporting periods beginning after June 15, 2003, except for certain instruments and certain entities which have been deferred by the FASB.  Such deferrals do not affect LG&E.

 

LG&E has $5.875 series mandatorily redeemable preferred stock outstanding having a current redemption price of $100 per share. The preferred stock has a sinking fund requirement sufficient to retire a minimum of 12,500 shares on July 15 of each year commencing with July 15, 2003, and the remaining 187,500 shares on July 15, 2008 at $100 per share.  LG&E redeemed 12,500 shares in accordance with these provisions on July 15, 2003 and 2004, leaving 225,000 shares currently outstanding.  Beginning with the three months ended September 30, 2003, LG&E reclassified its $5.875 series preferred stock as long-term debt with the minimum shares mandatorily redeemable within one year classified as current portion of long-term debt.  Dividends accrued beginning July 1, 2003, are charged as interest expense.

 

FIN 46

 

In January 2003, the Financial Accounting Standards Board issued Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51 (“FIN 46”).  FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support

 

41



 

from other parties.  FIN 46 was effective immediately for all new variable interest entities created or acquired after January 31, 2003.  For variable interest entities created or acquired prior to February 1, 2003, the provisions of FIN 46 must have been applied for the first interim or annual period beginning after June 15, 2003.

 

In December 2003, FIN 46 was revised, delaying the effective dates for certain entities created before February 1, 2003, and making other amendments to clarify application of the guidance.  For potential variable interest entities other than special purpose entities, the revised FIN 46 (“FIN 46R”) was required to be applied no later than the end of the first fiscal year or interim reporting period ending after March 15, 2004.  The original guidance under FIN 46 was applicable, however, for all special purpose entities created prior to February 1, 2003, at the end of the first interim or annual reporting period ending after December 15, 2003.  FIN 46R may be applied prospectively with a cumulative-effect adjustment as of the date it is first applied, or by restating previously issued financial statements with a cumulative-effect adjustment as of the beginning of the first year restated.  FIN 46R also requires certain disclosures of an entity’s relationship with variable interest entities. The adoption of FIN 46 and FIN 46R had no impact on the financial position or results of operations for LG&E.

 

Although LG&E holds an investment interest in OVEC, it is not the primary beneficiary of OVEC and, therefore, OVEC is not consolidated into the financial statements of LG&E.  LG&E and 11 other electric utilities are participating owners of OVEC, located in Piketon, Ohio. OVEC owns and operates two power plants that burn coal to generate electricity, Kyger Creek Station in Ohio and Clifty Creek Station in Indiana.  LG&E’s share is 7%, representing approximately 155 Mw of generation capacity.

 

LG&E’s original investment in OVEC was made in 1952. As of December 31, 2004, LG&E’s investment in OVEC totaled $0.5 million.  In March 2005, LG&E purchased from AEP an additional 0.73% interest in OVEC for a purchase price of approximately $0.1 million, which resulted in an increase in LG&E ownership in OVEC from 4.9% to 5.63%.  LG&E’s investment in OVEC 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 the investments.  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 11 of LG&E’s Notes to Financial Statements under Item 8 for further discussion of developments regarding LG&E’s ownership interest and power purchase rights.

 

FSP 106-2

 

In May 2004, the FASB finalized FSP 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“Medicare Act”) with guidance on accounting for subsidies provided under the Medicare Act which became law in December 2003.  FSP No. 106-2 is effective for the first interim or annual period beginning after June 15, 2004.  FSP 106-2 does not have a material impact on LG&E.

 

FSP 109-1

 

In December 2004, the FASB finalized FSP 109-1, Accounting for Income Taxes, Application of FAS 109 to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004, which requires the tax deduction on qualified production activities to be treated as a special deduction in accordance with FAS 109.  FSP 109-1 became effective December 21, 2004, and does not have a material impact on LG&E.

 

42



 

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, 2004, LG&E is in a negative working capital position in part because of the classification of certain variable-rate pollution control bonds 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 had to access these facilities.  LG&E 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 $171.6 million, $163.3 million and $212.4 million in 2004, 2003, and 2002, respectively.  The 2004 increase of $8.3 million compared to 2003 resulted largely from the reduction in pension funding of $54.6 million, higher gas supply cost recovery of $15.0 million, higher earnings sharing mechanism of $10.1 million and receipt of a litigation settlement of $7.0 million. These increases were largely offset by a reduction in accounts receivable of $66.3 million, including the termination of the accounts receivable securitization program, and a reduction in accrued income taxes of $22.4 million. The 2003 decrease compared to 2002 of $49.1 million resulted primarily from pension funding in 2003 of $89.1 million and an increase in accounts receivable balances of $33.4 million, including the sale of accounts receivable through the accounts receivable securitization program, partially offset by an increase in accounts payable and accrued income taxes of $35.0 million and $36.0 million, respectively.  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 $148.3 million, $213.0 million and $220.4 million in 2004, 2003, and 2002, respectively.  LG&E expects its capital expenditures for 2005 and 2006 to total approximately $268 million, which consists primarily of construction estimates associated with the redevelopment of the Ohio Falls hydro facility, totaling $19.6 million, construction of Trimble County Unit 2, totaling $8.8 million, and on-going construction related to generation and distribution assets.

 

Net cash used for investing activities decreased $64.6 million in 2004 compared to 2003, primarily due to the level of construction expenditures.  NOx equipment expenditures were approximately $5.3 million in 2004 and $29.6 million in 2003, while CT expenditures were approximately $8.1 million in 2004 and $71.4 million in 2003.    Net cash used for investing activities decreased $7.2 million in 2003 compared to 2002 primarily due to the level of construction expenditures.

 

Financing Activities

 

Net cash inflows (outflows) for financing activities were $(18.3) million in 2004, $34.2 million in 2003 and $22.5 million in 2002.

 

In January 2004, LG&E entered into two long-term loans from Fidelia, one totaling $25 million with an interest

 

43



 

rate of 4.33% that matures in January 2012, and one totaling $100 million with an interest rate of 1.53% that matured in January 2005.  The loans are collateralized by a pledge of substantially all assets of LG&E that is subordinated to the first mortgage bond lien. The proceeds were used to fund a pension contribution and to repay other debt obligations.  In April 2004, LG&E prepaid $50 million of the $100 million 1.53% note payable to Fidelia.  The prepayment was paid out of cash balances.  The remaining $50 million under this note was paid at maturity in January 2005.

 

In November 2003, LG&E issued $128 million variable-rate pollution control bonds due October 1, 2033, and exercised its call option on the $102 million, 5.625% pollution control bonds due August 15, 2019 and on the $26 million, 5.45% pollution control bonds due October 15, 2020.

 

During 2003, LG&E entered into two long-term loans from Fidelia totaling $200 million.  $100 million of this total is unsecured and the remaining $100 million is collateralized by a pledge of substantially all assets of LG&E that is subordinated to the first mortgage bond lien.

 

LG&E first mortgage bond, 6% Series of $42.6 million matured in August 2003 and was retired.

 

In March 2002, LG&E refinanced its $22.5 million and $27.5 million unsecured pollution control bonds, both due September 1, 2026.  The replacement bonds, due September 1, 2026, are variable-rate bonds and are secured by first mortgage bonds. LG&E also refinanced its two $35 million unsecured pollution control bonds due November 1, 2027.  The replacement variable-rate bonds are secured by pollution control series bonds treated as first mortgage bonds and will mature November 1, 2027.

 

In October 2002, LG&E issued $41.7 million variable-rate pollution control bonds due October 1, 2032, and exercised its call option on $41.7 million, 6.55% pollution control bonds due November 1, 2020.

 

Under the provisions of certain variable-rate pollution control bonds totaling $246.2 million, the bonds are subject to tender for purchase by LG&E 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.  Backup credit facilities totaling $185 million are in place to fund such tenders if necessary.  LG&E has never had to access these facilities.

 

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.  The Company 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 LG&E Energy and 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.

 

Certain regulatory approvals are required for the Company to incur additional debt.  The SEC authorizes the issuance of short-term debt while the Kentucky Commission authorizes issuance of long-term debt.  As of December 31, 2004 the Company has received approvals from the SEC to borrow up to $400 million in short-term funds.

 

44



 

LG&E’s debt ratings as of December 31, 2004, 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, 2004.  LG&E anticipates cash from operations and external financing will be sufficient to fund future obligations.

 

(in thousands)

 

Payments Due by Period

 

Contractual Cash Obligations

 

2005

 

2006

 

2007

 

2008

 

2009

 

Thereafter

 

Total

 

Short-term debt (a)

 

$

58,220

 

$

 

$

 

$

 

$

 

$

 

$

58,220

 

Long-term debt

 

297,450

 

1,250

 

1,250

 

18,750

 

 

553,104

(b)

871,804

 

Operating lease (c)

 

3,469

 

3,538

 

3,609

 

3,681

 

3,754

 

22,375

 

40,426

 

Unconditional power purchase obligations (d)

 

11,230

 

10,098

 

9,726

 

9,932

 

10,145

 

181,089

 

232,220

 

Coal and gas purchase obligations (e)

 

202,450

 

95,478

 

52,656

 

49,396

 

6,037

 

6,037

 

412,054

 

Retirement obligations (f)

 

9,250

 

10,106

 

13,305

 

10,992

 

15,839

 

 

59,492

 

Other long-term obligations (g)

 

14,767

 

 

 

 

 

 

14,767

 

Total contractual cash obligations

 

$

596,836

 

$

 120,470

 

$

80,546

 

$

92,751

 

$

35,775

 

$

762,605

 

$

1,688,983

 

 


(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 2005.

(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.

 

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

 

45



 

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, 2004, the maximum aggregate amount of default fees or amounts, which decrease over the term of the lease, was $9.5 million, of which LG&E would be responsible for $3.6 million (38%).  LG&E has made arrangements with LG&E Energy, via guarantee and regulatory commitment, for LG&E Energy to pay its 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 Notes 1 and 4 of LG&E’s Notes to Financial Statements under Item 8.

 

Interest Rate Sensitivity

 

LG&E has short-term and long-term variable-rate debt obligations outstanding.  At December 31, 2004, 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 after the impact of interest rate swaps.

 

Interest rate swaps are used to hedge LG&E’s underlying variable-rate debt obligations.  These swaps hedge specific debt issuances and, consistent with management’s designation, are accorded hedge accounting treatment.  See Note 4 of LG&E’s Notes to Financial Statements under Item 8.

 

As of December 31, 2004, LG&E had swaps with a combined notional value of $228.3 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 $25.7 million as of December 31, 2004.  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.

 

Commodity Price Sensitivity

 

LG&E has limited exposure to market price volatility in prices of fuel and electricity, since its retail tariffs include the FAC and GSC commodity price pass-through mechanisms.  LG&E is exposed to market price volatility of fuel and electricity in its wholesale activities.

 

Energy Trading & Risk Management Activities

 

LG&E conducts energy trading and risk management activities to maximize the value of power sales from physical assets it owns, in addition to the wholesale sale of excess asset capacity.  Certain energy trading activities are accounted for on a mark-to-market basis in accordance with SFAS No. 133, SFAS No. 138 and SFAS No. 149.  Wholesale sales of excess asset capacity are treated as normal sales under these pronouncements and are not marked to market.  To be eligible for the normal sales exclusion under SFAS No. 133, sales are limited to the forecasted excess capacity of LG&E’s generation assets over what is needed to serve native load.  To be eligible for the normal purchases exclusion under SFAS No. 133 purchases must be used to serve LG&E’s

 

46



 

native load.  Without the normal sales and purchases exclusion these transactions would be considered derivatives and marked to market under SFAS No. 133.

 

The rescission of EITF No. 98-10 for fiscal periods ending after December 15, 2002, had no impact on LG&E’s energy trading and risk management reporting as all forward and option contracts marked to market under EITF No. 98-10 are also within the scope of SFAS No. 133.

 

The table below summarizes LG&E’s energy trading and risk management activities for 2004 and 2003:

 

(in thousands)

 

2004

 

2003

 

Fair value of contracts at beginning of period, net asset (liability)

 

$

572

 

$

(156

)

Fair value of contracts when entered into during the period

 

(75

)

2,654

 

Contracts realized or otherwise settled during the period

 

(858

)

(569

)

Changes in fair values due to changes in assumptions

 

164

 

(1,357

)

Fair value of contracts at end of period, net (liability) asset

 

$

(197

)

$

572

 

 

No changes to valuation techniques for energy trading and risk management activities occurred during 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 not result in a change of a material amount.  All contracts outstanding at December 31, 2004, 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, 2004, 100% of the trading and risk management commitments were with counterparties rated BBB-/Baa3 equivalent or better.

 

Accounts Receivable Securitization

 

On February 6, 2001, LG&E implemented an accounts receivable securitization program.  LG&E terminated the accounts receivable securitization program in January 2004, and in May 2004, dissolved its inactive accounts receivable securitization-related subsidiary, LG&E R. The purpose of this program was to enable LG&E to accelerate the receipt of cash from the collection of retail accounts receivable, thereby reducing dependence upon more costly sources of working capital.  The securitization program allowed for a percentage of eligible receivables to be sold.  Eligible receivables were generally all receivables associated with retail sales that had standard terms and were not past due.  LG&E was able to terminate the program at any time without penalty.

 

As part of the program, LG&E sold retail accounts receivable to LG&E R.  Simultaneously, LG&E R entered into two separate three-year accounts receivable securitization facilities with two financial institutions and their affiliates whereby LG&E R could sell, on a revolving basis, an undivided interest in certain of its receivables and receive up to $75 million from unrelated third-party purchasers.  The effective cost of the receivables program was comparable to LG&E’s lowest cost source of capital, and was based on prime rated commercial paper.  LG&E retained servicing rights of the sold receivables through two separate servicing agreements with the third-party purchasers.  LG&E obtained an opinion from independent legal counsel indicating these transactions qualified as a true sale of receivables.

 

To determine LG&E’s retained interest, the proceeds on the sale of receivables to the financial institutions was netted against the amount of eligible receivables sold by LG&E to LG&E R.  Interest expense, program fees,

 

47



 

and facility fees paid to the financial institutions and an allowance for doubtful accounts were deducted to arrive at the future value of retained interest.  The future value was discounted using the prime rate plus 25 basis points, assuming a 45-day receivable life.  No material pre-tax gains or losses from the sale of the receivables occurred in 2004, 2003, and 2002.  LG&E’s net cash flows from LG&E R were $(58.1) million, $(6.2) million, and $20.2 million for 2004, 2003 and 2002, respectively.

 

The allowance for doubtful accounts associated with the eligible securitized receivables at December 31, 2003 and 2002 was $1.4 million and $1.9 million, respectively.  This allowance was based on historical experience of LG&E. Each securitization facility contained a fully funded reserve for uncollectible receivables.

 

RATES AND REGULATION

 

LG&E is subject to the jurisdiction of the Kentucky Commission in virtually all matters related to electric and gas utility regulation, and as such, its accounting is subject to 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 of LG&E’s Notes to Financial Statements under Item 8.

 

Electric and Gas Rate Cases.  In December 2003, LG&E filed applications with the Kentucky Commission requesting adjustments in LG&E’s electric and gas rates.  LG&E requested general adjustments in electric and gas rates based on the twelve month test year ended September 30, 2003.  The revenue increases requested were $63.8 million for electric and $19.1 million for gas.

 

In June 2004, the Kentucky Commission issued an order approving increases in the base electric and gas rates of LG&E.  The Kentucky Commission’s order largely accepted proposed settlement agreements filed in May 2004 by LG&E and a majority of the parties to the rate case proceedings.   The rate increases took effect on July 1, 2004.

 

In the Kentucky Commission’s order, LG&E was granted increases in annual base electric rates of approximately $43.4 million (7.7%) and in annual base gas rates of approximately $11.9 million (3.4%).  Other provisions of the order include decisions on certain depreciation, gas supply clause, ECR and VDT amounts or mechanisms and a termination of the ESM with respect to all periods after 2003.  The order also provided for a recovery before March 31, 2005, by LG&E of previously requested amounts relating to the ESM during 2003.

 

During July 2004, the AG served subpoenas on LG&E, as well as on 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. The Kentucky Commission has procedurally reopened the rate cases for the limited purpose of taking evidence, if any, as to the communication issues. Subsequently, the AG filed pleadings with the Kentucky Commission requesting rehearing of the rate cases on certain computational components of the increased rates, including income tax, 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, with the effect that the rate increase order is final as to these matters, subject to the parties’ rights to judicial appeals. The Kentucky Commission further agreed to hold in abeyance further proceedings in the rate cases, including the AG’s concerns about alleged improper communications, until the AG could file with the Kentucky Commission an investigative report regarding the latter issue. In addition, the Kentucky Commission granted a rehearing on the income tax component once the abeyance discussed above is lifted.

 

In September and October 2004, various proceedings were held in circuit courts in Franklin and Jefferson Counties, Kentucky regarding the scope and timing of document production or other information required or

 

48



 

agreed to be produced under the AG’s subpoenas and matters were consolidated into the Franklin County court. In October 2004, the AG filed a motion with the Kentucky Commission requesting that the previously granted rate increases be set aside, that LG&E resubmit any applications for rate increases and that relevant Kentucky Commission personnel be recused from participation in rate case proceedings.  In November 2004, the Franklin County, Kentucky court denied an AG request for sanctions on LG&E relating to production matters and narrowed the AG’s permitted scope of discovery.   In January 2005, the AG conducted interviews of certain Company individuals.

 

In January 2005, the AG submitted its report to the Franklin County, Kentucky Circuit Court in confidence.  Concurrently the AG filed a motion summarizing the report as containing evidence of improper communications and record-keeping errors by LG&E in its conduct of activities before the Kentucky Commission or other state governmental entities and requesting release of the report to such agencies.  During February 2005 the court ruled that the report be forwarded 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 cases, including ending the current abeyance.  To date, LG&E has neither seen nor requested copies of the report or its contents.

 

LG&E believes no improprieties have occurred in its communications with the Kentucky Commission and is cooperating 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 base rates.

 

VDT Costs - Kentucky Commission Settlement Order.  During the first quarter 2001, LG&E recorded a $144 million charge for a workforce reduction program.  Primary components of the charge were separation benefits, enhanced early retirement benefits, and healthcare benefits.  The result of this workforce reduction was the elimination of approximately 700 positions, accomplished primarily through a voluntary enhanced severance program.

 

In June 2001, LG&E filed an application (“VDT case”) with the Kentucky Commission to create a regulatory asset relating to these first quarter 2001 charges.  The application requested permission to amortize these costs over a four-year period.  The Kentucky Commission also opened a case to review a new depreciation study and resulting depreciation rates implemented in 2001.

 

In December 2001, the Kentucky Commission approved a settlement in the VDT case as well as other cases involving the depreciation rates and ESM.  The order approving the settlement allowed LG&E to set up a regulatory asset of $141 million for the workforce reduction costs and begin amortizing these costs over a five year period starting in April 2001.  The first quarter 2001 charge of $144 million represented all employees who had accepted a voluntary enhanced severance program.  Some employees rescinded their participation in the voluntary enhanced severance program, thereby decreasing the original charge to the regulatory asset from $144 million to $141 million.  The settlement reduces revenues approximately $26 million through a surcredit on bills to ratepayers over the same five-year period.  The surcredit represents net savings stipulated by LG&E.

 

As mentioned, the current five-year VDT amortization period is scheduled to expire in March 2006.  As part of the settlement agreements in the electric and gas rate cases, LG&E shall file with the Kentucky Commission a plan for the future ratemaking treatment of the VDT surcredits and costs six months prior to the March 2006 expiration.  The surcredit shall remain in effect following the expiration of the fifth year until the Commission enters an order on the future disposition of VDT-related issues.

 

49



 

Merger Surcredit.  As part of the LG&E Energy merger with KU Energy in 1998, LG&E Energy estimated non-fuel savings over a ten-year period following the merger.  Costs to achieve these savings for LG&E of $50.2 million were recorded in the second quarter of 1998, $18.1 million of which was deferred and amortized over a five-year period pursuant to regulatory orders.  Primary components of the merger costs were separation benefits, relocation costs, and transaction fees, the majority of which were paid by December 31, 1998.  LG&E expensed the remaining costs associated with the merger ($32.1 million) in the second quarter of 1998.

 

In approving the merger, the Kentucky Commission adopted LG&E’s proposal to reduce its retail customers’ bills based on one-half of the estimated merger-related savings, net of deferred and amortized amounts, over a five-year period.  The surcredit mechanism provides that 50% of the net non-fuel cost savings estimated to be achieved from the merger be provided to ratepayers through a monthly bill credit, and 50% be retained by 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 Kentucky 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 and lower point for rate of return on equity, whereby if LG&E’s rate of return for the calendar year fell within the range of 10.5% to 12.5%, no action was necessary.  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 and interested parties had the opportunity to provide recommendations for modification and continuance of the ESM or other forms of alternative or incentive regulation.

 

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.

 

On June 30, 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 will continue 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 relating to all periods after 2003.

 

As a result of the settlement, LG&E accrued an additional $4.1 million in June 2004, related to 2003 ESM revenue.

 

FAC.  LG&E’s retail electric rates contain a FAC, whereby increases or decreases in the cost of fuel for electric generation are reflected in the rates charged to retail electric customers.  In January 2003, the Kentucky

 

50



 

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 is due in May 2005.

 

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 is expected in April 2005.  LG&E is seeking to increase the fuel component of base rates.  LG&E does not anticipate any issues will arise during the regulatory proceeding.

 

DSM.  LG&E’s rates contain a DSM provision.  The provision includes a rate mechanism that provides concurrent recovery of DSM costs and provides an incentive for implementing DSM programs.  This provision allowed LG&E to recover revenues from lost sales associated with the DSM programs.  In May 2001, the Kentucky Commission approved LG&E’s plan to continue DSM programs.  This plan called for the expansion of the LG&E DSM programs into the service territory served by KU and proposed a mechanism to recover revenues from lost sales associated with DSM programs based on program plan engineering estimates and post-implementation evaluations.

 

Gas Supply Cost PBR Mechanism.   Since November 1, 1997, LG&E has operated under an experimental PBR mechanism related to its gas procurement activities.   LG&E’s rates are adjusted annually to recover its portion of the savings (or expenses) incurred during each PBR year (12 months ending October 31). Since its implementation on November 1, 1997, through October 31, 2004, LG&E has achieved $60.7 million in savings. Of that total savings amount, LG&E’s portion has been $22.7 million and the ratepayers’ portion has been $38.0 million.  Pursuant to the extension of LG&E’s gas supply cost PBR mechanism effective November 1, 2001, the sharing mechanism under PBR requires savings (and expenses) to be shared 25% with shareholders and 75% with ratepayers up to 4.5% of the benchmarked gas costs.  Savings (and expenses) in excess of 4.5% of the benchmarked 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.

 

ECR.  In May 2002, the Kentucky Commission initiated a periodic two-year review of LG&E’s environmental surcharge.  The review included the operation of the surcharge mechanism, determination of the appropriateness of costs included in the surcharge mechanism, recalculation of the cost of debt to reflect actual costs for the period under review, final determination of the amount of environmental revenues over-collected from customers, and a final determination of the amount of environmental costs and revenues to be “rolled-in” to base rates.  A final order was issued in October 2002, in which LG&E was ordered to refund $0.3 million to customers over the four month period beginning November 2002 and ending February 2003.  Additionally, LG&E was ordered to roll $4.1 million into base rates and make corresponding adjustments to the monthly environmental surcharge filings to reflect that portion of environmental rate base now included in base rates.

 

In August 2002, LG&E filed an application with the Kentucky Commission to amend its compliance plan to

 

51



 

allow recovery of the cost of new and additional environmental compliance facilities.  The estimated capital cost of the additional facilities is $71.1 million. A final order was issued in February 2003, approving recovery of four new environmental compliance facilities totaling $43.1 million.  A fifth project, expansion of the landfill facility at the Mill Creek Station, was denied without prejudice with an invitation to reapply for recovery when required construction permits are approved.  Cost recovery through the environmental surcharge of the four approved projects began with bills rendered in April 2003.

 

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 on a going-forward basis.  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 the cost of new and additional environmental compliance facilities, including the expansion of the Mill Creek landfill. The estimated capital cost of the additional facilities is $40.2 million.  LG&E requested an overall rate of return of 10.72%, including an 11% return on common equity.  A final order in the case is anticipated in June 2005.

 

MISO.   LG&E is a founding member of the MISO.  Membership was obtained in 1998 in response to and consistent with federal policy initiatives.  In February 2002, LG&E turned over operational control of its high voltage transmission facilities (100kV and above) to the MISO.  The MISO currently controls over 100,000 miles of transmission over 1.1 million square miles located in the northern Midwest between Manitoba, Canada and Kentucky.  In September 2002, FERC granted a 12.88% ROE on transmission facilities for LG&E and the rest of the MISO owners.  On February 18, 2005, the United States Court of Appeals for the District of Columbia Circuit ruled that FERC did not provide proper notice that it would consider an incentive adder of 50 basis points, but affirmed the September 2002 FERC order in all other respects.  Effective ROE, retroactive to February 1, 2002, is 12.38% for LG&E and the original MISO owners.

 

In October 2001, the FERC issued an order requiring that the bundled retail load and grandfathered wholesale load of each member transmission owner be included in the current calculation of the MISO’s “cost-adder,” the Schedule 10 charges designed to recover the MISO’s costs of operation, including start-up capital (debt) costs.  LG&E, along with several other transmission owners, opposed the FERC’s ruling on this matter. The opposition was rejected by the FERC in 2002.   Later that year, the MISO’s transmission owners, appealed the FERC’s decision to the United States Court of Appeals for the District of Columbia Circuit.  In response, in November 2002, the FERC requested that the Court issue a partial remand of its challenged orders to allow the FERC to revisit certain issues, and requested that the case be held in abeyance pending the agency’s resolution of such issues.  The Court granted the FERC’s petition in December 2002.   In February 2003, FERC issued an order reaffirming its position concerning the calculation of the Schedule 10 charges and in July 2003 denied a rehearing.  LG&E, along with several other transmission owners, again petitioned the District Court of

 

52



 

Columbia Circuit for review. In July 2004 the court affirmed the FERC ruling.

 

In August 2004, the MISO filed its FERC-required proposed Transmission and Energy Markets Tariff (“TEMT”).  In September and October 2004, many MISO-related parties (including LG&E) filed proposals with the FERC regarding pending MISO-filed changes to transmission pricing principles, including the TEMT and elimination of Regional Through and Out Rates (“RTORs”). Additional filings of the companies before FERC in September 2004 sought to address issues relating to the treatment of certain “grandfathered” transmission agreements (“GFA’s”) should TEMT become effective. The utility proposals generally seek to appropriately delay the RTORs and TEMT effective dates based upon errors in administrative or procedural processes used by FERC or to appropriately limit potential reductions in transmission revenues received by the utilities should the RTORs, TEMT or GFA structures be implemented.  At present, existing FERC orders conditionally approve elimination of RTORs and implementation of general TEMT rates in the MISO by spring 2005.  At this time, LG&E cannot predict the outcome or effects of the various FERC proceedings described above, including whether such will have a material impact on the financial condition or results of operations of the companies. Financial consequences (changes in transmission revenues and costs) associated with the upcoming transmission market tariff changes are subject to varying assumptions and calculations and are therefore difficult to estimate. Changes in revenues and costs related to broader shifts in energy market practices and economics are not currently estimable.  Should LG&E be ordered to exit MISO, current MISO rules may also impose an exit fee.  LG&E is not able to predict the estimated outcome or economic impact of any of the MISO-related matters.  While LG&E believes legal and regulatory precedent should permit most or many of the MISO-related costs to be recovered in their rates charged to customers, they can give no assurance that state or federal regulators will ultimately agree with such position with respect to all costs, components or timing of recovery.

 

The MISO plans to implement a Day-ahead and Real-time market, including a congestion management system in April 2005. This system will be similar to the Locational Marginal Pricing (“LMP”) system currently used by the PJM RTO and contemplated in FERC’s SMD NOPR, currently being discussed.  The MISO filed with FERC a mechanism for recovery of costs for the congestion management system.  They proposed the addition of two new Schedules, 16 and 17.  Schedule 16 is the MISO’s cost recovery mechanism for the Financial Transmission Rights Administrative Service it will provide.  Schedule 17 is the MISO’s mechanism for recovering costs it will incur for providing Energy Marketing Support Administrative Service.  The MISO transmission owners, including LG&E, have objected to the allocation of costs among market participants and retail native load. FERC ruled in 2004 in favor of the MISO.

 

The Kentucky Commission opened an investigation into LG&E’s membership in the MISO in July 2003. The Kentucky Commission directed LG&E to file testimony addressing the costs and benefits of the MISO membership both currently and over the next five years and other legal issues surrounding continued membership.  LG&E engaged an independent third-party to conduct a cost benefit analysis on this issue.  The information was filed with the Kentucky Commission in September 2003.  The analysis and testimony supported the exit from the MISO, under certain conditions.  The MISO filed its own testimony and cost benefit analysis in December 2003.  A final Kentucky Commission order was expected in the second quarter of 2004; that ruling has since been delayed until summer 2005 due to the Kentucky Commission’s request for additional testimony on the MISO’s Market Tariff filing at FERC.

 

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 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.

 

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 will be 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

 

53



 

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.  The Kentucky Commission must provide its Strategic Blueprint to the Governor in early August 2005.  LG&E must respond to the Kentucky Commission’s first set of data requests by the end of March 2005.

 

FERC SMD NOPR.  In July 2002, the FERC issued a NOPR in Docket No. RM01-12-000 which would substantially alter the regulations governing the nation’s wholesale electricity markets by establishing a common set of rules, defined as SMD. The SMD NOPR would require each public utility that owns, operates, or controls interstate transmission facilities to become an Independent Transmission Provider (“ITP”), belong to an RTO that is an ITP, or contract with an ITP for operation of its transmission assets. It would also establish a standardized congestion management system, real-time and day-ahead energy markets, and a single transmission service for network and point-to-point transmission customers. Review of the proposed rulemaking is underway and no time frame has been established by the FERC for adoption of a final rule.  While it is expected that the SMD final rule will affect LG&E’s revenues and expenses, the specific impact of the rulemaking is not known at this time.

 

Kentucky Commission Administrative Case for Affiliate Transactions.  In December 1997, the Kentucky Commission opened Administrative Case No. 369 to consider Kentucky Commission policy regarding cost allocations, affiliate transactions and codes of conduct governing the relationship between utilities and their non-utility operations and affiliates.  The Kentucky Commission intended to address two major areas in the proceedings: the tools and conditions needed to prevent cost shifting and cross-subsidization between regulated and non-utility operations; and whether a code of conduct should be established to assure that non-utility segments of the holding company are not engaged in practices that could result in unfair competition caused by cost shifting from the non-utility affiliate to the utility.  In early 2000, the Kentucky General Assembly enacted legislation, House Bill 897, which authorized the Kentucky Commission to require utilities that provide nonregulated activities to keep separate accounts and allocate costs in accordance with procedures established by the Kentucky Commission.  In the same bill, the General Assembly set forth provisions to govern a utility’s activities related to the sharing of information, databases, and resources between its employees or an affiliate involved in the marketing or the provision of nonregulated activities and its employees or an affiliate involved in the provision of regulated services. The legislation became law in July 2000 and LG&E has been operating pursuant thereto since that time.  In February 2001, the Kentucky Commission published notice of their intent to promulgate new administrative regulations under the auspices of the new law.  This effort is still ongoing.

 

Wholesale Natural Gas Prices.  On September 12, 2000, the Kentucky Commission issued an order establishing Administrative Case No. 384 – “An Investigation of Increasing Wholesale Natural Gas Prices and the Impacts of such Increase on the Retail Customers Served by Kentucky’s Jurisdictional Natural Gas Distribution Companies”.

 

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, consider performance-based ratemaking mechanisms, and to increase the use of storage.

 

In May 2004, in Case No. 2004-148, LG&E proposed a hedge plan for the 2004/2005 winter heating season relying upon LG&E’s storage to mitigate customer exposure to price volatility. In August 2004, the Kentucky Commission approved LG&E’s proposed hedge plan, validating the effectiveness of storage to mitigate potential volatility associated with high winter 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.

 

54



 

Environmental Matters.   LG&E is subject to SO2 and NOx emission limits on its electric generating units pursuant to the Clean Air Act.  LG&E was exempt from Phase I SO2 requirements due to its low emission rates. LG&E opted into the Phase I NOx program to take advantage of the less stringent requirements and installed burner modifications as needed to meet these limitations.  LG&E’s strategy for Phase II SO2 reductions, which commenced January 1, 2000, is to increase FGD removal efficiency to delay additional capital expenditures and may also include fuel switching or upgrading FGDs.  LG&E met the NOx emission requirements of the Act through installation of low-NOx burner systems.  LG&E’s compliance plans are subject to many factors including developments in the emission allowance and fuel markets, future regulatory and legislative initiatives, and advances in clean air control technology.  LG&E will continue to monitor these developments to ensure that its environmental obligations are met in the most efficient and cost-effective manner.

 

In September 1998, the EPA announced its final “NOx SIP Call” rule requiring states to impose significant additional reductions in NOx emissions by May 2003, in order to mitigate alleged ozone transport impacts on the Northeast region.  The Commonwealth of Kentucky SIP, which was approved by the EPA on June 24, 2003, requires reductions in NOx emissions from coal-fired generating units to the 0.15 lb./MMBtu level on a system-wide basis.  In related proceedings in response to petitions filed by various Northeast states, in December 1999, the EPA issued a final rule pursuant to Section 126 of the Clean Air Act directing similar NOx reductions from a number of specifically targeted generating units including all LG&E units.  As a result of appeals to both rules, the compliance date was extended to May 31, 2004.  All LG&E generating units are in compliance with these NOx emissions reduction rules.

 

LG&E has added significant NOx controls to its generating units through the installation of SCR systems, advanced low-NOx burners and neural networks.  The NOx controls project commenced in late 2000 with the controls being placed into operation prior to the 2004 Summer Ozone Season. As of December 31, 2004, LG&E incurred total capital costs of approximately $186 million to reduce its NOx emissions below the 0.15 lb./MMBtu level on a company-wide basis.  In addition, LG&E will incur additional operating and maintenance costs in operating new NOx controls.  LG&E believes its costs in this regard to be comparable to those of similarly situated utilities with like generation assets. LG&E anticipated that such capital and operating costs are the type of costs that are eligible for recovery from customers under its environmental surcharge mechanism and believed that a significant portion of such costs could be recovered.  In April 2001, the Kentucky Commission granted recovery of these costs for LG&E.

 

LG&E is also monitoring several other air quality issues which may potentially impact coal-fired power plants, including EPA’s revised air quality standards for ozone and particulate matter, measures to implement EPA’s regional haze rule, and EPA’s Clean Air Mercury Rule which regulates mercury emissions from steam electric generating units and reductions in emissions of SO2 and NOx required under the Clean Air Interstate Rule.  In addition, LG&E has worked with local regulatory authorities to review the effectiveness of remedial measures aimed at controlling particulate matter emissions from its Mill Creek Station.  LG&E previously settled a number of property damage claims from adjacent residents and completed significant remedial measures as part of its ongoing capital construction program. LG&E has converted the Mill Creek Station to wet stack operation in an effort to resolve all outstanding issues related to particulate matter emissions.

 

LG&E owns or formerly owned three properties which are the location of past MGP operations.  Various contaminants are typically found at such former MGP sites and environmental remediation measures are frequently required.  With respect to the sites, LG&E has completed cleanups, obtained regulatory approval of site management plans, or reached agreements for other parties to assume responsibility for cleanup.  Based on currently available information, management estimates that it could incur additional costs of $0.4 million for additional cleanup.  Accordingly, an accrual for this amount has been recorded in the accompanying financial

 

55



 

statements at December 31, 2004 and 2003.

 

See Note 11 of LG&E’s Notes to Financial Statements under Item 8 for an additional discussion of environmental issues.

 

FUTURE OUTLOOK

 

Competition and Customer Choice

 

In the last several years, LG&E has taken many steps to keep its rates low while maintaining high levels of

 

56



 

customer satisfaction, including a reduction in the number of employees; aggressive cost cutting; an increase in focus on commercial, industrial and residential customers; an increase in employee involvement and training; and continuous modifications of its organizational structure.  LG&E will take additional steps to better position itself should retail competition come to Kentucky.

 

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 will be 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.  The Kentucky Commission must provide its Strategic Blueprint to the Governor in early August 2005.  LG&E must respond to the Kentucky Commission’s first set of data requests by the end of March 2005.

 

57



 

KU

 

RESULTS OF OPERATIONS

 

Net Income

 

KU’s net income in 2004 increased $42.1 million (46.0%) 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.  Offsetting the increase somewhat were $2.7 million in operating expenses related to severe May and July storms in 2004.

 

KU’s net income in 2003 decreased $2.0 million (2.1%) compared to 2002.  The decrease resulted primarily from increased depreciation expense due to plant additions, partially offset by increased sales to retail and wholesale customers.

 

Revenues

 

The following table presents a comparison of operating revenues for the years 2004 and 2003 with the immediately preceding year.

 

(in thousands)

 

Increase (Decrease)
From Prior Period

 

Cause

 

2004

 

2003

 

Retail sales:

 

 

 

 

 

Fuel clause adjustments

 

$

7,549

 

$

20,959

 

KU/LG&E Merger surcredit

 

(2,593

)

(1,254

)

Environmental cost recovery surcharge

 

6,276

 

6,038

 

Earnings sharing mechanism

 

7,749

 

8,718

 

Demand side management

 

1,011

 

365

 

VDT surcredit

 

(486

)

(1,740

)

Rate and rate structure

 

21,694

 

 

Variation in sales volumes, and other

 

24,575

 

(1,755

)

Provision for rate collections (refunds)

 

13,285

 

(24,015

)

Total retail sales

 

79,060

 

7,316

 

Wholesale sales

 

21,999

 

20,751

 

Other

 

2,525

 

2,047

 

Total

 

$

103,584

 

$

30,114

 

 

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.

 

Electric revenues increased in 2003 primarily due to an increase in the recovery of fuel costs passed through the FAC and higher wholesale sales.  Retail volumes decreased 0.2% as lower sales due to a milder summer than the previous year were offset by higher sales during the winter, when weather was colder than the previous year.Cooling degree days for 2003 decreased 38% from 2002 and were 21% below the 20-year average while heating degree days increased 3% from 2002 and were 3% above the 20-year average.  Wholesale revenues

 

58



 

increased due to a combination of a 28.6% increase in volumes and 3.8% higher prices.

 

The provision for rate collections (refunds) increased $13.3 million in 2004. This increase resulted primarily from fuel ($18.1 million) and ECR ($12.8 million) accruals partially offset by a decrease in the ESM ($17.6 million) accruals. The decrease in the provision for rate collections (refunds) in 2003 from 2002 ($24.0 million) results primarily from a decrease in the ESM accruals ($13.5 million), a decrease in 2003 fuel accruals ($6.0 million), and a decrease in ECR accruals during 2003 ($4.5 million).

 

Expenses

 

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

 

Fuel for electric generation increased $26.1 million (9.8%) in 2004 because of a 6% increase in the cost of fuel burned ($16.8 million) and an increase in generation ($9.3 million).   Fuel for electric generation increased $15.8 million (6.3%) in 2003 because of an increase in the cost of fuel burned ($18.9 million), partially offset by a decrease in generation ($3.1 million).   The average delivered cost per MMBtu of coal purchased was $1.56 in 2004, $1.47 in 2003 and $1.35 in 2002.

 

Power purchased expense in 2004 increased $4.2 million (3.0%) over 2003, primarily due to an increase in purchases to meet off-system sales requirements ($5.1 million) partially offset by a decrease in purchase price ($0.9 million).    Power purchased expense in 2003 increased $8.7 million (6.6%) over 2002, primarily due to an increase in purchases to meet off-system sales requirements ($15.1 million) partially offset by a decrease in purchase price ($6.4 million).

 

Other operation and maintenance expenses increased $0.8 million (0.4%) in 2004.

 

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).

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

                  Increased combustion turbine operations expense ($0.9 million); 2003 included Alstom settlement payments, lowering expense.

 

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); 2003 included Alstom settlement payments, lowering expense.

                  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

 

59



 

through June 2009.  KU earns a return of these amortized costs, which are included in KU’s jurisdictional operating expenses.

 

Property and other taxes increased $0.8 million (4.8%) in 2004 primarily due to:

                  Increased property taxes of $0.6 million.

                  Increased payroll taxes of $0.3 million.

 

Other operations and maintenance expenses decreased $0.2 million (0.1%) in 2003.

 

Other operation expenses increased $1.5 million (1.0%) in 2003 primarily due to:

                  Increased employee benefits costs ($4.7 million).

                  Increased property insurance expenses ($1.4 million).

                  Decreased amortization of regulatory assets ($4.7 million).

 

Maintenance expenses decreased $2.6 million (4.2%) in 2003 primarily due to:

                  Decreased steam generation and combustion turbine generation maintenance due to cancellation and postponement of scheduled outages ($5.1 million).

                  Decreased communications maintenance expenses ($1.0 million).

                  Increased maintenance to electric distribution equipment due to an ice storm ($4.1 million, net of $8.9 million in insurance recoveries).

 

Property and other taxes increased $0.9 million (6.0%) in 2003 primarily due to:

                  Increased property taxes ($0.5 million)

                  Increased Kentucky Commission assessment ($0.4 million).

 

Depreciation and amortization increased $6.8 million (6.7%) in 2004 and $6.3 million (6.6%) in 2003 primarily due to an increase in plant in service.

 

Other income - net increased $3.0 million (66.2%) in 2004.  In 2003, write-offs of $1.3 million decreased other income (see below).  In addition, 2004 miscellaneous non-operating income was $0.6 million higher and gains related to sale of property were $0.4 million higher. Other income - net decreased $1.9 million (30.1%) in 2003 due primarily to a decrease in earnings from KU’s equity earnings in a minority interest ($3.4 million) and write-off from CWIP for terminated plant projects ($1.0 million) and a terminated software project ($0.6 million), partially offset by a decrease in benefit costs ($1.3 million) and an increase in AFUDC income ($1.0 million) associated primarily with construction on NOx and CT projects.

 

Total interest expense increased $0.3 million (1.0%) in 2004 due primarily to increased borrowing from Fidelia ($9.0 million), partially offset by savings from retired first mortgage debt ($4.4 million), lower cost of interest rate swaps ($3.5 million) and reduced borrowing from the money pool ($0.8 million).

 

Total interest expense decreased $0.4 million (1.7%) in 2003 due primarily to savings from lower average interest rates on variable-rate long-term bonds ($9.0 million) and an increase in interest income from interest rate swaps ($0.8 million), offset by interest expense on new fixed-rate debt with Fidelia ($4.7 million) and additional expenses recognized from mark-to-market adjustments of underlying debt associated with the interest rate swaps ($5.1 million).

 

The weighted average interest rate on variable-rate long-term bonds for 2004, 2003 and 2002 was 1.32%, 1.07% and 1.56%, respectively.  At December 31, 2004, 2003 and 2002, KU’s percentage of long-term bonds having a

 

60



 

variable-rate, including the impact of interest rate swaps, was 48.6% at $349.0 million, 53.6% at $386.6 million and 73.8% at $369.5 million, respectively.  KU’s weighted average cost of long-term debt, including amortization of debt expense and interest rate swaps, was 3.43%, 2.96%, and 3.30% at December 31, 2004, 2003, and 2002, respectively.  See Note 9 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 2004 effective income tax rate increased to 36.4% from the 35.4% rate in 2003.  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 operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies applied has not changed.  Specific risks for these critical accounting policies are described in the following paragraphs.  Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions.  Events rarely develop exactly as forecast and the best estimates routinely require adjustment.  See also Note 1 of KU’s Notes to Financial Statements under Item 8.

 

Financial Instruments - KU uses over-the-counter interest-rate swap agreements to hedge its exposure to interest rates.  Gains and losses on interest-rate swaps used to hedge interest rate risk are reflected in interest charges monthly.  KU uses sales of market-traded electric forward contracts for periods less than one year to hedge the price volatility of its forecasted peak electric off-system sales.  Gains and losses resulting from ineffectiveness are shown in other income (expense) and to the extent that the hedging relationship has been effective, gains and losses are reflected in other comprehensive income.  Wholesale sales of excess asset capacity and wholesale purchases to be used to serve native load are treated as normal sales and purchases under SFAS No. 133, SFAS No. 138 and SFAS No. 149 and are not marked-to-market.   See Note 4 and Note 14 of KU’s Notes to Financial Statements under Item 8.

 

Unbilled Revenue – At each month end KU prepares a financial estimate that projects electric usage that has been used by customers, but not billed.  The estimated usage is based on 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, 2004, a 10% change in these estimated quantities would cause revenue and accounts receivable to change by approximately $4.8 million.  See also Note 1 of KU’s Notes to Financial Statements under Item 8.

 

Allowance for Doubtful Accounts - At December 31, 2004 and 2003, the KU allowance for doubtful accounts

 

61



 

was $0.6 million and $0.7 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.

 

Benefit Plan Accounting - KU’s costs of providing defined-benefit pension retirement plans is dependent upon a number of factors, such as the rates of return on plan assets, healthcare cost trend rates, discount rate, contributions made to the plan, and other actuarial assumptions used to value benefit obligations.  In  2002, KU was required to recognize a minimum liability of $17.5 million as prescribed by SFAS No. 87 Employers’ Accounting for Pensions since the fair value of the plan assets was less than the accumulated benefit obligation at that time.  During 2002, the combination of poor market performance and historically low corporate bond rates created a divergence in the potential value of the pension liabilities and the actual value of the pension assets.  The liability was recorded as a reduction to other comprehensive income, and did not affect net income.  In 2003, KU recognized a reduction of the minimum pension liability of $7.7 million.  During 2004, KU recognized an additional minimum pension liability of $12.4 million.  If the fair value of the plan assets exceeds the accumulated benefit obligation, the recorded liability will be reduced and other comprehensive income will be restored in the consolidated balance sheet.

 

Should poor market conditions return, these conditions could result in an increase in KU’s unfunded accumulated benefit obligations and future pension expense.  The primary assumptions that drive the value of the unfunded accumulated benefit obligations are the discount rate and expected return on plan assets.

 

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

 

 

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Discount rate

 

6.25

%

6.75

%

7.25

%

Expected long-term return on plan assets

 

8.50

%

9.00

%

9.50

%

Rate of compensation increase

 

3.50

%

3.75

%

4.25

%

 

KU made contributions to the pension plan of $43.4 million in January 2004 and $10.2 million during 2003.

 

A 1% increase or decrease in the assumed discount rate could have an approximate $26.8 million positive or negative impact to the accumulated benefit obligation of KU.

 

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

 

Regulatory Mechanisms – Judgments and uncertainties include future regulatory decisions, the impact of deregulation and competition on the ratemaking process and external regulator decisions.

 

Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates based upon Kentucky Commission orders.  Regulatory liabilities generally represent obligations to make refunds to customers for previous collections based upon orders by the Kentucky Commission.  Management believes, based on orders, the existing regulatory assets and liabilities are probable of recovery.   This determination reflects the current regulatory climate in the state.  If future recovery of costs ceases to be probable the assets would be required to be recognized in current period earnings.

 

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 many transactions for which the ultimate tax outcome is uncertain. 

 

To provide for these uncertainties or exposures, an allowance is maintained for tax contingencies, the balance of which management believes is adequate.  Tax contingencies are analyzed periodically and adjustments are made when events occur to warrant a change. The company is currently in the examination phase of IRS audits for the years 1999 to 2003 and expects some or all of these audits to be completed within the next 12 months.  The results of audit assessments by taxing authorities are not anticipated to have a material adverse effect on cash flows or results of operations.

 

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 generation taxable income in 2005. On a stand-alone basis, KU expects to generate a deduction in 2005 which will reduce KU’s effective tax rate by less than 1%. See Note 1 and Note 7 of KU’s Notes to Financial Statements under Item 8.

 

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.  The impact of these reduced rates is expected to decrease KU’s income tax expense in future periods.  Furthermore, these reduced rates will result in the reversal of accumulated temporary differences at lower rates than originally provided.  KU is presently evaluating the impact of this and other changes to the Kentucky tax system, however, no material adverse impacts on cash flows or results of operations are expected.

 

KU is subject to periodic changes in state tax law, regulation or interpretation, as well as enforcement proceedings.  KU is currently undergoing a routine Kentucky sales tax audit for the period January 1996 to July 2000.  The possible assessment or amount at issue is not known at this time, but is not expected to have a material adverse effect on cashflows or results of operations. 

 

See Note 1 and Note 7 of KU’s Notes to Financial Statements under Item 8.

 

Deferred Income Taxes - KU expects to have adequate levels of taxable income to realize its recorded deferred tax assets.  See Note 7 of KU’s Notes to Financial Statements under Item 8 for a breakdown of deferred tax assets.   

 

62



 

NEW ACCOUNTING PRONOUNCEMENTS

 

The following recent accounting pronouncements affected KU in 2004 and 2003:

 

SFAS No. 143

 

SFAS No. 143 was issued in 2001.  SFAS No. 143 establishes accounting and reporting standards for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.

 

The effective implementation date for SFAS No. 143 was January 1, 2003.  Management has calculated the impact of SFAS No. 143 and FERC Final Order No. 631 issued in Docket No. RM02-7.  As of January 1, 2003, KU recorded ARO assets in the amount of $8.6 million and liabilities in the amount of $18.5 million.  KU also recorded a cumulative effect adjustment in the amount of $9.9 million to reflect the accumulated depreciation and accretion of ARO assets at the transition date less amounts previously accrued under regulatory depreciation.  KU recorded offsetting regulatory assets of $9.9 million, pursuant to regulatory treatment prescribed under SFAS No. 71.  Also pursuant to SFAS No. 71, KU recorded regulatory liabilities in the amount of $0.9 million offsetting removal costs previously accrued under regulatory accounting in excess of amounts allowed under SFAS No. 143.

 

Had SFAS No. 143 been in effect for the 2002 reporting period, KU would have established asset retirement obligations as described in the following table:

 

(in thousands)

 

 

 

Provision at January 1, 2002

 

$

17,331

 

Accretion expense

 

1,146

 

Provision at December 31, 2002

 

$

18,477

 

 

As of December 31, 2004, KU recorded ARO assets, net of accumulated depreciation, of $6.7 million and liabilities of $21.0 million.  As of December 31, 2003, KU had ARO assets, net of accumulated depreciation, of $6.9 million and liabilities of $19.7 million.  KU recorded offsetting regulatory assets of $12.8 million and $11.3 million and regulatory liabilities of $1.4 million and $1.2 million as of December 31, 2004 and 2003, respectively.

 

For the year ended December 31, 2004, KU recorded ARO accretion expense of $1.3 million, ARO depreciation expense of $0.2 million and an offsetting regulatory credit in the income statement of $1.5 million, pursuant to regulatory treatment prescribed under SFAS No. 71. For the year ended December 31, 2003, KU recorded ARO accretion expense of $1.2 million, ARO depreciation expense of $0.2 million and an offsetting regulatory credit in the income statement of $1.4 million.  SFAS No. 143 has no impact on the results of operations of KU.

 

KU AROs are primarily related to final retirement of assets associated with generating units.  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, 2004 and 2003, KU recorded $0.3 million for both periods in 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.

 

KU also continues to include a cost of removal component in depreciation for assets that do not have a legal ARO. As of December 31, 2004 and 2003, KU has segregated this cost of removal, embedded in accumulated

 

63



 

depreciation, of $266.8 million and $256.7 million, respectively, in accordance with FERC Order No. 631.  For reporting purposes in its Consolidated Balance Sheets included in Item 8, KU has presented this cost of removal as a regulatory liability pursuant to SFAS No. 71.

 

KU transmission and distribution lines largely operate under perpetual property easement agreements which do not generally require restoration upon removal of the property.  Therefore, under SFAS No. 143, no material asset retirement obligations are recorded for transmission and distribution assets.

 

EITF No. 02-03

 

KU adopted EITF No. 98-10 effective January 1, 1999.  This pronouncement required that energy trading contracts be marked to market on the balance sheet, with the gains and losses shown net in the income statement.  Effective January 1, 2003, KU adopted EITF No. 02-03.  EITF No. 02-03 established the following:

 

                  Rescinded EITF No. 98-10,

                  Contracts that do not meet the definition of a derivative under SFAS No. 133 should not be marked to fair market value, and

                  Revenues should be shown in the income statement net of costs associated with trading activities, whether or not the trades are physically settled.

 

With the rescission of EITF No. 98-10, energy trading contracts that do not also meet the definition of a derivative under SFAS No. 133 must be accounted for as executory contracts.  Contracts previously recorded at fair value under EITF No. 98-10 that are not also derivatives under SFAS No. 133 must be restated to historical cost through a cumulative effect adjustment.  The rescission of this standard had no impact on financial position or results of operations of KU since all forward and option contracts marked to market under EITF No. 98-10 were also within the scope of SFAS No. 133.

 

As a result of EITF No. 02-03, KU has netted the power purchased expense for trading activities against electric operating revenue to reflect this accounting change.  KU applied this guidance to previously reported 2002 balances as shown below. The reclassifications had no impact on previously reported net income or common equity.

 

(in thousands)

 

 

 

 

Gross electric operating revenues as previously reported

 

$

888,219

 

 

Less costs reclassified from power purchased

 

26,555

 

 

Net electric operating revenues

 

$

861,664

 

 

 

 

 

 

 

Gross power purchased as previously reported

 

$

157,955

 

 

Less costs reclassified to revenues

 

26,555

 

 

Net power purchased

 

$

131,400

 

 

SFAS No. 150

 

In May 2003, the Financial Accounting Standards Board issued SFAS No. 150, which was effective immediately for financial instruments entered into or modified after May 31, 2003, and otherwise was effective for interim reporting periods beginning after June 15, 2003, except for certain instruments and certain entities which have been deferred by the FASB.  Such deferrals do not affect KU.

 

KU has no financial instruments that fall within the scope of SFAS No. 150.

 

64



 

FIN 46

 

In January 2003, the Financial Accounting Standards Board issued FIN 46.  FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties.  FIN 46 was effective immediately for all new variable interest entities created or acquired after January 31, 2003.  For variable interest entities created or acquired prior to February 1, 2003, the provisions of FIN 46 must have been applied for the first interim or annual period beginning after June 15, 2003.

 

In December 2003, FIN 46 was revised, delaying the effective dates for certain entities created before February 1, 2003, and making other amendments to clarify application of the guidance.  For potential variable interest entities other than special purpose entities, FIN 46R was required to be applied no later than the end of the first fiscal year or interim reporting period ending after March 15, 2004.  The original guidance under FIN 46 was applicable, however, for all special purpose entities created prior to February 1, 2003, at the end of the first interim or annual reporting period ending after December 15, 2003.  FIN 46R may be applied prospectively with a cumulative-effect adjustment as of the date it is first applied, or by restating previously issued financial statements with a cumulative-effect adjustment as of the beginning of the first year restated.  FIN 46R also requires certain disclosures of an entity’s relationship with variable interest entities. The adoption of FIN 46 and FIN 46R had no impact on the financial position or results of operations for KU.

 

Although KU holds investment interests in OVEC and EEI, it is not the primary beneficiary of OVEC or EEI, and, therefore, neither are consolidated into the financial statements of KU.  KU and 11 other electric utilities are participating owners of OVEC, located in Piketon, Ohio.  OVEC owns and operates two power plants that burn coal to generate electricity, Kyger Creek Station in Ohio and Clifty Creek Station in Indiana.  KU’s share is 2.5%, representing approximately 55 Mw of generation capacity.

 

KU’s original investment in OVEC was made in 1952.  KU’s investment in OVEC is the equivalent of 2.5% of OVEC’s common stock and is accounted for under the cost method of accounting.  As of December 31, 2004, KU’s investment in OVEC totaled $0.3 million. KU’s maximum exposure to loss as a result of the involvement with OVEC is limited to the value of the investments.  In the event of the inability of OVEC to fulfill its power provision requirements, KU 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 11 of KU’s Notes to Financial Statements under Item 8 for further discussion of developments regarding KU’s ownership interests and power purchase rights.

 

KU owns 20% of the common stock of EEI, which owns and operates a 1,000-Mw generating station in southern Illinois.  KU is entitled to take 20% of the available capacity of the station.  Purchases from EEI are made under a contractual formula which has resulted in costs which were and are expected to be comparable to the cost of other power generated by KU.  This contract governing the purchases from EEI will terminate on December 31, 2005.  Such power equated to approximately 10% of KU’s net generation system output in 2004.

 

KU’s original investment in EEI was made in 1953.  KU’s investment in EEI is accounted for under the equity method of accounting and, as of December 31, 2004, totaled $13.4 million.  KU’s direct exposure to loss as a result of its involvement with EEI is generally limited to the value of its investment.  In the event of the inability of EEI to fulfill its power provision requirements, KU would substitute such power supply with either owned generation or market purchases and would generally recover associated incremental costs through regulatory

 

65



 

rate mechanisms.

 

FSP 106-2

 

In May 2004, the FASB finalized FSP 106-2 with guidance on accounting for subsidies provided under the Medicare Act which became law in December 2003.  FSP 106-2 is effective for the first interim or annual period beginning after June 15, 2004.  FSP 106-2 does not have a material impact on KU.

 

FSP 109-1

 

In December 2004, the FASB finalized FSP 109-1, which requires the tax deduction on qualified production activities to be treated as a special deduction in accordance with FAS 109.  FSP 109-1 became effective December 21, 2004, and does not have a material impact on KU.

 

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, 2004, KU is in a negative working capital position in part because of the classification of certain variable-rate pollution control bonds 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 $185.9 million, $233.4 million and $175.8 million 2004, 2003, and 2002, respectively.  The 2004 decrease compared to 2003 of $47.5 million was primarily due to an increase in accounts receivable of $63.0 million, including the termination of the accounts receivable securitization program, additional pension funding of $33.2 million and lower environmental cost recovery of $14.2 million. These decreases were partially offset by higher earnings of $42.1 million, higher accounts payable of $13.5 million and receipt of a litigation settlement of $11.4 million. The 2003 increase compared to 2002 of $57.6 million was primarily the result of an increase in accrued income taxes of $19.4 million, an increase in deferred income taxes of $17.3 million, a decrease in pension funding of $6.5 million and the change in accounts receivable balances of $4.6 million, including the sale of accounts receivable through the accounts receivable securitization program.  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 $157.6 million, $341.9 million and $237.9 million in 2004, 2003 and 2002, respectively.  KU expects its capital expenditures for 2005 and 2006 to total approximately $448 million, which consists primarily of construction estimates associated with installation of FGDs on Ghent units, totaling $195.9 million, as described in the section titled “Environmental Matters,” the construction of Trimble County Unit 2, totaling $37.4 million, and on-going construction on generation and distribution assets.

 

66



 

Net cash used for investing activities decreased $185.2 million in 2004 compared to 2003 primarily due to the level of construction expenditures.  NOx expenditures were approximately $45.0 million in 2004 and $110.0 million in 2003, while CT expenditures were approximately $13.7 million in 2004 and $117.2 million in 2003. Net cash used for investment activities increased $107.5 million in 2003 compared to 2002 due to increased CT and NOx expenditures.

 

Financing Activities

 

Net cash inflows (outflows) from financing activities were $(30.6) million, $107.8 million and $64.2 million in 2004, 2003 and 2002, respectively.

 

In January 2004, KU entered into an unsecured long-term loan from Fidelia totaling $50 million with an interest rate of 4.39% that matures in January 2012.  The proceeds were used to fund a pension contribution and to repay other debt obligations.

 

In May 2004, KU redeemed $4.8 million of its Series 14 Pollution Control Bonds which were initially issued in the amount of $7.2 million.

 

In October 2004, KU completed a refinancing transaction regarding $50 million in existing pollution control indebtedness.  The original indebtedness, 5.75% Pollution Control Bonds, Series 9, due December 1, 2023, was discharged in November 2004, with the proceeds from the replacement indebtedness, KU Pollution Control Bonds, Series 17, due October 1, 2034, which carries a variable, auction rate of interest.  The call premium and unamortized debt expense of the Series 9 bonds are deferred assets being amortized over the life of the Series 17 bonds.

 

In June 2003, KU’s first mortgage bond, 6.32% Series Q of $62 million matured.

 

In November 2003, KU called its first mortgage bond, Series P 8.55% of $33 million, due in 2027, and replaced it with a loan from Fidelia.

 

During 2003, KU entered into four long-term loans from Fidelia totaling $283 million.  $100 million of this total is unsecured and the remaining $183 million is collateralized by a pledge of substantially all assets of KU that is subordinated to the first mortgage bond lien.

 

In May 2002, KU issued $37.9 million variable-rate pollution control Series 12, 13, 14 and 15 due February 1, 2032, and exercised its call option on $37.9 million, 6.25% pollution control Series 1B, 2B, 3B, and 4B due February 1, 2018.

 

In September 2002, KU issued $96 million variable-rate pollution control Series 16 due October 1, 2032, and exercised its call option on $96 million, 7.45% pollution control Series 8 due September 15, 2016.

 

Future Capital Requirements

 

Future capital requirements may be affected in varying degrees by factors such as 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.

 

67



 

KU has a variety of intercompany funding alternatives available to meet its capital requirements.  KU participates in an intercompany money pool agreement wherein LG&E Energy 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.

 

Certain regulatory approvals are required for the Company to incur additional debt.  The Virginia Commission and the SEC authorize the issuance of short-term debt while the Kentucky Commission, the Virginia Commission, and the Tennessee Regulatory Authority authorize issuance of long-term debt.  As of December 31, 2004 the Company has received approvals from the Virginia Commission and the SEC to borrow up to $400 million in short-term funds.

 

KU’s debt ratings as of December 31, 2004, 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, 2004.  KU anticipates cash from operations and external financing will be sufficient to fund future obligations.

 

(in thousands)

Contractual Cash Obligations

 

Payments Due by Period

 

 

2005

 

2006

 

2007

 

2008

 

2009

 

Thereafter

 

Total

 

Short-term debt (a)

 

$

 34,820

 

$

 —

 

$

 

$

 

$

 —

 

$

 

$

34,820

 

Long-term debt

 

162,130

 

36,000

 

58,088

 

 

 

469,993

(b)

726,211

 

Unconditional power purchase obligations (c)

 

40,098

 

41,141

 

42,625

 

43,690

 

45,138

 

655,720

 

868,412

 

Coal purchase obligations (d)

 

263,418

 

156,613

 

64,886

 

35,808

 

 

 

520,725

 

Retirement obligations (e)

 

6,564

 

6,915

 

7,236

 

7,479

 

7,757

 

 

35,951

 

Other long-term obligations (f)

 

14,771

 

 

 

 

 

 

14,771

 

Total contractual cash obligations

 

$

521,801

 

$

240,669

 

$

172,835

 

$

86,977

 

$

52,895

 

$

1,125,713

 

$

2,200,890

 

 


(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 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 2005.

(c)          Represents future minimum payments under OVEC, OMU and EEI 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.

 

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,

 

68



 

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, 2004, the maximum aggregate amount of default fees or amounts, which decrease over the term of the lease, was $9.5 million, of which KU would be responsible for $5.9 million (62%).  KU has made arrangements with LG&E Energy, via guarantee and regulatory commitment, for LG&E Energy to pay its 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 Notes 1 and 4 of KU’s Notes to Financial Statements under Item 8.

 

Interest Rate Sensitivity

 

KU has short-term and long-term variable-rate debt obligations outstanding.  At December 31, 2004, the potential change in interest expense associated with a 1% change in base interest rates of KU’s variable-rate debt is estimated at $3.8 million after the impact of interest rate swaps.

 

Interest rate swaps are used to hedge KU’s underlying debt obligations.  These swaps hedge specific debt issuances and, consistent with management’s designation, are accorded hedge accounting treatment.  See Note 4 of KU’s Notes to Financial Statements under Item 8.

 

As of December 31, 2004, KU has swaps with a combined notional value of $103 million.  The swaps exchange fixed-rate interest payments for floating rate interest payments on KU’s Series P and R first mortgage bonds.  The potential loss in fair value resulting from a hypothetical 1% adverse movement in base interest rates is estimated at $1.5 million as of December 31, 2004.  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 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 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 has limited exposure to market price volatility in prices of fuel and electricity, since its retail tariffs include the FAC commodity price pass-through mechanism.  KU is exposed to market price volatility of fuel and

 

69



 

electricity in its wholesale activities.

 

Energy Trading & Risk Management Activities

 

KU conducts energy trading and risk management activities to maximize the value of power sales from physical assets it owns, in addition to the wholesale sale of excess asset capacity.  Certain energy trading activities are accounted for on a mark-to-market basis in accordance with SFAS No. 133, SFAS No. 138 and SFAS No. 149. Wholesale sales of excess asset capacity are treated as normal sales under these pronouncements and are not marked to market.  To be eligible for the normal sales exclusion under SFAS No. 133, sales are limited to the forecasted excess capacity of KU’s generation assets over what is needed to serve native load.  To be eligible for the normal purchases exclusion under SFAS No. 133 purchases must be used to serve KU’s native load. Without the normal sales and purchases exclusion these transactions would be considered derivatives and marked to market under SFAS No. 133.

 

The rescission of EITF No. 98-10 for fiscal periods ending after December 15, 2002, had no impact on KU’s energy trading and risk management reporting as all forward and option contracts marked to market under EITF No. 98-10 are also within the scope of SFAS No. 133.

 

The table below summarizes KU’s energy trading and risk management activities for 2004 and 2003:

 

(in thousands)

 

2004

 

2003

 

Fair value of contracts at beginning of period, net asset (liability)

 

$

572

 

$

(156

)

Fair value of contracts when entered into during the period

 

(75

)

2,654

 

Contracts realized or otherwise settled during the period

 

(858

)

(569

)

Changes in fair values due to changes in assumptions

 

164

 

(1,357

)

Fair value of contracts at end of period, net (liability) asset

 

$

(197

$

572

 

 

No changes to valuation techniques for energy trading and risk management activities occurred during 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 not result in a change of a material amount.  All contracts outstanding at December 31, 2004 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, 2004, 100% of the trading and risk management commitments were with counterparties rated BBB-/Baa3 equivalent or better.

 

Accounts Receivable Securitization

 

On February 6, 2001, KU implemented an accounts receivable securitization program.  KU terminated the accounts receivable securitization program in January 2004, and in May 2004, dissolved its inactive accounts receivable securitization-related subsidiary, KU R. The purpose of this program was to enable KU to accelerate the receipt of cash from the collection of retail accounts receivable, thereby reducing dependence upon more costly sources of working capital. The securitization program allowed for a percentage of eligible receivables to be sold.  Eligible receivables were generally all receivables associated with retail sales that had standard terms and were not past due.  KU was able to terminate this program at any time without penalty.

 

70



 

As part of the program, KU sold retail accounts receivable to KU R.  Simultaneously, KU R entered into two separate three-year accounts receivable securitization facilities with two financial institutions and their affiliates whereby KU R could sell, on a revolving basis, an undivided interest in certain of its receivables and receive up to $50 million from unrelated third-party purchasers.  The effective cost of the receivable program was comparable to KU’s lowest cost source of capital, and was based on prime rated commercial paper.  KU retained servicing rights of the sold receivables through two separate servicing agreements with the third-party purchasers.  KU obtained an opinion from independent legal counsel indicating these transactions qualified as a true sale of receivables.

 

To determine KU’s retained interest, the proceeds on the sale of receivables to the financial institutions was netted against the amount of eligible receivables sold by KU to KU R.  Interest expense, program fees, and facility fees paid to the financial institutions and an allowance for doubtful accounts were deducted to arrive at the future value of retained interest.  The future value was discounted using the prime rate plus 25 basis points, assuming a 45-day receivable life.  No material pre-tax gains or losses from the sale of the receivables occurred during 2004, 2003 and 2002.  KU’s net cash flows from KU R were $(50.1) million, $(0.1) million and $3.3 million for 2004, 2003 and 2002, respectively.

 

The allowance for doubtful accounts associated with the eligible securitized receivables at December 31 was $0.5 million in 2003 and 2002.  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 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 the states of Kentucky and Virginia, KU has no plans or intentions to discontinue its application of SFAS No. 71.  See Note 3 of KU’s Notes to Financial Statements under Item 8.

 

Electric Rate Case. 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 year ended September 30, 2003.  The revenue increase requested was $58.3 million.

 

On June 30, 2004, the Kentucky Commission issued an order approving an increase in the base electric rates of KU.  The Kentucky Commission’s order largely accepted proposed settlement agreements filed in May 2004 by KU and a majority of the parties to the rate case proceedings.   The rate increases took effect on July 1, 2004.

 

In the Kentucky Commission’s order, KU was granted an increase in annual base electric rates of approximately $46.1 million (6.8%).  Other provisions of the order include decisions on certain depreciation, ECR and VDT amounts or mechanisms and a termination of the ESM with respect to all periods after 2003.  The order also provided for a recovery before March 31, 2005, by KU of previously requested amounts relating to the ESM during 2003.

 

During July 2004, the AG served subpoenas on KU, as well as on the Kentucky Commission and its staff, requesting information regarding allegedly improper communications between KU and the Kentucky Commission, particularly during the period covered by the rate case. The Kentucky Commission has procedurally reopened the rate cases for the limited purpose of taking evidence, if any, as to the communication

 

71



 

issues. Subsequently, the AG filed pleadings with the Kentucky Commission requesting rehearing of the rate case on certain computational components of the increased rates, including income tax, 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, with the effect that the rate increase order is final as to these matters, subject to the parties’ rights to judicial appeals. The Kentucky Commission further agreed to hold in abeyance further proceedings in the rate case, including the AG’s concerns about alleged improper communications, until the AG could file with the Kentucky Commission an investigative report regarding the latter issue. In addition, the Kentucky Commission granted a rehearing on the income tax component once the abeyance discussed above is lifted.

 

In September and October 2004, various proceedings were held in circuit courts in Franklin and Jefferson Counties, Kentucky regarding the scope and timing of document production or other information required or agreed to be produced under the AG’s subpoenas and matters were consolidated into the Franklin County court.  In October 2004, the AG filed a motion with the Kentucky Commission requesting that the previously granted rate increase be set aside, that KU resubmit any applications for rate increases and that relevant Kentucky Commission personnel be recused from participation in rate case proceedings.  In November 2004, the Franklin County, Kentucky court denied an AG request for sanctions on KU relating to production matters and narrowed the AG’s permitted scope of discovery.   In January 2005, the AG conducted interviews of certain Company individuals.

 

In January 2005, the AG submitted its report to the Franklin County, Kentucky Circuit Court in confidence.  Concurrently the AG filed a motion summarizing the report as containing evidence of improper communications and record-keeping errors by KU in its conduct of activities before the Kentucky Commission or other state governmental entities and requesting release of the report to such agencies.  During February 2005 the court ruled that the report be forwarded 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, including ending the current abeyance.  To date, KU has neither seen nor requested copies of the report or its contents.

 

KU believes no improprieties have occurred in its communications with the Kentucky Commission and is cooperating with the proceedings before the AG and the Kentucky Commission.

 

KU 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 increase in base rates.

 

VDT Costs - Kentucky Commission Settlement Order.  During the first quarter 2001, KU recorded a $64 million charge for a workforce reduction program.  Primary components of the charge were separation benefits, enhanced early retirement benefits, and healthcare benefits. The result of this workforce reduction was the elimination of approximately 300 positions, accomplished primarily through a voluntary enhanced severance program.

 

In June 2001, KU filed an application (VDT case) with the Kentucky Commission to create a regulatory asset relating to these first quarter 2001 charges.  The application requested permission to amortize these costs over a four-year period.  The Kentucky Commission also opened a case to review a new depreciation study and resulting depreciation rates implemented in 2001.

 

In December 2001, the Kentucky Commission approved a settlement in the VDT case as well as other cases

 

72



 

involving the depreciation rates and ESM.  The order approving the settlement allowed KU to set up a regulatory asset of $54 million for the workforce reduction costs and begin amortizing these costs over a five-year period starting in April 2001. The first quarter 2001 charge of $64 million represented all employees who had accepted a voluntary enhanced severance program.  Some employees rescinded their participation in the voluntary enhanced severance program which, along with the non-recurring charge of $6.9 million for FERC and Virginia jurisdictions, decreased the original charge to the regulatory asset from $64 million to $54 million. The settlement reduces revenues approximately $11 million through a surcredit on bills to ratepayers over the same five-year period.  The surcredit represents net savings stipulated  by KU.

 

As mentioned, the current five-year VDT amortization period is scheduled to expire in March 2006.  As part of the settlement agreements in the electric and gas rate cases, KU shall file with the Kentucky Commission a plan for the future ratemaking treatment of the VDT surcredits and costs six months prior to the March 2006 expiration.  The surcredit shall remain in effect following the expiration of the fifth year until the Commission enters an order on the future disposition of VDT-related issues.

 

Merger Surcredit.  As part of the LG&E Energy merger with KU Energy in 1998, LG&E Energy estimated non-fuel savings over a ten-year period following the merger.  Costs to achieve these savings for KU of $42.3 million were recorded in the second quarter of 1998, $20.5 million of which was deferred and amortized over a five-year period pursuant to regulatory orders.  Primary components of the merger costs were separation benefits, relocation costs, and transaction fees, the majority of which were paid by December 31, 1998.  KU expensed the remaining costs associated with the merger ($21.8 million) in the second quarter of 1998.

 

In approving the merger, the Kentucky Commission adopted KU’s proposal to reduce its retail customers’ bills based on one-half of the estimated merger-related savings, net of deferred and amortized amounts, over a five-year period.  The surcredit mechanism provides that 50% of the net non-fuel cost savings estimated to be achieved from 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 Kentucky Commission required LG&E and KU, after the end of the five-year period, to present a plan for sharing with customers the then-projected non-fuel savings associated with the merger.  The Companies submitted this filing 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. KU’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, KU’s Kentucky retail electric rates were subject to an ESM.  The ESM, initially in place for three years beginning in 2000, set an upper and lower point for rate of return on equity, whereby if KU’s rate of return for the calendar year fell within the range of 10.5% to 12.5%, no action was necessary.  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.

 

In November 2002, KU 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.  KU and interested parties had the opportunity to provide recommendations for modification and continuance of the ESM or other forms of alternative or incentive regulation.

 

73



 

KU filed its final 2003 ESM calculations with the Kentucky Commission on March 1, 2004, and applied for recovery of $16.2 million. Based upon estimates, KU previously accrued $9.3 million for the 2003 ESM as of December 31, 2003.

 

On June 30, 2004, the Kentucky Commission issued an order largely accepting proposed settlement agreements by KU and all intervenors regarding the ESM.  Under the ESM settlements, KU will continue to collect approximately $16.2 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.

 

As a result of the settlement, KU accrued an additional $6.9 million in June 2004, related to 2003 ESM revenue.

 

FAC.  KU’s Kentucky retail electric rates contain a FAC, whereby increases or 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 for the six month period ended October 31, 2001. The Kentucky Commission ordered KU to reduce its fuel costs for purposes of calculating its FAC by $0.7 million. At issue was the purchase of approximately 102,000 tons of coal from Western Kentucky Energy Corporation, a non-regulated affiliate, for use at KU’s Ghent facility. The Kentucky Commission further ordered that an independent audit be conducted to examine operational and management aspects of both KU’s and LG&E’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 KU and the Kentucky Commission Staff in the second quarter of 2004.  KU filed its first Audit Progress Report with the Kentucky Commission Staff in November 2004.  A second Audit Progress Report is due in May 2005.

 

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.  KU also employs a FAC mechanism for Virginia customers that 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.  No other significant issues have been identified as a result of these reviews.

 

In December 2004, the Kentucky Commission initiated a two-year review of KU’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 is expected in April 2005.  KU is seeking to increase the fuel component of base rates.  KU does not anticipate any issues will arise during the regulatory proceeding.

 

In February 2005, KU filed with the Virginia Commission an application seeking approval of an increase in its fuel cost factor to reflect higher fuel costs incurred.   KU anticipates implementing the increased fuel cost factor with April 2005 billings.

 

DSM.  In May 2001, the Kentucky Commission approved a plan that would expand LG&E’s DSM programs into the service territory served by KU.  The plan included a rate mechanism that provided for concurrent recovery of DSM costs, provided an incentive for implementing DSM programs, and recovered revenues from lost sales associated with the DSM programs based on program plan engineering estimates and post-implementation evaluations.

 

ECR.  In August 2002, KU filed an application with the Kentucky Commission to amend its compliance plan to

 

74



 

allow recovery of the cost of a new and additional environmental compliance facilities.  The estimated capital cost of the additional facilities is $17.3 million.  A final order was issued in February 2003. The final order approved recovery of the new environmental compliance facility totaling $17.3 million.  Cost recovery through the environmental surcharge of the approved project commenced with bills rendered in April 2003.

 

In March 2003, the Kentucky Commission initiated a series of six-month and two-year reviews of the operation of KU’s Environmental Surcharge.  A final order was issued in October 2003, resolving all outstanding issues related to over-recovery from customers and under-recovery of allowed O&M expense.  The Commission found that KU had over-collected a net $6.0 million from customers and ordered the refund to occur through adjustments to the calculation of the monthly surcharge billing factor over the subsequent 12 month period.  The Kentucky Commission further ordered KU to roll $17.9 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.  The rates of return for KU’s 1994 and post-1994 plans were reset to 1.24% and 12.60%, respectively.

 

In June 2004, the Kentucky Commission issued an order approving a settlement agreement that, among other things, revised the rate of return for KU’s post-1994 plan to 11.19%, with an 11% return on common equity.  The order also approved the elimination of KU’s 1994 Plan for its ECR billing mechanism, with all remaining costs associated with that plan to be included in their entirety in base rates.

 

In December 2004, KU filed an application with the Kentucky Commission for approval of a CCN to construct new SO2 control technology (FGDs) at the Ghent and Brown stations, and to amend its compliance plan to allow recovery of costs associated with new and additional environmental compliance facilities.  The estimated capital cost of the additional facilities is $702.5 million, of which $658.9 million is for the FGDs.  A final order in the case is expected in June 2005.

 

MISO.  KU is a founding member of the MISO.  Membership was obtained in 1998 in response to and consistent with federal policy initiatives.  In February 2002, KU turned over operational control of its high voltage transmission facilities (100kV and above) to the MISO.  The MISO currently controls over 100,000 miles of transmission over 1.1 million square miles located in the northern Midwest between Manitoba, Canada and Kentucky.  In September 2002, FERC granted a 12.88% ROE on transmission facilities for KU and the rest of the MISO owners.  On February 18, 2005, the United States Court of Appeals for the District of Columbia Circuit ruled that FERC did not provide proper notice that it would consider an incentive adder of 50 basis points, but affirmed the September 2002 FERC order in all other respects.  Effective ROE, retroactive to February 1, 2002, is 12.38% for KU and the original MISO owners.

 

In October 2001, the FERC issued an order requiring that the bundled retail load and grandfathered wholesale load of each member transmission owner be included in the current calculation of the MISO’s “cost-adder,” the Schedule 10 charges designed to recover the MISO’s costs of operation, including start-up capital (debt) costs.  KU, along with several other transmission owners, opposed the FERC’s ruling on this matter. The opposition was rejected by the FERC in 2002.   Later that year, the MISO’s transmission owners, appealed the FERC’s decision to the United States Court of Appeals for the District of Columbia Circuit.  In response, in November 2002, the FERC requested that the Court issue a partial remand of its challenged orders to allow the FERC to revisit certain issues, and requested that the case be held in abeyance pending the agency’s resolution of such issues.  The Court granted the FERC’s petition in December 2002.   In February 2003, FERC issued an order reaffirming its position concerning the calculation of the Schedule 10 charges and in July 2003 denied a rehearing. KU, along with several other transmission owners, again petitioned the District Court of Columbia Circuit for review. In July 2004, the court affirmed the FERC ruling.

 

75



 

 

In August 2004, the MISO filed its FERC-required proposed TEMT.  In September and October 2004, many MISO-related parties (including KU) filed proposals with the FERC regarding pending MISO-filed changes to transmission pricing principles, including the TEMT and elimination of RTORs. Additional filings of the companies before FERC in September 2004 sought to address issues relating to the treatment of certain GFA's should TEMT become effective. The utility proposals generally seek to appropriately delay the RTORs and TEMT effective dates based upon errors in administrative or procedural processes used by FERC or to appropriately limit potential reductions in transmission revenues received by the utilities should the RTORs, TEMT or GFA structures be implemented.  At present, existing FERC orders conditionally approve elimination of RTORs and implementation of general TEMT rates in the MISO by spring 2005.  At this time, KU cannot predict the outcome or effects of the various FERC proceedings described above, including whether such will have a material impact on the financial condition or results of operations of the companies. Financial consequences (changes in transmission revenues and costs) associated with the upcoming transmission market tariff changes are subject to varying assumptions and calculations and are therefore difficult to estimate. Changes in revenues and costs related to broader shifts in energy market practices and economics are not currently estimable.  Should KU be ordered to exit MISO, current MISO rules may also impose an exit fee.  KU is not able to predict the estimated outcome or economic impact of any of the MISO-related matters.  While KU believes legal and regulatory precedent should permit most or many of the MISO-related costs to be recovered in their rates charged to customers, they can give no assurance that state or federal regulators will ultimately agree with such position with respect to all costs, components or timing of recovery.

 

The MISO plans to implement a Day-ahead and Real-time market, including a congestion management system in April 2005. This system will be similar to the LMP system currently used by the PJM RTO and contemplated in FERC’s SMD NOPR, currently being discussed.  The MISO filed with FERC a mechanism for recovery of costs for the congestion management system.  They proposed the addition of two new Schedules, 16 and 17.  Schedule 16 is the MISO’s cost recovery mechanism for the Financial Transmission Rights Administrative Service it will provide.  Schedule 17 is the MISO’s mechanism for recovering costs it will incur for providing Energy Marketing Support Administrative Service.  The MISO transmission owners, including KU, have objected to the allocation of costs among market participants and retail native load. FERC ruled in 2004 in favor of the MISO.

 

The Kentucky Commission opened an investigation into KU’s membership in the MISO in July 2003. The Kentucky Commission directed KU to file testimony addressing the costs and benefits of the MISO membership both currently and over the next five years and other legal issues surrounding continued membership.  KU engaged an independent third-party to conduct a cost benefit analysis on this issue.  The information was filed with the Kentucky Commission in September 2003.  The analysis and testimony supported the exit from the MISO, under certain conditions.  The MISO filed its own testimony and cost benefit analysis in December 2003.  A final Kentucky Commission order was expected in the second quarter of 2004; that ruling has since been delayed until summer 2005 due to the Kentucky Commission’s request for additional testimony on the MISO’s Market Tariff filing at FERC.

 

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 KU is responsibly addressing the long-term supply needs of native load customers and that current reserve margins are appropriate.  However, due to the rapid pace of change in the industry, the order also requires KU to provide an annual assessment of supply resources, future demand, reserve margin, and the need for new resources.

 

Regarding the transmission system, the Kentucky Commission concluded that the transmission system within Kentucky can reliably serve native load and a significant portion of the proposed new unregulated power plants. However, it will not be able to handle the volume of transactions envisioned by FERC without future upgrades, the costs of which should be borne by those for whom the upgrades are required.

 

The Kentucky Commission pledged to continue to monitor all relevant issues and advocate Kentucky’s interests at all opportunities.

 

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 will be 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

 

76



 

all jurisdictional utilities in Kentucky, including KU, pertaining to Kentucky electric generation, transmission and distribution systems.  The Kentucky Commission must provide its Strategic Blueprint to the Governor in early August 2005.  KU must respond to the Kentucky Commission’s first set of data requests by the end of March 2005.

 

FERC SMD NOPR.  In July 2002, the FERC issued a NOPR in Docket No. RM01-12-000 which would substantially alter the regulations governing the nation’s wholesale electricity markets by establishing a common set of rules, defined as SMD. The SMD NOPR would require each public utility that owns, operates, or controls interstate transmission facilities to become an ITP, belong to an RTO that is an ITP, or contract with an ITP for operation of its transmission assets. It would also establish a standardized congestion management system, real-time and day-ahead energy markets, and a single transmission service for network and point-to-point transmission customers. Review of the proposed rulemaking is underway and no time frame has been established by the FERC for adoption of a final rule.  While it is expected that the SMD final rule will affect KU’s revenues and expenses, the specific impact of the rulemaking is not known at this time.

 

Kentucky Commission Administrative Case for Affiliate TransactionsIn December 1997, the Kentucky Commission opened Administrative Case No. 369 to consider Kentucky Commission policy regarding cost allocations, affiliate transactions and codes of conduct governing the relationship between utilities and their non-utility operations and affiliates.  The Kentucky Commission intended to address two major areas in the proceedings: the tools and conditions needed to prevent cost shifting and cross-subsidization between regulated and non-utility operations; and whether a code of conduct should be established to assure that non-utility segments of the holding company are not engaged in practices that could result in unfair competition caused by cost shifting from the non-utility affiliate to the utility.  In early 2000, the Kentucky General Assembly enacted legislation, House Bill 897, which authorized the Kentucky Commission to require utilities that provide nonregulated activities to keep separate accounts and allocate costs in accordance with procedures established by the Kentucky Commission. In the same bill, the General Assembly set forth provisions to govern a utility’s activities related to the sharing of information, databases, and resources between its employees or an affiliate involved in the marketing or the provision of nonregulated activities and its employees or an affiliate involved in the provision of regulated services. The legislation became law in July 2000 and KU has been operating pursuant thereto since that time.  In February 2001, the Kentucky Commission published notice of their intent to promulgate new administrative regulation under the auspices of the new law.  This effort is still on going.

 

Environmental Matters.  KU is subject to SO2 and NOx emission limits on its electric generating units pursuant to the Clean Air Act.  KU met its Phase I SO2 requirements primarily through installation of FGD equipment on Ghent Unit 1 and through the consumption of emission allowances granted under the Clean Air Act.  KU’s strategy for Phase II SO2 reductions, which commenced January 1, 2000, has been to use accumulated emissions allowances to delay additional capital expenditures and will include fuel switching and the installation of additional FGDs as necessary. KU decided in December 2004 that additional FGDs will be necessary to maintain compliance with Phase II SO2 reductions.  Those installations are currently scheduled for completion in 2007-2009.   KU met the NOx emission requirements of the Act through installation of low-NOx burner systems. KU’s compliance plans are subject to many factors including developments in the emission allowance and fuel markets, future regulatory and legislative initiatives, and advances in clean air control technology.  KU will continue to monitor these developments to ensure that its environmental obligations are met in the most efficient and cost-effective manner.

 

In September 1998, the EPA announced its final “NOx SIP Call” rule requiring states to impose significant additional reductions in NOx emissions by May 2003, in order to mitigate alleged ozone transport impacts on the Northeast region.  The Commonwealth of Kentucky SIP, which was approved by the EPA on June 24, 2003,

 

77



 

requires reductions in NOx emissions from coal-fired generating units to the 0.15 lb./MMBtu level on a system-wide basis.  In related proceedings in response to petitions filed by various Northeast states, in December 1999, the EPA issued a final rule pursuant to Section 126 of the Clean Air Act directing similar NOx reductions from a number of specifically targeted generating units including all KU units in the eastern half of Kentucky.  Additional petitions currently pending before the EPA may potentially result in rules encompassing KU’s remaining generating units.  As a result of appeals to both rules, the compliance date was extended to May 31, 2004.  All KU generating units are in compliance with these NOx emissions reduction rules.

 

KU has added significant NOx controls to its generating units through the installation of SCR systems, advanced low-NOx burners and neural networks.  The NOx controls project commenced in late 2000 with the controls being placed into operation prior to the 2004 Summer Ozone Season. As of December 31, 2004, KU incurred total capital costs of approximately $219 million to reduce its NOx emissions below the 0.15 lb./MMBtu level on a company-wide basis.  In addition, KU will incur additional operating and maintenance costs in operating new NOx controls.  KU believes its costs in this regard to be comparable to those of similarly situated utilities with like generation assets. KU anticipated that such capital and operating costs are the type of costs that are eligible for recovery from customers under its environmental surcharge mechanism and believed that a significant portion of such costs could be recovered.  In April 2001, the Kentucky Commission granted recovery of these costs for KU.

 

KU is also monitoring several other air quality issues which may potentially impact coal-fired power plants, including EPA’s revised air quality standards for ozone and particulate matter, measures to implement EPA’s regional haze rule, and EPA’s Clean Air Mercury Rule which regulates mercury emissions from steam electric generating units and reductions in emissions of SO2 and NOx required under the Clean Air Interstate Rule.  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. FGD’s) commencing in mid 2005 and continuing through the final installation and operation in 2009.  KU estimates that it will incur $678 million in capital costs related to the reduction of its SO2 emissions to achieve compliance with current emission limits on a company-wide basis.  In addition, KU will incur additional operating and maintenance costs in operating new SO2 controls.  KU believes its costs in this regard to be comparable to those of similarly situated utilities with like generation assets.  KU anticipates that such capital and operating costs are the type of costs that are eligible for recovery from customers under its environmental surcharge mechanism and believes that a significant portion of such costs could be recovered.  In December 2004, KU filed an application seeking recovery of its costs. KU expects the Kentucky Commission to issue an Order granting recovery of these costs in June 2005.

 

KU owns or formerly owned several properties that were used for company or company-predecessor operations, including MGP’s, power production facilities and substations.  While KU has completed a cleanup of one such site in 1995, evaluations of these types of properties generally have not identified issues of significance.  With regard to these properties, KU is unaware of any imminent exposure or liability.

 

In October 1999, approximately 38,000 gallons of diesel fuel leaked from a cracked valve in an underground pipeline at KU’s E.W. Brown Station.  KU commenced immediate spill containment and recovery measures which continued under the oversight of EPA and state officials and prevented the spill from reaching the Kentucky River.  KU ultimately recovered approximately 34,000 gallons of diesel fuel.  In November 1999, the Kentucky Division of Water issued a notice of violation for the incident.  KU has settled all outstanding issues for this incident with the Commonwealth of Kentucky.  KU incurred costs of approximately $1.8 million and received insurance reimbursement of $1.2 million.  In December 2002, the Department of Justice (DOJ) sent correspondence to KU regarding a potential per-day fine for failure to timely submit a facility response plan and

 

78



 

a per-gallon fine for the amount of oil discharged.  During August 2004, KU, the EPA, and the Department of Justice agreed in principle to settle outstanding matters concerning the 1999 oil discharge at KU’s E.W. Brown plant for approximately $0.6 million. The settlement is subject to completion of final definitive documents but is anticipated to be resolved by the construction of a separate environmental capital project and a cash payment of approximately $0.2 million. At December 31, 2004, KU has recorded an accrual and expense to operations of $0.2 million.

 

In April 2002, the EPA sent correspondence to KU regarding potential exposure in connection with $1.5 million in completed remediation costs associated with a transformer scrap-yard.  KU believes it is one of the more remote parties, among a number of potentially responsible parties, and has entered into settlement discussions with the EPA and the Kentucky Division of Waste Management on this matter.

 

In January 2005, approximately 1,000 gallons of fuel oil leaked from a cracked weld in a storage tank at KU’s Green River Generating Station.  KU commenced immediate spill containment, recovery and remediation actions and has received satisfactory inspections from state regulators to date.  The cost related to the cleanup of the oil spill is expected to be immaterial.

 

See Note 11 of KU’s Notes to Financial Statements under Item 8 for an additional discussion of environmental issues.

 

Lock 7 License Matter.  KU's 1.8 Mw hydroelectric facility located at Lock No. 7 on the Kentucky River has been inactive since 1999.  In connection with a possible transfer of Lock No.7 and the dam at the site from the U.S. Army Corps of Engineers to the Kentucky River Authority, KU is seeking to surrender or transfer its FERC license governing the hydroelectric facility.  KU has entered into negotiations with a prospective third party acquirer for the license.  If KU is unable to successfully transfer the license, it may become or remain obligated for certain construction or demolition expenditures or other financial liabilities in the approximate amount of $4 million.

 

79



 

FUTURE OUTLOOK

 

Competition and Customer Choice

 

In the last several years, KU has taken many steps to keep its rates low while maintaining high levels of customer satisfaction, including a reduction in the number of employees; aggressive cost cutting; an increase in focus on commercial, industrial and residential customers; an increase in employee involvement and training; and continuous modifications of its organizational structure.  KU will take additional steps to better position itself should retail competition come to Kentucky.

 

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 will be 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.  The Kentucky Commission must provide its Strategic Blueprint to the Governor in early August 2005.  KU must respond to the Kentucky Commission’s first set of data requests by the end of March 2005.

 

Virginia has enacted a phase-in of customer choice through the Virginia Electric Restructuring Act.  The Virginia Commission is promulgating regulations to govern the various activities required by the Act.  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.

 

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.

 

80




 

INDEX OF ABBREVIATIONS

 

AFUDC

 

Allowance for Funds Used During Construction

ARO

 

Asset Retirement Obligation

Capital Corp.

 

LG&E Capital Corp.

Clean Air Act

 

The Clean Air Act, as amended in 1990

CCN

 

Certificate of Public Convenience and Necessity

CO2

 

Carbon Dioxide

CT

 

Combustion Turbines

CWIP

 

Construction Work in Progress

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

EPA

 

U.S. Environmental Protection Agency

ESM

 

Earnings Sharing Mechanism

F

 

Fahrenheit

FAC

 

Fuel Adjustment Clause

FERC

 

Federal Energy Regulatory Commission

FGD

 

Flue Gas Desulfurization

FPA

 

Federal Power Act

FT and FT-A

 

Firm Transportation

GSC

 

Gas Supply Clause

IBEW

 

International Brotherhood of Electrical Workers

IMEA

 

Illinois Municipal Electric Agency

IMPA

 

Indiana Municipal Power Agency

Kentucky Commission

 

Kentucky Public Service Commission

KIUC

 

Kentucky Industrial Utility Consumers, Inc.

KU

 

Kentucky Utilities Company

KU Energy

 

KU Energy Corporation

KU R

 

KU Receivables LLC

kV

 

Kilovolts

Kva

 

Kilovolt-ampere

KW

 

Kilowatts

Kwh

 

Kilowatt hours

LEM

 

LG&E Energy Marketing Inc.

LG&E

 

Louisville Gas and Electric Company

LG&E Energy

 

LG&E Energy LLC (as successor to LG&E Energy Corp.)

LG&E R

 

LG&E Receivables LLC

LG&E Services

 

LG&E Energy Services Inc.

LNG

 

Liquefied Natural Gas

Mcf

 

Thousand Cubic Feet

MGP

 

Manufactured Gas Plant

MISO

 

Midwest Independent Transmission System Operator

MMBtu

 

Million British thermal units

Moody’s

 

Moody’s Investor Services, Inc.

Mw

 

Megawatts

Mwh

 

Megawatt hours

NNS

 

No-Notice Service

NOPR

 

Notice of Proposed Rulemaking

NOx

 

Nitrogen Oxide

OATT

 

Open Access Transmission Tariff

OMU

 

Owensboro Municipal Utilities

OVEC

 

Ohio Valley Electric Corporation

PBR

 

Performance-Based Ratemaking

PJM

 

Pennsylvania, New Jersey, Maryland Interconnection

Powergen

 

Powergen Limited (formerly Powergen plc)

PUHCA

 

Public Utility Holding Company Act of 1935

 

82



 

ROE

 

Return on Equity

RTO

 

Regional Transmission Organization

S&P

 

Standard & Poor’s Rating Services

SCR

 

Selective Catalytic Reduction

SEC

 

Securities and Exchange Commission

SERP

 

Supplemental Executive Retirement Plan

SFAS

 

Statement of Financial Accounting Standards

SIP

 

State Implementation Plan

SMD

 

Standard Market Design

SO2

 

Sulfur Dioxide

Tennessee Gas

 

Tennessee Gas Pipeline Company

Texas Gas

 

Texas Gas Transmission LLC

Trimble County

 

LG&E’s Trimble County Unit 1

USWA

 

United Steelworkers of America

Utility Operations

 

Operations of LG&E and KU

VDT

 

Value Delivery Team Process

Virginia Commission

 

Virginia State Corporation Commission

Virginia Staff

 

Virginia State Corporation Commission Staff

WNA

 

Weather Normalization Adjustment

 

83



 

Louisville Gas and Electric Company and Subsidiary

Consolidated Statements of Income

(Thousands of $)

 

 

 

Years Ended December 31

 

 

 

2004

 

2003

 

2002

 

OPERATING REVENUES:

 

 

 

 

 

 

 

Electric (Note 14)

 

$

815,697

 

$

768,188

 

$

736,042

 

Gas

 

357,071

 

325,333

 

267,693

 

Total operating revenues (Note 1)

 

1,172,768

 

1,093,521

 

1,003,735

 

 

 

 

 

 

 

 

 

OPERATING EXPENSES:

 

 

 

 

 

 

 

Fuel for electric generation

 

207,092

 

196,965

 

194,900

 

Power purchased (Note 14)

 

92,047

 

79,621

 

61,881

 

Gas supply expenses

 

266,013

 

233,601

 

182,108

 

Other operation and maintenance expenses

 

306,008

 

291,295

 

285,991

 

Depreciation and amortization (Note 1)

 

116,577

 

113,287

 

105,906

 

Total operating expenses

 

987,737

 

914,769

 

830,786

 

 

 

 

 

 

 

 

 

Net operating income

 

185,031

 

178,752

 

172,949

 

 

 

 

 

 

 

 

 

Other income (expense) - net (Note 8 and Note 14)

 

(3,332

)

(7,193

)

(1,536

)

Interest expense (Notes 9 and 10)

 

20,545

 

23,863

 

27,630

 

Interest expense to affiliated companies (Note 14)

 

12,242

 

6,784

 

2,175

 

 

 

 

 

 

 

 

 

Income before income taxes

 

148,912

 

140,912

 

141,608

 

 

 

 

 

 

 

 

 

Federal and state income taxes (Note 7)

 

53,294

 

50,073

 

52,679

 

 

 

 

 

 

 

 

 

Net income

 

$

95,618

 

$

90,839

 

$

88,929

 

 

Consolidated Statements of Retained Earnings

(Thousands of $)

 

 

 

Years Ended December 31

 

 

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Balance January 1

 

$

497,441

 

$

409,319

 

$

393,636

 

Add net income

 

95,618

 

90,839

 

88,929

 

 

 

593,059

 

500,158

 

482,565

 

 

 

 

 

 

 

 

 

Deduct:

Cash dividends declared on stock:

 

 

 

 

 

 

 

5% cumulative preferred

 

1,075

 

1,075

 

1,075

 

Auction rate cumulative preferred

 

962

 

908

 

1,702

 

$5.875 cumulative preferred

 

 

734

 

1,469

 

Common

 

57,000

 

 

69,000

 

 

 

59,037

 

2,717

 

73,246

 

 

 

 

 

 

 

 

 

Balance December 31

 

$

534,022

 

$

497,441

 

$

409,319

 

 

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

 

84



 

Louisville Gas and Electric Company and Subsidiary

Consolidated Statements of Comprehensive Income

(Thousands of $)

 

 

 

Years Ended December 31

 

 

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Net income

 

$

95,618

 

$

90,839

 

$

88,929

 

 

 

 

 

 

 

 

 

Gain/(losses) on derivative instruments and hedging activities, net of tax benefit/(expense) of $947, $(368) and $3,457 for 2004, 2003 and 2002, respectively (Notes 1 and 4)

 

(1,399

)

544

 

(5,107

)

 

 

 

 

 

 

 

 

Additional minimum pension liability adjustment, net of tax benefit/(expense) of $4,128, $(1,257) and $10,493 for 2004, 2003 and 2002, respectively (Note 6)

 

(6,100

)

1,857

 

(15,505

)

 

 

 

 

 

 

 

 

Other comprehensive (loss) income, net of tax (Note 15)

 

(7,499

)

2,401

 

(20,612

)

 

 

 

 

 

 

 

 

Comprehensive income

 

$

88,119

 

$

93,240

 

$

68,317

 

 

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

 

85



 

Louisville Gas and Electric Company and Subsidiary

Consolidated Balance Sheets

(Thousands of $)

 

 

 

December 31

 

 

 

2004

 

2003

 

ASSETS:

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents (Note 1)

 

$

6,809

 

$

1,706

 

Accounts receivable - less reserve of $785 in 2004 and $3,515 in 2003 (Note 4)

 

166,990

 

84,585

 

Materials and supplies - at average cost:

 

 

 

 

 

Fuel (predominantly coal) (Note 1)

 

21,771

 

25,260

 

Gas stored underground (Note 1)

 

77,503

 

69,884

 

Other (Note 1)

 

26,159

 

24,971

 

Prepayments and other

 

3,921

 

5,281

 

 

 

303,153

 

211,687

 

 

 

 

 

 

 

Other property and investments – less reserve of $63 in 2004 and 2003 (Note 1)

 

507

 

611

 

 

 

 

 

 

 

Utility plant, at original cost (Note 1):

 

 

 

 

 

Electric

 

3,113,653

 

2,809,957

 

Gas

 

487,771

 

468,504

 

Common

 

177,538

 

186,556

 

 

 

3,778,962

 

3,465,017

 

 

 

 

 

 

 

Less: reserve for depreciation

 

1,396,341

 

1,326,899

 

 

 

2,382,621

 

2,138,118

 

 

 

 

 

 

 

Construction work in progress

 

136,842

 

339,166

 

 

 

2,519,463

 

2,477,284

 

 

 

 

 

 

 

Deferred debits and other assets:

 

 

 

 

 

Restricted cash (Note 1)

 

10,943

 

 

Unamortized debt expense (Note 1)

 

8,453

 

8,753

 

Regulatory assets (Note 3)

 

91,866

 

143,626

 

Other

 

32,167

 

40,121

 

 

 

143,429

 

192,500

 

 

 

 

 

 

 

 

 

$

2,966,552

 

$

2,882,082

 

 

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

 

86



 

Louisville Gas and Electric Company and Subsidiary

Consolidated Balance Sheets (continued)

(Thousands of $)

 

 

 

December 31

 

 

 

2004

 

2003

 

CAPITAL AND LIABILITIES:

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Current portion of long-term debt:

 

 

 

 

 

Long-term bonds (Note 9)

 

$

246,200

 

$

246,200

��

Long-term notes to affiliated company (Note 9)

 

50,000

 

 

Mandatorily redeemable preferred stock (Note 9)

 

1,250

 

1,250

 

 

 

297,450

 

247,450

 

 

 

 

 

 

 

Notes payable to affiliated company (Notes 10 and 14)

 

58,220

 

80,332

 

Accounts payable

 

106,090

 

93,118

 

Accounts payable to affiliated companies (Note 14)

 

31,709

 

38,343

 

Accrued income taxes

 

6,208

 

11,472

 

Customer deposits

 

14,016

 

10,493

 

Other

 

18,624

 

16,533

 

 

 

234,867

 

250,291

 

 

 

 

 

 

 

 

 

532,317

 

497,741

 

Long-term debt (see statements of capitalization):

 

 

 

 

 

Long-term bonds (Note 9)

 

328,104

 

328,104

 

Long-term notes to affiliated company (Note 9)

 

225,000

 

200,000

 

Mandatorily redeemable preferred stock (Note 9)

 

21,250

 

22,500

 

 

 

574,354

 

550,604

 

Deferred credits and other liabilities:

 

 

 

 

 

Accumulated deferred income taxes (Notes 1 and 7)

 

347,233

 

337,704

 

Investment tax credit, in process of amortization

 

46,176

 

50,329

 

Accumulated provision for pensions and related benefits (Note 6)

 

120,566

 

140,598

 

Asset retirement obligations

 

10,266

 

9,747

 

Regulatory liabilities (Note 3):

 

 

 

 

 

Accumulated cost of removal of utility plant

 

220,214

 

216,491

 

Other

 

52,150

 

51,822

 

Other

 

40,105

 

32,957

 

 

 

836,710

 

839,648

 

Commitments and contingencies (Note 11)

 

 

 

 

 

 

 

 

 

 

 

Cumulative preferred stock (see statements of capitalization)

 

70,425

 

70,425

 

 

 

 

 

 

 

Common equity (see statements of capitalization)

 

952,746

 

923,664

 

 

 

 

 

 

 

 

 

$

2,966,552

 

$

2,882,082

 

 

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

 

87



 

Louisville Gas and Electric Company and Subsidiary

Consolidated Statements of Cash Flows

(Thousands of $)

 

 

 

Years Ended December 31

 

 

 

2004

 

2003

 

2002

 

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

 

 

Net income

 

$

95,618

 

$

90,839

 

$

88,929

 

Items not requiring cash currently:

 

 

 

 

 

 

 

Depreciation and amortization

 

116,577

 

113,287

 

105,906

 

Deferred income taxes - net

 

5,533

 

20,123

 

11,915

 

Investment tax credit - net

 

(4,153

)

(4,207

)

(4,153

)

VDT amortization

 

30,135

 

30,400

 

30,000

 

Mark-to-market financial instruments

 

2,576

 

(1,149

)

8,512

 

Other

 

(2,023

)

10,812

 

11,226

 

Change in certain net current assets:

 

 

 

 

 

 

 

Accounts receivable

 

(24,405

)

(10,945

)

(3,973

)

Materials and supplies

 

(5,318

)

(7,598

)

(15,048

)

Accounts payable

 

6,338

 

8,690

 

(26,299

)

Accrued income taxes

 

(5,264

)

17,165

 

(18,807

)

Prepayments and other

 

6,827

 

906

 

321

 

Sale of accounts receivable (Note 4)

 

(58,000

)

(5,200

)

21,200

 

Pension funding

 

(34,492

)

(89,125

)

336

 

Gas supply clause receivable, net

 

10,296

 

(4,712

)

3,873

 

Litigation settlement

 

6,972

 

 

 

Earnings sharing mechanism receivable

 

10,241

 

142

 

 

Other

 

14,178

 

(6,178

)

(1,557

)

Net cash provided by operating activities

 

171,636

 

163,250

 

212,381

 

 

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

 

 

Proceeds from sales of securities

 

103

 

153

 

412

 

Construction expenditures

 

(148,306

)

(212,957

)

(220,416

)

Net cash used for investing activities

 

(148,203

)

(212,804

)

(220,004

)

 

 

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

 

 

Increase in restricted cash

 

(10,943

)

 

 

Long-term borrowings from affiliated company

 

125,000

 

200,000

 

 

Repayment of long-term borrowings from affiliated company

 

(50,000

)

 

 

Repayment of short-term borrowings

 

 

 

(29,944

)

Short-term borrowings from affiliated company

 

552,800

 

602,700

 

652,300

 

Repayment of short-term borrowings from affiliated company

 

(574,912

)

(715,421

)

(523,500

)

Retirement of first mortgage bonds

 

 

(42,600

)

 

Issuance of pollution control bonds

 

 

128,000

 

161,665

 

Issuance expense on pollution control bonds

 

(135

)

(5,843

)

(3,030

)

Retirement of pollution control bonds

 

 

(128,000

)

(161,665

)

Retirement of mandatorily redeemable preferred stock

 

(1,250

)

(1,250

)

 

Payment of dividends

 

(58,890

)

(3,341

)

(73,300

)

Net cash (used for) provided by financing activities

 

(18,330

)

34,245

 

22,526

 

 

 

 

 

 

 

 

 

Change in cash and cash equivalents

 

5,103

 

(15,309

)

14,903

 

 

 

 

 

 

 

 

 

Cash and cash equivalents at beginning of year

 

1,706

 

17,015

 

2,112

 

 

 

 

 

 

 

 

 

Cash and cash equivalents at end of year

 

$

6,809

 

$

1,706

 

$

17,015

 

 

 

 

 

 

 

 

 

Supplemental disclosures of cash flow information:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash paid during the year for:

 

 

 

 

 

 

 

Income taxes

 

$

52,121

 

$

24,868

 

$

51,540

 

Interest on borrowed money

 

18,144

 

23,829

 

25,673

 

Interest to affiliated companies on borrowed money

 

11,323

 

4,162

 

1,850

 

 

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

 

88



 

Louisville Gas and Electric Company and Subsidiary

Consolidated Statements of Capitalization

(Thousands of $)

 

 

 

 

 

 

 

December 31

 

 

 

 

 

 

 

2004

 

2003

 

LONG-TERM DEBT (Note 9):

 

 

 

 

 

 

 

 

 

Pollution control series:

 

 

 

 

 

 

 

 

 

S due September 1, 2017, variable %

 

 

 

 

 

$

31,000

 

$

31,000

 

T due September 1, 2017, variable %

 

 

 

 

 

60,000

 

60,000

 

U due August 15, 2013, variable %

 

 

 

 

 

35,200

 

35,200

 

X due April 15, 2023, 5.90%

 

 

 

 

 

40,000

 

40,000

 

Y due May 1, 2027, variable %

 

 

 

 

 

25,000

 

25,000

 

Z due August 1, 2030, variable %

 

 

 

 

 

83,335

 

83,335

 

AA due September 1, 2027, variable %

 

 

 

 

 

10,104

 

10,104

 

BB due September 1, 2026, variable %

 

 

 

 

 

22,500

 

22,500

 

CC due September 1, 2026, variable %

 

 

 

 

 

27,500

 

27,500

 

DD due November 1, 2027, variable %

 

 

 

 

 

35,000

 

35,000

 

EE due November 1, 2027, variable %

 

 

 

 

 

35,000

 

35,000

 

FF due October 1, 2032, variable %

 

 

 

 

 

41,665

 

41,665

 

GG due October 1, 2033, variable %

 

 

 

 

 

128,000

 

128,000

 

Notes payable to Fidelia:

 

 

 

 

 

 

 

 

 

Due April 30, 2013, 4.55%, unsecured

 

 

 

 

 

100,000

 

100,000

 

Due August 15, 2013, 5.31%, secured

 

 

 

 

 

100,000

 

100,000

 

Due January 6, 2005, 1.53%, secured

 

 

 

 

 

50,000

 

 

Due January 16, 2012, 4.33%, secured

 

 

 

 

 

25,000

 

 

Mandatorily redeemable preferred stock:

 

 

 

 

 

 

 

 

 

$ 5.875 series, outstanding shares of 225,000 in 2004 and 237,500 in 2003

 

 

 

 

 

22,500

 

23,750

 

 

 

 

 

 

 

 

 

 

 

Total long-term debt outstanding

 

 

 

 

 

871,804

 

798,054

 

 

 

 

 

 

 

 

 

 

 

Less current portion of long-term debt

 

 

 

 

 

297,450

 

247,450

 

 

 

 

 

 

 

 

 

 

 

Long-term debt

 

 

 

 

 

574,354

 

550,604

 

 

 

 

 

 

 

 

 

 

 

CUMULATIVE PREFERRED STOCK:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Shares
Outstanding

 

Current
Redemption Price

 

 

 

 

 

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

 

860,287

 

$

28.00

 

21,507

 

21,507

 

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

 

500,000

 

$

100.00

 

50,000

 

50,000

 

Preferred stock expense, net

 

 

 

 

 

(1,082

)

(1,082

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

70,425

 

70,425

 

 

 

 

 

 

 

 

 

 

 

COMMON EQUITY:

 

 

 

 

 

 

 

 

 

Common stock, without par value -

 

 

 

 

 

 

 

 

 

Authorized 75,000,000 shares, outstanding 21,294,223 shares

 

 

 

 

 

425,170

 

425,170

 

Common stock expense

 

 

 

 

 

(836

)

(836

Additional paid-in capital

 

 

 

 

 

40,000

 

40,000

 

Accumulated other comprehensive income (Note 15)

 

 

 

 

 

(45,610

)

(38,111

Retained earnings

 

 

 

 

 

534,022

 

497,441

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

952,746

 

923,664

 

 

 

 

 

 

 

 

 

 

 

Total capitalization

 

 

 

 

 

$

1,597,525

 

$

1,544,693

 

 

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

 

89



 

Louisville Gas and Electric Company and Subsidiary
Notes to Consolidated Financial Statements

 

Note 1 - Summary of Significant Accounting Policies

 

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

 

On December 11, 2000, LG&E Energy was acquired by Powergen.   On July 1, 2002, E.ON, a German company, completed its acquisition of Powergen plc (now Powergen Limited).  E.ON is a registered public utility holding company under PUHCA.

 

No costs associated with the E.ON purchase of Powergen or the Powergen purchase of LG&E Energy nor any effects of purchase accounting have been reflected in the financial statements of LG&E.

 

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.

 

Certain reclassification entries have been made to the previous years’ financial statements to conform to the 2004 presentation with no impact on the balance sheet net assets or previously reported income.  Effective December 31, 2004, operating and non-operating income taxes are presented as “Federal and State Income Taxes” on LG&E’s Consolidated Statements of Income.  Prior to December 31, 2004, the component of income taxes associated with operating income was included in net operating income and the component of income taxes associated with non-operating income taxes was included in other income (expense) – net.  LG&E has applied this change in presentation to all prior periods.

 

Regulatory Accounting.  Accounting for the regulated utility business conforms with generally accepted accounting principles as applied to regulated public utilities and as prescribed by FERC and the Kentucky Commission.  LG&E is subject to SFAS No. 71 under which certain costs that would otherwise be charged to expense are deferred as regulatory assets based on expected recovery from customers in future rates.  Likewise, certain credits that would otherwise be reflected as income are deferred as regulatory liabilities based on expected return to customers in future rates.  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.  See Note 3 for additional detail regarding regulatory assets and liabilities.

 

Utility Plant.  LG&E’s utility plant is stated at original cost, which includes payroll-related costs such as taxes, fringe benefits, and administrative and general costs.  Construction work in progress has been included in the rate base for determining retail customer rates.  LG&E has not recorded any allowance for funds used during construction.

 

The cost of plant retired or disposed of in the normal course of business is deducted from plant accounts and such cost, plus removal expense less salvage value, is charged to the reserve for depreciation.  When complete operating units are disposed of, appropriate adjustments are made to the reserve for depreciation and gains and losses, if any, are recognized.

 

90



 

Depreciation and Amortization.  Depreciation is provided on the straight-line method over the estimated service lives of depreciable plant.  The amounts provided were approximately 3.1% in 2004 (2.9% electric, 2.8% gas, and 7.6% common); 3.3% in 2003 (2.9% electric, 2.8% gas and 9.4% common); and 3.1% for 2002 (2.9% electric, 2.8% gas and 6.6% common), of average depreciable plant.  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.   Of the amount provided for depreciation, at December 31, 2003, approximately 0.4% electric, 0.8% gas and 0.1% common were related to the retirement, removal and disposal costs of long lived assets.

 

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

 

Restricted Cash.  A deposit in the amount of $10.9 million, used as collateral for a $83.3 million interest rate swap, is classified as restricted cash on LG&E’s balance sheet.

 

Fuel Inventory.  Fuel inventories of $21.8 million and $25.3 million at December 31, 2004, and 2003, respectively, are included in Fuel in the balance sheet.  The inventory is accounted for using the average-cost method.

 

Gas Stored Underground.  Gas inventories of $77.5 million and $69.9 million at December 31, 2004, and 2003, respectively, are included in gas stored underground in the balance sheet.  The inventory is accounted for using the average-cost method.

 

Other Materials and Supplies.  Non-fuel materials and supplies of $26.2 million and $25.0 million at December 31, 2004 and 2003, respectively, are accounted for using the average-cost method.

 

Financial Instruments.  LG&E uses over-the-counter interest-rate swap agreements to hedge its exposure to fluctuations in the interest rates it pays on variable-rate debt.  Gains and losses on interest-rate swaps used to hedge interest rate risk are reflected in other comprehensive income.  LG&E uses sales of market-traded electric forward contracts for periods less than one year to hedge the price volatility of its forecasted peak electric off-system sales.  Gains and losses resulting from ineffectiveness are shown in other income (expense) and to the extent that the hedging relationship has been effective, gains and losses are reflected in other comprehensive income.  Wholesale sales of excess asset capacity and wholesale purchases to be used to serve native load are treated as normal sales and purchases under SFAS No. 133, SFAS No. 138 and SFAS No. 149 and are not marked-to-market.  See Note 4, Financial Instruments and Note 15, Accumulated Other Comprehensive Income.

 

Unamortized Debt Expense.  Debt expense is capitalized in deferred debits and amortized over the lives of the related bond issues, consistent with regulatory practices.

 

Deferred Income Taxes.  Deferred income taxes are recognized at currently enacted tax rates for all material temporary differences between the financial reporting and income tax basis of assets and liabilities.

 

Investment Tax Credits.  Investment tax credits resulted from provisions of the tax law that permitted a reduction of LG&E’s tax liability based on credits for certain construction expenditures.  Deferred investment tax credits are being amortized to income over the estimated lives of the related property that gave rise to the credits.

 

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

 

91



 

for income taxes, and there are many transactions for which the ultimate tax outcome is uncertain.  To provide for these uncertainties or exposures, an allowance is maintained for tax contingencies, the balance of which management believes is adequate.  Tax contingencies are analyzed periodically and adjustments are made when events occur to warrant a change.  The company is currently in the examination phase of IRS audits for the years 1999 to 2003 and expects some or all of these audits to be completed within the next 12 months.  The results of audit assessments by taxing authorities are not anticipated to have a material adverse effect on cash flows or results of operations.

 

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 $63.0 million and $50.8 million at December 31, 2004 and 2003, respectively.

 

Allowance for Doubtful Accounts. At December 31, 2004 and 2003, the LG&E allowance for doubtful accounts was $0.8 million and $3.5 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.

 

Fuel and Gas Costs.  The cost of fuel for electric generation is charged to expense as used, and the cost of gas supply is charged to expense as delivered to the distribution system.  LG&E implemented a Kentucky Commission-approved performance-based ratemaking mechanism related to gas procurement and off-system gas sales activity.  See Note 3, Rates and Regulatory Matters.

 

Other Property and Investments.  Other property and investments on the Balance Sheet consists of LG&E’s investment in OVEC and non-utility plant.  As of December 31, 2004 and 2003, LG&E’s investment in OVEC totaled $0.5 million.  In March 2005, LG&E purchased from AEP an additional 0.73% interest in OVEC for a purchase price of approximately $0.1 million, which resulted in an increase in LG&E ownership in OVEC from 4.9% to 5.63%.  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.

 

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. See Note 11, Commitments and Contingencies, for a further discussion.

 

New Accounting Pronouncements. The following accounting pronouncements were issued that affected LG&E in 2004 and 2003:

 

SFAS No. 143

 

SFAS No. 143 was issued in 2001.  SFAS No. 143 establishes accounting and reporting standards for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.

 

92



 

The effective implementation date for SFAS No. 143 was January 1, 2003.  Management has calculated the impact of SFAS No. 143 and FERC Final Order No. 631 issued in Docket No. RM02-7.  As of January 1, 2003, LG&E recorded ARO assets in the amount of $4.6 million and liabilities in the amount of $9.3 million.  LG&E also recorded a cumulative effect adjustment in the amount of $5.3 million to reflect the accumulated depreciation and accretion of ARO assets at the transition date less amounts previously accrued under regulatory depreciation.  LG&E recorded offsetting regulatory assets of $5.3 million, pursuant to regulatory treatment prescribed under SFAS No. 71.  Also pursuant to SFAS No. 71, LG&E recorded regulatory liabilities in the amount of $0.1 million offsetting removal costs previously accrued under regulatory accounting in excess of amounts allowed under SFAS No. 143.

 

Had SFAS No. 143 been in effect for the 2002 reporting period, LG&E would have established asset retirement obligations as described in the following table:

 

(in thousands)

 

 

 

Provision at January 1, 2002

 

$

8,752

 

Accretion expense

 

578

 

Provision at December 31, 2002

 

$

9,330

 

 

As of December 31, 2004, LG&E had ARO assets, net of accumulated depreciation, of $3.3 million and liabilities of $10.3 million.  As of December 31, 2003, LG&E had ARO assets, net of accumulated depreciation, of $3.5 million and liabilities of $9.7 million.  LG&E recorded regulatory assets of $6.9 million and $6.0 million and regulatory liabilities of $0.1 million as of both December 31, 2004 and 2003, respectively.

 

For the year ended December 31, 2004, LG&E recorded ARO accretion expense of approximately $0.7 million, ARO depreciation expense of $0.2 million and an offsetting regulatory credit in the income statement of $0.9 million, pursuant to regulatory treatment prescribed under SFAS No. 71.  For the year ended December 31, 2003, LG&E recorded ARO accretion expense of approximately $0.6 million, ARO depreciation expense of $0.1 million and an offsetting regulatory credit in the income statement of $0.7 million.  Removal costs incurred and charged against the ARO liability during 2004 and 2003, were $0.1 million and $0.2 million, respectively.  SFAS No. 143 has no impact on the results of operations of LG&E.

 

LG&E AROs are primarily related to final retirement of assets associated with generating units.  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, 2004 and 2003, LG&E recorded immaterial amounts (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 also continues to include a cost of removal component in depreciation for assets that do not have a legal ARO.  As of December 31, 2004 and 2003, LG&E has segregated this cost of removal, embedded in accumulated depreciation, of $220.2 million and $216.5 million, respectively, in accordance with FERC Order No. 631. For reporting purposes in its Consolidated Balance Sheets, LG&E has presented this cost of removal as a regulatory liability pursuant to SFAS No. 71.

 

LG&E transmission and distribution lines largely operate under perpetual property easement agreements which do not generally require restoration upon removal of the property.  Therefore, under SFAS No. 143, no material asset retirement obligations are recorded for transmission and distribution assets.

 

93



 

EITF No. 02-03

 

LG&E adopted EITF No. 98-10 effective January 1, 1999.  This pronouncement required that energy trading contracts be marked to market on the balance sheet, with the gains and losses shown net in the income statement.  Effective January 1, 2003, LG&E adopted EITF No. 02-03.  EITF No. 02-03 established the following:

 

                  Rescinded EITF No. 98-10,

                  Contracts that do not meet the definition of a derivative under SFAS No. 133 should not be marked to fair market value, and

                  Revenues should be shown in the income statement net of costs associated with trading activities, whether or not the trades are physically settled.

 

With the rescission of EITF No. 98-10, energy trading contracts that do not also meet the definition of a derivative under SFAS No. 133 must be accounted for as executory contracts.  Contracts previously recorded at fair value under EITF No. 98-10 that are not also derivatives under SFAS No. 133 must be restated to historical cost through a cumulative effect adjustment.  The rescission of this standard had no impact on financial position or results of operations of LG&E since all forward and option contracts marked to market under EITF No. 98-10 were also within the scope of SFAS No. 133.

 

As a result of EITF No. 02-03, LG&E has netted the power purchased expense for trading activities against electric operating revenue to reflect this accounting change.  LG&E applied this guidance to previously reported 2002 balances as shown below.  The reclassifications had no impact on previously reported net income or common equity.

 

(in thousands)

 

 

 

Gross electric operating revenues as previously reported

 

$

1,026,184

 

Less costs reclassified from power purchased

 

22,449

 

Net electric operating revenues

 

$

1,003,735

 

 

 

 

 

Gross power purchased as previously reported

 

$

84,330

 

Less costs reclassified to revenues

 

22,449

 

Net power purchased

 

$

61,881

 

 

SFAS No. 150

 

In May 2003, the Financial Accounting Standards Board issued SFAS No. 150, which was effective immediately for financial instruments entered into or modified after May 31, 2003, and otherwise was effective for interim reporting periods beginning after June 15, 2003, except for certain instruments and certain entities which have been deferred by the FASB.  Such deferrals do not affect LG&E.

 

LG&E has $5.875 series mandatorily redeemable preferred stock outstanding having a current redemption price of $100 per share. The preferred stock has a sinking fund requirement sufficient to retire a minimum of 12,500 shares on July 15 of each year commencing with July 15, 2003, and the remaining 187,500 shares on July 15, 2008 at $100 per share.  LG&E redeemed 12,500 shares in accordance with these provisions on July 15, 2004 and 2003, leaving 225,000 shares currently outstanding.  Beginning with the three months ended September 30, 2003, LG&E reclassified its $5.875 series preferred stock as long-term debt with the minimum shares mandatorily redeemable within one year classified as current.  Dividends accrued beginning July 1, 2003 are charged as interest expense.

 

94



 

FIN 46

 

In January 2003, the Financial Accounting Standards Board issued FIN 46.  FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties.  FIN 46 was effective immediately for all new variable interest entities created or acquired after January 31, 2003.  For variable interest entities created or acquired prior to February 1, 2003, the provisions of FIN 46 must have been applied for the first interim or annual period beginning after June 15, 2003.

 

In December 2003, FIN 46 was revised, delaying the effective dates for certain entities created before February 1, 2003, and making other amendments to clarify application of the guidance.  For potential variable interest entities other than special purpose entities, FIN 46R was required to be applied no later than the end of the first fiscal year or interim reporting period ending after March 15, 2004.  The original guidance under FIN 46 was applicable, however, for all special purpose entities created prior to February 1, 2003, at the end of the first interim or annual reporting period ending after December 15, 2003.  FIN 46R may be applied prospectively with a cumulative-effect adjustment as of the date it is first applied, or by restating previously issued financial statements with a cumulative-effect adjustment as of the beginning of the first year restated.  FIN 46R also requires certain disclosures of an entity’s relationship with variable interest entities. The adoption of FIN 46 and FIN 46R has no impact on the financial position or results of operations of LG&E.

 

Although LG&E holds an investment interest in OVEC, it is not the primary beneficiary of OVEC and, therefore, OVEC is not consolidated into the financial statements of LG&E.

 

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.  Through March 2006, LG&E’s share is 7%, representing approximately 155 Mw of generation capacity, and 5.63% thereafter.

 

LG&E’s original investment in OVEC was made in 1952.  As of December 31, 2004, LG&E’s investment in OVEC totaled $0.5 million.  In March 2005, LG&E purchased from AEP an additional 0.73% interest in OVEC for a purchase price of approximately $0.1 million, which resulted in an increase in LG&E ownership in OVEC from 4.9% to 5.63%.  LG&E’s investment in OVEC 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 the 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 11 for further discussion of developments regarding LG&E’s ownership interest and power purchase rights.

 

FSP 106-2

 

In May 2004, the FASB finalized FSP 106-2 with guidance on accounting for subsidies provided under the Medicare Act which became law in December 2003.  FSP 106-2 is effective for the first interim or annual period beginning after June 15, 2004.  FSP 106-2 does not have a material impact on LG&E.

 

FSP 109-1

 

In December 2004, the FASB finalized FSP 109-1, which requires the tax deduction on qualified production activities to be treated as a special deduction in accordance with FAS 109.  FSP 109-1 became effective

 

95



 

December 21, 2004, and does not have a material impact on LG&E.

 

Note 2 – Mergers and Acquisitions

 

On July 1, 2002, E.ON completed its acquisition of Powergen, including LG&E Energy, for approximately £5.1 billion ($7.3 billion).  As a result of the acquisition, LG&E Energy became a wholly owned subsidiary of E.ON and, as a result, LG&E also became an indirect subsidiary of E.ON.  LG&E has continued its separate identity and serves customers in Kentucky under its existing name.  The preferred stock and debt securities of LG&E were not affected by this transaction and the utilities continue to file SEC reports.  Following the acquisition, E.ON became a registered holding company under PUHCA. LG&E, as a subsidiary of a registered holding company, is subject to additional regulations under PUHCA.  In March 2003, E.ON, Powergen and LG&E Energy completed an administrative reorganization to move the LG&E Energy group from an indirect Powergen subsidiary to an indirect E.ON subsidiary.  In early 2004, LG&E Energy commenced direct reporting arrangements to E.ON.

 

LG&E Energy and KU Energy merged on May 4, 1998, with LG&E Energy as the surviving corporation.  Management accounted for the merger as a pooling of interests and as a tax-free reorganization under the Internal Revenue Code.  Following the acquisition, LG&E has continued to maintain its separate corporate identity and serve customers under its present name.

 

Note 3 - Rates and Regulatory Matters

 

Electric and Gas Rate Cases

 

In December 2003, LG&E filed applications with the Kentucky Commission requesting adjustments in LG&E’s electric and gas rates.  LG&E asked for general adjustments in electric and gas rates based on the twelve month test year ended September 30, 2003.  The revenue increases requested were $63.8 million for electric and $19.1 million for gas.

 

On June 30, 2004, the Kentucky Commission issued an order approving increases in the base electric and gas rates of LG&E.  The Kentucky Commission’s order largely accepted proposed settlement agreements filed in May 2004 by LG&E and a majority of the parties to the rate case proceedings.   The rate increases took effect on July 1, 2004.

 

In the Kentucky Commission’s order, LG&E was granted increases in annual base electric rates of approximately $43.4 million (7.7%) and in annual base gas rates of approximately $11.9 million (3.4%).  Other provisions of the order include decisions on certain depreciation, gas supply clause, ECR and VDT amounts or mechanisms and a termination of the ESM with respect to all periods after 2003.  The order also provided for a recovery before March 31, 2005, by LG&E of previously requested amounts relating to the ESM during 2003.

 

During July 2004, the AG served subpoenas on LG&E, as well as on 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. The Kentucky Commission has procedurally reopened the rate cases for the limited purpose of taking evidence, if any, as to the communication issues. Subsequently, the AG filed pleadings with the Kentucky Commission requesting rehearing of the rate cases on certain computational components of the increased rates, including income tax, 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, with the effect that the rate increase order is final as to these matters, subject to the parties’ rights to judicial appeals. The Kentucky Commission further agreed to hold in abeyance further proceedings in the rate cases, including the AG’s concerns about alleged improper communications,

 

96



 

until the AG could file with the Kentucky Commission an investigative report regarding the latter issue. In addition, the Kentucky Commission granted a rehearing on the income tax component once the abeyance discussed above is lifted.

 

In September and October 2004, various proceedings were held in circuit courts in Franklin and Jefferson Counties, Kentucky regarding the scope and timing of document production or other information required or agreed to be produced under the AG’s subpoenas and matters were consolidated into the Franklin County court.  In October 2004, the AG filed a motion with the Kentucky Commission requesting that the previously granted rate increases be set aside, that LG&E resubmit any applications for rate increases and that relevant Kentucky Commission personnel be recused from participation in rate case proceedings.  In November 2004, the Franklin County, Kentucky court denied an AG request for sanctions on LG&E relating to production matters and narrowed the AG’s permitted scope of discovery.   In January 2005, the AG conducted interviews of certain Company individuals.

 

In January 2005, the AG submitted its report to the Franklin County, Kentucky Circuit Court in confidence.  Concurrently the AG filed a motion summarizing the report as containing evidence of improper communications and record-keeping errors by LG&E in its conduct of activities before the Kentucky Commission or other state governmental entities and requesting release of the report to such agencies.  During February 2005 the court ruled that the report be forwarded 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 cases, including ending the current abeyance.  To date, LG&E has neither seen nor requested copies of the report or its contents.

 

LG&E believes no improprieties have occurred in its communications with the Kentucky Commission and is cooperating 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 base rates.

 

Regulatory Assets and Liabilities

 

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

 

(in thousands)

 

2004

 

2003

 

 

 

 

 

 

 

VDT Costs

 

$

37,676

 

$

67,810

 

Unamortized loss on bonds

 

20,272

 

21,333

 

ARO

 

6,870

 

6,015

 

Merger surcredit

 

4,838

 

6,220

 

ESM

 

2,118

 

12,359

 

Rate case expenses

 

1,111

 

854

 

FAC

 

842

 

 

DSM

 

 

24

 

Gas supply adjustments due from customers

 

13,320

 

22,077

 

Gas performance base ratemaking

 

3,673

 

5,480

 

Manufactured gas sites

 

1,146

 

1,454

 

Total regulatory assets

 

$

91,866

 

$

143,626

 

 

 

 

 

 

 

Accumulated cost of removal of utility plant

 

$

220,214

 

$

216,491

 

Deferred income taxes - net

 

37,184

 

41,180

 

ECR

 

4,039

 

17

 

DSM

 

2,439

 

1,706

 

ARO

 

136

 

85

 

FAC

 

8

 

1,950

 

ESM

 

 

79

 

Gas supply adjustments due to customers

 

8,344

 

6,805

 

Total regulatory liabilities

 

$

272,364

 

$

268,313

 

 

97



 

LG&E currently earns a return on all regulatory assets except for gas supply adjustments, ESM, 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 Costs - Kentucky Commission Settlement Order.  During the first quarter of 2001, LG&E recorded a $144 million charge for a workforce reduction program.  Primary components of the charge were separation benefits, enhanced early retirement benefits, and healthcare benefits.  The result of this workforce reduction was the elimination of approximately 700 positions, accomplished primarily through a voluntary enhanced severance program.

 

In June 2001, LG&E filed an application (VDT case) with the Kentucky Commission to create a regulatory asset relating to these first quarter 2001 charges.  The application requested permission to amortize these costs over a four-year period.  The Kentucky Commission also opened a case to review a new depreciation study and resulting depreciation rates implemented in 2001.

 

In December 2001, the Kentucky Commission approved a settlement in the VDT case as well as other cases involving the depreciation rates and ESM. The order approving the settlement allowed LG&E to set up a regulatory asset of $141 million for the workforce reduction costs and begin amortizing these costs over a five-year period starting in April 2001. The first quarter 2001 charge of $144 million represented all employees who had accepted a voluntary enhanced severance program.  Some employees rescinded their participation in the voluntary enhanced severance program, thereby decreasing the original charge to the regulatory asset from $144 million to $141 million. The settlement reduces revenues approximately $26 million through a surcredit on bills to ratepayers over the same five-year period.  The surcredit represents net savings stipulated by LG&E.

 

As mentioned, the current five-year VDT amortization period is scheduled to expire in March 2006.  As part of the settlement agreements in the electric and gas rate cases, LG&E shall file with the Kentucky Commission a plan for the future ratemaking treatment of the VDT surcredits and costs six months prior to the March 2006 expiration.  The surcredit shall remain in effect following the expiration of the fifth year until the Commission enters an order on the future disposition of VDT-related issues.

 

ARO.  At December 31, 2004 and 2003, LG&E had recorded $6.9 million and $6.0 million in regulatory assets and $0.1 million and $0.1 million in regulatory liabilities, respectively, related to SFAS No. 143.

 

Merger Surcredit.  As part of the LG&E Energy merger with KU Energy in 1998, LG&E Energy estimated non-fuel savings over a ten-year period following the merger.  Costs to achieve these savings for LG&E of $50.2 million were recorded in the second quarter of 1998, $18.1 million of which was deferred and amortized over a five-year period pursuant to regulatory orders.  Primary components of the merger costs were separation benefits, relocation costs, and transaction fees, the majority of which were paid by December 31, 1998.  LG&E expensed the remaining costs associated with the merger ($32.1 million) in the second quarter of 1998.

 

In approving the merger, the Kentucky Commission adopted LG&E’s proposal to reduce its retail customers’ bills based on one-half of the estimated merger-related savings, net of deferred and amortized amounts, over a five-year period.  The surcredit mechanism provides that 50% of the net non-fuel cost savings estimated to be

 

98



 

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 and lower point for rate of return on equity, whereby if LG&E’s rate of return for the calendar year fell within the range of 10.5% to 12.5%, no action was necessary.  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 and interested parties had the opportunity to provide recommendations for modification and continuance of the ESM or other forms of alternative or incentive regulation.

 

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.

 

On June 30, 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 will continue 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.

 

As a result of the settlement, LG&E accrued an additional $4.1 million in June 2004, related to 2003 ESM revenue.

 

FAC.  LG&E’s retail electric rates contain a FAC, whereby increases and decreases in the cost of fuel for electric generation are reflected in the rates charged to retail 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 is due in May 2005.

 

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.

 

99



 

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 is expected in April 2005.  LG&E is seeking to increase the fuel component of base rates.  LG&E does not anticipate any issues will arise during the regulatory proceeding.

 

DSM.  LG&E’s rates contain a DSM provision.  The provision includes a rate mechanism that provides concurrent recovery of DSM costs and provides an incentive for implementing DSM programs.  This provision allowed LG&E to recover revenues from lost sales associated with the DSM programs.  In May 2001, the Kentucky Commission approved LG&E’s plan to continue DSM programs.  This plan called for the expansion of the LG&E DSM programs into the service territory served by KU and proposed a mechanism to recover revenues from lost sales associated with DSM programs based on program plan engineering estimates and post-implementation evaluations.

 

Gas Supply Cost PBR Mechanism.   Since November 1, 1997, LG&E has operated under a PBR mechanism related to its gas procurement activities.   LG&E’s rates are adjusted annually to recover its portion of the savings (or expenses) incurred during each PBR year (12 months ending October 31). Since its implementation on November 1, 1997, through October 31, 2004, LG&E has achieved $60.7 million in savings. Of that total savings amount, LG&E’s portion has been $22.7 million and the ratepayers’ portion has been $38.0 million.  Pursuant to the extension of LG&E’s gas supply cost PBR mechanism effective November 1, 2001, the sharing mechanism under PBR requires savings (and expenses) to be shared 25% with shareholders and 75% with ratepayers up to 4.5% of the benchmarked gas costs.  Savings (and expenses) in excess of 4.5% of the benchmarked gas costs are shared 50% with shareholders and 50% with ratepayers.  LG&E filed a report and assessment with the Kentucky Commission on December 30, 2004, seeking modification and extension of the mechanism.

 

Accumulated Cost of Removal.  As of December 31, 2004 and 2003, LG&E has segregated the cost of removal, embedded in accumulated depreciation, of $220.2 million and $216.5 million, respectively, in accordance with FERC Order No. 631.  For reporting purposes in the Consolidated Balance Sheets, LG&E has presented this cost of removal as a regulatory liability pursuant to SFAS No. 71.

 

ECR.  In May 2002, the Kentucky Commission initiated a periodic two-year review of LG&E’s environmental surcharge.  The review included the operation of the surcharge mechanism, determination of the appropriateness of costs included in the surcharge mechanism, recalculation of the cost of debt to reflect actual costs for the period under review, final determination of the amount of environmental revenues over-collected from customers, and a final determination of the amount of environmental costs and revenues to be “rolled-in” to base rates.  A final order was issued in October 2002, in which LG&E was ordered to refund $0.3 million to customers over the four month period beginning November 2002 and ending February 2003.  Additionally, LG&E was ordered to roll $4.1 million into base rates and make corresponding adjustments to the monthly environmental surcharge filings to reflect that portion of environmental rate base now included in base rates.

 

In August 2002, LG&E filed an application with the Kentucky Commission to amend its compliance plan to allow recovery of the cost of new and additional environmental compliance facilities.  The estimated capital cost of the additional facilities is $71.1 million.  A final order was issued in February 2003, approving recovery of four new environmental compliance facilities totaling $43.1 million.  A fifth project, expansion of the landfill facility at the Mill Creek Station, was denied without prejudice with an invitation to reapply for recovery when required construction permits are approved.  Cost recovery through the environmental surcharge of the four approved projects commenced with bills rendered in April 2003.

 

In January 2003, the Kentucky Commission initiated a six-month review of LG&E’s environmental surcharge.

 

100



 

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 on a going-forward basis.  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 the cost of 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 is $40.2 million.  LG&E requested an overall rate of return of 10.72%, including an 11% return on common equity.  A final order in the case is anticipated in June 2005.

 

Other Regulatory Matters

 

MISO.  LG&E is a founding member of the MISO.  Membership was obtained in 1998 in response to and consistent with federal policy initiatives.  In February 2002, LG&E turned over operational control of their high voltage transmission facilities (100kV and above) to the MISO.  The MISO currently controls over 100,000 miles of transmission lines over 1.1 million square miles located in the northern Midwest between Manitoba, Canada and Kentucky.  In September 2002, FERC granted a 12.88% ROE on transmission facilities for LG&E and the rest of the MISO owners.  On February 18, 2005, the United States Court of Appeals for the District of Columbia Circuit ruled that FERC did not provide proper notice that it would consider an incentive adder of 50 basis points, but affirmed the September 2002 FERC order in all other respects.  Effective ROE, retroactive to February 1, 2002, is 12.38% for LG&E and the original MISO owners.

 

In October 2001, the FERC issued an order requiring that the bundled retail load and grandfathered wholesale load of each member transmission owner be included in the current calculation of the MISO’s “cost-adder,” the Schedule 10 charges designed to recover the MISO’s costs of operation, including start-up capital (debt) costs.  LG&E, along with several other transmission owners, opposed the FERC’s ruling on this matter. The opposition was rejected by the FERC in 2002.   Later that year, the MISO’s transmission owners, appealed the FERC’s decision to the United States Court of Appeals for the District of Columbia Circuit.  In response, in November 2002, the FERC requested that the Court issue a partial remand of its challenged orders to allow the FERC to revisit certain issues, and requested that the case be held in abeyance pending the agency’s resolution of such issues.  The Court granted the FERC’s petition in December 2002.   In February 2003, FERC issued an order reaffirming its position concerning the calculation of the Schedule 10 charges and in July 2003 denied a rehearing.  LG&E, along with several other transmission owners, again petitioned the District Court of Columbia Circuit for review. In July 2004 the court affirmed the FERC ruling.

 

In August 2004, the MISO filed its FERC-required proposed TEMT.  In September and October 2004, many MISO-related parties (including LG&E) filed proposals with the FERC regarding pending MISO-filed changes to transmission pricing principles, including the TEMT and elimination of RTORs. Additional filings of the companies before FERC in September 2004 sought to address issues relating to the treatment of certain GFA's should TEMT become effective. The utility proposals generally seek to appropriately delay the RTOR and TEMT effective dates based upon errors in administrative or procedural processes used by FERC or to appropriately limit potential reductions in transmission revenues received by the utilities should the RTOR, TEMT or GFA structures be implemented.  At present, existing FERC orders conditionally approve elimination of RTORs and implementation of general TEMT rates in the MISO by spring 2005.  At this time, LG&E cannot predict the outcome or effects of the various FERC proceedings described above, including whether such will have a material impact on the financial condition or results of operations of the companies. Financial consequences (changes in transmission revenues and costs) associated with the upcoming transmission market tariff changes are subject to varying assumptions and calculations and are therefore difficult to estimate. Changes in revenues and costs related to broader shifts in energy market practices and economics are not currently estimable.  Should LG&E be ordered to exit MISO, current MISO rules may also impose an exit fee.  LG&E is not able to predict the estimated outcome or economic impact of any of the MISO-related matters.  While LG&E believes legal and regulatory precedent should permit most or many of the MISO-related costs to be recovered in their rates charged to customers, they can give no assurance that state or federal regulators will ultimately agree with such position with respect to all costs, components or timing of recovery.

 

The MISO plans to implement a Day-ahead and Real-time market, including a congestion management system in April 2005. This system will be similar to the LMP system currently used by the PJM RTO and contemplated in FERC’s SMD NOPR, currently being discussed.  The MISO filed with FERC a mechanism for recovery of costs for the congestion management system.  They proposed the addition of two new Schedules, 16 and 17.  Schedule 16 is the MISO’s cost recovery mechanism for the Financial Transmission Rights Administrative Service it will provide.  Schedule 17

 

101



 

is the MISO’s mechanism for recovering costs it will incur for providing Energy Marketing Support Administrative Service.  The MISO transmission owners, including LG&E, have objected to the allocation of costs among market participants and retail native load. FERC ruled in 2004 in favor of the MISO.

 

The Kentucky Commission opened an investigation into LG&E’s membership in the MISO in July 2003. The Kentucky Commission directed LG&E to file testimony addressing the costs and benefits of the MISO membership both currently and over the next five years and other legal issues surrounding continued membership.  LG&E engaged an independent third-party to conduct a cost benefit analysis on this issue.  The information was filed with the Kentucky Commission in September 2003.  The analysis and testimony supported the exit from the MISO, under certain conditions.  The MISO filed its own testimony and cost benefit analysis in December 2003.  A final Kentucky Commission order was expected in the second quarter of 2004; that ruling has since been delayed until summer 2005 due to the Kentucky Commission’s request for additional testimony on the MISO’s Market Tariff filing at FERC.

 

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 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.

 

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 will be 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.  The Kentucky Commission must provide its Strategic Blueprint to the Governor in early August 2005.  LG&E must respond to the Kentucky Commission’s first set of data requests by the end of March 2005.

 

FERC SMD NOPR.  In July 2002, the FERC issued a NOPR in Docket No. RM01-12-000 which would substantially alter the regulations governing the nation’s wholesale electricity markets by establishing a common set of rules, defined as SMD. The SMD NOPR would require each public utility that owns, operates,

 

102



 

or controls interstate transmission facilities to become an ITP, belong to an RTO that is an ITP, or contract with an ITP for operation of its transmission assets. It would also establish a standardized congestion management system, real-time and day-ahead energy markets, and a single transmission service for network and point-to-point transmission customers. Review of the proposed rulemaking is underway and no timeframe has been established by the FERC for adoption of a final rule.  While it is expected that the SMD final rule will affect LG&E revenues and expenses, the specific impact of the rulemaking is not known at this time.

 

Kentucky Commission Administrative Case for Affiliate Transactions.  In December 1997, the Kentucky Commission opened Administrative Case No. 369 to consider Kentucky Commission policy regarding cost allocations, affiliate transactions and codes of conduct governing the relationship between utilities and their non-utility operations and affiliates.  The Kentucky Commission intended to address two major areas in the proceedings: the tools and conditions needed to prevent cost shifting and cross-subsidization between regulated and non-utility operations; and whether a code of conduct should be established to assure that non-utility segments of the holding company are not engaged in practices that could result in unfair competition caused by cost shifting from the non-utility affiliate to the utility.  In early 2000, the Kentucky General Assembly enacted legislation, House Bill 897, which authorized the Kentucky Commission to require utilities that provide nonregulated activities to keep separate accounts and allocate costs in accordance with procedures established by the Kentucky Commission.  In the same bill, the General Assembly set forth provisions to govern a utility’s activities related to the sharing of information, databases, and resources between its employees or an affiliate involved in the marketing or the provision of nonregulated activities and its employees or an affiliate involved in the provision of regulated services. The legislation became law in July 2000 and LG&E has been operating pursuant thereto since that time.  In February 2001, the Kentucky Commission published notice of its intent to promulgate new administrative regulations under the auspices of this new law.  This effort is still on-going.

 

Wholesale Natural Gas Prices.  On September 12, 2000, the Kentucky Commission issued an order establishing Administrative Case No. 384 – “An Investigation of Increasing Wholesale Natural Gas Prices and the Impacts of such Increase on the Retail Customers Served by Kentucky’s Jurisdictional Natural Gas Distribution Companies”.

 

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, consider performance-based ratemaking mechanisms, and to increase the use of storage.

 

In May 2004, in Case No. 2004-148, LG&E proposed a hedge plan for the 2004/2005 winter heating season  relying upon LG&E’s storage to mitigate customer exposure to price volatility. In August 2004, the Kentucky Commission approved LG&E’s proposed hedge plan, validating the effectiveness of storage to mitigate potential volatility associated with high winter 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.

 

Note 4 - Financial Instruments

 

The cost and estimated fair values of LG&E’s non-trading financial instruments as of December 31, 2004, and 2003 follow:

 

(in thousands)

 

2004

 

2003

 

 

Cost

 

Fair
Value

 

Cost

 

Fair
Value

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Preferred stock subject to mandatory redemption

 

$

22,500

 

$

22,781

 

$

23,750

 

$

23,893

 

Long-term debt (including current portion)

 

$

574,304

 

$

575,419

 

$

574,304

 

$

576,174

 

Long-term debt from affiliate

 

$

275,000

 

$

280,684

 

$

200,000

 

$

206,333

 

Interest-rate swaps - liability

 

 

$

(18,542

)

 

$

(15,966

)

 

103



 

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.

 

Interest Rate Swaps. LG&E uses interest rate swaps to hedge exposure to market fluctuations in certain of its debt instruments.  Pursuant to policy, use of these financial instruments is intended to mitigate risk, 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.  To the extent a financial instrument designated as a cash flow hedge or the underlying item being hedged is prematurely terminated or the hedge becomes ineffective, the resulting gains or losses are reclassified from other comprehensive income to net income. See Note 15, 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.

 

LG&E was party to various interest rate swap agreements with aggregate notional amounts of $228.3 million as of December 31, 2004 and 2003.  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 1.74% and 1.11% at December 31, 2004 and 2003, respectively. The swap agreements in effect at December 31, 2004 have been designated as cash flow hedges and mature on dates ranging from 2005 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 gain of $2.3 million for 2004, recorded in other comprehensive income.  Upon expiration of these hedges, the amount recorded in other comprehensive income will be reclassified into earnings.  The amounts expected to be reclassified from other comprehensive income to earnings in the next twelve months is immaterial (less than $0.1 million). A deposit in the amount of $10.9 million, used as collateral for the $83.3 million interest rate swap, 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 Trading & Risk Management Activities.  LG&E conducts energy trading and risk management activities to maximize the value of power sales from physical assets it owns, in addition to the wholesale sale of excess asset capacity.  Certain energy trading activities are accounted for on a mark-to-market basis in accordance with SFAS No. 133, SFAS No. 138 and SFAS No. 149.  Wholesale sales of excess asset capacity are treated as normal sales under  these pronouncements and are not marked to market.  To be eligible for the normal sales exclusion under SFAS No. 133, sales are limited to the forecasted excess capacity of LG&E’s generation assets over what is needed to serve native load.  To be eligible for the normal purchases exclusion under SFAS No. 133 purchases must be used to serve LG&E’s native load.  Without the normal sales and purchases exclusion these transactions would be considered derivatives and marked to market under SFAS No. 133.

 

The rescission of EITF No. 98-10 for fiscal periods ending after December 15, 2002, had no impact on LG&E’s energy trading and risk management reporting as all forward and option contracts marked to market under EITF No. 98-10 are also within the scope of SFAS No. 133.

 

104



 

No changes to valuation techniques for energy trading and risk management activities occurred during 2004.  Changes in market pricing, interest rate and volatility assumptions were made during both years.  All contracts outstanding at December 31, 2004, 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, 2004, 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 peak electric off-system sales with the sales of market-traded electric forward contracts for periods 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 Consolidated Statements of Income in other income (expense) – net.  Upon expiration of these instruments, 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 2004, 2003 and 2002.   See Note 15, Accumulated Other Comprehensive Income.

 

Accounts Receivable Securitization.  On February 6, 2001, LG&E implemented an accounts receivable securitization program. LG&E terminated the accounts receivable securitization program in January 2004, and in May 2004, LG&E dissolved its inactive accounts receivable securitization-related subsidiary, LG&E R.  The purpose of this program was to enable LG&E to accelerate the receipt of cash from the collection of retail accounts receivable, thereby reducing dependence upon more costly sources of working capital.  The securitization program allowed for a percentage of eligible receivables to be sold.  Eligible receivables were generally all receivables associated with retail sales that had standard terms and were not past due.  LG&E was able to terminate the program at any time without penalty.

 

As part of the program, LG&E sold retail accounts receivable to LG&E R.  Simultaneously, LG&E R entered into two separate three-year accounts receivable securitization facilities with two financial institutions and their affiliates whereby LG&E R could sell, on a revolving basis, an undivided interest in certain of its receivables and receive up to $75 million from unrelated third-party purchasers.  The effective cost of the receivables program was comparable to LG&E’s lowest cost source of capital, and was based on prime rated commercial paper. LG&E retained servicing rights of the sold receivables through two separate servicing agreements with the third-party purchasers.  LG&E obtained an opinion from independent legal counsel indicating these transactions qualified as a true sale of receivables.

 

To determine LG&E’s retained interest, the proceeds on the sale of receivables to the financial institutions were netted against the amount of eligible receivables sold by LG&E to LG&E R.  Interest expense, program fees, and facility fees paid to the financial institutions and an allowance for doubtful accounts were deducted to arrive at the future value of retained interest.  The future value was discounted using the prime rate plus 25 basis points, assuming a 45-day receivable life.  No material pre-tax gains and losses from the sale of the receivables occurred in 2004, 2003 and 2002.  LG&E’s net cash flows from LG&E R were $(58.1) million, $(6.2) million and $20.2 million for 2004, 2003 and 2002, respectively.

 

105



 

The allowance for doubtful accounts associated with the eligible securitized receivables at December 31 was  $1.4 million and $1.9 million in 2003 and 2002, respectively.  This allowance was based on historical experience of LG&E. Each securitization facility contained a fully funded reserve for uncollectible receivables.

 

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 318,000 customers and electricity to approximately 390,000 customers in Louisville and adjacent areas in Kentucky.  For the year ended December 31, 2004, 70% of total revenue was derived from electric operations and 30% from gas operations.

 

In November 2001, LG&E and IBEW Local 2100 employees, that represent approximately 72% of LG&E’s workforce, entered into a four-year collective bargaining agreement and completed wage and benefit re-opener negotiations in October 2003.

 

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, 2004, and a statement of the funded status as of December 31, 2004, for LG&E’s sponsored defined benefit plan:

 

(in thousands)

 

2004

 

2003

 

2002

 

Pension Plans:

 

 

 

 

 

 

 

Change in benefit obligation

 

 

 

 

 

 

 

Benefit obligation at beginning of year

 

$

378,691

 

$

364,794

 

$

356,293

 

Service cost

 

2,777

 

1,757

 

1,484

 

Interest cost

 

22,742

 

23,190

 

24,512

 

Plan amendments

 

3,301

 

3,978

 

576

 

Change due to transfers

 

(1,144

)

(2,759

)

 

Benefits paid

 

(30,520

)

(33,539

)

(34,823

)

Actuarial (gain) or loss and other

 

26,529

 

21,270

 

16,752

 

Benefit obligation at end of year

 

$

402,376

 

$

378,691

 

$

364,794

 

 

 

 

 

 

 

 

 

Change in plan assets

 

 

 

 

 

 

 

Fair value of plan assets at beginning of year

 

$

297,778

 

$

196,314

 

$

233,944

 

Actual return on plan assets

 

39,240

 

47,152

 

(15,648

)

Employer contributions

 

34,492

 

89,125

 

336

 

Change due to transfers

 

(1,071

)

238

 

13,814

 

Benefits paid

 

(30,520

)

(33,539

)

(34,824

)

Administrative expenses

 

(1,764

)

(1,512

)

(1,308

)

Fair value of plan assets at end of year

 

$

338,155

 

$

297,778

 

$

196,314

 

 

 

 

 

 

 

 

 

Reconciliation of funded status

 

 

 

 

 

 

 

Funded status

 

$

(64,221

)

$

(80,913

)

$

(168,480

)

Unrecognized actuarial (gain) or loss

 

70,304

 

56,219

 

60,313

 

Unrecognized transition (asset) or obligation

 

(1,455

)

(2,183

)

(3,199

)

Unrecognized prior service cost

 

31,505

 

32,275

 

32,265

 

Net amount recognized at end of year

 

$

36,133

 

$

5,398

 

$

(79,101

)

 

 

 

 

 

 

 

 

Other Benefits:

 

 

 

 

 

 

 

Change in benefit obligation

 

 

 

 

 

 

 

Benefit obligation at beginning of year

 

$

108,030

 

$

93,233

 

$

89,946

 

Service cost

 

895

 

604

 

444

 

Interest cost

 

6,524

 

6,872

 

5,956

 

Plan amendments

 

355

 

7,380

 

 

Benefits paid

 

(7,119

)

(9,313

)

(4,988

)

Actuarial (gain) or loss

 

4,265

 

9,254

 

1,875

 

Benefit obligation at end of year

 

$

112,950

 

$

108,030

 

$

93,233

 

 

 

 

 

 

 

 

 

Change in plan assets

 

 

 

 

 

 

 

Fair value of plan assets at beginning of year

 

$

674

 

$

1,478

 

$

2,802

 

Actual return on plan assets

 

(2,007

)

2,076

 

(533

)

Employer contributions

 

9,339

 

6,401

 

4,213

 

Change due to transfers

 

(105

)

 

 

Benefits paid

 

(7,126

)

(9,281

)

(5,004

)

Fair value of plan assets at end of year

 

$

775

 

$

674

 

$

1,478

 

 

 

 

 

 

 

 

 

Reconciliation of funded status

 

 

 

 

 

 

 

Funded status

 

$

(112,175

)

$

(107,356

)

$

(91,755

)

Unrecognized actuarial (gain) or loss

 

29,414

 

23,724

 

16,971

 

Unrecognized transition (asset) or obligation

 

5,357

 

6,027</