UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q10-Q/A
(Mark One) AMENDMENT NO. 1 TO
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 20042005
Or
[_] TRANSITION REPORT PURSUANT TO1TO SECTION 13 OR 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission Registrant, State of Incorporation IRS Employer
File Number Address, and Telephone Number Identification No.
1-2893 Louisville Gas and Electric Company 61-0264150
(A Kentucky Corporation)
220 West Main Street
P.O. Box 32010
Louisville, KY 40232
(502) 627-2000
1-3464 Kentucky Utilities Company 61-0247570
(A Kentucky and Virginia Corporation)
One Quality Street
Lexington, KY 40507-1428
(859) 255-2100
Indicate by check mark whether the registrant (1) has 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
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes X.X No _._
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes No X
Indicate by check mark whether the registrant is a shell company (as
defined in Exchange Act Rule 12b-2). Yes No X
Indicate the number of shares outstanding of each of the issuer's classes
of common stock, as of the latest practicable date:
Louisville Gas and Electric Company - 21,294,223 shares, without par
value, as of October 31, 2004,31,2005, all held by LG&E Energy LLC
Kentucky Utilities Company - 37,817,878 shares, without par value, as of
October 31, 2004,2005, all held by LG&E Energy LLC
This combined Form 10-Q10-Q/A 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
related to the other registrants.
New PageEXPLANATORY NOTE
Kentucky Utilities Company is filing this Amendment No. 1 on Form 10-Q/A for
the quarterly period ended September 30, 2005, to reflect a correction to
information contained in a single paragraph as described below in Part 1,
Item 2, "Management's Discussion and Analysis of Financial Condition and
Results of Operations" ("MD&A") of the original Form 10-Q. For reasons not
understood by the Company, the final version of Kentucky Utility Company's
original Form 10-Q did not agree with the Edgarized version. This
filing modifies the originally filed document to agree with the final
version. Except as described in this Explanatory Note, no other MD&A
information and no other information included in the original Form 10-Q
("Original Filing") is amended hereby.
As reflected in this Form 10-Q/A, the below-excerpted paragraph in KU's
"Results of Operations" for the "Three Months Ended September 30, 2005,
Compared to the Three Months Ended September 30, 2004" contains corrections
to each of the two sub-paragraphs (bullet-points). The paragraph, as
corrected, reads as follows:
Fuel for electric generation increased $40.3 million (52%) in 2005
primarily due to:
- Increased cost per Btu (36% higher), resulting in $31.2 million
higher fuel costs. Fuel costs are significantly higher due to
the MISO's dispatch of gas-fired units committed by the MISO's
Reliability Assessment and Commitment process in the real-time
market.
- Increased generation (12%) higher, resulting in $9.0 million
higher fuel costs, primarily due to higher dispatch of gas-fired
units
While this combined Form 10-Q/A contains information relating to Louisville
Gas and Electric Company due to the combined nature of its reporting
documents and process with its sister company, KU, no change or amendment
is hereby made to any LG&E information or items contained in that company's
original Form 10-Q.
Pursuant to Rule 12b-15 under the Securities Exchange Act of 1934, as a
result of this Amendment No. 1, the certifications of our Chief Executive
Officer and Chief Financial Officer required by Sections 302 and 906 of the
Sarbanes-Oxley Act of 2002, which were filed and furnished, respectively,
as exhibits to the Original Filing, have been re-executed and re-filed and
re-furnished, respectively, as of the date of this Form 10Q/A and are
attached to Amendment No. 1 as Exhibits 31.1, 31.2, 31.3, 31.4 and 32,
respectively.
For the convenience of the reader, Amendment No. 1 sets forth the Original
Filing in its entirety. However, except as described above, no other
information in the Original Filing is amended hereby. This Amendment No. 1
does not reflect events occurring after the filing of the Original Filing
or modify or update those disclosures in any way other than as required to
reflect the amendments as described above and set forth below.
INDEX OF ABBREVIATIONS
AG Attorney General of Kentucky
ARO Asset Retirement Obligation
CCN Certificate of Public Convenience and Necessity
DSM Demand Side Management
ECR Environmental Cost Recovery
EEI Electric Energy, Inc.
EITF Emerging Issues Task Force
E.ON E.ON AG
EPA Environmental Protection Agency
EPAct 2005 Energy Policy Act of 2005
ESM Earnings Sharing Mechanism
FAC Fuel Adjustment Clause
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
Fidelia Fidelia Corporation (an E.ON affiliate)
FIN FASB Interpretation No.
FGD Flue Gas Desulfurization
FSP FASB Staff Position
FTR Financial Transmission Right
IMEA Illinois Municipal Electric Agency
IMPA Indiana Municipal Power Agency
ITP Independent Transmission Provider
IRS Internal Revenue Service
Kentucky Commission Kentucky Public Service Commission
KIUC Kentucky Industrial Utility Consumers, Inc.
KU Kentucky Utilities Company
LIBOR London Interbank Offer Rate
LG&E Louisville Gas and Electric Company
LG&E Energy LG&E Energy LLC (as successor to LG&E Energy Corp.)
LG&E Services LG&E Energy Services Inc.
LMP Locational Marginal Pricing
MGP Manufactured Gas Plant
MISO Midwest Independent Transmission System Operator,
Inc.
Moody's Moody's Investor Services, Inc.
Mw Megawatts
Mwh Megawatt hours
NOPR Notice of Proposed Rulemaking
NOX Nitrogen Oxide
OMU Owensboro Municipal Utilities
PJM PJM Interconnection, LLC
Powergen Powergen Limited (formerly Powergen plc)
PUHCA Public Utility Holding Company Act of 1935
RSGMWP Revenue Sufficiency Guarantee Make Whole Payment
RTO Regional Transmission Operator
S&P Standard & Poor's Rating Services
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards
SMD Standard Market Design
SO2 Sulfur Dioxide
VDT Value Delivery Team Process
TABLE OF CONTENTS
PART I
ItemITEM 1. FINANCIAL STATEMENTS (UNAUDITED)
LOUISVILLE GAS AND ELECTRIC COMPANY
STATEMENTS OF INCOME 1
Consolidated Financial Statements
Louisville Gas and Electric Company and Subsidiary
Statements of IncomeSTATEMENTS OF RETAINED EARNINGS 1
Statements of Retained Earnings 1
Balance SheetsBALANCE SHEETS 2
Statements of Cash FlowSTATEMENTS OF CASH FLOWS 4
Statements of Other Comprehensive IncomeSTATEMENTS OF OTHER COMPREHENSIVE INCOME 5
Kentucky Utilities Company and Subsidiary
Statements of IncomeKENTUCKY UTILITIES COMPANY
STATEMENTS OF INCOME 6
Statements of Retained EarningsSTATEMENTS OF RETAINED EARNINGS 6
Balance SheetsBALANCE SHEETS 7
Statements of Cash FlowSTATEMENTS OF CASH FLOWS 9
Statements of Other Comprehensive IncomeSTATEMENTS OF OTHER COMPREHENSIVE INCOME 10
Notes to Consolidated Financial StatementsNOTES TO FINANCIAL STATEMENTS 11
Item 2 Management's Discussion and Analysis of F
Financial Condition and Results of Operations 23
Item 3 Quantitative and Qualitative Disclosures
About Market Risk 38
Item 4 Controls and ProceduresITEM 2.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS. 25
ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. 39
ITEM 4.CONTROLS AND PROCEDURES. 41
PART II
Item 1 Legal Proceedings 40
Item 2 Unregistered Sales of Equity Securities
and Use of Proceeds 41
Item 4 Submission of Matters to a Vote of Security Holders 41
Item 6 ExhibitsITEM 1.LEGAL PROCEEDINGS. 42
SignaturesITEM 6.EXHIBITS 43
ExhibitsSIGNATURES 44
New PageEXHIBITS 45
Part I. Financial Information - Item 1. Financial Statements (Unaudited)
Louisville Gas and Electric Company
and Subsidiary
Consolidated Statements of Income
(Unaudited)
(Thousands(Millions of $)
Three Months Nine Months
Ended Ended
September 30, September 30,
2005 2004 20032005 2004
2003
OPERATING REVENUES (Note 5):REVENUES:
Electric (Note 10) $227,024 $230,174 $617,839 $591,110$284.0 $227.0 $741.2 $617.8
Gas 34,818 32,659 242,178 213,93934.6 34.8 259.8 242.2
Total operating revenues 261,842 262,833 860,017 805,049318.6 261.8 1,001.0 860.0
OPERATING EXPENSES:
Fuel for electric generation 53,653 55,628 153,792 151,38279.4 53.8 207.8 154.5
Power purchased (Note 10) 19,344 18,805 65,578 60,24534.1 19.3 101.3 65.6
Gas supply expenses 20,172 19,509 181,919 151,57920.2 20.2 191.5 181.9
Other operation and maintenance
expenses 48,129 51,890 163,300 158,797
Maintenance 23,072 12,526 49,879 42,10987.9 75.4 227.3 227.0
Depreciation and amortization 30,299 28,429 86,021 85,866
Federal and state income taxes 21,089 23,707 45,487 45,062
Property and other taxes 4,343 4,659 14,483 12,84831.1 30.3 93.0 86.0
Total operating expenses 220,101 215,153 760,459 707,888252.7 199.0 820.9 715.0
NET OPERATING INCOME 41,741 47,680 99,558 97,16165.9 62.8 180.1 145.0
Other income (expense)expense (income) - net (1,091) 285 (1,419) (49)
Other income from affiliated
company (Note 10) - 2 - 61.9 (0.1) 2.8
Interest expense (Note 3) 5,072 5,985 15,086 18,0905.6 5.1 17.4 15.1
Interest expense to affiliated
companies (Note 10) 3,040 2,111 9,157 4,1379) 3.0 3.0 9.0 9.1
INCOME BEFORE INCOME TAXES 57.3 52.8 153.8 118.0
Federal and state income
taxes (Note 6) 15.3 20.3 50.0 44.1
NET INCOME $ 32,53842.0 $ 39,87132.5 $103.8 $ 73,896 $ 74,891
Consolidated73.9
The accompanying notes are an integral part of these financial statements.
Statements of Retained Earnings
(Unaudited)
(Thousands(Millions of $)
Three Months Nine Months
Ended Ended
September 30, September 30,
2005 2004 20032005 2004 2003
Balance at beginning of period $516,856 $442,498 $497,441 $409,319$555.4 $516.9 $534.0 $497.4
Net income 32,538 39,871 73,896 74,89142.0 32.5 103.8 73.9
Subtotal 549,394 482,369 571,337 484,210597.4 549.4 637.8 571.3
Cash dividends declared on stock:
5% cumulative preferred 269 269 807 8070.3 0.3 0.8 0.8
Auction rate cumulative preferred 244 174 649 743
$5.875 cumulative preferred (Note 9)0.4 0.2 1.3 0.6
Common - - - 734
Common 21,000 - 42,000 -21.0 39.0 42.0
Subtotal 21,513 443 43,456 2,2840.7 21.5 41.1 43.4
Balance at end of period $527,881 $481,926 $527,881 $481,926$596.7 $527.9 $596.7 $527.9
The accompanying notes are an integral part of these consolidated financial statements.
Page 1
Louisville Gas and Electric Company
and Subsidiary
Consolidated Balance Sheets
(Unaudited)
(Thousands(Millions of $)
ASSETS
September 30, December 31,
2005 2004 2003
UTILITY PLANT:
At original cost $3,880,901 $3,804,183
Less: reserve for depreciation 1,390,301 1,326,899
Net utility plant (Note 7) 2,490,600 2,477,284
OTHER PROPERTY AND INVESTMENTS -
less reserve of $63 as of September 30, 2004
and December 31, 2003 508 611
CURRENT ASSETS:
Cash and cash equivalents 5,902 1,706
Restricted cash 11,524 -$ 5.8 $ 6.8
Accounts receivable -
less reserve of $1,415$1.2 million and $3,515$0.8 million
as of September 30, 20042005 and December 31, 2003,2004,
respectively (Note 4) 108,761 84,585131.3 167.0
Materials and supplies - at average cost:
Fuel (predominantly coal) 22,268 25,26029.0 21.8
Gas stored underground 76,416 69,884106.8 77.5
Other 26,214 24,97127.5 26.1
Prepayments and other 1,634 5,28115.6 3.9
Total current assets 252,719 211,687316.0 303.1
OTHER PROPERTY AND INVESTMENTS -
less reserve of less than $0.1 million as of
September 30, 2005 and December 31, 2004 0.6 0.5
UTILITY PLANT:
At original cost 4,010.8 3,915.8
Less: reserve for depreciation 1,485.8 1,396.3
Net utility plant 2,525.0 2,519.5
DEFERRED DEBITS AND OTHER ASSETS:
Restricted cash 12.2 10.9
Unamortized debt expense 8,555 8,7538.5 8.4
Regulatory assets (Note 6) 100,183 143,6265) 73.3 91.9
Other 32,789 40,12131.8 32.2
Total deferred debits and other assets 141,527 192,500125.8 143.4
Total assets $2,885,354 $2,882,082$2,967.4 $2,966.5
The accompanying notes are an integral part of these consolidated financial statements.
Page 2
Louisville Gas and Electric Company
and Subsidiary
Consolidated Balance Sheets (cont.)
(Unaudited)
(Thousands(Millions of $)
CAPITALIZATION AND LIABILITIES
September 30, December 31,
2005 2004 2003
CAPITALIZATION:
Common stock, without par value -
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 loss (39,902) (38,111)
Retained earnings 527,881 497,441
Total common equity 952,313 923,664
Cumulative preferred stock 70,425 70,425
Mandatorily redeemable preferred stock (Note 9) 21,250 22,500
Long-term debt (Note 9) 328,104 328,104
Long-term debt to affiliated company (Note 9) 225,000 200,000
Total long-term debt 574,354 550,604
Total capitalization 1,597,092 1,544,693
CURRENT LIABILITIES:
Current portion of mandatorily
redeemable preferred stock (Note 9) 1,250 1,250
Current portion of long-term debt (Note 9) 246,200 246,2008) $247.5 $247.5
Current portion of long-term debt to
affiliated company (Note 9) 50,0008) - 50.0
Notes payable to affiliated companies (Note 9) 40,700 80,3328) 56.6 58.2
Accounts payable 62,959 93,118107.5 106.1
Accounts payable to affiliated companies (Note 10) 22,455 38,3439) 57.8 31.7
Accrued income taxes 8,330 11,472- 6.2
Customer deposits 12,255 10,493
Accrued interest 2,593 1,999
Accrued interest to affiliated company (Note 10) 2,996 2,75016.7 14.0
Other 18,493 11,784- 18.5
Total current liabilities 468,231 497,741486.1 532.2
DEFERRED CREDITS AND OTHER LIABILITIES:
Accumulated deferred income taxes - net 347,092 337,704324.4 347.2
Investment tax credit, in process of amortization 47,202 50,32943.1 46.2
Accumulated provision for pensions
and related benefits 109,436 140,598123.2 120.6
Customer advances for construction 10,637 9,8909.6 10.6
Asset retirement obligation 10,155 9,74710.7 10.3
Regulatory liabilities (Note 6)5):
Accumulated cost of removal of utility plant 214,950 216,491218.8 220.2
Deferred income taxes - net (Note 6) 52.7 37.2
Other 53,535 51,822
Long-term derivative liability (Note 3) 18,883 15,9669.5 15.0
Other 8,141 7,10132.2 29.4
Total deferred credits and other liabilities 820,031 839,648824.2 836.7
CAPITALIZATION:
Common stock, without par value -
Outstanding 21,294,223 shares 425.2 425.2
Common stock expense (0.8) (0.8)
Additional paid-in capital 40.0 40.0
Accumulated other comprehensive loss (47.5) (45.6)
Retained earnings 596.7 534.0
Total common equity 1,013.6 952.8
Cumulative preferred stock 70.4 70.4
Mandatorily redeemable preferred stock 20.0 21.3
Long-term debt (Note 8) 328.1 328.1
Long-term debt to affiliated company (Note 8) 225.0 225.0
Total capitalization 1,657.1 1,597.6
Total capital and liabilities $2,885,354 $2,882,082$2,967.4 $2,966.5
The accompanying notes are an integral part of these consolidated financial statements.
Page 3
Louisville Gas and Electric Company
and Subsidiary
Consolidated StatementStatements of Cash Flows
(Unaudited)
(Thousands(Millions of $)
Nine Months Ended
September 30,
2005 2004 2003
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 73,896103.8 $ 74,89173.9
Items not requiring cash currently:
Depreciation and amortization 86,021 85,86693.0 86.0
Value delivery team amortization 22.6 22.6
Deferred income taxes - net 6,803 24,589(7.3) 6.8
Investment tax credit - net (3,127) (3,156)
Value Delivery Team (VDT) amortization (Note 6) 22,601 22,866
Mark-to-market financial instruments (Note 3) 2,916 (651)
Provision for post-retirement benefits (Note 8) (8,047) (4,801)(3.1) (3.1)
Other (147) 7,997(1.0) 2.8
Changes in current assets and liabilities (10,576) (28,028)
Changesliabilities-net (8.4) (10.6)
Change in accounts receivable securitization-net (Note 4) (58,000) 11,600securitization - net - (58.0)
Pension funding (Notes 9 and 12) (34,492) (89,125)(Note 11) - (34.5)
Provision for post-retirement benefits 2.6 (8.1)
Gas supply clause (Note 6) 12,008 (14,970)receivable, net (2.8) 12.0
Earnings sharing mechanism (Note 6) 6,913 6,189
Combustion turbine litigationreceivable 2.1 6.9
Litigation settlement 7,003 - 7.0
Other 15,460 10,698(12.1) 15.5
Net cash flows fromprovided by operating activities 119,232 103,965189.4 119.2
CASH FLOWS FROMUSED IN INVESTING ACTIVITIES:
Proceeds from sales of securities 103 153Change in restricted cash (1.3) (11.5)
Construction expenditures (94,220) (153,064)(95.0) (94.2)
Other (0.1) 0.1
Net cash flows fromused for investing activities (94,117) (152,911)(96.4) (105.6)
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in restricted cash (11,524)Issuance of long-term debt (Note 8) 38.5 -
Retirement of long-term debt (Note 8) (40.0) -
Long-term borrowings from affiliated
company (Note 9) 125,000 200,0008) - 125.0
Repayment of long-term borrowings
from affiliated company (Note 8) (50.0) (50.0)
Short-term borrowings from affiliated
company (Note 9) 399,550 478,800
Repayment of long-term borrowings from d
affiliated company (Note 9) (50,000) -8) 480.5 399.5
Repayment of short-term borrowings
from affiliated company (Note 9) (439,182) (596,721)
Retirement of mandatorily redeemable preferred
stock (Note 9) (1,250) (1,250)
Retirement of first mortgage bonds - (42,600)
Issuance costs of pollution control bonds (135) -(482.1) (439.2)
Payment of common dividends (42,000) -
Payment of preferred dividends (1,378) (2,898)(41.1) (43.4)
Other 0.2 (1.3)
Net cash flows fromused for financing activities (20,919) 35,331(94.0) (9.4)
CHANGE IN CASH AND CASH EQUIVALENTS 4,196 (13,615)(1.0) 4.2
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 1,706 17,0156.8 1.7
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 5,9025.8 $ 3,4005.9
SUPPLEMENTAL DISCLOSURES:
Cash paid during the period for:
Income taxes $ 42,375 $ 12,968$74.6 $42.4
Interest on borrowed money 12,674 17,20415.8 12.7
Interest to affiliated companies on borrowed money 8,937 1,7079.7 8.9
The accompanying notes are an integral part of these consolidated financial statements.
Page 4
Louisville Gas and Electric Company and Subsidiary
Consolidated
Statements of Other Comprehensive Income
(Unaudited)
(Thousands(Millions of $)
Three Months Nine Months
Ended Ended
September 30, September 30,
2005 2004 20032005 2004 2003
Net income $32,538 $39,871 $73,896 $74,891
Gains/(losses)$42.0 $32.5 $103.8 $73.9
Income Taxes - Minimum Pension
Liability - - (1.1) -
Gain (loss) on derivative instruments
and hedging activities - net of
tax benefit/benefit / (expense) of
$3,639, $(1,416)$(3.1), $1,189$3.6, $0.9 and
$(382), $1.2,respectively (Note 3) (5,457) 2,123 (1,790) 5735.3 (5.4) (0.8) (1.8)
Other comprehensive income (loss),
net of tax 5.3 (5.4) (1.9) (1.8)
Comprehensive income $27,081 $41,994 $72,106 $75,464$47.3 $27.1 $101.9 $72.1
The accompanying notes are an integral part of these consolidated financial statements.
Page 5
Kentucky Utilities Company and Subsidiary
Consolidated
Statements of Income
(Unaudited)
(Thousands(Millions of $)
Three Months Nine Months
Ended Ended
September 30, September 30,
2005 2004 20032005 2004 2003
OPERATING REVENUES (Note 10) $252,669 $235,426 $732,424 $657,583$347.2 $252.6 $898.7 $732.4
OPERATING EXPENSES:
Fuel for electric generation 78,151 75,300 215,666 201,264118.5 78.2 290.0 215.9
Power purchased (Note 10) 33,182 31,702 105,152 106,55064.8 33.2 161.1 105.1
Other operation and maintenance
expenses 37,844 35,603 112,834 112,622
Maintenance 12,070 13,031 40,978 49,40080.1 54.2 206.3 166.5
Depreciation and amortization 29,065 24,751 80,265 76,663
Federal and state income taxes 19,565 18,196 58,127 32,263
Property and other taxes 4,406 4,067 12,942 12,23028.4 29.1 86.1 80.3
Total operating expenses 214,283 202,650 625,964 590,992291.8 194.7 743.5 567.8
NET OPERATING INCOME 38,386 32,776 106,460 66,59155.4 57.9 155.2 164.6
Other income - net 3,094 2,140 6,514 6,944
Other income (expense) from
affiliated company (Note 10) 11 5 26 4(1.1) (2.2) (3.3) (4.0)
Interest expense (Note 3) 3,116 2,695 7,532 13,8083.1 3.2 10.1 7.6
Interest expense to affiliated
companies (Note 10) 3,557 1,916 10,641 3,4019) 4.2 3.5 11.4 10.6
NET INCOME BEFORE INCOME TAXES 49.2 53.4 137.0 150.4
Federal and state income
taxes (Note 6) 17.5 18.6 50.0 55.6
NET INCOME $ 34,81831.7 $ 30,31034.8 $ 94,82787.0 $ 56,330
Consolidated94.8
The accompanying notes are an integral part of these financial statements.
Statements of Retained Earnings
(Unaudited)
(Thousands(Millions of $)
Three Months Nine Months
Ended Ended
September 30, September 30,
2005 2004 20032005 2004 2003
Balance at beginning of period $629,051 $526,916 $591,170 $502,024$673.6 $629.1 $659.4 $591.2
Net income 34,818 30,310 94,827 56,33031.7 34.8 87.0 94.8
Subtotal 663,869 557,226 685,997 558,354705.3 663.9 746.4 686.0
Cash dividends declared on stock:
4.75% cumulative preferred 237 237 712 7110.3 0.3 0.7 0.7
6.53% cumulative preferred 327 327 980 9810.4 0.3 1.1 1.0
Common 21,000 - 42,000 -10.0 21.0 50.0 42.0
Subtotal 21,564 564 43,692 1,69210.7 21.6 51.8 43.7
Balance at end of period $642,305 $556,662 $642,305 $556,662$694.6 $642.3 $694.6 $642.3
The accompanying notes are an integral part of these consolidated financial statements.
Page 6
Kentucky Utilities Company
and Subsidiary
Consolidated Balance Sheets
(Unaudited)
(Thousands(Millions of $)
ASSETS
September 30, December 31,
2005 2004 2003
UTILITY PLANT:
At original cost $3,670,707 $3,596,657
Less: reserve for depreciation 1,403,583 1,360,253
Net utility plant (Note 7) 2,267,124 2,236,404
OTHER PROPERTY AND INVESTMENTS -
less reserve of $131 as of September 30, 2004 and
December 31, 2003 19,721 17,862
CURRENT ASSETS:
Cash and cash equivalents 4,677 4,869$ 4.2 $ 4.6
Restricted cash 13.3 -
Accounts receivable - less reserve of
$482 and $672$0.6 million as of September 30, 20042005
and December 31, 2003,
respectively (Note 4) 97,437 49,2892004 119.6 112.6
Materials and supplies - at average cost:
Fuel (predominantly coal) 30,260 45,53850.3 52.2
Other 27,653 27,09429.4 28.0
Prepayments and other 6,802 13,10012.2 9.9
Total current assets 166,829 139,890229.0 207.3
OTHER PROPERTY AND INVESTMENTS -
less reserve of $0.1 million as of September 30,
2005 and December 31, 2004 22.1 20.5
UTILITY PLANT:
At original cost 3,788.4 3,712.1
Less: reserve for depreciation 1,486.7 1,415.0
Net utility plant 2,301.7 2,297.1
DEFERRED DEBITS AND OTHER ASSETS:
Unamortized debt expense 4,295 4,4814.6 4.7
Regulatory assets (Note 6) 62,668 72,3185) 70.6 61.4
Long-term derivative asset (Note 3) 7,530 12,2231.5 6.1
Cash surrender value of key man
life insurance 32.0 3.6
Other 12,164 21,91610.0 9.7
Total deferred debits and other assets 86,657 110,938118.7 85.5
Total assets $2,540,331 $2,505,094$2,671.5 $2,610.4
The accompanying notes are an integral part of these consolidated financial statements.
Page 7
Kentucky Utilities Company
and Subsidiary
Consolidated Balance Sheets (cont.)
(Unaudited)
(Thousands(Millions of $)
CAPITALIZATION AND LIABILITIES
September 30, December 31,
2005 2004 2003
CAPITALIZATION:
Common stock, without par value -
Outstanding 37,817,878 shares $ 308,140 $ 308,140
Common stock expense (322) (322)
Additional paid-in capital 15,000 15,000
Accumulated other comprehensive loss (6,071) (6,031)
Retained earnings 642,305 591,170
Total common equity 959,052 907,957
Cumulative preferred stock 39,727 39,727
Long-term debt (Note 9) 307,564 312,646
Long-term debt to affiliated company (Note 9) 333,000 283,000
Total long-term debt 640,564 595,646
Total capitalization 1,639,343 1,543,330
CURRENT LIABILITIES:
Current portion of long-term debt (Note 9) 87,130 91,9308) $ 123.1 $ 87.1
Current portion of long-term notes to
affiliated company (Note 8) 75.0 75.0
Notes payable to affiliated company (Note 9) 29,830 43,2318) 31.8 34.8
Accounts payable 41,317 69,94767.5 77.9
Accounts payable to affiliated companies (Note 10) 18,979 26,4269) 58.1 32.8
Accrued income taxes 12,337 7,104- 5.9
Customer deposits 14,163 13,453
Accrued interest 3,019 2,024
Accrued interest to affiliated company (Note 10) 3,866 2,45416.7 15.0
Other 20,566 9,7670.4 15.4
Total current liabilities 231,207 266,336372.6 343.9
DEFERRED CREDITS AND OTHER LIABILITIES:
Accumulated deferred income taxes - net 274,207 261,258278.0 282.6
Investment tax credit, in process of amortization 4,318 5,8592.5 3.8
Accumulated provision for pensions and
related benefits 65,260 103,101
Customer advances for construction 1,608 1,56481.0 77.9
Asset retirement obligation 20,661 19,69821.9 21.0
Regulatory liabilities (Note 6)5):
Accumulated cost of removal of utility plant 262,971 256,744277.6 266.8
Deferred income taxes - net (Note 6) 29.9 19.3
Other 28,301 38,02710.4 5.4
Other 12,455 9,17718.3 17.0
Total deferred credits and other liabilities 669,781 695,428719.6 693.8
CAPITALIZATION:
Common stock, without par value -
Outstanding 37,817,878 shares 308.1 308.1
Common stock expense (0.3) (0.3)
Additional paid-in capital 15.0 15.0
Accumulated other comprehensive loss (13.6) (13.3)
Retained earnings 680.9 647.3
Undistributed subsidiary earnings 13.7 12.1
Total retained earnings 694.6 659.4
Total common equity 1,003.8 968.9
Cumulative preferred stock (Note 12) 39.7 39.7
Long-term debt (Note 8) 227.8 306.1
Long-term debt to affiliated company (Note 8) 308.0 258.0
Total capitalization 1,579.3 1,572.7
Total capital and liabilities $2,540,331 $2,505,094$2,671.5 $2,610.4
The accompanying notes are an integral part of these consolidated financial statements.
Page 8
Kentucky Utilities Company
and Subsidiary
Consolidated StatementStatements of Cash Flows
(Unaudited)
(Thousands(Millions of $)
Nine Months Ended
September 30,
2005 2004 2003
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 94,82787.0 $ 56,33094.8
Items not requiring cash currently:
Depreciation and amortization 80,265 76,663
Deferred income taxes - net 11,064 10,277
Investment tax credit - net (1,540) (1,981)86.1 80.3
Value Delivery Team (VDT)delivery team amortization (Note 6) 8,816 9,091
Mark-to-market financial8.8 8.8
Change in fair value of derivative instruments (Note 3) (389) 1,231
Provision for post-retirement benefits (Note 8) (3,373) (4,417)
Deferred storm costs (3,760) -(5.5) (0.4)
Other 2,401 15,2128.4 8.2
Changes in current assets and liabilities 3,164 (4,888)(13.1) 3.2
Changes in accounts receivable securitizationsecuritization-net - net (Note 4) (50,000) -
Pension funding (Notes 9 and 12) (43,409) (9,515)(50.0)
Earnings sharing mechanism receivable 3.1 4.9
Pension funding (Note 6) 4,920 7,708
Environmental cost recovery mechanism (Note 6) (7,089) 1,157
Combustion turbine litigation11) - (43.4)
Provision for post-retirement benefits 3.1 (3.4)
Litigation settlement 11,426 - 11.4
Fuel adjustment clause receivable (18.4) (1.1)
Other 10,231 23,242(2.0) 4.3
Net cash provided by operating activities 157.5 117.6
CASH FLOWS USED IN INVESTING ACTIVITIES:
Change in restricted cash (13.3) -
Construction expenditures (76.3) (104.0)
Other - (1.9)
Net cash flows from operating activities 117,554 180,110
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of securities (1,858) (2,818)
Construction expenditures (103,992) (263,899)
Net cash flows fromused for investing activities (105,850) (266,717)(89.6) (105.9)
CASH FLOWS FROM FINANCING ACTIVITIES:
Long-term borrowings from affiliated
company (Note 9) 50,000 175,0008) 50.0 50.0
Short-term borrowings from affiliated
company (Note 9) 380,500 520,8408) 462.3 380.5
Repayment of long-term debt - -
Repayment of short-term borrowings
from affiliated company (Note 9) (393,900) (541,600)
Retirement8) (465.4) (393.9)
Proceeds from issuance of first mortgagepollution control bonds 13.3 - (62,000)
Retirement of pollution control bonds (4,800) -
Refund(50.0) (4.8)
Repayment of issuance costs of pollution
control bonds (4)other borrowings (Note 8) (26.7) -
Payment of common dividends (42,000) -
Payment of preferred dividends (1,692) (1,692)(51.8) (43.7)
Net cash flows fromused for financing activities (11,896) 90,548(68.3) (11.9)
CHANGE IN CASH AND CASH EQUIVALENTS (192) 3,941(0.4) (0.2)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 4,869 5,3914.6 4.9
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 4,6774.2 $ 9,3324.7
SUPPLEMENTAL DISCLOSURES:
Cash paid during the period for:
Income taxes $ 40,792 $ 19,012$58.3 $40.8
Interest on borrowed money 9,195 12,6815.1 9.2
Interest to affiliated companies on borrowed money 9,269 1,0606.7 9.3
The accompanying notes are an integral part of these consolidated financial statements.
Page 9
Kentucky Utilities Company and Subsidiary
Consolidated
Statements of Other Comprehensive Income
(Unaudited)
(Thousands(Millions of $)
Three Months Nine Months
Ended Ended
September 30, September 30,
2005 2004 20032005 2004 2003
Net income $34,818 $30,310 $94,827 $56,330
Losses on derivative instruments
and hedging activities$31.7 $34.8 $87.0 $94.8
Income Taxes - Minimum Pension
Liability - - (0.3) -
Other comprehensive loss, net of tax benefit/(expense) of $17, ($121), $23
and ($121), respectively (Note 3) (26) 182 (40) 182- - (0.3) -
Comprehensive income $34,792 $30,492 $94,787 $56,512$31.7 $34.8 $86.7 $94.8
The accompanying notes are an integral part of these consolidated financial statements.
Page 10
Louisville Gas and Electric Company
and Subsidiary
Kentucky Utilities Company
and Subsidiary
Notes to Consolidated Financial Statements
(Unaudited)
1. General
The unaudited condensed financial statements include the accounts of Louisville GasLG&E and Electric Company and Subsidiary and Kentucky
Utilities Company and Subsidiary (each "LG&E" and "KU", or the
"Companies").KU.
The common stock of each of LG&E and KU is wholly-owned by LG&E Energy LLC ("LG&E Energy").Energy.
In the opinion of management, the unaudited condensed interim financial
statements include all adjustments, consisting only of normal recurring
adjustments, necessary for a fair statement of consolidated financial position,
results of operations, comprehensive income and cash flows for the
periods indicated. Certain information and footnote disclosures
normally included in financial statements prepared in accordance with
generally accepted accounting principles have been condensed or omitted
pursuant to Securities and
Exchange Commission ("SEC")SEC rules and regulations, although the Companies believe
that the disclosures are adequate to make the information presented not
misleading.
See LG&E's and KU's Annual Reports on Form 10-K for the year ended
December 31, 2003,2004, for information relevant to the accompanying
financial statements, including information as to the significant
accounting policies of the Companies.
During the second quarter of 2005, LG&E and KU made out-of-period
adjustments for estimated over/under collection of ECR revenues to be
billed in subsequent periods. The adjustments were immaterial during
all reporting periods involved (March 2003 through October 2004 for
LG&E and May 2003 through January 2005 for KU). As a result, year-to-
date LG&E revenues were increased $4.8 million and KU revenues were
decreased $2.4 million. Year-to-date net income was increased $2.9
million for LG&E and was reduced $1.5 million for KU.
During the third quarter of 2005, LG&E and KU reclassified RSGMWP from
other operation and maintenance expenses to other revenue to better
reflect this revenue as part of the sales price paid by MISO. As a
result, LG&E's revenues and expenses increased $12.6 million and KU's
revenues and expenses increased $3.1 million. Also, during the third
quarter, the estimated allocation of RSGMWP between LG&E and KU was
revised based on better information about the percent of generation
contributed for the hour(s) the make whole payment was received. As a
result, LG&E revenues were decreased $6.7 million and KU revenues were
increased $6.7 million in the current period results of operations. Net
income in the current period was decreased $4.0 million for LG&E and
was increased $4.0 million for KU.
The accompanying financial statements for the three months and nine
months ended September 30, 2003,2004, have been revised to conform to
certain reclassifications in the current three months and nine months
ended September 30, 2004.2005. These reclassifications had no impact on the
balance sheet net
assets or net income, as previously reported.
LG&E and KU net operating income previously reported for the three
months ended September 30, 2004, increased by $21.1 million and $19.5
million, and for the nine months ended September 30, 2004, increased by
$45.5 million and $58.1 million, respectively, because the income
statement presentation was changed in 2005 to report income tax expense
in the category Federal and State income taxes, which appears just
before net income. LG&E other(income)expense - net previously reported
for the three months and nine months ended September 30, 2004,
increased $0.8 million and $1.4 million, respectively, as a result of
the reclassification. KU other income - net decreased $0.9 million and
$2.5 million, respectively, as a result of the reclassification.
2. Mergers and Acquisitions
LG&E and KU are each subsidiaries of LG&E Energy. InOn July 1, 2002, E.ON
AG ("E.ON"), a German company, completed its acquisition of Powergen, Limited ("Powergen"),including
LG&E Energy, for approximately 5.1 billion pounds sterling ($7.3
billion). As a result of the former parent companyacquisition, LG&E Energy became a
wholly-owned subsidiary of LG&E Energy. AsE.ON and, as a result, LG&E and KU also
became indirect subsidiaries of E.ON. LG&E and KU have continued
their separate identities and serve customers under their existing
names. The preferred stock and debt securities of LG&E and KU were
not affected by this transaction and the utilities continue to file
SEC reports. Following the purchase of Powergen by E.ON,acquisition, E.ON became a registered
holding company under the Public Utility Holding Company ActPUHCA (for discussion of 1935
("PUHCA")recent changes to PUHCA,
see EPAct 2005 under Note 5). As a result, E.ON, its utility subsidiaries, including LG&E and KU, and certainas subsidiaries of its non-utility subsidiariesa
registered holding company, are subject to extensive regulation by the SECadditional regulations 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.PUHCA. 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.
As contemplated in their regulatory filings in connection with the E.ON
acquisition,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. This reorganization was
effective in March 2003. In early
2004, LG&E Energy begancommenced direct reporting arrangements to E.ON.
The utility operations (LG&E and KU) of LG&E Energy have continued
their separate identities and continue to serve customers in Kentucky,
Virginia and Tennessee under their existing names. The preferred stock
and debt securities of LG&E and KU were not affected by these
transactions and LG&E and KU continue to file SEC reports.
Page 11
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. Following the conversion, LG&E Energy became a
registered holding company under PUHCA.
3. Financial Instruments
The Companies use interest rate swaps to hedge exposure to market
fluctuations in certain of their debt instruments. Pursuant to the
Companies' policies, 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 Companies' 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. 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 terminationincome to correspond with
income or expense recognized from changes in market value of any fair value hedge,
the resulting gain or loss is recorded into net income.items
being hedged.
As of September 30, 2004,2005, LG&E was party to various interest rate swap
agreements with aggregate notional amounts of $228.3$211.3 million. 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 1.37%2.61% at September 30, 2004.2005. The swap
agreements in effect at September 30, 20042005, have been designated as
cash flow hedges and mature on dates ranging from 20052020 to 2033. The
hedges have been deemed to be fully effective resulting in a pretax
lossgain of $9.1$8.4 million and a pretax loss of $2.9$1.7 million for the three
months and nine months ended September 30, 2004,2005, respectively, recorded
in other comprehensive income. Upon expiration of these hedges, the
amount recorded in other comprehensive income will be reclassified into
earnings. The amountsamount expected to be reclassified from other
comprehensive income to earnings in the next twelve months areis
immaterial. A deposit in the amount of $12.2 million, used as
collateral for an $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.
In February 2005, an LG&E interest rate swap with a notional amount of
$17 million matured. The swap was fully effective upon expiration. As a
result, the impact on earnings and other comprehensive income from the
swap maturity was less than $0.1 million.
As of September 30, 2004,2005, KU was party to variousone interest rate swap
agreementsagreement with aggregatea notional amountsamount of $103.0$53.0 million. Under thesethis swap
agreements,agreement, KU paid a variable ratesrate based on eitherthe LIBOR or
the Bond Market Association's municipal swap index averaging 2.70%of 5.86%,
and received a fixed rates averaging 7.74%rate of 7.92% at September 30, 2004.2005. The swap
agreementsagreement in effect at September 30, 2004 have2005 has been designated as a fair
value hedgeshedge and mature on dates ranging from 2007 to 2025.matures in 2007. During the three months and nine
months ended September 30, 2004,2005, the effect of marking thesethis financial
instrumentsinstrument and the underlying debt to market resulted in a net pretax gaingains
of $0.3$0.4 million and $1.0$0.9 million,
(representing the hedges' ineffectiveness), respectively, recorded in interest
expense, as required under SFAS No. 133 to recognize fair value hedge
effectiveness.
In June 2005, a KU interest rate swap with a notional amount of $50
million was terminated by the counterparty pursuant to the terms of the
swap agreement. KU received a payment of $1.9 million in consideration
for the termination of the agreement. KU also called the underlying
debt (First Mortgage Bond Series R) and paid a call premium of $1.9
million. The swap was fully effective upon termination. No impact on
earnings occurred as a decrease in interest expense.result of the bond call and related swap
termination.
Interest rate swaps hedge interest rate risk on the underlying debt.
Under SFAS No. 133, Accounting for Derivative Instruments and Hedging
Activities, in addition to swaps being marked to market, the item being
hedged using a fair value hedge must also be marked to market.
Consequently at September 30, 2004,2005, KU's debt reflects an increase of
$9.7a $2.7 million related to such
mark-to-market adjustment.
In February 2004, KU terminated the swap it had in place related to
its 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, resulting in a gain of $0.8
million.
Page 12
4. Accounts Receivable Securitization Programs
In January 2004, LG&E and KU terminated their accounts receivable
securitization programs, originally implemented in February 2001, and
replaced them with intercompany loans from an E.ON affiliate. In May
2004, LG&E and KU dissolved their inactive accounts receivable
securitization-related subsidiaries, LG&E Receivables LLC and KU
Receivables LLC. The accounts receivable securitization-related
subsidiaries were the only subsidiaries of LG&E and KU.
5. Segments of Business
LG&E's revenues, and net income and total assets by business segment for
the three months and nine months ended September 30, 20042005 and 2003,2004,
follow:
Three Months Ended Nine Months Ended
September 30, September 30,
(in thousands)millions) 2005 2004 20032005 2004 2003
LG&E Electric
Revenues $227,024 $230,174 $617,839 $591,110$284.0 $227.0 $741.2 $617.8
Net income 34,648 41,924 71,031 69,41345.3 34.6 99.1 71.0
Total assets 2,416.1 2,376.7 2,416.1 2,376.7
LG&E Gas
Revenues 34,818 32,659 242,178 213,93934.6 34.8 259.8 242.2
Net (loss) income (3.3) (2.1) 4.7 2.9
Total assets 551.3 508.7 551.3 508.7
Total
Revenues 318.6 261.8 1,001.0 860.0
Net income (2,110) (2,053) 2,865 5,47842.0 32.5 103.8 73.9
Total Revenues 261,842 262,833 860,017 805,049
Net income 32,538 39,871 73,896 74,891assets 2,967.4 2,885.4 2,967.4 2,885.4
KU is an electric utility company. It does not provide gas service and
therefore, is presented as a single business segment.
6.5. Rates and Regulatory AssetsMatters
For a description of each line item of regulatory assets and
Liabilitiesliabilities for LG&E and KU, reference is made to Part I, Item 8,
Financial Statements and Supplementary Data, Note 3 of LG&E's and KU's
Annual Reports on Form 10-K for the year ended December 31, 2004.
The following regulatory assets and liabilities were included in LG&E's
balance sheets as of September 30, 20042005 and December 31, 2003:2004:
Louisville Gas and Electric Company
(Unaudited)
September 30,December 31,
(in thousands)millions) 2005 2004
2003
VDT costsCosts $ 45,20915.1 $ 67,81037.7
Unamortized loss on bonds 20.9 20.3
ARO 7.5 6.9
Merger surcredit 3.8 4.8
FAC 7.1 0.8
Gas supply adjustments due from customers 11,068 22,077
Unamortized loss on bonds 20,537 21,333
Earnings sharing mechanism (ESM) provision 5,446 12,359
Merger surcredit 5,183 6,220
Asset retirement obligation (ARO) 6,674 6,015
Gas performance-based ratemaking (PBR) 3,467 5,48013.6 13.3
Other (including fuel adjustment clause
(FAC), demand side management (DSM),
etc.) 2,599 2,3325.3 8.1
Total regulatory assets $100,183 $143,626$ 73.3 $ 91.9
Accumulated cost of removal of utility
plant $214,950 $216,491$218.8 $220.2
Deferred income taxes - net 38,595 41,18052.7 37.2
ECR 0.7 4.0
Gas supply adjustments due to customers 7,804 6,805
DSM 2,602 1,7065.9 8.4
Other (including environmental cost
recovery (ECR), ARO, FAC and ESM) 4,534 2,1312.9 2.6
Total regulatory liabilities $268,485 $268,313
Page 13$281.0 $272.4
LG&E currently earns a return on all regulatory assets except for gas
supply adjustments, ESM, FAC, ECR and gas performance-basedperformance based ratemaking, FAC, 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.removed.
Due to a 2005 reduction in Kentucky's corporate income tax rate, LG&E
and KU established additional regulatory liabilities in accordance with
SFAS No. 71 for their excess state deferred income tax balances related
to depreciation. In June 2005, LG&E and KU each received orders from
the Kentucky Commission authorizing this treatment.
The following regulatory assets and liabilities were included in KU's
balance sheets as of September 30, 20042005 and December 31, 2003:2004:
Kentucky Utilities Company
(Unaudited)
September 30, December 31,
(in thousands)millions) 2005 2004 2003
VDT costs $ 17,6355.9 $ 26,45114.7
Unamortized loss on bonds 9,946 10,511
ESM provision 7,462 12,38211.2 11.4
ARO 14.1 12.8
Merger surcredit 4,012 4,815
ARO 12,464 11,3222.9 3.7
FAC 1,713 4,29827.7 9.4
Deferred storm costs 3,760 -3.0 3.6
Other 5,676 2,5395.8 5.8
Total regulatory assets $ 62,66870.6 $ 72,31861.4
Accumulated cost of removal of utility
plant $262,971 $256,744$277.6 $266.8
Deferred income taxes - net 22,174 24,058
ARO 1,351 1,162
Spare parts 1,062 1,05529.9 19.3
ECR 2,100 9,1895.8 1.2
Other (including FAC and DSM) 1,614 2,5634.6 4.2
Total regulatory liabilities $291,272 $294,771$317.9 $291.5
KU currently earns a return on all regulatory assets except for ESM,
FAC, and DSM,ECR, all of which are separate recovery 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.
Inremoved.
Based on an order from the Kentucky Commission in September 2004, KU
reclassified from maintenance expense to a regulatory asset, $4.0
million related to unreimbursed costs not reimbursed from the 2003 ice storm based on an order from the Kentucky Commission.storm. These
costs will be amortized through June 2009. KU earns a return of theseThese amortized costs, which
are included in KU's jurisdictional operating expenses.
During May and July,expenses, are recovered
in base rates.
Due to a 2005 reduction in Kentucky's corporate income tax rate, LG&E
and KU incurred $17.0 million and $3.5
million, respectively, of storm restoration costs associatedestablished additional regulatory liabilities in accordance with
severe storms inSFAS No. 71 for their service territories. Of these amountsexcess state deferred income tax balances related
to depreciation. In June 2005, LG&E
incurred $12.6 million of Operations and Maintenance ("O&M") expense
and $4.4 million of expenditures that were capitalized and KU incurred
$2.7 million of O&M expense and $0.8 million of expenditures that were
capitalized. The Companies are considering requestingeach received orders from
the Kentucky Commission authorizing this treatment.
ELECTRIC AND GAS RATE CASES
On June 30, 2004, the Kentucky Commission issued an order approving an
increase in the base electric rates of LG&E and KU and the gas rates of
LG&E. The rate increases took effect on July 1, 2004.
During July 2004, the Attorney General of Kentucky (AG) served
subpoenas on LG&E and KU, as well as on the Kentucky Commission and its
staff, requesting information regarding alleged improper communications
between LG&E and KU and the Kentucky Commission. The Kentucky
Commission procedurally reopened the rate case for the limited purpose
of taking evidence, if any, as to the communication issues. 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 January 2005, the AG conducted interviews of certain employees of
LG&E and KU and 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 and KU in their
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 would
be forwarded to the Kentucky Commission under continued confidential
treatment to allow deferral of these O&M expenses for recovery in a
future rate proceeding duringit to consider the fourth quarter of 2004.
Page 14
7. Utility Plant
KU retired two steam generating units, Green River Units 1report, including its impact, if
any, on completing its investigation and 2,any remaining steps in the
amountrate case, including ending the current abeyance. To date, LG&E and KU
have neither seen nor requested copies of $17.2 million,the report or its contents.
During Spring 2005, LG&E and KU responded to additional information
requests from its books asthe AG. LG&E and KU have also responded to investigative
requests for information from the Kentucky Commission.
LG&E and KU believe no improprieties have occurred in their
communications with the Kentucky Commission and are cooperating with
the proceedings before the AG and the Kentucky Commission.
LG&E and KU are currently unable to determine the ultimate impact of,
if any, 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
The current five-year VDT amortization period is scheduled to expire in
March 31, 2004.
Approximately $4 million2006. As part of the settlement agreements in common assets, whichthe electric and
gas rate cases, LG&E and KU are shared by Green
River Units 3required to file with the Kentucky
Commission a plan for the future ratemaking treatment of the VDT
surcredits and 4,costs six months prior to the March 2006 expiration. The
surcredit shall remain on KU's books. The common assets will
remain on KU's booksin effect following the expiration of the fifth
year unless and until the final retirementCommission enters an order on the future
disposition of Green River Units 3VDT-related issues. On September 30, 2005, LG&E and 4. The gross book value of Green River Units 1 and 2 was charged
toKU
filed a plan with the accumulated reserve for depreciationKentucky Commission in accordance with FERC
regulations and no gain or loss was recorded. The impactthe
requirements of the retirementsettlement agreement calling for termination of Green River Units 1the
VDT surcredit effective upon the expiration of the fifth year. The AG
and 2 on the ARO is immaterial. A
partial redemption of pollution control Series 14 bonds totaling $4.8
million was requiredKIUC were granted intervention in the second quarter asVDT proceedings. A procedural
schedule has been established for discovery and rebuttal testimony but
no public hearing has been scheduled yet.
ECR
In December 2004, KU and LG&E filed applications with the Kentucky
Commission for approval of a resultCCN to construct new SO2 control
technology (FGDs) at KU's Ghent and Brown stations, and to amend LG&E's
and KU's compliance plans to allow recovery of new and additional
environmental compliance facilities. The estimated capital cost of the
retirement (see Note 9).
The following data represent shares of jointly-owned additions to the
Trimble County plant for four combustion turbines ("CTs") as of
September 30, 2004. Trimble County CT Units 7 and 8 began commercial
operation on June 1, 2004. The addition to LG&E plant in service was
$37.0additional facilities is $742.7 million and for KU the addition was $63.2 million. Trimble County
CT Units 9 and 10 began commercial operation on July 1, 2004, resulting
in an increase to plant in service of $37.3 and $63.8($40.2 million for LG&E and
KU, respectively.
($$702.5 million for KU), of which $658.9 million is for the FGDs.
Hearings in millions)these cases occurred during May 2005 and final orders were
issued in June 2005, granting approval of the CCN and amendments to
LG&E's and KU's compliance plans.
During the second quarter of 2005, LG&E and KU Total
Trimble CTmade out-of-period
adjustments for estimated over/under collection of ECR revenues to be
billed in subsequent periods. The adjustments were immaterial during
all reporting periods involved (March 2003 through October 2004 for
LG&E and May 2003 through January 2005 for KU). As a result, year-to-
date LG&E revenues were increased $4.8 million and KU revenues were
decreased $2.4 million. Year-to-date net income was increased $2.9
million for LG&E and was reduced $1.5 million for KU.
IRP
In April 2005, LG&E and KU filed their 2005 Joint Integrated Resource
Plan (IRP) with the Kentucky Commission. The IRP is filed triennially
and provides historical and projected demand, resource, and financial
data, and other operating performance and system information. The AG
and the KIUC were granted intervention in the IRP proceeding. Discovery
is complete and an informal conference has not yet been scheduled.
MISO
The MISO implemented a day-ahead and real-time market (MISO Day 2),
including a congestion management system, in April 2005. This system is
similar to the LMP system currently used by the PJM RTO and
contemplated in FERC's SMD NOPR. The MISO filed with FERC a mechanism
for recovery of costs for the congestion management system proposing
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 provides. Schedule 17 is the MISO's mechanism
for recovering costs it incurs for providing Energy Marketing Support
Administrative Service. The MISO transmission owners, including LG&E
and KU, objected to the allocation of these regional market-related
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 and KU's
memberships in the MISO in July 2003. The Kentucky Commission directed
LG&E and 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. LG&E and 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 Companies'
exit from the MISO, under certain conditions. The MISO filed its own
testimony and cost benefit analysis in December 2003. The Kentucky
Commission requested additional testimony on the MISO's Market Tariff
filing. This additional testimony was received and a hearing before the
Kentucky Commission was held in July 2005. Additional post-hearing data
requests were submitted in September with an order expected in the
first half of 2006.
Should LG&E and KU be ordered to exit the MISO, an aggregate exit fee
up to $41 million could be imposed, depending on the timing and
circumstances of actual withdrawal. While LG&E and KU believe 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. In April 2005, the Kentucky Commission issued an
order declining an LG&E and KU request for an automatic monthly
recovery mechanism for certain MISO-related costs and benefits.
On October 7, Ownership % 37% 63% 100%2005, LG&E and KU filed an application with the FERC
seeking the requisite authority to exit the MISO. This proceeding is
expected to continue into 2006.
At this time, LG&E and KU cannot predict the outcome or effects of the
various Kentucky Commission and FERC proceedings described above,
including whether such proceedings will have a material impact on the
financial condition or results of operations of the Companies. Further,
ultimate financial consequences (changes in transmission revenues and
costs) associated with the April 2005 implementation of transmission
day-ahead and real-time market tariff charges 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.
EPAct 2005
EPAct 2005 was enacted on August 8, 2005. Among other matters, this
comprehensive legislation contains provisions mandating improved
electric reliability standards and performance; providing economic and
other incentives relating to transmission, pollution control and
renewable generation assets; increasing funding for clean coal
generation incentives; and repealing the Public Utility Holding Company
Act of 1935.
The FERC was directed by the EPAct 2005 to adopt rules to address many
areas previously regulated by the other agencies under other statutes,
including PUHCA. The FERC is in various stages of rulemaking on these
issues and the Companies are monitoring these rulemaking activities and
actively participating in these and other rulemaking proceedings. The
Companies are still evaluating the potential impacts of the EPAct 2005
and the associated rulemakings and cannot predict what impact the EPAct
2005, and any such rulemakings, will have on their operations or
financial position.
FERC SMD NOPR
In July 2002, the FERC issued a NOPR which would substantially alter
the regulations governing the nation's wholesale electricity markets by
establishing a common set of rules, known 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. On July
19, 2005, the FERC issued an order terminating the SMD proceeding. FERC
noted that the industry has made significant progress in the voluntary
development of the RTO/ITP functions and asserted its intent to
consider revisions to the Order 888 pro-forma Open Access Transmission
Tariffs to reflect the current experience with open transmission over
the last decade.
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 and KU, pertaining to Kentucky electric generation, transmission
and distribution systems. LG&E and KU responded to the Kentucky
Commission's first set of data requests at the end of March 2005 and to
a second set of data requests in May 2005. The Commission held a
Technical Conference on June 14, 2005, in which all parties
participated in a panel discussion. A final report was provided on
August 22, 2005 from the Kentucky Commission to the Governor. Some of
the key findings are that (1)Kentucky's electric utilities currently
have adequate infrastructure as well as adequate planning to serve the
needs of customers through 2025, (2) Kentucky will need 7,000 megawatts
of additional generating capacity by 2025, (3) Kentucky's electric
transmission is reliable but intrastate power transfers are limited,
(4) additional incentives to use renewable energy and educate the
public on the benefits of renewables are needed, (5) financial
incentives should be available for coal gasification and other clean
air technologies, (6) cautious approach should be taken towards
deregulation, and (7) Kentucky must be involved in federal decisions
that impact its status as a low cost energy provider.
LOCK 7
On September 27, 2005, KU filed an application with FERC seeking
authority to transfer the operating license for the Lock 7
Hydroelectric Station, a 2.04 Mw capacity 59 101 160
Cost $18.5 $31.7 $50.2
Depreciation 0.2 0.3 0.5
Netfacility, from KU to the Lock 7 Hydro
Partners, LLC, an unaffiliated third party, for less than $0.1 million.
On September 28, 2005, KU filed an application with the Kentucky
Commission seeking: 1) a determination that Kentucky Commission
approval is not required for the transfer of the Lock 7 Hydroelectric
Station or 2) Kentucky Commission approval, pursuant to a Kentucky
Commission order in Case No. 2005-00405, to sell any real property
associated with the Lock 7 Hydroelectric Station to Lock 7 Hydro
Partners, LLC. These proceedings are expected to conclude in 2005.
6. Income and Other Taxes
On September 19, 2005, E.ON U.S. Investments Corp., the parent of LG&E
Energy, LG&E and KU, received notice from the Congressional Joint
Committee on Taxation approving the Internal Revenue Service's audit of
the Companies' income tax returns for the periods December 1999 through
December 2003. As a result of this audit, LG&E and KU released income
tax reserves of $5.1 million and $4.4 million, respectively.
During the quarter, KU recognized additional deferred tax expense ($3.1
million) related to the undistributed earnings of its EEI
unconsolidated investment. Recent EEI management decisions regarding
changes in the distribution of EEI's earnings led to the decision to
provide deferred taxes for all book value $18.3 $31.4 $49.7
Trimble CT 8
Ownership % 37% 63% 100%
Mw capacity 59 101 160
Cost $18.5 $31.5 $50.0
Depreciation 0.2 0.3 0.5
Net book value $18.3 $31.2 $49.5
Trimble CT 9
Ownership % 37% 63% 100%
Mw capacity 59 101 160
Cost $18.7 $31.9 $50.6
Depreciation 0.1 0.2 0.3
Net book value $18.6 $31.7 $50.3
Trimble CT 10
Ownership % 37% 63% 100%
Mw capacity 59 101 160
Cost $18.6 $31.9 $50.5
Depreciation 0.1 0.2 0.3
Net book value $18.5 $31.7 $50.2
8.and tax basis differences in this
investment.
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, LG&E and KU maintain an allowance 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.
LG&E's Kentucky sales and use tax audit for the periods October 1, 1997
through December 31, 2001 resulted in an initial assessment of $1.1
million. LG&E filed a protest on July 22, 2005, stating that no
additional tax was due and that LG&E was owed a refund. At Kentucky's
request, the Company has provided additional information to supplement
the initial protest. This audit assessment is not expected to have a
material adverse impact on the Company.
KU is also being audited by the Kentucky Department of Revenue. This
audit began on September 19, 2005 and covers the period August 1, 2000
through July 31, 2005. At this time there are no proposed adjustments.
The results of the audit assessments described above and any future
audits by taxing authorities could have a material effect on quarterly
or annual cash flows as well as results of operations. However, LG&E
and KU do not believe any existing matters will have a material adverse
effect on their results of operations.
7. New Accounting Pronouncements
FSP 109-1
In December 2004, the FASB finalized FSP 109-1, Accounting for Income
Taxes, Application of SFAS No. 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 SFAS
No. 109. FSP 109-1 became effective December 21, 2004. For the nine
months ended September 30, 2005, LG&E and KU recognized $1.2 million
and $0.6 million, respectively, in tax benefits related to this
deduction.
FIN 4647
In January 2003,March 2005, the Financial Accounting Standards Board ("FASB")FASB issued Financial Accounting Standards Board
Interpretation No. 46,
Consolidation47, Accounting for Conditional Asset Retirement
Obligations, an interpretation of Variable Interest Entities, an Interpretation of ARBFASB Statement No. 51 ("FIN 46")143 (FIN 47). FIN
46 required certain variable interest entities47 clarifies that the term "conditional asset retirement obligation" as
used in SFAS No. 143, Accounting for Asset Retirement Obligations,
refers to a legal obligation to perform an asset retirement activity in
which the timing and/or method of settlement are conditional on a
future event that may or may not be consolidated bywithin the primary beneficiarycontrol of the entity.
The obligation to perform the asset retirement activity is
unconditional even though uncertainty exists about the timing and/or
method of settlement. An entity is required to recognize a liability
for the fair value of a conditional asset retirement obligation if the
equity investors infair value of the entity do not have the characteristicsliability can be reasonably estimated. The fair value
of a controlling financial interest or do not have sufficient equity at riskliability 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 createdconditional asset retirement obligation should
be recognized when incurred; generally, upon acquisition, construction,
or acquired after January 31, 2003.
Page 15
In December 2003, FIN 46 was revised, delayingdevelopment and through the effective dates for
certain entities created before February 1, 2003, and making other
amendments to clarify applicationnormal operation of the guidance. For potential
variable interest entities other than special purpose entities, the
revisedasset. FIN 46 ("FIN 46R")47 is
now required to be appliedeffective no later than the end of the first fiscal year or interim reporting period ending
after March 15, 2004. For all special purpose entities created prior
to February 1, 2003, FIN 46R is now required to be applied at the end
of the first interim or annual reporting periodyears 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.
Both2005. LG&E and KU hold investment interests in Ohio Valley Electric
Corporation ("OVEC"),are currently evaluating the impact of this
pronouncement.
8. Short-Term and KU holds an investment interest in Electric
Energy, Inc. ("EEI"). Neither LG&E nor KU are the primary beneficiary
of OVEC or EEI, and thus neither are consolidated into the financial
statements of LG&E or KU.
LG&E, KU and ten 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 and KU's share
is 2.5%, representing approximately 55 Mw of generation capacity.
LG&E's and KU's original investments in OVEC were made in 1952. LG&E's
investment in OVEC is the equivalent of 4.9% of OVEC's common stock and
KU's investment is the equivalent of 2.5% of OVEC's common stock.
LG&E's and KU's investments in OVEC are accounted for under the cost
method of accounting. As of September 30, 2004, LG&E's and KU's
investments in OVEC totaled $0.5 million and $0.3 million,
respectively. LG&E's and KU's maximum exposure to loss as a result of
their involvement with OVEC is limited to the value of their
investments. In the event of the inability of OVEC to fulfill its
power provision requirements, LG&E and 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 and Part II, Item 1, for further discussion of
developments regarding LG&E's and 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 purchased or
generated by KU. Such power equated to approximately 9% of KU's net
generation system output in 2003.
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
September 30, 2004, totaled $12.7 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 rate
mechanisms.
FSP 106-2
In May 2004, the FASB finalized FASB Staff Position ("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 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 the Companies.
Page 16
9.Long-Term Debt
Under the provisions for LG&E's variable-rate Pollution Control Bonds,pollution control bonds,
Series S, T, U, BB, CC, DD and EE, and KU's variable-rate Pollution
Control Bonds,pollution
control bonds Series 10, 12, 13, 14, and 15, the bonds are subject to
tender for purchase at the option of the holder and to mandatory tender
for purchase upon the occurrence of certain events, causing the bonds
to be classified as current portion of long-term debt in the Consolidated Balance
Sheets. The average annualized interest rate for these bonds during the
three months and nine months ending September 30, 20042005 was 1.20%2.63% and 1.14%2.36%,
respectively, for the LG&E bonds and 1.30%2.59% and 1.18%2.40%, respectively, for the KU bonds.
In January 2004,KU.
During June 2005, LG&E entered into two long-term loans from Fidelia
Corporation ("Fidelia"), an E.ON financing subsidiary, one totaling $25
million with an interest rate of 4.33% that matures in January 2012,
and one totaling $100 million with an interest rate of 1.53% that
matures in January 2005. The loans are secured by a lien 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 and there was
no prepayment fee.
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.
On October 20, 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, will be discharged on November 22, 2004, with the proceeds from
the replacement indebtedness, KU Pollution Control Bonds, Series 17,
due October 1, 2034, which will carry a variable, auction rate of
interest.
LG&E maintainsrenewed five bilateralrevolving lines of credit with
banks totaling $185 million
that mature in 2005.million. There was no outstanding balance under any
of these facilities at September 30, 2004. Management2005. The Company expects to renew
these facilities as they expire.prior to their expiration in June 2006.
LG&E, KU and KULG&E Energy participate in an intercompany money pool
agreement wherein
LG&E Energy and KU make funds available to LG&E at market-based rates
(based on an index of highly rated commercial paper issues asagreement. Details of the prior month end) up to $400 million. Likewise, LG&E Energy and LG&E
make funds available to KU at market-based rates up to $400 million.
LG&E had $40.7 million in money pool loans from LG&E Energy (included
in "Notes payable to affiliated companies") at an average rate of 1.60%balances at September 30, 2004,2005, and $75.1 million at an average rate of 1.06% at
September 30, 2003. The balance of the money pool loans from LG&E
Energy to KU (included in "Notes payable to affiliated companies") was
$29.8 million at an average rate of 1.60% and $98.7 million at an
average rate of 1.06% at September
30, 2004, and 2003, respectively.
The amount available towere as follows:
Total Money Amount Balance Average
($ in millions) Pool Available Outstanding Available Interest Rate
September 30, 2005:
LG&E under the money pool agreement at$400.0 $56.6 $343.4 3.64%
KU $400.0 $31.8 $368.2 3.64%
September 30, 2004, was2004:
LG&E $400.0 $40.7 $359.3 million. The amount available to1.60%
KU under the money pool agreement at September 30, 2004, was$400.0 $29.8 $370.2 million.1.60%
LG&E Energy maintains a revolving credit facility totaling $150$200 million
with an affiliated company, E.ON affiliateNorth America, Inc., to ensure funding
availability for the money pool. LG&E Energy had anThe balance outstanding balance of $79.1
million at an average rate of 2.13% underon this
facility as ofat September 30, 2004,2005, was $65.4 million.
Redemptions and availabilitymaturities of $70.9 million remained.
Page 17
As oflong-term debt year-to-date through
September 30, 2004,2005, are summarized below:
($ in millions)
Principal Secured/
Year Company Description Amount Rate Unsecured Maturity
2005 LG&E had 225,000 sharesPollution control bonds $40.0 5.90% Secured Apr 2023
2005 LG&E Due to Fidelia $50.0 1.53% Secured Jan 2005
2005 LG&E Mand. Red. Pref. Stock $1.3 5.875% Unsecured Jul 2005
2005 KU First mortgage bonds 50.0 7.55% Secured Jun 2025
Issuances of $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 $100 per share. Beginninglong-term debt year-to-date through September 30, 2003,2005,
are summarized below:
($ in millions)
Principal Secured/
Year Company Description Amount Rate Unsecured Maturity
2005 LG&E reclassified its $5.875 series preferred stock as long-
term debt withPollution control bonds $40.0 Variable Secured Feb 2035
2005 KU Pollution control bonds $13.3 Variable Secured Jun 2035
2005 KU Due to Fidelia $50.0 4.735% Unsecured Jul 2015
In May 2005, KU repaid a $26.7 million loan against the minimum shares mandatorily redeemable within one
year classified as current. Dividends accrued are charged as interest
expense, pursuant to SFAS No. 150. On July 15, 2004, LG&E redeemed
12,500 shares as required at a pricecash surrender
value of $100 per share.
10. Related Partylife insurance policies.
9. Related-Party Transactions
LG&E, KU, certain subsidiaries of LG&E Energy and other subsidiaries of E.ON
engage in related-party transactions. Transactions among LG&E, KU and
LG&E Energy subsidiaries are eliminated upon consolidation of LG&E
Energy subsidiaries.Energy. Transactions between LG&E or KU and E.ON subsidiaries are
eliminated upon consolidation of E.ON subsidiaries.E.ON. These transactions are generally
performed at cost and are in accordance with the SEC regulations under
the PUHCA and the applicable Kentucky Public Service Commission ("Kentucky Commission") regulations.regulations (for
discussion of recent changes to PUHCA, see EPAct 2005 under Note 5).
Accounts payable to and receivable from related parties are netted and
presented as accounts payable to affiliated companies on the balance
sheets of LG&E and KU, as allowed due to the right of offset.
Obligations related to intercompany debt arrangements with LG&E Energy
and Fidelia, an E.ON affiliate, are presented as separate line items on
the balance sheet, as appropriate. The significant related-party
transactions are disclosed below.
Electric Purchases
LG&E and KU intercompany electric revenues and purchased power expense
(including LG&E Energy Marketing Inc. ("LEM"))from affiliated companies for the three months and nine months ended
September 30, 20042005, and 2003, were as follows:
Three months endedNine months ended
September 30, September 30,
(in thousands) 2004, 2003 2004 2003
LG&E
Electric operating revenues
from KU $10,095 $11,980 $40,598 $39,799
Electric operating revenues
from LEM 1,092 537 2,443 8,691
Purchased power from KU 12,206 11,000 42,905 34,675
KU
Electric operating revenues
from LG&E $12,206 $11,000 $42,905 $34,675
Electric operating revenues
from LEM 346 174 895 2,196
Purchased power from LG&E 10,095 11,980 40,598 39,799
Interest Income and Expense
LG&E intercompany interest income and expense for the three months and
nine months ended September 30, 2004 and 2003, were as follows:
Three months ended Nine months ended
September 30, September 30,
(in thousands)millions) 2005 2004 20032005 2004
2003LG&E
Electric operating revenues
from KU $14.8 $ 10.1 $61.5 $40.6
Purchased power from KU 15.9 12.2 64.6 42.9
KU
Electric operating revenues
from LG&E $15.9 $ 12.2 $64.6 $42.9
Purchased power from LG&E 14.8 10.1 61.5 40.6
Interest to affiliate
(money pool) $ 102 $ 305 $ 137 $1,573
Interest to affiliate
(Fidelia loans) 2,927 1,801 8,995 2,560
Interest to affiliate (KU) 11 5 25 4
Interest expense to
affiliated companies $3,040 $2,111 $9,157 $4,137
Interest income from affiliate (KU) - $ 2 - $ 6
Page 18Charges
LG&E and KU intercompany interest income and expense for the three months and nine
months ended September 30, 20042005 and 2003,2004, were as follows:
Three months ended Nine months ended
September 30, September 30,
(in thousands)millions) 2005 2004 20032005 2004
2003
Interest to affiliate
(money pool) $ 96 $ 279 $ 315 $1,001
Interest to affiliate
(Fidelia loans) 3,461 1,635 10,326 2,394
Interest to affiliate (LG&E) - 2 - 6
InterestLG&E intercompany interest
expense to affiliated
companies $3,557 $1,916 $10,641 $3,401
Interest income from
affiliate (LG&E) $ 11 $ 5 $ 26 $ 4$3.0 $3.0 $9.0 $9.1
KU intercompany interest expense $4.2 $3.5 $11.4 $10.6
Other Intercompany Billings
Other intercompany billings (including LG&E Energy Services Inc. ("LG&E
Services")) related to LG&E and KU for the three months
and nine months ended September 30, 20042005 and 2003,2004, were as follows:
Three months ended Nine months ended
September 30, September 30,
(in thousands)millions) 2005 2004 20032005 2004 2003
LG&E Services billings to LG&E $40,221 $44,607 $138,796 $132,894$52.8 $40.2 $160.9 $138.8
LG&E Services billings to KU 42,342 48,508 117,530 134,91644.3 42.3 145.5 117.5
LG&E billings to LG&E Services 5,951 12,801 10,475 18,944
LG&E billings to KU 14,962 25,127 48,464 61,2480.8 6.0 6.1 10.5
KU billings to LG&E Services 516 4,774 4,430 12,6380.4 0.5 3.9 4.4
LG&E billings to KU 54.9 14.9 83.4 48.5
KU billings to LG&E 2,097 3,104 26,928 11,549
11.Commitments7.6 2.1 20.7 5.5
10.Commitments and Contingencies
Except as may be discussed in this Quarterly Report on Form 10-Q
(including Note 5), material changes have not occurred in the current
status of various commitments or contingent liabilities from that
discussed in the Companies' Annual Report on Form 10-K for the year
ended December 31, 2003, (including in
Notes 32004 and 11 to the financial statements of LG&E and KU contained
therein and incorporated herein by reference) or Quarterly Reports on Form 10-Q for the
quartersthree months ended March 31, 20042005 and June 30, 2004.
Electric2005. See Notes 3 and Gas Rates Cases
In December 2003, LG&E and KU filed applications with the Kentucky
Commission requesting increases in LG&E's and KU's electric rates and
LG&E's gas rates. The Companies requested general adjustments in
electric rates and LG&E requested general adjustments in gas rates
based on the twelve-month test year ended September 30, 2003. The
revenue increases requested by LG&E were $63.8 million for electric and
$19.1 million for gas. The revenue increase requested by KU was $58.3
million.
On June 30, 2004, the Kentucky Commission issued an order approving
increases in the base electric and gas rates of LG&E and the base
electric rates of KU. The Kentucky Commission's order largely accepted
proposed settlement agreements filed in May 2004 by LG&E, KU and a
majority of the parties11
to the rate case proceedings. The rate
increases took effectCompanies' Annual Report on July 1, 2004.
Page 19
InForm 10-K and Note 10 to the
Kentucky Commission's order, (a) 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%) and (b) KU
was granted an increase in annual base electric rates of approximately
$46.1 million (6.8%). Other provisions ofCompanies' Quarterly Reports on Form 10-Q for 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 beforethree months ended
March 31, 2005, by the Companies of previously requested amounts relating to the
ESM during 2003.
During July 2004, the Attorney General of Kentucky ("AG") served
subpoenas on KU and LG&E, as well as on the Kentucky Commission and its
staff, requestingJune 30, 2005, for information regarding allegedly improper
communications between KU and 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 productionsuch
commitments or other information required or
agreed to be produced under the AG's subpoenas. On October 12, 2004,
the AG filed a status report with the Kentucky Commission in which the
AG indicated that it had not completed its investigation and requested
that the Kentucky Commission continue to hold these matters in
abeyance. On October 21, 2004, the AG filed a motion with the Kentucky
Commission requesting that the previously granted rate increases be set
aside, that the Companies resubmit any applications for rate increases
and that relevant Kentucky Commission personnel be recused from
participation in rate case proceedings. On November 8, 2004, the
Franklin County, Kentucky court denied an AG request for sanctions on
KU and LG&E relating to production matters and narrowed the AG's
permitted scope of discovery. As so required, LG&E's and KU's
production of materials requested by the AG is expected to continue.
LG&E and KU believe no improprieties have occurred in their
communications with the Kentucky Commission and are cooperating with
the proceedings before the AG and the Kentucky Commission.
LG&E and KU are currently unable to estimate the general status or
progress of the AG investigation, including when the AG will submit its
report to the Kentucky Commission, and the content, findings and
recommendations contained in any such report. The Companies are
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.
Page 20
Earnings Sharing Mechanism
The Companies filed their final 2003 ESM calculations with the Kentucky
Commission on March 1, 2004, and applied for recovery of $13.0 million
related to LG&E and $16.2 million related to KU. Based upon estimates,
the Companies previously accrued $8.9 million at LG&E and $9.3 million
at KU 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 the Companies and all
intervenors regarding the ESM mechanisms of LG&E and KU. Under the ESM
settlements, LG&E and KU will continue to collect approximately $13.0
million and $16.2 million, respectively, 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, the Company accrued an additional $4.1
million at LG&E and $6.9 million at KU in June 2004, related to 2003
ESM revenue.
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.
LG&E's estimated future minimum annual demand payments under the
Amended and Restated Inter-Company Power Agreement are as follows:
(in thousands)
2006 $ 10,098
2007 9,726
2008 9,932
2009 10,144
2010 10,361
Thereafter 170,646
Total $220,907
In addition, LG&E will purchase from American Electric Power Company
Inc. ("AEP") an additional 0.73% interest in OVEC for a purchase price
of approximately $104,000, resulting in an increase in LG&E ownership
in OVEC from 4.9% to 5.63%. The share purchase transaction is
anticipated to be completed during 2005, subject to receipt of certain
regulatory approvals. The change to the power agreement and the share
purchase are expected to have no impact on the accounting for OVEC
under FIN 46R as discussed in Footnote 8.
Owensboro Contract Litigationcontingencies.
LITIGATION
In May 2004, the City of Owensboro, Kentucky and Owensboro Municipal
Utilities (collectively "OMU"), filed suit in Davies County, Kentucky
District CourtOMU commenced litigation against KU concerning a long-term
power supply contract
(the "OMU Agreement") with KU. The dispute involves interpretational
differences regarding certain issues under thecontract. KU filed counterclaims against OMU. To date, OMU
Agreement, including
various payments or charges between KU and OMU and rights concerning
excess power, termination and emissions allowances, respectively. The
complaint seekshas claimed approximately $6 million in damages for historical
periods as well asthrough
early 2004, and is expected to claim further amounts for later-
occurring periods. OMU has additionally requested injunctive and other
relief, including a declaration that KU is in material breach.breach of the
contract. In March 2005, the FERC denied a rehearing request by KU
has removed this
litigationregarding the FERC's December 2004 decision 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
declineddecline to exercise
exclusive jurisdiction regarding thecertain issues in dispute, whichdispute. In July
2005, the district court resolved a summary judgment motion of KU in
OMU's favor, ruling that a contractual provision grants OMU the ability
to terminate the contract without cause upon 4 years' prior notice. OMU
filed a motion seeking to make that ruling "final and appealable." In
October 2005, however, the Court denied OMU's motion. This case is
otherwise currently in the discovery stage and a trial schedule has not
yet been established.
ENVIRONMENTAL MATTERS
LG&E and KU has appealed.
Environmental Matters
In September 1998, the EPA announced its final "NOx SIP Call" rule
requiring statesare subject to impose significant additional reductions in NOx
emissions by May 2003, in order to mitigate alleged ozone transport
impactsSO2 and NOX emission limits on the Northeast region. The Commonwealth of Kentucky SIP,
Page 21
which was approved by EPA June 24, 2003, required reductions in NOx
emissions from coal-firedtheir
electric 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 allAct. LG&E and KU
units.placed into operation significant NOX controls for their generating
units prior to the 2004 Summer Ozone Season. As a result of appeals to both rules, the compliance date was extended to May 2004.December 31, 2004,
LG&E and KU have complied with these NOx emissions reduction rules by
installing additional NOx controls to their generating units.
Installations of additional NOx controls were performed on a phased
basis, which commenced in late 2000 and continued through the final
compliance date. As of September 30, 2004, LG&E has incurred total capital costs of approximately $185$186 million
and $219 million, respectively, to reduce their NOX emissions below
required levels. In addition, LG&E and KU incur additional operating
and maintenance costs in operating the new NOX controls.
On March 10, 2005, EPA issued the final Clean Air Interstate Rule
(CAIR) which requires substantial additional reductions in SO2 and NOX
emissions from electric generating units. The CAIR rule provides for a
two-phased reduction program with Phase I reductions in NOX and SO2
emissions in 2009 and 2010, respectively, and Phase II reductions in
2015. On March 15, 2005, EPA issued a related regulation, the final
Clean Air Mercury Rule (CAMR), which requires substantial mercury
reductions from electric generating units. CAMR also provides for a two-
phased reduction, with the Phase I target in 2010 achieved as a "co-
benefit" of the controls installed to meet CAIR. Additional control
measures will be required to meet the Phase II target in 2018. Both
CAIR and CAMR establish a cap and trade framework, in which a limit is
set on the total amount of emissions and allowances that can be bought
or sold on the open market, that can be used for compliance unless the
state chooses another approach.
In order to meet these new regulatory requirements, KU has implemented
a plan for adding significant additional SO2 controls to its NOx emissionsgenerating
units. Installation of additional SO2 controls will proceed on a phased
basis, with construction of controls (i.e., FGDs) having commenced in
September 2005 and continuing through the final installation and
operation in 2009. KU estimates that it will incur $658.9 million in
capital costs related to the 0.15 lb./Mmbtu level on a company-wide basis. Asconstruction of September
30, 2004, KU has incurred total capital costs of approximately $203
millionthe FGDs to reduce its NOx emissions to the 0.15 lb./Mmbtu levelachieve
compliance with current emission limits on a company-wide basis. In
addition, LG&E and KU have begun incurringwill incur additional operationoperating and maintenance costs in
operating the new NOxSO2 controls. LG&E and KU believe their costs in this regardcurrently has FGDs on all its
units but will continue to be
comparableevaluate improvements to those of similarly situated utilities with like
generation assets. In April 2001, the Kentucky Commission granted
recovery of these costs under the environmental surcharge mechanism for
LG&E and KU.
During August 2004, KU, the EPA and the Department of Justice agreed in
principle to settle outstanding matters concerning a 1999 oil discharge
at KU's E.W. Brown plant for approximately $0.6 million, a portion of
which may be satisfied by KU's construction of a separate environmental
capital project. The settlement is subject to completion of final
definitive documents. In December 2003, KU recorded an accrual and
expense to operations of $0.6 million.further reduce SO2
emissions.
LG&E and KU are also monitoring several other air quality issuesmatters which
may potentially impact coal-fired power plants, including the EPA's revised
air quality standards for ozone and particulate matter, and measures to
implement the EPA's regional haze rule,rule.
After extensive negotiations between KU and the EPA's
December 2003 proposalsEPA and Department of
Justice, the government filed a consent decree in U. S. District Court
on October 13, 2005, that would resolve alleged violations relating to
regulate mercury emissions from steam
electric generating unitsoil spills at the E.W. Brown plant occurring in October 1999 and
January 2001. Under the terms of the settlement, KU would pay a civil
penalty of $0.2 million (which has been accrued), construct a
supplemental environmental project at a cost of $0.8 million, and
maintain that project for ten years at a cost of $0.4 million. After
reviewing any public comments, the Court will consider entry of the
consent decree.
From time to further reduce emissions of sulfur
dioxide and nitrogen oxides under the Clean Air Interstate Rule. In
addition,time, LG&E is currently reviewing and making comments on proposed
regulations concerning toxic air emissions within Metro Louisville,
whereKU have conducted negotiations with the
company operates two coal-fired generating stations. LG&E is
also working with localrelevant regulatory authorities to review the
effectiveness ofaddress various environmental-
related matters, including: remedial measures aimed at controlling
particulate matter emissions from itsLG&E's Mill Creek Station. LG&E previously settled
a numberplant; liability
for cleanup of property damage claims from adjacent residentsoff-site facilities that allegedly handled materials
associated with company operations; and completed significant remedial measures as partinvestigation and cleanup of
its ongoing capital
construction program. LG&E has converted the Mill Creek Station to a
wet stack operation in an effort to resolve all outstanding issues
related to particulate matter emissions.
FERC Developments
A number of regional or industry-wide FERC proceedings regarding
transmission market structure changes are in varying stages of
development. In August 2004, MISO filed its FERC-required proposed
Transmission and Energy Markets Tariff ("TEMT"). In September and
October 2004, many MISO-related parties filed proposals with the FERC
regarding pending MISO-filed changes to transmission pricing
principles,company properties including the TEMT and elimination of through-and-out
transmission ("T&O") charges. Additional filings of the Companies
before FERC in September 2004 sought to address issues relating to the
Page 22
treatment of certain "grandfathered" transmission agreements ("GFA's")
should TEMT become effective. The utility proposals generally seek to
appropriately delay the T&O and TEMT tariff effective dates based upon
errors in administrative or procedural processes used by FERC or to
appropriately limit potential reductions in transmission revenues
received byformer LG&E and KU shouldMGP sites. Based on
negotiations to date, management does not anticipate that any of the
T&O, TEMTliabilities arising out of any of these matters will have a material
adverse affect on LG&E's or GFA tariffs structures
be implemented. At present, existing FERC orders conditionally approve
eliminationKU's financial position or results of
T&O ratesoperations.
In the normal course of business, lawsuits, claims, environmental
actions, and implementationvarious non-ratemaking governmental proceedings arise
against LG&E and KU. To the extent that damages are assessed in any of
general TEMT rates in
MISO of December 1, 2004 and March 1, 2005, respectively. At this
time,these lawsuits, LG&E and KU cannot predictbelieve that their insurance coverage or
other appropriate reserves are adequate. Management, after
consultation with legal counsel, and based upon the outcomepresent status of
these items, does not anticipate that liabilities arising out of other
currently pending or effectsthreatened lawsuits and claims of the various
FERC proceedings describedtype
referenced above including whether such will have a material impactadverse effect on theLG&E's or KU's
financial conditionsposition or results of operationsoperations.
EEI CONTRACT
KU owns 20% of the Companies.
12.Pensioncommon stock of EEI, which owns and operates a 1,000-
Mw generating station in southern Illinois. KU presently purchases 20%
of the available capacity and energy 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 and for the nine months of
2005. Discussions are on-going related to the extension or replacement
of the contract, including whether any such future contract will be at
cost or market-based rates, and whether the purchasing party will
continue to be the shareholding utility, such as KU. The outcome of
such discussions cannot be predicted at this time. However, EEI has
filed for authority from FERC for EEI to sell its output at market-
based rates, and management of EEI has indicated to KU that future
power offers by EEI will be made only at market based prices.
E W BROWN FIRE
On September 12, 2005, a fire occurred at KU's E.W. Brown unit 3
resulting in damage to the switchgear and computer room. The total of
the repair and replacement costs of damaged equipment is approximately
$3.3 million, approximately $0.3 million of which will be covered by
insurance. Net operating income at KU is expected to be reduced by
approximately $7.4 million due to increased purchased power costs not
covered by the FAC, and potential losses of off-system sales revenue
due to the outage.
11.Pension and Other Post-retirement Benefit Plans
The following table provides the components of net periodic benefit
cost for pension and other benefit plans:
Three Months Ended Year to Dateplans for the three months and nine
months ended September 30, 20042005 and 2004:
LG&E
Three months ended Nine months ended
September 30, September 30,
(in millions) 2005 2004 (in thousands) LG&E KU LG&E KU2005 2004
Pension and Other Benefit Plans:
Components of net periodicperiod benefit
cost:cost
Service cost $ 9771.3 $ 1,1521.0 $ 3,9974.4 $ 4,7544.0
Interest cost 4,910 3,692 20,092 15,2405.1 4.9 17.3 20.0
Expected return on plan assets (4,469) (3,334) (18,287) (13,764)(4.8) (4.5) (16.1) (18.2)
Amortization of prior service
cost (2) 154 (9) 6361.1 - 3.6 -
Amortization of transition
obligation 939 281 3,843 1,161- 1.0 - 3.8
Recognized actuarial loss 515 331 2,107 1,3690.6 0.5 2.0 2.1
$ 2,8703.3 $ 2,276 $11,7432.9 $11.2 $11.7
KU
Three months ended Nine months ended
September 30, September 30,
(in millions) 2005 2004 2005 2004
Pension and Other Benefit Plans:
Components of net period benefit
cost
Service cost $ 9,3962.3 $ 1.1 $ 5.8 $ 4.8
Interest cost 5.6 3.7 14.1 15.2
Expected return on plan assets (5.2) (3.3) (13.2) (13.8)
Amortization of prior service
cost 0.4 0.2 1.1 0.6
Amortization of transition
obligation 0.2 0.3 0.6 1.2
Recognized actuarial loss 0.8 0.3 2.0 1.4
$ 4.1 $ 2.3 $ 10.4 $ 9.4
In January 2004, LG&E and KU made discretionary contributions to theirthe
pension plans in the amounts of $34.5 million and $43.4 million, respectively. No
discretionary contributions to the pension plans are required for 2004currently
anticipated for either LG&E or KU for 2005. LG&E and no further discretionary contributions are planned for 2004.
13. SubsequentKU contributed
$0.7 million and $3.0 million, respectively, to their other post-
retirement benefit plans during the second quarter of 2005.
12.Subsequent Events
On October 20, 2004,24, 2005, KU completedredeemed all outstanding shares of preferred
stock. The Company paid $101 per share for the 4.75% Series and
$102.939 per share for the 6.53% Series.
On October 27, 2005, LG&E received an order issuing 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, will be discharged on November 22, 2004, withnew license to
upgrade, operate and maintain the proceedsOhio Falls Hydroelectric Project from
the replacement indebtedness,FERC. The license is issued to LG&E for a period of 40 years,
effective November 11, 2005. LG&E intends to spend approximately $75
million to refurbish the facility and add approximately 20 Mw of
generating capacity.
On November 1, 2005, the Kentucky Commission approved the application
of LG&E and KU Pollution Control Bonds, Series 17,
due October 1, 2034,to expand the Trimble County electric generating
plant. The Companies plan to construct a 750-megawatt coal-fired
generating unit at the plant. The unit is expected to cost about $1.1
billion and be completed by 2010. LG&E's and KU's share of LG&E
Energy's total capital cost of $885 million for Trimble County Unit 2
is estimated to be $168 million and $717 million, respectively, through
2010. The Companies have not yet entered into final construction
contracts. The Companies also need to obtain approval from the
Kentucky State Board on Electric Generation and Transmission Siting, as
well as obtain the air permit from the Kentucky Department of Air
Quality, both of which will carry a variable, auction rateare expected by the end of interest.November 2005. In
September 2005, the Kentucky Commission approved one of three
transmission facilities for the additional Trimble County unit. The
Companies expect to refile the applications for the remaining two
transmission facilities in the fourth quarter.
Item 2. 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's and KU's financial results of
operations and financial condition during the three and nine month periods
ended September 30, 2004,2005, and should be read in connection with the
financial statements and notes thereto.
Some of the following discussion may contain forward-looking statements
that are subject to certain risks, uncertainties and assumptions. Such
forward-looking statements are intended to be identified in this document
by the words "anticipate," "expect," "estimate," "objective," "possible,"
"potential" and similar expressions. Actual results may vary materially.
Factors that could cause actual results to differ materially include:
general economic conditions; business and competitive conditions in the
energy industry; changes in federal or state legislation; unusual weather;
actions by state or federal regulatory agencies; and other factors
described from time to time in LG&E's and KU's reports to the SEC,
including the Annual Reports on Form 10-K for the year ended December 31,
2003.2004.
Executive Summary
LG&E's net income&E and KU, subsidiaries of LG&E Energy (an indirect subsidiary of E.ON),
are regulated public utilities. LG&E supplies electricity to approximately
395,000 customers and natural gas to approximately 320,000 customers in
Louisville and adjacent areas in Kentucky. KU provides electric service to
approximately 492,000 customers in over 77 counties in central,
southeastern and western Kentucky, to approximately 30,000 customers in
southwestern Virginia and to less than 10 customers in Tennessee. KU also
sells wholesale electric energy to 12 municipalities.
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 the three months ended September 30, 2004 was $32.5
million ($7.3 million lower than the three months ended September 30,
2003). The decrease was primarily related to maintenance costs resulting
from severe storms which swept through the service territory in Julyour employees, communities and lower electric sales due to milder weather. KU's net income for the three
months ended September 30, 2004, was $34.8 million ($4.5 million higher
than the three months ended September 30, 2003). The increase was
primarily due to higher retail electric revenues resulting from the general
rate increase, partially offset by higher depreciation expense.
Page 23
LG&E's net income for the nine months ended September 30, 2004 was $73.9
million ($1.0 million lower than the nine months ended September 30, 2003).
The decrease was primarily related to higher operations and maintenance
expense, offset by higher electric revenues resulting from the general rate
increase and a higher environmental cost recovery surcharge. KU's net
income for the nine months ended September 30, 2004 was $94.8 million
($38.5 million higher than the nine months ended September 30, 2003). The
increase was primarily due to higher electric revenues and lower
maintenance expense (KU service territory experienced a severe ice storm in
2003).
As regulated utilities,other stakeholders.
LG&E and KU's financial performance is greatly
impacted by regulatory proceedings. Onstrategy focuses on the following:
- - Achieve scale as an integrated U.S. electric and gas business through
organic growth
- - Maintain excellent customer satisfaction
- - Maintain best-in-class cost position versus U.S. utility companies
- - Develop and transfer best practices throughout the company
- - Invest in infrastructure to meet expanding load and comply with
increasing environmental requirements
- - Achieve appropriate regulated returns on all investment
- - Attract, retain and develop the best people
- - Act with a commitment to corporate social responsibility that enhances
the well being of our employees, demonstrate environmental stewardship,
promote quality of life in our communities and reflect the diversity of
the society we serve
In a June 30, 2004 order, the Kentucky Commission issued an order approving increasesaccepted the settlement
agreements reached by the majority of the parties in the base rates ofrate cases filed
by LG&E and KU.KU in December 2003. 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. The rate increaseincreases took
effect on July 1, 2004. Subsequently,Base electric rates at KU have increased $46.1
million (6.8%) annually. The 2004 increases were the AG commenced an investigation examining communications betweenfirst increases in
electric base rates for LG&E and KU in 13 and 20 years, respectively; the
previous gas rate increase for the LG&E gas utility took effect in
September 2000.
With the installation of four combustion turbines at Trimble County in
2004, near-term regulated load growth in Kentucky is expected to be
satisfied. However, the Integrated Resource Plan submitted by LG&E and KU
to the Kentucky Commission in April 2005 indicated the requirement for
additional base-load capacity in the longer-term. Consequently, LG&E and KU
have begun development efforts for a new base-load coal-fired unit. Trimble
County Unit 2, with a 732 Mw capacity rating, is expected to be jointly-
owned by LG&E and KU (75% aggregate ownership) and IMEA and IMPA (25%
aggregate ownership). Of their 75% (549 Mw) ownership, LG&E will own 19%
(104 Mw) and KU will own 81% (445 Mw). An application for a construction
CCN was filed with the Kentucky Commission and an air permit application
was filed with the Companies and, separately, filed for a rehearingKentucky Department of Air Quality in December 2004. A
public hearing on the rate cases on such issue and certain calculation components of the
increased rates and filed for the existing rate increases to be set aside.draft air permit application occurred in August 2005.
The Kentucky Commission ruled favorably on the CCN application on November
1, 2005. The air permit is consideringexpected to be issued by the matters relatingKentucky Department
of Air Quality in November 2005. LG&E's and KU's share of LG&E Energy's
total capital cost of $885 million for Trimble County Unit 2 is estimated
to be $168 million and $717 million, respectively, through 2010.
Three applications for transmission CCN's were filed with the Kentucky
Commission in May 2005 for the construction of three transmission
facilities to support Trimble County Unit 2. In September 2005, the
Kentucky Commission approved one of the transmission facilities and denied
the other two on the basis that the Companies did not sufficiently
investigate alternative routes. The Kentucky Commission recognized the need
for transmission upgrades contingent upon the approval of the generation
CCN. The Companies expect to refile the applications in the fourth quarter
with the additional supporting documentation requested by the Kentucky
Commission.
In addition to the AG's
actions. ForTrimble County Unit 2 project, another focus of major
utility investment is environmental expenditures. In order to mitigate the
declining SO2 allowance bank at KU over the next several years, KU filed
with the Kentucky Commission in December 2004 an application for a descriptionCCN to
construct four FGDs at an estimated cost of developments$658.9 million, which was
approved in these cases, see Note 11June 2005.
The Kentucky Commission opened an investigation into LG&E's and KU's
membership in the MISO in July 2003. Should LG&E and KU be ordered to exit
the MISO, an aggregate fee of up to $41 million could be imposed, depending
on the timing and circumstances of actual withdrawal. On October 7, 2005,
LG&E and KU filed an application with the FERC seeking the requisite
authority to exit the MISO. This proceeding is expected to continue into
2006. At this time, LG&E and KU cannot predict the outcome or effects of
the Notesvarious Kentucky Commission and FERC proceedings, including whether
they will have a material impact on the financial condition or the results
of operations of the Companies.
The MISO implemented a day-ahead and real-time market (MISO Day 2),
including a congestion management system, in April 2005. This system is
similar to Consolidated Financial Statementsthe LMP system currently used by the PJM RTO and contemplated in
Part 1, Item 1FERC's SMD NOPR. Ultimate financial consequences (changes in transmission
revenues and costs) associated with the implementation of this
Quarterly Report on Form 10-Q.MISO Day 2 are
subject to varying assumptions and calculations and are therefore difficult
to estimate.
Results of Operations
The results of operations for LG&E and KU are affected by seasonal
fluctuations in temperature and other weather-related factors. Because of
these and other factors, the results of one interim period are not
necessarily indicative of results or trends to be expected for another period.the full
year.
Three Months Ended September 30, 2004,2005, Compared to
Three Months Ended September 30, 20032004
LG&E Results:
LG&E's net income decreased $7.3increased $9.5 million (18%(29%) for the three months ended
September 30, 2004,2005, as compared to the three months ended September 30,
2003,2004, primarily due to higher maintenance expenses related to July stormsretail electric revenues resulting from
warmer summer weather (cooling degree days were 29% higher than in 2004),
higher wholesale revenues and lower electric sales.income tax expense.
A comparison of LG&E's revenues for the three months ended September 30,
2004,2005, with the three months ended September 30, 2003,2004, reflects increases
and (decreases) which have been segregated by the following principal
causes:
(in thousands)Cause Electric Gas
Cause(in millions) Revenues Revenues
Retail sales:
Fuel and gas supply adjustments $ (425) $1,24313.3 $(0.1)
Environmental cost recovery surcharge 3,7070.7 -
Earnings sharing mechanism 139(5.1) -
LG&E/KU merger surcredit 123 -
Value delivery surcredit (256) 28
Demand side management 3 (42)
General rate increase 10,105 1,443
Variation in sales volume and other (11,353) (647)22.4 0.1
Total retail sales 2,043 2,02531.3 -
Wholesale sales (2,448) -
Provision for rate refunds (2,689)19.7 -
Other (56) 1346.0 (0.2)
Total $(3,150) $2,159
Page 24$57.0 $(0.2)
Electric revenues decreased $3.2increased $57.0 million (25%) in 2005 primarily as a result of lowerdue to:
- - Higher sales volumes from coolervolume ($27.3 million) related to weather
as cooling degree days declined 3.2% from
last year. Also contributing- - Wholesale sales increased $19.7 million
- Higher MISO related revenue ($13.1 million), due to MISO Day 2 RSGMWP,
earned due to the decrease were lowerMISO's dispatch of higher cost gas-fired units ($7.2
million) and a $12.6 million reclass to revenue from expense offset by a
$6.7 million reclass to KU revenue for activity dating back to the
inception of MISO Day 2
- Higher wholesale revenues and($6.6 million), primarily due to 6% higher
provisions for rate refunds. The provision for rate refunds
decreased revenues $2.7 million, largely as a result of a higher provision
for the environmental cost recovery surcharge. The revenue decreases wereprices ($12.7 million) partially offset by the general rate increase, effective with service
rendered July3% lower volumes ($6.1 million)
- - Higher fuel supply adjustments ($13.3 million) due to significantly
higher fuel costs
- - Lower MISO Day 1 2004, and an increase in environmental cost recovery. Gas
revenues increased $2.2 million primarily as a result of the general rate
increase, effective with service rendered July 1, 2004, and an increase in
recovery of higher natural gas prices billed to customers through the gas
supply clause.transmission revenue ($1.3 million)
Fuel for electric generation and gas supply expenses comprise a large
component of LG&E's total operating expenses. LG&E's electric and gas rates
contain a fuel adjustment clause and a gas supply clause, respectively,
whereby increases or decreases in the cost of fuel and gas supply are
reflected in retail rates, subject to the approval of the Kentucky
Commission.
Fuel for electric generation decreased $2.0increased $25.6 million (4%(48%) in 2005
primarily due to:
- Increased cost per Btu (42% higher), resulting in $23.6 million higher
fuel costs. Fuel costs are significantly higher due to a decrease in generation ($1.8 million)the MISO's
dispatch of gas-fired units committed by the MISO's Reliability
Assessment and a decreaseCommitment process in the real-time market.
- Increased generation (4% higher), resulting in $1.9 million higher fuel
costs
Power purchased increased $14.8 million (77%) in 2005 primarily due to:
- Increased cost of coal burned ($0.2 million). Gas supplyper Mwh (53% higher), resulting in $11.8 million higher
costs
- Increased Mwh purchases (15% higher), resulting in $2.9 million higher
costs
- Higher purchased power costs from the MISO due to unit outages totaled
$9.2 million
Other operations and maintenance expenses increased $0.7$12.5 million (3%(17%) due to an increase in
net gas supply cost ($1.2 million),
offset by a decrease in the volume of retail gas sold ($0.5 million).2005.
Other operation expenses decreased $3.8increased $19.9 million (7%(41%) in 2005 primarily
due to:
- Increased other power supply expenses ($18.7 million) due largely to
MISO Day 2 costs ($19.0 million), as comparedincluding a $12.6 million reclass from
expense to 2003.
Pension expense decreased $1.2 million. Electricrevenue for activity dating back to the inception of MISO Day 2
and $6.4 million administration charges and allocated charges from the
MISO for Day 2 operations
- Increased distribution operations
expense decreased $2.9 millioncosts ($3.1 million) largely due to the transfer
of $4.0 millionstorm expenses in the third quarter of 2004 from operations expenses to
maintenance (relatedexpenses
- Increased administrative and general expenses ($1.2 million) largely
for increased employee benefit costs
- Increased cost of gas losses due to storms) offset by higher non-storm related
distribution operationsthe increase in the unit cost of
$1.1 million.natural gas ($0.6 million)
- Decreased transmission expenses ($3.5 million), primarily MISO related.
Prior to the MISO Day 2 market, most bilateral transactions required the
purchase of transmission; however with the Day 2 market, most transactions
are handled directly with MISO and no additional transmission is
necessary.
Maintenance expenses decreased $7.3 million (32%) in 2005 primarily due
to:
- Decreased distribution costs ($8.9 million) due to the transfer of
storm expenses to from operations expenses to maintenance expenses in 2004
and lower storm costs in 2005
- Increased administrative and general maintenance ($1.3 million)
- Increased maintenance on combustion turbines ($0.4 million)
Depreciation and amortization expense increased $10.5$0.8 million (84%(3%) in 2005
primarily due to storms
($8.8 million, including $4.0 million transferred from Operations to
Maintenanceadditional plant in third quarter 2004). Non-storm related distribution
maintenance increased $2.1 million.
Depreciation and amortization increasedservice.
Other expense - net decreased $1.9 million (7%in 2005 primarily due to:
- Decreased miscellaneous deductions ($1.4 million)
- Increased mark-to-market gains related to energy trading contracts
($0.6 million)
In total, interest expense increased $0.5 million (6%) in 2005 primarily
due to:
- Increased interest on variable-rate debt ($1.7 million)
- Decreased interest costs on interest rate swaps ($0.8 million)
- Decreased interest due to a
corresponding increase in plant in service of $199.4 million (5.8%). The
increase in plant included $37.2 million related to the completion of
Trimble County CT's 9 and 10, as well as increases to steam production
plant of $59.3 million, to electric distribution plant of $31.0 million and
to gas distribution plant of $29.9 million. The increase in depreciation
and amortization was partially offset by a reduction in amortization
expense related to certain software, which became fully amortized in the
final quarter of 2003.
Other income decreased $1.4 million, resulting from a $1.3 million write-
off in July 2004 related to the cancellation of the "Pay As You Go"
metering project.
Variations in income tax expense are largely attributable to changes in pre-
tax income.
Three Months Three Months
Ended Ended
Sept. 30, 2004 Sept. 30, 2003
Statutory federal income taxrefinancing fixed rate 35.0% 35.0%
State income taxes net of federal benefit 4.6 4.9
Amortization of investment tax credit & R&D (0.6) (1.7)
Other differences (0.7) (2.4)
Effective income taxdebt with variable
rate 38.3% 35.8%
Page 25
The variation in the tax rate is largely attributable to excess deferred
tax benefits recorded in 2003, reflecting the benefits of deferred taxes
reversing at lower tax rates than what were provided, and lower
amortization of the investment tax credit.
Interest expense decreased $0.9 million (15%) primarily due to savings on
interest expense realized from the refinancing of fixed-rate Series V and
Series W Pollution Control Bonds to the variable-rate Series GG Pollution
Control Bonds in November 2003.
Interest expense to affiliated companies increased $0.9 million (44%)
primarily due to a $1.1 million increase in interest expense to Fidelia
related to new notes issued in August 2003 and January 2004. Offsetting
this increase is a $0.2 million decrease in interest expense on borrowings
from the money pool due to lower borrowing levels.debt ($0.4 million)
The weighted average interest rate on variable-rate bonds for the three
months ended September 30, 2005, was 2.54%, compared to 1.30% for the
comparable period in 2004.
Variances in income tax expense are largely attributable to changes in pre-
tax income, a reduction of previous accruals per final IRS audit, and a
reduction in the statutory Kentucky income tax rate.
Three Months Three Months
Ended Ended
Sept. 30, 2005 Sept. 30, 2004
was 1.30%Effective Rate
Statutory federal income tax rate 35.0% 35.0%
State income taxes net of federal benefit 3.7 4.6
Reduction of previous accruals per final
IRS audit (9.0) -
Amortization of investment and other
tax credits (1.8) (0.6)
Other differences (1.2) (0.7)
Effective income tax rate 26.7% 38.3%
The increased tax benefit in other differences is largely attributable to
the new Internal Revenue Code Section 199 Qualified Production Activities
deduction and the corresponding rateamortization of excess deferred income taxes, which
reflect the benefits of deferred tax reversing at higher tax rates than the
current statutory rate.
See Part 1 - Item 1, Notes to Financial Statements, Note 6 for the three months ended September 30, 2003, was 0.99%.additional
discussion of income taxes.
KU Results:
KU's net income increased $4.5decreased $3.1 million (15%(9%) for the three months ended
September 30, 2004,2005, as compared to the three months ended September 30,
2003.2004. The increasedecrease was primarily due to higher revenues due to July 2004
rate increases,operation and maintenance
expenses, partially offset by increased retail revenues as a result of
warmer summer weather (cooling degree days were 77% higher depreciation expense.than in 2004)
and higher wholesale revenues.
A comparison of KU's revenues for the three months ended September 30,
2004,2005, with the three months ended September 30, 2003,2004, reflects increases
and (decreases) which have been segregated by the following principal
causes:
Cause Electric
(in thousands) Electric
Causemillions) Revenues
Retail sales:
Fuel supply adjustments $ 2,297$41.7
Environmental cost recovery surcharge 1,1512.1
Earnings sharing mechanism 1,332
LG&E/KU merger surcredit (615)
Value delivery surcredit (111)
Demand side management 404
General(5.1)
Rates and rate increase 9,596structure 0.8
Variation in sales volume and other (446)19.4
Total retail sales 13,60858.9
Wholesale sales 1,465
Provision for rate collections 1,79436.7
Other 376(1.0)
Total $17,243$94.6
Electric revenues increased $17.2$94.6 million (37%) in 2005 primarily as the resultdue to:
- Higher fuel supply adjustments ($41.7 million) due to higher cost of
the
general rate increase, effective with service rendered July 1, 2004,fuel used for generation and increases in fuel adjustment clause recoveries, recovery of environmental
costs, earnings sharing mechanism revenues,purchased power
- Higher sales volumes ($23.6 million) due to weather
- Wholesale sales increased $36.7 million
- Higher wholesale revenues and an
increase in provision for rate collections. The provision for rate
collections increased $1.8 million largely as the result of a higher
provision for the environmental cost recovery surcharge ($4.218.6 million), partially offset by lower provisions for the earnings sharing mechanismprimarily due to 6% higher
prices ($1.314.8 million) and fuel clause recovery2% higher sales volume ($1.13.8 million).
- Higher MISO related revenue ($18.1 million), due to MISO Day 2 RSGWMP,
earned due to the MISO's dispatch of higher cost gas-fired units
($8.3 million), a $3.1 million reclass to revenue from expense and
a $6.7 million reclass from LG&E revenue for activity dating back
to the inception of MISO Day 2
- Lower MISO Day 1 transmission revenue ($2.6 million)
Fuel for electric generation comprises a large component of KU's total
operating expenses. KU's electric rates contain a fuel adjustment clause,
whereby increases or decreases in the cost of fuel are reflected in retail
rates, subject to the approval of the Kentucky Commission, the Virginia
State Corporation Commission, and the Federal Energy Regulatory Commission.FERC.
Fuel for electric generation increased $2.9$40.3 million (4%(52%) forin 2005
primarily due to:
- Increased cost per Btu (36% higher), resulting in $31.2 million higher
fuel costs. Fuel costs are significantly higher due to the quarter
becauseMISO's
dispatch of an increase in generation ($3.2 million), partially offsetgas-fired units committed by a
slight decreasethe MISO's Reliability
Assessment and Commitment process in the costreal-time market.
- Increased generation (12% higher), resulting in $9.0 million higher
fuel costs, primarily due to higher dispatch of coal burned ($0.3 million).
Page 26gas-fired units
Power purchased increased $1.5$31.6 million (5%(95%) in 2005 primarily due to:
- Increased cost per Mwh (89% higher), resulting in $30.5 million higher
costs
- Increased volumes of Mwh purchased (3% higher), resulting in $1.1
million higher costs
- Higher purchased power costs from the MISO due to an increaseunit outages totaled
$12.7 million
Other operations and maintenance expenses increased $25.9 million (48%) in
the price
of power purchased ($3.1 million), offset by a decrease in the volume
purchased ($1.6 million).2005.
Other operation expenses increased $2.2$20.3 million (6%(54%) as compared to 2003.
Steam power operations increased $1.9 million,in 2005 primarily
due to:
- Increased other power supply expenses due largely to MISO Day 2 costs
($19.0 million), including a $3.1 million reclass from expense to revenue
for activity dating back to the inception of MISO Day 2 and $15.9 million
of administration charges and allocated charges from the MISO for Day 2
operations
- Increased administrative and general expenses ($2.4 million) largely
the result of increased emission allowance expenseemployee benefit costs
- Decreased transmission expenses ($1.20.9 million), primarily MISO related.
Prior to the MISO Day 2 market, most bilateral transactions required the
purchase of transmission; however with the Day 2 market, most transactions
are handled directly with MISO and higher expense related to
SCR/NOX reduction ($0.4 million).no additional transmission is necessary.
Maintenance expense decreased $1.0expenses increased $6.4 million (53%) in 2005 primarily due
to a decreaseto:
- Increased distribution system costs ($2.4 million), the result of
$1.4 million in distribution maintenance. In September 2004,reclassifying $4.0 million in costs related to the 2003 ice storm were reclassifiedexpenses in 2004 from maintenance
expense to a
regulatory asset
based on an order from the Kentucky
Commission,- Increased steam generation maintenance ($2.1 million) due to be amortized through June 2009. KU earns a return of these
amortized costs, which are includedoutages at
E.W. Brown and Green River
- Increased administrative and general maintenance ($1.2 million)
- Increased combustion turbine expenses ($0.7 million)
Property and other taxes decreased $0.8 million (18%).
Other (income) - net decreased $1.1 million (50%) in KU's jurisdictional operating
expenses. Offsetting this decrease was $1.3 million in expense2005 primarily due to:
- Increased miscellaneous deductions $1.7 million.
- Increased mark-to-market gains related to 2004 storms,energy trading contracts
($0.6 million)
In total, interest expense increased $0.6 million higher vegetation management expense, and $0.2
million amortization of the ice storm deferral.
Depreciation and amortization increased $4.3 million (17%(9%) in 2005 primarily
due to a
corresponding increase in plant in service of $155.4 million (5%). The
increase in plant included $63.8 million related to the completion of
Trimble County CT's 9 and 10, as well as increases to transmission plant of
$11.1 million and to electric distribution plant of $30.6 million.
Variations in income tax expense are largely attributable to changes in
pretax income.
Three Months Three Months
Ended Ended
Sept. 30, 2004 Sept. 30, 2003
Statutory federal income tax rate 35.0% 35.0%
State income taxes net of federal benefit 4.1 5.0
Amortization of investment tax credit & R&D (1.0) (1.4)
Other differences (3.2) (2.9)
Effective income tax rate 34.9% 35.7%
Interest expense increased $0.4 million (16%). A reduction in the savingsto:
- Increased interest costs associated with the interest rate swaps caused primarily by the termination of
a swap, increased($1.1
million)
- Increased interest expense by $1.2 million. This increase was
offset by $0.7 million incosts associated with variable rate debt ($0.6
million)
- Decreased interest expense savings from the redemption of
8.55% Series P Pollution Control Bonds redeemed in November of 2003.
Interest expense to affiliated companies increased $1.6 million (86%)
primarilycosts due to a $1.8 million increase inrefinancing fixed rate debt with
variable rate debt ($0.4 million)
- Decreased interest expense to Fidelia
related to new notes issued from August 2003 through January 2004.
Offsetting this increase is a $0.2 million decrease in interest expense on
borrowings from the money poolcosts due to lower borrowing levels.refinancing first mortgage bonds with
long-term debt from affiliates ($0.4 million)
- Decreased interest costs for mark-to-market of the interest rate swaps
($0.1 million)
The weighted average interest rate on variable-rate bonds for the three
months ended September 30, 2004,2005, was 2.54%, compared to 1.32% and the corresponding rate for the
three months ended September 30, 2003, was 0.91%.
Nine Months Ended September 30, 2004, Compared to
Nine Months Ended September 30, 2003
LG&E Results:
LG&E's net income decreased $1.0 million (1%) for the nine months ended
September 30, 2004, as compared to the nine months ended September 30,
2003, primarily due to higher operations and maintenance expense, offset by
higher electric revenues.
Page 27
A comparison of LG&E's revenues for the nine months ended September 30,
2004, with the nine months ended September 30, 2003, reflects increases and
(decreases) which have been segregated by the following principal causes:
(in thousands) Electric Gas
Cause Revenues Revenues
Retail sales:
Fuel and gas supply adjustments $(1,493) $ 46,625
Environmental cost recovery surcharge 11,618 -
Earnings sharing mechanism 3,913 -
LG&E/KU merger surcredit (1,296) -
Value delivery surcredit (786) 5
Demand side management 357 (420)
Weather normalization - 2,419
General rate increase 10,105 1,443
Variationcomparable period in sales volume and other 4,244 (22,523)
Total retail sales 26,662 27,549
Wholesale sales 5,642 1,034
Provision for rate refunds (5,670) -
Other 95 (344)
Total $26,729 $ 28,239
Electric revenues increased $26.7 million primarily as a result of
increased environmental cost recovery, the general rate increase, effective
with service rendered July 1, 2004, wholesale revenues (4% higher pricing
offset by 3% lower volumes), and higher retail sales volumes. The
provision for rate refunds decreased revenues $5.7 million due to a
decrease in environmental cost recovery surcharge ($6.7 million) and
earnings sharing mechanism recoveries ($0.9 million), partially offset by
higher fuel adjustment clause recoveries ($1.9 million).
Gas revenues increased $28.2 million primarily as a result of higher
natural gas prices passed on to customers through the gas supply clause,
partially offset by lower sales volumes resulting from milder weather
during the heating months than in the prior period.
Fuel for electric generation increased $2.4 million (2%) for the nine
months due to an increase in the cost of coal burned ($1.4 million) and
higher generation ($1.0 million). Gas supply expenses increased $30.3
million (20%) due to an increase in net gas supply cost ($42.0 million),
offset by a decrease in the volume of retail gas delivered to the
distribution system ($11.5 million).
Power purchased increased $5.3 million (9%) due to an increase in the price
of power purchased ($4.3 million) and a 2% increase in the volume of the
purchases ($1.0 million) primarily to meet slightly higher load
requirements.
Other operations expenses increased $4.5 million (3%) in 2004, as compared
to 2003, due to higher transmission expense of $2.7 million, primarily due
to higher MISO-related expense, and $4.6 million higher electric
distribution expense, due in part to the May and July 2004 storms. These
higher expenses were partially offset by $2.8 million lower amortization of
costs to achieve the KU/LG&E merger and One Utility initiative. These
costs were fully amortized by June 2003 (KU/LG&E merger) and September 2003
(One Utility).
Maintenance expenses increased $7.8 million (18%). Distribution
maintenance increased $9.6 million, primarily due to the May and July storm
restoration. In 2003, $2.1 million of obsolete inventory was written off.
Page 28
Depreciation and amortization increased $0.2 million (0.2%). The net
increase in depreciation and amortization expense for the nine months ended
was due to an increase in depreciation related to an increase in plant in
service of $199.4 million (5.8%) which was largely offset by a decrease in
amortization expense related to certain software, which became fully
amortized in the final quarter of 2003.2004.
Variations in income tax expense are largely attributable to changes in
pre-
tax income.
Ninepretax income and a reduction of previous accruals per final IRS audit.
Three Months Three Months
Ended Nine Months Ende
dEnded
Sept. 30, 2005 Sept. 30, 2004
Sept. 30, 2003Effective Rate
Statutory federal income tax rate 35.0% 35.0%
State income taxes net of federal benefit 5.2 5.34.6 4.1
Reduction of previous accruals per final
IRS audit (8.9) -
EEI adjustment 6.3 -
Amortization of investment and other
tax credit & R&D (2.7) (2.7)credits (0.9) (1.0)
Other differences (0.1) (1.6)(0.5) (3.3)
Effective income tax rate 37.4% 36.0%35.6% 34.8%
The variationreduced tax benefit in other differences for 2005 is attributable to
the recognition of a deferred tax liability on the undistributed earnings
from the Company's investment in EEI. In prior periods, the effective rate
was reduced for the anticipated EEI dividends received deduction.
See Part 1 - Item 1, Notes to Financial Statements, Note 6 for additional
discussion of income taxes.
Nine Months Ended September 30, 2005, Compared to
Nine Months Ended September 30, 2004
LG&E Results:
LG&E's net income increased $29.9 million (40%) for the nine months ended
September 30, 2005, as compared to the nine months ended September 30,
2004, primarily due to the full period effect of the increase in electric
and gas base rates effective July 1, 2004 increased electric sales volumes
due to warmer summer weather and higher wholesale sales.
A comparison of LG&E's revenues for the nine months ended September 30,
2005, with the nine months ended September 30, 2004, reflects increases and
(decreases) which have been segregated by the following principal causes:
Cause Electric Gas
(in millions) Revenues Revenues
Retail sales:
Fuel and gas supply adjustments $ 22.7 $ 12.4
Environmental cost recovery surcharge 4.3 -
Earnings sharing mechanism (12.3) -
LG&E/KU merger surcredit (1.3) -
Rates and rate structure 25.1 4.9
Variation in sales volume and other 22.4 (8.9)
Total retail sales 60.9 8.4
Wholesale sales 56.1 9.2
Other 6.4 -
Total $123.4 $17.6
Electric revenues increased $123.4 million (20%) in 2005 primarily due to:
- - Higher revenues due to an increase in rates and a change in rate
structure ($25.1 million), related to the rate case order which took
effect on July 1, 2004
- - Higher sales volumes ($32.7 million) due to weather
- - Higher fuel supply adjustments ($22.7 million) due to higher cost of
fuel used for generation and purchased power
- - Wholesale sales increased $56.1 million
- Higher wholesale revenues ($43.0 million), primarily due to 5% higher
prices ($30.5 million) and 2% higher sales volumes ($12.5 million)
- Higher MISO related revenue ($13.1 million), due to MISO Day 2 RSGMWP,
earned due to the MISO's dispatch of higher cost gas-fired units
- - Lower ESM revenues ($12.3 million)
- - Lower MISO Day 1 transmission revenue ($3.4 million)
During the second quarter of 2005, LG&E made out-of-period adjustments for
estimated under collection of ECR revenues to be billed in subsequent
periods. The adjustments were immaterial during all reporting periods
involved (March 2003 through October 2004). As a result, year-to-date LG&E
revenues were increased $4.8 million. Year-to-date net income was increased
$2.9 million for LG&E.
Gas revenues increased $17.6 million (7%) in 2005 primarily due to:
- - Higher revenues due to an increase ($12.4 million) in recovery of
higher natural gas prices billed to customers through the gas supply clause
- - Higher wholesale revenues ($9.2 million) due to 3% higher sales prices
and 1% higher volumes
- - Higher revenues due to an increase in rates and a change in rate
structure ($4.9 million), related to the rate case order which took effect
on July 1, 2004
- - Lower retail revenues ($8.9 million) due to lower retail volumes
Fuel for electric generation and gas supply expenses comprise a large
component of LG&E's total operating expenses. LG&E's electric and gas rates
contain a fuel adjustment clause and a gas supply clause, respectively,
whereby increases or decreases in the other differences is largely attributablecost of fuel and gas supply are
reflected in retail rates, subject to excess
deferred tax benefits recordedthe approval of the Kentucky
Commission.
Fuel for electric generation increased $53.3 million (34%) in 2003, reflecting2005
primarily due to:
- Increased cost per Btu (28% higher), resulting in $45.1 million higher
fuel costs. Fuel costs are significantly higher due to the benefitsMISO's dispatch
of deferred
taxes reversing at lower tax ratesgas-fired units committed by the MISO's Reliability Assessment and
Commitment process in the real-time market.
- Increased generation (5% higher), resulting in $8.2 million higher fuel
costs
Power purchased increased $35.7 million (54%) in 2005 primarily due to:
- Increased cost per Mwh (43%), resulting in $30.2 million higher costs
- Increased volume of power purchased (8%), resulting in $5.5 million
higher costs
- Higher purchased power costs from the MISO due to unit outages totaled
$9.8 million
Gas supply expenses increased $9.6 million (5%) in 2005 primarily due to:
- Increased cost of purchases for wholesale sales ($8.3 million)
- Increased cost per MCF ($1.6 million)
- Decreased volume of gas delivered to the distribution system ($0.4
million)
Other operations and maintenance expenses increased $0.3 million (less than
what were provided.
Property and other taxes1%) in 2005.
Other operation expenses increased $1.6 million (13%). Property tax
expense reflected a $1.2 million coal incentive tax credit in 2003, and a $0.7 million credit(less than 1%) in 2004. The remaining increase related2005
primarily due to:
- Increased power supply expenses ($10.8 million) due largely to MISO Day
2 costs ($11.6 million) of administration charges and allocated charges
from the MISO for Day 2 operations
- Increased steam power costs ($2.5 million) due primarily to increased
property tax accruals, as a result of capital expansion, and
higher employment taxes.
Interest expense decreased $3.0 million (17%). Interest related to long-
term debt decreased $5.8 millionscrubber reactant expenses
- Increased gas storage losses ($1.4 million) due to the refinancingincreased unit
cost of fixed-rate
Series V and Series W Pollution Control Bonds intonatural gas
- Decreased transmission expenses ($9.0 million), primarily MISO related.
Prior to the variable-rate Series
GG Pollution Control Bonds andMISO Day 2 market, most bilateral transactions required the
redemptionpurchase of the first mortgage bond in
August 2003. These savings were partially offset by an increase in interest
expense related to interest rate swaps associatedtransmission; however with the Series GG bonds
totaling $2.6 million.
Interest expenseDay 2 market, most transactions
are handled directly with MISO and no additional transmission is necessary.
- Decreased distribution costs ($4.5 million) due to affiliated companiessignificantly lower
storm expenses in 2005
- Decreased administrative and general expenses ($0.7 million)
Maintenance expenses decreased $0.6 million (1%) in 2005 primarily due
to:
- Decreased distribution expenses ($8.1 million) due to significantly
lower storm costs in 2005
- Increased administrative and general expenses ($3.9 million) primarily
for information technology expenses charged to operations in 2004
- Increased steam generation costs ($2.5 million) due to boiler and
pollution control equipment repairs
- Increased repairs to combustion turbines ($0.8 million)
- Increased repairs to gas distribution facilities $(0.4 million)
Depreciation and amortization increased $5.0$7.0 million (121%(8%) primarily due to
a $6.4additional plant in service.
Other expense - net decreased $2.9 million increase in 2005 primarily due to:
- Increased mark-to-market gains related to energy trading contracts
($1.7 million)
- Decreased miscellaneous deductions ($1.3 million)
In total, interest expense to Fidelia
related to new notes issuedincreased $2.2 million (9%) in August 2003 and January 2004. Offsetting
this increase is a $1.4 million decrease in2005 primarily
due to:
- Increased interest expense on borrowings
from thevariable-rate debt ($4.9 million)
- Increased interest on money pool debt ($0.6 million)
- Increased interest on customer deposits ($0.6 million)
- Decreased interest costs on interest rate swaps ($2.3 million)
- Decreased interest on affiliated loans with Fidelia ($0.8 million)
- Decreased interest due to lower borrowing levels.refinancing fixed rate debt with variable
rate debt ($0.5 million)
- Decreased interest on income taxes ($0.3 million)
The weighted average interest rate on variable-rate bonds for the nine
months ended September 30, 20042005, was 1.14%2.36%, compared to 1.12%1.14% for the
comparable period in 2003.
KU Results:
KU's net income increased $38.5 million (68%) for the nine months ended
September 30, 2004, as compared to the nine months ended September 30,
2003. The increase was primarily due to higher electric revenues and lower
maintenance expense.
Page 29
A comparison of KU's revenues for the nine months ended September 30, 2004,
with the nine months ended September 30, 2003, reflects increases and
(decreases) which have been segregated by the following principal causes:
(in thousands) Electric
Cause Revenues
Retail sales:
Fuel supply adjustments $ 2,683
Environmental cost recovery surcharge 3,218
Earnings sharing mechanism 6,636
LG&E/KU merger surcredit (2,443)
Value delivery surcredit (296)
Demand side management 424
General rate increase 9,596
Variation in sales volume and other 18,874
Total retail sales 38,692
Wholesale sales 13,382
Provision for rate collections 17,657
Other 5,110
Total $74,841
Electric revenues increased $74.8 million primarily due to increased sales
volumes to ultimate consumers of 3.9% due to warmer weather than last year
as cooling degree days increased 3%. The general rate increase, effective
with service rendered July 1, 2004, increased revenues approximately $9.6
million. Also contributing to the overall revenue increase were increases
in the provision for rate collections, wholesale revenues (26% higher
pricing offset by 3% lower volumes), earnings sharing mechanism recoveries
and the recovery of fuel and environmental costs. The provision for rate
collections included higher provisions for the environmental cost recovery
($14.6 million), the earnings sharing mechanism ($2.2 million) and the fuel
adjustment clause ($0.9 million).
Fuel for electric generation increased $14.4 million (7%) for the nine
months due to an increase in the cost of coal burned ($6.4 million) and an
increase in generation ($8.0 million).
Power purchased decreased $1.4 million (1%) due to a decrease in the price
of power purchased ($2.1 million), partially offset by an increase in
volumes purchased ($0.7 million) due to higher retail and wholesale loads.
Other operation expenses increased $0.2 million. Steam generation expense
increased $4.3 million, primarily due to higher emission allowance expense,
and transmission expense increased $0.5 million. Amortization of $2.9
million related to costs to achieve the KU/LG&E merger and One Utility
initiative was recorded in 2003 and was fully amortized as of June 2003.
Pension expense decreased $0.8 million, and bad debt expense decreased $0.7
million.
Maintenance expenses decreased $8.4 million (17%). Steam power maintenance
expense decreased $3.2 million; Ghent Unit 3, Green River Unit 4 and Tyrone
Unit 3 all had major overhauls in 2003. Distribution maintenance decreased
$2.8 million. In September 2004, $4.0 million in costs related to the 2003
ice storm were reclassified from maintenance expense to a regulatory asset,
based on an order from the Kentucky Commission, to be amortized through
June 2009. KU earns a return of these amortized costs, which are included
in KU's jurisdictional operating expenses. Offsetting this decrease was
$2.2 million in expense related to the 2004 storms. Transmission overhead
line maintenance decreased $0.4 million.
Page 30
Depreciation and amortization increased $3.6 million (5%) due to an
increase in plant in service of $155.4 million (4.8%). The increase in
plant included $63.8 million related to the completion of Trimble County
CTs 9 and 10, as well as increases to transmission plant of $11.1 million
and to electric distribution plant of $30.6 million.
Variations2004.
Variances in income tax expense are largely attributable to changes in pretax income.pre-
tax income, reduction of previous accruals per final IRS audit and a
reduction in the statutory Kentucky rate.
Nine Months Nine Months
Ended Nine Months Ended
Sept. 30, 20042005 Sept. 30, 20032004
Effective Rate
Statutory federal income tax rate 35.0% 35.0%
State income taxes net of federal benefit 5.3 5.84.3 5.2
Reduction of previous accruals per
final IRS audit (3.4) 0.0
Amortization of investment and other
tax credit & R&D (1.0) (2.3)credits (2.0) (2.7)
Other differences (2.4) (3.6)(1.4) (0.2)
Effective income tax rate 36.9% 34.9%32.5% 37.3%
The increased tax benefit in other differences is largely attributable to
the new Internal Revenue Code Section 199 Qualified Production Activities
deduction and the amortization of excess deferred income taxes, which
reflect the investmentbenefits of deferred tax credit and other differences were
approximatelyreversing at higher tax rates than the
same in both periods, but lower pretaxcurrent statutory rate.
See Part 1 - Item 1, Notes to Financial Statements, Note 6 for additional
discussion of income taxes.
KU Results:
KU's net income decreased $7.8 million (8%) for the nine months ended
September 30, 2003, caused the percentage changes to be
greater in the 2003 period.
Interest expense decreased $6.3 million (45%) due primarily2005, as compared to the redemptionnine months ended September 30,
2004. The decrease was primarily due higher operations and maintenance
expenses partially offset by the increase in base rates effective July 1,
2004, and higher retail and wholesale sales.
A comparison of 8.55% Series P Pollution Control BondsKU's revenues for the nine months ended September 30, 2005,
with the nine months ended September 30, 2004, reflects increases and
6.32% Series Q
Pollution Control Bonds redeemed(decreases) which have been segregated by the following principal causes:
Cause Electric
(in millions) Revenues
Retail sales:
Fuel supply adjustments $77.4
Environmental cost recovery surcharge 8.9
Earnings sharing mechanism (13.5)
LG&E/KU merger surcredit (1.8)
Rates and rate structure 27.6
Variation in Novembersales volume and Juneother 20.1
Total retail sales 118.7
Wholesale sales 57.5
Other (9.9)
Total $166.3
Electric revenues increased $166.3 million (23%) in 2005 primarily due to:
- - Higher fuel supply adjustments ($77.4 million) due to higher cost of
2003,
respectively. Additionally, interestfuel used for generation and purchased power
- - Wholesale sales increased $57.5 million
- Higher wholesale revenues ($39.4 million), primarily due to 5% higher
prices ($36.6 million) and less than 1% higher sales volumes
($2.8 million)
- Higher MISO related revenue ($18.1 million), due to MISO Day 2 RSGMWP,
earned due to the MISO's dispatch of higher cost gas-fired units
- - An increase in rates and a change in rate swaps yielded a $1.6 million
decrease in related interest expenses resulting primarily from the February
termination of a swapstructure ($27.6 million),
related to the Series 9 Pollution Control Bondsrate case order which took effect on July 1, 2004
- - Higher sales volumes ($24.3 million) due to weather
- - Lower revenues due to the discontinuation of the earnings sharing
mechanism (ESM) in the first quarter of 2005 ($13.5 million)
- - Lower MISO Day 1 transmission revenue ($6.7 million)
During the second quarter of 2005, KU made out-of-period adjustments for
estimated over collection of ECR revenues to be billed in subsequent
periods. The adjustments were immaterial during all reporting periods
involved (May 2003 through January 2005). As a result, year-to-date KU
revenues were decreased $2.4 million. Year-to-date net income in the
current period was reduced $1.5 million for KU.
Fuel for electric generation comprises a large component of KU's total
operating expenses. KU's electric rates contain a fuel adjustment clause,
whereby increases or decreases in the cost of fuel are reflected in retail
rates, subject to the approval of the Kentucky Commission, the Virginia
State Corporation Commission, and better performancethe FERC.
Fuel for electric generation increased $74.1 million (34%) in 2005
primarily due to:
- Increased cost per Btu (32% higher), resulting in $70.5 million higher
fuel costs. Fuel costs are significantly higher due to the MISO's dispatch
of remaining swaps.
Interestgas-fired units committed by the MISO's Reliability Assessment and
Commitment process in the real-time market.
- Increased generation (2% higher), resulting in $3.5 million higher fuel
costs.
Power purchased increased $56.0 million (53%) in 2005 primarily due to:
- Increased cost per Mwh (41% higher), resulting in $46.5 million higher
costs.
- Increased volumes of Mwh purchased (9% higher), resulting in $9.4
million higher costs.
- Higher purchased power costs from the MISO due to unit outages totaled
$15.5 million
Other operations and maintenance expenses increased $39.8 million (24%) in
2005.
Other operation expenses increased $23.3 million (21%) in 2005 primarily
due to:
- Increased power supply costs ($22.5 million) due largely to MISO Day 2
costs ($22.4 million) administration charges and allocated charges from the
MISO for Day 2 operations
- Increased administrative and general costs ($2.4 million) due to
increases in customer accounts and collection expenses
- Decreased transmission expense ($1.6 million), primarily MISO related.
Prior to affiliated companiesthe MISO Day 2 market, most bilateral transactions required the
purchase of transmission; however with the Day 2 market, most transactions
are handled directly with MISO and no additional transmission is necessary.
Maintenance expenses increased $7.2$17.6 million (213%(43%) in 2005 primarily due
to:
- Increased steam generation maintenance ($9.1 million) due to outages at
E.W. Brown, Ghent and Green River.
- Increased distribution system costs ($4.0 million), the result of
reclassifying $4.0 million in storm expenses in 2004 from maintenance to a
regulatory asset.
- Increased administrative and general expenses ($3.3 million) primarily
for information technology expenses charged to operations in 2004.
- Increased combustion turbine expenses ($0.8 million).
- Increased transmission line maintenance ($0.3 million).
Property and other taxes decreased $1.1 million.
Other (income) - net decreased $0.7 million (18%) in 2005 primarily due to:
- Decreased miscellaneous deductions ($2.4 million)
- Increased mark-to-market gains related to energy trading contracts
($1.7 million)
Depreciation and amortization increased $5.8 million (7%) primarily due to
a $7.9 million increaseadditional plant in service.
In total, interest expense to Fidelia
related to new notes issuedincreased $3.3 million (18%) in August 2003 through January 2004.
Offsetting this increase is a $0.7 million decrease in2005 primarily
due to:
- Increased interest expensecosts on borrowings frominterest rate swaps ($1.9 million).
- Increased interest on variable rate debt ($1.8 million).
- Increased interest costs associated with the money poolmark-to-market of the
interest rate swaps ($1.5 million).
- Decreased interest costs due to lower borrowing levels.refinancing fixed rate debt with
variable rate debt ($1.3 million).
- Decreased interest costs from refinancing first mortgage bonds with
long-term debt from affiliates ($0.6 million).
The weighted average interest rate on variable-rate bonds for the nine
months ended September 30, 2004,2005, was 2.39%, compared to 1.16% and the corresponding rate for the
nine months ended Septembercomparable period in 2004.
Variations in income tax expense are largely attributable to changes in
pretax income and a reduction of previous accruals per final IRS audit.
Nine Months Nine Months
Ended Ended
Sept. 30, 2003,2005 Sept. 30, 2004
Effective Rate
Statutory federal income tax rate 35.0% 35.0%
State income taxes net of federal benefit 4.7 5.3
Reduction of previous accruals per
final IRS audit (3.2) 0.0
EEI adjustment 2.3 0.0
Amortization of investment and other
tax credits (0.9) (1.0)
Other differences (1.4) (2.3)
Effective income tax rate 36.5% 37.0%
The reduced tax benefit in other differences for 2005 is attributable to
the recognition of a deferred tax liability on the undistributed earnings
from the Company's investment in EEI. In prior periods, the effective rate
was 1.08%.reduced for the anticipated EEI dividends received deduction.
See Part 1 - Item 1, Notes to Financial Statements, Note 6 for additional
discussion of income taxes.
Liquidity and Capital Resources
LG&E and KU's needs for capital funds are largely related to the
construction of plant and equipment necessary to meet the needs of electric
and gas utility customers.customers, in addition to debt service requirements and
dividend payments. Internal and external lines of credit are maintained to
fund short-term capital requirements. LG&E and KU believe that such sources
of funds will be sufficient to meet the needs of the business in the
foreseeable future.
As ofAt September 30, 2004,2005, LG&E and KU arewere 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. The CompaniesLG&E and KU
expect to cover any working capital deficiencies with cash flow from
operations, money pool borrowings and borrowings from Fidelia, an E.ON
financing subsidiary.Fidelia.
Construction expenditures for the nine months ended September 30, 20042005,
amounted to $95.0 million for LG&E and KU amounted to $94.2$76.3 million and $104.0 million, respectively.
Suchfor KU. At LG&E,
expenditures include constructionconnection of new customers ($9.8 million),
expenditures to meet nitrogen oxide (NOx)
emission standardsimprove boiler and the acquisition of combustion turbinesother generation equipment ($9.6
million), enhancements/upgrades to meet peak
power demands. Expenditures for the nine months ended September 30, 2004,
by LG&Edistribution equipment ($9.6 million),
pollution control facilities ($5.7 million), a new transmission line ($2.4
million) and KU for NOx construction were $4.1 million and $29.2 million,
respectively. Expenditures for the nine months ended September 30, 2004,
for Trimble County combustion turbines, Units 7 through 10, by LG&E and KU
were $7.0 million and $12.0 million, respectively. In addition, LG&E
construction expenditures include $10.0 million for distribution overhead
line construction, $4.1 million for Mill Creek Unit 3 ductwork installation
related to the flue gas desulfurization ("FGD") project, and $8.3 million
for gas main replacements.replacements ($2.2 million). At KU, construction expenditures
include $6.4
million for E.W. Brown Unit 3 cooling towerincluded improvements to boiler and precipitator rebuildother generation equipment ($14.8
million), connection of new customers ($8.4 million), enhancements/upgrades
to distribution equipment ($6.6 million) and $9.0 million for distribution construction in the Lexington area.pollution control facilities
($3.4 million). The expenditures were financed with internally generated
fundsfunds.
LG&E's and intercompany
loans from affiliates.
Page 31
LG&E'sKU's cash balance increased $4.2balances decreased $1.0 million due to increased net borrowings
from affiliated companies, partially offset by pension funding and payment
of common dividends to its parent company. LG&E's restricted cash balance
increased $11.5$0.4 million,
respectively, during the nine months ended September 30, 2004,2005, primarily
due to an increase in collateral held by third parties related to
interest rate swaps. KU's cash balance remained level, decreasing $0.2
million during the nine months ended September 30, 2004, as higher net
income and increased net borrowings from affiliated companies offset
pension funding, construction expenditures and the payment of common
dividends to its parent company.and repayments of debt and construction
expenditures, partially offset by higher cash provided by operating
activities.
Variations in accounts receivable, accounts payable and materials and
suppliesinventories are
generally not significant indicators of LG&E's and KU's liquidity. In general, suchSuch
variations are usuallyprimarily attributable to seasonal fluctuations in weather,
which have a direct effect on sales of electricity and natural gas. However, the increaseThe
decrease in accounts receivable at LG&E and KU, as of September 30, 2004, was primarily due to the termination of the accounts receivable securitization programs in January
2004. Discontinuing the accounts receivable securitization programs
resulted in an increase in accounts receivable of $58.0 million at LG&E and
$50.0 million at KU. (LG&E and KU maintained a reserve for uncollectible
accounts related to receivables sold during the securitization program).
The increase in accounts receivable at LG&E as of September 30, 2004 was
somewhat offset by theseasonal
impact of decreased gas salessales. The increase in September 2004
compared to December 2003. The decrease in fuel inventory at KU as of
September 30, 2004, was dueLG&E's gas stored
underground relates to an increase in tons burned and a slow downthe average unit cost of coal deliveries.gas in
inventory.
Interest rate swaps are used to hedge LG&E's and KU's underlying variable-
rate debt obligations. These swaps hedge specific debt issuances and,
consistent with management's designation, are accorded hedge accounting
treatment. As of September 30, 2004,2005, LG&E had swaps with a combined
notional value of $228.3$211.3 million and KU had swapsone swap with a combined notional value
of $103.0$53.0 million. LG&E's 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. KU's swapsswap effectively convert fixed-rateconverts fixed-
rate obligations on KU's First Mortgage Bondsfirst mortgage bonds Series P and R to variable-rate
obligations.
In February 2004,June 2005, a KU terminated theinterest rate swap it had in place at December 31,
2003 related to its Series 9 Pollution Control Bonds. Thewith a notional amount of the terminated swap was $50 million
andwas terminated by the counterparty pursuant to the terms of the swap
agreement. KU received a payment of $2.0$1.9 million as partin consideration for the
termination of the agreement. KU also called the underlying debt (First
Mortgage Bond Series R) and paid a call premium of $1.9 million. The swap
was fully effective upon termination, resulting intherefore, no impact on earnings
occurred as a gainresult of $0.8the bond call and related swap termination.
In February 2005, an LG&E interest rate swap with a notional amount of $17
million matured. The swap was fully effective upon expiration, therefore,
the impact on earnings and other comprehensive income from the swap
maturity was less than $0.1 million.
At September 30, 2004,2005, LG&E's and KU's percentage of debt having a variable
rate, debt, including the impact of interest rate swaps, was 38.0% of LG&E's total debt at $346.7 million47.8% ($419.6
million) and 44.0% of
KU's total debt at $328.9 million. At December 31, 2003, variable rate
debt, including the impact of interest rate swaps, was 44.0% of LG&E's
total debt at $386.3 million and 55.5% of KU's total debt at $397.1
million.45.1% ($344.1 million), respectively.
Under the provisions offor LG&E's variable-rate Pollution Control Bonds,pollution control bonds,
Series S, T, U, BB, CC, DD and EE, and KU's variable-rate Pollution Control
Bonds,pollution control
bonds Series 10, 12, 13, 14, and 15, the bonds are subject to tender for
purchase at the option of the holder and to mandatory tender for purchase
upon the occurrence of certain events, causing the bonds to be classified
as current portion of long-term debt in the Consolidated Balance Sheets. The average
annualized interest rate for these bonds during the three months and nine months
ending September 30, 2004,2005 was 1.20%2.63% and 1.14%2.36%, respectively, for the LG&E bonds and
1.30%2.59% and 1.18%2.40%, respectively, for the
KU bonds.
In January 2004,KU.
During June 2005, LG&E entered into two long-term loans with Fidelia, one
totaling $25 million with an interest rate of 4.33% that matures in January
2012, and one totaling $100 million with an interest rate of 1.53% that
matures in January 2005. The loans are secured by a lien 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 and there was no prepayment fee.
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.
Page 32
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.
On October 20, 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, will be discharged on November 22, 2004, by the proceeds from the
replacement indebtedness, KU Pollution Control Bonds, Series 17, due
October 1, 2034, which will carry a variable, auction rate of interest.
LG&E maintainsrenewed five bilateralrevolving lines of credit with banks
totaling $185 million that mature in 2005.million. There was no outstanding balance under any of these
facilities at September 30, 2004. Management2005. The Company expects to renew these
facilities as they expire.prior to their expiration in June 2006.
LG&E, KU and KULG&E Energy participate in an intercompany money pool
agreement wherein
LG&E Energy and KU make funds available to LG&E at market-based rates
(based on an index of highly rated commercial paper issues asagreement. Details of the prior
month end) up to $400 million. Likewise, LG&E Energy and LG&E make funds
available to KU at market-based rates up to $400 million. LG&E had $40.7
million in money pool loans from LG&E Energy (included in "Notes payable to
affiliated companies") at an average rate of 1.60%balances at September 30, 2004,2005 and $75.1 million at an average rate of 1.06% at September 30, 2003. The
balance of the money pool loans from LG&E Energy to KU (included in "Notes
payable to affiliated companies") was $29.8 million at an average rate of
1.60% and $98.7 million at an average rate of 1.06% at September 30,
2004 and 2003, respectively. The amount available towere as follows:
Total Money Amount Balance Average
($ in millions) Pool Available Outstanding Available Interest Rate
September 30, 2005:
LG&E under the money pool
agreement at$400.0 $56.6 $343.4 3.64%
KU $400.0 $31.8 $368.2 3.64%
September 30, 2004, was2004:
LG&E $400.0 $40.7 $359.3 million. The amount available
to1.60%
KU under the money pool agreement at September 30, 2004, was$400.0 $29.8 $370.2 million.1.60%
LG&E Energy maintains a revolving credit facility totaling $150$200 million
with an affiliateaffiliated company, E.ON North America, Inc., to ensure funding
availability for the money pool. LG&E Energy had anThe balance outstanding balance of $79.1 million at an
average rate of 2.13% underon this facility
as ofat September 30, 20042005 was $65.4 million.
Redemptions and availabilitymaturities of $70.9 million remained.
As oflong-term debt year-to-date through September
30, 2004,2005, are summarized below:
($ in millions)
Principal Secured/
Year Company Description Amount Rate Unsecured Maturity
2005 LG&E had 225,000 sharesPollution control bonds 40.0 5.90% Secured Apr 2023
2005 LG&E Due to Fidelia $50.0 1.53% Secured Jan 2005
2005 LG&E Mand. Red. Pref. Stock $1.3 5.875% Unsecured Jul 2005
2005 KU First mortgage bonds $50.0 7.55% Secured Jun 2025
Issuances of $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 $100 per share. Beginning with the three months endedlong-term debt year-to-date through September 30, 2003,2005, are
summarized below:
($ in millions)
Principal Secured/
Year Company Description Amount Rate Unsecured Maturity
2005 LG&E reclassified its $5.875 series preferred stock as
long-term debt withPollution control bonds $40.0 Variable Secured Feb 2035
2005 KU Pollution control bonds $13.3 Variable Secured Jun 2035
2005 KU Due to Fidelia $50.0 4.735% Unsecured Jul 2015
In May 2005, KU repaid a $26.7 million loan against the minimum shares mandatorily redeemable within one
year classified as current. Dividends accrued are charged as interest
expense, pursuant to SFAS No. 150. On July 15, 2004, LG&E redeemed 12,500
shares as required at a pricecash surrender
value of $100 per share.life insurance policies.
In January 2004, LG&E and KU made discretionary contributions to their
pension plans of $34.5 million and $43.4 million, respectively. No
contributions are required for 2004 and no further discretionary contributions to the pension plans are planned in 2004.currently anticipated
for either LG&E's security&E or KU for 2005. LG&E and KU contributed $0.7 million and
$3.0 million, respectively, to their other post-retirement benefit plans
during the second quarter of 2005.
Security ratings as of September 30, 2004,2005, were:
LG&E KU
Moody's S&P Moody's S&P
First mortgage bonds A1 A- A1 A
Preferred stock Baa1 BBB- Baa1 BBB-
Commercial paper P-1 A-2
KU's security ratings as of September 30, 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.
Page 33
LG&E's capitalizationCapitalization ratios at September 30, 2004,2005, and December 31, 2003,2004, follow:
SeptemberLG&E KU
Sept. 30,December Dec. 31, Sept. 30, Dec. 31,
2005 2004 20032005 2004
Long-term debt
(including current portion) 30.8% 31.9%30.3% 30.5% 19.4% 22.2%
Long-term debt to
affiliated company (including
current portion) 14.2 10.711.5 14.1 21.2 18.8
Notes payable to affiliated
companies 2.1 4.32.9 3.0 1.7 2.0
Preferred stock 3.6 3.83.6 2.2 2.2
Common equity 49.3 49.351.7 48.8 55.5 54.8
Total 100.0% 100.0%
KU's capitalization ratios at September 30, 2004, and December 31, 2003,
follow:
September 30,December 31,
2004 2003
Long-term debt (including current portion) 22.4% 24.1%
Long-term debt to affiliated company
(including current portion) 19.0 16.8
Notes payable to affiliated companies 1.7 2.6
Preferred stock 2.3 2.4
Common equity 54.6 54.1
Total 100.0% 100.0%
New Accounting Pronouncements
FIN 46
In January 2003, the Financial Accounting Standards Board ("FASB") issued
Financial Accounting Standards Board Interpretation No. 46, ConsolidationFor a discussion of Variable Interest Entities, an Interpretation of ARB No. 51 ("FIN 46").
FIN 46 required 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.
In December 2003, FIN 46 was revised, delaying the effective dates for
certain entities created before February 1, 2003,accounting pronouncements 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") is now required to be applied no later than the end of the
first fiscal year or interim reporting period ending after March 15, 2004.
For all special purpose entities created prior to February 1, 2003, FIN 46R
is now required to be applied 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.
Boththeir impacts on LG&E
and KU, hold investment interests in OVEC and KU holds an
investment interest in EEI. Neither LG&E nor KU is the primary beneficiary
of OVEC or EEI, and thus neither is consolidated into the financial
statements of LG&E or KU.
Page 34
LG&E, KU and ten 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 and KU's share is 2.5%, representing
approximately 55 Mw of generation capacity.
LG&E's and KU's original investments in OVEC were made in 1952. LG&E's
investment in OVEC is the equivalent of 4.9% of OVEC's common stock and
KU's investment is the equivalent of 2.5% of OVEC's common stock. LG&E's
and KU's investments in OVEC are accounted for on the cost method of
accounting. As of September 30, 2004, LG&E's and KU's investments in OVEC
totaled $0.5 million and $0.3 million, respectively. LG&E's and KU's
maximum exposure to loss as a result of their involvement with OVEC is
limited to the value of their investment. In the event of the inability of
OVEC to fulfill its power provision requirements, LG&E and KU would
substitute such power supply with either owned generation or market
purchases and would generally recover associated incremental costs through
regulatory rate mechanisms. Seesee Part II,I - Item 1, for further discussion of
developments regarding LG&E's and KU's OVEC 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 entitledNotes to take 20% of the
available capacity of the station. Purchases from EEI are made under a
contractual formula which has resulted in costs which were and are expected
to be comparable to the cost of other power purchased or generated by KU.
Such power equated to approximately 9% of KU's net generation system output
in 2003.
KU's original investment in EEI was made in 1953. KU's investment in EEI
is accounted for on the equity method of accounting. As of September 30,
2004, KU's investment in EEI totaled $12.7 million. KU's maximum exposure
to loss as a result of its involvement with EEI is 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 rate mechanisms.
FSP 106-2
In May 2004, the FASB finalized FASB Staff Position ("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 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 the Companies.Financial Statements, Note 7.
Contingencies
For a description of significant contingencies that may affect LG&E and KU,
reference is made to Part I, Item 3, Legal Proceedings in LG&E's and KU's
Annual Reports on Form 10-K for the year ended December 31, 2003;2004; and to
Part I - Item 1, Notes to Financial Statements, Notes 5 and 10, and Part II
- - Item 1, Legal Proceedings in LG&E's and KU's Quarterly Reports on Form
10-Q for the quarters ended March 31, 2004 and June 30, 2004; and to Part
II, Item 1, Legal Proceedings herein.
Page 35
Electric and Gas Rates Cases
On June 30, 2004, the Kentucky Commission issued an order approving
increases in the base electric and gas rates of LG&E and the base electric
rates of KU. Subsequently, the AG commenced an investigation examining
communications between the Kentucky Commission and the Companies and
separately filed for a rehearing of the rate cases on such issue and
certain calculation components of the increased rates and filed for the
existing rate increases to be set aside. The Kentucky Commission is
considering the matters relating to the AG's actions. For a description of
developments in these cases, see Note 11 of the Notes to Consolidated
Financial Statements in Part 1, Item 1 of this Quarterly Report on Form 10-
Q.
Earnings Sharing Mechanism
The Companies filed their final 2003 ESM calculations with the Kentucky
Commission on March 1, 2004, and applied for recovery of $13.0 million
related to LG&E and $16.2 million related to KU. Based upon estimates, the
Companies previously accrued $8.9 million at LG&E and $9.3 million at KU
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 the Companies and all intervenors
regarding the ESM mechanisms of LG&E and KU. Under the ESM settlements,
LG&E and KU will continue to collect approximately $13.0 million and $16.2
million, respectively, 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, the Companies accrued an additional $4.1
million at LG&E and $6.9 million at KU in June 2004, related to 2003 ESM
revenue.
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.
LG&E's estimated future minimum annual demand payments under the Amended
and Restated Inter-Company Agreement are as follows:
(in thousands)
2006 $ 10,098
2007 9,726
2008 9,932
2009 10,144
2010 10,361
Thereafter 170,646
Total $220,907
In addition, LG&E will purchase from American Electric Power Company Inc.
("AEP") an additional 0.73% interest in OVEC for a purchase price of
approximately $104,000, resulting in an increase in LG&E ownership in OVEC
from 4.9% to 5.63%. The share purchase transaction is anticipated to be
completed during 2005, subject to receipt of certain regulatory approvals.
The changes to the power agreement and the share purchases are expected to
have no impact on the accounting for OVEC under FIN 46R as described in
Footnote 8.
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.
Page 36
Environmental Matters
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 EPA June 24, 2003, required 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 and KU
units. As a result of appeals to both rules, the compliance date was
extended to May 2004.
LG&E and KU have complied with these NOx emissions reduction rules by
installing additional NOx controls to their generating units. Installations
of additional NOx controls were performed on a phased basis, which
commenced in late 2000 and continued through the final compliance date. As
of September 30, 2004, LG&E has incurred total capital costs of
approximately $185 million to reduce its NOx emissions to the 0.15
lb./Mmbtu level on a company-wide basis. As of September 30, 2004, KU has
incurred total capital costs of approximately $203 million to reduce its
NOx emissions to the 0.15 lb./Mmbtu level on a company-wide basis. In
addition, LG&E and KU have begun incurring additional operation and
maintenance costs in operating new NOx controls. LG&E and KU believe their
costs in this regard to be comparable to those of similarly situated
utilities with like generation assets. In April 2001, the Kentucky
Commission granted recovery of these costs under the environmental
surcharge mechanism for LG&E and KU.
During August 2004, KU, the EPA, and the Department of Justice agreed in
principle to settle outstanding matters concerning a 1999 oil discharge at
KU's E.W. Brown plant for approximately $0.6 million, a portion of which
may be satisfied by KU's construction of a separate environmental capital
project. The settlement is subject to completion of final definitive
documents. In December 2003, KU recorded an accrual and expense to
operations of $0.6 million.
LG&E and KU are also monitoring several other air quality issues which may
potentially impact coal-fired power plants, including the EPA's revised air
quality standards for ozone and particulate matter, measures to implement
the EPA's regional haze rule, and the EPA's December 2003 proposals to
regulate mercury emissions from steam electric generating units and to
further reduce emissions of sulfur dioxide and nitrogen oxides under the
Clean Air Interstate Rule. In addition, LG&E is currently reviewing and
making comments on proposed regulations concerning toxic air emissions
within Metro Louisville, where the company operates two coal-fired
generating stations. LG&E is also working with local regulatory
authorities to review the effectiveness of remedial measures aimed at
controlling particulate matter emissions from its Mill Creek Station. LG&E
previously settled a number of property damage claims from adjacent
residents and completed significant remedial measures as part of its
ongoing capital construction program. LG&E has converted the Mill Creek
Station to a wet stack operation in an effort to resolve all outstanding
issues related to particulate matter emissions.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
LG&E&E's and KU, and their respective ratepayers,KU's operations are exposed to market risks.
Market risk exposures includerisks from changes in
interest rates and commodity prices. To mitigate changes in cash flows
attributable to these exposures, the Companies have entered into various
derivative instruments. Derivative positions are monitored using techniques
that include market value and sensitivity analysis.
Page 37Interest Rate Risk
The Companies use interest rate swaps to hedge exposure to market
fluctuations in certain of their debt instruments. Pursuant to the
Companies' policies, use of these financial instruments is intended to
mitigate risk and earnings volatility and is not speculative in nature.
Management has designated all of the Companies' interest rate swaps as
hedge instruments. Financial instruments designated as cash flow hedges
have resulting gains and losses recorded within other comprehensive income
and stockholders' equity. To the extent a financial instrument or the
underlying item being hedged is prematurely terminated or the hedge becomes
ineffective, the resulting gains or losses are reclassified from other
comprehensive income to net income. Financial instruments designated as
fair value hedges are periodically marked to market with the resulting
gains and losses recorded directly into net income to correspond with
income or expense recognized from changes in market value of the items
being hedged.
The potential change in interest expense associated with a 1% change in
base interest rates of LG&E's and KU's unswapped variable debt is estimated
at $3.5$4.2 million and $3.3$3.4 million, respectively, at September 30, 2004.2005.
LG&E's
exposure to floating interest rates decreased $1.0 million and KU's exposure to floating interest rates decreased $1.2 milliondid not materially
change during the first nine months of 2004.2005.
The potential loss in fair value of LG&E's interest rate swaps resulting
from a hypothetical 1% change in base interest rates is estimated at
approximately $25.8$18.0 million as of September 30, 2004.2005. The potential loss in
fair value of KU's interest rate swaps resulting from a hypothetical 1%
change in base interest rates is estimated at approximately $2.4$0.8 million as
of September 30, 2004.2005. These estimates are derived from third-party
valuations. Changes in the market values of these swaps, if held to
maturity, will have no effect on LG&E's or KU's net income or cash flow.
Pension Risk
LG&E's and KU's costs of providing defined-benefit pension retirement plans
is dependent upon a number of factors, such as the rates of return on plan
assets, discount rate, and contributions made to the plan. At September
30, 2004, LG&E and KU have
arecognized an additional minimum pension liability as prescribed by SFAS No. 87,
Employers' Accounting for Pensions inbecause the pre-tax amountsaccumulated benefit
obligation exceeds the fair value of $47.6 and $9.9 million, respectively.their plans' assets. The liabilities
arewere recorded as a reduction to other comprehensive income, and dodid not
affect net income. The amount of the liabilitiesliability depends upon the discount
rate, the asset returns experienced in
2003 and contributions made by LG&E and KUthe Companies to the
plan during 2003.plans. If the fair value of the planplans' assets exceeds the accumulated
benefit obligation, the recorded liabilityliabilities will be reduced and other
comprehensive income will be restored in the Consolidated Balance Sheets.balance sheet.
A 1% increase or decrease in the assumed discount rate could have an
approximate $41$39.9 million positive or negative impact to the accumulated
benefit obligation of LG&E. A 1% increase or decrease in the assumed
discount rate could have an approximate $27$26.8 million positive or negative
impact to the accumulated benefit obligation of KU.
In January 2004, LG&E and KU made discretionary contributions to their
pension plans of $34.5 million and $43.4 million, respectively. Page 38No
discretionary contributions to the pension plans are currently anticipated
for either LG&E or KU for 2005. LG&E and KU contributed $0.7 million and
$3.0 million, respectively, to their other post-retirement benefit plans
during the second quarter of 2005.
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
Accounting for Derivative Instruments and Hedging Activities and SFAS No.
138 Accounting for Certain Derivative Instruments and Certain Hedging
Activities. Wholesale sales of excess asset capacity are treated as normal
sales under SFAS No. 133 and SFAS No. 138 and are not marked to market.
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 contracts marked to market under EITF No. 98-10 are also
within the scope of SFAS No. 133.
Since the inception of the MISO Day 2 market in April 2005, LG&E and KU
have been eligible to receive Financial Transmission Rights (FTRs) from
MISO. FTRs are assigned by MISO to market participants for a 12 month
period of time beginning June 1, 2006 for off-peak and peak periods based
on each market participant's share of generation. FTRs entitle the holder
to manage price risk associated with hourly market price fluctuations
caused by transmission congestion. The value of FTRs is determined by the
transmission congestion charges that arise when the transmission grid is
congested in the day-ahead market. Holders of FTRs use them to cover
charges assessed for congestion in the hourly market, while market
participants without FTRs must pay congestion costs in order to obtain less
expensive power through the transmission system. FTRs are obtained through
an allocation from MISO, however, they can also be bought and sold.
Although FTRs are financial instruments they are not marked to market under
SFAS No. 133 due to the lack of liquidity in the forward market.
The table below summarizes LG&E's and KU's energy trading and risk management
activities for the three months and nine months ended September 30, 2004,2005,
and 2003 (in thousands of $). Trading volumes2004. Volumes are allocated evenly divided between LG&E and KU.
Three Months Nine Months
Ended Ended
September 30, September 30,
2005 2004 20032005 2004
2003(in millions)
Fair value of contracts at beginning of
period, net asset/(liability) $ 541- $ 318 $572 $(156)0.5 $(0.2) $ 0.6
Fair value of contracts when entered
into during the period (70) (30) (75) 2,5900.2 (0.1) 0.2 (0.1)
Contracts realized or otherwise
settled during the period (431) (356) (663) (639)- (0.4) 0.2 (0.7)
Changes in fair value due to
changes in assumptions 107 148 313 (1,715)- 0.1 - 0.3
Fair value of contracts at end
of period,net asset $ 1470.2 $ 800.1 $ 1470.2 $ 800.1
No changes to valuation techniques for energy trading and risk management activities
occurred during 2005 or 2004. Changes in market pricing, interest rate and
volatility assumptions were made during bothall periods. The outstanding mark-
to-market value is sensitive to changes in prices, price volatilities, and
interest rates. The Companies estimate that a movement in prices of $1 and
a change in interest and volatilities of 1% would result in a change in the
mark-to-market value of less than $0.1 million. All contracts outstanding
at September 30, 2004,2005, have a maturity of less than one year and are valued
using prices actively quoted for proposed or executed transactions or
quoted by brokers.
LG&E and KU maintain policies intended to minimize credit risk and revalue
credit exposures daily to monitor compliance with those policies. As of
September 30, 2004,2005, 100% of the trading and risk management commitmentstransactions marked-to-market according to
SFAS No. 133 were with counterparties rated BBB-/Baa3 equivalent or better.
Item 4. Controls and Procedures.
LG&E and KU maintain a system of disclosure controls and procedures
designed to ensure that information required to be disclosed by the
Companies in reports they file or submit under the Securities Exchange Act
of 1934 is recorded, processed, summarized and reported, within the time
periods specified in the Securities and Exchange Commission rules and
forms. LG&E and KU conducted an evaluation of such controls and procedures
under the supervision and with the participation of the Companies'
management, including the Chairman, President and Chief Executive Officer
("CEO")(CEO) and the Chief Financial Officer ("CFO")(CFO). Based upon that evaluation,
the CEO and CFO have concluded that the Companies' disclosure controls and
procedures are effective as of the end of the period covered by this
report.
LG&E and KU are not accelerated filers under the Sarbanes-Oxley Act of 2002
and associated rules (the Act) and consequently anticipate issuing
Management's Report on Internal Control over Financial Reporting pursuant
to Section 404 of the Act in their first periodic report covering the
fiscal year ended December 31, 2007, as permitted by SEC rulemaking.
In preparation for required reporting under Section 404 of the Sarbanes-
Oxley Act of 2002, the Companies are conducting a thorough review of their
internal controls over financial reporting, including disclosure controls
and procedures. Based on this review, the Companies have made internal
controls enhancements and will continue to make future enhancements to
their internal controls over financial reporting. There hasOn April 1, 2005, the
MISO Day 2, a day-ahead and real-time energy market, became effective which
impacted the Companies' regulated electric generation operations and
purchased power. In connection with the implementation of MISO Day 2, LG&E
and KU have implemented a new software system and modified existing
processes to facilitate participation in, and validate resultant
settlements from the MISO market. Apart from this change, there have been
no changeother changes in the Companies' internal controlscontrol over financial
reporting that occurred during the fiscal quarter ended September 30, 2004,2005,
that hashave materially affected, or isare reasonably likely to materially
affect, the Companies' internal controlscontrol over financial reporting.
Page 39
Part II. Other Information
Item 1. Legal Proceedings.
For a description of the significant legal proceedings involving LG&E and
KU, reference is made to the information under the following items and
captions of (a) LG&E's and KU's respective combined Annual Report on Form 10-K
for the year ended December 31, 2003:2004: Item 1, Business; Item 3, Legal
Proceedings; Item 7, Management's Discussion and Analysis of Financial
Condition and Results of Operations,Operations; and Item 8, Financial Statements and
Supplementary Data in Note 11. Reference is also made to the matters
described in Notes 5 and (b)10 of Part I, Item 1 of LG&E's and KU's Quarterly
ReportsReport on Form 10-Q for the periodsthree months ended March 31, 2004 and2005, June 30,
2004: Item I, Legal
Proceedings.2005, and this 10-Q, respectively. Except as described herein, to-date,to date, the
proceedings reported in LG&E's and KU's respective combined Annual Report
on Form 10-K or
Quarterly Reports on Form 10-Q have not changed materially.
Electricmaterially changed.
Other
In the normal course of business, other lawsuits, claims, environmental
actions, and Gas Rates Cases
On June 30, 2004, the Kentucky Commission issued an order approving
increases in the base electric and gas rates ofother governmental proceedings arise against LG&E and KU. To
the base electric
ratesextent that damages are assessed in any of KU. Subsequently, the AG commenced an investigation examining
communications between the Kentucky Commission and the Companies and
separately filed for a rehearing of the rate cases on such issue and
certain calculation components of the increased rates and filed for the
existing rate increases to be set aside. The Kentucky Commission is
considering the matters relating to the AG's actions. For a description of
developments in these cases, see Note 11 of the Notes to Consolidated
Financial Statements in Part 1, Item 1 of this Quarterly Report on Form 10-
Q.
MISO
During 2004 to-date, the Kentucky Commission has continued its proceedings
examining the costs and benefits of MISO membership, including reopening
the matter for further testimony and hearings on recently-filed MISO energy
market tariffs and analysis of potential membership in other Regional
Transmission Organizations. Proceedings in this matter are anticipated to
continue into 2005. In September 2004, in response to requests of the
Kentucky Commission, the Companies filed pleadings indicating that MISO
membership will not provide benefits commensurate with its costs to the
Companies and to Kentucky ratepayers. The Companies requested an order of
the Kentucky Commission directing their ultimate exit from MISO, if
approved by the FERC and under other appropriate conditions.
OVEC Power Agreement and Share Purchase
On April 30, 2004, OVEC and its shareholders, includinglawsuits, LG&E and KU
entered into an Amendedbelieve 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 Restated Inter-Company Power Agreement, to be
effective beginning March 2006, upon the expirationclaims
will have a material adverse effect on LG&E's or KU's financial position or
results 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 will purchase from American Electric Power Company Inc.
("AEP") an additional 0.73% interest in OVEC for a purchase price of
approximately $104,000, resulting in an increase in LG&E ownership in OVEC
from 4.9% to 5.63%. The share purchase transaction is anticipated to be
completed during 2005, subject to receipt of certain regulatory approvals.
Page 40
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,operations, 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.
Environmental Matter
During August 2004, KU and the EPA and Department of Justice agreed in
principle to settle outstanding matters concerning a 1999 oil discharge at
KU's E.W. Brown plant for approximately $628,750, a portion of which may be
satisfied by KU's construction of a separate environmental capital project.
The settlement is subject to completion of final definitive documents.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.Proceeds
2(c)
LG&E has an existing $5.875 series of 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 a minimum of 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,
2004,2005, leaving 225,500212,500 shares currently outstanding. Beginning with the
three months ended September 30, 2003, LG&E reclassified, at fair value,
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, pursuant to SFAS No. 150.
July 2005 August 2005 September Period 2004 2004 20042005
Total number of shares (or units) 12,500 n/a n/a
purchasedshares (or units) ($5.875 Pref.)
purchased
Average price $100 n/a n/a
paid per share
(or unit)$100
Total number of 12,500 n/a n/a
Total number of shares (or units) ($5.875 Pref.)
purchased as part
of publicly
12,500
announced plans
or programs
($5.875 Pref.)Maximum number 212,500 n/a n/a
Maximum number (or approximate ($5.875 Pref.)
dollar value) of
shares (or units)
that may yet be
purchased 225,000
under
the plans or
programs ($5.875 Pref.) n/a n/a
Item 4. Submission of Matters to a Vote of Security Holders.
a)LG&E's and KU's Annual Meetings of Shareholders were held on July 8,
2004.
b)Not applicable.
Page 41
c)The matters voted upon and the results of the voting at the Annual
Meetings are set forth below:
1. LG&E
i)The shareholders voted to elect LG&E's nominees for election to the
Board of Directors, as follows:
Victor A. Staffieri - 21,294,223 common shares and 88,855
preferred shares cast in favor of election and 5,725 preferred
shares withheld.
S. Bradford Rives - 21,294,223 common shares and 89,005 preferred
shares cast in favor of election and 5,575 preferred shares
withheld.
John R. McCall - 21,294,223 common shares and 89,191 preferred
shares cast in favor of election and 5,389 preferred shares
withheld.
No holders of common or preferred shares abstained from voting on
this matter.
ii)The shareholders voted 21,294,223 common shares and 91,600
preferred shares in favor of and 991 preferred shares against the
approval of PricewaterhouseCoopers LLP as independent accountants
for 2004. Holders of 1,989 preferred shares abstained from voting
on this matter.
2. KU
i)The sole shareholder voted to elect KU's nominees for election to
the Board of Directors, as follows:
37,817,878 common shares cast in favor of election and no shares
withheld for each of Victor A. Staffieri, S. Bradford Rives and
John R. McCall, respectively.
ii)The sole shareholder voted 37,817,878 common shares in favor of and
no shares withheld for approval of PricewaterhouseCoopers LLP as
independent accountants for 2004.
No holders of common shares abstained from voting on these matters.
d) Not applicable.
Item 6. Exhibits.
Applicable to Form
10-Q of
Exhibit
No. LG&E KU Description
31 X X CertificationsCertification - Section 302 of Sarbanes-Oxley Act of 2002
31.1 X Certification of Chairman of the Board, President and Chief
Executive Officer, pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002
31.2 X Certification of Chief Financial Officer, pursuant to
Section 302 of
the Sarbanes-Oxley Act of 2002
31.3 X Certification of Chairman of the Board, President and Chief
Executive Officer, pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002
31.4 X Certification of Chief Financial Officer, pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
32 X X Certification pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002
Certain instruments defining the rights of holders of certain long-term
debt of LG&E andor KU have not been filed with the SEC but will be furnished
to the SEC upon request.
Page 42
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Louisville Gas and Electric Company
Registrant
Date: November 12, 200414, 2005 /s/ S. Bradford Rives
S. Bradford Rives
Chief Financial Officer
(On behalf of the registrant in his
capacities as Principal Financial Officer
and Principal
Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Kentucky Utilities Company
Registrant
Date: November 12, 200414, 2005 /s/ S. Bradford Rives
S. Bradford Rives
Chief Financial Officer
(On behalf of the registrant in his
capacities as Principal Financial Officer
and Principal
Accounting Officer)
_______________________________