UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.D. C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended SeptemberJune 30, 2005
Or
[_]2006
OR
[ ] TRANSITION REPORT PURSUANT 1TOTO SECTION 13 OR 15 (d)15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
Commission Registrant, State of Incorporation, IRS Employer
File Number Address, and Telephone Number Identification No.Number
1-2893 Louisville Gas and Electric Company 61-0264150
(A Kentucky Corporation)
220 West Main Street
P.O.P. O. Box 32010
Louisville, KYKentucky 40232
(502) 627-2000
1-3464 Kentucky Utilities Company 61-0247570
(A Kentucky and Virginia Corporation)
One Quality Street
Lexington, KYKentucky 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 No _
Indicate by check mark whether the registrant is a large accelerated filer,
an accelerated filer, (as
definedor a non-accelerated filer. See definition of
"accelerated filer and large accelerated filer" in Rule 12-b2 of the
Exchange Act Rule 12b-2). Yes No XAct. (Check one):
Large accelerated filer _____ Accelerated filer_____
Non-accelerated filer __X___
Indicate by check mark whether the registrant is a shell company (as
defined in Rule 12b-2 of the Exchange Act Rule 12b-2)Act). 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 OctoberJuly 31, 2005,2006, all held by LG&E EnergyE.ON U.S. LLC
Kentucky Utilities Company - 37,817,878 shares, without par value, as of
OctoberJuly 31, 2005,2006, all held by LG&E EnergyE.ON U.S. LLC
This combined Form 10-Q 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.
INDEX OF ABBREVIATIONS
AG Attorney General of Kentucky
ARO Asset Retirement Obligation
CAIR Clean Air Interstate Rule
CAMR Clean Air Mercury Rule
CCN Certificate of Public Convenience and Necessity
Company LG&E or KU, as applicable
Companies LG&E and KU
DSM Demand Side Management
ECR Environmental Cost Recovery
EEI Electric Energy, Inc.
EITF Emerging Issues Task Force
E.ON E.ON AG
E.ON U.S. E.ON U.S. LLC (formerly LG&E Energy LLC and LG&E
Energy Corp.)
E.ON U.S. Services E.ON U.S. Services Inc. (formerly LG&E Energy
Services Inc.)
EPA U.S. Environmental Protection Agency
EPAct 2005 Energy Policy Act of 2005
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 RightRights
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
NOXNOx Nitrogen Oxide
OMU Owensboro Municipal Utilities
PJM PJM Interconnection, LLC
Powergen Powergen Limited (formerly Powergen plc)
PUHCA 1935 Public Utility Holding Company Act of 1935
RSGMWP Revenue Sufficiency Guarantee Make Whole Payment
RTO Regional Transmission OperatorPUHCA 2005 Public Utility Holding Company Act of 2005
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
TEMT Transmission and Energy Markets Tariff
VDT Value Delivery Team Process
Virginia Commission Virginia State Corporation Commission
TABLE OF CONTENTS
PART I
ITEMItem 1. FINANCIAL STATEMENTS (UNAUDITED)
LOUISVILLE GAS AND ELECTRIC COMPANY
STATEMENTS OF INCOMEFinancial Statements (Unaudited)
Louisville Gas and Electric Company
Statements of Income 1
STATEMENTS OF RETAINED EARNINGSStatements of Retained Earnings 1
BALANCE SHEETSBalance Sheets 2
STATEMENTS OF CASH FLOWSStatements of Cash Flows 4
STATEMENTS OF OTHER COMPREHENSIVE INCOMEStatements of Comprehensive Income 5
KENTUCKY UTILITIES COMPANY
STATEMENTS OF INCOMEKentucky Utilities Company
Statements of Income 6
STATEMENTS OF RETAINED EARNINGSStatements of Retained Earnings 6
BALANCE SHEETSBalance Sheets 7
STATEMENTS OF CASH FLOWSStatements of Cash Flows 9
STATEMENTS OF OTHER COMPREHENSIVE INCOMEStatements of Comprehensive Income 10
NOTES TO FINANCIAL STATEMENTSNotes to Financial Statements 11
ITEMItem 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS. 25
ITEMManagement's Discussion and Analysis of Financial
Condition and Results of Operations 26
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. 40
ITEMQuantitative and Qualitative Disclosures About Market Risk 36
Item 4. CONTROLS AND PROCEDURES. 42Controls and Procedures 38
PART II
ITEMItem 1. LEGAL PROCEEDINGS. 43
ITEMLegal Proceedings 39
Item 1A.Risk Factors 39
Item 5. Other Information 39
Item 6. EXHIBITS 44
SIGNATURES 45
EXHIBITS 46Exhibits 39
Signatures 41
Exhibits 42
Part I. Financial Information - Item 1. Financial Statements (Unaudited)
Louisville Gas and Electric Company
Statements of Income (Unaudited)
(Millions of $)
Three Months NineSix Months
Ended June 30, Ended SeptemberJune 30,
September 30,2006 2005 20042006 2005 2004
OPERATING REVENUES:
Electric $284.0 $227.0 $741.2 $617.8$223 $228 $435 $457
Gas 34.6 34.8 259.8 242.254 53 254 225
Total operating revenues 318.6 261.8 1,001.0 860.0277 281 689 682
OPERATING EXPENSES:
Fuel for electric generation 79.4 53.8 207.8 154.570 68 135 129
Power purchased 34.1 19.3 101.3 65.626 28 54 67
Gas supply expenses 20.2 20.2 191.5 181.938 36 200 171
Other operation and maintenance expenses 87.9 75.4 227.3 227.065 65 143 139
Depreciation and amortization 31.1 30.3 93.0 86.031 31 61 62
Total operating expenses 252.7 199.0 820.9 715.0
NET230 228 593 568
OPERATING INCOME 65.9 62.8 180.1 145.047 53 96 114
Other expense (income) - net 1 - 1.9 (0.1) 2.81 -
Interest expense (Note 3) 5.6 5.1 17.4 15.16 6 13 12
Interest expense to affiliated
companies (Note 9) 3.0 3.0 9.0 9.18) 3 3 7 6
INCOME BEFORE INCOME TAXES 57.3 52.8 153.8 118.037 44 75 96
Federal and state income taxes (Note 6) 15.3 20.3 50.0 44.112 16 25 34
NET INCOME $ 42.0 $ 32.5 $103.8 $ 73.9$25 $28 $50 $62
The accompanying notes are an integral part of these financial statements.
Statements of Retained Earnings (Unaudited)
(Millions of $)
Three Months NineSix Months
Ended June 30, Ended SeptemberJune 30,
September 30,2006 2005 20042006 2005 2004
Balance at beginning of period $555.4 $516.9 $534.0 $497.4$605 $538 $621 $534
Net income 42.0 32.5 103.8 73.925 28 50 62
Subtotal 597.4 549.4 637.8 571.3630 566 671 596
Cash dividends declared on stock:
5% cumulativeCumulative preferred 0.3 0.3 0.8 0.8
Auction rate cumulative preferred 0.4 0.2 1.3 0.61 1 2 2
Common - 21.0 39.0 42.020 10 60 39
Subtotal 0.7 21.5 41.1 43.421 11 62 41
Balance at end of period $596.7 $527.9 $596.7 $527.9$609 $555 $609 $555
The accompanying notes are an integral part of these financial statements.
Louisville Gas and Electric Company
Balance Sheets
(Unaudited)
(Millions of $)
ASSETS SeptemberJune 30, December 31,
2006 2005
2004
CURRENT ASSETS:Current Assets:
Cash and cash equivalents $ 5.85 $ 6.87
Accounts receivable - less reservereserves of $1.2 million and $0.8$1
million as of September 30, 2005June 30,2006
and December 31, 2004,
respectively 131.3 167.02005 123 231
Accounts receivable from affiliated
companies (Note 8) 19 36
Materials and supplies - at average cost:supplies:
Fuel (predominantly coal) 29.0 21.853 39
Gas stored underground 106.8 77.530 125
Other 27.5 26.1materials and supplies 29 28
Prepayments and other 15.6 3.9current assets 4 6
Total current assets 316.0 303.1
OTHER PROPERTY AND INVESTMENTS263 472
Other property and investments - less reservereserves
of less than $0.1$1 million as of SeptemberJune 30, 20052006
and December 31, 2004 0.6 0.5
UTILITY PLANT:2005 1 1
Utility plant:
At original cost 4,010.8 3,915.84,077 4,049
Less: reserve for depreciation 1,485.8 1,396.31,523 1,509
Net utility plant 2,525.0 2,519.5
DEFERRED DEBITS AND OTHER ASSETS:2,554 2,540
Deferred debits and other assets:
Restricted cash 12.2 10.97 10
Unamortized debt expense 8.5 8.48 8
Regulatory assets (Note 5) 73.3 91.92) 78 84
Other 31.8 32.2assets 36 31
Total deferred debits and other assets 125.8 143.4129 133
Total assets $2,967.4 $2,966.5$2,947 $3,146
The accompanying notes are an integral part of these financial statements.
Louisville Gas and Electric Company
Balance Sheets (cont.)
(Unaudited)
(Millions of $)
CAPITALIZATIONLIABILITIES AND LIABILITIES
SeptemberEQUITY June 30, December 31,
2006 2005
2004
CURRENT LIABILITIES:Current liabilities:
Current portion of long-term debt (Note 8) 247.5 247.5
Current portion of long-term debt to
affiliated company (Note 8) - 50.0$248 $248
Notes payable to affiliated companies
(Note 5 and Note 8) 56.6 58.21 141
Accounts payable 107.5 106.180 141
Accounts payable to affiliated
companies (Note 9) 57.8 31.78) 47 52
Accrued income taxes - 6.29 6
Customer deposits 16.7 14.018 17
Other - 18.5current liabilities 26 15
Total current liabilities 486.1 532.2
DEFERRED CREDITS AND OTHER LIABILITIES:429 620
Long-term debt:
Long-term debt (Note 5) 328 328
Long-term debt to affiliated company
(Note 5 and Note 8) 225 225
Mandatorily redeemable preferred stock 20 20
Total long-term debt 573 573
Deferred credits and other liabilities:
Accumulated deferred income taxes - net 324.4 347.2312 322
Investment tax credit, in process of
amortization 43.1 46.240 42
Accumulated provision for pensions and
related benefits 123.2 120.6129 143
Customer advances for construction 9.6 10.610 10
Asset retirement obligation 10.7 10.327 27
Regulatory liabilities (Note 5)2):
Accumulated cost of removal of utility
plant 218.8 220.2
Deferred225 219
Regulatory liability deferred income taxes - net (Note 6) 52.7 37.244 42
Other 9.5 15.0regulatory liabilities 42 20
Other 32.2 29.4liabilities 23 31
Total deferred credits and other liabilities 824.2 836.7
CAPITALIZATION:852 856
Cumulative preferred stock 70 70
Common equity:
Common stock, without par value -
OutstandingAuthorized 75,000,000 shares,
outstanding 21,294,223 shares 425.2 425.2
Common stock expense (0.8) (0.8)424 424
Additional paid-in capital 40.0 40.040 40
Accumulated other comprehensive loss (47.5) (45.6)(50) (58)
Retained earnings 596.7 534.0609 621
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) 225.0 225.01,023 1,027
Total capitalization 1,657.1 1,597.6
Total capitalliabilities and liabilities $2,967.4 $2,966.5equity $2,947 $3,146
The accompanying notes are an integral part of these financial statements.
Louisville Gas and Electric Company
Statements of Cash Flows
(Unaudited)
(Millions of $)
NineSix Months Ended
SeptemberJune 30,
2006 2005 2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 103.8 $ 73.9$50 $62
Items not requiring cash currently:
Depreciation and amortization 93.0 86.0
Value delivery team amortization 22.6 22.661 62
Deferred income taxes - net (7.3) 6.8
Investment tax credit - net (3.1) (3.1)(13) (11)
VDT amortization 7 15
Other (1.0) 2.8(3) (3)
Changes in current assets and liabilities-net (8.4) (10.6)
Changeliabilities:
Accounts receivable 108 41
Accounts receivable from affiliated companies 17 (15)
Fuel (14) (6)
Gas stored underground 95 58
Other changes in accounts receivable securitizationcurrent assets 1 -
net - (58.0)Accounts payable (61) (39)
Accounts payable to affiliated companies (5) 29
Accrued income taxes 3 (6)
Other changes in current liabilities 12 (7)
Pension funding (Note 11)4) (18) - (34.5)
Provision for post-retirement benefits 2.6 (8.1)
Gas supply clause receivable, net (2.8) 12.0
Earnings sharing mechanism receivable 2.1 6.9
Litigation settlement - 7.031 2
Other (12.1) 15.5(8) (3)
Net cash provided by operating activities 189.4 119.2263 179
CASH FLOWS USED INFROM INVESTING ACTIVITIES:
Construction expenditures (66) (51)
Change in restricted cash (1.3) (11.5)
Construction expenditures (95.0) (94.2)
Other (0.1) 0.13 (2)
Net cash used for investing activities (96.4) (105.6)(63) (53)
CASH FLOWS FROM FINANCING ACTIVITIES:
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 8) - 125.0
Repayment of long-term borrowings from
affiliated company (Note 8) (50.0) (50.0)
Short-term borrowings from affiliated
company (Note 8) 480.5 399.5- (50)
Repayment of short-term borrowings from
affiliated company (482.1) (439.2)(Note 5) (140) (37)
Payment of dividends (41.1) (43.4)
Other 0.2 (1.3)(62) (41)
Net cash used for financing activities (94.0) (9.4)(202) (128)
CHANGE IN CASH AND CASH EQUIVALENTS (1.0) 4.2(2) (2)
CASH AND CASH EQUIVALENTS AT BEGINNING OF
PERIOD 6.8 1.77 7
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 5.8 $ 5.9
SUPPLEMENTAL DISCLOSURES:
Cash paid during the period for:
Income taxes $74.6 $42.4
Interest on borrowed money 15.8 12.7
Interest to affiliated companies on borrowed money 9.7 8.9$5 $5
The accompanying notes are an integral part of these financial statements.
Louisville Gas and Electric Company
Statements of Other Comprehensive Income
(Unaudited)
(Millions of $)
Three Months NineSix Months
Ended June 30, Ended SeptemberJune 30,
September 30,2006 2005 20042006 2005 2004
Net income $42.0 $32.5 $103.8 $73.9$25 $28 $50 $62
Income Taxes - Minimum Pension Liability - - (1.1) - (1)
Gain (loss) on derivative instruments
and hedging activities - net of tax
benefit /(expense)(expense) of $(3.1), $3.6, $0.9$(2) million,
$5 million, $(5) million and $1.2,$4
million, respectively (Note 3) 5.3 (5.4) (0.8) (1.8)
Other comprehensive4) 3 (8) 8 (6)
Comprehensive income (loss), net of tax 5.3 (5.4) (1.9) (1.8)3 (8) 8 (7)
Comprehensive income $47.3 $27.1 $101.9 $72.1$28 $20 $58 $55
The accompanying notes are an integral part of these financial statements.
Kentucky Utilities Company
Statements of Income
(Unaudited)
(Millions of $)
Three Months NineSix Months
Ended June 30, Ended SeptemberJune 30,
September 30,2006 2005 20042006 2005 2004
OPERATING REVENUES $347.2 $252.6 $898.7 $732.4$276 $265 $569 $552
OPERATING EXPENSES:
Fuel for electric generation 118.5 78.2 290.0 215.9100 84 195 172
Power purchased 64.8 33.2 161.1 105.144 50 90 96
Other operation and maintenance expenses 80.1 54.2 206.3 166.563 68 133 126
Depreciation and amortization 28.4 29.1 86.1 80.329 29 57 58
Total operating expenses 291.8 194.7 743.5 567.8
NET236 231 475 452
OPERATING INCOME 55.4 57.9 155.2 164.640 34 94 100
Other income(income) - net (1.1) (2.2) (3.3) (4.0)(5) (2) (13) (3)
Interest expense (Note 3) 3.1 3.2 10.1 7.64 4 7 7
Interest expense to affiliated
companies(companies (Note 5 and Note 9) 4.2 3.5 11.4 10.6
NET8) 5 4 11 7
INCOME BEFORE INCOME TAXES 49.2 53.4 137.0 150.436 28 89 89
Federal and state income taxes (Note 6) 17.5 18.6 50.0 55.611 10 29 34
NET INCOME $ 31.7 $ 34.8 $ 87.0 $ 94.8$25 $18 $60 $55
The accompanying notes are an integral part of these financial statements.
Statements of Retained Earnings
(Unaudited)
(Millions of $)
Three Months NineSix Months
Ended June 30, Ended SeptemberJune 30,
September 30,2006 2005 20042006 2005 2004
Balance at beginning of period $673.6 $629.1 $659.4 $591.2$753 $666 $718 $660
Net income 31.7 34.8 87.0 94.825 18 60 55
Subtotal 705.3 663.9 746.4 686.0778 684 778 715
Cash dividends declared on stock:
4.75% cumulativeCumulative preferred 0.3 0.3 0.7 0.7
6.53% cumulative preferred 0.4 0.3 1.1 1.0- - - 1
Common 10.0 21.0 50.0 42.0- 10 - 40
Subtotal 10.7 21.6 51.8 43.7- 10 - 41
Balance at end of period $694.6 $642.3 $694.6 $642.3$778 $674 $778 $674
The accompanying notes are an integral part of these financial statements.
Kentucky Utilities Company
Balance Sheets
(Unaudited)
(Millions of $)
ASSETS
SeptemberJune 30, December 31,
ASSETS 2006 2005
2004
CURRENT ASSETS:Current assets:
Cash and cash equivalents $ 4.2 $ 4.6$5 $7
Restricted cash 13.3 -10 22
Accounts receivable - less reservereserves of $0.6$2
million as of SeptemberJune 30, 20052006 and
December 31, 2004 119.6 112.62005 113 135
Accounts receivable from affiliated
companies (Note 8) 18 32
Materials and supplies - at average cost:supplies:
Fuel (predominantly coal) 50.3 52.275 55
Other 29.4 28.0materials and supplies 35 32
Prepayments and other 12.2 9.9current assets 9 5
Total current assets 229.0 207.3
OTHER PROPERTY AND INVESTMENTS265 288
Other property and investments -
less reservereserves of $0.1less than $1 million as
of September 30,
2005June 30,2006 and December 31, 2004 22.1 20.5
UTILITY PLANT:2005 22 23
Utility plant:
At original cost 3,788.4 3,712.13,944 3,847
Less: reserve for depreciation 1,486.7 1,415.01,532 1,508
Net utility plant 2,301.7 2,297.1
DEFERRED DEBITS AND OTHER ASSETS:2,412 2,339
Deferred debits and other assets:
Unamortized debt expense 4.6 4.75 5
Regulatory assets (Note 5) 70.6 61.4
Long-term derivative asset 1.5 6.12) 70 58
Cash surrender value of key man life insurance 32.0 3.634 32
Other 10.0 9.7assets 9 11
Total deferred debits and other assets 118.7 85.5118 106
Total assets $2,671.5 $2,610.4$2,817 $2,756
The accompanying notes are an integral part of these financial statements.
Kentucky Utilities Company
Balance Sheets (cont.)
(Unaudited)
(Millions of $)
CAPITALIZATION AND LIABILITIES
SeptemberJune 30, December 31,
LIABILITIES AND EQUITY 2006 2005
2004
CURRENT LIABILITIES:Current liabilities:
Current portion of long-term debt (Note 8) $ 123.1 $ 87.1
Current portion of long-term notes to
affiliated company (Note 8) 75.0 75.0$140 $123
Notes payable to affiliated companycompanies
(Note 5 and Note 8) 31.8 34.852 70
Accounts payable 67.5 77.981 89
Accounts payable to affiliated companies
(Note 9) 58.1 32.88) 60 53
Accrued income taxes - 5.913
Customer deposits 16.7 15.018 17
Other 0.4 15.4current liabilities 24 18
Total current liabilities 372.6 343.9
DEFERRED CREDITS AND OTHER LIABILITIES:375 383
Long-term debt:
Long-term debt (Note 5) 186 240
Long-term debt to affiliated company
(Note 5 and Note 8) 433 383
Total long-term debt 619 623
Deferred credits and other liabilities:
Accumulated deferred income taxes - net 278.0 282.6
Investment tax credit, in process of
amortization 2.5 3.8277 274
Accumulated provision for pensions and
related benefits 81.0 77.997 92
Asset retirement obligation 21.9 21.028 27
Regulatory liabilities (Note 5)2):
Accumulated cost of removal of utility plant 277.6 266.8
Deferred288 281
Regulatory liability deferred income taxes - net (Note 6) 29.9 19.322 23
Other 10.4 5.4regulatory liabilities 10 11
Other 18.3 17.0liabilities 19 20
Total deferred credits and other liabilities 719.6 693.8
CAPITALIZATION:741 728
Common equity:
Common stock, without par value -
OutstandingAuthorized 80,000,000 shares,
outstanding 37,817,878 shares 308.1 308.1
Common stock expense (0.3) (0.3)308 308
Additional paid-in capital 15.0 15.015 15
Accumulated other comprehensive loss (13.6) (13.3)(19) (19)
Retained earnings 680.9 647.3765 704
Undistributed subsidiary earnings 13.7 12.113 14
Total retained earnings 694.6 659.4778 718
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) 308.0 258.01,082 1,022
Total capitalization 1,579.3 1,572.7
Total capitalliabilities and liabilities $2,671.5 $2,610.4equity $2,817 $2,756
The accompanying notes are an integral part of these financial statements.
Kentucky Utilities Company
Statements of Cash Flows
(Unaudited)
(Millions of $)
NineSix Months Ended
SeptemberJune 30,
2006 2005 2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 87.0 $ 94.8$60 $55
Items not requiring cash currently:
Depreciation and amortization 86.1 80.3
Value delivery team57 58
Deferred income taxes 2 (4)
VDT amortization 8.8 8.8
Change in fair value of derivative instruments (5.5) (0.4)3 6
Other 8.4 8.26 (5)
Changes in current assets and liabilities:
Accounts receivable 22 26
Accounts receivable from affiliated companies 14 (21)
Fuel (20) (5)
Other changes in current assets (7) 3
Accounts payable (8) (20)
Accounts payable to affiliated companies 7 35
Accrued income taxes (13) (2)
Other changes in current liabilities (13.1) 3.2
Changes in accounts receivable securitization - net - (50.0)
Earnings sharing mechanism receivable 3.1 4.9
Pension funding (Note 11) - (43.4)
Provision for post-retirement benefits 3.1 (3.4)
Litigation settlement - 11.47 (12)
Fuel adjustment clause receivable, (18.4) (1.1)net (15) (13)
Other (2.0) 4.3(4) 2
Net cash provided by operating activities 157.5 117.6111 103
CASH FLOWS USED INFROM INVESTING ACTIVITIES:
Construction expenditures (121) (44)
Change in restricted cash (13.3)12 -
Construction expenditures (76.3) (104.0)
Other - (1.9)
Net cash flows used for investing activities (89.6) (105.9)(109) (44)
CASH FLOWS FROM FINANCING ACTIVITIES:
Retirement of first mortgage bonds (Note 5) (36) (50)
Short-term borrowings from affiliated company
(Note 5) - 58
Long-term borrowings from affiliated company
(Note 8) 50.0 50.0
Short-term borrowings from affiliated
company (Note 8) 462.3 380.5
Repayment of long-term debt -5) 50 -
Repayment of short-term borrowings from
affiliated company (Note 8) (465.4) (393.9)
Proceeds from issuance of pollution control
bonds 13.35) (18) -
Retirement of pollution control bonds (50.0) (4.8)
Repayment of other borrowings (Note 8) (26.7) - (27)
Payment of dividends (51.8) (43.7)- (41)
Net cash flows used for financing activities (68.3) (11.9)(4) (60)
CHANGE IN CASH AND CASH EQUIVALENTS (0.4) (0.2)(2) (1)
CASH AND CASH EQUIVALENTS AT BEGINNING OF
PERIOD 4.6 4.97 5
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 4.2 $ 4.7
SUPPLEMENTAL DISCLOSURES:
Cash paid during the period for:
Income taxes $58.3 $40.8
Interest on borrowed money 5.1 9.2
Interest to affiliated companies on borrowed money 6.7 9.3$5 $4
The accompanying notes are an integral part of these financial statements.
Kentucky Utilities Company
Statements of Other Comprehensive Income
(Unaudited)
(Millions of $)
Three Months NineSix Months
Ended June 30, Ended SeptemberJune 30,
September 30,2006 2005 20042006 2005 2004
Net income $31.7 $34.8 $87.0 $94.8
Income Taxes - Minimum Pension
Liability - - (0.3) -
Other comprehensive loss,$25 $18 $60 $55
Comprehensive income, net of tax - - (0.3)- -
Comprehensive income $31.7 $34.8 $86.7 $94.8$25 $18 $60 $55
The accompanying notes are an integral part of these financial statements.
Louisville Gas and Electric Company
Kentucky Utilities Company
Notes to Financial Statements
(Unaudited)
1. General
The unaudited financial statements include the accounts of LG&E and KU.the
Companies. The common stock of each of LG&E and KUCompany is wholly-owned by LG&E Energy.E.ON
U.S. 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 financial
position, results of operations, retained earnings, 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 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'sthe Companies' Annual Reports on Form 10-K for the year ended
December 31, 2004,2005, for information relevant to the accompanying
financial statements, including information as to the significant
accounting policies of the Companies.
DuringNew Accounting Pronouncements
In July 2006, the secondFASB issued FIN 48, Accounting for Uncertainty in
Income Taxes, an interpretation of FASB Statement No. 109, Accounting
for Income Taxes. FIN 48 is effective for fiscal years beginning after
December 15, 2006. FIN 48 clarifies accounting for income taxes to
provide improved consistency of criteria used to recognize, derecognize
and measure benefits related to income taxes. The Companies are now
analyzing the future impacts of FIN 48 on results of operations and
financial condition.
2. Rates and Regulatory Matters
For a description of each line item of regulatory assets and
liabilities for the Companies, reference is made to Part I, Item 8,
Financial Statements and Supplementary Data, Note 3 of the Companies'
Annual Reports on Form 10-K for the year ended December 31, 2005.
The following regulatory assets and liabilities were included in LG&E's
Balance Sheets as of June 30, 2006 and December 31, 2005:
Louisville Gas and Electric Company
(Unaudited)
June 30, December 31,
(in millions) 2006 2005
ARO $21 $20
Gas supply adjustments 21 29
Unamortized loss on bonds 20 21
ECR 6 2
FAC 5 -
VDT - 7
Other 5 5
Total regulatory assets $78 $84
Accumulated cost of removal of utility plant $225 $219
Deferred income taxes - net 44 42
Gas supply adjustments 40 17
Other 2 3
Total regulatory liabilities $311 $281
LG&E currently earns a return on all regulatory assets, excluding the
ARO regulatory assets, gas supply adjustments and the FAC. The ARO
regulatory assets earn no current return and will be offset against the
associated regulatory liability (included in other regulatory
liabilities), ARO asset and ARO liability at the time the underlying
asset is retired. The gas supply adjustments and the FAC have separate
rate mechanisms with recovery within twelve months.
The increase in FAC for the period is due to the higher cost of fuel
being passed on to customers. The decrease in VDT for the period is due
to the completion of the amortization of the VDT in the first quarter
of 2006. The increase in the Gas supply adjustments net liability for
the period reflects over-recovery of gas supply costs, in process of
being refunded to customers.
The following regulatory assets and liabilities were included in KU's
Balance Sheets as of June 30, 2006 and December 31, 2005:
Kentucky Utilities Company
(Unaudited)
June 30, December 31,
(in millions) 2006 2005
LG&EARO $21 $20
Unamortized loss on bonds 10 11
ECR 5 4
FAC 27 12
VDT - 3
Other 7 8
Total regulatory assets $70 $58
Accumulated cost of removal of utility plant $288 $281
Deferred income taxes - net 22 23
Other 10 11
Total regulatory liabilities $320 $315
KU currently earns a return on all regulatory assets, excluding the ARO
regulatory assets and KU made out-of-period
adjustmentsthe FAC. The ARO regulatory assets earn no
current return and will be offset against the associated regulatory
liability (included in other regulatory liabilities), ARO asset and ARO
liability at the time the underlying asset is retired. The FAC has a
separate recovery mechanism with recovery within twelve months.
The increase in FAC for estimated over/under collectionthe period is due to the higher cost of ECR revenuesfuel
being passed on to be
billedcustomers. The decrease in subsequent periods.VDT for the period is due
to the completion of the amortization of the VDT in the first quarter
of 2006.
ELECTRIC AND GAS RATE CASES
On June 30, 2004, the Kentucky Commission issued an order approving an
increase in the base electric rates of the Companies and the natural
gas rates of LG&E. The adjustments were immaterialrate increases took effect on July 1, 2004.
During 2004 and 2005, the AG conducted an investigation of the
Companies, as well as of the Kentucky Commission and its staff,
requesting information regarding allegedly improper communications
between the Companies and the Kentucky Commission, particularly during
all reporting periods involved (March 2003 through Octoberthe period covered by the rate cases. Concurrently, the AG had filed
pleadings with the Kentucky Commission requesting rehearing of the rate
cases on computational components of the increased rates, including
income taxes, cost of removal and depreciation amounts. In August 2004,
for
LG&Ethe Kentucky Commission denied the AG's rehearing request on the cost
of removal and May 2003 throughdepreciation issues and granted rehearing on the income
tax component. The Kentucky Commission agreed to hold in abeyance
further proceedings in the rate case, until the AG filed its
investigative report regarding the allegations of improper
communication.
In January 2005 and February 2005, the AG filed a motion summarizing
its investigative report as containing evidence of improper
communications and record-keeping errors by the Companies in their
conduct of activities before the Kentucky Commission or other state
governmental entities and forwarded such report to the Kentucky
Commission under continued confidential treatment to allow it to
consider the report, including its impact, if any, on completing its
investigation and any remaining steps in the rate case. To date, the
Companies have neither seen nor requested copies of the report or its
contents.
In December 2005, the Kentucky Commission issued an order noting
completion of its inquiry, including review of the AG's investigative
report. The order concludes that no improper communications occurred
during the rate proceeding. The order further established a procedural
schedule through the first quarter of 2006 for KU). Asconsidering the sole
issue for which rehearing was granted: state income tax rates used in
calculating the granted rate increase. On March 31, 2006, the Kentucky
Commission issued an order resolving this issue in the Companies' favor
consistent with the original rate increase order.
The Companies believe no improprieties have occurred in their
communications with the Kentucky Commission and have cooperated in the
proceedings before the AG and the Kentucky Commission. The Companies
are currently unable to predict whether there will be any additional
actions or consequences as a result year-to-
date LG&E revenues were increased $4.8of the AG's report and
investigation.
ECR
In June 2006, the Companies filed applications to amend their ECR plans
with the Kentucky Commission seeking approval to recover investments in
environmental upgrades at the Companies' generating facilities. The
estimated capital cost of the upgrades for the years 2006 through 2008
is approximately $391 million and KU revenues were
decreased $2.4 million. Year-to-date net income was increased $2.9($66 million for LG&E and was reduced $1.5$325 million
for KU.
DuringKU), of which $229 million is for the Air Quality Control System at
Trimble County Unit 2 ($44 million for LG&E and $185 million for KU)
and $95 million is for KU's Ghent Unit 2 Selective Catalytic Reduction.
A final order is expected to be issued by the end of 2006.
In April 2006, the Kentucky Commission initiated routine periodic
reviews of the ECR mechanisms for the Companies. These proceedings are
expected to be completed before the end of the third quarter of 2005,2006.
In December 2004, KU and LG&E filed applications with the Kentucky
Commission for approval of a CCN to construct new SO2 control
technology (FGDs) at KU's Ghent and KU reclassified RSGMWP from
other operationBrown stations, and maintenance expenses to other revenueamend LG&E's
compliance plan to better
reflect this revenue as partallow recovery of new and additional environmental
compliance facilities. The estimated capital cost of the sales price paid by MISO. As a
result, LG&E's revenues and expenses increased $12.6additional
facilities for 2006 through 2008 is approximately $720 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($40
million for LG&E and was increased $4.0$680 million for KU.
The accompanying financial statementsKU), of which $560 million is for
the three monthsKU FGDs at Brown and nine
monthsGhent. Hearings in these cases occurred
during May 2005 and final orders were issued in June 2005, granting
approval of the CCN and amendments to the Companies' compliance plans.
FAC
On February 15, 2006, KU filed with the Virginia Commission an
application seeking approval of an increase in its fuel cost factor to
reflect higher fuel costs incurred during 2005, and anticipated to be
incurred in 2006, of approximately $6 million. The Virginia Commission
approved KU's request on April 5, 2006.
VDT
In December 2001, the Companies received an order from the Kentucky
Commission permitting them to set up regulatory assets for workforce
reduction costs (VDT costs) and begin amortizing them over a five-year
period beginning in April 2001. The order also reduced revenues through
a surcredit on bills to ratepayers over the same five-year period,
reflecting a sharing (40% to the ratepayers and 60% to the Companies)
of the stipulated savings, net of amortization costs, of the workforce
reduction. The five-year VDT amortization period ended March 31, 2006.
On February 27, 2006, the AG, Kentucky Industrial Utility Consumers,
Inc. and the Companies reached a settlement agreement on the future
ratemaking treatment of the VDT surcredits and costs and subsequently
submitted a joint motion to the Kentucky Commission to approve the
unanimous settlement agreement. Under the terms of the settlement
agreement, the VDT surcredit will continue at the current level until
such time as LG&E or KU file for a change in electric or natural gas
base rates. The Kentucky Commission issued an order on March 24, 2006,
approving the settlement agreement.
MISO
The MISO is a non-profit independent transmission system operator that
controls more than 100,000 miles of transmission lines over 1.1 million
square miles in 17 northern Midwest states and one Canadian province.
The MISO operates the regional power grid and wholesale electricity
market in an effort to optimize efficiency and safeguard reliability in
accordance with federal energy policy.
The Companies are now involved in proceedings with the Kentucky
Commission and the FERC seeking the authority to exit the MISO. Based
on various financial analyses performed internally due to the July 2003
Kentucky Commission investigation into MISO membership, and
particularly in light of the financial impact of MISO's implementation
of the new day-ahead and real-time markets, the Companies determined
that the costs of MISO membership, both now and in the future, outweigh
the benefits. A timeline of events regarding the MISO and various
proceedings is as follows:
- September 30,1998 - The FERC granted conditional approval for the
formation of the MISO. The Companies were founding members.
- October 2001 - The FERC ordered that all bundled retail loads and
grandfathered wholesale loads of each member transmission owner
be included in the calculation of the MISO "cost adder," the
Schedule 10 charges designed to recover the MISO's cost of
operation, including start-up capital (debt) costs. The Companies
and several owners opposed the FERC order and filed suit with the
United States Court of Appeals.
- February 2002 - The MISO began commercial operations.
- February 2003 - The FERC reaffirmed its position on the Schedule
10 charges and the order was subsequently upheld by the U.S. Court
of Appeals.
- July 2003 - The Kentucky Commission opened an investigation into
the Companies' MISO membership. Testimony was filed by the
Companies that supported an exit from the MISO, under certain
conditions.
- August 2004 have been revised to conform- The MISO filed its FERC-required TEMT. The Companies
and other owners filed opposition to certain reclassifications inconditions of the current three monthsTEMT
and nine months
ended September 30, 2005. These reclassifications had no impact on net
assets or net income, as previously reported.
LG&Esought to delay the implementation. Such opposition was denied
by the FERC.
- December 2004 - The Companies provided the MISO its required
one-year notice of intent to exit the grid.
- April 2005 - The MISO implemented its day-ahead and KU net operating income previously reportedreal-time
market (MISO Day 2), including a congestion management system.
- October 2005 - The Companies filed documents with the FERC seeking
authority to exit the MISO.
- November 2005 - The Companies requested a Kentucky Commission order
authorizing the transfer of functional control of their
transmission facilities from the MISO to the Companies
respectively, for the three
months ended September 30, 2004, increased by $21.1 million and $19.5
million,purpose of withdrawing from the MISO. The
request stated that the Tennessee Valley Authority ("TVA") would
have control to the extent necessary to act as the Companies'
Reliability Coordinator and for the nine months ended September 30, 2004, increasedSouthwest Power Pool, Inc.
("SPP") to perform its function as the Companies' Independent
Transmission Organization. The Kentucky Commission issued an order
authorizing this transfer in July 2006.
- March 2006 - the FERC issued an order conditionally approving the
request of the Companies to exit the MISO. The FERC order
contained a number of conditions that the Companies needed to
satisfy to effect their exit from the MISO including:
- Submission of various compliance filings addressing:
- the Companies' hold-harmless obligations under the MISO
Transmission Owners' Agreement, and the amount of the MISO
exit fee to be paid by $45.5 millionthe Companies as calculated under the
approved methodology;
- the Companies' anticipated arrangements with Southwest Power
Pool, Inc. and $58.1 million, respectively, becauseTennessee Valley Authority, including revisions
to address certain independence and transmission planning
considerations, and reciprocity arrangements to ensure certain
KU requirements customers do not incur pancaked rates for
transmission and ancillary services;
- the income
statement presentation was changed in 2005Companies' proposed Open Access Transmission Tariff as
revised to report income tax expenseaddress possible capacity hoarding, available
transmission calculation methodology, curtailment priority and
pricing, among other matters; and
- the Companies' finalized arrangements with the Southwest Power
Pool, Inc. and Tennessee Valley Authority.
- The Companies must also file an application of the proposed Open
Access Transmission Tariff under Section 205 of the Federal Power
Act including a proposed return on equity. During April 2006
through the present, the Companies have submitted filings to the
FERC addressing the majority of the conditions contained in the
category Federal and State income taxes, which appears just
before net income. LG&E other(income)expenseMarch 2006 order, including a proposed return on equity of 10.88%
as part of its open access transmission tariff effective upon any
exit from the MISO.
- net previously reportedMay 2006 - the Kentucky Commission issued an order approving the
request of the Companies to exit the MISO. The order authorized
the Companies, upon exit of the MISO, to establish a regulatory
asset for the three monthsexit fee, subject to adjustment for possible future
MISO credits, and nine months ended September 30, 2004,
increased $0.8 million and $1.4 million, respectively,a regulatory liability for certain revenues which
may be collected via current base rates as a result of the reclassification. KU other incomeexisting
inclusion of amounts associated with certain MISO Schedule 10
charges.
- net decreased $0.9 millionJuly 2006 - the Kentucky Commission issued an order approving the
Companies' contractual arrangements with TVA and $2.5 million,SPP to provide
services to the Companies as reliability coordinator and
independent transmission organization, respectively, asupon a
resultwithdrawal from the MISO. This order was subject to certain
conditions based upon a satisfactory outcome of pending FERC
proceedings involving the Companies' market-based rate authority.
- July 2006 - the Kentucky Commission issued further orders denying
the MISO's request for a rehearing regarding the May 2006 order
and denying the MISO's request for intervenor status in the
proceeding concerning the Companies' TVA/SPP arrangements.
- July 2006 - the FERC issued a further decision accepting, in
substantial part, certain of the reclassification.
2. MergersCompanies' steps, including
compliance and Acquisitions
Onother filings, which constituted conditions to the
FERC's March 2006 order conditionally approving their exit from the
MISO. Also in July 2006, the FERC issued an order denying the
MISO's request for a rehearing regarding the FERC's March 2006
order.
The Companies now estimate that they may complete their exit from the
MISO during late summer 2006. The Companies have tendered a
contractual notice to the MISO providing for a withdrawal date of
September 1, 2002, E.ON completed its acquisition of Powergen, including
LG&E Energy, for approximately 5.1 billion pounds sterling
($7.3 billion). As a result2006. There remain certain further conditions that must
be satisfied under the FERC's exit orders, which conditions the
Companies currently anticipate they can accomplish. The Companies are
in continuing discussions with the MISO concerning operational elements
of the acquisition, LG&E Energy becameexit and transition.
On or about the date of a wholly-owned subsidiarycompleted exit from the MISO, and following
initial calculation and invoicing from the MISO, the Companies would
pay an exit fee to the MISO in an amount of E.ON and, as a result,up to approximately $41
million (allocated approximately $16 million for LG&E and KU also became
indirect subsidiaries$25 million
for KU). The ultimate amount would be determined based upon the actual
timing and circumstances of E.ON. LG&Eexit and, KU have continued their separate
identitiesfollowing payment, is subject to
confirmation, correction and serve customers under their existing names. The preferred
stock and debt securities of LG&E and KU were not affected by this
transactiontrue-up, as agreed between the Companies
and the utilitiesMISO. The Kentucky Commission's May 2006 order granted certain
relief regarding the exit fee, including the establishment of a
regulatory asset relating to such fee and continuing ability to recover
certain MISO charges in existing rates.
While the Companies believe they can reasonably achieve the remaining
conditions imposed by the FERC relating to MISO exit by the late
summer, including possibly as early as September 1, 2006, the actual
timing or occurrence of withdrawal cannot be assured.
Market-Based Rate Authority
Beginning in April 2004, the FERC initiated proceedings to modify its
methods used to assess generation market power and has established more
stringent interim market screen tests. During 2005, in connection with
the Companies' tri-annual market-based rate tariff renewals, the FERC
continued to contend that the Companies failed such market screens in
certain regions. The Companies disputed this contention and, in January
2006, in an attempt to resolve the matter, the Companies submitted
proposed tariff schedules to the FERC containing a mitigation mechanism
with respect to applicable power sales into the control area of Big
Rivers Electric Corporation ("BREC") in western Kentucky, where Western
Kentucky Energy Corp., an affiliate of the Companies, maintains a long-
term contractual relationship with BREC. Under the proposed tariff
schedule, prices for such sales would be capped at a relevant MISO
power pool index price. Should the Companies exit the MISO, the FERC
contended that they would have market power in their own joint control
area, potentially requiring a similar mitigation mechanism for power
sales into such region. In July 2006, the FERC issued an order in the
Companies' market-based rate proceeding accepting the Companies'
further proposal to address certain market power issues the FERC had
claimed would arise upon an exit from the MISO. In particular, the
Companies received permission to sell power at market-based rates at
the interface of control areas in which they may be deemed to have
market power, subject to a restriction that such power not be
collusively re-sold back into such control areas. Certain general FERC
proceedings continue with respect to market-based rate matters, and the
Companies' market-based rate authority is subject to such future
developments.
In some cases, recent FERC decisions in other market-based rate
proceedings have proposed or required cost-based, rather than market
index, price caps. The Companies cannot predict the ultimate impact of
the current or potential mitigation mechanisms on their future
wholesale power sales.
EPAct 2005
The EPAct 2005 was enacted on August 8, 2005. Among other matters, this
comprehensive legislation contains provisions mandating improved
electric reliability standards and performance; providing economic and
other incentives relating to transmission, pollution control and
renewable generation assets; increasing funding for clean coal
generation incentives (see Note 6); repealing PUHCA 1935; enacting
PUHCA 2005 and expanding FERC jurisdiction over public utility holding
companies and related matters via the Federal Power Act and PUHCA 2005.
The FERC was directed by the EPAct 2005 to adopt rules to address many
areas previously regulated by the other agencies under other statutes,
including PUHCA 1935. The FERC remains 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 continue to file SEC reports. Followingevaluate the acquisition, E.ON became a registered holding company under PUHCA.
(for discussionpotential impacts
of recent changes to PUHCA, seethe EPAct 2005 under Note 5). LG&E and KU, as subsidiaries of a registered
holding company, are subject to additional regulations under PUHCA. In
March 2003, E.ON, Powergenthe associated rulemakings and LG&E Energy completed an administrative
reorganization to movecannot predict
what impact the LG&E Energy group from an indirect Powergen
subsidiary to an indirect E.ON subsidiary. In early 2004, LG&E Energy
commenced direct reporting arrangements to E.ON.EPAct 2005, and any uncompleted rulemakings, will have
on their operations or financial position.
3. Financial Instruments
The Companies use over-the-counter 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 to correspond with
incomeincome. Upon termination of any
fair value hedge, the resulting gain or expense recognized from changes in market value of the items
being hedged.loss is recorded into net
income.
As of SeptemberJune 30, 2005,2006, LG&E was party to various interest rate swap
agreements with aggregate notional amounts of $211.3$211 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 2.61%3.67% at SeptemberJune 30, 2005.2006. The swap
agreements in effect at SeptemberJune 30, 2005,2006, have been designated as cash
flow hedges and mature on dates ranging from 2020 to 2033. The hedges
have been deemed to be fully effective resulting in a pretax gain of
$8.4 million and a pretax loss of $1.7$13 million for the three
months and ninesix months ended SeptemberJune 30, 2005, respectively,2006, recorded in other
comprehensive income. Upon expiration of these hedges, the amount
recorded in other comprehensive income will be reclassified into earnings.
The amountamounts expected to be reclassified from other comprehensive income to
earnings in the next twelve months isare immaterial. A deposit in the
amount of $12.2$7 million, used as collateral for an $83.3the $83 million interest
rate swap, is classified as restricted cash on LG&E's balance sheet.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 SeptemberJune 30, 2005,2006, KU was party to onean interest rate swap agreement
with a notional amount of $53.0$53 million. Under this swap agreement, KU
paid a variable raterates based on the LIBOR index of 5.86%averaging 7.24%, and received a fixed
rate ofrates averaging 7.92% at SeptemberJune 30, 2005.2006. The swap agreement in effect at
SeptemberJune 30, 20052006 has been designated as a fair value hedge and matures in
2007. During the three months and nine
months ended SeptemberAt June 30, 2005,2006, the effect of marking this financial
instrument and the underlying debt to market resulted in pretax gains
of $0.4 million and $0.9 million, 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 $1.9less than $1 million. The swap was fully effective upon termination. No impact on
earnings occurred as a 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, as amended, 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 SeptemberJune 30, 2005,2006, KU's debt reflects a $2.7 million
mark-to-market adjustment.mark-to-
market adjustment of less than $1 million.
At June 30, 2006, the Companies' percentage of debt having a variable
rate, including the impact of interest rate swaps, was 44%($364 million)
for LG&E and 47% ($378 million) for KU.
4. SegmentsPension and Other Post-retirement Benefit Plans
The following table provides the components of Business
LG&E's revenues, net incomeperiodic benefit
cost for pension and total assets by business segmentother benefit plans for the three months and ninesix months
ended SeptemberJune 30, 20052006 and 2004,
follow:2005:
Three Months Ended NineSix Months Ended
SeptemberJune 30, SeptemberJune 30,
2006 2005 2006 2005
(in millions) 2005 2004 2005 2004
LG&E Electric
Revenues $284.0 $227.0 $741.2 $617.8
Net income 45.3 34.6 99.1 71.0
Total assets 2,416.1 2,376.7 2,416.1 2,376.7KU LG&E Gas
Revenues 34.6 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 42.0 32.5 103.8 73.9
Total assets 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.
5. Rates and Regulatory Matters
For a description of each line item of regulatory assets and
liabilities 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, 2005 and December 31, 2004:
Louisville Gas and Electric Company
(Unaudited)
September 30, December 31,
(in millions) 2005 2004
VDT Costs $ 15.1 $ 37.7
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 13.6 13.3
Other 5.3 8.1
Total regulatory assets $ 73.3 $ 91.9
Accumulated cost of removal of utility
plant $218.8 $220.2
Deferred income taxes - net 52.7 37.2
ECR 0.7 4.0
Gas supply adjustments due to customers 5.9 8.4
Other 2.9 2.6
Total regulatory liabilities $281.0 $272.4 LG&E currently earns aKU
Pension and Other Benefit Plans
Components of net periodic
benefit cost
Service cost $2 $2 $1 $2 $3 $4 $3 $3
Interest cost 5 5 6 4 11 8 12 9
Expected return on
all regulatoryplan assets except for gas
supply adjustments, ESM, FAC, ECR and gas performance based ratemaking,
all(5) (4) (5) (4) (10) (7) (11) (8)
Amortization 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 removed.
Due toprior
service cost 1 - 1 - 2 1 3 1
Recognized actuarial
loss 1 1 1 1 2 2 1 1
Total net period benefit
cost $4 $4 $4 $3 $8 $8 $8 $6
LG&E made 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, 2005 and December 31, 2004:
Kentucky Utilities Company
(Unaudited)
September 30, December 31,
(in millions) 2005 2004
VDT costs $ 5.9 $ 14.7
Unamortized loss on bonds 11.2 11.4
ARO 14.1 12.8
Merger surcredit 2.9 3.7
FAC 27.7 9.4
Deferred storm costs 3.0 3.6
Other 5.8 5.8
Total regulatory assets $ 70.6 $ 61.4
Accumulated cost of removal of
utility plant $277.6 $266.8
Deferred income taxes - net 29.9 19.3
ECR 5.8 1.2
Other 4.6 4.2
Total regulatory liabilities $317.9 $291.5
KU currently earns a return on all regulatory assets except for ESM,
FAC, and 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 removed.
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 costs not reimbursed from the 2003 ice storm. These
costs will be amortized through June 2009. These amortized costs, which
are included in KU's jurisdictional operating expenses, are recovered
in base rates.
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.
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, asdiscretionary contribution to the communication issues. In
September and October 2004, various proceedings were heldpension plan of $18
million 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 of2006. LG&E andmade no contributions during 2005. KU
and submitted its reportmade no contributions to the Franklin County, Kentucky
Circuit Courtpension plan 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 Commission2006 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 it to consider the report, including its impact, if
any, on completing its investigation and any remaining steps in the
rate case, including ending the current abeyance. To date, LG&E and KU
have neither seen nor requested copies of the report or its contents.
During Spring 2005, LG&E and KU responded to additional information
requests from the 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 2006. As part of the settlement agreements in the electric and
gas rate cases, LG&E and KU are required to file with the Kentucky
Commission a plan for the future ratemaking treatment of the VDT
surcredits and costs six months prior to the March 2006 expiration. The
surcredit shall remain in effect following the expiration of the fifth
year unless and until the Commission enters an order on the future
disposition of VDT-related issues. On September 30, 2005, LG&E and KU
filed a plan with the Kentucky Commission in accordance with the
requirements of the settlement agreement calling for termination of the
VDT surcredit effective upon the expiration of the fifth year. The AG
and KIUC were granted intervention in the VDT 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 CCN 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
additional facilities is $742.7 million ($40.2 million for LG&E and
$702.5 million for KU), of which $658.9 million is for the FGDs.
Hearings in 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 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.
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, 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 facility, 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 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 47
In March 2005, the FASB issued Financial Accounting Standards Board
Interpretation No. 47, Accounting for Conditional Asset Retirement
Obligations, an interpretation of FASB Statement No. 143 (FIN 47). FIN
47 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 within the control of the entity.
The obligation to perform the asset retirement activity is
unconditional even though uncertainty exists about the timing and/or
method of settlement. An entity is required to recognize a liability
for the fair value of a conditional asset retirement obligation if the
fair value of the liability can be reasonably estimated. The fair value
of a liability for the conditional asset retirement obligation should
be recognized when incurred; generally, upon acquisition, construction,
or development and through the normal operation of the asset. FIN 47 is
effective no later than the end of fiscal years ending after December
15, 2005. LG&E and KU are currently evaluating the impact of this
pronouncement.
8.5. Short-Term and Long-Term Debt
Under the provisions for LG&E's variable-rate pollution control bonds,
Series S, T, U, BB, CC, DD and EE, and KU's variable-rate 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 Balance
Sheets.balance
sheets. The average annualized interest rate for these bonds during the
three and ninesix months ending SeptemberJune 30, 20052006 was 2.63% and 2.36%,
respectively,3.38% for LG&E and 2.59% and 2.40%, respectively,3.41% for KU.
During June 2005,2006, LG&E renewed five revolving lines of credit with
banks totaling $185 million. There was no outstanding balance under any
of these facilities at SeptemberJune 30, 2005. The Company2006. LG&E expects to renew these
facilities prior to their expiration in June 2006.2007.
LG&E, KU and LG&E EnergyE.ON U.S. participate in an intercompany money pool
agreement. Details of the balances at SeptemberJune 30, 2005,2006 and September
30, 2004,December 31,
2005 were as follows:
Total Money Amount Balance Average
($ in millions) Pool Available Outstanding Available Interest Rate
September($ in millions)
June 30, 2006:
LG&E $400 $ 1 $399 4.96%
KU $400 $ 52 $348 4.96%
December 31, 2005:
LG&E $400.0 $56.6 $343.4 3.64%$400 $141 $259 4.21%
KU $400.0 $31.8 $368.2 3.64%
September 30, 2004:
LG&E $400.0 $40.7 $359.3 1.60%
KU $400.0 $29.8 $370.2 1.60%
LG&E Energy$400 $ 70 $330 4.21%
E.ON U.S. maintains a revolving credit facility totaling $200 million
with an affiliated company, E.ON North America, Inc., to ensure funding
availability for the money pool. The balance outstanding on this
facility at SeptemberJune 30, 2005,2006, was $65.4$64 million.
Redemptions and maturities of long-term debt year-to-date through SeptemberJune
30, 2005,2006, are summarized below:
($ in millions)
Principal Secured/
Year Company Description Amount Rate Unsecured Maturity
2005 LG&E Pollution 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
20052006 KU First mortgage bonds $50.0 7.55%$36 5.99% Secured Jun 2025Jan 2006
Issuances of long-term debt year-to-date through SeptemberJune 30, 2005,2006, are
summarized below:
($ in millions)
Principal Secured/
Year Company Description Amount Rate Unsecured Maturity
2005 LG&E Pollution control bonds $40.0 Variable Secured Feb 2035
20052006 KU Pollution control bonds $13.3 Variable SecuredFidelia note $50 6.33% Unsecured Jun 2035
2005KU Due to Fidelia $50.0 4.735% Unsecured Jul 2015
In May 2005, KU repaid a $26.7 million loan against the cash surrender
value of life insurance policies.
9. Related-Party Transactions
LG&E, KU, 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. Transactions between LG&E or KU and E.ON subsidiaries are
eliminated upon consolidation of E.ON. These transactions are generally
performed at cost and are in accordance with the SEC regulations under
the PUHCA and the applicable Kentucky Commission 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
from affiliated companies for the three months and nine months ended
September 30, 2005, and 2004, were as follows:
Three months ended Nine months ended
September 30, September 30,
(in millions) 2005 2004 2005 2004
LG&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 Charges
LG&E and KU intercompany interest expense for the three months and nine
months ended September 30, 2005 and 2004, were as follows:
Three months ended Nine months ended
September 30, September 30,
(in millions) 2005 2004 2005 2004
LG&E intercompany interest expense $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 related to LG&E and KU for the three months
and nine months ended September 30, 2005 and 2004, were as follows:
Three months ended Nine months ended
September 30, September 30,
(in millions) 2005 2004 2005 2004
LG&E Services billings to LG&E $52.8 $40.2 $160.9 $138.8
LG&E Services billings to KU 44.3 42.3 145.5 117.5
LG&E billings to LG&E Services 0.8 6.0 6.1 10.5
KU billings to LG&E Services 0.4 0.5 3.9 4.4
LG&E billings to KU 54.9 14.9 83.4 48.5
KU billings to LG&E 7.6 2.1 20.7 5.5
10.Commitments2036
6. Commitments and Contingencies
Except as may be discussed in this Quarterly Report on Form 10-Q
(including Note 5)2), 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, 20042005 (including in Notes 3 and 10 to the financial
statements of the Companies contained therein) and Quarterly ReportsReport on
Form 10-Q for the three monthsquarter ended March 31, 20052006 (including in Notes 2
and June 30, 2005.6 to the financial statements contained therein). See Notes 3 and 11
tothe above-
referenced notes in the Companies' Annual Report on Form 10-K and
Note 10 to the
Companies' Quarterly ReportsReport on Form 10-Q for the three months ended
March 31, 2005, and June 30, 2005, for information regarding such
commitments or contingencies.
TRIMBLE COUNTY UNIT 2
In June 2006, the Companies, as 75% owners, entered into and delivered
notice to proceed under an engineering, procurement and construction
agreement with Bechtel Power Corporation ("Bechtel"), regarding
construction of Trimble County Unit 2 valued at approximately $1.1
billion. IMEA and IMPA, as 25% owners, are also parties to the
contract. The contract is generally in the form of a lump-sum, turnkey
agreement for the design, engineering, procurement, construction,
commissioning, testing and delivery of the project, according to
designated specifications, terms and conditions. The contract price
and its components are subject to a number of potential adjustments
which may serve to increase or decrease the ultimate construction price
paid or payable to the contractor. The contract also contains standard
representations, covenants, indemnities, termination and other
provisions for arrangements of this type, including termination for
convenience or for cause rights. In general, termination by the owners
for convenience or by the contractor due to owners' default will limit
payment obligations to payment for work or incentives performed or
earned to date and termination by owners due to contractor's default
will similarly limit payment obligations, subject however to owners'
rights with respect to cover damages and to certain collateral
provided. In connection with this matter, the Companies dismissed
their litigation against Bechtel regarding the contract previously
commenced in April 2006 in United States District Court for the Western
District of Kentucky.
In June 2006, the Companies filed an application with the Department of
Energy ("DOE") requesting certification to be eligible for investment
tax credits applicable to the construction of Trimble County Unit 2.
The EPAct 2005 added a new 48A to the Internal Revenue Code, which
provides for an investment tax credit to promote the commercialization
of advanced coal technologies that will generate electricity in an
environmentally responsible manner. The application requested up to
the maximum amount of "advanced coal project" credit allowed per
taxpayer, or $125 million, based on an estimate of 15% of projected
qualifying Trimble County Unit 2 expenditures. The DOE is anticipated
to select and certify feasible and suitable qualifying projects, in
their discretion, from among the applicant group during the late fall
of 2006. If selected, the Companies would submit an additional
application to the Internal Revenue Service ("IRS"). IRS action on
such applications would thereafter be expected to occur during the
fourth quarter of 2006. If, and to the extent the Companies'
applications are ultimately accepted, the Companies could thereafter
claim allocated federal income tax credits on eligible expenditures, as
they occur over time, relating to the Trimble County Unit 2 project.
LOUISVILLE DOWNTOWN ARENA
LG&E has been asked by the Louisville Arena Authority, Inc., a non-
profit corporation (the "Authority"), to transfer certain property and
relocate certain LG&E facilities so that an LG&E-owned site, in part,
could be used for the development and construction of a new multi-
purpose arena in Louisville, Kentucky. The Authority and LG&E are
negotiating a non-binding letter of intent regarding the arena
transactions. LG&E estimates that the cost of relocating the LG&E
facilities will be approximately $63 million and LG&E expects to
request that the Authority arrange for the provision of state funds
necessary for the relocation, as well as up to $10 million in state
funds for the purchase of the property at fair market value. Current
estimates are that the arena project could be completed by
approximately 2010. The anticipated letter of intent would be subject
to a number of contingencies, including completion of definitive
documents and regulatory approvals necessary for the transactions
contemplated.
OMU LITIGATION
In May 2004, OMUthe City of Owensboro, Kentucky and Owensboro Municipal
Utilities (collectively "OMU") commenced litigationa suit now removed to the U.S.
District Court for the Western District of Kentucky, against KU
concerning a long-term power supply contract.contract (the "OMU Agreement") with
KU. The dispute involves interpretational differences regarding issues
under the OMU Agreement, including various payments or charges between
KU filed counterclaims against OMU. To date,and OMU has claimedand rights concerning excess power, termination and
emissions allowances. The complaint seeks approximately $6 million in
damages for periods through
earlyprior to 2004 and OMU is expected to claim further
amounts for later-
occurringlater-occurring periods. OMU has additionally requested
injunctive and other relief, including a declaration that KU is in
material breach of the contract. In MarchKU has filed an answer in that court
denying the OMU claims and presenting counterclaims. During 2005, the
FERC denied a rehearing request by KU
regarding the FERC's December 2004 decision to declinedeclined KU's application to exercise exclusive jurisdiction regarding certain issues in dispute.over
the matter. In July 2005, the district court resolved a summary
judgment motion ofmade by KU in OMU's favor, ruling that a contractual
provision grants OMU the ability to terminate the contract without
cause upon 4four years' prior notice. OMU
filed a motion seekingnotice, for which ruling KU retains
certain rights to make that ruling "final and appealable." In
October 2005, however,appeal. At this time the Court denied OMU's motion. Thisdistrict court case is
otherwise currently in
the discovery stage and a trial schedule has not yet been established.
In May 2006, OMU issued a notification of its intent to terminate the
contract in May 2010, without cause, absent any earlier termination
which may be permitted by the proceeding.
ENVIRONMENTAL MATTERS
LG&EIn April 2006, the EPA issued a notice of violation for alleged
violations of the Clean Air Act involving work performed on Unit 3 of
KU's E.W. Brown Station in 1997. The EPA alleges modification of a
source without a permit, failure to comply with requirements under the
Prevention of Significant Deterioration ("PSD") program, operation of a
source in violation of the New Source Performance Standards ("NSPS"),
and failure to identify the applicability of PSD and NSPS requirements
in compliance certifications. Violations, if ultimately found, could
result in additional expenditures on pollution controls or civil
penalties. KU has responded to certain data requests of the EPA and
held initial discussions with the EPA regarding this matter. Due to the
early stage of this matter, KU is unable to determine its ultimate
potential impact.
The Companies are subject to SO2 and NOXNOx emission limits on their
electric generating units pursuant to the Clean Air Act. LG&E and KUThe Companies
placed into operation significant NOXNOx controls for their generating
units prior to the 2004 Summer Ozone Season.summer ozone season. As of December 31, 2004,June 30, 2006, LG&E
and KU have incurred total capital costs of approximately $186$191 million
and $219$217 million, respectively, to reduce their NOXNOx emissions belowto
required levels. In addition, LG&E and KUthe Companies incur additional operating
and maintenance costs in operating the new NOXNOx controls. On March 10,
2005, the EPA issued the final Clean Air Interstate Rule
(CAIR)CAIR which requires substantial
additional reductions in SO2 and NOXNOx emissions from electric generating
units. The CAIR rule provides for a two-phased reduction program with Phase
I reductions in NOXNOx and SO2 emissions in 2009 and 2010, respectively,
and Phase II reductions in 2015. On March 15, 2005, the EPA issued a
related regulation, the final Clean Air Mercury Rule (CAMR),CAMR, which requires substantial mercury
reductions from electric generating units. The CAMR also provides for a
two-
phasedtwo-phased reduction, with the Phase I target in 2010 achieved as a "co-
benefit" of the controls installed to meet the CAIR. Additional control
measures will be required to meet the Phase II target in 2018. Both the
CAIR and the 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 canto be used for compliance, unless the state chooses another
approach. LG&E currently has FGDs on all its coal-fired units, but will
continue to evaluate improvements to further reduce SO2 emissions.
In order to meet these new regulatory requirements, KU has implemented
a plan for adding significant additional SO2 controls to its generating
units. Installation of additional SO2 controls will proceed on a phased
basis, with construction of controls (i.e., FGDs) having commenced in
September 2005 and continuing through the final installation and
operation in 2009. KU estimates that it will incur $658.9$659 million in
capital costs related to the construction of the FGDs to achieve
compliance with current emission limits on a company-wide basis. Of
this amount, $77 million has been incurred through June 30, 2006. In
addition, KU will incur additional operating and maintenance costs in
operating the new SO2 controls.
LG&E currently has FGDs on all its
units but will continue to evaluate improvements to further reduce SO2
emissions.
LG&E and KUThe Companies are also monitoring several other air quality mattersissues
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.
After extensive negotiations between KU and the EPA 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
oil 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 time, LG&E and KU have conducted negotiations with the
relevant regulatory authorities to address various environmental-
related matters, including: remedial measures aimed at controlling
particulate matter emissions from LG&E's Mill Creek plant; liability
for cleanup of off-site facilities that allegedly handled materials
associated with company operations; and investigation and cleanup of
company properties including former LG&E and KU MGP sites. Based on
negotiations to date, management does not anticipate that any of the
liabilities arising out of any of these matters will have a material
adverse affect on LG&E's or KU's financial position or results of
operations.Clean Air Visibility Rule.
In the normal course of business, lawsuits, claims, environmental
actions and various non-ratemaking governmental proceedings arise
against LG&E and KU.the Companies. To the extent that damages are assessed in any
of
these lawsuits LG&E and KUrelating to the above, the Companies believe that their
insurance coverage or other appropriate reserves are adequate.
Management, after consultation with legal counsel, and based upon the
present status of these items, does not anticipate that liabilities
arising out of other currently pending or threatened lawsuits and
claims of the type referenced above will have a material adverse effect
on LG&E's or KU'sthe Companies' financial position or results of operations.
EEI CONTRACT
KU owns 20%7.Segments of the common stock of EEI, which ownsBusiness
LG&E's revenues, net income 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
generatedtotal assets 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 andbusiness segment for
the ninethree and six months ended June 30, 2006 and 2005, follow:
Three Months Six Months
Ended June 30, Ended June 30,
(in millions) 2006 2005 2006 2005
LG&E Electric
Revenues $223 $228 $435 $457
Net income 27 30 42 54
Total assets 2,440 2,404 2,440 2,404
LG&E Gas
Revenues 54 53 254 225
Net income (2) (2) 8 8
Total assets 507 454 507 454
Total
Revenues 277 281 689 682
Net income 25 28 50 62
Total assets 2,947 2,858 2,947 2,858
KU is an electric utility company. It does not provide natural gas
service and, therefore, is presented as a single business segment.
8. Related Party Transactions
LG&E, KU, subsidiaries of 2005. DiscussionsE.ON U.S. and other subsidiaries of E.ON
engage in related-party transactions. These transactions are on-goinggenerally
performed at cost and in accordance with applicable FERC, Kentucky
Commission and Virginia Commission regulations. The significant
related-party transactions are disclosed below.
Electric Purchases
The Companies' intercompany electric revenues and purchased power
expense from affiliated companies for the three and six months ended
June 30, 2006 and 2005 were as follows:
Three Months Six Months
Ended June 30, Ended June 30,
(in millions) 2006 2005 2006 2005
LG&E KU LG&E KU LG&E KU LG&E KU
Electric operating
revenues from KU $22 $- $21 $- $44 $- $47 $-
Electric operating
revenues from LG&E - 17 - 19 - 36 - 49
Purchased power from KU 17 - 19 - 36 - 49 -
Purchased power from LG&E - 22 - 21 - 44 - 47
Interest Charges
The Companies' intercompany interest income and expense for the three
and six months ended June 30, 2006 and 2005 were as follows:
Three Months Six Months
Ended June 30, Ended June 30,
(in millions) 2006 2005 2006 2005
LG&E KU LG&E KU LG&E KU LG&E KU
Interest on money pool
loans $- $1 $- $- $1 $2 $- $-
Interest on Fidelia
loans 3 4 3 4 6 9 6 7
Other Intercompany Billings
Other intercompany billings 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 plansCompanies for the three months and
ninesix months ended SeptemberJune 30, 2006 and 2005 and 2004:
LG&Ewere as follows:
Three months ended Nine months ended
SeptemberMonths Six Months
Ended June 30, SeptemberEnded June 30,
(in millions) 2006 2005 20042006 2005
2004
Pension and Other Benefit Plans:
Components of net period benefit cost
Service cost $ 1.3 $ 1.0 $ 4.4 $ 4.0
Interest cost 5.1 4.9 17.3 20.0
Expected return on plan assets (4.8) (4.5) (16.1) (18.2)
Amortization of prior service
cost 1.1 - 3.6 -
Amortization of transition
obligation - 1.0 - 3.8
Recognized actuarial loss 0.6 0.5 2.0 2.1
$ 3.3 $ 2.9 $ 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 $ 2.3 $ 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 the
pension plans of $34.5 million and $43.4 million, respectively. No
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.
12.Subsequent Events
On October 24, 2005, KU redeemed 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 new license to
upgrade, operate and maintain the Ohio Falls Hydroelectric Project from
the FERC. The license is issuedE.ON U.S. Services billings to LG&E for a period of 40 years,
effective November 11, 2005.$69 $76 $105 $108
E.ON U.S. Services billings to KU 78 75 120 101
LG&E intendsbillings to spendE.ON U.S. Services 2 1 3 5
KU billings to E.ON U.S. Services 2 - 3 4
LG&E billings to KU 6 7 10 10
KU billings to LG&E 3 9 15 13
9. Subsequent Events
On July 14, 2006, LG&E redeemed 12,500 shares of its 5.875% mandatorily
redeemable preferred stock pursuant to sinking fund requirements at
$100 per share.
On July 20, 2006, KU completed a new tax-exempt financing totaling
approximately $75
million to refurbish the facility$17 million. The new bonds, due June 1, 2036, have a
variable, auction rate of interest.
Effective August 1, 2006, KU and add approximately 20 Mw of
generating capacity.
On November 1, 2005, the Kentucky Commission approved the application
of LG&E and KU 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 completedits employees represented 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 yetIBEW
Local 2100 entered into final construction
contracts. The Companies also needa new three-year collective bargaining
agreement. Such agreement provides for routine updates to obtain approval from the
Kentucky State Board on Electric Generationwages,
benefits or other provisions and Transmission Siting, as
well as obtain the air permit from the Kentucky Department of Air
Quality, both of which are expected by the end of November 2005. In
September 2005, the Kentucky Commission approved one of three
transmission facilitiesprovides for annual wage re-openers
for the additional Trimble County unit. The
Companies expect to refile the applications for the remaining two
transmission facilities in the fourth quarter.second and third years.
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'sthe Companies' financial results of
operations and financial condition during the three and ninesix month periods
ended SeptemberJune 30, 2005,2006, 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'sthe Companies' reports to the SEC, including
the Annual Reports on Form 10-K for the year ended December 31, 2004.2005.
Executive Summary
LG&E and KU, subsidiaries of LG&E Energy (an indirect subsidiaryE.ON U.S. (indirect subsidiaries of E.ON), are
regulated public utilities. At June 30, 2006, LG&E suppliessupplied electricity to
approximately 395,000398,000 customers and natural gas to approximately 320,000323,000
customers in Louisville and adjacent areas in Kentucky. At June 30, 2006,
KU provides electric serviceprovided electricity to approximately 492,000497,000 customers in over 77 counties
in central, southeastern and western Kentucky, to approximately 30,000
customers in southwestern Virginia and to less than 105 customers in Tennessee. KU also
sells wholesale electric energyelectricity to 12 municipalities.
The mission of LG&E and KUthe Companies is to build on our tradition and achieve
world-
classworld-class status providing reliable, low-cost energy services and
superior customer satisfaction; and to promote safety, financial success
and quality of life for our employees, communities and other stakeholders.
LG&E and KU'sThe Companies' strategy focuses on the following:
- Achieve scale as an integrated U.S. electric and gas business through
organic growthgrowth;
- Maintain excellent customer satisfactionsatisfaction;
- Maintain best-in-class cost position versus U.S. utility companiescompanies;
- Develop and transfer best practices throughout the companycompany;
- Invest in infrastructure to meet expanding load and comply with
increasing environmental requirementsrequirements;
- Achieve appropriate regulated returns on all investmentinvestment;
- Attract, retain and develop the best peoplepeople; and
- Act with a commitment to corporate social responsibility that enhances
the well being of our employees, demonstratedemonstrates environmental
stewardship, promotepromotes quality of life in our communities and reflectreflects
the diversity of the society we serveserve.
In a June 2004 order, the Kentucky Commission accepted the settlement
agreements reached by the majority of the parties in the rate cases filed
by LG&E and KUthe Companies in December 2003. Under the ruling, the LG&E utility base
electric rates have increased $43.4$43 million (7.7%) and base natural gas rates
have increased $11.9$12 million (3.4%), on an annual basis. annually. Base electric rates at KU have
increased $46 million (6.8%) annually. The rate increases took effect on
July 1, 2004. Base electric rates at KU have increased $46.1
million (6.8%) annually. The 2004 increases were the first increases in electric base
rates for LG&E and KUthe Companies in 13 and 20 years, respectively; the previous
natural gas rate increase for the LG&E gas utility took effect in September
2000.
WithThe Companies have begun construction of another base-load coal-fired unit
at the installation of four combustion turbines at Trimble County in
2004, near-term regulated load growth in Kentuckysite. The Companies believe this is expectedthe least cost
alternative to be
satisfied. However,meet 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.future needs of customers. Trimble County Unit 2,
with a 732750 Mw capacity rating, is expected to be jointly-jointly owned by LG&E and KUthe
Companies (75% aggregate ownership)owners of the unit) and IMEA and IMPA (25% aggregate ownership)owners). 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 Kentucky Department of Air Quality in December 2004. A
public hearing on the draft air permit application occurred in August 2005.
The Kentucky Commission ruled favorably on the CCN application on November
1, 2005. The air permitTrimble
County Unit 2 is expected to cost $1.1 billion and be issuedcompleted by the Kentucky Department
of Air Quality in November 2005. LG&E's and KU's2010.
The Companies' aggregate 75% share of LG&E Energy'sthe total Trimble County Unit 2
capital cost ofis approximately $885 million and is estimated to be
approximately $120 million for LG&E and $510 million for KU through 2008.
Through June 2006, expenditures for Trimble County Unit 2 is estimated
to be $168have been $7
million for LG&E and $717$25 million respectively, through 2010.
Three applications for transmission CCN's were filed withKU. In June 2006, the Kentucky
Commission in May 2005 forCompanies
entered into a construction contract regarding the construction of three transmission
facilities to support Trimble County Unit 2.2
project. See Note 6 of the Notes to Financial Statements, in Part 1, Item
1, herein.
In SeptemberNovember 2005, the Kentucky Commission approved onethe CCN construction
application 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 toexpand the Trimble County Unit 2 project, another focusgenerating plant.
Kentucky Commission approvals for the related transmission line CCNs were
granted in September 2005 and May 2006. In July 2006, certain property
owners filed a motion for judicial appeal of major
utility investment is environmental expenditures.the latter transmission line
CCN ruling. A schedule for such proceeding has not been established. In
order to mitigate the
declining SO2 allowance bank at KU over the next several years, KU filed
withNovember 2005, the Kentucky CommissionDivision for Air Quality issued the final air
permit, which was challenged via a request for remand in December 2004 an application2005 by
three environmental advocacy groups, including the Sierra Club.
Administrative proceedings with respect to the challenge are expected to
continue during 2006 with a hearing scheduled for a CCN to
construct four FGDs at an estimated cost of $658.9 million, which was
approved in June 2005.
The Kentucky Commission opened an investigation into LG&E's and KU's
membershipOctober 2006. A ruling
thereafter may be anticipated in the MISO infirst half of 2007.
In July 2003. Should2006, the FERC issued a final report under a routine audit that its
Office of Enforcement (formerly its Office of Market Oversight and
Investigations) had conducted regarding the compliance of E.ON U.S. and
subsidiaries, including LG&E and KU, be orderedunder the FERC's standards of conduct
and codes of conduct requirements, as well as other areas. The final report
contained certain findings calling for improvements in E.ON U.S. and
subsidiaries' structures, policies and procedures relating to exittransmission,
generation dispatch, energy marketing and other practices. E.ON U.S. and
affiliates have agreed to certain corrective actions and plan to submit
procedures related to such corrective actions to the MISO, an aggregate feeFERC. The corrective
actions are in the nature of up to $41 million could be imposed, depending
on the timingorganization and circumstances of actual withdrawal. On October 7, 2005,
LG&Eoperational improvements as
described above and KU filed an application with the FERC seeking the requisite
authority to exit the MISO. This proceeding isare not 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, including whether
they will have a material adverse impact on
the financial condition or theCompanies' 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 the LMP system currently used by the PJM RTO and contemplated in
FERC's SMD NOPR. Ultimateor financial consequences (changes in transmission
revenues and costs) associated with the implementation of MISO Day 2 are
subject to varying assumptions and calculations and are therefore difficult
to estimate.condition.
Results of Operations
The results of operations for LG&E and KUthe Companies 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 the full
year.
Three Months Ended SeptemberJune 30, 2005,2006, Compared to
Three Months Ended SeptemberJune 30, 20042005
LG&E Results:
LG&E's net income increased $9.5decreased $3 million (29%(11%) for the three months ended
SeptemberJune 30, 2005,2006, as compared to the three months ended SeptemberJune 30, 2004,2005,
primarily due to higherlower electricity and natural gas retail electric revenuesand wholesale
sales volumes resulting largely from warmer summermilder weather (cooling degree days were 29% higher than in 2004),
higher wholesale revenues and lower income tax expense.the prior year.
A comparison of LG&E's revenues for the three months ended SeptemberJune 30, 2005,2006,
with the three months ended SeptemberJune 30, 2004,2005, 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 $ 13.3 $(0.1)$6 $7
Environmental cost recovery surcharge 0.7 -
Earnings sharing mechanism (5.1)(3) -
Variation in sales volume and other 22.4 0.1(5) (2)
Total retail sales 31.3 -(2) 5
Wholesale sales 19.7(4) (4)
Other 1 -
Other 6.0 (0.2)
Total $57.0 $(0.2)$(5) $1
Electric revenues increased $57.0decreased $5 million (25%(2%) in 2005 primarily due to:
- - Higher sales volumeDecreased wholesale revenues ($27.34 million) related to weather
- - Wholesale sales increased $19.7 million
- Higher MISO related revenue ($13.1 million),largely due to MISO Day 2 RSGMWP,
earned4% lower
volumes
- Decreased retail electric volumes delivered ($5 million) resulting from
a 14% decrease in cooling degree days in the second quarter of 2006
compared to the same period in 2005 and an 16% decrease from the
20-year average
- Decreased environmental cost recovery ($3 million) due to lower ECR
billing rates
- Increased fuel costs billed to customers through the fuel adjustment
clause ($6 million) due to higher costs of coal and natural gas
Gas revenues increased $1 million (2%) primarily due to:
- Increased gas supply costs billed to customers through the gas supply
adjustment ($7 million) due to the MISO'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 2natural gas
- HigherDecreased wholesale revenues ($6.64 million), primarily as a result of 7% lower
volumes due to 6% higher
priceslower demand from wholesale customers
- Decreased retail gas volumes delivered ($12.72 million) partially offset by 3% lower volumes
($6.1 million)
- - Higher fuel supply adjustments ($13.3 million) dueresulting from a
17% decrease in heating degree days in the second quarter of 2006
compared to significantly
higher fuel costs
- - Lower MISO Day 1 transmission revenue ($1.3 million)the same period in 2005 and an 20% decrease from the
20-year average
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 increasesIncreases or decreases in the
cost of fuel and natural gas supply are reflected in LG&E's electric and
natural gas retail rates, through the fuel adjustment clause and gas supply
clause, subject to the approval of the Kentucky Commission.
Fuel for electric generation increased $25.6$2 million (48%(3%) in 20052006 primarily
due to:
- Increased unit cost per Btu (42% higher), resulting in $23.6 millionof fuel burned ($4 million) due to higher fuel
costs. Fuel costs are significantly higherprices
- Decreased generation ($2 million) due to the MISO's
dispatch of gas-fired units committed by the MISO's Reliability
Assessmentlower wholesale and Commitment processretail
sales volumes
Power purchased decreased $2 million (7%) in the real-time market.2006 primarily due to:
- Decreased volumes purchased ($6 million) due to lower wholesale and
retail sales
- Increased generation (4% higher), resulting in $1.9unit cost of purchases ($4 million) due to higher market
prices
Gas supply expenses increased $2 million higher fuel
costs
Power purchased increased $14.8 million (77%(6%) in 20052006 primarily due to:
- Increased cost per 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 $12.5 million (17%) in
2005.
Other operation expenses increased $19.9 million (41%) in 2005 primarily
due to:
- Increased other power supply expenses ($18.7 million) due largely to
MISO Day 2 costs ($19.0 million), including a $12.6 million reclass from
expense to revenue 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 costs ($3.1 million) largely due to the transfer
of storm expenses in the third quarter of 2004 from operations expenses
to maintenance expenses
- Increased administrative and general expenses ($1.2 million) largely
for increased employee benefit costs
- Increased cost of gas losses due to the increase in the unit cost of natural gas purchased ($0.68 million)
- Decreased transmission expensesvolumes of natural gas delivered into the distribution
system ($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 ($8.96 million) due to milder weather
A comparison of 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 $0.8 million (3%) in 2005
primarily due to additional plant in service.
Other expense - net decreased $1.9 million 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 interestLG&E effective income tax rate swaps ($0.8 million)
- - Decreased interest due to refinancing fixed rate debt with variable
rate debt ($0.4 million)
The weighted average interest rate on variable-rate bonds for the three months
ended SeptemberJune 30, 2006 and 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.follows:
Three Months Three Months
Ended Ended
Sept.June 30, 2005 Sept.2006 June 30, 20042005
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) -3.5 5.2
Amortization of investment and other
tax credits 1.8) (0.6)(2.7) (2.3)
Other differences (1.2) (0.7)(3.4) (1.5)
Effective income tax rate 26.7% 38.3%32.4% 36.4%
State income taxes in 2006 reflect Kentucky Coal Tax credits earned. The
increasedchange in amortization of investment tax benefit incredits and other differences is
largely attributable to the new Internal Revenue Code Section 199 Qualified Production Activities
deduction andchange in the amortizationlevels 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 additional
discussion of income taxes.pre-tax income.
KU Results:
KU's net income decreased $3.1increased $7 million (9%(39%) for the three months ended SeptemberJune
30, 2005,2006, as compared to the three months ended SeptemberJune 30, 2004. The decrease was2005, primarily
due to higher operation andlower maintenance expenses, partially offset by increased retail revenues ascosts, a result of
warmer summer weather (cooling degree days were 77% higher than in 2004)lower effective income tax rate and
higher wholesale revenues.earnings from EEI.
A comparison of KU's revenues for the three months ended SeptemberJune 30, 2005,2006,
with the three months ended SeptemberJune 30, 2004,2005, reflects increases and
(decreases) which have been segregated by the following principal causes:
Cause
Electric
(in millions) Revenues
Retail sales:
Fuel supply adjustments $41.7$17
Environmental cost recovery surcharge 2.1
Earnings sharing mechanism (5.1)
Rates and rate structure 0.83
Variation in sales volumevolumes and other 19.4(7)
Total retail sales 58.9
Wholesale sales 36.713
Other (1.0)(2)
Total $94.6$11
Electric revenues increased $94.6$11 million (37%(4%) in 20052006 primarily due to:
- - HigherIncreased fuel supply adjustmentscosts billed to customers through the fuel adjustment
clause ($41.717 million) due to higher costs of coal and natural gas
- Increased environmental cost of
fuel used for generation and purchased power
- - Higher sales volumesrecovery ($23.63 million) due to weatherhigher ECR
billing rates
- - Wholesale sales increased $36.7 million
- Higher wholesale revenuesDecreased retail electric volumes delivered ($18.67 million), primarily due to 6% higher
prices ($14.8 million) and 2% higher sales volume ($3.8 million)
- Higher MISO related revenue ($18.1 million), due to MISO Day 2 RSGWMP,
earned due resulting from
a 17% decrease in cooling degree days in the second quarter of 2006
compared to the MISO's dispatch of higher cost gas-fired units ($8.3
million), a $3.1 million reclass to revenuesame period in 2005 and an 19% decrease 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)20-year average
Fuel for electric generation comprises a large component of KU's total
operating expenses. KU's electric rates contain a fuel adjustment clause,
whereby increasesIncreases or decreases in the cost of fuel are
reflected in KU's retail electric rates through the fuel adjustment clause,
subject to the approval of the Kentucky Commission, the Virginia State
Corporation Commission and the FERC.
Fuel for electric generation increased $40.3$16 million (52%(19%) in 20052006
primarily due to:
- Increased unit cost per Btu (161% higher), resulting in $73.1 millionof fuel burned ($9 million) due to higher fuel
costs. Fuel costs are significantly higherprices
- Increased generation ($7 million) largely 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.
- Decreased generation (42% lower), resulting in $32.8 million lower fuel
costs, primarily due to a major turbine overhaul at E.W. Brown Unit 3
and outage at Green River Unit 4higher unit
availability
Power purchased increased $31.6decreased $6 million (95%(12%) in 20052006 primarily due to:
- Increased cost per Mwh (89% higher), resulting in $30.5 millionDecreased volumes purchased ($8 million) largely due to higher costsunit
availability and decreased retail demand
- Increased volumesunit cost of Mwh purchased (3% higher), resulting in $1.1
million higher costs
- Higher purchased power costs from the MISOpurchases ($2 million) due to unit outages totaled
$12.7 millionhigher market
prices
Other operationsoperation and maintenance expenses increased $25.9decreased $5 million (48%(7%) in
2005.
Other operation expenses increased $20.3 million (54%) in 20052006 primarily due to:
- IncreasedDecreased maintenance costs ($3 million) largely due to an outage last
year at Brown Unit 3
- Decreased other power supply expenses due largelycosts ($2 million) related to lower 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 employee benefit costs
- Decreased transmission expenses ($0.9 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 no additional
transmission is necessary.
Maintenance expenses increased $6.4 million (53%) in 2005 primarily due to:
- Increased distribution system costs ($2.4 million), the result of
reclassifying $4.0 million in storm expenses in 2004 from maintenance to
a regulatory asset
- Increased steam generation maintenance ($2.1 million) due to outages 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 $1.1increased $3 million (50%(150%) primarily due to increased
equity in earnings from EEI as a result of EEI selling electricity at
market based rates, effective January 2006.
Interest expense increased $1 million (13%) in 20052006 primarily due to:
- - Increased miscellaneous deductions $1.7 million.
- - Increased mark-to-market gains related to
energy trading contracts
($0.6 million)
In total, interest expense increased $0.6 million (9%) in 2005 primarily
due to:
- - Increased interest costs associated with the interest rate swaps ($1.1
million)
- - Increased interest costs associated with variable rate debt ($0.6
million)
- - Decreased interest costs due to refinancing fixed rate debt with
variable rate debt ($0.4 million)
- - Decreased interest costs due to refinancing first mortgage bonds with
long-term debtborrowing from affiliates ($0.4 million)
- - Decreased interest costs for mark-to-marketFidelia.
A comparison of the interestKU effective income tax rate swaps
($0.1 million)
The weighted average interest rate on variable-rate bonds for the three months ended
SeptemberJune 30, 2006 and 2005 was 2.54%, compared to 1.32% for the
comparable 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.follows:
Three Months Three Months
Ended Ended
Sept.June 30, 2005 Sept.2006 June 30, 20042005
Effective Rate
Statutory federal income tax rate 35.0% 35.0%
State income taxes net of federal benefit 4.6 4.1
Reduction of previous accruals per final
IRS audit (8.9) -
EEI adjustment 6.3 -4.4 5.0
Amortization of investment and other
tax credits (0.9) (1.0)(0.8) (1.4)
EEI dividend (6.1) -
Other differences (0.5) (3.3)(1.9) (2.9)
Effective income tax rate 35.6% 34.8%30.6% 35.7%
The reducedEEI dividend in the second quarter of 2006 reflects a tax benefit
associated with the receipt of dividends from KU's investment in EEI. The
change in amortization of investment tax credits and other differences for 2005 is
largely attributable to the recognitionchange in the levels 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.
Ninepre-tax income.
Six Months Ended SeptemberJune 30, 2005,2006, Compared to
NineSix Months Ended SeptemberJune 30, 20042005
LG&E Results:
LG&E's net income increased $29.9decreased $12 million (40%(19%) for the ninesix months ended SeptemberJune
30, 2005,2006, as compared to the ninesix months ended SeptemberJune 30, 2004,2005, primarily due
to the full period effect of the increase in electriclower electricity and natural gas base rates effective July 1, 2004 increased electricretail and wholesale sales volumes,
due to warmer summer weatherhigher maintenance costs and higher wholesale sales.interest expense.
A comparison of LG&E's revenues for the ninesix months ended SeptemberJune 30, 2005,2006,
with the ninesix months ended SeptemberJune 30, 2004,2005, 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$15 $73
Merger surcredit 1 -
Earnings sharing mechanism (12.3)Weather normalization - LG&E/KU merger surcredit (1.3) -
Rates and rate structure 25.1 4.92
Variation in sales volume and other 22.4 (8.9)(8) (31)
Total retail sales 60.9 8.48 44
Wholesale sales 56.1 9.2(32) (16)
Other 6.4 -2 1
Total $123.4 $17.6$(22) $29
Electric revenues increased $123.4decreased $22 million (20%(5%) in 20052006 primarily due to:
- - HigherDecreased wholesale revenues ($32 million) largely due to an increase10% lower
volumes
- Decreased retail electric volumes delivered ($8 million) resulting from
a 10% decrease in rates and a changecooling degree days in rate
structure ($25.1 million), relatedthe first six months of 2006
compared to the rate case order which took effect
on July 1, 2004same period in 2005 and an 12% decrease from the
20-year average
- - Higher sales volumesIncreased fuel costs billed to customers through the fuel adjustment
clause ($32.7 million) due to weather
- - Higher fuel supply adjustments ($22.715 million) due to higher costcosts of fuel used for generationcoal and purchased powernatural gas
- - Wholesale sales increased $56.1 million
- Higher wholesaleIncreased miscellaneous revenues ($43.02 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$29 million (7%(13%) in 20052006 primarily due to:
- - Higher revenues due to an increase ($12.4 million) in recovery of
higher naturalIncreased gas pricessupply costs billed to customers through the gas supply
clauseadjustment ($73 million) due to higher natural gas costs
- Increased weather normalization revenues ($2 million) due to warmer
weather
- HigherDecreased retail gas volumes delivered ($31 million) resulting from a
10% decrease in heating degree days in the first six months of 2006
compared to the same period in 2005 and an 12% decrease from the
20-year average
- Decreased wholesale revenues ($9.216 million) due to 3% higher sales prices
and 1% higheras a result of 7% lower
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 volumesdemand from wholesale customers
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 increasesIncreases or decreases in
the cost of fuel and natural gas supply are reflected in LG&E's electric
and natural gas retail rates, through the fuel adjustment clause and gas
supply clause, subject to the approval of the Kentucky Commission.
Fuel for electric generation increased $53.3$6 million (34%(5%) in 20052006 primarily
due to:
- Increased unit cost per Btu (28% higher), resulting in $45.1 millionof fuel burned ($13 million) due to higher fuel
costs. Fuel costs are significantly higherprices
- Decreased generation ($5 million) due to the MISO's
dispatch of gas-fired units committed by the MISO's Reliability
Assessmentlower wholesale and Commitment processretail
sales volumes
Power purchased decreased $13 million (19%) in the real-time market.2006 primarily due to:
- Decreased volumes purchased ($22 million) due to lower wholesale and
retail sales
- Increased generation (5% higher), resulting in $8.2unit cost of purchases ($9 million) due to higher market
prices
Gas supply expenses increased $29 million higher fuel
costs
Power purchased increased $35.7 million (54%(17%) in 20052006 primarily due to:
- Increased unit cost per Mwh (43%), resulting in $30.2 million higher costsof natural gas purchased ($69 million)
- Increased volumeDecreased volumes of power purchased (8%), resulting in $5.5 million
higher costs
- Higher purchased power costs fromnatural gas delivered into the MISOdistribution
system ($40 million) due to unit outages totaled
$9.8 million
Gas supplymilder weather
Other operation and maintenance expenses increased $9.6$4 million (5%(3%) in 20052006
primarily due to:
- Increased cost of purchases for wholesale salessteam maintenance ($8.33 million) largely due to the outage at
Mill Creek Unit 4
- Increased cost per MCFdistribution maintenance ($1.62 million) - Decreased volume of gas delivereddue to the distribution system ($0.4
million)
Other operations and maintenance expenseshigher storm
restoration costs
Interest expense increased $0.3$2 million (less than
1%(11%) in 2005.
Other operation expenses increased $0.7 million (less than 1%) in 20052006 primarily due to:
- Increased power supply expensesinterest rates on variable rate debt ($10.83 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
scrubber reactant expenses
- Increased gas storage losses ($1.4 million) due to the increased unit
cost of natural gas
- Decreased transmission expenses ($9.0 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.
- Decreased distribution costs ($4.5 million) due to significantly 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 $7.0 million (8%) primarily due to
additional plant in service.
Other expense - net decreased $2.9 million 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 increased $2.2 million (9%) in 2005 primarily
due to:
-
- Increased interest on variable-rate debttax deficiencies ($4.91 million)
-
- Increased interest rates on money pool debtborrowing ($0.61 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 Fideliathe swaps ($0.82 million)
-
- Decreased interest due to refinancing fixed rate debt with variable
rate debt ($0.5 million)
- - Decreased interest on income taxes ($0.31 million)
The weighted average interest rate on variable-rate bonds for the ninesix
months ended SeptemberJune 30, 2005,2006, was 2.36%3.33%, compared to 1.14%2.27% for the comparable
period in 2004.
Variances in2005.
A comparison of the LG&E effective income tax expense are largely attributable to changes in pre-
tax income, reduction of previous accruals per final IRS auditrate for the six months ended
June 30, 2006 and a
reduction in the statutory Kentucky rate.
Nine2005 follows:
Six Months NineSix Months
Ended Ended
Sept.June 30, 2005 Sept.2006 June 30, 20042005
Effective Rate
Statutory federal income tax rate 35.0% 35.0%
State income taxes net of federal benefit 4.3 5.2
Reduction of previous accruals per final
IRS audit (3.4) 0.03.6 4.8
Amortization of investment and other
tax credits (2.0) (2.7) (2.2)
Other differences (1.4) (0.2)(2.6) (2.2)
Effective income tax rate 32.5% 37.3%33.3% 35.4%
State income taxes in 2006 reflect Kentucky Coal Tax credits earned. The
increasedchange in amortization of investment tax benefit incredits and other differences is
largely attributable to the new Internal Revenue Code Section 199 Qualified Production Activities
deduction andchange in the amortizationlevels 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 additional
discussion of income taxes.pre-tax income.
KU Results:
KU's net income decreased $7.8increased $5 million (8%(9%) for the ninesix months ended SeptemberJune 30,
2005,2006, as compared to the ninesix months ended SeptemberJune 30, 2004. The decrease was2005, primarily due
higher operationsearnings from EEI and maintenance
expensesa lower effective income tax rate, which is
partially offset by the increase in base rates effective July 1,
2004,higher transmission costs and higher retail and wholesale sales.interest charges.
A comparison of KU's revenues for the ninesix months ended SeptemberJune 30, 2005,2006, with
the ninesix months ended SeptemberJune 30, 2004,2005, reflects increases and (decreases)
which have been segregated by the following principal causes:
Cause Electric
(in millions) Revenues
Retail sales:
Fuel supply adjustments $77.4$36
Environmental cost recovery surcharge 8.9
Earnings sharing mechanism (13.5)
LG&E/KU merger3
Merger surcredit (1.8)
Rates1
Rate and rate structure 27.62
Variation in sales volume and other 20.1(6)
Total retail sales 118.736
Wholesale sales 57.5(18)
Other (9.9)(1)
Total $166.3$17
Electric revenues increased $166.3$17 million (23%(3%) in 20052006 primarily due to:
- - HigherIncreased fuel supply adjustmentscosts billed to customers through the fuel adjustment
clause ($77.436 million) due to higher costs of coal and natural gas
- Increased environmental cost ofrecovery ($3 million) due to higher ECR
billing rates
- Increased Virginia revenues due to a rate change for increased fuel
used for generation and purchased powerrecovery ($2 million)
- - WholesaleDecreased wholesale sales increased $57.5 million
- Higher wholesale revenues ($39.418 million), primarily largely due to 5% higher
priceslower volumes
- Decreased retail electric volumes delivered ($36.67 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 increaseresulting from
a 9% decrease in rates and a change in rate structure ($27.6 million),
related to the rate 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)cooling degree days in the first quartersix months of 2006
compared to the same period in 2005 ($13.5 million)
- - Lower MISO Day 1 transmission revenue ($6.7 million)
Duringand an 11% decrease from 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.20-year average
Fuel for electric generation comprises a large component of KU's total
operating expenses. KU's electric rates contain a fuel adjustment clause,
whereby increasesIncreases or decreases in the cost of fuel are
reflected in KU's retail electric rates through the fuel adjustment clause,
subject to the approval of the Kentucky Commission, the Virginia State
Corporation Commission and the FERC.
Fuel for electric generation increased $74.1$23 million (34%(13%) in 20052006
primarily due to:
- Increased unit cost per Btu (32% higher), resulting in $70.5 millionof fuel burned ($20 million) due to 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.prices
- Increased generation (2% higher), resulting in $3.5 million($3 million) largely due to higher fuel
costs.unit
availability
Power purchased increased $56.0decreased $6 million (53%(6%) in 20052006 primarily due to:
- Decreased volumes purchased ($18 million) largely due to higher unit
availability and decreased retail demand
- Increased unit cost of purchases ($12 million) due to higher market
prices
Other operation and maintenance expenses increased $7 million (6%) in
2006 primarily due to:
- Increased cost per Mwh (41% higher), resulting in $46.5 million higher
costs.other power supply ($5 million) largely due to MISO Day 2
- Increased volumes of Mwh purchased (9% higher), resulting in $9.4
million higher costs.
- Higher purchased power costs from the MISOtransmission expense ($3 million) largely due to unit outages totaled
$15.5MISO Day 1
Other (income) - net increased $10 million Other operations and maintenance expenses(333%) primarily due to
increased $39.8equity in earnings from EEI as a result of EEI selling
electricity at market based rates, effective January 2006.
Interest expense increased $4 million (24%(29%) in 2005.
Other operation expenses increased $23.3 million (21%) in 20052006 primarily due to:
- Increased power supply costsborrowing from Fidelia ($22.52 million) due largely to MISO Day 2
costs ($22.4 million) administration charges and allocated charges from
the MISO for Day 2 operations
- Increased administrativeborrowing 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 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 increased $17.6 million (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
additional plant in service.
In total, interest expense increased $3.3 million (18%) in 2005 primarily
due to:
- Increased interest costsrates on interest rate swaps ($1.9 million).
- Increased interest on variable ratemoney pool debt
($1.82 million).
- Increased interest costs associated with the mark-to-market
A comparison of the interestKU effective income tax rate swaps ($1.5 million).
- Decreased interest costs due to 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 ninesix months ended
SeptemberJune 30, 2006 and 2005 was 2.39%, compared to 1.16% for the
comparable 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.
Ninefollows:
Six Months NineSix Months
Ended Ended
Sept.June 30, 2005 Sept.2006 June 30, 20042005
Effective Rate
Statutory federal income tax rate 35.0% 35.0%
State income taxes net of federal benefit 4.4 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 (0.6) (0.9)
(1.0)EEI dividend (5.1) -
Other differences (1.4) (2.3)(1.1) (0.6)
Effective income tax rate 36.5% 37.0%32.6% 38.2%
The reducedEEI dividend for the six months ended June 30, 2006, reflects a tax
benefit in other differences for 2005 is attributable toassociated with the recognitionreceipt of a deferred tax liability on the undistributed earningsdividends from the Company'sKU'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.
Liquidity and Capital Resources
LG&E and KU'sThe Companies' 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, 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 KUThe Companies believe that such
sources of funds will be sufficient to meet the needs of the business in
the foreseeable future.
At SeptemberJune 30, 2005, LG&E and KU2006, the Companies were 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. LG&E and KUThe Companies expect to cover
any working capital deficiencies with cash flow from operations, money pool
borrowings and borrowings from Fidelia.
Construction expenditures for the ninesix months ended SeptemberJune 30, 2005,2006 amounted
to $95.0$66 million for LG&E and $76.3$121 million for KU. At LG&E, capital
expenditures include connection ofincluded infrastructure for new customers, ($9.8 million),gas main
replacements/extensions and capital repairs to Mill Creek Unit 4. At KU,
capital expenditures to improve boilerincluded construction of FGD and other generationenvironmental
equipment ($9.6
million), enhancements/upgrades to distribution equipment ($9.6 million),
pollution control facilities ($5.7 million), aat the Ghent generating station and infrastructure for new
transmission line ($2.4
million) and gas main replacements ($2.2 million). At KU, expenditures
included improvements to boiler and other generation equipment ($14.8
million), connection of new customers ($8.4 million), enhancements/upgrades
to distribution equipment ($6.6 million) and pollution control facilities
($3.4 million). The expenditures were financed with internally generated
funds.customers.
LG&E's and KU's cash balancesbalance decreased $1.0$2 million and $0.4 million,
respectively, during the ninesix months ended SeptemberJune
30, 2005, primarily
due to the payment of dividends and2006, largely resulting from repayments of debt and construction
expenditures, partially offset by higherthe payment of
dividends. KU's cash provided by operating
activities.balance decreased $2 million during the six months
ended June 30, 2006, primarily due to increased capital expenditures.
Variations in accounts receivable, inventories and accounts payable and inventories are
generally not significant indicators of LG&E's and KU'sthe Companies' liquidity. Such
variations are primarily attributable to seasonal fluctuations in weather,
which have a direct effect on sales of electricity and natural gas. The
decreasedecreases in LG&E's accounts receivable at LG&E was primarily due to the seasonal
impact of decreased gas sales. The increase in LG&E'sand natural gas stored underground
relatesrelate primarily to an increase inseasonal uses of natural gas.
For information regarding the average unit cost of 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, 2005, LG&E had swaps with a combined
notional value of $211.3 million and KU had one swap with a notional value
of $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 swap effectively converts fixed-
rate obligations on KU's first mortgage bonds Series P to variable-rate
obligations.
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, therefore, no impact on earnings
occurred as a result of the 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, 2005, LG&E's and KU's percentage of debt having a variable
rate, including the impactCompanies' use of interest rate swaps was 47.8% ($419.6
million)to
hedge underlying variable-rate (LG&E) and 45.1% ($344.1 million), respectively.
Underfixed-rate (KU) debt obligations,
see Note 3 of the provisionsNotes to Financial Statements.
See Note 5 of the Notes to Financial Statements for LG&E's variable-rate pollution controlinformation regarding
the Companies' long-term and short-term debt including: accounting
treatment of bonds Series S, T, U, BB, CC, DD and EE, and KU's variable-rate pollution control
bonds Series 10, 12, 13, 14, and 15, the bonds are subject topermitting tender for purchase at the option of the
holder, re-negotiation of revolving credit lines, intercompany debt
transactions and to mandatory tender for purchase
upon the occurrenceissuance and redemption of certain events, causing the bonds to be classified
as current portion of long-term debt in the Balance Sheets. The average
annualized interest rate for these bondsfinancial instruments
during the three and nine months
ending September 30, 2005 was 2.63% and 2.36%, respectively, for LG&E and
2.59% and 2.40%, respectively, for KU.
During June 2005, LG&E renewed five revolving lines of credit with banks
totaling $185 million. There was no outstanding balance under any of these
facilities at September 30, 2005. The Company expects to renew these
facilities prior to their expiration in June 2006.
LG&E, KU and LG&E Energy participate in an intercompany money pool
agreement. Details of the balances at September 30, 2005 and September 30,
2004 were as follows:
Total Money Amount Balance Average
($ in millions) Pool Available Outstanding Available Interest Rate
September 30, 2005:
LG&E $400.0 $56.6 $343.4 3.64%
KU $400.0 $31.8 $368.2 3.64%
September 30, 2004:
LG&E $400.0 $40.7 $359.3 1.60%
KU $400.0 $29.8 $370.2 1.60%
LG&E Energy maintains a revolving credit facility totaling $200 million
with an affiliated company, E.ON North America, Inc., to ensure funding
availability for the money pool. The balance outstanding on this facility
at September 30, 2005 was $65.4 million.
Redemptions and maturities of long-term debt year-to-date through September
30, 2005, are summarized below:
($ in millions)
Principal Secured/
Year Company Description Amount Rate Unsecured Maturity
2005 LG&E Pollution 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 $50.0 7.55% Secured Jun 2025
Issuances of long-term debt year-to-date through September 30, 2005, are
summarized below:
($ in millions)
Principal Secured/
Year Company Description Amount Rate Unsecured Maturity
2005 LG&E Pollution control bonds $40.0 Variable Secured Feb 2035
2005KU Pollution control bonds $13.3 Variable Secured Jun 2035
2005KU Due to Fidelia $50.0 4.735% Unsecured Jul 2015
In May 2005, KU repaid a $26.7 million loan against the cash surrender
value of 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
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.year.
Security ratings as of SeptemberJune 30, 2005,2006, 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 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.
Capitalization ratios at September 30, 2005, and December 31, 2004, follow:
LG&E KU
Sept. 30, Dec. 31, Sept. 30, Dec. 31,
2005 2004 2005 2004
Long-term debt
(including current portion) 30.3% 30.5% 19.4% 22.2%
Long-term debtmade a discretionary contribution to affiliated company
(including current portion) 11.5 14.1 21.2 18.8
Notes payable to affiliated
companies 2.9 3.0 1.7 2.0
Preferred stock 3.6 3.6 2.2 2.2
Common equity 51.7 48.8 55.5 54.8
Total 100.0% 100.0% 100.0% 100.0%
New Accounting Pronouncements
For a discussionthe pension plan of new accounting pronouncements and their impacts on$18 million
in January 2006. LG&E andmade no contributions during 2005. KU see Part I - Item 1, Notesmade no
contributions to Financial Statements, Note 7.the pension plan in 2006 or 2005.
Contingencies
For a description of significant contingencies that may affect LG&E and KU,the
Companies, reference is made to Part I, Item 3, Legal Proceedings in LG&E's and KU'sthe
Companies' Annual Reports on Form 10-K for the year ended December 31,
2004; and2005; to Part I - Item 1 and Part II - Item 1, Legal Proceedings in the
Companies' Quarterly Report on Form 10-Q for the period ended March 31,
2006; and to Notes 2 and 6 of the Notes to Financial Statements Notes 5 and 10,in Part I
- - Item 1, and Part II
- - Item 1, Legal Proceedings herein.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
LG&E's and KU's operations are exposed to market risks 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.
Interest 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'sthe Companies' unswapped variable debt is estimated
at $4.2$4 million and $3.4 million, respectively,each at SeptemberJune 30, 2005.
LG&E's and KU's2006. The Companies' exposure to floating
interest rates did not materially change during the first ninesix months of
2005.2006.
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 $18.0$17 million as of SeptemberJune 30, 2005.2006. 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 $0.8less than $1 million as of SeptemberJune 30,
2005.2006. 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'sThe Companies' 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. LG&E and KUThe Companies
have recognized an additional minimum liability as prescribed by SFAS No.
87, Employers' Accounting for Pensions because the accumulated benefit
obligation exceeds the fair value of their plans' assets. The liabilities
were recorded as a reduction to other comprehensive income, and did not affect
net income. The amount of the liability depends upon the discount rate, the
asset returns and contributions made by the Companies to the plans. If the
fair value of the plans' assets exceeds the accumulated benefit obligation,
the recorded liabilities will be reduced and other
comprehensive income will be
restored in the balance sheet.
A 1% increase or decrease in the assumed discount rate could have an
approximate $39.9$49 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 $26.8$33 million positive or negative
impact to the accumulated benefit obligation of KU.
InLG&E made a discretionary contribution to the pension plan for $18 million
in January 2004,2006. LG&E andmade no contributions during 2005. KU made discretionary contributions to their
pension plans of $34.5 million and $43.4 million, respectively. No
discretionaryno
contributions to the pension plans are currently anticipated
for either LG&Eplan in 2006 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 & Risk Management Activities
LG&E conductsThe Companies conduct 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.they own. 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.as amended. Wholesale sales of excess asset
capacity are treated as normal sales under SFAS No. 133, and SFAS No. 138as amended, 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 KUthe Companies
have been eligible to receive Financial Transmission Rights (FTRs)FTRs from the MISO. FTRs are assigned by the
MISO to market participants for a 12 monthtwelve-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 holderare utilized 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 the MISO at zero cost, however, they can also be bought and
sold. Although FTRs are financial instruments they are not marked to market under
SFAS No. 133derivatives and their fair value is insignificant due to
the lack of liquidity in the forward market.
The table below summarizes LG&E'sfair values of the Companies' energy trading and KU's energy risk management
activities for the three months and nine months ended Septembercontracts as of June 30, 2006 were each approximately $2 million. The fair
values at June 30, 2005, and 2004. Volumes are allocated evenly between LG&E and KU.
Three Months Nine Months
Ended Ended
September 30, September 30,
2005 2004 2005 2004
(in millions)
Fair value of contracts at beginning of
period, net asset/(liability) $ - $ 0.5 $(0.2) $ 0.6
Fair value of contracts when entered
into during the period 0.2 (0.1) 0.2 (0.1)
Contracts realized or otherwise
settled during the period - (0.4) 0.2 (0.7)
Changes in fair value due to
changes in assumptions - 0.1 - 0.3
Fair value of contracts at end of period,
net asset $ 0.2 $ 0.1 $ 0.2 $ 0.1were less than $1 million each. No changes to
valuation techniques for energy trading and risk management activities
occurred during 20052006 or 2004.2005. Changes in market pricing, interest rate and
volatility assumptions were made during all 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$1 million. All contracts outstanding at
SeptemberJune 30, 2005,2006, 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 KUThe Companies maintain policies intended to minimize credit risk and
revalue credit exposures daily to monitor compliance with those policies.
As of SeptemberJune 30, 2005,2006, 100% of the transactions marked-to-market according to
SFAS No. 133trading and risk management commitments
were with counterparties rated BBB-/Baa3 equivalent or better.
Item 4. Controls and Procedures.
LG&E and KUProcedures
The Companies 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 KUThe Companies 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 KUThe Companies are not accelerated filers under the Sarbanes-Oxley Act of
2002 and associated rules (the Act)"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 controlscontrol over
financial reporting. On 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 haveThere has been no other changeschange in the Companies' internal
control over financial reporting that occurred during the fiscal quarter
ended SeptemberJune 30, 2005,2006, that havehas materially affected, or areis reasonably likely
to materially affect, the Companies' internal control over financial
reporting.
Part II. Other Information
Item 1. Legal Proceedings.
For a description of the significant legal proceedings involving LG&E and
KU,the
Companies, reference is made to the information under the following items
and captions of LG&E's and KU'sthe Companies' respective combined Annual Report on Form 10-K10-
K for the year ended December 31, 2004:2005: Item 1, Business; Item 3, Legal
Proceedings; Item 7, Management's Discussion and Analysis of Financial
Condition and Results of Operations; and Item 8, Financial Statements and
Supplementary Data in Note 11.Notes 3 and 10. Reference is also made to the
matters described in Notes 52 and 106 of Part I,1, Item 1 of LG&E's and KU'sthe Companies'
Quarterly Report on Form 10-Q for the three months ended March 31, 2005, June 30,
2005,2006,
and Notes 2 and 6 of the Notes to Financial Statements in Part I, Item 1 of
this 10-Q, respectively.10-Q. Except as described herein, to date, the proceedings reported in
LG&E's and KU'sthe Companies' respective combined Annual Report on Form 10-K have not
materially changed.changed materially.
Other
In the normal course of business, other lawsuits, claims, environmental
actions, and other governmental proceedings arise against LG&E and KU.the Companies.
To the extent that damages are assessed in any of these lawsuits, LG&E and KUthe
Companies believe that their insurance coverage is adequate. Management,
after consultation with legal counsel, does not anticipate that liabilities
arising out of other currently pending or threatened lawsuits and claims
will have a material adverse effect on LG&E's or KU's financial position or
results of operations, respectively.
Item 2. Unregistered Sales1A. Risk Factors.
LG&E and KU currently anticipate withdrawal from the MISO effective
September 1, 2006. The resulting changes to transmission and wholesale
power market structures and prices are not completely estimable and may
result in unforeseen effects on costs or revenues. As required by the
FERC, in connection with their exit, the Companies have engaged two
independent third parties to perform certain oversight and functional
control activities relating to transmission and related activities. The
Companies will save certain MISO membership costs and charges, but will
incur an exit fee and fees related to the new transmission service vendors.
The Companies believe that, over time, the benefits and savings from an
exit of Equity Securitiesthe MISO will outweigh the costs and Useexpenses. However, until
post-MISO market conditions and operations have matured, the effects on
financial condition, liquidity or results of Proceeds
2(c)operations will remain
difficult to fully predict.
See Note 2 of LG&E has an existing $5.875 series&E's and KU's Notes to Financial Statements in Part I, Item
1 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,
2005, leaving 212,500 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 2005
Total number of 12,500 n/a n/a
shares (or units) ($5.875 Pref.)
purchased
Average price $100 n/a n/a
paid per share
(or unit)
Total number of 12,500 n/a n/a
shares (or units) ($5.875 Pref.)
purchased as part
of publicly
announced plans
or programs
Maximum number 212,500 n/a n/a
(or approximate ($5.875 Pref.)
dollar value) of
shares (or units)
that may yet be
purchased under
the plans or
programsthis 10-Q.
Item 5. Other Information.
None.
Item 6. Exhibits.
Applicable to Form
10-Q of
Exhibit
No. LG&E KU Description
314.1 X Loan Agreement dated June 23, 2006 between
Kentucky Utilities Company and Fidelia Corporation. [Filed
as Exhibit 4.1 to KU's Current Report on Form 8-K dated June
23, 2006 and incorporated by reference herein.]
4.2 X Certification - Section 302Copy of Sarbanes-Oxley ActPromissory Note from KU to
Fidelia Corporation, dated as of 2002June 23, 2006. [Filed as
Exhibit 4.2 to KU's Current Report on Form 8-K dated June
23, 2006 and incorporated by reference herein.]
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 or KU have not been filed with the SEC but will be furnished
to the SEC upon request.
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 9, 2005August 14, 2006 /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 9, 2005August 14, 2006 /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)