UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, 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 JuneSeptember 30, 2006
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
Commission Registrant, State of Incorporation, IRS Employer
File Number Address, and Telephone Number IdentificationNumberIdentification Number
1-2893 Louisville Gas and Electric Company 61-0264150
(A Kentucky Corporation)
220 West Main Street
P. O. Box 32010
Louisville, Kentucky 40232
(502) 627-2000
1-3464 Kentucky Utilities Company 61-0247570
(A Kentucky and Virginia Corporation)
One Quality Street
Lexington, Kentucky 40507-1428
(859) 255-2100
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, or a non-accelerated filer. See definition of
"accelerated filer and large accelerated filer" in Rule 12-b2 of the
Exchange Act. (Check one):
Large accelerated filer _____ 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). 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 JulyOctober 31, 2006, all held by E.ON U.S. LLC
Kentucky Utilities Company - 37,817,878 shares, without par value, as of
JulyOctober 31, 2006, all held by E.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 ManagementDOE Department of Energy
ECR Environmental Cost Recovery
EEI Electric Energy, Inc.
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
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
FTR Financial Transmission Rights
IMEA Illinois Municipal Electric Agency
IMPA Indiana Municipal Power Agency
IRS Internal Revenue Service
Kentucky Commission Kentucky Public Service Commission
KU Kentucky Utilities Company
LIBOR London Interbank Offer Rate
LG&E Louisville Gas and Electric Company
MISO Midwest Independent Transmission System
Operator,Inc.
Moody's Moody's Investor Services, Inc.
Mw Megawatts
NOx Nitrogen Oxide
OMU Owensboro Municipal Utilities
PUHCA 1935 Public Utility Holding Company Act of 1935
PUHCA 2005 Public Utility Holding Company Act of 2005
RSG MWP Revenue Sufficiency Guarantee Make Whole Payment
S&P Standard & Poor's Rating Services
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards
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
Item 1. Financial Statements (Unaudited)
Louisville Gas and Electric Company
Statements of Income 1
Statements of Retained Earnings 1
Balance Sheets 2
Statements of Cash Flows 4
Statements of Comprehensive Income 5
Kentucky Utilities Company
Statements of Income 6
Statements of Retained Earnings 6
Balance Sheets 7
Statements of Cash Flows 9
Statements of Comprehensive Income 10
Notes to Financial Statements 11
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 26
Item 3. Quantitative and Qualitative Disclosures About Market Risk 3638
Item 4. Controls and Procedures 3840
PART II
Item 1. Legal Proceedings 39Proceedings. 41
Item 1A.Risk Factors 39Factors. 41
Item 2. Unregistered Sales of Equity Securities and
Use of Proceeds. 41
Item 4. Submission of Matters to a Vote of Security Holders. 42
Item 5. Other Information 3943
Item 6. Exhibits 3944
Signatures 4145
Exhibits 4246
Part I. Financial Information - Item 1. Financial Statements (Unaudited)
Louisville Gas and Electric Company
Statements of Income (Unaudited)
(Millions of $)
Three Months SixNine Months
Ended JuneEnded
September 30, Ended JuneSeptember 30,
2006 2005 2006 2005
OPERATING REVENUES:
Electric $223 $228 $435 $457$269 $284 $704 $741
Gas 54 53 254 22534 35 288 260
Total operating revenues 277 281 689 682303 319 992 1,001
OPERATING EXPENSES:
Fuel for electric generation 70 68 135 12986 80 221 208
Power purchased 26 28 54 6734 81 101
Gas supply expenses 38 36 200 17119 20 219 192
Other operation and maintenance expenses 65 65 143 13970 88 212 227
Depreciation and amortization 31 31 61 6292 93
Total operating expenses 230 228 593 568232 253 825 821
OPERATING INCOME 47 53 96 11471 66 167 180
Other expense(income) - net 1(2) - 1(1) -
Interest expense (Note 3) 8 6 6 13 1222 17
Interest expense to affiliated
companies (Note 8) 3 3 7 69 9
INCOME BEFORE INCOME TAXES 37 44 75 9662 57 137 154
Federal and state income taxes 12 16 25 3422 15 47 50
NET INCOME $25 $28 $50 $62$40 $42 $90 $104
The accompanying notes are an integral part of these financial statements.
Statements of Retained Earnings (Unaudited)
(Millions of $)
Three Months SixNine Months
Ended JuneEnded
September 30, Ended JuneSeptember 30,
2006 2005 2006 2005
Balance at beginning of period $605 $538$609 $555 $621 $534
Net income 25 28 50 6240 42 90 104
Subtotal 630 566 671 596649 597 711 638
Cash dividends declared on stock:
Cumulative preferred 1 1- - 2 2
Common 20 10 6035 - 95 39
Subtotal 21 11 6235 - 97 41
Balance at end of period $609 $555 $609 $555$614 $597 $614 $597
The accompanying notes are an integral part of these financial statements.
Louisville Gas and Electric Company
Balance Sheets
(Unaudited)
(Millions of $)
ASSETS JuneSeptember December
30, December 31,
2006 2005
Current Assets:
Cash and cash equivalents $ 5 $ 7$5 $7
Accounts receivable - less reserves of $1
million as of June 30,2006September 30, 2006 and
December 31, 2005 123111 231
Accounts receivable from affiliated
companies (Note 8) 1926 36
Materials and supplies:
Fuel (predominantly coal) 5343 39
Gas stored underground 3087 125
Other materials and supplies 29 28
Prepayments and other current assets 48 6
Total current assets 263309 472
Other property and investments - less reserves
of less than $1 million as of June 30, 2006
and December 31, 2005 1 1
Utility plant:
At original cost 4,0774,108 4,049
Less: reserve for depreciation 1,5231,541 1,509
Net utility plant 2,5542,567 2,540
Deferred debits and other assets:
Restricted cash 79 10
Unamortized debt expense 8 8
Regulatory assets (Note 2) 7893 84
Intangible pension asset 31 31
Other assets 36 31- 1
Total deferred debits and other assets 129 133141 134
Total assets $2,947$3,017 $3,146
The accompanying notes are an integral part of these financial statements.
Louisville Gas and Electric Company
Balance Sheets (cont.)
(Unaudited)
(Millions of $)
LIABILITIES AND EQUITY JuneSeptember December
30, December 31,
2006 2005
Current liabilities:
Current portion of long-term debt $248 $248
Notes payable to affiliated companies (Note
5 and Note 8) 152 141
Accounts payable 8086 141
Accounts payable to affiliated companies
(Note 8) 4743 52
Accrued income taxes 98 6
Customer deposits 18 17
Other current liabilities 2629 15
Total current liabilities 429484 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 2019 20
Total long-term debt 573572 573
Deferred credits and other liabilities:
Accumulated deferred income taxes - net 312315 322
Investment tax credit, in process of
amortization 4039 42
Accumulated provision for pensions and
related benefits 129131 143
Customer advances for construction 10 10
Asset retirement obligation 2728 27
Regulatory liabilities (Note 2):
Accumulated cost of removal of utility
plant 225230 219
Regulatory liability deferred income
taxes 4447 42
Other regulatory liabilities 4241 20
Other liabilities 2328 31
Total deferred credits and other
liabilities 852869 856
Cumulative preferred stock
70 70
Common equity:
Common stock, without par value -
Authorized 75,000,000 shares,
outstanding 21,294,223 shares 424 424
Additional paid-in capital 40 40
Accumulated comprehensive loss (50)(56) (58)
Retained earnings 609614 621
Total common equity 1,0231,022 1,027
Total liabilities and equity $2,947$3,017 $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 $)
SixNine Months Ended
JuneSeptember 30,
2006 2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $50 $62$ 90 $104
Items not requiring cash currently:
Depreciation and amortization 61 6292 93
Deferred income taxes (13) (11)(3) (8)
VDT amortization 7 1523
Other (3) (3)(4)
Changes in current assets and liabilities:
Accounts receivable 108 41120 68
Accounts receivable from affiliated
companies 17 (15)10 (32)
Fuel (14) (6)(4) (7)
Gas stored underground 95 5838 (29)
Other changes in current assets 1 -(3) (13)
Accounts payable (61) (39)(55) 1
Accounts payable to affiliated companies (5) 29(9) 26
Accrued income taxes 32 (6)
Other changes in current liabilities 12 (7)15 (16)
Pension funding (Note 4) (18) -
Gas supply clause receivable, net 31 232 (3)
MISO exit (13) -
Other (10) (8) (3)
Net cash provided by operating
activities 263 179288 189
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction expenditures (66) (51)(104) (95)
Change in restricted cash 3 (2)1 (1)
Net cash used for investing activities (63) (53)(103) (96)
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of long-term debt - 39
Retirement of long-term debt (1) (40)
Repayment of long-term borrowings from
affiliated company (Note 8) - (50)
Repayment of short-term borrowings from
affiliated company (Note 5) (140) (37)(89) (2)
Payment of dividends (62)(97) (41)
Net cash used for financing activities (202) (128)(187) (94)
CHANGE IN CASH AND CASH EQUIVALENTS (2) (2)(1)
CASH AND CASH EQUIVALENTS AT BEGINNING OF
PERIOD 7 7
CASH AND CASH EQUIVALENTS AT END OF PERIOD $5 $5$6
The accompanying notes are an integral part of these financial statements.
Louisville Gas and Electric Company
Statements of Comprehensive Income
(Unaudited)
(Millions of $)
Three Months SixNine
Months Ended JuneMonths Ended
September 30, Ended JuneSeptember 30,
2006 2005 2006 2005
Net income $25 $28 $50 $62$40 $42 $90 $104
Income Taxes - Minimum Pension
Liability - - - (1)
Gain (loss) on derivative instruments
and hedging activities - net of tax
benefit (expense) of $(2)$4 million,
$5$(3) million, $(5)$(1) million and $4$1
million, respectively (Note 4) 3 (8) 8 (6) 5 2 (1)
Comprehensive income (loss), net of
tax 3 (8) 8 (7)(6) 5 2 (2)
Comprehensive income $28 $20 $58 $55$34 $47 $92 $102
The accompanying notes are an integral part of these financial statements.
Kentucky Utilities Company
Statements of Income
(Unaudited)
(Millions of $)
Three Months SixNine Months
Ended JuneEnded
September 30, Ended JuneSeptember 30,
2006 2005 2006 2005
OPERATING REVENUES $276 $265 $569 $552$342 $347 $911 $899
OPERATING EXPENSES:
Fuel for electric generation 100 84 195 172130 119 325 290
Power purchased 44 50 90 9649 65 140 161
Other operation and maintenance
expenses 63 68 133 12680 195 207
Depreciation and amortization 29 29 57 5828 86 86
Total operating expenses 236 231 475 452271 292 746 744
OPERATING INCOME 40 34 94 10071 55 165 155
Other (income) - net (5)(13) (2) (13) (3)(26) (5)
Interest expense (Note 3) 4 4 7 73 11 10
Interest expense to affiliated
companies (Note 5 and Note 8) 56 4 11 717 12
INCOME BEFORE INCOME TAXES 36 28 89 8974 50 163 138
Federal and state income taxes 11 10 29 3425 18 54 51
NET INCOME $25 $18 $60 $55$49 $32 $109 $87
The accompanying notes are an integral part of these financial statements.
Statements of Retained Earnings
(Unaudited)
(Millions of $)
Three Months SixNine Months
Ended JuneEnded
September 30, Ended JuneSeptember 30,
2006 2005 2006 2005
Balance at beginning of period $753 $666$778 $674 $718 $660
Net income 25 18 60 5549 32 109 87
Subtotal 778 684 778 715827 706 827 747
Cash dividends declared on stock:
Cumulative preferred - 1 - - 12
Common - 10 - 4050
Subtotal - 1011 - 4152
Balance at end of period $778 $674 $778 $674$827 $695 $827 $695
The accompanying notes are an integral part of these financial statements.
Kentucky Utilities Company
Balance Sheets
(Unaudited)
(Millions of $)
JuneSeptember December
ASSETS 30, December 31,
ASSETS
2006 2005
Current assets:
Cash and cash equivalents $5 $7
Restricted cash 1015 22
Accounts receivable - less reserves of $2
million as of JuneSeptember 30, 2006
and December 31, 2005 113118 135
Accounts receivable from affiliated
companies (Note 8) 1814 32
Materials and supplies:
Fuel (predominantly coal) 7559 55
Other materials and supplies 35 32
Prepayments and other current assets 98 5
Total current assets 265254 288
Other property and investments -
less reserves of less than $1 million as
of June 30,2006September 30, 2006 and December 31, 2005 2224 23
Utility plant:
At original cost 3,9444,057 3,847
Less: reserve for depreciation 1,5321,552 1,508
Net utility plant 2,4122,505 2,339
Deferred debits and other assets:
Unamortized debt expense 56 5
Regulatory assets (Note 2) 70101 58
Cash surrender value of key man life
insurance 34 32
Intangible pension asset 8 8
Other assets 9 11- 3
Total deferred debits and other assets 118149 106
Total assets $2,817$2,932 $2,756
The accompanying notes are an integral part of these financial statements.
Kentucky Utilities Company
Balance Sheets (cont.)
(Unaudited)
(Millions of $)
June 30,September December 31,
LIABILITIES AND EQUITY 30, 31,
2006 2005
Current liabilities:
Current portion of long-term debt $140 $123
Notes payable to affiliated companies (Note
5 and Note 8) 5259 70
Accounts payable 8191 89
Accounts payable to affiliated companies
(Note 8) 6076 53
Accrued income taxes - 13
Customer deposits 18 17
Other current liabilities 2430 18
Total current liabilities 375414 383
Long-term debt:
Long-term debt (Note 5) 186203 240
Long-term debt to affiliated company (Note
5 and Note 8) 433 383
Total long-term debt 619636 623
Deferred credits and other liabilities:
Accumulated deferred income taxes - net 277279 274
Accumulated provision for pensions and
related benefits 97101 92
Asset retirement obligation 28 27
Regulatory liabilities (Note 2):
Accumulated cost of removal of
utility plant 288294 281
Regulatory liability deferred income
taxes 2219 23
Other regulatory liabilities 1011 11
Other liabilities 19 20
Total deferred credits and other
liabilities 741751 728
Common equity:
Common stock, without par value -
Authorized 80,000,000 shares, outstanding
37,817,878 shares 308 308
Additional paid-in capital 15 15
Accumulated comprehensive loss (19) (19)
Retained earnings 765812 704
Undistributed subsidiary earnings 1315 14
Total retained earnings 778827 718
Total common equity 1,0821,131 1,022
Total liabilities and equity $2,817$2,932 $2,756
The accompanying notes are an integral part of these financial statements.
Kentucky Utilities Company
Statements of Cash Flows
(Unaudited)
(Millions of $)
SixNine Months Ended
JuneSeptember 30,
2006 2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $60 $55$109 $87
Items not requiring cash currently:
Depreciation and amortization 57 5886 86
Deferred income taxes 2 (4)1 6
VDT amortization 3 69
Other 6 (5)10 (3)
Changes in current assets and liabilities:
Accounts receivable 17 22 26
Accounts receivable from affiliated
companies 14 (21)18 (29)
Fuel (20) (5)(4) 2
Other changes in current assets (7) 3(6) (4)
Accounts payable (8) (20)2 (10)
Accounts payable to affiliated companies 7 3523 25
Accrued income taxes (13) (2)(6)
Other changes in current liabilities 7 (12)13 (13)
Fuel adjustment clause receivable, net (15) (13)(24) (18)
MISO exit (20) -
Other (4) 2(7) 4
Net cash provided by operating activities 111 103208 158
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction expenditures (121) (44)(236) (77)
Change in restricted cash 12 -7 (13)
Net cash used for investing activities (109) (44)(229) (90)
CASH FLOWS FROM FINANCING ACTIVITIES:
Retirement of first mortgage bonds (Note 5) (36) (50)
Short-term borrowings from affiliated company
(Note 5) - 58Issuance of pollution control bonds 16 14
Long-term borrowings from affiliated company
(Note 5) 50 -50
Repayment of short-term borrowings from
affiliated company (Note 5) (18) -(11) (3)
Repayment of other borrowings - (27)
Payment of dividends - (41)(52)
Net cash used for financing activities (4) (60)19 (68)
CHANGE IN CASH AND CASH EQUIVALENTS (2) (1)-
CASH AND CASH EQUIVALENTS AT BEGINNING OF
PERIOD 7 54
CASH AND CASH EQUIVALENTS AT END OF PERIOD $5 $4
The accompanying notes are an integral part of these financial statements.
Kentucky Utilities Company
Statements of Comprehensive Income
(Unaudited)
(Millions of $)
Three Months SixNine Months
Ended JuneEnded
September 30, Ended JuneSeptember 30,
2006 2005 2006 2005
Net income $25 $18 $60 $55$49 $32 $109 $87
Comprehensive income, net of tax - - - -
Comprehensive income $25 $18 $60 $55$49 $32 $109 $87
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 the
Companies. The common stock of each Company is wholly-owned by 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 the Companies' Annual Reports on Form 10-K for the year ended
December 31, 2005, for information relevant to the accompanying
financial statements, including information as to the significant
accounting policies of the Companies.
New Accounting PronouncementsKU INVESTMENT IN EEI
Other property and investments on the KU balance sheet consists largely
of KU's investment in EEI, which was $17 million at September 30, 2006
and $16 million at December 31, 2005. KU owns 20% of the common stock
of EEI, which owns and operates a 1,000-Mw generating station in
southern Illinois. Prior to 2006, KU was entitled to take 20% of the
available capacity of the station under a pricing formula comparable to
the cost of other power generated by KU. This contract governing the
purchases from EEI terminated on December 31, 2005. Subsequent to
December 31, 2005, EEI has sold power under general market-based
pricing and terms, generating increases in EEI earnings in 2006.
KU's investment in EEI is accounted for under the equity method of
accounting and, accordingly, as EEI earnings have increased
significantly in 2006, KU's equity in EEI earnings has also increased
and is recorded in other income on the income statement. For the three
and nine months ended September 30, 2006, KU's equity in EEI earnings
was $9 million and $22 million, respectively, as compared with less
than $1 million and $2 million, respectively, for the comparable
periods in 2005.
NEW ACCOUNTING PRONOUNCEMENTS
In July 2006, the FASB 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.
In September 2006, the FASB issued SFAS No. 157, Fair Value
Measurements. SFAS No. 157 is effective for fiscal years ending after
November 15, 2007. This statement defines fair value, establishes a
framework for measuring fair value in generally accepted accounting
principles, and expands disclosures about fair value measurements. The
Companies are now analyzing the future impacts of SFAS No. 157 on
results of operations and financial condition.
In September 2006, the FASB issued SFAS No. 158, Employers' Accounting
for Defined Benefit Pension and Other Postretirement Plans. SFAS No.
158 is effective for fiscal years ending after December 15, 2006 for
employers with publicly traded equity securities, and for employers
controlled by entities with publicly traded equity securities, which is
applicable for LG&E and KU. This statement requires employers to
recognize the over-funded or under-funded status of a defined benefit
postretirement plan as an asset or a liability in the balance sheet and
to recognize changes in that funded status in the year in which the
changes occur through comprehensive income. This statement also
requires employers to measure the funded status of a plan as of the
date of its year-end balance sheet. This statement amends SFAS No. 87,
Employers' Accounting for Pensions, SFAS No. 88, Employers' Accounting
for Settlements and Curtailments of Defined Benefit Pension Plans and
for Termination Benefits, SFAS No. 106, Employers' Accounting for
Postretirement Benefits Other than Pensions and SFAS No. 132,
Employers' Disclosures about Pensions and Other Postretirement
Benefits. The Companies are now analyzing the future impacts of SFAS
No. 158 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 JuneSeptember 30, 2006 and December 31, 2005:
Louisville Gas and Electric Company
(Unaudited)
JuneSeptember December
(in millions) 30, December 31,
(in millions)
2006 2005
ARO $21$23 $20
Gas supply adjustments 21 29
Unamortized loss on bonds 20 21
Gas supply adjustments 18 29
MISO exit 13 -
FAC 10 -
ECR 65 2
FAC 5 -
VDT - 7
Other 54 5
Total regulatory assets $78$93 $84
Accumulated cost of removal of utility
plant $225$230 $219
Deferred income taxes - net 4447 42
Gas supply adjustments 4038 17
Other 23 3
Total regulatory liabilities $311$318 $281
In addition to generally earning applicable returns on approved assets,
LG&E currently earns a return on all regulatory assets, excluding the
ARO regulatory assets, gas supply adjustments, MISO exit 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 raterecovery mechanisms with recovery within twelve months.
The MISO exit amount represents the fee accrued at September 30, 2006
to record the applicable costs relating to the withdrawal from MISO
membership. LG&E expects to seek recovery of this asset in future
proceedings with the Kentucky Commission. See Note 9, Subsequent
Events.
The increase in the gas supply adjustments net liability for the nine
months ended September 30, 2006 reflects over-recovery of gas supply
costs, which are in the process of being refunded to customers. The
increase in FAC for the periodnine months ended September 30, 2006 is due to
the higher cost of fuel being passed on to customers. The decrease in
VDT for the periodnine months ended September 30, 2006 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 JuneSeptember 30, 2006 and December 31, 2005:
Kentucky Utilities Company
(Unaudited)
JuneSeptember December
(in millions) 30, December 31,
(in millions)
2006 2005
ARO $21$22 $20
Unamortized loss on bonds 10 11 11
MISO exit 20 -
FAC 36 12
ECR 56 4
FAC 27 12
VDT - 3
Other 76 8
Total regulatory assets $70$101 $58
Accumulated cost of removal of utility
plant $288$294 $281
Deferred income taxes - net 2219 23
Other 1011 11
Total regulatory liabilities $320$324 $315
In addition to generally earning applicable returns on approved assets,
KU currently earns a return on all regulatory assets, excluding the ARO
regulatory assets, MISO exit 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 FAC has a separate recovery mechanism with recovery within twelve
months. The MISO exit amount represents the fee accrued at September
30, 2006 to record the applicable costs relating to the withdrawal from
MISO membership. KU expects to seek recovery of this asset in future
proceedings with the Kentucky Commission. See Note 9, Subsequent
Events.
The increase in FAC for the periodnine months ended September 30, 2006 is due
to the higher cost of fuel being passed on to customers. The decrease
in VDT for the periodnine months ended September 30, 2006 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 rate 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
the period covered by the rate cases. Concurrently, the AG had filed
pleadings with the Kentucky Commission requesting rehearing of the rate
cases on computational components of the increased rates, including
income taxes, cost of removal and depreciation amounts. In August 2004,
the Kentucky Commission denied the AG's rehearing request on the cost
of removal and depreciation issues and granted rehearing on the income
tax component. The Kentucky Commission 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 concludesconcluded that no improper communications occurred
during the rate proceeding. The order further established a procedural
schedule through the first quarter of 2006 for considering the sole
issue for which rehearing was granted: state income tax rates used in
calculating the granted rate increase. 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 of the AG's report and
investigation.
MISO EXIT
Following receipt of applicable FERC, Kentucky Commission and other
regulatory orders, LG&E and KU withdrew from the MISO effective
September 1, 2006. Specific proceedings regarding the costs and
benefits of the MISO and exit matters had been underway since July
2003. Since their exit from the MISO, the Companies have been
operating under a FERC-approved open access-transmission tariff
providing for a return on equity of 10.88%. The Companies have further
contracted with the Tennessee Valley Authority to act as their
Reliability Coordinator and Southwest Power Pool, Inc. to function as
the Companies' Independent Transmission Operator, pursuant to FERC
requirements, with respect to transmission matters.
The Companies and the MISO have agreed upon overall calculation methods
for the contractual exit fee to be paid by the Companies following
their withdrawal. In September 2006, the MISO submitted an initial
invoice for approximately $33 million for the exit fee, which the
Companies have allocated approximately $13 million to LG&E and $20
million to KU. The Companies and the MISO continue to discuss the
specifics of the exit fee calculation. The outcome of these discussions
and the eventual settlement of any disputed amount cannot be estimated
at this time. Orders of the Kentucky Commission approving the
Companies' exit from the MISO have authorized the establishment of a
regulatory asset for the exit fee, subject to adjustment for possible
future MISO credits, and a regulatory liability for certain revenues
associated with former MISO Schedule 10 charges, which may continue to
be collected via base rates. The treatment of the regulatory asset and
liability will be determined in the Companies' next rate cases,
however, the Companies historically have received approval to recover
regulatory assets and liabilities.
See also Note 9, Subsequent Events.
FAC
On February 15, 2006, KU filed an application with the Virginia
Commission seeking approval of an increase of approximately $6 million
in its fuel cost factor to reflect higher fuel costs incurred during
2005, and anticipated to be incurred in 2006. The Virginia Commission
approved KU's request on April 5, 2006.
In July 2006, the Kentucky Commission initiated routine periodic
reviews of the FAC for the Companies. The Kentucky Commission issued
Orders for both Companies on November 8, 2006, approving the charges
and credits billed through the FAC during the review period.
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$324 million ($6648 million for LG&E and $325$276 million
for KU), of which $229$226 million is for the Air Quality Control System at
Trimble County Unit 2 ($4443 million for LG&E and $185$183 million for KU)
and $95 million is for KU's Ghent Unit 2 Selective Catalytic Reduction.
The estimated total capital cost of the upgrades is $364 million. 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 areHearings have been
completed and the Kentucky Commission's Order is expected to be completed before the end of the third quarter of 2006.year-
end.
In December 2004, KU and LG&Ethe Companies 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
compliance plan to allow recovery of new and additional environmental
compliance facilities. The estimated capital cost of the additional
facilities for 2006 through 2008 is approximately $720$840 million ($40
million for LG&E and $680$800 million for KU), of which $560$680 million is for
the KU FGDs at Brown and Ghent. 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,In
October 2006, KU filed with the VirginiaKentucky Commission commenced an application seeking approvalinquiry into
elements of an increase inKU's planned construction of one of 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.three new FGDs at
the Ghent generating station. See also Note 9, Subsequent Events.
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 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 - The MISO filed its FERC-required TEMT. The Companies
and other owners filed opposition to certain conditions of the TEMT
and sought to delay the implementation. Such opposition was denied
by the FERC.
- December 2004 - 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 real-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 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 Southwest 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 the Companies as calculated under the
approved methodology;
- the Companies' anticipated arrangements with Southwest Power
Pool, Inc. and Tennessee 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 Companies' proposed Open Access Transmission Tariff as
revised to address 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
March 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.
- May 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 exit fee, subject to adjustment for possible future
MISO credits, and a regulatory liability for certain revenues which
may be collected via current base rates as a result of the existing
inclusion of amounts associated with certain MISO Schedule 10
charges.
- July 2006 - the Kentucky Commission issued an order approving the
Companies' contractual arrangements with TVA and SPP to provide
services to the Companies as reliability coordinator and
independent transmission organization, respectively, upon a
withdrawal 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 Companies' steps, including
compliance and other 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, 2006. 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 exit and transition.
On or about the date of a completed 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 up to approximately $41
million (allocated approximately $16 million for LG&E and $25 million
for KU). The ultimate amount would be determined based upon the actual
timing and circumstances of exit and, following payment, is subject to
confirmation, correction and true-up, as agreed between the Companies
and the MISO. 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 AuthorityMARKET-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. ShouldUpon the CompaniesCompanies' exit from 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,Additionally, recent FERC decisions in certain 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 evaluate the potential impacts
of the EPAct 2005 and the associated rulemakings and cannot predict
what impact the EPAct 2005, and any uncompleted rulemakings, will have
on their operations or financial position.
3. Financial Instruments
INTEREST RATE SWAPS (hedging derivatives)
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
interest rate swaps as hedge instruments. Financial instruments
designated as cash flow hedges have resulting gains and losses recorded
within comprehensive income and stockholders' equity. Financial
instruments designated as fair value hedges and the underlying hedged
items are periodically marked to market with the resulting net gains
and losses recorded directly into net income. Upon termination of any
fair value hedge, the resulting gain or loss is recorded into net
income.
As of JuneSeptember 30, 2006, LG&E was party to various interest rate swap
agreements with aggregate notional amounts of $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 3.67% at JuneSeptember 30, 2006. The swap
agreements in effect at JuneSeptember 30, 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 $13$3 million for the sixnine months ended JuneSeptember 30, 2006,
recorded in comprehensive income. Upon expiration of these hedges, the
amount recorded in comprehensive income will be reclassified into
earnings. The amounts expected to be reclassified from comprehensive
income to earnings in the next twelve months are immaterial. A deposit
in the amount of $7$9 million, used as collateral for the $83 million
interest rate swap, is classified as restricted cash on LG&E's Balance
Sheet. The amount of the deposit required is tied to the market value
of the swap.
As of JuneSeptember 30, 2006, KU was party to an interest rate swap
agreement with a notional amount of $53 million. Under this swap
agreement, KU paid variable rates based on LIBOR averaging 7.24%7.48%, and
received fixed rates averaging 7.92% at JuneSeptember 30, 2006. The swap
agreement in effect at JuneSeptember 30, 2006 has been designated as a fair
value hedge and matures in 2007. At JuneSeptember 30, 2006, the effect of
marking this financial instrument and the underlying debt to market
resulted in pretax gains recorded in interest expense of less than $1
million.
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 JuneSeptember 30, 2006, KU's debt reflects a mark-to-
marketmark-
to-market adjustment of less than $1 million.
At JuneSeptember 30, 2006, the Companies' percentage of debt having a
variable rate, including the impact of interest rate swaps, was 44%($36448%
($415 million) for LG&E and 47%48% ($378401 million) for KU.
ENERGY TRADING AND RISK MANAGEMENT CONTRACTS (non-hedging derivatives)
The Companies conduct energy trading and risk management activities to
maximize the value of power sales from physical assets they own.
Certain energy trading activities are accounted for on a mark-to-market
basis in accordance with SFAS No. 133, as amended. The mark-to-market
adjustment as of September 30, 2006 generated an increase in other
income for each Company of approximately $2 million during the third
quarter of 2006.
The fair values of the Companies' energy trading and risk management
contracts as of September 30, 2006 were each approximately $4 million,
recorded in other assets on the balance sheets of each Company. The
fair values at September 30, 2005, were less than $1 million each. No
changes to valuation techniques for energy trading and risk management
activities occurred during 2006 or 2005. All contracts outstanding at
September 30, 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.
4. Pension and Other Post-retirement Benefit Plans
The following table provides the components of net periodic benefit
cost for pension and other benefit plans for the three and sixnine months
ended JuneSeptember 30, 2006 and 2005:
Three Months Ended SixNine Months Ended
JuneSeptember 30, JuneSeptember 30,
2006 2005 2006 2005
(in millions) LG&E KU LG&E KU LG&E KU LG&E KU
Pension and Other
Benefit Plans
Components of net
periodicperiod benefit cost
Service cost $2 $2 $1 $2 $3$5 $6 $4 $3 $3$6
Interest cost 6 5 5 6 4 11 8 12 917 13 17 14
Expected return on
plan assets (5)(6) (4) (5) (4) (10) (7) (11) (8)(5) (16) (12) (16) (13)
Amortization of prior
service cost 1 -1 1 - 3 2 1 34 1
Recognized actuarial
loss 1 1 1 1 3 3 2 2 1 1
Total net period benefit
cost $4 $5 $3 $4 $4 $3 $8 $8 $8 $6$12 $12 $11 $10
LG&E made a discretionary contribution to the pension plan of $18
million in January 2006. LG&E made no contributions during 2005. KU
made no contributions to the pension plan in 2006 or 2005.
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. The average annualized interest rate for these bonds during the
sixnine months ending JuneSeptember 30, 2006 was 3.38%3.47% for LG&E and 3.41%3.50% for
KU.
During June 2006, LG&E renewed five revolving lines of credit with
banks totaling $185 million. There was no outstanding balance under any
of these facilities at JuneSeptember 30, 2006. LG&E expects to renew these
facilities prior to their expiration in June 2007.
LG&E, KU and E.ON U.S. participate in an intercompany money pool
agreement. Details of the balances at JuneSeptember 30, 2006 and December
31, 2005 were as follows:
Total Money Average
Pool Amount Balance Average
PoolInterest
Available Outstanding Available Interest Rate
($ in millions)
JuneSeptember 30, 2006:
LG&E $400 $ 1 $399 4.96%52 $348 5.27%
KU $400 $ 52 $348 4.96%59 $341 5.27%
December 31, 2005:
LG&E $400 $141$ 141 $259 4.21%
KU $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 JuneSeptember 30, 2006, was $64$52 million.
Redemptions and maturities of long-term debt year-to-date through
JuneSeptember 30, 2006, are summarized below:
($ in millions)
Principal
Amount Secured/
Year Company Description Amount(in millions) Rate Unsecured Maturity
2006 LG&E Mand. Red. Pref.
Stock $1 5.875% Unsecured Jul 2006
2006 KU First mortgage
bonds $36 5.99% Secured Jan 2006
Issuances of long-term debt year-to-date through JuneSeptember 30, 2006,
are summarized below:
($ in millions)
Principal
Amount Secured/
Year Company Description Amount(in millions) Rate Unsecured Maturity
2006 KU Fidelia note $50 6.33% Unsecured Jun 2036
2006 KU Pollution
control bonds $17 Variable Secured Jun 2036
6. Commitments and Contingencies
Except as may be discussed in this Quarterly Report on Form 10-Q
(including Note 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, 2005 (including in Notes 3 and 10 to the financial
statements of the Companies contained therein) and Quarterly ReportReports on
Form 10-Q for the quarterquarters ended March 31, 2006 and June 30, 2006
(including in Notes 2 and 6 to the financial statements contained
therein). See the above-
referencedabove-referenced notes in the Companies' Annual
Report on Form 10-K and Quarterly ReportReports on Form 10-Q 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")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 selectIn September and certify feasible and suitable qualifying projects, in
their discretion, from among the applicant group during the late fall
of 2006. If selected,October 2006, the
Companies would submit an additionalsubmitted a follow-on application and additionally
requested information to the Internal Revenue Service ("IRS").IRS. IRS action on such applications
would thereafteralso be expected to occur during the fourth quarter of 2006. If, and toTo
the extent the Companies' applications areapplication is ultimately accepted by the
Companies could thereafter
claim allocatedIRS, federal income tax credits may be claimed on eligible
expenditures, as they occur over time, relating to the Trimble County Unit 2 project.incurred.
LOUISVILLE DOWNTOWN ARENA
In August 2006, LG&E has been asked byand the Louisville Arena Authority, Inc., a non-
profit corporation (the "Authority"), entered into a non-binding
Memorandum of Understanding ("MOU") 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 intentMOU contemplates the parties
working in good faith toward completing definitive documents regarding
the arena transactions. LG&E estimatestransaction. The MOU notes that the cost of relocating the
LG&E facilities will be approximately $63 million and LG&E expects to
requestcommits 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, includingAssuming completion of
definitive documents, and regulatory approvals necessarythe transfer of the property to the Authority is
anticipated to occur before the end of 2008. In September 2006, the
Kentucky Commission approved LG&E's application for authority to
transfer applicable property as part of the transactions
contemplated.arena transaction. In
November 2006, the parties completed definitive documents relating to
the arena transactions. See also Note 9, Subsequent Events.
OMU LITIGATION
In May 2004, the City of Owensboro, Kentucky and Owensboro Municipal
Utilities (collectively "OMU") commenced a suit now removed to the U.S.
District Court for the Western District of Kentucky, against KU
concerning a long-term power supply contract (the "OMU Agreement") with
KU. The dispute involves interpretational differences regarding issues
under the OMU Agreement, including various payments or charges between
KU and OMU and rights concerning excess power, termination and
emissions allowances. The complaint seeks approximately $6 million in
damages for periods prior to 2004 and OMU is expected to claim further
amounts for later-occurring periods. OMU has additionally requested
injunctive and other relief, including a declaration that KU is in
material breach of the contract. KU has filed an answer in that court
denying the OMU claims and presenting counterclaims. During 2005, the
FERC declined KU's application to exercise exclusive jurisdiction over
the matter. In July 2005, the district court resolved a summary
judgment motion made by KU in OMU's favor, ruling that a contractual
provision grants OMU the ability to terminate the contract without
cause upon four years' prior notice, for which ruling KU retains
certain rights to appeal. At this time the district court case is in
the discovery stage and currently a trial scheduledate of January 2008 has not yet been
established.scheduled. In May 2006, OMU issued a notification of its intent to
terminate the contract in May 2010, without cause, absent any earlier
terminationrelief which may be permitted by the proceeding.
ENVIRONMENTAL MATTERS
In 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 NOx emission limits on their
electric generating units pursuant to the Clean Air Act. The Companies
placed into operation significant NOx controls for their generating
units prior to the 2004 summer ozone season. As of JuneSeptember 30, 2006,
LG&E and KU have incurred total capital costs of approximately $191$187
million and $217$215 million, respectively, to reduce their NOx emissions
to required levels. In addition, the Companies incur additional
operating and maintenance costs in operating the new NOx controls. On
March 10, 2005, the EPA issued the final CAIR which requires
substantial additional reductions in SO2 and NOx emissions from
electric generating units. The CAIR provides for a two-phased reduction
program with Phase I reductions in NOx and SO2 emissions in 2009 and
2010, respectively, and Phase II reductions in 2015. On March 15, 2005,
the EPA issued a related regulation, the final CAMR, which requires
substantial mercury reductions from electric generating units. The CAMR
also provides for a two-phased reduction, with the Phase I target in
2010 achieved as a "co-
benefit""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 total emissions and allowances
can be bought or sold on the open market to 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 $659$809 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$126 million has been incurred through JuneSeptember 30, 2006.
In addition, KU will incur additional operating and maintenance costs
in operating the new SO2 controls.
The Companies are also monitoring several other air quality issues
which may potentially impact coal-fired power plants, including the
EPA's revised air quality standards for ozone and particulate matter
and measures to implement the EPA's Clean Air Visibility Rule.
During 2006, the EPA and state environmental authorities agreed to a
tentative general settlement with KU and other parties regarding
recovery of remediation and other costs relating to the former Tindall
transformer scrap yard. KU's share of such overall settlement is less
than $1 million. The tentative settlement remains subject to certain
actions at the EPA and state levels, including completion of certain
public notice and comment procedures, following which actions final
regulatory approvals can commence.
In the normal course of business, lawsuits, claims, environmental
actions and various non-ratemaking governmental proceedings arise
against the Companies. To the extent that damages are assessed in any
lawsuits relating 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 the Companies' financial position or results of operations.
7.SegmentsEMPLOYEES AND LABOR RELATIONS
Effective August 1, 2006, KU and its employees represented by IBEW
Local 2100 entered into a new three-year collective bargaining
agreement. The new agreement provides for negotiated increases or
changes to wages, benefits or other provisions and for annual wage re-
openers.
PENSION LEGISLATION
The Pension Protection Act of 2006 was enacted in August 2006. Among
other matters, this comprehensive legislation contains provisions
applicable to defined benefit plans which generally (i) mandate 100%
funding of current liabilities within seven years; (ii) increase tax-
deduction levels regarding contributions; (iii) revise certain
actuarial assumptions, such as mortality tables and discount rates; and
(iv) raise federal insurance premiums and other fees for funded and
distressed plans. The legislation also contains similar provisions
relating to defined-contribution plans and qualified and non-qualified
executive pension plans and other matters. The Companies are currently
examining the potential impacts of the Pension Protection Act of 2006.
7. Segments of Business
LG&E's revenues, net income and total assets by business segment for
the three and sixnine months ended JuneSeptember 30, 2006 and 2005, follow:
Three Months SixNine Months
Ended JuneEnded
September 30, Ended JuneSeptember 30,
(in millions) 2006 2005 2006 2005
LG&E Electric
Revenues $223 $228 $435 $457$269 $284 $704 $741
Net income 27 30 42 5443 45 86 99
Total assets 2,440 2,404 2,440 2,4042,454 2,416 2,454 2,416
LG&E Gas
Revenues 54 53 254 22534 35 288 260
Net income (2) (2) 8 8(3) (3) 4 5
Total assets 507 454 507 454563 551 563 551
Total
Revenues 277 281 689 682303 319 992 1,001
Net income 25 28 50 6240 42 90 104
Total assets 2,947 2,858 2,947 2,8583,017 2,967 3,017 2,967
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 E.ON U.S., and other subsidiaries of E.ON
engage in related-party transactions. These transactions are generally
performed at cost and in accordance with applicable FERC, Kentucky
Commission and Virginia Commission regulations. The significant related-partyrelated-
party transactions are disclosed below.
Electric PurchasesELECTRIC PURCHASES
The Companies' intercompany electric revenues and purchased power
expense from affiliated companies for the three and sixnine months ended
JuneSeptember 30, 2006 and 2005 were as follows:
Three Months SixNine Months
Ended JuneEnded
September 30, Ended JuneSeptember 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 $-$23 - $15 - $67 - $62 -
Electric operating
revenues from LG&E - 17 - 1916 - 3652 - 4965
Purchased power from KU 17 - 1916 - 3652 - 4965 -
Purchased power from LG&E - 2223 - 2115 - 4467 - 47
Interest Charges62
INTEREST CHARGES
The Companies' intercompany interest income and expense for the three
and sixnine months ended JuneSeptember 30, 2006 and 2005 were as follows:
Three Months SixNine Months
Ended JuneEnded
September 30, Ended JuneSeptember 30,
(in millions)
2006 2005 2006 2005
(in millions) LG&E KU LG&E KU LG&E KU LG&E KU
Interest on money pool
loans $- $1 $- $- $1 $2 $- $-$1 $1
Interest on Fidelia
loans 3 45 3 4 6 9 6 7
Other Intercompany Billings8 15 8 11
OTHER INTERCOMPANY BILLINGS
Other intercompany billings related to the Companies for the three and
sixnine months ended JuneSeptember 30, 2006 and 2005 were as follows:
Three Months SixNine Months
Ended JuneEnded
September 30, Ended JuneSeptember 30,
(in millions) 2006 2005 2006 2005
E.ON U.S. Services billings to LG&E $69 $76 $105 $108$57 $53 $162 $161
E.ON U.S. Services billings to KU 78 75 120 10199 44 221 146
LG&E billings to E.ON U.S. Services 2 1 3 51 4 6
KU billings to E.ON U.S. Services 21 - 3 4
LG&E billings to KU 6 7 10 1021 55 31 83
KU billings to LG&E 3 9 15 1314 8 29 21
9. Subsequent Events
On July 14,In October 2006, the Companies paid approximately $33 million to the
MISO pursuant to a revised MISO invoice regarding the exit fee and made
related FERC compliance filings. The Companies' payment of this exit
fee amount was with reservation of their rights to contest the amount,
or components thereof, following a continuing review of its calculation
and supporting documentation.
In October 2006, E.ON U.S., LG&E and KU announced plans to provide up
to $25 million over a period of up to twelve years to the FutureGen
Industrial Alliance, Inc. ("FutureGen"), a non-profit consortium.
FutureGen will conduct research, development and demonstration
activities relating to advanced coal technologies, including proposed
construction of the world's first coal-fired, "near zero emissions"
power plant. Among the members of FutureGen are companies with
interests in coal-fired electric power generation or coal production.
FutureGen has signed an initial cooperative agreement with the DOE and
expects to sign a full-scope cooperative agreement in 2007. Beyond
their initial aggregate membership amount of $0.3 million, E.ON U.S.
and the Companies have rights at sequential future times to terminate
participation prior to incurring the obligation to contribute the
relevant remaining contribution amounts. The next estimated
contribution will be in the amount of $0.8 million during the remainder
of 2006.
In October 2006, KU entered into a $50 million long-term unsecured loan
from Fidelia. The loan matures in October 2016, and has an interest
rate of 5.675%.
In October 2006, the Kentucky Commission commenced an inquiry into
elements of KU's planned construction of one of its three new FGD's at
the Ghent generating station. The proceeding requests additional
information from KU regarding configuration details, expenditures and
the proposed construction sequence applicable to future construction
phases of the Ghent FGD project. The inquiry focuses on KU's proposal
to complete the project in a manner which would result in connecting
the final new FGD to the generating unit currently served by an
existing FGD and reconnecting such existing FGD to the final remaining
generating unit. Pursuant to various Kentucky Commission approvals, KU
has built and operated an FGD on one generating unit since the mid-
1990's and is in varying stages of construction or pre-construction on
FGD's for the remaining three generating units at its Ghent plant. KU
is currently unable to predict the outcome and ultimate impact, if any,
of the Kentucky Commission's proceeding.
In November 2006, the Kentucky Commission issued orders for both
Companies regarding the routine periodic reviews approving the changes
and credits billed through the FAC during the review period.
In November 2006, LG&E redeemed 12,500 shares of its 5.875% mandatorily
redeemable preferred stockcompleted certain agreements pursuant to sinking fund requirements at
$100 per share.
On July 20,its
August 2006 KU completed a new tax-exempt financing totaling
approximately $17 million. The new bonds, due June 1, 2036, have a
variable, auction rateMOU with the Authority regarding the proposed construction
of interest.
Effective August 1, 2006, KU and its employees represented by IBEW
Local 2100an arena in downtown Louisville. LG&E entered into a new three-year collective bargaining
agreement. Suchrelocation
agreement provides for routine updates to wages,
benefits or other provisions and provides for annual wage re-openersproviding for the secondreimbursement by the Authority to LG&E of
the costs to be incurred in moving certain LG&E facilities related to
the arena transaction, which costs are currently estimated to be
approximately $63 million. The parties further entered into a
property sale contract providing for LG&E's sale of a downtown site to
the Authority for approximately $10 million, which represents the
appraised value of the parcel, less certain agreed demolition costs.
The amounts specified in the contracts are subject to certain
adjustments. Depending upon continuing progress in the proposed arena
transaction generally, the transactions contemplated by the contracts
are anticipated to occur between 2006 and third years.2010.
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 the Companies' financial results of
operations and financial condition during the three and sixnine month periods
ended JuneSeptember 30, 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 the Companies' reports to the SEC, including
the Annual Reports on Form 10-K for the year ended December 31, 2005.
Executive Summary
LG&E and KU, subsidiaries of E.ON U.S. (indirect subsidiaries of E.ON),
are regulated public utilities. At JuneSeptember 30, 2006, LG&E
supplied electricity to approximately 398,000397,000 customers and natural
gas to approximately 323,000322,000 customers in Louisville and adjacent
areas in Kentucky. At JuneSeptember 30, 2006, KU provided electricity to
approximately 497,000499,000 customers in 77 counties in central,
southeastern and western Kentucky, to approximately 30,000 customers
in southwestern Virginia and 5 customers in Tennessee. KU also sells
wholesale electricity to 12 municipalities.
The mission of the Companies is to build on our tradition and achieve
world-class status providing reliable, low-cost energy services and
superior customer satisfaction; and to promote safety, financial success
and quality of life for our employees, communities and other stakeholders.
The Companies' strategy focuses on the following:
- Achieve scale as an integrated U.S. electric and gas business through
organic growth;
- Maintain excellent customer satisfaction;
- Maintain best-in-class cost position versus U.S. utility companies;
- Develop and transfer best practices throughout the company;
- Invest in infrastructure to meet expanding load and comply with
increasing environmental requirements;
- Achieve appropriate regulated returns on all investment;
- Attract, retain and develop the best people; and
- Act with a commitment to corporate social responsibility that enhances
the well being of our employees, demonstrates environmental
stewardship, promotes quality of life in our communities and reflects
the diversity of the society we serve.
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 the Companies in December 2003. Under the ruling, the LG&E utility base
electric rates have increased $43 million (7.7%) and base natural gas rates
have increased $12 million (3.4%) annually. Base electric rates at KU have
increased $46 million (6.8%) annually. The rate increases took effect on
July 1, 2004. The 2004 increases were the first increases in electric base
rates for the Companies in 13 and 20 years, respectively; the previous
natural gas rate increase for the LG&E gas utility took effect in September
2000.
The Companies have begun construction of another base-load coal-fired unit
at the Trimble County site. The Companies believe this is the least cost
alternative to meet the future needs of customers. Trimble County Unit 2,
with a 750 Mw capacity rating, is expected to be jointly owned by the
Companies (75% owners of the unit) and the IMEA and IMPA (25% owners).
Trimble County Unit 2 is expected to cost $1.1 billion and be completed by
2010. The Companies' aggregate 75% share of the total Trimble County Unit 2
capital cost is approximately $885$879 million and is estimated to be
approximately $120$151 million for LG&E and $510$601 million for KU through 2008.
Through JuneSeptember 2006, expenditures for Trimble County Unit 2 have been
$7$18 million for LG&E and $25$66 million for KU. In June 2006, the Companies
entered into a construction contract regarding the Trimble County Unit 2
project. See Note 6 of the Notes to Financial Statements, in Part 1, Item
1, herein.
In November 2005, the Kentucky Commission approved the CCN construction
application of the Companies to expand the Trimble County generating 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 the latter transmission line
CCN ruling. A schedule for such proceeding has not been established. In
November 2005, the Kentucky Division for Air Quality issued the final air
permit, which was challenged via a request for remand in December 2005 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 October 2006. A ruling thereafter may be anticipated in the first
half of 2007.
In July 2006, 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, under 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 transmission,
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 FERC. The corrective
actions are in the nature of organization and operational improvements as
described above and are not expected to have a material adverse impact on
the Companies' results of operations or financial condition.
Results of Operations
The results of operations for the 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 JuneSeptember 30, 2006, Compared to
Three Months Ended JuneSeptember 30, 2005
LG&E Results:
LG&E's net income decreased $3$2 million (11%(5%) for the three months ended
JuneSeptember 30, 2006, as compared to the three months ended JuneSeptember 30,
2005, primarily due to lower electricity and natural gas retail and wholesale sales volumes resulting largely from mildercooler
weather than inlast year and a higher effective income tax rate this year,
partially offset by lower MISO expenses and lower other operation expenses
primarily from the priorcompletion of the VDT amortization earlier this year.
A comparison of LG&E's revenues for the three months ended JuneSeptember 30,
2006, with the three months ended JuneSeptember 30, 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 $6 $7$3 $1
Environmental cost recovery
surcharge (3)(1) -
Merger surcredit 1 -
Variation in sales volume and
other (5)(12) (2)
Total retail sales (2) 5(9) (1)
Wholesale sales (4) (4)
Other 14 -
MISO Day 2 RSG MWP (10) -
Total $(5) $1$(15) $(1)
Electric revenues decreased $5$15 million (2%(5%) primarily due to:
- Decreased wholesale revenues ($4 million) largely due to 4% lower
volumes
- Decreased retail electricsales volumes delivered ($512 million) resulting from a 14%16%
decrease in cooling degree days in the secondthird quarter of 2006 as
compared to the same period in 2005
and an 16% decrease from the
20-year average
- Decreased environmental cost recoveryMISO related revenue ($310 million) due to lower ECR
billing ratesthe accounting
reclassification of MISO Day 2 RSG MWP in the third quarter of 2005.
This reclass of the RSG MWP was made from an expense account to a
revenue account back to the inception of MISO Day 2 on April 1, 2005.
- Increased fuel costs ($3 million) billed to customers through the fuel
adjustment clause
- Increased wholesale sales ($64 million) largely due to 20% higher
costs of coal and natural gasvolumes
Gas revenues increased $1 million (2%) primarily due to:
- Increased gas supply costs billed to customers throughfor the gas supply
adjustment ($7 million) due to the higher cost of natural gas
- Decreased wholesale revenues ($4 million)quarter ending September 2006 as a result of 7% lower
volumes due to lower demand from wholesale customers
- Decreased retail gas volumes delivered ($2 million) resulting from a
17% decrease in heating degree days in the second quarter of 2006 compared to 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. Increases 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 $2 million (3%) in 2006 primarily
due to:
- Increased unit cost of fuel burned ($4 million) due to higher fuel
prices
- Decreased generation ($2 million) due to lower wholesale and retail
sales volumes
Power purchased decreased $2 million (7%) in 2006 primarily due to:
- Decreased volumes purchased ($6 million) due to lower wholesale and
retail sales
- Increased unit cost of purchases ($4 million) due to higher market
prices
Gas supply expenses increased $2 million (6%) in 2006 primarily due to:
- Increased unit cost of natural gas purchased ($8 million)
- Decreased volumes of natural gas delivered into the distribution
system ($6 million) due to milder weather
A comparison of the LG&E effective income tax rate for the three months
ended June 30, 2006 and 2005 follows:
Three Months Three Months
Ended Ended
June 30, 2006 June 30, 2005
Effective Rate
Statutory federal income tax rate 35.0% 35.0%
State income taxes net of federal benefit 3.5 5.2
Amortization of investment tax credits (2.7) (2.3)
Other differences (3.4) (1.5)
Effective income tax rate 32.4% 36.4%
State income taxes in 2006 reflect Kentucky Coal Tax credits earned. The
change in amortization of investment tax credits and other differences is
largely attributable to the change in the levels of pre-tax income.
KU Results:
KU's net income increased $7 million (39%) for the three months ended June
30, 2006, as compared to the three months ended June 30, 2005, primarily
due to lower maintenance costs, a lower effective income tax rate and
higher earnings from EEI.
A comparison of KU's revenues for the three months ended June 30, 2006,
with the three months ended June 30, 2005, reflects increases and
(decreases) which have been segregated by the following principal causes:
Cause
Electric
(in millions) Revenues
Retail sales:
Fuel supply adjustments $17
Environmental cost recovery surcharge 3
Variation in sales volumes and other (7)
Total retail sales 13
Other (2)
Total $11
Electric revenues increased $11 million (4%) in 2006 primarily due to:
- Increased fuel costs billed to customers through the fuel adjustment
clause ($17 million) due to higher costs of coal and natural gas
- Increased environmental cost recovery ($3 million) due to higher ECR
billing rates
- Decreased retail electric volumes delivered ($7 million) resulting from
a 17% decrease in cooling degree days in the second quarter of 2006
compared to the same period in 2005 and an 19% decrease from the
20-year average
Fuel for electric generation comprises a large component of KU's total
operating expenses. Increases 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 $16 million (19%) in 2006
primarily due to:
- Increased unit cost of fuel burned ($9 million) due to higher fuel
prices
- Increased generation ($7 million) largely due to higher unit
availability
Power purchased decreased $6 million (12%) in 2006 primarily due to:
- Decreased volumes purchased ($8 million) largely due to higher unit
availability and decreased retail demand
- Increased unit cost of purchases ($2 million) due to higher market
prices
Other operation and maintenance expenses decreased $5 million (7%) in
2006 primarily due to:
- Decreased maintenance costs ($3 million) largely due to an outage last year at Brown Unit 3
- Decreased other power supply costs ($2 million) related to lower MISO
Day 2 expenses
Other (income) - net increased $3 million (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 2006 primarily due to
increased borrowing from Fidelia.
A comparison of the KU effective income tax rate for the three months ended
June 30, 2006 and 2005 follows:
Three Months Three Months
Ended Ended
June 30, 2006 June 30, 2005
Effective Rate
Statutory federal income tax rate 35.0% 35.0%
State income taxes net of federal benefit 4.4 5.0
Amortization of investment tax credits (0.8) (1.4)
EEI dividend (6.1) -
Other differences (1.9) (2.9)
Effective income tax rate 30.6% 35.7%
The EEI dividend in the second quarter of 2006 reflects a tax benefit
associatedwere essentially flat with the receipt of dividends from KU's investment in EEI. The
change in amortization of investment tax credits and other differences is
largely attributable to the change in the levels of pre-tax income.
Six Months Ended June 30, 2006, Compared to
Six Months Ended June 30, 2005
LG&E Results:
LG&E's net income decreased $12 million (19%) for the six months ended June
30, 2006, as compared to the six months ended June 30, 2005, primarily due
to lower electricity and natural gas retail and wholesale sales volumes,
higher maintenance costs and higher interest expense.
A comparison of LG&E's revenues for the six months ended June 30, 2006,
with the six months ended June 30, 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 $15 $73
Merger surcredit 1 -
Weather normalization - 2
Variation in sales volume and other (8) (31)
Total retail sales 8 44
Wholesale sales (32) (16)
Other 2 1
Total $(22) $29
Electric revenues decreased $22 million (5%) in 2006 primarily due to:
- Decreased wholesale revenues ($32 million) largely due to 10% lower
volumes
- Decreased retail electric volumes delivered ($8 million) resulting from
a 10% decrease in cooling 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
- Increased fuel costs billed to customers through the fuel adjustment
clause ($15 million) due to higher costs of coal and natural gas
- Increased miscellaneous revenues ($2 million)
Gas revenues increased $29 million (13%) in 2006 primarily due to:
- Increased gas supply costs billed to customers through the gas supply
adjustment ($73 million) due to higher natural gas costs
- Increased weather normalization revenues ($2 million) due to warmer
weather
- Decreased 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 ($16 million) as a result of 7% lower
volumes due to lower demand from wholesale customersno significant variances.
Fuel for electric generation and gas supply expenses comprise a large
component of LG&E's total operating expenses. Increases 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 $6 million (5%(8%) in 2006 primarily
due to:
- Increased unit cost of fuel burned ($133 million) due to higher fuel
prices
- DecreasedIncreased generation ($53 million) due to lower wholesale and retail
sales volumeshigher unit availability
Power purchased decreased $13$8 million (19%(24%) in 2006 primarily due to:
- Decreased volumes purchased ($229 million) due to higher unit
availability and lower wholesale and retail sales volumes
- Increased unit cost of purchases ($91 million) due to higher market
prices
Gas supply expenses increased $29decreased $1 million (17%(5%) in 2006 primarily due to:
- IncreasedDecreased unit cost of natural gas purchased ($693 million)
- DecreasedIncreased volumes of natural gas delivered intoto the distribution system ($402 million) due to milder weather
Other operation and maintenance expenses increased $4decreased $18 million (3%(20%) in
20062006.
Other operation expenses decreased $23 million (34%) primarily due to:
- Decreased other power supply costs ($16 million) primarily due to
lower MISO Day 2 expenses
- Decreased administrative and general expenses ($7 million) primarily
due to completion of the VDT amortization
Maintenance expense increased $3 million (22%) primarily due to:
- Increased steamelectric distribution maintenance ($32 million) largelyprimarily due
to the outage attree trimming
- Increased steam generation maintenance ($1 million) primarily related
to Mill Creek Unit 4
- Increased distribution maintenance ($2 million)Property and other taxes increased $1 million (30%)
Other income increased $2 million in 2006 primarily due to higher storm
restoration costsnon-hedging
derivative mark-to-market income.
Interest expense increased $2 million (11%(33%) in 2006 primarily due to:
- Increased interest rates on variable rate debt ($32 million)
- Increased interest expense on tax deficiencies ($1 million)
- IncreasedDecreased interest rates on money pool borrowing ($1 million)
- Decreased interestexpense on the swaps ($2 million)
- Decreased interest due to refinancing fixed rate debt with variable
rate debt ($1 million)
The weighted average interest rate on variable-rate bonds for the sixthree
months ended JuneSeptember 30, 2006, was 3.33%3.63%, compared to 2.27%2.54% for the
comparable period in 2005.
A comparison of the LG&E effective income tax rate for the sixthree months
ended JuneSeptember 30, 2006 and 2005 follows:
Six Months SixThree Three
Months Ended Months Ended
JuneSeptember 30, 2006 JuneSeptember 30, 2005
Effective Rate
Statutory federal income tax
rate 35.0% 35.0%
State income taxes net of federal
benefit 3.6 4.84.0 3.7
Reduction of previous accruals (0.6) (9.0)
Amortization of investment tax
credits (2.7) (2.2)(1.6) (1.8)
Other differences (2.6) (2.2)(1.3) (1.6)
Effective income tax
rate 33.3% 35.4%
State35.5% 26.3%
In September 2005, E.ON U.S. Investments Corp., the parent of E.ON U.S. and
indirect parent of LG&E, received notice from the Congressional Joint
Committee on Taxation approving the IRS audit of the consolidated group's
returns for the periods December 1999 through December 2003. As a result of
this approval, LG&E released income taxestax reserves of $5.1 million in the
third quarter of 2005. Further reductions of previous tax accruals were
made in the third quarter of 2006 reflect Kentucky Coal Tax credits earned.primarily due to the expiration of the
statute of limitations for a prior year.
The change in amortization of investment tax credits and other differences
is largely attributable to the change in the levels of pre-tax income.
KU Results:
KU's net income increased $5$17 million (9%(53%) for the sixthree months ended
JuneSeptember 30, 2006, as compared to the sixthree months ended JuneSeptember 30,
2005, primarily due to higher equity in earnings from EEI, lower MISO
expenses and a lower effective income tax rate, which isother operation expenses primarily from the completion
of the VDT amortization earlier this year, partially offset by higher transmission costslower retail
and higherwholesale sales volumes and increased interest charges.expense.
A comparison of KU's revenues for the sixthree months ended JuneSeptember 30,
2006, with the sixthree months ended JuneSeptember 30, 2005, reflects increases
and (decreases) which have been segregated by the following principal
causes:
Cause Electric
(in millions) Revenues
Retail sales:
Fuel supply adjustments $36$27
Environmental cost recovery
surcharge 3
Merger surcredit 1
Rate and rate structure 2
Variation in sales volumevolumes and
other (6)(13)
Total retail sales 3619
Wholesale sales (18)
Other (1)(10)
MISO Day 2 RSG MWP (14)
Total $17$(5)
Electric revenues increased $17decreased $5 million (3%(1%) in 2006 primarily due to:
- Decreased MISO related revenue ($14 million) due to the accounting
reclassification of MISO Day 2 RSG MWP in the third quarter of 2005.
This reclass of the RSG MWP was made from an expense account to a
revenue account back to the inception of MISO Day 2 on April 1, 2005.
- Decreased sales volumes delivered ($13 million) resulting from a 21%
decrease in cooling degree days in the third quarter of 2006, as
compared to the same period in 2005
- Decreased wholesale revenues ($10 million) largely due to 37% lower
volumes
- Increased fuel costs ($27 million) billed to customers through the
fuel adjustment clause ($36 million) due to higher costs of coal and natural gasprices
- Increased environmental cost recovery ($3 million) duebilled to higher ECR
billing ratescustomers
- Increased Virginiamerger surcredit revenues due to a rate change for increased fuel
recovery ($2 million)
- Decreased wholesale sales ($18 million) largely due to 5% lower volumes
- Decreased retail electric volumes delivered ($7 million) resulting from
a 9% decrease in cooling degree days in the first six months of 2006
compared to the same period in 2005 and an 11% decrease from the
20-year average
Fuel for electric generation comprises a large component of KU's total
operating expenses. Increases 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 $23$11 million (13%(9%) in 2006
primarily due to:
- Increased unit cost of fuel burned ($2017 million) due to higher fuel
prices
- IncreasedDecreased generation ($36 million) largelydue to lower sales volumes
Power purchased decreased $16 million (25%) in 2006 primarily due to:
- Decreased unit cost of purchases ($12 million) due to lower market
prices
- Decreased volumes purchased ($4 million) due to higher unit
availability and lower sales volumes
Other operation and maintenance expenses decreased $17 million (21%) in
2006.
Other operation expenses decreased $19 million (33%) primarily due to:
- Decreased other power supply costs ($15 million) primarily due to lower
MISO Day 2 expenses
- Decreased administrative and general expenses ($3 million) primarily
due to the completion of the VDT amortization
- Decreased transmission expense ($2 million) primarily due to lower MISO
Day 1 expenses
- Increased steam generation operations expense ($1 million)
Property and other taxes increased $1 million (29%)
Other income - net increased $11 million primarily due to:
- Increased equity in earnings from EEI as a result of EEI selling
electricity at market based rates, effective January 2006 ($9 million)
- Increased non-hedging derivative mark-to-market income ($2 million)
Interest expense increased $1 million (33%) primarily due to higher
interest rates on variable rate debt. The weighted average interest rate on
variable-rate bonds for the three months ended September 30, 2006, was
3.63%, compared to 2.54% for the comparable period in 2005.
Interest expense to affiliated companies increased $2 million (50%) in 2006
primarily due to increased borrowing from Fidelia.
A comparison of the KU effective income tax rate for the three months ended
September 30, 2006 and 2005 follows:
Three Months Three Months
Ended Ended
September September
30, 2006 30, 2005
Effective Rate
Statutory federal income tax
rate 35.0% 35.0%
State income taxes net of federal
benefit 4.5 4.6
Reduction of previous accruals (0.3) (8.9)
Amortization of investment tax
credits (0.4) (0.9)
EEI dividend (3.0) -
EEI adjustment - 6.3
Other differences (2.0) (0.1)
Effective income tax rate 33.8% 36.0%
The EEI dividend in the third quarter of 2006 reflects tax benefits
associated with the receipt of dividends from KU's investment in EEI.
During the third quarter in 2005, KU recognized additional deferred tax
expense ($3.1 million) related to the undistributed earnings in its EEI
unconsolidated investment. An EEI management decision regarding changes in
the distribution of EEI's previous earnings led to the decision to provide
deferred income taxes for all book and tax basis differences in this
investment.
The change in amortization of investment tax credits is largely
attributable to the change in the levels of pre-tax income.
In September 2005, E.ON U.S. Investments Corp., the parent of E.ON U.S. and
indirect parent of KU, received notice from the Congressional Joint
Committee on Taxation approving the IRS audit of the consolidated group's
returns for the periods December 1999 through December 2003. As a result of
this approval, KU released income tax reserves of $4.4 million in the third
quarter of 2005. Further reductions of previous tax accruals were made in
the third quarter of 2006 primarily due to the expiration of the statute of
limitations for a prior year.
Nine Months Ended September 30, 2006, Compared to
Nine Months Ended September 30, 2005
LG&E Results:
LG&E's net income decreased $14 million (13%) for the nine months ended
September 30, 2006, as compared to the nine months ended September 30,
2005, primarily due to lower electric and gas retail and wholesale sales
volumes resulting from milder weather this year, higher interest expense
and a higher effective income tax rate, partially offset by lower other
operations expenses primarily from the completion of the VDT amortization
earlier this year and lower MISO expenses.
A comparison of LG&E's revenues for the nine months ended September 30,
2006, with the nine months ended September 30, 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 $18 $74
Merger surcredit 2 -
Environmental cost recovery (1) -
Value delivery surcredit - 1
Weather normalization - 2
Variation in sales volume and
other (19) (34)
Total retail sales - 43
Wholesale sales (28) (16)
MISO Day 2 RSG MWP (7) -
Other (2) 1
Total $(37) $28
Electric revenues decreased $37 million (5%) in 2006 primarily due to:
- Decreased wholesale sales ($28 million) resulting from 16% lower
volumes
- Decreased retail sales volumes and other ($19 million) resulting from
a 12% decrease in cooling degree days as compared to the same period
in 2005
- Decreased MISO related revenue ($7 million) largely due to the
accounting reclassification of MISO Day 2 RSG MWP in the third quarter
of 2005. This reclass of the RSG MWP was made from an expense account
to a revenue account back to the inception of MISO Day 2 on April 1,
2005.
- Increased fuel costs ($18 million) billed to customers through the
fuel adjustment clause due to higher costs of coal
Gas revenues increased $28 million (11%) in 2006 primarily due to:
- Increased gas supply costs ($74 million) billed to customers through
the gas supply adjustment clause due to higher costs of natural gas
- Increased weather normalization revenues ($2 million) due to warmer
weather
- Increased value delivery surcredit revenues ($1 million)
- Decreased sales volumes and other ($34 million) resulting from a 8%
decrease in heating degree days as compared to the same period in 2005
- Decreased wholesale sales ($16 million) due to limited opportunities
to sell off-system
Fuel for electric generation and gas supply expenses comprise a large
component of LG&E's total operating expenses. Increases 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 $13 million (6%) in 2006
primarily due to:
- Increased unit cost of fuel burned ($17 million) due to higher fuel
prices
- Decreased generation ($4 million) due to lower sales volumes
Power purchased decreased $6$20 million (6%(20%) in 2006 primarily due to:
- Decreased volumes purchased ($1830 million) largely due to higher unit
availability and decreased retail demandlower sales volumes
- Increased unit cost of purchases ($10 million) due to higher market
prices
Gas supply expenses increased $27 million (14%) in 2006 primarily due
to:
- Increased unit cost of natural gas purchased ($69 million)
- Decreased volumes delivered to the distribution system ($41 million)
Other operation and maintenance expenses decreased $15 million (7%) in
2006.
Other operation expenses decreased $25 million (15%) primarily due to:
- Decreased administrative and general expenses ($14 million) primarily
due to the completion of the VDT amortization
- Decreased other power supply expenses ($6 million) primarily due to
lower MISO Day 2 expenses
- Decreased transmission expenses ($6 million) primarily due to lower
MISO expenses
Maintenance expenses increased $9 million (18%) primarily due to:
- Increased steam maintenance ($4 million) primarily related Mill
Creek Unit 4
- Increased distribution maintenance ($4 million) primarily related to
storm restoration
- Increased administrative and general maintenance ($2 million)
Property and other taxes increased $1 million (8%)
Interest expense increased $5 million (29%) in 2006 primarily due to:
- Increased interest rates on variable rate debt ($4 million)
- Increased interest on tax deficiencies ($3 million)
- Decreased interest expense on the swaps ($2 million)
The weighted average interest rate on variable-rate bonds for the nine
months ended September 30, 2006, was 3.43%, compared to 2.36% for the
comparable period in 2005.
A comparison of the LG&E effective income tax rate for the nine months
ended September 30, 2006 and 2005 follows:
Nine Months Nine Months
Ended Ended
September September
30, 2006 30, 2005
Effective Rate
Statutory federal income tax
rate 35.0% 35.0%
State income taxes net of federal
benefit 3.8 4.3
Reduction of previous accruals (0.3) (3.4)
Amortization of investment tax
credits (2.2) (2.0)
Other differences (2.0) (1.4)
Effective income tax rate 34.3% 32.5%
State income taxes in 2006 reflect Kentucky Coal Tax credits earned. The
change in amortization of investment tax credits is largely attributable to
the change in the levels of pre-tax income.
In September 2005, E.ON U.S. Investments Corp., the parent of E.ON U.S. and
indirect parent of LG&E, received notice from the Congressional Joint
Committee on Taxation approving the IRS audit of the consolidated group's
returns for the periods December 1999 through December 2003. As a result of
this approval, LG&E released income tax reserves of $5.1 million in the
third quarter of 2005. Further reductions of previous tax accruals were
made in 2006 primarily due to the expiration of the statute of limitations
for a prior year.
KU Results:
KU's net income increased $22 million (25%) for the nine months ended
September 30, 2006, as compared to the nine months ended September 30,
2005, primarily due to higher equity in earnings from EEI, lower MISO
expenses, lower other operation expenses primarily from the completion of
the VDT amortization earlier this year and a lower effective income tax
rate, partially offset by lower retail and wholesale sales volumes and
increased interest expense.
A comparison of KU's revenues for the nine months ended September 30, 2006,
with the nine months ended September 30, 2005, reflects increases and
(decreases) which have been segregated by the following principal causes:
Cause Electric
(in millions) Revenues
Retail sales:
Fuel supply adjustments $ 52
Environmental cost recovery surcharge 6
Merger surcredit 2
Rate and rate structure 2
Value delivery surcredit 1
Variation in sales volume and other (8)
Total retail sales 55
Wholesale sales (28)
MISO Day 2 RSG MWP (4)
Other (11)
Total $ 12
Electric revenues increased $12 million (1%) in 2006 primarily due to:
- Increased fuel costs ($52 million) billed to customers through the fuel
adjustment clause
- Increased environmental cost recovery surcharge ($6 million)
- Increased merger surcredit revenues ($2 million)
- Increased revenues from changes in Virginia rates and rate structure
($2 million)
- Decreased wholesale sales ($28 million) resulting from 51% lower
volumes
- Decreased transmission revenue ($10 million) due to lower volumes
- Decreased retail sales volumes and other ($9 million) resulting from a
10% decrease in cooling degree days as compared to the same period in 2005
- Decreased MISO related revenues ($4 million) largely due to the
accounting reclassification of MISO Day 2 RSG MWP in the third quarter of
2005.This reclass of the RSG MWP was made from an expense account to a
revenue account back to the inception of MISO Day 2 on April 1, 2005.
Fuel for electric generation comprises a large component of KU's total
operating expenses. Increases 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 $35 million (12%) in 2006
primarily due to:
- Increased unit cost of fuel burned ($37 million) due to higher fuel
prices
- Decreased generation ($2 million) due to decreased sales volumes
Power purchased decreased $21 million (13%) in 2006 primarily due to:
- Decreased volumes purchased ($24 million) due to higher unit
availability and lower sales volumes
- Increased unit cost of purchases ($3 million) due to higher market
prices
Other operation and maintenance expenses increased $7decreased $12 million (6%) in
20062006.
Other operation expenses decreased $9 million (6%) primarily due to:
- IncreasedDecreased other power supply expenses ($59 million) largelyprimarily due to
lower MISO Day 2 expenses
- Decreased administrative and general expenses ($3 million) primarily
due to the completion of the VDT amortization
- Increased transmission expenses ($2 million)
- Increased steam generation operation expense ($31 million)
largelyMaintenance expenses decreased $3 million (6%) primarily due to:
- Decreased steam generation maintenance ($7 million) due to MISO Day outages in
2005 at E.W. Brown, Ghent and Green River
- Increased administrative and general maintenance ($2 million)
- Increased combustion turbine maintenance ($1 million)
- Increased electric distribution maintenance ($1 million)
Property and other taxes increased $1 million (12%)
Other (income)income - net increased $10$21 million (333%) 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 $4$1 million (29%(10%) in 2006 primarily due to:
- Increased cost of the interest rate swap ($2 million)
- Increased interest rates on variable rate debt ($2 million)
- Decreased interest due to replacing external debt with debt to
affiliated companies ($3 million)
The weighted average interest rate on variable-rate bonds for the nine
months ended September 30, 2006, was 3.32%, compared to 2.39% for the
comparable period in 2005.
Interest expense to affiliated companies increased $5 million (42%)
primarily due to:
- Increased borrowing from Fidelia ($24 million)
- Increased borrowing and increased interest rates onfrom the money pool debt
($21 million)
A comparison of the KU effective income tax rate for the sixnine months ended
JuneSeptember 30, 2006 and 2005 follows:
SixNine Months SixNine Months
Ended Ended
JuneSeptember September
30, 2006 June 30, 2005
Effective Rate
Statutory federal income tax
rate 35.0% 35.0%
State income taxes net of federal
benefit 4.4 4.7
Reduction of previous accruals (0.1) (3.2)
Amortization of investment tax
credits (0.6)(0.5) (0.9)
EEI dividend (5.1)(4.1) -
EEI adjustment - 2.3
Other differences (1.1) (0.6)(1.6) (0.9)
Effective income tax rate 32.6% 38.2%33.1% 37.0%
The EEI dividend for the sixnine months ended JuneSeptember 30, 2006, reflects a tax
benefitbenefits associated with the receipt of dividends from KU's investment in
EEI. During the third quarter in 2005, KU recognized additional deferred
tax expense ($3.1 million) related to the undistributed earnings in its EEI
unconsolidated investment. Subsequent to an EEI management decision
regarding changes in the distribution of EEI's previous earnings, KU has
elected to record deferred income taxes for all book and tax basis
differences in this investment.
In September 2005, E.ON U.S. Investments Corp., the parent of E.ON U.S. and
the indirect parent of KU, received notice from the Congressional Joint
Committee on Taxation approving the IRS audit of the consolidated group's
returns for the periods December 1999 through December 2003. As a result of
this approval, KU released income tax reserves of $4.4 million in the third
quarter of 2005. Further reductions of previous tax accruals were made in
2006 primarily due to the expiration of the statute of limitations for a
prior year.
Liquidity and Capital Resources
The 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. The Companies believe that such
sources of funds will be sufficient to meet the needs of the business in
the foreseeable future.
At JuneSeptember 30, 2006, 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. The Companies
expect to cover any working capital deficiencies with cash flow from
operations, money pool borrowings and borrowings from Fidelia.
Construction expenditures for the sixnine months ended JuneSeptember 30, 2006
amounted to $66$104 million for LG&E and $121$236 million for KU. At LG&E, capital
expenditures included Trimble County Unit 2, infrastructure for new
customers, gas main replacements/extensionsreplacements and capital repairs to Mill Creek Unit 4.
At KU, capital expenditures included construction of FGDTrimble County Unit 2, FGD's and other
environmental equipment at the Brown and Ghent generating stationstations and
infrastructure for new customers.
LG&E's cash balance decreased $2 million during the sixnine months ended
JuneSeptember 30, 2006, largely resulting from repaymentsthe retirement of debt and the
payment of dividends. KU's cash balance decreased $2 million during the
sixnine months ended JuneSeptember 30, 2006, primarily due to increased capitallargely resulting from increasing
construction expenditures.
Variations in accounts receivable, inventories and accounts payable are
generally not significant indicators of the 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
decreases in LG&E's accounts receivable and natural gas stored underground
relate primarily to seasonal uses of natural gas.
For information regarding the Companies' use of interest rate swaps to
hedge underlying variable-rate (LG&E) and fixed-rate (KU) debt obligations,
see Note 3 of the Notes to Financial Statements.
See Note 5 of the Notes to Financial Statements for information regarding
the Companies' long-term and short-term debt including: accounting
treatment of bonds permitting tender for purchase at the option of the
holder, re-negotiation of revolving credit lines, intercompany debt
transactions and the issuance and redemption of financial instruments
during the year.
Security ratings as of JuneSeptember 30, 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.
LG&E made a discretionary contribution to the pension plan of $18 million
in January 2006. LG&E made no contributions during 2005. KU made no
contributions to the pension plan in 2006 or 2005.
Contingencies
For a description of significant contingencies that may affect the
Companies, reference is made to Part I, Item 3, Legal Proceedings in the
Companies' Annual Reports on Form 10-K for the year ended December 31,
2005; to Part I - Item 1 and Part II - Item 1, Legal Proceedings in the
Companies' Quarterly ReportReports on Form 10-Q for the periodperiods ended March 31,
2006 and June 30, 2006; and to Notes 2 and 6 of the Notes to Financial
Statements in Part I
- - Item 1, and Part II - Item 1, Legal Proceedings
herein.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
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 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
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 the Companies' unswappednon-hedged variable debt is estimated
at $4 million each at JuneSeptember 30, 2006. The Companies' exposure to
floating interest rates did not materially change during the first sixnine
months of 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 $17$18 million as of JuneSeptember 30, 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 less than $1 million as of
JuneSeptember 30, 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
The Companies' costs of providing defined-benefit pension retirement plans
isare dependent upon a number of factors, such as the rates of return on plan
assets, discount rate and contributions made to the plan.plans. The 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 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 comprehensive income will be
restored in the balance sheet. See Note 1 of the Notes to Financial
Statements in Item 1, Part 1 for a discussion of the new accounting
pronouncement SFAS No. 158, Employers' Accounting for Defined Benefit
Pension and Other Postretirement Plans.
A 1% increase or decrease in the assumed discount rate could have an
approximate $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 $33 million positive or negative
impact to the accumulated benefit obligation of KU.
LG&E made a discretionary contribution to the pension plan forof $18 million
in January 2006. LG&E made no contributions during 2005. KU made no
contributions to the pension plan in 2006 or 2005.
Energy & Risk Management Activities
The Companies conduct energy trading and risk management activities to
maximize the value of power sales from physical assets they own. Certain
energy trading activities are accounted for on a mark-to-market basis in
accordance with SFAS No. 133, as amended. Wholesale sales of excess asset
capacity are treated as normal sales under SFAS No. 133, as amended, and
are not marked to market.
Since the inception of the MISO Day 2 market in April 2005, the Companies
have been eligible to receive FTRs from the MISO. FTRs are assigned by the
MISO to market participants for a twelve-month period of time beginning
June 1, 2006, for off-peak and peak periods based on each market
participant's share of generation. FTRs are utilized to manage price risk
associated with transmission congestion. The value of FTRs is determined by
the transmission congestion charges that arise when the transmission grid
is congested in the day-ahead market. FTRs are obtained through an
allocation from the MISO at zero cost, however, they can also be bought and
sold. FTRs are derivatives and their fair value is insignificant due to
the lack of liquidity in the forward market.
The fair values of the Companies' energy trading and risk management
contracts as of JuneSeptember 30, 2006 were each approximately $2$4 million. The
fair values at JuneSeptember 30, 2005, were less than $1 million each. No
changes to valuation techniques for energy trading and risk management
activities occurred during 2006 or 2005. Changes in market pricing,
interest rate and volatility assumptions were made during all periods. The
outstanding mark-
to-marketmark-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 $1 million. All
contracts outstanding at JuneSeptember 30, 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.
The Companies maintain policies intended to minimize credit risk and
revalue credit exposures daily to monitor compliance with those policies.
As of JuneSeptember 30, 2006, 100% of the trading and risk management
commitments were with counterparties rated BBB-/Baa3 equivalent or better.
MISO Exit
For further discussions of certain market risks relating to the Companies'
withdrawal from MISO, see also Part II, Item 1A, Risk Factors in this
quarterly report and in the Companies' Annual Report on Form 10-K for the
year ended December 31, 2005.
Item 4. Controls and Procedures
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. The 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") and the Chief Financial Officer ("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.
The Companies are not accelerated filers under the Sarbanes-Oxley Act of
2002 and associated rules (the "Act") and consequently anticipate issuing
Management's Report on Internal Control over Financial Reporting pursuant
to Section 404 of the Act in their first periodic report covering the
fiscal year ended December 31, 2007 as permitted by SEC rulemaking.
In preparation for required reporting under Section 404 of the Act, 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 control over
financial reporting. There has been no change in the Companies' internal
control over financial reporting that occurred during the fiscal quarter
ended JuneSeptember 30, 2006, that has materially affected, or is 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 the
Companies, reference is made to the information under the following items
and captions of the Companies' respective combined Annual Report on Form 10-
K for the year ended December 31, 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 Notes 3 and 10. Reference is also made to the matters
described in Notes 2 and 6 of Part 1, Item 1 of the Companies' Quarterly
ReportReports on Form 10-Q for the three months ended March 31, 2006 and June 30,
2006; and Notes 2 and 6 of the Notes to Financial Statements in Part I,
Item 1 of this 10-Q. Except as described herein, to date, the proceedings
reported in the Companies' respective combined Annual Report on Form 10-K
have not changed materially.
Other
In the normal course of business, other lawsuits, claims, environmental
actions, and other governmental proceedings arise against the Companies. To
the extent that damages are assessed in any of these lawsuits, the
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 1A. Risk Factors.
MISO Exit
LG&E and KU currently anticipate withdrawalwithdrew 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
energy purchases and sales, transmission and related 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. Such activities may have an effect on the Companies' abilities
to access the transmission system for wholesale or native load power
activities. The Companies will save certain MISO membership costs and
charges, but will incur ana MISO exit fee andas well as fees related to the new
transmission service vendors. The Companies believe that, over time, the
benefits and savings from antheir exit of the MISO will outweigh the costs
and expenses. However, until post-MISO market conditions and operations
have matured, the effects on financial condition, liquidity or results of
operations will remain difficult to fully predict.
See Note 2 of LG&E's and KU's Notes to Financial Statements in Part I, Item
1 of this 10-Q.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
2(c)
LG&E has an existing $5.875 series of mandatorily redeemable preferred
stock outstanding having a current redemption price of $100 per share. The
preferred stock has a sinking fund requirement sufficient to retire a
minimum of 12,500 shares on July 15 of each year commencing with July 15,
2003, and a minimum of 187,500 shares on July 15, 2008 at $100 per share.
LG&E redeemed 12,500 shares in accordance with these provisions on July 15,
2006, leaving 200,000 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, Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity.
July 2006 August 2006 September 2006
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 200,000 n/a n/a
(or approximate ($5.875 Pref.)
dollar value) of
shares (or units)
that may yet be
purchased under
the plans or
programs
Item 4. Submission of Matters to a Vote of Security Holders.
a)LG&E's and KU's Annual Meetings of Shareholders were held on July 20,
2006.
b)Not applicable.
c)The matters voted upon and the results of the voting at the Annual
Meetings are set forth below:
1. LG&E
i)The shareholders voted to elect LG&E's nominees for election to the
Board of Directors, as follows:
Victor A. Staffieri - 21,294,223 common shares and 596,501
preferred shares cast in favor of election and 7,687 preferred
shares withheld.
S. Bradford Rives - 21,294,223 common shares and 595,801 preferred
shares cast in favor of election and 8,387 preferred shares
withheld.
John R. McCall - 21,294,223 common shares and 596,956 preferred
shares cast in favor of election and 7,232 preferred shares
withheld.
Paul W. Thompson - 21,294,223 common shares and 596,656 preferred
shares cast in favor of election and 7,532 preferred shares
withheld.
Chris Hermann - 21,294,223 common shares and 596,713 preferred
shares cast in favor of election and 7,475 preferred shares
withheld.
No holders of common or preferred shares abstained from voting
on this matter.
ii)The shareholders voted 21,294,223 common shares and 599,991
preferred shares in favor of and 2,564 preferred shares against the
approval of PricewaterhouseCoopers LLP as the Independent
Registered Public Accounting Firm for 2006. Holders of 1,633
preferred shares abstained from voting on this matter.
2. KU
i)The sole shareholder voted to elect KU's nominees for election to
the Board of Directors, as follows:
37,817,878 common shares cast in favor of election and no shares
withheld for each of Victor A. Staffieri, S. Bradford Rives,
John R. McCall, Paul W. Thompson, and Chris Hermann, respectively.
ii)The sole shareholder voted 37,817,878 common shares in favor of and
no shares withheld for approval of PricewaterhouseCoopers LLP as the
Independent Registered Public Accounting Firm for 2006.
No holders of common shares abstained from voting on these matters.
d) Not applicable.
Item 5. Other Information.
None.In October 2006, executive officers of LG&E and KU received initial grants
of performance units under a new long-term variable compensation plan, the
E.ON AG Share Performance Plan ("New Plan") established by E.ON during
2006. These grants, which have a maturity period of three years, commencing
on January 1 of this year, are payable in cash after the end of the
maturity period. The ultimate amount of compensation paid to the executives
is determined by the value E.ON AG share performance during the final 60
days of the period and the relative performance of E.ON AG stock's total
shareholder return ("TSR") against the TSR of a European utility stock
index over the maturity period. Minimum E.ON AG performance against the
index must be attained in order for a performance unit to have any value.
The maximum value of a performance unit granted under the New Plan is three
times the initial value of the performance unit, which initial value is set
at E.ON AG's average share price for the 60 trading days preceding the
commencement of the three year period. The performance units are subject to
accelerated payment prior to their maturity date, using performance
calculations to date, upon certain events of change-in-control.
Additionally, acceleration of payment may occur in the event of death,
disability or termination of employment of the executive officer by the
Company for other than for cause. This description is qualified in its
entirety by reference to the text of the New Plan and related documents,
copies of which are filed with this Form 10-Q as Exhibits 10.01 and 10.02,
respectively.
Item 6. Exhibits.
Applicable to Form
10-Q of
Exhibit
No. LG&E KU Description
4.1 X Loan AgreementSupplemental Indenture dated June 23,July 1, 2006
between Kentucky Utilities CompanyKU and Fidelia Corporation.U.S. Bank National Association, Chicago
Illinois, as Trustee. [Filed as Exhibit 4.1 to KU's Current
Report on Form 8-K dated June
23,July 20, 2006 and incorporated by
reference herein.]
4.2 X Copy of Promissory Note from KU to
Fidelia Corporation,Loan Agreement dated as of June 23, 2006.1, 2006
between KU and the County of Carroll, Kentucky. [Filed as
Exhibit 4.2 to KU's Current Report on Form 8-K dated June
23,July
20, 2006 and incorporated by reference herein.]
10.01 X X Copies of E.ON Share Performance Plan (i) Terms and
Conditions for the 1. Tranche (2006-2008) and (ii) Technical
Annex, each dated as of June 2006.
10.02 X X Copies of form representative specimen Certificate
Award under E.ON Share Performance Plan
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: August 14,November 9, 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: August 14,November 9, 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)