Exhibit 99.2

E.ON U.S. LLC and Subsidiaries

Condensed Consolidated Financial Statements

(Unaudited)

As of September 30, 2010 and December 31, 2009

and for the three and nine months ended

September 30, 2010 and 2009

INDEX OF ABBREVIATIONS

AG	Attorney General of Kentucky
ARO	Asset Retirement Obligation
ASC	Accounting Standards Codification
BART	Best Available Retrofit Technology
Big Rivers	Big Rivers Electric Corporation
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
Capital Corp.	E.ON U.S. Capital Corp.
CATR	Clean Air Transport Rule
CCN	Certificate of Public Convenience and Necessity
Centro	Distribuidora de Gas Del Centro S.A.
Clean Air Act	The Clean Air Act, as amended in 1990
CMRG	Carbon Management Research Group
Company	E.ON U.S. LLC and Subsidiaries
CT	Combustion Turbine
Cuyana	Distribuidora de Gas Cuyana S.A.
DSM	Demand Side Management
ECR	Environmental Cost Recovery
EEI	Electric Energy, Inc.
EKPC	East Kentucky Power Cooperative, Inc.
E.ON	E.ON AG
E.ON Spain	E.ON Espana S.L.
E.ON U.S.	E.ON U.S. LLC
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
FGD	Flue Gas Desulfurization
Fidelia	Fidelia Corporation (an E.ON affiliate)
GHG	Greenhouse Gas
GSC	Gas Supply Clause
ICSID	International Council for the Settlement of Investment Disputes
IMEA	Illinois Municipal Electric Agency
IMPA	Indiana Municipal Power Agency
IRS	Internal Revenue Service
KCCS	Kentucky Consortium for Carbon Storage
Kentucky Commission	Kentucky Public Service Commission
KU	Kentucky Utilities Company
Kwh	Kilowatt hours
LEM	LG&E Energy Marketing Inc.
LG&E	Louisville Gas and Electric Company
LIBOR	London Interbank Offered Rate
MISO	Midwest Independent Transmission System Operator
MMBtu	Million British thermal units
Moody's	Moody's Investor Services, Inc.
Mw	Megawatts
NAAQS	National Ambient Air Quality Standards
NGHH	Natural Gas-Henry Hub

NOV	Notice of Violation
NOx	Nitrogen Oxide
OCI	Other Comprehensive Income
OMU	Owensboro Municipal Utilities
OVEC	Ohio Valley Electric Corporation
PBR	Performance Based Rates
PUHCA	Public Utility Holding Company Act
PUHCA 1935	Public Utility Holding Company Act of 1935
PUHCA 2005	Public Utility Holding Company Act of 2005
PPL	PPL Corporation
RSG	Revenue Sufficiency Guarantee
S&P	Standard and Poor's Rating Service
SCR	Selective Catalytic Reduction
Servco	LG&E and KU Services Company (formerly E.ON U.S. Services Inc.)
SIP	State Implementation Plan
SO2	Sulfur Dioxide
TC2	Trimble County Unit 2
Trimble County	LG&E's Trimble County generating station
Virginia Commission	Virginia State Corporation Commission
WKE	Western Kentucky Energy Corp. and its Affiliates
WNA	Weather Normalization Adjustment

E.ON U.S. LLC and Subsidiaries

Condensed Consolidated Financial Statements

(Unaudited)

As of September 30, 2010 and December 31, 2009

and for the three and nine months ended

September 30, 2010 and 2009

Table of Contents

Financial Statements:
	Condensed Consolidated Statements of Income	1
	Condensed Consolidated Statements of Comprehensive Income (Loss)	3
	Condensed Consolidated Statements of Retained Deficit	4
	Condensed Consolidated Balance Sheets	5
	Condensed Consolidated Statements of Cash Flows	8
Notes to Condensed Consolidated Financial Statements:
	Note 1 - General	10
	Note 2 - Goodwill	13
	Note 3 - Discontinued Operations	14
	Note 4 - Rates and Regulatory Matters	16
	Note 5 - Asset Retirement Obligations	24
	Note 6 - Derivative Financial Instruments	24
	Note 7 - Fair Value Measurements	29
	Note 8 - Pension and Other Postretirement Benefit Plans	34
	Note 9 - Income Taxes	35
	Note 10 - Short-Term and Long-Term Debt	38
	Note 11 - Commitments and Contingencies	40
	Note 12 - Related Party Transactions	50
	Note 13 - Share Performance Plan	50
	Note 14 - Subsequent Events	50

E.ON U.S. LLC and Subsidiaries

Condensed Consolidated Statements of Income

(Unaudited)

(Millions of $)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Operating revenues:
Electric	$	689		$	566		$	1,838		$	1,621
Gas		30			28			196			270
Other		-			1			1			2
Total operating revenues		719			595			2,035			1,893
Operating expenses:
Fuel for electric generation		250			197			668			586
Power purchased		29			34			97			102
Gas supply expenses		10			10			103			189
Other operation and maintenance expenses		182			71			528			497
Depreciation, accretion and amortization		73			72			211			203
Total operating expenses		544			384			1,607			1,577
Operating income		175			211			428			316
Derivative gain (loss) (Note 6)		29			(4	)		18			12
Interest expense (Notes 6 and 10)		6			6			19			18
Interest expense to affiliated companies (Notes 10 and 12)		39			40			118			115
Other income (expense) - net		2			(3	)		(1	)		5
Income from continuing operations, before Income taxes		161			158			308			200
Income tax expense (Note 9)		59			57			112			64
Income from continuing operations		102			101			196			136
Discontinued operations (Note 3):
Income (loss) from discontinued operations before tax		(2	)		(1	)		(7	)		(207	)
Income tax benefit (expense) from discontinued operations		1			-			3			78
Income (loss) from discontinued operations before noncontrolling interest		(1	)		(1	)		(4	)		(129	)

E.ON U.S. LLC and Subsidiaries

Condensed Consolidated Statements of Income (Continued)

(Unaudited)

(Millions of $)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Gain (loss) on disposal of discontinued operations before tax		2			(115	)		4			(115	)
Income tax benefit (expense) from disposal of discontinued operations		(1	)		45			(2	)		45
Gain (loss) on disposal of discontinued operations		1			(70	)		2			(70	)
Net income (loss)		102			30			194			(63	)
Noncontrolling interest - loss from discontinued operations		-			(2	)		-			(4	)
Net income (loss) attributable to member	$	102		$	28		$	194		$	(67	)

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

E.ON U.S. LLC and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income (Loss)

(Unaudited)

(Millions of $)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Net income (loss)	$	102		$	30		$	194		$	(63	)
Other comprehensive income (loss):
Gain (loss) on derivative instruments, net of tax benefit (expense) of $(8), $1, $(7), and $(1), respectively (Note 6)		13			(2	)		10			2
Equity investee's other comprehensive income (loss), net of tax benefit benefit of $1, $0, $1, and $0, respectively		(2	)		-			(2	)		-
Foreign currency translation adjustment, net of tax benefit of $0, $1, $0 and $3, respectively		-			-			-			(7	)
Comprehensive income (loss)		113			28			202			(68	)
Noncontrolling interest - loss from discontinued operations		-			(2	)		-			(4	)
Other comprehensive (income) loss allocable to noncontrolling interest:
Foreign currency translation adjustment		-			1			-			6
Income tax benefit related to items of other comprehensive income		-			-			-			(1	)
Comprehensive income (loss) attributable to member	$	113		$	27		$	202		$	(67	)

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

E.ON U.S. LLC and Subsidiaries

Condensed Consolidated Statements of Retained Deficit

(Unaudited)

(Millions of $)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Balance at beginning of period	$	(2,702	)	$	(1,302	)	$	(2,763	)	$	(1,172	)
Net income (loss) attributable to member		102			28			194			(67	)
Cash dividends declared		(25	)		(8	)		(56	)		(43	)
Balance at end of period	$	(2,625	)	$	(1,282	)	$	(2,625	)	$	(1,282	)

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

E.ON U.S. LLC and Subsidiaries

Condensed Consolidated Balance Sheets

(Unaudited)

(Millions of $)

	September 30,			December 31,
	2010			2009
Assets:
Current assets:
Cash and cash equivalents	$	6		$	7
Accounts receivable:
Customer - less reserve of $4 in 2010 and $2 in 2009		293			286
Affiliated companies		6			-
Other - less reserve of $3 in 2010 and $2 in 2009		39			34
Materials and supplies:
Fuel (predominantly coal)		164			158
Gas stored underground		61			56
Other materials and supplies		76			72
Deferred income taxes - net		22			10
Assets of discontinued operations (Note 3)		-			90
Regulatory assets (Note 4)		35			46
Prepayments and other current assets		18			36
Total current assets		720			795
Investment in unconsolidated venture		22			21
Property, plant and equipment:
Regulated utility plant - electric and gas		9,759			9,092
Nonregulated property, plant and equipment		12			19
Property, plant and equipment in service, gross		9,771			9,111
Accumulated depreciation		(3,666	)		(3,560	)
Construction work in progress		1,258			1,599
Property, plant and equipment - net		7,363			7,150
Deferred debits and other assets:
Collateral deposit (Notes 6 and 7)		21			17
Regulatory assets (Notes 4 and 8):
Pension and postretirement benefits		309			309
Other regulatory assets		285			242
Goodwill		837			837
Cash surrender value of key man life insurance		39			38
Other assets		11			20
Total deferred debits and other assets		1,502			1,463
Total assets	$	9,607		$	9,429

E.ON U.S. LLC and Subsidiaries

Condensed Consolidated Balance Sheets (Continued)

(Unaudited)

(Millions of $)

	September 30,		December 31,
	2010		2009
Liabilities and Equity:
Current liabilities:
Current portion of long-term debt (Notes 7 and 10)	$	348	$	348
Current portion of long-term debt to affiliated company (Notes 12 and 10)		458		358
Notes payable to affiliated company (Note 12)		1,006		851
Accounts payable		205		222
Accounts payable to affiliated companies (Note 12)		44		43
Customer deposits		48		44
Liabilities of discontinued operations (Note 3)		-		7
Regulatory liabilities (Note 4)		25		42
Derivative liabilities (Note 6)		31		76
Other current liabilities		116		117
Total current liabilities		2,281		2,108
Long-term debt (Notes 7 and 10)		416		416
Long-term debt to affiliated companies (Notes 7, 10 and 12)		2,763		3,063
Total long-term debt		3,179		3,479
Deferred credits and other liabilities:
Deferred income taxes		203		87
Accumulated provision for pensions and related benefits (Note 8)		541		540
Investment tax credits – net (Note 9)		150		152
Asset retirement obligations (Note5)		121		65
Regulatory liabilities (Note 4):
Accumulated cost of removal of utility plant		613		587
Other regulatory liabilities		63		76
Derivative liabilities (Notes 6 and 7)		50		28
Other liabilities		78		83
Total deferred credits and other liabilities		1,819		1,618

E.ON U.S. LLC and Subsidiaries

Condensed Consolidated Balance Sheets (Continued)

(Unaudited)

(Millions of $)

	September 30,			December 31,
	2010			2009
Equity:
Membership units, without par value - Authorized 10,000,000 units, outstanding 1,001 units		774			774
Additional paid-in capital		4,224			4,224
Accumulated other comprehensive loss		(45	)		(43	)
Retained deficit		(2,625	)		(2,763	)
Total member's equity		2,328			2,192
Noncontrolling interest		-			32
Total equity		2,328			2,224
Total liabilities and equity	$	9,607		$	9,429

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

E.ON U.S. LLC and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(Unaudited)

(Millions of $)

	Nine Months Ended
	September 30,
	2010			2009
Cash flows from operating activities:
Net income (loss)	$	194		$	(63	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, accretion and amortization		211			203
Deferred income taxes - net		85			38
Investment tax credits (Note 9)		(2	)		17
Provision for pensions and postretirement benefits		55			62
Unrealized (gain) loss on derivatives (Note 6)		14			(24	)
Regulatory asset for unrealized gain on interest rate swaps (Note 4)		(22	)		-
Undistributed earnings of unconsolidated ventures		(3	)		10
Loss from discontinued operations - net of tax (Note 3)		2			199
Other		(1	)		(1	)
Changes in current assets and liabilities:
Accounts receivable		(9	)		123
Materials and supplies		(14	)		35
Regulatory assets and liabilities		(6	)		41
Income tax receivable		15			-
Accounts payable		(33	)		(79	)
Accrued interest		-			(91	)
Prepayments and other		16			9
Changes in regulatory assets and liabilities		(15	)		(109	)
Changes in smelter contract liability		(45	)		-
Pension and postretirement funding		(54	)		(39	)
Net operating cash flows from discontinued operations		27			(578	)
Other		(5	)		1
Net cash flows provided by (used in) operating activities		410			(246	)

E.ON U.S. LLC and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Continued)

(Unaudited)

(Millions of $)

	Nine Months Ended
	September 30,
	2010			2009
Cash flows from investing activities:
Proceeds from sales of property		-			2
Construction expenditures		(326	)		(507	)
Construction expenditures - discontinued operations		-			(23	)
Proceeds from sales of discontinued operations		21			-
Change in restricted cash		-			9
Change in non-hedging derivatives (Note 4)		-			6
Net cash flows used in investing activities		(305	)		(513	)
Cash flows from financing activities:
Borrowings from affiliated companies (Note 12)		627			1,709
Repayment of borrowings from affiliated companies (Note 12)		(671	)		(912	)
Payment of common dividends (Note 12)		(62	)		(43	)
Net cash flows (used in) provided by financing activities		(106	)		754
Change in cash and cash equivalents		(1	)		(5	)
Cash and cash equivalents at beginning of period		7			15
Cash and cash equivalents at end of period	$	6		$	10

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

E.ON U.S. LLC AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(Unaudited)

Note 1 - General

E.ON U.S. is an indirect wholly-owned subsidiary of E.ON, a German corporation. The consolidated financial statements include the following companies:  E.ON U.S., LG&E, KU, LEM, Servco and Capital Corp., and their wholly owned subsidiaries.  E.ON U.S.'s utility operations are comprised of LG&E and KU.  E.ON and E.ON U.S. are registered as holding companies under PUHCA 2005 and were formerly registered holding companies under PUHCA 1935.

LG&E and KU are regulated public utilities engaged in the generation, transmission, distribution and sale of electric energy.  LG&E also engages in the distribution and sale of natural gas.  LG&E and KU maintain their separate identities and serve customers in Kentucky under their respective names.  KU also serves customers in Virginia under the Old Dominion Power name, and it serves customers in Tennessee under the KU name.

Capital Corp. has been the primary holding company for the Company's non-utility businesses.  Its businesses included:

∙  WKE and affiliates.  WKE had a 25-year lease of and operated the generating facilities of Big Rivers, a power generation cooperative in western Kentucky, and a coal-fired facility owned by Henderson Municipal Power and Light, which is owned by the City of Henderson, Kentucky.  The Company classified WKE as discontinued operations effective December 31, 2005, and it terminated the WKE lease and disposed of the operations in July 2009.  See Note 3, Discontinued Operations.

∙  Argentine Gas Distribution.  Through its Argentine Gas Distribution operations, Capital Corp. owned interests in entities which distribute natural gas to approximately one million customers in Argentina through two distribution companies (Centro and Cuyana).  The Company classified its Argentine Gas Distribution operations as discontinued operations effective December 31, 2009, and it sold the operations on January 1, 2010.  See Note 3, Discontinued Operations.

Servco provides services to affiliated entities, including E.ON U.S., LG&E, KU, Capital Corp. and LEM, at cost, as permitted under PUHCA 2005.

The Company aggregates similar operating segments into a single reportable operating segment if the businesses are considered similar under the segment reporting guidance of the FASB ASC.  Since the termination of the WKE and the Argentine Gas Distribution operations, the Company has conducted the business as a single operating segment - the regulated utility business.

In the opinion of management, the unaudited condensed financial statements include all adjustments, consisting only of normal recurring adjustments, necessary for fair statements of income, comprehensive income (loss), retained deficit, balance sheets, and statements of 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.  These unaudited condensed financial statements and notes should be read in conjunction with the Company's Financial Statements for the year ended December 31, 2009, including the notes therein.

The December 31, 2009, condensed balance sheet included herein is derived from the December 31, 2009, audited balance sheet.  Amounts reported in the condensed statements of income are not necessarily indicative of amounts expected for the respective annual periods due to the effects of seasonal temperature variations on energy consumption, regulatory rulings, the timing of maintenance on electric generating units, changes in mark-to-market valuations, changing commodity prices and other factors.

Certain reclassification entries have been made to the previous year's financial statements to conform to the 2010 presentation with no impact on total assets, liabilities and capitalization or previously reported net income and cash flows.  These reclassifications consist mainly of those necessary to present the Company's Argentine Gas Distribution businesses as discontinued operations.  See Note 3, Discontinued Operations.

PPL Acquisition

On April 28, 2010, E.ON U.S. announced that a Purchase and Sale Agreement (the "Agreement") had been entered into among E.ON US Investments, PPL and E.ON.

The Agreement provides for the sale of E.ON U.S. to PPL.  Pursuant to the Agreement, at closing, PPL will acquire all of the outstanding limited liability company interests of E.ON U.S. for cash consideration of $2.6 billion.  In addition, pursuant to the Agreement, PPL agreed to assume $764 million of pollution control bonds and medium term notes and to repay indebtedness owed by E.ON U.S. and its subsidiaries to E.ON US Investments and its affiliates.  Such affiliate indebtedness is currently estimated to be $4.2 billion.  The aggregate consideration payable by PPL on closing is currently estimated to be $7.6 billion (including the assumed indebtedness), subject to contractually agreed adjustments.

The transaction is subject to customary closing conditions, including the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Act, receipt of required regulatory approvals (including state regulators in Kentucky, Virginia and Tennessee, and the FERC) and the absence of injunctions or restraints imposed by governmental entities.  As of October 26, 2010, all of the required regulatory approvals were received, and the transaction is expected to close on November 1, 2010.

Change of control and financing-related applications were filed on May 28, 2010, with the Kentucky Commission and on June 15, 2010, with the Virginia Commission and the Tennessee Regulatory Authority.  An application with the FERC was filed on June 28, 2010.  During the second quarter of 2010, a number of parties were granted intervenor status in the Kentucky Commission proceedings and data request filings and responses occurred.  Early termination of the Hart-Scott-Rodino waiting period was received on August 2, 2010.

A hearing in the Kentucky Commission proceedings was held on September 8, 2010 at which time a unanimous settlement agreement was presented.  In the settlement, LG&E and KU commit that no base rate increases would take effect before January 1, 2013.  The LG&E and KU rate increases that took effect on August 1, 2010, were not impacted by the settlement.  Under the terms of the settlement, the Companies retain the right to seek approval for the deferral of "extraordinary and uncontrollable costs."  Interim rate adjustments will continue to be permissible during that period for existing fuel, environmental and demand-side management cost trackers.  The agreement also substitutes an acquisition savings shared deferral mechanism for the requirement that the Companies file a synergies plan with the Kentucky Commission.  This mechanism, which will be in place until the earlier of five years or the first day of the year in which a base rate increase becomes effective, permits the Companies to earn up to a 10.75 percent return on equity.  Any earnings above a 10.75 percent return on equity will be shared with customers on a 50%/50% basis.  On September 30, 2010, the Kentucky Commission issued an Order approving the transfer of ownership of LG&E and KU via the acquisition of E.ON U.S. by PPL, incorporating the terms of the submitted settlement.  On October 19, 2010 and October 21, 2010, respectively, Orders approving the acquisition of E.ON U.S. by PPL were received from the Virginia Commission and the Tennessee Regulatory Authority.  The Commissions’ Orders contained a number of other commitments with regard to operations, workforce, community involvement and other matters.

In mid-September 2010, LG&E and KU and other applicants in the FERC change of control proceeding reached an agreement with the protesters, whereby such protests have been withdrawn.  The agreement, which has subsequently been filed for consideration with the FERC, includes various conditional commitments, such as a continuation of certain existing undertakings with protesters in prior cases, an agreement not to terminate certain KU municipal customer contracts prior to January 2017, an exclusion of any transaction-related costs from wholesale energy and tariff customer rates to the extent that the Company has agreed to not seek the same transaction-related cost from retail customers and agreements to coordinate with protesters in certain open or ongoing matters.  A FERC Order approving the transaction was received on October 26, 2010.

On September 30, 2010, LG&E and KU received Kentucky Commission approval to complete certain refinancing transactions in connection with the anticipated PPL acquisition and other business factors.  KU also received the same approvals from the Virginia Commission and the Tennessee Regulatory Authority on October 19, 2010 and October 21, 2010, respectively.  Based on credit and financial market conditions, LG&E and KU anticipate issuing up to $535 million and $1.5 billion in first mortgage bonds, respectively, the proceeds of which will substantially be used to refund existing long-term intercompany debt.  On October 22, 2010, as required by existing covenants, in connection with the anticipated issuance of any such secured debt, LG&E completed collateralization of certain outstanding pollution control bond debt series which were formerly unsecured.  On October 29, 2010, as required by existing covenants, in connection with the anticipated issuance of any such secured debt, KU completed collateralization of certain outstanding pollution control bond debt series which were formerly unsecured.  Pursuant to such collateralization, approximately $574 million and $351 million, respectively, of LG&E's and KU's existing pollution control debt (including $163 million of reacquired bonds at LG&E) became collateralized debt, supported by a first mortgage lien.  LG&E also anticipates replacing its $125 million bilateral lines of credit with unaffiliated institutions by entering into a multi-year revolving credit facility with several financial institutions in an aggregate amount not to exceed $400 million.  KU also anticipates replacing its $35 million bilateral line of credit with an unaffiliated institution by entering into a multi-year revolving credit facility with several financial institutions in an aggregate amount not to exceed $400 million.  LG&E and KU may complete these transactions, in whole or in part, during late 2010 and early 2011.  See Note 10, Short-Term and Long-Term Debt, for further information regarding the refinancing, remarketing or conversion of existing pollution control debt.

Recent Accounting Pronouncements

Fair Value Measurements

In January 2010, the FASB issued guidance related to fair value measurement disclosures requiring separate disclosure of amounts of significant transfers in and out of level 1 and level 2 fair value measurements and separate information about purchases, sales, issuances and settlements within level 3 measurements.  This guidance is effective for the interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about the roll-forward of activity in level 3 fair value measurements.  Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years.  This guidance has no impact on the Company's results of operations, financial position, liquidity or disclosures.

Note 2 - Goodwill

The following table shows goodwill as of and for the periods ended September 30, 2010, and December 31, 2009.  Goodwill is attributable to the Company's regulated utilities, LG&E and KU.

			Accumulated
	Cost		Impairment			Net
(in millions)
Balance at January 1, 2009	$	4,136	$	(1,806	)	$	2,330
Impairment loss		-		(1,493	)		(1,493	)
Balance at December 31, 2009
and September 30, 2010	$	4,136	$	(3,299	)	$	837

The Company performs its required annual goodwill impairment test in the fourth quarter of each year.  Impairment tests are performed between the annual tests when the Company determines that a triggering event that would, more likely than not, reduce the fair value of a reporting unit below its carrying value has occurred.  The goodwill impairment test is comprised of a two-step process.  In step 1, the Company identifies a potential impairment by comparing the estimated fair value of the regulated utilities (the goodwill reporting unit) to their carrying value, including goodwill, on the measurement date.  If the fair value is less than the carrying value, then step 2 is performed to measure the amount of impairment loss.  The step 2 calculation compares the implied fair value of the goodwill to the carrying value of the goodwill.  The implied fair value of goodwill is equal to the excess of the regulated utilities' estimated fair value over the fair values of its identified assets and liabilities.  If the carrying value of goodwill exceeds the implied fair value of goodwill, an impairment loss is recognized in an amount equal to that excess (but not in excess of the carrying value).

The determination of the fair value of the regulated utilities and their assets and liabilities is performed as of the measurement date using observable market data before and after the measurement date (if that subsequent information is relevant to the fair value on the measurement date).  For the 2009 annual impairment test, the estimated fair value of the regulated utilities was based on a combination of the income approach, which estimates the fair value of the reporting unit based on discounted future cash flows, and the market approach, which estimates the fair value of the reporting unit based on market comparables.  The discounted cash flows for LG&E and KU were based on discrete financial forecasts developed by management for planning purposes and consistent with those given to E.ON.  Cash flows beyond the discrete forecasts were estimated using a terminal-value calculation, which incorporated historical and forecasted financial trends for each of LG&E and KU and considered long-term earnings growth rates for publicly-traded peer companies.  The level 3 income-approach valuations included a cash flow discount rate of 6.3% and a terminal-value growth rate of 1.1%.

In addition, subsequent to 2009, but prior to the issuance of the 2009 financial statements, discussions were held with interested parties for the possible sale of the Company, including the regulated utilities.  Data from this process was used for evaluating the carrying value of goodwill as of December 31, 2009.

Based on information represented by bids received from interested parties, the Company completed a goodwill impairment analysis as of December 31, 2009.  Step 1 of the impairment test indicated a possible impairment, so the Company completed step 2.  The implied fair value of goodwill in the step 2 calculation was determined in the same manner utilized to estimate the amount of goodwill recognized in a business combination.   The Company concluded that the fair values of LG&E and KU assets and liabilities equaled their book values, due to the regulatory environment in which they operate.  The Kentucky and Virginia Commissions allow LG&E and KU to earn returns on their capitalization, which approximates book values of their regulated asset bases, at rates the Commissions determine to be fair and reasonable.  Since there is no current prospect for deregulation, the Company assumed LG&E and KU will remain in a regulated environment for the foreseeable future.  As a result of the impairment analysis described above, the Company recorded a 2009 goodwill impairment charge of $1.493 billion.

The primary factors contributing to the goodwill impairment charges were the significant economic downturn, which caused a decline in the volume of projected sales of electricity to commercial customers, and an increase in the implied discount rate due to higher risk premiums.  In addition, a lower control premium was assumed, based on observable market data.

Note 3 - Discontinued Operations

WKE Lease

Through WKE and its subsidiaries, the Company had a 25-year lease on and operated the generating facilities of Big Rivers, a power-generating cooperative in western Kentucky, and a coal-fired generating facility owned by the City of Henderson, Kentucky.

In March 2007, the Company entered into a termination agreement with Big Rivers to terminate the lease and the operational agreements for nine coal-fired power plants and one oil-fired electricity-generating facility in western Kentucky.  The transaction closed in July 2009.  Assets and liabilities remaining after the completion of the transaction have been reclassified to continuing operations in the balance sheets.  During the three and nine months ended September 30, 2010, the Company made payments totaling $15 million and $47 million, respectively, as part of the transaction.  The Company will continue to make payments related to the transaction through January 2011, and under certain circumstances to the end of 2011.  The estimated remaining payments were accrued at September 30, 2010, and December 31, 2009.  See also Note 7, Fair Value Measurements, Note 9, Income Taxes, and the Guarantees section in Note 11, Commitments and Contingencies, for further discussion of these or of additional elements of the WKE lease termination transaction.

The table below provides selected income statement information for the WKE discontinued operations:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
(in millions)
Revenues	$	-		$	10		$	-		$	128
Income (loss) before taxes		(2	)		(1	)		(7	)		(207	)
Income tax (expense) benefit		1			-			3			78
Income (loss) from discontinued operations		(1	)		(1	)		(4	)		(129	)
Gain (loss) on disposal of discontinued operations before tax		2			(115	)		4			(115	)
Income tax benefit (expense)from (disposal) of discontinued operations		(1	)		45			(2	)		45
Gain (loss) on disposal of discontinued operations		1			(70	)		2			(70	)
Net loss	$	-		$	(71	)	$	(2	)	$	(199	)

Argentine Gas Distribution

At December 31, 2009, the Company owned interests in two gas distribution companies in Argentina: 45.9% of Centro and 14.4% of Cuyana.  These two entities served a combined customer base of approximately one million customers.  The Centro investment was consolidated due to the Company's majority ownership in the holding company of Centro.  The Cuyana investment was accounted for using the equity method due to the ownership influence the Company exerted on the businesses.

In November 2009, subsidiaries of the Company entered into agreements to sell their direct and indirect interests in Centro and Cuyana to E.ON Spain and a subsidiary, both affiliates of E.ON.  On January 1, 2010, the parties completed the transfer of the interests for a sale price of $35 million.  In December 2009, the Company recorded an impairment loss of $12.4 million before income taxes.  The impairment loss represented the difference between the carrying values of the Company's interests in Centro and Cuyana and the sales price.  The Company classified the assets, liabilities and results of operations of the Argentine gas distribution companies, including the impairment loss, as discontinued operations for all periods presented effective December 31, 2009.  In connection with the reorganization transaction, E.ON Spain assumed rights and obligations relating to claims and liabilities associated with the former Argentine businesses or indemnified the Company with respect to such matters.

The table below provides summarized income statement information for the Argentine gas distribution discontinued operations:

	Three			Nine
	Months			Months
	Ended			Ended
	September 30,			September 30,
	2009			2009
(in millions)
Revenues	$	22		$	50
Income before taxes	$	10		$	11
Income tax expense		(4	)		(6	)
Noncontrolling interest		(2	)		(4	)
Net income	$	4		$	1

The table below provides summarized balance-sheet information for the Argentine gas distribution discontinued operations as of December 31, 2009:

(in millions)
Assets:
Current assets	$	25
Property, plant and equipment		52
Investments in unconsolidated ventures		7
Deferred income taxes		6
Total assets	$	90
Liabilities:
Other liabilities	$	7

Note 4 - Rates and Regulatory Matters

LG&E's and KU's Kentucky base rates are calculated based on a return on capitalization (common equity, long-term debt and notes payable) including certain regulatory adjustments to exclude non-regulated investments and environmental compliance plans recovered separately through the ECR mechanism.  Currently, none of the regulatory assets or regulatory liabilities are excluded from the return on capitalization utilized in the calculation of Kentucky base rates; therefore, a return is earned on all Kentucky regulatory assets.

KU’s Virginia base rates are calculated based on a return on rate base (net utility plant less deferred taxes and miscellaneous deductions).  All regulatory assets and liabilities are excluded from the return on rate base utilized in the calculation of Virginia base rates.

For a description of each line item of regulatory assets and liabilities and for descriptions of certain matters which may not have undergone material changes relating to the period covered by this quarterly report, reference is made to Note 5, Rates and Regulatory Matters, of the Company's audited financial statements for the year ended December 31, 2009.

2010 Electric and Gas Rate Cases

In January 2010, LG&E and KU filed applications with the Kentucky Commission requesting increases in electric base rates of approximately 12%, or $95 million and $135 million annually, respectively.  In addition, LG&E requested an increase in its gas base rates of approximately 8%, or $23 million annually.  All requested rate increases for both LG&E and KU included an 11.5% return on equity.  LG&E and KU requested the increases, based on the twelve month test year ended October 31, 2009, to become effective on and after March 1, 2010.  The requested rates were suspended until August 1, 2010.  A number of intervenors entered the rate cases, including the AG, certain representatives of industrial and low-income groups and other third parties, and submitted filings challenging the utilities' requested rate increases, in whole or in part.  A hearing was held on June 8, 2010.  LG&E and all of the intervenors, except for the AG, agreed to a stipulation providing for increases in LG&E's electric base rates of $74 million annually and LG&E's gas base rates of $17 million annually, and filed a request with Kentucky Commission to approve such settlement.  KU and all of the intervenors, except for the AG, agreed to a stipulation providing for increases in KU's electric base rates of $98 million annually, and filed a request with the Kentucky Commission to approve such settlement.  An Order in the proceeding was issued in July 2010, approving all the provisions in the stipulation.  The new rates became effective on August 1, 2010.

Virginia Rate Case

In June 2009, KU filed an application with the Virginia Commission requesting an increase in electric base rates for its Virginia jurisdictional customers in an amount of $12 million annually or approximately 21%.  The proposed increase reflected a proposed rate of return on rate base of 8.586% based on a return on equity of 12%.  During December 2009, KU and the Virginia Commission Staff agreed to a Stipulation and Recommendation authorizing base rate revenue increases of $11 million annually and a return on rate base of 7.846% based on a 10.5% return on common equity.  A public hearing was held during January 2010.  As permitted, pursuant to a Virginia Commission Order, KU elected to implement the proposed rates effective November 1, 2009, on an interim basis.  In March 2010, the Virginia Commission issued an Order approving the stipulation, with the increased rates to be put into effect as of April 1, 2010.  As part of the stipulation, KU refunded approximately $1 million in interim rate amounts in excess of the ultimate approved rates.  During August 2010, a report was filed detailing the costs of the refunds, the accounts charged and details validating that all refunds have been applied.

FERC Wholesale Rate Case

In September 2008, KU filed an application with the FERC for increases in electric base rates applicable to wholesale power sales contracts or interchange agreements involving, collectively, twelve Kentucky municipalities.  The application requested a shift from an all-in stated unit charge rates to an unbundled formula rate, including an annual adjustment mechanism.  In May 2009, the FERC issued an Order approving a settlement among the parties in the case, incorporating increases of approximately 3% from prior rates and a return on equity of 11%.  In May 2010, KU submitted to the FERC the proposed current annual adjustment to the formula rate.  This updated rate became effective on July 1, 2010, subject to certain review procedures by the wholesale requirements customers and the FERC, including potential refunds in the case of disallowed costs or charges.

By mutual agreement, the parties' settlement of the 2008 application left outstanding the issue of whether KU must allocate to the municipal customers a portion of renewable resources it may be required to procure on behalf of its retail ratepayers.  In August 2009, the FERC accepted the issue for briefing and the parties completed briefing submissions during 2009.  An Order was issued by the FERC in July 2010, indicating that KU is not required to allocate a portion of any renewable resources to the twelve municipalities, thus resolving the remaining issue.

Regulatory Assets and Liabilities

The following regulatory assets and liabilities were included in the consolidated balance sheets as of:

	September 30,		December 31,
	2010		2009
(in millions)
Current regulatory assets:
Storm restoration (a)	$	13	$	-
GSC (b)		4		3
FAC (c)		8		1
ECR (c)		3		35
MISO exit (a)		2		3
Other (a) (d)		5		4
Total current regulatory assets	$	35	$	46
Non-current regulatory assets:
Pension and postretirement benefits (e)	$	309	$	309
Other non-current regulatory assets:
Storm restoration (a)		111		126
ARO (f)		67		60
Mark-to-market impact of interest rate swaps (g)		50		-
Unamortized loss on bonds (a)		33		34
Swap termination (a)		9		-
MISO exit (a)		5		13
Other (d)		10		9
Subtotal other non-current regulatory assets		285		242
Total non-current regulatory assets	$	594	$	551

	September 30,		December 31,
	2010		2009
Current regulatory liabilities:
GSC	$	8	$	34
DSM		9		7
ECR		6		-
Other (h)		2		-
Total current regulatory liabilities	$	25	$	41
Non-current regulatory liabilities:
Accumulated cost of removal of utility plant	$	613	$	587
Other non-current regulatory liabilities:
Deferred income taxes – net		44		50
Postretirement benefits		9		9
MISO exit		1		7
Other (h)		9		10
Subtotal other non-current regulatory liabilites		63		76
Total non-current regulatory liabilities	$	676	$	663

(a)  These regulatory assets are recovered through base rates.

(b)  The GSC and gas performance-based ratemaking regulatory assets have separate recovery mechanisms with recovery within eighteen months.

(c)  The FAC and ECR regulatory assets have separate recovery mechanisms with recovery within twelve months.

(d)  Other regulatory assets:

  •  A return was earned on the balance of Mill Creek Ash Pond costs included in other current regulatory assets at December 31, 2009, as well as recovery of these costs.  There is no remaining balance as of September 30, 2010.

  •  Other current and non-current regulatory assets, including the CMRG and KCCS contributions, an EKPC FERC transmission settlement agreement and rate case expenses, are recovered through base rates.

  •  The current portion of the unamortized loss on bonds is recovered through base rates.

  •  KU generally recovers the FERC jurisdictional portion of the EKPC FERC transmission settlement agreement included in current and non-current regulatory assets in the annual formula rate updates.

  •  Recovery of the FERC jurisdictional pension expense in non-current regulatory assets will be requested in the next FERC rate case.

  •  The current portion of the swap termination and unamortized loss on bonds is recovered through base rates.

(e)  LG&E and KU generally recover this asset through pension expense included in the calculation of base rates.

(f)  When an asset with an ARO is retired, the related ARO regulatory asset will be offset against the associated ARO regulatory liability, ARO asset and ARO liability.

(g)  Beginning in the third quarter of 2010, based on an Order from the Kentucky Commission in the 2010 rate case whereby the cost of a terminated interest rate swap was allowed to be recovered in base rates, the mark-to-market impact of the effective and ineffective interest rate swaps is considered probable of recovery through rates and therefore included in regulatory assets.  No return is currently earned on this regulatory asset.  See Note 6, Derivative Financial Instruments, for further discussion.

(h)  Other current and non-current regulatory liabilities includes the Virginia levelized fuel factor, ARO liabilities, and a change in accounting method for FERC jurisdictional spare parts.  ARO liabilities are established from the removal costs accrued through depreciation under regulatory accounting for assets associated with AROs.

Storm Restoration

In January 2009, a significant ice storm passed through LG&E's and KU's service territories causing approximately 404,000 customer outages, followed closely by a severe wind storm in February 2009, causing approximately 81,000 customer outages.  LG&E and KU incurred $44 million and $57 million, respectively, in incremental operation and maintenance expenses, and $10 million and $33 million, respectively, in capital expenditures related to the restoration following the two storms.  LG&E and KU filed an application with the Kentucky Commission in April 2009, requesting approval to establish regulatory assets, and defer for future recovery, approximately $45 million and $62 million, respectively, in incremental operation and maintenance expenses related to the storm restoration.  In September 2009, the Kentucky Commission issued an Order allowing LG&E and KU to establish regulatory assets of up to $45 million and $62 million, respectively, based on their actual costs for storm damages and service restoration due to the January and February 2009 storms.  In September 2009, LG&E and KU established regulatory assets of $44 million and $57 million, respectively, for actual costs incurred, and received approval in their 2010 base rate cases to recover these assets over a ten year period, beginning August 1, 2010.

In September 2008, high winds from the remnants of Hurricane Ike passed through the service territory causing significant outages and system damage.  In October 2008, LG&E and KU filed an application with the Kentucky Commission requesting approval to establish a regulatory asset, and defer for future recovery, approximately $24 million and $3 million, respectively, of expenses related to the storm restoration.  In December 2008, the Kentucky Commission issued an Order allowing LG&E and KU to establish regulatory assets of up to $24 million and $3 million, respectively, based on their actual costs for storm damages and service restoration due to Hurricane Ike.  In December 2008, LG&E and KU established regulatory assets of $24 million and $2 million, respectively, for actual costs incurred, and LG&E and KU received approval in their 2010 base rate cases to recover these assets over a ten year period, beginning August 1, 2010.

GSC

In December 2009, LG&E filed with the Kentucky Commission an application to extend and modify its existing gas cost PBR.  The current PBR was set to expire at the end of October 2010.  In April 2010, the Kentucky Commission issued an Order approving a five year extension and the requested minor modifications to the PBR effective November 2010.

FAC

In August 2010, the Kentucky Commission initiated a six-month review of LG&E's and KU's FAC mechanism for the expense period ended April 2010.  An order is expected by the end of the year.

In February 2010, KU filed an application with the Virginia Commission seeking approval of a decrease in its fuel cost factor beginning with service rendered in April 2010.  An Order was issued in April 2010, resulting in an agreed on decrease of 23% from the fuel factor in effect for April 2009 through March 2010.

In January 2010, the Kentucky Commission initiated a six-month review of LG&E's and KU's FAC mechanism for the expense period ended August 2009.  In May 2010, an Order was issued approving the charges and credits billed through the FAC during the review period.

ECR

In July 2010, the Kentucky Commission initiated a six-month review of LG&E's and KU's environmental surcharge for the billing period ending April 2010.  An order is expected in the fourth quarter of 2010.

In January 2010, the Kentucky Commission initiated a six-month review of LG&E's and KU's environmental surcharge for the billing period ending October 2009.  In May 2010, an Order was issued approving the amounts billed through the ECR during the six-month period and the rate of return on capital, and allowing recovery of the under-recovery position in subsequent monthly filings.

In June 2009, LG&E and KU filed applications for a new ECR plan with the Kentucky Commission seeking approval to recover investments in environmental upgrades and operations and maintenance costs at their generating facilities.  During 2009, LG&E and KU reached a unanimous settlement with all parties to the case and the Kentucky Commission issued an Order approving their application.  Recovery on customer bills through the monthly ECR surcharge for these projects began with the February 2010 billing cycle.  At December 31, 2009, KU had a regulatory asset of $28 million, which changed to a regulatory liability in the first quarter of 2010, as a result of these roll-in adjustments to base rates.  At September 30, 2010, the regulatory liability balance was $6 million.

MISO

In August 2010, the FERC issued three Orders accepting most facets of several MISO Revenue Sufficiency Guarantee ("RSG") compliance filings.  The FERC ordered the MISO to issue refunds for RSG charges that were imposed by the MISO on the assumption that there were rate mismatches for the period beginning November 5, 2007 through the present. There is no financial statement impact to the Company from this Order, as the MISO had anticipated that the FERC would require these refunds and had preemptively included them in the resettlements paid in 2009.  The FERC denied the MISO's proposal to exempt certain resources from RSG charges, effective prospectively.  The FERC accepted portions and rejected portions of the MISO's proposed RSG rate Redesign Proposal, which will be effective when the software is ready for implementation subject to further compliance filings.  The impact of the Redesign Proposal on the Company cannot be estimated at this time.

Interest Rate Swaps

Interest rate swaps are accounted for on a fair value basis in accordance with the derivatives and hedging topic of the FASB ASC.  Beginning in the third quarter of 2010, the unrealized gains and losses of the effective and ineffective interest rate swaps are included in a regulatory asset based on an Order from the Kentucky Commission in the 2010 rate case whereby the cost of a terminated swap was allowed to be recovered in base rates.  Previously, interest rate swaps designated as effective cash flow hedges had resulting gains and losses recorded within OCI and common equity.  The ineffective portion of interest rate swaps designated as cash flow hedges was previously recorded to earnings monthly, as was the entire change in the market value of the ineffective swaps.  LG&E is able to recover the unrealized gains and losses on the interest rate swaps under its existing rate recovery structure as the interest expense on the swaps is realized.

Other Regulatory Matters

TC2 Depreciation

In August 2009, LG&E and KU jointly filed an application with the Kentucky Commission to approve new common depreciation rates for applicable jointly-owned TC2-related generating, pollution control and other plant equipment and assets.  During December 2009, the Kentucky Commission extended the data discovery process through January 2010, and authorized LG&E and KU on an interim basis to begin using the depreciation rates for TC2 as proposed in the application.  In March 2010, the Kentucky Commission issued a final Order approving the use of the proposed depreciation rates on a permanent basis.

TC2 Transmission Matters

LG&E's and KU's CCN for a transmission line associated with the TC2 construction has been challenged by certain property owners in Hardin County, Kentucky.  In August 2006, LG&E and KU obtained a successful dismissal of the challenge at the Franklin County Circuit Court, which was reversed by the Kentucky Court of Appeals in December 2007.  In April 2009, the Kentucky Supreme Court granted LG&E's and KU's motion for discretionary review of the Court of Appeal's decision.  In August 2010, the Kentucky Supreme Court issued an Order reversing the decision of the Kentucky Court of Appeals and reinstating the Franklin County Circuit Court's dismissal of the property owners' challenge to LG&E's and KU's CCN.

During 2008, KU obtained various successful rulings at the Hardin County Circuit Court confirming its condemnation rights.  In August 2008, several landowners appealed such rulings to the Kentucky Court of Appeals.  In May 2010, the Kentucky Court of Appeals issued an Order affirming the Hardin Circuit Court's finding that KU had the right to condemn easements on the properties.  In May 2010, the landowners filed a petition for reconsideration with the Court of Appeals.  In July 2010, the Court of Appeals denied that petition.  In August 2010, the landowners filed for discretionary review of that denial by the Kentucky Supreme Court.

In a separate proceeding, certain Hardin County landowners have filed an action in federal district court in Louisville, Kentucky against the U.S. Army challenging the same transmission line claiming that certain Fort Knox-related sections of the line failed to comply with certain National Historic Preservation Act procedural requirements.  In October 2009, the federal court granted the defendants' motion for summary judgment and dismissed the plaintiffs' claims.  During November 2009, the petitioners filed submissions for review of the decision with the 6th Circuit Court of Appeals.  In May 2010, the appellate court issued an order approving the plaintiffs' voluntary withdrawal of their appeals.

Consistent with the regulatory authorizations and relevant legal proceedings, LG&E and KU have completed construction activities on temporary or permanent transmission line segments.  During the second quarter of 2010, LG&E and KU placed into operation an appropriate combination of permanent and temporary sections of the transmission line.  While LG&E and KU are not currently able to predict the ultimate outcome and possible financial effects of the remaining legal proceedings, LG&E and KU do not believe the matter involves relevant or continuing risks to operations.

Mandatory Reliability Standards

As a result of the EPAct 2005, certain formerly voluntary reliability standards became mandatory in June 2007, and authority was delegated to various Regional Reliability Organizations ("RROs") by the North American Electric Reliability Corporation ("NERC"), which was authorized by the FERC to enforce compliance with such standards, including promulgating new standards.  Failure to comply with mandatory reliability standards can subject a registered entity to sanctions, including potential fines of up to $1 million per day, as well as non-monetary penalties, depending on the circumstances of the violation. LG&E and KU are members of the SERC Reliability Corporation ("SERC"), which acts as LG&E's and KU's RRO.  During December 2009, SERC and LG&E and KU agreed to settlements involving penalties totaling less than $1 million for each utility related to their self-reports during June and October 2008, concerning possible violations of standards.  During December 2009 and April, July and August 2010, LG&E and KU submitted ten self-reports relating to various standards, which self-reports remain in the early stages of RRO review, and therefore LG&E and KU are unable to estimate the outcome of these matters.  Mandatory reliability standard settlements commonly also include non-penalty elements, including compliance steps and mitigation plans.  Settlements with SERC proceed to NERC and the FERC review before becoming final.  While LG&E and KU believe they are in compliance with the mandatory reliability standards, events of potential non-compliance may be identified from time-to-time.  LG&E and KU cannot predict such potential violations or the outcomes of the self-reports described above.

Gas Customer Choice Study

In April 2010, the Kentucky Commission commenced a proceeding to investigate natural gas retail competition programs, their regulatory, financial and operational aspects and potential benefits, if any, of such programs to Kentucky consumers.  A number of entities, including LG&E, are parties to the proceeding.  Data discovery, inclusive of a public hearing to be held by the Kentucky Commission, continued through October 2010.  An order in this proceeding is anticipated by year end.

Note 5 - Asset Retirement Obligations

A summary of the Company's net ARO assets, ARO liabilities and regulatory assets established under the asset retirement and environmental obligations guidance of the FASB ASC, follows:

	ARO Net		ARO			Regulatory
(in millions)	Assets		Liabilities			Assets
As of December 31, 2009	$	7	$	(65	)	$	60
ARO accretion		-		(4	)		4
ARO revaluation		50		(53	)		3
Removal cost incurred		-		1			-
As of September 30, 2010	$	57	$	(121	)	$	67

As of September 30, 2010, the Company performed a revaluation of its AROs as a result of recently proposed environmental legislation and improved ability to forecast asset retirement costs due to recent construction and retirement activity.

Pursuant to regulatory treatment prescribed under the regulated operations guidance of the FASB ASC, an offsetting regulatory credit was recorded in depreciation and amortization in the income statement of $4 million for the nine months ended September 30, 2010 for the ARO accretion and depreciation expense.  LG&E's and KU's AROs are primarily related to the final retirement of assets associated with generating units and natural gas wells.

LG&E and KU transmission and distribution lines largely operate under perpetual property easement agreements which do not generally require restoration on removal of the property.  Therefore, under the asset retirement and environmental obligations guidance of the FASB ASC, no material asset retirement obligations are recorded for transmission and distribution assets.

Note 6 – Derivative Financial Instruments

The Company is subject to interest rate and commodity price risk related to on-going business operations.  It currently manages these risks using derivative instruments, including swaps and forward contracts.  The Company's policies allow for the interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate swaps.  At September 30, 2010, a 100-basis-point change in the benchmark rate on the Company's variable-rate debt, not effectively hedged by an interest rate swap, would impact pre-tax interest expense by $24 million annually.

The Company does not net collateral against derivative instruments.

Interest Rate Swaps

LG&E uses over-the-counter interest rate swaps to limit exposure to market fluctuations in interest expense.  Pursuant to Company policy, use of these derivative instruments is intended to mitigate risk, earnings and cash flow volatility and is not speculative in nature.

LG&E's interest rate swap agreements range in maturity through 2033, with aggregate notional amounts of $179 million as of September 30, 2010 and December 31, 2009.  Under these swap agreements, LG&E paid fixed rates averaging 4.52% and received variable rates based on LIBOR or the Securities Industry and Financial Markets Association's municipal swap index averaging 0.22% and 0.20% at September 30, 2010 and December 31, 2009, respectively.  One swap hedging a portion of LG&E's $83 million Trimble County 2000 Series A bond has been designated as a cash flow hedge and continues to be highly effective.  The three remaining interest rate swaps are ineffective.  The unrealized gains and losses on the effective and ineffective interest rate swaps are included in a regulatory asset based on an Order from the Kentucky Commission in the 2010 rate case, whereby the cost of a terminated swap was allowed to be recovered in base rates.

The fair value of the interest rate swaps is determined by a quote from the counterparty.  This value is verified monthly by LG&E using a model that calculates the present value of future payments under the swap utilizing current swap market rates obtained from another dealer active in the swap market and validated by market transactions.  Market liquidity is considered, however, the valuation does not require an adjustment for market liquidity as the market is very active for the type of swaps used by LG&E.  LG&E considered the impact of its own credit risk and that of counterparties by evaluating credit ratings and financial information.  LG&E and all counterparties had strong investment grade ratings at September 30, 2010.  LG&E did not have any credit exposure to the swap counterparties, as it was in a liability position at September 30, 2010, therefore, the market valuation required no adjustment for counterparty credit risk.  In addition, LG&E and certain counterparties have agreed to post margin if the credit exposure exceeds certain thresholds.  Cash collateral for interest rate swaps is classified as a long-term asset in the accompanying balance sheets.

The tables below show the fair value and balance sheet location of interest rate swap derivatives:

(in millions)
September 30, 2010:
Derivative Designation	Balance Sheet Location	Fair Value
Hedging	Long-term derivative liability	$	25
Non-hedging	Long-term derivative liability		25
		$	50

December 31, 2009:
Derivative Designation	Balance Sheet Location	Fair Value
Hedging	Long-term derivative liability	$	19
Non-hedging	Long-term derivative liability		9
		$	28

Beginning in the third quarter of 2010, the unrealized gains and losses of the effective and ineffective interest rate swaps are included in a regulatory asset, which offsets the hedging and non-hedging long-term derivative liabilities.

The interest rate swaps are accounted for on a fair value basis in accordance with the derivatives and hedging topic of the FASB ASC.  The tables below show the pre-tax amount and income statement location of derivative gains and losses for the change in the mark-to-market value of the ineffective interest rate swaps, realized losses and the change in the ineffective portion of the interest rate swaps deemed highly effective, including the impact of reclassifying these amounts to regulatory assets during the three months ended September 30, 2010:

(in millions)		Three Months Ended
		September 30,
Gain (Loss) Recognized in Income	Location	2010			2009
Reclassification to regulatory assets of unrealized loss on interest rate swaps	Derivative gains (loss)	$	21		$	-
Unrealized loss on ineffective swaps	Derivative gain (loss)		-			(3	)
Reclassification to regulatory assets of unrealized loss on terminated swap	Derivative gain (loss)		9			-
Realized loss on ineffective swaps	Derivative gain (loss)		(1	)		(1	)
Totals		$	29		$	(4	)

For the three months ended September 30, 2009, LG&E recorded a pre-tax gain of less than $1 million in interest expense to reflect the change in the ineffective portion of the interest rate swaps deemed highly effective.  During the three months ended September 30, 2010, the Company recorded pre-tax gains of $21 million and $9 million, respectively, to reflect the reclassification of the ineffective swaps and the terminated swap to a regulatory asset.

(in millions)		Nine Months Ended
		September 30,
Gain (Loss) Recognized in Income	Location	2010			2009
Change in the ineffective portion deemed highly effective	Interest expense	$	-		$	1
Reclassification to regulatory assets of unrealized loss on interest rate swaps	Derivative gain (loss)		21			-
Unrealized gain (loss) on ineffective swaps	Derivative gain (loss)		(10	)		14
Reclassification to regulatory assets of unrealized loss on terminated swap	Derivative gain (loss)		9			-
Realized loss on ineffective swaps	Derivative gain (loss)		(2	)		(2	)
Totals		$	18		$	13

During the nine months ended September 30, 2010, the Company recorded a pre-tax gain of $21 million and $9 million, respectively, to reflect the reclassification of the ineffective swaps and the terminated swap to a regulatory asset.

The gain on hedging interest rate swaps recognized in OCI for the three and nine months ended September 30, 2010, was $21 million and $17 million, respectively.  For the three and nine months ended September 30, 2010, the gain on derivatives reclassified from accumulated OCI to regulatory assets was $23 million.

Prior to including the unrealized gains and losses on the effective and ineffective interest rate swaps in regulatory assets, amounts previously recorded in accumulated OCI were reclassified into earnings in the same period during which the hedged forecasted transaction affected earnings.  The amount amortized from OCI to income in the three-month and nine-month periods ended September 30, 2010 and 2009, was less than $1 million, respectively.

A decline of 100 basis points in the current market interest rates would reduce the fair value of LG&E's interest rate swaps by approximately $31 million.

Energy Trading and Risk Management Activities

The Company conducts energy trading and risk management activities to maximize the value of power sales from physical assets it owns.  Energy trading activities are principally forward financial transactions to manage price risk and are accounted for as non-hedging derivatives on a mark-to-market basis in accordance with the derivatives and hedging topic of the FASB ASC.

Energy trading and risk management contracts are valued using prices based on active trades from Intercontinental Exchange Inc.  In the absence of a traded price, midpoints of the best bids and offers are the primary determinants of valuation.  When sufficient trading activity is unavailable, other inputs include prices quoted by brokers or observable inputs other than quoted prices, such as one-sided bids or offers as of the balance sheet date.  Quotes are verified quarterly using an independent pricing source of actual transactions.  Quotes for combined off-peak and weekend timeframes are allocated between the two timeframes based on their historical proportional ratios to the integrated cost.  No other adjustments are made to the forward prices.  No changes to valuation techniques for energy trading and risk management activities occurred during 2010 or 2009.  Changes in market pricing, interest rate and volatility assumptions were made during both years.

The tables below show the fair value and balance sheet location of energy trading and risk management derivative contracts:

September 30, 2010:
(in millions)
	Asset Derivatives		Liability Derivatives
Derivative	Balance Sheet		Balance Sheet
Designation	Location	Fair Value	Location	Fair Value
Non-hedging	Prepayments and other current assets	$           2	Other current liabilities	$           1

December 31, 2009:
(in millions)
	Asset Derivatives		Liability Derivatives
Derivative	Balance Sheet		Balance Sheet
Designation	Location	Fair Value	Location	Fair Value
Non-hedging	Prepayments and other current assets	$            2	Other current liabilities	$            2

The Company maintains credit policies intended to minimize credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties prior to entering into transactions with them and continuing to evaluate their creditworthiness once transactions have been initiated.  To further mitigate credit risk, the Company seeks to enter into netting agreements or require cash deposits, letters of credit and parental company guarantees as security from counterparties.  The Company uses S&P, Moody's and definitive qualitative and quantitative data to assess the financial strength of counterparties on an on-going basis.  If no external rating exists, the Company assigns an internally generated rating for which it sets appropriate risk parameters.  As risk management contracts are valued based on changes in market prices of the related commodities, credit exposures are revalued and monitored on a daily basis.  At September 30, 2010, 100% of the trading and risk management commitments were with counterparties rated BBB-/Baa3 equivalent or better.  The Company has reserved against counterparty credit risk based on the counterparty's credit rating and applying historical default rates within varying credit ratings over time provided by S&P's or Moody's.  At September 30, 2010, and December 31, 2009, counterparty credit reserves related to energy trading and risk management contracts were less than $1 million.

The net volume of electricity based financial derivatives outstanding at September 30, 2010, and December 31, 2009, was zero and 631,200 Mwhs, respectively.  No cash collateral related to the energy trading and risk management contracts was required at September 30, 2010.  Cash collateral related to the energy trading and risk management contracts was $2 million at December 31, 2009.  Cash collateral related to the energy trading and risk management contracts is categorized as other accounts receivable in the accompanying balance sheets.

The Company manages the price risk of its estimated future excess economic generation capacity using market-traded forward contracts.  Hedge accounting treatment has not been elected for these transactions, and therefore realized and unrealized gains and losses are included in the statements of income.

The following tables present the effect of market-traded forward contract derivatives not designated as hedging instruments on income:

(in millions)		Three Months Ended
		September 30,
Gain (Loss) Recognized in Income	Location	2010			2009
Realized gain	Electric revenues	$	1		$	5
Unrealized loss	Electric revenues		(1	)		(6	)
Totals		$	-		$	(1	)

		Nine Months Ended
		September 30,
	Location	2010 (a)		2009
Realized gain	Electric revenues	$	3	$	8
Unrealized loss	Electric revenues		-		(2	)
Totals		$	3	$	6

(a)  Unrealized gains were less than $1 million.

Credit Risk Related Contingent Features

Certain of the Company's derivative instruments contain provisions that require the Company to provide immediate and on-going collateralization on derivative instruments in net liability positions based on the Company's credit ratings from each of the major credit rating agencies.  At September 30, 2010, there are no energy trading and risk management contracts with credit risk related contingent features that are in a liability position, and no collateral posted in the normal course of business.  The aggregate mark-to-market value of all interest rate swaps with credit risk related contingent features that are in a liability position on September 30, 2010, is $34 million, for which LG&E has posted collateral of $21 million in the normal course of business.  If the credit risk related contingent features underlying these agreements were triggered on September 30, 2010, due to a one notch downgrade in LG&E's credit rating, LG&E would be required to post an additional $4 million of collateral to its counterparties for the interest rate swaps.  At September 30, 2010, a one notch downgrade of LG&E's credit rating would have no effect on the energy trading and risk management contracts or collateral required.

See Note 7, Fair Value Measurements, for a discussion of the WKE sales contract derivative.

Note 7 - Fair Value Measurements

The Company adopted the fair value guidance in the FASB ASC in two phases.  Effective January 1, 2008, the Company adopted it for all financial instruments and non-financial instruments accounted for at fair value on a recurring basis, and January 1, 2009, the Company adopted it for all non-financial instruments accounted for at fair value on a non-recurring basis.  The FASB ASC guidance clarifies that fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants.  As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or a liability.  As a basis for considering such assumptions, the FASB ASC guidance establishes a three-tier value hierarchy, which prioritizes the inputs used in the valuation methodologies in measuring fair value.

The carrying values and estimated fair values of the Company's non-trading financial instruments as of September 30, 2010, and December 31, 2009, follow:

	September 30, 2010				December 31, 2009
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
(in millions)
Long-term debt (including current portion of $348 million)	$	764	$	771	$	764	$	764
Long-term debt to affiliated company (including current portion of $458 million and $358 million)		3,221		3,526		3,421		3,553
Derivative liability - interest rate swaps		50		50		28		28

The long-term bond valuations reflect prices quoted by investment banks, which are active in the market for these instruments.  The fair value of the long-term debt due to affiliated companies is determined using an internal valuation model that discounts the future cash flows of each loan at current market rates as determined based on quotes from investment banks that are actively involved in capital markets for utilities and factor in the Company's credit ratings and default risk.  The fair values of the interest rate swaps reflect price quotes from investment banks, consistent with the fair value measurements and disclosures topic of the FASB ASC.  This value is verified monthly by the Company using a model that calculates the present value of future payments under the swap utilizing current swap market rates obtained from another dealer active in the swap market and validated by market transactions.  The fair values of cash and cash equivalents, accounts receivable, cash surrender value of key man life insurance, accounts payable and notes payable are substantially the same as their carrying values.

The Company has classified the applicable financial assets and liabilities that are accounted for at fair value into the three levels of the fair value hierarchy, as defined by the fair value measurements and disclosures topic of the FASB ASC, as follows:

  ·  Level 1 - Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.

  ·  Level 2 - Include other inputs that are directly or indirectly observable in the marketplace.

  ·  Level 3 - Unobservable inputs which are supported by little or no market activity.

The fair value hierarchy also requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

The Company classifies its derivative cash collateral balances within level 1 based on funds being held in a demand deposit account.  The Company classifies its derivative energy trading and risk management contracts and interest rate swaps within level 2 because it values them using prices actively quoted for proposed or executed transactions, quoted by brokers or observable inputs other than quoted prices.  The Company classifies its liability for the E.ON share performance plan within level 2 because it is valued using a model that considers the quoted market price of E.ON's common shares traded on the Frankfurt Stock Exchange as well as the performance of E.ON stock compared to the change in the Dow Jones STOXX Utilities Index (Total Return EUR).  See Note 13, Share Performance Plan.  The Company classifies its derivative contracts within level 2 because it values them using prices actively quoted for proposed or executed transactions, quoted by brokers or observable inputs other than quoted prices.

Prior to its termination in 2009, the Company classified its liability for WKE's long-term sales contract within level 3.  The contracts were with an electric cooperative and two aluminum smelters.  The valuation was done on a monthly basis using market prices from Platts' on-line pricing service for the current and forward four years and a forecast for the outer years where market prices are not available.  The outer year pricing was extrapolated from an annual forecast from the Energy Information Administration for NGHH pricing based on historical ratios of around-the-clock electricity prices to NGHH prices.  See Note 3, Discontinued Operations.

The Company has an obligation through the end of 2010 (and under certain circumstances to the end of 2011) to pay one of the aluminum smelters the difference between the electricity prices charged by WKE under the previous long-term sales contract and the electricity prices charged by its current electricity supplier.  The Company also classifies this liability within level 3.  The valuation is calculated on a quarterly basis using monthly Northern East Central Area Reliability Cinergy Hub forward prices by peak-type.  See Note 3, Discontinued Operations.

The following tables set forth, by level within the fair value hierarchy, the Company's financial assets and liabilities that were accounted for at fair value on a recurring basis.

(in millions)
September 30, 2010
	Level 1		Level 2		Level 3		Totals
Financial assets:
Energy trading and risk management contracts	$	-	$	2	$	-	$	2
Interest rate swap cash collateral		21		-		-		21
Total financial assets	$	21	$	2	$	-	$	23
Financial liabilities:
Energy trading and risk management contracts	$	-	$	1	$	-	$	1
Interest rate swaps		-		50		-		50
Smelter contract		-		-		30		30
Total financial liabilities	$	-	$	51	$	30	$	81

December 31, 2009
	Level 1		Level 2		Level 3		Totals
Financial assets:
Energy trading and risk management contract cash collateral	$	2	$	-	$	-	$	2
Energy trading and risk management contracts		-		2		-		2
Interest rate swap cash collateral		17		-		-		17
Total financial assets	$	19	$	2	$	-	$	21
Financial liabilities:
Energy trading and risk management contracts	$	-	$	2	$	-	$	2
Interest rate swaps		-		28		-		28
Smelter contract		-		-		75		75
E.ON share performance plan		-		2		-		2
Total financial liabilities	$	-	$	32	$	75	$	107

The following table presents the changes in net liabilities measured at fair value using significant unobservable inputs (level 3) as defined in FASB ASC for the three months ended September 30:

(in millions)	2010			2009
Balance at beginning of period	$	45		$	804
Realized loss included in earnings		2			2
Unrealized loss included in earnings		-			1
Unrealized gain included in earnings		(3	)		(814	)
Issuances		-			106
Settlements		(14	)		(9	)
Balance at end of period	$	30		$	90

The following table presents the changes in net liabilities measured at fair value using significant unobservable inputs (level 3) as defined in FASB ASC for the nine months ended September 30:

(in millions)	2010			2009
Balance at beginning of period	$	75		$	908
Realized loss included in earnings		6			2
Unrealized loss included in earnings		2			109
Unrealized gain included in earnings		(5	)		(1,026	)
Issuances		-			106
Settlements		(48	)		(9	)
Balance at end of period	$	30		$	90

Note 8 - Pension and Other Postretirement Benefit Plans

Net Periodic Benefit Costs

The following tables provide the components of net periodic benefit cost for pension and other postretirement benefit plans for the three and nine months ended September 30, 2010 and 2009, respectively:

(in millions)	Three Months Ended September 30,
							Other
							Postretirement
	Pension Benefits						Benefits
	2010			2009			2010			2009
Service cost	$	6		$	5		$	1		$	2
Interest cost		16			16			3			3
Expected return on plan assets		(15	)		(12	)		(1	)		-
Amortization of prior service costs		2			3			-			1
Amortization of actuarial loss		5			7			-			-
Amortization of transitional obligation		-			-			1			-
Net periodic benefit cost	$	14		$	19		$	4		$	6

(in millions)	Nine Months Ended September 30,
							Other
							Postretirement
	Pension Benefits						Benefits
	2010			2009			2010			2009
Service cost	$	16		$	15		$	3		$	4
Interest cost		48			47			8			8
Expected return on plan assets		(42	)		(36	)		(2	)		(1	)
Amortization of prior service costs		6			7			1			2
Amortization of actuarial loss		15			20			-			-
Amortization of transitional obligation		-			-			1			1
Net periodic benefit cost	$	43		$	53		$	11		$	14

Contributions

In January 2010, the Company made discretionary contributions to its pension plans of $41 million.  The Company also made discretionary contributions to its WKE Union pension plan totaling $4 million in 2010.  The amount of future contributions to the pension plans will depend on the actual return on plan assets and other factors, but the Company's intent is to fund its pension plans in a manner consistent with the requirements of the Pension Protection Act of 2006.

Through September 2010, the Company made contributions to its other postretirement benefit plans totaling $9 million.  An additional contribution totaling $3 million was made in October.  The Company anticipates further funding in 2010 to match the annual postretirement expense and funding the 401(h) plan up to the maximum amount allowed by law.

Health Care Reform

In March 2010, Health Care Reform (the Patient Protection and Affordable Care Act of 2010) was signed into law.  Many provisions of Health Care Reform do not take effect for an extended period of time, and many aspects of the law which are currently unclear or undefined will likely be clarified in future regulations.

During each of the three and nine months ended September 30, 2010, KU recorded an income tax expense of less than $1 million, to recognize the impact of the elimination of the tax deduction related to the Medicare Retiree Drug Subsidy that becomes effective in 2013.

Specific provisions within Health Care Reform that may impact the Company include:

  ·  Beginning in 2011, requirements extend dependent coverage up to age 26, remove the $2 million lifetime maximum and eliminate cost sharing for certain preventative care procedures.

  ·  Beginning in 2018, a potential excise tax is expected on high-cost plans providing health coverage that exceeds certain thresholds.

The Company continues to evaluate all implications of Health Care Reform on its benefit programs, but at this time cannot predict the significance of those implications.

Note 9 - Income Taxes

A United States consolidated income tax return is filed by E.ON U.S.'s direct parent, E.ON US Investments Corp., for each tax period.  Each subsidiary of the consolidated tax group calculates its separate income tax for each period.  The resulting separate-return tax cost or benefit is paid to or received from the parent company or its designee.  The Company also files income tax returns in various state jurisdictions.  While 2007 and later years are open under the federal statute of limitations, Revenue Agent Reports for 2006-2008 have been received from the IRS, effectively closing these years to additional audit adjustments.  Tax years beginning with 2007 were examined under an IRS pilot program, Compliance Assurance Process ("CAP").  This program accelerates the IRS review to begin during the year applicable to the return and ends 90 days after the return is filed.  Adjustments for 2007, agreed to and recorded in January 2009, were comprised of $5 million of depreciation-related differences.  For 2008, the IRS allowed additional deductions in connection with the Company's application for a change in repair deductions and disallowed some of the bonus depreciation claimed on the original return.  The net temporary tax impact for the Company was $25 million; and was recorded in the second quarter of 2010.  Tax years 2009 and 2010 are also being examined under CAP.  The 2009 federal return was filed in the third quarter, and the IRS issued a Partial Acceptance Letter with the 2009 return.  The IRS is continuing to review bonus depreciation, storms and other repairs, contributions in aid of construction and purchased gas adjustments.  No material impact is expected from the IRS review.  For the tax year 2010, no material items have been raised by the IRS at this time.

In the third quarter the uncertain tax positions changed by less than $1 million.  Possible amounts of uncertain tax positions that may decrease within the next 12 months total $1 million and are based on the expiration of the audit periods as defined in the statutes.  If recognized, the $1 million of unrecognized tax benefits would reduce the effective income tax rate.

The amount recognized as interest expense and interest accrued related to unrecognized tax benefits was less than $1 million as of September 30, 2010 and December 31, 2009.  The interest expense and interest accrued is based on IRS and Kentucky Department of Revenue large corporate interest rates for underpayment of taxes.  At the date of adoption, the Company accrued less than $1 million in interest expense on uncertain tax positions.  The Company records the interest as interest expense and penalties as operating expenses in the income statement and accrued expenses in the balance sheet, on a pre-tax basis.  No penalties were accrued by the Company through September 30, 2010.

In June 2006, LG&E and KU filed a joint application with the U.S. Department of Energy ("DOE") requesting certification to be eligible for investment tax credits applicable to the construction of TC2.  In November 2006, the DOE and the IRS announced that LG&E and KU were selected to receive $125 million in tax credits.  A final IRS certification required to obtain the investment tax credits was received in August 2007.  In September 2007, LG&E and KU received an Order from the Kentucky Commission approving the accounting of the investment tax credits, which includes a full depreciation basis adjustment for the amount of the credits.  Based on eligible construction expenditures incurred, the Company recorded investment tax credits of $7 million and $21 million during the three- and nine-months ended September 30, 2009, decreasing current federal income taxes.  As of December 31, 2009, the Company had recorded its maximum credit of $125 million.  The income tax expense impact from amortizing these credits over the life of the related property will begin when the facility is placed in service, which is expected to occur by year end.

In March 2008, certain environmental and preservation groups filed suit in federal court in North Carolina against the DOE and IRS claiming the investment tax credit program was in violation of certain environmental laws and demanded relief, including suspension or termination of the program.  The  plaintiffs voluntarily dismissed their complaint in August 2010.

A reconciliation of differences between the income tax expense at the statutory U.S. federal income tax rate and the Company's actual income tax expense follows:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in millions)	2010			2009			2010			2009
Statutory federal income tax	$	56		$	56		$	108		$	70
State income taxes net of federal benefit		6			6			10			5
Dividends received deduction related to EEI     investment		-			-			-			(3	)
Other differences - net		(3	)		(5	)		(6	)		(8	)
Income tax expense	$	59		$	57		$	112		$	64
Effective income tax rate		36.6	%		36.1	%		36.4	%		32.0	%

The amounts shown in the table above are rounded to the nearest $1 million; however, the effective tax rates are based on actual underlying amounts.  Other differences – net includes the qualified production activities deduction, amortization of investment tax credits and excess deferred tax depreciation.

The effective tax rate for the nine months ended September 30, 2010, was higher than the rate for the nine months ended 2009 due to state income taxes – net of federal benefit being lower due to a coal credit recorded in 2009 and a lower dividends received deduction primarily due to the lack of EEI dividends in 2010.

Note 10 – Short-Term and Long-Term Debt

The Company's long-term debt includes $348 million of pollution control bonds that are classified as current portion of long-term debt because these bonds are subject to tender for purchase at the option of the holder and to mandatory tender for purchase on the occurrence of certain events.  These bonds include:

	Amount
LG&E:
Jefferson Co. 2001 Series A, due September 1, 2026, variable %	$	22
Trimble Co. 2001 Series A, due September 1, 2026, variable %		28
Jefferson Co. 2001 Series B, due November 1, 2027, variable %		35
Trimble Co. 2001 Series B, due November 1, 2027, variable %		35
KU:
Mercer Co. 2000 Series A, due May 1, 2023, variable %		13
Carroll Co. 2002 Series A, due February 1, 2032, variable %		21
Carroll Co. 2002 Series B, due February 1, 2032, variable %		2
Carroll Co. 2008 Series A, due February 1, 2032, variable %		78
Mercer Co. 2002 Series A, due February 1, 2032, variable %		8
Muhlenberg Co. 2002 Series A, due February 1, 2032, variable %		2
Carroll Co. 2004 Series A, due October 1, 2034, variable %		50
Carroll Co. 2006 Series B, due October 1, 2034, variable %		54
Total	$	348

The average annualized interest rates for these bonds follows:

	LG&E						KU
	September 30,						September 30,
	2010			2009			2010			2009
Three months ended		1.10	%		1.04	%		0.37	%		0.51	%
Nine months ended		0.90	%		1.11	%		0.36	%		0.65	%

Pollution control bonds are obligations of LG&E or KU issued in connection with tax-exempt pollution control bonds issued by various governmental entities, principally counties in Kentucky.  A loan agreement obligates LG&E and KU to make debt service payments to governmental entities that equate to the debt service due from the entities on the related pollution control bonds.  The loan agreement is an unsecured obligation of LG&E or KU.  Debt issuance expense is capitalized in either regulatory assets or current or long-term other assets and amortized over the lives of the related bond issues, consistent with regulatory practices.

In October 2010, LG&E and KU’s pollution control bonds were converted from unsecured debt to debt which is collateralized by first mortgage bonds.  Also, in October 2010, two national rating agencies revised the credit ratings of the pollution control bonds issued by LG&E and KU.  One revised downward the short-term credit rating of the pollution control bonds and the issuer rating of the Company, LG&E and KU as a result of the pending acquisition by PPL.  The other rating agency increased the long-term rating of the pollution control bonds of LG&E as a result of the addition of the first mortgage bonds as collateral.

Several of the LG&E and KU pollution control bonds are insured by monoline bond insurers whose ratings have been reduced due to exposures relating to insurance of sub-prime mortgages.  At September 30, 2010, LG&E and KU had an aggregate $925 million of outstanding pollution control indebtedness (including $163 million of reacquired bonds), of which $231 million is in the form of insured auction rate securities wherein interest rates are reset either weekly or every 35 days via an auction process.  Beginning in late 2007, the interest rates on these insured bonds began to increase due to investor concerns about the creditworthiness of the bond insurers.  Since 2008, LG&E and KU have experienced "failed auctions" when there were insufficient bids for the bonds.  When a failed auction occurs, the interest rate is set pursuant to a formula stipulated in the indenture.

The average annualized interest rates on LG&E's and KU's auction-rate bonds are as follows:

	LG&E						KU
	September 30,						September 30,
	2010			2009			2010			2009
Three months ended		0.49	%		0.38	%		0.61	%		0.34	%
Nine months ended		0.44	%		0.42	%		0.50	%		0.51	%

The instruments governing these auction rate bonds permit LG&E and KU to convert the bonds to other interest rate modes, such as various short-term variable rates, long-term fixed rates or intermediate-term fixed rates that are reset infrequently.  In June 2009, one national rating agency downgraded the credit rating of an insurer of the Company's bonds.  As a result, the national rating agency downgraded the ratings on certain bonds.  The national rating agency's ratings of these bonds are now based on the ratings of LG&E and KU rather than the rating of the insurer since LG&E's and KU's ratings are higher.

During 2008, LG&E converted several series of its pollution control bonds from the auction rate mode to a weekly interest rate mode, as permitted under the loan documents. In connection with these conversions, LG&E purchased the bonds from the remarketing agent.  For financial reporting purposes, the repurchase of the bonds was accounted for as debt extinguishments.  As of September 30, 2010 and December 31, 2009, LG&E continued to hold repurchased bonds in the amount of $163 million, and therefore, such amount is excluded from the Company's balance sheets.  The other repurchased bonds were remarketed during 2008 in an intermediate-term fixed rate mode wherein the interest rate is reset periodically (every three to five years).  LG&E will hold some or all of such repurchased bonds until a later date, at which time it may refinance, remarket or further convert such bonds.  Uncertainty in markets relating to auction rate securities or steps LG&E has taken or may take to mitigate such uncertainty, such as additional conversion, subsequent restructuring or redemption and refinancing, could result in increased interest expense, transaction expenses or other costs and fees or experiencing reduced liquidity relating to existing or future pollution control financing structures.

E.ON U.S. maintained revolving credit facilities totaling $313 million at September 30, 2010 and December 31, 2009.  At September 30, 2010, one facility, totaling $150 million, was with E.ON North America, Inc., while the remaining facility, totaling $163 million, was with Fidelia.  Both are affiliated companies.  Details of the balances are as follows:

							Average
	Total		Amount		Balance		Interest
	Available		Outstanding		Available		Rate
($ in millions)
September 30, 2010	$	313	$	181	$	132		1.44	%
December 31, 2009		313		276		37		1.25	%

In addition to the above revolving lines of credit, E.ON U.S. entered into a short-term loan in 2009 totaling $575 million with Fidelia.  The loan matured and was refinanced as a short-term loan in July 2010, with a new maturity date of July 2011.  The interest rate on the loan equals the three-month LIBOR rate plus 0.60167%.  The Company used the proceeds from the loan to make payments related to the termination agreement with Big Rivers.  See Note 3, Discontinued Operations.

E.ON U.S. entered into short-term loans with Fidelia totaling $150 million and $100 million in April 2010 and June 2010, respectively.  These loans replaced maturing long-term loans from Fidelia.  The interest rate for the April loan is one-month LIBOR plus 0.52% while the June loan has an interest rate of three-month LIBOR plus 0.78%.

As of September 30, 2010, LG&E maintained bilateral lines of credit totaling $125 million maturing in June 2012, with unaffiliated financial institutions.  At September 30, 2010, there was no balance outstanding under any of these facilities.

As of September 30, 2010, KU maintained a $35 million bilateral line of credit maturing in June 2012, with an unaffiliated financial institution.  At September 30, 2010, there was no balance outstanding under this facility.  KU also maintains letter of credit facilities that support $195 million of the $228 million of bonds that can be put back to it.  Should the holders elect to put the bonds back and they cannot be remarketed, the letter of credit would fund the investor's payment.

E.ON U.S. issued $50 million of long-term debt payable to affiliates year-to-date through September 30, 2010.  There were no issuances of long-term debt payable to external parties or redemptions of long-term debt payable to affiliates or external parties year-to-date through September 30, 2010.  E.ON U.S. and its subsidiaries, where applicable, are in compliance with all debt covenants at September 30, 2010 and December 31, 2009.  See Note 1, General, for certain debt refinancing and associated transactions which are anticipated by the Company in connection with the PPL acquisition and Note 12, Related Party Transactions, for long-term debt payable to affiliates.

Note 11 - Commitments and Contingencies

Except as may be discussed in this quarterly report (including Note 4, Rates and Regulatory Matters), material changes have not occurred in the current status of various commitments or contingent liabilities from that discussed in the Company's audited financial statements for the year ended December 31, 2009 (including, but not limited to, Note 4, Related Party Transactions; Note 5, Utility Rates and Regulatory Matters; and Note 17, Subsequent Events; to the financial statements of the Company contained therein).  See the Company's audited financial statements regarding such commitments or contingencies.

Letters of Credit

E.ON U.S. has provided letters of credit securing off-balance sheet commitments totaling $8 million as of September 30, 2010 and December 31, 2009.  The underlying obligation is a performance guarantee.  LG&E has also issued letters of credit as of September 30, 2010 and December 31, 2009, for off-balance sheet obligations totaling $3 million, and KU has issued letters of credit as of the same dates for off-balance sheet obligations of less than $1 million and for on-balance sheet obligations of $198 million to support outstanding bonds of $195 million.

Owensboro Contract Litigation and Contract Termination

In May 2004, the City of Owensboro, Kentucky and OMU commenced a suit against KU concerning a long-term power supply contract (the "OMU Agreement") with KU.  In May 2009, KU and OMU executed a settlement agreement resolving the matter on a basis consistent with prior court rulings, and KU has received the agreed settlement amounts.  Pursuant to the settlement's operation, the OMU agreement terminated in May 2010.  In connection with such termination during the second quarter of 2010, KU has recorded a net receivable totaling $4 million reflecting its estimate of remaining adjustments concerning prior accruals.  The parties are engaged in discussions to resolve those remaining adjustments.

Construction Program

LG&E and KU had approximately $180 million and $165 million, respectively, of commitments in connection with their construction programs at September 30, 2010.

In June 2006, LG&E and KU entered into a construction contract regarding the TC2 project.  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.  During 2009 and 2010, LG&E and KU have received several contractual notices from the TC2 construction contractor asserting historical force majeure and excusable event claims for a number of adjustments to the contract price construction schedule, commercial operations date, liquidated damages or other relevant provisions.  In September 2010, the Companies and the construction contractor agreed to a settlement to resolve certain force majeure and excusable event claims occurring through July 2010, under the TC2 construction contract, which settlement provided for a limited, negotiated extension of the contractual commercial operations date and/or relief from liquidated damages calculations.  During commissioning activities in the second and third quarters, separate delays have occurred related to burner malfunctions and an excitation transformer failure.  Certain temporary or permanent repairs for both matters have been completed, are underway or are planned for appropriate future outage periods.  Commissioning steps resumed in October 2010, and a revised commercial operations date is currently expected by year end.  The parties are analyzing the treatment of these additional delays under the liquidated damages provisions of the construction agreement.  The Company cannot currently estimate the ultimate outcome of these matters, including the extent, if any, that such outcome may result in materially increased costs for the construction of TC2, further changes in the TC2 construction completion or commercial operation dates or potential effects on levels of power purchases or wholesale sales due to such changed dates.

TC2 Air Permit

The Sierra Club and other environmental groups filed a petition challenging the air permit issued for the TC2 baseload generating unit which was issued by the Kentucky Division for Air Quality ("KDAQ") in November 2005.  In September 2007, the Secretary of the Kentucky Environmental and Public Protection Cabinet issued a final Order upholding the permit.  The environmental groups petitioned the EPA to object to the state permit and subsequent permit revisions.  In determinations made in September 2008 and June 2009, the EPA rejected most of the environmental groups' claims, but identified three permit deficiencies which the KDAQ addressed by revising the permit.  In August 2009, the EPA issued an Order denying the remaining claims with the exception of two additional deficiencies which the KDAQ was directed to address.  The EPA determined that the proposed permit subsequently issued by the KDAQ satisfied the conditions of the EPA Order, although the agency recommended certain enhancements to the administrative record.  In January 2010, the KDAQ issued a final permit revision incorporating the proposed changes to address the EPA objections.  In March 2010, the environmental groups submitted a petition to the EPA to object to the permit revision, which is now pending before the EPA.  The Company believes that the final permit as revised should not have a material adverse effect on its financial condition or results of operations.  However, until the EPA issues a final ruling on the pending petition and all applicable appeals have been exhausted, the Company cannot predict the final outcome of this matter.

Thermostat Replacement

During January 2010, LG&E and KU announced a voluntary plan to replace certain thermostats which had been provided to customers as part of their demand reduction programs, due to concerns that the thermostats may present a safety hazard.  Under the plan, LG&E and KU have replaced approximately 90% of the estimated 14,000 thermostats that need to be replaced.  Total estimated costs associated with the replacement program are $2 million.  However, LG&E and KU cannot fully predict the ultimate outcome of the replacement program or other effects or developments which may be associated with the thermostat replacement matter at this time.

OVEC

LG&E and KU hold 5.63% and 2.5% investment interests in OVEC, respectively, with 10 other electric utilities.  LG&E and KU are not the primary beneficiaries; therefore the investment is not consolidated into LG&E's and KU's financial statements, but is recorded on the cost basis.  OVEC is located in Piketon, Ohio, and owns and operates two coal-fired power plants, Kyger Creek Station in Ohio, and Clifty Creek Station in Indiana.  LG&E and KU are contractually entitled to 5.63% and 2.5%, respectively, of OVEC's output, approximately 124 and 55 Mw of generation capacity, respectively.  Pursuant to the OVEC power purchase contract, LG&E and KU may be conditionally responsible for 5.63% and 2.5% pro-rata shares, respectively, of certain obligations of OVEC under defined circumstances.  These contingent liabilities may include unpaid OVEC indebtedness as well as shortfall amounts in certain excess decommissioning costs and post-retirement benefits other than pension.  LG&E's and KU's potential proportionate shares of OVEC's September 30, 2010, outstanding debt were $78 million and $35 million, respectively.

Environmental Matters

LG&E's and KU's operations are subject to a number of environmental laws and regulations in each of the jurisdictions in which they operate, governing, among other things, air emissions, wastewater discharges, the use, handling and disposal of hazardous substances and wastes, soil and groundwater contamination and employee health and safety.  As indicated below and summarized at the conclusion of this section, evolving environmental regulations will likely increase the level of capital and operating and maintenance expenditures incurred by the Company during the next several years.  Based on prior regulatory precedent, the Company believes that many costs of complying with such pending future requirements would likely be recoverable under the ECR or other potential cost-recovery mechanisms, but the Company can provide no assurance as to the ultimate outcome of such proceedings before the regulatory authorities.

Ambient Air Quality.  The Clean Air Act requires the EPA to periodically review the available scientific data for six criteria pollutants and establish concentration levels in the ambient air sufficient to protect the public health and welfare with an extra margin for safety.  These concentration levels are known as NAAQS.  Each state must identify "nonattainment areas" within its boundaries that fail to comply with the NAAQS and develop a SIP to bring such nonattainment areas into compliance.  If a state fails to develop an adequate plan, the EPA must develop and implement a plan.  As the EPA increases the stringency of the NAAQS through its periodic reviews, the attainment status of various areas may change, thereby triggering additional emission reduction obligations under revised SIPs aimed to achieve attainment.

In 1997, the EPA established new NAAQS for ozone and fine particulates that required additional reductions in SO2 and NOx emissions from power plants.  In 1998, the EPA issued its final "NOx SIP Call" rule requiring reductions in NOx emissions of approximately 85% from 1990 levels in order to mitigate ozone transport from the midwestern U.S. to the northeastern U.S.  To implement the new federal requirements, Kentucky amended its SIP in 2002 to require electric generating units to reduce their NOx emissions to 0.15 pounds weight per MMBtu on a company-wide basis.  In 2005, the EPA issued the CAIR which required additional SO2 emission reductions of 70% and NOx emission reductions of 65% from 2003 levels.  The CAIR provided for a two-phase cap and trade program, with initial reductions of NOx and SO2 emissions due by 2009 and 2010, respectively, and final reductions due by 2015.  In 2006, Kentucky proposed to amend its SIP to adopt state requirements similar to those under the federal CAIR.

In July 2008, a federal appeals court issued a ruling finding deficiencies in the CAIR and vacating it.  In December 2008, the Court amended its previous Order, directing the EPA to promulgate a new regulation, but leaving the CAIR in place in the interim.  The remand of the CAIR results in some uncertainty with respect to certain other EPA or state programs and proceedings and LG&E's and KU's compliance plans relating thereto, due to the interconnection of the CAIR with such associated programs.

In January 2010, the EPA proposed a revised NAAQS for ozone which would increase the stringency of the standard.  In addition, the EPA published final revised NAAQS standards for nitrogen dioxide ("NO2") and SO2 in February 2010 and June 2010, respectively, which are more stringent than previous standards.  Depending on the level of action determined necessary to bring local nonattainment areas into compliance with the revised NAAQS standards, LG&E's and KU's power plants are potentially subject to requirements for additional reductions in SO2 and NOx emissions.

In July 2010, the EPA issued the proposed CATR, which serves to replace the CAIR.  The CATR provides for a two-phase SO2 reduction program with Phase I reductions due by 2012, and Phase II reductions due by 2014.  The CATR provides for NOx reductions in 2012, but the EPA advised that it is studying whether additional NOx reductions should be required for 2014.  The CATR is more stringent than the CAIR as it accelerates certain compliance dates and provides for only intrastate and limited interstate trading of emission allowances.  In addition to its preferred approach, the EPA is seeking comment on an alternative approach which would provide for individual emission limits at each power plant.  The EPA has announced that it will propose additional "transport" rules to address compliance with revised NAAQS standards for ozone and particulate matter which will be issued by the EPA in the future, as discussed below.

Hazardous Air Pollutants.  As provided in the Clean Air Act, the EPA investigated hazardous air pollutant emissions from electric utilities and submitted a report to Congress identifying mercury emissions from coal-fired power plants as warranting further study.  In 2005, the EPA issued the CAMR establishing mercury standards for new power plants and requiring all states to issue new SIPs including mercury requirements for existing power plants.  The EPA issued a model rule which provides for a two-phase cap and trade program with initial reductions due by 2010 and final reductions due by 2018.  The CAMR provided for reductions of 70% from 2003 levels.  The EPA closely integrated the CAMR and CAIR programs to ensure that the 2010 mercury reduction targets would be achieved as a "co-benefit" of the controls installed for purposes of compliance with the CAIR.  In addition, in 2006, the Metro Louisville Air Pollution Control District adopted rules aimed at regulating additional hazardous air pollutants from sources including power plants.

In February 2008, a federal appellate court issued a decision vacating the CAMR.  The EPA has entered into a consent decree requiring it to promulgate a utility Maximum Achievable Control Technology rule to replace the CAMR with a proposed rule due by March 2011, and a final rule by November 2011.  Depending on the final outcome of the rulemaking, the CAMR could be replaced by new rules with different or more stringent requirements for reduction of mercury and other hazardous air pollutants. Kentucky has also repealed its corresponding state mercury regulations.

Acid Rain Program.  The Clean Air Act imposed a two-phased cap and trade program to reduce SO2 emissions from power plants that were thought to contribute to "acid rain" conditions in the northeastern U.S.  The Clean Air Act also contains requirements for power plants to reduce NOx emissions through the use of available combustion controls.

Regional Haze.  The Clean Air Act also includes visibility goals for certain federally designated areas, including national parks, and requires states to submit SIPs that will demonstrate reasonable progress toward preventing future impairment and remedying any existing impairment of visibility in those areas.  In 2005, the EPA issued its Clean Air Visibility Rule detailing how the Clean Air Act's BART requirements will be applied to facilities, including power plants, built between 1962 and 1974 that emit certain levels of visibility impairing pollutants.  Under the final rule, as the CAIR provided for more visibility improvement than BART, states are allowed to substitute CAIR requirements in their regional haze SIPs in lieu of controls that would otherwise be required by BART.  The final rule has been challenged in the courts.  Additionally, because the regional haze SIPs incorporate certain CAIR requirements, the remand of the CAIR could potentially impact regional haze SIPs.  See "Ambient Air Quality" above for a discussion of CAIR-related uncertainties.

Installation of Pollution Controls.  Many of the programs under the Clean Air Act utilize cap and trade mechanisms that require a company to hold sufficient emissions allowances to cover its authorized emissions on a company-wide basis and do not require installation of pollution controls on every generating unit.  Under cap and trade programs, companies are free to focus their pollution control efforts on plants where such controls are particularly efficient and utilize the resulting emission allowances for smaller plants where such controls are not cost effective.  LG&E had previously installed FGD equipment on all of its generating units prior to the effective date of the acid rain program.  KU met its Phase I SO2 requirements primarily through installation of FGD equipment on Ghent Unit 1.  LG&E's strategy for its Phase II SO2 requirements, which commenced in 2000, is to use accumulated emission allowances to defer additional capital expenditures and continue to evaluate improvements to further reduce SO2 emissions.  KU's strategy for its Phase II SO2 requirements, which commenced in 2000, includes the installation of additional FGD equipment, as well as, using accumulated emission allowances and fuel switching to defer certain additional capital expenditures.  In order to achieve the NOx emission reductions mandated by the NOx SIP Call, LG&E and KU installed additional NOx controls, including SCR technology, during the 2000 through 2009 time period at a cost of $197 million and $221 million, respectively.  In 2001, the Kentucky Commission granted approval to recover the costs incurred by LG&E and KU for these projects through the ECR mechanisms.  Such monthly recovery is subject to periodic review by the Kentucky Commission.

In order to achieve currently mandated emissions reductions, LG&E and KU expect to incur additional capital expenditures totaling approximately $80 million and $285 million, respectively, during the 2010 through 2012 time period for pollution controls including FGD and SCR equipment, and additional operating and maintenance costs in operating such controls.  In 2005, the Kentucky Commission granted approval to recover the costs incurred by LG&E and KU for these projects through the ECR mechanism.  Such monthly recovery is subject to periodic review by the Kentucky Commission.  LG&E and KU believe their costs in reducing SO2, NOx and mercury emissions to be comparable to those of similarly situated utilities with like generation assets.  LG&E's and KU's compliance plans are subject to many factors including developments in the emission allowance and fuels markets, future legislative and regulatory enactments, legal proceedings and advances in clean air technology.  LG&E and KU will continue to monitor these developments to ensure that its environmental obligations are met in the most efficient and cost-effective manner.  See "Ambient Air Quality" above for a discussion of CAIR-related uncertainties.

GHG Developments.  In 2005, the Kyoto Protocol for reducing GHG emissions took effect, obligating 37 industrialized countries to undertake substantial reductions in GHG emissions.  The U.S. has not ratified the Kyoto Protocol and there are currently no mandatory GHG emission reduction requirements at the federal level. As discussed below, legislation mandating GHG reductions has been introduced in the Congress, but no federal legislation has been enacted to date.  In the absence of a program at the federal level, various states have adopted their own GHG emission reduction programs, including 11 northeastern U.S. states and the District of Columbia under the Regional GHG Initiative program and California.  Substantial efforts to pass federal GHG legislation are on-going.  The current administration has announced its support for the adoption of mandatory GHG reduction requirements at the federal level.  The United States and other countries met in Copenhagen, Denmark in December 2009, in an effort to negotiate a GHG reduction treaty to succeed the Kyoto Protocol, which is set to expire in 2013.  In Copenhagen, the U.S. made a nonbinding commitment to, among other things, seek to reduce GHG emissions to 17% below 2005 levels by 2020 and provide financial support to developing countries.  The United States and other nations are scheduled to meet in Cancun, Mexico in late 2010 to continue negotiations toward a binding agreement.

GHG Legislation.  LG&E and KU are monitoring on-going efforts to enact GHG reduction requirements and requirements governing carbon sequestration at the state and federal level and is assessing potential impacts of such programs and strategies to mitigate those impacts.  In June 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, which is a comprehensive energy bill containing the first-ever nation-wide GHG cap and trade program.  The bill would provide for reductions in GHG emissions of 3% below 2005 levels by 2012, 17% by 2020 and 83% by 2050.  In order to cushion potential rate impacts for utility customers, approximately 43% of emissions allowances would initially be allocated at no cost to the electric utility sector, with this allocation gradually declining to 7% in 2029 and zero thereafter.  The bill would also establish a renewable electricity standard requiring utilities to meet 20% of their electricity demand through renewable energy and energy efficiency by 2020.  The bill contains additional provisions regarding carbon capture and sequestration, clean transportation, smart grid advancement, nuclear and advanced technologies and energy efficiency.

In September 2009, the Clean Energy Jobs and American Power Act, which is largely patterned on the House legislation, was introduced in the U.S. Senate.  The Senate bill raises the emissions reduction target for 2020 to 20% below 2005 levels and does not include a renewable electricity standard.  While the initial bill lacked detailed provisions for the allocation of emissions allowances, a subsequent revision incorporated allowance allocation provisions similar to the House bill.  In 2010, Senators Kerry and Lieberman and others have undertaken additional work to draft GHG legislation, but have introduced no bill in the Senate to date.  In July 2010, Senate Majority Leader Reid announced that he did not anticipate that GHG legislation would be brought to the Senate floor in the current session.  The Company is closely monitoring the progress of pending energy legislation, but the prospect for passage of comprehensive GHG legislation in 2010 is uncertain.

GHG Regulations.  In April 2007, the U.S. Supreme Court ruled that the EPA has the authority to regulate GHG under the Clean Air Act.  In April 2009, the EPA issued a proposed endangerment finding concluding that GHGs endanger public health and welfare, which is an initial rulemaking step under the Clean Air Act.  A final endangerment finding was issued in December 2009.  In September 2009, the EPA issued a final GHG reporting rule requiring reporting by facilities with annual GHG emissions equivalent to at least 25,000 tons of carbon dioxide.  A number of the Company's facilities will be required to submit annual reports commencing with calendar year 2010.  In May 2010, the EPA issued a final GHG "tailoring" rule requiring new or modified sources with GHG emissions equivalent to at least 75,000 tons of carbon dioxide to obtain permits under the Prevention of Significant Deterioration Program.  Such new or modified facilities would be required to install Best Available Control Technology.  While the Company is unaware of any currently available GHG control technology that might be required for installation on new or modified power plants, it is currently assessing the potential impact of the rule.  The final rule will apply to new and modified power plants beginning in January 2011.  The Company is unable to predict whether mandatory GHG reduction requirements will ultimately be enacted through legislation or regulations.

GHG Litigation.  A number of lawsuits have been filed asserting common law claims including nuisance, trespass and negligence against various companies with GHG emitting facilities.  In October 2009, a three-judge panel of the United States Court of Appeals for the 5th Circuit in the case of Comer v. Murphy Oil reversed a lower court, holding that private plaintiffs have standing to assert certain common law claims against more than 30 utility, oil, coal and chemical companies.  In March 2010, the court vacated the opinion of the three-judge panel and granted a motion for rehearing, but subsequently denied the appeal due to the lack of a quorum.  The appellate ruling leaves in effect the lower court ruling dismissing the plaintiffs' claims.  The petitioners filed a petition for a writ of mandamus with the Supreme Court in August 2010.  The Comer complaint alleges that GHG emissions from the defendants' facilities contributed to global warming which increased the intensity of Hurricane Katrina.  E.ON, the Company's parent, was included as a defendant in the complaint, but has not been subject to the proceedings due to the failure of the plaintiffs to pursue service under the applicable international procedures.  LG&E and KU are currently unable to predict further developments in the Comer case. LG&E and KU continue to monitor relevant GHG litigation to identify judicial developments that may be potentially relevant to their operations.

Ghent Opacity NOV.  In September 2007, the EPA issued a NOV alleging that KU had violated certain provisions of the Clean Air Act's operating rules relating to opacity during June and July of 2007 at Units 1 and 3 of KU's Ghent generating station.  The parties have met on this matter and KU has received no further communications from the EPA.  The Company is not able to estimate the outcome or potential effects of these matters, including whether substantial fines, penalties or remedial measures may result.

Ghent New Source Review NOV.  In March 2009, the EPA issued a NOV alleging that KU violated certain provisions of the Clean Air Act's rules governing new source review and prevention of significant deterioration by installing FGD and SCR controls at its Ghent generating station without assessing potential increased sulfuric acid mist emissions.  KU contends that the work in question, as pollution control projects, was exempt from the requirements cited by the EPA.  In December 2009, the EPA issued a Section 114 information request seeking additional information on this matter.  In March 2010, KU received an EPA settlement proposal providing for imposition of additional permit limits and emission controls and anticipates continued settlement negotiations with the EPA.  Depending on the provisions of a final settlement or the results of litigation, if any, resolution of this matter could involve significant increased operating and capital expenditures.  The Company is currently unable to determine the final outcome of this matter or the impact of an unfavorable determination on the Company's financial position or results of operations.

Ash Ponds and Coal-Combustion Byproducts.  The EPA has undertaken various initiatives in response to the December 2008 impoundment failure at the Tennessee Valley Authority's Kingston power plant, which resulted in a major release of coal combustion byproducts into the environment.  The EPA issued information requests to utilities throughout the country, including LG&E and KU, to obtain information on their ash ponds and other impoundments.  In addition, the EPA inspected a large number of impoundments located at power plants to determine their structural integrity.  The inspections included several of LG&E's and KU's impoundments, which the EPA found to be in satisfactory condition except for certain impoundments at LG&E's Mill Creek and Cane Run stations, which were determined to be in fair condition.  In June 2010, the EPA published proposed regulations for coal combustion byproducts handled in landfills and ash ponds.  The EPA has proposed two alternatives: (1) regulation of coal combustion byproducts in landfills and ash ponds as a hazardous waste; or (2) regulation of coal combustion byproducts as a solid waste with minimum national standards.  Under both alternatives, the EPA has proposed safety requirements to address the structural integrity of ash ponds. In addition, the EPA will consider potential refinements of the provisions for beneficial reuse of coal combustion byproducts.

Water Discharges and PCB Regulations.  The EPA has also announced plans to develop revised effluent limitation guidelines governing discharges from power plants and standards for cooling water intake structures.  The EPA has further announced plans to develop revised standards governing the use of polychlorinated biphenyls ("PCB") in electrical equipment.  The Company is monitoring these ongoing regulatory developments, but will be unable to determine the impact until such time as new rules are finalized.

Impact of Pending and Future Environmental Developments.  As companies with significant coal-fired generating assets, LG&E and KU will likely be substantially impacted by pending or future environmental rules or legislation requiring mandatory reductions in GHG emissions or other air emissions, imposing more stringent standards on discharges to waterways, or establishing additional requirements for handling or disposal of coal combustion byproducts.  These evolving environmental regulations will likely require an increased level of capital expenditures and increased incremental operating and maintenance costs by the Company over the next several years.  Due to the uncertain nature of the final regulations that will ultimately be adopted by the EPA, including the reduction targets and the deadlines that will be applicable, the Company cannot finalize estimates of the potential compliance costs, but should the final rules incorporate additional emission reduction requirements, require more stringent emissions controls, or implement more stringent byproducts storage and disposal practices, such costs will likely be significant.  With respect to NAAQS, CATR, CAMR replacement and coal combustion byproducts developments, based on a preliminary analysis of proposed regulations, the Company may be required to consider actions such as upgrading existing emissions controls, installing additional emissions controls, upgrading byproducts disposal and storage and possible early replacement of coal-fired units.  Capital expenditures for LG&E and KU associated with such actions are preliminarily estimated to be in the $2.3 billion and $1.7 billion range, respectively, over the next 10 years, although final costs may substantially vary.  With respect to potential developments in water discharge, revised PCB standards, or GHG initiatives, costs in such areas cannot be estimated due to the preliminary status or uncertain outcome of such developments, but would be in addition to the above amount and could be substantial.  Ultimately the precise impact on the Company’s operations of these various environmental developments cannot be determined prior to the finalization of such requirements.  Based on prior regulatory precedent, the Company believes that many costs of complying with such pending or future requirements would likely be recoverable under the ECR or other potential cost-recovery mechanisms, but the Company can provide no assurance as to the ultimate outcome of such proceedings before the regulatory authorities.

TC2 Water Permit.  In May 2010, the Kentucky Waterways Alliance and other environmental groups filed a petition with the Kentucky Energy and Environment Cabinet challenging the Kentucky Pollutant Discharge Elimination System permit issued in April 2010, which covers water discharges from the Trimble County  generating station.  In October 2010, the hearing officer issued a report and recommended order providing for dismissal of the claims raised by the petitioners.  Until such time as the Secretary issues a final order of the agency and all appeals are exhausted, the Company is unable to predict the outcome or precise impact of this matter.

General Environmental Proceedings.  From time to time, LG&E and KU appear before the EPA, various state or local regulatory agencies and state and federal courts regarding matters involving compliance with applicable environmental laws and regulations.  Such matters include a prior Section 114 information request from the EPA relating to new source review issues at LG&E's Mill Creek Unit 4 and Trimble County Unit 1 and KU's Ghent Unit 2, a completed settlement with state regulators regarding compliance with particulate limits in the air permit for KU's Tyrone generating station, remediation obligations or activities for former manufactured gas plant sites, or other risks relating to elevated PCB levels at existing properties; liability under the Comprehensive Environmental Response, Compensation and Liability Act for cleanup at various off-site waste sites; and on-going claims regarding alleged particulate emissions from LG&E's Cane Run generating station and claims regarding GHG emissions from LG&E's and KU's generating stations.  With respect to the former manufactured gas plant sites, LG&E has estimated that it could incur additional costs of less than $1 million for remaining clean-up activities under existing approved plans or agreements.  Based on analysis to date, the resolution of these matters is not expected to have a material impact on the Company's operations.

Argentina Matters

In December 2001, the Company commenced arbitration proceedings against the Republic of Argentina under the U.S.-Argentina Bilateral Investment Treaty before the ICSID.  The arbitration presents claims relating to the diminution in value of the former investments of the Company in Argentina due to certain prejudicial actions of the Argentine government.  In July 2007, the panel issued an Order awarding E.ON U.S. $57 million (including interest) for the period through February 2005.  In July 2007, the panel denied an E.ON U.S. request for additional damages of approximately $56 million for the period March 2005 - July 2007.  In August and November 2008, E.ON U.S. and the Argentine government submitted respective petitions for annulment of elements of the prior decisions.  Since late 2008, in connection with on-going interim and final gas tariff renegotiation processes in Argentina, the parties have agreed to a temporary suspension and potential dismissal of the ICSID proceeding, subject to certain conditions.  E.ON Spain has assumed relevant rights and obligations with respect to claims and liabilities relating to the Argentine businesses in connection with the 2010 sale of such businesses to E.ON Spain.  In October 2010, the Company transferred its ICSID claims to an affiliate of E.ON Spain.

During November 2008, the Argentine Central Bank commenced an administrative proceeding alleging a violation of certain emergency currency exchange laws in place during the country's economic crisis in connection with a December 2002 refinancing by Centro of $35 million of a previously-existing, maturing loan. Centro and its individual directors have filed responsive pleadings in the matter and requested dismissal at the administrative phase.  In April 2010, the Argentine Central Bank staff issued a ruling declining to dismiss the case at the conclusion of the administrative stage and therefore forwarded the matter to a specialized financial criminal court where further proceedings will continue.  The parties are currently addressing assignment to the relevant specific court, at which time a phase relating to certain jurisdictional or procedural issues may occur.  A subsidiary of E.ON U.S. has entered into indemnity agreements with certain associated directors.  E.ON Spain has assumed relevant rights and obligations with respect to claims and liabilities relating to the Argentine businesses in connection with its purchase of the business in 2010.

Guarantees

In connection with various divestitures, the Company has indemnified/guaranteed respective parties against certain liabilities that may arise in connection with these transactions and business activities.  The terms of these indemnifications/guarantees vary, as do the expiration terms.  If the indemnified party were to incur a liability or have a liability increase as a result of a successful claim, pursuant to the terms of the indemnification, the Company would be required to reimburse the indemnified party.  The maximum amount of potential future payments is generally unlimited and relate to WKE.

In connection with the WKE transaction, WKE indemnified the purchaser against certain liabilities primarily related to litigation from third parties.  The estimated fair value of this indemnity obligation is $11 million at September 30, 2010, and December 31, 2009.  Additionally, WKE issued a direct financial guarantee, in the form of a swap, to a third party customer.  The estimated fair value of this guarantee is $30 million at September 30, 2010, and was $74 million at December 31, 2009.  The obligation valuations were calculated based on management's best estimate of the value expected to be required to issue the indemnifications in a standalone, arm's length transaction with an unrelated party and, where appropriate, by the utilization of probability weighted discounted net cash flow models.

The Company has issued direct financial guarantees to parties involved in the WKE transaction guaranteeing the due and punctual payment, performance and discharge by each party of its respective present and future obligations.  The most comprehensive of these guarantees is the parental guarantee covering the WKE Transaction Termination Agreement, which has a term of 12 years beginning on July 16, 2009.  Among other matters, such obligations include indemnities regarding operational, regulatory or environmental matters, if any, relating to the Company's completed leasing and operating period; however, the Company is not aware of claims made by any party at this time.  See Note 3, Discontinued Operations.

Additionally, the Company has indemnified various third parties related to historical obligations for divested subsidiaries and affiliates.  The indemnifications vary by entity and the maximum amount limits range from being capped at the sale price to no specified maximum; however, the Company is not aware of claims made by any party at this time.  The Company could be required to perform on these indemnifications in the event of covered losses or liabilities being claimed by an indemnified party.  No additional material loss is anticipated by reason of such indemnifications.

Note 12 – Related Party Transactions

The Company's balances with affiliates as of September 30, 2010, and December 31, 2009 were with E.ON and its affiliates.  See Note 9, Income Taxes, and Note 10, Short-Term and Long-Term Debt.

The Company paid dividends totaling $62 million during the nine months ended September 30, 2010. On October 7, 2010, the Company's Board of Directors authorized a $25 million dividend payable on October 15, 2010, to the Company's sole member, E.ON US Investments Corp.

Note 13 - Share Performance Plan

The 2007 grant under E.ON Share Performance Plan of 6,820 virtual shares with target prices of €96.52 each was paid out in January 2010.  The total of the payouts was $1 million.  In the second quarter of 2010, the Company issued 27,643 virtual shares to Plan participants with a target price of €27.25.  All virtual shares outstanding will vest on the closing of the PPL acquisition.  If the PPL acquisition does not close, the virtual shares issued in the second quarter of 2010 will vest over four years.

The Company recorded expense of less than $1 million related to the Plan in the three- and nine-month periods ended September 30, 2010 and 2009.

Note 14 – Subsequent Events

Subsequent events have been evaluated through October 29, 2010, the date of issuance of these statements and these statements contain all necessary adjustments and disclosures resulting from that evaluation.

On October 29, 2010, KU's pollution control bonds were converted from unsecured debt to debt which is collateralized by first mortgage bonds.  See Note 1, General, and Note 10, Short-Term and Long-Term Debt.

On October 26, 2010, the FERC issued an Order approving the acquisition of E.ON U.S. by PPL.  See Note 1, General.

On October 22, 2010, LG&E's pollution control bonds were converted from unsecured debt to debt which is collateralized by first mortgage bonds.  See Note 1, General, and Note 10, Short-Term and Long-Term Debt.

On October 19, 2010 and October 21, 2010, respectively, the Virginia Commission and Tennessee Regulatory Authority issued Orders approving the acquisition of E.ON U.S. by PPL.  On the same dates, KU received Virginia Commission and Tennessee Regulatory Authority approvals to complete certain refinancing transactions in connection with the anticipated PPL acquisition and other business factors.  See Note 1, General, and Note 10, Short-Term and Long-Term Debt.