PPL Corp - FORM 8-K - EX-99.2 - EXHIBIT 99.2

Attached files

file	filename
8-K - FORM 8-K - PPL Corp	form8k.htm
EX-23.A - EXHIBIT 23(A) - PPL Corp	form8k-exhibit23_a.htm
EX-99.3 - EXHIBIT 99.3 - PPL Corp	form8k-exhibit99_3.htm
EX-99.1 - EXHIBIT 99.1 - PPL Corp	form8k-exhibit99_1.htm

Exhibit 99.2

E.ON U.S. LLC and Subsidiaries

Condensed Consolidated Financial Statements

As of March 31, 2010, and December 31, 2009,

And for the Three Months Ended

March 31, 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.
CAVR	Clean Air Visibility 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.
DOE	U.S. Department of Energy
DSM	Demand Side Management
EEI	Electric Energy, Inc.
E.ON	E.ON AG
E.ON Spain	E.ON Espana S.L.
E.ON U.S.	E.ON U.S. LLC
E.ON U.S. Services	E.ON U.S. Services Inc.
ECR	Environmental Cost Recovery
EKPC	East Kentucky Power Cooperative
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)
GAAP	Generally Accepted Accounting Principles
GAC	Group Annuity Contract
GHG	Greenhouse Gas
GSC	Gas Supply Clause
IBEW	International Brotherhood of Electrical Workers
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
KIUC	Kentucky Industrial Utility Consumers, Inc.
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

Index of Abbreviations (Cont.)

NAAQS	National Ambient Air Quality Standards
NGHH	Natural Gas-Henry Hub
NOV	Notice of Violation
NOx	Nitrogen Oxide
OCI	Other Comprehensive Income (Loss) or Accumulated Other Comprehensive Income (Loss)
OMU	Owensboro Municipal Utilities
OVEC	Ohio Valley Electric Corporation
PUHCA	Public Utility Holding Company Act
PUHCA 1935	Public Utility Holding Company Act of 1935
PUHCA 2005	Public Utility Holding Company Act of 2005
RSG	Revenue Sufficiency Guarantee
S&P	Standard and Poor's Rating Service
SCR	Selective Catalytic Reduction
SIP	State Implementation Plan
SO2	Sulfur Dioxide
TC2	Trimble County Unit 2
Trimble County	LG&E's Trimble County plant
USWA	United Steelworkers of America
VDT	Value Delivery Team
VEBA	Voluntary Employee Beneficiary Association
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

As of March 31, 2010, and December 31, 2009,

And for the Three Months Ended

March 31, 2010 and 2009

Table of Contents

Financial Statements:
	Condensed Consolidated Statements of Operations		1
	Condensed Consolidated Statements of Comprehensive Income (Loss)		2
	Condensed Consolidated Statements of Member's Equity		3
	Condensed Consolidated Balance Sheets		4
	Condensed Consolidated Statements of Cash Flows		6

Notes to Condensed Consolidated Financial Statements:
	Note 1	General	8
	Note 2	Goodwill	10
	Note 3	Discontinued Operations	11
	Note 4	Related Party Transactions	12
	Note 5	Utility Rates and Regulatory Matters	13
	Note 6	Financial Instruments	20
	Note 7	Fair Value Measurements	23
	Note 8	Pension and Other Postretirement Benefit Plans	25
	Note 9	Income Taxes	26
	Note 10	Short-Term and Long-Term Debt	28
	Note 11	Commitments and Contingencies	29
	Note 12	Accumulated Other Comprehensive Income	38
	Note 13	Share Performance Plan	39
	Note 14	Subsequent Events	39

E.ON U.S. LLC and Subsidiaries

Condensed Consolidated Statements of Operations

(Unaudited - Millions of $)

	Three Months Ended
	March 31,
	2010			2009
Operating revenues:
Electric utility	$	579		$	556
Gas utility		134			193
Other		-			1

Total revenues		713			750

Operating expenses:
Fuel and power purchased		261			256
Gas supply expenses		81			150
Utility operation and maintenance		151			246
Other general and administrative expenses		4			6
Depreciation, accretion and amortization		69			65

Total operating expenses		566			723

Operating income		147			27

Equity in earnings of unconsolidated venture		3			2
Derivative (loss) gain (Note 6)		(1	)		5
Other (deductions) income		(2	)		2
Interest expense - affiliated companies		(40	)		(37	)
Interest expense		(6	)		(7	)

Income (loss) from continuing operations, before income taxes		101			(8	)

Income tax expense (benefit) (Note 9)		38			(8	)

Income from continuing operations		63			-

Discontinued operations (Note 3):
Loss from discontinued operations before tax		(3	)		(55	)
Income tax benefit from discontinued operations		1			20

Loss from discontinued operations before noncontrolling interest		(2	)		(35	)

Loss on disposal of discontinued operations before tax		(1	)		-
Income tax benefit from loss on disposal of discontinued operations		-			-

Loss on disposal of discontinued operations		(1	)		-

Net income (loss)		60			(35	)

Noncontrolling interest – loss from discontinued operations		-			(1	)

Net income (loss) attributable to member	$	60		$	(36	)

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

E.ON U.S. LLC and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income (Loss) (Note 12)

(Unaudited - Millions of $)

	Three Months Ended
	March 31,
	2010		2009

Net income (loss)	$	60	$	(35	)

Other comprehensive income (loss):
Gains on derivative instruments		1		2
Foreign currency translation adjustment		-		(8	)
Income tax benefit related to items of other
comprehensive income		-		2

Comprehensive income (loss)		61		(39	)

Noncontrolling interest - loss from discontinued operations		-		(1	)

Other comprehensive (income) loss allocable to noncontrolling interest:
Foreign currency translation adjustment		-		5
Income tax benefit related to items of other
comprehensive income		-		(1	)

Comprehensive income (loss) attributable to member	$	61	$	(36	)

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

E.ON U.S. LLC and Subsidiaries

Condensed Consolidated Statements of Member's Equity

(Unaudited - Millions of $)

	Member-						Accum-
	ship				Addi-		ulated						Non-
	Units		Member-		tional		Other						Control-
	Out-		ship		Paid-in		Comp.			Retained			ing			Total
	standing		Units		Capital		Loss			Deficit			Interest			Equity

Balance January 1, 2010		1,001	$	774	$	4,224	$	(43	)	$	(2,763	)	$	32		$	2,224

Net income attributable
to member		-		-		-		-			60			-			60
Dividends declared		-		-		-		-			(6	)		-			(6	)
Other comprehensive
income (loss)		-		-		-		1			-						1
Disposal of discontin-
ued operations		-		-		-		(11	)		-			(32	)		(43	)

Balance March 31, 2010		1,001	$	774	$	4,224	$	(53	)	$	(2,709	)	$	-		$	2,236

	Member-						Accum-
	ship				Addi-		ulated						Non-
	Units		Member-		tional		Other						Control-
	Out-		ship		Paid-in		Comp.			Retained			Ing			Total
	standing		Units		Capital		Loss			Deficit			Interest			Equity

Balance January 1, 2009		1,001	$	774	$	4,224	$	(61	)	$	(1,172	)	$	32		$	3,797

Net loss attributable
to member		-		-		-		-			(36	)		-			(36	)
Dividends declared		-		-		-		-			(14	)		-			(14	)
Other comprehensive loss		-		-		-		-			-			(4	)		(4	)
Noncontrolling interest -
income from discon-
tinued operations		-		-		-		-			-			1			1

Balance March 31, 2009		1,001	$	774	$	4,224	$	(61	)	$	(1,222	)	$	29		$	3,744

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

E.ON U.S. LLC and Subsidiaries

Condensed Consolidated Balance Sheets

(Unaudited - Millions of $)

	March 31,		December 31,
	2010		2009
Assets:
Current assets:
Cash and cash equivalents	$	13	$	7
Accounts receivable:
Customer - less reserve of $3 in 2010 and $2 in 2009		288		286
Other - less reserve of $3 in 2010 and $2 in 2009		48		34
Materials and supplies:
Fuel (predominantly coal)		172		158
Gas stored underground		20		56
Other materials and supplies		74		72
Deferred income taxes (Note 9)		10		10
Assets of discontinued operations (Note 3)		-		90
Regulatory assets (Note 5)		17		46
Prepayments and other current assets		7		36

Total current assets		649		795

Utility plant, at original cost:
Electric		8,274		8,226
Gas		647		640
Common		223		226

Total utility plant, at original cost		9,144		9,092

Less: reserve for depreciation		3,579		3,546

Total utility plant, net		5,565		5,546

Construction in progress		1,619		1,599

Net utility plant and construction work in progress		7,184		7,145

Other property and investments:
Investment in unconsolidated venture		24		21
Other		5		5

Total other property and investments		29		26

Regulatory assets – pension and postretirement benefits (Notes 5 and 8)		309		309
Regulatory assets - other (Note 5)		244		242
Goodwill		837		837
Other long-term assets		65		75

Total deferred debits and other assets		1,455		1,463

Total assets	$	9,317	$	9,429

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

E.ON U.S. LLC and Subsidiaries

Condensed Consolidated Balance Sheets (Continued)

(Unaudited - Millions of $)

	March 31,		December 31,
	2010		2009
Liabilities and equity:
Current liabilities:
Current portion of long-term debt (Note 10)	$	348	$	348
Current portion of long-term debt - affiliated company (Notes 4 and 10)		408		358
Notes payable - affiliated company (Note 4)		739		851
Accounts payable		211		222
Accounts payable - affiliated companies (Note 4)		54		43
Customer deposits		47		44
Liabilities of discontinued operations (Note 3)		-		7
Regulatory liabilities (Note 5)		23		41
Derivative liability		69		76
Other current liabilities		93		117

Total current liabilities		1,992		2,107

Long-term debt - affiliated companies (Notes 4 and 10)		3,063		3,063
Long-term debt (Note 10)		416		416

Total long-term debt		3,479		3,479

Deferred income taxes (Note 9)		99		87
Investment tax credit (Note 9)		151		152
Accumulated provision for pensions and related benefits (Note 8)		514		540
Asset retirement obligations (Note 5)		67		66
Regulatory liability - accumulated cost of removal (Note 5)		598		587
Regulatory liability - other (Note 5)		75		76
Derivative liability (Note 6)		29		28
Other long-term liabilities		77		83

Total deferred credits and other liabilities		1,610		1,619

Equity		2,236		2,224

Total liabilities and equity	$	9,317	$	9,429

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

E.ON U.S. LLC and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(Unaudited - Millions of $)

	Three Months Ended
	March 31,
	2010			2009
Cash flows from operating activities:
Net income (loss)	$	60		$	(35	)
Items not requiring cash currently:
Depreciation, accretion and amortization		69			65
Deferred income taxes - net (Note 9)		5			(8	)
Investment tax credit - net (Note 9)		(1	)		5
Provision for pensions		19			22
Undistributed earnings of unconsolidated ventures		(3	)		4
Loss from discontinued operations - net of tax (Note 3)		3			35
Gains on interest-rate swaps		(2	)		(11	)
Changes in current assets and liabilities:
Accounts receivable		6			50
Materials and supplies		20			66
Accounts payable		3			19
Accrued taxes and interest		21			3
Prepayments and other		(33	)		(22	)
Changes in other deferred credits		(3	)		(3	)
Changes in regulatory assets and liabilities		9			17
Changes in deferred income tax liabilities		2			2
Pension and postretirement funding		(45	)		(3	)
Net operating cash flows from discontinued operations		24			(38	)
Other		(12	)		(2	)

Net cash flows provided by operating activities		142			166

Cash flows from investing activities:
Construction expenditures		(90	)		(173	)
Construction expenditures - discontinued operations		-			(8	)
Proceeds from sales of consolidated subsidiaries		14			-
Proceeds from sales in investments in unconsolidated ventures		7			-
Change in non-hedging derivative liability		-			1
Decrease in restricted cash		-			7

Net cash flows used by investing activities		(69	)		(173	)

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

E.ON U.S. LLC and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Continued)

(Unaudited - Millions of $)

	Three Months Ended
	March 31,
	2010			2009
Cash flows from financing activities:
Borrowings from affiliates (Note 4)		174			376
Repayment of borrowings from affiliates (Note 4)		(235	)		(354	)
Payment of common dividends		(6	)		(14	)

Net cash flows (used) provided by financing activities		(67	)		8

Change in cash and cash equivalents		6			1

Beginning cash and cash equivalents		7			15

Ending cash and cash equivalents	$	13		$	16

The accompanying notes are an integral part of these 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 AG, a German corporation. The consolidated financial statements include the following companies: E.ON U.S., LG&E, KU, LEM, E.ON U.S. Services and Capital Corp., and their wholly owned subsidiaries. E.ON U.S.'s utility operations are comprised of LG&E and KU. E.ON AG 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.

E.ON U.S. Services 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 ASC 280, Segment Reporting. 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 interim financial statements include all adjustments, consisting only of normal recurring adjustments, necessary for a fair statement of financial position, results of operations, retained earnings, comprehensive income and cash flows for the periods indicated. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted. These unaudited financial statements and notes should be read in conjunction with the Company's Financial Statements for the year ended December 31, 2009, including the audited financial statements and notes therein.

PPL Corporation ("PPL") Acquisition

On April 28, 2010, E.ON U.S. announced that E.ON AG and E.ON US Investments Corp. had entered into a definitive agreement with PPL, a Pennsylvania corporation, to sell to PPL all the equity interests of E.ON U.S. for a base purchase price totaling $7.625 billion, including the refinancing of debt currently payable to E.ON affiliates and the assumption of $764 million of debt. The transaction is anticipated to close by the end of 2010, subject to completion of all the conditions precedent to its consummation. These conditions include the approval of the Kentucky Commission, the Virginia Commission and the Tennessee Regulatory Authority under state utilities laws, the approval of the FERC under the Federal Power Act and the filing of required notices with the Department of Justice and the Federal Trade Commission under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and the application of relevant waiting periods. On May 28, 2010, the transaction parties, including the Company, submitted applications to the Kentucky Commission relating to the acquisition transaction and certain finance-related aspects thereof. Subject to the applicable regulatory processes and procedural requirements governing financing and acquisition applications, Kentucky Commission orders relating to such filings could occur during the third or fourth quarters of 2010.

Reclassifications

Certain reclassification entries have been made to the previous years' financial statements to conform to the 2010 presentation. These reclassifications consist mainly of those necessary to present the Company's Argentine Gas Distribution businesses as discontinued operations. See Note 3, Discontinued Operations.

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 first reporting period beginning after issuance except for disclosures about the roll-forward of activity in level 3 fair value measurements. This guidance has no impact on the Company's results of operations, financial position, or liquidity. The Company adjusted its disclosures as required.

Note 2 - Goodwill

The following table shows goodwill as of and for the periods ended March 31, 2010, and December 31, 2009. Goodwill is attributable to the Company's regulated utilities, LG&E and KU (in millions of $).

			Accumu-
			lated
			Impair-
	Cost		ment			Net

Balance at January 1, 2009	$	4,136	$	(1,806	)	$	2,330

Impairment loss		-		(1,493	)		(1,493	)

Balance at December 31, 2009		4,136		(3,299	)		837

Impairment loss		-		-			-

Balance at March 31, 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 its 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 AG. 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 the 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 BREC, 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 BREC 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 months ended March 31, 2010, the Company recorded a pretax loss on disposal of $1 million and made payments totaling $15 million as part of the transaction. The Company will continue to make payments related to the transaction through the end of 2010 (and under certain circumstances to the end of 2011). The remaining payments were accrued. 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 WKEC lease termination transaction.

The table below provides selected income statement information for the WKE discontinued operations for the three-month periods ended March 31 (in millions of $):

	2010			2009

Revenues	$	-		$	61

Loss before taxes		(3	)		(56	)
Income tax benefit		1			22

Net loss	$	(2	)	$	(34	)

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 serve 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 AG. 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 for the three-month period ended March 31, 2009 (in millions of $):

Revenues	$	12

Income before taxes		1
Income tax expense		(2	)
Noncontrolling interest		(1	)

Net (loss)	$	(2	)

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

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 – Related Party Transactions

The Company had the following balances with E.ON AG and its affiliates as of March 31, 2010, and December 31, 2009 (in millions of $):

	March 31,		December 31,
	2010		2009

Accounts payable	$	54	$	43
Notes payable		739		851
Long-term debt		3,471		3,421

The Company recorded interest expense to E.ON and its affiliates of $40 million and $37 million in the three-month periods ended March 31, 2010 and 2009, respectively. The Company also paid dividends to E.ON totaling $6 million and $14 million in the three-month periods ended March 31, 2010 and 2009, respectively. See Note 9, Income Taxes, and Note 10, Short-Term and Long-Term Debt.

Note 5 - Utility Rates and Regulatory Matters

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 of the Company's audited financial statements for the year ended December 31, 2009.

2010 Kentucky Electric and Gas Rate Cases. In January 2010, LG&E filed an application with the Kentucky Commission requesting an increase in electric base rates of approximately 12%, or $95 million annually, and its gas base rates of approximately 8%, or $23 million annually, including an 11.5% return on equity for electric and gas. At the same time, KU also filed an application with the Kentucky Commission requesting an increase in base electric rates of approximately 12%, or $135 million annually, including an 11.5% return on equity. LG&E and KU have 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 have been suspended until August 1, 2010, at which time they may be put into effect, subject to refund, if the Kentucky Commission has not issued an order in the proceeding. The parties are currently exchanging data requests and other filings in the proceedings and a hearing date has been scheduled for June 2010. A number of intervenors have entered the rate cases, including the Kentucky Attorney General's office, certain representatives of industrial and low-income groups and other third parties, and submitted filings challenging LG&E's and KU's requested rate increases, in whole or in part. An order in the proceeding may occur during the third or fourth quarters of 2010.

2008 Kentucky Electric and Gas Rate Cases. In January 2009, LG&E, KU, the AG, KIUC and all other parties to electric and gas base rate cases filed a settlement agreement with the Kentucky Commission. Under the terms of the settlement agreement, LG&E's base gas rates increased $22 million annually, and LG&E's and KU's base electric rates decreased $13 million and $9 million annually, respectively. An Order approving the settlement was received in February 2009, and the new rates were implemented effective February 6, 2009. In connection with the application and effective date of the new rates, the VDT surcredit and merger surcredit terminated, resulting in increased revenues of approximately $21 million and $16 million annually for LG&E and KU, respectively.

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 upon 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 will refund certain amounts collected since November 2009, consisting of interim rates in excess of the ultimate approved rates. These refunds aggregate approximately $1 million and are anticipated to occur during the second quarter of 2010.

FERC Wholesale Rate Case. In September 2008, KU filed an application with the FERC for increases in base electric rates applicable to wholesale power sales contracts or interchange agreements involving, collectively, twelve Kentucky municipalities. The application requested a shift from current, all-in stated unit charge rates to an unbundled formula rate. In May 2009, as a result of settlement negotiations, KU submitted an unopposed motion informing the FERC of the filing of a settlement agreement and agreed-upon seven-year service agreements with the municipal customers. The unopposed motion requested interim rate structures containing terms corresponding to the overall settlement principles, to be effective from May 1, 2009, until FERC approval of the settlement agreement. The settlement and service agreements provide for unbundled formula rates which are subject to annual adjustment and approval processes. In May 2009, the FERC issued an Order approving the interim settlement with respect to rates effective May 1, 2009, representing increases of approximately 3% from prior charges and a return on equity of 11%. Additionally, during May 2009, KU filed the first annual adjustment to the formula rates to incorporate 2008 data, which adjusted formula rates became effective on July 1, 2009, and were approved by the FERC during September 2009. In May 2010, KU submitted to the FERC the 2009 update to KU's FERC-jurisdictional wholesale requirements formula rate. The updated rate will go into effect on July 1, 2010, pending review by KU's FERC-jurisdictional wholesale requirements customers and review by the FERC, which could require a refund if the customers and/or the FERC identify inappropriate costs or charges.

Separately, the parties were not able to reach agreement on 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 by the FERC on this matter may occur during 2010. KU is not currently able to predict the outcome of this proceeding, including whether its wholesale customers may or may not be entitled to certain rights or benefits relating to renewable energy, and the financial or operational effects, if any, of such outcomes.

Regulatory Assets and Liabilities. The following regulatory assets and liabilities were included in the consolidated balance sheets as of March 31, 2010, and December 31, 2009 (in millions of $):

	March 31,		December 31,
	2010		2009

Current regulatory assets:
GSC	$	4	$	3
ECR		4		35
FAC		2		1
MISO exit		3		3
Other		4		4

Total current regulatory assets	$	17	$	46

Non-current regulatory assets:
Storm restoration	$	126	$	126
ARO		61		60
Unamortized loss on bonds		34		34
MISO exit		12		13
Other		11		9

Subtotals		244		242

Pension and postretirement benefits		309		309

Total non-current regulatory assets	$	553	$	551

Current regulatory liabilities:
GSC	$	10	$	34
DSM		9		7
ECR		2		-
Other		2		-

Total current regulatory liabilities	$	23	$	41

Non-current regulatory liabilities:
Accumulated cost of removal of utility plant	$	598	$	587
Deferred income taxes – net		48		50
Postretirement benefits		9		9
MISO exit		6		7
Other		12		10

Total non-current regulatory liabilities	$	673	$	663

LG&E does not currently earn a rate of return on the ECR, FAC, GSC and gas performance-based ratemaking (included in "GSC" above) regulatory assets which are separate recovery mechanisms with recovery within twelve months. KU does not currently earn a rate of return on the ECR and FAC regulatory assets and the Virginia levelized fuel factor included in other regulatory assets, which are separate recovery mechanisms with recovery within twelve months. No return is earned on the pension benefits regulatory asset that represents the changes in funded status of the plans. LG&E and KU will recover this asset through pension expense included in the calculation of base rates with the Kentucky Commission, and KU will seek recovery of this asset in future proceedings with the Virginia Commission. No return is currently earned on the ARO asset. 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. A return is earned on the unamortized loss on bonds, and these costs are recovered through amortization over the life of the debt. LG&E currently earns a rate of return on the balance of Mill Creek Ash Pond costs included in other regulatory assets, as well as recovery of these costs. LG&E and KU are seeking recovery of the storm restoration regulatory asset and adjustments to the amortization of CMRG and KCCS contributions, included in other regulatory assets, in the current base rate case. LG&E and KU recover through the calculation of base rates, the amortization of the net MISO exit regulatory asset in Kentucky incurred through April 30, 2008, and other regulatory assets including the EKPC FERC transmission settlement agreement and the Kentucky rate case expenses. KU received approval to recover the Virginia portion of the net MISO exit regulatory asset, as incurred through December 31, 2008, over a five year period and, due to the formula nature of its FERC rate structure, the FERC jurisdictional portion of the regulatory asset will be included in the annual updates to the rate formula. Recovery of the FERC jurisdictional pension expense, included in other assets, and the change in accounting method for spare parts, included in other liabilities, will be requested in the next FERC rate case. Other regulatory liabilities include DSM, FERC jurisdictional supplies inventory and MISO administrative charges collected via base rates from May 2008 through February 5, 2009. The MISO regulatory liability will be netted against the remaining costs of withdrawing from the MISO, per a Kentucky Commission Order, in the current Kentucky base rate case.

ECR. 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.

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 LG&E's and KU's 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 LG&E's and KU's applications. 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 of $2 million at March 31, 2010, as a result of these roll-in adjustments to base rates.

FAC. 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. In February 2010, the Virginia Commission recommended a change to the fuel factor KU had in its application, to which KU agreed. Following a public hearing in March 2010, and an Order in April 2010, the recommended charge became effective as of April 1, 2010, resulting in a 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 mechanisms 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 six-month period.

GSC. In December 2009, LG&E filed with the Kentucky Commission an application to extend and modify its existing gas cost performance-based ratemaking ("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.

Other Regulatory Matters

Kentucky Commission Report on Storms. In November 2009, the Kentucky Commission issued a report following review and analysis of the effects and utility response to the September 2008 wind storm and the January 2009 ice storm, and possible utility industry preventative measures relating thereto. The report suggested a number of proposed or recommended preventative or responsive measures, including consideration of selective hardening of facilities, altered vegetation management programs, enhanced customer outage communications and similar measures. In March 2010, LG&E and KU filed a joint response reporting on their actions with respect to such recommendations. The response indicated implementation or completion of substantially all of the recommendations, including, among other matters, on-going reviews of system hardening and vegetation management procedures, certain test or pilot programs and implementation of enhanced operational and customer outage-related systems.

Wind Power Agreements. In August 2009, LG&E and KU filed a notice of intent with the Kentucky Commission indicating their intent to file an application for approval of wind power purchase contracts and cost recovery mechanisms. The contracts were executed in August 2009, and were contingent upon LG&E and KU receiving acceptable regulatory approvals. Pursuant to the proposed 20-year contracts, LG&E and KU would jointly purchase respective assigned portions of the output of two Illinois wind farms totaling an aggregate 109.5 Mw. In September 2009, LG&E and KU filed an application and supporting testimony with the Kentucky Commission. In October 2009, the Kentucky Commission issued an Order denying LG&E's and KU's request to establish a surcharge for recovery of the costs of purchasing wind power. The Kentucky Commission stated that such recovery constitutes a general rate adjustment and is subject to the regulations of a base rate case. The Kentucky Commission Order provided for the request for approval of the wind power agreements to proceed independently from the request to recover the costs thereof via surcharges. In November 2009, LG&E and KU filed for rehearing of the Kentucky Commission's Order and requested that the matters of approval of the contract and recovery of the costs thereof remain the subject of the same proceeding. During December 2009, the Kentucky Commission issued data requests on this matter.

In March 2010, LG&E and KU delivered notices of termination under provisions of the wind power contracts. LG&E and KU also filed a motion with the Kentucky Commission noting the termination of the contracts and seeking withdrawal of their application in the related regulatory proceeding. In April 2010, the Kentucky Commission issued an Order allowing LG&E and KU to withdraw their pending application.

Trimble County Asset Transfer and Depreciation. LG&E and KU are currently constructing a new base-load, coal fired unit, TC2, which will be jointly owned by LG&E and KU, together with the IMEA and the IMPA. In July 2009, LG&E and KU notified the Kentucky Commission of the proposed sale from LG&E to KU of certain ownership interests in certain existing Trimble County generating station assets which are anticipated to provide joint or common use in support of the jointly-owned TC2 generating unit under construction at the station. The undivided ownership interests being sold are intended to provide KU an ownership interest in these common assets that is proportional to its interest in TC2 and the assets' role in supporting both TC1 and TC2. In December 2009, LG&E and KU completed the sale transaction at a price of $48 million, representing the current net book value of the assets, multiplied by the proportional interest being sold.

In August 2009, in a separate proceeding, LG&E and KU jointly filed an application with the Kentucky Commission to approve new depreciation rates for applicable TC2-related generating, pollution control and other plant equipment and assets. The filing requests common depreciation rates for the applicable jointly-owned TC2-related assets, rather than applying differing depreciation rates in place with respect to LG&E's and KU's separately-owned base-load generating 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 CCN Application and Transmission Matters. An application for a CCN for construction of TC2 was approved by the Kentucky Commission in November 2005. CCNs for two transmission lines associated with TC2 were issued by the Kentucky Commission in September 2005 and May 2006. All regulatory approvals and rights of way for one transmission line have been obtained.

The CCN for the remaining line 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 ruling was reversed by the Kentucky Court of Appeals in December 2007, and the proceeding reinstated. A motion for discretionary review of that reversal was filed by LG&E and KU with the Kentucky Supreme Court and was granted in April 2009. That proceeding, which seeks reinstatement of the Circuit Court dismissal of the CCN challenge, has been fully briefed and oral argument occurred during March 2010. A ruling on the matter could occur by mid 2010.

Completion of the transmission lines are also subject to standard construction permit, environmental authorization and real property or easement acquisition procedures and certain Hardin County landowners have raised challenges to the transmission line in some of these forums as well.

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 and received a temporary stay preventing KU from accessing their properties. In April 2009, that appellate court denied KU's motion to lift the stay and issued an Order retaining the stay until a decision on the merits of the appeal. Efforts to seek reconsideration of that ruling, or to obtain intermediate review of the ruling by the Kentucky Supreme Court, were unsuccessful, and the stay remains in effect. In April 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, which appellate Order remains subject to certain reconsideration or appeals rights of the parties.

Settlement discussions with the Hardin County property owners involved in the appeals of the condemnation proceedings have been unsuccessful to date. During the fourth quarter of 2008, LG&E and KU entered into settlements with certain Meade County landowners and obtained dismissals of prior litigation they had brought challenging the same transmission line.

As a result of the aforementioned unresolved litigation delays encountered in obtaining access to certain properties in Hardin County, KU has obtained easements to allow construction of temporary transmission facilities bypassing those properties while the litigated issues are resolved. In September 2009, the Kentucky Commission issued an Order stating that a CCN was necessary for two segments of the proposed temporary facilities. In December 2009, the Kentucky Commission granted the CCNs for the relevant segments and the property owners have filed various motions to intervene, stay and appeal certain elements of the Kentucky Commission's recent orders. In January 2010, in respect of two of such proceedings, the Franklin County circuit court issued Orders denying the property owners' request for a stay of construction and upholding the prior Kentucky Commission denial of their intervenor status. In parallel with, and consistent with the relevant legal proceedings and their status, KU is proceeding with the construction activities with respect to these temporary transmission facilities.

In a separate proceeding, certain Hardin County landowners have also challenged the same transmission line in federal district court in Louisville, Kentucky. In that action, the landowners claim that the U.S. Army failed to comply with certain National Historic Preservation Act requirements relating to easements for the line through Fort Knox. LG&E and KU are cooperating with the U.S. Army in its defense in this case and 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.

The Company is not currently able to predict the ultimate outcome and possible effects, if any, on the construction schedule relating to the transmission line approval, land acquisition and permitting proceedings.

Utility Competition in Virginia. The Commonwealth of Virginia passed the Virginia Electric Utility Restructuring Act in 1999. This act gave customers the ability to choose their electric supplier and capped electric rates through December 2010. KU subsequently received a legislative exemption from the customer choice requirements of this law. In April 2007, however, the Virginia General Assembly amended the Virginia Electric Utility Restructuring Act, thereby terminating this competitive market and commencing re-regulation of utility rates. The new act ended the cap on rates at the end of 2008. Pursuant to this legislation, the Virginia Commission adopted regulations revising the rules governing utility rate increase applications. As of January 2009, a hybrid model of regulation is being applied in Virginia. Under this model, utility rates are reviewed every two years. KU's exemption from the requirements of the Virginia Electric Utility Restructuring Act in 1999, however, discharges KU from the requirements of the new hybrid model of regulation. In lieu of submitting an annual information filing, KU has the option of requesting a change in base rates to recover prudently incurred costs by filing a traditional base rate case. KU is also subject to other utility regulations in Virginia, including, but not limited to, the recovery of prudently incurred fuel costs through an annual fuel factor charge and the submission of integrated resource plans.

Market-Based Rate Authority. In July 2006, the FERC issued an Order in LG&E's and KU's market-based rate proceedings accepting their further proposal to address certain market power issues the FERC had claimed would arise upon an exit from the MISO. In particular, LG&E and KU received permission to sell power at market-based rates at the interface of control areas in which it may be deemed to have market power, subject to a restriction that such power not be collusively re-sold back into such control areas. However, restrictions exist on sales by LG&E and KU of power at market-based rates in the LG&E/KU and Big Rivers Electric Corporation control areas. In June 2007, the FERC issued Order No. 697 implementing certain reforms to market-based rate regulations, including restrictions similar to those previously in place for LG&E's and KU's power sales at control area interfaces. In December 2008, the FERC issued Order No. 697-B potentially placing additional restrictions on certain power sales involving areas where market power is deemed to exist. As a condition of receiving and retaining market-based rate authority, LG&E and KU must comply with applicable affiliate restrictions set forth in the FERC regulation. During September 2008, LG&E and KU submitted a regular tri-annual update filing under market-based rate regulations.

In June 2009, the FERC issued Order No. 697-C which generally clarified certain interpretations relating to power sales and purchases at control area interfaces or into control areas involving market power. In July 2009, the FERC issued an order approving LG&E's and KU's September 2008 application for market-based rate authority. During July 2009, WKE and LEM completed a transaction terminating certain prior generation and power marketing activities in the Big Rivers Electric Corporation control area, which termination should ultimately allow a filing to request a determination that LG&E and KU are no longer deemed to have market power in such control area.

LG&E and KU conduct certain of their wholesale power sales activities in accordance with existing market-based rate authority principles and interpretations. Future FERC proceedings relating to Orders 697 or market-based rate authority could alter the amount of sales made at market-based versus cost-based rates. LG&E's sales under market-based rate authority totaled $10 million for the three months ended March 31, 2010. KU's sales under market-based rate authority totaled less than $1 million for the year ended March 31, 2010.

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 upon 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, the 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 2010, LG&E and KU submitted self-reports relating to additional standards, the resolution of which LG&E and KU do not anticipate will result in material penalties or remedial actions, but which processes remain in the early stages and therefore LG&E and KU are unable to determine the outcome. Mandatory reliability standard settlements commonly include other non-penalty elements, including compliance steps and mitigation plans. Settlements with the SERC proceed to NERC and FERC review before becoming final. While LG&E and KU believe they are in compliance with the mandatory reliability standards, they cannot predict the outcome of other analyses, including on-going SERC or other reviews described above.

Integrated Resource Plan. Pursuant to the Virginia Commission's December 2008 Order, KU filed its Integrated Resource Plan ("IRP") in July 2009. The filing consisted of the 2008 Joint IRP filed by KU and LG&E with the Kentucky Commission along with additional data. During March 2010, the Virginia Commission Staff issued a staff report acknowledging that KU fairly and adequately evaluated all resource options, documented and supported all critical model assumptions and methodologies, and complied with all legislative requirements and Virginia Commission guidelines.

Green Energy Riders. In May 2007, a Kentucky Commission Order was issued authorizing LG&E and KU to establish Small and Large Green Energy Riders, allowing customers to contribute funds to be used for the purchase of renewable energy credits ("REC") through June 1, 2010. During November 2009, LG&E and KU filed an application to both continue and modify the existing Green Energy Programs. In February 2010, the Kentucky Commission approved LG&E's and KU's application, as filed.

Note 6 - Financial Instruments

The cost and estimated fair values of the Company's non-trading financial instruments as of March 31, 2010, and December 31, 2009 follow (in millions of $):

	March 31, 2010				December 31, 2009
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
Long-term debt (including
current portion):
Affiliated companies		3,471		3,616		3,421		3,553
External		764		771		765		764
Interest rate swaps (liability)		29		29		28		28

The fair values for external long-term debt reflect prices quoted by dealers. The fair values for debt due to affiliates are determined using an internal valuation model that discounts the future cash flows of each loan at current market rates. The current market values are 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 swaps reflect price quotes from dealers, consistent with the fair value measurements and disclosures guidance of the FASB ASC. 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 is subject to the risk of fluctuating interest rates in the normal course of business. 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 March 31, 2010, a 100-basis-point change in the benchmark rate on the Company's variable-rate debt, not hedged by an interest rate swap, would impact pre-tax interest expense by $22 million annually.

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

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 counterparty credit risk by evaluating credit ratings and financial information. All counterparties had strong investment grade ratings at March 31, 2010. LG&E did not have any credit exposure to the swap counterparties, as it was in a liability position at March 31, 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 included in long-term assets in the accompanying balance sheets.

LG&E was party to various interest rate swap agreements with aggregate notional amounts of $179 million as of March 31, 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 0.19% and 0.20% at March 31, 2010, and December 31, 2009, respectively. One swap hedging 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 interest rate swaps are accounted for on a mark-to-market basis in accordance with the Derivatives and Hedging topic of the FASB ASC. Financial instruments designated as effective cash flow hedges have resulting gains and losses recorded within other comprehensive income and member's equity. The ineffective portion of financial instruments designated as cash flow hedges is recorded to earnings monthly as is the entire change in the market value of the ineffective swaps.

The table below shows the pretax amount and income statement location of other gains and losses from interest-rate swaps for the three months ended March 31, 2010 and 2009 (in millions of $):

			Amount
	Notes		2010			2009

Change in market value of
ineffective swaps		(1)	$	(1	)	$	5
Change in the ineffective
portion of swaps deemed
highly effective		(2)		(1	)		(1	)

Totals			$	(2	)	$	4

Notes:
(1)	Included in derivative gain (loss).
(2)	Included in interest expense.

Amounts recorded in accumulated other comprehensive income will be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The amount amortized from other comprehensive income to income in the three-month periods ended March 31, 2010 and 2009, was less than $1 million and $2 million, respectively. The amount expected to be reclassified from other comprehensive income to earnings in the next twelve months is less than $1 million. A deposit, used as collateral for one of the interest rate swaps, is included in long-term assets in the accompanying balance sheets. The deposit equaled $15 million and $17 million at March 31, 2010 and December 31, 2009, respectively. The amount of the deposit required is tied to the market value of the swap.

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 $28 million. Such a change could affect other comprehensive income if the hedge is effective, or the income statement if the hedge is ineffective.

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 the 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 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, letter 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 March 31, 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 March 31, 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 March 31, 2010 and December 31, 2009, was zero and 631,200 Mwhs, respectively.

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 Company recorded realized and unrealized gains of $1 million and $2 million, respectively, during the three months ended March 31, 2010, and realized and unrealized gains of $1 million and $4 million, respectively, during the three months ended March 31, 2009.

The Company does not net collateral against derivative instruments.

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 upon the Company 's credit ratings from each of the major credit rating agencies. At March 31, 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 March 31, 2010, is $22 million, for which LG&E has posted collateral of $15 million in the normal course of business. If the credit risk related contingent features underlying these agreements were triggered on March 31, 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 and there would be no effect on the energy trading and risk management contracts or collateral required as a result of these contracts.

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:

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 measures the assets and liabilities listed in the table below at fair value. The Company classifies its derivative cash collateral balances within level 1 based on the funds being held in liquid accounts. 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 other relevant economic measure. 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 old 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 ("NECAR")/Cinergy Hub forward prices by peak-type. See Note 3, Discontinued Operations.

Assets and liabilities measured at fair value as of March 31, 2010, are summarized below (in millions of $):

	Quoted Prices
	In Active		Significant
	Markets For		Other		Significant
	Identical		Observable		Unobservable
	Assets		Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)		Totals
Assets:
Interest-rate swap cash collateral	$	15	$	-	$	-	$	15
Electricity derivative contracts		-		8		-		8

Total assets	$	15	$	8	$	-	$	23

Liabilities:
Interest-rate swaps	$	-	$	29	$	-	$	29
Electricity derivative contracts		-		6		-		6
Smelter contract		-		-		63		63
E.ON share performance plan		-		1		-		1

Total liabilities	$	-	$	36	$	63	$	99

At March 31, 2010, interest-rate swap cash collateral was included in other long-term assets in the accompanying balance sheet, and the electricity derivative contract asset was included in prepayments and other current assets. Interest-rate swaps were included in other current liabilities and derivative liability (noncurrent) in the accompanying balance sheet, and the electricity derivative contract liability was included in derivative liability (current). The smelter-contract liability was included in derivative liability (current), and the liability for the E.ON share performance plan was included in other long-term liabilities.

Assets and liabilities measured at fair value as of December 31, 2009, are summarized below (in millions of $):

	Quoted Prices
	In Active		Significant
	Markets For		Other		Significant
	Identical		Observable		Unobservable
	Assets		Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)		Totals
Assets:
Interest-rate swap cash collateral	$	17	$	-	$	-	$	17
Electricity derivative cash collateral		2		-		-		2
Electricity derivative contracts		-		2		-		2

Total assets	$	19	$	2	$	-	$	21

Liabilities:
Interest-rate swaps	$	-	$	28	$	-	$	28
Electricity derivative contracts		-		2		-		2
Smelter contract		-		-		75		75
E.ON share performance plan		-		2		-		2

Total liabilities	$	-	$	32	$	75	$	107

At December 31, 2009, interest-rate swap cash collateral was included in accounts receivable and other long-term assets in the accompanying balance sheet, and the electricity derivative contract asset was included in prepayments and other current assets. Interest-rate swaps were included in other current liabilities and derivative liability (noncurrent) in the accompanying balance sheet, and the electricity derivative contract liability was included in derivative liability (current). The smelter-contract liability was included in derivative liability (noncurrent), and the liability for the E.ON share performance plan was included in other long-term liabilities.

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 March 31 (in millions of $):

	2010			2009

Balance at beginning of period	$	75		$	908

Realized losses included in earnings		2			-
Unrealized losses included in earnings		2			-
Unrealized gains included in earnings		-			(197	)
Settlements		(16	)		-

Balance at end of period	$	63		$	711

Note 8 - Pension and Other Postretirement Benefit Plans

E.ON U.S. employees benefit from both funded and unfunded non-contributory defined benefit pension plans and other postretirement benefit plans that together cover employees hired by December 31, 2005. Employees hired after this date participate in the Retirement Income Account ("RIA"), a defined contribution plan, and other postretirement benefit plans. The Company makes an annual lump sum contribution to the RIA, based on years of service and a percentage of covered compensation. The health care plans are contributory with participants' contributions adjusted annually. E.ON U.S. uses December 31 as the measurement date for its plans.

Components of Net Periodic Benefit Costs. The following table provides the components of net periodic benefit cost for the plans for the three months ended March 31, (in millions of $):

							Other
							Postretirement
	Pension Benefits						Benefits
	2010			2009			2010			2009

Service cost	$	5		$	5		$	1		$	1
Interest cost		16			16			3			3
Expected return on plan assets		(13	)		(12	)		(1	)		-
Amortization of prior service cost		2			2			1			-
Amortization of actuarial loss (gain)		5			6			-			-

Net periodic benefit cost	$	15		$	17		$	4		$	4

Contributions. The Company made discretionary contributions to its pension plans of $41 million and $29 million in January 2010 and April 2009, respectively. The Company also made a discretionary contribution to its WKE Union pension plan totaling $3 million in April 2010. The amount of future contributions to the pension plan will depend upon the actual return on plan assets and other factors, but the Company funds its pension obligations in a manner consistent with the Pension Protection Act of 2006.

The Company made contributions to its other postretirement benefit plans of $3 million in January 2010. The Company plans on making voluntary contributions to fund VEBA trusts to match the annual postretirement expense and funding the 401(h) plan up to the maximum amount allowed by law.

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 the federal statute of limitations related to 2006 and later years are open under the federal statute of limitations, Revenue Agent Reports for 2006-2007 have been received from the IRS, effectively closing these years to additional audit adjustments. Adjustments to these tax years were previously recorded in the financial statements. Tax years 2007 and 2008 were examined under an IRS pilot program named Compliance Assurance Process ("CAP"). This program accelerates the IRS's 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. Areas remaining under examination for 2008 include bonus depreciation and the Company's application for a change in repair deductions. No net material adverse impact is expected from these remaining areas.

Additions and reductions of uncertain tax positions during 2010 and 2009 were 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 March 31, 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 March 31, 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 the tax credit. A final IRS certification required to obtain the investment tax credit 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 credit. LG&E's portion of the TC2 tax credit will be approximately $24 million and KU's portion will be approximately $101 million. The tax credit will be amortized to income over the life of the related property beginning when the facility is placed in service. Based on eligible construction expenditures incurred, the Company recorded investment tax credits of $6 million during the three months ended March 31, 2009, decreasing current federal income taxes. The amount claimed through December 31, 2009, is all that the Company is allowed to claim. The Company has recorded its maximum credit of $125 million. In addition, a full depreciation basis adjustment is required for the amount of the credit and will be reflected in tax expense over the life of the related project.

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. During 2008 and 2009, the plaintiffs submitted amended complaints alleging additional claims for relief. In October 2009, the plaintiffs filed a motion for a preliminary injunction seeking temporary implementation of certain elements of the requested relief. The Company is not currently a party to this proceeding and is not able to predict the ultimate outcome of this matter.

In the first quarter 2010, KU recorded an income tax expense of less than $1 million to recognize the impact of the elimination of tax deduction related to Medicare Part D subsidy as required of the enactment of the Patient Protection and Affordable Care Act.

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

	Three Months Ended
	March 31,
	2010			2009

Statutory federal income tax rate		35.0	%		35.0	%
State income taxes, net of federal benefit		3.6			18.8
Dividends received deduction related to EEI investment		0.0			22.9
Amortization of investment tax credits		(0.6	)		11.1
Other differences – net		(0.4	)		12.2

Effective income tax rate		37.6	%		100.0	%

The effective income tax rate was at a more historically normal level for the three months ended March 31, 2010, compared to the three months ended March 31, 2009, primarily due to a change in pretax income. The effective rate for the three months ended March 31, 2010, was also impacted by the lack of EEI dividends in 2010 and, therefore, no related dividends received deduction. State income taxes, net of federal benefit, changed in the three months ended March 31, 2009, due to a coal credit recorded in 2009. The changes in the amortization of investment tax credits and other differences are directly attributable to the quarter over quarter increase in pretax income.

Note 10 – Short-Term and Long-Term Debt

Long-term debt and the current portion of long-term debt, summarized below, consists primarily of pollution control bonds issued by LG&E and KU, loans from an affiliated company, and medium-term notes issued by Capital Corp. Utility debt issuance expense is capitalized in regulatory assets and amortized over the lives of the related bond issues for LG&E and KU, consistent with regulatory practices. Non-utility issuance expense is amortized using the effective interest rate method.

Under the provisions for LG&E's and KU's variable-rate pollution control bonds classified as current portion of long-term debt, the bonds are subject to tender for purchase at the option of the holder and to mandatory tender for purchase upon the occurrence of certain events, causing the bonds to be classified as current portion of long-term debt. The following bond series are subject to tender for purchase:

LG&E:

Jefferson Co. 2001 Series A, due September 1, 2026, variable %

Trimble Co. 2001 Series A, due September 1, 2026, variable %

Jefferson Co. 2001 Series B, due November 1, 2027, variable %

Trimble Co. 2001 Series B, due November 1, 2027, variable %

KU:

Mercer Co. 2000 Series A, due May 1, 2023, variable %

Carroll Co. 2002 Series A, due February 1, 2032, variable %

Carroll Co. 2002 Series B, due February 1, 2032, variable %

Carroll Co. 2008 Series A, due February 1, 2032, variable %

Mercer Co. 2002 Series A, due February 1, 2032, variable %

Muhlenberg Co. 2002 Series A, due February 1, 2032, variable %

Carroll Co. 2004 Series A, due October 1, 2034, variable %

Carroll Co. 2006 Series B, due October 1, 2034, variable %

The average annualized interest rates for these bonds for the three months ended March 31, 2010, were 0.69% and 0.36% for LG&E and KU, respectively. The average annualized interest rates for these bonds during 2009 were 1.06% and 0.61% for LG&E and KU, respectively.

Pollution control bonds are obligations of LG&E or KU issued in connection with tax-exempt pollution control revenue bonds by various governmental entities, principally counties in Kentucky. A loan agreement obligates LG&E and KU to make debt service payments to the governmental entity that equates to the debt service due from the entity on the related pollution control revenue bonds. The loan agreement is an unsecured obligation of LG&E or KU.

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 March 31, 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. During 2008, interest rates increased, and LG&E and KU 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. During the three months ended March 31, 2010 and 2009, the average rate on LG&E's auction-rate bonds was 0.27% and 0.47%, respectively. The average rate on KU's auction-rate bonds was 0.27% and 0.65%, for the three months ended March 31, 2010 and 2009, respectively. 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, S&P downgraded the credit rating of Ambac, an insurer of the Company's bonds, from "A" to "BBB." As a result, S&P downgraded the ratings on certain bonds from "A" to "BBB+" in June 2009. The S&P ratings of these bonds are now based on the rating of LG&E and KU rather than the rating of Ambac 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. As of March 31, 2010, LG&E continued to hold repurchased bonds in the amount of $163 million. 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. maintains revolving credit facilities totaling $313 million at March 31, 2010, and December 31, 2009. At March 31, 2010, and December 31, 2009, one facility, totaling $150 million, is with E.ON North America, Inc., while the remaining facility, totaling $163 million, is with Fidelia; both are affiliated companies. Unused capacity under these facilities totaled $149 million and $37 million at March 31, 2010, and December 31, 2009, respectively. The average interest rates on outstanding balances under these facilities at March 31, 2010, and December 31, 2009, equaled 1.47% and 1.25%, respectively.

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 matures in July 2010. The interest rate on the loan equals the three-month LIBOR rate plus 1.28%. The Company used the proceeds from the loan to make payments related to the termination agreement with BREC. See Note 3, Discontinued Operations.

At March 31, 2010, and December 31, 2009, LG&E maintained bilateral line-of-credit facilities, with unaffiliated financial institutions, totaling $125 million, which mature in June 2012. Unused capacity under the facilities totaled $125 million at March 31, 2010, and December 31, 2009.

At March 31, 2010, and December 31, 2009, KU maintained a line-of-credit facility, with an unaffiliated financial institution, totaling $35 million, which matures in June 2012. Unused capacity under the facility totaled $35 million at March 31, 2010, and December 31, 2009. KU also maintains letter of credit facilities that support $195 million of the $228 million of bonds that can be put back to KU. Should the holders elect to put the bonds back and they cannot be remarketed, the letter of credit would fund the investor's payment.

All debt covenants at E.ON U.S. subsidiaries were satisfied at March 31, 2010, and December 31, 2009.

Note 11 - Commitments and Contingencies

Except as may be discussed in this quarterly report (including Note 5, Utility 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 a letter of credit securing off-balance sheet commitments totaling $8 million at March 31, 2010, and December 31, 2009. The underlying obligation is a performance guarantee. LG&E has also issued letters of credit as of March 31, 2010, and December 31, 2009, for off-balance sheet obligations totaling $4 million, and KU has issued a letter 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

In May 2004, the City of Owensboro, Kentucky and OMU commenced a suit which was removed to the U.S. District Court for the Western District of Kentucky, against KU concerning a long-term power supply contract (the "OMU Agreement") with KU. The dispute involved interpretational differences regarding issues under the OMU Agreement, including various payments or charges between KU and OMU and rights concerning excess power, termination and emissions allowances. In July 2005, the court issued a summary judgment ruling upholding OMU's contractual right to terminate the OMU agreement in May 2010.

In September and October 2008, the court granted rulings on a number of summary judgment petitions in the KU's favor. The summary judgment rulings resulted in the dismissal of all of OMU's remaining claims against KU. The trial on KU's counterclaim occurred during October and November 2008. During February 2009, the court issued orders on the matters covered at trial, including (i) awarding KU an aggregate $9 million relating to the cost of NOx allowances charged by OMU to KU and the price of back-up power purchased by OMU from KU, plus pre- and post-judgment interest, and (ii) denying KU's claim for damages based upon sub-par operations and availability of the OMU units. In April 2009, the court issued a ruling on various post-trial motions denying certain challenges to calculation elements of the $9 million award or of interest amounts associated therewith. In May 2009, KU and OMU executed a settlement agreement resolving the matter on a basis consistent with the court's prior rulings and KU has received the agreed settlement amounts. Therefore, pursuant to the settlement's operation, the OMU agreement terminated in May 2010, as described above.

Construction Program

LG&E had $50 million of commitments in connection with its construction program at March 31, 2010, and KU also had $50 million of commitments in connection with its construction program as of the same date.

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. The contract also contains standard representations, covenants, indemnities, termination and other provisions for arrangements of this type, including termination for convenience or for cause rights. In March 2009, the parties completed an agreement resolving certain construction cost increases due to higher labor and per diem costs above an established baseline, and certain safety and compliance costs resulting from a change in law. LG&E's and KU's shares of additional costs from inception of the contract through the expected project completion in 2010 are estimated to be approximately $10 million and $35 million, respectively. During the past and to date in 2010, LG&E and KU have received a number of contractual notices from the TC2 construction contractor asserting force majeure/excusable event claims for additional adjustments to either or both of contract price or construction schedule with respect to certain events which, if granted, may affect such contractual terms in addition to a possible extension of the commercial operations date, liquidated damages or other relevant provisions. The parties are continuing to discuss such matters in good faith and are attempting to resolve them in a commercially reasonable manner. The Company cannot currently estimate the ultimate outcome of these matters, including the extent, if any, that may result in increased costs charged for construction of TC2 and/or relief relating to the construction completion or operations 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 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 petition 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 anticipate replacing up to approximately 14,000 thermostats. Estimated costs associated with the replacement program may be $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.

Environmental

LG&E's and KU's operations are subject to a number of environmental laws and regulations, 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.

Clean Air Act Requirements. The Clean Air Act establishes a comprehensive set of programs aimed at protecting and improving air quality in the United States by, among other things, controlling stationary sources of air emissions such as power plants. While the general regulatory framework for these programs is established at the federal level, most of the programs are implemented and administered by the states under the oversight of the EPA. The key Clean Air Act programs relevant to LG&E's and KU's business operations are described below.

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 National Ambient Air Quality Standards ("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. Depending on the level of action determined necessary to bring local nonattainment areas into compliance with the new ozone and fine particulate standards, LG&E's and KU's power plants are potentially subject to additional reductions in SO2 and NOx emissions. In January 2010, EPA issued a proposed rule to reconsider the NAAQS for Ozone, previously revised in 2008. The proposal would institute more stringent standards. At present, the Company is unable to determine what, if any, additional requirements may be imposed to achieve compliance with the new ozone standard.

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. Depending upon the course of such matters, the CAIR could be superseded by new or revised NOx or SO2 regulations with different or more stringent requirements and SIPs which incorporate CAIR requirements could be subject to revision. LG&E and KU are also reviewing aspects of their compliance plan relating to the CAIR, including scheduled or contracted pollution control construction programs. Finally, as discussed below, the remand of the CAIR results in some uncertainty with respect to certain other EPA or state programs and proceedings and the companies' compliance plans relating thereto, due to the interconnection of the CAIR with such associated programs. At present, LG&E and KU are not able to predict the outcomes of the legal and regulatory proceedings related to the CAIR and whether such outcomes could have a material effect on the Company's financial or operational conditions.

Hazardous Air Pollutants. As provided in the Clean Air Act, as amended, 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 Clean Air Mercury Rule ("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 announced that it intends to promulgate a new rule to replace the CAMR. 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. At present, LG&E and KU are not able to predict the outcomes of the legal and regulatory proceedings related to the CAMR and whether such outcomes could have a material effect on the Company's financial or operational conditions.

Acid Rain Program. The Clean Air Act, as amended, 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, as amended, 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 ("CAVR") detailing how the Clean Air Act's Best Available Retrofit Technology ("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 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 flue gas desulfurization equipment on all of its generating units prior to the effective date of the acid rain program. 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 LG&E will continue to evaluate improvements to further reduce SO2 emissions. In order to achieve the NOx emission reductions mandated by the NOx SIP Call, LG&E installed additional NOx controls, including selective catalytic reduction technology, during the 2000 through 2009 time period at a cost of $197 million. In 2001, the Kentucky Commission granted approval to recover the costs incurred by LG&E for these projects through the environmental surcharge mechanisms. Such monthly recovery is subject to periodic review by the Kentucky Commission.

KU met its Phase I SO2 requirements primarily through installation of FGD equipment on Ghent Unit 1. 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 and associated obligations, KU installed additional NOx controls, including SCR technology, during the 2000 through 2009 time period at a cost of $221 million. In 2001, the Kentucky Commission granted approval to recover the costs incurred by KU for these projects through the environmental surcharge mechanism. Such monthly recovery is subject to periodic review by the Kentucky Commission.

In order to achieve mandated emissions reductions, LG&E and KU expect to incur additional capital expenditures totaling approximately $85 million and $320 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 the Company 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. Such programs have been adopted in various states 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. At 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, (H.R. 2454), 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 (S. 1733), 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. More recently, Senators Kerry, Lieberman and others have announced that they are currently working on GHG legislation covering the utility and transportation sectors that would provide for a 17% reduction in GHG emissions by 2020, but have introduced no bill in the Senate to date. The Company is closely monitoring the progress of the legislation, although 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. Also in September 2009, the EPA proposed the GHG "tailoring" rule requiring new or modified sources with GHG emissions equivalent to at least 10,000 to 25,000 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 proposed rule. A final tailoring rule is expected in 2010. The EPA has announced that the final tailoring rule will address the phase in of GHG regulation for these stationary sources and will provide for regulation of new or modified stationary sources such as power plants in 2011.

The Company is unable to predict whether mandatory GHG reduction requirements will ultimately be enacted through legislation or regulations. As companies with significant coal-fired generating assets, LG&E and KU could be substantially impacted by programs requiring mandatory reductions in GHG emissions, although the precise impact on its operations, including the reduction targets and deadlines that would be applicable, cannot be determined prior to the enactment of such programs. While the Company believes that many costs of complying with mandatory GHG reduction requirements or purchasing emission allowances to meet applicable requirements would likely be recoverable, in whole or in part under the ECR, where such costs are related to the Company's coal-fired generating assets, or other potential cost-recovery mechanisms, this cannot be assured.

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. However, in March 2010, the court vacated the opinion of the three-judge panel and granted a motion for rehearing. The Comer complaint alleges that GHG emissions from the defendants' facilities contributed to global warming which increased the intensity of Hurricane Katrina. LG&E and KU were included as 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.

Brown New Source Review Litigation. In April 2006, the EPA issued a NOV alleging that KU had violated certain provisions of the Clean Air Act's new source review rules relating to work performed in 1997, on a boiler and turbine at KU's E.W. Brown generating station. In December 2006, the EPA issued a second NOV alleging KU had exceeded heat input values in violation of the air permit for the unit. In March 2007, the Department of Justice filed a complaint in federal court in Kentucky alleging the same violations specified in the prior NOVs. The complaint sought civil penalties, including potential per-day fines, remedial measures and injunctive relief. In December 2008, KU reached a tentative settlement with the government resolving all outstanding claims. The consent decree, which was approved by the court in March 2009, provides for payment of a $1 million civil penalty; funding of $3 million in environmental mitigation projects; surrender of 53,000 excess SO2 allowances; surrender of excess NOx allowances estimated at 650 allowances annually for eight years; installation of an FGD by December 31, 2010; installation of an SCR by December 31, 2012; and compliance with specified emission limits and operational restrictions. KU is currently implementing the provisions of the consent decree.

Section 114 Requests. In August 2007, the EPA issued administrative information requests under Section 114 of the Clean Air Act requesting new source review-related data regarding certain projects undertaken at LG&E's Mill Creek 4 and TC1 generating units and KU's Ghent 2 generating unit. LG&E and KU have complied with the information requests and are not able to predict further proceedings in this matter at this time.

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. KU 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. KU is currently unable to determine the final outcome of this matter or the impact of an unfavorable determination upon KU's financial position or results of operations.

Ash Ponds, Coal-Combustion Byproducts and Water Discharges. 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 May 2010, the EPA announced 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. The EPA has also announced plans to develop revised effluent limitations guidelines and standards governing discharges from power plants. The Company is monitoring these ongoing regulatory developments, but will be unable to determine the impact until such time as new rules are finalized.

In May 2010, the Sierra Club 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 Station. Due to the preliminary stage of the proceedings, the Company is currently 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 completed settlement with state regulators regarding particulate limits in the air permit for KU's Tyrone generating station, remediation obligations or activities for LG&E's former manufactured gas plant sites, remediation activities for or other risks relating to elevated Polychlorinated Biphenyl levels at existing properties; liability under the Comprehensive Environmental Response, Compensation and Liability Act for cleanup at various off-site waste sites; on-going claims regarding alleged particulate emissions from LG&E's Cane Run station and claims regarding GHG emissions from LG&E'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 LG&E'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.

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 awaiting 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. The carrying amount recorded for all indemnifications/guarantees was $74.3 million at March 31, 2010 and $85.6 million at December 31, 2009, and relate to WKE.

In connection with the WKE transaction, see Note 3, Discontinued Operations, WKE indemnified the purchaser against certain liabilities primarily related to litigation from third parties. The estimated fair value of this indemnity obligation is $10.8 million and is included in the indemnifications/guarantees balance of $74.3 million at March 31, 2010 and $85.6 million at December 31, 2009. Additionally, regarding the WKE transaction, a direct financial guarantee in the form of a swap was issued to a third party customer. The estimated fair value of this guarantee is $63.5 million at March 31, 2010 and was $74.8 million at December 31, 2009, and is included in the indemnifications/ guarantees balance of $74.3 million at March 31, 2010 and $85.6 million at December 31, 2009. The Company has issued direct financial guarantees to all parties involved guaranteeing the due and punctual payment, performance and discharge by each WKE 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. 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.

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 - Accumulated Other Comprehensive Income

Accumulated other comprehensive income for the three months ended March 31, 2010, consisted of the following (in millions of $):

	Funded Status Of
	Pension And					Accumulated Deri-					Foreign Currency
	Postretirement Plans					vative Gain or Loss					Translation Adj.						____________Totals___________
	Pretax			Tax		Pretax			Tax		Pretax			Tax			Pretax			Tax		Net

Balance at December 31, 2009	$	(80	)	$	32	$	(8	)	$	2	$	13		$	(2	)	$	(75	)	$	32	$	(43	)

Gains (losses) on derivative in-
struments designated and qualifying
as cash flow hedging instruments		-			-		1			-		-			-			1			-		1

Disposal of discontinued operations		-			-		-			-		(13	)		2			(13	)		2		(11	)

Balance at March 31, 2010	$	(80	)	$	32	$	(7	)	$	2	$	-		$	-		$	(87	)	$	34	$	(53	)

Accumulated other comprehensive income for the three months ended March 31, 2009, consisted of the following (in millions of $):

	Funded Status Of
	Pension And					Accumulated Deri-					Foreign Currency
	Postretirement Plans					vative Gain or Loss					Translation Adj.						____________Totals___________
	Pretax			Tax		Pretax			Tax		Pretax			Tax			Pretax			Tax		Net

Balance at December 31, 2008	$	(109	)	$	43	$	(13	)	$	4	$	17		$	(3	)	$	(105	)	$	44	$	(61	)

Gains (losses) on derivative in-
struments designated and qualifying
as cash flow hedging instruments		-			-		2			-		-			-			2			-		2

Foreign currency translation
adjustment		-			-		-			-		(3	)		1			(3	)		1		(2	)

Balance at March 31, 2009	$	(109	)	$	43	$	(11	)	$	4	$	14		$	(2	)	$	(106	)	$	45	$	(61	)

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 equaled $1 million.

The Company recorded income of less than $1 million related to the Plan in both of the three- month periods ended March 31, 2010, and 2009, as a result of a decline in relative performance of E.ON shares compared to a benchmark.

Note 14 – Subsequent Events

Subsequent events have been evaluated through June 4, 2010, the date of issuance of these statements and these statements contain all necessary adjustments and disclosures resulting from that evaluation.

On May 27, 2010, LG&E and KU filed rebuttal testimony in the Kentucky rate cases with the Kentucky Public Service Commission.

On April 30, 2010, the Company refinanced a maturing loan from Fidelia totaling $150 million. The new loan from Fidelia matures in April 2011 and has an interest rate of LIBOR plus .52%.

On April 30, 2010, the Kentucky Commission issued an order approving LG&E's application to extend for five years and modify its existing gas cost performance-based rate-making ("PBR") and the requested minor modifications to the PBR effective November 2010. The current PBR was set to expire at the end of October 2010.

On April 28, 2010, the Company announced that E.ON AG and E.ON US Investments Corp., the Company's direct parent, had entered into a definitive agreement with PPL, a Pennsylvania corporation, to sell to PPL all the equity interests of E.ON U.S. for a base purchase totaling $7.625 billion, including the refinancing of debt currently payable to E.ON affiliates and the assumption of $764 million of debt. The transaction is anticipated to close by the end of 2010, subject to completion of all the conditions precedent to its consummation. In connection with the announcement, Moody's placed the debt ratings of LG&E and KU under review for possible downgrade. S&P affirmed the existing ratings of the Company. On May 28, 2010, the transaction parties, including the Company, submitted applications to the Kentucky Commission relating to the acquisition transaction and certain finance-related aspects thereof. Subject to the applicable regulatory processes and procedural requirements governing financing and acquisition applications, Kentucky Commission orders relating to such filings could occur during the third or fourth quarters of 2010.

On April 15, 2010, the Company made a discretionary contribution to its WKE Union pension plan totaling $3.3 million.

On April 9, 2010, the Kentucky Commission issued an Order allowing LG&E and KU to withdraw their pending application for approval of the wind power contracts.

PPL Corp - FORM 8-K - EX-99.2 - EXHIBIT 99.2 - June 21, 2010

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PPL Corp Reports