PART I

Item 1. Business.

LG&E is a subsidiary of E.ON U.S. LLC (E.ON U.S.) (formerly known as LG&E Energy LLC and LG&E Energy Corp.). E.ON U.S. is a subsidiary of E.ON AG (E.ON), a German corporation. E.ON acquired LG&E Energy through its July 1, 2002 acquisition of Powergen plc, now Powergen Limited, a United Kingdom company and holding company for E.ON UK plc, E.ON’s United Kingdom market unit operating parent. As contemplated in their regulatory filings in connection with the E.ON acquisition, E.ON, Powergen and E.ON U.S. completed an administrative reorganization to move the E.ON U.S. group from an indirect Powergen subsidiary to an indirect E.ON subsidiary. This reorganization was effective in March 2003. In early 2004, E.ON U.S. began direct reporting arrangements to E.ON.

LG&E is now an indirect subsidiary of E.ON. As a result of these acquisitions and otherwise, E.ON and E.ON U.S. registered as holding companies under PUHCA 2005 in June 2006, and were formerly registered holding companies under PUHCA 1935.

LG&E’s affiliate, KU, is a regulated public utility engaged in the generation, transmission, distribution and sale of electric energy in Kentucky, Virginia and Tennessee.

In order to comply with PUHCA 1935, E.ON U.S. Services (formerly LG&E Energy Services), which was formed as a subsidiary service company of E.ON U.S., provides services to affiliated entities, including LG&E, at cost as permitted under PUHCA 1935 and PUHCA 2005.

E.ON, its utility subsidiaries, including LG&E, and certain of its non-utility subsidiaries are subject to certain regulation by the FERC under the Federal Power Act, PUHCA 2005 and the EPAct 2005, including with respect to record-keeping and reporting, acquisitions and sales of utility securities and properties, financial matters and intra-system sales of goods and services. LG&E believes that it has adequate authority (including financing authority) under existing FERC orders and regulations to conduct its business. LG&E will seek additional authorization when necessary.

LG&E has continued its separate identity and its preferred stock and debt securities were not affected by these transactions.

General

LG&E, incorporated in 1913 in Kentucky, is a regulated public utility that supplies natural gas to approximately 324,000 customers and electricity to approximately 398,000 customers in Louisville and adjacent areas in Kentucky. LG&E’s service area covers approximately 700 square miles in 17 counties and has an estimated population of one million. Included in this area is the Fort Knox Military Reservation, to which LG&E transports natural gas and provides electric service, but does not provide any distribution services. LG&E also provides natural gas service in limited additional areas. LG&E’s coal-fired electric generating stations, all equipped with systems to reduce SO2 emissions, produce most of LG&E’s electricity. The remainder is generated by a hydroelectric power plant and combustion turbines. Underground natural gas storage fields help LG&E provide economical and reliable natural gas service to customers. See Item 2, Properties.

Operating Revenues

For the year ended December 31, 2006, 70% of total operating revenues were derived from electric operations and 30% from natural gas operations. Electric and gas operating revenues and the percentages by class of service on a combined basis for this period were as follows:

(in millions)	Electric		Gas		Combined		% Combined
Residential	$	272	$	248	$	520	48	%
Commercial	227		103		330		30	%
Industrial	134		16		150		14	%
Public authorities	69		19		88		8	%
Total retail	702		386		1,088		100	%
Wholesale sales	224		1		225
Gas transported	—		5		5
Miscellaneous	17		3		20
Total	$	943	$	395	$	1,338

See Note 11 of Notes to Financial Statements under Item 8 for financial information concerning segments of business for the three years ended December 31, 2006.

Electric Operations

The sources of LG&E’s electric operating revenues and the sales volumes for the three years ended December 31, 2006, were as follows:

(in millions)	2006		2005		2004
ELECTRIC OPERATING REVENUES
Residential	$	272	$	276	$	241
Commercial	227		221		202
Industrial	134		128		120
Public authorities	69		66		62
Total retail	702		691		625
Wholesale sales	224		259		185
Provision for rate collections (refunds)	—		—		(11		)
Miscellaneous	17		37		17
Total	$	943	$	987	$	816

(Thousands of Mwh)	2006	2005	2004
ELECTRIC SALES
Residential	4,018	4,265	3,923
Commercial	3,614	3,682	3,534
Industrial	3,068	3,077	3,019
Public authorities	1,265	1,268	1,248
Total retail	11,965	12,292	11,724
Wholesale sales	7,621	8,704	7,819
Total	19,586	20,996	19,543

LG&E set its annual peak load of 2,729 Mw on August 3, 2006, when the temperature reached 94 degrees Fahrenheit in Louisville. LG&E’s record peak load of 2,754 Mw occurred in July 2005.

The electric utility business is affected by seasonal weather patterns. As a result, operating revenues (and associated operating expenses) are not generated evenly throughout the year. See Results of Operations under Item 7.

LG&E currently maintains a 12% - 14% reserve margin range. At December 31, 2006, LG&E owned steam and combustion turbine generating facilities with a net summer capability of 3,083 Mw and an 80 Mw nameplate-rated hydroelectric facility on the Ohio River with a net summer capability of 48 Mw. See Item 2, Properties. LG&E also obtains power from other utilities under bulk power purchase and interchange contracts. At December 31, 2006, LG&E’s system net summer capability, including purchases from others and excluding the hydroelectric facility, was 3,207 Mw.

LG&E uses efficient coal-fired boilers, fully equipped with SO2 removal systems, to generate most of its electricity. LG&E’s weighted-average system-wide emission rate for SO2 in 2006 was approximately 0.50 lbs./MMBtu of heat input, with every generating unit below its emission limit established by the Kentucky Division for Air Quality.

LG&E and 11 other electric utilities are participating owners of OVEC, located in Piketon, Ohio. OVEC owns and operates two power stations that burn coal to generate electricity, Kyger Creek Station in Ohio and Clifty

Creek Station in Indiana. LG&E owns 5.63% of OVEC’s common stock. Pursuant to current contractual arrangements, LG&E’s share of OVEC’s output is 5.63%, approximately 124 Mw of generation capacity.

LG&E was formerly a member of the MISO, a non-profit independent transmission system operator that serves the electrical transmission needs of much of the Midwest. Following receipt of applicable FERC, Kentucky Commission and other regulatory orders, LG&E withdrew from the MISO effective September 1, 2006. Specific proceedings regarding the costs and benefits of the MISO and exit matters had been underway since July 2003. Since its exit from the MISO, LG&E has been operating under a FERC-approved open access-transmission tariff. LG&E further contracted with the Tennessee Valley Authority to act as its reliability coordinator and Southwest Power Pool, Inc. to function as its independent transmission operator, pursuant to FERC requirements, with respect to transmission matters.

LG&E has changed its regional reliability council membership from the Reliability First Corporation to the SERC Reliability Corporation, effective January 1, 2007. Regional reliability councils are industry consortiums that promote, coordinate and ensure the reliability of the bulk electric supply systems in North America.

Gas Operations

The sources of LG&E’s natural gas operating revenues and the sales volumes for the three years ended December 31, 2006, were as follows:

(in millions)	2006		2005		2004
GAS OPERATING REVENUES
Residential	$	248	$	265	$	223
Commercial	103		108		89
Industrial	16		19		15
Public authorities	19		19		15
Total retail	386		411		342
Wholesale sales	1		19		7
Gas transported	5		5		6
Miscellaneous	3		2		2
Total	$	395	$	437	$	357

(Millions of cu. ft.)
GAS SALES
Residential	17,816	20,801	21,402
Commercial	8,130	9,131	9,144
Industrial	1,491	1,711	1,736
Public authorities	1,499	1,574	1,646
Total retail	28,936	33,217	33,928
Wholesale sales	149	2,652	1,221
Gas transported	12,000	12,549	13,692
Total	41,085	48,418	48,841

The natural gas utility business is affected by seasonal weather patterns. As a result, operating revenues (and associated operating expenses) are not generated evenly throughout the year. While natural gas usage patterns are seasonal, LG&E received approval from the Kentucky Commission for a WNA mechanism. The WNA

mechanism adjusts the distribution cost recovery component of the natural gas billings of residential and commercial customers to normal temperatures during the heating season months of November through April, somewhat mitigating the effect of weather extremes. In October 2006, the Kentucky Commission approved LG&E’s request to extend the current WNA mechanism through April 30, 2009. See Results of Operations under Item 7.

LG&E has five underground natural gas storage fields that help provide economical and reliable natural gas service to ultimate consumers. By using natural gas storage facilities, LG&E avoids the costs associated with typically more expensive pipeline transportation capacity to serve peak winter space-heating loads. LG&E stores natural gas in the summer season for withdrawal in the subsequent winter heating season. Without its storage capacity, LG&E would be forced to buy additional natural gas and pipeline transportation services during the winter months when customer demand increases and when the prices for natural gas supply and transportation services are typically at their highest. Currently, LG&E buys competitively priced natural gas from several large suppliers under contracts of varying duration. LG&E’s underground storage facilities, in combination with its purchasing practices, enable it to offer natural gas sales service at competitive rates. At December 31, 2006, LG&E had an inventory balance of natural gas stored underground of approximately 11.6 million Mcf of working natural gas valued at approximately $83 million.

A number of industrial customers purchase their natural gas requirements directly from alternate suppliers for delivery through LG&E’s distribution system. These large industrial customers account for approximately one-fourth of LG&E’s annual throughput.

During 2006, the maximum daily gas sendout was approximately 380,000 Mcf, occurring on December 7, 2006, when the average temperature for the day was 19 degrees Fahrenheit. Supply on that day consisted of approximately 226,000 Mcf from purchases, approximately 84,000 Mcf delivered from underground storage and approximately 70,000 Mcf transported for industrial customers. For a further discussion, see Gas Supply under Item 1.

Rates and Regulation

E.ON, LG&E’s ultimate parent, is a registered holding company under PUHCA 2005 and was a registered holding company under PUHCA 1935. As a registered holding company, E.ON, its utility subsidiaries, including LG&E, and certain of its non-utility subsidiaries have been subject to extensive regulation by the SEC and the FERC with respect to numerous matters, including: electric utility facilities and operations, wholesale sales of power and related transactions, accounting practices, issuances and sales of securities, acquisitions and sales of utility properties, payments of dividends out of capital and surplus, financial matters and inter-system sales of non-power goods and services. LG&E believes that it has adequate authority (including financing authority) under existing FERC orders and regulations to conduct its business and will seek additional authorization when necessary.

In August 2005, President Bush signed into law the EPAct 2005, significantly changing many federal statutes, repealing PUHCA 1935 as of February 8, 2006 and enacting PUHCA 2005. As part of the repeal of PUHCA 1935, the FERC was given more authority over the merger and acquisition of public utilities and more authority over the books and records of public utilities. Despite these increases in the FERC’s authority, LG&E believes that the repeal of PUHCA 1935 will lessen its regulatory burdens and provide more flexibility in the event of expansion.

Besides repealing PUHCA 1935, the EPAct 2005 is also expected to have substantial long-term effects on

energy markets, energy investment and regulation of public utilities and holding company systems by the FERC and the DOE. The FERC and the DOE are in various stages of rulemaking in implementing the EPAct 2005. While the precise impact of these rulemakings cannot be determined at this time, LG&E generally views the EPAct 2005 as legislation that will enhance the utility industry going forward.

The Kentucky Commission has regulatory jurisdiction over LG&E’s retail rates and service, and over the issuance of certain of its securities. The Kentucky Commission has the ability to examine the rates LG&E charges its retail customers at any time.

Pursuant to Kentucky law, the Kentucky Commission has established the boundaries of the service territory or area of each retail electric supplier in Kentucky (including LG&E), other than municipal corporations. Within this service territory each such supplier has the exclusive right to render retail electric service.

LG&E’s retail electric rates contain an FAC, whereby increases and decreases in the cost of fuel for electric generation are reflected in the rates charged to retail electric customers. The Kentucky Commission requires public hearings at six-month intervals to examine past fuel adjustments, and at two-year intervals to review past operations of the fuel clause and transfer of the then current fuel adjustment charge or credit to the base charges. The Kentucky Commission also requires that electric utilities, including LG&E, file documents relating to fuel procurement and the purchase of power and energy from other utilities.

Prior to 2004, LG&E’s retail electric rates were subject to an ESM which set an upper (12.5%) and lower (10.5%) limit for rate of return on equity. Any earnings excess or deficiency was shared 40% with ratepayers and 60% with shareholders. LG&E filed its final 2003 ESM calculations with the Kentucky Commission in March 2004 and applied for recovery of $13 million which was challenged by intervenors. In June 2004, the Kentucky Commission issued an Order largely accepting proposed settlement agreements by LG&E and the intervenors regarding the ESM. Under the settlements, LG&E continued to collect the $13 million of previously requested 2003 ESM revenue through March 2005. As part of the settlements, the parties agreed to a termination of the ESM relating to all periods after 2003. For discussion of current ESM matters, see Note 2 of Notes to Financial Statements under Item 8.

In June 2001, LG&E filed an application (“VDT case”) with the Kentucky Commission to create a regulatory asset relating to first quarter 2001 charges for a workforce reduction program. In December 2001, the Kentucky Commission approved a settlement in the VDT case and allowed LG&E to establish a regulatory asset of $141 million for the workforce reduction costs and begin amortizing these costs over a five year period starting in April 2001. The settlement reduced revenues by approximately $26 million through a surcredit on bills to ratepayers over the same five-year period, reflecting a sharing (40% to the ratepayers and 60% to LG&E) of the stipulated savings, net of amortization costs, of the workforce reduction. For discussion of current VDT matters, see Note 2 of Notes to Financial Statements under Item 8.

LG&E’s retail rates contain an ECR surcharge which recovers costs incurred by LG&E that are required to comply with the Clean Air Act and other environmental regulations. See Note 2 of Notes to Financial Statements under Item 8.

LG&E’s natural gas rates contain a GSC, whereby increases or decreases in the cost of natural gas supply are reflected in LG&E’s rates, subject to approval by the Kentucky Commission. The GSC procedure prescribed by Order of the Kentucky Commission provides for quarterly rate adjustments to reflect the expected cost of natural gas supply in that quarter. In addition, the GSC contains a mechanism whereby any over- or under-

recoveries of natural gas supply cost from prior quarters are to be refunded to or recovered from customers through the adjustment factor determined for subsequent quarters.

Integrated resource planning regulations in Kentucky require LG&E and the other major utilities to make triennial filings with the Kentucky Commission of various historical and forecasted information relating to load, capacity margins and DSM techniques. LG&E filed its most recent IRP in April 2005. The AG and KIUC were granted intervention in the IRP proceeding. The Kentucky Commission issued its staff report with no substantive issues noted and closed the case by Order in February 2006.

In December 2003, LG&E filed an application with the Kentucky Commission requesting adjustments in LG&E’s electric and natural gas rates. In June 2004, the Kentucky Commission issued an Order approving increases in LG&E’s annual electric base rates of approximately $43 million (7.7%) and annual natural gas base rates of approximately $12 million (3.4%). The rate increases took effect on July 1, 2004.

Subsequently during 2004 and 2005, the AG conducted an investigation regarding the proceedings resulting in the rate increases. The AG requested information from LG&E and the Kentucky Commission and its staff regarding alleged improper communications between LG&E and the Kentucky Commission related to the rate proceedings. The AG also requested rehearing of the rate increase orders on the basis of these allegations, as well as calculational aspects of the increased rates. In February 2005, the AG submitted a confidential report on its investigation with the Kentucky Commission and filed a motion summarizing the report as containing evidence of improper communications and record-keeping errors by LG&E in respect of its activities with state governmental agencies, including the Kentucky Commission.

In December 2005, the Kentucky Commission issued an Order noting completion of its inquiry, including review of the AG’s investigative report. The Order concluded that no improper communications occurred during the rate proceedings. Final proceedings took place during the first quarter of 2006 concerning the sole remaining open issue relating to state income tax rates used in calculating the granted rate increase. In March 2006, the Kentucky Commission issued an Order resolving this issue in LG&E’s favor consistent with the original rate increase order.

In August 2006, LG&E filed an application with the Kentucky Commission requesting approval for sale of the Waterside property to the Louisville Arena Authority, a non-profit corporation, in connection with the development and construction of a new multi-purpose arena in downtown Louisville. The Kentucky Commission issued an Order in September 2006, approving the proposed transaction. In November 2006, LG&E entered into a definitive relocation agreement with the Louisville Arena Authority providing for the reimbursement of the costs to be incurred in moving certain facilities related to the arena transaction. Those costs are currently estimated to be approximately $63 million. The parties further entered into a definitive property sale agreement providing for the sale of LG&E’s downtown site to the Louisville Arena Authority for approximately $10 million, representing the appraised value of the parcel, less certain agreed upon demolition costs. The amounts specified in the agreements are subject to certain adjustments. Depending upon continuing progress of the proposed arena, the transactions contemplated by the agreements are anticipated to occur between 2006 and 2010.

For a further discussion of regulatory matters, see Note 2 of Notes to Financial Statements under Item 8.

Construction Program and Financing

LG&E’s construction program is designed to ensure that there will be adequate capacity and reliability to meet the electric and natural gas needs of its service area. These needs are continually being reassessed and appropriate revisions are made, when necessary, in construction schedules. LG&E’s estimates of its construction expenditures can vary substantially due to numerous items beyond LG&E’s control, such as changes in interest rates, economic conditions, construction costs and new environmental or other governmental laws and regulations.

During the five years ended December 31, 2006, gross property additions amounted to approximately $872 million. Internally generated funds and external financings for the five-year period were utilized to provide for these gross additions. The gross additions during this period amounted to approximately 21% of total utility plant at December 31, 2006, and consisted of $698 million for electric properties and $174 million for natural gas properties. Gross retirements during the same period were $171 million, consisting of $138 million for electric properties and $33 million for natural gas properties.

Capital expenditures during the three years ending December 31, 2009, are estimated to be approximately $665 million. The major expenditures during this period relate to the development and construction of TC2, of which LG&E’s portion totals approximately $150 million (including $40 million for environmental controls), other environmental control equipment of approximately $80 million and approximately $30 million for the redevelopment of the Ohio Falls hydro facility.

Coal Supply

Coal-fired generating units provided approximately 97% of LG&E’s net kilowatt-hour generation for 2006. The remaining net generation for 2006 was provided by natural gas and oil-fueled combustion turbine peaking units and a hydroelectric plant. Coal is expected to be the predominant fuel used by LG&E in the foreseeable future, with natural gas and oil being used for peaking capacity and flame stabilization in coal-fired boilers or in emergencies. LG&E has no nuclear generating units and has no plans to build any in the foreseeable future.

LG&E maintains its fuel inventory at levels estimated to be necessary to avoid operational disruptions at its coal-fired generating units. Reliability of coal deliveries can be affected from time to time by a number of factors, including fluctuations in demand, coal mine production issues and other supplier or transporter operating difficulties.

LG&E has entered into coal supply agreements with various suppliers for coal deliveries for 2007 and beyond and normally augments its coal supply agreements with spot market purchases. LG&E has a coal inventory policy which it believes provides adequate protection under most contingencies. A coal inventory of approximately one million tons, or a 47-day supply, was on hand at December 31, 2006.

LG&E expects to continue purchasing most of its coal, which has sulfur content in the 2% - 3.5% range, from western Kentucky, southern Indiana, southern Illinois, Ohio and West Virginia for the foreseeable future. This supply, in combination with the Company’s SO2 removal systems, is expected to enable LG&E to continue to provide electric service in compliance with existing environmental laws and regulations.

Coal is delivered to LG&E’s Mill Creek station by rail and barge, Trimble County station by barge and Cane Run station by rail.

The historical average delivered cost of coal purchased and the percentage of spot coal purchases were:

	2006			2005			2004
Per ton	$	34.83		$	30.37		$	26.25
Per MMBtu	$	1.51		$	1.32		$	1.15
Spot purchases as % of all sources	8		%	14		%	7		%

Gas Supply

LG&E purchases natural gas supplies from multiple sources under contracts for varying periods of time, while transportation services are purchased from Texas Gas and Tennessee Gas.

LG&E transports natural gas on the Texas Gas system under Rate Schedules NNS and FT service. LG&E’s winter season NNS levels are 184,900 MMBtu/day and its winter season FT levels are 28,000 MMBtu/day. LG&E’s summer season NNS levels are 60,000 MMBtu/day and its summer season FT levels are 28,000 MMBtu/day. Each of the NNS agreements with Texas Gas is subject to termination by LG&E in equal portions during 2008, 2010 and 2011. Each of the FT agreements with Texas Gas is subject to termination by LG&E during 2008 and 2011. LG&E also transports on the Tennessee Gas system under Tennessee Gas’ Rate Schedule FT-A. LG&E’s contract levels with Tennessee Gas are 51,000 MMBtu/day throughout the year. The FT-A agreement with Tennessee Gas expires during 2012.

LG&E participates in rate and other proceedings affecting the regulated interstate natural gas pipelines that provide it service. Both Texas Gas and Tennessee Gas have active proceedings at the FERC in which LG&E is participating. During 2005, Texas Gas filed an application with the FERC to increase its base rates. Texas Gas began billing its rates subject to refund in that same year, pending approval of final rates by the FERC. Along with other interested parties, LG&E participated in this proceeding. The intervening parties reached a settlement of the issues, and the FERC approved the settlement in 2006. Shortly thereafter, Texas Gas refunded all amounts collected in excess of the final approved rates and refunded the applicable amounts to all customers. LG&E is in the process of refunding its portion of those refunded amounts to its retail customers through the GSC. The rates of Tennessee Gas are not being billed subject to refund.

LG&E also has a portfolio of supply arrangements of various terms with a number of suppliers designed to meet its firm sales obligations. These natural gas supply arrangements include pricing provisions that are market-responsive. These firm natural gas supplies, in tandem with pipeline transportation services, provide the reliability and flexibility necessary to serve LG&E’s natural gas customers.

LG&E owns and operates five underground natural gas storage fields with a current working natural gas capacity of approximately 15.1 million Mcf. Natural gas is purchased and injected into storage during the summer season and is then withdrawn to supplement pipeline supplies to meet the gas-system load requirements during the winter heating season. See Gas Operations under Item 1.

The estimated maximum deliverability from storage during the early part of the heating season is expected to be in excess of 350,000 Mcf/day. Under mid-winter design conditions, LG&E expects to be able to withdraw in excess of 300,000 Mcf/day from its storage facilities. The deliverability of natural gas from LG&E’s storage facilities decreases as storage inventory levels are reduced by seasonal withdrawals.

LG&E relies upon its significant underground storage to mitigate the price volatility to which customers might otherwise be exposed. In 2000, the Kentucky Commission issued an Order establishing Administrative Case

No. 384 — An Investigation of Increasing Wholesale Natural Gas Prices and the Impacts of such Increase on the Retail Customers Served by Kentucky’s Jurisdictional Natural Gas Distribution Companies. Subsequent to this investigation, the Kentucky Commission issued an Order in July 2001, encouraging natural gas distribution companies in Kentucky to take various actions, among them to propose a natural gas hedge plan. LG&E currently operates under a hedge plan proposed by LG&E beginning with the 2004/2005 winter heating season. This hedge plan relies upon LG&E’s underground natural gas storage to mitigate customer exposure to price volatility. In 2004, the Kentucky Commission approved LG&E’s proposed hedge plan, validating the effectiveness of storage to mitigate potential volatility associated with high winter natural gas prices. The Kentucky Commission also ordered that LG&E need not file hedge plans in the future unless it intended to utilize financial hedging instruments.

The average cost per Mcf of natural gas purchased by LG&E was $7.80 in 2006, $10.23 in 2005 and $7.18 in 2004. For further discussion of wholesale natural gas prices, see Note 2 of Notes to Financial Statements under Item 8.

Environmental Matters

Protection of the environment is a major priority for LG&E. Federal, state and local regulatory agencies have issued LG&E permits for various activities subject to air quality, water quality and waste management laws and regulations. For the five-year period ending with 2006 expenditures for pollution control facilities represented $179 million or 20% of total construction expenditures. LG&E estimates that construction expenditures for environmental control equipment from 2007 through 2009 will be approximately $120 million. For a discussion of environmental matters, see Note 9 of Notes to Financial Statements under Item 8.

In October 2006, E.ON U.S., LG&E and KU announced plans to provide up to $25 million over a period of up to twelve years to FutureGen Industrial Alliance, Inc. (“FutureGen”), a non-profit consortium. FutureGen will conduct research, development and demonstration activities relating to advanced coal technologies, including proposed construction of the world’s first coal-fired, “near zero emissions” power plant. Among the members of FutureGen are companies with interests in coal-fired electric power generation or coal production. FutureGen has signed an initial cooperative agreement with the DOE and expects to sign a full-scope cooperative agreement in 2007. Beyond their initial aggregate membership amount and contributions paid through 2006 of approximately $1 million, E.ON U.S., LG&E and KU have rights at sequential future times to terminate participation prior to incurring the obligation to contribute the relevant remaining contribution amounts.

Competition

At this time, neither the Kentucky General Assembly nor the Kentucky Commission has adopted or approved a plan or timetable for retail electric industry competition in Kentucky. The nature or timing of the ultimate legislative or regulatory actions regarding industry restructuring and their impact on LG&E, which may be significant, cannot currently be predicted. Some states that have already deregulated have begun discussions that could lead to re-regulation.

Over the last several years, LG&E has taken many steps to maintain efficient rate structures while achieving high levels of customer satisfaction, including: an increase in focus on commercial, industrial and residential customers; an increase in employee involvement and training; and continuous modifications of its organizational structure. LG&E also strives to control costs through competitive bidding and process improvements. LG&E’s performance in national customer satisfaction surveys continues to be high.

EMPLOYEES AND LABOR RELATIONS

LG&E had approximately 917 full-time regular employees at February 28, 2007. Of the total, 632 operating, maintenance and construction employees were represented by the IBEW Local 2100. LG&E and employees represented by the IBEW Local 2100 signed a three-year collective bargaining agreement in November 2005 with annual benefits re-openers.

E.ON U.S. Services provides services to affiliated entities, including LG&E, at cost as permitted under PUHCA 2005. On February 28, 2007, approximately 993 employees worked for E.ON U.S. Services.

Executive Officers of LG&E at February 28, 2007:

Name	Age	Position	Effective Date of Election to Present Position
Victor A. Staffieri	51	Chairman of the Board, President and Chief Executive Officer	May 1, 2001
John R. McCall	63	Executive Vice President, General Counsel and Corporate Secretary	July 1, 1994
S. Bradford Rives	48	Chief Financial Officer	September 15, 2003
Paul W. Thompson	50	Senior Vice President - Energy Services	June 7, 2000
Chris Hermann	59	Senior Vice President - Energy Delivery	February 14, 2003
Wendy C. Welsh	53	Senior Vice President - Information Technology	December 11, 2000
Martyn Gallus	42	Senior Vice President - Energy Marketing	December 11, 2000
Paula H. Pottinger	50	Senior Vice President - Human Resources	January 2, 2006

Other Officers of LG&E at February 28, 2007:

David A. Vogel*	41	Vice President - Retail and Gas Storage Operations	March 1, 2003
Michael S. Beer	48	Vice President - Federal Regulation and Policy	September 27, 2004
George R. Siemens	57	Vice President - External Affairs	January 11, 2001
D. Ralph Bowling	49	Vice President - Power Operations WKE	August 1, 2002
R. W. Chip Keeling	50	Vice President - Communications	March 18, 2002
John N. Voyles, Jr.	52	Vice President - Regulated Generation	June 16, 2003
Daniel K. Arbough	45	Treasurer	December 11, 2000
Valerie L. Scott	50	Controller	January 1, 2005

Officers generally serve in the same capacities at LG&E and its affiliates, E.ON U.S. and KU.

* Mr. Vogel announced his resignation from the Company during March 2007.

The present term of office of each of the above executive and other officers extends to the meeting of the Board of Directors following the 2007 Annual Meeting of Shareholders.

There are no family relationships between or among executive and other officers of LG&E. The above tables indicate officers serving as executive officers of LG&E at February 28, 2007.

Before he was elected to his current position, Mr. Staffieri was President and Chief Operating Officer of LG&E Energy from March 1999 to April 2001 (including President of LG&E from June 2000 to April 2001).

Mr. McCall has been Executive Vice President, General Counsel and Corporate Secretary of LG&E Energy and LG&E since July 1994.

Before he was elected to his current position, Mr. Rives was Senior Vice President - Finance and Controller of LG&E Energy and LG&E from December 2000 to September 2003.

Before he was elected to his current position, Mr. Thompson was Senior Vice President - Energy Services for LG&E Energy from August 1999 to June 2000.

Before he was elected to his current position, Mr. Hermann was Senior Vice President - Distribution Operations, from December 2000 to February 2003.

Before she was elected to her current position, Ms. Welsh was Vice President - Information Technology from February 1998 to December 2000 for LG&E Energy.

Before he was elected to his current position, Mr. Gallus was Vice President, Energy Marketing from August 1998 to December 2000 for LG&E Energy.

Before she was elected to her current position, Ms. Pottinger was Director, Human Resources from June 1997 to June 2002 and Vice President - Human Resources from June 2002 to January 2006.

Before he was elected to his current position, Mr. Vogel was Vice President - Retail Services from December 2000 to March 2003.

In addition to being elected to his current position, Mr. Arbough has held the positions of Director, Corporate Finance of LG&E Energy and LG&E from May 1998 to present.

Before he was elected to his current position, Mr. Beer was Senior Counsel Specialist, Regulatory from February 2000 to February 2001 and Vice President - Rates and Regulatory from February 2001 to September 2004.

Before he was elected to his current position, Mr. Siemens held the position of Director of External Affairs for LG&E Energy from August 1982 to January 2001.

Before he was elected to his current position, Mr. Bowling was General Manager Black Fossil Operations for E.ON U.K. in the United Kingdom from January 2002 to August 2002.

Before he was elected to his current position, Mr. Keeling was Director, Corporate Communications for LG&E

Energy from February 2000 to March 2002.

Before he was elected to his current position, Mr. Voyles was General Manager, Cane Run, Ohio Falls and Combustion Turbines, November 1998 to February 2003 and Director, Generation Services, February 2003 to June 2003.

Before she was elected to her current position, Ms. Scott was Director, Trading Controls and Energy Marketing Accounting from February 1999 to September 2002 and Director, Financial Planning and Accounting - Utility Operations from September 2002 to December 2004.

Item 1A. Risk Factors

In addition to the other information in this Form 10-K and other documents furnished to or filed by LG&E with the SEC from time to time, the following factors should be carefully considered in evaluating the Company. Such factors could affect actual results and cause results to differ materially from those expressed in any forward-looking statements made by, or on behalf of, the Company.

The electric and gas rates that LG&E charges customers, as well as other aspects of the business, are subject to significant state and FERC regulation.

The rates that the Company is allowed to charge for its services are a primary item influencing the results of operations, financial position and liquidity of the Company. The regulation of the rates that are collected from customers is determined, in large part, by governmental organizations outside the Company’s control, including the Kentucky Commission. This commission regulates many aspects of utility operations, including financial and capital structure matters, siting and construction of facilities, terms and conditions of service, safety and operations, accounting and cost allocation methodologies and other matters. While rate regulation is premised on recovery of prudently incurred costs and reasonable rate of return on capital, such cannot be assured. Regulatory proceedings regarding all matters of operations can thus significantly affect the earnings, liquidity and business activities of the Company.

Transmission and interstate market activities of LG&E, as well as other aspects of the business, are subject to significant FERC regulation.

The Company’s business is subject to regulation under the FERC covering matters including rates charged to transmission users and wholesale customers, interstate market structure and design, construction and operation of transmission facilities, acquisition and disposal of utility assets and securities, Standards of Conduct, Codes of Conduct, cost allocations and financial matters. Existing FERC regulation, changes thereto or issuance of new rules in these areas, can affect the earnings, operations and other activities of the Company.

LG&E’s exit from the MISO, as well as changes in transmission and wholesale power market structures, could increase costs or reduce revenues.

LG&E withdrew from the MISO effective September 1, 2006. The resulting changes to transmission and wholesale power market structures and prices are not completely estimable and may result in unforeseen effects on energy purchases and sales, transmission and related costs or revenues. As required by the FERC, in connection with its exit, the Company has engaged two independent third parties to perform certain oversight and functional control activities relating to transmission and related activities. Such activities may have an

effect on the Company’s ability to access the transmission system for wholesale, native load and off-system power activities. The Company will save certain MISO membership costs and charges, but is subject to MISO charges for off-system transactions in the MISO day-ahead and real-time energy markets as well as fees related to the new transmission service vendors. The Company believes that, over time, the benefits and savings from its exit of the MISO will outweigh the costs and expenses. However, until post-MISO market conditions and operations have matured, the effects on financial condition, liquidity or results of operations will remain difficult to fully predict.

LG&E undertakes significant capital projects and is subject to unforeseen costs, delays or failures in such projects, as well as risk of full recovery of such costs.

In the ordinary course of business, the Company is continually developing, permitting and constructing new generation and transmission facilities, as well as maintaining and improving existing facilities. The completion of these facilities without delays or cost overruns is subject to risks in many areas including approval and licensing; permitting; construction problems or delays; increases in commodity or equipment prices or in labor rates; contractor performance; weather and geological issues and political, labor and regulatory developments. Delays, additional costs or unsatisfactory regulatory treatment can result in reduced earnings. Further, if construction projects are not completed according to specifications, the Company may incur reduced plant efficiency, higher operating costs or continued capital costs.

Projects underway at LG&E include plans to construct a new base-load generating unit, TC2, and associated transmission facilities; the upgrade or construction of other transmission facilities and upgrades to emissions reduction equipment. These projects are in varying stages of construction, planning or regulatory approval.

LG&E’s costs of compliance with environmental laws are significant and are subject to continuing changes.

LG&E is subject to extensive federal, state and local environmental requirements which, among other things, regulate air emissions, water discharges and the management of hazardous and solid waste in order to adequately protect the environment. Compliance by the Company requires significant expenditures for installation of pollution control equipment, environmental monitoring, emission fees and permits at all of its facilities. If the Company fails to comply with environmental laws and regulations, even if caused by factors beyond its control, civil or criminal penalties and fines can result. Revised or additional laws and regulations could result in significant additional expense and operating restrictions on LG&E’s facilities or increased compliance costs which may not be fully recoverable from customers. The cost impact of such changes would depend upon the specific requirements enacted and cannot be determined at this time.

LG&E is undertaking significant emissions construction projects relating to upcoming compliance with the Clean Air Act, CAIR and CAMR standards, among others. Rate recovery and other regulatory proceedings regarding these matters occur periodically and will continue for some time.

LG&E’s operating results are affected by weather conditions, including storms and seasonal temperature variations, as well as by significant man-made or accidental disturbances.

Customer demand for electricity and natural gas is seasonal and can cause extreme variability in load due to higher or lower than normal temperatures. Generally, demand for electricity peaks during the summer and demand for natural gas peaks during the winter. As a result, LG&E’s overall operating results can fluctuate

substantially on a seasonal basis. LG&E maintains adequate generating and natural gas supply resources to accommodate system demands for electricity and natural gas. In addition, the Company has generally sold less electricity or natural gas, as applicable, and consequently earned lower revenues, when weather conditions have been milder. However, the natural gas rates contain a WNA mechanism which adjusts the distribution cost recovery component of the natural gas billings of residential and commercial customers to normal temperatures during the heating season months of November through April, somewhat mitigating the effect of weather extremes. Severe weather, such as tornadoes, ice storms, thunderstorms, high wind or floods could also significantly affect the Company’s operations by causing power outages, damaging infrastructure and requiring significant repair costs. Terrorism, explosions or fires pose similar risks. LG&E maintains a comprehensive storm management plan for efficient and timely restoration of service to customers after major storm events.

LG&E is subject to risks regarding potential developments concerning global climate change matters.

LG&E is exposed to risks related to possible developments concerning climate change or global warming, including regulations relating to GHG. Such developments could include potential federal or state legislation or industry initiatives limiting GHG emissions, establishing costs or charges on GHG emissions or on fuels relating to such emissions, requiring remediation, sequestration or generation fleet-diversification to address GHG emissions, promoting energy efficiency or other measures. These actions could have substantial effects on the Company’s financial condition or results of operations, including increased capital expenditures or operating costs and changes in rate structures, fuel prices or customer demand levels. The Company’s generation fleet is predominantly coal-fired and may, as a relative matter, be highly impacted by developments in this area.

LG&E’s business is concentrated in the Midwest United States, specifically Kentucky.

The operations of the Company are located in Kentucky and are therefore impacted by changes in the Midwest United States economy in general, and the Kentucky economy in particular. General economic conditions, such as population growth, industrial growth or expansion and economic development, as well as the operational or financial performance of major industries or customers in the Company’s service territory can affect the demand for electricity and natural gas.

LG&E is subject to operational risks relating to its generating plants, transmission facilities and distribution equipment.

Operation of power plants, transmission and distribution facilities subjects LG&E to many risks, including the breakdown or failure of equipment, accidents, labor disputes, delivery/transportation problems, disruptions of fuel supply and performance below expected levels. Because LG&E’s transmission facilities are interconnected with those of third parties, the operation of its facilities may be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties. Operation of the Company’s power plants below expected capacity levels could result in lost revenues or increased expenses, including higher maintenance costs that may not be recovered from customers. Unplanned outages may result in significant replacement power costs. While LG&E believes appropriate prevention or mitigation measures are in place, where possible, with respect to these potential business disruptions, no assurances can be given that such events will not occur in the future or will not negatively affect its financial condition or results of operations.

LG&E could be negatively affected by rising interest rates, downgrades to credit ratings or other negative developments in its ability to access capital markets.

In the ordinary course of business, the Company has significant long-term and short-term financing requirements to fund its capital expenditures, debt interest or maturities and operating needs. If rating agencies were to downgrade the Company’s credit ratings, particularly below investment grade, or withdraw such ratings, it could significantly limit access to the capital market and the Company’s borrowing costs could increase. In addition, the Company’s financing costs can be affected by financial matters involving its parent holding company, including its overall credit rating, its provision of intra-company financing and the terms and rates of such financing.

LG&E is subject to commodity price risk, credit risk, counterparty risk and other risks associated with the energy business.

LG&E is exposed to market, operating and financial risks common to utility operations. Although the Company operates largely in regulated markets, increases in the cost of power and fuel, such as coal or natural gas, as well as other major inputs and supplies, can affect its margins because authorized rate structures and pass-through cost mechanisms may include timing lags or regulatory discretion which do not lead to full cost recovery. Changes in the wholesale market price for electricity can impact LG&E’s financial results by altering the revenues from off-system sales of excess power from period to period. LG&E is also exposed to risk that counterparties could fail to perform their obligations to provide energy, fuel, goods, services or payments resulting in potential increased costs to the Company.

LG&E is subject to risks associated with defined benefit retirement plans, health care plans, wages and other employee-related benefits.

The Company’s funding obligations concerning defined benefit pension and postretirement plans are subject to risks relating to developments in future costs, returns on investments, interest rates and other actuarial matters which may differ from assumptions currently in effect for the plans and may lead to higher required funding outlays. Further, higher wage levels, whether related to collective bargaining agreements or employment market conditions, and costs of providing health care benefits to employees may adversely affect LG&E’s results of operations, financial position or liquidity.

Item 1B. Unresolved Staff Comments.

None.

ITEM 2. Properties.

LG&E’s power generating system consists of the coal-fired units operated at its three steam generating stations. Combustion turbines supplement the system during peak or emergency periods. LG&E owns and operates the following electric generating stations unless otherwise stated:

		Summer Capability Rating (Mw)
Steam Stations:
Mill Creek — Jefferson County, KY
Unit 1		303
Unit 2		301
Unit 3		391
Unit 4		477
Total Mill Creek		1,472
Cane Run — Jefferson County, KY
Unit 4		155
Unit 5		168
Unit 6		240
Total Cane Run		563

Trimble County — Trimble County, KY (a)		383

Combustion Turbine Generators (Peaking capability):

Zorn — Jefferson County, KY		14
Paddy’s Run — Jefferson County, KY (b)		119
Cane Run — Jefferson County, KY		14
Waterside — Jefferson County, KY (c)		—
E.W. Brown — Mercer County, KY (d)		190
Trimble County — Trimble County, KY (e)		328
Total combustion turbine generators		665

Total capability rating		3,083

(a) Amount shown represents LG&E’s 75% interest. See Notes 9 and 10 of Notes to Financial Statements under Item 8 for further discussion on ownership.

(b) Amount shown represents LG&E’s 53% interest in Unit 13 and 100% ownership of Units 11 and 12. See Notes 9 and 10 of Notes to Financial Statements, under Item 8 for further discussion on ownership. Unit 12 was mothballed in November 2006. Life assessment (repair or retire) studies are ongoing.

(c) Pursuant to the Definitive Property Sale Agreement entered into with the Louisville Arena Authority in 2006, the Waterside property will be sold to the Louisville Arena Authority when the relocation of the LG&E assets has been completed, which is expected to occur by the end of 2008. The Waterside units were retired in December 2006.

(d) Amount shown represents LG&E’s 53% interest in Unit 5, 38% interest in Units 6 and 7 and 10% of the Inlet Air Cooling system, attributable to Unit 5. See Notes 9 and 10 of Notes to Financial Statements, under Item 8 for further discussion on ownership. KU operates these units on behalf of LG&E.

(e) Amount shown represents LG&E’s 29% interest in Units 5 and 6 and LG&E’s 37% interest in Units 7, 8, 9 and 10. See Notes 9 and 10 of Notes to Financial Statements, under Item 8 for further discussion on ownership.

LG&E also owns an 80 Mw nameplate-rated hydroelectric generating station located in Jefferson County, Kentucky (Ohio Falls), with an expected summer capability rating of 48 Mw, operated under a license issued by the FERC.

At December 31, 2006, LG&E’s electric transmission system included 41 substations (26 of which are shared with the distribution system) with a total capacity of approximately 11,900 Mva and approximately 894 miles of lines. The electric distribution system included 93 substations (26 of which are shared by the transmission system) with a total capacity of approximately 4,940 Mva, 3,931 miles of overhead lines and 2,161 miles of underground conduit.

LG&E’s natural gas transmission system includes 260 miles of transmission mains and the natural gas distribution system includes 4,175 miles of distribution mains.

LG&E operates underground natural gas storage facilities with a current working gas capacity of approximately 15.1 million Mcf. See Gas Supply under Item 1.

In 1990, LG&E entered into an operating lease for its corporate office building located in downtown Louisville, Kentucky. The lease was renegotiated in 2002 and is scheduled to expire July 31, 2015.

Other properties owned by LG&E include office buildings, service centers, warehouses, garages and other structures and equipment, the use of which is common to both the electric and gas departments.

The trust indenture securing LG&E’s first mortgage bonds constitutes a direct first mortgage lien upon much of the property owned by LG&E. In addition, Fidelia has a second secured lien on the property subject to the first mortgage bond lien for certain of its intercompany loans to LG&E.

ITEM 3. Legal Proceedings.

Rates and Regulatory Matters

For a discussion of current rate and regulatory matters, including electric and natural gas base rate increase proceedings, the Kentucky AG investigation, VDT proceedings, TC2 proceedings, various Kentucky Commission, FERC and MISO proceedings and other rate or regulatory matters affecting LG&E, see Rates and Regulation under Item 1 and Note 2 of Notes to Financial Statements under Item 8.

Environmental

For a discussion of environmental matters including additional reductions in SO2, NOx and other emissions mandated by recent regulations; items regarding the Cane Run generating station, MGP sites; global warming or climate change matters and other environmental items affecting LG&E, see Executive Summary (Environmental Matters) and Note 9 of Notes to Financial Statements under Item 8.

FERC Audit Results

In July 2006, the FERC issued a final report under a routine audit that its Office of Enforcement (formerly its Office of Market Oversight and Investigations) had conducted regarding the compliance of E.ON U.S. and subsidiaries, including LG&E, under the FERC’s standards of conduct and codes of conduct requirements, as well as other areas. The final report contained certain findings calling for improvements in E.ON U.S. and subsidiaries’ structures, policies and procedures relating to transmission, generation dispatch, energy marketing and other practices. E.ON U.S. and affiliates have agreed to certain corrective actions and have submitted procedures related to such corrective actions to the FERC. The corrective actions are in the nature of organizational and operational improvements as described above and are not expected to have a material adverse impact on the Company’s results of operations or financial condition.

Employment Discrimination Case

In October 2001, approximately 30 employees or former employees filed a complaint against LG&E claiming past and current instances of employment discrimination. LG&E has removed the case to the U.S. District Court for the Western District of Kentucky and filed an answer denying all plaintiffs’ claims. To date, the U.S. Equal Employment Opportunity Commission has declined to proceed to litigation on any claims reviewed. Through continuing mediation, settlements have been reached with the majority of plaintiffs, including the lead plaintiff. In November 2006, LG&E obtained dismissal orders on all but two remaining plaintiffs. The complaint contains a claimed damage amount of $100 million as well as requests for injunctive relief, however, all prior settlements have been for non-material amounts and LG&E does not anticipate that the remaining outcome will have a material impact on its operations or financial condition.

Other

In the normal course of business, other lawsuits, claims, environmental actions and other governmental proceedings arise against LG&E. To the extent that damages are assessed in any of these lawsuits, LG&E believes that its insurance coverage is adequate. Management, after consultation with legal counsel, does not anticipate that liabilities arising out of other currently pending or threatened lawsuits and claims will have a material adverse effect on LG&E’s financial position or results of operations, respectively.

ITEM 4. Submission of Matters to a Vote of Security Holders.

None.

PART II.

ITEM 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer

Purchases of Equity Securities.

All LG&E common stock, 21,294,223 shares, is held by E.ON U.S. Therefore, there is no public market for LG&E’s common stock.

The following table sets forth LG&E’s cash distributions on common stock paid to E.ON U.S. during 2006:

(in millions)
First quarter	$	40
Second quarter	20
Third quarter	35
Fourth quarter	—

LG&E paid cash distributions on common stock to E.ON U.S. in the amount of $39 million in 2005 and $57 million in 2004.

ITEM 6. Selected Financial Data.

	Years Ended December 31
(in millions)
	2006		2005		2004		2003		2002

Operating revenues	$	1,338	$	1,424	$	1,173	$	1,094	$	1,004

Net operating income	$	223	$	230	$	185	$	179	$	173

Net income	$	117	$	129	$	96	$	91	$	89

Total assets	$	3,184	$	3,146	$	2,967	$	2,882	$	2,769

Long-term obligations (including amounts due within one year)	$	820	$	821	$	872	$	798	$	617

Management’s Discussion and Analysis of Financial Condition and Results of Operations and Notes to Financial Statements should be read in conjunction with the above information.

ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

GENERAL

The following discussion and analysis by management focuses on those factors that had a material effect on LG&E’s financial results of operations and financial condition during 2006, 2005 and 2004 and should be read in connection with the financial statements and notes thereto.

Some of the following discussion may contain forward-looking statements that are subject to risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “expect,” “estimate,” “objective,” “possible,” “potential” and similar expressions. Actual results may materially vary. Factors that could cause actual results to materially differ include: general economic conditions; business and competitive conditions in the energy industry; changes in federal or state legislation; unusual weather; actions by state or federal regulatory agencies; actions by credit rating agencies and other factors described from time to time in LG&E’s reports to the SEC, including Risk Factors in Item 1A of this report on Form 10-K and in Exhibit No. 99.01 to this report on Form 10-K.

EXECUTIVE SUMMARY

Business

LG&E is a wholly-owned subsidiary of E.ON U.S., which is an indirect subsidiary of E.ON, a German company. LG&E maintains a separate corporate identity and serves customers in Kentucky.

LG&E, incorporated in 1913 in Kentucky, is a regulated public utility that supplies natural gas to approximately 324,000 customers and electricity to approximately 398,000 customers in Louisville and adjacent areas in Kentucky. LG&E’s service area covers approximately 700 square miles in 17 counties and has an estimated population of one million. Included in this area is the Fort Knox Military Reservation, to which LG&E transports natural gas and provides electric service, but does not provide any distribution services. LG&E also provides natural gas service in limited additional areas. LG&E’s coal-fired electric generating plants, all equipped with systems to reduce SO2 emissions, produce most of LG&E’s electricity. The remainder is generated by a hydroelectric power plant and combustion turbines. Underground natural gas storage fields help LG&E provide economical and reliable natural gas service to customers.

Customers

The following table provides statistics regarding LG&E’s retail customers:

Customers (in thousands)

	Electric			Gas			2006% Retail Revenues
Retail Customer Data	2006	2005	2004	2006	2005	2004	Electric		Gas

Residential	350	347	343	298	296	293	39	%	64	%
Industrial & Commercial	42	41	41	25	24	24	51	%	31	%
Other	6	6	6	1	1	1	10	%	5	%
Total Retail	398	394	390	324	321	318	100	%	100	%

Mission

The mission of LG&E is to build on our tradition and achieve world-class status providing reliable, low-cost energy services and superior customer satisfaction; and to promote safety, financial success and quality of life for our employees, communities and other stakeholders.

Strategy

LG&E’s strategy focuses on the following:

· Achieve scale as an integrated U.S. electric and gas business through organic growth and acquisitions;

· Maintain excellent customer satisfaction;

· Maintain best-in-class cost position versus U.S. utility companies;

· Develop and transfer best practices throughout the company;

· Invest in infrastructure to meet expanding load and comply with increasing environmental requirements;

· Achieve appropriate regulated returns on all investment;

· Attract, retain and develop the best people; and

· Act with a commitment to corporate social responsibility that enhances the well being of our employees, demonstrates environmental stewardship, promotes quality of life in our communities and reflects the diversity of the society we serve.

Low Rates

LG&E believes it is well positioned in the regulated Kentucky market. LG&E continues to sustain high customer satisfaction, ranking first among all large Midwest utilities for the seventh time in eight years in the J.D. Power and Associates 2006 survey of residential electric customers. This excellent performance is balanced with cost control. The customer benefits of the LG&E culture of cost management are evident in rate comparisons among U.S. utilities. As of July 1, 2006, the average residential rate per thousand Kwh for LG&E customers was 6.54 cents versus the national average of U.S. investor-owned utilities of 10.98 cents.

LG&E must continue to address new cost pressures. The Kentucky Commission accepted the settlement agreements reached by the majority of the parties in the rate cases filed by LG&E in December 2003. New rates, implemented in July 2004, produced approximately $55 million of revenue for LG&E for a full year. Under the settlement agreements, the Company’s base electric rates increased approximately $43 million

(7.7%) and base natural gas rates increased approximately $12 million (3.4%) annually. The 2004 increases were the first increases in electric base rates for LG&E in 13 years; the last natural gas rate increase for the Company took effect in September 2000. Competitors also face the same cost pressures that caused LG&E to initiate rate cases (e.g., pensions, benefits and reliability expenditures) and many other utility companies recently had rate cases. Despite these increases, LG&E’s rates remain significantly lower than the national average.

Commodity Prices: Fuel and Electricity

Nationally, coal price increases continued during 2006, up approximately 10% from 2005, with modest increases projected over the near term. Nationwide coal stockpiles grew during 2006, due to a surplus of 37 million tons of coal production over consumption, driven by a 1.4% decline in power generation usage of coal and a 3% increase in coal supply.

During 2006, natural gas prices declined significantly from the record levels reached the prior year. During 2005, natural gas prices averaged over $8/MMBtu and spiked as high as $15/MMBtu in late September following hurricanes that interrupted natural gas production activities in the Gulf of Mexico. Prices in 2006 averaged just over $7/MMBtu and fell as low as $4/MMBtu. Price declines are in part the result of ample national gas storage inventories, which are the result of a warmer-than-normal winter in 2005/2006 and the absence of any hurricanes during 2006 that could have otherwise disrupted natural gas supplies in the Gulf of Mexico. Although the supply situation has improved from 2005, the underlying and fundamental U.S. supply/demand imbalance shows no significant signs of immediate or significant improvement.

LG&E’s average coal and natural gas purchase prices for the last five years are as follows:

	2006		2005		2004		2003		2002
Coal (per MMBtu)	$	1.51	$	1.32	$	1.15	$	1.12	$	1.11
Natural gas (per MMBtu)	$	7.80	$	10.23	$	7.18	$	6.30	$	4.19

Actual fuel costs associated with retail electric sales are recovered from customers through the FAC. The FAC allows the Company to adjust customers’ accounts for the difference between the fuel cost component of base rates and the actual fuel cost, including transportation costs. Refunds to customers occur if the actual costs are below the embedded cost component. Additional charges to customers occur if the actual costs exceed the embedded cost component.

Actual natural gas costs are recovered from customers through the GSC. The GSC also contains an incentive component, the PBR component, which is determined for each 12-month period ending October 31.

Generation Reliability

Generation reliability also remains a key aspect to meeting the Company’s strategy. LG&E believes that it has maintained good performance and reliability in the key area of utility generation operation. While maintaining low cost levels, LG&E has also been able to generate increasing volumes and expect to continue high levels of availability and low outage levels. This performance is also important to maintaining margins from off-system sales.

Generation Capacity

The installation of Trimble County Units 7-10, completed in 2004, increased LG&E’s total system capability by 9%. However, the joint IRP submitted by LG&E and KU to the Kentucky Commission in 2005, outlining the least cost alternative to meet Kentucky’s needs, indicated the requirement for additional base-load capacity by 2010. Consequently, LG&E and KU have begun construction of another base-load coal-fired unit at the Trimble County site. LG&E believes this is the least cost alternative to meet the future needs of its customers. TC2, with a 750 MW capacity rating, will be jointly owned by LG&E (14.25%) and KU (60.75%) and IMEA and IMPA (25% owners). TC2 is expected to cost $1.1 billion and be completed by 2010. LG&E’s and KU’s aggregate 75% share of the total TC2 capital cost is approximately $880 million, of which LG&E will spend approximately $180 million through 2009. Through December 2006, LG&E’s expenditures for TC2 have been $32 million. See Note 10 of Notes to Financial Statements.

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.

A CCN application for TC2 construction was filed with the Kentucky Commission in December 2004, and initial CCN applications for three transmission lines were filed in early 2005, with further applications submitted in December 2005. The proposed air permit was filed with the Kentucky Division for Air Quality in December 2004. In November 2005, the Kentucky Commission approved the application to expand the Trimble County generating station. Kentucky Commission approval for one transmission line CCN was granted in September 2005, and a ruling that a second transmission line was not subject to the CCN process was received in February 2006. The Kentucky Commission granted approval for the remaining transmission line CCN in May 2006. In August 2006, LG&E and KU obtained dismissal of a judicial review of such CCN approval by certain property owners. A further appeal of such dismissal was thereafter filed, which action remains pending. The transmission lines are also subject to routine regulatory filings and the right-of-way acquisition process. In November 2005, the Kentucky Division for Air Quality issued the final air permit, which was challenged via a request for remand in December 2005 by three environmental advocacy groups, including the Sierra Club. Administrative proceedings with respect to the challenge continued throughout 2006. A ruling may occur during the first half of 2007.

In October 2005, LG&E received from the FERC a new license to upgrade, operate and maintain the Ohio Falls Hydroelectric Project. The license is for a period of 40 years, effective November 2005. LG&E intends to spend approximately $76 million to refurbish the facility and add approximately 20 Mw of generating capacity over the next six years.

Environmental Matters

In addition to the TC2 project, the second major area of utility investment is environmental expenditures. LG&E is subject to SO2 and NOx emission limits on its electric generating units pursuant to the Clean Air Act. LG&E placed into operation significant NOx controls for its generating units prior to the 2004 summer ozone season. As of December 31, 2006, LG&E has incurred total capital costs of approximately $187 million since

2000 to reduce its NOx emissions below required levels. In addition, LG&E has incurred additional operating and maintenance costs in operating the new NOx controls.

In March 2005, the EPA issued the final CAIR which requires substantial additional reductions in SO2 and NOx emissions from electric generating units. The CAIR provides for a two-phased reduction program with Phase I reductions in NOx and SO2 emissions in 2009 and 2010, respectively, and Phase II reductions in 2015. In March 2005, the EPA issued a related regulation, the final CAMR, which requires substantial mercury reductions from electric generating units. The CAMR also provides for a two-phased reduction, with the Phase I target in 2010 achieved as a “co-benefit” of the controls installed to meet the CAIR. Additional control measures will be required to meet the Phase II target in 2018. Both the CAIR and CAMR establish a cap and trade framework, in which limits are set on total emissions and allowances can be bought or sold on the open market, to be used for compliance, unless the state chooses another approach. LG&E currently has flue gas desulfurization equipment on all its units but will continue to evaluate improvements to further reduce SO2 emissions.

Kentucky law permits LG&E to recover the costs of complying with the Federal Clean Air Act, including a return of operating expenses, and a return of and on capital invested, through the ECR mechanism once approved by the Kentucky Commission. A majority of the applicable environmental costs, those related to servicing our native load, including investment and operating costs, are recoverable through the ECR. The remaining costs, attributable to off-system sales, are not recoverable through the ECR, however, these costs are recoverable in coordination with a general rate case.

COMPANY STRUCTURE

As contemplated in their regulatory filings in connection with the E.ON acquisition of Powergen in 2002, E.ON, Powergen and E.ON U.S. completed an administrative reorganization to move the LG&E Energy Corp. group from an indirect Powergen subsidiary to an indirect E.ON subsidiary. This reorganization was effective in March 2003. In early 2004, E.ON U.S. began direct reporting arrangements to E.ON.

Effective December 30, 2003, LG&E Energy LLC became the successor, by assignment and subsequent merger, to all the assets and liabilities of LG&E Energy Corp.

Effective December 1, 2005, LG&E Energy LLC was renamed E.ON U.S. LLC.

LG&E has continued its separate identity and the preferred stock and debt securities of LG&E were not affected by these transactions.

RESULTS OF OPERATIONS

Net Income

LG&E’s net income in 2006 decreased $12 million (9%) compared to 2005. The primary drivers of the decrease were lower wholesale and retail electric sales volumes due to cooler summer weather in 2006 and increased interest expense. Partially offsetting the lower revenues were lower operation and maintenance expenses primarily from the expiration of the VDT amortization and lower costs associated with MISO Day 2.

LG&E’s net income related to the electric business in 2006 decreased $12 million (10%) compared to 2005. Electric operating revenues decreased $44 million (4%) primarily due to lower wholesale and retail sales volumes associated with cooler summer weather in 2006 and lower MISO revenues. Partially offsetting the lower revenues were lower operation and maintenance expenses of $20 million (8%) primarily from the expiration of the VDT amortization and lower costs from MISO Day 2. Combined fuel and power purchased expenses in 2006 also declined $15 million (4%) from 2005. Interest expense increased $3 million (10%) in 2006.

LG&E’s net income related to the natural gas business was unchanged from 2005.

LG&E’s net income in 2005 increased $33 million (34%) compared to 2004. The increase resulted primarily from higher electric revenues due to increased retail sales volumes resulting from warmer summer weather and increased base rates implemented for service rendered on and after July 1, 2004. Wholesale revenues also increased due to higher volumes and higher prices. These increases were partially offset by increased fuel and power purchased costs largely due to MISO Day 2 costs.

LG&E’s net income in 2005 related to the electric business increased $32 million (37%) compared to 2004. Electric operating revenues increased $171 million (21%), partially offset by higher fuel for electric generation and power purchased of $123 million (41%). Income tax and depreciation expense increased $12 million (25%) and $6 million (6%), respectively.

LG&E’s net income in 2005 related to the natural gas business increased $1 million (11%) compared to 2004. Natural gas operating revenues increased $80 million (22%) offset by higher natural gas supply expenses of $73 million (27%). Other natural gas operation and maintenance expenses increased $4 million (7%) and depreciation expense increased $1 million (6%).

Revenues

The following table presents a comparison of operating revenues for the years 2006 and 2005 with the immediately preceding year.

Increase (Decrease) From Prior Period

(in millions)	Electric Revenues						Gas Revenues
Cause	2006			2005			2006			2005
Retail sales:
Fuel and gas supply adjustments	$	23		$	23		$	20		$	67
LG&E/KU merger surcredit	3			(1		)	—			—
Environmental cost recovery surcharge	3			10			—			—
Earnings sharing mechanism	—			(6		)	—			—
Weather normalization adjustment	—			—			4			(3		)
Rate changes	—			25			—			5
Variation in sales volumes and other	(18		)	27			(48		)	(1		)
Total retail sales	11			78			(24		)	68
Wholesale sales	(35		)	73			(18		)	12
MISO Day 2	(20		)	18			—			—
Other	—			2			—			—
Total	$	(44	)	$	171		$	(42	)	$	80

Electric revenues in 2006 decreased $44 million (4%) primarily due to:

· Decreased wholesale sales ($35 million) primarily resulting from lower sales volumes due to decreased regional demand

· Decreased MISO related revenue ($20 million) due to exit from the MISO

· Decreased sales volumes and other ($18 million) resulting from a 12% decrease in cooling degree days in 2006 as compared to the same period in 2005 (the number of cooling degree days in 2006 was 9% below the 20-year average)

· Increased fuel costs ($23 million) billed to customers through the FAC

· Increased revenue due to lower merger surcredit given to customers based on lower sales volumes ($3 million)

· Increased ECR surcharge ($3 million) billed to customers

Electric revenues in 2005 increased $171 million (21%) primarily due to:

· Increased wholesale sales ($73 million) primarily due to an 11% higher sales volume due to increased regional demand and a 29% increase in prices caused by higher fuel prices

· Increased retail sales volumes and other ($27 million) primarily due to warmer summer weather resulting from a 13% increase in cooling degree days (the number of cooling degree days in 2005 was 14% above the 20-year average)

· Increased rates ($25 million) implemented in July 2004

· Increased fuel costs ($23 million) billed to customers through the FAC

· Increased MISO related revenue ($18 million) due to the inception of MISO Day 2 on April 1, 2005

· Increased ECR surcharge ($10 million) billed to customers

· Decreased ESM revenues ($6 million) billed to customers due to termination of the ESM program

Natural gas revenues in 2006 decreased $42 million (10%) primarily due to:

· Decreased sales volumes and other ($48 million) resulting from a 9% decrease in heating degree days in 2006 as compared to the same period in 2005 (the number of heating degree days in 2006 was 10% below the 20-year average)

· Decreased wholesale sales ($18 million) due to limited market opportunities to sell natural gas off-system

· Increased natural gas supply costs ($20 million) billed to customers through the GSC

· Increased weather normalization revenue ($4 million)

Natural gas revenues in 2005 increased $80 million (22%) primarily due to:

· Increased natural gas supply costs ($67 million) billed to customers through the GSC

· Increased wholesale sales ($12 million) due to increased market opportunities to sell natural gas off-system

· Increased rates ($5 million) implemented in July 2004

· Decreased weather normalization revenue ($3 million)

Expenses

Fuel for electric generation and natural gas supply expenses comprise a large component of LG&E’s total operating expenses. Increases or decreases in the cost of fuel and natural gas supply are reflected in LG&E’s electric and natural gas retail rates, through the FAC and GSC, subject to the approval of the Kentucky Commission.

Fuel for electric generation increased $12 million (4%) in 2006 primarily due to:

· Increased cost of fuel burned ($15 million) due to higher prices for coal

· Decreased generation ($3 million) due to lower demand

Fuel for electric generation increased $74 million (36%) in 2005 primarily due to:

· Increased cost of fuel burned ($62 million) due to the MISO’s dispatch of natural gas-fired units and higher coal and natural gas prices

· Increased generation ($12 million) due to increased demand and the dispatch of units for MISO Day 2

Power purchased expense decreased $27 million (19%) in 2006 primarily due to:

· Decreased volumes purchased ($35 million) due to lower demand

· Increased unit cost per Mwh of purchases ($9 million) due to higher fuel prices

Power purchased expense increased $49 million (53%) in 2005 primarily due to:

· Increased unit cost per Mwh of purchases ($41 million) due to higher fuel prices

· Increased volumes purchased ($8 million) due to increased demand and unit outages

· Purchased power costs from the MISO due to unit outages totaled $10 million

Gas supply expenses decreased $44 million (13%) in 2006 primarily due to:

· Decreased volumes of natural gas delivered to the distribution system ($64 million) due to milder winter weather

· Increased cost of net gas supply ($20 million) due to higher inventory unit cost

Gas supply expenses increased $73 million (27%) in 2005 primarily due to:

· Increased cost of net gas supply ($62 million) due to the increase in natural gas prices

· Increased volumes of natural gas delivered to the distribution system ($12 million)

Other operation and maintenance expenses decreased $20 million (6%) in 2006 primarily due to decreased other operation expenses ($37 million) partially offset by increased maintenance expenses ($15 million) and property and other taxes ($1 million).

Other operation expenses decreased $37 million (16%) in 2006 primarily due to:

· Decreased administrative and general expense ($21 million) primarily due to the completion of the VDT amortization

· Decreased other power supply costs ($11 million) resulting from lower MISO Day 2 costs

· Decreased electrical transmission costs ($9 million) due to lower MISO related expenses

· Increased steam generation expense ($2 million) primarily for scrubber reactant and waste disposal

· Increased distribution operations costs ($1 million) primarily due to higher storm restoration costs

· Increased underground storage costs ($1 million) due to higher costs of materials and contractor expenses

Maintenance expenses increased $15 million (24%) in 2006 primarily due to:

· Increased steam maintenance ($8 million) primarily related to Mill Creek Unit 4

· Increased distribution maintenance ($5 million) primarily related to vegetation management and storm restoration

· Increased administrative and general maintenance ($2 million)

Other operation and maintenance expenses increased $3 million (1%) in 2005 primarily due to higher other operation expenses ($11 million) and higher property taxes ($2 million), partially offset by lower maintenance expenses ($9 million).

Other operation expenses increased $11 million (5%) in 2005 primarily due to:

· Increased other power supply costs ($17 million) due largely to MISO Day 2 costs ($18 million) for administrative and allocated charges from the MISO for Day 2 operations

· Increased steam generation expense ($4 million) primarily for scrubber reactant and waste disposal

· Increased employee benefit costs ($3 million)

· Increased customer service and collection expenses ($2 million)

· Decreased transmission costs ($11 million), due largely to MISO Day 2 ($13 million). Prior to the MISO Day 2 market, most bilateral transactions required the purchase of transmission; however, with the Day 2 market, most transactions are handled directly with the MISO and no additional transmission is necessary

· Decreased distribution operating costs ($5 million) due to fewer storms

Maintenance expenses decreased $9 million (13%) in 2005 primarily due to:

· Decreased distribution maintenance ($9 million) due to fewer storms

· Decreased steam generation expense ($2 million)

· Increased administrative and general maintenance ($1 million)

Other expense (income) — net decreased $4 million in 2006 primarily due to:

· Decreased other income ($2 million)

· Increased other expense ($2 million)

Other expense (income) expense - net increased $4 million in 2005 primarily due to:

· Increased other income ($2 million)

· Decreased other expense ($1 million)

Interest expense, including interest expense to affiliated companies, increased $4 million (11%) in 2006 primarily due to:

· Increased interest rates on variable rate debt ($5 million)

· Increased interest on tax deficiencies ($2 million)

· Decreased interest expense on swaps ($2 million)

Interest expense, including interest expense to affiliated companies, increased $4 million (12%) in 2005 primarily due to:

· Increased interest rates on variable rate debt ($6 million)

· Increased borrowing from the money pool ($2 million)

· Decreased cost of interest rate swaps ($3 million)

· Decreased costs due to refinancing fixed rate debt with variable rate debt ($1 million)

Details of exposure to variable interest rates on long-term debt are shown in the table below:

	2006			2005			2004
Debt exposed to interest rate risk (in millions)	$	363		$	363		$	306
Debt exposed to interest rate risk as a percentage of long-term debt	44.3		%	44.2		%	35.1		%
Weighted average interest rate on variable rate debt for the year	3.47		%	2.49		%	1.28		%
Weighted average interest rate on total long-term debt at year-end, including expense amortization and interest rate swaps	4.33		%	4.13		%	3.92		%

See Note 7 of Notes to Financial Statements under Item 8.

Variations in income tax expenses are largely attributable to changes in pre-tax income. See Note 6 of Notes to Financial Statements under Item 8.

The rate of inflation may have a significant impact on LG&E’s operations, its ability to control costs and the need to seek timely and adequate rate adjustments. However, relatively low rates of inflation in the past few years have moderated the impact on current operating results.

CRITICAL ACCOUNTING POLICIES/ESTIMATES

Preparation of financial statements and related disclosures in compliance with generally accepted accounting principles requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including legal and regulatory challenges and anticipated recovery of costs. These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment also may have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies applied has not changed. Specific risks for these critical accounting policies are described in the following paragraphs. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Events rarely develop exactly as forecasted and the best

estimates routinely require adjustment. See also Note 1 of Notes to Financial Statements under Item 8.

Unbilled Revenue. At each month-end LG&E prepares a financial estimate that projects electric and natural gas usage by customers that has not been billed. The estimated usage is based on allocating the daily system net deliveries between billed volumes and unbilled volumes. The allocation is based on a daily ratio of the number of meter reading cycles remaining in the month to the total number of meter reading cycles in each month. Each day’s ratio is then multiplied by each day’s system net deliveries to determine an estimated billed and unbilled volume for each day of the accounting period. At December 31, 2006, a 10% change in these estimated quantities would cause revenue and accounts receivable to change by approximately $5 million ($3 million for electric usage and $2 million for natural gas usage). See also Note 1 of Notes to Financial Statements under Item 8.

Allowance for Doubtful Accounts. At December 31, 2006 and 2005, the LG&E allowance for doubtful accounts was $2 million and $1 million, respectively. The allowance is based on the ratio of the amounts charged-off during the last twelve months to the retail revenues billed over the same period multiplied by the retail revenues billed over the last four months. Accounts with no payment activity are charged-off after four months, although collection efforts continue thereafter.

Pension and Postretirement Benefits. LG&E has both funded and unfunded non-contributory defined benefit pension and postretirement benefit plans that together cover substantially all of its employees. The plans are accounted for under SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, which amended SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other than Pensions and SFAS No. 87, Employers’ Accounting for Pensions.

The pension and other postretirement benefit plan costs and liabilities are determined on an actuarial basis and are dependent upon numerous economic assumptions, such as discount rates, rates of compensation increases, estimates of the expected return on plan assets and health care cost trend rates and demographic and economic assumptions. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower health care costs or turnover or longer or shorter life spans of participants. These differences may result in a significant impact on the amount of expenses recorded in future periods. The underlying assumptions and estimates related to the pension and postretirement benefit plan costs and liabilities are reviewed annually.

The assumed discount rate, expected return on assets and rate of compensation increases generally have the most significant impact on the pension costs and liabilities. The discount rate is used to calculate the actuarial present value of the benefits provided by the plans. LG&E bases its discount rate assumption on the November Mercer Pension Discount Yield Curve, adjusted by the basis point change in the Moody’s Investors Services, Inc. Aa Corporate Bond Rate in December. The Mercer Pension Discount Yield Curve provides a more refined estimate of the discount by matching the plan’s specific cash flow to a spot-rate yield curve based on high-quality, fixed-income investments.

The expected long-term rate of return on assets is used to calculate the net periodic pension costs for the plans. To develop the expected long-term rate of return on assets assumption, consideration is given to the current level of expected returns on risk free investments (primarily government bonds), the historical performance of the asset managers versus their respective benchmarks, the historical level of the risk premium associated with the other asset classes in which the portfolio is invested and the expectations for future returns of each asset class. The expected return for each asset class is then weighted based on a target asset allocation. For 2006, the actual return

on pension assets was favorable compared to the assumed expected rate of return.

The following describes the effects on pension benefits by changing the major actuarial assumptions discussed above:

· A 1% change in the assumed discount rate could have an approximate $47 million positive or negative impact to the 2006 accumulated benefit obligation and an approximate $51 million positive or negative impact to the 2006 projected benefit obligation.

· A 25 basis point change in the expected rate of return on assets would have an approximate $1 million positive or negative impact on 2006 pension expense.

Compensation rate increases are used to calculate service costs and the projected benefit obligation. Such rates are based on a review of LG&E’s historical salaries, promotion and bonus increases. For 2006 net periodic pension benefit costs, LG&E used an assumption of 5.25%.

The assumptions related to the discount rate, retirement, turnover and healthcare cost trends, which represent expected rates of increase in health care claim payments, generally have the most significant impact on postretirement benefit plan costs and liabilities. Unlike pensions, however, assumptions about per capita claims cost by age and participation rates also significantly impact postretirement liability computations. A 1% change in the healthcare cost trend rates could have a positive or negative impact on the 2006 postretirement benefit obligation and postretirement expense of approximately $3 million and less than $1 million, respectively.

Additionally, demographic and other economic assumptions affect the pension and postretirement computations. Beginning with the December 31, 2005 liability, LG&E replaced the 1983 Group Annuity Mortality tables for males and females with the RP 2000 combined tables for males and females projected to 2006. These updated mortality tables were used for the 2006 calculation and will be used in subsequent periods.

The benefit obligation is compared with the plan asset values to determine a net position. Asset values are increased primarily by actual rates of return on plan assets and by employer contributions. For an explanation of the investment policy including targeted asset allocations, see Note 5 of Notes to Financial Statements under Item 8.

The pension plans are funded in accordance with all applicable requirements of the Employee Retirement Income Security Act of 1974 and the IRC. In accordance with these guidelines, LG&E made discretionary contributions to the pension plans of $18 million in 2006 and $35 million in 2004. No contributions were made in 2005. LG&E anticipates making additional contributions as deemed necessary. Additionally, LG&E made contributions of approximately $11 million, $10 million and $9 million to the postretirement plans in 2006, 2005 and 2004, respectively. LG&E may continue to make subsequent contributions in accordance with the maximum funding limitation governed by tax laws. In January 2007, LG&E made a discretionary contribution to the pension plan in the amount of $56 million, which was slightly more than the $52 million accrued benefit liability as of December 31, 2006. In 2007, LG&E anticipates making voluntary contributions to fund the Voluntary Employee Beneficiary Association (VEBA) trusts to match the annual postretirement expense and funding the 401(h) plan up to the maximum amount allowed by law. See Note 15 of Notes to Financial Statements under Item 8.

As prescribed by SFAS No. 87, LG&E was required to recognize an additional minimum pension liability of $19 million during 2005 since the fair value of the plan assets was less than the accumulated benefit obligation at that time. This additional minimum pension liability was recorded as a reduction to other comprehensive income and

did not affect net income. Historically low corporate bond rates, used to determine the discount rate, significantly increased the potential value of the pension liabilities above the actual value of the plan assets. These provisions of SFAS No. 87 were not applicable to 2006 due to the implementation of SFAS No. 158.

Should poor market conditions return or should interest rates decline, LG&E’s unfunded accumulated benefit obligations and future pension expense could increase. The Company believes that such increases are recoverable in whole or in part under future rate proceedings or mechanisms.

See also Notes 5 and 13 of Notes to Financial Statements under Item 8.

Regulatory Mechanisms. Judgments and uncertainties include future regulatory decisions, the impact of deregulation and competition on the ratemaking process and external regulatory decisions. Regulatory assets generally represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections. Management believes, based on Kentucky Commission Orders and historical precedents, the existing regulatory assets and liabilities are probable of recovery. This determination reflects the current regulatory climate in the state. If future recovery of costs ceases to be probable, the assets and liabilities would be required to be recognized in current period earnings. See also Note 2 of Notes to Financial Statements under Item 8.

Income Taxes. Income taxes are accounted for under SFAS No. 109, Accounting for Income Taxes. In accordance with this statement, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, as measured by enacted tax rates that are expected to be in effect in the periods when the deferred tax assets and liabilities are expected to be settled or realized. Significant judgment is required in determining the provision for income taxes, and there are transactions for which the ultimate tax outcome is uncertain.

To provide for these uncertainties or exposures, an allowance is maintained for tax contingencies based on management’s best estimate of probable loss. Tax contingencies are analyzed periodically and adjustments are made when events occur to warrant a change. In September 2005, LG&E received notice from the Congressional Joint Committee on Taxation approving the Internal Revenue Service’s audit of LG&E’s income tax returns for the periods December 1999 through December 2003. As a result of resolving numerous tax matters during these periods, LG&E reduced income tax accruals by $4 million during 2005.

H. R. 4520, known as the “American Jobs Creation Act of 2004” allows electric utilities to take a deduction of up to 3% of their qualified production activities income starting in 2005. This deduction reduced LG&E’s effective tax rate by less than 1% for 2006.

Kentucky House Bill 272, also known as “Kentucky’s Tax Modernization Plan,” was signed into law in March 2005. This bill contains a number of changes in Kentucky’s tax system, including the reduction of the Corporate income tax rate from 8.25% to 7% effective January 1, 2005, and a further reduction to 6% effective January 1, 2007. As a result of the income tax rate change, LG&E’s deferred tax reserve amount will exceed its actual deferred tax liability attributable to existing temporary differences since the new statutory rates are lower than the rates were when the deferred tax liability originated. This excess amount is referred to as excess deferred income taxes. In June 2005 and December 2006, LG&E received approval from the Kentucky Commission to establish and amortize a regulatory liability ($16 million) for its net excess deferred income tax balances.

Under this accounting treatment, LG&E will amortize its depreciation-related excess deferred income tax balances under the average rate assumption method. The average rate assumption method matches the amortization of the excess deferred income taxes with the life of the timing differences to which it relates. Excess deferred income tax balances related to non-depreciation timing differences were expensed in 2005 and 2006.

LG&E expects to have adequate levels of taxable income to realize its recorded deferred taxes.

For further discussion of income tax issues, see Notes 1 and 6 of Notes to Financial Statements under Item 8.

RECENT ACCOUNTING PRONOUNCEMENTS

The following are recent accounting pronouncements affecting LG&E:

FIN 48

In July 2006, the FASB issued FIN 48, Accounting for Uncertainty in Income Taxes, an Interpretation of SFAS No. 109. FIN 48 clarifies the accounting for the uncertainty of income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109. This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.

The evaluation of a tax position in accordance with FIN 48 is a two-step process. The first step is recognition based on the determination of whether it is “more likely than not” that a tax position will be sustained upon examination. The second step is to measure a tax position that meets the “more likely than not” threshold. The tax position will be measured as the amount of potential benefit that exceeds 50% likelihood of being realized.

FIN 48 is effective for fiscal years beginning after December 15, 2006. FIN 48 was adopted effective January 1, 2007. The impact of FIN 48 on the statements of operations, financial position and cash flows is not expected to be material.

SFAS No. 157

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. LG&E is now analyzing the future impacts of SFAS No. 157 on results of operations and financial condition.

SFAS No. 158

In September 2006, the FASB issued SFAS No. 158, which is effective for fiscal years ending after December 15, 2006 for employers with publicly traded equity securities and for employers controlled by entities with publicly traded equity securities, which is applicable for LG&E. This statement requires employers to recognize the over-funded or under-funded status of a defined benefit pension and postretirement plan as an asset or a liability in the balance sheet and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. This statement also requires employers to measure the funded status of a plan as of the date of its year-end balance sheet. This statement amended SFAS No. 87, SFAS No. 88, Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination

Benefits, SFAS No. 106 and SFAS No. 132, Employers’ Disclosures about Pensions and Other Postretirement Benefits.

SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, provides guidance to regulated utilities for deferring costs that would otherwise be charged to expense or equity by non-regulated enterprises. In applying the provisions of this statement to the requirements of SFAS No. 158, LG&E recorded a regulatory asset representing the adjustment to the pension liability in recognizing the funded status of the pension liability. This adjustment would have been represented in Accumulated Other Comprehensive Income without the application of SFAS No. 71.

LG&E has adopted SFAS No. 158 effective for the fiscal year ending December 31, 2006. The incremental effects of applying SFAS No. 158 are shown in the following table:

(in millions)	Before Adoption of SFAS No. 158*			Adjustments			After Adoption of SFAS No. 158
Accrued pension and postretirement liability-noncurrent	$	(102	)	$	(47	)	$	(149	)
Accrued pension and postretirement liability-current	—			(2		)	(2		)
Pension and postretirement regulatory asset	77			49			126

*Balances before the application of SFAS No. 158 include the effects of 2006 plan experience and changes in actuarial assumptions on the additional minimum liability, coupled with the regulatory impacts of SFAS No. 71.

LIQUIDITY AND CAPITAL RESOURCES

LG&E uses net cash generated from its operations and external financing (including financing from affiliates) to fund construction of plant and equipment and the payment of dividends. LG&E believes that such sources of funds will be sufficient to meet the needs of its business in the foreseeable future.

As of December 31, 2006, LG&E is in a negative working capital position in part because of the classification of certain variable-rate pollution control bonds totaling $246 million that are subject to tender for purchase at the option of the holder as current portion of long-term debt. Backup credit facilities totaling $185 million are in place to fund such tenders, if necessary. LG&E has never needed to access these facilities. LG&E expects to cover any working capital deficiencies with cash flow from operations, money pool borrowings and borrowings from Fidelia.

Operating Activities

Cash provided by operations was $320 million, $150 million and $171 million in 2006, 2005 and 2004, respectively.

The 2006 increase of $170 million was primarily the result of increases in cash due to changes in:

· Accounts receivable ($183 million) primarily from decreased natural gas prices and milder December weather

· Materials and supplies ($107 million) primarily resulting from decreased natural gas prices

· Property and other taxes payable ($21 million)

· GSC recovery ($20 million)

These increases were partially offset by cash used for changes in:

· Accounts payable ($102 million) due to lower natural gas prices

· Earnings, net of non-cash items ($22 million)

· Pension and postretirement funding ($19 million)

· Payment of the fee required to exit the MISO ($13 million)

· ECR recovery ($7 million)

The 2005 decrease of $21 million was primarily the result of decreases in cash due to changes in:

· Materials and supplies ($61 million) largely the result of increased coal and natural gas prices

· Accounts receivable ($17 million) primarily due to colder December weather

· Gas supply recovery ($13 million) primarily due to higher natural gas prices

· ESM recovery ($8 million) due to termination of the ESM program

· Property and other taxes payable ($7 million)

These decreases were partially offset by cash provided by changes in:

· Accounts payable ($49 million) primarily from the increase in natural gas prices

· Pension and postretirement funding ($34 million)

Investing Activities

LG&E’s primary use of funds for investing activities continues to be for capital expenditures. Capital expenditures were $146 million, $139 million and $148 million in 2006, 2005 and 2004, respectively. LG&E expects its capital expenditures for the three-year period ending December 31, 2009, to total approximately $665 million, which consists primarily of construction estimates associated with the construction of TC2 totaling approximately $150 million (including $40 million for environmental controls), other environmental control equipment of approximately $80 million, redevelopment of the Ohio Falls hydro facility totaling approximately $30 million and on-going construction related to generation and distribution assets.

Net cash used for investing activities in 2006 increased $9 million in 2006 compared to 2005 and decreased $21 million in 2005 compared to 2004, primarily due to the level of construction expenditures.

Financing Activities

Net cash outflows for financing activities were $173 million, $12 million and $7 million in 2006, 2005 and 2004, respectively.

Redemptions and maturities of long-term debt for 2006, 2005 and 2004 are summarized below:

($ in millions)		Principal			Secured/
Year	Description	Amount	Rate		Unsecured	Maturity
2006	Mandatorily Redeemable Preferred Stock	$ 1	5.875	%	Unsecured	Jul	2006
2005	Pollution control bonds	$ 40	5.90	%	Secured	Apr	2023
2005	Due to Fidelia	$ 50	1.53	%	Secured	Jan	2005
2005	Mandatorily Redeemable Preferred Stock	$ 1	5.875	%	Unsecured	Jul	2005
2004	Due to Fidelia	$ 50	1.53	%	Secured	Jan	2005
2004	Mandatorily Redeemable Preferred Stock	$ 1	5.875	%	Unsecured	Jul	2004

LG&E did not issue any long-term debt in 2006. Issuances of long-term debt for 2005 and 2004 are summarized below:

($ in millions)

Principal

Secured/

Year

Description

Amount

Rate

Unsecured

Maturity

2005

Pollution control bonds

Variable

Secured

Feb 2035

2004

Due to Fidelia

4.33%

Secured

Jan 2012

2004

Due to Fidelia

100

1.53%

Secured

Jan 2005

See also Notes 7 and 15 of Notes to Financial Statements under Item 8.

Future Capital Requirements

Future capital requirements may be affected in varying degrees by factors such as electric energy demand load growth, changes in construction expenditure levels, rate actions by regulatory agencies, new legislation, market entry of competing electric power generators, changes in commodity prices and labor rates, changes in environmental regulations and other regulatory requirements. See Note 9 of Notes to Financial Statements under Item 8 for current commitments. LG&E anticipates funding future capital requirements through operating cash flow, debt and/or infusions of capital from its parent.

LG&E has a variety of funding alternatives available to meet its capital requirements. LG&E maintains a series of bilateral credit facilities with banks totaling $185 million. Several intercompany financing arrangements are also available. LG&E participates in an intercompany money pool agreement wherein E.ON U.S. and/or KU make funds of up to $400 million available to LG&E at market-based rates. Fidelia also provides long-term intercompany funding to LG&E. See Note 8 of Notes to Financial Statements under Item 8.

Regulatory approvals are required for LG&E to incur additional debt. The FERC authorizes the issuance of short-term debt while the Kentucky Commission authorizes issuance of long-term debt. In February 2006, LG&E received a two-year authorization from the FERC to borrow up to $400 million in short-term funds.

LG&E’s debt ratings from Moody’s Investor Services, Inc. (“Moody’s”) and Standard and Poor’s Rating Services (“S&P”) as of December 31, 2006, were:

	Moody’s	S&P
First mortgage bonds	A1	A-
Preferred stock	Baa1	BBB-
Issuer rating	A2	—
Corporate credit rating	—	BBB+

These ratings reflect the views of Moody’s and S&P. A security rating is not a recommendation to buy, sell or hold securities and is subject to revision or withdrawal at any time by the rating agency.

Contractual Obligations

The following is provided to summarize contractual cash obligations for periods after December 31, 2006. LG&E anticipates cash from operations and external financing will be sufficient to fund future obligations. Future interest obligations cannot be quantified because most of LG&E’s debt is variable rate. (See Statements of Capitalization)

(in millions)	Payments Due by Period

Contractual Cash Obligations	2007			2008			2009			2010			2011			Thereafter				Total
Short-term debt (a)		$	68		$	—		$	—		$	—		$	—		$	—			$	68
Long-term debt		1			19			—			—			—			800		(b)		820
Operating leases (c)		2			2			2			2			2			8				18
Unconditional power purchase obligations (d)		11			13			16			17			17			328				402
Coal and gas purchase obligations (e)		266			249			202			207			200			3				1,127
Retirement obligations (f)		36			37			36			35			34			168				346
Other obligations (g)		89			70			20			1			—			—				180
Total contractual cash obligations		$	473		$	390		$	276		$	262		$	253		$	1,307			$	2,961

(a) Represents borrowings from affiliated company due within one year.

(b) Includes long-term debt of $246 million classified as current liabilities because these 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. Maturity dates for these bonds range from 2013 to 2027. LG&E does not expect to pay these amounts in 2007.

(d) Represents future minimum payments under OVEC power purchase agreements through 2024.

(e) Represents contracts to purchase coal and natural gas.

(f) Represents currently projected cash flows for pension plans and other post-employment benefits as calculated by the actuary.

(g) Represents construction commitments, including commitments for TC2.

Off-Balance Sheet Arrangements

In the ordinary course of business LG&E has operating leases for various vehicles, equipment and real estate. See Note 9 of Notes to Financial Statements under Item 8 for further discussion of leases.

Sale and Leaseback Transaction

LG&E is a participant in a sale and leaseback transaction involving its 38% interest in two jointly-owned combustion turbines at KU’s E.W. Brown generating station (Units 6 and 7). Commencing in December 1999, LG&E and KU entered into a tax-efficient, 18-year lease of the combustion turbines. LG&E and KU have provided funds to fully defease the lease, and have executed an irrevocable notice to exercise an early purchase option contained in the lease after 15.5 years. The financial statement treatment of this transaction is no different than if LG&E had retained its ownership. The leasing transaction was entered into following receipt of required state and federal regulatory approvals.

currently exist with respect to the lease. Upon any termination of the lease, whether by default or expiration of its term, title to the combustion turbines reverts jointly to LG&E and KU.

At December 31, 2006, the maximum aggregate amount of default fees or amounts was $9 million, of which LG&E would be responsible for 38% (approximately $3 million). LG&E has made arrangements with E.ON U.S., via guarantee and regulatory commitment, for E.ON U.S. to pay LG&E’s full portion of any default fees or amounts.

Potential Preferred Stock Transaction

In October 2006, LG&E submitted an application to the Kentucky Commission seeking authorization for various potential financial transactions, including a request for approval of certain funding arrangements which could provide a source of funds for the possible redemption of LG&E’s three existing series of preferred stock having an aggregate book value of approximately $90 million. In January 2007, the Kentucky Commission issued an Order granting approval of LG&E’s application and in March 2007, a committee of LG&E’s board authorized the redemption of the preferred stock, effective in April 2007. See also Note 15 of Notes to Financial Statements under Item 8.

MARKET RISKS

LG&E is exposed to market risks from changes in interest rates and commodity prices. To mitigate changes in cash flows attributable to these exposures, LG&E uses various financial instruments including derivatives. Derivative positions are monitored using techniques that include market value and sensitivity analysis. See Notes 1 and 3 of Notes to Financial Statements under Item 8.

Interest Rate Sensitivity

LG&E has short-term and long-term variable-rate debt obligations outstanding. At December 31, 2006, the potential change in interest expense associated with a 1% change in base interest rates of LG&E’s unhedged debt is estimated at $4 million.

As of December 31, 2006, LG&E had swaps with an aggregate notional value of $211 million. The swaps exchange floating-rate interest payments for fixed rate interest payments to reduce the impact of interest rate changes on LG&E’s pollution control bonds. The potential loss in fair value resulting from a hypothetical 1% adverse movement in base interest rates is estimated at approximately $21 million as of December 31, 2006. This estimate is derived from third-party valuations. Changes in the market value of these swaps if held to maturity, as LG&E intends to do, will have no effect on LG&E’s net income or cash flow. See Note 3 of Notes to Financial Statements under Item 8.

Commodity and Other Price Sensitivities

LG&E is exposed to the market price volatility of coal, natural gas and oil (the fuels used to generate electricity) in its wholesale activities. It has limited exposure to such market price volatility as the result of its retail FAC and GSC commodity price pass-through mechanisms. LG&E can also be exposed to the market price volatility

of other significant input commodities, including but not limited to costs of steel, copper and specialized equipment or machinery used in the industry, as well as labor rates, in elements of its capital construction or operating and maintenance activities. In some cases, elements of these risks are mitigated via periodic rate or other regulatory recovery mechanisms or via the terms of applicable contractual arrangements.

Energy & Risk Management Activities

LG&E 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 hedge price risk and are accounted for on a mark-to-market basis in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Prior to the MISO establishing its Day 2 energy market in April 2005, wholesale forward transactions were primarily physically settled and thus were treated as normal sales under SFAS No. 133, as amended, and were not marked to market.

The table below summarizes LG&E’s energy trading and risk management activities for 2006 and 2005:

(in millions)	2006				2005
Fair value of contracts at beginning of period, net asset		$	1			$	—
Fair value of contracts when entered into during the period		3				1
Contracts realized or otherwise settled during the period		(6		)		—
Changes in fair values due to changes in assumptions		3				—
Fair value of contracts at end of period, net asset		$	1			$	1

The fair value of LG&E’s energy trading and risk management contracts as of December 31, 2006 and 2005, was less than $1 million. No changes to valuation techniques for energy trading and risk management activities occurred during 2006 or 2005. Changes in market pricing, interest rate and volatility assumptions were made during both years. The outstanding mark-to-market value is sensitive to changes in prices, price volatilities and interest rates. The Company estimates that a movement in prices of $1 and a change in interest and volatilities of 1% would result in a change of less than $1 million. All contracts outstanding at December 31, 2006 and 2005 have a maturity of less than one year and are valued using prices actively quoted for proposed or executed transactions or quoted by brokers.

LG&E maintains policies intended to minimize credit risk and revalues credit exposures daily to monitor compliance with those policies. At December 31, 2006, 100% of the trading and risk management commitments were with counterparties rated BBB-/Baa3 equivalent or better.

RATES AND REGULATION

LG&E is subject to the jurisdiction of the Kentucky Commission in virtually all matters related to electric and natural gas utility regulation, and as such, its accounting is subject to SFAS No. 71. Given LG&E’s competitive position in the marketplace and the status of regulation in Kentucky, LG&E has no plans or intentions to discontinue its application of SFAS No. 71. See Notes 2 and 9 of Notes to Financial Statements under Item 8 for a discussion of rates and regulation.

FUTURE OUTLOOK

Competition and Customer Choice

ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk.

See Management’s Discussion and Analysis of Financial Condition and Results of Operations, Market Risks, under Item 7.

ITEM 8. Financial Statements and Supplementary Data.

Louisville Gas and Electric Company
Statements of Income
(Millions of $)

	Years Ended December 31
	2006		2005			2004
OPERATING REVENUES:
Electric (Note 12)	$	943	$	987		$	816
Gas	395		437			357
Total operating revenues	1,338		1,424			1,173

OPERATING EXPENSES:
Fuel for electric generation	294		282			208
Power purchased (Notes 9 and 12)	114		141			92
Gas supply expenses	295		339			266
Other operation and maintenance expenses	288		308			305
Depreciation and amortization (Note 1)	124		124			117
Total operating expenses	1,115		1,194			988

Net operating income	223		230			185

Other expense (income) - net	3		(1		)	3
Interest expense (Notes 7 and 8)	28		24			21
Interest expense to affiliated companies (Note 12)	13		13			12

Income before income taxes	179		194			149

Federal and state income taxes (Note 6)	62		65			53

Net income	$	117	$	129		$	96

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

Statements of Retained Earnings
(Millions of $)

	Years Ended December 31
	2006		2005		2004

Balance January 1	$	621	$	534	$	497
Add net income	117		129		96
	738		663		593
Deduct: Cash dividends declared on stock:
5% cumulative preferred	1		1		1
Auction rate cumulative preferred	3		2		1
Common	95		39		57
	99		42		59

Balance December 31	$	639	$	621	$	534

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

Louisville Gas and Electric Company
Statements of Comprehensive Income
(Millions of $)

	Years Ended December 31
	2006			2005				2004
Net income		$	117		$	129			$	96

Gain (loss) on derivative instruments and hedging activities, net of tax benefit (expense) of $(1), $0 and $1 for 2006, 2005 and 2004, respectively (Notes 1 and 3)		2			—				(2		)

Additional minimum pension liability adjustment, net of tax benefit (expense) of $(30), $6 and $4 for 2006, 2005 and 2004, respectively (Note 5)		47			(13		)		(6		)

Other comprehensive income (loss), net of tax (Note 13)		49			(13		)		(8		)

Comprehensive income		$	166		$	116			$	88

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

Louisville Gas and Electric Company
Balance Sheets
(Millions of $)

	December 31
	2006		2005
ASSETS:
Current assets:
Cash and cash equivalents (Note 1)	$	7	$	7
Accounts receivable - less reserve of $2 million in 2006 and $1 million in 2005 (Note 1)	165		231
Accounts receivable from affiliated companies (Note 12)	19		36
Materials and supplies (Note 1):
Fuel (predominantly coal)	38		39
Gas stored underground	83		125
Other materials and supplies	30		28
Prepayments and other current assets	6		6
Total current assets	348		472

Utility plant, at original cost (Note 1):
Electric	3,200		3,180
Gas	526		511
Common	180		199
Total utility plant, at original cost	3,906		3,890

Less: reserve for depreciation	1,534		1,509
Total utility plant, net	2,372		2,381

Construction work in progress	217		159
Total utility plant and construction work in progress	2,589		2,540

Deferred debits and other assets:
Restricted cash (Note 1)	16		10
Regulatory assets (Notes 1 and 2):
Pension and postretirement benefits	126		—
Other	93		84
Intangible pension asset	—		31
Other assets	12		9
Total deferred debits and other assets	247		134

Total Assets	$	3,184	$	3,146

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

Louisville Gas and Electric Company
Balance Sheets (continued)
(Millions of $)

	December 31
	2006			2005
LIABILITIES AND EQUITY:
Current liabilities:
Current portion of long term debt (Note 7)	$	248		$	248
Notes payable to affiliated companies (Notes 8 and 12)	68			141
Accounts payable	103			141
Accounts payable to affiliated companies (Note 12)	55			56
Customer deposits	18			17
Other current liabilities	40			17
Total current liabilities	532			620

Long-term debt:
Long-term bonds (Note 7)	328			328
Long-term notes to affiliated company (Note 7)	225			225
Mandatorily redeemable preferred stock (Note 7)	19			20
Total long-term debt	572			573
Deferred credits and other liabilities:
Accumulated deferred income taxes (Note 6)	333			322
Accumulated provision for pensions and related benefits (Note 5)	149			143
Investment tax credit, in process of amortization	41			42
Asset retirement obligations	28			27
Regulatory liabilities (Note 2):
Accumulated cost of removal of utility plant	232			219
Regulatory liability deferred income taxes	54			42
Other regulatory liabilities	35			20
Other liabilities	44			41
Total deferred credits and other liabilities	916			856

Commitments and contingencies (Note 9)

Cumulative preferred stock	70			70

COMMON EQUITY:
Common stock, without par value - Authorized 75,000,000 shares, outstanding 21,294,223 shares	424			424
Additional paid-in capital	40			40
Accumulated other comprehensive income (Note 13)	(9		)	(58		)
Retained earnings	639			621
Total common equity	1,094			1,027

Total Liabilities and Equity	$	3,184		$	3,146

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

Louisville Gas and Electric Company

Statements of Cash Flows

(Millions of $)

	Years Ended December 31
	2006			2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	117		$	129		$	96
Items not requiring cash currently:
Depreciation and amortization	124			119			117
Deferred income taxes - net	22			(14		)	5
Investment tax credit - net	(1		)	(4		)	(4		)
VDT amortization	8			30			30
Provision for pension and postretirement plans	(13		)	14			25
Other	3			8			1
Change in certain current assets and liabilities:
Accounts receivable	83			(100		)	(83		)
Materials and supplies	41			(66		)	(5		)
Accounts payable	(47		)	55			6
Accrued income taxes	8			—			(5		)
Property and other taxes payable	14			(7		)	—
Prepayments and other	2			4			7
Pension and postretirement funding	(29		)	(10		)	(44		)
Gas supply clause receivable, net	17			(3		)	10
Litigation settlement	—			—			7
Earnings sharing mechanism receivable	—			2			10
MISO exit fee	(13		)	—			—
Environmental cost recovery mechanism receivable	(7		)	—			—
Other	(9		)	(7		)	(2		)
Net cash provided by operating activities	320			150			171

CASH FLOWS FROM INVESTING ACTIVITIES:
Construction expenditures	(146		)	(139		)	(148		)
Change in restricted cash	(1		)	1			(11		)
Net cash used for investing activities	(147		)	(138		)	(159		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Long-term borrowings from affiliated company	—			—			125
Repayment of long-term borrowings from affiliated company	—			(50		)	(50		)
Short-term borrowings from affiliated company	700			789			553
Repayment of short-term borrowings from affiliated company	(773		)	(706		)	(575		)
Issuance of pollution control bonds	—			40			—
Issuance expense on pollution control bonds	—			(2		)	—
Retirement of pollution control bonds	—			(40		)	—
Retirement of mandatorily redeemable preferred stock	(1		)	(1		)	(1		)
Payment of dividends	(99		)	(42		)	(59		)
Net cash used for financing activities	(173		)	(12		)	(7		)
Change in cash and cash equivalents	—			—			5
Cash and cash equivalents at beginning of year	7			7			2
Cash and cash equivalents at end of year	$	7		$	7		$	7

Supplemental disclosures of cash flow information:
Cash paid during the year for:
Income taxes	$	64		$	83		$	52
Interest on borrowed money	24			21			18
Interest to affiliated companies on borrowed money	11			13			11

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

Louisville Gas and Electric Company

Statements of Capitalization

(Millions of $)

	December 31
	2006		2005
LONG-TERM DEBT (Note 7):
Pollution control series:
S due September 1, 2017, variable %	$	31	$	31
T due September 1, 2017, variable %	60		60
U due August 15, 2013, variable %	35		35
Y due May 1, 2027, variable %	25		25
Z due August 1, 2030, variable %	83		83
AA due September 1, 2027, variable %	10		10
BB due September 1, 2026, variable %	23		23
CC due September 1, 2026, variable %	28		28
DD due November 1, 2027, variable %	35		35
EE due November 1, 2027, variable %	35		35
FF due October 1, 2032, variable %	42		42
GG due October 1, 2033, variable %	128		128
HH due February 1, 2035, variable %	40		40
Notes payable to Fidelia:
Due January 16, 2012, 4.33%, secured	25		25
Due April 30, 2013, 4.55%, unsecured	100		100
Due August 15, 2013, 5.31%, secured	100		100
Mandatorily redeemable preferred stock:
$5.875 series, outstanding shares of 200,000 in 2006 and 212,500 in 2005	20		21
Total long-term debt outstanding	820		821
Less current portion of long-term debt	248		248
Long-term debt	572		573

CUMULATIVE PREFERRED STOCK:
	Shares	Current
	Outstanding	Redemption Price
$25 par value, 1,720,000 shares authorized - 5% series	860,287	$28.00	21	21
Without par value, 6,750,000 shares authorized - Auction rate	500,000	$100.00	49	49
			70	70

COMMON EQUITY:
Common stock, without par value -
Authorized 75,000,000 shares, outstanding 21,294,223 shares	424			424
Additional paid-in capital	40			40
Accumulated other comprehensive income (Note 13)	(9		)	(58		)
Retained earnings	639			621
Total common equity	1,094			1,027

Total capitalization	$	1,736		$	1,670

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

Regulatory Assets and Liabilities

The following regulatory assets and liabilities were included in LG&E’s Balance Sheets as of December 31:

(in millions)	2006		2005
ARO	$	22	$	20
Gas supply adjustments	21		25
Unamortized loss on bonds	20		21
MISO exit	13		—
ECR	9		2
Merger surcredit	2		3
VDT costs	—		8
Other	6		5
Subtotal	93		84

Pension and postretirement benefits	126		—

Total regulatory assets	$	219	$	84

Accumulated cost of removal of utility plant	$	232	$	219
Deferred income taxes - net	54		42
Gas supply adjustments	31		18
Other	4		2
Total regulatory liabilities	$	321	$	281

LG&E does not currently earn a rate of return on the gas supply adjustments, FAC (included in other regulatory assets) and gas performance-based ratemaking regulatory assets, all of which are separate recovery mechanisms with recovery within twelve months. No return is earned on the pension and postretirement benefits regulatory asset which represents the changes in funded status of the plans that the Company will seek recovery of in future proceedings with the Kentucky Commission. No return is currently earned on the ARO asset. This regulatory asset will be offset against the associated regulatory liability, ARO asset and ARO liability at the time the underlying asset is retired. The MISO exit amount represents the costs relating to the withdrawal from MISO membership. LG&E expects to seek recovery of this asset in future proceedings with the Kentucky Commission. LG&E currently earns a rate of return on the remaining regulatory assets. Other regulatory liabilities include DSM and MISO Schedule 10. See Note 1, Summary of Significant Accounting Policies.

Pension and Postretirement Benefits. LG&E adopted SFAS No. 158 in 2006. This statement requires employers to recognize the over-funded or under-funded status of a defined benefit pension and postretirement plan as an asset or liability in the balance sheet and to recognize through comprehensive income the changes in the funded status in the year in which the changes occur. Under SFAS No. 71, LG&E can defer recoverable costs that would otherwise be charged to expense or equity by non-regulated entities. Current rate recovery in Kentucky is based on SFAS No. 87 and SFAS No. 106, both of which were amended by SFAS No. 158. Regulators have been clear and consistent with their historical treatment of such rate recovery; therefore, LG&E has recorded a regulatory asset representing the probable recovery of the portion of the change in funded status of the postretirement and pension plans that is expected to be recovered. The regulatory asset will be adjusted annually as prior service cost and actuarial losses are recognized in net periodic benefit cost.

ARO. A summary of LG&E’s net ARO assets, regulatory assets, liabilities and cost of removal established under FIN 47 and SFAS No. 143, Accounting for Asset Retirement Obligations follows:

	ARO Net			ARO				Regulatory			Accumulated
(in millions)	Assets			Liabilities				Assets			Cost of Removal
As of December 31, 2004		$	3		$	(11	)		$	7		$	—
FIN 47 net asset additions		1			(15		)		12			3
ARO accretion		—			(1		)		1			—
As of December 31, 2005		4			(27		)		20			3
ARO accretion		—			(1		)		2			—
As of December 31, 2006		$	4		$	(28	)		$	22		$	3

ARO depreciation, removal cost incurred and cost of removal depreciation during 2005 and 2006 and FIN 47 net asset additions for 2006 were less than $1 million. In addition, regulatory liabilities and cost of removal depreciation as of December 31, 2005 and 2006 were less than $1 million.

Pursuant to regulatory treatment prescribed under SFAS No. 71, an offsetting regulatory credit was recorded in depreciation and amortization in the income statement of $2 million in 2006 and $1 million in 2005 for the ARO accretion and depreciation expense. LG&E AROs are primarily related to the final retirement of assets associated with generating units and natural gas wells. For assets associated with AROs, the removal cost accrued through depreciation under regulatory accounting is established as a regulatory asset or liability pursuant to regulatory treatment prescribed under SFAS No. 71. For the years ended December 31, 2006 and 2005, LG&E recorded less than $1 million of depreciation expense related to the cost of removal of ARO related assets. An offsetting regulatory liability was established pursuant to regulatory treatment prescribed under SFAS No. 71.

LG&E transmission and distribution lines largely operate under perpetual property easement agreements which do not generally require restoration upon removal of the property. Therefore, under SFAS No. 143, no material asset retirement obligations are recorded for transmission and distribution assets.

Gas Supply Cost Adjustments. LG&E’s natural gas rates contain a GSC, whereby increases or decreases in the cost of natural gas supply are reflected in LG&E’s rates, subject to approval by the Kentucky Commission. The GSC procedure prescribed by Order of the Kentucky Commission provides for quarterly rate adjustments to reflect the expected cost of natural gas supply in that quarter. In addition, the GSC contains a mechanism whereby any over- or under-recoveries of natural gas supply cost from prior quarters is to be refunded to or recovered from customers through the adjustment factor determined for subsequent quarters. In late 2005, as wholesale natural gas prices began to decrease, a one-time interim adjustment in the GSC was requested by LG&E and approved by the Kentucky Commission to pass the lower natural gas costs to the customers on a more timely basis.

LG&E’s GSC was modified in 1997 to incorporate an experimental natural gas procurement incentive mechanism. Since November 1, 1997, LG&E has operated under this experimental PBR mechanism related to its natural gas procurement activities. LG&E’s rates are adjusted annually to recover (or refund) its portion of the expense (or savings) incurred during each PBR year (12 months ending October 31). During the PBR year ending in 2006, LG&E achieved $17 million in savings. Of that total savings amount, LG&E’s portion was approximately $5 million and the ratepayers’ portion was approximately $12 million. Pursuant to the extension of LG&E’s natural gas supply cost PBR mechanism effective November 1, 2001, the sharing mechanism under the PBR requires savings (and expenses) to be shared 25% with shareholders and 75% with ratepayers up to 4.5% of the benchmarked natural gas costs. Savings (and expenses) in excess of 4.5% of the benchmarked

natural gas costs are shared 50% with shareholders and 50% with ratepayers. The current natural gas supply cost PBR mechanism was extended through 2010 without further modification.

Unamortized Loss on Bonds. The costs of early extinguishment of debt, including call premiums, legal and other expenses, and any unamortized balance of debt expense are amortized over the life of either replacement debt (in the case of refinancing) or the original life of the extinguished debt.

MISO Exit. Following receipt of applicable FERC, Kentucky Commission and other regulatory orders, LG&E withdrew from the MISO effective September 1, 2006. Specific proceedings regarding the costs and benefits of the MISO and exit matters had been underway since July 2003. Since the exit from the MISO, LG&E has been operating under a FERC-approved open access-transmission tariff. LG&E has further contracted with the Tennessee Valley Authority to act as its reliability coordinator and Southwest Power Pool, Inc. to function as its independent transmission operator, pursuant to FERC requirements, with respect to transmission matters.

LG&E and the MISO have agreed upon overall calculation methods for the contractual exit fee to be paid by the Company following its withdrawal. In October 2006, LG&E paid approximately $13 million to the MISO pursuant to an invoice regarding the exit fee and made related FERC compliance filings. The Company’s payment of this exit fee amount was with reservation of its rights to contest the amount, or components thereof, following a continuing review of its calculation and supporting documentation. In December 2006, LG&E provided notice to the MISO of its disagreement with the calculation of the exit fee. LG&E and the MISO continue to discuss the specifics of the exit fee calculation. The outcome of these discussions and the eventual settlement of the disputed amount cannot be estimated at this time. Orders of the Kentucky Commission approving the Company’s exit from the MISO have authorized the establishment of a regulatory asset for the exit fee, subject to adjustment for possible future MISO credits, and a regulatory liability for certain revenues associated with former MISO Schedule 10 charges, which may continue to be collected via base rates. The treatment of the regulatory asset and liability will be determined in LG&E’s next rate case; however, the Company historically has received approval to recover and refund regulatory assets and liabilities.

ECR. Kentucky law permits LG&E to recover the costs of complying with the Federal Clean Air Act, including a return of operating expenses, and a return of and on capital invested, through the ECR mechanism. The amount of the regulatory asset or liability is the amount that has been under- or over-recovered due to timing or adjustments to the mechanism once approved by the Kentucky Commission.

In April 2006, the Kentucky Commission initiated six-month and two-year reviews of LG&E’s environmental surcharge. A final order was received in January 2007, approving the changes and credits billed through the ECR during the review period as well as approving billing adjustments, a roll-in to base rates, revisions to the monthly surcharge filing and a rate of return on capital.

In June 2004, the Kentucky Commission issued an Order approving a settlement agreement that, among other things, revised the rate of return for LG&E’s post-1995 plan. The Order also approved the elimination of LG&E’s 1995 plan from its ECR billing mechanism, with all remaining costs associated with that plan to be included in their entirety in base rates.

In December 2004, LG&E filed an application with the Kentucky Commission to amend its compliance plan to allow recovery of costs associated with new and additional environmental compliance facilities, including the expansion of the landfill facility at the Mill Creek station. The estimated capital cost of the additional facilities over the next three years is approximately $25 million. A final Order was issued in June 2005, granting approval of the amendments to LG&E’s compliance plan.

In June 2006, LG&E filed an application to amend its ECR plan with the Kentucky Commission seeking approval to recover investments in environmental upgrades at the Company’s generating facilities. The estimated capital cost of the upgrades for the years 2007 through 2009 is approximately $50 million, of which $40 million is for the Air Quality Control System at TC2. A final Order was issued by the Kentucky Commission in December 2006 approving all expenditures and investments as submitted.

Merger Surcredit. As part of the LG&E Energy merger with KU Energy Corporation in 1998, LG&E estimated non-fuel savings over a ten-year period following the merger. Costs to achieve these savings were deferred and amortized over a five-year period pursuant to regulatory orders. In approving the merger, the Kentucky Commission adopted LG&E’s proposal to reduce its retail customers’ bills based on one-half of the estimated merger-related savings, net of deferred and amortized amounts, over a five-year period. The surcredit mechanism provides that 50% of the net non-fuel cost savings estimated to be achieved from the merger be provided to ratepayers through a monthly bill credit, and 50% be retained by LG&E and KU, over a five-year period. The surcredit was allocated 47% to LG&E and 53% to KU. In that same order, the Kentucky Commission required LG&E and KU, after the end of the five-year period, to present a plan for sharing with ratepayers the then-projected non-fuel savings associated with the merger. The Companies submitted this filing in January 2003, proposing to continue to share with ratepayers, on a 50%/50% basis, the estimated fifth-year gross level of non-fuel savings associated with the merger. In October 2003, the Kentucky Commission issued an Order approving a settlement agreement reached with the parties in the case. LG&E’s merger surcredit will remain in place for another five-year term beginning July 1, 2003 and the merger savings will continue to be shared 50% with ratepayers and 50% with shareholders.

VDT. In December 2001, the Kentucky Commission issued an Order approving a settlement agreement allowing LG&E to set up a regulatory asset of $141 million for workforce reduction costs and begin amortizing it over a five-year period starting in April 2001. Some employees rescinded their participation in the voluntary enhanced severance program, which thereby decreased the charge to the regulatory asset from $144 million to $141 million. The Order reduced revenues by approximately $26 million through a surcredit on bills to ratepayers over the same five-year period, reflecting a sharing (40% to the ratepayers and 60% to LG&E) of savings as stipulated by LG&E, net of amortization costs of the workforce reduction. The five-year VDT amortization period expired in March 2006.

As part of the settlement agreements in the electric and natural gas rate cases, in September 2005, LG&E filed with the Kentucky Commission a plan for the future ratemaking treatment of the VDT surcredit and costs. In February 2006, the AG, KIUC and LG&E reached a settlement agreement on the future ratemaking treatment of the VDT surcredits and costs and subsequently submitted a joint motion to the Kentucky Commission to approve the unanimous settlement agreement. Under the terms of the settlement agreement, the VDT surcredit will continue at the current level until such time as LG&E files for a change in electric or natural gas base rates. The Kentucky Commission issued an Order in March 2006, approving the settlement agreement.

FAC. LG&E’s retail electric rates contain an FAC, whereby increases and decreases in the cost of fuel for electric generation are reflected in the rates charged to retail electric customers. The FAC allows the Company to adjust customers’ accounts for the difference between the fuel cost component of base rates and the actual fuel cost, including transportation costs. Refunds to customers occur if the actual costs are below the embedded cost component. Additional charges to customers occur if the actual costs exceed the embedded cost component. The amount of the regulatory asset or liability is the amount that has been under- or over-recovered due to timing or adjustments to the mechanism.

In January 2003, the Kentucky Commission reviewed KU’s FAC and, as part of the Order in that case, required that an independent audit be conducted to examine operational and management aspects of both LG&E’s and KU’s fuel procurement functions. The final report was issued in February 2004. The report’s recommendations

related to documentation and process improvements. Management Audit Action Plans were agreed upon by LG&E and the Kentucky Commission Staff in the second quarter of 2004. LG&E filed its first Audit Progress Report with the Kentucky Commission Staff in November 2004. The second Audit Progress Report was filed May 2005. The third Audit Progress Report was filed in December 2005. In January 2006, the Kentucky Commission staff informed LG&E and KU that reporting on all of the original recommendations, but one, has been concluded. LG&E filed another Audit Progress Report on the remaining open recommendation in August 2006.

The Kentucky Commission requires public hearings at six-month intervals to examine past fuel adjustments, and at two-year intervals to review past operations of the fuel clause and transfer of the then current fuel adjustment charge or credit to the base charges. In July 2006, the Kentucky Commission initiated a six-month review of the FAC for LG&E for the period of November 1, 2005 through April 30, 2006. The Kentucky Commission issued an Order in November 2006 approving the charges and credits billed through the FAC during the review period.

In December 2006, the Kentucky Commission initiated a two-year review of LG&E’s past operations of the fuel clause and transfer of fuel costs from the FAC to base rates. LG&E anticipates Kentucky Commission approval of the charges and credits billed and the fuel procurement practices of LG&E during the second quarter of 2007.

ESM. Prior to 2004, LG&E’s retail electric rates were subject to an ESM which set an upper (12.5%) and lower (10.5%) limit for rate of return on equity. Any earnings excess or deficiency was shared 40% with ratepayers and 60% with shareholders. LG&E filed its final 2003 ESM calculations with the Kentucky Commission in March 2004, and applied for recovery of $13 million which was challenged by intervenors. In June 2004, the Kentucky Commission issued an Order largely accepting proposed settlement agreements by LG&E and the intervenors regarding the ESM. Under the settlements, LG&E continued to collect the $13 million of previously requested 2003 ESM revenue through March 2005. As part of the settlements, the parties agreed to a termination of the ESM relating to all periods after 2003.

DSM. LG&E’s rates contain a DSM provision. The provision includes a rate mechanism that provides for concurrent recovery of DSM costs and provides an incentive for implementing DSM programs. The provision allows LG&E to recover revenues from lost sales associated with the DSM programs based on program plan engineering estimates and post-implementation evaluations.

Accumulated Cost of Removal of Utility Plant. As of December 31, 2006 and 2005, LG&E has segregated the cost of removal, embedded in accumulated depreciation, of $232 million and $219 million, respectively, in accordance with FERC Order No. 631. This cost of removal component is for assets that do not have a legal ARO under SFAS No. 143. For reporting purposes in the balance sheets, LG&E has presented this cost of removal as a regulatory liability pursuant to SFAS No. 71.

Deferred Income Taxes — Net. Deferred income taxes represent the future income tax effects of recognizing the regulatory assets and liabilities in the income statement. Deferred income taxes are recognized at currently enacted tax rates for all material temporary differences between the financial reporting and income tax bases of assets and liabilities.

Other Regulatory Matters

Regional Reliability Council. LG&E has changed its regional reliability council membership from the Reliability First Corporation to the Southeastern Electric Reliability Council, effective January 1, 2007.

Regional reliability councils are industry consortiums that promote, coordinate and ensure the reliability of the bulk electric supply systems in North America.

Arena. In August 2006, LG&E filed an application with the Kentucky Commission requesting approval for sale of the Waterside property to the Louisville Arena Authority. The Kentucky Commission issued an Order in September 2006, approving the proposed transaction. In November 2006, LG&E completed certain agreements pursuant to its August 2006 Memorandum of Understanding with the Louisville Arena Authority regarding the proposed construction of an arena in downtown Louisville. LG&E entered into a relocation agreement with the Louisville Arena Authority providing for the reimbursement to LG&E of the costs to be incurred in moving certain LG&E facilities related to the arena transaction. Those costs are currently estimated to be approximately $63 million. The parties further entered into a property sale contract providing for LG&E’s sale of a downtown site to the Louisville Arena Authority for approximately $10 million, which represents the appraised value of the parcel, less certain agreed upon demolition costs. The amounts specified in the contracts are subject to certain adjustments. Depending upon continuing progress of the proposed arena, the transactions contemplated by the contracts will occur between 2006 and 2010.

TC2 CCN Application. A CCN application for TC2 construction was filed with the Kentucky Commission in December 2004, and initial CCN applications for three transmission lines were filed in early 2005, with further applications submitted in December 2005. The proposed air permit was filed with the Kentucky Division for Air Quality in December 2004. In November 2005, the Kentucky Commission approved the application to expand the Trimble County generating station. Kentucky Commission approval for one transmission line CCN was granted in September 2005, and a ruling that a second transmission line was not subject to the CCN process was received in February 2006. The Kentucky Commission granted approval for the remaining transmission line CCN in May 2006. In August 2006, LG&E and KU obtained dismissal of a judicial review of such CCN approval by certain property owners. A further appeal of such dismissal was thereafter filed, which action remains pending. The transmission lines are also subject to routine regulatory filings and the right-of-way acquisition process. In November 2005, the Kentucky Division for Air Quality issued the final air permit, which was challenged via a request for remand in December 2005 by three environmental advocacy groups, including the Sierra Club. Administrative proceedings with respect to the challenge continued throughout 2006. A ruling may occur during the first half of 2007.

Market-Based Rate Authority. Beginning in April 2004, the FERC initiated proceedings to modify its methods used to assess generation market power and has established more stringent interim market screen tests. During 2005, in connection with LG&E’s tri-annual market-based rate tariff renewals, the FERC continued to contend that the Company failed such market screens in certain regions. LG&E disputed this contention.

In July 2006, the FERC issued an Order in LG&E’s market-based rate proceeding accepting LG&E’s further proposal to address certain market power issues the FERC had claimed would arise upon an exit from the MISO. In particular, LG&E received permission to sell power at market-based rates at the interface of control areas in which they may be deemed to have market power, subject to a restriction that such power not be collusively re-sold back into such control areas. However, restrictions exist on sales by LG&E of power at market-based rates in the LG&E/KU and Big River Electric Corporation control areas. Certain general FERC proceedings continue with respect to market-based rate matters, and LG&E’s market-based rate authority is subject to such future developments.

LG&E cannot predict the ultimate impact of the current or potential mitigation mechanisms on its future wholesale power sales.

IRP. Integrated resource planning regulations in Kentucky require major utilities to make triennial IRP filings with the Kentucky Commission. In April 2005, LG&E and KU filed their joint 2005 IRP with the Kentucky Commission. The IRP provides historical and projected demand, resource and financial data, and other operating performance and system information. The AG and the KIUC were granted intervention in the IRP proceeding. The Kentucky Commission issued its staff report, with no substantive issues noted and closed the case by Order in February 2006.

PUHCA 2005. E.ON, LG&E’s ultimate parent, is a registered holding company under PUHCA 2005 and was a registered holding company under PUHCA 1935. E.ON, its utility subsidiaries, including LG&E, and certain of its non-utility subsidiaries are subject to extensive regulation by the SEC and the FERC with respect to numerous matters, including: electric utility facilities and operations, wholesale sales of power and related transactions, accounting practices, issuances and sales of securities, acquisitions and sales of utility properties, payments of dividends out of capital and surplus, financial matters and inter-system sales of non-power goods and services. LG&E believes that it has adequate authority (including financing authority) under existing FERC orders and regulations to conduct its business and will seek additional authorization when necessary.

EPAct 2005. The EPAct 2005 was enacted in August 2005. Among other matters, this comprehensive legislation contains provisions mandating improved electric reliability standards and performance; providing economic and other incentives relating to transmission, pollution control and renewable generation assets; increasing funding for clean coal generation incentives; repealing PUHCA 1935; enacting PUHCA 2005 and expanding FERC jurisdiction over public utility holding companies and related matters via the Federal Power Act and PUHCA 2005.

The FERC was directed by the EPAct 2005 to adopt rules to address many areas previously regulated by the other agencies under other statutes, including PUHCA 1935. The FERC is in various stages of rulemaking on these issues and LG&E is monitoring these rulemaking activities and actively participating in these and other rulemaking proceedings. LG&E is still evaluating the potential impacts of the EPAct 2005 and the associated rulemakings and cannot predict what impact the EPAct 2005, and any such rulemakings, will have on its operations or financial position.

In February 2006, the Kentucky Commission initiated an administrative proceeding to consider the requirements of the EPAct 2005, Subtitle E Section 1252, Smart Metering, which concerns time-based metering and demand response, and Section 1254, Interconnections. EPAct 2005 requires each state regulatory authority to conduct a formal investigation and issue a decision on whether or not it is appropriate to implement certain Section 1252, Smart Metering standards within eighteen months after the enactment of EPAct 2005 and to commence consideration of Section 1254, Interconnection standards within one year after the enactment of EPAct 2005. The Kentucky Commission held a public hearing in July 2006, in this proceeding with all Kentucky jurisdictional electric utilities. In December 2006, the Kentucky Commission issued an Order in this proceeding indicating that the EPAct 2005 Section 1252, Smart Metering and Section 1254, Interconnection standards should not be adopted. However, all five Kentucky Commission jurisdictional utilities are required to file real-time pricing pilot programs for their large commercial and industrial customers. LG&E will develop a real-time pricing pilot for large industrial and commercial customers and file the details of the plan with the Kentucky Commission in April 2007.

As part of the rate case settlement agreements, and as referred to in the EPAct 2005 administrative order, LG&E made its pilot program filing, which addresses real-time pricing for residential and general service customers, in March 2007.

Hydro Upgrade. In October 2005, LG&E received from the FERC a new license to upgrade, operate and maintain the Ohio Falls Hydroelectric Project. The license is for a period of 40 years, effective November 2005. LG&E intends to spend approximately $76 million to refurbish the facility and add approximately 20 Mw of generating capacity over the next six years.

Note 3 - Financial Instruments

The cost and estimated fair values of LG&E’s non-trading financial instruments as of December 31 follow:

	2006						2005
	Carrying			Fair			Carrying			Fair
(in millions)	Value			Value			Value			Value
Preferred stock subject to mandatory redemption (including current portion of $1 million)	$	20		$	20		$	21		$	21
Long-term debt (including current portion)	$	574		$	574		$	574		$	574
Long-term debt from affiliate	$	225		$	222		$	225		$	225
Interest-rate swaps - liability	$	(15	)	$	(15	)	$	(19	)	$	(19	)

All of the above valuations reflect prices quoted by exchanges except for the swaps and intercompany loans. The fair values of the swaps and intercompany loans reflect price quotes from dealers or amounts calculated using accepted pricing models. The fair values of cash and cash equivalents, accounts receivable, accounts payable and notes payable are substantially the same as their carrying values.

Interest Rate Swaps (hedging derivatives). LG&E uses over-the-counter interest rate swaps to hedge 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. Management has designated all of the interest rate swaps as hedge instruments. Financial instruments designated as cash flow hedges have resulting gains and losses recorded within other comprehensive income and stockholders’ equity. See Note 13, Accumulated Other Comprehensive Income. Financial instruments designated as fair value hedges and the underlying hedged items are periodically marked to market with the resulting net gains and losses recorded directly into net income. Upon termination of any fair value hedge, the resulting gain or loss is recorded into net income.

LG&E was party to various interest rate swap agreements with aggregate notional amounts of $211 million as of December 31, 2006 and 2005. Under these swap agreements, LG&E paid fixed rates averaging 4.38% and received variable rates based on London Interbank Borrowing Offer Rate or the Bond Market Association’s municipal swap index averaging 3.75% and 3.15% at December 31, 2006 and 2005, respectively. The swap agreements in effect at December 31, 2006 have been designated as cash flow hedges and mature on dates ranging from 2020 to 2033. The cash flow designation was assigned because the underlying variable rate debt has variable future cash flows. The hedges have been deemed to be fully effective resulting in a pretax gain of $3 million for 2006 and a pre-tax loss of less than $1 million in 2005, recorded in other comprehensive income. Upon expiration of these hedges, the amount recorded in other comprehensive income will be reclassified into earnings. The amount expected to be reclassified from other comprehensive income to earnings in the next

twelve months is less than $1 million. A deposit in the amount of $11 million, used as collateral for one of the interest rate swaps, is classified as restricted cash on the balance sheet. The amount of the deposit required is tied to the market value of the swap.

Energy Risk Management Activities (non-hedging derivatives). LG&E 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 hedge price risk and are accounted for on a mark-to-market basis in accordance with SFAS No. 133, as amended. Prior to the MISO establishing its Day 2 energy market in April 2005, wholesale forward transactions were primarily physically settled and thus were treated as normal sales under SFAS No. 133, as amended, and were not marked to market.

The table below summarizes LG&E’s energy trading and risk management activities:

(in millions)	2006			2005
Fair value of contracts at beginning of period, net asset	$	1		$	—
Fair value of contracts when entered into during the period	3			1
Contracts realized or otherwise settled during the period	(6		)	—
Changes in fair values due to changes in assumptions	3			—
Fair value of contracts at end of period, net asset	$	1		$	1

No changes to valuation techniques for energy trading and risk management activities occurred during 2006 or 2005. Changes in market pricing, interest rate and volatility assumptions were made during both years. All contracts outstanding at December 31, 2006 and 2005, have a maturity of less than one year and are valued using prices actively quoted for proposed or executed transactions or quoted by brokers.

LG&E hedges the price volatility of its forecasted electric off-system sales with the sales of market-traded electric forward contracts for periods of less than one year. These electric forward sales have been designated as cash flow hedges and are not speculative in nature. Gains or losses on these instruments, to the extent that the hedging relationship has been effective, are deferred in other comprehensive income. Gains and losses resulting from ineffectiveness are shown in the statements of income in other expense (income)-net. Upon completion of the underlying hedge transaction, the amount recorded in other comprehensive income is recorded in earnings. No material pre-tax gains and losses resulted from these cash flow hedges in 2006, 2005 and 2004. See Note 13, Accumulated Other Comprehensive Income.

Note 4 - Concentrations of Credit and Other Risk

Credit risk represents the accounting loss that would be recognized at the reporting date if counterparties failed to perform as contracted. Concentrations of credit risk (whether on- or off-balance sheet) relate to groups of customers or counterparties that have similar economic or industry characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in economic or other conditions.

LG&E’s customer receivables and natural gas and electric revenues arise from deliveries of natural gas to approximately 324,000 customers and electricity to approximately 398,000 customers in Louisville and adjacent areas in Kentucky. For the year ended December 31, 2006, 70% of total revenue was derived from electric operations and 30% from natural gas operations. For the year ended December 31, 2005, 69% of total revenue was derived from electric operations and 31% from natural gas operations.

In November 2005, LG&E and IBEW Local 2100 employees, that represent approximately 69% of LG&E’s workforce at February 28, 2007, entered into a three-year collective bargaining agreement with annual benefits re-openers.

Note 5 - Pension and Other Postretirement Benefit Plans

LG&E has both funded and unfunded non-contributory defined benefit pension plans and other postretirement benefit plans that together cover substantially all of its employees. The healthcare plans are contributory with participants’ contributions adjusted annually. LG&E uses December 31 as the measurement date for its plans.

Obligations and Funded Status. The following tables provide a reconciliation of the changes in the plans’ benefit obligations and fair value of assets over the three-year period ending December 31, 2006, and a statement of the funded status as of December 31 for LG&E’s sponsored defined benefit plans:

	Pension Benefits												Other Postretirement Benefits
(in millions)	2006				2005				2004				2006				2005				2004
Change in benefit obligation
Benefit obligation at beginning of year		$	427			$	402			$	379			$	106			$	113			$	108
Service cost		4				4				3				1				1				1
Interest cost		23				22				23				6				6				7
Plan amendments		4				3				3				—				2				—
Benefits paid		(29		)		(30		)		(31		)		(8		)		(8		)		(7		)
Actuarial (gain) or loss and other		(21		)		26				25				—				(8		)		4
Benefit obligation at end of year		$	408			$	427			$	402			$	105			$	106			$	113

Change in plan assets
Fair value of plan assets at beginning of year		$	333			$	338			$	298			$	3			$	1			$	1
Actual return on plan assets		36				27				39				—				—				(2		)
Employer contributions		18				—				35				11				10				9
Benefits paid		(29		)		(30		)		(31		)		(8		)		(8		)		(7		)
Administrative expenses and other		(2		)		(2		)		(3		)		—				—				—
Fair value of plan assets at end of year		$	356			$	333			$	338			$	6			$	3			$	1

Funded status at end of year		$	(52	)		$	(94	)		$	(64	)		$	(99	)		$	(103	)		$	(112	)

Amounts Recognized in Statement of Financial Position. The following tables provide the amounts recognized in the balance sheet and information for plans with benefit obligations in excess of plan assets as of December 31:

	PensionBenefits								Other Postretirement Benefits
(in millions)	2006				2005				2006				2005
Prior to the application of SFAS No. 158:

Accrued benefit liability		$	(35	)		$	(77	)		$	(66	)		$	(67	)
Intangible asset		27				31				—				—
Accumulated other comprehensive income		49				77				—				—

After the application of SFAS No. 158:

Regulatory assets		93				—				33				—
Accrued benefit liability (current)		—				—				(2		)		—
Accrued benefit liability (non-current)		(52		)		(77		)		(97		)		(67		)

The following table shows the calculation of the accrued benefit liability at December 31:

	Pension Benefits								Other Postretirement Benefits
(in millions)	2006				2005				2006				2005
Funded status		$	(52	)		$	(94	)		$	(99	)		$	(103	)
Unrecognized prior service costs		N/A				—				N/A				10
Unrecognized actuarial loss		N/A				94				N/A				21
Unrecognized transition obligation		N/A				—				N/A				5
Other comprehensive income		N/A				(77		)		N/A				—
Accrued benefit liability		$	(52	)		$	(77	)		$	(99	)		$	(67	)

Additional year-end information for plans with accumulated benefit obligations in excess of plan assets:

	Pension Benefits						Other Postretirement Benefits
(in millions)	2006			2005			2006			2005
Benefit obligation		$	408		$	427		$	105		$	106
Accumulated benefit obligation		391			410			—			—
Fair value of plan assets		356			333			6			3

Components of Net Periodic Benefit Cost. The following table provides the components of net periodic benefit cost for the plans:

	Pension Benefits												Other Postretirement Benefits
(in millions)	2006				2005				2004				2006			2005			2004
Service cost		$	4			$	4			$	3			$	1		$	1		$	1
Interest cost		23				22				23				6			5			6
Expected return on plan assets		(27		)		(26		)		(27		)		—			—			—
Amortization of prior service costs		4				4				4				2			2			2
Amortization of transitional asset		(1		)		(1		)		(1		)		—			1			1
Amortization of actuarial loss		4				2				2				—			—			1
Amortization of transitional obligation		—				—				—				1			—			—
Benefit cost at end of year		$	7			$	5			$	4			$	10		$	9		$	11

The assumptions used in the measurement of LG&E’s pension benefit obligation are shown in the following table:

	2006		2005		2004
Weighted-average assumptions as of December 31:
Discount rate-Union plan	5.91	%	5.50	%	5.75	%
Discount rate-Non-union plan	5.96	%	5.50	%	5.75	%
Rate of compensation increase	5.25	%	5.25	%	4.50	%

The assumptions used in the measurement of LG&E’s net periodic benefit cost are shown in the following table:

	2006		2005		2004
Discount rate	5.50	%	5.75	%	6.25	%
Expected long-term return on plan assets	8.25	%	8.25	%	8.50	%
Rate of compensation increase	5.25	%	4.50	%	3.50	%

To develop the expected long-term rate of return on assets assumption, LG&E considered the current level of expected returns on risk free investments (primarily government bonds), the historical level of the risk premium associated with the other asset classes in which the portfolio is invested and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based on the target asset allocation to develop the expected long-term rate of return on assets assumption for the portfolio.

Assumed Healthcare Cost Trend Rates. For measurement purposes, a 10% annual increase in the per capita cost of covered healthcare benefits was assumed for 2006. The rate was assumed to decrease gradually to 5% by 2015 and remain at that level thereafter.

Assumed healthcare cost trend rates have a significant effect on the amounts reported for the healthcare plans. A 1% change in assumed healthcare cost trend rates would have resulted in an increase or decrease of less than $1 million on the 2006 total of service and interest costs components and an increase or decrease of $3 million in year-end 2006 postretirement benefit obligations.

Expected Future Benefit Payments. The following list provides the amount of expected future benefit payments, which reflect expected future service, as appropriate:

				Other
	Pension			Postretirement
(in millions)	Plans			Benefits
2007		$	28		$	8
2008		$	28		$	9
2009		$	27		$	9
2010		$	26		$	9
2011		$	25		$	9
2012-16		$	124		$	44

Plan Assets. The following table shows LG&E’s weighted-average asset allocation by asset category at December 31:

	Target Range	2006			2005			2004
Pension Plans:
Equity securities	4 5%- 75%		61	%		57	%		66	%
Debt securities	30% - 50%		39	%		42	%		33	%
Other	0% - 10%		0	%		1	%		1	%
Totals			100	%		100	%		100	%

The investment policy of the pension plans was developed in conjunction with financial consultants, investment advisors and legal counsel. The goal of the investment policy is to preserve the capital of the fund and maximize investment earnings. The return objective is to exceed the benchmark return for the policy index comprised of the following: Russell 3000 Index, MSCI-EAFE Index, Lehman Aggregate and Lehman Long Duration Gov/Corporate Bond Index in proportions equal to the targeted asset allocation.

Evaluation of performance focuses on a long-term investment time horizon of at least three to five years or a complete market cycle. The assets of the pension plans are broadly diversified within different asset classes (equities, fixed income securities and cash equivalents).

To minimize the risk of large losses in a single asset class, no more than 5% of the portfolio will be invested in the securities of any one issuer with the exclusion of the U.S. government and its agencies. The equity portion of the fund is diversified among the market’s various subsections to diversify risk, maximize returns and avoid undue exposure to any single economic sector, industry group or individual security. The equity subsectors include, but are not limited to, growth, value, small capitalization and international.

In addition, the overall fixed income portfolio may have an average weighted duration, or interest rate sensitivity which is within +/- 20% of the duration of the overall fixed income benchmark. Foreign bonds in the aggregate shall not exceed 10% of the total fund. The portfolio may include a limited investment of up to 20% in below investment grade securities provided that the overall average portfolio quality remains “AA” or better. The below investment grade securities include, but are not limited to, medium-term notes, corporate debt, non-dollar and emerging market debt and asset backed securities. The cash investments should be in securities that either are of short maturities (not to exceed 180 days) or readily marketable with modest risk.

Derivative securities are permitted only to improve the portfolio’s risk/return profile, to modify the portfolio’s duration or to reduce transaction costs and must be used in conjunction with underlying physical assets in the portfolio. Derivative securities that involve speculation, leverage, interest rate anticipation, or any undue risk whatsoever are not deemed appropriate investments.

The investment objective for the postretirement benefit plan is to provide current income consistent with stability of principal and liquidity while maintaining a stable net asset value of $1.00 per share. The postretirement funds are invested in a prime cash money market fund that invests primarily in a portfolio of short-term, high-quality fixed income securities issued by banks, corporations and the U.S. government.

Contributions. LG&E made discretionary contributions to the pension plan of $18 million in January 2006 and $35 million in January 2004. There were no contributions during 2005. LG&E made an additional discretionary contribution to the pension plan of $56 million in January 2007, which was slightly more than the $52 million accrued benefit liability as of December 31, 2006. LG&E does not expect to make any further contributions in 2007. See Note 15, Subsequent Events.

In addition, LG&E made contributions to other postretirement benefit plans of approximately $11 million, $10 million and $9 million in 2006, 2005 and 2004, respectively. In 2007, LG&E anticipates making voluntary contributions to fund the Voluntary Employee Beneficiary Association (VEBA) trusts to match the annual postretirement expense and funding the 401(h) plan up to certain maximum applicable amounts under law or regulation.

Pension Legislation. The Pension Protection Act of 2006 was enacted in August 2006. The new rules are generally effective for plan years beginning after 2008. Among other matters, this comprehensive legislation contains provisions applicable to defined benefit plans which generally (i) mandate 100% funding of current liabilities within seven years; (ii) increase tax-deduction levels regarding contributions; (iii) revise certain actuarial assumptions, such as mortality tables and discount rates; and (iv) raise federal insurance premiums and other fees for under-funded and distressed plans. The legislation also contains similar provisions relating to defined-contribution plans and qualified and non-qualified executive pension plans and other matters. While LG&E continues to examine the potential impacts of the Pension Protection Act of 2006, its $56 million contribution in January 2007 was slightly more than the accrued benefit liability as of December 31, 2006.

FSP 106-2. FSP 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003, which provided guidance on accounting for subsidies provided under the Medicare Act, was effective for the first interim or annual period beginning after June 15, 2004. The impact of the subsidy in 2004 was a reduction in the accumulated postretirement benefit obligation of $3 million. The effect of the subsidy on the measurement of the net periodic postretirement benefit cost was less than $1 million.

Thrift Savings Plans. LG&E has a thrift savings plan under section 401(k) of the IRC. Under the plan, eligible employees may defer and contribute to the plan a portion of current compensation in order to provide future retirement benefits. LG&E makes contributions to the plan by matching a portion of the employee contributions. The costs of this matching were approximately $2 million for 2006 and $1 million for 2005 and 2004, respectively.

Note 6 - Income Taxes

Components of income tax expense are shown in the table below:

(in millions)		2006				2005				2004
Current	- federal		$	60			$	73			$	34
	- state		11				10				13
Deferred	- federal — net		(7		)		(12		)		11
	- state — net		(1		)		(2		)		(1		)
Investment tax credit — deferred			3				—				—
Amortization of investment tax credit			(4		)		(4		)		(4		)

Total income tax expense			$	62			$	65			$	53

Deferred federal income tax expense during 2004 included significant deductions attributable to federal bonus depreciation which ended after December 2004.

In June 2006, LG&E and KU filed a joint application with the DOE requesting certification to be eligible for investment tax credits applicable to the construction of TC2. The EPAct 2005 added Section 48A to the Internal Revenue Code, which provides for an investment tax credit to promote the commercialization of advanced coal technologies that will generate electricity in an environmentally responsible manner. LG&E’s and KU’s application requested up to a maximum amount of “advanced coal project” credit allowed per taxpayer, or $125 million, based on an estimate of 15% of projected qualifying TC2 expenditures.

In November 2006, the DOE and Internal Revenue Service announced that LG&E and KU were selected to receive the tax credit. LG&E’s portion of the tax credit will be approximately $24 million over the construction period of TC2. This tax credit will be amortized to income over the life of the related property. In 2006, based on eligible construction expenditures incurred in 2006, LG&E recorded a federal investment tax credit, decreasing current federal income taxes in 2006 by $3 million.

Components of net deferred tax liabilities included in the balance sheet are shown below:

(in millions)	2006		2005
Deferred tax liabilities:
Depreciation and other plant-related items	$	367	$	391
Regulatory assets and other	22		23
Pension and related benefits	6		—
Total deferred tax liabilities	395		414

Deferred tax assets:
Investment tax credit	15		17
Income taxes due to customers	21		17
Pensions and related benefits	—		39
Liabilities and other	26		19
Total deferred tax assets	62		92

Net deferred income tax liability	$	333	$	322

A reconciliation of differences between the statutory U.S. federal income tax rate and LG&E’s effective income tax rate follows:

	2006		2005		2004
Statutory federal income tax rate	35.0	%	35.0	%	35.0	%
State income taxes, net of federal benefit	3.8		4.3		5.3
Reduction of income tax accruals	(0.4	)	(2.0	)	(0.7	)
Amortization of investment tax credits	(2.2	)	(2.1	)	(3.6	)
Other differences	(1.6	)	(1.7	)	(0.4	)

Effective income tax rate	34.6	%	33.5	%	35.6	%

State income taxes net of federal benefit in 2006 reflect Kentucky Coal Tax Credits earned.

Other differences primarily relate to excess deferred taxes which reflect the benefits of deferred taxes reversing at tax rates that differ from statutory rates and various other permanent differences.

In September 2005, LG&E received notice from the Congressional Joint Committee on Taxation approving the Internal Revenue Service’s audit of LG&E’s income tax returns for the periods December 1999 through December 2003. As a result of resolving numerous tax matters during these periods, LG&E reduced income tax accruals by $4 million during 2005.

Kentucky House Bill 272, also known as “Kentucky’s Tax Modernization Plan”, was signed into law in March 2005. This bill contains a number of changes in Kentucky’s tax system, including the reduction of the Corporate income tax rate from 8.25% to 7% effective January 1, 2005, and a further reduction to 6% effective January 1, 2007. As a result of the income tax rate change, LG&E’s deferred tax reserve amount will exceed its actual deferred tax liability attributable to existing temporary differences, since the new statutory rates are lower than the rates were when the deferred tax liability originated. This excess amount is referred to as excess deferred income taxes. In June 2005 and December 2006, LG&E received approval from the Kentucky Commission to establish and amortize a regulatory liability ($16 million) for its net excess deferred income tax balances. LG&E will amortize its depreciation-related excess deferred income tax balances under the average rate assumption method. The average rate assumption method matches the amortization of the excess deferred

income taxes with the life of the timing differences to which they relate. Excess deferred income tax balances related to non-depreciation timing differences were expensed in 2005 and 2006 due to their immaterial amount.

LG&E expects to have adequate levels of taxable income to realize its recorded deferred tax assets.

Note 7 - Long-Term Debt

As of December 31, 2006 and 2005, long-term debt and the current portion of long-term debt consist primarily of pollution control bonds and long-term loans from affiliated companies as summarized below.

	Stated			Principal
(in millions)	Interest Rates		Maturities	Amounts
Outstanding at December 31, 2006:
Noncurrent portion	Variable - 5.875	%	2008-2035	$	572
Current portion	Variable		2007-2027	248
Outstanding at December 31, 2005:
Noncurrent portion	Variable - 5.875	%	2008-2035	$	573
Current portion	Variable		2006-2027	248

Under the provisions for LG&E’s variable-rate pollution control bonds, Series S, T, U, BB, CC, DD and EE, the bonds are subject to tender for purchase at the option of the holder and to mandatory tender for purchase upon the occurrence of certain events, causing the bonds to be classified as current portion of long-term debt in the balance sheets. The average annualized interest rate for these bonds during 2006 and 2005 was 3.50% and 2.50%, respectively.

Pollution control series bonds are first mortgage bonds that have been issued by LG&E in connection with tax-exempt pollution control revenue bonds issued by various governmental entities, principally counties in Kentucky. A loan agreement obligates LG&E to make debt service payments to the county that equate to the debt service due from the county on the related pollution control revenue bonds. The county’s debt is also secured by LG&E’s first mortgage bonds of an equal amount (the pollution control series bonds) that are pledged to the trustee for the pollution control revenue bonds, and that matches the terms and conditions of the county’s debt, but require no payment of principal and interest unless LG&E defaults on the loan agreement.

Substantially all of LG&E’s utility assets are pledged as collateral for its first mortgage bonds. LG&E’s first mortgage bond indenture, as supplemented, provides that portions of retained earnings will not be available for the payment of dividends on common stock, under certain specified conditions. No portion of retained earnings was restricted by this provision as of either December 31, 2006 or 2005.

Interest rate swaps are used to hedge LG&E’s underlying variable-rate debt obligations. These swaps hedge specific debt issuances and, consistent with management’s designation, are accorded hedge accounting treatment. The swaps exchange floating-rate interest payments for fixed rate interest payments to reduce the impact of interest rate changes on LG&E’s pollution control bonds. As of December 31, 2006 and 2005, LG&E had swaps with an aggregate notional value of $211 million. See Note 3, Financial Instruments.

Redemptions and maturities of long-term debt for 2006, 2005 and 2004 are summarized below:

($ in millions)		Principal						Secured/
Year	Description	Amount			Rate			Unsecured	Maturity
2006	Mandatorily Redeemable Preferred Stock		$	1		5.875	%	Unsecured	Jul	2006
2005	Pollution control bonds		$	40		5.90	%	Secured	Apr	2023
2005	Due to Fidelia		$	50		1.53	%	Secured	Jan	2005
2005	Mandatorily Redeemable Preferred Stock		$	1		5.875	%	Unsecured	Jul	2005
2004	Due to Fidelia		$	50		1.53	%	Secured	Jan	2005
2004	Mandatorily Redeemable Preferred Stock		$	1		5.875	%	Unsecured	Jul	2004

LG&E did not issue any new long-term debt in 2006. Issuances of long-term debt for 2005 and 2004 are summarized below:

($ in millions)		Principal				Secured/
Year	Description	Amount			Rate	Unsecured	Maturity
2005	Pollution control bonds		$	40	Variable	Secured	Feb	2035
2004	Due to Fidelia		$	25	4.33%	Secured	Jan	2012
2004	Due to Fidelia		$	100	1.53%	Secured	Jan	2005

LG&E has existing $5.875 series mandatorily redeemable preferred stock outstanding having a current redemption price of $100 per share. The preferred stock has a sinking fund requirement sufficient to retire a minimum of 12,500 shares on July 15 of each year commencing with July 15, 2003, and the remaining 187,500 shares on July 15, 2008 at $100 per share. LG&E redeemed 12,500 shares in accordance with these provisions on July 15, 2006, 2005, 2004 and 2003, leaving 200,000 shares currently outstanding.

Long-term debt maturities for LG&E are shown in the following table:

(in millions)
2007	$	1
2008	19
2009-11	—
Thereafter	800		(a)
Total	$	820

(a) Includes long-term debt of $246 million classified as current liabilities because these 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. Maturity dates for these bonds range from 2013 to 2027. LG&E does not expect to pay these amounts in 2007.

Note 8 - Notes Payable and Other Short-Term Obligations

LG&E participates in an intercompany money pool agreement wherein E.ON U.S. and/or KU make funds available to LG&E at market-based rates (based on an index of highly rated commercial paper issues) up to $400 million.

	Total Money			Amount			Balance			Average
($ in millions)	Pool Available			Outstanding			Available			Interest Rate
December 31, 2006		$	400		$	68		$	332		5.25	%
December 31, 2005		$	400		$	141		$	259		4.21	%

At December 31, 2006 and 2005, E.ON U.S. maintained a revolving credit facility totaling $200 million with an affiliated company, E.ON North America, Inc., to ensure funding availability for the money pool. The balance is as follows:

	Total			Amount			Balance			Average
($ in millions)	Available			Outstanding			Available			Interest Rate
December 31, 2006		$	200		$	102		$	98		5.49	%
December 31, 2005		$	200		$	105		$	95		4.49	%

During June 2006, LG&E renewed five revolving lines of credit with banks totaling $185 million. These credit facilities expire in June 2007, and there was no outstanding balance under any of these facilities at December 31, 2006 and 2005.

The covenants under these revolving lines of credit include:

· The debt/total capitalization ratio must be less than 70%;

· E.ON AG must own at least 66.667% of voting stock of LG&E directly or indirectly;

· The corporate credit rating of the Company must be at or above BBB- and Baa3; and

· A limitation on disposing of assets aggregating more than 15% of total assets as of December 31, 2005.

Note 9 - Commitments and Contingencies

Operating Leases. LG&E leases office space, office equipment and vehicles and accounts for these leases as operating leases. Total lease expense for 2006, 2005 and 2004, less amounts contributed by affiliated companies occupying a portion of the office space leased by LG&E, was $5 million for 2006 and $3 million each for 2005 and 2004. The future minimum annual lease payments for operating leases for years subsequent to December 31, 2006, are shown in the following table:

(in millions)
2007	$	2
2008	2
2009	2
2010	2
2011	2
Thereafter	8

Total	$	18

Sale and Leaseback Transaction. LG&E is a participant in a sale and leaseback transaction involving its 38% interest in two jointly-owned combustion turbines at KU’s E.W. Brown generating station (Units 6 and 7). Commencing in December 1999, LG&E and KU entered into a tax-efficient, 18-year lease of the combustion turbines. LG&E and KU have provided funds to fully defease the lease, and have executed an irrevocable notice to exercise an early purchase option contained in the lease after 15.5 years. The financial statement treatment of this transaction is no different than if LG&E had retained its ownership. The leasing transaction was entered into following receipt of required state and federal regulatory approvals.

In case of default under the lease, LG&E is obligated to pay to the lessor its share of certain fees or amounts. Primary events of default include loss or destruction of the combustion turbines, failure to insure or maintain the combustion turbines and unwinding of the transaction due to governmental actions. No events of default currently exist with respect to the lease. Upon any termination of the lease, whether by default or expiration of its term, title to the combustion turbines reverts jointly to LG&E and KU.

Letters of Credit. LG&E has provided letters of credit totaling $3 million to support certain obligations related to landfill reclamation and a letter of credit totaling less than $1 million to support certain obligations related to workers’ compensation.

Purchased Power. LG&E has a contract for purchased power with OVEC for various Mw capacities. LG&E has an investment of 5.63% ownership in OVEC’s common stock, which is accounted for on the cost method of accounting. LG&E’s share of OVEC’s output is 5.63%, approximately 124 Mw of generation capacity. Future obligations for power purchases are shown in the following table:

(in millions)
2007	$	11
2008	13
2009	16
2010	17
2011	17
Thereafter	328

Total	$	402

Construction Program. LG&E had approximately $180 million of commitments in connection with its construction program at December 31, 2006.

Environmental Matters. LG&E’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 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 State Implementation Plan (“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 percent 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, in 2002, Kentucky amended its SIP 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 requires additional SO2 emission reductions of 70 percent and NOx emission reductions of 65 percent from 2003 levels. The CAIR provides 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. The final rule is currently under challenge in a number of federal court proceedings. 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 power plants are potentially subject to additional reductions in SO2 and NOx emissions.

Hazardous Air Pollutants. As provided in the 1990 amendments to the Clean Air Act, the EPA investigated hazardous air pollutant emissions from electric utilities and submitted a report to Congress identifying mercury emissions from coal-fired power plants as warranting further study. In 2005, the EPA issued the CAMR establishing mercury standards for new power plants and requiring all states to issue new SIPs including mercury requirements for existing power plants. The EPA issued a model rule which provides for a two-phase cap and trade program with initial reductions due by 2010 and final reductions due by 2018. The CAMR provides for reductions of 70 percent from 2003 levels. The EPA closely integrated the CAMR and CAIR programs to ensure that the 2010 mercury reduction targets will be achieved as a “co-benefit” of the controls installed for purposes of compliance with the CAIR. The final rule is also currently under challenge in the federal courts. In 2006, Kentucky proposed to amend its SIP to adopt state requirements similar to those under the federal CAMR. In addition, in 2005 and 2006, state and local air agencies in Kentucky have proposed or adopted rules aimed at regulating additional hazardous air pollutants from sources including power plants. To the extent those rules are final, they are not expected to have a material impact on LG&E’s power plant operations.

Acid Rain Program. The 1990 amendments to the Clean Air Act imposed a two-phased cap and trade program to reduce SO2 emissions from power plants that were thought to contribute to “acid rain” conditions in the northeastern U.S. The 1990 amendments also contained requirements for power plants to reduce NOx emissions through the use of available combustion controls.

Regional Haze. The Clean Air Act also includes visibility goals for certain federally designated areas, including national parks, and requires states to submit SIPs that will demonstrate reasonable progress toward preventing future impairment and remedying any existing impairment of visibility in those areas. In 2005, the EPA issued its Clean Air Visibility Rule detailing how the Clean Air Act’s 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 will result in 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.

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 emissions 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 to 2006 time period at a cost of $187 million. In 2001, the Kentucky Commission granted recovery in principal of these costs incurred by LG&E under its periodic environmental surcharge review mechanisms.

In order to achieve the emissions reductions mandated by the CAIR and CAMR, LG&E expects to incur additional operating and maintenance costs in operating such controls. In 2005, the Kentucky Commission granted recovery in principal of these costs incurred by LG&E under its periodic environmental surcharge review mechanisms. LG&E believes its costs in reducing SO2, NOx and mercury emissions to be comparable to those of similarly situated utilities with like generation assets. LG&E’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 will continue to monitor these developments to ensure that its environmental obligations are met in the most efficient and cost-effective manner.

Potential GHG Controls. 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. 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 under the Regional GHG Initiative program and California. Substantial efforts to pass federal GHG legislation are ongoing. In addition, litigation is currently pending before various courts to determine whether the EPA and the states have the authority to regulate GHG emissions under existing law. LG&E is monitoring ongoing efforts to enact GHG reduction requirements at the state and federal level. LG&E is unable to predict whether mandatory GHG reduction requirements will ultimately be enacted or to determine the reduction

targets and deadlines that would be applicable under such programs. As a Company with significant coal-fired generating assets, LG&E could be substantially impacted by programs requiring mandatory reductions in GHG emissions, although the precise impact on the operations of LG&E cannot be determined prior to the enactment of such programs.

General Environmental Proceedings. From time to time, LG&E appears 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 remediation obligations for former MGP sites; liability under the Comprehensive Environmental Response, Compensation and Liability Act for cleanup at various off-site waste sites; ongoing claims regarding alleged particulate emissions from LG&E’s Cane Run station; and ongoing claims regarding GHG emissions from LG&E’s generating stations. With respect to the former MGP 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. An accrual for this amount had been recorded in the accompanying financial statements at December 31, 2005, which accrual was reversed as of December 31, 2006 upon the evaluation that the likelihood of such occurrence is remote. Based on analysis to date, the resolution of the other matters is also not expected to have a material impact on the operations of LG&E.

Note 10 - Jointly Owned Electric Utility Plant

LG&E owns a 75% undivided interest in TC1 which the Kentucky Commission has allowed to be reflected in customer rates. Of the remaining 25% of the Unit, IMEA owns a 12.12% undivided interest, and IMPA owns a 12.88% undivided interest. Each company is responsible for its proportionate ownership share of fuel cost, operation and maintenance expenses and incremental assets. The following data represent shares of the jointly owned property:

	TC1
	LG&E		IMPA		IMEA		Total
Ownership interest	75	%	12.88	%	12.12	%	100	%
Mw capacity	383		66		62		511

(in millions)
LG&E’s 75% ownership:
Cost	$	604
Accumulated depreciation	(231		)
Net book value	$	373

Construction work in progress (included in above)	$	9

LG&E and KU have begun construction of another jointly owned unit at the Trimble County site. LG&E and KU own undivided 14.25% and 60.75% interests, respectively, in TC2. Of the remaining 25% of TC2, IMEA owns a 12.12% undivided interest and IMPA owns a 12.88% undivided interest. Each company is responsible for its proportionate share of capital cost during construction, and fuel, operation and maintenance cost when TC2 begins operation, which is expected to occur in 2010.

	TC2
	LG&E		KU		IMPA		IMEA		Total
Ownership interest	14.25	%	60.75	%	12.88	%	12.12	%	100	%
Mw capacity	107		455		97		91		750

(in millions)	LG&E		KU
Construction work in progress	$	25	$	96

LG&E and KU jointly own the following combustion turbines and related equipment:

($ in millions)	LG&E					KU					Total
Ownership Percentage	Mw Capacity	($) Cost	($) Depre- ciation		($) Net Book Value	Mw Capacity	($) Cost	($) Depre- ciation		($) Net Book Value	Mw Capacity	($) Cost	($) Depre- ciation		($) Net Book Value
LG&E 53%, KU 47% (1)	146	58	(10	)	48	129	51	(10	)	41	275	109	(20	)	89
LG&E 38%, KU 62% (2)	118	46	(8	)	38	190	72	(12	)	60	308	118	(20	)	98
LG&E 29%, KU 71% (3)	92	32	(4	)	28	228	80	(12	)	68	320	112	(16	)	96
LG&E 37%, KU 63% (4)	236	79	(8	)	71	404	137	(12	)	125	640	216	(20	)	196
LG&E 29%, KU 71% (5)	n/a	3	(0	)	3	n/a	9	(1	)	8	n/a	12	(1	)	11

(1) Comprised of Paddy’s Run 13 and E.W. Brown 5. In addition to the above jointly owned utility plant, there is an inlet air cooling system attributable to Unit 5 and Units 8-11 at the E.W. Brown facility. This inlet air cooling system is not jointly owned, however it is used to increase production on the units to which it relates, resulting in an additional 10Mw of capacity for LG&E.

(2) Comprised of units 6 and 7 at the E.W. Brown facility.

(3) Comprised of units 5 and 6 at the Trimble County facility.

(4) Comprised of CT Substation 7-10 and units 7, 8, 9 and 10 at the Trimble County facility.

(5) Comprised of CT Substation 5 and 6 and CT Pipeline at the Trimble County facility.

Both LG&E’s and KU’s participating share of direct expenses of the joint fuel plants is included in the corresponding operating expenses on its respective income statement (e.g., fuel, maintenance of plant, other operating expense).

Note 11 - Segments of Business and Related Information

LG&E is a regulated public utility engaged in the generation, transmission, distribution and sale of electricity and the storage, distribution and sale of natural gas. LG&E is regulated by the Kentucky Commission and files electric and natural gas financial information separately with the Kentucky Commission. The Kentucky Commission establishes rates specifically for the electric and natural gas businesses. Therefore, management reports and analyzes financial performance based on the electric and natural gas segments of the business. Financial data for business segments follow:

(in millions)	Electric			Gas			Total
2006
Operating revenues		$	943		$	395		$	1,338
Depreciation and amortization		105			19			124
Income taxes		57			5			62
Interest income		1			—			1
Interest expense		33			8			41
Net income		107			10			117
Total assets		2,520			664			3,184
Construction expenditures		111			35			146

2005
Operating revenues		$	987		$	437		$	1,424
Depreciation and amortization		106			18			124
Income taxes		60			5			65
Interest income		1			—			1
Interest expense		30			7			37
Net income		119			10			129
Total assets		2,475			671			3,146
Construction expenditures		97			42			139

2004
Operating revenues		$	816		$	357		$	1,173
Depreciation and amortization		100			17			117
Income taxes		48			5			53
Interest income		—			—			—
Interest expense		27			6			33
Net income		87			9			96
Total assets		2,417			550			2,967
Construction expenditures		113			35			148

Note 12 - Related Party Transactions

LG&E and other subsidiaries of E.ON engage in related party transactions. Transactions between LG&E and E.ON U.S. subsidiaries are eliminated upon consolidation of E.ON U.S. Transactions between LG&E and E.ON subsidiaries are eliminated upon consolidation of E.ON. These transactions are generally performed at cost and are in accordance with FERC regulations under PUHCA 2005 and the applicable Kentucky Commission regulations. The significant related party transactions are disclosed below.

Electric Purchases

LG&E and KU purchase energy from each other in order to effectively manage the load of their retail and off-system customers. In 2004, LG&E also had sales to LG&E Energy Marketing Inc., another E.ON U.S. subsidiary, of less than $1 million. These sales and purchases are included in the statements of income as electric operating revenues and purchased power operating expense. LG&E intercompany electric revenues and purchased power expense for the years ended December 31, 2006, 2005 and 2004 were as follows:

(in millions)	2006		2005		2004
Electric operating revenues from KU	$	99	$	92	$	59
Purchased power from KU	77		96		62

Interest Charges

See Note 8, Notes Payable and Other Short-Term Obligations, for details of intercompany borrowing arrangements. Intercompany agreements do not require interest payments for receivables related to services provided when settled within 30 days.

LG&E’s intercompany interest income and expense for the years ended December 31, 2006, 2005 and 2004 were as follows:

(in millions)	2006		2005		2004
Interest on money pool loans	$	2	$	2	$	—
Interest on Fidelia loans	11		11		12

Other Intercompany Billings

E.ON U.S. Services provides LG&E with a variety of centralized administrative, management and support services. These charges include payroll taxes paid by E.ON U.S. on behalf of LG&E, labor and burdens of E.ON U.S. Services employees performing services for LG&E and vouchers paid by E.ON U.S. Services on behalf of LG&E. The cost of these services are directly charged to LG&E, or for general costs which cannot be directly attributed, charged based on predetermined allocation factors, including the following ratios: number of customers, total assets, revenues, number of employees and other statistical information. These costs are charged on an actual cost basis.

In addition, LG&E and KU provide services to each other and to E.ON U.S. Services. Billings between LG&E and KU relate to labor and overheads associated with union employees performing work for the other utility, charges related to jointly-owned combustion turbines and other miscellaneous charges. Billings from LG&E to E.ON U.S. Services relate to information technology-related services provided by LG&E employees, cash received by E.ON U.S. Services on behalf of LG&E and services provided by LG&E to other non-regulated businesses which are paid through E.ON U.S. Services.

Intercompany billings to and from LG&E for the years ended December 31, 2006, 2005 and 2004 were as follows:

(in millions)	2006		2005		2004
E.ON U.S. Services billings to LG&E	$	230	$	208	$	191
LG&E billings to KU	53		101		60
KU billings to LG&E	56		29		7
LG&E billings to E.ON U.S. Services	7		8		13

Note 13 — Accumulated Other Comprehensive Income

Accumulated other comprehensive income (loss) consisted of the following:

(in millions)	Minimum Pension Liability Adjustment				Accumulated Derivative Gain or Loss				Pre-Tax				Income Taxes				Net
Balance at December 31, 2003		$	(48	)		$	(16	)		$	(64	)		$	27			$	(37	)

Minimum pension liability adjustment		(10		)		—				(10		)		4				(6		)
Gains (losses) on derivative instruments
designated and qualifying as cash flow
hedging instruments		—				(2		)		(2		)		—				(2		)
Balance at December 31, 2004		(58		)		(18		)		(76		)		31				(45		)

Minimum pension liability adjustment		(19		)		—				(19		)		6				(13		)
Balance at December 31, 2005		(77		)		(18		)		(95		)		37				(58		)

Minimum pension liability adjustment		77				—				77				(30		)		47
Gains (losses) on derivative instruments
designated and qualifying as cash flow
hedging instruments		—				3				3				(1		)		2
Balance at December 31, 2006		$	—			$	(15	)		$	(15	)		$	6			$	(9	)

Note 14 - Selected Quarterly Data (Unaudited)

Selected financial data for the four quarters of 2006 and 2005 are shown below. Because of seasonal fluctuations in temperature and other factors, results for quarters may fluctuate throughout the year.

	Quarters Ended
(in millions)	March			June			September			December
2006
Operating revenues		$	413		$	277		$	303		$	345
Net operating income		50			47			71			55
Net income		26			25			40			26

2005
Operating revenues		$	402		$	281		$	319		$	422
Net operating income		62			53			66			49
Net income		34			28			42			25

PART IV

ITEM 15. Exhibits, Financial Statement Schedules.

(a) 1. Financial Statements (included in Item 8):

Statements of Income for the three years ended December 31, 2006 (page 47).

Statements of Retained Earnings for the three years ended December 31, 2006 (page 47).

Statements of Comprehensive Income for the three years ended December 31, 2006 (page 48).

Balance Sheets-December 31, 2006, and 2005 (page 49).

Statements of Cash Flows for the three years ended December 31, 2006 (page 51).

Statements of Capitalization-December 31, 2006, and 2005 (page 52).

Notes to Financial Statements (pages 53-85).

Report of Management (page 86).

Report of Independent Registered Public Accounting Firm (page 87).

2. Financial Statement Schedules (included in Part IV):

All schedules have been omitted as not applicable or not required or because the information required to be shown is included in the Financial Statements or the accompanying Notes to Financial Statements.

3. Exhibits:

Exhibit No.		Description

2.01		Copy of Agreement and Plan of Merger, dated as of February 27, 2000, by and among Powergen plc, LG&E Energy Corp., US Subholdco2 and Merger Sub, including certain exhibits thereto. [Filed as Exhibit 1 to LG&E’s Current Report on Form 8-K filed February 29, 2000 and incorporated by reference herein.]

2.02		Amendment No. 1 to Agreement and Plan of Merger, dated as of December 8, 2000, among LG&E Energy Corp., Powergen plc, Powergen US Investments Corp. and Powergen Acquisition Corp. [Filed as Exhibit 2.01 to LG&E’s Current Report on Form 8-K filed December 11, 2000 and incorporated by reference herein.]

2.03		Copy of Agreement and Plan of Merger, dated as of May 20, 1997, by and between LG&E Energy and KU Energy, including certain exhibits thereto. [Filed as Exhibit 2 to LG&E’s Current Report on Form 8-K filed May 30, 1997 and incorporated by reference herein.]

3.01		Copy of Restated Articles of Incorporation of LG&E, dated November 6, 1996. [Filed as Exhibit 3.06 to LG&E’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1996, and incorporated by reference herein.]

3.02		Copy of Amendment to Articles of Incorporation of LG&E, dated February 6, 2004. [Filed as Exhibit 3.02 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2003, and incorporated by reference herein.]

3.03		Copy of By-Laws of LG&E, as amended through December 16, 2003. [Filed as Exhibit 3.03 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2003, and incorporated by reference herein.]

4.01		Copy of Trust Indenture dated November 1, 1949, from LG&E to Harris Trust and Savings Bank, Trustee. [Filed as Exhibit 7.01 to LG&E’s Registration Statement 2-8283 and incorporated by reference herein.]

4.02		Copy of Supplemental Indenture dated September 1, 1992, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.32 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein.]

4.03		Copy of Supplemental Indenture dated September 2, 1992, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.33 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein.]

4.04		Copy of Supplemental Indenture dated August 16, 1993, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.35 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein.]

4.05		Copy of Supplemental Indenture dated August 1, 2000, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.38 to LG&E’s Annual Report on Form 10-K/A for the year ended December 31, 2000, and incorporated by reference herein.]

4.06		Copy of Supplemental Indenture dated September 1, 2001, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.42 to LG&E’s Annual Report on Form 10-K/A for the year ended December 31, 2001, and incorporated by reference herein.]

4.07		Copy of Supplemental Indenture dated March 1, 2002, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.39 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein.]

4.08		Copy of Supplemental Indenture dated March 15, 2002, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.40 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein.]

4.09		Copy of Supplemental Indenture dated October 1, 2002, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.41 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein.]

4.10		Copy of Supplemental Indenture dated October 1, 2003, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.22 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2003, and incorporated by reference herein.]

4.11		Supplemental Indenture dated as of April 1, 2005, from Louisville Gas and Electric Company to BNY Midwest Trust Company, as Trustee, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.1 to LG&E’s Form 8-K filed on April 13, 2005, and incorporated by reference herein.]

4.12		Copy of Loan Agreement between LG&E and Fidelia Corporation, dated April 30, 2003. [Filed as Exhibit 4.24 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2003, and incorporated by reference herein.]

4.13		Copy of Loan Agreement between LG&E and Fidelia Corporation, dated January 15, 2004. [Filed as Exhibit 4.27 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2004, and incorporated by reference herein.]

4.14		Copy of Loan and Security Agreement between LG&E and Fidelia Corporation, dated as of August 15, 2003. [Filed as Exhibit 4.27 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2003, and incorporated by reference herein.]

10.01		Copies of (i) Inter-Company Power Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies (which Agreement includes as Exhibit A the Power Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation); (ii) First Supplementary Transmission Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies; (iii) Inter-Company Bond Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies; (iv) Inter-Company Bank Credit Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 5.02f to LG&E’s Registration Statement 2-61607 and incorporated by reference herein.]

10.02		Copy of Modification No. 1 and No. 2 dated June 3, 1966 and January 7, 1967, respectively, to Inter-Company Power Agreement dated July 10, 1953. [Filed as Exhibits 4(a)(8) and 4(a)(10) to LG&E’s Registration Statement 2-26063 and incorporated by reference herein.]

10.03		Copies of Amendments to Agreements (iii) and (iv) referred to under 10.01 above as follows: (i) Amendment to Inter-Company Bond Agreement and (ii) Amendment to Inter-Company Bank Credit Agreement. [Filed as Exhibit 5.02h to LG&E’s Registration Statement 2-61607 and incorporated by reference herein.]

10.04		Copy of Modification No. 1, dated August 20, 1958, to First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 5.02i to LG&E’s Registration Statement 2-61607 and incorporated by reference herein.]

10.05		Copy of Modification No. 2, dated April 1, 1965, to the First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 5.02j to LG&E’s Registration Statement 2-61607 and incorporated by reference herein.]

10.06		Copy of Modification No. 3, dated January 20, 1967, to First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 4(a)(7) to LG&E’s Registration Statement 2-26063 and incorporated by reference herein.]

10.07		Copy of Modification No. 3 dated November 15, 1967, to the Inter-Company Power Agreement dated July 10, 1953. [Filed as Exhibit 4.02m to LG&E’s Registration Statement 2-37368 and incorporated by reference herein.]

10.08		Copy of Modification No. 4 dated November 5, 1975, to the Inter-Company Power Agreement dated July 10, 1953. [Filed as Exhibit 5.02o to LG&E’s Registration Statement 2-56357 and incorporated by reference herein.]

10.09		Copy of Modification No. 4 dated April 30, 1976, to First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 5.02p to LG&E’s Registration Statement 2-61607 and incorporated by reference herein.]

10.10		Copy of Modification No. 5 dated September 1, 1979, to Inter-Company Power Agreement dated July 5, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 4 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1979, and incorporated by reference herein.]

10.11		Copy of Modification No. 6 dated August 1, 1981, to Inter-Company Power Agreement dated July 5, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 10.26 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1981, and incorporated by reference herein.]

10.12		* Copy of Non-Qualified Savings Plan covering officers of the Company, effective January 1, 1992. [Filed as Exhibit 10.43 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein.]

10.13		Copy of Modification No. 7 dated January 15, 1992, to Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 10.44 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein.]

10.14		Copy of Modification No. 8 dated January 19, 1994, to Inter-Company Power Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 10.43 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein.]

10.15		Copy of Modification No. 9, dated August 17, 1995, to the Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 10.39 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1996, and incorporated by reference herein.]

10.16		* Copy of Amendment to the Non-Qualified Savings Plan, effective January 1, 1992. [Filed as Exhibit 10.55 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein.]

10.17		* Copy of Amendment to the Non-Qualified Savings Plan, effective January 1, 1995. [Filed as Exhibit 10.56 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein.]

10.18		* Copy of Amendment to the Non-Qualified Savings Plan, effective January 1, 1995. [Filed as Exhibit 10.57 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein.]

10.19		* Copy of Supplemental Executive Retirement Plan as amended through January 1, 1998, covering officers of LG&E Energy. [Filed as Exhibit 10.74 to LG&E Energy’s Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated by reference herein.]

10.20		* Copy of Amendment to LG&E Energy’s Supplemental Executive Retirement Plan, effective September 2, 1998. [Filed as Exhibit 10.90 to LG&E Energy’s Annual Report on Form 10-K for the year ended December 31, 1998 and incorporated by reference herein.]

10.21		* Copy of Employment and Severance Agreement, dated as of February 25, 2000, by and among LG&E Energy, Powergen plc and an executive officer of the Company. [Filed as Exhibit 10.54 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein.]

10.22		* Copy of Amendment, effective October 1, 1999, to LG&E Energy’s Non-Qualified Savings Plan. [Filed as Exhibit 10.96 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated by reference herein.]

10.23		* Copy of Amendment, effective December 1, 1999, to LG&E Energy’s Non-Qualified Savings Plan. [Filed as Exhibit 10.97 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated by reference herein.]

10.24		Copy of Modification No. 10, dated January 1, 1998, to the Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 10.102 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated by reference herein.]

10.25		Copy of Modification No. 11, dated April 1, 1999, to the Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 10.103 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated by reference herein.]

10.26		* Copy of Powergen Short-Term Incentive Plan, effective January 1, 2001, applicable to certain employees of LG&E Energy Corp. and its subsidiaries. [Filed as Exhibit 10.109 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2000, and incorporated herein by reference.]

10.27		* Copy of two forms of Change-In-Control Agreement applicable to certain employees of LG&E Energy Corp. and its subsidiaries. [Filed as Exhibit 10.110 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2000, and incorporated by reference herein.]

10.28		* Copy of Employment and Severance Agreement, dated as of February 25, 2000, and amendments thereto dated December 8, 2000 and April 30, 2001, by and among LG&E Energy, Powergen plc and Victor A. Staffieri. [Filed as Exhibit 10.74 to LG&E’s Annual Report on Form 10-K/A for the year ended December 31, 2001, and incorporated by reference herein.]

10.29		* Copy of Amendment, dated as of December 8, 2000, to Employment and Severance Agreement dated as of February 25, 2000, by and among LG&E Energy, Powergen plc and an executive officer of the Company. [Filed as Exhibit 10.63 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein.]

10.30		* Copy of Third Amendment, dated July 1, 2002, to Employment and Severance Agreement dated as of February 25, 2000 by and among E.ON AG, LG&E Energy, Powergen and Victor A. Staffieri. [Filed as Exhibit 10.74 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein.]

10.31		* Copy of form of Retention and Severance Agreement dated April/May, 2002 by and among LG&E Energy, E.ON AG and certain executive officers of the Companies. [Filed as Exhibit 10.75 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein.]

10.32		* Copy of Second Amendment, dated May 20, 2002, to Employment and Severance Agreement, dated February 25, 2000, by and among E.ON AG, LG&E Energy Corp., Powergen plc and an executive of the Companies. [Filed as Exhibit 10.76 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein.]

10.33		* Copy of Representative Terms and Conditions for Stock Appreciation Rights Issued as part of E.ON Group’s Stock Appreciation Rights Programs, applicable to certain executive officers of the Companies. [Filed as Exhibit 10.79 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein.]

10.34		* Copy of LG&E Energy Corp. Long-Term Performance Unit Plan, adopted April 25, 2003, effective January 1, 2003. [Filed as Exhibit 10.65 to LG&E Annual Report on Form 10-K for the year ended December 31, 2003, and incorporated by reference herein.]

10.35		Copy of Modification No. 12 dated as of November 1, 1999, to Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 10.69 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2003, and incorporated by reference herein.]

10.36		Copy of Modification No. 13 dated as of May 24, 2000, to Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 10.70 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2003, and incorporated by reference herein.]

10.37		Copy of Modification No. 14 dated as of April 1, 2001, to Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 10.71 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2003, and incorporated by reference herein.]

10.38		Copy of Amended and Restated Inter-Company Power Agreement dated as of March 13, 2006, among Ohio Valley Electric Corporation and Sponsoring Companies, including LG&E. [Filed as Exhibit 10.1 to LG&E’s Form 10-Q for the period ended June 30, 2004, and incorporated by reference herein.]

10.39		* Copy of Fourth Amendment dated as of February 1, 2004 to Employment and Severance Agreement dated as of February 25, 2000 by and among E.ON AG, LG&E’s Energy, Powergen and Victor A. Staffieri. [Filed as Exhibit 10.02 to LG&E’s Form 10-Q for the period ended June 30, 2004, and incorporated by reference herein.]

10.40		Copy of Modification No. 15, dated as of April 30, 2004, to Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 10.03 to LG&E’s Form 10-Q for the period ended June 30, 2004, and incorporated by reference herein.]

10.41		Participation Agreement between LG&E and Illinois Municipal Electric Agency, dated as of September 24, 1990. [Filed as Exhibit 10.42 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2004, and incorporated by reference herein.]

10.42		Participation Agreement between LG&E and Indiana Municipal Power Agency, dated as of February 1, 1993. [Filed as Exhibit 10.43 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2004, and incorporated by reference herein.]

10.43		Participation Agreement by and among LG&E and KU and Illinois Municipal Electric Agency and Indiana Municipal Power Agency, dated as of February 9, 2004. [Filed as Exhibit 10.44 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2004, and incorporated by reference herein.]

10.44		Copy of Barge Transportation Agreement between LG&E, effective January 1, 2002, and KU, effective July 1, 2002, and Crounse Corporation. [Filed as Exhibit 10.45 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2004, and incorporated by reference herein.]

10.45		Amendment No. 1 to Barge Transportation Agreement between Louisville Gas and Electric Company and Kentucky Utilities Company and Crounse Corporation, dated as of January 1, 2005. [Filed as Exhibit 10.46 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2005, and incorporated by reference herein.]

10.46		* Copy of LG&E Energy LLC Nonqualified Savings Plan, effective January 1, 2005. [Filed as Exhibit 10.47 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2005, and incorporated by reference herein.]

10.47		* Executive Officer Salary Information.

10.48		* Form of Representative Specimen Award under LG&E Energy Long-Term Performance Unit Plan. [Filed as Exhibit 10.47 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2004, and incorporated by reference herein.]

10.49		* Form of Representative Specimen Award under E.ON Group Stock Appreciation Rights Program. [Filed as Exhibit 10.48 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2004, and incorporated by reference herein.]

10.50		* Copies of E.ON Share Performance Plan (i) Terms and Conditions for the 1. Tranche (2006-2008) and (ii) Technical Annex, each dated as of June 2006. [Filed as Exhibit 10.01 to LG&E’s Form 10-Q for the quarter ended September 30, 2006 and incorporated by reference herein.]

10.51		* Copies of form representative specimen Certificate Award under E.ON Share Performance Plan. [Filed as Exhibit 10.02 to LG&E’s Form 10-Q for the quarter ended September 30, 2006 and incorporated by reference herein.]

12		Computation of Ratio of Earnings to Fixed Charges for LG&E.

21		Subsidiaries of the Registrant.

24		Power of Attorney.

31.1		Certification of Chief Executive Officer, Pursuant to Section 302 of Sarbanes-Oxley Act of 2002.

31.2		Certification of Chief Financial Officer, Pursuant to Section 302 of Sarbanes-Oxley Act of 2002.

32		Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.01		Cautionary Statement for purposes of the “Safe Harbor” provisions of the Private Securities Litigation Reform Act of 1995.

Commission		IRS Employer
File Number		Identification Number

1-2893		61-0264150

PART I

Item 1. Business.

Item 1A. Risk Factors

Item 1B. Unresolved Staff Comments.

ITEM 2. Properties.

ITEM 6. Selected Financial Data.

Commodity Prices: Fuel and Electricity

Energy & Risk Management Activities

ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk.

See Management’s Discussion and Analysis of Financial Condition and Results of Operations, Market Risks, under Item 7.

ITEM 8. Financial Statements and Supplementary Data.

Long-term debt maturities for LG&E are shown in the following table:

Report of Independent Registered Public Accounting Firm

ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

ITEM 9A. Controls and Procedures.

PART III

SIGNATURES — LOUISVILLE GAS AND ELECTRIC COMPANY

PART I
			Page

Item 1.	Business		4
		General	5
		Electric Operations	6
		Gas Operations	7
		Rates and Regulations	8
		Construction Program and Financing	11
		Coal Supply	11
		Gas Supply	12
		Environmental Matters	13
		Competition	13
		Employees and Labor Relations	14
		Executive Officers	15
Item 1A.	Risk Factors		17
Item 1B.	Unresolved Staff Comments		20
Item 2.	Properties		21
Item 3.	Legal Proceedings		23
Item 4.	Submission of Matters to a Vote of Security Holders		24

PART II

Item 5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		25
Item 6.	Selected Financial Data		25
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		26
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		46
Item 8.	Financial Statements and Supplementary Data		47
Item 9.	Changes and Disagreements with Accountants on Accounting and Financial Disclosure		88
Item 9A.	Controls and Procedures		88
Item 9B.	Other Information		88

PART III

Item 10,11,12,13 and 14			88

PART IV

Item 15.	Exhibits, Financial Statement Schedules		89
Signatures			97

AG		Attorney General of Kentucky
ARO		Asset Retirement Obligation
CAIR		Clean Air Interstate Rule
CAMR		Clean Air Mercury Rule
CCN		Certificate of Public Convenience and Necessity
Clean Air Act		The Clean Air Act, as amended in 1990
Company		LG&E
DOE		Department of Energy
DSM		Demand Side Management
ECR		Environmental Cost Recovery
E.ON		E.ON AG
E.ON U.S.		E.ON U.S. LLC. (formerly LG&E Energy LLC and LG&E Energy Corp.)
E.ON U.S. Services		E.ON U.S. Services Inc. (formerly LG&E Energy Services Inc.)
EPA		U.S. Environmental Protection Agency
EPAct 2005		Energy Policy Act of 2005
ESM		Earnings Sharing Mechanism
FAC		Fuel Adjustment Clause
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
Fidelia		Fidelia Corporation (an E.ON affiliate)
FIN		FASB Interpretation No.
FT and FT-A		Firm Transportation
GHG		Greenhouse Gas
GSC		Gas Supply Clause
IBEW		International Brotherhood of Electrical Workers
IMEA		Illinois Municipal Electric Agency
IMPA		Indiana Municipal Power Agency
IRC		Internal Revenue Code of 1986, as amended
IRP		Integrated Resource Plan
Kentucky Commission		Kentucky Public Service Commission
KIUC		Kentucky Industrial Utility Consumers, Inc.
KU		Kentucky Utilities Company
Kwh		Kilowatt hours
LG&E		Louisville Gas and Electric Company
LG&E Energy		LG&E Energy LLC (now E.ON U.S. LLC)
Mcf		Thousand Cubic Feet
MGP		Manufactured Gas Plant
MISO		Midwest Independent Transmission System Operator, Inc.
MMBtu		Million British thermal units
Mva		Megavolt-ampere
Mw		Megawatts
Mwh		Megawatt hours
NNS		No-Notice Service
NOx		Nitrogen Oxide
OVEC		Ohio Valley Electric Corporation
PBR		Performance-Based Ratemaking
Powergen		Powergen Limited (formerly Powergen plc)
PUHCA 1935		Public Utility Holding Company Act of 1935
PUHCA 2005		Public Utility Holding Company Act of 2005
SEC		Securities and Exchange Commission
SFAS		Statement of Financial Accounting Standards
SO2		Sulfur Dioxide
TC1		Trimble County Unit 1
TC2		Trimble County Unit 2
Tennessee Gas		Tennessee Gas Pipeline Company
Texas Gas		Texas Gas Transmission LLC
VDT		Value Delivery Team Process
WNA		Weather Normalization Adjustment

(in millions)	Before Adoption of SFAS No. 158*			Adjustments				After Adoption of SFAS No. 158
Accrued pension and postretirement liability-noncurrent	$	(102	)		$	(47	)		$	(149	)
Accrued pension and postretirement liability-current	—				(2		)		(2		)
Pension and postretirement regulatory asset	77				49				126

/s/ PricewaterhouseCoopers LLP
Louisville, Kentucky
February 8, 2007

		LOUISVILLE GAS AND ELECTRIC COMPANY
		Registrant

March 21, 2007	By:	/s/ S. Bradford Rives
(Date)		S. Bradford Rives
		Chief Financial Officer

Signature		Title	Date

Victor A. Staffieri		Chairman of the Board,
		President and Chief Executive Officer
		(Principal Executive Officer)

S. Bradford Rives		Director and Chief Financial Officer
		(Principal Financial Officer and Principal Accounting Officer)

John R. McCall		Director and Executive Vice President,
		General Counsel and Corporate Secretary

Chris Hermann		Director and Senior Vice President, Energy Delivery

Paul W. Thompson		Director and Senior Vice President, Energy Services




By:	/s/ S. Bradford Rives		March 21, 2007
	(Attorney-In-Fact)