IPALCO ENTERPRISES, INC. - FORM 10-K

Attached files

file	filename
EX-32 - EXHIBIT 32 - IPALCO ENTERPRISES, INC.	exhibit32200910k.htm
EX-31 - EXHIBIT 31.2 - IPALCO ENTERPRISES, INC.	exhibit31200910k.htm
EX-31 - EXHIBIT 31.1 - IPALCO ENTERPRISES, INC.	exhibit311200910k.htm

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)

þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2009

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-8644

IPALCO ENTERPRISES, INC.
(Exact name of registrant as specified in its charter)


Indiana	35-1575582
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

One Monument Circle, Indianapolis, Indiana	46204
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: 317-261-8261

Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer o	Accelerated filer o
Non-accelerated filer þ (Do not check if a smaller reporting company)	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

At February 25, 2010, 89,685,177 shares of IPALCO Enterprises, Inc. common stock were outstanding. All of such shares were owned by The AES Corporation.

THE REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND IS THEREFORE FILING THIS FORM WITH THE REDUCED DISCLOSURE FORMAT

IPALCO ENTERPRISES, INC.
Annual Report on Form 10-K
For Year Ended December 31, 2009


Table of Contents

Item No.

CAUTIONARY NOTE REGARDING FORWARD LOOKING STATEMENTS

PART I
	1.	Business
	1A.	Risk Factors
	1B.	Unresolved Staff Comments
	1C.	Defined Terms
	2.	Properties
	3.	Legal Proceedings
	4.	Submission of Matters to a Vote of Security Holders

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

PART III
	10.	Directors, Executive Officers, and Corporate Governance
	11.	Executive Compensation
	12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
	13.	Certain Relationships and Related Transactions, and Director Independence
	14.	Principal Accounting Fees and Services

PART IV
	15.	Exhibits, Financial Statements and Financial Statement Schedules

SIGNATURES

CAUTIONARY NOTE REGARDING FORWARD LOOKING STATEMENTS

This Report on Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Exchange Act including, in particular, the statements about our plans, strategies and prospects under the heading “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Forward-looking statements express an expectation or belief and contain a projection, plan or assumption with regard to, among other things, our future revenues, income or capital structure. Such statements of future events or performance are not guarantees of future performance and involve estimates, assumptions and uncertainties. The words “could,” “may,” “predict,” “anticipate,” “would,” “believe,” “estimate,” “expect,” “forecast,” “project,” “objective,” “intend,” “continue,” “should,” “plan,” and similar expressions are intended to identify forward-looking statements.

Some important factors that could cause our actual results or outcomes to differ materially from those discussed in the forward-looking statements include, but are not limited to:

fluctuations in retail customer and wholesale market demand;
impacts of weather on retail sales and wholesale prices and weather-related damage to our electrical system;
fuel and other input costs;
generating unit availability and capacity;
transmission and distribution system reliability and capacity;
purchased power costs and availability;
regulatory action, including, but not limited to, the review of our basic rates and charges by the Indiana Utility Regulatory Commission;
federal and state legislation;
our ownership by The AES Corporation;
changes in our credit ratings or the credit ratings of AES;
decreases in the value of pension plan assets, increases in pension plan expenses and our ability to fund defined benefit pension and other post-retirement plans;
changes in financial or regulatory accounting policies;
environmental matters, including costs of compliance with current and future environmental requirements;
interest rates and other costs of capital;
the availability of capital;
labor strikes or other workforce factors;
facility or equipment maintenance, repairs and capital expenditures;
the economy;
acts of terrorism, acts of war, pandemic events or natural disasters such as floods, earthquakes, tornadoes, ice storms or other catastrophic events;
costs and effects of legal and administrative proceedings, settlements, investigations and claims and the ultimate disposition of litigation;
issues related to our participation in the Midwest Independent Transmission System Operator, Inc., including recovery of costs incurred; and
product development and technology changes.

Most of these factors affect us through our consolidated subsidiary Indianapolis Power & Light Company. All such factors are difficult to predict, contain uncertainties that may materially affect actual results and many are beyond our control. Also see “Item 1A. Risk Factors” for further discussion of some of these factors. Except to the extent required by federal securities laws, we undertake no obligation to publicly update or review any forward-looking information, whether as a result of new information, future events or otherwise.

PART I

Throughout this document, the terms “we,” “us,” and “our” refer to IPALCO Enterprises, Inc. and its consolidated subsidiaries. IPALCO is wholly-owned by AES. For a list of other abbreviations or acronyms used in this report, see “Item 1C. Defined Terms.”

ITEM 1. BUSINESS

OVERVIEW

IPALCO is a holding company incorporated under the laws of the state of Indiana in 1983. Our principal subsidiary is Indianapolis Power & Light Company, a regulated electric utility with its customer base concentrated in Indianapolis, Indiana. Substantially all of our business consists of the generation, transmission, distribution and sale of electric energy conducted through IPL. Our other direct subsidiary, Mid-America Capital Resources, Inc. is the holding company for our unregulated activities. Mid-America Capital Resources’ only significant investment is a small minority ownership interest in EnerTech Capital Partners II L.P., a venture capital fund, with a recorded value of $5.3 million, as of December 31, 2009. Our total electric revenues and net income for the fiscal year ended December 31, 2009 were $1.1 billion and $70.6 million, respectively. The book value of our total assets as of December 31, 2009 was $3.0 billion. All of our operations are conducted within the United States of America in the state of Indiana. Please see Note 16, “Segment Information” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K.

Our principal executive offices are located at One Monument Circle, Indianapolis, Indiana 46204, and our telephone number is (317) 261-8261. Our internet website address is www.iplpower.com. The information on our website is not incorporated by reference into this report.

INDIANAPOLIS POWER & LIGHT COMPANY

IPALCO owns all of the outstanding common stock of IPL. IPL was incorporated under the laws of the state of Indiana in 1926. IPL is engaged primarily in generating, transmitting, distributing and selling electric energy to approximately 470,000 retail customers in the city of Indianapolis and neighboring areas within Indiana; the most distant point being approximately 40 miles from Indianapolis. IPL has an exclusive right to provide electric service to those customers. IPL’s service area covers about 528 square miles with an estimated population of approximately 882,000. IPL owns and operates four generating stations. Two of the generating stations are primarily coal-fired stations. A third station has a combination of units that use coal (base load capacity) and natural gas and/or oil (peaking capacity) for fuel to produce electricity. The fourth station is a small peaking station that uses gas-fired combustion turbine technology for the production of electricity. IPL’s net electric generation capability for winter is 3,492 Megawatt and net summer capability is 3,353 MW. IPL’s generation, transmission and distribution facilities are further described under “Item 2. Properties.” There have been no significant changes in the services rendered by IPL during 2009.

The electric utility business is affected by seasonal weather patterns throughout the year and, therefore, the operating revenues and associated operating expenses are not generated evenly by month during the year. IPL’s business is not dependent on any single customer or group of customers. Traditionally, retail kilowatt hour sales, after adjustments for weather variations, have grown in reasonable correlation with growth in service territory economic activity. During the past 10 years, IPL’s retail kWh sales have grown at a compound annual rate of 0.3%. During the same period, our number of retail customers grew at a compound annual rate of 0.8%. IPL’s electricity sales for 2005 through 2009 are set forth in the table of statistical information included at the end of this section.

IPL is a transmission company member of ReliabilityFirst Corporation, which began operations on January 1, 2006. RFC is one of eight Regional Reliability Councils under the North American Electric Reliability Corporation, which has been designated as the Electric Reliability Organization under the Energy Policy Act of 2005. The mission of RFC is to preserve and enhance electric service reliability and security for the interconnected electric systems within the RFC geographic area. RFC members cooperate under agreements to augment the reliability of its members’ electricity supply systems in the RFC region through coordination of the planning and operation of the members’ generation and transmission facilities. Small electric utility systems, independent power producers and power marketers can participate as full members of RFC. In addition, we are one of many transmission owners of the Midwest ISO (See “Industry Matters - Midwest ISO Operations”), a regional transmission organization which maintains functional control over the combined transmission systems of its members and manages one of the largest energy markets in the U.S. IPL participates in the Midwest ISO’s Energy and Operating Reserves Markets and each Asset Owner receives separate Day-Ahead, Real-Time, and FTR market Settlement Statements for each operating day.

REGULATORY MATTERS

Regulation

We are subject to regulation by the Indiana Utility Regulatory Commission with respect to the following: our services and facilities; the valuation of property, the construction, purchase, or lease of electric generating facilities; the classification of accounts; rates of depreciation; retail rates and charges; the issuance of securities (other than evidences of indebtedness payable less than twelve months after the date of issue); the acquisition and sale of some public utility properties or securities; and certain other matters. The regulatory power of the IURC over our business is both comprehensive and typical of the traditional form of regulation generally imposed by state public utility commissions.

In addition, we are subject to the jurisdiction of the Federal Energy Regulatory Commission with respect to, among other things, short-term borrowing not regulated by the IURC, the sale of electricity at wholesale and the transmission of electric energy in interstate commerce, the classification of accounts, reliability standards, and the acquisition and sale of utility property in certain circumstances as provided by the Federal Power Act. As a regulated entity, IPL is required to use certain accounting methods prescribed by regulatory bodies which may differ from those accounting methods required to be used by nonregulated entities. We maintain our books and records consistent with GAAP reflecting the impact of regulation. See Note 2, “Summary of Significant Accounting Policies” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K.

We are also affected by the regulatory jurisdiction of the U.S. Environmental Protection Agency, at the federal level, and Indiana Department of Environmental Management, at the state level. Other significant regulatory agencies affecting us include, but are not limited to, the North American Electric Reliability Corporation, the U.S. Department of Labor, and the Indiana Occupational Safety and Health Administration.

Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Regulatory Matters” for a more comprehensive discussion of regulatory matters impacting us.

Retail Ratemaking

Our tariff rates for electric service to retail customers consist of basic rates and charges which are set and approved by the IURC after public hearings. In addition, our rates include various adjustment mechanisms including, but not limited to those to reflect changes in fuel costs to generate electricity or purchased power prices, referred to as Fuel Adjustment Charges and for the timely recovery of costs incurred to comply with environmental laws and regulations referred to as Environmental Compliance Cost Recovery Adjustment. Each of our tariff rate components may be set and approved by the IURC in separate proceedings at different points in time. These components function somewhat independently of one another, but would all be subject to review at the time of any review of our basic rates and charges. For example, FAC proceedings occur on a quarterly basis and the ECCRA proceedings occur on a semi-annual basis. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Regulatory Matters” for further discussion of our basic rates and the various adjustment mechanisms and for a discussion of an ongoing review of IPL by the IURC.

INDUSTRY MATTERS

Energy Policy Act of 2005

In 2005, the EPAct was signed into law. Much of the legislation directs the FERC, the Department of Energy and other agencies to develop rules for the implementation of the EPAct. The EPAct implementation process at the FERC and the IURC is ongoing and we are actively engaged in the process. The EPAct contains provisions specifically related to the electric utility industry including, but not limited to, the following: climate change issues, mandatory reliability standards, amendments to the Public Utility Regulatory Policies Act, repeal of the Public Utility Holding Company Act of 1935, establishment of the Public Utility Holding Company Act of 2005, clean power initiatives, and energy efficiency proposals. IPALCO is currently exempt from the Public Utility Holding Company Act of 2005.

There are currently 109 FERC approved reliability standards that cover the planning and operation of the bulk-power system, facilities design, connections and maintenance. There are an additional 46 standards that have been approved by the North American Electric Reliability Corporation Board of Trustees and are awaiting FERC approval. All of the 109 FERC approved standards are mandatory and enforceable. Non-compliance may result in monetary fines up to $1 million per violation per day. Enforcement of the reliability standards is the responsibility of the North American Electric Reliability Corporation as the designated Electric Reliability Organization. To date, compliance with all of these standards has not resulted in a material impact to our financial statements and we have not been required to pay any fines, but there can be no guarantee that the standards will not be material to future results of operations, financial conditions, or cash flows. We will continue to monitor any revisions to the reliability standards and will continue working toward assuring full compliance with all applicable reliability standards.

Midwest ISO Operations

We are a member of the Midwest ISO. Midwest ISO serves as the third-party operator of our transmission system and runs the day-ahead and real-time Energy Market and, beginning in January 2009, the Ancillary Services Market for its members. Midwest ISO policies are developed through a stakeholder process in which we are an active participant. We focus our participation in this process primarily on items that could impact our customers, results of operations, financial condition, and cash flows. Additionally, we attempt to influence Midwest ISO policy by filing comments with the FERC.

We have transferred functional control of our transmission facilities to the Midwest ISO and our transmission operations were integrated with those of the Midwest ISO. Our participation and authority to sell wholesale power at market based rates are subject to the FERC jurisdiction. Transmission service over our facilities is now provided through the Midwest ISO’s tariff.

As a member of the Midwest ISO market, we offer our generation and bid our demand into the market on an hourly basis. The Midwest ISO settles energy hourly offers and bids based on locational marginal prices, which is pricing for energy at a given location based on a market clearing price that takes into account physical limitations, generation and demand, throughout the Midwest ISO region. The Midwest ISO evaluates the market participants’ energy offers and demand bids optimizing for energy products to economically and reliably dispatch the entire Midwest ISO system. The IURC has authorized IPL to recover the fuel portion of its costs from the Midwest ISO through FAC proceedings, and to defer certain operational, administrative and other costs from the Midwest ISO and seek recovery in IPL’s next basic rate case proceeding. Total Midwest ISO costs deferred as long-term regulatory assets were $62.8 million and $57.9 million as of December 31, 2009 and December 31, 2008, respectively. In January 2009, the Midwest ISO launched the ASM in conjunction with the Energy Market. Under the ASM, the Midwest ISO evaluates the market participants’ ancillary services offers and demand bids optimizing for all ancillary services products to economically and reliably dispatch the entire Midwest ISO system. IPL has authority from the IURC to include all specifically identifiable ASM costs and revenues as recoverable fuel costs in our FAC filings and to defer the remaining costs as regulatory assets. IPL will seek to recover the deferred costs in its next basic rate case proceeding.

We have preserved our right to withdraw from the Midwest ISO by tendering our Notice of Withdrawal (subject to the FERC and the IURC approval). We have made no decision to seek withdrawal from the Midwest ISO at this time. We will continue to assess the relative costs and benefits of being a Midwest ISO member, as well as actively advocate for our positions through the existing Midwest ISO stakeholder process and in filings at FERC.

Please see also, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Regulatory Matters.”

ENVIRONMENTAL MATTERS

We are subject to various federal, state and local environmental protection and health and safety laws and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of hazardous materials; the emission and discharge of hazardous and other materials into the environment; and the health and safety of our employees. These laws and regulations often require a lengthy and complex process of obtaining and renewing permits and other governmental authorizations from federal, state and local agencies. Violation of these laws, regulations or permits can result in substantial fines, other sanctions, suspension or revocation of permits and/or facility shutdowns. Environmental Matters in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” describes potential legislation that we believe may be significant to our business as well as a Notice of Violation and Finding of Violation from the EPA pursuant to the Clean Air Act Section 113(a). This NOV from the EPA may result in a fine which could be material. We do not believe any other currently open investigations will result in fines material to our results of operations, financial condition, and cash flows.

FUEL

More than 99% of the total kWhs produced by us was generated from coal in each of 2009, 2008, and 2007. Our existing coal contracts provide for substantially all of our current projected coal requirements in 2010 and approximately 90% for the three year period ending December 31, 2012. We have long-term coal contracts with five suppliers. Approximately 40% of our existing coal under contract comes from one supplier. Pricing provisions in some of our long-term coal contracts allow for price changes under certain circumstances. Substantially all of the coal is currently mined in the state of Indiana. All coal currently burned by us and under purchase contracts is mined by third parties. Our goal is to carry a 25-50 day system supply of coal and fuel oil to offset unforeseen occurrences such as equipment breakdowns and transportation or mine delays.

EMPLOYEES

As of January 31, 2010, IPL had 1,471 employees of whom 1,415 were full time. Of the total employees, 929 were represented by the International Brotherhood of Electrical Workers in two bargaining units: a physical unit and a clerical-technical unit. As of January 31, 2010, neither IPALCO nor any of its subsidiaries other than IPL had any employees.

STATISTICAL INFORMATION ON OPERATIONS

The following table of statistical information presents additional data on our operations:


	Year Ended December 31,
	2009		2008		2007		2006		2005
*Operating Revenues (In Thousands):*
Residential	$	392,181	$	390,892	$	377,081	$	363,668	$	344,323
Small commercial and industrial		160,814		165,660		160,456		155,314		147,091
Large commercial and industrial		436,060		435,578		416,694		418,782		377,904
Public Lighting		11,093		10,973		11,221		11,160		11,161
Miscellaneous		17,778		18,554		18,809		22,678		17,274
Revenues - retail customers		1,017,926		1,021,657		984,261		971,602		897,753
Wholesale		50,155		57,456		68,366		60,449		53,326
Total electric revenues	$	1,068,081	$	1,079,113	$	1,052,627	$	1,032,051	$	951,079

*Kilowatt-hour Sales (In Millions):*
Residential		5,085		5,350		5,467		5,027		5,314
Small commercial and industrial		1,892		2,030		2,101		1,989		2,076
Large commercial and industrial		7,041		7,550		7,683		7,627		7,663
Public Lighting		68		73		77		73		83
Sales - retail customers		14,086		15,003		15,328		14,716		15,136
Wholesale		1,881		1,189		1,640		1,571		1,140
Total kilowatt-hour sold		15,967		16,192		16,968		16,287		16,276

Retail Customers at End of Year:
Residential		416,500		416,019		417,227		417,249		414,566
Small commercial and industrial		46,708		46,719		46,749		46,316		45,870
Large commercial and industrial		4,625		4,610		4,559		4,509		4,434
Public Lighting		940		905		813		793		710
Total retail customers		468,773		468,253		469,348		468,867		465,580

ITEM 1A. RISK FACTORS

Investors should consider carefully the following risk factors that could cause our results of operations, financial condition, and cash flows to be materially adversely affected. New risks may emerge at any time, and we cannot predict those risks or estimate the extent to which they may affect our business or financial performance. These risk factors should be read in conjunction with the other detailed information concerning IPALCO and IPL set forth in the Notes to audited Consolidated Financial Statements in “Item 8. Financial Statements and Supplementary Data” and in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” herein.

Our electric generating facilities are subject to operational risks that could result in: unscheduled plant outages, unanticipated operation and/or maintenance expenses, increased fuel or purchased power costs, and other significant liabilities.

We operate coal, oil and natural gas generating facilities, which involve certain risks that can adversely affect energy output and efficiency levels. These risks include:

increased prices for fuel and fuel transportation as existing contracts expire;
facility shutdowns due to a breakdown or failure of equipment or processes;
disruptions in the availability or delivery of fuel and lack of adequate inventories;
labor disputes;
reliability of our suppliers;
inability to comply with regulatory or permit requirements;
disruptions in the delivery of electricity;
the availability of qualified personnel;
operator error; and
catastrophic events such as fires, explosions, terrorist acts, acts of war, pandemic events, or natural disasters such as floods, earthquakes, tornadoes, ice storms, or other similar occurrences affecting our generating facilities.

The above risks could result in unscheduled plant outages, unanticipated operation and/or maintenance expenses, increased capital expenditures, and/or increased fuel and purchased power costs, any of which could have a material adverse effect on our operations and if such plant outages occur frequently and/or for extended periods of time, could result in regulatory action.

Additionally, as a result of the above risks and other potential hazards associated with the power generation industries, we may from time to time become exposed to significant liabilities for which we may not have adequate insurance coverage. Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. In addition to natural risks, such as earthquakes, floods, lightning, tornadoes, ice storms and wind, hazards, such as fire, explosion, collapse and machinery failure, are inherent risks in our operations which may occur as a result of inadequate internal processes, technological flaws, human error or certain external events. The control and management of these risks depend upon adequate development and training of personnel and on the existence of operational procedures, preventative maintenance plans and specific programs supported by quality control systems which reduce, but do not eliminate the possibility of the occurrence and impact of these risks.

The hazardous activities described above can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in us being named as a defendant in lawsuits asserting claims for substantial damages, environmental cleanup costs, personal injury and fines and/or penalties. We maintain an amount of insurance protection that we believe is adequate, but there can be no assurance that our insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. A successful claim for which we are not fully insured could hurt our financial results and materially harm our financial condition. Further, due to rising insurance costs and changes in the insurance markets, we cannot provide assurance that insurance coverage will continue to be available on terms similar to those presently available to us or at all. Any such losses not covered by insurance could have a material adverse effect on our financial condition, results of operations or cash flows.

We may not always be able to recover our costs to provide electricity to our retail customers.

We are currently obligated to supply electric energy to our retail customers in our service territory. From time to time and because of unforeseen circumstances, the demand for electric energy required to meet these obligations could exceed our available electric generating capability. When our retail customer demand exceeds our generating capacity for units operating under Midwest ISO economic dispatch, recovery of our cost to purchase electric energy in the Midwest ISO market to meet that demand is subject to a stipulation and settlement agreement. The agreement includes a benchmark which compares hourly purchased power costs to daily natural gas prices. Purchased power costs above the benchmark must meet certain criteria in order for us to fully recover them from our retail customers, such as consideration of the capacity of units available but not selected by the Midwest ISO economic dispatch. As a result, we may not always have the ability to pass all of the purchased power costs on to our customers, and even if we are able to do so, there may be a significant delay between the time the costs are incurred and the time the costs are recovered. Since these situations most often occur during periods of peak demand, the market price for electric energy at the time we purchase it could be very high under these circumstances, and we may not be allowed to recover all of such costs through our FAC. Even if a supply shortage was brief, we could suffer substantial losses that could adversely affect our results of operations, financial condition, and cash flows. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Regulatory Matters - Fuel Adjustment Charge and Authorized Annual Jurisdictional Net Operating Income” for additional details regarding the benchmark and the process to recover fuel costs.

Our transmission and distribution system is subject to reliability and capacity risks.

The on-going reliable performance of our transmission and distribution system is subject to risks due to, among other things, weather damage, intentional or unintentional damage, plant outages, labor disputes, operator error, or inoperability of key infrastructure internal or external to us. The failure of our transmission and distribution system to fully deliver the energy demanded by customers could have a material adverse effect on our results of operations, financial condition, and cash flows, and if such failures occur frequently and/or for extended periods of time, could result in regulatory action. In addition, the advent and quick adaptation of new products and services that require increased levels of electrical energy cannot be predicted and could result in insufficient transmission and distribution system capacity. As with all utilities, potential concern over transmission capacity could result in the Midwest ISO, or the FERC requiring us to upgrade or expand our transmission system through additional capital expenditures.

Substantially all of our electricity is generated by coal and approximately 40% of our supply of coal comes from one supplier.

Please see “Item 1. Business - Fuel” for a discussion of concentration risks associated with coal.

Catastrophic events could adversely affect our facilities, systems and operations.

Catastrophic events such as fires, explosions, terrorist acts, acts of war, pandemic events, or natural disasters such as floods, earthquakes, tornadoes, ice storms or other similar occurrences could adversely affect our generation facilities, transmission and distribution systems, operations, earnings and cash flow. Our Petersburg Plant, which is our largest source of generating capacity, is located in the Wabash Valley seismic zone, adjacent to the New Madrid seismic zone, areas of significant seismic activity in the central United States.

Our business is sensitive to weather and seasonal variations.

Our business is affected by variations in general weather conditions and unusually severe weather. As a result of these factors, the operating revenues and associated operating expenses are not generated evenly by month during the year. We forecast electric sales on the basis of normal weather, which represents a long-term historical average. Significant variations from normal weather (such as warmer winters and cooler summers) could have a material impact on our revenue, operating income and net income and cash flows. Storms that interrupt services to our customers have required us in the past, and may require us in the future, to incur significant costs to restore services.

The electricity business is highly regulated and any changes in regulations, or adverse regulatory action, could reduce revenues or increase costs.

As an electric utility, we are subject to extensive regulation at both the federal and state level. At the federal level, we are regulated by the FERC and the North American Electric Reliability Corporation and, at the state level, we are regulated by the IURC. The regulatory power of the IURC over IPL is both comprehensive and typical of the traditional form of regulation generally imposed by state public utility commissions. We face the risk of unexpected or adverse regulatory action. Regulatory discretion is reasonably broad in Indiana. We are subject to regulation by the IURC as to our services and facilities, the valuation of property, the construction, purchase, or lease of electric generating facilities, the classification of accounts, rates of depreciation, the increase or decrease in retail rates and charges, the issuance of securities (other than evidences of indebtedness payable less than twelve months after the date of issue), the acquisition and sale of some public utility properties or securities and certain other matters.

Our tariff rates for electric service to retail customers consist of basic rates and charges and various adjustment mechanisms which are set and approved by the IURC after public hearings. Pursuant to statute, the IURC is to conduct a periodic review of the basic rates and charges of all Indiana utilities at least once every four years, but the IURC has the authority to review the rates of any Indiana utility at any time. Proceedings to review our basic rates and charges, which were last adjusted in 1996, involve IPL, the Indiana Office of Utility Consumer Counselor and other interested consumer groups and customers. In addition, we must seek approval from the IURC through such public proceedings of our tracking mechanism factors to reflect changes in our fuel costs to generate electricity or purchased power costs and for the timely recovery of costs incurred during construction and operation of Clean Coal Technology facilities constructed to comply with environmental laws and regulations and for certain other costs. There can be no assurance that we will be granted approval of tracking mechanism factors that we request from the IURC. The failure of the IURC to approve any requested relief, or any other adverse rate determination by the IURC could have a material adverse effect on our results of operations, financial condition, and cash flows.

In recent years, federal and state regulation of electric utilities has changed dramatically, and the pace of regulatory change is likely to pick up in coming years. As a result of the EPAct and subsequent legislation affecting the electric utility industry, we have been required to comply with new rules and regulations in areas including mandatory reliability standards, cyber security, transmission expansion and energy efficiency. These rules and regulations are, for the most part, still in their infancy. Regulatory agencies at the state and federal level are in the process of implementation. While we have complied with these rules and regulations to date without significant impact on our business, we are currently unable to predict the long term impact, if any, to our results of operations, financial condition, and cash flows.

Independent of the IURC’s ability to review basic rates and charges, Indiana law requires electric utilities under the jurisdiction of the IURC to meet operating expense and income test requirements as a condition for approval of requested changes in FAC. Additionally, customer refunds may result if a utility’s rolling twelve month operating income, determined at quarterly measurement dates, exceeds a utility’s authorized annual jurisdictional net operating income and there are not sufficient applicable cumulative net operating income deficiencies against which the excess rolling twelve month jurisdictional net operating income can be offset.

In September 2009, IPL received a letter from the staff of the IURC relevant to the IURC’s periodic review of IPL’s basic rates and charges which expressed concerns about IPL’s level of earnings and invited IPL to provide additional information. The staff of the IURC has since requested additional information relative to IPL’s level of earnings. In response, IPL provided information to the staff of the IURC. It is not possible to predict what impact, if any, the IURC’s review may have on IPL.

Additionally, in February 2009, an IPL customer sent a letter to the OUCC claiming IPL’s tree trimming practices were unreasonable and expressed concerns with language contained in IPL’s tariff that specifically addressed IPL’s tree trimming and tree removal rights. The OUCC forwarded the complaint to the IURC and in March 2009 the IURC initiated a docketed proceeding to investigate the matter. The same customer also separately filed an inverse condemnation lawsuit, purportedly as a class action, claiming that IPL’s trimming and/or removal of trees without payment of compensation to landowners constituted unconstitutional taking of private property.

In April 2009, the IURC initiated a generic state-wide investigation into electric utility tree trimming practices and tariffs. In December 2009, the IURC issued a docket entry, pending a final order in the generic investigation, that suspended certain language in IPL’s tariff regarding its right to trim or remove trees. In January 2010, the IURC held a hearing in the generic proceeding. We do not expect a ruling or final order before mid-year 2010. There has been very little activity in the civil suit during the IURC proceeding and no class has been certified. It is not possible to predict the outcome of the IURC investigation or the civil suit but, conceivably, either could significantly increase our vegetation management costs and the costs of defending our vegetation management program in litigation which could have a material impact on our consolidated financial statements.

Our participation in the Midwest ISO network involves risks.

We are a member of the Midwest ISO, a FERC approved regional transmission organization. The Midwest ISO serves the electrical transmission needs of much of the Midwest and maintains functional operational control over our electric transmission facilities as well as that of the other Midwest utility members of the Midwest ISO. We retain control over our distribution facilities. As a result of membership in the Midwest ISO and their operational control, our continued ability to import power, when necessary, and export power to the wholesale market has been, and may continue to be, impacted. We offer our generation and bid our load into this market on a day-ahead basis and settle differences in real time. Given the nature of the Midwest ISO’s policies regarding use of transmission facilities, and its administration of the energy and ancillary services markets, it is difficult to predict near term operational impacts. We cannot assure the Midwest ISO’s reliable operation of the regional transmission system, nor the impact of its operation of the energy and ancillary services markets.

At the federal level, there are business risks for us associated with multiple proceedings pending before the FERC related to our membership and participation in the Midwest ISO. These proceedings involve such issues as transmission rates, construction of new transmission facilities, evolving methodologies for socialized costs of regional transmission facilities, and MISO administered standards for resource adequacy including sanctions for non-compliance and forecasting error.

To the extent that we rely, at least in part, on the performance of the Midwest ISO to maintain the reliability of our transmission system, it puts us at some risk for the performance of the Midwest ISO. In addition, actions taken by the Midwest ISO to secure the reliable operation of the entire transmission system operated by the Midwest ISO could result in voltage reductions, rolling blackouts, or sustained system wide blackouts on IPL’s transmission and distribution system, any of which could have a material adverse effect on our results of operations, financial condition, or cash flows. (See also “Item 1. Business - Industry Matters - Midwest ISO Operations” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Regulatory Matters.”)

Our ownership by AES subjects us to potential risks that are beyond our control.

All of IPL’s common stock is owned by IPALCO, all of whose common stock is owned by AES. The interests of AES may differ from the interests of IPALCO, IPL or any of their creditors or other stakeholders. Further, due to our relationship with AES, any adverse developments and announcements concerning them may affect our ability to access the capital markets and to otherwise conduct business. In particular, downgrades in AES’s credit ratings could potentially result in IPL or IPALCO’s credit ratings being downgraded. IPL’s common stock is pledged to secure certain indebtedness of IPALCO, and IPALCO’s common stock is pledged to secure certain indebtedness of AES.

IPALCO is a holding company and is dependent on IPL for dividends to meet its debt service obligations.

IPALCO is a holding company with no material assets other than the common stock of its subsidiaries, and accordingly all cash is generated by the operating activities of our subsidiaries, principally IPL. None of IPALCO’s subsidiaries, including IPL, is obligated to make any payments with respect to its $375 million of 8.625% (original coupon 7.625%) Senior Secured Notes due November 14, 2011 and $400 million of 7.25% Senior Secured Notes due April 1, 2016; however, the common stock of IPL is pledged to secure payment of these notes. Accordingly, IPALCO’s ability to make payments on the 2011 IPALCO Notes and the 2016 IPALCO Notes is dependent not only on the ability of IPL to generate cash in the future, but also on the ability of IPL to distribute cash to IPALCO. IPL’s mortgage and deed of trust, its amended articles of incorporation and its Credit Agreement contain restrictions on IPL’s ability to issue certain securities or pay cash dividends to IPALCO. For example, there are restrictions on the maintenance of a leverage ratio and interest coverage ratio which could limit the ability of IPL or IPALCO to pay dividends. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources” for a discussion of these restrictions. See Note 11, “Indebtedness” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K for information regarding indebtedness.

We rely on access to the capital markets. General economic conditions and disruptions in the financial markets could adversely affect our ability to raise capital on favorable terms or at all, and cause increases in our interest expense.

From time to time we rely on access to capital markets as a source of liquidity for capital requirements not satisfied by operating cash flows. Over the past two years conditions in the financial markets have been unprecedented and continue to fluctuate, which has reduced the availability of capital and credit. If these conditions continue or worsen, our ability to raise capital on favorable terms or at all could be adversely affected, and we may be unable to access adequate funding to refinance our debt as it becomes due or finance capital expenditures. The extent of any impact will depend on several factors, including our operating cash flows, the duration of tight credit conditions and volatile equity markets, our credit ratings, credit capacity, the cost of financing, and other general economic and business conditions. It may also depend on the performance of counterparties and financial institutions with which we do business.

See Note 11, “Indebtedness” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K for information regarding indebtedness. See also “Item 7A. Quantitative and Qualitative Disclosure about Market Risk - Credit Market Risk” for information related to credit market risks.

The level of our indebtedness, and the security provided for this indebtedness, could adversely affect our financial flexibility.

As of December 31, 2009, we had on a consolidated basis $1.7 billion of long-term indebtedness and total common shareholder’s deficit of $9.1 million. IPL had $837.7 million of First Mortgage Bonds outstanding as of December 31, 2009, which are secured by the pledge of substantially all of the assets of IPL under the terms of IPL’s mortgage and deed of trust. IPL also had $100 million of unsecured indebtedness. This level of indebtedness and related security could have important consequences, including the following:

increase our vulnerability to general adverse economic and industry conditions;
require us to dedicate a substantial portion of our cash flow from operations to make payments on our indebtedness, thereby reducing the availability of our cash flow to fund other corporate purposes;
limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
limit, along with the financial and other restrictive covenants in our indebtedness, among other things, our ability to borrow additional funds, as needed.

We expect to incur additional debt in the future, subject to the terms of our debt agreements and regulatory approvals for any IPL debt. To the extent we become more leveraged, the risks described above would increase. Further, our actual cash requirements in the future may be greater than expected. Accordingly, our cash flow from operations may not be sufficient to repay at maturity all of the outstanding debt as it becomes due and, in that event, we may not be able to borrow money, sell assets or otherwise raise funds on acceptable terms or at all to refinance our debt as it becomes due. For a further discussion of outstanding debt, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources.”

Current and future conditions in the economy may adversely affect our customers, suppliers and counterparties, which may adversely affect our results of operations, financial condition, and cash flows.

Our business, results of operations, financial condition, and cash flows have been and will continue to be affected by general economic conditions. As a result of slowing global economic growth, the credit market crisis, declining consumer and business confidence, fluctuating commodity prices, and other challenges currently affecting the general economy, some of our customers are experiencing and may continue to experience deterioration of their businesses, cash flow shortages, and difficulty obtaining financing. As a result, existing customers may reduce their electricity consumption and may not be able to fulfill their payment obligations to us in the normal, timely fashion. In addition, some existing commercial and industrial customers may discontinue their operations. Projects which may result in potential new customers will likely be delayed until economic conditions improve.

At times, we may utilize forward contracts to manage the risk associated with power purchases and wholesale power sales, and could be exposed to counter-party credit risk in these contracts. Further, some of our suppliers, customers and other counterparties, and others with whom we transact business may be experiencing financial difficulties, which may impact their ability to fulfill their obligations to us. For example, our counterparties on the interest rate swap, forward purchase contracts, and financial institutions involved in our credit facility may become unable to fulfill their contractual obligations. We may not be able to enter into replacement agreements on terms as favorable as our existing agreements. If the general economic slowdown continues for significant periods or deteriorates significantly, our results of operations, financial condition, and cash flows could be materially adversely affected. In particular, the projected economic growth and total employment in Indianapolis are important to the realization of our forecasts for annual energy sales growth. A continued downturn in the Indianapolis economy could adversely affect our expected performance.

Wholesale power marketing activities may add volatility to earnings.

We engage in wholesale power marketing activities that primarily involve the offering of utility-owned or contracted generation into the MISO hourly and real time markets. As part of these strategies, we may also execute energy contracts that are integrated with portfolio requirements around power supply and delivery. The earnings from wholesale marketing activities may vary based on fluctuating prices for electricity and the amount of electric generating capacity or purchased power available, beyond that needed to meet firm service requirements. In order to reduce the risk of volatility in earnings from wholesale marketing activities, we may at times enter into forward contracts to hedge such risk. If we do not accurately forecast future commodities prices or if our hedging procedures do not operate as planned we may experience losses. As of December 31, 2009 and December 31, 2008, no such hedges were in place.

In addition, under the current Midwest ISO market rules (which are under review), the introduction of additional renewable energy into the Midwest ISO market could have the affect of reducing the demand for wholesale energy from other sources. Under these rules, renewable energy sources are given priority in the Midwest ISO market as “must run” units. The additional generation produced by renewable energy sources could have the impact of reducing market prices for energy and could reduce our opportunity to sell into the Midwest ISO market, thereby reducing our wholesale sales.

Parties providing construction materials or services may fail to perform their obligations, which could harm our results of operations, financial condition, and cash flows.

Our construction program calls for extensive expenditures for capital improvements and additions, including the installation of environmental upgrades, improvements to transmission and distribution facilities as well as other initiatives. As a result, we have engaged, and will continue to engage, numerous contractors and have entered into a number of agreements to acquire the necessary materials and/or obtain the required construction related services. This exposes us to the risk that these contractors and other counterparties could fail to perform. In addition, some contracts provide for us to assume the risk of price escalation and availability of certain metals and key components. This could force us to enter into alternative arrangements at then-current market prices that may exceed our contractual prices and cause construction delays. It could also subject us to enforcement action by regulatory authorities to the extent that such a failure resulted in a failure to comply with requirements or expectations. Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than these mitigation provisions. This would adversely affect our financial results, and we might incur losses or delays in completing construction.

We could incur significant capital expenditures to comply with environmental laws and regulations and/or material fines for noncompliance with environmental laws and regulations.

We are subject to various federal, state and local environmental protection and health and safety laws and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of hazardous materials; the emission and discharge of hazardous and other materials into the environment; and the health and safety of our employees. These laws and regulations often require a lengthy and complex process of obtaining and renewing permits and other governmental authorizations from federal, state and local agencies. A violation of these laws, regulations or permits can result in substantial fines, other sanctions, and permit revocation and/or facility shutdowns. The amount of capital expenditures required to comply with environmental laws or regulations could be impacted by the outcome of the EPA’s NOV described in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Environmental Matters” in which EPA alleges that several physical changes to IPL’s generating stations were made in noncompliance with existing environmental laws. This NOV from the EPA may also result in a fine which could be material.

While we believe IPL operates in compliance with applicable environmental requirements, from time to time the company is subject to enforcement actions for claims of noncompliance. IPL cannot assure that it will be successful in defending against any claim of noncompliance. Under certain environmental laws, we could be held responsible for costs relating to contamination at our past or present facilities and at third party waste disposal sites. We could also be held liable for human exposure to such hazardous substances or for other environmental damage. We cannot assure that our costs of complying with current and future environmental and health and safety laws, and our liabilities arising from past or future releases of, or exposure to, hazardous substances will not adversely affect our business, results of operations, financial condition, and cash flows. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Environmental Matters” for a more comprehensive discussion of environmental matters impacting IPL and IPALCO.

Regulators, politicians, non-governmental organizations and other private parties have expressed concern about greenhouse gas, or GHG, emissions and are taking actions which, in addition to the potential physical risks associated with climate change, could have a material adverse impact on our consolidated results of operations, financial condition and cash flows.

At the federal and various regional and state levels, policies are under development to regulate GHG emissions, thereby effectively putting a cost on such emissions in order to create financial incentives to reduce them. In 2009, IPL emitted 17 million tons of carbon dioxide from our power plants. IPL uses CO2 emission estimation methodologies supported by “The Greenhouse Gas Protocol” reporting standard on GHG emissions. Our CO2 emissions are calculated from actual fuel heat inputs and fuel type CO2 emission factors.

Any federal, state or regional regulation of GHG emissions that may be promulgated could have a material adverse impact on our financial performance. The actual impact on our financial performance will depend on a number of factors, including among others, the degree and timing of GHG emissions reductions required under any such legislation or regulations, the price and availability of offsets, the extent to which market based compliance options are available, the extent to which we would be entitled to receive GHG emissions allowances without having to purchase them in an auction or on the open market and the impact of such legislation or regulation on our ability to recover costs incurred through rate increases or otherwise. As a result of these factors, our cost of compliance could be substantial and could have a material impact on our results of operations. Another factor is the success of our GHG Emissions Reduction Projects, which may generate credits that will help offset our GHG emissions.

In January 2005, based on European Community “Directive 2003/87/EC on Greenhouse Gas Emission Allowance Trading,” the European Union Greenhouse Gas Emission Trading Scheme commenced operation as the largest multi-country GHG emission trading scheme in the world. On February 16, 2005, the Kyoto Protocol became effective. The Kyoto Protocol requires the 40 developed countries that have ratified it to substantially reduce their GHG emissions, including CO2. To date, the Kyoto Protocol and the European Union Greenhouse Gas Emission Trading Scheme have not had a material adverse effect on IPALCO’s consolidated results of operations, financial condition and cash flows.

The United States has not ratified the Kyoto Protocol. In the United States, there currently are no federal mandatory GHG emission reduction programs (including CO2) affecting our electric power generation facilities. However, there is federal GHG legislation pending before the U.S. Congress that would, if enacted, constrain GHG emissions, including CO2, and/or impose costs on us that could be material to our business or results of operations. There is also a proposed EPA regulation that could result in a requirement for all new sources of GHG emissions over 250 tons per year, and existing sources planning physical changes that would increase their GHG emissions over certain “significant” emission thresholds to obtain new source review permits from the EPA prior to construction.

In addition to government regulators, other groups such as politicians, environmentalists and other private parties have expressed increasing concern about GHG emissions. For example, certain financial institutions have expressed concern about providing financing for facilities which would emit GHGs, which can affect our ability to obtain capital, or if we can obtain capital, to receive it on commercially viable terms. In addition, rating agencies may decide to downgrade our credit ratings based on our emissions or increased compliance costs which could make financing unattractive. In addition, environmental groups and other private plaintiffs may decide to bring private lawsuits against us because of our GHG emissions, unless the U.S. Congress acts to preempt such suits as part of comprehensive federal legislation. Consequently, it is impossible to determine whether such lawsuits are likely to have a material adverse effect on our consolidated results of operations and financial condition.

Furthermore, according to the Intergovernmental Panel on Climate Change, physical risks from climate change could include, but are not limited to, increased runoff and earlier spring peak discharge in many glacier and snow fed rivers, warming of lakes and rivers, an increase in sea level, changes and variability in precipitation and in the intensity and frequency of extreme weather events. Physical impacts may have the potential to significantly affect our business and operations. For example, extreme weather events could result in increased downtime and operation and maintenance costs at our electric power generation facilities and our support facilities. Variations in weather conditions, primarily temperature and humidity, attributable to climate change also would be expected to affect the energy needs of customers. A decrease in energy consumption could decrease our revenues. In addition, while revenues would be expected to increase if the energy consumption of customers increased, such increase could prompt the need for additional investment in generation capacity. Changes in the temperature of lakes and rivers and changes in precipitation that result in drought could adversely affect the operations of our fossil-fuel fired electric power generation facilities. If any of the foregoing risks materialize, costs may increase or revenues may decrease and there could be a material adverse effect on our electric power generation businesses and on our consolidated results of operations, financial condition and cash flows.

Regulatory initiatives regarding CO2 may be implemented in the future, although at this time we cannot predict if, how, or to what extent such initiatives would affect us. Generally, we believe costs to comply with any regulations implemented to reduce GHG emissions would be deemed as part of the costs of providing electricity to our customers and as such, we would seek recovery for such costs in our rates. However, no assurance can be given as to whether the IURC will approve such requests. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Environmental Matters” for a more comprehensive discussion of environmental matters impacting IPL and IPALCO.

Commodity price changes may affect the operating costs and competitive position of our business.

Our business is sensitive to changes in the price of coal, the primary fuel we use to produce electricity, and to a lesser extent, to the changes in the prices of natural gas, purchased power and emissions allowances. In addition, changes in the prices of steel, copper and other raw materials can have a significant impact on our costs. Any changes in coal prices could affect the prices we charge, our operating costs and our competitive position with respect to our products and services. While we have approximately 90% of our current coal requirements for the three-year period ending December 31, 2012 under long-term contracts, the balance is yet to be purchased and will be purchased under a combination of long-term contracts, short-term contracts and on the spot market. Prices can be volatile in both short-term market and on the spot market. Pricing provisions in some of our long-term coal contracts allow for price changes under certain circumstances. We are also dependent on purchased power, in part, to meet our seasonal planning reserve margins. Our exposure to fluctuations in the price of coal is limited because pursuant to Indiana law, we may apply to the IURC for a change in our FAC every three months to recover our estimated fuel costs, which may be above or below the levels included in our basic rates. In addition, we may recover the energy portion of our purchased power costs in these quarterly FAC proceedings. We must present evidence in each proceeding that we have made every reasonable effort to acquire fuel and generate or purchase power or both so as to provide electricity to our retail customers at the lowest fuel cost reasonably possible.

We are subject to employee workforce factors that could affect our businesses, results of operations, financial condition, and cash flows.

We are subject to employee workforce factors, including, among other things, loss or retirement of key personnel (approximately 50% of our employees are over the age of 50), availability of qualified personnel, and collective bargaining agreements with employees who are members of a union. Approximately 65% of our employees are represented by the International Brotherhood of Electrical Workers. We may not be able to successfully train new personnel as current workers with significant knowledge and expertise retire. We also may be unable to staff our business with qualified personnel in the event of significant absenteeism related to a pandemic illness. Work stoppages or other workforce issues could affect our businesses, results of operations, financial condition, and cash flows.

Economic conditions relating to the asset performance and interest rates of the Employees’ Retirement Plan of Indianapolis Power & Light Company and Supplemental Retirement Plan of Indianapolis Power & Light Company could materially impact our results of operations, financial condition, and cash flows.

Pension costs are based upon a number of actuarial assumptions, including an expected long-term rate of return on pension plan assets, level of employer contributions, the expected life span of pension plan beneficiaries and the discount rate used to determine the present value of future pension obligations. Any of these assumptions could prove to be wrong, resulting in a shortfall of our Pension Plans’ assets compared to pension obligations under the Pension Plans. We are responsible for funding any shortfall of Pension Plans’ assets compared to pension obligations under the Pension Plans, and a significant increase in our pension liabilities could materially impact our results of operations, financial condition, and cash flows. The Pension Protection Act of 2006, which contains comprehensive pension funding reform legislation, was enacted into law during the third quarter of 2006. The pension funding provisions are effective January 1, 2008. The Pension Protection Act of 2006 requires plans that are less than 100% funded to fully fund any funding shortfall in amortized level installments over seven years, beginning in the year of the shortfall. In addition, we must also contribute the normal service cost earned by active participants during the plan year. Then, each year thereafter, if the plan’s underfunding increases to more than the present value of the remaining annual installments, the excess is separately amortized over a new seven year period.

Please see Note 13, “Pension and Other Postretirement Benefits” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K for further discussion.

From time to time, we are subject to material litigation and regulatory proceedings.

We may be subject to material litigation, regulatory proceedings, administrative proceedings, settlements, investigations and claims from time to time. There can be no assurance that the outcome of these matters will not have a material adverse effect on our business, results of operations, financial condition, and cash flows. Please see Note 4, “Regulatory Matters” and Note 14, “Commitments and Contingencies” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K for a summary of significant regulatory matters and legal proceedings involving us.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 1C. DEFINED TERMS


DEFINED TERMS
The following is a list of frequently used abbreviations or acronyms that are found in this Form 10-K:

1995B Bonds	$40 Million City of Petersburg, Indiana, Pollution Control Refunding Revenue Bonds Adjustable Rate Tender Securities Series 1995B, Indianapolis Power & Light Company Project
2008 IPALCO Notes	$375 million of 8.375% (original coupon 7.375%) Senior Secured Notes due November 14, 2008
2011 IPALCO Notes	$375 million of 8.625% (original coupon 7.625%) Senior Secured Notes due November 14, 2011
2016 IPALCO Notes	$400 million of 7.25% Senior Secured Notes due April 1, 2016
AES	The AES Corporation
ASC	Financial Accounting Standards Board Accounting Standards Codification
ASM	Ancillary Services Market
BART	Best Available Retrofit Technology
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CCB	Coal Combustion Byproducts
CCT	Clean Coal Technology
CO₂	Carbon Dioxide
Defined Benefit Pension Plan	Employees’ Retirement Plan of Indianapolis Power & Light Company
ECCRA	Environmental Compliance Cost Recovery Adjustment
EPA	U.S. Environmental Protection Agency
EPAct	Energy Policy Act of 2005
Exchange Act	Securities Exchange Act of 1934, as amended
FAC	Fuel Adjustment Charges
FERC	Federal Energy Regulatory Commission
GHG	Greenhouse Gas
IPALCO	IPALCO Enterprises, Inc.
IPL	Indianapolis Power & Light Company
IURC	Indiana Utility Regulatory Commission
kWh	Kilowatt hours
MW	Megawatt
Midwest ISO	Midwest Independent Transmission System Operator, Inc.
NAAQS	National Ambient Air Quality Standards
NOV	Notice of Violation
NOx	Nitrogen Oxides
Pension Plans	Employees’ Retirement Plan of Indianapolis Power & Light Company and Supplemental Retirement Plan of Indianapolis Power & Light Company
RFC	ReliabilityFirst Corporation
RSG	Revenue Sufficiency Guarantee
RSP	AES Retirement Savings Plan
SO2	Sulfur Dioxide
S&P	Standard & Poors
Thrift Plan	Employees’ Thrift Plan of Indianapolis Power & Light Company

ITEM 2. PROPERTIES

Our executive offices are located at One Monument Circle, Indianapolis, Indiana. This facility and the remainder of our material properties in our business and operations are owned directly by Indianapolis Power & Light Company. The following is a description of these material properties.

We own two distribution service centers in Indianapolis. We also own the building in Indianapolis which houses our customer service center.

We own and operate four generating stations. Two of the generating stations are primarily coal-fired stations. The third station has a combination of units that use coal (base load capacity) and natural gas and/or oil (peaking capacity) for fuel to produce electricity. The fourth station is a small peaking station that uses gas-fired combustion turbine technology for the production of electricity. For electric generation, the net winter capability is 3,492 MW and net summer capability is 3,353 MW. Our highest summer peak load of 3,139 MW was recorded in August 2007 and the highest winter peak load of 2,971 MW was recorded in January 2009.

Our sources of electric generation are as follows:


Fuel	Name	Number of Units	Winter Capacity (MW)	Summer Capacity (MW)	Location

Coal	Petersburg	4	1,752	1,752	Pike County, Indiana
	Harding Street	3	645	639	Marion County, Indiana
	Eagle Valley	4	263	260	Morgan County, Indiana
	Total	11	2,660	2,651
Gas	Harding Street	3	385	322	Marion County, Indiana
	Georgetown	2	200	158	Marion County, Indiana
	Total	5	585	480
Oil	Petersburg	3	8	8	Pike County, Indiana
	Harding Street	6	158	133	Marion County, Indiana
	Eagle Valley	3	81	81	Morgan County, Indiana
	Total	12	247	222
Grand Total		28	3,492	3,353

Net electrical generation during 2009, at the Petersburg, Harding Street, Eagle Valley and Georgetown plants, accounted for approximately 69.3%, 24.1%, 6.5% and less than 0.1%, respectively, of our total net generation.

Our electric system is directly interconnected with the electric systems of Indiana Michigan Power Company, Vectren Corporation, Hoosier Energy Rural Electric Cooperative, Inc., and the electric system jointly owned by Duke Energy Indiana, Indiana Municipal Power Agency and Wabash Valley Power Association, Inc. Our transmission system includes 457 circuit miles of 345,000 volt lines and 363 circuit miles of 138,000 volt lines. The distribution system consists of 4,640 circuit miles underground primary and secondary cables and 6,168 circuit miles of overhead primary and secondary wire. Underground street lighting facilities include 725 circuit miles of underground cable. Also included in the system are 75 bulk power substations and 88 distribution substations.

We hold an option, through 2013, to purchase suitable acreage of land in Switzerland County, Indiana to use as a potential power plant site. In addition, IPL owns the mineral rights underlying approximately 5,875 acres in Pike and Gibson Counties, Indiana.

All of our critical facilities are well maintained, in good condition and meet our present needs. Currently, our plants generally have enough capacity to meet the needs of our retail customers when all of our units are available. During periods when our generating capacity is not sufficient to meet our retail demand, we purchase power on the wholesale market.

MORTGAGE FINANCING ON PROPERTIES

The mortgage and deed of trust of IPL, together with the supplemental indentures to the mortgage, secure first mortgage bonds issued by IPL. Pursuant to the terms of the mortgage, substantially all property owned by IPL is subject to a direct first mortgage lien in the amount of $837.7 million at December 31, 2009. In addition, IPALCO has $375 million of 8.625% (original coupon 7.625%) Senior Secured Notes due November 14, 2011 and $400 million of 7.25% Senior Secured Notes due April 1, 2016 outstanding which are secured by its pledge of all of the outstanding common stock of IPL.

ITEM 3. LEGAL PROCEEDINGS

Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Environmental Matters,” and Note 4, “Regulatory Matters” and Note 14, “Commitments and Contingencies” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K for a summary of significant legal proceedings involving us. We are also subject to routine litigation, claims and administrative proceedings arising in the ordinary course of business.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Not applicable pursuant to General Instruction I of the Form 10-K.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASE OF EQUITY SECURITIES

All of the outstanding common stock of IPALCO is owned by AES, and as a result is not listed for trading on any stock exchange.

Dividends

During 2009, 2008 and 2007, we paid dividends to AES totaling $70.9 million, $71.6 million and $85.8 million, respectively. Future distributions will be determined at the discretion of the Board of Directors of IPALCO and will depend primarily on dividends received from Indianapolis Power & Light Company and such other factors as the Board of Directors of IPALCO deems relevant. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources” of this Form 10-K for a discussion of limitations on dividends from IPL. In order for us to make any dividend payments to AES, we must, at the time and as a result of such dividends, either maintain certain credit ratings on the 2011 IPALCO Notes or be in compliance with leverage and interest coverage ratios contained in the Indenture for such notes. We do not believe this requirement will be a limiting factor in paying dividends in the ordinary course of prudent business operations.

ITEM 6. SELECTED FINANCIAL DATA

The following table presents our selected consolidated financial data. This data should be read in conjunction with our audited Consolidated Financial Statements and the related notes thereto and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The “Results of Operations” discussion in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” addresses significant fluctuations in operating data. IPALCO is a wholly-owned subsidiary of AES and therefore does not report earnings or dividends on a per-share basis. Other data that management believes is important in understanding trends in our business are also included in this table.


	Year Ended December 31,
	2009		2008		2007		2006		2005
	(In Thousands)
Operating Data:
Total utility operating revenues	$	1,068,081	$	1,079,113	$	1,052,627	$	1,032,051	$	951,079
Utility operating income		169,957		181,893		210,418		179,503		208,728
Allowance for funds used during construction		3,632		2,292		7,445		5,350		3,646
Net income		73,768		74,665		125,329		95,629		117,142

Balance Sheet Data (end of period):
Utility plant - net		2,321,676		2,341,072		2,347,406		2,248,045		2,165,391
Total assets		3,035,345		3,102,411		2,841,941		2,807,965		2,573,156
Common shareholder’s deficit⁽¹⁾		(9,058)		(9,909)		(11,238)		(50,682)		(126,401)
Cumulative preferred stock of subsidiary		59,784		59,784		59,784		59,135		59,135
Long-term debt (less current maturities)		1,706,695		1,666,085		1,271,558		1,481,516		1,443,316
Long-term capital lease obligations		28		301		729		1,546		2,401

Other Data:
Utility capital expenditures		115,363		106,906		201,060		195,009		112,207

⁽¹⁾ Upon the application of the Financial Accounting Standards Board Accounting Standards Codification 715 “Compensation - Retirement Benefits,” we reclassified $72.1 million from Accumulated Other Comprehensive Loss to Regulatory Assets for 2006.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our audited Consolidated Financial Statements and the notes thereto included in “Item 8. Financial Statements and Supplementary Data” of this Form 10-K. The following discussion contains forward-looking statements. Our actual results may differ materially from the results suggested by these forward-looking statements. Please see “Cautionary Note Regarding Forward - Looking Statements” at the beginning of this Form 10-K and “Item 1A. Risk Factors.” For a list of certain abbreviations or acronyms in this discussion, see “Item 1C. Defined Terms” included in Part I of this Form 10-K.

EXECUTIVE OVERVIEW

The most important matters on which we focus in evaluating our financial condition and operating performance and allocating our resources include: (i) recurring factors which have significant impacts on operating performance such as: regulatory action, environmental matters, weather and weather-related damage in our service area, our ability to sell power in the wholesale market at a profit, and the local economy; (ii) our progress on performance improvement strategies designed to maintain high standards in several operating areas (including safety, environmental, reliability, and customer service) simultaneously; and (iii) our short-term and long-term financial and operating strategies. For a discussion of how we are impacted by regulation and environmental matters, please see “Liquidity and Capital Resources - Regulatory Matters” and “Liquidity and Capital Resources - Environmental Matters” later in this section and “Item 1. Business.”

Weather and weather-related damage in our service area.

Extreme high and low temperatures in our service area have a significant impact on revenues as many of our retail customers use electricity to power air conditioners, electric furnaces and heat pumps. The effect is generally more significant with high temperatures than with low temperatures as many of our customers use gas heat. To illustrate, during the third fiscal quarter of 2008, when our service territory experienced a 22.4% decrease in cooling degree days as compared to the same period in 2007, we realized a 4.5% decrease in net retail revenues (excluding revenues from tracker mechanisms such as fuel and environmental costs - see “Liquidity and Capital Resources - Regulatory Matters”) primarily due to weather. In addition, because extreme temperatures have the effect of increasing demand for electricity, the wholesale price for electricity generally increases during periods of extreme hot or cold weather and, therefore, if we have available capacity not needed to serve our retail load, we may be able to generate additional income by selling power on the wholesale market (see below).

Storm activity can also have an adverse effect on our operating performance. Severe storms often damage transmission and distribution equipment, which can cause power outages, which reduces revenues and increases repair costs. To illustrate, storm related operating expenses (primarily repairs and maintenance) were $1.8 million, $5.3 million and $0.5 million in 2009, 2008 and 2007, respectively. During 2008, we experienced unusually high severe storm activity, while 2007 was relatively mild and 2009 had a normal amount of storm activity.

Our ability to sell power in the wholesale market at a profit.

At times, we will purchase power on the wholesale markets, and at other times we will have electric generation available for sale on the wholesale market in competition with other utilities and power generators. During the past five years, wholesale revenues represented 6% of our total electric revenues on average. Our ability to be dispatched in the Midwest ISO market to sell power is primarily impacted by the locational market price of electricity and our variable generation costs. The amount of electricity we have available for wholesale sales is impacted by our retail load requirements, our generation capacity and our unit availability. From time to time, we must shut generating units down to perform maintenance or repairs. Generally, maintenance is scheduled during the spring and fall months when demand for power is lowest. Occasionally, it is necessary to shut units down for maintenance or repair during periods of high power demand. For example, during 2008, we had outages at a coal fired unit related to performance issues related to CCT placed in service in 2007. See also, “Liquidity and Capital Resources - Regulatory Matters” for information about our participation in the Midwest ISO that impacts both revenues and costs associated with our energy service to our utility customers. The price of wholesale power in the Midwest ISO market can be volatile and therefore our revenues from wholesale sales can fluctuate significantly from year to year. The weighted average price of wholesale kWhs we sold was $26.62, $48.31, and $41.70 in 2009, 2008 and 2007, respectively.

Local economy.

The local economy is currently suffering like the global economy as evidenced by an elevated unemployment rate in Indianapolis, Indiana which approximates the national average. During 2009, 41% of our revenues came from large commercial and industrial customers. In total, retail kWh sales were down 6% in 2009 as compared to 2008. During the past 10 years, our total retail kWh sales have grown at a compound annual rate of 0.3%. Such rate for the 10 years ending 2008 was 1.2%. This decline illustrates the impact of the economic recession, as well as the mild weather in 2009. Please see also, “Impact of Weak Economic Conditions,” below for further discussion of current economic conditions.

Operational Excellence.

Our objective is to achieve top industry performance in the United States utility industry by focusing on performance in seven key areas: safety, the environment, customer satisfaction, reliability (production and delivery), financial performance (retail rates and shareholder value), employee engagement and community leadership. We set and measure these objectives carefully, balancing them in a way and to a degree necessary to ensure a sustainable high level of performance in these areas simultaneously as compared to our peers. We monitor our performance in these areas, and where practical and meaningful, compare performance in some areas to peer utilities. Because employee engagement and community leadership are company specific performance goals, they are not benchmarked.

During 2009, our safety performance was very near our 2008 performance, which is better than top quartile in our industry in both lost work day and severity rates. Our customer satisfaction rating, as measured through the annual JD Power residential electric survey, was consistent relative to our midwestern peers. While our performance in reliability (delivery and production) was unfavorable to previous years due to an unusually high incidence of lightning and unscheduled outages at our power plants, we have initiated process improvements to restore performance to target levels.

Short-term and long-term financial and operating strategies.

Our financial management plan is closely integrated with our operating strategies. Our objective is to maintain stand-alone credit statistics at IPL that are comparable to investment grade credit ratings. Key aspects of our financial planning include rigorous budgeting and analysis, maintaining sufficient levels of liquidity and a prudent dividend policy at both our subsidiary and holding company levels. This strategy allows us to remain flexible in the face of evolving environmental legislation and regulatory initiatives in our industry, as well as weak economic conditions.

IMPACTS OF WEAK ECONOMIC CONDITIONS

The United States and global economies have experienced significant turmoil, including an economic recession, a crisis in the credit markets, and significant volatility in the equity markets. The timing and extent of the recovery is unknown, and much uncertainty still exists in the Unites States and global economies and the credit and equity markets. While currently not material to our liquidity or ability to service our debts, we nonetheless have been affected by the weak economic conditions on several fronts and have taken steps to lessen its impact.

Impact on Operating Results

There has been a significant decrease in average wholesale electric prices in our region since the recession began, due primarily to the decline in demand for power and the decline in market prices of fuel (primarily natural gas and coal). Over the past five years, wholesale revenues represented 6% of our total electric revenue on average. Because most of our nonfuel costs are fixed in the short term, a decline in wholesale prices can have a significant impact on earnings. During the year ended December 31, 2009 as compared to 2008 we experienced a $40.9 million unfavorable price variance on our wholesale revenues, which was partially offset by reduced fuel costs. The weighted average price of wholesale kWhs we sold was $26.62, $48.31, and $41.70 in 2009, 2008 and 2007, respectively.

The economic recession and, to a lesser extent, the mild temperatures of 2009 led to a 6.1% decrease in retail energy sales volume during 2009 as compared to 2008. This decrease resulted in a $49.4 million unfavorable retail volume variance in revenues in the comparable periods. IPL is generally able to sell excess energy in the wholesale markets; however as described above wholesale prices were significantly lower on average in 2009, so the drop in retail demand was only partially mitigated by increased wholesale sales volume. We believe demand for energy will increase over time, but we do not expect it to return to 2008 levels quickly.

To counteract the impacts of the recession on our operating results in 2009, we have implemented several initiatives, including but not limited to the following examples. First, we have reduced operating costs by maximizing our efficiencies in manpower resulting in a 3.3% decrease in full time employees during 2009, primarily through attrition. Secondly, we have closely analyzed repairs and maintenance activities and were able to eliminate or postpone certain discretionary projects leading to a $19.0 million decrease in maintenance expense in 2009 as compared to the amount we originally budgeted, even though such costs still increased versus 2008. We expect maintenance costs to increase in 2010 as some of the projects were shifted from 2009 to 2010. Thirdly, as described in further detail below, our repurchase of the $40 Million City of Petersburg, Indiana, Pollution Control Refunding Revenue Bonds Adjustable Rate Tender Securities Series 1995B, Indianapolis Power & Light Company Project Bonds reduced our effective interest rate on the 1995B Bonds, including the liquidity facility and interest rate swap agreement from approximately 12% per annum to approximately 5.67% per annum. Lastly, as described in further detail below, IPL had $131.9 million of auction rate securities that had experienced failed auctions during portions of 2008 and 2009, resulting in IPL being liable for interest at 12% per annum. During 2009, we refinanced this debt to a fixed rate of 4.9% per annum.

Also, on a positive note, during 2009 the recession has had the effect of halting the rapid inflation on certain raw materials, including steel, copper and other commodities that we experienced over the previous few years to the point where some costs have even declined. These and other raw materials serve as inputs to many operating and maintenance processes fundamental to the electric utility industry. Lower prices reduce our operating and maintenance costs and improve our liquidity.

Impact on Indebtedness

The recession and crisis in the credit markets has provided us with some liquidity challenges as well. In 2008, we were liable for principal and interest on three series of auction rate securities totaling $131.9 million. IPL’s liability on these auction rate securities was secured by its first mortgage bonds. While the securities had long term maturities, the interest rates were variable and were set weekly through an auction process. Beginning in late September 2008, the auctions failed on these securities and as a result, the interest rates were reset to the maximum rates of 12% per annum on each series. This rate is in effect every time the auctions fail. In January 2009, the IURC issued an order approving IPL’s financing petition filed in August 2008 requesting authority to refinance all of our auction rate securities as well as the 1995B Bonds (see below).

In June 2009, the Indiana Finance Authority issued on behalf of IPL an aggregate principal amount of $131.9 million of 4.90% Environmental Facilities Refunding Revenue Bonds (Indianapolis Power & Light Company Project) due January 2016. These bonds were issued in three series: $41.9 million Series 2009A Bonds, $30 million Series 2009B Bonds, and $60 million 2009C Bonds. IPL issued $131.9 million aggregate principal amount of first mortgage bonds to the IFA to secure the loan of proceeds from these series of bonds issued by the IFA. Proceeds of these bonds were used to retire $131.9 million of existing IPL first mortgage bonds issued in the form of auction rate securities.

IPL is also liable for interest and principal on the 1995B Bonds. Interest on the 1995B Bonds varied weekly and was set through a remarketing process. IPL maintains a $40.6 million long-term liquidity facility supporting the 1995B Bonds. The liquidity facility expires in May 2011. IPL also entered into an interest rate swap agreement to hedge our interest rate exposure on the 1995B Bonds. The interest rate is synthetically fixed at 5.21% per annum through this interest rate swap agreement.

During several months in the second half of 2008 and during January of 2009, as much as $39.6 million of the 1995B Bonds were not successfully remarketed and were therefore tendered to the trustee. In accordance with the terms of IPL’s committed liquidity facility, the trustee drew $39.7 million against this facility to fund the tender and related accrued interest. As specified in the swap agreement, while the 1995B Bonds were not being remarketed, the swap counterparty exercised its right to pay interest to IPL at the alternative floating rate, which applied to the 1995B Bonds that were not remarketed, instead of the cost of funds rate. As a result of the tender, the trustee held the $39.6 million of the 1995B Bonds on IPL’s behalf on December 31, 2008. Beginning in January through August of 2009, all of these 1995B Bonds were successfully remarketed and the trustee no longer held those bonds on IPL’s behalf.

Beginning on May 6, 2009, as a result of the bond insurer’s credit downgrades, the swap counterparty again exercised its right to pay interest to IPL at the alternative floating rate. As a result, IPL’s effective interest rate for the 1995B Bonds as of August 31, 2009, including the interest rate swap agreement, increased from 5.21% to approximately 12% per annum.

In September 2009, in accordance with the terms of the 1995B Bonds, IPL converted the 1995B Bonds from tax-exempt weekly interest rate mode to commercial paper mode and directed the remarketing agent to no longer remarket the 1995B Bonds. In connection with this conversion all of the outstanding 1995B Bonds were tendered back to the trustee. In accordance with the terms of IPL’s committed liquidity facility, the trustee drew $40 million against this facility to fund the tender and the trustee is again holding the 1995B Bonds on IPL’s behalf. In accordance with the terms of the 1995B Bonds, these bonds do not bear interest while in commercial paper mode since they are being held by the trustee IPL is liable for the interest and principal on the liquidity facility. IPL also continues to be liable to the swap counterparty for 5.21% interest rate and the swap counterparty continues to exercise its right to pay interest to IPL at the alternative floating rate. As of the end of 2009, our effective interest rate on the 1995B Bonds, including the liquidity facility and interest rate swap agreement was approximately 5.67% per annum. All of the 1995B Bonds remain outstanding and IPL remains liable for payment of interest and principal thereon, even though the 1995B Bonds are being held by the trustee on behalf of IPL. Given the volatility in the market, we continue to evaluate our alternatives with regard to refinancing this debt.

In addition, we have undertaken certain initiatives, including the refinancing of $375 million of 8.375% (original coupon 7.375%) Senior Secured Notes due November 14, 2008 in the second quarter of 2008, which helped preserve our liquidity and improved our financial flexibility. For additional information on the refinancing, see “Liquidity and Capital Resources - Capital Resources - Indebtedness.” As a result of this refinancing, we do not have any long-term indebtedness maturing until 2011. There are also no borrowings outstanding on the working capital portion of our credit facility and we have cash and cash equivalents of $48.0 million as of December 31, 2009. Therefore, we do not anticipate a need for new long-term financings until 2011. As a result of these initiatives and other factors, we believe that existing cash balances, short-term investments, cash generated from operating activities and borrowing capacity on our committed credit facility will be adequate on a short-term and long-term basis to meet anticipated operating expenses, interest expense on outstanding indebtedness and recurring capital expenditures. See “Liquidity and Capital Resources” for further discussion of our liquidity position. Although there can be no assurance, due to the challenging times currently faced by financial institutions, management believes that the participating banks under our facilities will continue to meet their funding commitments. However, if the credit crisis is protracted, deteriorates, or leads to a larger recession, such events could have a material adverse impact on our cash flows from operations and our liquidity and financial position.

Impact on Pension Plans Affecting both Operating Results and Liquidity

Also impacted significantly by the economy was our Pension Plans. During the year 2008, our Pension Plans suffered a net actuarial loss of $186 million. The net actuarial loss is comprised of two parts: (1) a $157 million pension asset actuarial loss primarily due to the lower than expected return on assets, and (2) a $29 million pension liability actuarial loss primarily due to a decrease in the discount rate that is used to value pension liabilities, and a change in assumptions to include progressions upward through pension bands over the future working lifetime of participants. This loss was partially recovered in 2009 as we had a net actuarial gain for the year of $35 million. The 2009 net actuarial gain was comprised of: (1) a $47 million pension asset actuarial gain primarily due to the higher than expected return on assets, and (2) a $12 million pension liability actuarial loss primarily due to a decrease in the discount rate that is used to value pension liabilities. The unrecognized net loss for the Pension Plans was approximately $198 million as of December 31, 2009. This loss has arisen over time primarily due to the long-term declining trend in corporate bond rates, the lower than expected return on assets during the year 2008, and the adoption of new mortality tables which increased the expected benefit obligation due to the longer expected lives of participants, since ASC 715 “Compensation - Retirement Benefits” was adopted. The unrecognized net loss, to the extent that it exceeds 10% of the greater of the benefit obligation or the assets, will be amortized and included as a component of net periodic benefit cost (pension expense) in future years, which means pension expenses will continue to be higher as this unrecognized loss is amortized into expense over the next 12 years, which is the estimated average remaining working lifetime of plan participants. Illustrating the impact, net periodic benefit cost increased from $8.9 million in 2008 to $34.3 million in 2009, but is expected to decrease to $24.3 million in 2010. When taking into account the amount of net periodic benefit cost capitalized, pension expense increased from $8.1 million in 2008 to $31.8 million in 2009, but is expected to decrease to $22.4 million in 2010.

In addition, a funding shortfall was created primarily by the poor performance of the pension assets in 2008. The funding shortfall decreased as a result of the higher than expected return on pension assets during the year 2009. The funding shortfall is estimated to be approximately $115 million as of January 1, 2010. The shortfall must be funded over seven years. Please see Note 13, “Pension and Other Postretirement Benefits” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K for additional Pension Plan information.

For other impacts on our business caused by the recent recession in the local and global economy and the crisis in the financial markets, see “Item 1A. Risk Factors - Current and future conditions in the economy may adversely affect our results of operations, financial condition, and cash flows.”

RESULTS OF OPERATIONS

In addition to the discussion on operations below, please see the statistical information table included in “Item 1. Business” of this report for additional data such as kWh sales and number of customers by customer class.

Comparison of year ended December 31, 2009 and year ended December 31, 2008

Utility Operating Revenues

Utility operating revenues decreased in 2009 from the prior year by $11.0 million, which resulted from the following changes (dollars in thousands):


	2009		2008		Change		Percent Change

Utility Operating Revenue
Retail Revenues	$	1,000,148	$	1,003,103	$	(2,955)	(0.3%)
Wholesale Revenues		50,155		57,456		(7,301)	(12.7%)
Miscellaneous Revenues		17,778		18,554		(776)	(4.2%)
Total Utility Operating Revenues	$	1,068,081	$	1,079,113	$	(11,032)	(1.0%)

Heating Degree Days
Actual		5,195		5,463		(268)	(4.9%)
30-year Average		5,519		5,551
Cooling Degree Days
Actual		968		1,086		(118)	(10.9%)
30-year Average		1,041		1,042

The 1.0% decrease in utility operating revenues was primarily due to a 12.7% ($7.3 million) decrease in wholesale revenues and a 0.3% ($3.0 million) decrease in retail revenues. The decrease was mitigated by the $32.0 million decrease in revenue associated with the deferred fuel regulatory liabilities recorded in 2008 for credits to our retail customers. See “Liquidity and Capital Resources - Regulatory Matters - Fuel Adjustment Charge and Authorized Annual Jurisdictional Net Operating Income” for further information regarding the credit.

The 12.7% ($7.3 million) decrease in wholesale revenues is primarily due to a 44.9% decrease in the weighted average price per kWh sold ($40.9 million), partially offset by a 58.4% increase in the quantity of kWh sold ($33.6 million). The decreased market price of purchased power is influenced primarily by changes in the market price of delivered fuel (primarily natural gas), the price of environmental emissions allowances, the supply of and demand for electricity, and the time of day in which power is purchased. The amount of electricity available for wholesale sales is impacted by our retail load requirements, our generation capacity and unit availability. The increase in quantity was primarily due to the timing and duration of scheduled and forced generating unit maintenance outages. The quantity and price of wholesale kWh sales are also impacted by the ability of our generation to be dispatched by the Midwest ISO at wholesale prices that are above our variable costs and the amount of electricity we have available to sell in the wholesale market. Our ability to be dispatched in the Midwest ISO market is primarily impacted by the locational market price of electricity and variable generation costs.

Excluding the effect of the $32.0 million of credits in 2008, retail revenues decreased by 3.4% ($35.0 million). This decrease was primarily due to a 6.1% decrease in the quantity of kWh sold ($49.4 million), partially offset by a 2.9% increase in the weighted average price per kWh sold ($14.4 million). The decrease in the quantity of retail kWhs sold was primarily due to the economic recession and milder weather conditions (approximately $49.4 million) in 2009 compared to 2008. There was a 10.9% decrease in cooling degree days during the comparable periods and a 4.9% decrease in heating degree days during the comparable periods. The increase in the weighted average price of kWhs sold was primarily due to a (i) a $16.8 million increase in the rate charged to our retail customers primarily due to higher prices associated with our declining block rate structure and (ii) $1.2 million increase in fuel revenues, which is offset by increased fuel and purchased power expenses attributable to serving our jurisdictional retail customers as described below in “Utility Operating Expenses.” Our declining block rate structure generally provides for residential and commercial customers to be charged a lower per kWh rate at higher consumption levels. Therefore, as volumes decrease, the weighted average price per kWh increases. These increases were partially offset by a $4.7 million decrease in revenues related to our CCT projects.

Utility Operating Expenses

The following table illustrates our primary operating expense changes from 2008 to 2009 (in millions):



2008 Operating Expenses	$	897.2
Increase in deferred fuel costs		21.1
Increase in other operating expenses		10.0
Decrease in fuel costs		(13.7)
Decrease in power purchased		(10.6)
Decrease in income taxes - net		(7.2)
Other miscellaneous variances		1.3
2009 Operating Expenses	$	898.1

The $21.1 million increase in deferred fuel costs is the result of variances between estimated fuel and purchased power costs in our FAC and actual fuel and purchased power costs. We are generally permitted to recover underestimated fuel and purchased power costs in future rates through the FAC proceedings and therefore, the costs are deferred and amortized into expense in the same period that our rates are adjusted. (See also “Liquidity and Capital Resources - Regulatory Matters - Fuel Adjustment Charge and Authorized Annual Jurisdictional Net Operating Income.”) Deferred fuel costs are recorded in Fuel on the accompanying Consolidated Statements of Income.

The $10.0 million increase in other operating expenses was primarily due to an increase in pension expenses, partially offset by: decreased wages and benefits excluding pension expense ($4.3 million); contractor and consulting services ($3.8 million); operating expenses related to our CCT projects ($3.4 million); and various other individually immaterial items. Net periodic benefit cost after amounts capitalized (pension expense) increased from $8.1 million during 2008 to $31.8 million during 2009. This increase was primarily due to an increase of $14.9 million in amortization of actuarial loss and a $7.3 million decrease in the expected return on plan assets. Both of these unfavorable variances are primarily the result of the significant decline in market value of our pension assets in 2008. This decline coupled with a decrease in the discount rate used to value pension liabilities resulted in a $185.9 million net actuarial loss in 2008, which is being amortized into expense over 12 years in accordance with accounting principles generally accepted in the United States of America. During 2009 our pension fund investments performed well above the expected rate of return, which is the primary reason our pension expense is expected to decline from $31.8 million in 2009 to approximately $22.4 million in 2010. The decrease in wages and benefits excluding pension expense was primarily the result of staffing reductions.

The decrease in fuel costs was primarily due to a 3.6% decrease in the quantity of coal consumed as a result of a 2.5% decrease in the amount of electricity we generated.

The decrease in power purchased was primarily due to a decrease in the market price of purchased power ($21.7 million), partially offset by a 15.8% increase in the volume of power purchased during the period ($8.7 million) and a $2.4 million increase in capacity purchases. The volume of power we purchase each period is primarily influenced by our retail demand, our generating unit capacity and outages and because at times it is less expensive for us to buy power in the market than to produce it ourselves. The market price of purchased power is influenced primarily by changes in the market price of delivered fuel (primarily natural gas), the price of environmental emissions allowances, the supply of and demand for electricity, and the time of day in which power is purchased.

The $7.2 million decrease in income tax expense was primarily due to the decrease in pretax net operating income for the reasons previously described.

Other Income and Deductions

Other income and deductions decreased from income of $30.2 million in 2008 to income of $24.3 million in 2009, primarily due to a $6.7 million decrease in the income tax benefit, and an impairment recorded on our investment in EnerTech of $1.8 million, partially offset by decreases in charitable donations ($1.2 million), contracted services ($0.9 million) and a $0.9 million increase in the allowance for equity funds used during construction. The decrease in the income tax benefit was primarily due to a $16.3 million decrease in interest expense on long-term debt. The increase in allowance for equity funds used during construction was primarily due to the higher average balance of construction work in progress during 2009 as compared to 2008.

Interest and Other Charges

Interest and other charges decreased $16.9 million in 2009 as compared to 2008. The decrease is primarily due to a $13.9 million early tender premium related to the refinancing in April 2008 of the 2008 IPALCO’s Notes with the proceeds from the issuance of the 2016 IPALCO Notes. The decrease is partially offset by increased interest related to the 1995B Bonds. See “Impacts of Weak Economic Conditions” for further discussion on the 1995B Bonds.

Comparison of year ended December 31, 2008 and year ended December 31, 2007

Utility Operating Revenues

Utility operating revenues increased in 2008 from the prior year by $26.5 million, which resulted from the following changes (dollars in thousands):


	2008		2007		Change		Percent Change

Utility Operating Revenue
Retail Revenues	$	1,003,103	$	965,452	$	37,651	3.9%
Wholesale Revenues		57,456		68,366		(10,910)	(16.0)%
Miscellaneous Revenues		18,554		18,809		(255)	(1.4)%
Total Utility Operating Revenues	$	1,079,113	$	1,052,627	$	26,486	2.5%

Heating Degree Days
Actual		5,463		5,031		432	8.6%
30-year Average		5,551		5,521
Cooling Degree Days
Actual		1,086		1,551		(465)	(30.0)%
30-year Average		1,042		1,042

Utility Operating Expenses

The 2.5% increase in utility operating revenues was primarily due to a 3.9% increase in retail revenues. The increase was mitigated by the $32.0 million decrease in revenue associated with the deferred fuel regulatory liabilities recorded in 2008 for credits to our retail customers. See “Liquidity and Capital Resources - Regulatory Matters - Fuel Adjustment Charge and Authorized Annual Jurisdictional Net Operating Income” for further information regarding the credit.

Excluding the effect of the $32.0 million of credits, retail revenues increased by 7.2% ($69.7 million) primarily due to a 9.5% increase in the weighted average price per kWh sold ($87.7 million), partially offset by a 2.1% decrease in the quantity of kWh sold ($18.0 million). The increase in the weighted average price of kWhs sold was primarily due to a $42.5 million increase in revenues related to our CCT projects and a $42.2 million increase in fuel revenues, which is offset by increased fuel and purchased power expenses attributable to serving our jurisdictional retail customers (see discussion in “Utility Operating Expenses”). Also, our declining block rate structure generally provides for residential and commercial customers to be charged a lower per kWh rate at higher consumption levels. Therefore, as volumes decrease, the weighted average price per kWh increases. The decrease in the quantity of retail kWhs sold was primarily due to the 30.0% decrease in cooling degree days during the comparable periods.

The 16.0% decrease in wholesale revenues is primarily due to a 27.5% decrease in the quantity of kWh sold ($18.8 million), partially offset by a 15.9% increase in the weighted average price per kWh sold ($7.9 million). The decrease in quantity was primarily due to the timing and duration of scheduled and forced generating unit maintenance outages. The quantity and price of wholesale kWh sales are also impacted by the ability of our generation to be dispatched by the Midwest ISO at wholesale prices that are above our variable costs and the amount of electricity we have available to sell in the wholesale market. Our ability to be dispatched in the Midwest ISO market is primarily impacted by the locational market price of electricity and variable generation costs. The increased market price of purchased power is influenced primarily by changes in the market price of delivered fuel (primarily natural gas), the price of environmental emissions allowances, the supply of and demand for electricity, and the time of day in which power is purchased. The amount of electricity available for wholesale sales is impacted by our retail load requirements, our generation capacity and unit availability.

Utility Operating Expenses

The following table illustrates our primary operating expense changes from 2007 to 2008 (in millions):



2007 Operating Expenses	$	842.2
Increase in depreciation and amortization		20.1
Increase in other operating expenses		18.3
Increase in fuel costs		16.8
Increase in deferred fuel costs		15.0
Increase in maintenance expenses		12.2
Decrease in income taxes - net		(26.6)
Other miscellaneous variances		(0.8)
2008 Operating Expenses	$	897.2

The $20.1 million increase in depreciation and amortization is primarily due to amortization of regulatory deferrals related to CCT placed into service in September 2007 at our Harding Street generating station ($9.8 million) and an increase in depreciation expense related to the Harding Street CCT project ($8.8 million).

The increase in other operating expenses was primarily due to increased operating expenses related to our CCT projects ($4.8 million), wages and employee benefits ($5.1 million), contractor and consulting services ($3.3 million), and various individually immaterial items.

The increase in fuel cost was primarily due to an increase in actual fuel costs of $15.5 million and a $1.0 million increase in ash disposal transportation costs. The increase in actual fuel costs was due to a 12.5% increase in the per ton cost of coal resulting primarily from a price reopener on one of our large coal contracts, as well as increases in the diesel component for coal and transportation costs. This increase is partially offset by a 5.2% decrease in the quantity of coal consumed due to a 5.2% decrease in the amount of electricity we generated.

The $15.0 million increase in deferred fuel costs is the result of variances between estimated fuel and purchased power costs in our FAC and actual fuel and purchased power costs. We are generally permitted to recover underestimated fuel and purchased power costs in future rates through the FAC proceedings and therefore, the costs are deferred and amortized into expense in the same period that our rates are adjusted. (See also “Liquidity and Capital Resources - Regulatory Matters - Fuel Adjustment Charge and Authorized Annual Jurisdictional Net Operating Income.”) Deferred fuel costs are recorded in Fuel on the accompanying Consolidated Statements of Income.

The increase in maintenance expenses is primarily due to an increase in maintenance on overhead lines of approximately $5.4 million primarily as a result of increased storm damage and increased forced outages on our generating units of approximately $4.3 million.

The $26.6 million decrease in income tax expense was primarily due to a decrease in pretax net operating income for the reasons previously described.

Other Income and Deductions

Other income and deductions remained relatively flat in 2008 as compared to 2007. Included in the variation is a $4.1 million decrease in miscellaneous income and (deductions) - net due to a $1.7 million decrease in dividend revenue and various individually immaterial items. In addition, there was a $2.6 million decrease in the allowance for equity funds used during construction primarily due to decreased capital expenditures in 2008 compared to 2007. These decreases are partially offset by a $6.7 million increase in the income tax benefit, primarily due to the increase in interest on long-term debt (see below).

Interest and Other Charges

Interest and other charges increased $22.1 million for the year ended December 31, 2008 from the same period in 2007. This increase is primarily due to a $13.9 million early tender premium related to the repurchase of the 2008 IPALCO Notes and a $3.9 million increase in interest on long-term debt due to a weighted average increase in the amount of long-term debt we had outstanding in the comparable periods. There was also a $2.5 million decrease in allowance for borrowed funds used during construction primarily due to decreased capital expenditures in 2008 compared to 2007.

LIQUIDITY AND CAPITAL RESOURCES

As of December 31, 2009, we had unrestricted cash and cash equivalents of $48.0 million. We also had available borrowing capacity of $108.7 million under our $150.0 million committed credit facility after outstanding borrowings, existing letters of credit and liquidity support for the 1995B Bonds. As of December 31, 2009, we have borrowed $40.0 million on our committed credit facility to support the 1995B Bonds. See “Impacts of Weak Economic Conditions” for further information. All of IPL’s long-term borrowings must first be approved by the IURC and the aggregate amount of IPL’s short-term indebtedness must be approved by the FERC. We have approval from FERC to borrow up to $500 million of short-term indebtedness outstanding at any time through July 27, 2010. We anticipate submitting an application to FERC to request a new order prior to the expiration of the current order. We also have approval from the IURC to refinance the 1995B Bonds and to enter into capital lease obligations not to exceed an aggregate principal amount of $10 million outstanding at any time at various times throughout the period ending December 31, 2010. However, we also have restrictions on the amount of new debt that may be issued due to contractual obligations of AES and by financial covenant restrictions under our existing debt obligations. We do not believe such restrictions will be a limiting factor in our ability to issue debt in the ordinary course of prudent business operations.

We believe that existing cash balances, short-term investments, cash generated from operating activities and borrowing capacity on our committed credit facility will be adequate on a short-term and long-term basis to meet anticipated operating expenses, interest expense on outstanding indebtedness, recurring capital expenditures and to make dividend payments to AES. Sources for principal payments on outstanding indebtedness and nonrecurring capital expenditures are expected to be obtained from: (i) existing cash balances; (ii) cash generated from operating activities; (iii) borrowing capacity on our committed credit facility; and (iv) additional debt financing. As described previously, the current weak economic conditions may limit our access to financing in the capital markets, however we do not have any indebtedness maturing until 2011 and do not anticipate a need to access the debt capital markets until 2011, although we may decide to do so earlier if terms are economically favorable.

Historical Cash Flow Analysis

Our principal source of funds in 2009 was net cash provided by operating activities of $241.7 million. Net cash provided by operating activities is net of cash paid for interest of $115.3 million and pension funding of $20.1 million. Net cash provided by operating activities in 2009 was $57.9 million more than in 2008 primarily due to a decrease in pension funding of $36.6 million and the change in deferred fuel of $21.7 million. At the end of 2008, we had an asset for under recovered fuel costs of $15.2 million and at the end of 2009, we had a liability for the over collection of fuel costs of $8.2 million. The principal uses of funds in 2009 included capital expenditures of $115.4 million, dividends to AES of $70.9 million, and net debt repayments of $12.7 million.

Our principal sources of funds in 2008 were net cash provided by operating activities of $183.8 million, net proceeds of approximately $394.1 million from the sale of $400 million of the 2016 IPALCO Notes and net borrowings of $51.7 million on our committed credit facility. Net cash provided by operating activities is net of cash paid for interest of $130.0 million and pension funding of $56.7 million. The net cash provided by operating activities of $183.8 million in 2008 was $77.5 million less than net cash provided by operating activities of $261.3 million in 2007 primarily due to a decrease in net income of $50.7 million and an increase in pension funding of $57.3 million, partially offset by an increase in noncash add backs to net income for depreciation and amortization ($20.7 million, including amortization of regulatory assets) and early tender premium ($13.9 million) for the retirement of the 2008 IPALCO Notes. The principal uses of funds in 2008 included capital expenditures of $106.9 million, dividends to AES of $71.6 million, the retirement in April 2008, of the 2008 IPALCO Notes, and net purchases of short-term investments of $39.5 million.

Our principal sources of funds in 2007 were net cash provided by operating activities of $261.3 million, net proceeds of approximately $165.0 million from the sale of IPL first mortgage bonds and the use of $32.7 million of restricted cash. Net cash provided by operating activities is net of cash paid for interest of $117.6 million. The principal uses of funds in 2007 included capital expenditures of $201.1 million, dividends to AES of $85.8 million, the retirement of $80.0 million of first mortgage bonds and net paydowns of $74.0 million on our credit facility.

Capital Requirements

Capital Expenditures

Our construction program is composed of capital expenditures necessary for prudent utility operations and compliance with environmental laws and regulations, along with discretionary investments designed to improve overall performance. Our capital expenditures totaled $115.4 million, $106.9 million, and $201.1 million in 2009, 2008 and 2007, respectively. Construction expenditures in 2009 and 2008 were financed with internally generated cash provided by operations and borrowings on our credit facility. Construction expenditures in 2007 were financed with internally generated cash provided by operations, borrowings on our credit facilities, a portion of the proceeds from the June 2007 issuance of $165 million IPL first mortgage bonds (see “Capital Resources”), and $32 million in draws from the construction fund associated with the issuance of $60 million IPL first mortgage bonds in September 2006.

Our capital expenditure program, including development and permitting costs, for the three year period 2010-2012 is currently estimated to cost approximately $545 million. It includes approximately $192 million for additions, improvements and extensions to transmission and distribution lines, substations, power factor and voltage regulating equipment, distribution transformers and street lighting facilities. The capital expenditure program also includes approximately $178 million for power plant related projects; $107 million for construction projects designed to reduce Sulfur Dioxide and mercury emissions; $17 million for Demand-Side Management programs; $16 million of development and permitting costs associated with renewable energy generation; and $35 million for other miscellaneous equipment. The majority of the expenditures for construction projects designed to reduce SO2 and mercury emissions are recoverable through jurisdictional retail rate revenue through our ECCRA filings, subject to regulatory approval. Capital expenditures are financed with a combination of internally generated funds and short-term and long-term borrowings.

Contractual Cash Obligations

Our non-contingent contractual obligations as of December 31, 2009 are set forth below:


	Payment Due
	Total		Less Than 1 Year		1 - 3 Years		3 - 5 Years		More Than 5 Years
	*(In Millions)*
Long-term debt	$	1,712.7	$	-	$	415.0	$	110.0	$	1,187.7
Capital lease obligations		0.3		0.3		-		-		-
Operating lease obligations		0.2		0.2		-		-		-
Interest obligations⁽¹⁾		1,210.6		114.9		193.0		154.2		748.5
Purchase obligations⁽²⁾:
Coal, gas, purchased power and related transportation		1,200.4		248.3		447.9		233.9		270.3
Other		51.7		6.7		13.1		12.7		19.2
Pension Funding⁽³⁾		28.0		28.0		-		-		-
Total⁽⁴⁾	$	4,203.9	$	398.4	$	1,069.0	$	510.8	$	2,225.7

⁽¹⁾Represents interest payment obligations related to fixed and variable rate debt. Interest related to variable rate debt is calculated using the rate in effect at December 31, 2009.
⁽²⁾Does not include purchase orders or normal purchases for goods or services: (1) for which there is not also an enforceable contract; or (2) which does not specify all significant terms, including fixed or minimum quantities. Also, does not included contractual commitments that can be terminated by us without penalty on notice of 90 days or less.
⁽³⁾IPL is required to fund approximately $28.0 million during 2010. However, IPL may decide to contribute more than $28.0 million to meet certain funding thresholds. For years 2011 and thereafter, our contractual obligation for pension funding can fluctuate due to various factors. Please see “Pension Funding” below and Note 13, “Pension and Other Postretirement Benefits” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K for further discussion.
⁽⁴⁾ Does not include an uncertain tax liability of $8.6 million (tax and related interest) as of December 31, 2009. IPALCO adopted the provisions of ASC 740 on accounting for uncertainty in income taxes on January 1, 2007, however it is not possible to determine in which future period or periods that the non-current income tax liability for uncertain tax positions might be paid.

Dividends

All of IPALCO’s outstanding common stock is held by AES. During 2009, 2008 and 2007, we paid $70.9 million, $71.6 million, and $85.8 million, respectively, in dividends to AES. Future distributions will be determined at the discretion of our board of directors and will depend primarily on dividends received from IPL. Dividends from IPL are affected by IPL’s actual results of operations, financial condition, cash flows, capital requirements, regulatory considerations, and such other factors as IPL’s board of directors deems relevant.

Pension Funding

We contributed $20.1 million and $56.7 million to the Pension Plans in 2009 and 2008, respectively. There were no contributions to the Pension Plans in 2007. Funding for the Employees’ Retirement Plan of Indianapolis Power & Light Company, or Defined Benefit Pension Plan, is based upon actuarially determined contributions that take into account the amount deductible for income tax purposes and the minimum contribution required under Employee Retirement Income Security Act of 1974, as amended by the Pension Protection Act of 2006, as well as targeted funding levels necessary to meet certain thresholds. Management does not currently expect any of the pension assets to revert back to IPL during 2010.

From a funding perspective, IPL’s funding target liability shortfall is estimated to be approximately $115 million as of January 1, 2010. The shortfall must be funded over seven years. In addition, IPL must also contribute the normal service cost earned by active participants during the plan year. The service cost is expected to be approximately $7 million in 2010. Then, each year thereafter, if the plan’s underfunding increases to more than the present value of the remaining annual installments, the excess is separately amortized over a new seven year period. IPL is required to fund approximately $28 million during 2010. However, IPL may decide to contribute more than $28 million to meet certain funding thresholds. IPL’s funding policy for the Pension Plans is to contribute annually no less than the minimum required by applicable law, nor more than the maximum amount that can be deducted for federal income tax purposes.

Benefit payments made from the Pension Plans for the years ended December 31, 2009 and 2008 were $28.5 million and $30.8 million respectively. Benefit payments made by IPL for other postretirement obligations were $0.4 million and $0.6 million respectively.

See also “Critical Accounting Policies” for further discussion of Pension Plans.

Capital Resources

IPALCO is a holding company, and accordingly substantially all of its cash is generated by the operating activities of its subsidiaries, principally IPL. None of its subsidiaries, including IPL, is obligated under or has guaranteed to make payments with respect to the 2011 IPALCO Notes or the 2016 IPALCO Notes, however, all of IPL’s common stock is pledged to secure these notes. Accordingly, IPALCO’s ability to make payments on the 2011 IPALCO Notes and the 2016 IPALCO Notes depends on the ability of IPL to generate cash and distribute it to IPALCO.

While we believe that our sources of liquidity will be adequate to meet our needs, this belief is based on a number of material assumptions, including, without limitation, assumptions about revenues, weather, economic conditions, our credit ratings and those of AES and IPL, regulatory constraints, environmental regulation and pension obligations. If and to the extent these assumptions prove to be inaccurate, our sources of liquidity may be affected. Moreover, changes in these factors or in the bank or other credit markets could reduce available credit or our ability to renew existing credit or liquidity facilities on acceptable terms. The absence of adequate liquidity could adversely affect our ability to operate our business, and our results of operations, financial condition, and cash flows.

During 2009, we amended our receivable sale agreement to extend the maturity date to May 25, 2010, as discussed in Note 6, “Sales of Accounts Receivable” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data.”

Indebtedness

IPL First Mortgage Bonds

IPALCO’s Senior Secured Notes

In April 2008, IPALCO completed the sale of the 2016 IPALCO Notes pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended. The 2016 IPALCO Notes were sold at 98.526% of par resulting in net proceeds of $394.1 million. The $5.9 million discount is being amortized through 2016 using the effective interest method. We used these net proceeds to repurchase or redeem all of the 2008 IPALCO Notes. The proceeds were also used to pay the early tender premium of $13.9 million (included in Interest on long-term debt in the accompanying Consolidated Statements of Income) and other fees and expenses related to the tender offer and the redemption of the 2008 IPALCO Notes and the issuance of the 2016 IPALCO Notes.

The 2016 IPALCO Notes are secured by IPALCO’s pledge of all of the outstanding common stock of IPL. The lien on the pledged shares will be shared equally and ratably with IPALCO’s existing senior secured notes. IPALCO has entered into a Pledge Agreement Supplement with The Bank of New York Mellon Trust Company, N.A., as Collateral Agent, dated April 15, 2008 to the Pledge Agreement between IPALCO and The Bank of New York Mellon Trust Company, N.A. as successor Collateral Agent dated November 14, 2001.

See “Impacts of Weak Economic Conditions” for information regarding the 1995B Bonds.

Credit Ratings

Our ability to borrow money or to refinance existing indebtedness and the interest rates at which we can borrow money or refinance existing indebtedness are affected by our credit ratings. In addition, the applicable interest rates on the 2011 IPALCO Notes and IPL’s credit facility (as well as the amount of certain other fees on the credit facility) are dependent upon the credit ratings of IPALCO and IPL, respectively. In the event IPALCO’s or IPL’s credit ratings are downgraded or upgraded, the interest rates and certain other fees charged to IPALCO and IPL could increase, or decrease, respectively. However, the applicable interest rate on the 2011 IPALCO Notes cannot increase any further, but upgrades in IPALCO’s credit ratings would decrease the interest rate. Downgrades in the credit ratings of AES could result in IPL’s and/or IPALCO’s credit ratings being downgraded.

In August 2009, the corporate credit ratings of IPL and IPALCO were upgraded by Standard & Poors from BB+ to BBB-, resulting in an investment grade rating. This upgrade led to a downgrade in IPL’s senior unsecured debt rating from BBB to BBB- as a result of S&P applying its criteria for investment grade ratings to IPL. Under this criterion the senior unsecured rating of an investment grade company typically cannot be higher than its corporate credit rating. At this same time, S&P also upgraded the credit rating of IPALCO’s senior secured notes from BB to BB+. Additionally in August 2009, Moody’s upgraded the credit rating of IPL’s senior secured debt from Baa1 to A3. This upgrade was due to a change in Moody’s methodology for notching the senior secured debt ratings of investment-grade regulated utilities. Moody’s notching practices widened as a result of their research which indicated that regulated utilities have defaulted at a lower rate and experienced lower loss given default rates than non-financial, non-utility corporate issuers.

The credit ratings of IPALCO and IPL as of February 25, 2010 are as follows:


	Moody’s		S&P		Fitch

IPALCO Issuer Rating/Corporate Credit Rating/Long-term Issuer Default Rating		-		BBB-		BBB-
IPALCO Senior Secured Notes		Ba1		BB+		BBB-
IPL Issuer Rating/Corporate Credit Rating/Long term Issuer Default Rating		Baa2		BBB-		BBB-
IPL Senior Secured		A3		BBB		BBB+
IPL Senior Unsecured		Baa2		BBB-		BBB

We cannot predict whether our current credit ratings or the credit ratings of IPL will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. A security rating is not a recommendation to buy, sell or hold securities. The rating may be subject to revision or withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating.

Related Party Transactions

We participate in a property insurance program in which we buy insurance from AES Global Insurance Company, a wholly-owned subsidiary of AES. We are not self-insured on property insurance with the exception of a $1 million self-insured retention per occurrence. We do not carry insurance on transmission and distribution assets, which are considered to be outside the scope of property insurance. AES and other AES subsidiaries also participate in the AES global insurance program. We pay premiums for a policy that is written and administered by a third party insurance company. The premiums paid to this third party administrator by the participants are deposited into a trust fund owned by AES Global Insurance Company, but controlled by the third party administrator. This trust fund pays aggregate claims up to $25 million. Claims above the $25 million aggregate will be covered by separate insurance policies issued by a syndicate of third party carriers. These policies provide coverage of $600 million per occurrence. The cost to us of coverage under this program was approximately $3.9 million, $3.6 million, and $3.3 million in 2009, 2008, and 2007, respectively, and is recorded in Other operating expenses on the accompanying Consolidated Statements of Income. As of December 31, 2009 and 2008, we had prepaid approximately $1.7 million, which is recorded in Prepayments and other current assets on the accompanying Consolidated Balance Sheets.

We are party to an agreement with Health and Welfare Benefit Plans LLC, an affiliate of AES, to participate in a group benefits program, including but not limited to, health, dental, vision and life benefits. Health and Welfare Benefit Plans LLC administers the financial aspects of the group insurance program, receives all premium payments from the participating affiliates, and makes all vendor payments. We believe that, though our insurance costs will likely continue to rise, cost savings can be realized through participation in this group benefits program with AES. The cost of coverage under this program, was approximately $20.5 million, $21.0 million, and $20.5 million in 2009, 2008 and 2007, respectively and is recorded in Other operating expenses on the accompanying Consolidated Statements of Income. As of December 31, 2009 and 2008 we had prepaid approximately $0.5 million and $2.9 million, respectively, for coverage under this plan, which is recorded in Prepayments and other current assets on the accompanying Consolidated Balance Sheets.

In the first quarter of 2008, IPL exchanged 20,661 SO2 environmental air emissions allowances for 20,718 SO2 environmental air emissions allowances with wholly-owned subsidiaries of AES. Because the transactions lacked commercial substance and were between entities under common control, the exchanges have been accounted for by IPL at their historical cost. This transaction did not have a material impact on our results of operations, financial condition, or cash flows.

AES files federal and state income tax returns which consolidate IPALCO and its subsidiaries. Under a tax sharing agreement with AES, IPALCO is responsible for the income taxes associated with its own taxable income and records the provision for income taxes using a separate return method. IPALCO had a receivable/(payable) balance under this agreement of $1.2 million and ($1.1 million) as of December 31, 2009, and 2008, respectively.

During 2009 and 2008, many of IPL’s non-union employees received benefits under the AES Long-term Compensation Plan, a deferred compensation program. This type of plan is a common employee retention tool used in our industry. Benefits under this plan are granted in the form of performance units payable in cash, AES restricted stock units and options to purchase shares of AES common stock. All three of such components vest in thirds over a three year period and the terms of the AES restricted stock units also include a five year minimum holding period. In addition, the performance units payable in cash are subject to certain AES performance criteria. Total deferred compensation expense recorded during 2009 and 2008 was $1.4 million and $3.0 million, respectively and was included in Other Operating Expenses on IPALCO’s Consolidated Statements of Income. The value of these benefits is being recognized over the 36 month vesting period and a portion is recorded as miscellaneous deferred credits with the remainder recorded as paid in capital on IPALCO’s Consolidated Balance Sheets in accordance with ASC 718 “Compensation - Stock Compensation.”

See also “The AES Retirement Savings Plan” included in Note 13, “Pension and Other Postretirement Benefits” to the audited Consolidated Financial Statements of IPALCO for a description of benefits awarded to IPL employees by AES under the AES Retirement Savings Plan.

Sales of Accounts Receivable

Please see, Note 6, “Sales of Accounts Receivable” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data.”

Dividend and Capital Structure Restrictions

IPL’s mortgage and deed of trust and its amended articles of incorporation contain restrictions on IPL’s ability to issue certain securities or pay cash dividends. So long as any of the several series of bonds of IPL issued under its mortgage remains outstanding, and subject to certain exceptions, IPL is restricted in the declaration and payment of dividends, or other distribution on shares of its capital stock of any class, or in the purchase or redemption of such shares, to the aggregate of its net income, as defined in the mortgage, after December 31, 1939. The amount which these mortgage provisions would have permitted IPL to declare and pay as dividends at December 31, 2009, exceeded IPL’s retained earnings at that date. In addition, pursuant to IPL’s articles, no dividends may be paid or accrued and no other distribution may be made on IPL’s common stock unless dividends on all outstanding shares of IPL preferred stock have been paid or declared and set apart for payment.

IPL is also restricted in its ability to pay dividends if it is in default under the terms of its credit facility, which could happen if IPL fails to comply with certain covenants. These covenants, among other things, require IPL to maintain a ratio of earnings before interest and taxes to interest expense of not less than 2.5 to 1, and a ratio of total debt to total capitalization not in excess of 0.65 to 1, in order to pay dividends. As of December 31, 2009 and as of the filing of this report, IPL was in compliance with all financial covenants and no event of default existed.

IPALCO is also restricted in its ability to pay dividends under the terms of its 2011 IPALCO Notes if it is not in compliance with certain financial covenants. These covenants require IPALCO to maintain a minimum ratio of earnings before taxes, interest, depreciation and amortization to interest expense of not less than 2.5 to 1, and a ratio of total debt to total adjusted capitalization, as defined in the terms of its 2011 IPALCO Notes documents, not in excess of 0.67 to 1, in order to pay dividends. As of December 31, 2009 and as of the filing of this report, IPALCO was in compliance with all financial covenants and no event of default existed.

IPL’s amended articles of incorporation also require that, so long as any shares of preferred stock are outstanding, the net income of IPL, as specified in the articles, be at least one and one-half times the total interest on the funded debt and the pro forma dividend requirements on the outstanding, and any proposed, preferred stock before any additional preferred stock is issued. IPL’s mortgage and deed of trust requires that net earnings as calculated thereunder be at least two and one-half times the annual interest requirements before additional bonds can be authenticated on the basis of property additions. As of December 31, 2009, these requirements would not materially restrict IPL’s ability to issue additional preferred stock or first mortgage bonds in the ordinary course of prudent business operations.

Regulatory Matters

General

IPL is a regulated public utility principally engaged in providing electric service to the Indianapolis metropolitan area. As a regulated entity, we are required to use certain accounting methods prescribed by regulatory bodies which may differ from accounting methods required to be used by nonregulated entities.

An inherent business risk facing any regulated public utility is that of unexpected or adverse regulatory action. Regulatory discretion is reasonably broad in Indiana, as it is elsewhere. We attempt to work cooperatively with regulators and those who participate in the regulatory process, while remaining vigilant in protecting or asserting our legal rights in the regulatory process. We take an active role in addressing regulatory policy issues in the current regulatory environment. Additionally, there is increased activity by environmental regulators. (See “Environmental Matters.”)

Basic Rates and Charges

Our basic rates and charges represent the largest component of our annual revenues. Our basic rates and charges are determined after giving consideration, on a pro-forma basis, to all allowable costs for ratemaking purposes including a fair return on the fair value of the utility property used and useful in providing service to customers. These basic rates and charges are set and approved by the IURC after public hearings. Such proceedings, which have occurred at irregular intervals, involve IPL, the Indiana Office of Utility Consumer Counselor, and other interested consumer groups and certain customers. Pursuant to statute, the IURC is to conduct a periodic review of the basic rates and charges of all Indiana utilities at least once every four years, but the IURC has the authority to review the rates of any Indiana utility at any time. Once set, the basic rates and charges authorized do not assure the realization of a fair return on the fair value of property. Our basic rates and charges were last adjusted in 1996. Our declining block rate structure generally provides for residential and commercial customers to be charged a lower per kWh rate at higher consumption levels. Therefore, as volumes increase, the weighted average price per kWh decreases. Numerous factors including, but not limited to, weather, inflation, customer growth and usage, the level of actual operating and maintenance expenditures, capital expenditures including those required by environmental regulations, fuel costs, generating unit availability and purchased power costs, can affect the return realized.

Fuel Adjustment Charge and Authorized Annual Jurisdictional Net Operating Income

IPL may apply to the IURC for a change in IPL’s fuel charge every three months to recover IPL’s estimated fuel costs, including the energy portion of purchased power costs, which may be above or below the levels included in IPL’s basic rates and charges. Independent of the IURC’s ability to review basic rates and charges, Indiana law requires electric utilities under the jurisdiction of the IURC to meet operating expense and income test requirements as a condition for approval of requested changes in the FAC. Additionally, customer refunds may result if a utility’s rolling twelve month operating income, determined at quarterly measurement dates, exceeds a utility’s authorized annual jurisdictional net operating income and there are not sufficient applicable cumulative net operating income deficiencies against which the excess rolling twelve month jurisdictional net operating income can be offset.

In IPL’s six most recently approved FAC filings (FAC 81 through 86), the IURC found that IPL’s rolling annual jurisdictional retail electric net operating income was lower than the authorized annual jurisdictional net operating income. FAC 86 includes the twelve months ended October 31, 2009. In IPL’s FAC 76 through 80 filings, the IURC found that IPL’s rolling annual jurisdictional retail electric net operating income was greater than the authorized annual jurisdictional net operating income. Because IPL has a cumulative net operating income deficiency, it has not been required to make customer refunds in its FAC proceedings. In IPL’s FAC 76 through 80 filings, the IURC found that IPL’s rolling annual jurisdictional retail electric net operating income was greater than the authorized annual jurisdictional net operating income. Because IPL has a cumulative net operating income deficiency, it has not been required to make customer refunds in its FAC proceedings.

In December 2007, IPL received a letter from the staff of the IURC requesting information relevant to the IURC’s periodic review of IPL’s basic rates and charges and IPL subsequently provided information to the staff. Since IPL’s cumulative net operating income deficiency (described above) requires no customer refunds in the FAC process, the IURC staff was concerned that the higher than usual 2007 earnings may continue in the future. In an effort to allay staff’s concerns, in IPL’s IURC approved FAC 79 and 80, IPL provided voluntary credits to its retail customers totaling $30 million and $2 million, respectively. IPL recorded a $30 million deferred fuel regulatory liability in March 2008 and a $2 million deferred fuel regulatory liability in June 2008, with corresponding and respective reductions against revenues for these voluntary credits. All of these credits have been applied in the form of offsets against fuel charges that customers would have otherwise been billed during June 1, 2008 through February 28, 2009.

Purchased power costs below an established benchmark are presumed to be recoverable fuel costs. The current benchmark is based on natural gas prices. Purchased power costs over the benchmark not recovered from our customers have not had a material impact on our results of operations, financial condition, or cash flows to date.

Clean Coal Technology Filings

In April 2008, in response to a petition we filed, the IURC issued an order approving recovery of capital expenditures of approximately $92.7 million over three years through our ECCRA filings. The $92.7 million approved by the IURC includes $90.0 million to install and/or upgrade CCT to further reduce SO2 and mercury emissions at our Petersburg generating station and $2.7 million for mercury emissions monitoring equipment at our coal-fired power plants. Our current estimate is that the installation and/or upgrade of CCT to further reduce SO2 and mercury emissions at our Petersburg generating station will cost approximately $119.9 million. We have received authorization for cost recovery for such amount by the IURC in a manner consistent with existing CCT projects.

The targeted in service date of CCT to further reduce SO2 and mercury emissions at our Petersburg generating station is 2011, with the majority of the construction expenditures occurring in 2010 and 2011. Given that the EPA is now expected to propose a new rule to address hazardous air pollutant emissions from electric generating power plants, including mercury, as discussed in “Environmental Matters - Clean Air Mercury Rule,” we have suspended our plan to install mercury monitors until there is greater regulatory clarity around our obligations.

During the years ended December 31, 2009, 2008 and 2007, we made $21.5 million, $23.3 million, and $97.2 million, respectively, in CCT expenditures. The majority of such costs are recoverable as a result of the filings described above.

Demand-Side Management

In 2004, the IURC initiated an investigation to examine the overall effectiveness of DSM programs throughout the State of Indiana and to consider any alternatives to improve DSM performance statewide. On December 9, 2009, the IURC issued a Generic DSM Order that found that electric utilities subject to its jurisdiction must meet an overall goal of 2% annual cost-effective DSM savings within ten years from the date of its Order (beginning at 2010 at 0.3% and growing to 2.0% in 2019, and subject to certain adjustments). The IURC also found that all jurisdictional electric utilities have to participate in five initial, statewide core DSM programs, which will be administered by a Third Party Administrator. It is not possible at this time to predict the impact that the IURC’s Generic DSM Order will have on IPL.

Prior to the issuance of the Generic DSM Order, IPL filed a petition seeking relief for substantive DSM programs. IPL proposed a DSM plan to be considered in two phases. The first phase (Phase I) sought recovery for traditional-type DSM programs (such as residential home weatherization and energy efficiency education programs). The IURC issued an Order in February 2010 that approved the programs included in IPL’s Phase I request. In addition to IPL’s traditional recovery of the direct costs of the DSM program, the Order also included performance based incentives. The second phase (Phase II) sought recovery for “Advanced” DSM programs and was coincident with IPL’s application for a smart grid funding grant from the Department of Energy. The “Advanced” DSM programs included an Advanced Metering Infrastructure communication backbone as well as two-way meters and home area network devices for certain of IPL’s customers. In February 2010, the IURC issued an Order that approved IPL’s Phase II program, but denied IPL’s request to timely recover its expenditures. Instead, IPL would need to seek recovery of the costs incurred under its Phase II program during its next basic rate case proceeding. In light of these recent IURC Orders and the $20 million smart grid investment grant that IPL is currently negotiating (discussed below), IPL is still evaluating its DSM program and what the financial impacts will be.

Smart Grid Investment Grant

The American Recovery and Reinvestment Act of 2009 was enacted into law in February 2009. The American Recovery and Reinvestment Act of 2009 includes various provisions that fund the development of the electric power industry at the federal and state level. These provisions include, but are not limited to, improving energy efficiency and reliability; electricity delivery (including smart grid technology); energy research and development; renewable energy; and demand response management. In August 2009, we submitted an application for a smart grid investment grant for $20 million to provide our customers with tools to help them more efficiently use electricity and also to upgrade our delivery system infrastructure. In October 2009, the U.S. Department of Energy notified us that our application had been selected for award negotiations. The U.S. Department of Energy’s Office of Electricity Delivery and Energy Reliability conducted a briefing for all selectees in November 2009. Negotiations with the U.S. Department of Energy to finalize the award continue. It is unclear at this time what the tax impacts of this grant may be. Our project is part of our DSM plan (discussed above). IPL is evaluating the impact these recent IURC DSM Orders may have on its smart grid investment grant.

Wind Power Purchase Agreements

In June 2009, we entered into a wind power purchase agreement for approximately 200 MW of wind generated electricity for 20 years. In January 2010, the IURC approved IPL’s petition for recovery of costs associated with this agreement via a cost recovery mechanism similar to the FAC. However, the approval included conditions which may not be acceptable to IPL. As such, IPL is evaluating its options with regard to moving forward with this wind contract.

In April 2008, we entered into a power purchase agreement to purchase approximately 106 MW of wind generated electricity for 20 years from a wind project in Indiana. In October 2009, the construction of the facility was completed and the facility began its commercial operation in November 2009. We applied for and were granted authority from the IURC to recover the costs for such power through our FAC. Renewable resources will help us to diversify the resources available to serve our customers in light of potential GHG and renewable portfolio standards legislation.

Midwest ISO Real Time Revenue Sufficiency Guarantee

The Midwest ISO collects RSG charges from market participants that cause additional generation to be dispatched when the costs of such generation are not recovered. Over the past two years, there have been disagreements between interested parties regarding the calculation methodology for RSG charges and how such charges should be allocated to the individual Midwest ISO participants. The Midwest ISO has changed their methodology multiple times. Per past FERC orders, in December 2008, the Midwest ISO filed with the FERC its proposed revisions and clarifications to the calculation of the RSG charges and had begun to use its new methodology in January 2009, including making resettlements of previous calculations. In the second quarter of 2009, the FERC withdrew its previous orders related to RSG charges and further directed Midwest ISO to cease the ongoing market resettlements and refund process and to reconcile the amounts paid and collected in order to return each market participant to the financial state it was in before the refund process began. This has the potential implication that IPL would no longer be entitled to refunds that were due to IPL under the previous order for periods between April 1, 2005 and November 4, 2007.

In July 2009, IPL filed a Request for Clarification or alternately a Request for Rehearing on this issue alone. In addition to our requests, other interested parties have expressed interest in a different model of allocating RSG charges. Another factor that affects how RSG charges impact IPL is our ability to recover such costs from our customers through our FAC and/or in a future basic rate case proceeding. Under the methodology currently in effect, RSG charges have little effect on IPL’s financial statements as the vast majority of such charges are considered to be fuel costs and are recoverable through IPL’s FAC, while the remainder are being deferred for future recovery in accordance with GAAP. However, the IURC’s orders in IPL’s FAC 77, 78 and 79 proceedings approved IPL’s FAC factor on an interim basis, subject to refund, pending the outcome of the FERC proceeding regarding RSG charges and any subsequent appeals therefrom. As a result, it is not possible to predict how these proceedings will ultimately impact IPL, but we do not believe they will have a material impact on our financial statements.

Midwest ISO Transmission Expansion Cost Sharing

Beginning in 2007, Midwest ISO transmission owners including IPL began to share the costs of transmission expansion projects with other transmission owners after such projects were approved by the Midwest ISO Board of Directors. Upon approval by the Midwest ISO Board of Directors the transmission owners must make a good faith effort to build the projects. Costs allocated to IPL for the projects of other transmission owners are collected by the Midwest ISO per their Tariff. We believe it is probable, but not certain, that IPL will ultimately be able to recover from its customers the money it pays to the Midwest ISO for its share of transmission expansion projects of other utilities, but such recovery is subject to IURC approval in IPL’s next basic rate case. Therefore, such costs to date have been deferred as long term regulatory assets. To date, such costs have not been material to IPL, however, given the magnitude of the costs anticipated to enable conformance with renewables mandates in the Midwest ISO footprint, it is probable that such costs will become material in the next few years. Our current estimates are that IPL’s share of such costs could be more than $50 million annually by 2020 and continue increasing after that.

Ongoing Regulatory Proceeding

In February 2009, an IPL customer sent a letter to the OUCC claiming IPL’s tree trimming practices were unreasonable and expressed concerns with language contained in IPL’s tariff that specifically addressed IPL’s tree trimming and tree removal rights. The OUCC forwarded the complaint to the IURC and in March 2009 the IURC initiated a docketed proceeding to investigate the matter. The same customer also separately filed an inverse condemnation lawsuit, purportedly as a class action, claiming that IPL’s trimming and/or removal of trees without payment of compensation to landowners constituted unconstitutional taking of private property.

In April 2009, the IURC initiated a generic state-wide investigation into electric utility tree trimming practices and tariffs. In December 2009, the IURC issued a docket entry, pending a final order in the generic investigation, that suspended certain language in IPL’s tariff regarding its right to trim or remove trees. In January 2010, the IURC held a hearing in the generic proceeding. We do not expect a ruling or final order before mid-year 2010. There has been very little activity in the civil suit during the IURC proceeding and no class has been certified. It is not possible to predict the outcome of the IURC investigation or the civil suit but, conceivably, either could significantly increase our vegetation management costs which could have a material impact on our consolidated financial statements.

Environmental Matters

We are subject to various federal, state and local environmental protection and health and safety laws and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of hazardous materials; the emission and discharge of hazardous and other materials into the environment; and the health and safety of our employees. These laws and regulations often require a lengthy and complex process of obtaining and renewing permits and other governmental authorizations from federal, state and local agencies. Violation of these laws, regulations or permits can result in substantial fines, other sanctions, and permit revocation and/or facility shutdowns. While we believe IPL operates in compliance with applicable environmental requirements, from time to time the company is subject to enforcement actions for claims of noncompliance. IPL cannot assure that it will be successful in defending against any claim of noncompliance. However, other than the NOV from the EPA (which remains to be resolved but could potentially result in fines or other required changes that could be material to our results of operations, financial condition, or cash flows), we do not believe any currently open investigations will result in fines material to our results of operations, financial condition, or cash flows.

Under certain environmental laws, we could be held responsible for costs relating to contamination at our past or present facilities and at third party waste disposal sites. We could also be held liable for human exposure to such hazardous substances or for other environmental damage. Our costs of complying with current and future environmental and health and safety laws, and our liabilities arising from past or future releases of, or exposure to, hazardous substances may adversely affect our business, results of operations, financial condition, and cash flows. A discussion of the legislative and regulatory initiatives most likely to affect us follows.

Climate Change Regulations

We face certain risks related to potential GHG legislation or regulations, including risks related to increased capital expenditures or other compliance costs which could have a material adverse effect on our results of operations, financial condition or cash flows.

In 2009, a key development in the area of GHG legislation in the U.S. was the passage of H.R. 2454, “The American Clean Energy and Security Act of 2009” by the U.S. House of Representatives. ACES contemplates a nationwide cap and trade program to reduce U.S. emissions of CO2 and other GHG starting in 2012. Key features of ACES, among other things, include:

A planned target to reduce by 2020 GHG emissions by 17% from 2005 levels and to reduce GHG emissions by 83% from 2005 levels by 2050.
A requirement that certain GHG emitting companies, including most power generators, surrender on an annual basis one ton of CO2 equivalent allowances or GHG offset credits for each ton of annual CO2 equivalent emissions. Such companies will be required to meet allowance surrender requirements via the allocation of free allowances if available from the U.S. Environmental Protection Agency, or purchases in the open market at auctions if free allowances are not allocated, or otherwise.
A mechanism under which the EPA would initially issue a capped and steadily declining number of tradable free emissions allowances to certain sections of affected industries, including certain generators and utilities in the electricity sector, with such free distribution of allowances to the electricity sector phasing out over a five year period from 2026 through 2030.
A provision permitting up to two billion tons of GHG offset credits in the aggregate, if available, to be purchased annually by all emitters to satisfy the requirements above.
A provision precluding the EPA from regulating GHG emissions under the existing provisions of the CAA.
A temporary prohibition on the implementation of similar state or regional GHG cap and trade programs with a six year moratorium (2012 to 2017) on the implementation or enforcement of similar GHG emission caps.
The establishment of a combined energy efficiency and renewable electricity standard that would require retail electric utilities to receive 6% of their power from renewable sources by 2012, with such requirement increasing to 20% by 2020. In certain circumstances, a portion of this requirement for renewable energy could be satisfied through measures intended to increase energy efficiency.

The U.S. Senate introduced similar legislation in September 2009 with draft bill S. 1733, “The Clean Energy Jobs and American Power Act.” CEJAP contemplates a planned target to reduce by 2020 GHG emissions by 20% from 2005 levels and by 83% from 2005 levels by 2050. CEJAP has been voted out of the U.S. Senate committee in which it was introduced (the Environmental and Public Works Committee), but it has not set for debate in the U.S. Senate. It is uncertain whether CEJAP, in a modified form or its current form, will be voted upon by the U.S. Senate or if the U.S. Senate will pursue less comprehensive legislation concerning GHG emissions.

At this time, if ACES, CEJAP or some reconciled version of ACES and CEJAP were to be enacted into law its impact on our results of operations, financial conditions or cash flows cannot be accurately predicted because of a number of uncertainties with respect to the specific terms and implementation of any such potential legislation, including among other provisions:

The number of free allowances that will be allocated to IPL.
The cost to purchase allowances in an auction or on the open market, and the cost of purchasing GHG offset credits.
The extent to which IPL will be able to recover compliance costs from its customers and the timeliness of such recoveries.
Whether such legislation would preempt the EPA from regulating GHG emissions from electric generating units.

The EPA has proposed to regulate GHG emissions from motor vehicles in 2010 in accordance with the decision by the U.S. Supreme Court concluding that GHG emissions could be considered a “pollutant” under the CAA, subject to regulation under the CAA. Pursuant to that decision, the EPA has a duty to determine whether CO2 emissions contribute to climate change or to provide some reasonable explanation why it will not exercise its authority. In order for the EPA to regulate CO2 and other GHG emissions under Section 202 of the CAA, the EPA must determinate that such emissions “endanger public health and welfare” under the CAA. In April 2009, the EPA released proposed findings for comment which included a proposed finding that atmospheric concentrations of six GHG’s, including CO2, “endanger public health and welfare within the meaning of Section 202(a) of the CAA.” In December 2009, after review of the public comments to the proposed finding, the EPA issued the endangerment finding.

Also, in response to the above-mentioned U.S. Supreme Court’s decision, in July 2008 the EPA issued an Advanced Notice of Proposed Rulemaking to solicit public input on whether CO2 emissions should be regulated from both mobile and stationary sources under Section 202 of the CAA. In September 2009, the EPA proposed a rule to regulate GHG emissions from automobiles, a mobile source of emissions. If the proposed rule is ultimately enacted with respect to a mobile source, subject stationary sources of GHG emissions (including power plants) will likely become subject to regulation under various sections of the CAA. The most important impact on stationary sources would be a requirement that all new sources of GHG emissions over 250 tons per year, and any existing sources planning physical changes that would increase their GHG emissions by certain “significance” thresholds, obtain “new source review” permits from the EPA prior to construction. Such sources would be required to apply “best available control technology” to limit the emission of GHGs. In September 2009, the EPA proposed a rule that would set the “significance” threshold for those stationary sources emitting CO2 to be between 10,000 tons per year and 25,000 tons per year of GHGs. In 2009, our generating power plants emitted approximately 17 million tons of CO2 and would fall within the scope of this proposed rule if they were to undertake physical changes that would increase their GHG emissions in excess of any promulgated significance thresholds. In September 2009, the EPA also finalized a rule mandating the widespread reporting and tracking of GHG emissions. Although this tracking and reporting rule does not mandate reductions in GHG emissions, data generated from its implementation may facilitate the further development of federal GHG policy, which may include mandatory GHG emissions limits.

In November 2007, six Midwestern state governors (including the governor of Indiana) and the premier of Manitoba, Canada signed the Midwestern Greenhouse Gas Reduction Accord committing the participating states and province to reduce GHG emissions through the implementation of a cap-and-trade program. Three states (including Indiana) and the province of Ontario, Canada have signed as observers. The Midwestern Greenhouse Gas Reduction Accord Advisory Group has finalized a set of recommendations which are now being reviewed by the Governors of the relevant states. The recommendations are from the advisory group only, and have not been endorsed or approved by individual Governors, including the Governor of Indiana.

At this time, we cannot estimate the costs of compliance with potential federal, state or regional CO2 emissions reductions legislation or initiatives due to the fact that these proposals are in earlier stages of development and any final regulations or laws, if adopted, could vary drastically from current proposals. Any federal, state or regional legislation or regulations adopted in the U.S. that would require the reduction of GHG emissions could have a material adverse effect on our business and/or results of operations, financial condition and cash flows.

The possible impact of any future federal GHG legislation or regulations or any regional or state proposal will depend on various factors, including but not limited to:

The geographic scope of legislation and/or regulation (e.g., federal, regional, state), which entities are subject to the legislation and/or regulation (e.g., electricity generators, load serving entities, electricity deliverers, etc.), the enactment date of the legislation and/or regulation and the compliance deadlines set forth therein;
The level of reductions of CO2 being sought by the regulation and/or legislation (e.g., 10%, 20%, 50%, etc.) and the year selected as a baseline for determining the amount or percentage of mandated CO2 reduction (e.g., 10% reduction from 1990 CO2 emission levels, 20% reduction from 2000 CO2 emission levels, etc.);
The legislative structure (e.g., a CO2 cap-and-trade program, a carbon tax, CO2 emission limits, etc.);
In any cap-and-trade program, the mechanism used to determine the price of emission allowances or offsets to be auctioned by designated governmental authorities or representatives;
The price of offsets and emission allowances in the secondary market, including any price floors on the costs of offsets and emission allowances and price caps on the cost of offsets and emission allowances;
The operation of and emissions from regulated units;
The permissibility of using offsets to meet reduction requirements (e.g., type of offset projects allowed, the amount of offsets that can be used for compliance purposes, any geographic limitations regarding the origin or location of creditable offset projects) and the methods required to determine whether the offsets have resulted in reductions in GHG emissions and that those reductions are permanent (i.e., the verification method);
Whether the use of proceeds of any auction conducted by responsible governmental authorities is reinvested in developing new energy technologies, is used to offset any cost impact on certain energy consumers or is used to address issues unrelated to power;
How the price of electricity is determined at the affected businesses, including whether the price includes any costs resulting from any new CO2 legislation and the potential to transfer compliance costs pursuant to legislation, market or contract, to other parties;
Any impact on fuel demand and volatility that may affect the market clearing price for power;
The effects of any legislation or regulation on the operation of power generation facilities that may in turn affect reliability;
The availability and cost of carbon control technology;
Whether legislation regulating GHG emissions will preclude the EPA from regulating GHG emissions under the CAA or preempt private nuisance suits by third parties; and
Any opportunities to change the use of fuel at the generation facilities or opportunities to increase efficiency.

Clean Air Interstate Rule

In March 2005 the EPA signed the federal CAIR, which imposes restrictions against polluting the air of downwind states. The federal CAIR established a two-phase regional “cap and trade” program for Sulfur Dioxide and Nitrogen Oxide emissions that requires the largest reduction in air pollution in more than a decade. Federal CAIR covers 28 eastern states, including Indiana, and the District of Columbia.

In July 2008, the U.S. Court of Appeals for the D.C. Circuit vacated and remanded the federal CAIR to the EPA. However, in December 2008, in response to motions from the EPA and other petitioners, the Court issued an opinion and remanded the rule to the EPA without vacating federal CAIR to allow the EPA to remedy CAIR’s flaws in accordance with the Court’s July 2008 opinion. The EPA plans to issue a proposed revision to CAIR in the spring of 2010. In the interim, until EPA finalizes a new rule to replace CAIR, we are operating subject to the existing version of CAIR. Since the federal CAIR is now effective, the Indiana Department of Environmental Management formally withdrew the Indiana CAIR rulemaking process that it had initiated in the event that the federal CAIR was no longer valid.

Phase I of federal CAIR the program for NOx emissions became effective on January 1, 2009 and requires reductions of NOx emissions by 1.7 million tons or 53% from 2003 levels, and requires year-round compliance with the NOx emissions reduction requirements. Phase I of the program for SO2 emissions became effective on January 1, 2010, and requires reductions in SO2 emissions by 4.3 million tons, or 45% lower than 2003 levels. Phase II of federal CAIR is set to become effective for both NOx and SO2 on January 1, 2015. It is anticipated that Phase II of federal CAIR will require reduction of SO2 emissions by 5.4 million tons or 57% from 2003 levels, and NOx emissions by 2 million tons, requiring a regional emissions level of 1.3 million tons or a 61% reduction from 2003 levels.

We have been able to comply with federal CAIR Phase I for NOx without any material additional capital expenditures. Recent installation of CCT at our Harding Street Unit 7 generating station and recent upgrade at our Petersburg Unit 3 generating station, along with our plan to upgrade existing CCT at our Petersburg Unit 4 generating station, will help us to meet the requirements of federal CAIR Phase I for SO2. It is unclear at this time what actions may be required to achieve compliance with federal CAIR Phase II reductions, if Phase II becomes effective. It is also unclear at this time what actions may be required to achieve compliance after EPA revises federal CAIR rules pursuant to the D.C. Circuit Court’s July 2008 order.

Clean Air Mercury Rule

The CAMR was promulgated in March 2005 and as proposed required reductions of mercury emissions from coal-fired power plants in two phases. However, in February 2008, the U.S. Court of Appeals for the District of Columbia Circuit ruled that CAMR as promulgated violated the CAA and vacated the rule. The EPA is obligated under the CAA, and the District of Columbia Circuit court ruling, to develop a rule requiring pollution controls for hazardous air pollutants, including mercury, from coal and oil-fired power plants. The EPA has entered into a consent decree under which it is obligated to propose the rule by March 2011 and to finalize the rule by November 2011. Under the CAA, compliance is required within 3 years of the effective date of the rule; however, the compliance period may be extended by the state permitting authorities (for one additional year) or through a determination by the U.S. President (for up to two additional years). The CAA requires EPA to establish maximum achievable control technology standards for each hazardous air pollutant regulated under the CAA. The MACT minimum standard is defined as the emission limitation achieved by the “best performing 12%” of sources in the source category. While it is impossible to project what emission rate levels the EPA may propose as MACT for mercury emissions at coal-fired utility boilers, the rule will likely require all coal-fired power plants to install acid gas scrubbers (wet or dry flue gas desulfurization technology) and/or some other type of mercury control technology, such as sorbent injection. While the exact impact and cost of any such new federal rules cannot be established until they are promulgated they could have a material adverse effect on our business and/or results of operations, financial condition or cash flows.

Clean Coal Technology

Please see “Regulatory Matters - Clean Coal Technology Filings” and “Liquidity and Capital Resources - Capital Requirements - Capital Expenditures” for a detailed discussion of our environmental technologies and capital expenditures and see “Item 7A. Quantitative and Qualitative Disclosure about Market Risk” for a detailed discussion of SO2 allowances.

National Ambient Air Quality Standards

Over the past several years, the EPA has tightened the National Ambient Air Quality Standards for ground level ozone by lowering the standard for daily emissions of ozone from 0.080 parts per million to 0.075 parts per million and lowering the standard for daily emissions of fine particulate matter from 65 micrograms per cubic meter to 35 micrograms per cubic meter. Based on the new ozone daily emission standard, it would be expected that several areas that are currently designated as in attainment for ozone would be redesignated as nonattainment, including areas where IPL’s Eagle Valley and Harding Street plants are located. In January 2010, the EPA announced that it is extending by one year the deadline for promulgating initial area designations for the 2008 ozone NAAQS. EPA originally intended to complete the initial designations for the 2008 ozone NAAQS by March 12, 2010. However, if the Proposal is finalized, the 2008 ozone NAAQS would no longer apply and any area designations would be irrelevant. If EPA does not finalize the proposed revisions to the 2008 ozone NAAQS, it will promulgate initial area designations by March 12, 2011. In addition, the EPA released a proposed rule revising the current ozone standard. The proposed rule establishes a primary ozone standard at a level within the range of 0.060 to 0.070 parts per million (ppm) and a cumulative, seasonal secondary ozone standard at a level within the range of 7 to 15 ppm-hours. According to the proposed rule, EPA intends to issue a final rule revising the ozone NAAQS by August 31, 2010.

In 2005, several areas in the state of Indiana were designated as nonattainment for fine particulate matter for the daily and annual standards, which include the areas where IPL’s Eagle Valley, Petersburg, and Harding Street plants are located. With respect to the annual standard, nonattainment area designations have been challenged in court by the electric utility industry and others. In July 2009, the U.S. Court of Appeals for the District of Columbia Circuit upheld the EPA’s designation of nonattainment areas for fine particulate matter under the annual standard. The IPL plants continue to be in nonattainment areas under the annual fine particulate matter standard. With respect to the daily standard, in October 2009, the EPA announced plans to designate areas as nonattainment based on new data, and all areas where IPL plants are located, despite the more stringent standard, will be in attainment according to EPA.

Several states have also sued the EPA for failing to adopt more stringent standards for ozone and fine particulate matter. With regard to the challenge to the ozone standard, the EPA requested a stay in connection with its plans to reconsider this standard. With regard to the challenge to the fine particulate matter standard, a federal appeals court remanded the annual fine particulate matter standard to the EPA for further justification or, if appropriate, modification. The court found that the EPA failed to explain adequately why the annual fine particulate matter standard was sufficient to protect public health.

The nonattainment designations for both ozone and fine particulate matter, if upheld and if they remain in effect, will legally require the state of Indiana to modify its State Implementation Plan for ozone and fine particulate matter, in order to detail how the state will regain its attainment status. Indiana Department of Environmental Management has drafted plans to reach attainment status for fine particulate matter in the relevant counties, and Indiana Department of Environmental Management plans are pending approval by the EPA. The Indiana Department of Environmental Management current draft plan does not require our plants to install additional controls. However, it remains possible that the Indiana Department of Environmental Management or the EPA may require further efforts by our generating stations to reach attainment status. At this time, we cannot predict the impact of these EPA nonattainment designations.

In July 2009, the U.S. Court of Appeals for the District of Columbia Circuit vacated a rule that allowed compliance with the NOx State Implementation Plan Call to constitute compliance with reasonably available control technology for NOx emissions in ozone non-attainment areas. The decision implies that sources within ozone non-attainment areas may need to take actions in addition to compliance with the NOx State Implementation Plan Call, which may result in more stringent controls required at some of IPL’s generating facilities. However, at this time, we can not predict the impact of this decision on the EPA rules or Indiana’s State Implementation Plan.

In November 2009, the EPA released a proposed rule that would strengthen the primary NAAQS for SO2 by replacing the existing primary standards with a new one-hour standard. Specifically, the EPA is proposing to establish a new one-hour SO2 standard within the range of 50-100 parts per billion (ppb) based on the three-year average of the annual 99th percentile (or fourth highest) one-hour daily maximum concentrations. The new standard would replace the existing 24-hour standard of 140 ppb and the annual standard of 30 ppb. The EPA also is proposing changes to the ambient air monitoring and reporting requirements for SO2. The changes are expected to result in a minimum of 348 SO2 monitoring sites. The EPA will address the secondary NAAQS for SO2 in a separate rulemaking, planned for 2011. At this time, we can not predict the impact of this decision.

New Source Review

In October 2009, IPL received an NOV and Finding of Violation from EPA pursuant to CAA Section 113(a). The Notice alleges violations of the CAA at IPL’s three coal-fired electric generating facilities dating back to 1986. The alleged violations primarily pertain to EPA’s Prevention of Significant Deterioration and New Source Review programs under the CAA. Since receiving the letter, IPL management has met with EPA staff and is currently in discussions with the EPA regarding possible resolutions to this NOV. At this time, we cannot predict the ultimate resolution of this matter. However, settlements and litigated outcomes of similar cases have required companies to pay civil penalties and to install additional pollution control technology projects on coal-fired electric generating units. A similar outcome in this case could have a material impact to our business. We would seek recovery of any operating or capital expenditures related to pollution control technology projects to reduce regulated air emissions; however, there can be no assurances that we would be successful in that regard.

Regional Haze

Regional haze rule established planning and emissions reduction timelines for states to use to improve visibility in national parks throughout the United States. The rule sets guidelines for states in setting Best Available Retrofit Technology at older power plants. The EPA determined that states, such as Indiana, which adopt the federal CAIR “cap and trade” program for SO2 and NOx, will be allowed to apply federal CAIR controls to satisfy BART requirements. The Indiana Air Pollution Control Board also approved a final rule implementing BART which provides that sources in compliance with federal CAIR controls are also in compliance with BART requirements for SO2 and NOx. We anticipate that this rule will continue to apply after the EPA revises the federal CAIR rule, as described above, but there can be no assurance that it will.

Waste Management

In the course of operations, our facilities generate solid and liquid waste materials requiring eventual disposal or processing. With the exception of Coal Combustion Byproducts, its wastes are not usually physically disposed of on our property, but are shipped off site for final disposal, treatment or recycling. CCB, which consists of bottom ash, fly ash and air pollution control wastes, is disposed of at some of our coal-fired power generation plant sites using engineered, permitted landfills. Waste materials generated at our electric power and distribution facilities include CCB, oil, scrap metal, rubbish, small quantities of industrial hazardous wastes such as spent solvents, tree and land clearing wastes and polychlorinated biphenyl contaminated liquids and solids. We endeavor to ensure that all our solid and liquid wastes are disposed of in accordance with applicable national, regional, state and local regulations. In December 2008, a dike at a coal ash containment area at the Tennessee Valley Authority’s plant in Kingston, Tennessee failed and over 1 billion gallons of ash was released into adjacent waterways and properties. Following such incident, there has been heightened focus on the regulation of CCB and the EPA is expected to issue a proposed rule shortly regarding CCB storage and management. The EPA is also evaluating whether CCB should be regulated as a hazardous waste under the Resource Conservation and Recovery Act. If the EPA promulgates a rule that deems CCB to be a hazardous waste under the Resource Conservation and Recovery Act then our ash disposal costs would likely increase significantly. Also, we currently sell some of our CCB to third parties undertaking “beneficial use” projects in which the CCB is recycled, such as for use in concrete and other building materials. If CCB were deemed to be a hazardous waste under the Resource Conservation and Recovery Act, it could pose a significant hurdle for us to continue to sell CCB as a raw material for beneficial use. If third parties are likely to be less willing or unable to continue using CCB in their products we may no longer be able to generate revenue from the sale of such CCB, which would increase our disposal costs. While the exact impact and compliance cost associated with future regulations of CCB cannot be established until such regulations are promulgated, it is not clear whether the costs to implement such regulations will materially and adversely affect our business, results of operations, financial conditions or cash flows.

Summary

In summary, environmental laws and regulations presently require material capital expenditures and operating costs. Our capital expenditures relating to environmental matters were approximately $21 million in 2009, substantially all of which are related to CCT projects. We currently estimate total additional capital expenditures related to environmental matters of approximately $107 million for the three year period 2010-2012. This estimate could be impacted by the outcome of the EPA’s NOV described previously in this section. In addition, environmental laws are complex, change frequently and have tended to become more stringent over time. As a result, our operating expenses and continuing capital expenditures associated with environmental matters may increase. More stringent standards may also limit our operating flexibility. Because other U.S. electric power plants will have similar restrictions, we believe that compliance with more stringent environmental laws and regulations is not likely to affect our competitive position. However, depending upon the level and timing of recovery allowed by the IURC, these costs could materially and adversely affect our results of operations, financial condition, and cash flows. Please see “Regulatory Matters - Clean Coal Technology Filings” for a discussion of CCT filings.

Risk Management

Please see “Item 7A. Quantitative and Qualitative Disclosure about Market Risk” of this Form 10-K for a discussion of market risk and management’s risk management.

CRITICAL ACCOUNTING POLICIES

General

We prepare our consolidated financial statements in accordance with generally accepted accounting principles in the United States. As such, we are required to make certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period presented. Therefore, the possibility exists for materially different reported amounts under different conditions or assumptions. Significant accounting policies used in the preparation of the consolidated financial statements in Item 8 of this Form 10-K are described in Note 2, “Summary of Significant Accounting Policies” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K. This section addresses only those accounting policies involving amounts material to our financial statements that require the most estimation, judgment or assumptions and should be read in conjunction with Note 2, “Summary of Significant Accounting Policies” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K.

Regulation

As a regulated utility, we apply the provisions of ASC 980 “Regulated Operations,” which gives recognition to the ratemaking and accounting practices of the IURC and the FERC. In accordance with ASC 980, we have recognized as regulatory assets, deferred costs totaling $400.5 million that have been included as allowable costs for ratemaking purposes, as authorized by the IURC or established regulatory practices. Specific regulatory assets are disclosed in Note 8, “Regulatory Assets and Liabilities” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K. The deferral of costs (as regulatory assets) is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific orders from the IURC, regulatory precedent and the current regulatory environment. To the extent recovery of costs is no longer deemed probable, related regulatory assets would be required to be expensed in current period earnings. Our regulatory assets have been created pursuant to a specific order of the IURC or established regulatory practices, such as other utilities under the jurisdiction of the IURC being granted recovery of similar costs.

Revenue Recognition

Revenues related to the sale of energy are generally recognized when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is accrued. In making our estimates of unbilled revenue, we use complex models that consider various factors including daily generation volumes, known amounts of energy usage by certain customers, estimated line losses and estimated customer rates based on prior period billings. Given the use of these models, and that customers are billed on a monthly cycle, we believe it is unlikely that materially different results will occur in future periods when revenue is billed. As part of the estimation of unbilled revenues, we estimate line losses on a monthly basis. The effect on 2009 revenues and ending unbilled revenues of a 1% percentage point increase and decrease in the estimated line losses for the month of December 2009 is ($0.4 million) and $0.4 million, respectively. At December 31, 2009 and 2008, customer accounts receivable include unbilled energy revenues of $48.7 million and $47.4 million, respectively, on a base of annual revenue of $1.1 billion in each of 2009 and 2008.

Pension Costs

We contributed $20.1 million and $56.7 million to the Pension Plans in 2009 and 2008, respectively. There were no contributions to the Pension Plans in 2007.

Approximately 90% of IPL’s active employees are covered by the Defined Benefit Pension Plan as well as the Employees’ Thrift Plan of Indianapolis Power & Light Company. The Defined Benefit Pension Plan is a qualified defined benefit plan, while the Thrift Plan is a qualified defined contribution plan. The remaining 10% of active employees are covered by the RSP. The RSP is a qualified defined contribution plan containing a profit sharing component. All non-union new hires are covered under the RSP, while International Brotherhood of Electrical Workers physical unit union new hires are covered under the Defined Benefit Pension Plan and Thrift Plan. Beginning in 2007, International Brotherhood of Electrical Workers clerical-technical unit new hires are no longer covered under the Defined Benefit Pension Plan but do receive an annual lump sum company contributions into the Thrift Plan. This lump sum is in addition to IPL’s matching of participant contributions up to 5% of base compensation. The Defined Benefit Pension Plan is noncontributory and is funded through a trust. Benefits are based on each individual employee’s pension band and years of service as opposed to their compensation. Pension bands are based primarily on job duties and responsibilities.

Reported expenses relevant to the Defined Benefit Pension Plan are dependant upon numerous factors resulting from actual plan experience and assumptions of future experience, including the performance of plan assets and actual benefits paid out in future years. Pension costs associated with the Defined Benefit Pension Plan are impacted by the level of contributions made to the plan, earnings on plan assets and employee demographics, including age, job responsibilities and employment periods. Changes made to the provisions of the Defined Benefit Pension Plan may impact current and future pension costs. Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the corporate bond discount rates used in determining the projected benefit obligation and pension costs.

Additionally, a small group of former officers and their surviving spouses are covered under a funded non-qualified supplemental pension plan. The total number of participants in the plan as of December 31, 2009 is 29. The plan is closed to new participants.

From a Financial Accounting Standards Board financial statement perspective, IPL’s total underfunded pension liability was approximately $181.3 million as of December 31, 2009 of which the Defined Benefit Pension Plan liability and the Supplemental Retirement Plan of Indianapolis Power & Light Company liability represented $180.3 million and $1.0 million, respectively.

Pension plan assets consist of investments in equities (domestic and international), fixed income securities, alternative investments (hedge funds), and cash. Differences between actual portfolio returns and expected returns may result in increased or decreased pension costs in future periods. Pension costs are determined as of the plan’s measurement date of December 31, 2009. Per ASC 715, IPL elected to change the Pension Plans’ measurement date from November 30 to December 31, effective December 31, 2008. Pension costs are determined for the following year based on the market value of pension plan assets, expected level of employer contributions, a discount rate used to determine the projected benefit obligation and the expected long-term rate of return on plan assets.

For 2009, pension expense was determined using an assumed long-term rate of return on plan assets of 8.0%. As of the December 31, 2009 measurement date, IPL decreased the discount rate from 6.26% to 5.93% for the qualified plan and increased the discount rate from 5.06% to 5.27% for the supplemental plan, while maintaining an assumed long-term rate of return on plan assets at 8.0%. Due to settlement accounting, the discount rate for the supplemental plan which was initially 6.31% for the period January 1, 2009 thru November 30, 2009, was decreased to 5.06% on November 30, 2009. The effect on 2010 total pension expense of a 25 basis point increase and decrease in the assumed discount rate is ($1.1 million) and $1.2 million, respectively. The effect on 2010 total pension expense of a one percentage point increase and decrease in the expected long-term rate of return on plan assets is ($3.6 million) and $3.6 million, respectively.

During the year 2009, our pension plans incurred a net actuarial gain of $35.0 million. The net actuarial gain is comprised of two parts (net): (1) $46.6 million of pension asset actuarial gain is primarily due to the higher than expected return on assets, and (2) $11.6 million of pension liability actuarial loss is primarily due to a decrease in the discount rate that is used to value pension liabilities.

In determining the discount rate to use for valuing liabilities we use the market yield curve on high quality fixed income investments as of December 31, 2009. We project the expected benefit payments under the plan based on participant data which we supply and based on certain assumptions concerning mortality, retirement rates, termination rates, etc. The expected benefit payments for each year are discounted back to the measurement date using the appropriate spot rate for each half year from the yield curve, thereby obtaining a present value of all expected future benefit payments using the yield curve. Finally, an equivalent single discount rate is determined which produces a present value equal to the present value determined using the full yield curve.

In determining our discount rate, we utilize a yield curve created by deriving the rates for hypothetical zero coupon bonds from high-yield AA-rated coupon bonds of varying maturities between 0.5 and 30 years. Non-callable bonds and outliers (defined as bonds with yields outside of two standard deviations from the mean) are excluded in computing the yield curve. Using the bond universe just described, regression analysis using least squares regression is used to determine the best-fitting regression curve that links yield-to-maturity to time-to maturity. We then convert the regressed coupon yield curve into a spot rate curve using the standard “bootstrapping” technique, which assumes that the price of a coupon bond for a given maturity equals the present value of the underlying bond cash flows using zero-coupon spot rates. In making this conversion, we assume that the regressed coupon yield at each maturity date represents a coupon-paying bond trading at par. We also convert the bond-equivalent (compounded semiannually) yields to effective annual yields during this process. The pension cash flows are produced for each year into the future until no more benefit payments are expected to be paid, and represent the cash flows used to produce the pension benefit obligation for pension valuations. The pension cash flows are matched to the appropriate spot rates and discounted back to the measurement date. The cash flows after 30 years are discounted assuming the 30-year spot rate remains constant beyond 30 years. Once the present value of the cash flows as of the measurement date has been determined using the spot rates from the Mercer Yield Curve, a single equivalent discount rate is developed. This rate is the single uniform discount rate that, when applied to the same cash flows, results in the same present value of the cash flows as of the measurement date.

In establishing our expected long-term rate of return assumption, we utilize a methodology which employs the practice of using a “risk premium building block” approach as the framework. This approach involves using historical performance data to first determine the return differential between a particular asset class and a less risky base index (i.e., the added return provided to investors as compensation for assuming added risk), then applying that premium to the estimate of the base index’s future long-term return. The expected future weighted-average returns for each asset class based on the target asset allocation are taken into account.

The process begins by calculating the long-term return estimate for cash, or the “risk-free rate.” This is the foundation for the building block methodology. Then a long-term inflation rate is estimated based upon certain economic assumptions. For each asset class, the historical annualized return of the asset class is determined, then reduced by the historical annualized return of cash during the same time period, which represents the historical “risk premium.” This calculated risk premium is then added to the long-term return estimate for cash. The calculated estimate is then adjusted to take into account current market conditions and expectations. We conducted an additional analysis of the long-term rate of return on pension assets to validate the results of the “risk premium building block” methodology.

Impairment of Long-lived Assets

Generally accepted accounting principles in the United States require that we measure long-lived assets for impairment when indicators of impairment exist. If an asset is deemed to be impaired, we are required to write down the asset to its fair value with a charge to current earnings. The net book value of our utility plant assets was $2.3 billion at December 31, 2009 and 2008. We do not believe any of these assets are currently impaired. In making this assessment, we consider such factors as: the overall condition and generating and distribution capacity of the assets; the expected ability to recover additional expenditures in the assets, such as CCT projects; the anticipated demand and relative pricing of retail electricity in our service territory and wholesale electricity in the region; and the cost of fuel.

Fair Value Measurements

ASC 820 defined and established a framework for measuring fair value and expands disclosures about fair value measurements for financial assets and liabilities that are adjusted to fair value on a recurring basis and/or financial assets and liabilities that are measured at fair value on a nonrecurring basis, which have been adjusted to fair value during the period. IPALCO did have one financial asset measured at fair value on a nonrecurring basis, which has been adjusted to fair value during the periods covered by this report. In June 2009, IPALCO recorded a $1.8 million impairment loss on its investment in EnerTech, which is accounted for using the cost method. The investment was deemed to be other than temporarily impaired. In making this determination, we considered, among other things, the amount and length of time of impairment of the individual investments held by EnerTech as well as the future outlook of such investments. Because the investment is not publicly traded and therefore does not have a quoted market price, the impairment loss was based on our best available estimate of the fair value of the investment, which included primarily unobservable estimates.

In accordance with ASC 820, we have categorized our financial assets and liabilities that are adjusted to fair value on a recurring basis, based on the priority of the inputs to the valuation technique, based on the three-level fair value hierarchy prescribed by ASC 820. As of December 31, 2009 and 2008 (excluding pension assets) all of our financial assets or liabilities measured at fair value on a recurring basis were categorized as Level 3 because the values were based primarily on unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability. For a complete discussion of the impact of recognizing pension assets at fair value, please see Note 13, “Pension and Other Postretirement Benefits,” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K

The following table presents those financial assets and liabilities:


	Fair Value Measurements using Level 3 at:
	December 31, 2009		December 31, 2008
	*(In Thousands)*
Financial assets:
Investments in debt securities	$	42,000	$	41,550
Financial transmission rights		944		5,298
Total financial assets measured at fair value	$	42,944	$	46,848

Financial liabilities:
Interest rate swap	$	8,179	$	9,918
Other derivative liability		198		194
Total financial liabilities measured at fair value	$	8,377	$	10,112

Of the items in the table above, any changes in fair value for the interest rate swap or financial transmission rights are recorded with an offsetting adjustment to a regulatory asset or regulatory liability and therefore do not impact our earnings. Any changes in the fair value of the investments in debt securities or derivative liability would be adjusted through earnings. While we believe that the recorded value of these items approximates fair value, because the fair values are based primarily from unobservable inputs, it is likely that the actual amount we would receive if we were to sell the assets and/or the amount we would have to pay to transfer these liabilities is different from their book values and such difference, if known, would be adjusted through earnings.

Income Taxes

We are subject to federal and state of Indiana income taxes. Our income tax provision requires significant judgment and is based on calculations and assumptions that are subject to examination by the U.S. Internal Revenue Service and other tax authorities. We regularly assess the potential outcome of tax examinations when determining the adequacy of our income tax provisions by considering the technical merits of the filing position, case law, and results of previous tax examinations. ASC 740 prescribes a more-likely-than-not recognition threshold and measurement requirements for financial statement reporting of our income tax positions. Tax reserves have been established, which we believe to be adequate in relation to the potential for additional assessments. Once established, reserves are adjusted only when there is more information available or when an event occurs necessitating a change to the reserves. While we believe that the amount of the tax reserves is reasonable, it is possible that the ultimate outcome of future examinations may exceed current reserves in amounts that could be material.

Contingencies

We accrue for loss contingencies when the amount of the loss is probable and estimable. We are subject to various environmental regulations, and are involved in certain legal proceedings. If our actual environmental and/or legal obligations are different from our estimates, the recognition of the actual amounts may have a material impact on our results of operations, financial condition, and cash flows; although that has not been the case during the periods covered by this report. Please see Note 14, “Commitments and Contingencies” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K for a summary of significant contingencies involving us.

NEW ACCOUNTING STANDARDS

Please see Note 2, “Summary of Significant Accounting Policies” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K for a discussion of new accounting pronouncements and the potential impact to our results of operations, financial condition, and cash flows.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

Overview

The primary market risks to which we are exposed are those associated with fluctuations in interest rates and the prices of fuel, wholesale power, SO2 allowances and certain raw materials, including steel, copper and other commodities. We use financial instruments and other contracts to hedge against such fluctuations, including, on a limited basis, financial and commodity derivatives. We generally do not enter into derivative instruments for trading or speculative purposes.

Interest Rate Risk

We use long-term debt as a significant source of capital in our business, which exposes us to interest rate risk. We do not enter into market risk sensitive instruments for trading purposes. We manage our exposure to interest rate risk through the use of fixed-rate debt, interest rate derivative instruments and by refinancing existing long-term debt at times when it is deemed economic and prudent. In addition, Indianapolis Power & Light Company has one credit facility that bears interest at variable rates based either on the Prime interest rate or on the London InterBank Offer Rate. Our fair values relating to financial instruments are dependent upon prevalent market rates of interest, primarily the London InterBank Offer Rate. At December 31, 2009, we had approximately $1,633 million principal amount fixed rate debt and $80.0 million principal amount variable rate debt outstanding.

The variable rate debt included (i) a $40 million IPL unsecured note, which is synthetically fixed at 5.21% through a floating-to-fixed interest rate swap, which expires concurrent with the maturity of the 1995B Bonds in January 2023 and (ii) $40 million outstanding on our credit facility. The fair value of IPL’s swap agreement was ($8.2 million) at December 31, 2009. Based on amounts outstanding as of December 31, 2009, a 25 basis point increase in the applicable rates on our variable-rate debt would have the effect of increasing our annual interest expense and cash paid for interest by $0.1 million. Conversely, a 25 basis point decrease in the applicable rates would have the effect of decreasing our annual interest expense and cash paid for interest by $0.1 million.

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Impacts of Weak Economic Conditions” for information regarding the 1995B Bonds.

The following table shows our consolidated indebtedness (in millions) by maturity as of December 31, 2009:


	2010		2011		2012		2013		2014		Thereafter		Total		Fair Value
	*(In Millions)*
Fixed-rate debt	$	-	$	375.0	$	-	$	110.0	$	-	$	1,147.7	$	1,632.7	$	1,664.9
Variable-rate debt		-		40.0		-		-		-		-		40.0		40.0
Variable-rate debt swapped to fixed		-		-		-		-		-		40.0		40.0		40.0
Total Indebtedness	$	-	$	415.0	$	-	$	110.0	$	-	$	1,187.7	$	1,712.7	$	1,744.9

Weighted Average Interest Rates by Maturity		N/A		7.86%		N/A		6.30%		N/A		6.35%		6.71%

For further discussion of our fair value of our indebtedness and book value of our indebtedness please see Note 7, “Fair Value Measurements” and Note 11, “Indebtedness” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K.

Credit Market Risk

In the recent past there has been volatility and a downturn in the credit market in the United States. This situation has impacted volatility and returns in many areas of the economy. Based on our relatively small percentage of unhedged variable rate debt in our capital structure, our interest rate exposure to the current credit market crisis is limited and to date, has not been material. See “Interest Rate Risk” above. Additionally, because we do not have any indebtedness maturing before May 2011 and because of other factors that contribute to an overall strong liquidity position, we do not anticipate a need to access the credit markets in 2010.

Equity Market Risk

Our pension plan is impacted significantly by the economy as a result of the pension plan being heavily invested in common equity securities. As described previously under Overview, during the year 2008, our Pension Plans suffered a significant net actuarial loss. In addition, a funding shortfall was created primarily by the poor performance of the pension assets in 2008. The funding shortfall decreased as a result of the higher than expected return on pension assets during the year 2009. Please see Note 13, “Pension and Other Postretirement Benefits” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K for additional Pension Plan information.

Inflation

During 2009 the recession has had the effect of halting the rapid inflation on certain raw materials, including steel, copper and other commodities that we experienced over the previous few years to the point where some costs have even declined. These and other raw materials serve as inputs to many operating and maintenance processes fundamental to the electric utility industry. Lower prices reduce our operating and maintenance costs and improve our liquidity. The primary area in which inflation has continued at a steep rate is in the cost of healthcare provided to our employees. This has negatively impacted our results of operations, financial condition, and cash flows in recent years.

Fuel

We have limited exposure to commodity price risk for the purchase of coal, the primary fuel used by us for the production of electricity. We manage this risk by providing for nearly all of our current projected burn through 2010 and approximately 90% of our current projected burn for the three year period ending December 31, 2012, under long-term contracts. Pricing provisions in some of our long-term coal contracts allow for price changes under certain circumstances. Coal purchases made in 2010 are expected to be made at prices that are higher than our weighted average price in 2009. Our exposure to fluctuations in the price of coal is limited because pursuant to Indiana law, we may apply to the IURC for a change in our fuel charge every three months to recover our estimated fuel costs, which may be above or below the levels included in our basic rates. We must present evidence in each FAC proceeding that we have made every reasonable effort to acquire fuel and generate or purchase power or both so as to provide electricity to our retail customers at the lowest fuel cost reasonably possible.

Power Purchases

We depend on purchased power, in part, to meet our retail load obligations. As a result, we also have limited exposure to commodity price risk for the purchase of electric energy for our retail customers. Purchased power costs can be highly volatile. We are generally allowed to recover, through our FAC, the energy portion of purchased power costs incurred to meet jurisdictional retail load. In certain circumstances, we may not be allowed to recover a portion of purchased power costs incurred to meet our jurisdictional retail load. See “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Regulatory Matters - Fuel Adjustment Charge and Authorized Annual Jurisdictional Net Operating Income.”

Retail Energy Market

The legislatures of several states have enacted laws that would allow various forms of competition or that experiment with allowing some form of customer choice of electricity suppliers for retail sales of electric energy. Indiana has not done so. In Indiana, competition among electric energy providers for sales has focused primarily on the sale of bulk power to other public and municipal utilities. Indiana law provides for electricity suppliers to have exclusive retail service areas. In order to increase sales, we work to attract new customers into our service territory. Although the retail sales of electric energy are regulated, we face competition from other energy sources. For example, customers have a choice of installing electric or natural gas home and hot water heating systems.

Wholesale Sales

We engage in limited wholesale power marketing to earn wholesale revenues after first providing for our projected utility retail load. Our ability to compete effectively in the wholesale market is dependent on a variety of factors, including our generating availability, the supply of wholesale power, and the price, terms and conditions of sales we propose. Our wholesale revenues are generated primarily from sales directly to the Midwest ISO Energy Market, replacing the previous practice of direct wholesale sales to individual wholesale counter-parties using existing interchange agreements. During 2009, the average market price per kWh we sold wholesale decreased by 45% to $26.62 when compared to 2008. During the past five years, wholesale revenues represented 6% of our total electric revenues on average.

Counter-Party Credit Risk

At times, we may utilize forward purchase contracts to manage the risk associated with power purchases, and could be exposed to counter-party credit risk in these contracts. We manage this exposure to counter-party credit risk by entering into contracts with companies that are expected to fully perform under the terms of the contract. Individual credit limits are implemented for each counter-party to further mitigate credit risk. We may also ask a counter-party to provide collateral in the event certain credit ratings are not maintained, or certain financial benchmarks are not maintained.

Other Risks

We have experienced a slight increase in write-offs of our customer accounts over the past three years, which may have been impacted by the volatility in the financial markets and general slowing of the economy. If the recession worsens or is prolonged, write-offs could increase.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


Index to Financial Statements


IPALCO Enterprises, Inc. and Subsidiaries - Consolidated Financial Statements
	Report of Independent Registered Public Accounting Firm - 2009 and 2008
	Report of Independent Registered Public Accounting Firm - 2007
	Defined Terms
	Consolidated Statements of Income for the years ended December 31, 2009, 2008 and 2007
	Consolidated Balance Sheets as of December 31, 2009 and 2008
	Consolidated Statements of Cash Flows for the years ended December 31, 2009, 2008 and 2007
	Consolidated Statements of Common Shareholder’s Deficit for the years ended December 31, 2009, 2008 and 2007
	Notes to Consolidated Financial Statements

Indianapolis Power & Light Company and Subsidiary - Consolidated Financial Statements
	Report of Independent Registered Public Accounting Firm - 2009 and 2008
	Report of Independent Registered Public Accounting Firm - 2007
	Defined Terms
	Consolidated Statements of Income for the years ended December 31, 2009, 2008 and 2007
	Consolidated Balance Sheets as of December 31, 2009 and 2008
	Consolidated Statements of Cash Flows for the year ended December 31, 2009, 2008 and 2007
	Consolidated Statements of Common Shareholder’s Deficit for the years ended December 31, 2009, 2008 and 2007
	Notes to Consolidated Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholder and Board of Directors of

IPALCO Enterprises, Inc.

We have audited the accompanying consolidated balance sheets of IPALCO Enterprises, Inc. and subsidiaries (the Company) as of December 31, 2009 and 2008, and the related consolidated statements of income, common shareholder’s deficit, and cash flows for each of the two years in the period ended December 31, 2009. Our audits also included the financial statement schedules listed in the Index at Item 15 as of and for the years ended December 31, 2009 and 2008. These financial statements and schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of IPALCO Enterprises, Inc. and subsidiaries at December 31, 2009 and 2008, and the consolidated results of their operations and their cash flows for each of the two years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedules as of and for the years ended December 31, 2009 and 2008, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.

/s/ ERNST & YOUNG LLP

Indianapolis, Indiana

February 25, 2010

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholder and Board of Directors of

IPALCO Enterprises, Inc.

Indianapolis, Indiana

We have audited the accompanying consolidated statements of income, common shareholder’s deficit and noncontrolling interest, and cash flows of IPALCO Enterprises, Inc. and subsidiaries (the “Company”) for the year ended December 31, 2007. Our audit also included the financial statement schedule for 2007 listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such 2007 consolidated financial statements present fairly, in all material respects, the results of operations and cash flows of IPALCO Enterprises, Inc. and subsidiaries for the year ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule for 2007, when considered in relation to the basic 2007 consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 2 to the consolidated financial statements, the accompanying 2007 financial statements have been retrospectively adjusted for the adoption of accounting guidance related to the presentation of noncontrolling interests in consolidated financial statements.

/s/ DELOITTE & TOUCHE LLP

Indianapolis, Indiana
March 24, 2008 (February 25, 2010 as to Note 2)


DEFINED TERMS
The following is a list of frequently used abbreviations or acronyms that are found in the Financial Statements and Supplementary Data:

1995B Bonds	$40 Million City of Petersburg, Indiana, Pollution Control Refunding Revenue Bonds Adjustable Rate Tender Securities Series 1995B, Indianapolis Power & Light Company Project
2011 IPALCO Notes	$375 million of 8.625% (original coupon 7.625%) Senior Secured Notes due November 14, 2011
2016 IPALCO Notes	$400 million of 7.25% Senior Secured Notes due April 1, 2016
AES	The AES Corporation
ARO	Asset Retirement Obligations
ASM	Ancillary Services Market
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CCT	Clean Coal Technology
Defined Benefit Pension Plan	Employees’ Retirement Plan of Indianapolis Power & Light Company
ECCRA	Environmental Compliance Cost Recovery Adjustment
EPA	U.S. Environmental Protection Agency
FAC	Fuel Adjustment Charges
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FTR	Financial Transmission Right
GAAP	Generally accepted accounting principles in the United States
IBEW	International Brotherhood of Electrical Workers
IPALCO	IPALCO Enterprises, Inc.
IPL	Indianapolis Power & Light Company
IPL Funding	IPL Funding Corporation
IURC	Indiana Utility Regulatory Commission
Mid-America	Mid-America Capital Resources, Inc.
Midwest ISO	Midwest Independent Transmission System Operator, Inc.
NOV	Notice of Violation
NOx	Nitrogen Oxides
Pension Plans	Employees’ Retirement Plan of Indianapolis Power & Light Company and Supplemental Retirement Plan of Indianapolis Power & Light Company
RSG	Revenue Sufficiency Guarantee
RSP	The AES Retirement Savings Plan
SFAS	Statement of Financial Accounting Standards
SO2	Sulfur Dioxide
Supplemental Retirement Plan	Supplemental Retirement Plan of Indianapolis Power & Light Company
S&P	Standard & Poors
Thrift Plan	Employees’ Thrift Plan of Indianapolis Power & Light Company
VEBA Trust	Voluntary Employee Beneficiary Association Trust
VERP	Voluntary Early Retirement Program


IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Income
For the Years Ended December 31, 2009, 2008 and 2007
*(In Thousands)*

	2009		2008		2007

UTILITY OPERATING REVENUES	$	1,068,081	$	1,079,113	$	1,052,627

UTILITY OPERATING EXPENSES:
Operation:
Fuel		276,422		268,997		237,154
Other operating expenses		200,890		190,871		172,571
Power purchased		46,646		57,220		57,565
Maintenance		102,332		97,056		84,859
Depreciation and amortization		162,167		161,022		140,944
Taxes other than income taxes		35,732		40,934		41,361
Income taxes - net		73,935		81,120		107,755
Total utility operating expenses		898,124		897,220		842,209
UTILITY OPERATING INCOME		169,957		181,893		210,418

OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used during construction		2,024		1,104		3,747
Miscellaneous income and (deductions) - net		(3,785)		(3,740)		347
Income tax benefit - net		26,103		32,847		26,158
Total other income and (deductions) - net		24,342		30,211		30,252

INTEREST AND OTHER CHARGES:
Interest on long-term debt		116,970		133,302		114,146
Other interest		1,391		1,579		1,837
Allowance for borrowed funds used during construction		(1,608)		(1,188)		(3,698)
Amortization of redemption premiums and expense on debt		3,778		3,746		3,056
Total interest and other charges-net		120,531		137,439		115,341
NET INCOME		73,768		74,665		125,329
LESS: PREFERRED DIVIDENDS OF SUBSIDIARY		3,213		3,213		3,213
NET INCOME APPLICABLE TO COMMON STOCK	$	70,555	$	71,452	$	122,116

See notes to consolidated financial statements.


IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Balance Sheets
(In Thousands)

	December 31, 2009		December 31, 2008
ASSETS
UTILITY PLANT:
Utility plant in service	$	4,020,492	$	3,919,710
Less accumulated depreciation		1,788,588		1,677,496
Utility plant in service - net		2,231,904		2,242,214
Construction work in progress		76,472		86,858
Spare parts inventory		12,309		11,053
Property held for future use		991		947
Utility plant - net		2,321,676		2,341,072

OTHER ASSETS:
Investment in long-term debt securities (Note 3)		42,000		-
Nonutility property - at cost, less accumulated depreciation		693		698
Other investments		7,992		9,886
Other assets - net		50,685		10,584

CURRENT ASSETS:
Cash and cash equivalents		48,022		16,509
Short-term investments (Note 3)		-		41,550
Accounts receivable and unbilled revenue (less allowance for doubtful accounts of $2,143 and $1,801, respectively)		86,657		86,876
Fuel - at average cost		38,203		31,119
Materials and supplies - at average cost		49,925		47,917
Financial transmission rights		944		5,298
Deferred tax asset - current		9,550		8,531
Regulatory assets		4,828		17,345
Prepayments and other current assets		7,773		9,216
Total current assets		245,902		264,361

DEFERRED DEBITS:
Regulatory assets		395,651		461,729
Miscellaneous		21,431		24,665
Total deferred debits		417,082		486,394
TOTAL	$	3,035,345	$	3,102,411


CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common shareholder’s deficit:
Pain in Capital		9,820		8,624
Accumulated deficit		(18,878)		(18,533)
Total common shareholder’s deficit		(9,058)		(9,909)
Cumulative preferred stock of subsidiary		59,784		59,784
Long-term debt		1,706,695		1,666,085
Total capitalization		1,757,421		1,715,960

CURRENT LIABILITIES:
Short-term debt		-		52,691
Accounts payable		60,672		69,599
Accrued expenses		23,026		22,473
Accrued real estate and personal property taxes		23,631		26,812
Regulatory liabilities		13,863		5,735
Accrued interest		30,826		28,168
Customer deposits		18,816		16,928
Other current liabilities		9,498		11,204
Total current liabilities		180,332		233,610

DEFERRED CREDITS AND OTHER LONG-TERM LIABILITIES:
Accumulated deferred income taxes - net		374,953		398,089
Non-current income tax liability		8,618		8,351
Regulatory liabilities		492,000		471,002
Unamortized investment tax credit		13,153		15,212
Accrued pension and other postretirement benefits		185,815		234,670
Miscellaneous		23,053		25,517
Total deferred credits and other long-term liabilities		1,097,592		1,152,841

COMMITMENTS AND CONTINGENCIES (Note 14)
TOTAL	$	3,035,345	$	3,102,411

See notes to consolidated financial statements.


IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Cash Flows
For the Years Ended December 31, 2009, 2008 and 2007
*(In Thousands)*

	2009		2008		2007
CASH FLOWS FROM OPERATIONS:
Net income	$	73,768	$	74,665	$	125,329
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		159,706		154,452		143,496
Amortization of regulatory assets		7,726		11,598		1,810
Deferred income taxes and investment tax credit adjustments - net		(22,394)		(12,135)		(5,769)
Tender fees expensed as interest		-		13,852		-
Emissions allowance expense		-		-		2,227
Gains on sales and exchange of environmental emissions allowances		(84)		(549)		(655)
Allowance for equity funds used during construction		(1,807)		(954)		(3,656)
Change in certain assets and liabilities:
Accounts receivable		219		(16,446)		(2,554)
Fuel, materials and supplies		(9,093)		(13,122)		7,921
Income taxes receivable or payable		(2,007)		8,071		(506)
Financial transmission rights		4,353		(3,745)		(279)
Accounts payable and accrued expenses		570		12,848		5,366
Accrued real estate and personal property taxes		(3,180)		6,534		4,369
Accrued interest		2,658		4,279		(2,206)
Pension and other postretirement benefit expenses		(48,855)		144,890		(43,085)
Short-term and long-term regulatory assets and liabilities		75,241		(209,737)		27,004
Other - net		4,878		9,320		2,498
Net cash provided by operating activities		241,699		183,821		261,310

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures - utility		(115,363)		(106,906)		(201,060)
Decrease in restricted cash		-		6		32,700
Purchase of environmental emissions allowances		-		(200)		(2,743)
Purchase of investments		(40,300)		(121,842)		(529,720)
Proceeds from sales and maturities of short-term investments		40,436		83,425		530,023
Other		(6,078)		(3,710)		(10,515)
Net cash used in investing activities		(121,305)		(149,227)		(181,315)

CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt borrowings (repayments) - net		(52,691)		51,691		(74,000)
Long-term borrowings		171,850		394,105		164,985
Retirement of long-term debt and early tender premium		(131,850)		(388,852)		(80,000)
Dividends on common stock		(70,900)		(71,558)		(85,762)
Preferred dividends of subsidiary		(3,213)		(3,213)		(3,213)
Other		(2,077)		(8,001)		(2,907)
Net cash used in financing activities		(88,881)		(25,828)		(80,897)
Net change in cash and cash equivalents		31,513		8,766		(902)
Cash and cash equivalents at beginning of period		16,509		7,743		8,645
Cash and cash equivalents at end of period	$	48,022	$	16,509	$	7,743

Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized)	$	115,297	$	130,031	$	117,584
Income taxes	$	72,000	$	51,583	$	85,433

See notes to consolidated financial statements.


IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Common Shareholder’s Deficit
and Noncontrolling Interest
For the Years Ended December 31, 2009, 2008 and 2007
*(In Thousands)*

	Premium on 4% Cumulative Preferred Stock		Paid in Capital		Accumulated Deficit		Accumulated Other Comprehensive Loss			Total		Cumulative Preferred Stock of Subsidiary
2007
Beginning Balance	$	649	$	3,479	$	(54,808)	$	(2)	$	(50,682)	$		59,135
Comprehensive Income:
Net income applicable to common stock						122,116				122,116
Other comprehensive income:
Sale of available for sale securities								2		2
Total Comprehensive Income								2		122,118

Reclassification to cumulative preferred stock of subsidiary		(649)								(649)			649
Adjustment for the adoption of FIN 48						438				438
Distributions to AES						(85,762)				(85,762)
Contributions from AES				3,299						3,299
Balance at December 31, 2007	$	-	$	6,778	$	(18,016)	$	-	$	(11,238)	$		59,784
2008
Comprehensive Income:
Net income applicable to common stock						71,452				71,452
Total Comprehensive Income										71,452

Adjustment for the adoption of SFAS 158, net of income taxes of $281 stock of subsidiary						(411)				(411)
Distributions to AES						(71,558)				(71,558)
Contributions from AES				1,846						1,846
Balance at December 31, 2008	$	-	$	8,624	$	(18,533)	$	-	$	(9,909)	$		59,784
2009
Comprehensive Income:
Net income applicable to common stock						70,555				70,555
Total Comprehensive Income										70,555

Distributions to AES						(70,900)				(70,900)
Contributions from AES				1,196						1,196
Balance at December 31, 2009	$	-	$	9,820	$	(18,878)	$	-	$	(9,058)	$		59,784
See notes to consolidated financial statements.

IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Notes to Consolidated Financial Statements
For the Years Ended December 31, 2009, 2008 and 2007

1. ORGANIZATION

IPALCO Enterprises, Inc. is a holding company incorporated under the laws of the state of Indiana. IPALCO is a wholly-owned subsidiary of The AES Corporation, acquired by AES in March 2001. IPALCO owns all of the outstanding common stock of its subsidiaries. Substantially all of IPALCO’s business consists of the generation, transmission, distribution and sale of electric energy conducted through its principal subsidiary, Indianapolis Power & Light Company. IPL was incorporated under the laws of the state of Indiana in 1926. IPL has approximately 470,000 retail customers in the city of Indianapolis and neighboring cities, towns and communities, and adjacent rural areas all within the state of Indiana, the most distant point being approximately forty miles from Indianapolis. IPL has an exclusive right to provide electric service to those customers. IPL owns and operates two primarily coal-fired generating plants, one combination coal and gas-fired plant and a separately-sited combustion turbine that are all used for generating electricity. IPL’s net electric generation capability for winter is 3,492 megawatts and net summer capability is 3,353 megawatts.

IPALCO’s other direct subsidiary is Mid-America Capital Resources, Inc. Mid-America is the holding company for IPALCO’s unregulated activities. Mid-America owns a 4.4% interest in EnerTech Capital Partners II L.P., a venture capital fund that invests in early stage and emerging growth companies in the energy technology, clean technology and related markets, with a recorded value of $5.3 million as of December 31, 2009. IPALCO’s regulated business is conducted through IPL. IPALCO has two business segments: utility and nonutility. The utility segment consists of the operations of IPL and everything else is included in the nonutility segment.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

IPALCO’s consolidated financial statements are prepared in accordance with generally accepted accounting principles in the United States and in conjunction with the rules and regulations of the Securities and Exchange Commission. The consolidated financial statements include the accounts of IPALCO, its regulated utility subsidiary, IPL, and its unregulated subsidiary, Mid-America. All intercompany items have been eliminated in consolidation. We have evaluated subsequent events through February 25, 2010, which is the same date this report is issued.

All income of Mid-America, as well as nonoperating income of IPL, are included below UTILITY OPERATING INCOME in the accompanying consolidated statements of income.

Use of Management Estimates

The preparation of financial statements in conformity with GAAP requires that management make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. The reported amounts of revenues and expenses during the reporting period may also be affected by the estimates and assumptions management is required to make. Actual results may differ from those estimates.

Reclassifications

Certain prior period amounts have been reclassified to conform to the current year presentation.

Regulation

The retail utility operations of IPL are subject to the jurisdiction of the Indiana Utility Regulatory Commission. IPL’s wholesale power transactions are subject to the jurisdiction of the Federal Energy Regulatory Commission. These agencies regulate IPL’s utility business operations, tariffs, accounting, depreciation allowances, services, security issues and the sale and acquisition of utility properties. The financial statements of IPL are based on GAAP, including the provisions of ASC 980 “Regulated Operations,” which gives recognition to the ratemaking and accounting practices of these agencies. See also Note 8, “Regulatory Assets and Liabilities” for a discussion of specific regulatory assets and liabilities.

Revenues

Revenues related to the sale of energy are generally recognized when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is accrued. In making its estimates of unbilled revenue, IPL uses complex models that consider various factors including daily generation volumes, known amounts of energy usage by certain customers, estimated line losses and estimated customer rates based on prior period billings. Given the use of these models, and that customers are billed on a monthly cycle, we believe it is unlikely that materially different results will occur in future periods when revenue is billed. As part of the estimation of unbilled revenues, IPL estimates line losses on a monthly basis. At December 31, 2009 and 2008, customer accounts receivable include unbilled energy revenues of $48.7 million and $47.4 million, respectively, on a base of annual revenue of $1.1 billion in each of 2009 and 2008.

IPL’s basic rates include a provision for fuel costs as established in IPL’s most recent rate proceeding. IPL is permitted to recover actual costs of purchased power and fuel consumed, subject to certain restrictions. This is accomplished through quarterly Fuel Adjustment Charge proceedings, in which IPL estimates the amount of fuel and purchased power costs in future periods. Through these proceedings, IPL is also permitted to recover, in future rates, underestimated fuel and purchased power costs from prior periods, subject to certain restrictions, and therefore the over or underestimated costs are deferred or accrued and amortized into fuel expense in the same period that IPL’s rates are adjusted.

In addition, we are one of many transmission owners of the Midwest Independent Transmission System Operator, Inc., a regional transmission organization which maintains functional control over the combined transmission systems of its members and manages one of the largest energy markets in the U.S. In the Midwest ISO market, IPL offers its generation and bids its demand into the market on an hourly basis. The Midwest ISO settles these hourly offers and bids based on locational marginal prices, which is pricing for energy at a given location based on a market clearing price that takes into account physical limitations, generation and demand throughout the Midwest ISO region. The Midwest ISO evaluates the market participants’ energy offers and demand bids to economically and reliably dispatch the entire Midwest ISO system on a five-minute basis. IPL accounts for these hourly offers and bids, on a net basis, in UTILITY OPERATING REVENUES when in a net selling position and in UTILITY OPERATING EXPENSES - Power Purchased when in a net purchasing position.

Contingencies

IPALCO accrues for loss contingencies when the amount of the loss is probable and estimable. IPL is subject to various environmental regulations, and is involved in certain legal proceedings. If IPL’s actual environmental and/or legal obligations are different from our estimates, the recognition of the actual amounts may have a material impact on our results of operations, financial condition, and cash flows; although that has not been the case during the periods covered by this report.

Concentrations of Risk

Substantially all of IPL’s customers are located within the Indianapolis area. In addition, approximately 65% of IPL’s full-time employees are covered by collective bargaining agreements in two bargaining units: a physical unit and a clerical-technical unit. IPL’s current contract with the physical unit expires on December 3, 2012 and the contract with the clerical-technical unit expires February 14, 2011. Additionally, IPL has long-term coal contracts with five suppliers, with about 40% of our existing coal under contract coming from one supplier. Substantially all of the coal is currently mined in the state of Indiana.

Allowance For Funds Used During Construction

In accordance with the Uniform System of Accounts prescribed by FERC, IPL capitalizes an allowance for the net cost of funds (interest on borrowed funds and a reasonable rate of return on equity funds) used for construction purposes during the period of construction with a corresponding credit to income. IPL capitalized amounts using pretax composite rates of 8.8%, 8.7%, and 8.4% during 2009, 2008, and 2007, respectively.

Utility Plant and Depreciation

Utility plant is stated at original cost as defined for regulatory purposes. The cost of additions to utility plant and replacements of retirement units of property are charged to plant accounts. Units of property replaced or abandoned in the ordinary course of business are retired from the plant accounts at cost; such amounts, less salvage, are charged to accumulated depreciation. Depreciation is computed by the straight-line method based on functional rates approved by the IURC and averaged 4.0%, 3.9%, and 3.8% during 2009, 2008 and 2007, respectively. Depreciation expense was $156.9 million, $151.4 million, and $141.7 million for the years ended December 31, 2009, 2008 and 2007, respectively.

Derivatives

We have only limited involvement with derivative financial instruments and do not use them for trading purposes. IPALCO accounts for its derivatives in accordance with ASC 815 “Derivatives and Hedging.” IPL has one interest rate swap agreement, which is recognized on the audited Consolidated Balance Sheets at its estimated fair value as a liability of approximately $8.2 million. IPL entered into this agreement as a means of managing the interest rate exposure on a $40 million unsecured variable-rate debt instrument. The swap was approved by the IURC as part of IPL’s 1994 financing order. In accordance with ASC 980, IPALCO recognized a regulatory asset equal to the value of the interest rate swap, which is adjusted as that fair value changes. The settlement amounts from the swap agreement are reported in the financial statements as a component of interest expense. Management uses standard market conventions, in accordance with ASC 820 “Fair Value Measurements and Disclosures,” to determine the fair value of the interest rate swap.

In addition, IPL has entered into contracts involving the physical delivery of energy and fuel. Because these contracts qualify for the normal purchases and sales scope exception in ASC 815, IPL has elected to account for them as accrual contracts, which are not adjusted for changes in fair value.

Fuel, Materials and Supplies

We maintain coal, fuel oil, materials and supplies inventories for use in the production of electricity. These inventories are accounted for at the lower of cost or market, using the average cost.

Emissions Allowances

IPL uses environmental air emissions allowances to meet standards set forth by the EPA related to emission of Sulfur Dioxide and Nitrogen Oxide gases. IPL accounts for environmental air emissions allowances as intangible assets and records expenses for allowances using a First In First Out method. The total book value of SO2 and NO_x emissions allowances, included in MISCELLANEOUS DEFERRED DEBITS on the accompanying Consolidated Balance Sheets, as of both December 31, 2009 and 2008 was $0.9 million.

Income Taxes

IPALCO includes any applicable interest and penalties related to income tax deficiencies or overpayments in the provision for income taxes in its Consolidated Statements of Income. The income tax provision includes gross interest income/(expense) of ($0.1 million) and $2.0 million for the years ended December 31, 2009 and 2008, respectively.

Deferred taxes are provided for all significant temporary differences between book and taxable income. The effects of income taxes are measured based on enacted laws and rates. Such differences include the use of accelerated depreciation methods for tax purposes, the use of different book and tax depreciable lives, rates and in-service dates and the accelerated tax amortization of pollution control facilities. Deferred tax assets and liabilities are recognized for the expected future tax consequences of existing differences between the financial reporting and tax reporting basis of assets and liabilities. Those income taxes payable which are includable in allowable costs for ratemaking purposes in future years are recorded as regulatory assets with a corresponding deferred tax liability. Investment tax credits that reduced federal income taxes in the years they arose have been deferred and are being amortized to income over the useful lives of the properties in accordance with regulatory treatment. Contingent liabilities related to income taxes are recorded in accordance with ASC 740 “Income Taxes.”

Cash and Cash Equivalents

We consider all highly liquid investments purchased with original maturities of three months or less at the date of acquisition to be cash equivalents.

Other Investments

As described in Note 1, as of December 31, 2009, Mid-America owned a 4.4% investment in EnerTech, which is accounted for using the cost method. The book value was $5.3 million and $6.8 million as of December 31, 2009 and 2008, respectively, and is included in OTHER ASSETS - Other investments on the accompanying Consolidated Balance Sheets.

We evaluate the recoverability of investments in unconsolidated subsidiaries and other investments when events or changes in circumstances indicate the carrying amount of the asset is other than temporarily impaired. An investment is considered impaired if the fair value of the investment is less than its carrying value. Impairment losses are recognized when an impairment is considered to be other than temporary. Impairments are considered to be other than temporary when we do not expect to recover the investment’s carrying value for a reasonable period of time. In making this determination, we consider several factors, including, but not limited to, the intent and ability to hold the investment, the severity of the impairment, the duration of the impairment and the entity’s historical and projected financial performance. Once an investment is considered other than temporarily impaired and an impairment loss is recognized, the carrying value of the investment is not adjusted for any subsequent recoveries in fair value.

In June 2009, we recorded a $1.8 million impairment on our investment in EnerTech. The investment was deemed to be other than temporarily impaired. In making this determination, we considered, among other things, the amount and length of time of impairment of the individual investments held by EnerTech as well as the future outlook of such investments.

Repair and Maintenance Costs

Repair and maintenance costs are expensed as incurred.

Per Share Data

IPALCO is a wholly-owned subsidiary of AES and does not report earnings on a per-share basis.

New Accounting Pronouncements

ASC 105 “Generally Accepted Accounting Principles”

In June 2009, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards 168, “The FASB Accounting Standards Codification and Hierarchy of Generally Accepted Accounting Principles, a replacement of FASB Statement No. 162,” which establishes the ASC as the source of authoritative GAAP recognized by the FASB to be applied to nongovernmental entities. The ASC supersedes all the existing non-SEC accounting and reporting standards effective July 1, 2009. The adoption of this statement did not have a material impact on our results of operations, financial condition or cash flows.

ASC 320 “Investments - Debt and Equity Securities”

In April 2009, the FASB issued FASB Staff Position No. SFAS 115-2 and 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments,” which amends the other-than-temporary impairment guidance for debt securities to make the guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments on debt and equity securities in the financial statements. This update does not amend existing recognition and measurement guidance related to other-than-temporary impairments of equity securities. This update does not require disclosures for earlier periods presented for comparative purposes at initial adoption. In periods after initial adoption, this update requires comparative disclosures only for periods ending after initial adoption. The adoption of this statement did not have a material impact on our results of operations, financial condition or cash flows.

ASC 715 “Compensation - Retirement Benefits”

In December 2008, FASB issued FASB Staff Position No. 132(R)-1. “Employers’ Disclosure about Postretirement Benefit Plan Assets” which requires additional disclosures about assets held in employer’s defined benefit pension or other postretirement plans and is now part of ASC 715. FSP 132(R)-1 replaces the requirement to disclose the percentage of the fair value of total plan assets with a requirement to disclose the fair value of each major asset category of plan assets. FSP 132(R)-1 also requires disclosure of the level within the fair value hierarchy (i.e., Level 1, Level 2 and Level 3) in which each major category of plan assets falls, using the guidance in ASC 820. The adoption of this statement did not have a material impact on our results of operations, financial condition or cash flows. However, we have updated our disclosures accordingly.

ASC 810 “Consolidation”

In December 2007, the FASB issued SFAS 160 “Non-controlling Interests in Consolidated Financial Statements - an amendment of ARB No. 51,” which establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and is now part of ASC 810. This update was effective for IPALCO beginning January 1, 2009 and must be applied to all periods presented in the financial statements. In accordance with this update, we have changed the presentation on IPALCO’s audited Consolidated Statements of Income to show the dividends related to the cumulative preferred stock of IPL as a deduction from Net Income to arrive at Net Income Applicable to Common Stock and have updated the audited Consolidated Statements of Cash Flows accordingly.

ASC 815 “Derivatives and Hedging”

In March 2008, the FASB issued SFAS 161“Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133,” which requires additional disclosures about derivatives, but does not change the method of accounting for derivatives. This guidance is now part of ASC 815. The additional disclosures include: the objectives of the derivative instruments and hedging activities, the method of accounting for such instruments under ASC 815, and a tabular disclosure of the effects of such instruments and related hedged items on an entity’s financial position, operations, and cash flows. Contracts that meet the criteria for and that are designated under the normal purchases and normal sales exception are not recorded at fair value and are not included in the disclosure requirements of this update. This guidance became effective for IPALCO beginning January 1, 2009. The guidance also states that the provisions of the Statement need not be applied to immaterial items. IPALCO engages in limited derivative and hedging activities. Additionally, IPALCO’s larger derivative items both qualify for regulatory treatment under ASC 980, “Regulated Operation” and therefore any unrealized gains or losses related to those items are deferred as regulatory assets or liabilities instead of being recognized in the statements of income. As a result, we have determined that our derivative items are not material to our financial statements at this time and have therefore excluded the additional disclosures. Please refer to Note 7, “Fair Value Measurements,” included in this Form 10-K for more information related to IPL’s derivative activities.

ASC 820 “Fair Value Measurements and Disclosures”

In April 2009, the FASB issued FSP SFAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,” which provides additional guidance for estimating fair value in accordance with ASC 820, when the volume and level of activity for the asset or liability have significantly decreased. This update also includes guidance on identifying circumstances that indicate a transaction is not orderly and requires the disclosure of the inputs and valuation technique(s) used to measure fair value and a discussion of changes in valuation techniques and related inputs, if any, during the period. The adoption of this statement did not have a material impact on our results of operations, financial condition or cash flows.

In August 2009, the FASB issued Accounting Standards Update 2009-05, “Fair Value Measurements and Disclosures (ASC 820) - Measuring Liabilities at Fair Value,” which further updates ASC 820. The update provides guidance on several key issues regarding the estimated fair value of liabilities in accordance with ASC 820. The guidance addresses restrictions on the transfer of a liability and clarifies how the price of a traded debt security should be considered in estimating the fair value of the issuer’s liability. The adoption of this update did not have a material impact on our results of operations, financial condition or cash flows.

ASC 855 “Subsequent Events”

In May 2009, the FASB issued SFAS 165 “Subsequent Events,” which establishes general standards for accounting for and disclosure of events that occur after the balance sheet date but before financial statements are available to be issued. This guidance is now part of ASC 855. ASC 855 sets forth the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition in the financial statements; identifies the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and sets forth the disclosures that should be made about events or transactions that occur after the balance sheet date. ASC 855 provides largely the same guidance on subsequent events which previously existed only in auditing literature. The adoption of this statement did not have a material impact on our results of operations, financial condition or cash flows.

3. Short-term and long-term Investments

We did not have any short-term investments as of December 31, 2009. As of December 31, 2008, IPL’s short-term investments consisted of available-for-sale debt securities and included $2.0 million of auction rate securities and $39.6 million in variable rate demand notes (see below).

As of December 31, 2009, IPL’s long-term investments consisted of available-for-sale debt securities and included the $2.0 million of auction rate securities, reclassified as long-term investments due to the uncertainty of our ability to convert them into cash in the current market environment and $40.0 million of variable rate demand notes (see below). We did not have any long-term investments as of December 31, 2008.

Variable Rate Demand Notes

IPL’s investment in variable rate demand notes consisted of the City of Petersburg, Indiana, Pollution Control Refunding Revenue Bonds Adjustable Rate Tender Securities Series 1995B (Indianapolis Power & Light Company Project). IPL received the proceeds from the original issuance of the 1995B Bonds and is liable for interest and principal on the 1995B Bonds, which mature on January 1, 2023. Interest on the 1995B Bonds varied weekly and was set through a remarketing process. IPL maintains a $40.6 million long-term liquidity facility supporting the 1995B Bonds. The liquidity facility expires in May 2011. IPL also entered into an interest rate swap agreement to hedge our interest rate exposure on the 1995B Bonds. The interest rate is synthetically fixed at 5.21% per annum through this interest rate swap agreement.

During several months in the second half of 2008, as much as $39.6 million of the 1995B Bonds were not successfully remarketed and were therefore tendered to the trustee. In accordance with the terms of IPL’s committed liquidity facility, the trustee drew $39.7 million against this facility to fund the tender and related accrued interest. As specified in the swap agreement, while the 1995B Bonds were not being remarketed, the swap counterparty exercised its right to pay interest to IPL at the alternative floating rate, which applied to the 1995B Bonds that were not remarketed instead of the cost of funds rate. As a result of the tender, the trustee held the $39.6 million of the 1995B Bonds on IPL’s behalf on December 31, 2008. Because management believed the 1995B Bonds would be successfully remarketed within one year, IPL’s investment in the 1995B Bonds was presented as current on our December 31, 2008 balance sheet. During the first half of 2009, all of these 1995B Bonds were successfully remarketed and the trustee no longer held those bonds on IPL’s behalf.

In September 2009, in accordance with the terms of the 1995B Bonds, IPL converted the 1995B Bonds from tax-exempt weekly interest rate mode to commercial paper mode and directed the remarketing agent to no longer remarket the 1995B Bonds. In connection with this conversion all of the outstanding 1995B Bonds were tendered back to the trustee. In accordance with the terms of IPL’s committed liquidity facility, the trustee drew $40 million against this facility to fund the tender and the trustee is again holding the 1995B Bonds on IPL’s behalf. In accordance with the terms of the 1995B Bonds, these bonds do not bear interest while in commercial paper mode since they are being held by the trustee. Because IPL’s committed liquidity facility does not expire until May 2011 and because management does not currently intend to retire or remarket the 1995B Bonds within the next 12 months, we have classified the associated 1995B Bonds as available-for-sale within long-term investment on our December 31, 2009 balance sheet. IPL is liable for the interest and principal on the liquidity facility. IPL also continues to be liable to the swap counterparty for 5.21% interest rate and the swap counterparty continues to exercise its right to pay interest to IPL at the alternative floating rate. As of December 31, 2009, our effective interest rate on the 1995B Bonds, including the liquidity facility and interest rate swap agreement was approximately 5.67% per annum. All of the 1995B Bonds remain outstanding and IPL remains liable for payment of interest and principal thereon, even though 1995B Bonds are being held by the trustee on behalf of IPL.

4. REGULATORY MATTERS

General

IPL is subject to regulation by the IURC as to its services and facilities, the valuation of property, the construction, purchase, or lease of electric generating facilities, the classification of accounts, rates of depreciation, retail rates and charges, the issuance of securities (other than evidences of indebtedness payable less than twelve months after the date of issue), the acquisition and sale of some public utility properties or securities and certain other matters.

In addition, IPL is subject to the jurisdiction of the FERC with respect to short-term borrowing not regulated by the IURC, the sale of electricity at wholesale and the transmission of electric energy in interstate commerce, the classification of accounts, and the acquisition and sale of utility property in certain circumstances as provided by the Federal Power Act. As a regulated entity, IPL is required to use certain accounting methods prescribed by regulatory bodies which may differ from those accounting methods required to be used by unregulated entities.

IPL is also affected by the regulatory jurisdiction of the U.S. Environmental Protection Agency at the federal level, and the Indiana Department of Environmental Management at the state level. Other significant regulatory agencies affecting IPL include, but are not limited to, North American Electric Reliability Corporation, the U.S. Department of Labor and the Indiana Occupational Safety and Health Administration.

FAC and Authorized Annual Jurisdictional Net Operating Income

Environmental Compliance Cost Recovery Adjustment

The IURC has approved the ratemaking treatment for expenditures applicable to qualified pollution control property to be recovered through an ECCRA when incurred to comply with environmental regulations. Clean Coal Technology constitutes qualified pollution control property, as defined in Indiana Code section 8-1-2-6.6, which allows IPL to reduce SO2, NOx, and mercury emissions and to reduce fine particulate pollution in the atmosphere. The approved ratemaking treatment includes a return on the expenditures and recovery of depreciation and operation and maintenance expenses associated with these projects and grants IPL the authority to add the approved return on our environmental projects to its authorized annual jurisdictional net operating income in subsequent FAC proceedings. The approved ratemaking treatment also provides for the periodic review of IPL’s capital expenditures on these projects. IPL’s ECCRA also allows it to recover the cost of NOx emissions allowances, when purchased to comply with environmental regulations that restrict the amount of NOx it may emit from its generating units used to serve its retail customers. Such ECCRA filings are made on a semi-annual basis.

Please see Note 14, “Commitments and Contingencies - Environmental” for a discussion of our current CCT filings and the current status of the federal Clean Air Interstate Rule and Indiana Clean Air Mercury Rule.

Midwest ISO

General

IPL is a member of the Midwest ISO. The Midwest ISO serves as the third-party operator of IPL’s transmission system and runs the day-ahead and real-time Energy Market and, beginning in January 2009, the Ancillary Services Market for its members. Midwest ISO policies are developed through a stakeholder process in which IPL is an active participant. IPL focuses its participation in this process primarily on items that could impact its customers, results of operations, financial condition, and cash flows. Additionally, IPL attempts to influence Midwest ISO policy by filing comments with FERC.

Midwest ISO’s Energy and Ancillary Services Markets Tariff

As a member of the Midwest ISO, we must comply with the Midwest ISO Tariff. The tariff has been amended from time to time to cover expansions of Midwest ISO’s operations. The tariff originally covered only transmission, but was amended to include terms and conditions of the Energy Market that was launched in April 2005 and the ASM that was launched in January 2009. Ancillary services are services required to reliably deliver electric power, and include such things as operating reserves and frequency control. Traditionally, each utility was required to provide these services themselves or purchase them from a third party. With the launch of the ASM, the buying and selling of ancillary services are able to be integrated with the existing Energy Market, thus providing greater efficiency in the delivery of these services and lower costs. IPL has authority from the IURC to include all specifically identifiable ASM costs and revenues as recoverable fuel costs in our FAC filings and to defer the remaining costs as regulatory assets. IPL will seek to recover the deferred costs in its next basic rate case proceeding.

Midwest ISO Real Time Revenue Sufficiency Guarantee

Demand-Side Management

Smart Grid Investment Grant

Voluntary Employee Beneficiary Association Trust Complaint

In November 2007, the International Brotherhood of Electrical Workers, Local Union No. 1395, and sixteen individual retirees filed a complaint at the IURC seeking enforcement of their interpretation of the 1995 final order and associated settlement agreement resolving IPL’s basic rate case. The Complainants requested that the IURC conduct an investigation of IPL’s failure to fund the Voluntary Employee Beneficiary Association Trust, at a level of approximately $19 million per year. The Voluntary Employee Beneficiary Association Trust was spun off to an independent trustee in 2001. The complaint sought an IURC order requiring IPL to make contributions to place the VEBA Trust in the financial position in which allegedly it would have been had IPL not ceased making annual contributions to the VEBA Trust after its spin off. The complaint also sought an IURC order requiring IPL to resume making annual contributions to the VEBA Trust. IPL filed a motion to dismiss and both parties sought summary judgment in the IURC proceeding. In May 2009, the IURC granted summary judgment in favor of IPL and in June 2009 the Complainants filed an appeal of the IURC’s May 2009 order with the Indiana Court of Appeals. On January 29, 2010, the appellate court affirmed the IURC's determination. Absent a petition for reconsideration, the Complainants have 30 days to petition for transfer to the Indiana Supreme Court. We have assessed our risk of loss on this complaint to be remote.

Financing Order

Please, see Note 11, “Indebtedness” for information regarding approval from the IURC to refinance our variable rate debt.

5. UTILITY PLANT IN SERVICE

The original cost of utility plant in service segregated by functional classifications, follows:


	As of December 31,
	2009		2008
	*(In Thousands)*
Production	$	2,479,056	$	2,429,724
Transmission		208,979		208,164
Distribution		1,160,106		1,129,739
General plant		172,351		152,083
Total utility plant in service	$	4,020,492	$	3,919,710

Substantially all of IPL’s property is subject to a $837.7 million direct first mortgage lien, as of December 31, 2009, securing IPL’s first mortgage bonds. Total utility plant in service includes $2.8 million and $2.8 million of property under capital leases as of December 31, 2009 and 2008, respectively. Total non-legal removal costs of utility plant in service at December 31, 2009 and 2008 were $494.7 million and $470.8 million, respectively and total legal removal costs of utility plant in service at December 31, 2009 and 2008 were $14.7 million and $13.9 million, respectively. Please see Note 9, “Asset Retirement Obligations” for further information.

In September 2007, IPL placed into service pollution control technology to address required SO2 and mercury emissions reductions from its power plants and to reduce fine particulate pollution in the atmosphere at a cost of approximately $212 million as of December 31, 2009. This enhancement was performed at IPL’s Harding Street generating station on Unit 7 and is part of IPL’s CCT projects. The amount recognized as of December 31, 2009 does not reflect the total cost of the project, which is not yet finalized. IPL believes these expenditures were necessary to reliably and economically achieve a level of emissions reductions that complies with the EPA’s NOx State Implementation Plan, the federal CAIR and the Indiana CAMR. IPL anticipates additional costs to comply with the federal CAIR and the Indiana CAMR and it is IPL’s intent to seek recovery of any additional costs. Please see, Note 14, “Commitments and Contingencies - Environmental” for a discussion regarding status of federal CAIR and Indiana CAMR. The majority of the expenditures for construction projects designed to reduce SO2 and mercury emissions are recoverable from jurisdictional retail customers as part of IPL’s CCT projects, however, since jurisdictional retail rates are subject to regulatory approval, there can be no assurance that all costs will be recovered in rates.

6. SALES OF ACCOUNTS RECEIVABLE

Accounts Receivable Securitization

IPL formed IPL Funding Corporation in 1996 as a special-purpose entity to purchase receivables originated by IPL pursuant to a purchase agreement entered into with IPL. At the same time, IPL Funding entered into a sale facility with unrelated parties (Royal Bank of Scotland plc and Windmill Funding Corporation) pursuant to which the Purchasers agree to purchase from IPL Funding, on a revolving basis, interests in the pool of receivables purchased from IPL up to the lesser of (1) an amount determined pursuant to the sale facility that takes into account certain eligibility requirements and reserves relating to the receivables, or (2) $50.0 million. Historically that amount has remained at $50 million, but during the fourth quarter of 2009, the eligible receivables balances was below $50 million and IPL Funding was required to repay Royal Bank of Scotland the shortfall, which was $9.5 million. This shortfall was based on our December reporting to Royal Bank of Scotland of the November 30th data. As of December 31, 2009, the eligible receivables balance was once again over $50 million and Royal Bank of Scotland purchased the additional $9.5 million of receivables from IPL Funding in January 2010. As collections reduce accounts receivable included in the pool, IPL Funding sells ownership interests in additional receivables acquired from IPL to return the ownership interests sold to the maximum amount permitted by the sale facility. During 2009, the sale facility was extended through May 25, 2010. IPL Funding is included in the audited Consolidated Financial Statements of IPALCO. Since IPL Funding is a wholly owned subsidiary of IPL, IPL is the primary beneficiary of IPL Funding. Accounts receivable on the accompanying audited Consolidated Balance Sheets of IPALCO are stated net of $40.5 million sold.

IPL retains servicing responsibilities in its role as collection agent on the amounts due on the sold receivables. However, the Purchasers assume the risk of collection on the purchased receivables without recourse to IPL in the event of a loss. While no direct recourse to IPL exists, we risk loss in the event collections are not sufficient to allow for full recovery of the retained interests. No servicing asset or liability is recorded since the servicing fee paid to IPL approximates a market rate. Per the terms of the purchase agreement, IPL Funding pays IPL $0.6 million annually in servicing fees which is financed by capital contributions from IPL to IPL Funding.

The carrying value of the retained interest is determined by allocating the carrying value of the receivables between the interests sold and the interests retained based on relative fair value. The key assumptions in estimating fair value are credit losses, the selection of discount rates, and expected receivables turnover rate. As a result of short accounts receivable turnover periods and historically low credit losses, the impact of these assumptions have not been significant to the fair value. The hypothetical effect on the fair value of the retained interests assuming both a 10% and a 20% unfavorable variation in credit losses or discount rates is not material due to the short turnover of receivables and historically low credit loss history.

The losses recognized on the sales of receivables were $1.2 million, $2.0 million, and $3.0 million for 2009, 2008, and 2007, respectively. These losses are included in Other operating expense on the audited Consolidated Statements of Income. The amount of the losses recognized depends on the previous carrying amount of the financial assets involved in the transfer, allocated between the assets sold and the interests that continue to be held by the transferor based on their relative fair value at the date of transfer, and the proceeds received.

The following tables show the receivables sold and retained interests as of the periods ended and cash flows during the periods ending:


	As of December 31,
	2009		2008
	*(In Millions)*
Receivables at IPL Funding	$	128.0	$	137.4
Less: Retained interests		87.5		87.4
Net receivables sold	$	40.5	$	50.0

	Twelve Months Ended December 31,
	2009		2008		2007
	*(In Millions)*
Cash flows during period
Cash proceeds from interest retained	$	689.8	$	623.1	$	541.1
Cash proceed from sold receivables⁽¹⁾	$	315.2	$	363.0	$	419.0

⁽¹⁾ Cash flows from the sale of receivables are reflected within Operating Activities on the audited Consolidated Statements of Cash Flows.

There were no proceeds from new securitizations for each of 2009, 2008 and 2007.

IPL and IPL Funding provide certain indemnities to the Purchasers, including indemnification in the event that there is a breach of representations and warranties made with respect to the purchased receivables. IPL Funding and IPL each have agreed to indemnify the Purchasers on an after-tax basis for any and all damages, losses, claims, liabilities, penalties, taxes, costs and expenses at any time imposed on or incurred by the indemnified parties arising out of or otherwise relating to the sale facility, subject to certain limitations as defined in the sale facility.

Under the sale facility, if IPL fails to maintain certain financial covenants including but not limited to interest coverage and debt-to-capital ratios, it would constitute a “termination event.” As of December 31, 2009, IPL is in compliance with such covenants.

In the event that IPL’s unsecured credit rating falls below BBB- at Standard & Poors or Baa3 at Moody’s, the facility agent has the ability to (i) replace IPL as the collection agent; and (ii) declare a “lock-box” event. Under a lock-box event or a termination event, the facility agent has the ability to require all proceeds of purchased receivables of IPL to be directed to lock-box accounts within 45 days of notifying IPL. A termination event would also (i) give the facility agent the option to take control of the lock-box account, and (ii) give the Purchasers the option to discontinue the purchase of additional interests in receivables and cause all proceeds of the purchased interests to be used to reduce the Purchaser’s investment and to pay other amounts owed to the Purchasers and the facility agent. This would have the effect of reducing the operating capital available to IPL by the aggregate amount of such purchased interests in receivables ($40.5 million as of December 31, 2009).

7. FAIR VALUE MEASUREMENTS

Whenever possible, quoted prices in active markets are used to determine the fair value of our financial instruments. Our financial instruments are not held for trading or other speculative purposes. The estimated fair value of financial instruments has been determined by using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

Cash Equivalents

As of December 31, 2009 and 2008, our cash equivalents consisted of money market funds. The fair value of cash equivalents approximates their book value due to their short maturity, which was $31.9 million and $5.2 million as of December 31, 2009 and 2008, respectively.

Customer Deposits

Our customer deposits do not have defined maturity dates and therefore, fair value is estimated to be the amount payable on demand, which equaled book value. Customer deposits totaled $18.8 million and $16.9 million as of December 31, 2009 and 2008, respectively.

Pension Assets

As of December 31, 2009, IPL’s pension assets are recognized at fair value in accordance with the guidelines established in ASC 715 and ASC 820, which is described below. For a complete discussion of the impact of recognizing pension assets at fair value, please refer to Note 13, “Pension and Other Postretirement Benefits.”

Indebtedness

The fair value of our outstanding fixed rate debt has been determined on the basis of the quoted market prices of the specific securities issued and outstanding. In certain circumstances, the market for such securities was inactive and therefore the valuation was adjusted to consider changes in market spreads for similar securities. Accordingly, the purpose of this disclosure is not to approximate the value on the basis of how the debt might be refinanced.

The following table shows the carrying amount and the fair value of fixed rate and variable rate indebtedness for the periods ending:

		December 31, 2009					December 31, 2008
	Carrying Amount		Fair Value		Carrying Amount			Fair Value
	*(In Millions)*
Fixed-rate	$	1,632.7	$	1,664.9		$	1500.8	$	1,287.1
Variable-rate		80.0		80.0			224.5		224.5
Total indebtedness	$	1,712.7	$	1,744.9		$	1,725.3	$	1,511.6

Fair Value Hierarchy

In accordance with ASC 820, we have categorized our financial assets and liabilities that are adjusted to fair value on a recurring basis, based on the priority of the inputs to the valuation technique, based on the three-level fair value hierarchy prescribed by ASC 820. As of December 31, 2009 and 2008 all (excluding pension assets) of our financial assets or liabilities measured at fair value on a recurring basis were categorized as Level 3 because the values were based primarily on unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability. For a complete discussion of the impact of recognizing pension assets at fair value, please refer to Note 13, “Pension and Other Postretirement Benefits.”

Financial assets and liabilities recorded on the audited Consolidated Balance Sheets are categorized based on the inputs to the valuation techniques as follows:

Level 1 - unadjusted quoted prices for identical assets or liabilities in an active market.

Level 2 - inputs from quoted prices in markets where trading occurs infrequently or quoted prices of instruments with similar attributes in active markets.

Level 3 - unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability.

As of December 31, 2009 and 2008 all (excluding pension assets) of IPALCO’s financial assets or liabilities measured at fair value on a recurring basis were considered Level 3, based on the fair value hierarchy. For a complete discussion of the impact of recognizing pension assets at fair value, please refer to Note 13, “Pension and Other Postretirement Benefits.” The following table presents those financial assets and liabilities:


	Fair Value Measurements using Level 3 at:
	December 31, 2009		December 31, 2008
	*(In Thousands)*
Financial assets:
Investments in debt securities	$	42,000	$	41,550
Financial transmission rights		944		5,298
Total financial assets measured at fair value	$	42,944	$	46,848

Financial liabilities:
Interest rate swap	$	8,179	$	9,918
Other derivative liabilities		198		194
Total financial liabilities measured at fair value	$	8,377	$	10,112

The following table sets forth a reconciliation of financial instruments classified as Level 3 in the fair value hierarchy:


	Derivative Financial Instruments, net liability		Investment in Debt Securities	Total
	*(In Thousands)*

Balance at January 1, 2008	$	(4,814)	41,550	36,736
Unrealized losses recognized in earnings		(32)	-	(32)
Unrealized gain recognized as a regulatory asset		227	-	227
Issuances and settlements, net		(2,813)	450	(2,363)
Balance at December 31, 2009	$	(7,432)	42,000	34,568

Valuation Techniques

Investments in debt securities

As of December 31, 2009, IPL’s investment in debt securities consisted of available-for-sale debt securities and included $2.0 million of auction rate securities and $40.0 million of variable rate demand notes.

The $2.0 million of auction rate securities have experienced failed auctions consistently since the first quarter of 2008. The fair values of these securities are estimated primarily using a qualitative analysis of such things as, the collateral underlying the security; the creditworthiness of the issuer; the timing of the expected future cash flows, including the final maturity; and an expectation of the securities’ next successful auction or receipt of notification indicating the securities’ conversion from the auction rate market to a more liquid market. These securities are also compared, when possible, to other observable and relevant market data which, however, is limited at this time. Primarily as a result of the following factors, we have determined that the fair value is at or near our original cost and therefore no impairment has been recognized: (1) all of the issuers of such securities are rated A or higher, (2) the securities are backed by insurance companies with affirmed ratings of AAA, and (3) all interest payments have been received timely. Due to the illiquid nature of these investments in the current market, we have classified these securities during the current period as Level 3.

As of December 31, 2009, IPL’s investment in variable rate demand notes consisted of the 1995B Bonds. See Note 3, “Short-term and Long-term Investments” for further discussion of the 1995B Bonds. Similar to the analysis performed on the auction rate securities, we have estimated the fair value of the 1995B Bonds and concluded the fair value approximates their face value and have also classified them as Level 3 due to the lack of observable market inputs.

Financial Transmission Rights

In connection with IPL’s participation in the Midwest ISO, in the second quarter of each year IPL is granted financial instruments that can be converted into cash or FTRs based on IPL’s forecasted peak load for the period. FTRs are used in the Midwest ISO market to hedge IPL’s exposure to congestion charges, which result from constraints on the transmission system. IPL converts all of these financial instruments into FTRs. IPL’s FTRs are valued at the cleared auction prices for FTRs in the Midwest ISO’s annual auction. Because of the infrequent nature of this valuation, the fair value assigned to the FTRs is considered a Level 3 input under the fair value hierarchy required by ASC 820. An offsetting regulatory liability has been recorded as management believes that these revenues or costs will be flowed through to customers through the FAC. As such, there is no impact on our Consolidated Statements of Income.

Other Financial Instruments

We do not believe any of the other financial instruments which we held as of December 31, 2009 are material to our results of operations, financial condition, and cash flows either qualitatively or quantitatively. As described in Note 2, “Summary of Significant Accounting Polices - Derivatives,” IPL has one interest rate swap agreement, which is recognized on the audited Consolidated Balance Sheets at its estimated fair value as a liability. IPL entered into this agreement as a means of managing the interest rate exposure related to the 1995B Bonds. In accordance with ASC 980, IPL recognized a regulatory asset equal to the value of the interest rate swap, which is adjusted as that fair value changes. Therefore there is no impact to IPALCO’s audited Consolidated Statements of Income or Cash Flows for the changes in the fair value of the interest rate swap.

8. REGULATORY ASSETS AND LIABILITIES

Regulatory assets represent deferred costs or credits that have been included as allowable costs or credits for ratemaking purposes. IPL has recorded regulatory assets or liabilities relating to certain costs or credits as authorized by the IURC or established regulatory practices in accordance with ASC 980. IPL is amortizing non tax-related regulatory assets to expense over periods ranging from 1 to 35 years. Tax-related regulatory assets represent the net income tax costs to be considered in future regulatory proceedings generally as the tax-related amounts are paid.

The amounts of regulatory assets and regulatory liabilities at December 31 are as follows:


	2009		2008		Recovery Period
	*(In Thousands)*
Regulatory Assets
Current:
Deferred fuel under-collection	$	-	$	9,252	Through 2009⁽¹⁾
NO_x & CCT project expenses		2,693		5,398	Through 2010⁽¹⁾
Air conditioning load management (demand management)		1,144		2,072	Through 2010⁽¹⁾
Other Demand-Side Management program costs		991		623	Through 2010⁽¹⁾⁽²⁾
Total current regulatory assets		4,828		17,345

Long-term:
Unrecognized pension and other postretirement benefit plan costs	$	217,238	$	280,668	Various
Income taxes recoverable from customers		70,278		75,501	Various
Deferred Midwest ISO costs		62,829		57,921	To be determined⁽³⁾
Unamortized Petersburg unit 4 carrying charges and certain other costs		19,490		20,298	Through 2026⁽¹⁾⁽²⁾
Unamortized reacquisition premium on debt		15,864		15,339	Over remaining life of debt
Unrealized loss on interest rate swap		8,179		9,919	Through 2023
NO_x project expenses - Petersburg unit 2 precipitator		1,731		1,875	Through 2021⁽¹⁾
Other Demand-Side Management and green power program costs		42		208	Various
Total long-term regulatory assets		395,651		461,729
Total regulatory assets	$	400,479	$	479,074

Regulatory Liabilities
Current:
Deferred fuel over-collection	$	12,390	$	-	Through 2010⁽¹⁾
FTR's		944		5,298	Through 2010⁽⁴⁾
Fuel related		382		363	Through 2010
NO_x & CCT project credits		147		74	Through 2010⁽⁴⁾
Total current regulatory liabilities		13,863		5,735

Long-term:
ARO costs and accrued asset removal costs		481,676		458,767	Not Applicable
Unamortized investment tax credit		9,192		10,595	Through 2014
Fuel related		1,132		1,640	Through 2013
Total long-term regulatory liabilities		492,000		471,002
Total regulatory liabilities	$	505,863	$	476,737

⁽¹⁾ Recovered per specific rate orders
⁽²⁾ Recovered with a current return
⁽³⁾ Recovery is probable but timing not yet determined
⁽⁴⁾ Recovered (credited) per specific rate orders

Deferred Fuel

Deferred fuel costs are a component of current regulatory assets and are expected to be recovered through future FAC proceedings. IPL records deferred fuel in accordance with standards prescribed by the FERC. The deferred fuel adjustment is the result of variances between estimated fuel and purchased power costs in IPL’s FAC and actual fuel and purchased power costs. IPL is permitted to recover underestimated fuel and purchased power costs in future rates through the FAC proceedings and therefore the costs are deferred and amortized into fuel expense in the same period that IPL’s rates are adjusted. Deferred fuel was a liability of $12.4 million as of December 31, 2009 included in current regulatory liabilities while deferred fuel was an asset of $9.3 million as of December 31, 2008 which was included in current regulatory assets. The net change in the deferred fuel liability of $21.7 million was primarily because the amount of fuel charged to customers increased to recover underbilled fuel costs from prior periods and because fuel costs in 2009 have been less than estimated.

Unrecognized Pension and Postretirement Benefit Plan Costs

In accordance with ASC 715 “Compensation - Retirement Benefits” and ASC 980, we recognize a regulatory asset equal to the unrecognized actuarial gains and losses and prior service costs. Pension expenses are recorded based on the benefit plan’s actuarially determined pension liability and associated level of annual expenses to be recognized. The other postretirement benefit plan’s deferred benefit cost is the excess of the other postretirement benefit liability over the amount previously recognized. The asset representing the unrecognized pension and postretirement benefit plan costs decreased $63.4 million during 2009 primarily resulting from a higher than expected return on assets during the year 2009, partially offset by recognized actuarial losses in 2009.

Deferred Income Taxes

This amount represents the portion of deferred income taxes that we believe will be recovered through future rates, based upon established regulatory practices, which permit the recovery of current taxes. Accordingly, this regulatory asset is offset by a deferred tax liability and is expected to be recovered, without interest, over the period underlying book-tax timing differences reverse and become current taxes.

Deferred Midwest ISO Costs

These consist of administrative costs for transmission services and certain other operational and administrative costs from the Midwest ISO market. IPL received orders from the IURC that granted authority for IPL to defer such costs and seek recovery in a future basic rate case. See Note 4, “Regulatory Matters.”

Unrealized Loss on Interest Rate Swap

The interest rate swap on the 1995B Bonds is used to mitigate interest rate risk. The swap, which expires upon the maturity of the related note in 2023, was approved by the IURC as part of IPL’s 1994 financing order. The unrealized loss on the swap as of December 31, 2009 is considered in the determination of IPL’s cost of capital for rate making purposes as these amounts are realized through the periodic settlement payments under the swap. Should the swap be prudently terminated before its scheduled maturity date, the settlement of the swap would likely be recoverable in future rates.

Asset Retirement Obligation and Accrued Asset Removal Costs

In accordance with ASC 715 and ASC 980, IPL, a regulated utility, recognizes the cost of removal component of its depreciation reserve that does not have an associated legal retirement obligation as a deferred liability. This amount is net of the portion of legal ARO costs that is currently being recovered in rates.

9. ASSET RETIREMENT OBLIGATIONS

ASC 420 “Exit or Disposal Cost Obligations” addresses financial accounting and reporting for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal operation. A legal obligation for purposes of ASC 420 is an obligation that a party is required to settle as a result of an existing law, statute, ordinance, written or oral contract or the doctrine of promissory estoppels. ARO liability is included in Miscellaneous on the accompanying Consolidated Balance Sheets.

IPL’s ARO relates primarily to environmental issues involving asbestos, ash ponds, landfills and miscellaneous contaminants associated with its generating plants, transmission system and distribution system. The following is a reconciliation of the ARO legal liability year end balances:


	2009		2008
	*(In Millions)*
Balance as of January 1	$	13.9	$	13.1
Accretion Expense		0.8		0.8
Balance as of December 31	$	14.7	$	13.9

As of December 31, 2009 and 2008, IPL did not have any assets that are legally restricted for settling its ARO liability.

10. SHAREHOLDER’S EQUITY

Capital Stock

IPALCO’s no par value common stock is pledged under AES’ Amended and Restated Credit and Reimbursement Agreement as well as AES’ Collateral Trust Agreement. There have been no changes to IPALCO’s capital stock balances during the three years ended December 31, 2009.

Dividend Restrictions

IPL is also restricted in its ability to pay dividends if it is in default under the terms of its credit agreement, which could happen if IPL fails to comply with certain covenants. These covenants, among other things, require IPL to maintain a ratio of earnings before interest and taxes to interest expense of not less than 2.5 to 1, and a ratio of total debt to total capitalization not in excess of 0.65 to 1, in order to pay dividends. As of December 31, 2009 and as of the filing of this report, IPL was in compliance with all financial covenants and no event of default existed.

IPALCO is also restricted in its ability to pay dividends under the terms of its $375 million of 8.625% (original coupon 7.625%) Senior Secured Notes due November 14, 2011 if it is not in compliance with certain financial covenants. These covenants require IPALCO to maintain a minimum ratio of earnings before taxes, interest, depreciation and amortization to interest expense of not less than 2.5 to 1, and a ratio of total debt to total adjusted capitalization not in excess of 0.67 to 1, in order to pay dividends. As of December 31, 2009 and as of the filing of this report, IPALCO was in compliance with all financial covenants and no event of default existed.

Cumulative Preferred Stock of Subsidiary

IPL has five separate series of cumulative preferred stock. Holders of preferred stock are entitled to receive dividends at rates per annum ranging from 4.0% to 5.65%. During each year ended December 31, 2009, 2008 and 2007, total preferred stock dividends declared were $3.2 million. Holders of preferred stock are entitled to two votes per share for IPL matters, and if four full quarterly dividends are in default on all shares of the preferred stock then outstanding, they are entitled to elect the smallest number of IPL directors to constitute a majority of IPL’s board of directors. Based on the preferred stockholders’ ability to elect a majority of IPL’s board of directors in this circumstance, the redemption of the preferred shares is considered to be not solely within the control of the issuer and the preferred stock was considered temporary equity and presented in the mezzanine level of the audited consolidated balance sheets in accordance with the relevant accounting guidance for non-controlling interests and redeemable securities. IPL has issued and outstanding 500,000 shares of 5.65% Preferred Stock, which are redeemable at par value, subject to certain restrictions, in whole or in part, at any time on or after January 1, 2008, at the option of IPL. Additionally, IPL has 91,353 shares of preferred stock which are redeemable solely at the option of IPL and can be redeemed in whole or in part at any time at specific call prices.

At December 31, 2009, 2008 and 2007, preferred stock consisted of the following:


	December 31, 2009			December 31,
	Shares Outstanding	Call Price		2009		2008		2007
	Shares Outstanding	Call Price		Par Value, plus premium, if applicable
				*(In Thousands)*
Cumulative $100 par value, authorized 2,000,000 shares
4% Series	47,611	$	118.00	$	5,410	$	5,410	$	5,410
4.2% Series	19,331		103.00		1,933		1,933		1,933
4.6% Series	2,481		103.00		248		248		248
4.8% Series	21,930		101.00		2,193		2,193		2,193
5.65% Series	500,000		100.00		50,000		50,000		50,000
Total cumulative preferred stock	591,353			$	59,784	$	59,784	$	59,784

11. INDEBTEDNESS

Restrictions on Issuance of Debt

Before IPL can incur additional long-term debt, it must first have the approval of the IURC. The current IURC approved financing petition, grants IPL the authority to enter into capital lease obligations not to exceed an aggregate principal amount of $10.0 million and to refinance, if appropriate, the 1995B Bonds (See below). Before IPL can incur additional short-term debt, it must first have the approval of the FERC. The current FERC order authorizes IPL to issue up to $500 million of short-term indebtedness outstanding at any time through July 27, 2010. We anticipate submitting an application to FERC to request a new order prior to the expiration of the current order. Also, IPL and IPALCO have restrictions on the amount of new debt they may issue due to contractual obligations of AES and financial covenant restrictions under existing debt obligations at IPL and IPALCO. Under such restrictions, IPL is generally allowed to fully draw the amounts available on its credit facility, refinance existing debt and issue new debt approved by the IURC and issue certain other indebtedness.

Credit Ratings

The applicable interest rates on the 2011 IPALCO Notes and IPL’s credit facility (as well as the amount of certain other fees on the credit facility) are dependent upon the credit ratings of IPALCO and IPL, respectively. In the event IPALCO’s or IPL’s credit ratings are downgraded or upgraded, the interest rates and certain other fees charged to IPALCO and IPL could increase, or decrease, respectively. However, the applicable interest rate on the 2011 IPALCO Notes cannot increase any further, but upgrades in IPALCO’s credit ratings would decrease the interest rate. Downgrades in the credit ratings of AES could result in IPL’s and/or IPALCO’s credit ratings being downgraded.

In August 2009, the corporate credit ratings of IPL and IPALCO were upgraded by S&P from BB+ to BBB-, resulting in an investment grade rating. This upgrade led to a downgrade in IPL’s senior unsecured debt rating from BBB to BBB- as a result of S&P applying its criteria for investment grade ratings to IPL. Under this criterion the senior unsecured rating of an investment grade company typically cannot be higher than its corporate credit rating. At this same time, S&P also upgraded the credit rating of IPALCO’s senior secured notes from BB to BB+. Additionally in August 2009, Moody’s upgraded the credit rating of IPL’s senior secured debt from Baa1 to A3. This upgrade was due to a change in Moody’s methodology for notching the senior secured debt ratings of investment-grade regulated utilities. Moody’s notching practices widened as a result of their research which indicated that regulated utilities have defaulted at a lower rate and experienced lower loss given default rates than non-financial, non-utility corporate issuers.

In March 2008, S&P raised its issue-level ratings on IPALCO’s senior debt from BB- to BB and IPL’s senior unsecured debt from BB- to BBB.

Long-Term Debt

The following table presents our long-term indebtedness:


Series	Due	December 31,
Series	Due	2009		2008
		*(In Thousands)*
IPL First Mortgage Bonds (see below)
6.30%	July 2013	$	110,000	$	110,000
Variable⁽¹⁾	January 2016		-		41,850
4.90%⁽²⁾	January 2016		30,000		-
4.90%⁽²⁾	January 2016		41,850		-
4.90%⁽²⁾	January 2016		60,000		-
5.40%⁽¹⁾	August 2017		24,650		24,650
5.75%⁽¹⁾	August 2021		40,000		40,000
Variable⁽¹⁾	October 2023		-		30,000
4.55%⁽²⁾	December 2024		40,000		40,000
5.90%⁽¹⁾	December 2024		20,000		20,000
5.95%⁽¹⁾	December 2029		30,000		30,000
5.95%⁽²⁾	August 2030		17,350		17,350
6.60%	January 2034		100,000		100,000
6.05%	October 2036		158,800		158,800
6.60%	June 2037		165,000		165,000
Variable⁽²⁾	September 2041		-		60,000
Unamortized discount - net			(1,048)		(1,071)
Total IPL first mortgage bonds			836,602		836,579
IPL Unsecured Debt:
Variable⁽³⁾	May 2011		40,000		-
Variable⁽⁴⁾⁽⁵⁾	January 2023		40,000		40,000
6.375%⁽⁴⁾	November 2029		20,000		20,000
Total IPL unsecured debt			100,000		60,000

Total Long-term Debt - IPL			936,602		896,579
Long-term Debt - IPALCO:

8.625% Senior Secured Notes	November 2011		375,000		375,000
7.250% Senior Secured Notes	April 2016		400,000		400,000
Unamortized discount - net			(4,907)		(5,494)
Total Long-term Debt - IPALCO			770,093		769,506
Total Consolidated IPALCO Long-term Debt		$	1,706,695	$	1,666,085

⁽¹⁾First Mortgage Bonds are issued to the city of Petersburg, Indiana, to secure the loan of proceeds from various tax-exempt instruments issued by the city.
⁽²⁾First Mortgage Bonds are issued to the Indiana Finance Authority, to secure the loan of proceeds from the tax-exempt bonds issued by the Indiana Finance Authority.
⁽³⁾Outstanding draw on a credit facility in order to purchase the 1995B Bonds. See below.
⁽⁴⁾Notes are issued to the city of Petersburg, Indiana, by IPL to secure the loan of proceeds from various tax-exempt instruments issued by the city. ⁽⁵⁾Please see, “Variable-Rate Unsecured Debt” below for detail regarding 1995B Bonds and the related swap agreement.

IPL First Mortgage Bonds

The mortgage and deed of trust of IPL, together with the supplemental indentures thereto, secure the first mortgage bonds issued by IPL. Pursuant to the terms of the mortgage, substantially all property owned by IPL is subject to a $837.7 million direct first mortgage lien, as of December 31, 2009. The IPL first mortgage bonds require net earnings as calculated thereunder be at least two and one-half times the annual interest requirements before additional bonds can be authenticated on the basis of property additions. IPL was in compliance with such requirements as of December 31, 2009.

IPALCO’s Senior Secured Notes

In April 2008, IPALCO completed the sale of $400 million aggregate principal amount of 7.25% Senior Secured Notes due April 1, 2016 pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended. The 2016 IPALCO Notes were sold at 98.526% of par resulting in net proceeds of $394.1 million. The $5.9 million discount is being amortized through 2016 using the effective interest method. We used these net proceeds to repurchase or redeem all of the outstanding $375 million of 8.375% (original coupon 7.375%) Senior Secured Notes due November 14, 2008 and to pay the early tender premium of $13.9 million (included in Interest on long-term debt in the accompanying Consolidated Statements of Income) and other fees and expenses related to the tender offer and the redemption of the 2008 IPALCO Notes and the issuance of the 2016 IPALCO Notes. The 2016 IPALCO Notes are secured by IPALCO’s pledge of all of the outstanding common stock of IPL. The lien on the pledged shares will be shared equally and ratably with IPALCO’s existing senior secured notes.

Variable-Rate Unsecured Debt

IPL’s variable-rate unsecured debt consists of the 1995B Bonds and its line of credit agreement (See below). Pursuant to the terms of a Loan Agreement between IPL and the City of Petersburg, IPL is liable for interest and principal on the 1995B Bonds. Our December 31, 2009 and 2008 balance sheets reflect our obligation on the 1995B Bonds in long-term debt. The 1995B Bonds are currently being held by the trustee on IPL’s behalf. In accordance with the terms of the 1995B Bonds, they do not bear interest while in commercial paper mode since they are being held by the trustee, however IPL continues to be liable to a swap counterparty for 5.21% interest. As of the end of 2009, our total effective interest rate on the 1995B Bonds, including the liquidity facility draw and interest rate swap agreement was approximately 5.67% per annum. See Note 3, “Short-term and Long-term Investments” for further discussion.

Line of Credit

IPL maintains a credit agreement in the aggregate principal amount of $150.0 million which includes an $109.4 million committed line of credit and a $40.6 million liquidity facility (related to the 1995B Bonds). As of December 31, 2009, IPL had available borrowing capacity of $108.7 million under our $150.0 million committed credit facility after outstanding borrowings, existing letters of credit and the liquidity facility for the 1995B Bonds. The committed line of credit also provides a sub limit for the issuance of letters of credit. As of December 31, 2009, IPL did not have any outstanding borrowings on the committed line of credit and $40.0 million of outstanding borrowings on the liquidity facility. As of December 31, 2008 IPL had $13.0 million of outstanding borrowings on the committed line of credit and $39.7 million of outstanding borrowings on the liquidity facility.

Debt Maturities

Maturities on long-term indebtedness subsequent to December 31, 2009, are as follows:


Year	Amount
	*(In Thousands)*
2010	$	-
2011		415,000
2012		-
2013		110,000
2014		-
Thereafter		1,187,650
Total	$	1,712,650

12. INCOME TAXES

IPALCO follows a policy of comprehensive interperiod income tax allocation. Investment tax credits related to utility property have been deferred and are being amortized over the estimated useful lives of the related property.

AES files federal and state income tax returns which consolidate IPALCO and its subsidiaries. Under a tax sharing agreement with AES, IPALCO is responsible for the income taxes associated with its own taxable income and records the provision for income taxes as if IPALCO and its subsidiaries each filed separate income tax returns. IPALCO is no longer subject to U.S. or state income tax examinations for tax years through March 27, 2001, but is open for all subsequent periods.

The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the year ended December 31, 2009, 2008 and 2007:


	2009		2008			2007
Unrecognized tax benefits at January 1	*(In Thousands)*
Gross increases - current period tax positions	$	7,756	$	21,582	$	22,753
Gross decreases - prior period tax positions		753		754		1,249
Settlements		(562)		(7,535)		(2,420)
Unrecognized tax benefits at December 31		-		(7,045)		-
	$	7,947	$	7,756	$	21,582

The unrecognized tax benefits at December 31, 2009, represent tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, other than interest and penalties, the timing of the deductions will not affect the annual effective tax rate but would accelerate the tax payments to an earlier period.

Tax-related interest expense and income is reported as part of the provision for federal and state income taxes. Penalties, if incurred, would also be recognized as a component of tax expense. As of December 31, 2009 and 2008, IPALCO has recorded a liability for interest of $0.7 million and $0.6 million, respectively. The income tax provision includes interest expense/(income) of $0.1 million, ($2.0 million), and ($0.6 million) for the years ended December 31, 2009, 2008 and 2007, respectively.

Federal and state income taxes charged to income are as follows:


	2009		2008		2007
	*(In Thousands)*
Charged to utility operating expense
Current income taxes:
Federal	$	74,472	$	71,012	$	89,296
State		21,200		19,973		24,683
Total current income taxes		95,672		90,985		113,979
Deferred income taxes:
Federal		(17,794)		(8,428)		(5,636)
State		(1,884)		1,002		1,976
Total deferred income taxes		(19,678)		(7,426)		(3,660)
Net amortization of investment credit		(2,059)		(2,439)		(2,564)
Total charge to utility operating expenses		73,935		81,120		107,755
Charged to other income and deductions:
Current income taxes:
Federal		(20,267)		(25,606)		(21,033)
State		(5,370)		(6,829)		(5,580)
Total current income taxes		(25,637)		(32,435)		(26,613)
Deferred income taxes:
Federal		(368)		(326)		360
State		(98)		(86)		95
Total deferred income taxes		(466)		(412)		455
Net credit to other income and deductions		(26,103)		(32,847)		(26,158)
Total federal and state income tax provisions	$	47,832	$	48,273	$	81,597

The provision for income taxes (including net investment tax credit adjustments) is different than the amount computed by applying the statutory tax rate to pretax income. The reasons for the difference, stated as a percentage of pretax income, are as follows:


	2009	2008	2007

Federal statutory tax rate	35.0%	35.0%	35.0%
State income tax, net of federal tax benefit	7.9	7.6	6.8
Amortization of investment tax credits	(1.7)	(2.0)	(1.3)
Preferred dividends of subsidiary	1.0	0.9	0.6
Depreciation flow through and amortization	1.8	2.8	1.7
Manufacturers’ Production Deduction (Sec. 199)	(2.7)	(2.5)	(1.9)
Change in tax reserves	(0.0)	(1.1)	0.0
Other - net	(0.9)	(0.4)	(0.8)
Effective tax rate	40.4%	40.3%	40.1%

The American Jobs Creation Act of 2004 created Internal Revenue Code Section 199 which, beginning in 2005, permits taxpayers to claim a deduction from taxable income attributable to certain domestic production activities. IPL’s electric production activities qualify for this deduction. The deduction was equal to 3% of qualifying production activity income for the 2005 and 2006 taxable years, with certain limitations. This deduction increased to 6% of qualifying production activity income beginning in 2007 and will increase to 9% of qualifying production activity income beginning in 2010 and thereafter. The tax benefit associated with the Internal Revenue Code Section 199 domestic production deduction for 2007 and 2008 was $3.9 million and $3.1 million, respectively. The benefit for 2009 is estimated to be $3.2 million.

The significant items comprising IPALCO’s net accumulated deferred tax liability recognized on the audited Consolidated Balance Sheets as of December 31, 2009 and 2008, are as follows:


	2009		2008
	*(In Thousands)*
Deferred tax liabilities:
Relating to utility property, net	$	505,591	$	517,076
Regulatory assets recoverable through future rates		154,269		180,746
Other		5,227		12,044
Total deferred tax liabilities		665,087		709,866
Deferred tax assets:
Investment tax credit		5,467		6,302
Regulatory liabilities including ARO		204,193		197,237
Employee benefit plans		79,902		101,013
Other		10,122		15,756
Total deferred tax assets		299,684		320,308
Accumulated net deferred tax liability		365,403		389,558
Less: Net current deferred tax asset		(9,550)		(8,531)
Accumulated deferred income taxes - net	$	374,953	$	398,089

13. PENSION AND OTHER POSTRETIREMENT BENEFITS

Approximately 90% of IPL’s active employees are covered by the Employees’ Retirement Plan of Indianapolis Power & Light Company as well as the Employees’ Thrift Plan of Indianapolis Power & Light Company. The Defined Benefit Pension Plan is a qualified defined benefit plan, while the Thrift Plan is a qualified defined contribution plan. The remaining 10% of active employees are covered by the AES Retirement Savings Plan. The RSP is a qualified defined contribution plan containing a profit sharing component. All non-union new hires are covered under the RSP, while IBEW physical unit union new hires are covered under the Defined Benefit Pension Plan and Thrift Plan. Beginning in 2007, IBEW clerical-technical unit new hires are no longer covered under the Defined Benefit Pension Plan but do receive an annual lump sum company contribution into the Thrift Plan. This lump sum is in addition to the IPL match of participant contributions up to 5% of base compensation. The Defined Benefit Pension Plan is noncontributory and is funded through a trust. Benefits are based on each individual employee’s pension band and years of service as opposed to their compensation. Pension bands are based primarily on job duties and responsibilities.

Additionally, a small group of former officers and their surviving spouses are covered under a funded non-qualified Supplemental Retirement Plan of Indianapolis Power & Light Company. The total number of participants in the plan as of December 31, 2009 is 29. The plan is closed to new participants.

IPL provides postretirement health care benefits to certain active or retired employees and the spouses of certain active or retired employees. Approximately 195 active employees and 138 retirees (including spouses) were receiving such benefits or entitled to future benefits as of December 31, 2009. The plan is unfunded.


	Pension benefits as of December 31,				Other postretirement benefits as of December 31,
	2009		2008		2009		2008
	*(In Thousands)*
Change in benefit obligation:
Projected benefit obligation at beginning Measurement Date (see below)	$	527,741	$	482,253	$	13,083	$	10,151
Adjustment due to adoption of ASC 715: Service cost and interest cost during gap period		-		2,964		-		-
Service cost		6,319		5,249		681		1,115
Interest cost		32,066		30,292		470		645
Plan Settlements		(454)		(1,160)		-		-
Actuarial (gain) loss		11,629		29,094		(4,524)		1,929
Amendments (primarily increases in pension bands)		-		9,873		(4,264)		(162)
Benefits paid		(28,522)		(30,824)		(365)		(595)
Projected benefit obligation at ending Measurement Date		548,779		527,741		5,081		13,083
Change in plan assets:
Fair value of plan assets at beginning Measurement Date		305,508		403,619		-		-
Actual return on plan assets		70,804		(122,787)		-		-
Employer contributions		20,127		56,660		365		595
Plan Settlements		(454)		(1,160)		-		-
Benefits paid		(28,522)		(30,824)		(365)		(595)
Fair value of plan assets at ending Measurement Date		367,463		305,508				-
Funded status	$	(181,316)	$	(222,233)	$	(5,081)	$	(13,083)
Amounts recognized in the statement of financial position under ASC 715:
Current liabilities	$		$	-	$	(586)	$	(646)
Noncurrent liabilities		(181,316)		(222,233)		(4,495)		(12,437)
Net amount recognized	$	(181,316)	$	(222,233)	$	(5,081)	$	(13,083)
Sources of change in regulatory assets⁽¹⁾:
Prior service cost (credit) arising during period	$	-	$	9,873	$	(4,264)	$	(162)
Net loss (gain) arising during period		(35,024)		185,948		(4,524)		1,929
Amortization of prior service (cost) credit		(3,523)		(2,868)		339		56
Recognition of gain (loss) due to settlement		(256)		-		-		-
Amortization of gain (loss)		(16,279)		(1,912)		102		18
Total recognized in regulatory assets⁽¹⁾	$	(55,082)	$	191,041	$	(8,347)	$	1,841
Total amounts included in accumulated other comprehensive income (loss)		NA⁽¹⁾		NA⁽¹⁾		NA⁽¹⁾		NA⁽¹⁾
Amounts included in regulatory assets and liabilities⁽¹⁾
Net loss (gain)	$	197,945	$	249,505	$	(3,853)	$	569
Prior service cost (credit)		27,249		30,772		(4,104)		(179)
Total amounts included in regulatory assets (liabilities)	$	225,194	$	280,277	$	(7,957)	$	390

⁽¹⁾Represents amounts included in regulatory assets (liabilities) yet to be recognized as components of net prepaid (accrued) benefit costs.

Effect of ASC 715

ASC 715 requires a portion of pension and other postretirement liabilities to be classified as current liabilities to the extent the following year’s expected benefit payments are in excess of the fair value of plan assets. As each Pension Plan has assets with fair values in excess of the following year’s expected benefit payments, no amounts have been classified as current. Therefore, the entire net amount recognized in IPALCO’s Consolidated Balance Sheets of $181.3 million is classified as a long-term liability. As there are no plan assets related to the other postretirement plan, the current other postretirement liability is equal to the following year’s expected other postretirement benefit payment of $0.6 million, resulting in a long-term other postretirement liability of $4.5 million.

Information for Pension Plans with a benefit obligation in excess of plan assets


	Pension benefits as of December 31,
	2009		2008
	*(In Thousands)*
Benefit obligation	$	548,779	$	527,741
Plan assets		367,463		305,508
Benefit obligation in excess of plan assets	$	181,316	$	222,233

IPL’s total benefit obligation in excess of plan assets was $181.3 million as of December 31, 2009 ($180.3 million Defined Benefit Pension Plan and $1.0 million Supplemental Retirement Plan).

Information for Pension Plans with an accumulated benefit obligation in excess of plan assets


	Pension benefits as of December 31,
	2009		2008
	*(In Thousands)*
Accumulated benefit obligation	$	535,452	$	516,307
Plan assets		367,463		305,508
Accumulated benefit obligation in excess of plan assets	$	167,989	$	210,799

IPL’s total accumulated benefit obligation in excess of plan assets was $168.0 million as of December 31, 2009 ($167.0 million Defined Benefit Pension Plan and $1.0 million Supplemental Retirement Plan).

Pension Benefits and Expense

The 2009 net actuarial gain of $35.0 million is comprised of two parts (net): (1) $46.6 million of pension asset actuarial gain is primarily due to the higher than expected return on assets, and (2) $11.6 million of pension liability actuarial loss is primarily due to a decrease in the discount rate that is used to value pension liabilities. The unrecognized net loss of $197.9 million in the Pension Plans has arisen over time primarily due to the long-term declining trend in corporate bond rates, the lower than expected return on assets during the year 2008, and the adoption of new mortality tables which increased the expected benefit obligation due to the longer expected lives of participants, since ASC 715 was adopted. The unrecognized net loss, to the extent that it exceeds 10% of the greater of the benefit obligation or the assets, will be amortized and included as a component of net periodic benefit cost in future years. The amortization period is approximately 12 years based on estimated demographic data as of December 31, 2009. The projected benefit obligation of $548.8 million, less the fair value of assets of $367.5 million results in a funded status of ($181.3 million) at December 31, 2009.

Effective for fiscal years ending after December 15, 2008, ASC 715 requires plan assets and liabilities to be measured at their fair value as of fiscal year-end. See “Pension Assets” for further discussion of pension assets measured at fair value. The Pension Plans had a measurement date of November 30 for the fiscal year ended December 31, 2007. Therefore, in accordance with ASC 715, IPL elected to change the Pension Plans’ measurement date from November 30 to December 31, effective December 31, 2008. ASC 715 gave employers two methods for changing their measurement dates: (1) The “remeasurement method,” which would require assets and liabilities to be remeasured at the end of the preceding fiscal year (December 31, 2007) or (2) A simplified “13-month method,” that avoids a remeasurement at the start of the transition year.

Under either option, the plan must book an adjustment to retained earnings to reflect net periodic cost for the “gap period” (December 1, 2007 to December 31, 2007). IPL elected the simplified “13-month method” for remeasurement. The “gap period” adjustment is booked as an adjustment to retained earnings to reflect net periodic cost for the “gap period” of $0.4 million, net of income taxes, and Accumulated Other Comprehensive Income or Loss, to the extent it includes amortization components and does not flow through earnings or income. Under the 13-month method, no adjustment was required to Accumulated Other Comprehensive Income or Loss for gains and losses arising during the gap period. Amounts that would otherwise be charged/credited to Accumulated Other Comprehensive Income or Loss upon application of ASC 715 are recorded as a regulatory asset or liability because IPL has historically recovered and currently recovers pension and other postretirement benefit expenses in rates. These are unrecognized amounts yet to be recognized as components of net periodic benefit costs.

The following table presents the “gap period” adjustment that was booked to IPL’s January 1, 2008 beginning retained earnings. The information relates to the Pension Plans:


	*(In Thousands)*
Components of net periodic benefit cost:
Service cost	$	437
Interest cost		2,527
Expected return on plan assets		(2,624)
Amortization of actuarial loss		114
Amortization of prior service cost		239
Net periodic benefit cost	$	693


	Pension benefits for years ended December 31,
	2009		2008		2007
	*(In Thousands)*
Components of net periodic benefit cost:
Service cost	$	6,319	$	5,248	$	5,886
Interest cost		32,066		30,293		28,608
Plan Settlements		256		546		-
Expected return on plan assets		(24,150)		(31,443)		(30,811)
Amortization of prior service cost		3,523		2,868		2,747
Recognized actuarial loss		16,279		1,366		5,636
Total pension cost		34,293		8,878		12,066
Less: amounts capitalized		2,469		747		1,074
Amount charged to expense	$	31,824	$	8,131	$	10,992
Rates relevant to each year's expense calculation:
Discount rate - defined benefit pension plan		6.26%		6.49%		5.63%
Discount rate - supplemental retirement plan		6.31%/5.06% ⁽¹⁾		6.49%/6.355%/7.18%⁽²⁾		5.63%
Expected return on defined benefit pension plan assets		8.00%		7.75%		8.00%
Expected return on supplemental retirement plan assets		8.00%		7.75%		8.00%
⁽¹⁾ 6.31% for the period January 1, 2009 thru November 30, 2009, 5.06% for the settlement on November 30, 2009 and the period December 1, 2009 thru December 31, 2009. ⁽²⁾ 6.49% for the period January 1, 2008 thru January 31, 2008; 6.355% for the settlement on January 31, 2008 and the period February 1, 2008 thru July 31, 2008; and 7.18% for the settlement on July 31, 2008 and the period August 1, 2008 thru December 31, 2008.

Pension expense for the following year is determined as of the December 31st measurement date based on the fair value of the Pension Plans’ assets, the expected long-term rate of return on plan assets and a discount rate used to determine the projected benefit obligation. In establishing our expected long-term rate of return assumption, we consider historical returns, as well as, the expected future weighted-average returns for each asset class based on the target asset allocation. For 2009, pension expense was determined using an assumed long-term rate of return on plan assets of 8.0%. As of the December 31, 2009 measurement date, IPL decreased the discount rate from 6.26% to 5.93% for the Defined Benefit Pension Plan and increased the discount rate from 5.06% to 5.27% for the Supplemental Retirement Plan while maintaining an assumed long-term rate of return on plan assets at 8.0%. Due to settlement accounting, the discount rate for the supplemental plan which was initially 6.31% for the period January 1, 2009 thru November 30, 2009, was decreased to 5.06% on November 30, 2009. The effect on 2010 total pension expense of a 25 basis point increase and decrease in the assumed discount rate is ($1.1 million) and $1.2 million, respectively. The effect on 2010 total pension expense of a one percentage point increase and decrease in the expected long-term rate of return on plan assets is ($3.6 million) and $3.6 million, respectively.

Expected amortization

The estimated net loss and prior service cost for the Pension Plans that will be amortized from the regulatory asset into net periodic benefit cost over the 2010 plan year are $11.8 million and $3.5 million, respectively (Defined Benefit Pension Plan of $11.7 million and $3.5 million, respectively; and the Supplemental Retirement Plan of $0.1 million and $0 million, respectively).

Pension Assets

Fair Value Measurements

FSP 132(R)-1 replaces the requirement to disclose the percentage of the fair value of total plan assets with a requirement to disclose the fair value of each major asset category. FSP 132(R)-1 also requires disclosure of the level within the fair value hierarchy (i.e., Level 1, Level 2 and Level 3) in which each major category of plan assets falls, using the guidance in ASC 820.

Following is a description of the valuation methodologies used for assets and liabilities measured at fair value:

Other than Common/Collective Trusts and Hedge Funds, all Plan investments are actively traded on an open market and are categorized as Level 1 in the fair value hierarchy.

Investments in Hedge Funds are valued utilizing the observable net asset values (NAV) of the Plan’s interest provided by the underlying Hedge Fund, after considering subscription and redemption rights, including any restrictions on the disposition of the interest in its determination of fair value. The Fund’s investments in Hedge Funds have been recorded at fair value and are all categorized as Level 2 investments in the fair value hierarchy.

The Plan’s investments in Common/Collective Trusts are valued at the net asset value of shares held by the Plan at year end. These net asset values have been determined based on the market value of the underlying securities held by the Common/Collective Trusts. The securities held by the Common/Collective Trusts are actively traded on an open market.

The primary long-term investment objective of managing pension assets is to achieve a total return equal to or greater than the weighted average targeted rate of return (see table below). Additional objectives include maintenance of sufficient income and liquidity to pay retirement benefits, as well as, a long-term annualized rate of return (net of relevant fees) that meets or exceeds the assumed targeted rate. In order to achieve these objectives, the plan seeks to achieve a long-term above-average total return consisting of capital appreciation and income. Though it is the intent to achieve an above-average return, that intent does not include taking extraordinary risks or engaging in investment activities not commonly considered prudent. In times when the securities markets demonstrate uncommon volatility and instability, it is the intent to place more emphasis on the preservation of principal. Please refer to the table below for more detailed information concerning the target allocations, allocation ranges, expected annual return, and expected standard deviation of the applicable pension asset categories. The expected long-term rate of return on pension assets is based on the assumption in the table below.

The investment management of the pension assets are managed with the following asset allocation guidelines:



	Lower Limit		Target Allocation	Upper Limit	Return⁽²⁾	Risk⁽³⁾
U.S. Large Cap Equities		20.0%	30.0%	40.0%	10.4%	15.0%
U.S. Mid Cap Equities		2.5%	5.0%	7.5%	11.3%	16.8%
U.S. Small Cap Equities		2.5%	5.0%	7.5%	11.9%	19.5%
International Equities		0.0%	10.0%	20.0%	9.9%	17.4%
Fixed Income - Core		20.0%	30.0%	40.0%	5.7%	3.9%
High Yield		5.0%	10.0%	15.0%	8.0%	9.5%
Real Estate Investment Trusts⁽¹⁾		0.0%	5.0%	10.0%	9.4%	17.5%
Hedge Funds ⁽¹⁾		0.0%	5.0%	10.0%	11.7%	10.5%

⁽¹⁾Alternative investments (combined) not to exceed 10%
⁽²⁾ Expected long-term annual return
⁽³⁾ Expected standard deviation

The fair values of the pension plan assets at December 31, 2009, by asset category are as follows:


	Fair Value Measurements at December 31, 2009
	(In Thousands)

Asset Category	Total	(Level 1)	(Level 2)	(Level 3)	%

Cash and cash equivalents	15,697	15,697	-	-	4%

Equity securities:
U.S. small cap value	21,242	21,242	-	-	6%
U.S. small cap growth	178	178	-	-	-
U.S. small-mid cap growth	22,212	22,212	-	-	6%
U.S. mid cap core	276	276	-	-	-
U.S. large cap value ⁽¹⁾	32,634	18,183	14,451	-	9%
U.S. large cap growth⁽²⁾	35,323	18,410	16,913	-	10%
U.S. large cap core	55,217	55,217	-	-	15%
International developed markets ⁽³⁾	29,609	29,609	-	-	8%
International emerging markets	5,254	5,254	-	-	1%
Preferred Stock	271	271	-	-	-
REIT - domestic	8,213	8,213	-	-	2%

Fixed Income securities:
International developed markets	237	237	-	-	-
International emerging markets	62	62	-	-	-
Government debt securities ⁽⁴⁾	43,540	43,540	-	-	12%
High Yield	34,657	34,657	-	-	9%
Mortgage backed securities	9,817	9,817	-	-	3%
Asset backed securities	3,889	3,889	-	-	1%
Collateralized mortgage obligations	1,286	1,286	-	-	-
Corporate bonds ⁽⁵⁾	32,002	32,002	-	-	9%

Other types of investments:
Equity long/short fund of funds hedge fund ⁽⁶⁾	13,885	-	13,885	-	4%
Multi-strategy fund of funds hedge fund⁽⁷⁾	1,962	-	1,962	-	1%

TOTAL	367,463	320,252	47,211	-	100%

⁽¹⁾This category includes 44% of low-cost equity index funds that track the Russell 1000 Value index.
⁽²⁾This category includes 48% of low-cost equity index funds that track the Russell 1000 Value index.
⁽³⁾This category represents equity securities of developed non-U.S. issuers across diverse industries.
⁽⁴⁾This category includes U.S. Treasury and Government agency securities.
⁽⁵⁾This category represents investment grade bonds of U.S. issuers from diverse industries.
⁽⁶⁾This category includes fund of fund hedge funds that invest both long and short in primarily U.S. common stocks. Management of the hedge funds has the ability to shift investments from a net long position to a net short position.
⁽⁷⁾This category invests in multiple strategies to diversify risks and reduce volatility. The fund is currently in full liquidation.

Other Postretirement Benefits and Expense


	Other postretirement benefits for years ended December 31,
	2009		2008		2007
	*(In Thousands)*
Components of net periodic benefit cost:
Service cost	$	681	$	1,115	$	1,321
Interest cost		470		645		580
Amortization of prior service cost		(339)		(55)		6
Amortization of net gain (loss)		(102)		(18)		-
Total pension cost		710		1,687		1,907
Less: amounts capitalized		51		142		170
Amount charged to expense	$	659	$	1,545	$	1,737

Discount rate - Other postretirement benefit plan		5.79%/7.44% ⁽¹⁾		6.64%		5.81%
Expected return on Other postretirement benefit plan assets		NA		NA		NA
⁽¹⁾ 5.79% for the period January 1, 2009 through March 18, 2009, and 7.44% for the settlement on March 18, 2009 and the period March 19, 2009 through December 31, 2009.

As of the December 31, 2009 measurement date, IPL decreased the discount rate from 7.44% to 5.90%. The discount rate assumption affects the other postretirement expense determined for 2010. Due to a plan amendment materially decreasing plan benefits, the discount rate for the plan which was initially 5.79% for the period January 1, 2009 thru March 18, 2009, was increased to 7.44% on March 19, 2009. The effect on 2010 total other postretirement expense of a 25 basis point increase and decrease in the assumed discount rate is ($10 thousand) and $10 thousand, respectively.

Health Care Cost Trend Rates

For measurement purposes, we assumed an annual rate of increase in the per capita cost of covered medical care benefits of 7.35% for 2010, gradually declining to 4.5% in 2029 and remaining level thereafter. In addition, we assumed an annual rate of increase in the per capita cost of covered prescription drugs of 7.35% for 2010, gradually declining to 4.5% in 2029 and then remaining level.

Effect of Change in Health Care Cost Trend Rates


	2009		2008
	*(In Thousands)*
Effect on total service cost and interest cost components:
One-percentage point increase	$	237	$	465
One-percentage point decrease	$	(193)	$	(346)
Effect on year-end benefit obligation:
One-percentage point increase	$	609	$	3,084
One-percentage point decrease	$	(506)	$	(2,320)

The Medicare Prescription Drug, Improvement and Modernization Act of 2003

The Medicare Prescription Drug Improvement and Modernization Act of 2003 includes Medicare drug coverage that became effective on January 1, 2006. Current covered retirees are only eligible for coverage until age 55 (First Voluntary Early Retirement Program) or age 62 (Second and Third Voluntary Early Retirement Program). Following the March, 2009 plan changes, no future retirees are eligible for post age-65 coverage. IPL does not expect to qualify for significant subsidies under the Medicare Prescription Drug Improvement and Modernization Act of 2003 and, as a result, no projected subsidy was included in the actuarial valuation of the benefit obligation.

Expected amortization

The estimated net gain and prior service credit for the other postretirement plan that will be amortized from the regulatory liability into net periodic benefit cost over the 2010 plan year are $176,042 and $310,851, respectively.

Pension Funding

We contributed $20.1 million and $56.7 million to the Pension Plans in 2009 and 2008, respectively. There were no contributions to the Pension Plans in 2007. Funding for the qualified Defined Benefit Pension Plan is based upon actuarially determined contributions that take into account the amount deductible for income tax purposes and the minimum contribution required under Employee Retirement Income Security Act of 1974, as amended by the Pension Protection Act of 2006, as well as targeted funding levels necessary to meet certain thresholds. Management does not currently expect any of the pension assets to revert back to IPL during 2010.

From a funding perspective, IPL’s funding target liability shortfall is estimated to be approximately $115 million as of January 1, 2010. The shortfall must be funded over seven years. In addition, IPL must also contribute the normal service cost earned by active participants during the plan year. The service cost is expected to be about $7 million in 2010. Then, each year thereafter, if the plan’s underfunding increases to more than the present value of the remaining annual installments, the excess is separately amortized over a new seven year period. IPL is required to fund approximately $28 million during 2010. However, IPL may decide to contribute more than $28 million to meet certain funding thresholds. IPL’s funding policy for the Pension Plans is to contribute annually no less than the minimum required by applicable law, nor more than the maximum amount that can be deducted for federal income tax purposes.


Year	Pension Benefits		Other Postretirement Benefits
	*(In Thousands)*
2010	$	31,004	$	586
2011		30,490		499
2012		31,467		405
2013		32,636		356
2014		34,020		341
2015 through 2019 (in total)		189,951		804

Voluntary Early Retirement Programs

In conjunction with the AES acquisition, IPL implemented three Voluntary Early Retirement Programs which offered eligible employees enhanced retirement benefits upon early retirement. Participation in the VERPs was accepted by 551 qualified employees, who elected actual retirement dates between March 1, 2001, and August 1, 2004. Additionally, we currently intend to provide postretirement medical and life insurance benefits to the retirees in the first VERP until age 55; at which time they will be eligible to receive similar benefits from the independent VEBA Trust. IPL reserves the right to modify or terminate any of the postretirement health care and life insurance benefits provided by IPL. IPL also provides postretirement medical and life insurance benefits to the retirees in the second and third VERPs from their retirement until age 62. The additional cost was initially estimated to be $7.5 million to be amortized over 8 years.

Due to plan changes effective January 1, 2007, an additional $2.7 million negative prior service cost base was created as of December 31, 2006. This prior service cost base reduces the unrecognized prior service cost for the second and third VERPs ($3.1 million as of December 31, 2006) to $0.4 million which is amortized over the remaining four years ($0.1 million per year). When those retirees reach age 62, they will be eligible for benefits from the VEBA Trust.

Due to plan changes effective January 1, 2008, an additional $0.2 million negative prior service cost base was created as of December 31, 2007. This prior service cost base reduces the unrecognized prior service cost for the second and third VERPs ($0.3 million as of December 31, 2007) to $0.1 million which is amortized over the remaining three years. When those retirees reach age 62, they will be eligible for benefits from the VEBA Trust.

Due to the plan changes effective January 1, 2009, an additional $0.2 million negative prior service cost base was created as of December 31, 2008. This prior service cost base eliminated the unrecognized prior service cost for the second and third VERPs ($0.1 million as of December 31, 2008). The remaining $0.1 million is amortized over 14 years.

Effective March 1, 2009, the plan was amended to eliminate post-65 coverage for participants retiring after December 31, 2009. This change created a $4.2 million negative prior service cost base. The $4.2 million is amortized over 14 years.

Due to the plan changes effective January 1, 2010, an additional $38 thousand negative prior service cost base was created as of December 31, 2009. This amount is amortized over 13 years.

Defined Contribution Plans

All of IPL’s employees are covered by one of two defined contribution plans, the Thrift Plan or the RSP:

The Thrift Plan

Approximately 90% of IPL’s active employees are covered by the Thrift Plan. The Thrift Plan is a qualified defined contribution plan. All union new hires are covered under the Thrift Plan.

Participants elect to make contributions to the Thrift Plan based on a percentage of their base compensation. Each participant’s contribution is matched in amounts up to, but not exceeding, 4% of the participant’s base compensation, except for employees hired after October 20, 2000 who are members of the clerical-technical unit; and employees hired on or after December 19, 2005 who are members of the physical bargaining unit of the IBEW union, who are not eligible for postretirement health care benefits; whose contributions are matched up to 5% of their base compensation. Beginning in 2007, the IBEW clerical-technical union new hires, in addition to the IPL match, receive an annual lump sum company contribution into the Thrift Plan. Employer contributions to the Thrift Plan were $2.9 million, $2.8 million and $2.6 million for 2009, 2008 and 2007, respectively.

The AES Retirement Savings Plan

Approximately 10% of IPL’s active employees are covered by the RSP. The RSP is a qualified defined contribution plan containing a profit sharing component. All non-union new hires are covered under the RSP, while union new hires are covered under the Thrift Plan. Participants elect to make contributions to the RSP based on a percentage of their taxable compensation. Each participant’s contribution is matched in amounts up to, but not exceeding, 5% of the participant’s taxable compensation. In addition, the RSP has a profit sharing component whereby IPL contributes a percentage of each employee’s annual salary into the plan on a pre-tax basis. The profit sharing percentage is determined by the AES Board of Directors on an annual basis. Employer payroll-matching and profit sharing contributions (by IPL) relating to the RSP were $2.3 million, $2.0 million and $1.9 million for 2009, 2008 and 2007, respectively.

14. COMMITMENTS AND CONTINGENCIES

Legal

IPL is a defendant in a little more than one hundred pending lawsuits alleging personal injury or wrongful death stemming from exposure to asbestos and asbestos containing products formerly located in IPL power plants. IPL has been named as a “premises defendant” in that IPL did not mine, manufacture, distribute or install asbestos or asbestos containing products. These suits have been brought on behalf of persons who worked for contractors or subcontractors hired by IPL. IPL has insurance which may cover some portions of these claims; currently, these cases are being defended by counsel retained by various insurers who wrote policies applicable to the period of time during which much of the exposure has been alleged.

It is possible that material additional loss with regard to the asbestos lawsuits could be incurred. At this time, an estimate of additional loss cannot be made. IPL has settled a number of asbestos related lawsuits for amounts which, individually and in the aggregate, were not material to IPL or IPALCO’s results of operations, financial condition, or cash flows. Historically, settlements paid on IPL’s behalf have been comprised of proceeds from one or more insurers along with comparatively smaller contributions by IPL. We are unable to estimate the number of, the effect of, or losses or range of loss which are reasonably possible from the pending lawsuits or any additional asbestos suits. Furthermore, we are unable to estimate the portion of a settlement amount, if any, that may be paid from any insurance coverage for any known or unknown claims. Accordingly, there is no assurance that the pending or any additional suits will not have a material adverse effect on IPALCO’s results of operations, financial condition, or cash flows.

Please see Note 4, “Regulatory Matters - Voluntary Employee Beneficiary Association Trust Complaint” for a discussion of VEBA Trust related legal proceedings.

In addition, IPALCO and IPL are involved in litigation arising in the normal course of business. While the results of such litigation cannot be predicted with certainty, management believes that the final outcome will not have a material adverse effect on IPALCO’s results of operations, financial condition, or cash flows. Amounts accrued or expensed for legal or environmental contingencies collectively during the periods covered by this report have not been material to IPALCO’s audited Consolidated Financial Statements.

Environmental

We are subject to various federal, state and local environmental protection and health and safety laws and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of hazardous materials; the emission and discharge of hazardous and other materials into the environment; and the health and safety of our employees. These laws and regulations often require a lengthy and complex process of obtaining and renewing permits and other governmental authorizations from federal, state and local agencies. Violation of these laws, regulations or permits can result in substantial fines, other sanctions, and permit revocation and/or facility shutdowns. While we believe IPL operates in compliance with applicable environmental requirements, from time to time the company is subject to enforcement actions for claims of noncompliance. IPL cannot assure that it will be successful in defending against any claim of noncompliance. However, other than the Notice of Violation from the EPA (which remains to be resolved but could potentially result in fines or other required changes that could be material to our results of operations, financial condition, or cash flows), we do not believe any currently open investigations will result in fines material to our results of operations, financial condition, or cash flows.

New Source Review

In October 2009, IPL received a Notice of Violation and Finding of Violation from EPA pursuant to CAA Section 113(a). The Notice alleges violations of the CAA at IPL’s three coal-fired electric generating facilities dating back to 1986. The alleged violations primarily pertain to EPA’s Prevention of Significant Deterioration and New Source Review programs under the CAA. Since receiving the letter, IPL management has met with EPA staff and is currently in discussions with the EPA regarding possible resolutions to this Notice of Violation. At this time, we cannot predict the ultimate resolution of this matter. However, settlements and litigated outcomes of similar cases have required companies to pay civil penalties and to install additional pollution control technology projects on coal-fired electric generating units. A similar outcome in this case could have a material impact to our business. We would seek recovery of any operating or capital expenditures related to pollution control technology projects to reduce air regulated emissions; however, there can be no assurances that we would be successful in that regard.

Clean Air Interstate Rule

In March 2005 the EPA signed the federal CAIR, which imposes restrictions against polluting the air of downwind states. The federal CAIR established a two-phase regional “cap and trade” program for SO2 and NOx emissions that requires the largest reduction in air pollution in more than a decade. Federal CAIR covers 28 eastern states, including Indiana, and the District of Columbia.

Clean Air Mercury Rule

CAMR was promulgated in March 2005 and as proposed required reductions of mercury emissions from coal-fired power plants in two phases. However, in February 2008, the U.S. Court of Appeals for the District of Columbia Circuit ruled that CAMR as promulgated violated the CAA and vacated the rule. The EPA is obligated under the CAA, and the District of Columbia Circuit court ruling, to develop a rule requiring pollution controls for hazardous air pollutants, including mercury, from coal and oil-fired power plants. The EPA has entered into a consent decree under which it is obligated to propose the rule by March 2011 and to finalize the rule by November 2011. Under the CAA, compliance is required within 3 years of the effective date of the rule; however, the compliance period may be extended by the state permitting authorities (for one additional year) or through a determination by the U.S. President (for up to two additional years). The CAA requires the EPA to establish maximum achievable control technology standards for each hazardous air pollutant regulated under the CAA. The MACT minimum standard is defined as the emission limitation achieved by the “best performing 12%” of sources in the source category. While it is impossible to project what emission rate levels the EPA may propose as MACT for mercury emissions at coal-fired utility boilers, the rule will likely require all coal-fired power plants to install acid gas scrubbers (wet or dry flue gas desulfurization technology) and/or some other type of mercury control technology, such as sorbent injection. While the exact impact and cost of any such new federal rules cannot be established until they are promulgated they could have a material adverse effect on our business and/or results of operations, financial condition or cash flows.

Clean Coal Technology Filings

In April 2008, in response to a petition we filed, the IURC issued an order approving recovery of capital expenditures of approximately $92.7 million over three years through our ECCRA filings. The $92.7 million approved by the IURC includes $90.0 million to install and/or upgrade CCT to further reduce SO2 and mercury emissions at our Petersburg generating station and $2.7 million for mercury emissions monitoring equipment at our coal-fired power plants. We currently estimate the installation and/or upgrade of CCT to further reduce SO2 and mercury emissions at our Petersburg generating station will cost approximately $119.9 million. We have received authorization for cost recovery for such amount by the IURC in a manner consistent with existing CCT projects.

15. RELATED PARTY TRANSACTIONS

IPL participates in a property insurance program in which IPL buys insurance from AES Global Insurance Company, a wholly-owned subsidiary of AES. IPL is not self-insured on property insurance with the exception of a $1 million self-insured retention per occurrence. Except for IPL’s large substations, IPL does not carry insurance on transmission and distribution assets, which are considered to be outside the scope of property insurance. AES and other AES subsidiaries, including IPALCO also participate in the AES global insurance program. IPL pays premiums for a policy that is written and administered by a third party insurance company. The premiums paid to this third party administrator by the participants are deposited into a trust fund owned by AES Global Insurance Company, but controlled by the third party administrator. This trust fund pays aggregate claims up to $25 million. Claims above the $25 million aggregate will be covered by separate insurance policies issued by a syndicate of third party carriers. These policies provide coverage of $600 million per occurrence. The cost to IPL of coverage under this program was approximately $3.9 million, $3.6 million, and $3.3 million in 2009, 2008, and 2007, respectively, and is recorded in Other operating expenses on the accompanying Consolidated Statements of Income. As of December 31, 2009 and 2008, we had prepaid approximately $1.7 million, which are recorded in Prepayments and other current assets on the accompanying Consolidated Balance Sheets.

IPL participates in an agreement with Health and Welfare Benefit Plans LLC, an affiliate of AES, to participate in a group benefits program, including but not limited to, health, dental, vision and life benefits. Health and Welfare Benefit Plans LLC administers the financial aspects of the group insurance program, receives all premium payments from the participating affiliates, and makes all vendor payments. Health insurance costs have risen significantly during the last few years. The cost of coverage under this program was approximately $20.5 million, $21.0 million, and $20.5 million in 2009, 2008 and 2007, respectively and is recorded in Other operating expenses on the accompanying Consolidated Statements of Income. As of December 31, 2009 and 2008 we had prepaid approximately $0.5 million and $2.9 million for coverage under this plan, which is recorded in Prepayments and other current assets on the accompanying Consolidated Balance Sheets.

Long-term Compensation Plan

16. SEGMENT INFORMATION

Operating segments are components of an enterprise for which separate financial information is available and is evaluated regularly by the chief operating decision maker in assessing performance and deciding how to allocate resources. Substantially all of our business consists of the generation, transmission, distribution and sale of electric energy conducted through IPL which is a vertically integrated electric utility. IPALCO’s reportable business segments are utility and nonutility. The nonutility category primarily includes the 2011 IPALCO Notes and the 2016 IPALCO Notes; approximately $6.3 million and $5.2 million of nonutility cash and cash equivalents, as of December 31, 2009 and 2008 respectively; short-term and long-term nonutility investments (including the 4.4% ownership interest in EnerTech) of $7.8 million and $9.0 million at December 31, 2009 and 2008, respectively; and income taxes and interest related to those items. Nonutility assets represented less than 1% of IPALCO’s total assets as of December 31, 2009 and 2008. The accounting policies of the identified segments are consistent with those policies and procedures described in the summary of significant accounting policies. Intersegment sales, if any, are generally based on prices that reflect the current market conditions.

The following table provides information about IPALCO’S business segments (in millions):

	2009			2008			2007
	Electric	All Other	Total	Electric	All Other	Total	Electric	All Other	Total

Operating revenues	$1,068	-	$1,068	$1,079	-	$1,079	$1,053	-	$1,053
Depreciation and amortization	162	-	162	161	-	161	141	-	141
Income taxes	74	(26)	48	80	(32)	48	107	(25)	82
Net income	113	(39)	74	123	(48)	75	165	(39)	125
Property - net of depreciation	2,322	-	2,322	2,341	-	2,341	2,347	-	2,347
Capital expenditures	115	-	115	107	-	107	201	-	201

17. QUARTERLY RESULTS (UNAUDITED)

Operating results for the years ended December 31, 2009 and 2008, by quarter, are as follows:


	2009
	March 31		June 30		September 30		December 31
	*(In Thousands)*
Utility operating revenue	$	289,728	$	261,339	$	265,902	$	251,112
Utility operating income		48,750		35,673		46,456		39,078
Net income		34,040		22,181		32,665		24,225


	2008
	March 31		June 30		September 30		December 31
	*(In Thousands)*
Utility operating revenue	$	249,033	$	267,328	$	287,973	$	274,779
Utility operating income		36,491		42,926		54,620		47,856
Net income		22,262		28,573		41,149		31,097

The quarterly figures reflect seasonal and weather-related fluctuations that are normal to IPL’s operations.

************

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholder and Board of Directors of

Indianapolis Power & Light Company

We have audited the accompanying consolidated balance sheets of Indianapolis Power & Light Company and subsidiary (the Company) as of December 31, 2009 and 2008, and the related consolidated statements of income, common shareholder’s equity, and cash flows for each of the two years in the period ended December 31, 2009. Our audits also included the financial statement schedules listed in the Index at Item 15 as of and for the years ended December 31, 2009 and 2008. These financial statements and schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Indianapolis Power & Light Company and subsidiary at December 31, 2009 and 2008, and the consolidated results of their operations and their cash flows for each of the two years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedules as of and for the years ended December 31, 2009 and 2008, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.

/s/ ERNST & YOUNG LLP

Indianapolis, Indiana

February 25, 2010 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholder and Board of Directors of

Indianapolis Power & Light Company

Indianapolis, Indiana

We have audited the accompanying consolidated statements of income, common shareholders' equity and cash flows of Indianapolis Power & Light Company (the “Company”) for the year ended December 31, 2007. Our audit also included the financial statement schedule for 2007 listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audit.

In our opinion, such consolidated financial statements present fairly, in all material respects, the results of operations and cash flows of Indianapolis Power & Light Company for the year ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule for 2007, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ DELOITTE & TOUCHE LLP

Indianapolis, Indiana

March 24, 2008


IPL-DefinedTerms
The following is a list of frequently used abbreviations or acronyms that are found in the Financial Statements and Supplementary Data:

1995B Bonds	$40 Million City of Petersburg, Indiana, Pollution Control Refunding Revenue Bonds Adjustable Rate Tender Securities Series 1995B, Indianapolis Power & Light Company Project
2008 IPALCO Notes	$375 million of 8.375% (original coupon 7.375%) Senior Secured Notes due November 14, 2008
2011 IPALCO Notes	$375 million of 8.625% (original coupon 7.625%) Senior Secured Notes due November 14, 2011
2016 IPALCO Notes	$400 million of 7.25% Senior Secured Notes due April 1, 2016
AES	The AES Corporation
ARO	Asset Retirement Obligations
ASM	Ancillary Services Market
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CCT	Clean Coal Technology
Defined Benefit Pension Plan	Employees’ Retirement Plan of Indianapolis Power & Light Company
ECCRA	Environmental Compliance Cost Recovery Adjustment
EPA	U.S. Environmental Protection Agency
FAC	Fuel Adjustment Charges
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FTR	Financial Transmission Right
GAAP	Generally accepted accounting principles in the United States
IPALCO	IPALCO Enterprises, Inc.
IPL	Indianapolis Power & Light Company
IPL Funding	IPL Funding Corporation
IURC	Indiana Utility Regulatory Commission
MW	Megawatt
MWh	Megawatt hour
Medicare Prescription Drug Act	Medicare Prescription Drug, Improvement and Modernization Act of 2003
Midwest ISO	Midwest Independent Transmission System Operator, Inc.
NO_x	Nitrogen Oxides
Pension Plans	Employees’ Retirement Plan of Indianapolis Power & Light Company and Supplemental Retirement Plan of Indianapolis Power & Light Company
RSG	Revenue Sufficiency Guarantee
RSP	The AES Retirement Savings Plan
SFAS	Statement of Financial Accounting Standards
SO₂	Sulfur Dioxide
Supplemental Retirement Plan	Supplemental Retirement Plan of Indianapolis Power & Light Company
S&P	Standard & Poors
Thrift Plan	Employees’ Thrift Plan of Indianapolis Power & Light Company
VEBA Trust	Voluntary Employee Beneficiary Association Trust
VERP	Voluntary Early Retirement Program


INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY
Consolidated Statements of Income
For the Years Ended December 31, 2009, 2008 and 2007
*(In Thousands)*

	2009		2008		2007

OPERATING REVENUES	$	1,068,081	$	1,079,113	$	1,052,627

OPERATING EXPENSES:
Operation:
Fuel		276,422		268,997		237,154
Other operating expenses		200,890		190,871		172,571
Power purchased		46,646		57,220		57,565
Maintenance		102,332		97,056		84,859
Depreciation and amortization		162,167		161,022		140,944
Taxes other than income taxes		35,732		40,934		41,361
Income taxes - net		73,935		81,120		107,755
Total operating expenses		898,124		897,220		842,209
OPERATING INCOME		169,957		181,893		210,418

OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used during construction		2,024		1,104		3,747
Miscellaneous income and (deductions) - net		(1,477)		(1,810)		(437)
Income tax benefit applicable to nonoperating income		(98)		1,072		809
Total other income and (deductions) - net		449		366		4,119

INTEREST AND OTHER CHARGES:
Interest on long-term debt		55,626		57,223		50,396
Other interest		1,391		1,579		1,837
Allowance for borrowed funds used during construction		(1,608)		(1,188)		(3,698)
Amortization of redemption premiums and expense on debt		1,886		1,564		1,736
Total interest and other charges-net		57,295		59,178		50,271

NET INCOME		113,111		123,081		164,266

PREFERRED DIVIDEND REQUIREMENTS		3,213		3,213		3,213

INCOME APPLICABLE TO COMMON STOCK	$	109,898	$	119,868	$	161,053

See notes to consolidated financial statements.


INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY
Consolidated Balance Sheets
*(In Thousands)*

	December 31, 2009		December 31, 2008
ASSETS
UTILITY PLANT:
Utility plant in service	$	4,020,492	$	3,919,710
Less accumulated depreciation		1,788,588		1,677,496
Utility plant in service - net		2,231,904		2,242,214
Construction work in progress		76,472		86,858
Spare parts inventory		12,309		11,053
Property held for future use		991		947
Utility plant - net		2,321,676		2,341,072

OTHER ASSETS:
Investment in long term debt securities (Note 3)		42,000		-
Other - At cost, less accumulated depreciation		861		1,547
Other assets - net		42,861		1,547

CURRENT ASSETS:
Cash and cash equivalents		41,715		11,266
Short-term investments (Note 3)		-		41,550
Accounts receivable and unbilled revenue (less allowance for doubtful accounts of $2,143 and $1,801, respectively)		86,585		86,767
Fuel - at average cost		38,203		31,119
Materials and supplies - at average cost		49,926		47,917
Financial transmission rights		944		5,298
Deferred tax asset - current		10,233		9,220
Regulatory assets		4,828		17,345
Prepayments and other current assets		8,532		9,332
Total current assets		240,966		259,814

DEFERRED DEBITS:
Regulatory assets		395,651		461,729
Miscellaneous		14,291		16,227
Total deferred debits		409,942		477,956
TOTAL	$	3,015,445	$	3,080,389


CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common shareholder’s equity:
Common Stock	$	324,537	$	324,537
Paid in capital		11,610		10,439
Retained earnings		417,311		415,057
Total common shareholder’s equity		753,458		750,033
Cumulative preferred stock		59,784		59,784
Long-term debt		936,602		896,579
Total capitalization		1,749,844		1,706,396

CURRENT LIABILITIES:
Short-term and current portion of long-term debt		-		52,691
Accounts payable		60,630		69,598
Accrued expenses		22,894		22,338
Accrued real estate and personal property taxes		23,631		26,812
Regulatory Liabilities		13,863		5,735
Accrued interest		19,409		16,751
Customer deposits		18,816		16,928
Other current liabilities		9,198		11,243
Total current liabilities		168,441		222,096

DEFERRED CREDITS AND OTHER LONG-TERM LIABILITIES:
Accumulated deferred income taxes - net		374,555		397,192
Non-current income tax liability		8,618		8,351
Regulatory liabilities		492,000		471,002
Unamortized investment tax credit		13,153		15,212
Accrued pension and other postretirement benefits		185,810		234,670
Miscellaneous		23,024		25,470
Total deferred credits and other long-term liabilities		1,097,160		1,151,897

COMMITMENTS AND CONTINGENCIES (Note 14)
TOTAL	$	3,015,445	$	3,080,389

See notes to consolidated financial statements.


INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY
Consolidated Statements of Cash Flows
*(In Thousands)*

	2009		2008		2007

CASH FLOWS FROM OPERATIONS:
Net income	$	113,111	$	123,081	$	164,266
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		157,814		152,251		142,176
Amortization of regulatory assets		7,726		11,598		1,810
Deferred income taxes and investment tax credit adjustments - net		(21,890)		(11,873)		(6,201)
Emissions allowance expense		-		-		2,227
Gains on sales and exchange of environmental emissions allowances		(84)		(549)		(655)
Allowance for equity funds used during construction		(1,807)		(954)		(3,656)
Change in certain assets and liabilities:
Accounts receivable		266		(16,303)		(2,733)
Fuel, materials and supplies		(9,093)		(12,854)		7,921
Income taxes receivable or payable		(3,060)		8,583		(7,226)
Financial transmission rights		4,353		(3,745)		(279)
Accounts payable and accrued expenses		533		12,939		5,236
Accrued real estate and personal property taxes		(3,180)		6,534		4,369
Accrued interest		2,658		1,041		(2,206)
Pension and other postretirement benefit expenses		(48,860)		144,890		(43,085)
Short-term and long-term regulatory assets and liabilities		75,241		(209,737)		27,004
Other - net		4,385		8,755		2,975
Net cash provided by operating activities		278,113		213,657		291,943

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(115,363)		(106,906)		(201,060)
Decrease in restricted cash		-		6		32,700
Purchase of environmental emissions allowances		-		(200)		(2,743)
Purchase of investments		(40,000)		(115,072)		(518,720)
Proceeds from sales and maturities of short-term investments		40,436		74,555		519,389
Proceeds from sales of assets		84		541		672
Other		(7,196)		(4,350)		(11,187)
Net cash used in investing activities		(122,039)		(151,426)		(180,949)

CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt borrowings (repayments) - net		(52,691)		51,691		(74,000)
Long-term borrowings		171,850		-		164,985
Retirement of long-term debt and early tender premium		(131,850)		-		(80,000)
Dividends on common stock		(107,644)		(104,547)		(117,637)
Dividends on preferred stock		(3,213)		(3,213)		(3,213)
Other		(2,077)		(928)		(2,827)
Net cash used in financing activities		(125,625)		(56,997)		(112,692)
Net change in cash and cash equivalents		30,449		5,234		(1,698)
Cash and cash equivalents at beginning of period		11,266		6,032		7,730
Cash and cash equivalents at end of period	$	41,715	$	11,266	$	6,032

Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized)	$	53,953	$	57,184	$	53,834
Income taxes	$	98,750	$	82,583	$	117,933

See notes to consolidated financial statements.


INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY
Consolidated Statements of Common Shareholder’s Equity
For the Years Ended December 31, 2009, 2008 and 2007
*(In Thousands)*

	Common Stock		Premium and Net Gain on Preferred Stock		Paid in Capital		Retained Earnings		Accumulated Other Comprehensive Loss		Total
2007
Beginning Balance	$	324,537	$	2,642	$	3,396	$	356,293	$		$	686,868
Comprehensive Income:
Net income								164,266				164,266
Total Comprehensive Income												164,266

Reclassified to paid in capital				(1,993)		1,993						-
Reclassified to cumulative preferred stock				(649)								(649)
Adjustment for the adoption of FIN 48								438				438
Cash dividends declared
Common stock								(117,637)				(117,637)
Cumulative preferred stock								(3,213)				(3,213)
Contributions from IPALCO						3,247						3,247
Balance at December 31, 2007	$	324,537	$	-	$	8,636	$	400,147	$	-	$	733,320
2008
Comprehensive Income:
Net income								123,081				123,081
Total Comprehensive Income												123,081

Adjustment for the adoption of SFAS 158, net of income taxes of $281								(411)				(411)
Cash dividends declared
Common stock								(104,547)				(104,547)
Cumulative preferred stock								(3,213)				(3,213)
Contributions from IPALCO						1,803						1,803
Balance at December 31, 2008	$	324,537	$	-	$	10,439	$	415,057	$	-	$	750,033
2009
Comprehensive Income:
Net income								113,111				113,111
Total Comprehensive Income												113,111

Cash dividends declared
Common stock								(107,644)				(107,644)
Cumulative preferred stock								(3,213)				(3,213)
Contributions from IPALCO						1,171						1,171
Balance at December 31, 2009	$	324,537	$	-	$	11,610	$	417,311	$	-	$	753,458

See notes to consolidated financial statements.

INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY
Notes to Consolidated Financial Statements
For the Years Ended December 31, 2009, 2008 and 2007

1. ORGANIZATION

Indianapolis Power & Light Company was incorporated under the laws of the state of Indiana in 1926. All of the outstanding common stock of IPL is owned by IPALCO Enterprises, Inc. IPALCO is a wholly-owned subsidiary of AES. IPALCO was acquired by AES in March 2001. IPL is engaged primarily in generating, transmitting, distributing and selling electric energy to more than 470,000 retail customers in the city of Indianapolis and neighboring cities, towns and communities, and adjacent rural areas all within the state of Indiana, the most distant point being approximately forty miles from Indianapolis. IPL has an exclusive right to provide electric service to those customers. IPL owns and operates two primarily coal-fired generating plants, one combination coal and gas-fired plant and a separately-sited combustion turbine that are all used for generating electricity. IPL’s net electric generation capability for winter is 3,492 megawatts and net summer capability is 3,353 megawatts.

IPL Funding Corporation is a special-purpose entity and a wholly owned subsidiary of IPL and is included in the audited Consolidated Financial Statements of IPL. IPL formed IPL Funding in 1996 to sell, on a revolving basis, up to $50 million of the retail accounts receivable and related collections of IPL to the Purchasers in exchange for cash (see Sales of Accounts Receivable in Note 3, “Summary of Significant Accounting Policies”)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

IPL’s consolidated financial statements are prepared in accordance with generally accepted accounting principles in the United States and in conjunction with the rules and regulations of the Securities and Exchange Commission. The consolidated financial statements include the accounts of IPL and its unregulated subsidiary, IPL Funding. All intercompany items have been eliminated in consolidation. We have evaluated subsequent events through February 25, 2010, which is the same date this report is issued.

Use of Management Estimates

Reclassifications

Certain prior period amounts have been reclassified to conform to the current year presentation.

Regulation

The retail utility operations of IPL are subject to the jurisdiction of the Indiana Utility Regulatory Commission. IPL’s wholesale power transactions are subject to the jurisdiction of the Federal Energy Regulatory Commission. These agencies regulate IPL’s utility business operations, tariffs, accounting, depreciation allowances, services, security issues and the sale and acquisition of utility properties. The financial statements of IPL are based on GAAP, including the provisions of ASC 980 “Regulated Operations,” which gives recognition to the ratemaking and accounting practices of these agencies. See also Note 8, “Regulatory Assets and Liabilities” for a discussion of specific regulatory assets and liabilities.

Revenues

Revenues related to the sale of energy are generally recognized when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is accrued. In making its estimates of unbilled revenue, IPL uses complex models that consider various factors including daily generation volumes, known amounts of energy usage by certain customers, estimated line losses and estimated customer rates based on prior period billings. Given the use of these models, and that customers are billed on a monthly cycle, we believe it is unlikely that materially different results will occur in future periods when revenue is billed. As part of the estimation of unbilled revenues, IPL estimates line losses on a monthly basis. At December 31, 2009 and 2008, customer accounts receivable include unbilled energy revenues of $48.7 million and $47.4 million, respectively, on a base of annual revenue of $1.1 billion in each of 2009 and 2008.

Contingencies

IPL accrues for loss contingencies when the amount of the loss is probable and estimable. IPL is subject to various environmental regulations, and is involved in certain legal proceedings. If IPL’s actual environmental and/or legal obligations are different from our estimates, the recognition of the actual amounts may have a material impact on our results of operations, financial condition, and cash flows; although that has not been the case during the periods covered by this report.

Concentrations of Risk

Allowance For Funds Used During Construction

Utility Plant and Depreciation

Derivatives

We have only limited involvement with derivative financial instruments and do not use them for trading purposes. IPL accounts for its derivatives in accordance with ASC 815 “Derivatives and Hedging.” IPL has one interest rate swap agreement, which is recognized on the audited Consolidated Balance Sheets at its estimated fair value as a liability of approximately $8.2 million. IPL entered into this agreement as a means of managing the interest rate exposure on a $40 million unsecured variable-rate debt instrument. The swap was approved by the IURC as part of IPL’s 1994 financing order. In accordance with ASC 980, IPL recognized a regulatory asset equal to the value of the interest rate swap, which is adjusted as that fair value changes. The settlement amounts from the swap agreement are reported in the financial statements as a component of interest expense. Management uses standard market conventions, in accordance with ASC 820 “Fair Value Measurements and Disclosures,” to determine the fair value of the interest rate swap.

Fuel, Materials and Supplies

We maintain coal, fuel oil, materials and supplies inventories for use in the production of electricity. These inventories are accounted for at the lower of cost or market, using the average cost.

Emissions Allowances

IPL uses environmental air emissions allowances to meet standards set forth by the EPA related to emission of Sulfur Dioxide and Nitrogen Oxide gases. IPL accounts for environmental air emissions allowances as intangible assets and records expenses for allowances using a First In First Out method. The total book value of SO2 and NOx emissions allowances, included in MISCELLANEOUS DEFERRED DEBITS on the accompanying Consolidated Balance Sheets, as of both December 31, 2009 and 2008 was $0.9 million.

Income Taxes

IPL includes any applicable interest and penalties related to income tax deficiencies or overpayments in the provision for income taxes in its Consolidated Statements of Income. The income tax provision includes gross interest income/(expense) of ($0.1) million and $2.0 million for the years ended December 31, 2009 and 2008, respectively.

Cash and Cash Equivalents

We consider all highly liquid investments purchased with original maturities of three months or less at the date of acquisition to be cash equivalents.

Other Investments

Repair and Maintenance Costs

Repair and maintenance costs are expensed as incurred.

Per Share Data

IPL is a wholly-owned subsidiary of IPALCO and does not report earnings on a per-share basis.

New Accounting Pronouncements

ASC 105 “Generally Accepted Accounting Principles”

ASC 320 “Investments - Debt and Equity Securities”

ASC 715 “Compensation - Retirement Benefits”

ASC 815 “Derivatives and Hedging”

In March 2008, the FASB issued SFAS 161“Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133,” which requires additional disclosures about derivatives, but does not change the method of accounting for derivatives. This guidance is now part of ASC 815. The additional disclosures include: the objectives of the derivative instruments and hedging activities, the method of accounting for such instruments under ASC 815, and a tabular disclosure of the effects of such instruments and related hedged items on an entity’s financial position, operations, and cash flows. Contracts that meet the criteria for and that are designated under the normal purchases and normal sales exception are not recorded at fair value and are not included in the disclosure requirements of this update. This guidance became effective for IPL beginning January 1, 2009. The guidance also states that the provisions of the Statement need not be applied to immaterial items. IPL engages in limited derivative and hedging activities. Additionally, IPL’s larger derivative items both qualify for regulatory treatment under ASC 980, “Regulated Operation” and therefore any unrealized gains or losses related to those items are deferred as regulatory assets or liabilities instead of being recognized in the statements of income. As a result, we have determined that our derivative items are not material to our financial statements at this time and have therefore excluded the additional disclosures. Please refer to Note 7, “Fair Value Measurements,” included in this Form 10-K for more information related to IPL’s derivative activities.

ASC 820 “Fair Value Measurements and Disclosures”

ASC 855 “Subsequent Events”

In May 2009, the FASB issued SFAS 165 “Subsequent Events,” which establishes general standards for accounting for and disclosure of events that occur after the balance sheet date but before financial statements are available to be issued. This guidance is now part of ASC 855. ASC 855 sets forth the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition in the financial statements; identifies the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and sets forth the disclosures that should be made about events or transactions that occur after the balance sheet date. ASC 855 provides largely the same guidance on subsequent events which previously existed only in auditing literature. The adoption of this statement did not have a material impact on our results of operations, financial condition or cash flows.

3. Short-term and long-term Investments

Variable Rate Demand Notes

In September 2009, in accordance with the terms of the 1995B Bonds, IPL converted the 1995B Bonds from tax-exempt weekly interest rate mode to commercial paper mode and directed the remarketing agent to no longer remarket the 1995B Bonds. In connection with this conversion all of the outstanding 1995B Bonds were tendered back to the trustee. In accordance with the terms of IPL’s committed liquidity facility, the trustee drew $40 million against this facility to fund the tender and the trustee is again holding the 1995B Bonds on IPL’s behalf. In accordance with the terms of the 1995B Bonds, these bonds do not bear interest while in commercial paper mode since they are being held by the trustee. Because IPL’s committed liquidity facility does not expire until May 2011 and because management does not currently intend to retire or remarket the 1995B Bonds within the next 12 months, we have classified the associated 1995B Bonds as available-for-sale within long-term investment on our December 31, 2009 balance sheet. IPL is liable for the interest and principal on the liquidity facility. IPL also continues to be liable to the swap counterparty for 5.21% interest rate and the swap counterparty continues to exercise its right to pay interest to IPL at the alternative floating rate. As of December 31, 2009, our effective interest rate on the 1995B Bonds, including the liquidity facility and interest rate swap agreement was approximately 5.67% per annum. All of the 1995B Bonds remain outstanding and IPL remains liable for payment of interest and principal thereon, even though 1995B Bonds are being held by the trustee on behalf of IPL.

4. REGULATORY MATTERS

General

FAC and Authorized Annual Jurisdictional Net Operating Income

Environmental Compliance Cost Recovery Adjustment

Midwest ISO

General

Midwest ISO’s Energy and Ancillary Services Markets Tariff

Midwest ISO Real Time Revenue Sufficiency Guarantee

Demand-Side Management

Smart Grid Investment Grant

Voluntary Employee Beneficiary Association Trust Complaint

Financing Order

Please, see Note 11, “Indebtedness” for information regarding approval from the IURC to refinance our variable rate debt.

5. UTILITY PLANT IN SERVICE

The original cost of utility plant in service segregated by functional classifications, follows:


	As of December 31,
	2009		2008
	*(In Thousands)*
Production	$	2,479,056	$	2,429,724
Transmission		208,979		208,164
Distribution		1,160,106		1,129,739
General plant		172,351		152,083
Total utility plant in service	$	4,020,492	$	3,919,710

6. SALES OF ACCOUNTS RECEIVABLE

Accounts Receivable Securitization

IPL formed IPL Funding Corporation in 1996 as a special-purpose entity to purchase receivables originated by IPL pursuant to a purchase agreement entered into with IPL. At the same time, IPL Funding entered into a sale facility with unrelated parties (Royal Bank of Scotland plc and Windmill Funding Corporation) pursuant to which the Purchasers agree to purchase from IPL Funding, on a revolving basis, interests in the pool of receivables purchased from IPL up to the lesser of (1) an amount determined pursuant to the sale facility that takes into account certain eligibility requirements and reserves relating to the receivables, or (2) $50.0 million. Historically that amount has remained at $50 million, but during the fourth quarter of 2009, the eligible receivables balances was below $50 million and IPL Funding was required to repay Royal Bank of Scotland the shortfall, which was $9.5 million. This shortfall was based on our December reporting to Royal Bank of Scotland of the November 30th data. As of December 31, 2009, the eligible receivables balance was once again over $50 million and Royal Bank of Scotland purchased the additional $9.5 million of receivables from IPL Funding in January 2010. As collections reduce accounts receivable included in the pool, IPL Funding sells ownership interests in additional receivables acquired from IPL to return the ownership interests sold to the maximum amount permitted by the sale facility. During 2009, the sale facility was extended through May 25, 2010. IPL Funding is included in the audited Consolidated Financial Statements of IPL. Since IPL Funding is a wholly owned subsidiary of IPL, IPL is the primary beneficiary of IPL Funding. Accounts receivable on the accompanying audited Consolidated Balance Sheets of IPL are stated net of $40.5 million sold.

The following tables show the receivables sold and retained interests as of the periods ended and cash flows during the periods ending:


	As of December 31,
	2009		2008
	*(In Millions)*
Retail receivables at IPL Funding	$	128.0	$	137.4
Less: Retained interests		87.5		87.4
Net receivables sold	$	40.5	$	50.0

	Twelve Months Ended December 31,
	2009		2008		2007
	*(In Millions)*
Cash flows during period
Cash proceeds from interest retained	$	689.8	$	623.1	$	541.1
Cash proceed from sold receivables⁽¹⁾	$	315.2	$	363.0	$	419.0

⁽¹⁾ Cash flows from the sale of receivables are reflected within Operating Activities on the audited Consolidated Statements of Cash Flows.

There were no proceeds from new securitizations for each of 2009, 2008 and 2007.

7. FAIR VALUE MEASUREMENTS

Cash Equivalents

As of December 31, 2009 and 2008, our cash equivalents consisted of money market funds. The fair value of cash equivalents approximates their book value due to their short maturity, which was $26.1 million and $0.3 million as of December 31, 2009 and 2008, respectively.

Customer Deposits

Pension Assets

Indebtedness

The following table shows the carrying amount and the fair value of fixed rate and variable rate indebtedness for the periods ending:

		December 31, 2009					December 31, 2008
	Carrying Amount		Fair Value		Carrying Amount			Fair Value
	*(In Millions)*
Fixed-rate	$	857.7	$	873.9		$	725.8	$	633.9
Variable-rate		80.0		80.0			224.5		224.5
Total indebtedness	$	937.7	$	953.9		$	950.3	$	858.4

Fair Value Hierarchy

In accordance with ASC 820, we have categorized our financial assets and liabilities that are adjusted to fair value on a recurring basis, based on the priority of the inputs to the valuation technique, based on the three-level fair value hierarchy prescribed by ASC 820. As of December 31, 2009 and 2008 all (excluding pension assets) of our financial assets or liabilities measured at fair value on a recurring basis were categorized as Level 3 because the values were based primarily on unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability. For a complete discussion of the impact of recognizing pension assets at fair value, please refer to Note 13, “Pension and Other Postretirement Benefits.”

Financial assets and liabilities recorded on the audited Consolidated Balance Sheets are categorized based on the inputs to the valuation techniques as follows:

Level 1 - unadjusted quoted prices for identical assets or liabilities in an active market.

Level 2 - inputs from quoted prices in markets where trading occurs infrequently or quoted prices of instruments with similar attributes in active markets.

Level 3 - unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability.

As of December 31, 2009 and 2008 all (excluding pension assets) of IPL’s financial assets or liabilities measured at fair value on a recurring basis were considered Level 3, based on the fair value hierarchy. For a complete discussion of the impact of recognizing pension assets at fair value, please refer to Note 13, “Pension and Other Postretirement Benefits.” The following table presents those financial assets and liabilities:


	Fair Value Measurements using Level 3 at:
	December 31, 2009		December 31, 2008
	*(In Thousands)*
Financial assets:
Investments in debt securities	$	42,000	$	41,550
Financial transmission rights		944		5,298
Total financial assets measured at fair value	$	42,944	$	46,848

Financial liabilities:
Interest rate swap	$	8,179	$	9,918
Other derivative liability		198		194
Total financial liabilities measured at fair value	$	8,377	$	10,112

The following table sets forth a reconciliation of financial instruments classified as Level 3 in the fair value hierarchy:


	Derivative Financial Instruments, net liability		Investments in Debt Securities	Total
	*(In Thousands)*

Balance at January 1, 2009	$	(4,814)	41,550	36,736
Unrealized losses recognized in earnings		(32)	-	(32)
Unrealized gain recognized as a regulatory asset		227	-	227
Issuances and settlements, net		(2,813)	450	(2,363)
Balance at December 31, 2009	$	(7,432)	42,000	34,568

Valuation Techniques

Investments in debt securities

Financial Transmission Rights

Other Financial Instruments

We do not believe any of the other financial instruments which we held as of December 31, 2009 are material to our results of operations, financial condition, and cash flows either qualitatively or quantitatively. As described in Note 2, “Summary of Significant Accounting Polices - Derivatives,” IPL has one interest rate swap agreement, which is recognized on the audited Consolidated Balance Sheets at its estimated fair value as a liability. IPL entered into this agreement as a means of managing the interest rate exposure related to the 1995B Bonds. In accordance with ASC 980, IPL recognized a regulatory asset equal to the value of the interest rate swap, which is adjusted as that fair value changes. Therefore there is no impact to IPL’s Consolidated Statements of Income or Cash Flows for the changes in the fair value of the interest rate swap.

8. REGULATORY ASSETS AND LIABILITIES

The amounts of regulatory assets and regulatory liabilities at December 31 are as follows:


	2009		2008		Recovery Period
	*(In Thousands)*
Regulatory Assets
Current:
Deferred fuel under-collection	$	-	$	9,252	Through 2009⁽¹⁾
NO_x & CCT project expenses		2,693		5,398	Through 2010⁽¹⁾
Air conditioning load management (demand management)		1,144		2,072	Through 2010⁽¹⁾
Other Demand-Side Management program costs		991		623	Through 2010⁽¹⁾⁽²⁾
Total current regulatory assets		4,828		17,345

Long-term:
Unrecognized pension and other postretirement benefit plan costs	$	217,238	$	280,668	Various
Income taxes recoverable from customers		70,278		75,501	Various
Deferred Midwest ISO costs		62,829		57,921	To be determined⁽³⁾
Unamortized Petersburg unit 4 carrying charges and certain other costs		19,490		20,298	Through 2026⁽¹⁾⁽²⁾
Unamortized reacquisition premium on debt		15,864		15,339	Over remaining life of debt
Unrealized loss on interest rate swap		8,179		9,919	Through 2023
NO_x project expenses - Petersburg unit 2 precipitator		1,731		1,875	Through 2021⁽¹⁾
Other Demand-Side Management and green power program costs		42		208	Various
Total long-term regulatory assets		395,651		461,729
Total regulatory assets	$	400,479	$	479,074

Regulatory Liabilities
Current:
Deferred fuel over-collection	$	12,390	$	-	Through 2010⁽¹⁾
FTR's		944		5,298	Through 2010⁽⁴⁾
Fuel related		382		363	Through 2010
NO_x & CCT project credits		147		74	Through 2010⁽⁴⁾
Total current regulatory liabilities		13,863		5,735

Long-term:
ARO costs and accrued asset removal costs		481,676		458,767	Not Applicable
Unamortized investment tax credit		9,192		10,595	Through 2014
Fuel related		1,132		1,640	Through 2013
Total long-term regulatory liabilities		492,000		471,002
Total regulatory liabilities	$	505,863	$	476,737

⁽¹⁾ Recovered per specific rate orders
⁽²⁾ Recovered with a current return
⁽³⁾ Recovery is probable but timing not yet determined
⁽⁴⁾ Recovered (credited) per specific rate orders

Deferred Fuel

Unrecognized Pension and Postretirement Benefit Plan Costs

Deferred Income Taxes

Deferred Midwest ISO Costs

Unrealized Loss on Interest Rate Swap

Asset Retirement Obligation and Accrued Asset Removal Costs

9. ASSET RETIREMENT OBLIGATIONS


	2009		2008
	*(In Millions)*
Balance as of January 1	$	13.9	$	13.1
Accretion Expense		0.8		0.8
Balance as of December 31	$	14.7	$	13.9

As of December 31, 2009 and 2008, IPL did not have any assets that are legally restricted for settling its ARO liability.

10. SHAREHOLDER’S EQUITY

Capital Stock

All of the outstanding common stock of IPL is owned by IPALCO. IPL’s common stock is pledged under IPALCO’s $375 million of 8.625% (original coupon 7.625%) Senior Secured Notes due November 14, 2011 and $400 million of 7.25% Senior Secured Notes due April 1, 2016. There have been no changes in the capital stock of IPL during the periods covered by this report.

Dividend Restrictions

Cumulative Preferred Stock

IPL has five separate series of cumulative preferred stock. Holders of preferred stock are entitled to receive dividends at rates per annum ranging from 4.0% to 5.65%. During each year ended December 31, 2009, 2008 and 2007, total preferred stock dividends declared were $3.2 million. Holders of preferred stock are entitled to two votes per share for IPL matters, and if four full quarterly dividends are in default on all shares of the preferred stock then outstanding, they are entitled to elect the smallest number of IPL directors to constitute a majority of IPL’s board of directors. Based on the preferred stockholders’ ability to elect a majority of IPL’s board of directors in this circumstance, the redemption of the preferred shares is considered to be not solely within the control of the issuer and the preferred stock was considered temporary equity and presented in the mezzanine level of the audited Consolidated Balance Sheets in accordance with the relevant accounting guidance for non-controlling interests and redeemable securities. IPL has issued and outstanding 500,000 shares of 5.65% Preferred Stock, which are redeemable at par value, subject to certain restrictions, in whole or in part, at any time on or after January 1, 2008, at the option of IPL. Additionally, IPL has 91,353 shares of preferred stock which are redeemable solely at the option of IPL and can be redeemed in whole or in part at any time at specific call prices.

At December 31, 2009, 2008 and 2007, preferred stock consisted of the following:


	December 31, 2009			December 31,
	Shares Outstanding	Call Price		2009		2008		2007
	Shares Outstanding	Call Price		Par Value, plus premium, if applicable
				*(In Thousands)*
Cumulative $100 par value, authorized 2,000,000 shares
4% Series	47,611	$	118.00	$	5,410	$	5,410	$	5,410
4.2% Series	19,331		103.00		1,933		1,933		1,933
4.6% Series	2,481		103.00		248		248		248
4.8% Series	21,930		101.00		2,193		2,193		2,193
5.65% Series	500,000		100.00		50,000		50,000		50,000
Total cumulative preferred stock	591,353			$	59,784	$	59,784	$	59,784

11. INDEBTEDNESS

Restrictions on Issuance of Debt

Before IPL can incur additional long-term debt, it must first have the approval of the IURC. The current IURC approved financing petition, grants IPL the authority to enter into capital lease obligations not to exceed an aggregate principal amount of $10.0 million and to refinance, if appropriate, the 1995B Bonds (See below). Before IPL can incur additional short-term debt, it must first have the approval of the FERC. The current FERC order authorizes IPL to issue up to $500 million of short-term indebtedness outstanding at any time through July 27, 2010. We anticipate submitting an application to FERC to request a new order prior to the expiration of the current order. Also, IPL has restrictions on the amount of new debt it may issue due to contractual obligations of AES and financial covenant restrictions under existing debt obligations at IPL. Under such restrictions, IPL is generally allowed to fully draw the amounts available on its credit facility, refinance existing debt and issue new debt approved by the IURC and issue certain other indebtedness.

Credit Ratings

In August 2009, the corporate credit rating of IPL was upgraded by S&P from BB+ to BBB-, resulting in an investment grade rating. This upgrade led to a downgrade in IPL’s senior unsecured debt rating from BBB to BBB- as a result of S&P applying its criteria for investment grade ratings to IPL. Under this criterion the senior unsecured rating of an investment grade company typically cannot be higher than its corporate credit rating. Additionally in August 2009, Moody’s upgraded the credit rating of IPL’s senior secured debt from Baa1 to A3. This upgrade was due to a change in Moody’s methodology for notching the senior secured debt ratings of investment-grade regulated utilities. Moody’s notching practices widened as a result of their research which indicated that regulated utilities have defaulted at a lower rate and experienced lower loss given default rates than non-financial, non-utility corporate issuers. In March 2008, S&P raised its issue-level ratings on IPL’s senior unsecured debt from BB- to BBB.

We cannot predict whether the credit ratings of IPL will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. A security rating is not a recommendation to buy, sell or hold securities. The rating may be subject to revision or withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating.

Long-Term Debt

The following table presents our long-term indebtedness:


Series	Due	December 31,
Series	Due	2009		2008
		*(In Thousands)*
IPL First Mortgage Bonds (see below)
6.30%	July 2013	$	110,000	$	110,000
Variable⁽¹⁾	January 2016		-		41,850
4.90%⁽²⁾	January 2016		30,000		-
4.90%⁽²⁾	January 2016		41,850		-
4.90%⁽²⁾	January 2016		60,000		-
5.40%⁽¹⁾	August 2017		24,650		24,650
5.75%⁽¹⁾	August 2021		40,000		40,000
Variable⁽¹⁾	October 2023		-		30,000
4.55%⁽²⁾	December 2024		40,000		40,000
5.90%⁽¹⁾	December 2024		20,000		20,000
5.95%⁽¹⁾	December 2029		30,000		30,000
5.95%⁽²⁾	August 2030		17,350		17,350
6.60%	January 2034		100,000		100,000
6.05%	October 2036		158,800		158,800
6.60%	June 2037		165,000		165,000
Variable⁽²⁾	September 2041		-		60,000
Unamortized discount - net			(1,048)		(1,071)
Total IPL first mortgage bonds			836,602		836,579
IPL Unsecured Debt:
Variable⁽³⁾	May 2011		40,000		-
Variable⁽⁴⁾⁽⁵⁾	January 2023		40,000		40,000
6.375%⁽⁴⁾	November 2029		20,000		20,000
Total IPL unsecured notes			100,000		60,000

Total Consolidated Long-term Debt - IPL			936,602		896,579

⁽¹⁾First Mortgage Bonds are issued to the city of Petersburg, Indiana, to secure the loan of proceeds from various tax-exempt instruments issued by the city.
⁽²⁾First Mortgage Bonds are issued to the Indiana Finance Authority, to secure the loan of proceeds from the tax-exempt bonds issued by the Indiana Finance Authority.
⁽³⁾Outstanding draw on a credit facility in order to purchase the 1995B Bonds. See below.
⁽⁴⁾Notes are issued to the city of Petersburg, Indiana, by IPL to secure the loan of proceeds from various tax-exempt instruments issued by the city. ⁽⁵⁾Please see, “Variable-Rate Unsecured Debt” below for detail regarding 1995B Bonds and the related swap agreement.

IPL First Mortgage Bonds

Variable-Rate Unsecured Debt

Line of Credit

Debt Maturities

Maturities on long-term indebtedness subsequent to December 31, 2009, are as follows:


Year	Amount
	*(In Thousands)*
2010	$	-
2011		40,000
2012		-
2013		110,000
2014		-
Thereafter		787,650
Total	$	937,650

12. INCOME TAXES

IPL follows a policy of comprehensive interperiod income tax allocation. Investment tax credits related to utility property have been deferred and are being amortized over the estimated useful lives of the related property.

AES files federal and state income tax returns which consolidate IPALCO and IPL. Under a tax sharing agreement with IPALCO, IPL is responsible for the income taxes associated with its own taxable income and records the provision for income taxes as if IPL filed separate income tax returns. IPL is no longer subject to U.S. or state income tax examinations for tax years through March 27, 2001, but is open for all subsequent periods.

The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the year ended December 31, 2009, 2008 and 2007:


	2009		2008			2007
Unrecognized tax benefits at January 1	*(In Thousands)*
Gross increases - current period tax positions	$	7,756	$	21,582	$	22,753
Gross decreases - prior period tax positions		753		754		1,249
Settlements		(562)		(7,535)		(2,420)
Unrecognized tax benefits at December 31		-		(7,045)		-
	$	7,947	$	7,756	$	21,582

Tax-related interest expense and income is reported as part of the provision for federal and state income taxes. Penalties, if incurred, would also be recognized as a component of tax expense. As of December 31, 2009 and 2008, IPL has recorded a liability for interest of $0.7 million and $0.6 million, respectively. The income tax provision includes interest expense/(income) of $0.1 million, $(2.0) million, and $(0.6) million for the years ended December 31, 2009, 2008 and 2007, respectively.

Federal and state income taxes charged to income are as follows:


	2009		2008		2007
	*(In Thousands)*
Charged to utility operating expense
Current income taxes:
Federal	$	74,472	$	71,012	$	89,296
State		21,200		19,973		24,683
Total current income taxes		95,672		90,985		113,979
Deferred income taxes:
Federal		(17,794)		(8,428)		(5,636)
State		(1,884)		1,002		1,976
Total deferred income taxes		(19,678)		(7,426)		(3,660)
Net amortization of investment credit		(2,059)		(2,439)		(2,564)
Total charge to utility operating expenses		73,935		81,120		107,755
Charged to other income and deductions:
Current income taxes:
Federal		(34)		(875)		(803)
State		94		(48)		(30)
Total current income taxes		60		(923)		(833)
Deferred income taxes:
Federal		30		(118)		19
State		8		(31)		5
Total deferred income taxes		38		(149)		24
Net credit to other income and deductions		98		(1,072)		(809)
Total federal and state income tax provisions	$	74,033	$	80,048	$	106,946


	2009	2008	2007

Federal statutory tax rate	35.0%	35.0%	35.0%
State income tax, net of federal tax benefit	6.9	6.7	6.4
Amortization of investment tax credits	(1.1)	(1.2)	(1.0)
Depreciation flow through and amortization	1.2	1.6	1.3
Manufacturers’ Production Deduction (Sec. 199)	(2.0)	(1.8)	(1.7)
Change in tax reserves	0.1	(0.7)	0.0
Other - net	(0.5)	(0.2)	(0.6)
Effective tax rate	39.6%	39.4%	39.4%

The American Jobs Creation Act of 2004 created Internal Revenue Code Section 199 which, beginning in 2005, permits taxpayers to claim a deduction from taxable income attributable to certain domestic production activities. IPL’s electric production activities qualify for this deduction. The deduction was equal to 3% of qualifying production activity income for the 2005 and 2006 taxable years, with certain limitations. This deduction increased to 6% of qualifying production activity income beginning in 2007 and will increase to 9% of qualifying production activity income beginning in 2010 and thereafter. The tax benefit associated with the Internal Revenue Code Section 199 domestic production deduction for 2007 and 2008 was $4.5 million and $3.8 million, respectively. The benefit for 2009 is estimated to be $3.7 million.

The significant items comprising IPALCO’s net accumulated deferred tax liability recognized on the audited Consolidated Balance Sheets as of December 31, 2009 and 2008, are as follows:


	2009		2008
	*(In Thousands)*
Deferred tax liabilities:
Relating to utility property, net	$	505,591	$	517,076
Regulatory assets recoverable through future rates		154,269		180,746
Other		4,147		10,250
Total deferred tax liabilities		664,007		708,072
Deferred tax assets:
Investment tax credit		5,467		6,302
Regulatory liabilities including ARO		204,194		197,237
Employee benefit plans		79,815		100,961
Other		10,209		15,600
Total deferred tax assets		299,685		320,100
Accumulated net deferred tax liability		364,322		387,972
Less: Current portion of deferred tax liability		(10,233)		(9,220)
Accumulated deferred income taxes - net	$	374,555	$	397,192

13. PENSION AND OTHER POSTRETIREMENT BENEFITS


	Pension benefits as of December 31,				Other postretirement benefits as of December 31,
	2009		2008		2009		2008
	*(In Thousands)*
Change in benefit obligation:
Projected benefit obligation at beginning Measurement Date (see below)	$	527,741	$	482,253	$	13,083	$	10,151
Adjustment due to adoption of ASC 715: Service cost and interest cost during gap period		-		2,964		-		-
Service cost		6,319		5,249		681		1,115
Interest cost		32,066		30,292		470		645
Plan Settlements		(454)		(1,160)		-		-
Actuarial (gain) loss		11,629		29,094		(4,524)		1,929
Amendments (primarily increases in pension bands)		-		9,873		(4,264)		(162)
Benefits paid		(28,522)		(30,824)		(365)		(595)
Projected benefit obligation at ending Measurement Date		548,779		527,741		5,081		13,083
Change in plan assets:
Fair value of plan assets at beginning Measurement Date		305,508		403,619		-		-
Actual return on plan assets		70,804		(122,787)		-		-
Employer contributions		20,127		56,660		365		595
Plan Settlements		(454)		(1,160)		-		-
Benefits paid		(28,522)		(30,824)		(365)		(595)
Fair value of plan assets at ending Measurement Date		367,463		305,508				-
Funded status	$	(181,316)	$	(222,233)	$	(5,081)	$	(13,083)
Amounts recognized in the statement of financial position under ASC 715:
Current liabilities	$	-	$	-	$	(586)	$	(646)
Noncurrent liabilities		(181,316)		(222,233)		(4,495)		(12,437)
Net amount recognized	$	(181,316)	$	(222,233)	$	(5,081)	$	(13,083)
Sources of change in regulatory assets⁽¹⁾:
Prior service cost (credit) arising during period	$	-	$	9,873	$	(4,264)	$	(162)
Net loss (gain) arising during period		(35,024)		185,948		(4,524)		1,929
Amortization of prior service (cost) credit		(3,523)		(2,868)		339		56
Recognition of gain (loss) due to settlement		(256)		-		-		-
Amortization of gain (loss)		(16,279)		(1,912)		102		18
Total recognized in regulatory assets⁽¹⁾	$	(55,082)	$	191,041	$	(8,347)	$	1,841
Total amounts included in accumulated other comprehensive income (loss)		NA⁽¹⁾		NA⁽¹⁾		NA⁽¹⁾		NA⁽¹⁾
Amounts included in regulatory assets and liabilities⁽¹⁾
Net loss (gain)	$	197,945	$	249,505	$	(3,853)	$	569
Prior service cost (credit)		27,249		30,772		(4,104)		(179)
Total amounts included in regulatory assets (liabilities)	$	225,194	$	280,277	$	(7,957)	$	390

⁽¹⁾Represents amounts included in regulatory assets (liabilities) yet to be recognized as components of net prepaid (accrued) benefit costs.

Effect of ASC 715

ASC 715 requires a portion of pension and other postretirement liabilities to be classified as current liabilities to the extent the following year’s expected benefit payments are in excess of the fair value of plan assets. As each Pension Plan has assets with fair values in excess of the following year’s expected benefit payments, no amounts have been classified as current. Therefore, the entire net amount recognized in IPL’s Consolidated Balance Sheets of $181.3 million is classified as a long-term liability. As there are no plan assets related to the other postretirement plan, the current other postretirement liability is equal to the following year’s expected other postretirement benefit payment of $0.6 million, resulting in a long-term other postretirement liability of $4.5 million.

Information for Pension Plans with a benefit obligation in excess of plan assets

IPL’s total benefit obligation in excess of plan assets was $181.3 million as of December 31, 2009 ($180.3 million Defined Benefit Pension Plan and $1.0 million Supplemental Retirement Plan).


	Pension benefits as of December 31,
	2009		2008
	*(In Thousands)*
Benefit obligation	$	548,779	$	527,741
Plan assets		367,463		305,508
Benefit obligation in excess of plan assets	$	181,316	$	222,233

Information for Pension Plans with an accumulated benefit obligation in excess of plan assets


	Pension benefits as of December 31,
	2009		2008
	*(In Thousands)*
Accumulated benefit obligation	$	535,452	$	516,307
Plan assets		367,463		305,508
Accumulated benefit obligation in excess of plan assets	$	167,989	$	210,799

Pension Benefits and Expense

The following table presents the “gap period” adjustment that was booked to IPL’s January 1, 2008 beginning retained earnings. The information relates to the Pension Plans:


	*(In Thousands)*
Components of net periodic benefit cost:
Service cost	$	437
Interest cost		2,527
Expected return on plan assets		(2,624)
Amortization of actuarial loss		114
Amortization of prior service cost		239
Net periodic benefit cost	$	693


	Pension benefits for years ended December 31,
	2009		2008		2007
	*(In Thousands)*
Components of net periodic benefit cost:
Service cost	$	6,319	$	5,248	$	5,886
Interest cost		32,066		30,293		28,608
Plan Settlements		256		546		-
Expected return on plan assets		(24,150)		(31,443)		(30,811)
Amortization of prior service cost		3,523		2,868		2,747
Recognized actuarial loss		16,279		1,366		5,636
Total pension cost		34,293		8,878		12,066
Less: amounts capitalized		2,469		747		1,074
Amount charged to expense	$	31,824	$	8,131	$	10,992
Rates relevant to each year's expense calculation:
Discount rate - defined benefit pension plan		6.26%		6.49%		5.63%
Discount rate - supplemental retirement plan		6.31%/5.06% ⁽¹⁾		6.49%/6.355%/7.18%⁽²⁾		5.63%
Expected return on defined benefit pension plan assets		8.00%		7.75%		8.00%
Expected return on supplemental retirement plan assets		8.00%		7.75%		8.00%
⁽¹⁾ 6.31% for the period January 1, 2009 thru November 30, 2009, 5.06% for the settlement on November 30, 2009 and the period December 1, 2009 thru December 31, 2009. ⁽²⁾ 6.49% for the period January 1, 2008 thru January 31, 2008; 6.355% for the settlement on January 31, 2008 and the period February 1, 2008 thru July 31, 2008; and 7.18% for the settlement on July 31, 2008 and the period August 1, 2008 thru December 31, 2008.

Expected amortization

Pension Assets

Fair Value Measurements

Following is a description of the valuation methodologies used for assets and liabilities measured at fair value:

Other than Common/Collective Trusts and Hedge Funds, all Plan investments are actively traded on an open market and are categorized as Level 1 in the fair value hierarchy.



	Lower Limit		Target Allocation	Upper Limit	Return⁽²⁾	Risk⁽³⁾
U.S. Large Cap Equities		20.0%	30.0%	40.0%	10.4%	15.0%
U.S. Mid Cap Equities		2.5%	5.0%	7.5%	11.3%	16.8%
U.S. Small Cap Equities		2.5%	5.0%	7.5%	11.9%	19.5%
International Equities		0.0%	10.0%	20.0%	9.9%	17.4%
Fixed Income - Core		20.0%	30.0%	40.0%	5.7%	3.9%
High Yield		5.0%	10.0%	15.0%	8.0%	9.5%
Real Estate Investment Trusts⁽¹⁾		0.0%	5.0%	10.0%	9.4%	17.5%
Hedge Funds ⁽¹⁾		0.0%	5.0%	10.0%	11.7%	10.5%

⁽¹⁾Alternative investments (combined) not to exceed 10%
⁽²⁾ Expected long-term annual return
⁽³⁾ Expected standard deviation

The fair values of the pension plan assets at December 31, 2009, by asset category are as follows:


	Fair Value Measurements at December 31, 2009
	(In Thousands)

Asset Category	Total	(Level 1)	(Level 2)	(Level 3)	%

Cash and cash equivalents	15,697	15,697	-	-	4%

Equity securities:
U.S. small cap value	21,242	21,242	-	-	6%
U.S. small cap growth	178	178	-	-	-
U.S. small-mid cap growth	22,212	22,212	-	-	6%
U.S. mid cap core	276	276	-	-	-
U.S. large cap value ⁽¹⁾	32,634	18,183	14,451	-	9%
U.S. large cap growth⁽²⁾	35,323	18,410	16,913	-	10%
U.S. large cap core	55,217	55,217	-	-	15%
International developed markets ⁽³⁾	29,609	29,609	-	-	8%
International emerging markets	5,254	5,254	-	-	1%
Preferred Stock	271	271	-	-	-
REIT - domestic	8,213	8,213	-	-	2%

Fixed Income securities:
International developed markets	237	237	-	-	-
International emerging markets	62	62	-	-	-
Government debt securities ⁽⁴⁾	43,540	43,540	-	-	12%
High Yield	34,657	34,657	-	-	9%
Mortgage backed securities	9,817	9,817	-	-	3%
Asset backed securities	3,889	3,889	-	-	1%
Collateralized mortgage obligations	1,286	1,286	-	-	-
Corporate bonds ⁽⁵⁾	32,002	32,002	-	-	9%

Other types of investments:
Equity long/short fund of funds hedge fund ⁽⁶⁾	13,885	-	13,885	-	4%
Multi-strategy fund of funds hedge fund⁽⁷⁾	1,962	-	1,962	-	1%

TOTAL	367,463	320,252	47,211	-	100%

⁽¹⁾This category includes 44% of low-cost equity index funds that track the Russell 1000 Value index.
⁽²⁾This category includes 48% of low-cost equity index funds that track the Russell 1000 Value index.
⁽³⁾This category represents equity securities of developed non-U.S. issuers across diverse industries.
⁽⁴⁾This category includes U.S. Treasury and Government agency securities.
⁽⁵⁾This category represents investment grade bonds of U.S. issuers from diverse industries.
⁽⁶⁾This category includes fund of fund hedge funds that invest both long and short in primarily U.S. common stocks. Management of the hedge funds has the ability to shift investments from a net long position to a net short position.
⁽⁷⁾This category invests in multiple strategies to diversify risks and reduce volatility. The fund is currently in full liquidation.

Other Postretirement Benefits and Expense


	Other postretirement benefits for years ended December 31,
	2009		2008		2007
	*(In Thousands)*
Components of net periodic benefit cost:
Service cost	$	681	$	1,115	$	1,321
Interest cost		470		645		580
Amortization of prior service cost		(339)		(55)		6
Amortization of net gain (loss)		(102)		(18)		-
Total pension cost		710		1,687		1,907
Less: amounts capitalized		51		142		170
Amount charged to expense	$	659	$	1,545	$	1,737

Discount rate - Other postretirement benefit plan		5.79%/7.44% ⁽¹⁾		6.64%		5.81%
Expected return on Other postretirement benefit plan assets		NA		NA		NA
⁽¹⁾ 5.79% for the period January 1, 2009 through March 18, 2009, and 7.44% for the settlement on March 18, 2009 and the period March 19, 2009 through December 31, 2009.

Health Care Cost Trend Rates

Effect of Change in Health Care Cost Trend Rates


	2009		2008
	*(In Thousands)*
Effect on total service cost and interest cost components:
One-percentage point increase	$	237	$	465
One-percentage point decrease	$	(193)	$	(346)
Effect on year-end benefit obligation:
One-percentage point increase	$	609	$	3,084
One-percentage point decrease	$	(506)	$	(2,320)

The Medicare Prescription Drug, Improvement and Modernization Act of 2003

Expected amortization

Pension Funding

From a funding perspective, IPL’s funding target liability shortfall is estimated to be approximately $115 million as of January 1, 2010. The shortfall must be funded over seven years. In addition, IPL must also contribute the normal service cost earned by active participants during the plan year. The service cost is expected to be about $7 million in 2010. Then, each year thereafter, if the plan’s underfunding increases to more than the present value of the remaining annual installments, the excess is separately amortized over a new seven year period. IPL is required to fund approximately $28 million during 2010. However, IPL may decide to contribute more than $28 million to meet certain funding thresholds. IPL’s funding policy for the Pension Plans is to contribute annually no less than the minimum required by applicable law, nor more than the maximum amount that can be deducted for federal income tax purposes.


Year	Pension Benefits		Other Postretirement Benefits
	*(In Thousands)*
2010	$	31,004	$	586
2011		30,490		499
2012		31,467		405
2013		32,636		356
2014		34,020		341
2015 through 2019 (in total)		189,951		804

Voluntary Early Retirement Programs

Due to the plan changes effective January 1, 2010, an additional $38 thousand negative prior service cost base was created as of December 31, 2009. This amount is amortized over 13 years.

Defined Contribution Plans

All of IPL’s employees are covered by one of two defined contribution plans, the Thrift Plan or the RSP:

The Thrift Plan

Approximately 90% of IPL’s active employees are covered by the Thrift Plan. The Thrift Plan is a qualified defined contribution plan. All union new hires are covered under the Thrift Plan.

The AES Retirement Savings Plan

14. COMMITMENTS AND CONTINGENCIES

Legal

It is possible that material additional loss with regard to the asbestos lawsuits could be incurred. At this time, an estimate of additional loss cannot be made. IPL has settled a number of asbestos related lawsuits for amounts which, individually and in the aggregate, were not material to IPL’s results of operations, financial condition, or cash flows. Historically, settlements paid on IPL’s behalf have been comprised of proceeds from one or more insurers along with comparatively smaller contributions by IPL. We are unable to estimate the number of, the effect of, or losses or range of loss which are reasonably possible from the pending lawsuits or any additional asbestos suits. Furthermore, we are unable to estimate the portion of a settlement amount, if any, that may be paid from any insurance coverage for any known or unknown claims. Accordingly, there is no assurance that the pending or any additional suits will not have a material adverse effect on IPL’s results of operations, financial condition, or cash flows.

Please see Note 4, “Regulatory Matters - Voluntary Employee Beneficiary Association Trust Complaint” for a discussion of VEBA Trust related legal proceedings.

In addition, IPL is involved in litigation arising in the normal course of business. While the results of such litigation cannot be predicted with certainty, management believes that the final outcome will not have a material adverse effect on IPL’s results of operations, financial condition, or cash flows. Amounts accrued or expensed for legal or environmental contingencies collectively during the periods covered by this report have not been material to IPL’s audited Consolidated Financial Statements.

Environmental

We are subject to various federal, state and local environmental protection and health and safety laws and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of hazardous materials; the emission and discharge of hazardous and other materials into the environment; and the health and safety of our employees. These laws and regulations often require a lengthy and complex process of obtaining and renewing permits and other governmental authorizations from federal, state and local agencies. Violation of these laws, regulations or permits can result in substantial fines, other sanctions, and permit revocation and/or facility shutdowns. While we believe IPL operates in compliance with applicable environmental requirements, from time to time the company is subject to enforcement actions for claims of noncompliance. IPL cannot assure that it will be successful in defending against any claim of noncompliance. However, other than the Notice of Violation from the EPA (which remains to be resolved but could potentially result in fines or other required changes that could be material to our results of operations, financial condition, or cash flows), we do not believe any currently open investigations will result in fines material to our results of operations, financial condition, or cash flows.

New Source Review

Clean Air Interstate Rule

In March 2005 the EPA signed the federal CAIR, which imposes restrictions against polluting the air of downwind states. The federal CAIR established a two-phase regional “cap and trade” program for SO2 and NOx emissions that requires the largest reduction in air pollution in more than a decade. Federal CAIR covers 28 eastern states, including Indiana, and the District of Columbia.

Clean Air Mercury Rule

Clean Coal Technology Filings

In April 2008, in response to a petition we filed, the IURC issued an order approving recovery of capital expenditures of approximately $92.7 million over three years through our ECCRA filings. The $92.7 million approved by the IURC includes $90.0 million to install and/or upgrade CCT to further reduce SO2 and mercury emissions at our Petersburg generating station and $2.7 million for mercury emissions monitoring equipment at our coal-fired power plants. We currently estimate the installation and/or upgrade of CCT to further reduce SO2 and mercury emissions at our Petersburg generating station will cost approximately $119.9 million. We have received authorization for cost recovery for such amount by the IURC in a manner consistent with existing CCT projects.

15. RELATED PARTY TRANSACTIONS

IPL participates in a property insurance program in which IPL buys insurance from AES Global Insurance Company, a wholly-owned subsidiary of AES. IPL is not self-insured on property insurance with the exception of a $1 million self-insured retention per occurrence. Except for IPL’s large substations, IPL does not carry insurance on transmission and distribution assets, which are considered to be outside the scope of property insurance. AES and other AES subsidiaries, including IPL also participate in the AES global insurance program. IPL pays premiums for a policy that is written and administered by a third party insurance company. The premiums paid to this third party administrator by the participants are deposited into a trust fund owned by AES Global Insurance Company, but controlled by the third party administrator. This trust fund pays aggregate claims up to $25 million. Claims above the $25 million aggregate will be covered by separate insurance policies issued by a syndicate of third party carriers. These policies provide coverage of $600 million per occurrence. The cost to IPL of coverage under this program was approximately $3.9 million, $3.6 million, and $3.3 million in 2009, 2008, and 2007, respectively, and is recorded in Other operating expenses on the accompanying Consolidated Statements of Income. As of December 31, 2009 and 2008, we had prepaid approximately $1.7 million, which are recorded in Prepayments and other current assets on the accompanying Consolidated Balance Sheets.

AES files federal and state income tax returns which consolidate IPALCO and its subsidiaries, including IPL. Under a tax sharing agreement with IPALCO, IPL is responsible for the income taxes associated with its own taxable income and records the provision for income taxes using a separate return method. IPL had a receivable/(payable) balance under this agreement of $2.0 million and $(1.4) million as of December 31, 2009, and 2008, respectively.

Long-term Compensation Plan

During 2009 and 2008, many of IPL’s non-union employees received benefits under the AES Long-term Compensation Plan, a deferred compensation program. This type of plan is a common employee retention tool used in our industry. Benefits under this plan are granted in the form of performance units payable in cash, AES restricted stock units and options to purchase shares of AES common stock. All three of such components vest in thirds over a three year period and the terms of the AES restricted stock units also include a five year minimum holding period. In addition, the performance units payable in cash are subject to certain AES performance criteria. Total deferred compensation expense recorded during 2009 and 2008 was $1.4 million and $3.0 million, respectively and was included in Other Operating Expenses on IPL’s Consolidated Statements of Income. The value of these benefits is being recognized over the 36 month vesting period and a portion is recorded as miscellaneous deferred credits with the remainder recorded as paid in capital on IPL’s Consolidated Balance Sheets in accordance with ASC 718 “Compensation - Stock Compensation.”

See also “The AES Retirement Savings Plan” included in Note 13, “Pension and Other Postretirement Benefits” to the audited Consolidated Financial Statements of IPL for a description of benefits awarded to IPL employees by AES under the RSP.

16. SEGMENT INFORMATION

17. QUARTERLY RESULTS (UNAUDITED)

Operating results for the years ended December 31, 2009 and 2008, by quarter, are as follows:


	2009
	March 31		June 30		September 30		December 31
	*(In Thousands)*
Utility operating revenue	$	289,728	$	261,339	$	265,902	$	251,112
Utility operating income		48,750		35,673		46,456		39,078
Net income		34,040		22,181		32,665		24,225


	2008
	March 31		June 30		September 30		December 31
	*(In Thousands)*
Utility operating revenue	$	249,033	$	267,328	$	287,973	$	274,779
Utility operating income		36,491		42,926		54,620		47,856
Net income		22,262		28,573		41,149		31,097

The quarterly figures reflect seasonal and weather-related fluctuations that are normal to IPL’s operations.

************

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

On December 7, 2007, the Boards of Directors of IPALCO Enterprises, Inc. and Indianapolis Power & Light Company (collectively, the “Companies”) decided that following the completion of the audit for the fiscal year ending December 31, 2007, we would terminate the engagement of Deloitte & Touche LLP, as our independent registered public accounting firm. On April 18, 2008, upon completion of audit services related to Indianapolis Power & Light Company’s filing of Federal Energy Regulatory Commission Form No. 1, Deloitte completed its audit services for the Companies for the fiscal year ended December 31, 2007.

Deloitte’s audit reports dated March 24, 2008 on our consolidated financial statements as of and for the years ended December 31, 2007 and December 31, 2006 included in our Annual Report on Form 10-K for the year ended December 31, 2007 did not contain adverse opinions or disclaimers of opinion and were not qualified or modified as to uncertainty, audit scope, or accounting principles, except that the 2007 reports included explanatory paragraphs indicating (i) as discussed in Notes 3 and 11 to the consolidated financial statements, the Companies adopted Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes, on January 1, 2007 and (ii) as discussed in Note 13 to the consolidated financial statements, the Companies adopted the recognition and related disclosure provisions of Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106, and 132R, which changed the method of accounting for and the disclosures regarding pension and postretirement benefits.

During the years ended December 31, 2007 and December 31, 2006, and the subsequent interim period through April 18, 2008, there were no: (i) disagreements with Deloitte on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedures within the meaning of item 304(a)(1)(iv) of Regulation S-K, which, if not resolved to its satisfaction, would have caused Deloitte to make reference thereto in connection with its reports on our consolidated financial statements for such years, or (ii) reportable events (as defined in Regulation S-K Item 304 (a)(1)(v)).

We appointed Ernst & Young LLP as our independent registered public accounting firm for the consolidated financial statements for the fiscal year ending December 31, 2008. We had not consulted with Ernst & Young prior to their appointment as auditor regarding any matters described in Item 304(a)(2)(i) or Item 304(a)(2)(ii) of Regulation S-K.

ITEM 9A. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and communicated to the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures.

Evaluation of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, of the effectiveness of our “disclosure controls and procedures” (as defined in the Exchange Rules 13a-15(e) and 15-d-15 (e) as required by paragraph (b) of the Exchange Act Rules 13a-15 or 15d-15) as of December 31, 2009. Indianapolis Power & Light Company’s management, including the principal executive officer and principal financial officer, is engaged in a comprehensive effort to review, evaluate and improve our controls; however, management does not expect that our disclosure controls or our internal controls over financial reporting will prevent all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system’s objectives will be met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. In addition, any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or that the degree of compliance with the policies or procedures deteriorates. We have interests in certain unconsolidated entities. As we do not control or manage these entities, our disclosure controls and procedures with respect to such entities is generally more limited than those we maintain with respect to our consolidated subsidiaries.

Based upon the controls evaluation performed, the principal executive officer and principal financial officer have concluded that as of December 31, 2009, our disclosure controls and procedures were effective to provide reasonable assurance that material information relating to us and our consolidated subsidiaries is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures.

Management’s Report on Internal Control over Financial Reporting

Management for the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP and includes those policies and procedures that:

pertain to the maintenance of records that in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

Management, including our principal executive officer and principal financial officer, does not expect that our internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. In addition, any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or that the degree of compliance with the policies or procedures deteriorates.

Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2009. In making this assessment, management used the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations (COSO).

Management’s Conclusion on Internal Control over Financial Reporting

Management has concluded that, as of December 31, 2009, the Company maintained effective internal controls over financial reporting.

Changes in Internal Controls

In the course of our evaluation of disclosure controls and procedures, management considered certain internal control areas in which we have made and are continuing to make changes to improve and enhance controls. Based upon that evaluation, the principal executive officer and principal financial officer concluded that there were no changes in our internal controls over financial reporting identified in connection with the evaluation required by paragraph (d) of the Exchange Act Rules 13a-15 or 15d-15 that occurred during the quarter ended December 31, 2009 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit us to provide only management’s report in this annual report.

ITEM 9B. OTHER INFORMATION

Not applicable.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Not applicable pursuant to General Instruction I of the Form 10-K.

ITEM 11. EXECUTIVE COMPENSATION

Not applicable pursuant to General Instruction I of the Form 10-K.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Not applicable pursuant to General Instruction I of the Form 10-K.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Not applicable pursuant to General Instruction I of the Form 10-K.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The Financial Audit Committee of The AES Corporation pre-approved the audit and non-audit services provided by the independent auditors for 2009 and 2008 for itself and its subsidiaries, including IPALCO Enterprises, Inc. and its subsidiaries. The AES Financial Audit Committee maintained its policy established in 2002 within which to judge if the independent auditor may be eligible to provide certain services outside of its main role as outside auditor. Services within the established framework include audit and related services and certain tax services. Services outside of the framework require AES Financial Audit Committee approval prior to the performance of the service. The Sarbanes-Oxley Act of 2002 addresses auditor independence and this framework is consistent with the provisions of the Act. No services performed by the independent auditor with respect to IPALCO and its subsidiaries were approved after the fact by the AES Financial Audit Committee other than those that were considered to be de minimis and approved in accordance with Regulation 2-01 (c)(7)(i)(c) to Regulation S-X of the Exchange.

In addition to the pre-approval policies of the AES Financial Audit Committee, the IPALCO Board of Directors has established a pre-approval policy for audit, audit related, and certain tax and other non-audit services. The Board of Directors will specifically approve the annual audit services engagement letter, including terms and fees, with the independent auditor. Other audit, audit related and tax consultation services specifically identified in the pre-approval policy are pre-approved by the Board of Directors on an annual basis, subject to review of the policy at least annually. This pre-approval allows management to request the specified services on an as-needed basis during the year. Any such services are reviewed with the Board of Directors on a timely basis. Any audit or non-audit services that involve a service not listed on the pre-approval list must be specifically approved by the Board of Directors prior to commencement of such work. No services were approved after the fact by the IPALCO Board of Directors other than those that were considered to be de minimis and approved in accordance with Regulation 2-01 (c)(7)(i)(c) to Regulation S-X of the Exchange.

Audit fees are fees billed or expected to be billed by our principal accountant for professional services for the audit of IPALCO’s audited Consolidated Financial Statements, included in IPALCO’s annual report on Form 10-K and review of financial statements included in IPALCO’s quarterly reports on Form 10-Q, services that are normally provided by our principal accountants in connection with statutory, regulatory or other filings or engagements or any other service performed to comply with generally accepted auditing standards and include comfort and consent letters in connection with Securities and Exchange Commission filings and financing transactions.

The following table lists fees billed to IPALCO for products and services provided by our principal accountants:


	Years Ended December 31,
	2009		2008

Audit Fees	$	873,500	$	830,500
Audit Related Fees:
Fees for the audit of IPL’s employee benefit plans		61,222		60,300
Assurance services for debt offering documents		69,891		56,310
Total Principal Accounting Fees and Services	$	1,004,613	$	947,110

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

Index to the financial statements, supplementary data and financial statement schedules


Index to Financial Statements


IPALCO Enterprises, Inc. and Subsidiaries - Consolidated Financial Statements
	Report of Independent Registered Public Accounting Firm - 2009 and 2008
	Report of Independent Registered Public Accounting Firm - 2007
	Define Terms
	Consolidated Statements of Income for the years ended December 31, 2009, 2008 and 2007
	Consolidated Balance Sheets as of December 31, 2009 and 2008
	Consolidated Statements of Cash Flows for the year ended December 31, 2009, 2008 and 2007
	Consolidated Statements of Common Shareholder’s Deficit for the years ended December 31, 2009, 2008 and 2007
	Notes to Consolidated Financial Statements

Indianapolis Power & Light Company - Consolidated Financial Statements
	Report of Independent Registered Public Accounting Firm - 2009 and 2008
	Report of Independent Registered Public Accounting Firm - 2007
	Defined Terms
	Consolidated Statements of Income for the years ended December 31, 2009, 2008 and 2007
	Consolidated Balance Sheets as of December 31, 2009 and 2008
	Consolidated Statements of Cash Flows for the year ended December 31, 2009, 2008 and 2007
	Consolidated Statements of Common Shareholder’s Equity for the years ended December 31, 2009, 2008 and 2007
	Notes to Consolidated Financial Statements

Financial Statement Schedules
	Schedule I - Condensed Financial Information of Registrant
	Schedule II - Valuation and Qualifying Accounts and Reserves

(b) Exhibits


EXHIBIT NO.	DOCUMENT
3.1*	Articles of Incorporation
3.2	Amended and Restated By-Laws of IPALCO (Incorporated by reference to Exhibit No. 3.2 to IPALCO's 2007 Form 10-K)
4.1*	Indenture, dated as of November 14, 2001 between IPALCO and the Trustee
4.2*	Pledge Agreement dated as of November 14, 2001 between IPALCO and the Collateral Agent for the benefit of the Secured Parties
4.3*	Mortgage and Deed of Trust, dated as of May 1, 1940, between IPL and the Bank of new York Mellon Trust Company, NA as successor in interest to American National Bank & Trust Company of Chicago, Trustee
4.4	The following supplemental indentures to the Mortgage and Deed of Trust referenced in 4.3 above:
	Third Supplemental Indenture dated as of April 1, 1949 Tenth Supplemental Indenture dated as of October 1, 1960 Eighteenth Supplemental Indenture dated as of February 15, 1974 Thirty-Seventh Supplemental Indenture dated as of October 1, 1993 Forty-Second Supplemental Indenture dated as of October 1, 1995 Forty-Third Supplemental Indenture dated as of August 1, 2001 Forty-Fourth Supplemental Indenture dated as of August 1, 2001 Forty-Fifth Supplemental Indenture dated as of August 1, 2001 *Forty-Sixth Supplemental Indenture dated as of August 1, 2001 Forty-Seventh Supplemental Indenture dated as of August 1, 2003 (Incorporated by reference to Exhibit No. 10.1 to IPALCO’s June 30, 2003 Form 10-Q) Forty-Eighth Supplemental Indenture dated as of January 1, 2004 (Incorporated by reference to Exhibit No. 4.4 to IPALCO’s 2004 Form 10-K) Fifty-Second Supplemental Indenture dated as of September 1, 2006 (Incorporated by reference to Exhibit No. 4.2 to IPALCO’s September 30, 2006 Form 10-Q) Fifty-Third Supplemental Indenture dated as of October 1, 2006. (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s September 30, 2006 Form 10-Q) Fifty-Fourth Supplemental Indenture dated as of June 1, 2007 (Incorporated by reference to Exhibit No. 4.1 to IPALCO’s June 30, 2007 Form 10-Q) Fifty-Fifth Supplemental Indenture dated as of May 1, 2009 (Incorporated by reference to Exhibit No. 4.1 to IPALCO’s June 30, 2009 Form 10-Q) Fifty-Sixth Supplemental Indenture dated as of May 1, 2009 (Incorporated by reference to Exhibit No. 4.2 to IPALCO’s June 30, 2009 Form 10-Q) Fifty-Seventh Supplemental Indenture dated as of May 1, 2009 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s June 30, 2009 Form 10-Q)
4.5	Indenture between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, dated April 15, 2008 for the 7.25% Senior Secured Notes Due 2016. (Incorporated by reference to Exhibit No. 4.1 to IPALCO’s April 17, 2008 Form 8-K)
4.6	Indenture Supplement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, dated April 15, 2008, to the Indenture of Trust between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company dated November 14, 2001. (Incorporated by reference to Exhibit No. 4.1 to IPALCO’s April 17, 2008 Form 8-K)
4.7	Pledge Agreement Supplement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company, N.A., as successor Collateral Agent, dated April 15, 2008 to the Pledge Agreement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company dated November 14, 2001. (Incorporated by reference to Exhibit No. 4.1 to IPALCO’s April 17, 2008 Form 8-K)
10.1	Interconnection Agreement, dated April 1, 2008, between American Electric Power Service Corporation, as agent for Indiana Michigan Power Company, and IPL (Incorporated by reference to Exhibit No. 10.1 to IPALCO’s 2009 Form 10-K)
10.2*	Interconnection Agreement, dated December 2, 1969, between IPL and Southern Indiana Gas and Electric Company as modified through Modification Number 11
10.3*	Interconnection Agreement dated December 1, 1981, between IPL and Hoosier Energy Rural Electric Cooperative, Inc., as modified through Modification 6
10.4	Tenth supplemental agreement to interconnection agreement between IPL and PSI Energy, Inc., dated as of June 26, 2002, amending and completely restating prior agreements. (Incorporated by reference to Exhibit No. 10.2 to IPALCO’s September 30, 2002 Form 10-Q)
10.5*	IPALCO 1999 Stock Incentive Plan
10.6	Credit agreement by and among Indianapolis Power & Light Company, the various financial institutions party hereto, National City Bank of Indiana, as Syndication Agent, and LaSalle Bank National Association, as Administrative Agent, dated as of May 16, 2006. (Incorporated by reference to Exhibit 10.1 to IPALCO’s March 31, 2006 Form 10-Q)
31.1	Certification by Chief Executive Officer required by Rule 13a-14(a) or 15d-14(a).
31.2	Certification by Principal Financial Officer required by Rule 13a-14(a) or 15d-14(a).
32	Certification required by Rule 13a-14(b) or 15d-14(b).
99.1*	Receivables Purchase Agreement between IPL and IPL Funding Corporation dated December 20, 1996
99.2*	Subordination Agreement dated as of December 20, 1996, between IPL, IPL Funding Corporation and ABN AMRO Bank N.V., as the agent
99.3*	Revolving Subordinated Promissory Note between IPL Funding Corporation and IPL dated December 20, 1996
99.4	Remarketing Agreement between IPL and J.P. Morgan Securities, Inc. dated September 30, 1997 for the remarketing of the $40,000,000 City of Petersburg, Indiana, Pollution Control Refunding Revenue Bonds, Adjustable Rate Tender Securities (ARTS)^SM, Series 1995B (Incorporated by reference to Exhibit No. 99.6 to IPALCO’s 2007 Form 10-K)
99.5	Amendment of Remarketing Agreement dated as of July 10, 2008, by and between Indianapolis Power & Light Company and J.P. Morgan Securities, Inc. to amend the Remarketing Agreement between IPL and J.P. Morgan Securities, Inc. dated September 30, 1997 for the remarketing of the $40,000,000 City of Petersburg, Indiana, Pollution Control Refunding Revenue Bonds, Adjustable Rate Tender Securities (ARTS)^SM, Series 1995B. (Incorporated by reference to Exhibit No. 99.2 to IPALCO’s June 30, 2008 Form 10-Q)
99.6	First Amendment dated as of June 25, 2009 to Receivables Purchase Agreement dated as of December 20, 1996 (Incorporated by reference to Exhibit No. 99.1 to IPALCO’s June 30, 2009 Form 10-Q)
99.7	Second Amended and Restated Receivables Sale Agreement dated as of June 25, 2009 among IPL Funding Corporation, as the Seller, Indianapolis Power & Light Company, as the Collection Agent, The Royal Bank of Scotland PLC, as the Agent, The Liquidity Providers from time to time Party Hereto, and Windmill Funding Corporation (Incorporated by reference to Exhibit No. 99 to IPALCO’s September 30, 2009 Form 10-Q)
99.8	Amended and Restated Indemnity Agreement dated as of June 25, 2009 made by and between Indianapolis Power & Light Company and the Agent (Incorporated by reference to Exhibit No. 99.3 to IPALCO’s June 30, 2009 Form 10-Q)
* Incorporated by reference to IPALCO’s Registration Statement of Form S-4 filed with the Securities and Exchange Commission on April 3, 2002.

Schedules other than those listed below are omitted as the information is either not applicable, not required, or has been furnished in the financial statements or notes thereto included in Item 8 hereof.

SCHEDULE I - Condensed Financial Information of Registrant


IPALCO ENTERPRISES, INC.
SCHEDULE 1 - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
Unconsolidated Balance Sheets
As of December 31, 2009 and 2008
*(In Thousands)*

	2009		2008
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	4,010	$	2,866
Net income tax receivable		-		337
Short-term investments		-		-
Prepayments and other current assets		53		66
Total current assets		4,063		3,269

OTHER ASSETS:
Investment in subsidiaries		760,239		757,868
Other investments		2,531		2,260
Deferred financing costs		7,135		8,438
Total other assets		769,905		768,566
TOTAL	$	773,968	$	771,835

CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common shareholder’s deficit:
Paid in capital	$	9,820	$	8,624
Accumulated deficit		(18,878)		(18,533)
Total common shareholder’s deficit		(9,058)		(9,909)
Long-term debt		770,093		769,506
Total capitalization		761,035		759,597

CURRENT LIABILITIES:
Accounts payable and accrued expenses		200		210
Accrued income taxes		711		-
Accrued interest		11,384		11,384
Total current liabilities		12,295		11,594

DEFERRED CREDITS AND OTHER LONG-TERM LIABILITIES:		638		644
TOTAL	$	773,968	$	771,835

See notes to SCHEDULE I.


IPALCO ENTERPRISES, INC.
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
Unconsolidated Statements of Income
For the Years Ended December 31, 2009, 2008 and 2007
*(In Thousands)*

	2009		2008		2007

Equity in earnings of subsidiaries	$	108,873	$	119,920	$	162,111
Income tax benefit - net		25,481		31,801		26,065
Interest on long-term debt		(61,344)		(76,078)		(63,750)
Amortization of redemption premiums and expense on debt		(1,892)		(2,182)		(1,320)
Other - net		(563)		(2,009)		(990)
NET INCOME	$	70,555	$	71,452	$	122,116

See notes to SCHEDULE I.


IPALCO ENTERPRISES, INC.
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
Unconsolidated Statements of Cash Flows
For the Years Ended December 31, 2009, 2008 and 2007
*(In Thousands)*

	2009		2008		2007

CASH FLOWS FROM OPERATIONS:
Net income	$	70,555	$	71,452	$	122,116
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of subsidiaries		(108,873)		(119,903)		(162,087)
Cash dividends received from subsidiary companies		107,678		104,547		117,637
Amortization of debt issuance costs and discounts		1,892		2,182		1,239
Deferred income taxes - net		11		(305)		(88)
Tender fees expensed as interest		-		13,852		-
Change in certain assets and liabilities:
Income taxes receivable or payable		1,048		(589)		6,524
Accounts payable and accrued expenses		(9)		(212)		251
Accrued interest		-		3,238		-
Other - net		(258)		402		(4)
Net cash provided by operating activities		72,044		74,664		85,588

CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of short-term investments		-		(6,770)		(10,000)
Proceeds from sales and maturities of short-term investments		-		7,870		10,591
Investment in subsidiaries		-		-		-
Net cash used in investing activities		-		1,100		591

CASH FLOWS FROM FINANCING ACTIVITIES:
Long-term borrowing		-		394,105		-
Retirement of long-term debt		-		(388,852)		-
Dividends on common stock		(70,900)		(71,558)		(85,762)
Other - net		-		(7,071)		-
Net cash used in financing activities		(70,900)		(73,376)		(85,762)
Net change in cash and cash equivalents		1,144		2,388		417
Cash and cash equivalents at beginning of period		2,866		478		61
Cash and cash equivalents at end of period	$	4,010	$	2,866	$	478

See notes to SCHEDULE I.

IPALCO ENTERPRISES, INC.
Schedule I - Condensed Financial Information of Registrant
Notes to Schedule I

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Accounting for Subsidiaries and Affiliates - IPALCO Enterprises, Inc. has accounted for the earnings of its subsidiaries on the equity method in the unconsolidated condensed financial information.

2. INDEBTEDNESS

The following table presents IPALCO’s long-term indebtedness:


Series	Due	December 31,
Series	Due	2009		2008
		*(In Thousands)*
Long-term Debt
8.625% Senior Secured Notes	November 2011		375,000		375,000
7.250% Senior Secured Notes	April 2016		400,000		400,000
Unamortized discount - net			(4,907)		(5,494)
Net Long-term Debt		$	770,093	$	769,506

Long-term Debt

IPALCO’s Senior Secured Notes

In April 2008, IPALCO completed the sale of $400 million aggregate principal amount of 7.25% Senior Secured Notes due April 1, 2016 pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended. The 2016 IPALCO Notes were sold at 98.526% of par resulting in net proceeds of $394.1 million. The $5.9 million discount is being amortized through 2016 using the effective interest method. We used these net proceeds to repurchase or redeem all of the outstanding 2008 IPALCO Notes and to pay the early tender premium of $13.9 million (included in Interest on long-term debt in the accompanying Consolidated Statements of Income) and other fees and expenses related to the tender offer and the redemption of the 2008 IPALCO Notes and the issuance of the 2016 IPALCO Notes. The 2016 IPALCO Notes are secured by IPALCO’s pledge of all of the outstanding common stock of IPL. The lien on the pledged shares will be shared equally and ratably with IPALCO’s existing senior secured notes.

Debt Maturities

Maturities on indebtedness subsequent to December 31, 2009 are as follows:


Year	Amount
	*(In Thousands)*
2010	$	-
2011		375,000
2012		-
2013		-
2014		-
Thereafter		400,000
Total	$	775,000

SCHEDULE II - Valuation and Qualifying Accounts and Reserves


IPALCO ENTERPRISES, INC.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
For the Years Ended December 31, 2009, 2008 and 2007
*(In Thousands)*

Column A - Description	Column B - Balance at Beginning of Period		Column C - Additions				Column D - Deductions - Net Write-offs		Column E - Balance at End of Period
Column A - Description	Column B - Balance at Beginning of Period		Charged to Income		Charged to Other Accounts		Column D - Deductions - Net Write-offs		Column E - Balance at End of Period
Year ended December 31, 2009
Accumulated Provisions
Deducted from Assets - Doubtful Accounts	$	1,801	$	4,506	$	-	$	4,164	$	2,143

Year ended December 31, 2008
Accumulated Provisions
Deducted from Assets - Doubtful Accounts	$	1,882	$	4,227	$	-	$	4,308	$	1,801

Year ended December 31, 2007
Accumulated Provisions
Deducted from Assets - Doubtful Accounts	$	1,802	$	4,068	$	-	$	3,988	$	1,882


INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
For the Years Ended December 31, 2009, 2008 and 2007
*(In Thousands)*

Column A - Description	Column B - Balance at Beginning of Period		Column C - Additions				Column D - Deductions - Net Write-offs		Column E - Balance at End of Period
Column A - Description	Column B - Balance at Beginning of Period		Charged to Income		Charged to Other Accounts		Column D - Deductions - Net Write-offs		Column E - Balance at End of Period
Year ended December 31, 2009
Accumulated Provisions
Deducted from Assets - Doubtful Accounts	$	1,801	$	4,506	$	-	$	4,164	$	2,143

Year ended December 31, 2008
Accumulated Provisions
Deducted from Assets - Doubtful Accounts	$	1,882	$	4,227	$	-	$	4,308	$	1,801

Year ended December 31, 2007
Accumulated Provisions
Deducted from Assets - Doubtful Accounts	$	1,802	$	4,068	$	-	$	3,988	$	1,882

SIGNATURES

Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


			IPALCO ENTERPRISES, INC.
			(Registrant)

Date:	February 25, 2010	By:	/s/ Ann D. Murtlow
			Ann D. Murtlow
			President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.



Signature	Capacity	Date
/s/ Ann D. Murtlow
Ann D. Murtlow	President, Chief Executive Officer and Director of IPALCO (Principal Executive Officer)	February 25, 2010

/s/ Edward C. Hall III
Edward C. Hall III	Chairman of the Board of IPALCO and Executive Vice President, Regional President for North America of AES	February 25, 2010

/s/ Ronald E. Talbot
Ronald E. Talbot	Director of IPALCO and Senior Vice President, Power Supply of IPL	February 25, 2010

/s/ Kenneth J. Zagzebski
Kenneth J. Zagzebski	Director of IPALCO and Senior Vice President, Power Delivery of IPL	February 25, 2010

/s/ Richard Santoroski
Richard Santoroski	Director of IPALCO and Vice President, Global Risk & Commodity Organization of AES	February 25, 2010


Kenneth Uva	Director of IPALCO	February 25, 2010

/s/ Kirk B. Michael
Kirk B. Michael	Senior Vice President and Chief Financial Officer of IPALCO (Principal Financial Officer)	February 25, 2010
/s/ Kurt Tornquist
Kurt Tornquist	Vice President and Controller of IPALCO (Principal Accounting Officer)	February 25, 2010

Supplemental Information to be Furnished With Reports Filed Pursuant to Section 15 (d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act

No annual report or proxy material has been sent to security holders.

Attached files

IPALCO ENTERPRISES, INC. Reports

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