IPALCO Enterprises, Inc. 2012 Form 10-K

10-K 1 ye201210kcomplete.htm IPALCO 2012 FORM 10-K IPALCO Enterprises, Inc. 2012 Form 10-K

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, 2012

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 þ No o

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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 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 26, 2013, 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, 2012


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.	Mine Safety Disclosures

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 Annual 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 Securities Exchange Act of 1934, as amended (“Exchange Act”) including, in particular, the statements about our plans, strategies and prospects under the headings “Item 1. Business,” “Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities” and “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, expenses 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, or the negatives thereof, 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 customer growth and demand;
impacts of weather on retail sales and wholesale prices;
impacts of renewable energy generation, natural gas prices and other market factors on wholesale prices;
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 (“IURC”);
federal and state legislation and regulations;
changes in our credit ratings or the credit ratings of The AES Corporation ("AES");
fluctuations in the value of pension plan assets, fluctuations 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 laws and 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;
local economic conditions, including the fact that the local and regional economies have struggled through the recession and weak economic climate the past few years and continue to face uncertainty for the foreseeable future;
acts of terrorism, acts of war, pandemic events or natural disasters such as floods, earthquakes, tornadoes, ice storms, droughts or other catastrophic events;
costs and effects of legal and administrative proceedings, audits, settlements, investigations and claims and the ultimate disposition of litigation;
industry restructuring, deregulation and competition;
issues related to our participation in the Midwest Independent Transmission System Operator, Inc. (“MISO”), including the cost associated with membership and the recovery of costs incurred; and
product development and technology changes.

Most of these factors affect us through our consolidated subsidiary Indianapolis Power & Light Company (“IPL”). 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 as required by the 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. If one or more forward-looking statements are updated, no inference should be drawn that additional updates will be made with respect to those or other forward-looking statements.

PART I

Throughout this document, the terms “we,” “us,” and “our” refer to IPALCO Enterprises, Inc. (“IPALCO”) 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 IPL, 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 total electric revenues and net income for the fiscal year ended December 31, 2012 were $1.2 billion and $72.0 million, respectively. The book value of our total assets as of December 31, 2012 was $3.3 billion. All of our operations are conducted within the United States of America (“U.S.”) in the state of Indiana. Please see Note 15, “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 customers in the city of Indianapolis and neighboring areas within the state of Indiana; the most distant point being about 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 911,000. IPL owns and operates four generating stations. Two of the generating stations are primarily coal-fired. 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. IPL’s net electric generation capacity for winter is 3,492 megawatts (“MW”) and net summer capacity 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 2012.

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. Additionally, retail kilowatt hours (“kWh”) sales, after adjustments for weather variations, are impacted by changes in service territory economic activity as well as the number of retail customers we have. For the ten years ending in 2012, IPL’s retail kWh sales have decreased at a compound annual rate of 0.3%. Conversely, the number of our retail customers grew at a compound annual rate of 0.5% during that same period. Going forward, we expect this trend to continue as retail kWh sales growth is expected to be negatively impacted by our demand-side management programs. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Regulatory Matters - Demand-Side Management and IPL’s Smart Energy Project” for more details. IPL’s electricity sales for 2008 through 2012 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 (“RFC”). RFC is one of eight Regional Reliability Councils under the North American Electric Reliability Corporation (“NERC”), which has been designated as the Electric Reliability Organization under the Energy Policy Act of 2005 (“EPAct”). RFC seeks to preserve and enhance electric service reliability and security for the interconnected electric systems within the RFC geographic area by setting and enforcing electric reliability standards. 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. Smaller electric utility systems, independent power producers and power marketers can participate as full members of RFC. In addition, IPL is one of many transmission system owner members of MISO (see “MISO 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 MISO’s energy and operating reserves markets and each asset owner receives separate day-ahead, real-time, and financial transmission rights market settlement statements for each operating day.

REGULATORY MATTERS

Regulation

IPL is subject to regulation by the IURC with respect to the following: our services and facilities; retail rates and charges; the valuation of property; the construction, purchase, or lease of electric generating facilities; the classification of accounts; rates of depreciation; the issuance of securities (other than 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, IPL is subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”) with respect to, among other things, short-term borrowings 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 non-regulated entities. We maintain our books and records consistent with generally accepted accounting principles in the United States 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 (“EPA”), 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 NERC, 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

IPL’s 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 (see below). In addition, IPL’s 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 (“FAC”) and for the timely recovery of costs incurred to comply with environmental laws and regulations referred to as Environmental Compliance Cost Recovery Adjustment (“ECCRA”). Each of these tariff rate components may be set and approved by the IURC in separate proceedings at different points in time. For example, FAC proceedings occur on a quarterly basis and the ECCRA proceedings occur on a semi-annual basis. These components function somewhat independently of one another, but the overall structure of our rates and charges would be subject to review at the time of any review of our basic rates and charges.

Basic Rates and Charges

Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Regulatory Matters” for a discussion of our basic rates, charges and material adjustment mechanisms.

MISO OPERATIONS

IPL is one of many transmission system owner members in MISO. MISO is a regional transmission organization which maintains functional control over the combined transmission systems of its members and manages one of the largest energy and ancillary services markets in the U.S. MISO policies are developed, in part, 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 MISO and FERC policy by filing comments with MISO, the FERC or the IURC.

MISO has functional control of our transmission facilities and our transmission operations are integrated with those of MISO. 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 MISO’s tariff.

As a member of the MISO market, we offer our available electricity production of each of our generation assets into the MISO day-ahead and real-time markets. MISO dispatches generation assets in economic order considering transmission constraints and other reliability issues to meet the total demand in the MISO region. MISO settles 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 MISO region. MISO evaluates the market participants’ energy offers and demand bids optimizing for energy and ancillary services products to economically and reliably dispatch the entire MISO system. The IURC has authorized IPL to recover, through FAC proceedings, the fuel portion of its costs from MISO, including all specifically identifiable ancillary services market costs, and to defer certain operational, administrative and other costs from MISO and seek recovery in IPL’s next basic rate case proceeding. Total MISO costs deferred as long-term regulatory assets were $89.5 million and $80.4 million as of December 31, 2012 and December 31, 2011, respectively.

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

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, regional 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.

The section “Environmental Matters” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” describes environmental laws, potential changes in environmental laws and other risks that we believe may be significant to our business as well as a Notice of Violation (“NOV”) and Finding of Violation from the EPA pursuant to the Federal Clean Air Act (“CAA”) Section 113(a). The NOV may result in a fine and/or costs associated with the installation of additional pollution control technology systems and/or supplemental environmental projects, which could be material. The discussion in Item 7 also includes more detail on our plan to comply with EPA’s recently promulgated rule to establish maximum achievable control technology standards for each hazardous air pollutant regulated under the CAA emitted from coal and oil-fired electric utilities, known as the Mercury and Air Toxics Standards or “MATS”. It also contains an update on 2012 National Pollution Discharge Elimination System (“NPDES”) permitting activities, for which we are currently developing a compliance plan. We expect to incur material costs, both in capital expenditures and ongoing operating and maintenance costs, to comply with MATS and NPDES, and, to a lesser extent to which we cannot predict, other expected environmental regulations related to: coal combustion byproducts; cooling water intake; Polychlorinated Biphenyl-containing equipment; National Ambient Air Quality Standards; and wastewater effluent rules. We would expect to seek recovery of both capital and operating costs related to such compliance, although there can be no assurance that we would be successful.

ENERGY SUPPLY

Approximately 99% of the total kWhs we generated was from coal in each of 2012, 2011, and 2010. Natural gas and fuel oil provided the remaining kWh generation. Natural gas is used in our combustion turbines. Fuel oil is used for start-up and flame stabilization in coal-fired generating units, as primary fuel in oil-fired steam turbine generating units and three older combustion turbines, and as an alternate fuel in two combustion turbines. Additionally, we are committed under two separate power purchase agreements to purchase approximately 300 MW of wind generated electricity. We also expect to have up to 100 MW of solar generated electricity under contract in 2013, subject to approval by the IURC.

Our existing coal contracts provide for all of our current projected requirements in 2013 and approximately 74% for the three year period ending December 31, 2015. We have long-term coal contracts with six suppliers. Approximately 40% of our existing coal under contract comes from one supplier. We have entered into three long-term contracts with this supplier, which employs non-unionized labor, for the provision of coal from four separate mines. 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 we currently burn and under purchase contracts is mined by unaffiliated suppliers or third parties. Our goal is to carry a 25-50 day system supply of coal to offset unforeseen occurrences such as equipment breakdowns and transportation or mine delays.

EMPLOYEES

As of January 31, 2013, IPL had 1,485 employees of whom 1,391 were full time. Of the total employees, 921 were represented by the International Brotherhood of Electrical Workers (“IBEW”) in two bargaining units: a physical unit and a clerical-technical unit. In 2011, the membership of the IBEW clerical-technical unit ratified a three year labor agreement with us that expires on February 10, 2014. In December 2012, the IBEW physical unit ratified a three year agreement with us that expires on December 14, 2015. Both collective bargaining agreements shall continue in full force and effect from year to year unless either party provides prior written notice at least sixty (60) days prior to the expiration, or anniversary thereof, of its desire to amend or terminate the agreement. As of January 31, 2013, 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,
	2012		2011		2010		2009		2008
*Operating Revenues (In Thousands):*
Residential	$	466,294	$	438,204	$	427,899	$	392,181	$	390,892
Small commercial and industrial		183,681		174,934		170,345		160,814		165,660
Large commercial and industrial		510,669		482,223		455,458		436,060		435,578
Public lighting		10,872		10,910		10,857		11,093		10,973
Retail electric revenues		1,171,516		1,106,271		1,064,559		1,000,148		1,003,103
Wholesale		37,822		43,181		60,964		50,155		57,456
Miscellaneous		20,439		22,472		19,380		17,778		18,554
Total utility operating revenues	$	1,229,777	$	1,171,924	$	1,144,903	$	1,068,081	$	1,079,113

kWh *Sales (In Millions):*
Residential		5,144		5,266		5,501		5,085		5,350
Small commercial and industrial		1,862		1,887		1,957		1,892		2,030
Large commercial and industrial		6,945		7,012		7,086		7,041		7,550
Public lighting		64		64		65		68		73
Sales - retail customers		14,015		14,229		14,609		14,086		15,003
Wholesale		1,308		1,418		1,928		1,881		1,189
Total kWh sold		15,323		15,647		16,537		15,967		16,192

Retail Customers at End of Year:
Residential		419,867		417,153		416,276		416,500		416,019
Small commercial and industrial		47,108		46,974		46,844		46,708		46,719
Large commercial and industrial		4,645		4,630		4,628		4,625		4,610
Public lighting		957		954		948		940		905
Total retail customers		472,577		469,711		468,696		468,773		468,253

ITEM 1A. RISK FACTORS

Investors should consider carefully the following risk factors that could cause our business, operating results and financial condition 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. The risks and uncertainties described below are not the only ones we face.

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 for which we may or may not have adequate insurance coverage.

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

increased prices for fuel and fuel transportation as existing contracts expire or as such contracts are adjusted through price re-opener provisions or automatic adjustments;
unit or 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, cyber attacks, terrorist acts, acts of war, pandemic events, or natural disasters such as floods, earthquakes, tornadoes, ice storms, droughts, 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. If unexpected plant outages occur frequently and/or for extended periods of time, this could result in adverse regulatory action.

Additionally, as a result of the above risks and other potential hazards associated with the power generation industry, 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 also 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. In addition, transmission and distribution assets are not covered by insurance and are considered to be outside the scope of property insurance. 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 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 capacity. When our retail customer demand exceeds our generating capacity for units operating under MISO economic dispatch, recovery of our cost to purchase electric energy in the MISO 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 MISO 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 ongoing reliable performance of our transmission and distribution system is subject to risks due to, among other things, weather damage, intentional or unintentional damage, fires and/or explosions, 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 adverse 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 MISO, the NERC, the FERC or the IURC 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.

Approximately 99% of the total kWh we generated was from coal in each of 2012, 2011 and 2010. Our existing coal contracts provide for all of our current projected requirements in 2013 and approximately 74% for the three-year period ending December 31, 2015. Although we have long-term coal contracts with six suppliers, pricing provisions in some of our long-term coal contracts allow for price changes under certain circumstances. Accordingly, because of our substantial dependence on coal to meet customer demand for electricity, our business and operations could be materially adversely affected by continued price volatility in the coal market, price increases pursuant to the provisions of certain of our long-term coal contracts, and the continued regulatory and political scrutiny of coal. As discussed below, regulators, politicians, non-governmental organizations and other private parties have expressed concern about greenhouse gas (“GHG”) emissions and are taking actions which, in addition to the potential physical risk associated with climate change, could have a material adverse impact on our consolidated results of operations, financial condition and cash flows.

In addition, substantially all of our coal supply is currently mined in the state of Indiana and all coal currently burned by us and under purchase contracts is mined by unaffiliated suppliers or third parties. Our goal is to carry a 25-50 day system supply of coal to offset unforeseen occurrences such as equipment breakdowns and transportation or mine delays. Moreover, approximately 40% of our existing coal under contract comes from a single supplier. Any significant disruption in the ability of our suppliers to mine coal in Indiana or in the delivery of coal from our suppliers, or any failure on the part of our suppliers to fulfill their contractual obligations to deliver coal, particularly disruptions in the ability or failures on the part of our most significant supplier to deliver coal to us, could have a material adverse effect on our business. In the event of disruptions or failures, there can be no assurance that we would be able to purchase power or find another supplier of coal on similarly favorable terms, which could also limit our ability to recover fuel costs through the FAC proceedings.

Regulators, politicians, non-governmental organizations and other private parties have expressed concern about greenhouse gas (“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.

One byproduct of burning coal and other fossil fuels is the emission of GHGs, including carbon dioxide (“CO2”). At the federal, state and regional levels, policies are under development or have been developed to regulate GHG emissions, thereby effectively putting a cost on such emissions to create financial incentives to reduce them. In 2012, IPL emitted approximately 15 million tons of CO2 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 existing or future federal, state or regional legislation or regulation of GHG emissions 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.

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, would also 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 consolidated results of operations, financial condition and cash flows.

In addition to the rules already in effect, regulatory initiatives regarding GHG emissions 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, including those already promulgated, 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 us, including those relating to regulation of GHG emissions.

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, droughts, 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, which are areas of significant seismic activity in the central U.S.

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, adverse regulatory actions, deregulation, or new legislation could reduce revenues and/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 NERC 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 IURC, the Indiana Office of Utility Consumer Counselor and other interested stakeholders. 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 (“CCT”) facilities constructed to comply with environmental laws and regulations, recovery of costs associated with providing mandatory Demand Side Management (“DSM”) programs, 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. For example, the IURC denied IPL authority to recover retail electric sales margins lost as a result of offering mandatory DSM programs to retail customers. 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. 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 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.

Future events, including the advent of retail competition within IPL's service territory, could result in the deregulation of part of IPL's existing regulated business. Upon deregulation, adjustments to IPL's accounting records may be required to eliminate the historical impact of regulatory accounting. Such adjustments, as required by Financial Accounting Standards Board Accounting Standards Codification (“ASC”) 980 “Regulated Operations,” could eliminate the effects of any actions of regulators that have been recognized as assets and liabilities. Required adjustments could include the expensing of any unamortized net regulatory assets, the elimination of certain tax liabilities, and a write down of any impaired utility plant balances. We expect IPL to meet the criteria for the application of ASC 980 for the foreseeable future.

Our participation in MISO involves risks.

We are a member of MISO, a FERC approved regional transmission organization. MISO 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 MISO. We retain control over our distribution facilities. As a result of membership in MISO and its 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 MISO’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 MISO’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 MISO. These proceedings involve such issues as transmission rates, construction of new transmission facilities, the allocation of costs of transmission expansion due to the renewable mandates of other states, and the evolving tariff requirements for resource adequacy.

To the extent that we rely, at least in part, on the performance of MISO to maintain the reliability of our transmission system, it puts us at some risk for the performance of MISO. In addition, actions taken by MISO to secure the reliable operation of the entire transmission system operated by MISO 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 - MISO 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. 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 likely 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 dividends from IPL 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. 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 that require maintenance of a leverage ratio which could limit the ability of IPL 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 9, “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.

If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties, which likely would not be recoverable from customers through regulated rates.

As an owner and operator of a bulk power transmission system, IPL is subject to mandatory reliability standards promulgated by the NERC and enforced by the FERC. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and is guided by reliability and market interface principles. Compliance with reliability standards may subject us to higher operating costs or increased capital expenditures. Although we expect to recover costs and expenditures from customers through regulated rates, there can be no assurance that the IURC will approve full recovery in a timely manner. If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties, which likely would not be recoverable from customers through regulated rates and could have a material adverse effect on our results of operations, financial condition and cash flows.

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. It is possible that our ability to raise capital on favorable terms or at all could be adversely affected by future market conditions, 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 overall demand in the credit 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 credit counterparties and financial institutions with which we do business.

See Note 9, “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, 2012, we had on a consolidated basis $1.8 billion of indebtedness and total common shareholder’s deficit of $3.2 million. IPL had $965.3 million of First Mortgage Bonds outstanding as of December 31, 2012, 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 $50 million of secured indebtedness pursuant to a receivables sale facility. 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, 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, 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, credit market conditions, fluctuating consumer and business confidence, fluctuating commodity prices, and other challenges currently affecting the general economy, some of our customers have experienced 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. Furthermore, projects which may result in potential new customers may be delayed until economic conditions improve. In particular, the projected economic growth and total employment in Indianapolis are important to the realization of our forecasts for annual energy sales.

At times, we may utilize forward contracts to manage the risk associated with power purchases and wholesale power sales, and could be exposed to counterparty 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 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.

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 day-ahead 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, 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. We did not use such hedges in 2012 or 2011, and used them on a fairly limited basis in 2010 with no material impact to earnings. No such hedges are currently in place.

In addition, the introduction of additional renewable energy into the MISO market could have the effect of reducing the demand for wholesale energy from other sources. 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 coal fired and gas generation into the MISO market, thereby reducing our wholesale sales. Additionally, decreases in natural gas prices in the U.S. have the impact of reducing market prices for electricity, which can reduce our ability to sell excess generation on the wholesale market, as well as reduce our profit margin on 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 generation, 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 contractor failure resulted in a failure by IPL 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 could 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, regional 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, 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 the 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.

From time to time we are subject to enforcement actions for claims of noncompliance with environmental laws and regulations. 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 us.

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 74% of our current coal requirements for the three-year period ending December 31, 2015 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 highly volatile in both the 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 generally recover the energy portion of our purchased power costs in these quarterly FAC proceedings subject to a benchmark (as discussed in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Regulatory Matters”). 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 business, 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 59% of our employees are over the age of 50 and have an average of 24 years of experience), availability of qualified personnel, and collective bargaining agreements with employees who are members of a union. Approximately 63% of our employees are represented by the International Brotherhood of Electrical Workers in two bargaining units: a physical unit and a clerical-technical unit. 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 business, results of operations, financial condition, and cash flows.

Economic conditions relating to the asset performance and interest rates of the Employees’ Retirement Plan of IPL and Supplemental Retirement Plan of IPL (together, the “Pension Plans”) 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. We are subject to the Pension Protection Act of 2006, which 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. 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 11, “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 3, “Regulatory Matters” and Note 12, “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.

Information technology security vulnerabilities could have a material adverse impact to our reputation and/or our consolidated results of operations, financial condition and cash flows.

We require access to sensitive customer data in the ordinary course of business. If a significant breach of our information technology security system occurred, our reputation could be adversely affected, customer confidence could be diminished, customer information could be used for identity theft purposes, or we could be subject to costs associated with the breach. In the event of any such breach, we could be subject to fines and legal claims, which could affect our business, results of operations, financial condition, and cash flows.

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 aggregate principal amount of the City of Petersburg, Indiana, Pollution Control Refunding Revenue Bonds Adjustable Rate Tender Securities 1995B Series, 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
2018 IPALCO Notes	$400 million of 5.00% Senior Secured Notes due May 1, 2018
AES	The AES Corporation
ASC	Financial Accounting Standards Board Accounting Standards Codification
BACT	Best Achievable Control Technology
CAA	Federal Clean Air Act
CAIR	Clean Air Interstate Rule
CCB	Coal Combustion Byproducts
CCT	Clean Coal Technology
CO₂	Carbon Dioxide
CPCN	Certificate of Public Convenience and Necessity
Defined Benefit Pension Plan	Employees’ Retirement Plan of Indianapolis Power & Light Company
DSM	Demand Side Management
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
IBEW	International Brotherhood of Electrical Workers
IPALCO	IPALCO Enterprises, Inc.
IPL	Indianapolis Power & Light Company
IURC	Indiana Utility Regulatory Commission
kWh	Kilowatt hours
MATS	Mercury and Air Toxics Standards
MISO	Midwest Independent Transmission System Operator, Inc.
MW	Megawatts
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Corporation
NOV	Notice of Violation
NO_x	Nitrogen Oxides
NPDES	National Pollution Discharge Elimination System
Pension Plans	Employees’ Retirement Plan of Indianapolis Power & Light Company and Supplemental Retirement Plan of Indianapolis Power & Light Company
PSD	Prevention of Significant Deterioration
RFC	ReliabilityFirst Corporation
RSG	Revenue Sufficiency Guarantee
RSP	AES Retirement Savings Plan
SO₂	Sulfur Dioxides
Supplemental Retirement Plan	Supplemental Retirement Plan of Indianapolis Power & Light Company
Thrift Plan	Employees’ Thrift Plan of Indianapolis Power & Light Company
U.S.	United States of America

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 and 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 design capacity is 3,492 MW and net summer design capacity is 3,353 MW. Our highest summer peak level of 3,139 MW was recorded in August 2007 and the highest winter peak level 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 2012, at the Petersburg, Harding Street, Eagle Valley and Georgetown plants, accounted for approximately 69.9%, 27.4%, 2.2% and 0.5%, 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 458 circuit miles of 345,000 volt lines and 377 circuit miles of 138,000 volt lines. The distribution system consists of 4,756 circuit miles underground primary and secondary cables and 6,131 circuit miles of overhead primary and secondary wire. Underground street lighting facilities include 755 circuit miles of underground cable. Also included in the system are a total of 144 substations. Depending on the voltage levels at the substation, some substations may be considered both a bulk power substation and a distribution substation. The number of bulk power substations is 73, and the number of distribution substations is 123, reflecting the fact that 52 substations are considered both bulk power and distribution substations.

All critical facilities we own are well maintained, in good condition and meet our present needs (see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview - Market Developments” for further discussion of our “ready reserve” plan for the Eagle Valley generation plant). 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, or when MISO provides a lower cost alternative to some of our available generation, we purchase power on the MISO wholesale market.

Mortgage Financing on Properties

The First Mortgage secures first mortgage bonds issued by IPL. Pursuant to the terms of the First Mortgage, substantially all property owned by IPL is subject to a direct first mortgage lien securing indebtedness of $965.3 million at December 31, 2012. In addition, IPALCO has outstanding $800 million of Senior Secured Notes 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 3, “Regulatory Matters” and Note 12, “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. MINE SAFETY DISCLOSURES

Not applicable.

PART II

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

As of February 26, 2013, 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 2012, 2011 and 2010, we paid dividends to AES totaling $66.6 million, $59.2 million and $73.2 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 IPL 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 our senior long-term debt or be in compliance with leverage and interest coverage ratios contained in IPALCO’s Articles of Incorporation. 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 which 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,

2012 2011 2010 2009 2008

(In Thousands)

Operating Data:

Total utility operating revenues
$ 1,229,777 $ 1,171,924 $ 1,114,903 $ 1,068,081 $ 1,079,113

Utility operating income
162,900 152,653 172,438 169,957 181,893

Allowance for funds used during construction
2,146 6,624 6,427 3,632 2,292

Net income
71,996 60,575 79,947 73,768 74,665

Balance Sheet Data (end of period):

Utility plant - net
2,425,610 2,441,347 2,361,509 2,321,676 2,341,072

Total assets
3,285,347 3,271,652 3,137,980 3,035,345 3,102,411

Common shareholder’s deficit
(3,219) (5,846) (4,730) (9,058) (9,909)

Cumulative preferred stock of subsidiary
59,784 59,784 59,784 59,784 59,784

Long-term debt (less current maturities)
1,651,120 1,760,316 1,332,353 1,706,695 1,666,085

Long-term capital lease obligations
6 12 38 28 301

Other Data:

Utility capital expenditures
129,747 209,851 163,652 115,363 106,906

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, sustainability, reliability, customer service, and employee satisfaction) 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.”

Market Developments

We are one of many transmission system owner members in MISO. MISO is a regional transmission organization which maintains functional control over the combined transmission systems of its members and manages one of the largest energy and ancillary services markets in the U.S. IPL offers the available electricity production of each of its generation assets into the MISO day-ahead and real-time markets. MISO dispatches generation assets in economic order considering transmission constraints and other reliability issues to meet the total demand in the MISO region.

The increased interconnection of renewable energy to the MISO transmission system and participation of renewable energy resources in the MISO energy markets have decreased the economic dispatch of energy from coal resources. Additionally, the use of enhanced technologies to recover natural gas from shale deposits has increased natural gas supply and reserves, which has placed downward pressure on natural gas prices and, therefore, on wholesale power prices. The combination of these factors significantly reduced the clearing price of electricity in the MISO market in 2012 as compared to 2011. These factors, combined with the unusually mild winter in the MISO footprint in early 2012 and a weakened economy, resulted in clearing prices in the MISO market for much of the first half of 2012 at their lowest levels since the MISO energy market began in 2005. As a result, IPL’s coal-fired generation called upon by MISO to produce electricity during the 2012 winter and spring months was at its lowest levels since 2005. The hotter than normal summer temperatures in 2012 partially mitigated that trend, but wholesale sales volumes were still down from 2011, which was also hotter than normal during the summer.

The greatest impact of the depressed winter and spring MISO electricity prices was a reduction in the fuel portion of the retail rate to IPL’s customers, which did not impact net utility operating income due to the pass-through nature of fuel and purchased power cost under the FAC proceedings. There was also, however, a significant negative impact on our wholesale sales volumes, as well as our profit margin on wholesale sales. Accordingly, wholesale revenues are down $5.4 million or 12% in 2012 versus 2011, despite reductions in both planned and unplanned outage rates in 2012. The total impact to IPL is partially mitigated by the fact that wholesale revenues have typically represented less than 5% of total revenues in the years leading up to 2012.

In light of these circumstances, in March 2012, IPL management implemented a “ready reserve” plan for the Eagle Valley generation plant. This ready reserve plan means that IPL will do the work necessary to maintain the equipment at Eagle Valley and to be ready when the units are dispatched by MISO. In order to keep the plant prepared for intermittent use, we have retained a small team of people at Eagle Valley. The rest of IPL’s employees that were previously at Eagle Valley have mostly retired from IPL or have been positioned in other areas of IPL until the plant’s units are needed. The units at the Eagle Valley generation plant were dispatched by MISO at various times since implementation of the ready reserve plan and they performed successfully. As a result of the ready reserve plan, we estimate operating and maintenance costs for Eagle Valley in 2012 were approximately $8 million less than what we would have otherwise expected. Eagle Valley remains part of IPL’s operating and capacity plan and will continue to be, until it is no longer economical to maintain the facility and/or able to meet environmental regulations. The Eagle Valley units represent approximately 10% of IPL’s total generating capacity in each of the past three years, and approximately 2%, 7%, and 7% of actual electricity generated by IPL in 2012, 2011, and 2010, respectively.

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 impact is partially mitigated by our declining block rate structure, which 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 effect is generally more significant with high temperatures than with low temperatures as many of our customers use gas heat. To illustrate, during the first quarter of 2012, when our service territory experienced a 27% decrease in heating degree days as compared to the same period in 2011, we experienced an $11.7 million decrease in retail revenues due to a lower volume of kWh sales.

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, thereby causing power outages, which reduce revenues and increase repair costs. Storm related operating expenses (primarily repairs and maintenance) were $1.2 million, $1.6 million and $0.8 million in 2012, 2011 and 2010, respectively.

Our Ability to Sell Power in the Wholesale Market at a Profit

At times, we will purchase power in the wholesale markets, and at other times we will have electric generation available for sale in the wholesale market in competition with other utilities and power generators. Until recently, wholesale revenues generally represented approximately 5% of our total electric revenues. In 2011 and 2012, that percentage dropped to 3.7% and then 3.1%, respectively. A decline in wholesale prices can have a significant impact on earnings, because most of our nonfuel costs are fixed in the short term and lower wholesale prices can result in lower wholesale volumes sold.

Our ability to be dispatched in the MISO 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. See also, “Liquidity and Capital Resources - Regulatory Matters” for information about our participation in MISO that impacts both revenues and costs associated with our energy service to our utility customers. The price of wholesale power in the MISO market as well as our variable generating costs can be volatile and therefore our revenues from wholesale sales can fluctuate significantly from year to year. The weighted average price of wholesale MWhs we sold was $28.92, $30.45, and $31.62 in 2012, 2011 and 2010, respectively.

Local Economy

For several years now, the local economy has been suffering from an economic slowdown as evidenced by an elevated unemployment rate in Indianapolis, Indiana which approximates the national average. During 2012, 42% of our revenues came from large commercial and industrial customers. For the ten years ending 2012, our total retail kWh sales have decreased at a compound annual rate of 0.3%. In contrast, for the 10 years ending 2008, the compound annual rate was an increase of 1.2%. This decline over the past few years illustrates the impact of the economic recession, as well as the continued implementation of IPL’s energy efficiency program initiatives.

Operational Excellence

Our objective is to optimize IPL’s performance in the U.S. utility industry by focusing on seven key areas: safety, commitment to compliance, customer satisfaction, reliability (production and delivery), financial performance (retail rates and shareholder value), our people and community leadership. We set and measure these objectives carefully, balancing them in a way and to a degree necessary to ensure a sustainably 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 our people, commitment to compliance and community leadership are company-specific performance goals, they are not benchmarked.

Our safety performance as measured by our OSHA recordable incident, lost work day and severity rates regressed in 2012 and is worse than our goal of being within the top quartile in our industry. We are committed to excellence in safety performance and have implemented various programs in recent years to increase awareness and improve safety policies and practices. Among other things, these various programs are intended to bring a renewed emphasis on mitigating the hazards associated with high risk work activities commonly experienced in the industry.

Our customer satisfaction rating, as measured through the annual JD Power residential electric survey, is in the top quartile among our midwestern peer utilities, which we believe reflects our relatively low rates, strong reliability, corporate citizenship, and focus on excellence in customer service.

Our performance in production reliability was better than our target in 2012, with the exception of thermal discharge restrictions in the summer of 2012 attributed to unusually warm river temperatures. We experienced significant improvements in both our planned and unplanned outage rates associated with our generation plants in 2012 versus 2011. Our unplanned outage rate dropped 4.6 percentage points and the planned outage rate dropped 3.6 percentage points in 2012 versus 2011. The planned outage decrease in 2012 was primarily due to the timing of major generating unit overhauls. Two such outages were completed in 2011 at Petersburg (one that lasted 77 days on a 545 MW unit and another that lasted 86 days on a 232 MW unit), while none were performed in 2012. We believe the 2011 overhauls had a direct correlation to the improvement in unplanned outages. Another major generating unit overhaul is scheduled for 2013.

Most of our performance metrics in delivery reliability were better than our targets in 2012. IPL had the best performance in all delivery reliability metrics compared to the four Indiana investor-owned utilities as published in the most recent IURC reliability report. In addition, IPL ranked in or near the top decile in distribution reliability as reported in the 2011 Institute of Electrical and Electronics Engineers reliability benchmarking survey.

Short-Term and Long-Term Financial and Operating Strategies

Our financial management plan is closely integrated with our operating strategies. 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. This strategy also enabled us to refinance $542.4 million of long-term debt in 2011, all at significantly lower interest rates.

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, 2012 and year ended December 31, 2011

Utility Operating Revenues

Utility operating revenues increased in 2012 from the prior year by $57.9 million, which resulted from the following changes (dollars in thousands):

2012 2011 Change Percent Change

Utility Operating Revenue

Retail Revenues $ 1,171,516 $ 1,106,271 $ 65,245 5.9%

Wholesale Revenues 37,822 43,181 (5,359) (12.4)%

Miscellaneous Revenues 20,439 22,472 (2,033) (9.0)%

Total Utility Operating Revenues $ 1,229,777 $ 1,171,924 $ 57,853 4.9%

Heating Degree Days

Actual 4,399 4,912 (513) (10.4)%

30-year Average 5,548 5,519

Cooling Degree Days

Actual 1,534 1,482 52 3.5%

30-year Average 1,041 1,041

The increase in retail revenues of $65.2 million was primarily due to a 7.0% increase in the weighted average price per kWh sold ($72.6 million), partially offset by a 1.5% decrease in the volume of kWh sold ($12.4 million). The $72.6 million increase in the weighted average price of kWh sold was primarily due to increases in: fuel revenues of $41.5 million; environmental rate adjustment mechanism revenues of $12.3 million; DSM program rate adjustment mechanism revenues of $9.7 million; and favorable block rate variances of $9.3 million. The increase in fuel revenues is offset by increases in purchased power costs as described below. Likewise, the vast majority of the increases in environmental and DSM rate adjustment mechanism revenues are offset by increased operating expenses including depreciation and amortization. The favorable block rate variances of $9.3 million are mostly attributed to our declining block rate structure, which 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 $12.4 million decrease in the volume of electricity sold was primarily due to milder temperatures in our service territory during the winter of 2012 (demonstrated by the decrease in heating degree days, as shown in the table above).

The decrease in wholesale revenues of $5.4 million was primarily due to a 7.8% decrease in the quantity of kWh sold ($3.4 million) and a 5.0% decrease in the weighted average price per kWh sold ($2.0 million). These declines in the quantity and price of wholesale kWh sales are explained in the preceding section entitled “Market Developments.”

Utility Operating Expenses

The following table illustrates our primary operating expense changes from 2011 to 2012 (in millions):

2011 Operating Expenses $ 1,019.3

Increase in power purchased 31.1

Decrease in maintenance expenses (19.6)

Increase in depreciation and amortization costs 9.6

Increase in DSM program costs 8.6

Increase in fuel costs 6.3

Increase in pension expenses 4.7

Increase in income taxes - net 4.6

Other miscellaneous variances - individually immaterial 2.3

2012 Operating Expenses $ 1,066.9

The $31.1 million increase in purchased power costs was primarily due to a 48% increase in the volume of power purchased during the period ($35.4 million), partially offset by a 2% decrease in the market price of power purchased during the period ($4.3 million). A portion of the volume increase can be attributed to power purchased as part of a power purchase agreement for approximately 200 MW of wind generated electricity from a project in Minnesota, which began commercial operation in October 2011. Additionally, at times the MISO market provides a lower cost alternative to serve a portion of our jurisdictional customers’ electricity demand. For the reasons described in the preceding section entitled “Market Developments,” this situation occurred with greater frequency versus the comparable period.

Maintenance expenses decreased $19.6 million or 16% compared to 2011 primarily due to the timing of major generating unit overhauls. As described previously, two such overhauls occurred in 2011, while none took place in 2012. We expect maintenance expenses to increase in 2013 with another major generating unit overhaul scheduled. Another contributing factor for this decrease was the favorable impact resulting from the implementation of our “ready reserve” plan in 2012 for the Eagle Valley generation plant, which is described in the preceding section entitled “Market Developments.”

The increase in depreciation and amortization costs of $9.6 million was primarily due to additional utility plant assets placed in service, including the approximately $130 million Petersburg Unit 4 flue gas desulfurization enhancements project that was completed in the fourth quarter of 2011. Depreciation costs on this project are recoverable through customer rates.

The increase in DSM program costs of $8.6 million, which are included in “Other operating expenses” on our Consolidated Statements of Comprehensive Income, is attributed to the continued implementation of IPL’s energy efficiency program initiatives. The increase in DSM program costs is correlated to the increase in DSM program rate adjustment mechanism revenues as noted above.

The $6.3 million increase in fuel costs is primarily due to a $20.0 million or 8% increase in the price per ton of coal we consumed during the comparable periods and a $14.2 million increase in deferred fuel costs as the result of variances between estimated fuel and purchased power costs in our FAC and actual fuel and purchased power costs. These fuel cost increases were partially offset by a $24.1 million decrease in the quantity of fuel consumed, due primarily to a decrease in total electricity sales volume in the comparable periods and an increase in the volume of power purchased, as described above. We are generally permitted to recover underestimated fuel and purchased power costs to serve our retail customers in future rates through the FAC proceedings and, therefore, the costs are deferred when incurred and amortized into expense in the same period that our rates are adjusted to reflect these costs.

The $4.7 million increase in pension expenses, which is included in “Other operating expenses” on our Consolidated Statements of Comprehensive Income, is primarily due to a $6.2 million increase in the recognized actuarial loss (see Critical Accounting Policies - Pensions Costs for details). The $4.6 million increase in income taxes - net was primarily due to the tax effect of the increase in pretax net operating income, for the reasons previously described, offset by an increase in the manufacturer’s deduction of $1.0 million and a slight decrease in depreciation flow through taxes of $0.8 million.

Other Income and Deductions

Other income and deductions decreased $2.7 million, or 13%, in 2012 primarily due to a (i) $13.3 million gain on sale of our Oatsville coal reserve in 2011 (as discussed in Note 13, “Sale of Oatsville Coal Reserve” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K); (ii) a $6.0 million decrease in the income tax benefit, which was primarily due to the change in pretax nonoperating income during the comparable periods and a $1.2 million tax return true-up to the prior year accrual; and (iii) a $2.9 million decrease in the allowance for equity funds used during construction as a result of decreased construction activity. These decreases were partially offset by a $15.4 million loss on early extinguishment of debt in May of 2011 related to the repurchase of $375 million of 8.625% (original coupon 7.625%) Senior Secured Notes due November 14, 2011 (“2011 IPALCO Notes”), including a $14.4 million early tender premium; (ii) additional contingent loss accruals of $2.2 million in 2011; and (iii) impairment of $1.6 million recorded on a minority ownership investment in 2011.

Interest and Other Charges

Interest and other charges decreased $3.9 million, or 3%, during 2012 primarily due to lower interest on long-term debt of $5.8 million as a result of various debt refinancing activities in 2011, including the refinancing in May of 2011 of $375 million of 8.625% 2011 IPALCO Notes with $400 million of 5.00% Senior Secured Notes due May 1, 2018. This decrease was partially offset by a $1.6 million decrease in the allowance for borrowed funds used during construction as a result of decreased construction activity.

Comparison of year ended December 31, 2011 and year ended December 31, 2010

Utility Operating Revenues

Utility operating revenues increased in 2011 from the prior year by $27.0 million, which resulted from the following changes (dollars in thousands):

2011 2010 Change Percent Change

Utility Operating Revenue

Retail Revenues $ 1,106,271 $ 1,064,559 $ 41,712 3.9%

Wholesale Revenues 43,181 60,964 (17,783) (29.2)%

Miscellaneous Revenues 22,472 19,380 3,092 16.0%

Total Utility Operating Revenues $ 1,171,924 $ 1,144,903 $ 27,021 2.4%

Heating Degree Days

Actual 4,912 5,267 (355) (6.7)%

30-year Average 5,519 5,519

Cooling Degree Days

Actual 1,482 1,619 (137) (8.5)%

30-year Average 1,041 1,041

The increase in retail revenues of $41.7 million was due to a 7.2% increase in the weighted average price per kWh sold ($69.1 million), partially offset by a 2.6% decrease in the volume of kWh sold ($22.4 million) and a nonrecurring charge against retail revenues related to prior periods ($5.0 million). The $69.1 million increase in the weighted average price of kWh sold was primarily due to a $56.8 million increase in fuel revenues. The increase in fuel revenues is offset by increases in fuel and purchased power costs as described below. We believe the $22.4 million decrease in the volume of electricity sold was primarily due to milder temperatures in our service territory in 2011 (as demonstrated by the decreases in cooling degree days and heating degree days, as shown above), as well as local economic conditions.

The decrease in wholesale revenues of $17.8 million was primarily due to a 26.4% decrease in the quantity of kWh sold ($16.1 million), which was primarily due to an increase in unscheduled outages and major generating unit overhauls. The decline in the quantity of wholesale kWh sales was also impacted by the ability of our generation to be dispatched by MISO at wholesale prices that are above our variable costs. Our ability to be dispatched in the MISO market is primarily impacted by the locational market price of electricity and variable generation costs. 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 2010 to 2011 (in millions):

2010 Operating Expenses $ 972.5

Increase in power purchased 34.7

Increase in fuel costs 11.8

Increase in salaries, wages and benefits 6.9

Increase in contract services 4.4

Decrease in income taxes - net (13.3)

Other miscellaneous variances - individually immaterial 2.3

2011 Operating Expenses $ 1,019.3

The $34.7 million increase in purchased power costs was primarily due to a 111% increase in the volume of power purchased during the period ($40.4 million), primarily due to an increase in unscheduled outages and major generating unit overhauls. This increase was partially offset by a 5% decrease in the market price of power purchased during the period ($5.4 million). 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 $11.8 million increase in fuel costs is primarily due to (i) a 13% increase in the price per ton of coal we consumed during the comparable periods ($36.2 million); (ii) increases in the price of oil and gas consumed ($3.2 million); and (iii) a $2.4 million increase in deferred fuel costs as the result of variances between estimated fuel and purchased power costs in our FAC and actual fuel and purchased power costs. These increases were partially offset by a $30.0 million decrease in the quantity of fuel consumed due primarily to a decrease in total electricity sales volume in the comparable periods. We are generally permitted to recover underestimated fuel and purchased power costs to serve our retail customers in future rates through the FAC proceedings and, therefore, the costs are deferred when incurred and amortized into expense in the same period that our rates are adjusted to reflect these costs. (See also “Liquidity and Capital Resources - Regulatory Matters - Fuel Adjustment Charge and Authorized Annual Jurisdictional Net Operating Income.”)

The $6.9 million increase in salaries, wages and benefits is primarily due to overtime for generating unit outages. The $4.4 million increase in contract services is primarily due to an increase of $3.7 million in expenses on DSM programs versus the comparable period. These DSM program expenses are recoverable through retail rates resulting in the program expenses being offset by an increase in retail revenues through the DSM program recovery mechanism. Losses resulting from reduced sales attributable to the DSM programs are not recovered in retail rates.

The $13.3 million decrease in income taxes - net was primarily due to a decrease in pretax net operating income for the reasons previously described and, to a lesser extent, the benefit recorded related to the gradual decreases in enacted Indiana tax rates from 8.5% to 6.5% beginning July 1, 2012 through July 1, 2015 which are not probable to cause a reduction in future base customer rates.

Other Income and Deductions

Other income and deductions decreased $5.1 million, or 20%, in 2011 primarily due to a $15.4 million loss on early extinguishment of debt in 2011 related to the repurchase of the 2011 IPALCO Notes, including a $14.4 million early tender premium, and additional contingent loss accruals of $2.2 million in 2011. These decreases were partially offset by a $13.3 million gain on sale of our Oatsville coal reserve in 2011 (as discussed in Note 13, “Sale of Oatsville Coal Reserve” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K).

Interest and Other Charges

Interest and other charges decreased $5.5 million, or 5%, during 2011 primarily due to lower interest on long-term debt due to the refinancing in May of 2011 of $375 million of 8.625% 2011 IPALCO Notes with $400 million of 5.00% Senior Secured Notes due May 1, 2018 (“2018 IPALCO Notes”) and, to a lesser degree, the pay-down of $167.4 million of other interest-bearing IPL debt in 2011 with proceeds from long-term debt issuances at significantly lower interest rates, and the termination of a $40 million interest rate swap by IPL in November 2011 (as discussed in Note 9, “Indebtedness” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K).

LIQUIDITY AND CAPITAL RESOURCES

Overview

As of December 31, 2012, we had unrestricted cash and cash equivalents of $18.5 million and available borrowing capacity of $246.9 million under our $250.0 million committed revolving credit facilities after outstanding borrowings and existing letters of credit. 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 28, 2014. As of December 31, 2012, we also have remaining authority from the IURC to, among other things, issue up to $135 million in aggregate principal amount of long-term debt and refinance up to $110 million in existing indebtedness through December 31, 2013, and to have up to $250 million of long-term credit agreements and liquidity facilities outstanding at any one time. 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, cash generated from operating activities and borrowing capacity on our committed credit facilities will be adequate for the foreseeable future to meet anticipated operating expenses, interest expense on outstanding indebtedness, recurring capital expenditures and to pay dividends 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 facilities; and (iv) additional debt financing. In addition, due to current and future environmental regulations, it is likely that equity capital may also be used as a funding source.

Historical Cash Flow Analysis

Our principal sources of funds in 2012 were net cash provided by operating activities of $214.8 million. Net cash provided by operating activities is net of cash paid for interest of $103.3 million and pension funding of $48.3 million. Net cash provided by operating activities in 2012 was $31.7 million higher than in 2011 primarily due to lower repairs and maintenance costs in 2012 and a $12.6 million swap termination payment made in 2011. The principal uses of funds in 2012 included capital expenditures of $129.7 million, dividends to AES of $66.6 million and the payoff in 2012 of $14 million on the revolving credit facility.

Our principal sources of funds in 2011 were net cash provided by operating activities of $183.1 million and net borrowings of $89.4 million. Net cash provided by operating activities is net of cash paid for interest of $108.5 million and pension funding of $37.3 million. Net cash provided by operating activities in 2011 was $37.4 million less than in 2010 primarily due to lower earnings, a $12.6 million interest rate swap termination payment and other net changes in working capital. The principal uses of funds in 2011 included capital expenditures of $209.9 million, dividends to AES of $59.2 million and asset removal costs of $14.9 million.

Our principal source of funds in 2010 was net cash provided by operating activities of $220.5 million. Net cash provided by operating activities is net of cash paid for interest of $113.5 million and pension funding of $28.7 million. Net cash provided by operating activities in 2010 was $21.2 million less than in 2009 primarily due to changes in our accounts receivable portfolio and an $8.6 million increase in pension funding. The principal uses of funds in 2010 included capital expenditures of $163.7 million and dividends to AES of $73.2 million.

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 replace aging equipment or improve overall performance. Our capital expenditures totaled $129.7 million, $209.9 million, and $163.7 million in 2012, 2011 and 2010, respectively, and were financed with internally generated cash provided by operations, borrowings on our credit facility, long-term borrowings and federal grants for IPL’s Smart Energy Projects.

Our capital expenditure program, including development and permitting costs, for the three year period from 2013 to 2015 is currently estimated to cost approximately $427 million (excluding environmental compliance costs). It includes approximately $256 million for additions, improvements and extensions to transmission and distribution lines, substations, power factor and voltage regulating equipment, distribution transformers, street lighting facilities and Smart Energy Projects. The capital expenditure program also includes approximately $149 million for power plant related projects and $22 million for other miscellaneous equipment.

In addition to the amounts listed above, IPL plans to spend an additional $511 million through 2016, excluding demolition costs, to comply with the MATS rule. Of this amount, $456 million is projected to be spent in the three year period from 2013 to 2015. These amounts do not include any costs for environmental compliance other than for compliance with MATS. Please see “Environmental Matters - MATS” for more details.

Contractual Cash Obligations

Our non-contingent contractual obligations as of December 31, 2012 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
$ 1,765.3 $ 110.0 $ - $ 556.5 $ 1,098.8

Interest obligations⁽¹⁾
1,113.0 100.1 192.4 128.2 692.3

Purchase obligations⁽²⁾:

Coal, gas, purchased power and related transportation
2,080.7 330.6 475.5 184.7 1,089.9

Other
32.1 7.9 13.7 10.5 -

Pension Funding⁽³⁾
49.6 49.6 - - -

Total⁽⁴⁾
$ 5,040.7 $ 598.2 $ 681.6 $ 879.9 $ 2,881.0

⁽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, 2012.

⁽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 include contractual commitments that can be terminated by us without penalty on notice of 90 days or less. An EPC contract for the installation of environmental controls on IPL’s coal-fired units was executed January 3, 2013 and payable over the next 4 years in connection with the MATS-related construction project described herein. The related cash outlays are not included in the table because the contract was executed after December 31, 2012.

⁽³⁾IPL elected to fund $49.6 million during January 2013. However, IPL may decide to contribute more than $49.6 million to meet certain funding thresholds. For years 2014 and thereafter, our contractual obligation for pension funding can fluctuate due to various factors. Please see “Pension Funding” below and Note 11, “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 $6.1 million (tax and related interest) as of December 31, 2012 because 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.

Dividend Distributions

All of IPALCO’s outstanding common stock is held by AES. During 2012, 2011 and 2010, we paid $66.6 million, $59.2 million, and $73.2 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.

IRS Regulations

In December 2011, the Internal Revenue Service published regulations (T.D. 9564) under Internal Revenue Code Section 263(a) on the deduction and capitalization of expenditures related to tangible property. These regulations are applicable to taxable years beginning on or after January 1, 2014 (as amended, IRS Announcement 2013-7). We are evaluating the application of these tax provisions which may significantly change the timing of future income tax payments.

Pension Plans

We contributed $48.3 million, $37.3 million, and $28.7 million to the Pension Plans in 2012, 2011, and 2010, respectively. Funding for the qualified Employees’ Retirement Plan of Indianapolis Power & Light Company (“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 the 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 be returned to us during 2013.

From an ERISA funding perspective, IPL’s funding target liability shortfall was estimated to be approximately $104 million as of January 1, 2013. 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 ERISA funding normal cost is expected to be about $8.1 million in 2013, which includes $3.1 million for plan expenses. 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 elected to fund $49.6 million in January, 2013, which satisfies all funding requirements for the calendar year 2013. The $49.6 million contribution includes the $8.1 million referenced above. IPL’s funding policy for the Pension Plans is to contribute annually no less than the minimum required by applicable law, and no 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, 2012, 2011 and 2010 were $30.3 million, $29.9 million, and $29.7 million, respectively.

See also “Critical Accounting Policies - Pension Costs” and Note 11, “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 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 $400 million of 7.25% Senior Secured Notes due April 1, 2016 (“2016 IPALCO Notes”) or the 2018 IPALCO Notes, however, all of IPL’s common stock is pledged to secure these notes. Accordingly, IPALCO’s ability to make payments on the 2016 IPALCO Notes and the 2018 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 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 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.

Indebtedness

Line of Credit

In December 2010, IPL entered into a $250 million unsecured revolving credit agreement, as discussed in Note 9, “Indebtedness - Line of Credit” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data.” This credit agreement originally included two facilities: (i) a $209.4 million committed line of credit for letters of credit, working capital and general corporate purposes and (ii) a $40.6 million liquidity facility, which was dedicated for the sole purpose of providing liquidity for certain variable rate unsecured debt issued on behalf of IPL. As a result of the November 2011 IPL financing activity described below, the credit agreement was amended in February 2012 to eliminate the $40.6 million liquidity facility and to increase the committed line of credit for letters of credit, working capital and general corporate purposes by the same amount resulting in one facility in the amount of $250 million.

IPALCO’s Senior Secured Notes

In May 2011, IPALCO completed the sale of the 2018 IPALCO Notes pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended. The 2018 IPALCO Notes were issued pursuant to an Indenture dated May 18, 2011, by and between IPALCO and The Bank of New York Mellon Trust Company, N.A., as trustee. These notes were subsequently exchanged for new notes with identical terms and like principal amounts, which were registered with the Securities and Exchange Commission pursuant to a registration statement on Form S-4 made effective in November 2011. In connection with this issuance, IPALCO conducted a tender offer to repurchase for cash any and all of IPALCO’s then outstanding 2011 IPALCO Notes. As a result, IPALCO no longer has indebtedness with an interest rate that changes due to changes in its credit ratings. Additionally, IPALCO no longer has any debt with financial ratio maintenance covenants; although its articles of incorporation continue to contain the same financial ratios restricting dividend payments and intercompany loans to AES as were included in the 2011 IPALCO Notes.

The 2018 IPALCO Notes were priced to the public at 99.927% of par. Net proceeds to IPALCO were $394.7 million after deducting underwriting costs and the discount. These costs and other related financing costs are being amortized through 2018 using the effective interest method. We used the net proceeds to repurchase all of the outstanding 2011 IPALCO Notes through the tender offer and to subsequently redeem all of the remaining 2011 IPALCO Notes not tendered in the second quarter of 2011. A portion of the proceeds was also used to pay the early tender premium of $14.4 million and other fees and expenses related to the tender offer and the redemption of the 2011 IPALCO Notes, as well as other fees and expenses related to the issuance of the 2018 IPALCO Notes. The total loss on early extinguishment of debt of $15.4 million was included as a separate line item within Other Income and (Deductions) in the accompanying audited Consolidated Statements of Comprehensive Income.

The 2018 IPALCO Notes are secured by IPALCO’s pledge of all of the outstanding common stock of IPL. The lien on the pledged shares is 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 May 18, 2011 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.

IPL First Mortgage Bonds and Recent Indiana Finance Authority Bond Issuances

In September 2011, the Indiana Finance Authority issued on behalf of IPL an aggregate principal amount of $55.0 million of 3.875% Environmental Facilities Revenue Bonds Series 2011A (Indianapolis Power & Light Company Project) due August 2021 and an aggregate principal amount of $40.0 million of 3.875% Environmental Facilities Refunding Revenue Bonds Series 2011B (Indianapolis Power & Light Company Project) due August 2021. IPL issued $95.0 million aggregate principal amount of first mortgage bonds to the Indiana Finance Authority at 3.875% to secure the loan of proceeds from these two series of bonds issued by the Indiana Finance Authority. Proceeds of these bonds were used to retire $40.0 million of existing 5.75% IPL first mortgage bonds, and for the construction, installation and equipping of pollution control facilities, solid waste disposal facilities and industrial development projects at IPL’s Petersburg generating station.

In November 2011, IPL issued $140 million aggregate principal amount of 4.875% first mortgage bonds due November 2041. Net proceeds from this offering were approximately $138.2 million, after deducting the initial purchasers’ discount and fees and expenses for the offering payable by IPL. The net proceeds from the offering were used to finance the redemption of the following outstanding indebtedness, including redemption premiums of $1.6 million and to pay related fees and expenses:

$40.0 million aggregate principal amount of the City of Petersburg, Indiana Pollution Control Refunding Revenue Bonds Adjustable Rate Tender Securities, 1995B Series, Indianapolis Power & Light Company Project (“1995B Bonds”), variable rate, due 2023;
$20.0 million aggregate principal amount of the City of Petersburg, Indiana Solid Waste Disposal Revenue Bonds, 1994A Series, Indianapolis Power & Light Company Project, 5.90% Series, due 2024;
$30.0 million aggregate principal amount of the City of Petersburg, Indiana Solid Waste Disposal Revenue Bonds, 1995C Series, Indianapolis Power & Light Company Project, 5.95% Series, due 2029;
$20.0 million aggregate principal amount of the City of Petersburg, Indiana Solid Waste Disposal Revenue Bonds, 1996 Series, Indianapolis Power & Light Company Project, 6.375% Series, due 2029; and
$17.35 million aggregate principal amount of the Indiana Development Finance Authority’s Exempt Facilities Revenue Refunding Bonds, Series 1999, Indianapolis Power & Light Company Project, 5.95% Series, due 2030.

In addition, IPL used $10.0 million of the net proceeds to partially fund a $12.6 million termination payment on the interest rate swap related to the 1995B Bonds in November 2011. In accordance with ASC 980, the interest rate swap termination payment is being amortized to expense over the term of the newly issued debt.

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 IPL’s credit facility (as well as the amount of certain other fees on the credit facility) are dependent upon the credit ratings of IPL. Downgrades in the credit ratings of AES could result in IPL’s and/or IPALCO’s credit ratings being downgraded. Any reduction in our debt or credit ratings may adversely affect the trading price of our outstanding debt securities.

In April 2012, Fitch Ratings downgraded the Issuer Default Rating of IPALCO to ‘BB+’ from ‘BBB-’ and downgraded the instrument rating of IPALCO’s senior secured notes by one notch to ‘BB+’ from ‘BBB-’. In addition, Fitch Ratings affirmed the Issuer Default Rating of IPL at ‘BBB-’ as well as affirmed IPL’s security ratings. In a press release announcing the downgrade, Fitch Ratings cited various factors to explain the downgrade, including, but not limited to: IPALCO’s highly leveraged capital structure, the sole support IPALCO receives from the upstream distributions from IPL, a rise in operating costs including pension expenses, significant levels of capital spending for environmental compliance at IPL and lower wholesale power pricing.

On February 14, 2013, S&P announced that it had revised its criteria for rating utility first mortgage bonds. As a result of the revised criteria, S&P upgraded the rating of IPL's Senior Secured first mortgage bonds by one notch to BBB+ from BBB.

The credit ratings of IPALCO and IPL as of February 26, 2013 are as follows:

Moody’s S&P Fitch Ratings

IPALCO Issuer Rating/Corporate Credit Rating/Long-term Issuer Default Rating
- BBB- BB+

IPALCO Senior Secured Notes
Ba1 BB+ BB+

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. Such ratings 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.

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, 2012, 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 total debt to total capitalization not in excess of 0.65 to 1, in order to pay dividends. As of December 31, 2012 and as of the filing of this report, IPL 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, 2012, 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 stakeholders. 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. IPL must present evidence in each FAC proceeding that it has made every reasonable effort to acquire fuel and generate or purchase power or both so as to provide electricity to its retail customers at the lowest fuel cost reasonably possible.

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.

Environmental Compliance Cost Recovery Adjustment (“ECCRA”)

IPL may apply to the IURC for approval of a rate adjustment known as the Environmental Compliance Cost Recovery Adjustment (“ECCRA”) every six months to recover costs to install and/or upgrade CCT equipment. The total amount of IPL’s CCT equipment approved for ECCRA recovery as of December 31, 2012 was $618.8 million. The jurisdictional revenue requirement that was approved by the IURC to be included in IPL’s rates for the six month period from September 2012 through February 2013 was $52.9 million. During the years ended December 31, 2012, 2011 and 2010, we made total CCT expenditures of $15.0 million, $64.4 million, and $53.1 million, respectively. The vast majority of such costs are recoverable through our ECCRA filings.

The EPA released the final MATS rule in December 2011 to address hazardous air pollutant emissions from certain electric generating power plants, and IPL management has developed a plan to comply with this new rule, as discussed in “Environmental Matters - MATS” below. We will seek and expect to recover through our environmental rate adjustment mechanism, all operating and capital expenditures related to compliance with MATS; however, there can be no assurance that we will be successful in that regard.

Demand-Side Management and IPL’s Smart Energy Project

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 annual cost-effective DSM programs that reduce retail kWh sales (as compared to what sales would have been excluding the DSM programs) of 2% per year by 2019 (beginning in 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 are administered by a third party administrator. Consequently, our DSM spending, both capital and operating, began increasing significantly in 2010 and will continue to increase significantly going forward, which will likely reduce our retail energy sales and the associated revenues.

In October 2010, IPL filed a petition with the IURC for approval of its plan to comply with the IURC’s Generic DSM Order. In November 2011, IPL received approval from the IURC for this plan. Current spending approvals in effect through December 31, 2013 total $54.5 million and include the opportunity for performance based incentives. In August 2012, the IURC approved a one year extension of the contract with the current state-wide third party administrator to continue providing certain DSM programs for IPL and other jurisdictional utilities through December 31, 2014.

In 2010, IPL was awarded a smart grid investment grant for $20 million as part of its $48.9 million Smart Energy Project (including smart grid technology), which will provide its customers with tools to help them more efficiently use electricity and upgrade IPL’s electric delivery system infrastructure. Under the grant, the U.S. Department of Energy is providing nontaxable reimbursements to IPL for up to $20 million of capitalized costs associated with IPL’s Smart Energy Project. These reimbursements are being accounted for as a reduction of the capitalized Smart Energy Project costs. Through December 31, 2012, we have received total grant reimbursements of $19.1 million since the 2010 project inception.

Tree Trimming Practices Investigation

In February 2009, an IPL customer filed a complaint claiming our tree trimming practices were unreasonable and expressed concerns with language contained in our tariff that addressed our tree trimming and tree removal rights. Subsequently, the IURC initiated a generic investigation into electric utility tree trimming practices and tariffs in Indiana. In November 2010, the IURC issued an order in the investigation, which imposed additional requirements on the conduct of tree trimming. The order included requirements on utilities to provide advance customer notice and obtain customer consent or additional easements if existing easements and rights of way are insufficient to permit pruning in accordance with the required industry standards or in the event that a tree would need to have more than 25% of its canopy removed. The order also directed that a rulemaking would be initiated to further address vegetation management practices.

On July 7, 2011, the IURC issued an additional tree trimming order which did not provide the relief we were seeking, but clarified utility customer notice requirements and the relationship of the order to property rights and tariff requirements. It also clarified that in cases of emergency or public safety, utilities may, without customer consent, remove more than 25% of a tree or trim beyond existing easement or right of way boundaries to remedy the situation.

In July 2012, the IURC issued its final order in the tree trimming practices rulemaking, which was later approved by the Indiana governor and attorney general and became law in October 2012. IPL is implementing procedures to ensure it appropriately complies with the requirements of the new rule that addresses notification, dispute resolution and other activities associated with its vegetation management practices. The requirements of the new ruling are similar to current practices. However, the actual cost impact of the rule will not be known until we have experience operating under its terms.

Renewable Power Purchase Agreements

We are committed under a power purchase agreement to purchase approximately 100 MW of wind generated electricity through 2029 from a wind project in Indiana. We are also committed under another agreement to purchase approximately 200 MW of wind generated electricity for 20 years from a project in Minnesota, which began commercial operation in October 2011. We have authority from the IURC to recover the costs for both of these agreements through an adjustment mechanism administered within the FAC. We also expect to have up to 100 MW of solar generated electricity under contract in 2013, subject to approval by the IURC.

MISO Real Time Revenue Sufficiency Guarantee

MISO collects Revenue Sufficiency Guarantee (“RSG”) charges from market participants to pay for generation dispatched when the costs of such generation are not recovered in the market clearing price. Over the past several 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 MISO participants. MISO has changed their methodology multiple times. Per past FERC orders, in December 2008, MISO 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 MISO 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 generally accepted accounting principles in the U.S. 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. On August 30, 2010, FERC issued an order approving the RSG Redesign as previously filed under Section 206 on February 23, 2009 and required MISO to make a compliance filing with the changes. On October 29, 2010 MISO made its compliance filing regarding the RSG Redesign, and indicated that it would subsequently file under Section 205 modifications to the RSG Redesign rate. MISO also indicated it expected to be ready to implement the RSG Redesign rate on March 1, 2011. On February 15, 2011, MISO filed to amend its December 1, 2010 filing modifying the RSG Redesign rate, to change the effective date of the proposed modifications to April 1, 2011. FERC issued its order partially accepting the filings on March 31, 2011. On May 2, 2011, MISO submitted a request for rehearing or clarification of FERC’s March 31, 2011 order regarding the allocation of the cost of RSG. 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.

MISO Transmission Expansion Cost Sharing and FERC Order 1000

Beginning in 2007, MISO transmission system owner members including IPL began to share the costs of transmission expansion projects with other transmission system owner members after such projects were approved by the MISO board of directors. Upon approval by the MISO board of directors the transmission system owner members must make a good faith effort to build and/or pay for the projects. Costs allocated to IPL for the projects of other transmission system owner members are collected by MISO per their tariff. See also Senate Bill 251 below under “Environmental Matters.”

On July 21, 2011, the FERC issued Order 1000, amending the transmission planning and cost allocation requirements established in Order No. 890. Through Order 1000, the FERC:

(1) requires public utility transmission providers to participate in a regional transmission planning process and produce a regional transmission plan;

(2) requires public utility transmission providers to amend their open access transmission tariffs to describe how public policy requirements will be considered in local and regional transmission planning processes;

(3) removes the federal right of first refusal for certain transmission facilities; and

(4) seeks to improve coordination between neighboring transmission planning regions for interregional facilities.

MISO’s approved tariff in part already complies with Order 1000. However, Order 1000 will result in changes to transmission expansion costs charged to us by MISO. Such changes relate to public policy requirements for transmission expansion within the MISO footprint, such as to comply with renewable mandates of other states within the footprint. These charges are difficult to estimate, but are expected to be material to us within a few years; however, it is probable, but not certain, that these costs will be recoverable, subject to IURC approval. Through December 31, 2012, we have deferred as a regulatory asset $2.2 million of MISO transmission expansion costs.

ENVIRONMENTAL MATTERS

The combination of existing and expected environmental regulations make it likely that we will temporarily or permanently retire or repower several of our existing, primarily coal-fired, smaller and older generating units within the next several years. These units are not equipped with the advanced environmental control technologies needed to comply with existing and expected regulations, and collectively have made up less than 15% of our net electricity generation over the past five years. We are continuing to evaluate available options for replacing this generation, which include modifying one or more of the units to use natural gas as the fuel source, building new units, purchasing existing units, joint ownership of generating units, purchasing electricity and capacity from a third party, or some combination of these options. Accordingly, in June 2012, IPL issued a request for proposals for 600 MW of replacement capacity and energy beginning in June 2017, which is intended to help us determine the best plan for replacement generation. Proposals from outside parties have been received and we are currently evaluating appropriate next steps. Our decision on which replacement options to pursue will be impacted by the ultimate timetable for implementation of the MATS rule. We will seek and expect to recover our costs associated with replacing the retired units, but no assurance can be given as to whether the IURC would approve such a request.

From time to time we are subject to enforcement actions for claims of noncompliance with environmental laws and regulations. IPL cannot assure that it will be successful in defending against any claim of noncompliance. However, with the possible exception of the NOV from the EPA (see “New Source Review” below), we do not believe any currently open environmental 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.

MATS

In April 2012, the EPA’s rule to establish maximum achievable control technology standards for each hazardous air pollutant regulated under the CAA emitted from coal and oil-fired electric utilities, known as the Mercury and Air Toxics Standards or “MATS” became effective. IPL management has developed a plan to comply with this rule. Most of our coal-fired capacity has acid gas scrubbers or comparable control technologies; however, there are other improvements to such control technologies that are necessary to achieve compliance. Under the CAA, compliance is required by April 16, 2015; however, the compliance period for a unit, or group of units, may be extended by state permitting authorities (for one additional year) or through a CAA administrative order from the EPA (for another additional year) for generators that are deemed essential or critical to electric reliability. In the fourth quarter of 2012, we received a one-year extension from the Indiana Department of Environmental Management; therefore, the compliance period has been extended to April 16, 2016.

We have reviewed the impact of the MATS rule and estimate additional expenditures related to this rule for environmental controls for our baseload generating units to be approximately $511 million through 2016, excluding demolition costs which are not expected to be material. In June of 2012, we filed a petition and a request for a Certificate of Public Convenience and Necessity (“CPCN”) to comply with the MATS rule. These filings detail the controls we plan to add to each of our five baseload units, including four at our Petersburg generating station and one at our Harding Street generating station. We will seek and expect to recover through our environmental rate adjustment mechanism, all operating and capital expenditures related to compliance with MATS; however, there can be no assurance that we will be successful in that regard. Recovery of these costs is expected to be sought through an Indiana statute that allows for 100% recovery of qualifying costs through a rate adjustment mechanism.

Several lawsuits challenging the MATS rule have been filed and consolidated into a single proceeding before the U.S. Court of Appeals for the District of Columbia Circuit. We cannot predict the outcome of this litigation.

National Pollution Discharge Elimination System (“NPDES”)

On August 28, 2012, IDEM issued NPDES permits to the IPL Petersburg, Harding Street, and Eagle Valley generating stations, which became effective in October 2012. NPDES permits regulate specific industrial wastewater and storm water discharges to the waters of Indiana under Sections 402 and 405 of the Federal Water Pollution Control Act. These permits set new levels of acceptable metal effluent water discharge, as well as monitoring and other requirements designed to protect aquatic life, with full compliance required by October 2015. IPL is seeking an extension to the compliance deadline through November 2018; however, we do not know if it will be approved. IPL is conducting studies to determine what operational changes and/or additional equipment will be required to comply with the new limitation. In developing its compliance plans, IPL must make assumptions about the outcomes of future Federal rulemakings with respect to coal combustion byproducts, cooling water intake and wastewater effluents. We will seek and expect to recover through our environmental rate adjustment mechanism, any operating or capital expenditures related to compliance with these NPDES permits. Recovery of these costs is expected to be sought through an Indiana statute that allows for 80% recovery of qualifying costs through a rate adjustment mechanism with the remainder recorded as a regulatory asset to be considered for recovery in the next base rate case proceeding; however, there can be no assurances that we will be successful in that regard. In light of the uncertainties at this time, we cannot predict the impact of these regulations on our consolidated results of operations, cash flows, or financial condition, but it is expected to be material.

New Source Review

In October 2009, IPL received an NOV and Finding of Violation from the EPA pursuant to the CAA Section 113(a). The NOV alleges violations of the CAA at IPL’s three primarily coal-fired electric generating facilities dating back to 1986. The alleged violations primarily pertain to the Prevention of Significant Deterioration (“PSD”) and nonattainment New Source Review requirements under the CAA. Since receiving the letter, IPL management has met with the EPA staff regarding possible resolutions of the 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, install additional pollution control technology on coal-fired electric generating units, retire existing generating units, and invest in additional environmental projects. A similar outcome in this case could have a material impact on our business. We would seek recovery of any operating or capital expenditures related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that we would be successful in that regard. IPL has recorded a contingent liability related to this matter.

Climate Change Legislation and Regulation

One byproduct of burning coal and other fossil fuels is the emission of GHGs, including CO2. We face certain risks related to existing and potential federal, state, regional and local GHG legislation and 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.

The possible impact of any existing or 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 GHGs 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 GHG reduction (e.g., 10% reduction from 1990 emission levels, 20% reduction from 2000 emission levels, etc.);
The legislative and/or regulatory structure (e.g., a GHG cap-and-trade program, a carbon tax, GHG 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 or price caps on the costs of offsets and emission allowances;
The operation of and emissions from regulated units;
The permissibility of using offsets to meet reduction requirements and the requirements of such offsets (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), as well as 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, including whether the price includes any costs resulting from any new climate change 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 or other litigation by third parties;
Any opportunities to change the use of fuel at the generation facilities or opportunities to increase efficiency; and
Our ability to recover any resulting costs from our customers and the timing of such recovery.

At this time, we cannot estimate the costs of compliance with existing or potential federal, state or regional GHG emissions reductions legislation or initiatives due in part to the fact that many of these proposals are in earlier stages of development and any final laws, if adopted, could vary drastically from current proposals. Any federal, state or regional legislation 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 U.S. Congress has considered several different draft bills pertaining to GHG legislation, including comprehensive GHG legislation that would impact many industries and more limited legislation focusing only on the utility and electric generation industry. Although no legislation pertaining to GHG emissions has been passed to date by the U.S. Congress, similar legislation may be passed by the U.S. Congress in the future. In addition, in the past Midwestern state governors (including the governor of Indiana) and the premier of Manitoba, Canada committed to reduce GHG emissions through the implementation of a cap-and-trade program pursuant to the Midwestern Greenhouse Gas Reduction Accord. Though the participating states and province are no longer pursuing this commitment, similar state or regional initiatives may be pursued in the future.

In January 2011, the EPA began regulating GHG emissions from certain stationary sources under the so-called “Tailoring Rule.” The regulations are being implemented pursuant to two CAA programs: the Title V Operating Permit program and the program requiring a permit if undergoing certain new construction or major modifications, the PSD program. Obligations relating to Title V permits include recordkeeping and monitoring requirements. GHG emissions are measured in tons of each particular GHG emitted and are adjusted to be equivalent to one ton of CO2 emissions. These units are referenced as CO2 equivalents (‘‘CO2e’’). PSD applies to a new source that will emit or have the potential to emit 100,000 tons per year of CO2e and to any existing major stationary source that undergoes a modification that causes a significant increase in GHG emissions (currently defined to be 75,000 tons per year or more of CO2e). Sources subject to PSD can be required to implement Best Achievable Control Technology (“BACT”). The EPA has issued guidance on what BACT entails for the control of GHG and individual states are now required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis. In December 2010, the Indiana Air Pollution Control Board adopted a final rule implementing the EPA’s Tailoring Rule in Indiana, and the rule was published in the Indiana Register in March 2011. The ultimate impact of the Tailoring Rule and the BACT requirements applicable to us on our operations cannot be determined at this time, but the cost of compliance could be material.

In addition to the Tailoring Rule, in December 2010, the EPA announced that it had entered into a settlement agreement with several states and environmental groups that requires the EPA to promulgate New Source Performance Standards (‘‘NSPS’’) for GHG emissions from electric generating units (‘‘EGUs’’) and certain emissions units from refineries. In April 2012, the EPA published such proposed regulations. The proposed rule would require certain new electric generating units to meet a standard of 1,000 pounds of carbon dioxide per megawatt-hour, a standard based on the emissions limitations achievable through natural gas combined cycle generation. The proposal anticipates that affected coal-fired units would need to install carbon capture and storage or other expensive carbon dioxide emission control technology to meet the standard. As proposed, the standard would not apply to our existing generating units, but rather would regulate construction of new generating units. The EPA is expected to finalize the proposed NSPS for new generating units in early 2013, and may issue NSPS for existing generating units in the future.

There is some uncertainty with respect to the impact of GHG rules on IPL. Since the Tailoring Rule will not require IPL to implement BACT until IPL constructs a new major source or makes a major modification of an existing major source and the proposed NSPS will not require IPL to comply with an emissions standard until IPL constructs a new electric generating unit, and since it is not certain when IPL’s next major modification or construction of a new major source will be, it is unclear when the Tailoring Rule BACT requirements and proposed NSPS for GHG emissions will ultimately apply, if at all. In addition, Congress may take action that impacts EPA’s current regulations, including but not limited to enacting a cap-and-trade law, which could preclude the EPA from regulating GHG under existing CAA regulatory programs. In light of these uncertainties, we cannot predict the impact of the EPA’s current GHG regulations on our consolidated results of operations, cash flows, or financial condition, but it could be material.

Clean Air Interstate Rule and the Cross-State Air Pollution Rule

In March 2005 the EPA signed the federal Clean Air Interstate Rule (“CAIR”), which imposes restrictions against polluting the air of downwind states. At the time, CAIR established a two-phase regional “cap and trade” program for Sulfur Dioxides (“SO2”) and Nitrogen Oxides (“the program for NOx emissions”) emissions that requires the largest reduction in air pollution in more than a decade. CAIR covers 28 states, including Indiana, and the District of Columbia.

Phase I of CAIR for NOx became effective on January 1, 2009 and required reductions of NOx emissions by 1.7 million tons or 53% from 2003 levels, and required year-round compliance with the NOx emissions reduction requirements. Phase I of the program for SO2 emissions required reductions in SO2 emissions by 4.3 million tons, or 45% lower than 2003 levels beginning in 2010. We have thus far been able to comply with CAIR Phase I for NOx without any material additional capital expenditures. Installation of CCT at our Harding Street Unit 7 generating station completed in 2007 and the upgrades to existing CCT equipment at our Petersburg Unit 3 generating station completed in 2006, and at our Petersburg Unit 4 generating station completed in 2011, are enabling us to meet the requirements of CAIR Phase I for SO2.

On July 6, 2011, the EPA announced a new rule to replace CAIR that will require the further reduction of SO2 and NOx emissions from power plants in 28 states, including Indiana, that contribute to ozone and/or fine particle pollution in other states. This rule, which was known as the U.S. Cross-State Air Pollution Rule (‘‘CSAPR’’), required initial compliance by January 1, 2012 for SO2 and annual NOx reductions, and May 1, 2012 for ozone season reductions. On December 30, 2011, the U.S. Court of Appeals for the District of Columbia issued an order staying implementation of the CSAPR pending resolution of legal challenges to the rule. The Court further ordered that the CAIR remain in place while the CSAPR is stayed.

In August 2012, the U.S. Court of Appeals issued a ruling vacating the CSAPR. The Court ruling also required EPA to continue administering CAIR pending the promulgation of a replacement rule by EPA. IPL will continue to meet its CAIR requirement by virtue of existing pollution control equipment combined with the purchase of emission allowances, when needed. In October 2012, the EPA filed a petition for rehearing en banc of this case, which was denied in January 2013. At this time, we cannot predict the impact or timing of the new rules EPA will propose.

National Ambient Air Quality Standards

Under the CAA, the EPA sets National Ambient Air Quality Standards (“NAAQS”) for six criteria pollutants considered harmful to public health and the environment, including particulate matter, NOx, ozone and SO2, which result from coal combustion. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS. NAAQS must be reviewed by the EPA at five-year intervals.

Ozone. Over the past several years, the EPA has tightened the NAAQS 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. This standard was challenged by several environmental groups, industry groups and various states, all appeals having been consolidated in the D.C. Circuit Court of Appeals (see Mississippi v. EPA, No. 08-1200). Based on this ozone daily emission standard, it would be expected that several areas that are currently designated as in attainment for ozone may be redesignated as nonattainment, including areas where IPL’s Eagle Valley and Harding Street plants are located.

In September 2009, the EPA announced it would reconsider the 2008 Ozone NAAQS standard. In January 2010, the EPA proposed a rule that would significantly reduce both the primary and secondary NAAQS for ozone. The proposed rule would have established a primary standard at a level within the range of 0.060 to 0.070 parts per million (‘‘ppm’’) and a cumulative, seasonal secondary standard at a level within the range of 7 to 15 ppm-hours. In September 2011, the President withdrew the EPA’s proposed rule to alter the 2008 Ozone NAAQS. One of the reasons used by the President in his decision to withdraw the standard was that the CAA required reconsideration of NAAQS every five years, and the Ozone NAAQS will be reconsidered as required by the CAA in 2013. As a result, states are expected to begin implementing the 0.075 parts per million daily ambient ozone standard.

In addition to possible promulgation of new ozone standards, in December 2010, the EPA published a proposed rule that would rescind its earlier interpretation of reasonable further progress (‘‘RFP’’) requirements for the 1997 eight-hour Ozone NAAQS. It is not clear whether this rule was impacted by the President’s decision to withdraw the Ozone NAAQS. If the rule is finalized, states that relied on emissions reductions from sources outside of a nonattainment area to meet RFP requirements would have to submit new RFP demonstrations. This rulemaking could impact several states’ attainment determinations. If Indiana determines that certain areas are in ‘‘nonattainment’’ of the NAAQS, Indiana would be required to develop a plan to reach ‘‘attainment’’ status, which may include requiring our generating facilities to accept limits to reduce our emissions.

Fine Particulate Matter. In 2005, several areas in the state of Indiana were designated as nonattainment for fine particulate matter for the 1997 daily and annual standards, which include the areas where our Eagle Valley, Petersburg, and Harding Street plants are located. In 2006, the EPA lowered the daily standard fine for particulate matter from 65 micrograms per cubic meter to 35 micrograms per cubic meter. 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 our plants are located, despite the more stringent standard, will be in attainment according to the EPA.

With respect to the annual standard, in 2009 the D.C. Circuit Court of Appeals rejected the EPA’s 2006 annual fine particulate NAAQS. The court remanded the annual fine particulate matter standard to the EPA for further justification or, if appropriate, modification because the court found that the EPA failed to explain adequately why the annual fine particulate matter standard was sufficient to protect public health. On January 15, 2013, EPA published in the Federal Register a final rule revising the NAAQS for particulate matter. Among other things, the final rule lowers the primary annual PM2.5 standard from 15 to 12 micrograms per cubic meter of air. Our plants continue to be in nonattainment areas under the annual fine particulate matter standard. The impact of the new standards cannot be accurately predicted at this time, but could be material.

Nitrogen Oxides and Sulfur Dioxides. On April 12, 2010 a one-hour primary NAAQS became effective for NOx. Additionally, on August 23, 2010 a new one-hour SO2 primary NAAQS became effective. The final rule implementing the one-hour SO2 NAAQS also requires an increased amount of ambient SO2 monitoring sites. The EPA is considering one-hour secondary NAAQS for NOx and SO2, and plans to promulgate these secondary standards together in a separate rulemaking. In February 2013, EPA indicated that it intends to propose to designate the areas where our plants are located as non-attainment under the one-hour standard; however, no designations are final, and are therefore subject to change.

Based on these current and potential ambient standards, the state of Indiana will be required to determine whether certain areas within the state meet the NAAQS. If certain areas are determined to be in “nonattainment,” the state of Indiana would be required to modify its State Implementation Plan to detail how the state will regain its attainment status. As part of this process, it is possible that the IDEM or the EPA may require reductions of emissions from our generating stations to reach attainment status. For fine particulate matter, the IDEM has drafted plans to reach attainment status, and those plans are pending approval by the EPA. The IDEM’s current draft plan for fine particulate matter does not require our plants to install additional controls. However, it remains possible that the IDEM or the EPA may require further efforts by our generating stations to reach attainment status for fine particulate. It is expected that the state will make its attainment demonstrations for NO2, and SO2 within the next three years. At this time, we cannot predict what the impact will be to IPL with respect to these new ambient standards, but it could be material.

Waste Management and Coal Combustion Byproducts

In the course of operations, our facilities generate solid and liquid waste materials requiring eventual disposal or processing. Waste materials generated at our electric power and distribution facilities include coal combustion byproducts (‘‘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. With the exception of CCB, waste materials are not usually physically disposed of on our property, but are shipped off site for final disposal, treatment or recycling. A small amount of CCB, which consists of bottom ash, fly ash and air pollution control wastes, is disposed of at our Petersburg coal-fired power generation plant using engineered, permitted landfills; however, approximately 40% of our CCB are beneficially used off-site as a raw material for production of wallboard, concrete or cement and as a construction material in structural fills and approximately 60% is disposed of.

On June 21, 2010, the EPA published in the Federal Register a proposed rule that establishes regulation of coal combustion residues under the Resource Conservation and Recovery Act (‘‘RCRA’’). The proposed rule consists of two options to which coal combustion residues would be regulated. Each option would allow for the continued beneficial use of CCBs. The first option would subject CCBs to regulation as special waste under Subtitle C of RCRA. The second option would regulate CCBs as non-hazardous solid waste under Subtitle D of RCRA and impose national criteria applicable to CCBs disposed of in landfills and surface impoundments. The public comment period for this proposed regulation expired on November 19, 2010. The EPA will consider any public comments prior to promulgating a final rule. The EPA is expected to issue its final rule on CCBs in 2013 or 2014. The exact impact and compliance cost associated with future regulation of coal combustion residues cannot be established until such regulations are finalized, but our business, financial condition or results of operations could be materially and adversely affected by such regulations.

Wastewater Effluent

Some water used in our operations is discharged as wastewater effluent. This wastewater may contain heavy metals and other polluting substances. The EPA has stated it plans to propose revisions to the rules governing pollutants in wastewater effluent from coal-fired power plants with final action on the proposed rules expected to occur by May 2014. Although the impact of any new regulations cannot be determined at this time, more stringent regulations could have a material impact on our business, financial condition and results of operations.

Cooling Water Intake Regulations

We use water as a coolant at our generating facilities. Under the federal Clean Water Act (‘‘CWA’’), cooling water intake structures are required to reflect the Best Technology Available (‘‘BTA’’) for minimizing adverse environmental impact. In March 2011, the EPA announced its proposal for standards to protect fish and other aquatic organisms drawn into cooling water systems at large power plants and other industrial facilities. The proposal was published in the Federal Register in April 2011. The proposal, based on Section 316(b) of the CWA establishes BTA requirements regarding impingement mortality for all existing facilities that withdraw water from a source water body above a minimum volume and utilize at least 25% of the withdrawn water for cooling purposes. IPL believes in order to meet these BTA requirements, all cooling water intake structures associated with once through cooling processes will need to modify the existing traveling screens and add a fish return and handling system for each cooling system. The proposal would also require owners of facilities that withdraw very large amounts of water to perform comprehensive site-specific studies during the permitting process and/or may require closed-cycle cooling systems (closed-cycle cooling towers), or other technology. The proposal also establishes a public process, with opportunity for public input, by which the appropriate technology to reduce entrainment mortality would be implemented at each facility after considering site-specific factors. Under a consent decree filed in the U.S. District Court for the Southern District of New York, the EPA is required to issue a final rule by June of 2013. It is not possible to predict the total impacts of the final rule at this time, but if additional capital expenditures are necessary, they could be material. We would seek recovery of these capital expenditures; however, there is no guarantee we would be successful in that regard.

Other

On April 7, 2010, the EPA published an Advanced Notice of Proposed Rulemaking which contemplates a reassessment of the use authorizations under the Toxic Substances Control Act for Polychlorinated Biphenyl containing equipment of greater than 50 parts per million and considers a mandated phase-out of all Polychlorinated Biphenyl-containing equipment. At this time, it is too early to predict whether new regulations for hazardous air pollutants or Polychlorinated Biphenyls will be promulgated or, if promulgated, the extent of such regulations. IPL’s costs of compliance with any such regulations could be material.

Senate Bill 251

In May 2011, Senate Bill 251 became a law in the State of Indiana. Senate Bill 251 is a comprehensive bill which, among other things, provides Indiana utilities with a means for recovering 80% of costs incurred to comply with federal mandates through a periodic retail rate adjustment mechanism. This includes costs to comply with regulations from the EPA, FERC, NERC, Department of Energy, etc., including capital intensive requirements and/or proposals described herein, such as cooling water intake regulations, waste management and coal combustion byproducts, wastewater effluent, MISO transmission expansion costs and polychlorinated biphenyls. It does not change existing legislation that allows for 100% recovery of clean coal technology designed to reduce air pollutants (Senate Bill 29).

Some of the most important features of Senate Bill 251 to IPL are as follows. Any energy utility in Indiana seeking to recover federally mandated costs incurred in connection with a compliance project shall apply to the IURC for a CPCN for the compliance project. Senate Bill 251 sets forth certain factors that the IURC must consider in determining whether to grant a CPCN. It further specifies that if the IURC approves a proposed compliance project and the projected federally mandated costs associated with the project, the following apply: (i) 80% of the approved costs shall be recovered by the energy utility through a periodic retail rate adjustment mechanism, (ii) 20% of the approved costs shall be deferred and recovered by the energy utility as part of the next general rate case filed by the energy utility with the IURC, and (iii) actual costs exceeding the projected federally mandated costs of the approved compliance project by more than 25% shall require specific justification and approval before being authorized in the energy utility’s next general rate case. Senate Bill 251 also requires the IURC to adopt rules to establish a voluntary clean energy portfolio standard program. Such program will provide incentives to participating electricity suppliers to obtain specified percentages of electricity from clean energy sources in accordance with clean portfolio standard goals, including requiring at least 50% of the clean energy to originate from Indiana suppliers. The goals can also be met by purchasing clean energy credits.

Summary

Environmental laws and regulations presently require us to incur material capital expenditures and operating costs. We expect to incur material costs, both in capital expenditures and ongoing operating and maintenance costs, to comply with MATS (up to $511 million through 2016, excluding demolition costs which are not expected to be material, as discussed in “MATS” above) and NPDES, and, to a lesser extent to which we cannot predict, other expected environmental regulations related to: coal combustion byproducts; cooling water intake; Polychlorinated Biphenyl-containing equipment; National Ambient Air Quality Standards; and wastewater effluent rules. We would expect to seek recovery of both capital and operating costs related to such compliance, although there can be no assurances that we would be successful in that regard. 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 and have a negative impact on our wholesale volumes and margins. 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. We may seek recovery of any operating or capital expenditures; however, there can be no assurances that we would be successful in that regard. Please see “Regulatory Matters - Environmental Compliance Cost Recovery Adjustment” 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 U.S. 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 total regulatory assets of $528.7 million and $493.4 million as of December 31, 2012 and 2011 and total regulatory liabilities of $580.8 million and $559.7 million as of December 31, 2012 and 2011. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory assets have been included as allowable costs for ratemaking purposes, as authorized by the IURC or established regulatory practices. Regulatory liabilities generally represent obligations to make refunds or future rate reductions to customers for previous overcollections or the deferral of revenues collected for costs that IPL expects to incur in the future. Specific regulatory assets and liabilities are disclosed in Note 6, “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 and liabilities 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. It is probable, but not certain, that these regulatory assets will be recoverable, subject to IURC approval.

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 nearly all residential, small commercial and industrial 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 2012 revenues and ending unbilled revenues of a one percentage point increase and decrease in the estimated line losses for the month of December 2012 is ($0.4 million) and $0.4 million, respectively. At December 31, 2012 and 2011, customer accounts receivable include unbilled energy revenues of $50.6 million and $44.1 million, respectively, on a base of annual revenue of $1.2 billion in each of 2012 and 2011.

Pension Costs

We contributed $48.3 million, $37.3 million, and $28.7 million to the Pension Plans in 2012, 2011, and 2010, respectively.

Approximately 85% 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 (“Thrift Plan”). The Defined Benefit Pension Plan is a qualified defined benefit plan, while the Thrift Plan is a qualified defined contribution plan. The remaining 15% of active employees are covered by the AES Retirement Savings Plan (“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 contribution 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 dependent 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, 2012 was 26. The plan is closed to new participants.

From a Financial Accounting Standards Board financial statement perspective, IPL’s total underfunded pension liability was approximately $268.5 million as of December 31, 2012 of which the Defined Benefit Pension Plan liability and the Supplemental Retirement Plan of Indianapolis Power & Light Company (“Supplemental Retirement Plan”) liability represented $267.0 million and $1.5 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, 2012. 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 2012, pension expense was determined using an assumed long-term rate of return on plan assets of 7.50%. As of the December 31, 2012 measurement date, IPL decreased the discount rate from 4.56% to 3.80% for the Defined Benefit Pension Plan and decreased the discount rate from 4.37% to 3.41% for the Supplemental Retirement Plan. The discount rate assumption affects the pension expense determined for 2013. In addition, IPL decreased the expected long-term rate of return on plan assets from 7.50% to 7.25% effective January 1, 2013. The expected long-term rate of return assumption affects the pension expense determined for 2013. The effect on 2013 total pension expense of a 25 basis point increase and decrease in the assumed discount rate is ($1.7 million) and $1.8 million, respectively. The effect on 2013 total pension expense of a 100 basis point increase and decrease in the expected long-term rate of return on plan assets is ($5.3 million) and $5.3 million, respectively.

During the year 2012, our Pension Plans incurred a net actuarial loss of $50.9 million. The net actuarial loss is comprised of two parts (net): (1) $18.2 million of pension asset actuarial gain primarily due to the higher than expected return on assets, and (2) $69.1 million of pension liability actuarial loss 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, 2012. We project the expected benefit payments under the plan based on participant data 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 U.S. 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 $2.4 billion as of December 31, 2012 and 2011, respectively. 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.

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 12, “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 information about significant contingencies involving us. As of December 31, 2012 and 2011, total loss contingencies accrued were $3.9 million and $4.2 million, respectively, which were included in Other Current Liabilities on the accompanying Consolidated Balance Sheets.

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 sometimes 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 and by refinancing existing long-term debt at times when it is deemed economic and prudent. In addition, IPL’s credit facility bears interest at variable rates based either on the Prime interest rate or on the London InterBank Offer Rate. Fair values relating to financial instruments are dependent upon prevalent market rates of interest, primarily the London InterBank Offer Rate. At December 31, 2012, we had approximately $1,765 million principal amount fixed rate debt and $50 million principal amount variable rate debt outstanding.

Variable rate debt at December 31, 2012 was comprised of $50 million under the accounts receivable securitization facility. Based on amounts outstanding as of December 31, 2012, the effect of a 25 basis point change in the applicable rates on our variable-rate debt would increase or decrease our annual interest expense and cash paid for interest by $0.1 million and $(0.1 million), respectively.

The following table shows our consolidated indebtedness (in millions) by maturity as of December 31, 2012:

2013 2014 2015 2016 2017 Thereafter Total Fair Value

(In Millions)

Fixed-rate debt
$ 110.0 $ - $ - $ 531.9 $ 24.6 $ 1,098.8 $ 1,765.3 $ 2,012.3

Variable-rate debt
50.0 - - - - - 50.0 50.0

Total Indebtedness
$ 160.0 $ - $ - $ 531.9 $ 24.6 $ 1,098.8 $ 1,815.3 $ 2,062.3

Weighted Average Interest Rates by Maturity
4.62% N/A N/A 6.67% 5.40% 5.45% 5.66%

For further discussion of our fair value of our indebtedness and book value of our indebtedness please see Note 5, “Fair Value Measurements” and Note 9, “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

Based on our relatively small percentage of unhedged variable rate debt in our capital structure, our interest rate exposure to the credit market crisis was and continues to be limited and has not been material. See “Interest Rate Risk” above.

Equity Market Risk

Our Pension Plans are impacted significantly by the economy as a result of the Pension Plans being heavily invested in common equity securities. The performance of the Pension Plans’ investments in such common equity securities and other instruments impacts our earnings as well as our funding liability. Our Pension Plans investments’ realized material losses in the recession that began in 2008 followed by partial recoveries in 2009 through 2012. Please see Note 11, “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 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. Inflation on raw materials remained low in 2010, 2011 and 2012. 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 to increase 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 all of our current projected burn through 2013 and approximately 74% of our current projected burn for the three year period ending December 31, 2015, under long-term contracts. Pricing provisions in some of our long-term coal contracts allow for price changes under certain circumstances. Coal purchases contracted for in 2013 are at prices that average the same as our weighted average price in 2012 due to price renegotiations that occurred in 2012. 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 Purchased

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 wholesale power marketing activities that primarily involve the offering of utility-owned or contracted generation into the MISO day-ahead and real-time markets. 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, the demand by load serving entities, and the formation of IPL’s offers into the market. Our wholesale revenues are generated primarily from sales directly to the MISO energy market.

The average price per MWh we sold in the wholesale market was $28.92, $30.45 and $31.62 in 2012, 2011 and 2010, respectively. Until recently, wholesale revenues generally represented approximately 5% of our total electric revenues. In 2011 and 2012, that percentage dropped to 3.7% and then 3.1%, respectively. A decline in wholesale prices can have a significant impact on earnings, because most of our nonfuel costs are fixed in the short term and lower wholesale prices can result in lower wholesale volumes sold.

Counterparty Credit Risk

At times, we may utilize forward purchase contracts to manage the risk associated with power purchases, and could be exposed to counterparty credit risk in these contracts. We manage this exposure to counterparty 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 counterparty to further mitigate credit risk. We may also require a counterparty to provide collateral in the event certain financial benchmarks are not maintained, or certain credit ratings are not maintained.

We are also exposed to counterparty credit risk related to our ability to collect electricity sales from our customers, which may be impacted by volatility in the financial markets and the economy. Historically, our write-offs of customer accounts has been immaterial, which is common for the electric utility industry.

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 - 2012, 2011, and 2010
	Defined Terms
	Consolidated Statements of Comprehensive Income for the years ended December 31, 2012, 2011, and 2010
	Consolidated Balance Sheets as of December 31, 2012 and 2011
	Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011, and 2010
	Consolidated Statements of Common Shareholder’s Deficit for the years ended December 31, 2012, 2011, and 2010
	Notes to Consolidated Financial Statements

Indianapolis Power & Light Company and Subsidiary - Consolidated Financial Statements
	Report of Independent Registered Public Accounting Firm - 2012, 2011, and 2010
	Defined Terms
	Consolidated Statements of Comprehensive Income for the years ended December 31, 2012, 2011, and 2010
	Consolidated Balance Sheets as of December 31, 2012 and 2011
	Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011, and 2010
	Consolidated Statements of Common Shareholder’s Equity for the years ended December 31, 2012, 2011, and 2010
	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, 2012 and 2011, and the related consolidated statements of comprehensive income, common shareholder’s deficit, and cash flows for each of the three years in the period ended December 31, 2012. Our audits also included the financial statement schedules listed in the Index at Item 15. 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, 2012 and 2011, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, 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 26, 2013


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 aggregate principal amount of the City of Petersburg, Indiana, Pollution Control Refunding Revenue Bonds Adjustable Rate Tender Securities 1995B Series, 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
2018 IPALCO Notes	$400 million of 5.00% Senior Secured Notes due May 1, 2018
AES	The AES Corporation
ARO	Asset Retirement Obligations
ASC	Financial Accounting Standards Board Accounting Standards Codification
CCT	Clean Coal Technology
Defined Benefit Pension Plan	Employees’ Retirement Plan of Indianapolis Power & Light Company
DSM	Demand Side Management
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
FTRs	Financial Transmission Rights
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
kWh	Kilowatt hours
MATS	Mercury and Air Toxics Standards
Mid-America	Mid-America Capital Resources, Inc.
MISO	Midwest Independent Transmission System Operator, Inc.
NOV	Notice of Violation
Pension Plans	Employees’ Retirement Plan of Indianapolis Power & Light Company and Supplemental Retirement Plan of Indianapolis Power & Light Company
Purchasers	Royal Bank of Scotland plc and Windmill Funding Corporation
Receivables Sale Agreement	Second Amended and Restated Receivables Sale Agreement, dated as of June 25, 2009, among IPL, IPL Funding Corporation, as the Seller, Indianapolis Power & Light Company, as the collection Agent, Royal Bank of Scotland plc, as the Agent, the Liquidity Providers and Windmill Funding Corporation
RSG	Revenue Sufficiency Guarantee
RSP	The AES Retirement Savings Plan
Supplemental Retirement Plan	Supplemental Retirement Plan of Indianapolis Power & Light Company
Thrift Plan	Employees’ Thrift Plan of Indianapolis Power & Light Company
U.S.	United States of America


IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Comprehensive Income
For the Years Ended December 31, 2012, 2011 and 2010
*(In Thousands)*

	2012		2011		2010

UTILITY OPERATING REVENUES	$	1,229,777	$	1,171,924	$	1,144,903

UTILITY OPERATING EXPENSES:
Operation:
Fuel		340,647		334,385		322,541
Other operating expenses		217,124		203,286		196,166
Power purchased		121,238		90,159		55,456
Maintenance		99,568		119,152		118,883
Depreciation and amortization		176,843		167,245		164,102
Taxes other than income taxes		44,295		42,435		39,378
Income taxes - net		67,162		62,609		75,939
Total utility operating expenses		1,066,877		1,019,271		972,465
UTILITY OPERATING INCOME		162,900		152,653		172,438

OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used during construction		1,087		3,950		3,990
Loss on early extinguishment of debt		-		(15,422)		-
Miscellaneous income and (deductions) - net		(2,290)		6,963		(3,311)
Income tax benefit applicable to nonoperating income		19,463		25,476		25,410
Total other income and (deductions) - net		18,260		20,967		26,089

INTEREST AND OTHER CHARGES:
Interest on long-term debt		103,435		109,233		114,707
Other interest		1,913		1,786		2,136
Allowance for borrowed funds used during construction		(1,059)		(2,674)		(2,437)
Amortization of redemption premiums and expense on debt		4,875		4,700		4,174
Total interest and other charges - net		109,164		113,045		118,580
NET INCOME		71,996		60,575		79,947

LESS: PREFERRED DIVIDENDS OF SUBSIDIARY		3,213		3,213		3,213

NET INCOME APPLICABLE TO COMMON STOCK	$	68,783	$	57,362	$	76,734

ADD OTHER COMPREHENSIVE INCOME:
Unrealized loss on available for sale investment		-		-		(197)
Gain on sale of available for sale investment		-		197		-

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK	$	68,783	$	57,559	$	76,537

See notes to consolidated financial statements.


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

	December 31, 2012		December 31, 2011
ASSETS
UTILITY PLANT:
Utility plant in service	$	4,382,534	$	4,313,015
Less accumulated depreciation		2,043,540		1,940,633
Utility plant in service - net		2,338,994		2,372,382
Construction work in progress		70,169		52,429
Spare parts inventory		15,445		15,534
Property held for future use		1,002		1,002
Utility plant - net		2,425,610		2,441,347

OTHER ASSETS:
Nonutility property - at cost, less accumulated depreciation		533		539
Other investments		5,333		5,029
Other assets - net		5,866		5,568

CURRENT ASSETS:
Cash and cash equivalents		18,487		27,283
Accounts receivable and unbilled revenue (less allowance for doubtful accounts of $2,047 and $2,081, respectively)		141,508		136,007
Fuel inventories - at average cost		45,236		52,694
Materials and supplies - at average cost		57,256		54,137
Deferred tax asset - current		10,809		12,352
Regulatory assets		4,906		7,424
Prepayments and other current assets		21,135		16,838
Total current assets		299,337		306,735

DEFERRED DEBITS:
Regulatory assets		523,839		485,932
Miscellaneous		30,695		32,070
Total deferred debits		554,534		518,002
TOTAL	$	3,285,347	$	3,271,652


CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common shareholder’s deficit:
Pain in Capital	$	11,811	$	11,367
Accumulated deficit		(15,030)		(17,213)
Total common shareholder’s deficit		(3,219)		(5,846)
Cumulative preferred stock of subsidiary		59,784		59,784
Long-term debt (Note 9)		1,651,120		1,760,316
Total capitalization		1,707,685		1,814,254

CURRENT LIABILITIES:
Short-term debt (Note 9)		160,000		64,000
Accounts payable		76,343		81,206
Accrued expenses		24,310		24,138
Accrued real estate and personal property taxes		19,405		17,460
Regulatory liabilities		10,475		9,263
Accrued interest		31,979		31,008
Customer deposits		24,796		23,142
Other current liabilities		11,210		14,236
Total current liabilities		358,518		264,453

DEFERRED CREDITS AND OTHER LONG-TERM LIABILITIES:
Regulatory liabilities		570,344		550,432
Accumulated deferred income taxes - net		341,859		351,161
Non-current income tax liability		6,138		5,354
Unamortized investment tax credit		8,162		9,761
Accrued pension and other postretirement benefits		274,017		258,171
Miscellaneous		18,624		18,066
Total deferred credits and other long-term liabilities		1,219,144		1,192,945

COMMITMENTS AND CONTINGENCIES (Note 12)
TOTAL	$	3,285,347	$	3,271,652

See notes to consolidated financial statements.


IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Cash Flows
For the Years Ended December 31, 2012, 2011 and 2010
*(In Thousands)*

	2012		2011		2010
CASH FLOWS FROM OPERATIONS:
Net income	$	71,996	$	60,575	$	79,947
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		179,217		169,421		163,337
Amortization of regulatory assets		2,206		2,529		6,777
Deferred income taxes and investment tax credit adjustments - net		(4,370)		(8,889)		(5,759)
Loss on early extinguishment of debt		-		15,422		-
Termination of interest rate swap		-		(12,572)		-
Allowance for equity funds used during construction		(881)		(3,772)		(3,795)
Gain on sale of nonutility property		-		(13,320)		-
Change in certain assets and liabilities:
Accounts receivable		(5,501)		4,531		(13,389)
Fuel, materials and supplies		4,339		(17,938)		(764)
Income taxes receivable or payable		(6,681)		8,272		(5,443)
Financial transmission rights		360		(621)		(1,214)
Accounts payable and accrued expenses		(2,947)		2,514		19,698
Accrued real estate and personal property taxes		1,945		648		(6,819)
Accrued interest		971		1,777		354
Pension and other postretirement benefit expenses		15,846		58,883		13,473
Short-term and long-term regulatory assets and liabilities		(43,514)		(91,761)		(32,484)
Other - net		1,780		7,385		6,612
Net cash provided by operating activities		214,766		183,084		220,531

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures - utility		(129,747)		(209,851)		(163,652)
Purchase of investments		-		-		-
Proceeds from sales and maturities of short-term investments		-		2,000		-
Proceeds from sales of assets		1		13,467		-
Grants under the American Recovery and Reinvestment Act of 2009		6,028		7,919		5,130
Cost of removal, net of salvage		(9,251)		(14,896)		(3,035)
Other		(6,608)		(3,958)		(6,655)
Net cash used in investing activities		(139,577)		(205,319)		(168,212)

CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt borrowings		73,000		138,000		9,508
Short-term debt repayments		(87,000)		(124,000)		(40,000)
Long-term borrowings, net of discount		-		634,581		40,000
Retirement of long-term debt and early tender premium		-		(559,145)		-
Dividends on common stock		(66,600)		(59,231)		(73,200)
Preferred dividends of subsidiary		(3,213)		(3,213)		(3,213)
Deferred financing costs paid		(166)		(8,633)		(1,306)
Other		(6)		(637)		(334)
Net cash provided by (used in) financing activities		(83,985)		17,722		(68,545)
Net change in cash and cash equivalents		(8,796)		(4,513)		(16,226)
Cash and cash equivalents at beginning of period		27,283		31,796		48,022
Cash and cash equivalents at end of period	$	18,487	$	27,283	$	31,796

Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized)	$	103,254	$	108,488	$	113,458
Income taxes	$	58,750	$	37,750	$	61,650

See notes to consolidated financial statements.

IPALCO ENTERPRISES, INC. and SUBSIDIARIES

Consolidated Statements of Common Shareholder’s Deficit

and Noncontrolling Interest

(In Thousands)

Paid in Capital Accumulated Deficit Accumulated Other Comprehensive Income (Loss) Total Common Shareholder's Deficit Cumulative Preferred Stock of Subsidiary

2010

Beginning Balance $ 9,820 $ (18,878) $ -   $ (9,058) $ 59,784

Comprehensive Income attributable to common stock:

Net income applicable to common stock
76,734 76,734

Unrealized loss on available for sale investment (net of income tax benefit of $134)
(197) (197)

Distributions to AES
(73,200) (73,200)

Contributions from AES
991 991

Balance at December 31, 2010
$ 10,811 $ (15,344) $ (197) $ (4,730) $ 59,784

2011

Comprehensive Income attributable to common stock:

Net income applicable to common stock
57,362 57,362

Gain on sale of available for sale investment (net of income tax expense of $134)
197 197

Distributions to AES
(59,231) (59,231)

Contributions from AES
556 556

Balance at December 31, 2011
$ 11,367 $ (17,213) $ -   $ (5,846) $ 59,784

2012

Comprehensive Income attributable to common stock:

Net income applicable to common stock
68,783 68,783

Distributions to AES
(66,600) (66,600)

Contributions from AES
444 444

Balance at December 31, 2012
$ 11,811 $ (15,030) $ -   $ (3,219) $ 59,784

See notes to consolidated financial statements.

IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Notes to Consolidated Financial Statements
For the Years Ended December 31, 2012, 2011 and 2010

1. ORGANIZATION

IPALCO Enterprises, Inc. (“IPALCO”) is a holding company incorporated under the laws of the state of Indiana. IPALCO is a wholly-owned subsidiary of The AES Corporation (“AES”), 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”). 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 two combustion turbines at a separate site that are all used for generating electricity. IPL’s net electric generation capacity for winter is 3,492 megawatts and net summer capacity is 3,353 megawatts.

IPALCO’s other direct subsidiary is Mid-America Capital Resources, Inc. (“Mid-America”). Mid-America is the holding company for IPALCO’s unregulated activities. 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 U.S. (“GAAP”) 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. Certain costs for shared resources amongst IPL and IPALCO, such as labor and benefits, are allocated to each entity based on allocation methodologies that management believes to be reasonable. We have evaluated subsequent events through the 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 Comprehensive 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 (“IURC”). IPL’s wholesale power transactions are subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”). 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 Financial Accounting Standards Board Accounting Standards Codification (“ASC”) 980 “Regulated Operations,” which gives recognition to the ratemaking and accounting practices of these agencies. See also Note 6, “Regulatory Assets and Liabilities” for a discussion of specific regulatory assets and liabilities.

Revenues and Accounts Receivable

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 nearly all residential, small commercial and industrial 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, 2012 and 2011, customer accounts receivable include unbilled energy revenues of $50.6 million and $44.1 million, respectively, on a base of annual revenue of $1.2 billion in each of 2012 and 2011. Our provision for doubtful accounts included in Other operating expenses on the accompanying Consolidated Statements of Comprehensive Income was $3.4 million, $3.7 million and $4.0 million for the years ended December 31, 2012, 2011 and 2010, respectively.

IPL’s basic rates include a provision for fuel costs as established in IPL’s most recent rate proceeding, which last adjusted IPL’s rates in 1996. IPL is permitted to recover actual costs of purchased power and fuel consumed, subject to certain restrictions. This is accomplished through quarterly Fuel Adjustment Charges (“FAC”) 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 system owner members of the Midwest Independent Transmission System Operator, Inc. (“MISO”), 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 MISO market, IPL offers its generation and bids its demand into the market on an hourly basis. MISO 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 MISO region. MISO evaluates the market participants’ energy offers and demand bids to economically and reliably dispatch the entire MISO system. 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. As of December 31, 2012 and 2011, total loss contingencies accrued were $3.9 million and $4.2 million, respectively, which were included in Other Current Liabilities on the accompanying Consolidated Balance Sheets.

Concentrations of Risk

Substantially all of IPL’s customers are located within the Indianapolis area. In addition, approximately 63% 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 contract with the physical unit expires on December 14, 2015 and the contract with the clerical-technical unit expires February 10, 2014. Additionally, IPL has long-term coal contracts with six 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 8.4%, 8.6%, and 8.8% during 2012, 2011, and 2010, 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 4.0% during 2012, 2011 and 2010, respectively. Depreciation expense was $175.9 million, $166.3 million, and $160.5 million for the years ended December 31, 2012, 2011 and 2010, 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 had one interest rate swap agreement, which was terminated in November 2011. IPL entered into this agreement as a means of managing the interest rate exposure on a $40 million unsecured variable-rate debt instrument. The interest settlement amounts from the swap agreement prior to its termination were reported in the financial statements as a component of interest expense.

In addition, IPL has entered into contracts involving the physical delivery of energy and fuel. Because these contracts qualify for the normal purchases and normal 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.

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 Comprehensive Income. The income tax provision includes gross interest income/(expense) of $0.0 million, $0.0 million and $0.7 million for the years ended December 31, 2012, 2011 and 2010, 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.

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

Fair Value Measurement (Topic 820)

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update Topic 820 “Fair Value Measurement Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. Generally Accepted Accounting Principles and International Financial Reporting Standards.” The amendments in this update result in common fair value measurement and disclosure requirements under U.S. Generally Accepted Accounting Principles and International Financial Reporting Standards. Consequently, the amendments change the terminology used to describe many of the requirements under U.S. Generally Accepted Accounting Principles for measuring fair value and for disclosing information about fair value measurements. For many of the requirements, the FASB does not intend for the amendments in this update to result in a change in the application of the requirements in Topic 820. Some of the amendments clarify the FASB’s intent about the application of existing fair value measurement requirements. Other amendments change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. The amendments in this update were effective for IPALCO beginning January 1, 2012 and do not have a material effect on IPALCO’s consolidated financial statements.

Comprehensive Income (Topic 220)

In June 2011, the FASB issued Accounting Standards Update Topic 220 “Presentation of Comprehensive Income.” Under the amendments in this update, an entity has the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The amendments in this update were effective for IPALCO beginning January 1, 2012 and do not have a material effect on IPALCO’s consolidated financial statements.

3. 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, 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 unregulated entities.

IPL is also affected by the regulatory jurisdiction of the U.S. Environmental Protection Agency (“EPA”) 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.

Fuel Adjustment Charge and Authorized Annual Jurisdictional Net Operating Income

Environmental Compliance Cost Recovery Adjustment (“ECCRA”)

IPL may apply to the IURC for approval of a rate adjustment known as the Environmental Compliance Cost Recovery Adjustment (“ECCRA”) every six months to recover costs to install and/or upgrade Clean Coal Technology (“CCT”) equipment. The total amount of IPL’s CCT equipment approved for ECCRA recovery as of December 31, 2012 was $618.8 million. The jurisdictional revenue requirement that was approved by the IURC to be included in IPL’s rates for the six month period from September 2012 through February 2013 was $52.9 million. During the years ended December 31, 2012, 2011 and 2010, we made total CCT expenditures of $15.0 million, $64.4 million, and $53.1 million, respectively. The vast majority of such costs are recoverable through our ECCRA filings.

The EPA released the final Mercury and Air Toxics Standards (“MATS”) rule in December 2011 to address hazardous air pollutant emissions from certain electric generating power plants, and IPL management has developed a plan to comply with this new rule, as discussed in “Environmental Matters - MATS.” We will seek and expect to recover through our environmental rate adjustment mechanism, all operating and capital expenditures related to compliance with MATS; however, there can be no assurance that we will be successful in that regard.

Demand-Side Management and IPL’s Smart Energy Project

On December 9, 2009, the IURC issued a Generic Demand Side Management (“DSM”) Order that found that electric utilities subject to its jurisdiction must meet an overall goal of annual cost-effective DSM programs that reduce retail kilowatt hours (“kWh”) sales (as compared to what sales would have been excluding the DSM programs) of 2% per year by 2019 (beginning in 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 are administered by a third party administrator. Consequently, our DSM spending, both capital and operating, began increasing significantly in 2010 and will continue to increase significantly going forward, which will likely reduce our retail energy sales and the associated revenues.

Tree Trimming Practices Investigation

Renewable Power Purchase Agreements

MISO Real Time Revenue Sufficiency Guarantee

MISO Transmission Expansion Cost Sharing and FERC Order 1000

On July 21, 2011, the FERC issued Order 1000, amending the transmission planning and cost allocation requirements established in Order No. 890. Through Order 1000, the FERC:

(1) requires public utility transmission providers to participate in a regional transmission planning process and produce a regional transmission plan;

(3) removes the federal right of first refusal for certain transmission facilities; and

(4) seeks to improve coordination between neighboring transmission planning regions for interregional facilities.

4. UTILITY PLANT IN SERVICE

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

As of December 31,

2012 2011

(In Thousands)

Production
$ 2,708,826 $ 2,684,443

Transmission
249,577 238,762

Distribution
1,249,445 1,219,070

General plant
174,686 170,740

Total utility plant in service
$ 4,382,534 $ 4,313,015

Substantially all of IPL’s property is subject to a $965.3 million direct first mortgage lien, as of December 31, 2012, securing IPL’s first mortgage bonds. Property under capital leases as of December 31, 2012 and 2011 was insignificant. Total non-legal removal costs of utility plant in service at December 31, 2012 and 2011 were $575.9 million and $552.0 million, respectively and total legal removal costs of utility plant in service at December 31, 2012 and 2011 were $17.6 million and $16.6 million, respectively. Please see Note 7, “Asset Retirement Obligations” for further information.

IPL anticipates material additional costs to comply with various pending and final federal legislation and regulations and it is IPL’s intent to seek recovery of any additional costs. The majority of the expenditures for construction projects designed to reduce sulfur dioxides 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.

5. 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, 2012 and 2011, 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 $6.4 million and $5.9 million as of December 31, 2012 and 2011, respectively.

Investments in debt securities

As of December 31, 2012 and 2011, we had no investment in debt securities. Auction rate securities with a recorded value of $1.7 million as of December 31, 2010 were liquidated during the first quarter of 2011 at their face amount of $2.0 million. IPL’s investment in variable rate demand notes at December 31, 2010 consisted of the $40 Million aggregate principal amount of the City of Petersburg, Indiana, Pollution Control Refunding Revenue Bonds Adjustable Rate Tender Securities 1995B Series, Indianapolis Power & Light Company Project (“1995B Bonds”), which were redeemed in November 2011.

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 $24.8 million and $23.1 million as of December 31, 2012 and 2011, respectively.

Pension Assets

As of December 31, 2012, IPL’s pension assets are recognized at fair value in the determination of our net accrued pension obligation 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 11, “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 face value and the fair value of fixed rate and variable rate indebtedness for the periods ending:

December 31, 2012 December 31, 2011

Face Value Fair Value Face Value Fair Value

(In Millions)

Fixed-rate $ 1,765.3 $ 2,012.3 $ 1,765.3 $ 1,944.9

Variable-rate 50.0 50.0 64.0 64.0

Total indebtedness $ 1,815.3 $ 2,062.3 $ 1,829.3 $ 2,008.9

The difference between the face value and the carrying value of this indebtedness represents unamortized discounts of $4.2 million and $5.0 million at December 31, 2012 and December 31, 2011, respectively.

Fair Value Hierarchy

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. In accordance with ASC 820, we have categorized our financial assets and liabilities that are adjusted to fair value, based on the priority of the inputs to the valuation technique, following the three-level fair value hierarchy prescribed by ASC 820, 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.

IPALCO had one financial asset measured at fair value on a nonrecurring basis, which has been adjusted to fair value during the periods coved by this report due to impairment losses. In 2012, 2011 and 2010, we recorded impairments on this nonutility investment of $0.0 million, $1.6 million and 1.2 million, respectively, as 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 the fund 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 (Level 3). The recorded value for this asset was $1.9 million at both December 31, 2012 and December 31, 2011, respectively.

As of December 31, 2012 and 2011, all (excluding pension assets - see Note 11, “Pension and Other Postretirement Benefits”) 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. The following table presents those financial assets and liabilities:

Fair Value Measurements Using Level 3 at:

December 31, 2012 December 31, 2011

(In Thousands)

Financial assets:

Financial transmission rights
$ 2,419 $ 2,779

Total financial assets measured at fair value
$ 2,419 $ 2,779

Financial liabilities:

Other derivative liabilities
$ 170 $ 181

Total financial liabilities measured at fair value
$ 170 $ 181

The following table sets forth a reconciliation of financial instruments classified as Level 3 in the fair value hierarchy (note, amounts in this table indicate carrying values, which approximate fair values):

Derivative Financial Instruments, net Liability Investments in Debt Securities Total

(In Thousands)

Balance at January 1, 2011 $ (7,461) $ 41,669 $ 34,208

Unrealized gain recognized in OCI -   331 331

Unrealized losses recognized in earnings (15) -   (15)

Unrealized loss recognized as a regulatory liability (5,095) -   (5,095)

Issuances 8,085 -   8,085

Settlements 7,084 (42,000) (34,916)

Balance at December 31, 2011 $ 2,598 $ -   $ 2,598

Unrealized gain recognized in earnings 11 -   11

Issuances 8,832 -   8,832

Settlements (9,192) -   (9,192)

Balance at December 31, 2012 $ 2,249 $ -   $ 2,249

Valuation Techniques

Financial Transmission Rights

In connection with IPL’s participation in MISO, in the second quarter of each year IPL is granted financial instruments that can be converted into cash or Financial Transmission Rights (“FTRs”) based on IPL’s forecasted peak load for the period. FTRs are used in the MISO 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 MISO’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 these revenues or costs will be flowed through to customers through the FAC. As such, there is no impact on our Consolidated Statements of Comprehensive Income.

6. 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:

2012 2011 Recovery Period

(In Thousands)

Regulatory Assets

Current:

Deferred fuel
$ 1,332 $ 7,098 Through 2013 ⁽¹⁾

Environmental project costs 3,574 -   Through 2013 ⁽¹⁾

DSM program costs
-   326 Through 2012 ⁽¹⁾

Total current regulatory assets
4,906 7,424

Long-term:

Unrecognized pension and other postretirement benefit plan costs
341,471 306,923 Various

Income taxes recoverable from customers
44,259 49,525 Various

Deferred MISO costs
89,479 80,367 To be determined ⁽²⁾

Unamortized Petersburg Unit 4 carrying charges and certain other costs
14,803 15,466 Through 2026 ⁽¹⁾⁽³⁾

Unamortized reacquisition premium on debt
27,510 29,086 Over remaining life of debt

Environmental project costs
5,935 4,545 Through 2021 ⁽¹⁾

Other miscellaneous
382 20 To be determined ⁽²⁾

Total long-term regulatory assets
523,839 485,932

Total regulatory assets
$ 528,745 $ 493,356

Regulatory Liabilities

Current:

FTR's
$ 2,419 $ 2,779 Through 2013 ⁽¹⁾

Fuel related
2,500 2,500 Through 2013 ⁽⁴⁾

Environmental project costs
-   3,984 Through 2012 ⁽¹⁾

DSM program costs
5,556 -   Through 2013 ⁽¹⁾

Total current regulatory liabilities
10,475 9,263

Long-term:

ARO and accrued asset removal costs
559,760 536,920 Not Applicable

Unamortized investment tax credit
5,307 6,370 Through 2021

Fuel related
5,277 7,142 To be determined ⁽⁴⁾

Total long-term regulatory liabilities
570,344 550,432

Total regulatory liabilities
$ 580,819 $ 559,695

⁽¹⁾ Recovered (credited) per specific rate orders

⁽²⁾ Recovery is probable but timing not yet determined

⁽³⁾ Recovered with a current return

⁽⁴⁾ Per IURC Order, offset MISO transmission expansion costs beginning October 2011

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 generally permitted to recover underestimated fuel and purchased power costs in future rates through the FAC proceedings and therefore the costs are deferred when incurred and amortized into fuel expense in the same period that IPL’s rates are adjusted to reflect these costs. Deferred fuel was a regulatory asset of $1.3 million and $7.1 million as of December 31, 2012 and December 31, 2011, respectively. The deferred fuel asset decreased $5.8 million in 2012 as a result of IPL charging more for fuel than our actual costs to our jurisdictional customers.

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.

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 MISO Costs

These consist of administrative costs for transmission services, transmission expansion cost sharing, and certain other operational and administrative costs from the MISO 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. Recovery of these costs is believed to be probable, but not certain. See Note 3, “Regulatory Matters.”

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 Asset Retirement Obligations (“ARO”) costs that is currently being recovered in rates.

7. ASSET RETIREMENT OBLIGATIONS

ASC 410 “Asset Retirement and Environmental 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 410 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 estoppel. 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:

2012 2011

(In Millions)

Balance as of January 1
$ 16.6 $ 15.6

Accretion Expense
1.0 1.0

Balance as of December 31
$ 17.6 $ 16.6

As of December 31, 2012 and 2011, IPL did not have any assets that are legally restricted for settling its ARO liability.

8. 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, 2012.

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 total debt to total capitalization not in excess of 0.65 to 1, in order to pay dividends. As of December 31, 2012 and as of the filing of this report, IPL 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, 2012, 2011 and 2010, 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 now redeemable at par value, subject to certain restrictions, in whole or in part. 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, 2012, 2011 and 2010, preferred stock consisted of the following:

December 31, 2012 December 31,

Shares Outstanding Call Price 2012 2011 2010

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

9. INDEBTEDNESS

Restrictions on Issuance of Debt

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. IPL has approval from FERC to borrow up to $500 million of short-term indebtedness outstanding at any time through July 28, 2014. As of December 31, 2012, IPL also has remaining authority from the IURC to, among other things, issue up to $135 million in aggregate principal amount of long-term debt and refinance up to $110 million in existing indebtedness through December 31, 2013, and to have up to $250 million of long-term credit agreements and liquidity facilities outstanding at any one time. IPL also has 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. 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

Long-Term Debt

The following table presents our long-term indebtedness:


Series	Due	December 31,
Series	Due	2012		2011
		*(In Thousands)*
IPL First Mortgage Bonds (see below)
6.30%	July 2013	$	110,000	$	110,000
4.90%⁽²⁾	January 2016		30,000		30,000
4.90%⁽²⁾	January 2016		41,850		41,850
4.90%⁽²⁾	January 2016		60,000		60,000
5.40%⁽¹⁾	August 2017		24,650		24,650
3.875%⁽²⁾	August 2021		55,000		55,000
3.875%⁽²⁾	August 2021		40,000		40,000
4.55%⁽²⁾	December 2024		40,000		40,000
6.60%	January 2034		100,000		100,000
6.05%	October 2036		158,800		158,800
6.60%	June 2037		165,000		165,000
4.875%	November 2041		140,000		140,000
Unamortized discount - net			(1,096)		(1,125)
Total IPL first mortgage bonds			964,204		964,175
Total Long-term Debt - IPL			964,204		964,175
Long-term Debt - IPALCO:
7.25% Senior Secured Notes	April 2016		400,000		400,000
5.00% Senior Secured Notes	May 2018		400,000		400,000
Unamortized discount - net			(3,084)		(3,859)
Total Long-term Debt - IPALCO			796,916		796,141
Total Consolidated IPALCO Long-term Debt			1,761,120		1,760,316
Less: Current Portion of Long-term Debt			110,000		-
Net Consolidated IPALCO Long-term Debt		$	1,651,120	$	1,760,316

⁽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.

IPL First Mortgage Bonds and Indiana Finance Authority Bond Issuances

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 first mortgage lien securing indebtedness of $965.3 million as of December 31, 2012. 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, 2012.

$40.0 million aggregate principal amount of the City of Petersburg, Indiana Pollution Control Refunding Revenue Bonds Adjustable Rate Tender Securities, 1995B Series, Indianapolis Power & Light Company Project (“1995B Bonds”), variable rate, due 2023;
$20.0 million aggregate principal amount of the City of Petersburg, Indiana Solid Waste Disposal Revenue Bonds, 1994A Series, Indianapolis Power & Light Company Project, 5.90% Series, due 2024;
$30.0 million aggregate principal amount of the City of Petersburg, Indiana Solid Waste Disposal Revenue Bonds, 1995C Series, Indianapolis Power & Light Company Project, 5.95% Series, due 2029;
$20.0 million aggregate principal amount of the City of Petersburg, Indiana Solid Waste Disposal Revenue Bonds, 1996 Series, Indianapolis Power & Light Company Project, 6.375% Series, due 2029; and
$17.35 million aggregate principal amount of the Indiana Development Finance Authority’s Exempt Facilities Revenue Refunding Bonds, Series 1999, Indianapolis Power & Light Company Project, 5.95% Series, due 2030.

In the third quarter of 2012, we reclassified $110 million aggregate principal amount of 6.30% IPL first mortgage bonds due July 2013 from Long-term debt to Short-term debt on our Consolidated Balance Sheet as the debt is now due within one year. Management plans to refinance these bonds in 2013 with a new long-term issuance. In the unlikely event that we are unable to refinance these bonds on acceptable terms using a long-term issuance, IPL has available borrowing capacity on its revolving credit facility that could be used to satisfy the obligation.

IPALCO’s Senior Secured Notes

In May 2011, IPALCO completed the sale of $400 million of 5.00% Senior Secured Notes due May 1, 2018 (“2018 IPALCO Notes”) pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended. The 2018 IPALCO Notes were issued pursuant to an Indenture dated May 18, 2011, by and between IPALCO and The Bank of New York Mellon Trust Company, N.A., as trustee. These notes were subsequently exchanged for new notes with identical terms and like principal amounts, which were registered with the Securities and Exchange Commission pursuant to a registration statement on Form S-4 made effective in November 2011. In connection with this issuance, IPALCO conducted a tender offer to repurchase for cash any and all of IPALCO’s then outstanding $375 million of 8.625% (original coupon 7.625%) Senior Secured Notes due November 14, 2011 (“2011 IPALCO Notes”). As a result, IPALCO no longer has indebtedness with an interest rate that changes due to changes in its credit ratings. Additionally, IPALCO no longer has any debt with financial ratio maintenance covenants; although its articles of incorporation continue to contain the same financial ratios restricting dividend payments and intercompany loans to AES as were included in the 2011 IPALCO Notes.

Accounts Receivable Securitization

IPL formed IPL Funding Corporation (“IPL Funding”) in 1996 as a special-purpose entity to purchase receivables originated by IPL pursuant to a receivables purchase agreement between IPL and IPL Funding. IPL Funding also entered into a sale facility as defined in the Second Amended and Restated Receivables Sale Agreement, dated as of June 25, 2009, among IPL, IPL Funding Corporation, as the Seller, Indianapolis Power & Light Company, as the Collection Agent, Royal Bank of Scotland plc, as the Agent, the Liquidity Providers and Windmill Funding Corporation (“Receivables Sale Agreement”), which matured as extended on October 24, 2012. On October 22, 2012, under an amended and restated sale agreement, which matures on October 21, 2013, Citibank, N.A. and its affiliate, CRC Funding, LLC, replaced The Royal Bank of Scotland plc and Windmill Funding Corporation as Agent and Investor, respectively. The terms of the new arrangement to IPL are substantially the same as that of the previous arrangement. The Agent and Investor collectively, are referred to as the “Purchasers.” Pursuant to the terms of the Receivables Sale Agreement, 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 million. That amount was $50 million as of December 31, 2012 and December 31, 2011. 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. IPL Funding is included in the Consolidated Financial Statements of IPALCO.

IPL retains servicing responsibilities in its role as collection agent on the amounts due on the sold receivables. Per the terms of the purchase agreement IPL Funding pays IPL $0.6 million annually in servicing fees. Also in accordance with the purchase agreement, the receivables are purchased from IPL at a discounted rate of 3.5% as of December 31, 2012 facilitating IPL Funding’s ability to pay its expenses such as the servicing fee described above. No servicing asset or liability is recorded since the servicing fee paid to IPL approximates a market rate. However, the Purchasers assume the risk of collection on the purchased receivables without recourse to IPL in the event of a loss.

The total fees paid to the Purchasers recognized on the sales of receivables were $0.6 million, $0.6 million and $0.9 million for the years ended December 31, 2012, 2011 and 2010, respectively. These amounts were included in Other interest on the Consolidated Statements of Comprehensive Income.

IPL and IPL Funding have indemnified the Purchasers on an after-tax basis for any and all damages, losses, claims, etc., arising out of the facility, subject to certain limitations defined in the Receivables Sale Agreement, in the event that there is a breach of representations and warranties made with respect to the purchased receivables and/or certain other circumstances as described in the Receivables Sale Agreement.

Under the sale facility, if IPL fails to maintain a certain debt-to-capital ratio, it would constitute a “termination event.” As of December 31, 2012, IPL was in compliance with such covenant.

In the event that IPL’s long-term senior unsecured credit rating falls below BBB- at S&P and Baa3 at Moody’s Investors Service, 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 ($50 million as of December 31, 2012).

Line of Credit

In December 2010, IPL entered into a $250 million unsecured revolving credit facilities credit agreement (the “Credit Agreement”) with a syndication of banks. The Credit Agreement originally included two facilities: (i) a $209.4 million committed line of credit for letters of credit, working capital and general corporate purposes and (ii) a $40.6 million liquidity facility, which was dedicated for the sole purpose of providing liquidity for certain variable rate unsecured debt issued on behalf of IPL. As a result of the November 2011 IPL financing activity described above, the credit agreement was amended in February 2012 to eliminate the $40.6 million liquidity facility and to increase the committed line of credit for letters of credit, working capital and general corporate purposes by the same amount resulting in one facility in the amount of $250 million. The Credit Agreement matures on December 14, 2015 and bears interest at variable rates as defined in the Credit Agreement. Prior to execution, IPL and IPALCO had existing general banking relationships with the parties in this agreement. As of December 31, 2012 and 2011, IPL had $0.0 million and $14.0 million outstanding borrowings on the committed line of credit, respectively.

Debt Maturities

Maturities on long-term indebtedness subsequent to December 31, 2012, are as follows:


Year	Amount
	*(In Thousands)*
2013	$	110,000
2014		-
2015		-
2016		531,850
2017		24,650
Thereafter		1,098,800
Total	$	1,765,300

10. 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.

On May 10, 2011, the state of Indiana enacted House Bill 1004, which phases in over four years a 2% reduction to the state corporate income tax rate. Upon enactment of the law in the second quarter of 2011, an initial adjustment to the deferred tax balances was recorded according to the anticipated reversal of temporary differences. In the fourth quarter of each tax year until the tax rate becomes final with the 2016 tax year, the reversal of the temporary differences is to be re-evaluated and the appropriate adjustment to the deferred tax balances is to be recorded. The change in required deferred taxes on plant and plant-related temporary differences for 2012 tax year re-evaluation resulted in a reduction of the associated regulatory asset of $0.9 million. The change in required deferred taxes on non-property related temporary differences which are not probable to cause a reduction in future base customer rates resulted in a tax benefit of $0.2 million in 2012. The statutory state corporate income tax rate will be 7.75% for 2013.

The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the year ended December 31, 2012, 2011 and 2010:


	2012		2011			2010
	*(In Thousands)*
Unrecognized tax benefits at January 1	$	5,354	$	4,757	$	7,947
Gross increases - current period tax positions		997		753		753
Gross decreases - prior period tax positions		(213)		(156)		(3,943)
Unrecognized tax benefits at December 31	$	6,138	$	5,354	$	4,757

The unrecognized tax benefits at December 31, 2012, 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. The income tax provision includes interest expense/(income) of ($0.0 million), ($0.0 million), and $(0.7 million) million for the years ended December 31, 2012, 2011 and 2010, respectively.

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


	2012		2011		2010
	*(In Thousands)*
Charged to utility operating expenses:
Current income taxes:
Federal	$	55,201	$	54,377	$	61,999
State		16,641		16,539		18,818
Total current income taxes		71,842		70,916		80,817
Deferred income taxes:
Federal		(3,285)		(5,027)		(4,697)
State		204		(1,608)		1,539
Total deferred income taxes		(3,081)		(6,635)		(3,158)
Net amortization of investment credit		(1,599)		(1,672)		(1,720)
Total charge to utility operating expenses		67,162		62,609		75,939
Charged to other income and deductions:
Current income taxes:
Federal		(15,646)		(19,639)		(19,239)
State		(4,127)		(5,255)		(5,291)
Total current income taxes		(19,773)		(24,894)		(24,530)
Deferred income taxes:
Federal		251		(476)		(692)
State		59		(106)		(188)
Total deferred income taxes		310		(582)		(880)
Net credit to other income and deductions		(19,463)		(25,476)		(25,410)
Total federal and state income tax provisions	$	47,699	$	37,133	$	50,529


	2012	2011	2010

Federal statutory tax rate	35.0%	35.0%	35.0%
State income tax, net of federal tax benefit	7.2	6.7	7.7
Amortization of investment tax credits	(1.4)	(1.8)	(1.4)
Preferred dividends of subsidiary	1.0	1.2	0.9
Depreciation flow through and amortization	1.4	1.3	0.5
Manufacturers’ Production Deduction (Sec. 199)	(3.7)	(3.5)	(3.4)
Change in tax reserves	0.0	0.0	(0.3)
Other - net	1.4	0.4	0.7
Effective tax rate	40.9%	39.3%	39.7%

Internal Revenue Code Section 199 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 9% of qualifying production activity beginning in 2010 and thereafter. The tax benefit associated with the Internal Revenue Code Section 199 domestic production deduction for 2011 and 2010 was $3.1 million and $4.3 million, respectively. The benefit for 2012 is estimated to be $4.3 million.

The significant items comprising IPALCO’s net accumulated deferred tax liability recognized on the audited Consolidated Balance Sheets as of December 31, 2012 and 2011, are as follows:


	2012		2011
	*(In Thousands)*
Deferred tax liabilities:
Relating to utility property, net	$	475,517	$	483,261
Regulatory assets recoverable through future rates		197,909		181,593
Other		12,674		15,117
Total deferred tax liabilities		686,100		679,971
Deferred tax assets:
Investment tax credit		3,216		3,855
Regulatory liabilities including ARO		229,025		220,491
Employee benefit plans		114,420		106,243
Other		8,389		10,573
Total deferred tax assets		355,050		341,162
Accumulated net deferred tax liability		331,050		338,809
Less: Net current deferred tax asset		(10,809)		(12,352)
Accumulated deferred income taxes - net	$	341,859	$	351,161

11. PENSION AND OTHER POSTRETIREMENT BENEFITS

Approximately 85% of IPL’s active employees are covered by the Employees’ Retirement Plan of Indianapolis Power & Light Company (“Defined Benefit Pension Plan”) as well as the Employees’ Thrift Plan of Indianapolis Power & Light Company (“Thrift Plan”). The Defined Benefit Pension Plan is a qualified defined benefit plan, while the Thrift Plan is a qualified defined contribution plan. The remaining 15% of active employees are covered by the AES Retirement Savings Plan. The AES Retirement Savings Plan (“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 (“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 (“Supplemental Retirement Plan”). The total number of participants in the plan as of December 31, 2012 was 26. The plan is closed to new participants.

In addition, IPL provides postretirement health care benefits to certain active or retired employees and the spouses of certain active or retired employees. Approximately 183 active employees and 71 retirees (including spouses) were receiving such benefits or entitled to future benefits as of January 1, 2012. The plan is unfunded. These postretirement health care benefits and the related obligation were not material to the consolidated financial statements in the periods covered by this report.

The following table presents information relating to the Pension Plans:


	Pension benefits as of December 31,
	2012		2011
	*(In Thousands)*
Change in benefit obligation:
Projected benefit obligation at beginning Measurement Date (see below)	$	679,261	$	607,408
Service cost		7,986		7,234
Interest cost		30,232		31,828
Actuarial (gain) loss		69,099		62,587
Amendments (primarily increases in pension bands)		7,349		82
Benefits paid		(30,327)		(29,878)
Projected benefit obligation at ending Measurement Date		763,600		679,261
Change in plan assets:
Fair value of plan assets at beginning Measurement Date		426,384		412,611
Actual return on plan assets		50,713		6,305
Employer contributions		48,312		37,345
Benefits paid		(30,327)		(29,877)
Fair value of plan assets at ending Measurement Date		495,082		426,384
Funded status	$	(268,518)	$	(252,877)
Amounts recognized in the statement of financial position under ASC 715:
Current liabilities	$	-	$	-
Noncurrent liabilities		(268,518)		(252,877)
Net amount recognized	$	(268,518)	$	(252,877)
Sources of change in regulatory assets⁽¹⁾:
Prior service cost (credit) arising during period	$	7,350	$	82
Net loss (gain) arising during period		50,938		88,450
Amortization of prior service (cost) credit		(4,246)		(4,346)
Amortization of gain (loss)		(19,471)		(13,306)
Total recognized in regulatory assets⁽¹⁾	$	34,571	$	70,880
Total amounts included in accumulated other comprehensive income (loss)		NA⁽¹⁾		NA⁽¹⁾
Amounts included in regulatory assets and liabilities⁽¹⁾
Net loss (gain)	$	314,557	$	283,089
Prior service cost (credit)		33,836		30,732
Total amounts included in regulatory assets (liabilities)	$	348,393	$	313,821

⁽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 $268.5 million is classified as a long-term liability.

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

Pension benefits as of December 31,

2012 2011

(In Thousands)

Benefit obligation
$ 763,600 $ 679,261

Plan assets
495,082 426,384

Benefit obligation in excess of plan assets
$ 268,518 $ 252,877

IPL’s total accumulated benefit obligation in excess of plan assets was $251.5 million as of December 31, 2012 ($250.0 million Defined Benefit Pension Plan and $1.5 million Supplemental Retirement Plan).

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

Pension benefits as of December 31,

2012 2011

(In Thousands)

Accumulated benefit obligation
$ 746,542 $ 664,212

Plan assets
495,082 426,384

Accumulated benefit obligation in excess of plan assets
$ 251,460 $ 237,828

Pension Benefits and Expense

The Pension Plans incurred a net actuarial loss in 2012 of $50.9 million, comprised of two parts (net): (1) $18.2 million of pension asset actuarial gain, which is primarily due to the higher than expected return on assets in 2012, and (2) $69.1 million of pension liability actuarial loss, which is primarily due to a decrease in the discount rate that is used to value pension liabilities. The Pension Plans have a cumulative unrecognized net loss of $314.6 million, which has accumulated 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 10.4 years based on estimated demographic data as of December 31, 2012. The projected benefit obligation of $763.6 million, less the fair value of assets of $495.1 million results in a funded status of ($268.5 million) at December 31, 2012.


	Pension benefits for years ended December 31,
	2012		2011		2010
	*(In Thousands)*
Components of net periodic benefit cost:
Service cost	$	7,986	$	7,234	$	6,590
Interest cost		30,232		31,828		31,577
Plan settlements		-		-		204
Expected return on plan assets		(32,554)		(32,168)		(29,250)
Amortization of prior service cost		4,246		4,346		3,476
Recognized actuarial loss		19,471		13,306		11,838
Total pension cost		29,381		24,546		24,435
Less: amounts capitalized		2,497		2,258		2,321
Amount charged to expense	$	26,884	$	22,288	$	22,114
Rates relevant to each year's expense calculations:
Discount rate - defined benefit pension plan		4.56%		5.38%		5.93%
Discount rate - supplemental retirement plan		4.37%		5.09%		5.27%/5.08% ⁽¹⁾
Expected return on defined benefit pension plan assets		7.50%		7.75%		8.00%
Expected return on supplemental retirement plan assets		7.50%		7.75%		8.00%
⁽¹⁾ 5.27% for the period January 1, 2010 thru May 31, 2010, 5.08% for the settlement on May 31, 2010 and the period June 1, 2010 through December 31, 2010.

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 2012, pension expense was determined using an assumed long-term rate of return on plan assets of 7.50%. As of the December 31, 2012 measurement date, IPL decreased the discount rate from 4.56% to 3.80% for the Defined Benefit Pension Plan and decreased the discount rate from 4.37% to 3.41% for the Supplemental Retirement Plan. The discount rate assumption affects the pension expense determined for 2013. In addition, IPL decreased the expected long-term rate of return on plan assets from 7.50% to 7.25% effective January 1, 2013. The expected long-term rate of return assumption affects the pension expense determined for 2013. The effect on 2013 total pension expense of a 25 basis point increase and decrease in the assumed discount rate is ($1.7 million) and $1.8 million, respectively. The effect on 2013 total pension expense of a 100 basis point increase and decrease in the expected long-term rate of return on plan assets is ($5.3 million) and $5.3 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 2013 plan year are $22.7 million and $4.9 million, respectively (Defined Benefit Pension Plan of $22.6 million and $4.9 million, respectively; and the Supplemental Retirement Plan of $0.1 million and $0.0 million, respectively).

Pension Assets

Fair Value Measurements

Fair value is defined under ASC 820 as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). The fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3) as discussed in Note 2. IPL had a transfer of pension assets with a fair value of $20.6 million from Level 1 to Level 2 in January 2011. There were no transfers of pension assets between Level 1 and Level 2 in 2012. IPL’s policy regarding asset transfers is to record the transfer on the transfer date.

Purchases and sales of securities are recorded on a trade-date basis. Interest income is recorded as earned. Dividends are recorded on the ex-dividend date. Net appreciation includes the Plan’s gains and losses on investments bought and sold, as well as held, during the year.

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

Other than common/collective trust funds, hedge funds and non U.S. government fixed income securities, all the Plan’s investments are actively traded on an open market and are categorized as Level 1 in the fair value hierarchy.
All of the Plan’s hedge funds report the net asset value (NAV) from the funds audited financial statements of the Plan’s interest based on the fair value of the hedge funds’ underlying investments as determined in accordance with the American Institute of Certified Public Accountants’ Accounting and Auditing Guide for Investment Companies.
Investments in hedge funds are valued using the observable NAV of the Plan’s interest as of December 31, 2012, provided by the underlying hedge fund. The Plan may redeem its ownership interests in hedge funds at NAV, with 60 days’ notice, on either quarterly or semiannual terms.
The Plan’s investments in common/collective trust funds are valued at the NAV of the units of the common/collective trust funds held by the Plan at year-end. The Plan may redeem its units of the common/collective trust funds at NAV daily. These NAVs have been determined based on the market value of the underlying equity securities held by the common/collective trust funds.
The Plan’s investments in corporate bonds are valued from third-party pricing sources but they generally do not represent transaction prices for the identical security in an active market nor does it represent data obtained from an exchange.
The Fund’s investments in hedge funds, common/collective trust funds and non U.S. government fixed income securities have been recorded at fair value and are all categorized as Level 2 investments in the fair value hierarchy.

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 assumptions 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⁾
Liability Hedging Portfolio ⁽¹⁾
Liability Manager Fixed Income		10.0%	16.0%	40.0%	5.3%	3.6%
Core Fixed Income		10.0%	16.0%	22.0%	5.4%	3.8%

Growth Portfolio
High Yield Fixed Income		3.0%	8.0%	13.0%	8.9%	9.5%
U.S. Large Cap Equity		20.0%	30.0%	40.0%	10.4%	15.4%
U.S. Mid Cap Equity		2.5%	5.0%	7.5%	11.2%	17.1%
U.S. Small Cap Equity		2.5%	5.0%	7.5%	12.0%	19.9%
International Equity		5.0%	10.0%	15.0%	10.3%	17.7%
REIT		0.0%	5.0%	10.0%	10.4%	18.8%
Hedge Funds ⁽⁴⁾		0.0%	5.0%	10.0%	9.3%	8.4%

⁽¹⁾Upper limit for all assets held in the Liability Hedging Portfolio is 40%
⁽²⁾Expected long-term annual return
⁽³⁾Expected standard deviation
⁽⁴⁾Alternative investments (combined) not to exceed 10%

The fair values of the pension plan assets at December 31, 2012, by asset category are as follows:


		Fair Value Measurements at December 31, 2012 (in thousands)

				Quoted Prices in Active Markets for Identical Assets		Significant Observable Inputs

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

Cash and cash equivalents	$	42,139	$	42,139	$	-	9%

Equity Securities:
Common stock		96,347		96,347		-	19%
REIT		22,330		22,330		-	5%

Fixed Income Securities:
Government debt securities		25,170		25,170		-	5%
Corporate debt securities		148,553		-		148,553	30%

Other types of investments:
Mutual fund - Equities		51,154		51,154		-	10%
Mutual fund - Debt		3,626		3,626		-	1%
Mutual fund - REIT		174		174		-	0%
Hedge fund - Equity		35,498		-		35,498	7%
Common/collective trust funds		70,091		-		70,091	14%

Total	$	495,082	$	240,940	$	254,142	100%

The fair values of the pension plan assets at December 31, 2011, by asset category are as follows:

Fair Value Measurements at December 31, 2011 (in thousands)

Quoted Prices in Active Markets for Identical Assets Significant Observable Inputs

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

Cash and cash equivalents
$ 14,984 $ 14,984 $ -   4%

Equity Securities:

Common stock
99,152 99,152 -   23%

Preferred stock
718 718 -   0%

REIT
20,340 20,340 -   5%

Fixed Income Securities:

Government debt securities
30,542 30,542 -   7%

Corporate debt securities
77,838 -   77,838 18%

Other debt securities
49,650 -   49,650 12%

Other types of investments:

Mutual fund - Equities
38,054 38,054 -   9%

Mutual fund - Debt
1,748 1,748 -   0%

Mutual fund - REIT
149 149 -   0%

Hedge fund - Equity
32,432 -   32,432 8%

Common/collective trust funds (1)
60,777 -   60,777 14%

Total $ 426,384 $ 205,687 $ 220,697 100%

⁽¹⁾On January 26, 2011, we transferred Level 1 securities with a fair value of $20.6 million to a common/collective trust fund. This resulted in a transfer of $20.6 million from Level 1 to Level 2 because the fair value of the interest in the common/collective fund is classified as Level 2 within the fair value hierarchy.

Pension Funding

We contributed $48.3 million, $37.3 million, and $28.7 million to the Pension Plans in 2012, 2011, and 2010, respectively. 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 2013.

From an ERISA funding perspective, IPL’s funding target liability shortfall is estimated to be approximately $104 million as of January 1, 2013. 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 funding normal cost is expected to be about $8.1 million in 2013, which includes $3.1 million for plan expenses. 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 elected to fund $49.6 million in January, 2013 which satisfies all funding requirements for the calendar year 2013. IPL’s funding policy for the Pension Plans is to contribute annually no less than the minimum required by applicable law, and no 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, 2012 and 2011 were $30.3 million and $29.9 million respectively. Projected benefit payments are expected to be paid out of the Pension Plans as follows:


Year	Pension Benefits
	*(In Thousands)*
2013	$	51,238
2014		34,665
2015		36,274
2016		37,557
2017		38,962
2018 through 2022 (in total)		216,051

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 85% of IPL’s active employees are covered by the Thrift Plan, a qualified defined contribution plan. All union new hires are covered under the Thrift Plan, while non-union new hires are covered by the RSP.

Participants elect to make contributions to the Thrift Plan based on a percentage of their base compensation. Each participant’s contribution is matched up to certain thresholds. The IBEW clerical-technical union new hires receive an annual lump sum company contribution into the Thrift Plan in addition to the IPL match. Employer contributions to the Thrift Plan were $2.9 million, $2.9 million and $2.9 million for 2012, 2011 and 2010, respectively.

The AES Retirement Savings Plan

Approximately 15% of IPL’s active employees are covered by the RSP, a qualified defined contribution plan containing a profit sharing component. 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 $2.2 million, $2.2 million and $1.1 million for 2012, 2011 and 2010, respectively.

12. COMMITMENTS AND CONTINGENCIES

Legal Loss Contingencies

IPL is a defendant in approximately twenty 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”, which means 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’s 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. Additionally, several cases have been dismissed by the plaintiffs in the past few years without requiring a settlement. We are unable to estimate the number of, the effect of, or losses of 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.

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 Loss Contingencies

New Source Review

In October 2009, IPL received a Notice of Violation (“NOV”) and Finding of Violation from the EPA pursuant to the Federal Clean Air Act Section 113(a). The NOV alleges violations of the Federal Clean Air Act at IPL’s three coal-fired electric generating facilities dating back to 1986. The alleged violations primarily pertain to the Prevention of Significant Deterioration and nonattainment New Source Review requirements under the Federal Clean Air Act. Since receiving the letter, IPL management has met with the EPA staff regarding possible resolutions of the 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, install additional pollution control technology on coal-fired electric generating units, retire existing generating units, and invest in additional environmental projects. A similar outcome in this case could have a material impact on our business. We would seek recovery of any operating or capital expenditures related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that we would be successful in that regard. IPL has recorded a contingent liability related to this matter.

13. SALE OF OATSVILLE COAL RESERVE

In June 2011, IPL completed the sale of coal rights and a small piece of land in Indiana (the “Oatsville Coal Reserve”) for a sale price of $13.5 million. The property had a carrying value of $0.2 million. The total gain recognized on the sale of $13.3 million was included in Miscellaneous Income and (Deductions) - Net under Other Income and (Deductions) in the accompanying Consolidated Statements of Comprehensive Income.

14. 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 $5 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. The cost to IPL of coverage under this program was approximately $2.9 million, $3.2 million, and $4.0 million in 2012, 2011, and 2010, respectively, and is recorded in Other operating expenses on the accompanying Consolidated Statements of Comprehensive Income. As December 31, 2012 and 2011, we had prepaid approximately $1.5 million and $1.5 million, respectively, which is 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. The cost of coverage under this program was approximately $22.8 million, $22.6 million, and $21.0 million in 2012, 2011 and 2010, respectively, and is recorded in Other operating expenses on the accompanying Consolidated Statements of Comprehensive Income. As of December 31, 2012 and 2011 we had prepaid approximately $2.4 million and $2.1 million for coverage under this plan, which is 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. 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 balance under this agreement of $4.1 million as of December 31, 2012, which is recorded in Prepayments and other current assets on the accompanying Consolidated Balance Sheets. IPALCO had a payable balance under this agreement of $2.4 million as of December 31, 2011, which is recorded in Other current liabilities on the accompanying Consolidated Balance Sheets.

Long-term Compensation Plan

During 2012, 2011 and 2010, 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 and AES restricted stock units and options to purchase shares of AES common stock. All such components vest in thirds over a three year period and the terms of the AES restricted stock unit issued prior to 2011 also include a two year minimum holding period after the awards vest. Awards made in 2011 and for subsequent years will not be subject to a two year holding period. In addition, the performance units payable in cash are subject to certain AES performance criteria. Total deferred compensation expense recorded during 2012, 2011 and 2010 was $0.8 million, $1.2 million and $1.7 million, respectively and was included in Other Operating Expenses on IPALCO’s Consolidated Statements of Comprehensive 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 11, “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 RSP.

15. 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 $400 million of 7.25% Senior Secured Notes due April 1, 2016 (“2016 IPALCO Notes”) and the 2018 IPALCO Notes; approximately $6.4 million and $6.7 million of nonutility cash and cash equivalents, as of December 31, 2012 and 2011, respectively; short-term and long-term nonutility investments of $4.7 million and $4.6 million at December 31, 2012 and 2011, 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, 2012 and 2011. 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):

	2012			2011			2010
	Electric	All Other	Total	Electric	All Other	Total	Electric	All Other	Total

Operating revenues	$1,230	-	$1,230	$1,172	-	$1,172	$1,145	-	$1,145
Depreciation and amortization	177	-	177	167	-	167	164	-	164
Income taxes	68	(20)	48	66	(29)	37	76	(25)	51
Net income	104	(32)	72	105	(44)	61	120	(40)	80
Utility plant - net of depreciation	2,426	-	2,426	2,441	-	2,441	2,362	-	2,362
Capital expenditures	130	-	130	210	-	210	164	-	164

16. QUARTERLY RESULTS (UNAUDITED)

Operating results for the years ended December 31, 2012 and 2011, by quarter, are as follows:

2012

March 31 June 30 September 30 December 31

(In Thousands)

Utility operating revenue
$ 301,104 $ 292,659 $ 324,478 $ 311,536

Utility operating income
37,951 34,583 50,227 40,139

Net income
16,029 12,291 27,541 16,135


	2011
	March 31		June 30		September 30		December 31
	*(In Thousands)*
Utility operating revenue	$	289,165	$	279,943	$	320,550	$	282,266
Utility operating income		35,726		36,137		48,451		32,339
Net income		13,430		12,534		26,120		8,491

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 Shareholders 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, 2012 and 2011, and the related consolidated statements of comprehensive income, common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2012. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule 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, 2012 and 2011, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, 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 26, 2013


INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY
Consolidated Statements of Comprehensive Income
For the Years Ended December 31, 2012, 2011 and 2010
*(In Thousands)*

	2012		2011		2010

OPERATING REVENUES	$	1,229,777	$	1,171,924	$	1,144,903

OPERATING EXPENSES:
Operation:
Fuel		340,647		334,385		322,541
Other operating expenses		217,124		203,286		196,166
Power purchased		121,238		90,159		55,456
Maintenance		99,568		119,152		118,883
Depreciation and amortization		176,843		167,245		164,102
Taxes other than income taxes		44,295		42,435		39,378
Income taxes - net		67,162		62,609		75,939
Total operating expenses		1,066,877		1,019,271		972,465
OPERATING INCOME		162,900		152,653		172,438

OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used during construction		1,087		3,950		3,990
Miscellaneous income and (deductions) - net		(1,457)		9,431		(1,693)
Income tax (expense) benefit applicable to nonoperating income		(654)		(3,799)		252
Total other income and (deductions) - net		(1,024)		9,582		2,549

INTEREST AND OTHER CHARGES:
Interest on long-term debt		54,435		55,231		53,363
Other interest		1,913		1,786		2,136
Allowance for borrowed funds used during construction		(1,059)		(2,674)		(2,437)
Amortization of redemption premiums and expense on debt		2,458		2,494		2,137
Total interest and other charges - net		57,747		56,837		55,199
NET INCOME		104,129		105,398		119,788

LESS: PREFERRED DIVIDEND REQUIREMENTS		3,213		3,213		3,213

NET INCOME APPLICABLE TO COMMON STOCK	$	100,916	$	102,185	$	116,575

ADD OTHER COMPREHENSIVE INCOME:
Unrealized loss on available for sale investment		-		-		(197)
Gain on sale of available for sale investment		-		197		-

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK	$	100,916	$	102,382	$	116,378

See notes to consolidated financial statements.


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

	December 31, 2012		December 31, 2011
ASSETS
UTILITY PLANT:
Utility plant in service	$	4,382,534	$	4,313,015
Less accumulated depreciation		2,043,540		1,940,633
Utility plant in service - net		2,338,994		2,372,382
Construction work in progress		70,169		52,429
Spare parts inventory		15,445		15,534
Property held for future use		1,002		1,002
Utility plant - net		2,425,610		2,441,347

OTHER ASSETS:
At cost, less accumulated depreciation		1,123		944

CURRENT ASSETS:
Cash and cash equivalents		12,042		20,606
Accounts receivable and unbilled revenue (less allowance for doubtful accounts of $2,047 and $2,081, respectively)		141,508		136,007
Fuel inventories - at average cost		45,236		52,694
Materials and supplies - at average cost		57,257		54,137
Deferred tax asset - current		10,782		12,323
Regulatory assets		4,906		7,424
Prepayments and other current assets		22,045		16,474
Total current assets		293,776		299,665

DEFERRED DEBITS:
Regulatory assets		523,839		485,932
Miscellaneous		22,507		22,344
Total deferred debits		546,346		508,276
TOTAL	$	3,266,855	$	3,250,232


CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common shareholder’s equity:
Common stock	$	324,537	$	324,537
Paid in capital		13,536		13,114
Retained earnings		448,162		443,946
Total common shareholder’s equity		786,235		781,597
Cumulative preferred stock		59,784		59,784
Long-term debt (Note 9)		854,204		964,175
Total capitalization		1,700,223		1,805,556

CURRENT LIABILITIES:
Short-term debt (Note 9)		160,000		64,000
Accounts payable		76,282		81,175
Accrued expenses		24,226		24,049
Accrued real estate and personal property taxes		19,405		17,460
Regulatory liabilities		10,475		9,263
Accrued interest		21,362		20,391
Customer deposits		24,796		23,142
Other current liabilities		10,910		11,923
Total current liabilities		347,456		251,403

DEFERRED CREDITS AND OTHER LONG-TERM LIABILITIES:
Accumulated deferred income taxes - net		341,914		351,510
Non-current income tax liability		6,138		5,354
Regulatory liabilities		570,344		550,432
Unamortized investment tax credit		8,162		9,761
Accrued pension and other postretirement benefits		274,017		258,171
Miscellaneous		18,601		18,045
Total deferred credits and other long-term liabilities		1,219,176		1,193,273

COMMITMENTS AND CONTINGENCIES (Note 12)
TOTAL	$	3,266,855	$	3,250,232

See notes to consolidated financial statements.


INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY
Consolidated Statements of Cash Flows
For the Years Ended December 31, 2012, 2011 and 2010
*(In Thousands)*

	2012		2011		2010

CASH FLOWS FROM OPERATIONS:
Net income	$	104,129	$	105,398	$	119,788
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		176,800		167,216		161,300
Amortization of regulatory assets		2,206		2,529		6,777
Deferred income taxes and investment tax credit adjustments - net		(4,666)		(8,306)		(4,884)
Termination of interest rate swap		-		(12,572)		-
Allowance for equity funds used during construction		(881)		(3,772)		(3,795)
Gains on sales of assets		-		(13,320)		-
Change in certain assets and liabilities:
Accounts receivable		(5,501)		4,531		(13,461)
Fuel, materials and supplies		4,339		(17,938)		(764)
Income taxes receivable or payable		(5,825)		8,364		(6,410)
Financial transmission rights		360		(621)		(1,214)
Accounts payable and accrued expenses		(2,401)		3,153		19,785
Accrued real estate and personal property taxes		1,945		648		(6,819)
Accrued interest		971		2,577		354
Pension and other postretirement benefit expenses		15,846		58,883		13,473
Short-term and long-term regulatory assets and liabilities		(43,514)		(91,761)		(32,475)
Other - net		1,472		5,091		5,703
Net cash provided by operating activities		245,280		210,100		257,358

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(129,747)		(209,851)		(163,652)
Proceeds from sales and maturities of short-term investments		-		2,000		-
Proceeds from sales of assets		1		13,467		-
Grants under the American Recovery and Reinvestment act of 2009		6,028		7,919		5,130
Asset removal costs		(9,251)		(14,896)		(3,035)
Other		(6,790)		(3,969)		(7,396)
Net cash used in investing activities		(139,759)		(205,330)		(168,953)

CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt borrowings		73,000		138,000		9,508
Short-term debt repayments		(87,000)		(124,000)		(40,000)
Long-term borrowings		-		234,873		40,000
Retirement of long-term debt		-		(169,724)		-
Dividends on common stock		(96,700)		(80,603)		(111,522)
Dividends on preferred stock		(3,213)		(3,213)		(3,213)
Other		(172)		(2,750)		(1,640)
Net cash used in financing activities		(114,085)		(7,417)		(106,867)
Net change in cash and cash equivalents		(8,564)		(2,647)		(18,462)
Cash and cash equivalents at beginning of period		20,606		23,253		41,715
Cash and cash equivalents at end of period	$	12,042	$	20,606	$	23,253

Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized)	$	54,254	$	53,686	$	52,114
Income taxes	$	78,402	$	66,350	$	86,900

See notes to consolidated financial statements.


INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY
Consolidated Statements of Common Shareholder’s Equity
*(In Thousands)*

	Common Stock		Paid in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
2010
Beginning Balance	$	324,537	$	11,610	$	417,311	$		$	753,458
Comprehensive Income attributable to common stock:
Net income applicable to common stock						116,575				116,575
Unrealized loss on available for sale investment (net of income tax benefit of $134)								(197)		(197)
Cash dividends declared on common stock						(111,522)				(111,522)
Contributions from IPALCO				969						969
Balance at December 31, 2010	$	324,537	$	12,579	$	422,364	$	(197)	$	759,283
2011
Comprehensive Income attributable to common stock:
Net income applicable to common stock						102,185				102,185
Gain on sale of available for sale investment (net of income tax expense of $134)								197		197
Cash dividends declared on common stock:						(80,603)				(80,603)
Contributions from IPALCO				535						535
Balance at December 31, 2011	$	324,537	$	13,114	$	443,946	$	-	$	781,597
2012
Comprehensive Income attributable to common stock:
Net income applicable to common stock						100,916				100,916
Cash dividends declared on common stock						(96,700)				(96,700)
Contributions from IPALCO				422						422
Balance at December 31, 2012	$	324,537	$	13,536	$	448,162	$	-	$	786,235

See notes to consolidated financial statements.

INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY
Notes to Consolidated Financial Statements
For the Years Ended December 31, 2012, 2011 and 2010

1. ORGANIZATION

Indianapolis Power & Light Company (“IPL”) 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”). IPALCO is a wholly-owned subsidiary of The AES Corporation (“AES”). IPALCO was acquired by AES in March 2001. 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 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 two combustion turbines at a separate site that are all used for generating electricity. IPL’s net electric generation capacity for winter is 3,492 megawatts and net summer capacity is 3,353 megawatts.

IPL Funding Corporation (“IPL Funding”) 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 third party purchasers in exchange for cash (see Accounts Receivable Securitization in Note 9, “Indebtedness”).

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 U.S. (“GAAP”) 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. Certain costs for shared resources amongst IPL and IPALCO, such as labor and benefits, are allocated to each entity based on allocation methodologies that management believes to be reasonable. We have evaluated subsequent events through the 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

Revenues and Accounts Receivable

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 nearly all residential, small commercial and industrial 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, 2012 and 2011, customer accounts receivable include unbilled energy revenues of $50.6 million and $44.1 million, respectively, on a base of annual revenue of $1.2 billion in each of 2012 and 2011. Our provision for doubtful accounts included in Other operating expenses on the accompanying Consolidated Statements of Comprehensive Income was $3.4 million, $3.7 million and $4.0 million for the years ended December 31, 2012, 2011 and 2010, respectively.

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. As of December 31, 2012 and 2011, total loss contingencies accrued were $3.9 million and $4.2 million, respectively, which were included in Other Current Liabilities on the accompanying Consolidated Balance Sheets.

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 had one interest rate swap agreement, which was terminated in November 2011. IPL entered into this agreement as a means of managing the interest rate exposure on a $40 million unsecured variable-rate debt instrument. The interest settlement amounts from the swap agreement prior to its termination were reported in the financial statements as a component of interest expense.

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.

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 Comprehensive Income. The income tax provision includes gross interest income/(expense) of $0.0 million, $0.0 million and $0.7 million for the years ended December 31, 2012, 2011 and 2010, 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.

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

Fair Value Measurement (Topic 820)

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update Topic 820 “Fair Value Measurement Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. Generally Accepted Accounting Principles and International Financial Reporting Standards.” The amendments in this update result in common fair value measurement and disclosure requirements under U.S. Generally Accepted Accounting Principles and International Financial Reporting Standards. Consequently, the amendments change the terminology used to describe many of the requirements under U.S. Generally Accepted Accounting Principles for measuring fair value and for disclosing information about fair value measurements. For many of the requirements, the FASB does not intend for the amendments in this update to result in a change in the application of the requirements in Topic 820. Some of the amendments clarify the FASB’s intent about the application of existing fair value measurement requirements. Other amendments change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. The amendments in this update were effective for IPL beginning January 1, 2012 and do not have a material effect on IPL’s consolidated financial statements.

Comprehensive Income (Topic 220)

In June 2011, the FASB issued Accounting Standards Update Topic 220 “Presentation of Comprehensive Income.” Under the amendments in this update, an entity has the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The amendments in this update were effective for IPL beginning January 1, 2012 and do not have a material effect on IPL’s consolidated financial statements.

3. REGULATORY MATTERS

General

Fuel Adjustment Charge and Authorized Annual Jurisdictional Net Operating Income

Environmental Compliance Cost Recovery Adjustment (“ECCRA”)

IPL may apply to the IURC for approval of a rate adjustment known as the Environmental Compliance Cost Recovery Adjustment (“ECCRA”) every six months to recover costs to install and/or upgrade Clean Coal Technology (“CCT”) equipment. The total amount of IPL’s CCT equipment approved for ECCRA recovery as of December 31, 2012 was $618.8 million. The jurisdictional revenue requirement that was approved by the IURC to be included in IPL’s rates for the six month period from September 2012 through February 2013 was $52.9 million. During the years ended December 31, 2012, 2011 and 2010, we made total CCT expenditures of $15.0 million, $64.4 million, and $53.1 million, respectively. The vast majority of such costs are recoverable through our ECCRA filings.

The EPA released the final Mercury and Air Toxics Standards (“MATS”) rule in December 2011 to address hazardous air pollutant emissions from certain electric generating power plants, and IPL management has developed a plan to comply with this new rule, as discussed in “Environmental Matters - MATS.” We will seek and expect to recover through our environmental rate adjustment mechanism, all operating and capital expenditures related to compliance with MATS; however, there can be no assurance that we will be successful in that regard.

Demand-Side Management and IPL’s Smart Energy Project

Tree Trimming Practices Investigation

Renewable Power Purchase Agreements

MISO Real Time Revenue Sufficiency Guarantee

MISO Transmission Expansion Cost Sharing and FERC Order 1000

On July 21, 2011, the FERC issued Order 1000, amending the transmission planning and cost allocation requirements established in Order No. 890. Through Order 1000, the FERC:

(1) requires public utility transmission providers to participate in a regional transmission planning process and produce a regional transmission plan;

(3) removes the federal right of first refusal for certain transmission facilities; and

(4) seeks to improve coordination between neighboring transmission planning regions for interregional facilities.

4. UTILITY PLANT IN SERVICE

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

5. FAIR VALUE MEASUREMENTS

Cash Equivalents

As of December 31, 2012 and 2011, 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 $0.4 million and $0.5 million as of December 31, 2012 and 2011, respectively.

Investments in debt securities

Customer Deposits

Pension Assets

Indebtedness

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

December 31, 2012 December 31, 2011

Face Value Fair Value Face Value Fair Value

(In Millions)

Fixed-rate $ 965.3 $ 1,144.3 $ 965.3 $ 1,117.9

Variable-rate 50.0 50.0 64.0 64.0

Total indebtedness $ 1,015.3 $ 1,194.3 $ 1,029.3 $ 1,181.9

The difference between the face value and the carrying value of this indebtedness represents unamortized discounts of $1.1 million and $1.1 million at December 31, 2012 and December 31, 2011, respectively.

Fair Value Hierarchy

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.

IPL did not have any financial assets or liabilities measured at fair value on a nonrecurring basis, which have been adjusted to fair value during the periods covered by this report. As of December 31, 2012 and 2011, all (excluding pension assets - see Note 11, “Pension and Other Postretirement Benefits”) 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. The following table presents those financial assets and liabilities:

Valuation Techniques

Financial Transmission Rights

6. REGULATORY ASSETS AND LIABILITIES

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

2012 2011 Recovery Period

(In Thousands)

Regulatory Assets

Current:

Deferred fuel
$ 1,332 $ 7,098 Through 2013 ⁽¹⁾

Environmental project costs 3,574 -   Through 2013 ⁽¹⁾

DSM program costs
-   326 Through 2012 ⁽¹⁾

Total current regulatory assets
4,906 7,424

Long-term:

Unrecognized pension and other postretirement benefit plan costs
$ 341,471 $ 306,923 Various

Income taxes recoverable from customers
44,259 49,525 Various

Deferred MISO costs
89,479 80,367 To be determined ⁽²⁾

Unamortized Petersburg Unit 4 carrying charges and certain other costs
14,803 15,466 Through 2026 ⁽¹⁾⁽³⁾

Unamortized reacquisition premium on debt
27,510 29,086 Over remaining life of debt

Environmental project costs
5,935 4,545 Through 2021 ⁽¹⁾

Other miscellaneous
382 20 To be determined ⁽²⁾

Total long-term regulatory assets
523,839 485,932

Total regulatory assets
$ 528,745 $ 493,356

Regulatory Liabilities

Current:

FTR's
2,419 2,779 Through 2013 ⁽¹⁾

Fuel related
2,500 2,500 Through 2013 ⁽⁴⁾

Environmental project costs
-   3,984 Through 2012 ⁽¹⁾

DSM program costs
5,556 -   Through 2013 ⁽¹⁾

Total current regulatory liabilities
10,475 9,263

Long-term:

ARO and accrued asset removal costs
559,760 536,920 Not Applicable

Unamortized investment tax credit
5,307 6,370 Through 2021

Fuel related
5,277 7,142 To be determined ⁽⁴⁾

Total long-term regulatory liabilities
570,344 550,432

Total regulatory liabilities
$ 580,819 $ 559,695

⁽¹⁾ Recovered (credited) per specific rate orders

⁽²⁾ Recovery is probable but timing not yet determined

⁽³⁾ Recovered with a current return

⁽⁴⁾ Per IURC Order, offset MISO transmission expansion costs beginning October 2011

Deferred Fuel

Unrecognized Pension and Postretirement Benefit Plan Costs

Deferred Income Taxes

Deferred MISO Costs

Asset Retirement Obligation and Accrued Asset Removal Costs

7. ASSET RETIREMENT OBLIGATIONS

ASC 410 “Asset Retirement and Environmental 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 410 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 estoppel. ARO liability is included in Miscellaneous on the accompanying Consolidated Balance Sheets.

As of December 31, 2012 and 2011, IPL did not have any assets that are legally restricted for settling its ARO liability.

8. 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 $400 million of 7.25% Senior Secured Notes due April 1, 2016 (“2016 IPALCO Notes”) and $400 million of 5.00% Senior Secured Notes due May 1, 2018 (“2018 IPALCO Notes”). There have been no changes in the capital stock of IPL during the three years ended December 31, 2012.

Dividend Restrictions

Cumulative Preferred Stock of Subsidiary

At December 31, 2012, 2011 and 2010, preferred stock consisted of the following:

December 31, 2012 December 31,

Shares Outstanding Call Price 2012 2011 2010

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

9. INDEBTEDNESS

Restrictions on Issuance of Debt

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 IPL’s credit facility (as well as the amount of certain other fees on the credit facility) are dependent upon the credit ratings of IPL. Downgrades in the credit ratings of AES and/or IPALCO could result in IPL’s credit ratings being downgraded.

Long-Term Debt

The following table presents our long-term indebtedness:

Series Due December 31,

2012 2011

(In Thousands)

IPL First Mortgage Bonds (see below)

6.30%

July 2013
$ 110,000 $ 110,000

4.90%⁽²⁾

January 2016
30,000 30,000

4.90%⁽²⁾

January 2016
41,850 41,850

4.90%⁽²⁾

January 2016
60,000 60,000

5.40%⁽¹⁾

August 2017
24,650 24,650

3.875%⁽²⁾

August 2021
55,000 55,000

3.875%⁽²⁾

August 2021
40,000 40,000

4.55%⁽²⁾

December 2024
40,000 40,000

6.60%

January 2034
100,000 100,000

6.05%

October 2036
158,800 158,800

6.60%

June 2037
165,000 165,000

4.875%

November 2041
140,000 140,000

Unamortized discount - net
(1,096) (1,125)

Total IPL first mortgage bonds
964,204 964,175

Less: Current Portion of Long-term Debt 110,000 -

Net Consolidated IPL Long-term Debt $ 854,204 $ 964,175

⁽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.

IPL First Mortgage Bonds and Indiana Finance Authority Bond Issuances

$40.0 million aggregate principal amount of the City of Petersburg, Indiana Pollution Control Refunding Revenue Bonds Adjustable Rate Tender Securities, 1995B Series, Indianapolis Power & Light Company Project (“1995B Bonds”), variable rate, due 2023;
$20.0 million aggregate principal amount of the City of Petersburg, Indiana Solid Waste Disposal Revenue Bonds, 1994A Series, Indianapolis Power & Light Company Project, 5.90% Series, due 2024;
$30.0 million aggregate principal amount of the City of Petersburg, Indiana Solid Waste Disposal Revenue Bonds, 1995C Series, Indianapolis Power & Light Company Project, 5.95% Series, due 2029;
$20.0 million aggregate principal amount of the City of Petersburg, Indiana Solid Waste Disposal Revenue Bonds, 1996 Series, Indianapolis Power & Light Company Project, 6.375% Series, due 2029; and
$17.35 million aggregate principal amount of the Indiana Development Finance Authority’s Exempt Facilities Revenue Refunding Bonds, Series 1999, Indianapolis Power & Light Company Project, 5.95% Series, due 2030.

Accounts Receivable Securitization

IPL formed IPL Funding in 1996 as a special-purpose entity to purchase receivables originated by IPL pursuant to a receivables purchase agreement between IPL and IPL Funding. IPL Funding also entered into a sale facility as defined in the Second Amended and Restated Receivables Sale Agreement, dated as of June 25, 2009, among IPL, IPL Funding Corporation, as the Seller, Indianapolis Power & Light Company, as the Collection Agent, Royal Bank of Scotland plc, as the Agent, the Liquidity Providers and Windmill Funding Corporation (“Receivables Sale Agreement”), which matured as extended on October 24, 2012. On October 22, 2012, under an amended and restated sale agreement, which matures on October 21, 2013, Citibank, N.A. and its affiliate, CRC Funding, LLC, replaced The Royal Bank of Scotland plc and Windmill Funding Corporation as Agent and Investor, respectively. The terms of the new arrangement to IPL are substantially the same as that of the previous arrangement. The Agent and Investor collectively, are referred to as the “Purchasers.” Pursuant to the terms of the Receivables Sale Agreement, 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 million. That amount was $50 million as of December 31, 2012 and December 31, 2011. 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. IPL Funding is included in the Consolidated Financial Statements of IPL.

Under the sale facility, if IPL fails to maintain a certain debt-to-capital ratio, it would constitute a “termination event.” As of December 31, 2012, IPL was in compliance with such covenant.

Line of Credit

In December 2010, IPL entered into a $250 million unsecured revolving credit facilities credit agreement (the “Credit Agreement”) with a syndication of banks. The Credit Agreement originally included two facilities: (i) a $209.4 million committed line of credit for letters of credit, working capital and general corporate purposes and (ii) a $40.6 million liquidity facility, which was dedicated for the sole purpose of providing liquidity for certain variable rate unsecured debt issued on behalf of IPL. As a result of the November 2011 IPL financing activity described above, the credit agreement was amended in February 2012 to eliminate the $40.6 million liquidity facility and to increase the committed line of credit for letters of credit, working capital and general corporate purposes by the same amount resulting in one facility in the amount of $250 million. The Credit Agreement matures on December 14, 2015 and bears interest at variable rates as defined in the Credit Agreement. Prior to execution, IPL had existing general banking relationships with the parties in this agreement. As of December 31, 2012 and 2011, IPL had $0.0 million and $14.0 million outstanding borrowings on the committed line of credit, respectively.

Debt Maturities

Maturities on long-term indebtedness subsequent to December 31, 2012, are as follows:

Year Amount

(In Thousands)

2013 $ 110,000

2014 -

2015 -

2016 131,850

2017 24,650

Thereafter 698,800

Total
$ 965,300

10. 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, 2012, 2011 and 2010:

2012 2011 2010

(In Thousands)

Unrecognized tax benefits at January 1
$ 5,354 $ 4,757 $ 7,947

Gross increases - current period tax positions
997 753 753

Gross decreases - prior period tax positions
(213) (156) (3,943)

Unrecognized tax benefits at December 31 $ 6,138 $ 5,354 $ 4,757

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

2012 2011 2010

(In Thousands)

Charged to utility operating expenses:

Current income taxes:

Federal
$ 55,201 $ 54,377 $ 61,999

State
16,641 16,539 18,818

Total current income taxes
71,842 70,916 80,817

Deferred income taxes:

Federal
(3,285) (5,027) (4,697)

State
204 (1,608) 1,539

Total deferred income taxes
(3,081) (6,635) (3,158)

Net amortization of investment credit
(1,599) (1,672) (1,720)

Total charge to utility operating expenses
67,162 62,609 75,939

Charged to other income and deductions:

Current income taxes:

Federal
395 2,883 (286)

State
245 916 39

Total current income taxes
640 3,799 (247)

Deferred income taxes:

Federal
10 (5) (1)

State
4 5 (4)

Total deferred income taxes
14 - (5)

Net credit to other income and deductions
654 3,799 (252)

Total federal and state income tax provisions
$ 67,816 $ 66,408 $ 75,687

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:

2012 2011 2010

Federal statutory tax rate
35.0% 35.0% 35.0%

State income tax, net of federal tax benefit
6.5 6.0 6.8

Amortization of investment tax credits
(0.9) (1.0) (0.9)

Depreciation flow through and amortization
1.0 0.7 0.4

Manufacturers’ Production Deduction (Sec. 199)
(3.0) (2.4) (2.7)

Change in tax reserves
(0.0) (0.0) (0.2)

Other - net
0.9 0.4 0.3

Effective tax rate
39.5% 38.7% 38.7%

Internal Revenue Code Section 199 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 9% of qualifying production activity beginning in 2010 and thereafter. The tax benefit associated with the Internal Revenue Code Section 199 domestic production deduction for 2011 and 2010 was $4.0 million and $5.0 million, respectively. The benefit for 2012 is estimated to be $5.2 million.

The significant items comprising IPL’s net accumulated deferred tax liability recognized on the audited Consolidated Balance Sheets as of December 31, 2012 and 2011, are as follows:

2012 2011

(In Thousands)

Deferred tax liabilities:

Relating to utility property, net
$ 475,517 $ 483,261

Regulatory assets recoverable through future rates
197,909 181,593

Other
12,643 15,288

Total deferred tax liabilities
686,069 680,142

Deferred tax assets:

Investment tax credit
3,216 3,855

Regulatory liabilities including ARO
229,025 220,491

Employee benefit plans
114,420 106,243

Other
8,276 10,366

Total deferred tax assets
354,937 340,955

Accumulated net deferred tax liability
331,132 339,187

Less: Net current deferred tax asset
(10,782) (12,323)

Accumulated deferred income taxes - net
$ 341,914 $ 351,510

11. PENSION AND OTHER POSTRETIREMENT BENEFITS

The following table presents information relating to the Pension Plans:


	Pension benefits as of December 31,
	2012		2011
	*(In Thousands)*
Change in benefit obligation:
Projected benefit obligation at beginning Measurement Date (see below)	$	679,261	$	607,408
Service cost		7,986		7,234
Interest cost		30,232		31,828
Actuarial (gain) loss		69,099		62,587
Amendments (primarily increases in pension bands)		7,349		82
Benefits paid		(30,327)		(29,878)
Projected benefit obligation at ending Measurement Date		763,600		679,261
Change in plan assets:
Fair value of plan assets at beginning Measurement Date		426,384		412,611
Actual return on plan assets		50,713		6,305
Employer contributions		48,312		37,345
Benefits paid		(30,327)		(29,877)
Fair value of plan assets at ending Measurement Date		495,082		426,384
Funded status	$	(268,518)	$	(252,877)
Amounts recognized in the statement of financial position under ASC 715:
Current liabilities	$	-	$	-
Noncurrent liabilities		(268,518)		(252,877)
Net amount recognized	$	(268,518)	$	(252,877)
Sources of change in regulatory assets⁽¹⁾:
Prior service cost (credit) arising during period	$	7,350	$	82
Net loss (gain) arising during period		50,938		88,450
Amortization of prior service (cost) credit		(4,246)		(4,346)
Amortization of gain (loss)		(19,471)		(13,306)
Total recognized in regulatory assets⁽¹⁾	$	34,571	$	70,880
Total amounts included in accumulated other comprehensive income (loss)		NA⁽¹⁾		NA⁽¹⁾
Amounts included in regulatory assets and liabilities⁽¹⁾
Net loss (gain)	$	314,557	$	283,089
Prior service cost (credit)		33,836		30,732
Total amounts included in regulatory assets (liabilities)	$	348,393	$	313,821

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

Effect of ASC 715

Pension Benefits and Expense


	Pension benefits for years ended December 31,
	2012		2011		2010
	*(In Thousands)*
Components of net periodic benefit cost:
Service cost	$	7,986	$	7,234	$	6,590
Interest cost		30,232		31,828		31,577
Plan settlements		-		-		204
Expected return on plan assets		(32,554)		(32,168)		(29,250)
Amortization of prior service cost		4,246		4,346		3,476
Recognized actuarial loss		19,471		13,306		11,838
Total pension cost		29,381		24,546		24,435
Less: amounts capitalized		2,497		2,258		2,321
Amount charged to expense	$	26,884	$	22,288	$	22,114
Rates relevant to each year's expense calculations:
Discount rate - defined benefit pension plan		4.56%		5.38%		5.93%
Discount rate - supplemental retirement plan		4.37%		5.09%		5.27%/5.08% ⁽¹⁾
Expected return on defined benefit pension plan assets		7.50%		7.75%		8.00%
Expected return on supplemental retirement plan assets		7.50%		7.75%		8.00%
⁽¹⁾ 5.27% for the period January 1, 2010 thru May 31, 2010, 5.08% for the settlement on May 31, 2010 and the period June 1, 2010 through December 31, 2010.

Expected amortization

Pension Assets

Fair Value Measurements

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

Other than common/collective trust funds, hedge funds and non U.S. government fixed income securities, all the Plan’s investments are actively traded on an open market and are categorized as Level 1 in the fair value hierarchy.
All of the Plan’s hedge funds report the net asset value (NAV) from the funds audited financial statements of the Plan’s interest based on the fair value of the hedge funds’ underlying investments as determined in accordance with the American Institute of Certified Public Accountants’ Accounting and Auditing Guide for Investment Companies.
Investments in hedge funds are valued using the observable NAV of the Plan’s interest as of December 31, 2012, provided by the underlying hedge fund. The Plan may redeem its ownership interests in hedge funds at NAV, with 60 days’ notice, on either quarterly or semiannual terms.
The Plan’s investments in common/collective trust funds are valued at the NAV of the units of the common/collective trust funds held by the Plan at year-end. The Plan may redeem its units of the common/collective trust funds at NAV daily. These NAVs have been determined based on the market value of the underlying equity securities held by the common/collective trust funds.
The Plan’s investments in corporate bonds are valued from third-party pricing sources but they generally do not represent transaction prices for the identical security in an active market nor does it represent data obtained from an exchange.
The Fund’s investments in hedge funds, common/collective trust funds and non U.S. government fixed income securities have been recorded at fair value and are all categorized as Level 2 investments in the fair value hierarchy.

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⁾
Liability Hedging Portfolio ⁽¹⁾
Liability Manager Fixed Income		10.0%	16.0%	40.0%	5.3%	3.6%
Core Fixed Income		10.0%	16.0%	22.0%	5.4%	3.8%

Growth Portfolio
High Yield Fixed Income		3.0%	8.0%	13.0%	8.9%	9.5%
U.S. Large Cap Equity		20.0%	30.0%	40.0%	10.4%	15.4%
U.S. Mid Cap Equity		2.5%	5.0%	7.5%	11.2%	17.1%
U.S. Small Cap Equity		2.5%	5.0%	7.5%	12.0%	19.9%
International Equity		5.0%	10.0%	15.0%	10.3%	17.7%
REIT		0.0%	5.0%	10.0%	10.4%	18.8%
Hedge Funds ⁽⁴⁾		0.0%	5.0%	10.0%	9.3%	8.4%

⁽¹⁾Upper limit for all assets held in the Liability Hedging Portfolio is 40%
⁽²⁾Expected long-term annual return
⁽³⁾Expected standard deviation
⁽⁴⁾Alternative investments (combined) not to exceed 10%

The fair values of the pension plan assets at December 31, 2012, by asset category are as follows:

Fair Value Measurements at December 31, 2012 (in thousands)

Quoted Prices in Active Markets for Identical Assets Significant Observable Inputs

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

Cash and cash equivalents
$ 42,139 $ 42,139 $ -   9%

Equity Securities:

Common stock
96,347 96,347 -   19%

REIT
22,330 22,330 -   5%

Fixed Income Securities:

Government debt securities
25,170 25,170 -   5%

Corporate debt securities
148,553 -   148,553 30%

Other types of investments:

Mutual fund - Equities
51,154 51,154 -   10%

Mutual fund - Debt
3,626 3,626 -   1%

Mutual fund - REIT
174 174 -   0%

Hedge fund - Equity
35,498 -   35,498 7%

Common/collective trust funds
70,091 -   70,091 14%

Total $ 495,082 $ 240,940 $ 254,142 100%

Pension Funding


Year	Pension Benefits
	*(In Thousands)*
2013	$	51,238
2014		34,665
2015		36,274
2016		37,557
2017		38,962
2018 through 2022 (in total)		216,051

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

The AES Retirement Savings Plan

12. COMMITMENTS AND CONTINGENCIES

Legal Loss Contingencies

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. Additionally, several cases have been dismissed by the plaintiffs in the past few years without requiring a settlement. We are unable to estimate the number of, the effect of, or losses of 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.

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 Loss Contingencies

New Source Review

13. SALE OF OATSVILLE COAL RESERVE

14. 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 $5 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. The cost to IPL of coverage under this program was approximately $2.9 million, $3.2 million, and $4.0 million in 2012, 2011, and 2010, respectively, and is recorded in Other operating expenses on the accompanying Consolidated Statements of Comprehensive Income. As December 31, 2012 and 2011, we had prepaid approximately $1.5 million and $1.5 million, respectively, which is 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 balance under this agreement of $5.0 million as of December 31, 2012, which is recorded in Prepayments and other current assets on the accompanying Consolidated Balance Sheets. IPL had a payable balance under this agreement of $0.9 million as of December 31, 2011, which is recorded in Other current liabilities on the accompanying Consolidated Balance Sheets.

Long-term Compensation Plan

During 2012, 2011 and 2010, 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 and AES restricted stock units and options to purchase shares of AES common stock. All such components vest in thirds over a three year period and the terms of the AES restricted stock unit issued prior to 2011 also include a two year minimum holding period after the awards vest. Awards made in 2011 and for subsequent years will not be subject to a two year holding period. In addition, the performance units payable in cash are subject to certain AES performance criteria. Total deferred compensation expense recorded during 2012, 2011 and 2010 was $0.8 million, $1.2 million and $1.7 million, respectively and was included in Other Operating Expenses on IPL’s Consolidated Statements of Comprehensive 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 11, “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.

15. SEGMENT INFORMATION

16. QUARTERLY RESULTS (UNAUDITED)

Operating results for the years ended December 31, 2012 and 2011, by quarter, are as follows:

2012

March 31 June 30 September 30 December 31

(In Thousands)

Operating revenue
$ 301,104 $ 292,659 $ 324,478 $ 311,536

Operating income
37,951 34,583 50,227 40,139

Net income
23,744 20,316 35,505 24,564

2011

March 31 June 30 September 30 December 31

(In Thousands)

Operating revenue
$ 289,165 $ 279,943 $ 320,550 $ 282,266

Operating income
35,726 36,137 48,451 32,339

Net income
23,189 30,547 34,810 16,852

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

None.

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, 2012. Our 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, 2012, 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 assessed the effectiveness of our internal control over financial reporting as of December 31, 2012. 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, 2012, 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, 2012 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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 2012 and 2011 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,

2012 2011

Audit Fees
$ 900,000 $ 882,000

Audit Related Fees:

Fees for the audit of IPL’s employee benefit plans
54,500 53,000

Assurance services for debt offering documents
21,450 164,425

Total Principal Accounting Fees and Services
$ 975,950 $ 1,099,425

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

(a) 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 - 2012, 2011 and 2010
	Define Terms
	Consolidated Statements of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010
	Consolidated Balance Sheets as of December 31, 2012 and 2011
	Consolidated Statements of Cash Flows for the year ended December 31, 2012, 2011 and 2010
	Consolidated Statements of Common Shareholder’s Deficit for the years ended December 31, 2012, 2011 and 2010
	Notes to Consolidated Financial Statements
	Schedule I - Condensed Financial Information of Registrant
	Schedule II - Valuation and Qualifying Accounts and Reserves

Indianapolis Power & Light Company and Subsidiary - Consolidated Financial Statements
	Report of Independent Registered Public Accounting Firm - 2012, 2011 and 2010
	Defined Terms
	Consolidated Statements of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010
	Consolidated Balance Sheets as of December 31, 2012 and 2011
	Consolidated Statements of Cash Flows for the year ended December 31, 2012, 2011 and 2010
	Consolidated Statements of Common Shareholder’s Equity for the years ended December 31, 2012, 2011 and 2010
	Notes to Consolidated Financial Statements
	Schedule II - Valuation and Qualifying Accounts and Reserves

(b) Exhibits


EXHIBIT NO.	DOCUMENT
3.1*	Second Amended and Restated Articles of Incorporation
3.2*	Amended and Restated By-Laws of IPALCO Enterprises, Inc.
4.1*	Pledge Agreement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company, N.A. dated as of November 14, 2011
4.2*	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
4.3	The following supplemental indentures to the Mortgage and Deed of Trust referenced in 4.2 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-Seventh Supplemental Indenture dated as of August 1, 2003 Forty-Eighth Supplemental Indenture dated as of January 1, 2004 Fifty-Second Supplemental Indenture dated as of September 1, 2006 Fifty-Third Supplemental Indenture dated as of October 1, 2006 Fifty-Fourth Supplemental Indenture dated as of June 1, 2007 Fifty-Fifth Supplemental Indenture dated as of May 1, 2009 Fifty-Sixth Supplemental Indenture dated as of May 1, 2009 Fifty-Seventh Supplemental Indenture dated as of May 1, 2009 Fifty-Eighth Supplemental Indenture dated as of August 1, 2011 Fifty-Ninth Supplemental Indenture dated as of August 1, 2011 Sixtieth Supplemental Indenture dated as of November 1, 2011 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s December 31, 2011 10-K)
4.4*	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)
4.5*	Pledge Agreement Supplement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company, N.A., as successor Collateral Agent, dated as of April 15, 2008, to the Pledge Agreement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company dated November 14, 2001.
4.6*	Pledge Agreement Supplement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company, N.A., as successor Collateral Agent, dated as of May 18, 2011to the Pledge Agreement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company dated November 14, 2001.
4.7*	Indenture between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company, N.A., as Trustee, dated as of May 18, 2011 for the 5.00% Senior Secured Notes due 2018
10.1*	Interconnection Agreement, dated April 1, 2008, between American Electric Power Service Corporation, as agent for Indiana Michigan Power Company, and IPL
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.
10.5*	IPALCO 1999 Stock Incentive Plan
10.6*	$250,000,000 Revolving Credit Facilities Credit Agreement by and among Indianapolis Power & Light Company The Lenders Party Hereto, PNC Bank, National Association, as Administrative Agent, PNC Capital Markets LLC, as Sole Bookrunner and Sole Lead Arranger, Bank of America, N.A. as Syndication Agent and Union Bank, N.A., as Documentation Agent, dated as of December 14, 2010
10.7*	First Amendment, dated as of March 14, 2011 to $250,000,000 Revolving Credit Facilities Credit Agreement by and among Indianapolis Power & Light Company, The Lenders Party Hereto, PNC Bank, National Association, as Administrative Agent, PNC Capital Markets LLC, as Sole Bookrunner and Sole Lead Arranger, Bank of America, N.A. as Syndication Agent and Union Bank, N.A., as Documentation Agent, dated as of December 14, 2010
10.8	Second Amendment, dated as of February 21, 2012 to $250,000,000 Revolving Credit Facilities Credit Agreement by and among Indianapolis Power & Light Company, The Lenders Party Hereto, Bank of America, N.A., as Syndication Agent and PNC Bank, National Association, as Administrative Agent, dated as of December 14, 2010 (Incorporated by reference to Exhibit No. 10.8 to IPALCO’s December 31, 2011 10-K)
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).
101.INS	XBRL Instance Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.SCH	XBRL Taxonomy Extension Schema Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.LAB	XBRL Taxonomy Extension Label Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)
* Incorporated by reference to IPALCO’s Registration Statement on Form S-4 filed with the Securities and Exchange Commission on October 11, 2011.

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 1 - CONDENSED FINANCIAL INFORMATION OF REGISTRANT


IPALCO ENTERPRISES, INC.
Schedule 1 - Condensed Financial Information of Registrant
Unconsolidated Balance Sheets
*(In Thousands)*

	2012		2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2,750	$	3,135
Deferred tax asset - current		27		28
Prepayments and other current assets		70		56
Total current assets		2,847		3,219

OTHER ASSETS:
Investment in subsidiaries		791,673		786,926
Other investments		2,825		2,707
Deferred tax asset - long term		122		143
Deferred financing costs		8,172		9,728
Total other assets		802,792		799,504
TOTAL	$	805,639	$	802,723

CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common shareholder’s deficit:
Paid in capital	$	11,811	$	11,367
Accumulated deficit		(15,030)		(17,213)
Total common shareholder’s deficit		(3,219)		(5,846)
Long-term debt		796,916		796,141
Total capitalization		793,697		790,295

CURRENT LIABILITIES:
Accounts payable and accrued expenses		281		237
Accrued income taxes		1,055		1,588
Accrued interest		10,583		10,583
Total current liabilities		11,919		12,408

DEFERRED CREDITS AND OTHER LONG-TERM LIABILITIES:		23		20
TOTAL	$	805,639	$	802,723

See notes to Schedule I.


IPALCO ENTERPRISES, INC.
Schedule I - Condensed Financial Information of Registrant
Unconsolidated Statements of Comprehensive Income
*(In Thousands)*

	2012		2011		2010

Equity in earnings of subsidiaries	$	101,023	$	101,240	$	116,062
Loss on early extinguishment of debt		-		(15,422)		-
Income tax benefit - net		20,181		28,641		24,872
Interest on long-term debt		(49,000)		(54,002)		(61,344)
Amortization of redemption premiums and expense on debt		(2,417)		(2,205)		(2,037)
Other - net		(1,004)		(890)		(822)
NET INCOME	$	68,783	$	57,362	$	76,731

See notes to Schedule I.


IPALCO ENTERPRISES, INC.
Schedule I - Condensed Financial Information of Registrant
Unconsolidated Statements of Cash Flows
*(In Thousands)*

	2012		2011		2010

CASH FLOWS FROM OPERATIONS:
Net income	$	68,783	$	57,362	$	76,731
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of subsidiaries		(101,023)		(101,240)		(116,062)
Cash dividends received from subsidiary companies		96,914		80,603		111,549
Amortization of debt issuance costs and discounts		2,417		2,205		2,037
Deferred income taxes - net		22		(111)		(669)
Loss on early extinguishment of debt		-		15,422		-
Change in certain assets and liabilities:
Income taxes receivable or payable		(533)		160		716
Accounts payable and accrued expenses		(546)		(639)		15
Accrued interest		-		(800)		-
Other - net		166		711		(139)
Net cash provided by operating activities		66,200		53,673		74,178

CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in subsidiaries		15		11		(73)
Net cash provided by (used in) investing activities		15		11		(73)

CASH FLOWS FROM FINANCING ACTIVITIES:
Long-term borrowings		-		399,708		-
Retirement of long-term debt		-		(389,421)		-
Dividends on common stock		(66,600)		(59,231)		(73,200)
Other - net		-		(6,520)		-
Net cash used in financing activities		(66,600)		(55,464)		(73,200)
Net change in cash and cash equivalents		(385)		(1,780)		905
Cash and cash equivalents at beginning of period		3,135		4,915		4,010
Cash and cash equivalents at end of period	$	2,750	$	3,135	$	4,915

See notes to Schedule I.


IPALCO ENTERPRISES, INC.
Schedule I - Condensed Financial Information of Registrant
Unconsolidated Statement of Common Shareholder’s Deficit
*(In Thousands)*

	Paid in Capital		Accumulated Deficit		Total
2010
Beginning Balance	$	9,820	$	(18,875)	$	(9,055)
Comprehensive Income:
Net income applicable to common stock				76,731		76,731
Total Comprehensive Income						76,731

Distributions to AES				(73,200)		(73,200)
Contributions from AES		991				991
Balance at December 31, 2010	$	10,811	$	(15,344)	$	(4,533)
2011
Comprehensive Income:
Net income applicable to common stock				57,362		57,362
Total Comprehensive Income						57,362

Distributions to AES				(59,231)		(59,231)
Contributions from AES		556				556
Balance at December 31, 2011	$	11,367	$	(17,213)	$	(5,846)
2012
Comprehensive Income:
Net income applicable to common stock				68,783		68,783
Total Comprehensive Income						68,783

Distributions to AES				(66,600)		(66,600)
Contributions from AES		444				444
Balance at December 31, 2012	$	11,811	$	(15,030)	$	(3,219)

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,

2012 2011

(In Thousands)

Long-Term Debt

7.25% Senior Secured Notes

April 2016
400,000 400,000

5.00% Senior Secured Notes

May 2018
400,000 400,000

Unamortized discount - net
(3,084) (3,859)

Total Long-term Debt 796,916 796,141

Less: Current Portion of Long-term Debt - -

Net Long-term Debt
$ 796,916 $ 796,141

Long-term Debt

IPALCO’s Senior Secured Notes

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES


IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Valuation and Qualifying Accounts and Reserves
Years ended December 31, 2012, 2011 and 2010
*(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, 2012
Accumulated Provisions
Deducted from Assets - Doubtful Accounts	$	2,081	$	3,397	$	-	$	3,431	$	2,047

Year ended December 31, 2011
Accumulated Provisions
Deducted from Assets - Doubtful Accounts	$	2,218	$	3,669	$	-	$	3,806	$	2,081

Year ended December 31, 2010
Accumulated Provisions
Deducted from Assets - Doubtful Accounts	$	2,143	$	3,995	$	-	$	3,920	$	2,218


INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY
Valuation and Qualifying Accounts and Reserves
Years ended December 31, 2012, 2011 and 2010
*(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, 2012
Accumulated Provisions
Deducted from Assets - Doubtful Accounts	$	2,081	$	3,397	$	-	$	3,431	$	2,047

Year ended December 31, 2011
Accumulated Provisions
Deducted from Assets - Doubtful Accounts	$	2,218	$	3,669	$	-	$	3,806	$	2,081

Year ended December 31, 2010
Accumulated Provisions
Deducted from Assets - Doubtful Accounts	$	2,143	$	3,995	$	-	$	3,920	$	2,218

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 26, 2013 By: /s/ Kenneth J. Zagzebski

Kenneth J. Zagzebski

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/Other Titles Held	Date
/s/ Kenneth J. Zagzebski
Kenneth J. Zagzebski	President, Chief Executive Officer and Director of IPALCO (Principal Executive Officer)	February 26, 2013

/s/ Andrew M. Vesey
Andrew M. Vesey	Chairman of the Board of IPALCO and Executive Vice President of AES	February 26, 2013

/s/ William H. Henley
William H. Henley	Director of IPALCO and Vice President, Corporate Affairs of IPL	February 26, 2013

/s/ Elizabeth Hackenson
Elizabeth Hackenson	Director of IPALCO and Senior Vice President, Chief Information Officer of AES	February 26, 2013


Kenneth Uva	Director of IPALCO	February 26, 2013

/s/ Kelly M. Huntington
Kelly M. Huntington	Senior Vice President, Chief Financial Officer and Director of IPALCO (Principal Financial Officer)	February 26, 2013

/s/ Kurt A. Tornquist
Kurt A. Tornquist	Vice President and Controller of IPALCO (Principal Accounting Officer)	February 26, 2013

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.


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


	2012		2011		Change		Percent Change

Utility Operating Revenue
Retail Revenues	$	1,171,516	$	1,106,271	$	65,245	5.9%
Wholesale Revenues		37,822		43,181		(5,359)	(12.4)%
Miscellaneous Revenues		20,439		22,472		(2,033)	(9.0)%
Total Utility Operating Revenues	$	1,229,777	$	1,171,924	$	57,853	4.9%

Heating Degree Days
Actual		4,399		4,912		(513)	(10.4)%
30-year Average		5,548		5,519
Cooling Degree Days
Actual		1,534		1,482		52	3.5%
30-year Average		1,041		1,041



2011 Operating Expenses	$	1,019.3
Increase in power purchased		31.1
Decrease in maintenance expenses		(19.6)
Increase in depreciation and amortization costs		9.6
Increase in DSM program costs		8.6
Increase in fuel costs		6.3
Increase in pension expenses		4.7
Increase in income taxes - net		4.6
Other miscellaneous variances - individually immaterial		2.3
2012 Operating Expenses	$	1,066.9



2010 Operating Expenses	$	972.5
Increase in power purchased		34.7
Increase in fuel costs		11.8
Increase in salaries, wages and benefits		6.9
Increase in contract services		4.4
Decrease in income taxes - net		(13.3)
Other miscellaneous variances - individually immaterial		2.3
2011 Operating Expenses	$	1,019.3


	Payment due
	Total		Less Than 1 Year		1 - 3 Years		3 - 5 Years		More Than 5 Years
	*(In Millions)*
Long-term debt	$	1,765.3	$	110.0	$	-	$	556.5	$	1,098.8
Interest obligations⁽¹⁾		1,113.0		100.1		192.4		128.2		692.3
Purchase obligations⁽²⁾:
Coal, gas, purchased power and related transportation		2,080.7		330.6		475.5		184.7		1,089.9
Other		32.1		7.9		13.7		10.5		-
Pension Funding⁽³⁾		49.6		49.6		-		-		-
Total⁽⁴⁾	$	5,040.7	$	598.2	$	681.6	$	879.9	$	2,881.0

⁽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, 2012.
⁽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 include contractual commitments that can be terminated by us without penalty on notice of 90 days or less. An EPC contract for the installation of environmental controls on IPL’s coal-fired units was executed January 3, 2013 and payable over the next 4 years in connection with the MATS-related construction project described herein. The related cash outlays are not included in the table because the contract was executed after December 31, 2012.
⁽³⁾IPL elected to fund $49.6 million during January 2013. However, IPL may decide to contribute more than $49.6 million to meet certain funding thresholds. For years 2014 and thereafter, our contractual obligation for pension funding can fluctuate due to various factors. Please see “Pension Funding” below and Note 11, “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 $6.1 million (tax and related interest) as of December 31, 2012 because 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.


	Moody’s		S&P		Fitch Ratings

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


	2013		2014		2015		2016		2017		Thereafter		Total		Fair Value
	*(In Millions)*
Fixed-rate debt	$	110.0	$	-	$	-	$	531.9	$	24.6	$	1,098.8	$	1,765.3	$	2,012.3
Variable-rate debt		50.0		-		-		-		-		-		50.0		50.0
Total Indebtedness	$	160.0	$	-	$	-	$	531.9	$	24.6	$	1,098.8	$	1,815.3	$	2,062.3

Weighted Average Interest Rates by Maturity		4.62%		N/A		N/A		6.67%		5.40%		5.45%		5.66%


IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Common Shareholder’s Deficit
and Noncontrolling Interest
*(In Thousands)*

	Paid in Capital		Accumulated Deficit		Accumulated Other Comprehensive Income (Loss)			Total Common Shareholder's Deficit		Cumulative Preferred Stock of Subsidiary
2010
Beginning Balance	$	9,820	$	(18,878)	$	-	$	(9,058)	$		59,784
Comprehensive Income attributable to common stock:
Net income applicable to common stock				76,734				76,734
Unrealized loss on available for sale investment (net of income tax benefit of $134)						(197)		(197)
Distributions to AES				(73,200)				(73,200)
Contributions from AES		991						991
Balance at December 31, 2010	$	10,811	$	(15,344)	$	(197)	$	(4,730)	$		59,784
2011
Comprehensive Income attributable to common stock:
Net income applicable to common stock				57,362				57,362
Gain on sale of available for sale investment (net of income tax expense of $134)						197		197
Distributions to AES				(59,231)				(59,231)
Contributions from AES		556						556
Balance at December 31, 2011	$	11,367	$	(17,213)	$	-	$	(5,846)	$		59,784
2012
Comprehensive Income attributable to common stock:
Net income applicable to common stock				68,783				68,783
Distributions to AES				(66,600)				(66,600)
Contributions from AES		444						444
Balance at December 31, 2012	$	11,811	$	(15,030)	$	-	$	(3,219)	$		59,784

See notes to consolidated financial statements.


	As of December 31,
	2012		2011
	*(In Thousands)*
Production	$	2,708,826	$	2,684,443
Transmission		249,577		238,762
Distribution		1,249,445		1,219,070
General plant		174,686		170,740
Total utility plant in service	$	4,382,534	$	4,313,015

	December 31, 2012				December 31, 2011
	Face Value		Fair Value		Face Value			Fair Value
	*(In Millions)*
Fixed-rate	$	1,765.3	$	2,012.3	$	1,765.3	$	1,944.9
Variable-rate		50.0		50.0		64.0		64.0
Total indebtedness	$	1,815.3	$	2,062.3	$	1,829.3	$	2,008.9


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

Balance at January 1, 2011	$	(7,461)	$	41,669	$	34,208
Unrealized gain recognized in OCI		-		331		331
Unrealized losses recognized in earnings		(15)		-		(15)
Unrealized loss recognized as a regulatory liability		(5,095)		-		(5,095)
Issuances		8,085		-		8,085
Settlements		7,084		(42,000)		(34,916)
Balance at December 31, 2011	$	2,598	$	-	$	2,598
Unrealized gain recognized in earnings		11		-		11
Issuances		8,832		-		8,832
Settlements		(9,192)		-		(9,192)
Balance at December 31, 2012	$	2,249	$	-	$	2,249


	2012		2011		Recovery Period
	*(In Thousands)*
Regulatory Assets
Current:
Deferred fuel	$	1,332	$	7,098	Through 2013 ⁽¹⁾
Environmental project costs		3,574		-	Through 2013 ⁽¹⁾
DSM program costs		-		326	Through 2012 ⁽¹⁾
Total current regulatory assets		4,906		7,424

Long-term:
Unrecognized pension and other postretirement benefit plan costs		341,471		306,923	Various
Income taxes recoverable from customers		44,259		49,525	Various
Deferred MISO costs		89,479		80,367	To be determined ⁽²⁾
Unamortized Petersburg Unit 4 carrying charges and certain other costs		14,803		15,466	Through 2026 ⁽¹⁾⁽³⁾
Unamortized reacquisition premium on debt		27,510		29,086	Over remaining life of debt
Environmental project costs		5,935		4,545	Through 2021 ⁽¹⁾
Other miscellaneous		382		20	To be determined ⁽²⁾
Total long-term regulatory assets		523,839		485,932
Total regulatory assets	$	528,745	$	493,356

Regulatory Liabilities
Current:
FTR's	$	2,419	$	2,779	Through 2013 ⁽¹⁾
Fuel related		2,500		2,500	Through 2013 ⁽⁴⁾
Environmental project costs		-		3,984	Through 2012 ⁽¹⁾
DSM program costs		5,556		-	Through 2013 ⁽¹⁾
Total current regulatory liabilities		10,475		9,263

Long-term:
ARO and accrued asset removal costs		559,760		536,920	Not Applicable
Unamortized investment tax credit		5,307		6,370	Through 2021
Fuel related		5,277		7,142	To be determined ⁽⁴⁾
Total long-term regulatory liabilities		570,344		550,432
Total regulatory liabilities	$	580,819	$	559,695

⁽¹⁾ Recovered (credited) per specific rate orders
⁽²⁾ Recovery is probable but timing not yet determined
⁽³⁾ Recovered with a current return
⁽⁴⁾ Per IURC Order, offset MISO transmission expansion costs beginning October 2011


	December 31, 2012			December 31,
	Shares Outstanding	Call Price		2012		2011		2010
	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


	Years Ended December 31,
	2012		2011

Audit Fees	$	900,000	$	882,000
Audit Related Fees:
Fees for the audit of IPL’s employee benefit plans		54,500		53,000
Assurance services for debt offering documents		21,450		164,425
Total Principal Accounting Fees and Services	$	975,950	$	1,099,425


			IPALCO ENTERPRISES, INC.
			(Registrant)

Date:	February 26, 2013	By:	/s/ Kenneth J. Zagzebski
			Kenneth J. Zagzebski
			President and Chief Executive Officer