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:
ITEM 1A.
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. 		
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. Our decision on which replacement 		options to pursue will be impacted by the ultimate timetable for 		implementation of the EPA’s MATS rule, described in “Item 7. 		Management’s Discussion and analysis of Financial Condition and Results 		of Operations - Environmental Matters - MATS.” 		
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.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 1C. DEFINED TERMS
ITEM 2.
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:
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.
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.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5.
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.
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.
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):
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):
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): 		
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):
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:
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: 		
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 		
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, and permit revocation and/or facility shutdowns. 		
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.
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: 		
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.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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
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 		
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 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. 		
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. 		
4. UTILITY PLANT IN SERVICE 		
The original cost of 		utility plant in service segregated by functional classifications, 		follows:
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:
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: 		
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): 		
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: 		
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: 		
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’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 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:
		
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 		
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. 		
Long-Term Debt 		
The following table presents our long-term 		indebtedness: 		
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. 		
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. 		
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. 		
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. 		
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: 		
		 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. 		
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. 		
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: 		
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: 		
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: 		
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: 		
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:
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 		
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 		
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). 		
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 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: 		
		The fair values of the pension plan assets at December 31, 2012, by 		asset category are as follows:
		The fair values of the pension plan assets at December 31, 2011, by 		asset category are as follows:
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: 		
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 		
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, 		permit revocation and/or facility shutdowns. We cannot assure that we 		have been or will be at all times in full compliance with such laws, 		regulations and permits. 		
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): 		
16. QUARTERLY RESULTS (UNAUDITED) 		
Operating results for the 		years ended December 31, 2012 and 2011, by quarter, are as follows:
		
The quarterly figures reflect seasonal and weather-related 		fluctuations that are normal to IPL’s operations. 		
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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.
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 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
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 		
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 		
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 		
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. 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. 		
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 		
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. 		
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
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 		
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 		
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 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. 		
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. 		
4. UTILITY PLANT IN SERVICE 		
The original cost of 		utility plant in service segregated by functional classifications, 		follows:
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 $0.4 million and $0.5 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:
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 		
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. 		
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: 		 		
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): 		
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:
		
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: 		
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 		
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 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:
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 		
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: 		
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. 		
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. 		
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. 		
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. 		
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 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: 		
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. 		
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. 		
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. 		
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: 		
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: 		
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:
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:
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:
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 		
Information for Pension Plans with an accumulated benefit 		obligation in excess of plan assets 		
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). 		
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 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: 		
		The fair values of the pension plan assets at December 31, 2012, by 		asset category are as follows:
		The fair values of the pension plan assets at December 31, 2011, by 		asset category are as follows:
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: 		
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 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 		
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, permit revocation and/or facility 		shutdowns. We cannot assure that we have been or will be at all times in 		full compliance with such laws, regulations and permits. 		
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 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. 		
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, 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 		
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. 		All of IPL’s current business consists of the generation, transmission, 		distribution and sale of electric energy, and therefore IPL had only one 		reportable segment. 		
16. QUARTERLY RESULTS (UNAUDITED) 		
Operating 		results for the years ended December 31, 2012 and 2011, by quarter, are 		as follows:
		
The 		quarterly figures reflect seasonal and weather-related fluctuations that 		are normal to IPL’s operations. 		
************
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
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.
ITEM 9B. OTHER INFORMATION
Not applicable.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Not applicable pursuant to General Instruction I of the Form 10-K.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Not applicable pursuant to General Instruction I of the Form 10-K.
ITEM 12.
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.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Not applicable pursuant to General Instruction I of the Form 10-K.
ITEM 14.
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: 		
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
(a) Index to the financial statements, supplementary data and financial statement schedules
(b) Exhibits
(c) Financial Statement Schedules
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 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:
Long-term Debt
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. 		
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 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.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
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.