Ipalco Enterprises 424B3 Prospectus supplement

Filed Pursuant to Rule 424(b)(3)

Registration No. 333-221523

IPALCO Enterprises, Inc.

Offer to Exchange

3.70% Senior Secured Notes due 2024

for

New 3.70% Senior Secured Notes due 2024

We are offering to exchange up to $405 million of our new registered 3.70% Senior Secured Notes due 2024 (the “new notes” or “notes”) for up to $405 million of our existing unregistered 3.70% Senior Secured Notes due 2024 (the “old notes”). The terms of the new notes are identical in all material respects to the terms of the old notes, except that the new notes have been registered under the Securities Act of 1933, as amended (the “Securities Act”), and the transfer restrictions and registration rights relating to the old notes do not apply to the new notes. The new notes will represent the same debt as the old notes and we will issue the new notes under the same indenture.

To exchange your old notes for new notes:

•

you are required to make the representations described on page 3 to us; and

•

you should read the section called “The Exchange Offer” on page 109 for further information on how to exchange your old notes for new notes.

The exchange offer will expire at 11:59 p.m. New York City time on January 4, 2018 unless it is extended.

See “Risk Factors” beginning on page 6 of this prospectus for a discussion of risk factors that should be considered by you prior to tendering your old notes in the exchange offer.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of the securities to be issued in the exchange offer or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

December 6, 2017

TABLE OF CONTENTS

	Page

Glossary of Terms	iv
Summary	1
Risk Factors	6
Forward-Looking Statements	19
Use of Proceeds	21
Ratio of Earnings to Fixed Charges	22
Capitalization	23
Selected Consolidated Financial Data	24
Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Business	48
Management	62
Compensation Discussion and Analysis	67
Certain Relationships and Related Party Transactions	91
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	93
Description of the Notes	95
The Exchange Offer	111
Material United States Tax Consequences of the Exchange Offer	118
Plan of Distribution	118
Validity of Securities	119
Experts	119
Where You Can Find More Information	119
Index to Financial Statements	F-1

We have not authorized anyone to provide you with any information other than that contained in this prospectus or to which we have referred you. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. You should assume that the information appearing in this prospectus is accurate only as of the date on the front cover of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date.

This prospectus is based on information provided by us and by other sources that we believe are reliable. We cannot assure you that this information is accurate or complete. This prospectus summarizes certain documents and other information and we refer you to them for a more complete understanding of what we discuss in this prospectus. In making an investment decision, you must rely on your own examination of our company and the terms of the offering and the notes, including the merits and risks involved.

We are not making any representation to any purchaser of the notes regarding the legality of an investment in the notes by such purchaser under any legal investment or similar laws or regulations. You should not consider any information in this prospectus to be legal, business or tax advice. You should consult your own attorney, business advisor and tax advisor for legal, business and tax advice regarding an investment in the notes.

Neither the Securities and Exchange Commission (“SEC”) nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

iii

GLOSSARY OF TERMS
The following is a list of frequently used abbreviations or acronyms that are found in this prospectus:
2016 Rate Order	The order issued in March 2016 by the IURC authorizing IPL to increase its basic rates and charges by $30.8 million annually.
2018 IPALCO Notes	$400 million of 5.00% Senior Secured Notes due May 1, 2018
2020 IPALCO Notes	$405 million of 3.45% Senior Secured Notes due July 15, 2020
2024 IPALCO Notes	$405 million of 3.70% Senior Secured Notes due September 1, 2024
AES	The AES Corporation
AES Form 10-K	AES Annual Report on Form 10-K for the year ended December 31, 2016
AES U.S. Investments	AES U.S. Investments, Inc.
Amended and Restated By-laws	Amended and Restated By-laws of IPALCO Enterprises, Inc.
ARO	Asset Retirement Obligations
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
BACT	Best Achievable Control Technology
BTA	Best Technology Available
CAA	U.S. Clean Air Act
CAIR	Clean Air Interstate Rule
CCGT	Combined Cycle Gas Turbine
CCR	Coal Combustion Residuals
CCT	Clean Coal Technology
CDPQ	CDP Infrastructure Fund GP, a wholly-owned subsidiary of La Caisse de dépôt et placement du Québec
CO²	Carbon Dioxide
COSO	Committee of Sponsoring Organizations of the Treadway Commission
CPCN	Certificate of Public Convenience and Necessity
CPP	Clean Power Plan
Credit Agreement	$250,000,000 Revolving Credit Facilities Amended and Restated Credit Agreement by and among Indianapolis Power & Light Company, the Lenders Party thereto, PNC Bank, National Association, as Administrative Agent, PNC Capital Markets LLC, as Sole Bookrunner and Sole Lead Arranger, Fifth Third Bank, as Syndication Agent and BMO Harris Bank N.A., as Documentation Agent, Dated as of May 6, 2014, and as Amended under the First Amendment to Credit Agreement, Dated as of October 16, 2015.
CSAPR	Cross-State Air Pollution Rule
CWA	U.S. Clean Water Act
D.C. Circuit	U.S. Court of Appeals for the District of Columbia Circuit
Defined Benefit Pension Plan	Employees’ Retirement Plan of Indianapolis Power & Light Company
DOE	U.S. Department of Energy
DSM	Demand Side Management
ECCRA	Environmental Compliance Cost Recovery Adjustment
ELG	Effluent Limitation Guidelines
EPA	U.S. Environmental Protection Agency
EPAct	Energy Policy Act of 2005
ERISA	Employee Retirement Income Security Act of 1974
FAC	Fuel Adjustment Clause
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FGDs	Flue-Gas Desulfurizations

FTRs	Financial Transmission Rights
GAAP	Generally Accepted Accounting Principles in the United States
GHG	Greenhouse Gas
IBEW	International Brotherhood of Electrical Workers
IDEM	Indiana Department of Environmental Management
IOSHA	Indiana Occupational Safety and Health Administration
IPALCO	IPALCO Enterprises, Inc.
IPL	Indianapolis Power & Light Company
IPL Funding	IPL Funding Corporation
IURC	Indiana Utility Regulatory Commission
kWh	Kilowatt hours
LIBOR	London InterBank Offer Rate
Loan Agreement	Loan Agreement between Indiana Financing Authority and Indianapolis Power & Light Company relating to $30,000,000 Environmental Facilities Refunding Revenue Notes, Series 2015A (Indianapolis Power & Light Company Project) and $60,000,000 Environmental Facilities Refunding Revenue Notes, Series 2015B (Indianapolis Power & Light Company Project) dated as of December 1, 2015
MATS	Mercury and Air Toxics Standards
Mid-America	Mid-America Capital Resources, Inc.
MISO	Midcontinent Independent System Operator, Inc.
MW	Megawatts
MWh	Megawatt hours
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Corporation
NODA	Notice of Data Availability
Note Purchase Agreement	Note Purchase and Covenants Agreement by and among Indianapolis Power & Light Company the Lenders Party thereto and PNC Bank, National Association, as administrative agent relating to $30,000,000 Indiana Finance Authority Environmental Facilities Refunding Revenue Notes, Series 2015A (Indianapolis Power & Light Company Project) and $60,000,000 Indiana Finance Authority Environmental Facilities Refunding Revenue Notes, Series 2015B (Indianapolis Power & Light Company Project) dated as of December 22, 2015, as amended
NOV	Notice of Violation
NOx	Nitrogen Oxides
NPDES	National Pollutant Discharge Elimination System
NSPS	New Source Performance Standards
PCBs	Polychlorinated Biphenyls
Pension Plans	Employees’ Retirement Plan of Indianapolis Power & Light Company and Supplemental Retirement Plan of Indianapolis Power & Light Company
PSD	Prevention of Significant Deterioration
Purchasers	Citibank, N.A. and its affiliate, CRC Funding, LLC
Receivables Sale Agreement	Second Amended and Restated Receivables Sale Agreement, dated as of June 25, 2009, as amended, as described herein
RF	ReliabilityFirst
RSP	AES Retirement Savings Plan
SEA	Senate Enrolled Act
SEC	Securities and Exchange Commission
Service Company	AES U.S. Services, LLC
SO2	Sulfur Dioxides
Subscription Agreement	Subscription Agreement dated as of December 14, 2014, by and between IPALCO and CDPQ

Supplemental Retirement Plan	Supplemental Retirement Plan of Indianapolis Power & Light Company
Third Amended and Restated Articles of Incorporation	Third Amended and Restated Articles of Incorporation of IPALCO Enterprises, Inc.
Thrift Plan	Employees’ Thrift Plan of Indianapolis Power & Light Company
U.S.	United States of America
U.S. SBU	AES U.S. Strategic Business Unit
VIE	Variable Interest Entity

SUMMARY

This summary highlights information contained elsewhere in this prospectus. This summary may not contain all of the information that may be important to you. You should read this entire prospectus before making a decision to exchange your old notes for new notes, including the section entitled “Risk Factors” beginning on page 6 of this prospectus.

Unless otherwise indicated or the context otherwise requires, the terms “IPALCO,” we,” “our,” “us,” and “the Company” refer to IPALCO Enterprises, Inc., including all of its subsidiaries, collectively. The term “IPALCO Enterprises, Inc.” refers only to IPALCO Enterprises, Inc., excluding its subsidiaries and affiliates.

Our Company

IPALCO Enterprises, Inc. is a holding company incorporated under the laws of the state of Indiana. Our principal subsidiary is IPL, a regulated electric utility operating in the state of 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, 2016 were $1.3 billion and $131.1 million, respectively, and for the nine months ended September 30, 2017 were $1.0 billion and $83.9 million, respectively. The book value of our total assets as of September 30, 2017 was $4.7 billion. All of our operations are conducted within the United States of America and principally within the state of Indiana.

IPL is engaged primarily in generating, transmitting, distributing and selling electric energy to approximately 490,000 retail customers in the city of Indianapolis and neighboring cities, towns and communities, and adjacent rural areas all within the state of Indiana, with 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 four generating stations, all within the state of Indiana. IPL’s largest generating station, Petersburg, is coal-fired. The second largest station, Harding Street, has converted its coal-fired units to natural gas and uses natural gas and fuel oil to power combustion turbines. In addition, IPL began the operation of a 20 MW battery energy storage unit at this location in May 2016, which provides frequency response. The third station, Eagle Valley, retired its coal-fired units in April 2016. The CCGT at Eagle Valley is expected to be completed in the first half of 2018 with a rated output of 671 MW. The fourth station, Georgetown, is a small peaking station that uses natural gas to power combustion turbines. As of September 30, 2017, IPL’s net electric generation capacity for winter is 2,996 MW and net summer capacity is 2,881 MW.

Our principal executive offices are located at One Monument Circle, Indianapolis, Indiana 46204, and our telephone number is (317) 261-8261. Our website address is www.iplpower.com. The information on our website is not a part of this prospectus.

We are owned by AES U.S. Investments and CDPQ. As of September 30, 2017, AES U.S. Investments was owned by AES U.S. Holdings LLC (85%) and CDPQ (15%). AES U.S. Holdings is a wholly owned subsidiary of AES. AES is a global power company with operations in 18 countries. AES’ executive offices are located at 4300 Wilson Boulevard, Arlington, VA, 22203, and its telephone number is (703) 522-1315.

THE EXCHANGE OFFER

Securities Offered	We are offering up to $405 million aggregate principal amount of our new 3.70% Senior Secured Notes due 2024, which will be registered under the Securities Act.
The Exchange Offer	We are offering to issue the new notes in exchange for a like principal amount of your old notes. We are offering to issue the new notes to satisfy our obligations contained in the registration rights agreement entered into when the old notes were sold in transactions permitted by Rule 144A and Regulation S under the Securities Act and therefore not registered with the SEC. For procedures for tendering, see “The Exchange Offer.”
Tenders, Expiration Date, Withdrawal	The exchange offer will expire at 11:59 p.m. New York City time on January 4, 2018 unless it is extended. If you decide to exchange your old notes for new notes, you must acknowledge that you are not engaging in, and do not intend to engage in, a distribution of the new notes. If you decide to tender your old notes in the exchange offer, you may withdraw them at any time prior to January 4, 2018. If we decide for any reason not to accept any old notes for exchange, your old notes will be returned to you without expense to you promptly after the exchange offer expires. You may only exchange old notes in denominations of $2,000 and integral multiples of $1,000 in excess thereof.
Federal Income Tax Consequences	Your exchange of old notes for new notes in the exchange offer will not result in any income, gain or loss to you for federal income tax purposes. See “Material United States Tax Consequences of the Exchange Offer.”
Use of Proceeds	We will not receive any proceeds from the issuance of the new notes in the exchange offer.
Exchange Agent	U.S. Bank National Association is the exchange agent for the exchange offer.
Failure to Tender Your Old Notes	If you fail to tender your old notes in the exchange offer, you will not have any further rights under the registration rights agreement, including any right to require us to register your old notes or to pay you additional interest or liquidated damages. All untendered old notes will continue to be subject to the restrictions on transfer set forth in the old notes and in the indenture. In general, the old notes may not be offered or sold, unless registered under the Securities Act, except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. We do not currently anticipate that we will register such untendered old notes under the Securities Act and, following this exchange offer, will be under no obligation to do so.

You will be able to resell the new notes without registering them with the SEC if you meet the requirements described below.

Based on interpretations by the SEC’s staff in no-action letters issued to third parties, we believe that new notes issued in exchange for the old notes in the exchange offer may be offered for resale, resold or otherwise transferred by you without registering the new notes under the Securities Act or delivering a prospectus, unless you are a broker-dealer receiving securities for your own account, so long as:

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you are not one of our “affiliates,” which is defined in Rule 405 of the Securities Act;

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you acquire the new notes in the ordinary course of your business;

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you do not have any arrangement or understanding with any person to participate in the distribution of the new notes; and

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you are not engaged in, and do not intend to engage in, a distribution of the new notes.

If you are an affiliate of IPALCO Enterprises, Inc., or you are engaged in, intend to engage in or have any arrangement or understanding with respect to, the distribution of new notes acquired in the exchange offer, you (1) should not rely on our interpretations of the position of the SEC’s staff and (2) must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction.

If you are a broker-dealer and receive new notes for your own account in the exchange offer and/or in exchange for old notes that were acquired for your own account as a result of market-making or other trading activities:

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you must represent that you do not have any arrangement or understanding with us or any of our affiliates to distribute the new notes;

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you must acknowledge that you will deliver a prospectus in connection with any resale of the new notes you receive from us in the exchange offer; the letter of transmittal states that by so acknowledging and by delivering a prospectus, you will not be deemed to admit that you are an “underwriter” within the meaning of the Securities Act; and

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you may use this prospectus, as it may be amended or supplemented from time to time, in connection with the resale of new notes received in exchange for old notes acquired by you as a result of market-making or other trading activities.

For a period of 90 days after the expiration of the exchange offer, we will make this prospectus available to any broker-dealer for use in connection with any resale described above.

SUMMARY DESCRIPTION OF THE NOTES

The terms of the new notes and the old notes are identical in all material respects, except that the new notes have been registered under the Securities Act, and the transfer restrictions and registrations rights relating to old notes do not apply to the new notes. The new notes will represent the same debt as the old notes and will be governed by the same indenture under which the old notes were issued.

Issuer	IPALCO Enterprises, Inc.
Notes Offered	$405 million aggregate principal amount of new 3.70% senior secured notes due 2024.
Maturity	September 1, 2024.
Interest Payment Dates	Interest will be payable semiannually on March 1 and September 1 of each year commencing on March 1, 2018.
Denominations	Minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof.
Collateral	The notes are secured by our pledge of all of the outstanding common stock of Indianapolis Power & Light Company. The lien on the pledged shares will be shared equally and ratably with our existing senior secured notes, and, subject to certain limitations, we may secure other Indebtedness (as defined herein) equally and ratably with the notes.
Ranking	The notes will be secured and rank equally with our senior secured indebtedness secured by a pledge of the same assets. The notes will rank senior, to the extent of the assets securing such indebtedness, to our senior unsecured indebtedness and senior to our subordinated indebtedness. The notes will effectively rank junior to our subsidiaries’ liabilities. As of September 30, 2017: • IPALCO had outstanding $810 million of senior secured indebtedness; and • IPL had total long-term debt, current liabilities and preferred stock of approximately $2.1 billion.
Optional Redemption	We may redeem some or all of the notes at any time or from time to time at a redemption price as described under the caption “Description of Notes—Optional Redemption.”
Change of Control	When a Change of Control Triggering Event (as defined herein) occurs, each holder of notes may require us to repurchase all or a portion of its notes at a purchase price equal to 101% of the principal amount of the notes, plus accrued interest. See “Description of Notes—Repurchase at the Option of Holders.”

Covenants	The indenture governing the notes contains covenants that, among other things, will limit our ability and, in the case of restrictions on liens, the ability of our significant subsidiaries to: • create certain liens on assets and properties; and • consolidate or merge, or convey, transfer or lease all or substantially all of our consolidated properties and assets. These covenants are subject to important exceptions and qualifications, which are described in “Description of Notes—Covenants.” The indenture does not restrict or prevent IPL or any other subsidiary from incurring unsecured indebtedness.
Book-Entry Form	The notes will be issued in registered book-entry form represented by one or more global notes to be deposited with or on behalf of The Depository Trust Company (“DTC”) or its nominee. Transfers of the notes will be effected only through the facilities of DTC. Beneficial interests in the global notes may not be exchanged for certificated notes except in limited circumstances. See “Description of Notes—Form, Denomination and Registration of Notes.”
Further Issues	We may from time to time, without notice to or the consent of the holders of the notes, create and issue additional debt securities under the indenture governing the notes having the same terms as, and ranking equally with, the notes in all respects (except for the offering price and issue date), as described more fully in “Description of Notes—Basic Terms of Notes.”
Trustee, Registrar and Paying Agent	U.S. Bank National Association.
Governing Law	The indenture and the notes are governed by, and construed in accordance with, the laws of the State of New York.

RISK FACTORS

If any of the following risks occur, our business, results of operations or financial condition could be materially adversely affected. You should read the section captioned “Forward-looking Statements” for a discussion of what types of statements are forward-looking as well as the significance of such statements in the context of this prospectus. The risks described below are not the only ones we face. Additional risks of which we are not presently aware or that we currently believe are immaterial may also harm our business, results of operations or financial condition.

Risks Related to the Exchange Offer

If you choose not to exchange your old notes in the exchange offer, the transfer restrictions currently applicable to your old notes will remain in force and the market price of your old notes could decline.

If you do not exchange your old notes for new notes in the exchange offer, then you will continue to be subject to the transfer restrictions on the old notes as set forth in the offering memorandum distributed in connection with the private offering of the old notes. In general, the old notes may not be offered or sold unless they are registered or exempt from registration under the Securities Act and applicable state securities laws. Except as required by the registration rights agreement entered into in connection with the private offering of the old notes, we do not intend to register resales of the old notes under the Securities Act. The tender of old notes under the exchange offer will reduce the principal amount of the old notes outstanding, which may have an adverse effect upon, and increase the volatility of, the market price of the old notes due to reduction in liquidity.

You must follow the exchange offer procedures carefully in order to receive the new notes.

If you do not follow the procedures described in this prospectus, you will not receive any new notes. If you want to tender your old notes in exchange for new notes, you will need to contact a DTC participant to complete the book-entry transfer procedures, or otherwise complete and transmit a letter of transmittal, in each case described under “The Exchange Offer,” prior to the expiration date, and you should allow sufficient time to ensure timely completion of these procedures to ensure delivery. No one is under any obligation to give you notification of defects or irregularities with respect to tenders of old notes for exchange. For additional information, see the section captioned “The Exchange Offer” in this prospectus.

There are state securities law restrictions on the resale of the new notes.

In order to comply with the securities laws of certain jurisdictions, the new notes may not be offered or resold by any holder, unless they have been registered or qualified for sale in such jurisdictions or an exemption from registration or qualification is available and the requirements of such exemption have been satisfied. We currently do not intend to register or qualify the resale of the new notes in any such jurisdictions. However, generally an exemption is available for sales to registered broker-dealers and certain institutional buyers. Other exemptions under applicable state securities laws also may be available.

Risks Related to the Notes

The notes will be structurally subordinated to claims of creditors of our current and future subsidiaries.

The notes will be structurally subordinated to indebtedness and other liabilities of our subsidiaries, including IPL. Our subsidiaries may also incur additional indebtedness in the future. Any right that we have to receive any assets of any of our subsidiaries upon the liquidation or reorganization of those subsidiaries, and the consequent rights of holders of the notes to realize proceeds from the sale of any of those subsidiaries’ assets, will be effectively subordinated to the claims of those subsidiaries’ creditors, including trade creditors and holders of preferred equity interests of those subsidiaries. Accordingly, in the event of a bankruptcy, liquidation or reorganization of any of our subsidiaries, these subsidiaries will pay the holders of their debts, holders of their preferred equity interests and their trade creditors before they will be able to distribute any of their assets to us. The security interest in the common stock of IPL pledged by us to secure the notes will not alter the effective subordination of the notes to the creditors of our subsidiaries.

We may incur additional indebtedness, which may affect our financial health and our ability to repay the notes.

As of September 30, 2017, we had on a consolidated basis $2.5 billion of long-term indebtedness and total common shareholders’ equity of $577.7 million. As of September 30, 2017, our long-term indebtedness includes $810.0 million aggregate principal of senior secured notes, which are secured, equally and ratably with the notes, by the pledge of all the outstanding common stock of IPL. IPL had $1.6 billion of first mortgage bonds outstanding as of September 30, 2017, 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. The

indenture governing the notes does not restrict IPL’s or any of our subsidiaries’ ability to incur unsecured indebtedness. As of September 30, 2017, IPL had $120.5 million of outstanding borrowings on its unsecured, 5-year $250 million revolving credit facility and $90.0 million of unsecured notes issued by the Indiana Finance Authority on behalf of IPL. This level of indebtedness and related security could have important consequences, including the following:

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increase our vulnerability to general adverse economic and industry conditions;

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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;

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limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and

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limit, along with the financial and other restrictive covenants in our indebtedness, among other things, our ability to borrow additional funds, as needed.

We expect to incur additional debt in the future, subject to the terms of our debt agreements and we expect that IPL will incur additional debt in the future, subject to the terms of its debt agreements and regulatory approvals. To the extent we or IPL become more leveraged, the risks described above would increase. Further, our actual cash requirements in the future may be greater than expected. Accordingly, our cash flow from operations may not be sufficient to repay at maturity all of the outstanding debt as it becomes due and, in that event, we may not be able to borrow money, sell assets or otherwise raise funds on acceptable terms or at all to refinance our debt as it becomes due.

We are a holding company and are dependent on Indianapolis Power & Light Company for dividends to meet our debt service obligations.

We are a holding company with no material assets other than the common stock of our subsidiaries, and accordingly substantially all cash is generated by the operating activities of our subsidiaries, principally IPL. None of our subsidiaries, including IPL, is obligated to make any payments with respect to the notes, and none of our subsidiaries will guarantee the notes; however, the common stock of IPL is pledged to secure payment of these notes. Accordingly, our ability to make payments on the notes is dependent not only on the ability of our subsidiaries to generate cash in the future, but also on the ability of our subsidiaries to distribute cash to us. 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 us under certain circumstances.

We may not be able to repurchase the notes upon a change of control triggering event.

Upon the occurrence of specific kinds of change of control triggering events, we will be required to offer to repurchase all outstanding notes at 101% of their principal amount plus accrued and unpaid interest (see “Description of Notes-Repurchase at the Option of Holders”). The source of funds for any such purchase of the notes will be our available cash or cash generated from our subsidiaries’ operations or other sources, including borrowings, sales of assets or sales of equity. We may not be able to satisfy our obligations to repurchase the notes upon a change of control triggering event because we may not have sufficient financial resources to purchase all of the notes that are tendered upon a change of control triggering event.

Redemptions may adversely affect your return on the notes.

The notes are redeemable at our option, and therefore we may choose to redeem the notes at times when the prevailing interest rates are relatively low. As a result, you may not be able to reinvest the proceeds you receive from the redemption in a comparable security at an effective interest rate as high as the interest rate on your notes being redeemed.

Regulatory considerations may affect the ability of the collateral agent to exercise certain rights with respect to the collateral securing the notes.

Regulatory considerations may affect the ability of the collateral agent to exercise certain rights with respect to the common stock of IPL pledged by us to secure the notes upon the occurrence of an event of default under the indenture governing the notes. Because IPL is a regulated public utility, foreclosure proceedings and the enforcement of the pledge agreement and the right to take other actions with respect to the pledged shares of IPL common stock may be limited and subject to regulatory approval. IPL is subject to regulation at the state level by the IURC. At the federal level, it is subject to regulation by the FERC. See “Business-Regulatory Matters.” Regulation by the IURC and FERC includes regulation with respect to the change of control, transfer or ownership of utility property. In particular, foreclosure proceedings and the enforcement of the pledge agreement and the right to take other actions with respect to the pledged shares of IPL common stock would require (i) FERC approval to the extent such actions resulted in a change in control or a transfer of the ownership of the

pledged shares of IPL common stock and (ii) IURC approval to the extent such actions resulted in a transfer of the ownership of the pledged shares of IPL common stock to another Indiana utility. There can be no assurance that any such regulatory approval can be obtained on a timely basis, or at all.

Credit rating downgrades could adversely affect the trading price of the notes.

The trading price for the notes may be affected by our credit rating, and our credit rating may be affected by the credit rating of AES. Credit ratings are continually revised and there can be no assurance that our current credit rating or the current credit rating of AES will remain the same for any given period of time or that such ratings will not be downgraded or withdrawn entirely by a rating agency if, in that rating agency’s judgment, future circumstances relating to the basis of the rating, such as adverse changes, so warrant. Any downgrade in, or withdrawal of, our credit rating or the credit rating of AES could adversely affect the trading price of the notes or the trading markets for the notes to the extent trading markets for the notes develop. Credit ratings are not recommendations to purchase, hold or sell the notes. Additionally, credit ratings may not reflect the potential effect of risks related to the structure or marketing of the notes. One rating agency’s rating should be evaluated independently of any other rating agency’s rating.

Risks Related to Our Business

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 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:

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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;

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unit or facility shutdowns due to a breakdown or failure of equipment or processes;

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disruptions in the availability or delivery of fuel and lack of adequate inventories;

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shortages of or delays in obtaining equipment;

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loss of cost-effective disposal options for solid waste generated by the facilities;

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labor disputes or work stoppages by employees;

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accidents and injuries;

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reliability of our suppliers;

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inability to comply with regulatory or permit requirements;

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operational restrictions resulting from environmental or permit limitations or governmental interventions;

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construction delays and cost overruns;

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disruptions in the delivery of electricity;

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the availability of qualified personnel;

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events occurring on third party systems that interconnect to and affect our system;

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operator error; and

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catastrophic events.

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 results of operations, financial condition and cash flows. If unexpected plant outages occur frequently and/or for extended periods of time, this could result in adverse regulatory action and/or reduced wholesale revenues.

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. 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 our 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, except for IPL’s large substations, 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 and cash flows.

In addition, operation of our generating stations below expected capacity levels, or unplanned outages at these stations, could cause reduced energy output and efficiency levels, which would likely result in decreased revenues and/or increased expenses that could have a material adverse effect on our results of operations, financial condition and cash flows.

We may not always be able to recover our costs to deliver electricity to our retail customers. The costs we can recover and the return on capital we are permitted to earn for certain aspects of our business are regulated and governed by the laws of Indiana and the rules, policies and procedures of the IURC.

We are currently obligated to supply electric energy to retail customers in our service territory. Even though rate regulation is premised on full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the IURC will agree that all of our costs have been prudently incurred or are recoverable. There also is no assurance that the regulatory process in which rates are determined will always result in rates that will produce a full or timely recovery of our costs and authorized return. From time to time, the demand for electric energy required to meet our service 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. 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, and we may not be allowed to recover all of such costs through our FAC. Even if a supply shortage were brief, we could suffer substantial losses that could adversely affect our results of operations, financial condition and cash flows.

Changes in, or reinterpretations of, the laws, rules, policies and procedures that set electric rates, permitted rates of return, changes in IPL’s rate structure, regulations regarding ownership of generation assets and electric service, reliability initiatives, fuel and purchased power (which account for a substantial portion of our operating costs), capital expenditures and investments and the recovery of these and other costs on a full or timely basis through rates, power market prices and changes to the frequency and timing of rate increases could have a material adverse effect on our results of operations, financial condition and cash flows.

The availability and cost of fuel and other commodities have experienced and could continue to experience significant volatility and we may not be able to hedge the entire exposure of our operations from availability and price volatility. In addition, a significant amount of our electricity is generated by coal.

Our business is sensitive to changes in the price of coal, 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. We also are dependent on purchased power, in part, to meet our seasonal planning reserve margins. Any changes in fuel prices could affect the prices we charge, our operating costs and our competitive position with respect to our products and services.

Our exposure to fluctuations in the price of fuel 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 (please see “Business-Regulatory Matters-FAC and Authorized Annual Jurisdictional Net Operating Income” for additional details regarding the benchmark and the process to recover fuel costs). As part of this cost-recovery process, 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. If we are unable to timely or fully recover our fuel and purchased power costs, it could have a material adverse effect on our results of operations, financial condition and cash flows.

Approximately 84% of the energy we produced in 2016 was generated by coal as compared to approximately 97% and 99% in 2015 and 2014, respectively. While we have approximately 85% in total of our current coal requirements for the three-year period ending December 31, 2019 under long-term contracts as of the date of this prospectus, 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. The coal market has experienced significant price volatility in the last several years. We are now in a global market for coal in which our domestic price is increasingly affected by international supply disruptions and demand balance. Coal exports from the U.S. have increased significantly at times in recent years. In addition, domestic developments such as government-imposed direct costs and permitting issues that affect mining costs and supply availability, and the variable demand of retail customer load and the performance of our generation fleet have an impact on our fuel procurement operations. In addition, pricing provisions in some of our coal contracts with terms of one year or more allow for price changes under certain circumstances.

Because of our substantial dependence on coal to meet customer demand for electricity, our business and operations could be materially adversely affected by unexpected 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 and non-governmental organizations have expressed concern about 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 results of operations, financial condition and cash flows. Our dependence on coal also means that the output of our coal-fired generation units can be greatly affected by the costs of other fuels combusted by generation facilities that compete with our coal-fired generation units. Natural gas prices over the last several years have been relatively low and some gas-fired generators that previously were primarily used during periods of peak and intermediate electric demand have run even during periods of relatively low demand. This has caused many coal-fired generators, including ours, to run fewer hours during these periods of base-load demand.

In addition, substantially all of our coal supply is currently mined in the state of Indiana, and all of our coal supply is currently mined by unaffiliated suppliers or third parties. Our current 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. IPL has long-term contracts with three suppliers, with about 53% of our existing coal under contract for the three-year period ending December 31, 2019 coming from one supplier. In recent years, the coal industry has undergone significant restructuring as a result of debt restructurings, bankruptcy proceedings and other factors. Further restructuring may result in a failure of our suppliers to fulfill their contractual obligations or fewer suppliers and, consequently, increased dependency on any one supplier. Any significant disruption in the ability of our suppliers, particularly our most significant suppliers, to mine or deliver coal or other fuel, or any failure on the part of our suppliers to fulfill their contractual obligations 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 fuel on similarly favorable terms, which could also limit our ability to recover fuel costs through the FAC proceedings.

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

Catastrophic events such as fires, explosions, cyber-attacks, terrorist acts, acts of war, pandemic events, or natural disasters such as floods, earthquakes, tornadoes, severe winds, ice or snow storms, droughts or other similar occurrences could adversely affect our generation facilities, transmission and distribution systems, results of operations, financial condition and cash flows. 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 both areas of significant seismic activity in the central U.S.

Regulators, politicians and non-governmental organizations have expressed concern about 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 results of operations, financial condition and cash flows.

One byproduct of burning coal and other fossil fuels is the emission of GHGs, including CO₂. At the federal, state and regional levels, policies are under development or have been developed to regulate GHG emissions, including by effectively putting a cost on such emissions to create financial incentives to reduce them. In 2016, IPL emitted approximately 13 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 determined from emissions monitoring data and calculations using actual fuel heat inputs and fuel type CO₂ emission factors.

Any existing or future international, 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 adverse impact on our results of operations, financial condition and cash flows. Such legislation and regulations could also impair the value of our generation stations or make some of these stations uneconomical to maintain or operate and could raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new existing generation stations. Although we may seek recovery of costs associated with new climate change or GHG regulations, our inability to fully or timely recover such costs court have a material adverse effect on our results of operations, financial condition and cash flows. Additionally, concerns over GHG emissions and their effect on the environment have led, and could lead further, to reduced demand for coal-fired power, which could have a material adverse effect on our results of operations, financial condition and cash flows.

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 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 “Business-Environmental Matters” for additional information about environmental matters impacting us, including those relating to regulation of GHG emissions.

We are subject to numerous environmental laws and regulations that require capital expenditures, increase our cost of operations, may expose us to environmental liabilities or make continued operation of certain generating units unprofitable.

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 regulated materials, including ash; the use and discharge of water used in generation boilers and for cooling purposes; the emission and discharge of hazardous and other materials into the environment; and the health and safety of our employees. We could also become subject to additional environmental laws and regulations and other requirements in the future. Environmental laws and regulations also generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other governmental authorizations. 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. If we are not able to timely obtain, maintain or comply with all licenses, permits, inspections and other government authorizations required to operate our business, then our operations could be prevented, delayed or subject to additional costs. A violation of environmental laws, regulations, permits or other requirements can result in substantial fines, penalties, other sanctions, permit revocation, facility shutdowns, the imposition of stricter environmental standards and controls or other injunctive measures affecting operating assets. In addition, any alleged violation of these laws, regulations and other requirements may require us to expend significant resources to defend against any such alleged violations. Compliance with these laws, regulations and other requirements requires us to expend significant funds and resources and could at some point become prohibitively expensive or result in our shutting down (temporarily or permanently) or altering the operation of our facilities. Under certain environmental laws, we could also 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. From time to time we are subject to enforcement and litigation actions for claims of noncompliance with environmental laws and regulations. We cannot assure that we will be successful in defending against any claim of noncompliance. Any alleged violation of these laws, regulations and other requirements may require us to expend significant resources to defend against any such alleged violations. Our costs and liabilities relating to environmental matters could have a material adverse effect on our results of operations, financial condition and cash flows.

The amount of capital expenditures required to comply with environmental laws or regulations could be impacted by the outcome of the EPA’s NOVs described in “Business-Environmental Matters-New Source Review and Other CAA NOVs.” These NOVs could also result in fines, which could be material. In addition to the five oil-fired peaking units IPL retired in the second quarter of 2013, the four coal-fired units at Eagle Valley were retired in April 2016, as described in “Business-Environmental Matters-Unit Retirements and Replacement Generation.” Our units were primarily coal-fired and the units that have been retired and/or converted and were not equipped with the advanced environmental control technologies needed to comply with existing and expected regulations.

The use of non-derivative and derivative instruments in the normal course of business could result in losses that could negatively impact our results of operations, financial position and cash flows.

We sometimes use non-derivative and derivative instruments, such as swaps, options, futures and forwards, to manage commodity and financial risks. We may at times enter into forward contracts to hedge the risk of volatility in earnings from wholesale marketing activities. These trades are affected by a range of factors, including variations in power demand, fluctuations in market prices, market prices for alternative commodities and optimization opportunities. We have attempted to manage our commodities price risk exposure by establishing and enforcing risk limits and risk management policies. Despite our efforts, however, these risk limits and management policies may not work as planned and fluctuating prices and other events could adversely affect our results of operations, financial condition and cash flows. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these instruments can involve management’s judgment or the use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of some of these contracts. We could also recognize financial losses as a result of volatility in the market values of these contracts, a counterparty failing to perform, or the underlying transactions which the instruments are intended to hedge failing to materialize, which could result in a material adverse effect on our results of operations, financial condition and cash flows. Although we have not used any derivative instruments recently, we may do so in the future, and their use could result in losses that could negatively impact us.

The Dodd-Frank Act contains significant requirements related to derivatives that, among other things, could reduce the cost effectiveness of entering into derivative transactions.

In July 2010, The Dodd-Frank Act was signed into law. The Dodd-Frank Act contains significant requirements relating to derivatives, including, among others, a requirement that certain transactions be cleared on exchanges that would necessitate the posting of cash collateral for these transactions. We are considered an end-user under the Dodd-Frank Act and therefore are exempt from most of the collateral and margining requirements. We are required to report any bilateral derivative contracts, unless our counterparty is a major swap participant or has elected to report on our behalf. Even though we qualify for an exception from these requirements, our counterparties that do not qualify for the exception may pass along any increased costs incurred by them through higher prices and reductions in unsecured credit limits or be unable to enter into certain transactions with us. The occurrence of any of these events could have an adverse effect on our results of operations, financial condition and cash flows.

Our business is sensitive to weather and seasonal variations.

Weather conditions significantly affect the demand for electric power, and accordingly, our business is affected by variations in general weather conditions and unusually severe weather. As a result of these factors, our 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. In addition, severe or unusual weather, such as tornadoes and ice or snow storms, may cause outages and property damage that may require us to incur additional costs that may not be insured or recoverable from customers. While we are permitted to seek recovery of storm damage costs, if we are unable to fully recover such costs in a timely manner, it could have a material adverse effect on our results of operations, financial condition and cash flows.

Our membership in a regional transmission organization presents risks that could have a material adverse effect on our results of operations, financial condition and cash flows.

We are a member of MISO, a FERC-regulated regional transmission organization. MISO serves the electrical transmission needs of a 15-state area including much of the Mid-U.S and Canada and maintains functional operational control over our electric transmission facilities, as well as that of the other 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.

The rules governing the various regional power markets may also change from time to time which could affect our costs and revenues and have a material adverse effect on our results of operations, financial condition and cash flows. We may be required to expand or otherwise change our transmission system according to decisions made by MISO rather than our internal planning process. In addition, various proposals and proceedings before the FERC relating to MISO or otherwise may cause transmission rates to change from time to time. We also incur fees and costs to participate in MISO.

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 and cash flows. Please see “Business-MISO Operations” and “Business-Regulatory Matters.”

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 financial 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 the capital and credit markets as a source of liquidity for capital requirements not satisfied by operating cash flows. These capital and credit markets experience volatility and disruption from time to time, and the ability of corporations to raise capital can be negatively impacted. Disruptions in the capital and credit markets make it harder and more expensive to raise capital. 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 supply and 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. Access to funds under our existing financing arrangements is also dependent on the ability of our counterparties to meet their financing commitments. Our inability to obtain financing on reasonable terms, or at all, with creditworthy counterparties could adversely affect our results of operations, financial condition and cash flows. If our available funding is limited or we are forced to fund our operations at a higher cost, these conditions may require us to curtail our business activities and increase our cost of funding, both of which could reduce our profitability.

See Note 7, “Debt” to the audited Consolidated Financial Statements of IPALCO, which is included in this prospectus, for information regarding indebtedness. See also “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Quantitative and Qualitative Disclosures About Market Risk” for information related to market risks.

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. Beginning April 1, 2016, wholesale margins above and below an established annual benchmark of $6.3 million that is included in IPL’s base rates are shared with our customers at 50%. Accordingly, 50% of any margin above or below $6.3 million is returned to or recovered from IPL’s customers through a rider. 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 2016, 2015 or 2014.

In addition, the introduction of additional renewable energy, demand response or other energy supply into the MISO market could have the effect of reducing the demand for wholesale energy from other sources. This additional generation could have the impact of reducing market prices for energy and could reduce our opportunity to sell our 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.

As a result of the retirement of the coal-fired units at Eagle Valley (April 2016), we expect our ability to have excess generation available for sale on the wholesale market will be adversely impacted until the expected completion of the CCGT in the first half of 2018.

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 with the adequacy of transmission capacity on IPL’s system or the regional systems operated by MISO could result in MISO, the NERC, the FERC or the IURC requiring us to upgrade or expand our transmission system through additional capital expenditures or share in the costs of regional expansion.

Current and future conditions in the economy may adversely affect our customers, suppliers and other 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. Slowing global economic growth, credit market conditions, fluctuating consumer and business confidence, fluctuating commodity prices, and other challenges currently affecting the general economy, have caused and may continue to cause some of our customers 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. Sustained downturns, recessions or a sluggish economy generally affect the markets in which we operate and negatively influence our energy operations. A contracting, slow or sluggish economy could reduce the demand for energy in areas in which we are doing business. For example, during economic downturns, our commercial and industrial customers may see a decrease in demand for their products, which in turn may lead to a decrease in the amount of energy they require. Furthermore, projects which may result in potential new customers may be delayed until economic conditions improve. Some of our suppliers, customers and other counterparties, and others with whom we transact business may also experience 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. Reduced demand for our electric services, failure by our customers to timely remit full payment owed to us and supply delays or unavailability could have a material adverse effect on, our results of operations, financial condition and cash flows could be materially adversely affected. In particular, the projected economic growth and total employment in Indianapolis are important to the realization of our forecasts for annual energy sales.

Economic conditions relating to the asset performance and interest rates of the Pension Plans could materially and adversely 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. Further, the performance of the capital markets affects the values of the assets that are held in trust to satisfy future obligations under the Pension Plans. These

assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. A decline in the market value of the Pension Plans’ assets will increase the funding requirements under the Pension Plans if the actual asset returns do not recover these declines in value in the foreseeable future. Future pension funding requirements, and the timing of funding payments, may also be subject to changes in legislation. We are responsible for funding any shortfall of our Pension Plans’ assets compared to obligations under the Pension Plans, and a significant increase in our pension liabilities could materially and adversely impact our results of operations, financial condition, and cash flows. We are subject to the Pension Protection Act of 2006, which requires underfunded pension plans to improve their funding ratios within prescribed intervals based on the level of their underfunding. As a result, our required contributions to these plans, at times, have increased and may increase in the future. In addition, our pension and postemployment benefit plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the discounted liabilities increase benefit expense and funding requirements. Further, changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase the funding requirements for the obligations related to the pension and other postemployment benefit plans. Declines in market values and increased funding requirements could have a material adverse effect on our results of operations, financial condition and cash flows.

Please see Note 9, “Benefit Plans” to the audited Consolidated Financial Statements of IPALCO, which is included in this prospectus, for further discussion.

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

We enter into transactions with and rely on many counterparties in connection with our business, including for the purchase and delivery of inventory, including fuel and equipment components, for our capital improvements and additions and to provide professional services, such as actuarial calculations, payroll processing and various consulting services. If any of these counterparties fails to perform its obligations to us or becomes unavailable, our business plans may be materially disrupted, we may be forced to discontinue certain operations if a cost-effective alternative is not readily available or we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices and cause delays.

Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than the relief provided by these mitigation provisions. Any of the foregoing could result in regulatory actions, cost overruns, delays or other losses, any of which (or a combination of which) could have a material adverse effect on our results of operations, financial condition and cash flows.

Further, 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. 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, particularly with regard to the cost of the project. As a result of these events, we might incur losses or delays in completing construction.

Accidental improprieties and undetected errors in our internal controls and information reporting could result in the disallowance of cost recovery, noncompliant disclosure or incorrect payment processing.

Our internal controls, accounting policies and practices and internal information systems are designed to enable us to capture and process transactions and information in a timely and accurate manner in compliance with GAAP, laws and regulations, taxation requirements and federal securities laws and regulations in order to, among other things, disclose and report financial and other information in connection with the recovery of our costs and with our reporting requirements under federal securities, tax and other laws and regulations and to properly process payments. We have also implemented corporate governance, internal control and accounting policies and procedures in connection with the Sarbanes-Oxley Act of 2002. Our internal controls and policies have been and continue to be closely monitored by management and our Board of Directors. While we believe these controls, policies, practices and systems are adequate to verify data integrity, unanticipated and unauthorized actions of employees, temporary lapses in internal controls due to shortfalls in oversight or resource constraints could lead to improprieties and undetected errors that could result in the disallowance of cost recovery, noncompliant disclosure and reporting or incorrect payment processing. The consequences of these events could have a material adverse effect on our results of operations, financial condition and cash flows.

New accounting standards or changes to existing accounting standards could materially affect how we report our results of operations, financial condition and cash flows.

Our financial statements are prepared in accordance with GAAP. The SEC, FASB or other authoritative bodies or governmental entities may issue new pronouncements or new interpretations of existing accounting standards that may require us to change our accounting policies. These changes are beyond our control, can be difficult to predict and could materially affect how we report our results of operations, financial condition and cash flows. We could be required to apply a new or revised standard retroactively, which could adversely affect our financial condition. In addition, in preparing our financial statements, management is required to make estimates and assumptions. Actual results could differ significantly from those estimates.

We are subject to extensive laws and local, state and federal regulation, as well as litigation and other proceedings that could affect our operations and costs.

As an electric utility, we are subject to extensive regulation at both the federal and state level. For example, 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 and incurrence of long term debt, the acquisition and sale of some public utility properties or securities and certain other matters.

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. In addition, IPL’s rates include various adjustment mechanisms including, but not limited to: (i) a rider to reflect changes in fuel and purchased power costs to meet IPL’s retail load requirements, referred to as the FAC, and (ii) a rider for the timely recovery of costs (including a return) incurred to comply with environmental laws and regulations referred to as the ECCRA. IPL also received approval (in its March 2016 IURC order) to implement three new rate riders for current recovery from customers of ongoing MISO costs and capacity costs, and for sharing with retail customers 50% of wholesale sales margins above and below an established annual benchmark of $6.3 million. Additionally, the capacity rider provides that IPL will share with customers 50% of any capacity sales. Each of these tariff rate components may be set and approved by the IURC in separate proceedings at different points in time (the FAC proceedings occur on a quarterly basis, the ECCRA proceedings occur on a semiannual basis, and the proceedings for the three new rate riders occur on an 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.

In addition, we must seek approval from the IURC through such public proceedings of our rate adjustment mechanism factors to reflect changes in certain costs, such as: fuel and purchased power costs; costs incurred to comply with environmental laws, regulations and other federal mandates; DSM program costs; MISO costs; and for certain other costs. There can be no assurance that we will be granted approval of rate adjustment mechanism factors that we request from the IURC. The failure of the IURC to approve any requested relief, or any other adverse rate determination by the IURC could have a material adverse effect on our results of operations, financial condition and cash flows.

As a result of the EPAct and subsequent legislation affecting the electric utility industry, we have been required to comply with rules and regulations in areas including mandatory reliability standards, cyber security, transmission expansion and energy efficiency. We are currently unable to predict the long-term impact, if any, to our results of operations, financial condition and cash flows as a result of these rules and regulations. Complying with the regulatory environment to which we are subject requires us to expend a significant amount of funds and resources. The failure to comply with this regulatory environment could subject us to substantial financial costs and penalties and changes, either forced or voluntary, in the way we operate our business.

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. In addition to effects on our business that could result from any deregulation, such as a loss of customers and increased costs to retain or attract customers upon deregulation, adjustments to IPL’s accounting records may be required to eliminate the historical impact of regulatory accounting. Such adjustments, as required by FASB 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.

We may be subject to material litigation, regulatory proceedings, administrative proceedings, audits, 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 2, “Regulatory Matters” and Note 10, “Commitments and Contingencies” to the audited Consolidated Financial Statements of IPALCO, which are included in this prospectus, for a summary of significant regulatory matters and legal proceedings involving us.

If we are unable to maintain a qualified and properly motivated workforce, it could have a material adverse effect on our results of operations, financial condition and cash flows.

One of the challenges we face is to retain a skilled, efficient and cost-effective workforce while recruiting new talent to replace losses in knowledge and skills due to resignations, terminations or retirements. This undertaking could require us to make additional financial commitments and incur increased costs. If we are unable to successfully attract and retain an appropriately qualified workforce, it could have a material adverse effect on our results of operations, financial condition and cash flows. In addition, we have employee compensation plans that reward the performance of our employees. We seek to ensure that our compensation plans encourage acceptable levels for risk and high performance through pay mix, performance metrics and timing. We also have policies and procedures in place to mitigate excessive risk-taking by employees since excessive risk- taking by our employees to achieve performance targets could result in events that could have a material adverse effect on our results of operations, financial condition and cash flows.

We are subject to collective bargaining agreements that could adversely affect our business, results of operations, financial condition and cash flows.

We are subject to collective bargaining agreements with employees who are members of a union. Approximately 64% of our employees are represented by a union in two bargaining units: a physical unit and a clerical-technical unit. While we believe that we maintain a satisfactory relationship with our employees, it is possible that labor disruptions affecting some or all of our operations could occur during the period of the collective bargaining agreements or at the expiration of the collective bargaining agreements before new agreements are negotiated. 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 by, or poor relations or ineffective negotiations with, our employees or other workforce issues could have a material effect on our results of operations, financial condition and cash flows.

Potential security breaches (including cybersecurity breaches) and terrorism risks could adversely affect our businesses.

We operate in a highly regulated industry that requires the continued operation of sophisticated systems and network infrastructure at our generation stations, fuel storage facilities and transmission and distribution facilities. We also use various financial, accounting and other systems in our businesses. These systems and facilities are vulnerable to unauthorized access due to hacking, viruses, other cybersecurity attacks and other causes. In particular, given the importance of energy and the electric grid, there is the possibility that our systems and facilities could be targets of terrorism or acts of war. We have implemented measures to help prevent unauthorized access to our systems and facilities, including certain measures to comply with mandatory regulatory reliability standards. Despite our efforts, if our systems or facilities were to be breached or disabled, we may be unable to recover them in a timely way to fulfill critical business functions, including the supply of electric services to our customers, and we could experience decreases in revenues and increases in costs that could adversely affect our results of operations, cash flows and financial condition.

In the course of our business, we also store and use customer, employee, and other personal information and other confidential and sensitive information. If our or our third party vendors’ systems were to be breached or disabled, sensitive and confidential information and other data could be compromised, which could result in negative publicity, remediation costs and potential litigation, damages, consent orders, injunctions, fines and other relief.

To help mitigate these risks, we maintain insurance coverage against some, but not all, potential losses, including coverage for illegal acts against us. However, insurance may not be adequate to protect us against all costs and liabilities associated with these risks.

IPALCO is a holding company and parent of IPL and other subsidiaries. IPALCO’s cash flow is dependent on operating cash flows of IPL and its ability to pay cash to IPALCO.

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. As such, IPALCO’s cash flow is largely dependent on the operating cash flows of IPL and its ability to pay cash to IPALCO. IPL’s mortgage and deed of trust, its amended articles of incorporation and its Credit Agreement and unsecured notes 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources” for a discussion of these restrictions. See Note 7, “Debt” to the audited Consolidated Financial Statements of IPALCO, which is included in this prospectus, for information regarding indebtedness. In addition, IPL is regulated by the IURC, which possesses broad oversight powers to ensure that the needs of utility customers are being met. The IURC could impose additional restrictions on the ability of IPL to distribute, loan or advance cash to IPALCO pursuant to these broad powers. While we do not expect any of the foregoing restrictions to significantly affect IPL’s ability to pay funds to IPALCO in the future, a significant limitation on IPL’s ability to pay dividends or loan or advance funds to IPALCO would have a material adverse effect on IPALCO’s results of operations, financial condition and cash flows.

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 U.S. Investments (82.35%) and CDPQ (17.65%). Due to our relationship with AES, any adverse developments and announcements concerning AES may impair our ability to access the capital markets and to otherwise conduct business. In particular, downgrades in AES’s credit ratings could result in IPL or IPALCO’s credit ratings being downgraded.

FORWARD-LOOKING STATEMENTS

This prospectus includes certain “forward-looking statements” that involve many risks and uncertainties. Forward-looking statements express an expectation or belief and contain a projection, plan or assumption with regard to, among other things, our future revenues, income, expenses or capital structure. Such statements of future events or performance are not guarantees of future performance and involve estimates, assumptions and uncertainties. The words “could,” “may,” “predict,” “anticipate,” “would,” “believe,” “estimate,” “expect,” “forecast,” “project,” “objective,” “intend,” “continue,” “should,” “plan,” and similar expressions, or the negatives thereof, are intended to identify forward-looking statements unless the context requires otherwise. These forward-looking statements are based on management’s present expectations and beliefs about future events. As with any projection or forecast, these statements are inherently susceptible to uncertainty and changes in circumstances. We are under no obligation to, and expressly disclaim any obligation to, update or alter the forward-looking statements whether as a result of such changes, new information, subsequent events or otherwise. If we do update one or more forward-looking statements, no inference should be made that we will make additional updates with respect to those or other forward-looking statements.

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

•

fluctuations in customer growth and demand;

•

impacts of weather on retail sales and wholesale prices;

•

impacts of renewable energy generation, natural gas prices and other market factors on wholesale prices;

•

weather-related damage to our electrical system;

•

fuel, commodity and other input costs;

•

performance of our suppliers;

•

generating unit availability and capacity;

•

transmission and distribution system reliability and capacity; including natural gas pipeline system and supply constraints;

•

purchased power costs and availability;

•

availability and price of capacity;

•

regulatory action, including, but not limited to, the review of our basic rates and charges by the IURC;

•

federal and state legislation and regulations;

•

changes in our credit ratings or the credit ratings of AES;

•

fluctuations in the value of pension plan assets, fluctuations in pension plan expenses and our ability to fund defined benefit pension plans;

•

changes in financial or regulatory accounting policies;

•

environmental matters, including costs of compliance with current and future environmental laws and requirements;

•

interest rates, inflation rates and other costs of capital;

•

the availability of capital;

•

the ability of subsidiaries to pay dividends or distributions to IPALCO;

•

level of creditworthiness of counterparties to contracts and transactions;

•

labor strikes or other workforce factors, including the ability to attract and retain key personnel;

•

facility or equipment maintenance, repairs and capital expenditures;

•

significant delays or unanticipated cost increases associated with large construction projects;

•

the availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material;

•

local economic conditions;

•

catastrophic events such as fires, explosions, cyber-attacks, terrorist acts, acts of war, pandemic events, or natural disasters such as floods, earthquakes, tornadoes, severe winds, ice or snow storms, droughts, or other similar occurrences;

•

costs and effects of legal and administrative proceedings, audits, settlements, investigations and claims and the ultimate disposition of litigation;

•

industry restructuring, deregulation and competition;

•

issues related to our participation in MISO, including the cost associated with membership, allocation of costs, costs associated with transmission expansion, the recovery of costs incurred, and the risk of default of other MISO participants;

•

changes in tax laws and the effects of our strategies to reduce tax payments;

•

the use of derivative contracts; and

•

product development, technology changes, and changes in prices of products and technologies.

All of the above factors are difficult to predict, contain uncertainties that may materially affect actual results, and many are beyond our control. See “Risk Factors” and/or “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a more detailed discussion of the foregoing and certain other factors that could cause actual results to differ materially from those reflected in any forward-looking statements and that should be considered in evaluating our outlook.

USE OF PROCEEDS

We will not receive any cash proceeds from the issuance of the new notes. The new notes will be exchanged for old notes as described in this prospectus upon our receipt of old notes. We will cancel all of the old notes surrendered in exchange for the new notes.

RATIO OF EARNINGS TO FIXED CHARGES

The following table presents our consolidated ratio of earnings to fixed charges for the periods indicated:

	Nine Months Ended September 30, 2017	Year Ended December 31,
	Nine Months Ended September 30, 2017	2016	2015	2014	2013	2012
Ratio of earnings to fixed charges	2.04	2.33	1.61	1.96	1.80	1.98

For the purposes of computing the ratio of earnings to fixed charges, earnings consist of income from continuing operations before income taxes plus fixed charges (less capitalized interest) and the preferred dividend requirement of our subsidiary. Fixed charges consist of interest on all indebtedness, amortization of debt discount, the preferred dividend requirement of our subsidiary and that portion of rental expense which we believe to be representative of an interest factor.

CAPITALIZATION

The following table sets forth our consolidated capitalization as of September 30, 2017. This table should be read in conjunction with the discussions under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited and unaudited consolidated financial statements and notes thereto included in this prospectus.

	September 30, 2017
(Unaudited)	(in thousands)
Common shareholders’ equity:
Paid in capital	$	597,296
Accumulated deficit		(19,645	)
Total common shareholders’ equity		577,651
Cumulative preferred stock of subsidiary		59,784
Long-term debt (less current maturities) (1)		2,477,051
Total capitalization	$	3,114,486

(1)

As of September 30, 2017, $0 of our long-term debt was classified as current maturities exclusive of $120.5 due under our committed line of credit.

SELECTED CONSOLIDATED FINANCIAL DATA

The table below presents our selected consolidated financial and other data for the periods presented which should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our audited and unaudited consolidated financial statements and the related notes thereto included elsewhere in this prospectus.

The summary consolidated operating and other data for each of the years ended December 31, 2016, 2015 and 2014, and summary consolidated balance sheet data as of December 31, 2016 and 2015 are derived from our audited consolidated financial statements included elsewhere in this prospectus. The summary condensed consolidated operating and other data for each of the nine month periods ended September 30, 2017 and 2016, and summary condensed consolidated balance sheet data as of September 30, 2017 and 2016 are derived from our unaudited condensed consolidated financial statements included elsewhere in this prospectus. The summary consolidated operating and other data for each of the years ended December 31, 2013 and 2012, and summary consolidated balance sheet data as of December 31, 2013 and 2012 are derived from IPALCO’s Annual Report on Form 10-K for the year ended December 31, 2016. The unaudited condensed consolidated financial statements have been prepared on the same basis as the audited consolidated financial statements and, in the opinion of management, include all adjustments, consisting only of normal recurring adjustments, necessary to present fairly the data for the period. The historical results of consolidated operations are not necessarily indicative of results to be expected for any subsequent period.

	Year Ended December 31,											Nine Months Ended September 30,
	2016		2015		2014		2013		2012			2017		2016
	(dollars in thousands)
												(unaudited)
Statement of Operations Data:
Utility operating revenues	$	1,347,430	$	1,250,399	$	1,321,674	$	1,255,734	$	1,229,777		$	1,014,048	$	1,012,373
Utility operating income	$	188,411	$	144,711	$	160,913	$	150,746	$	162,900		$	135,221	$	144,381
Allowance for funds used during construction	$	51,006	$	28,111	$	12,344	$	6,848	$	2,146		$	36,339	$	38,461
Net income	$	131,060	$	59,524	$	77,968	$	64,049	$	71,996		$	83,868	$	104,733
Balance Sheet Data (end of period):
Total assets	$	4,702,281	$	4,217,169	$	3,652,522	$	3,257,989	$	3,268,932		$	4,745,786	$	4,641,622
Common shareholders’ equity (deficit)	$	571,183	$	352,933	$	151,271	$	47,774	$	(3,219	)	$	577,651	$	582,214
Cumulative preferred stock of subsidiary	$	59,784	$	59,784	$	59,784	$	59,784	$	59,784		$	59,784	$	59,784
Long-term debt (less current maturities)	$	2,474,840	$	2,153,276	$	1,935,717	$	1,805,638	$	1,634,780		$	2,477,051	$	2,473,463
Other Data:
Utility capital expenditures⁽¹⁾	$	607,716	$	686,064	$	381,626	$	242,124	$	129,747		$	173,502	$	531,885

(1) Capital expenditures includes $15.5 million and $13.2 million of payments for financed capital expenditures in 2016 and 2015, respectively. Capital expenditures includes $9.8 million and $15.0 million of payments for financed capital expenditures for the nine months ended September 30, 2017 and 2016, respectively.

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 and unaudited consolidated financial statements included elsewhere in this prospectus. The following discussion contains forward-looking statements. Our actual results may differ materially from the results suggested by these forward-looking statements. Please see “Forward Looking Statements” and “Risk Factors” in this prospectus.

OVERVIEW

The most important matters on which we focus in evaluating our consolidated 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, operations, financial and enterprise-wide performance, talent management/people, capital allocation/sustainability and corporate social responsibility) 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 “Business-Regulatory Matters” and “Business-Environmental Matters.”

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 increase, the weighted average price per kWh decreases. The effect is generally more significant with high temperatures than with low temperatures as many of our customers use gas heat. 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 $3.9 million, $3.6 million and $4.6 million in 2016, 2015 and 2014, respectively, and $1.7 million for the first nine months of 2017. In our March 2016 base rate order, we received approval to implement a storm damage restoration reserve account that allows us to defer level 3 storm costs over a benchmark for recovery in a future rate case proceeding.

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

At times, we will purchase power in the wholesale market, and at other times we will have electric generation available for sale in the wholesale market in competition with other utilities and power generators. During the past five fiscal years, wholesale revenues averaged 3.4% of our total electric revenues. A decline in wholesale prices can have a negative impact on earnings, because most of our non-fuel costs are fixed in the short term and lower wholesale prices can result in lower wholesale volumes sold. As a result of our March 2016 base rate order, we received approval to implement a new rate rider sharing 50% of wholesale sales margins over and under a specified benchmark with our retail customers.

As a result of the retirement of the coal-fired units at Eagle Valley (April 2016), our ability to have excess generation available for sale on the wholesale market was adversely impacted in 2016, and we expect will continue to be adversely impacted until the expected completion of the CCGT in the first half of 2018.

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, generation capacity and 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, or we could experience an unscheduled outage during that time. See also, “Business-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 MWh we

sold was $31.17, $28.02, and $34.71 in 2016, 2015 and 2014, respectively. The weighted average price of wholesale MWh we sold in the first nine months of 2017 was $32.98.

Operational Excellence

Our objective is to optimize IPL’s performance in the U.S. utility industry by focusing on the following areas: safety, operations (reliability and customer satisfaction), financial and enterprise-wide performance (efficiency and cost savings, talent management/people, capital allocation/sustainability and corporate social responsibility). 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 some of our financial and enterprise-wide performance measures are company-specific performance goals, they are not benchmarked.

Our safety performance is measured by our lost work day cases, severity rate, and IOSHA recordable incidents. In 2016, our safety performance fell short of our goal of being within the top quartile in our industry. We are committed to excellence in safety and have implemented various programs to increase safety awareness and improve work practices with special emphasis placed on mitigating the hazards associated with high-risk work activities commonly experienced in the industry.

IPL had the best satisfaction rating amongst Indiana investor-owned utilities, as measured by J.D. Power in its 2016 Electric Utility Residential Customer Satisfaction Study. In December 2016, IPL was one of only three Midwest electric utilities recognized as a Utility Customer Champion in the 2016 Utility Trusted Brand and Customer Engagement study by Cogent Reports, a division of Market Strategies International. The study also named IPL as a Utility Environmental Champion (out of 130 utility brands surveyed). We believe these favorable ratings reflect our relatively low rates, strong reliability, corporate citizenship, and focus on excellence in customer service.

The IPL delivery reliability metric for System Average Interruption Frequency Index (“SAIFI”) was better than our target in 2016; however, the System Average Interruption Duration Index (“SAIDI”) was slightly unfavorable to target in 2016. In 2015, IPL ranked near the top decile nationally in SAIDI, SAIFI and Customer Average Interruption Duration Index (“CAIDI”) reliability performance. In addition, IPL had the best SAIDI, SAIFI and CAIDI reliability performance excluding major events in 2015 as compared to the four Indiana investor-owned utilities.

RESULTS OF OPERATIONS

In addition to the discussion on operations below, please see the“Statistical Information on Operations” table included in“Business” for additional data such as kWh sales and number of customers by customer class.

Utility Operating Revenues

2016 versus 2015

Utility operating revenues increased in 2016 from the prior year by $97.0 million, which resulted from the following changes (dollars in thousands):

	2016		2015		Change			Percentage Change
Utility Operating Revenues:
Retail Revenues	$	1,309,006	$	1,210,485	$	98,521		8.1	%
Wholesale Revenues	15,804		19,307		(3,503		)	(18.1	)%
Miscellaneous Revenues	22,620		20,607		2,013			9.8	%
Total Utility Operating Revenues	$	1,347,430	$	1,250,399	$	97,031		7.8	%
Heating Degree Days:
Actual	4,752		5,116		(364		)	(7.1	)%
30-year Average	5,270		5,242
Cooling Degree Days:
Actual	1,454		1,163		291			25.0	%
30-year Average	1,143		1,143

The increase in retail revenues of $98.5 million was primarily due to a net increase in the weighted average price per kWh sold ($96.0 million), partially offset by a slight decrease in the volume of kWh sold ($1.3 million). The increase in retail revenues also includes the one-time impact of recognizing in IPL’s unbilled revenue calculation the increase in IPL’s base rates relating to revenues that were previously charged through IPL’s environmental cost recovery rate adjustment mechanism, or rider ($3.8 million). While billed through a rider, such revenues relating to environmental cost recovery were not includable in our unbilled calculation. The $96.0 million increase in the weighted average price of retail kWh sold was primarily due to: (i) a $55.7 million increase in revenues related to environmental projects, primarily MATS; (ii) DSM program rate adjustment mechanism revenues of $18.9 million; and (iii) the impact of implementing the 2016 rate order along with other retail rate variances. The increase in the weighted average price per kWh sold was partially offset by an $8.4 million decrease in fuel revenues. The majority of the increases in environmental and DSM revenues are offset by increased operating expenses, including depreciation and amortization. The decrease in fuel revenues was offset by decreases in fuel costs as described below.

The decrease in wholesale revenues of $3.5 million was primarily due to a 26% decrease in the quantity of kWh sold ($5.1 million) as IPL’s generation units were not called upon by MISO to produce electricity as often during 2016 versus 2015, largely due to unfavorable prices and unit availability; partially offset by an 11% increase in the weighted average price per kWh sold ($1.6 million). Our ability to be dispatched in the MISO market is primarily driven by the locational marginal price of electricity and variable generation costs. The amount of electricity available for wholesale sales is impacted by our retail load requirements, generation capacity and unit availability. As discussed previously, the retirement of the Eagle Valley coal-fired units and the outage of Harding Street units while they were being converted to natural gas were significant contributors to the lower availability in 2016. Currently, 50% of IPL’s wholesale sales margins above and below an established annual benchmark of $6.3 million are shared with our customers through a rate rider.

2015 versus 2014

Utility operating revenues decreased in 2015 from the prior year by $71.3 million, which resulted from the following changes (dollars in thousands):

	2015		2014		Change			Percentage Change
Utility Operating Revenues:
Retail Revenues	$	1,210,485	$	1,217,522	$	(7,037	)	(0.6	)%
Wholesale Revenues	19,307		83,208		(63,901		)	(76.8	)%
Miscellaneous Revenues	20,607		20,944		(337		)	(1.6	)%
Total Utility Operating Revenues	$	1,250,399	$	1,321,674	$	(71,275	)	(5.4	)%
Heating Degree Days:
Actual	5,116		6,238		(1,122		)	(18.0	)%
30-year Average	5,242		5,240
Cooling Degree Days:
Actual	1,163		900		263			29.2	%
30-year Average	1,143		1,154

The decrease in retail revenues of $7.0 million was primarily due to a decrease in the volume of kWh sold ($17.1 million), which was partially offset by an increase in the weighted average price per kWh sold ($10.1 million). The $17.1 million decrease in the volume of kWh sold was primarily due to warmer temperatures in our service territory during the winter of 2015 versus the comparable period (as demonstrated by the 18% decrease in heating degree days, as shown above). The $10.1 million increase in the weighted average price per retail kWh sold was primarily due to increases in (i) environmental rate adjustment mechanism revenues of $24.8 million and (ii) favorable block rate variances of $6.8 million, mostly attributed to our declining block rate structure, which generally provides for residential and commercial customers to be charged a higher per kWh rate at lower consumption levels. Therefore, as volumes decrease, the weighted average price per kWh increases. These increases in the weighted average price per retail kWh sold were partially offset by decreases in (i) fuel revenues of $20.4 million and (ii) DSM program rate adjustment mechanism revenues of $1.1 million. The decrease in fuel revenues was offset by decreases in fuel costs as described below. Likewise, the vast majority of the increases in environmental rate adjustment mechanism revenues are offset by increased operating expenses, including depreciation and amortization, while the decreases in DSM rate adjustment mechanism revenues are offset by decreased operating expenses.

The decrease in wholesale revenues of $63.9 million was primarily due to a 71% decrease in the quantity of kWh sold ($59.3 million) and a 19% decrease in the weighted average price per kWh sold ($4.6 million) as IPL’s coal-fired generation was not called upon by MISO to produce electricity as often during 2015 versus 2014. Our ability to be dispatched in the MISO market is primarily driven by the locational marginal 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. Unit availability was unfavorably impacted by increased planned and forced outages during 2015 versus 2014.

Comparison of three months ended September 30, 2017 and three months ended September 30, 2016

Utility operating revenues during the three months ended September 30, 2017 decreased by $6.0 million compared to the same period in 2016, which resulted from the following changes (dollars in thousands):

	Three Months Ended
	September 30,							Percentage
	2017		2016		Change			Change
Utility operating revenues:
Retail revenues	$	347,533	$	350,356	$	(2,823	)	(0.8)%
Wholesale revenues	1,530		4,603		(3,073		)	(66.8)%
Miscellaneous revenues	6,251		6,380		(129		)	(2.0)%
Total utility operating revenues	$	355,314	$	361,339	$	(6,025	)	(1.7)%

Heating degree days:
Actual	31		26		5			19.2%
30-year average	67		66

Cooling degree days:
Actual	772		1,003		(231		)	(23.0)%
30-year average	761		781

The decrease in retail revenues of $2.8 million was primarily due to a 6% decrease in the volume of kWh sold ($17.8 million); partially offset by a net increase in the weighted average price per kWh sold ($15.0 million). The $17.8 million decrease in the volume of kWh sold was primarily due to milder weather in our service territory during the third quarter of 2017 versus the comparable period (as demonstrated by the 23% decrease in cooling degree days, as shown above). The $15.0 million increase in the weighted average price of retail kWh sold was primarily due to: (i) a $5.3 million increase in billings for the MISO, Capacity, and Off System Sales riders, which took effect as part of the 2016 Rate Order (see Note 2,“Regulatory Matters”to the Financial Statements), (ii) a $5.4 million increase in fuel revenues and (iii) favorable block rate and other retail rate variances; partially offset by (iv) a $3.3 million decrease in DSM program rate adjustment mechanism revenues. The favorable block rate variances are mostly attributed to our declining block rate structure, which generally provides for residential and commercial customers to be charged a higher per kWh rate at lower consumption levels. Therefore, as volumes decrease, the weighted average price per kWh increases.

The decrease in wholesale revenues of $3.1 million was primarily due to a 71% decrease in the quantity of kWh sold as IPL’s generation units were called upon by MISO to produce electricity less often during the third quarter of 2017 compared to the third quarter of 2016, largely due to unfavorable prices, unit availability and increased outages. We made 38.2 million kWh in wholesale sales during the third quarter of 2017 compared to 131.9 million kWh during the third quarter of 2016. Our ability to be dispatched in the MISO market is primarily driven by the locational marginal price of electricity and variable generation costs. The amount of electricity available for wholesale sales is impacted by our retail load requirements, generation capacity and unit availability. Currently, 50% of IPL’s wholesale margins above and below an established annual benchmark of $6.3 million are shared with our retail customers through a rate rider.

Comparison of nine months ended September 30, 2017 and nine months ended September 30, 2016

Utility operating revenues during the nine months ended September 30, 2017 increased by $1.7 million compared to the same period in 2016, which resulted from the following changes (dollars in thousands):

	Nine Months Ended
	September 30,							Percentage
	2017		2016		Change			Change
Utility operating revenues:
Retail revenues	$	990,574	$	986,229	4,345			0.4%
Wholesale revenues	5,904		8,391		(2,487		)	(29.6)%
Miscellaneous revenues	17,570		17,753		(183		)	(1.0)%
Total utility operating revenues	$	1,014,048	$	1,012,373	$	1,675		0.2%

Heating degree days:
Actual	2,590		2,997		(407		)	(13.6)%
30-year average	3,350		3,316

Cooling degree days:
Actual	1,088		1,404		(316		)	(22.5)%
30-year average	1,096		1,124

The increase in retail revenues of $4.3 million was primarily due to a net increase in the weighted average price per kWh sold ($34.0 million), partially offset by a 5% decrease in the volume of kWh sold ($25.9 million) and the one-time impact in the prior period of recognizing in IPL’s unbilled revenue calculation the increase in IPL’s base rates relating to revenues that were previously charged through IPL’s environmental cost recovery rate adjustment mechanism, or rider ($3.8 million). While billed through a rider, such revenues relating to environmental cost recovery were not includable in our unbilled calculation. The $34.0 million increase in the weighted average price of retail kWh sold was primarily due to: (i) a $16.1 million increase in billings for the MISO, Capacity, and Off System Sales riders, which took effect as part of the 2016 Rate Order, (ii) a $5.2 million increase related to environmental rate adjustment mechanism revenues, (iii) a $4.2 million increase in fuel revenues, (iv) the impact of implementing the 2016 Rate Order (see Note 2,“Regulatory Matters”to the Financial Statements) and (v) favorable block rate and other retail rate variances. The favorable block rate variances are mostly attributed to our declining block rate structure, which generally provides for residential and commercial customers to be charged a higher per kWh rate at lower consumption levels. Therefore, as volumes decrease, the weighted average price per kWh increases. The majority of the increases in environmental rate adjustment mechanism revenues are offset by increased operating expenses, including depreciation and amortization. The $25.9 million decrease in the volume of kWh sold was primarily due to milder weather in our service territory during the first nine months of 2017 versus the comparable period (as demonstrated by the 14% decrease in heating degree days and 23% decrease in cooling degree days, as shown above).

The decrease in wholesale revenues of $2.5 million was primarily due to a 30% decrease in the quantity of kWh sold as IPL’s generation units were called upon by MISO to produce electricity less often during the first nine months of 2017 compared to the first nine months of 2016, largely due to unfavorable prices, unit availability and increased outages. We made 179.3 million kWh in wholesale sales during the first nine months of 2017 compared to 257.1 million kWh during the first nine months of 2016. Our ability to be dispatched in the MISO market is primarily driven by the locational marginal price of electricity and variable generation costs. The amount of electricity available for wholesale sales is impacted by our retail load requirements, generation capacity and unit availability. Currently, 50% of IPL’s wholesale margins above and below an established annual benchmark of $6.3 million are shared with our retail customers through a rate rider.

Utility Operating Expenses

2016 versus 2015

The following table illustrates utility primary operating expense changes from 2015 to 2016 (in millions):


2015 Operating Expenses	$	1,105.7
Decrease in fuel costs	(39.4		)
Increase in depreciation and amortization costs	30.2
Increase in power purchased	25.4
Increase in income taxes - net	15.9
Increase in non-purchased power MISO costs	15.5
Increase in DSM program costs	9.2
Decrease in maintenance expenses	(1.2		)
Other miscellaneous variances – individually immaterial	(2.3		)
2016 Operating Expenses	$	1,159.0

The $39.4 million decrease in fuel costs was primarily due to (i) a $21.1 million decrease in deferred fuel costs, which includes the one-time impact of recognizing in IPL’s deferred fuel calculation the increase in base rates relating to fuel revenues that were previously charged through a rate adjustment mechanism or rider, (ii) an $11.2 million decrease in the quantity of fuel consumed as the result of our units being called upon by MISO less often in the comparable period, as described previously, and (iii) a $5.5 million decrease due to the lower price of coal we consumed versus the comparable period. While part of the fuel rider, IPL’s unbilled fuel revenues were offset in the financial statements by an increase to fuel expense, which is no longer necessary now that these fuel revenues are included in base rates. We are generally permitted to recover underestimated fuel and purchased power costs to serve our retail customers in future rates through quarterly FAC proceedings. These variances are deferred when incurred and amortized into expense in the same period that our rates are adjusted to reflect these variances.

The increase in depreciation and amortization costs of $30.2 million was primarily due to a $15.6 million impact from the amortization of previously deferred environmental costs, as well as the deferral of fewer costs in the current year. The remaining $14.6 million increase was due to additional assets placed in service and new depreciation and ARO rates implemented beginning in April 2016, partially offset by the impact of the retirements of coal assets at our Eagle Valley and Harding Street stations.

The $25.4 million increase in purchased power costs was primarily due to a 34% increase in the volume of power purchased during the period ($43.8 million) and an increase in MISO non-fuel market participation ($8.3 million), partially offset by a 13% decrease in the market price of purchased power ($27.1 million). The volume of power we purchase each period is primarily influenced by our retail demand, generating unit capacity and outages, and the fact that 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. Additionally, MISO non-fuel market participation costs increased $8.3 million, which includes both current period costs and amortization of previously deferred costs, which were included in IPL’s customer billing rates beginning April 1, 2016. Such costs were deferred as a regulatory asset prior to April 1, 2016, and are now being amortized to expense over a ten-year period.

The $15.9 million increase in income taxes - net was primarily due to the tax effect of the increase in pretax net operating income.

MISO non-purchased power costs increased $15.5 million, which includes both current period costs and the amortization of previously deferred costs, which were included in IPL’s customer billing rates beginning April 1, 2016. Such costs were deferred as a regulatory asset prior to April 1, 2016, and are now being amortized to expense over a ten-year period.

The increase in DSM program costs of $9.2 million, which are included in “Other operating expenses” on our Consolidated Statements of Operations, was primarily due to a result of timing differences in spending patterns. These costs are recoverable through customer rates and are offset by an increase in DSM revenues.

Maintenance expenses decreased $1.2 million versus the comparable period primarily due to the timing and duration of outages.

2015 versus 2014

The following table illustrates utility primary operating expense changes from 2014 to 2015 (in millions):


2014 Operating Expenses	$	1,160.8
Decrease in fuel costs	(95.6		)
Increase in power purchased	28.4
Increase in maintenance expenses	18.3
Decrease in income taxes – net	(13.0		)
Increase in miscellaneous steam power expenses	8.0
Decrease in DSM program costs	(5.0		)
Increase in depreciation and amortization costs	3.0
Other miscellaneous variances – individually immaterial	0.8
2015 Operating Expenses	$	1,105.7

The $95.6 million decrease in fuel costs was primarily due to (i) a $52.3 million decrease in the quantity of fuel consumed as the result of a decrease in total kWh sales volume in the comparable period, (ii) a $21.4 million decrease in the price of natural gas we consumed during the comparable period, (iii) a $17.1 million decrease in the recognition of 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, (iv) a $4.0 million decrease in the price of oil we consumed during the comparable period, and (v) a $0.8 million decrease in the price of coal we consumed during the comparable period. 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 $28.4 million increase in purchased power costs was primarily due to a 136% increase in the volume of power purchased during the period ($129.3 million), partially offset by a 42% decrease in the market price of purchased power ($102.4 million). The volume of power we purchase each period is primarily influenced by our retail demand, our generating unit capacity and outages, and the fact that 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.

Maintenance expenses increased $18.3 million versus the comparable period primarily due to increased planned and forced outages. The $13.0 million decrease in income taxes – net was primarily due to the tax effect of the decrease in pretax net operating income, for the reasons previously described. The increase in miscellaneous steam power expenses of $8.0 million, which are included in “Other operating expenses” on our Consolidated Statements of Operations, is largely attributed to MATS compliance. The decrease in DSM program costs of $5.0 million, which are included in “Other operating expenses” on our Consolidated Statements of Operations and are recoverable through customer rates, is correlated to a decrease in DSM rate adjustment mechanism revenues as a result of timing differences in spending patterns. The increase in depreciation and amortization costs of $3.0 million was primarily due to additional assets placed in service.

Comparison of three months ended September 30, 2017 and three months ended September 30, 2016

The following table illustrates utility primary operating expense changes from the three months ended September 30, 2016 to the three months ended September 30, 2017 (dollars in millions):

Operating expenses for the three months ended September 30, 2016	$	301.5
Decrease in income taxes - net	(6.4		)
Increase in power purchased	5.0
Increase in maintenance expenses	3.8
Decrease in fuel costs	(3.4		)
Other miscellaneous variances - individually immaterial	1.1
Operating expenses for the three months ended September 30, 2017	$	301.6

The $6.4 million decrease in income taxes - net was primarily due to (i) the tax effect of the decrease in pretax net operating income, (ii) the manufacturer’s production deduction (Internal Revenue Code Section 199) that had been previously limited due to a Net Operating Loss carryover and (iii) the allowance for equity funds used during construction as a percentage of pretax income.

The $5.0 million increase in purchased power costs was primarily due to (i) a 17% increase in the volume of power purchased during the period ($5.8 million) and (ii) an increase in deferred capacity expense ($1.6 million), partially offset by (iii) a 9% decrease in the market price of purchased power ($3.1 million). The volume of power we purchase each period is primarily influenced by our retail demand, generating unit capacity and outages, and the fact that 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. Similar to fuel and purchased power costs described herein, we are generally permitted to recover underestimated capacity expenses to serve our retail customers in future rates through regulatory proceedings. These variances are deferred when incurred and amortized into expense in the same period that our rates are adjusted to reflect these variances.

Maintenance expenses increased $3.8 million versus the comparable period primarily due to the timing and duration of planned outages (including a 45-day scheduled outage at our 529 MW Petersburg Generating Station Unit 4 that was in progress during the third quarter of 2017). We had no such extended outages in the third quarter of 2016.

The $3.4 million decrease in fuel costs was primarily due to (i) a $13.5 million decrease in the quantity of fuel consumed versus the comparable period and (ii) a $2.5 million decrease due to the lower price of coal we consumed versus the comparable period; partially offset by (iii) an $11.2 million increase in deferred fuel costs and (iv) a $1.2 million increase due to the higher price of natural gas we consumed versus the comparable period. We are generally permitted to recover underestimated fuel and purchased power costs to serve our retail customers in future rates through quarterly FAC proceedings. These variances are deferred when incurred and amortized into expense in the same period that our rates are adjusted to reflect these variances.

Comparison of nine months ended September 30, 2017 and nine months ended September 30, 2016

The following table illustrates utility primary operating expense changes from the nine months ended September 30, 2016 to the nine months ended September 30, 2017 (dollars in millions):

Operating expenses for the nine months ended September 30, 2016	$	868.0
Increase in non-purchased power MISO costs	12.2
Increase in fuel costs	10.4
Decrease in income taxes - net	(10.1		)
Decrease in depreciation and amortization costs	(9.9		)
Increase in power purchased	8.7
Other miscellaneous variances - individually immaterial	(0.5		)
Operating expenses for the nine months ended September 30, 2017	$	878.8

MISO non-purchased power costs increased $12.2 million, which includes both current period costs and the amortization of previously deferred costs, which were included in IPL’s customer billing rates beginning April 1, 2016. Such costs were deferred as a regulatory asset prior to April 1, 2016, and are now being amortized to expense over a ten-year period.

The $10.4 million increase in fuel costs was primarily due to (i) a $26.4 million increase in deferred fuel costs, which includes the one-time favorable impact of $14.2 million in the prior period of recognizing in IPL’s deferred fuel calculation the increase in base rates relating to fuel revenues that were previously charged through a rate adjustment mechanism or rider, and (ii) an $8.2 million increase due to the higher price of natural gas we consumed versus the comparable period; partially offset by (iii) a $16.6 million decrease in the quantity of fuel consumed versus the comparable period and (iv) a $7.4 million decrease due to the lower price of coal we consumed versus the comparable period. We are generally permitted to recover underestimated fuel and purchased power costs to serve our retail customers in future rates through quarterly FAC proceedings. These variances are deferred when incurred and amortized into expense in the same period that our rates are adjusted to reflect these variances.

The $10.1 million decrease in income taxes - net was primarily due to (i) the tax effect of the decrease in pretax net operating income, (ii) the manufacturer’s production deduction (Internal Revenue Code Section 199) that had been previously limited due to a Net Operating Loss carryover and (iii) the allowance for equity funds used during construction as a percentage of pretax income.

The decrease in depreciation and amortization costs of $9.9 million was primarily due to an $8.3 million decrease in regulatory deferrals and amortization related to environmental projects, and the impact of the retirements of coal assets at our Eagle Valley and Harding Street locations during the second quarter of 2016.

The $8.7 million increase in purchased power costs was primarily due to a (i) a 6% increase in the market price of purchased power ($9.7 million), (ii) an increase in deferred capacity expense ($4.3 million) and (iii) an increase in MISO non-fuel market participation costs ($4.0 million); partially offset by (iv) a 7% decrease in the volume of power purchased during the period ($8.8 million). The volume of power we purchase each period is primarily influenced by our retail demand, generating unit capacity and outages, and the fact that 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 MISO non-fuel market participation costs, which include both current period costs and amortization of previously deferred costs, were included in IPL’s customer billing rates beginning April 1, 2016. Such costs were deferred as a regulatory asset prior to April 1, 2016, and are now being amortized to expense over a ten-year period. Similar to fuel and purchased power costs described above, we are generally permitted to recover underestimated capacity expenses to serve our retail customers in future rates through regulatory proceedings. These variances are deferred when incurred and amortized into expense in the same period that our rates are adjusted to reflect these variances.

Other Income and Deductions

2016 versus 2015

Other income and deductions increased $20.7 million, from income of $16.1 million in 2015 to income of $36.8 million in 2016, reflecting a 129% increase. The increase was primarily due to (i) a $22.0 million loss on early extinguishment of debt

from the purchase and redemption of $400 million of 2016 IPALCO Notes during the summer of 2015 and (ii) an $11.8 million increase in the allowance for equity funds used during construction as a result of increased construction activity. These increases were partially offset by a decrease in the income tax benefit of $13.8 million, which was primarily due to the change in pretax nonoperating income during the comparable periods.

2015 versus 2014

Other income and deductions decreased $11.3 million from income of $27.4 million in 2014 to income of $16.1 million in 2015, reflecting a 41% decrease. The decrease was primarily due to a $22.0 million loss on early extinguishment of debt from the purchase and redemption of $400 million of 2016 IPALCO Notes during the summer of 2015. This decrease was partially offset by (i) a $7.9 million increase in the allowance for equity funds used during construction as a result of increased construction activity, and (ii) an increase in the income tax benefit of $3.5 million, which was primarily due to the change in pretax nonoperating income during the comparable periods.

Comparison of three months ended September 30, 2017 and three months ended September 30, 2016

Other income and deductions decreased $5.4 million, from income of $11.3 million for the three months ended September 30, 2016, to income of $5.9 million for the same period in 2017. The decrease was primarily due to an $8.9 million loss on early extinguishment of debt from the redemption of $400 million of the 2018 IPALCO Notes during the third quarter of 2017. This decrease was partially offset by an increase in the income tax benefit of $3.8 million, which was primarily due to the change in pretax nonoperating income during the comparable periods.

Comparison of nine months ended September 30, 2017 and nine months ended September 30, 2016

Other income and deductions decreased $4.3 million, from income of $29.8 million for the nine months ended September 30, 2016, to income of $25.5 million for the same period in 2017. The decrease was primarily due to an $8.9 million loss on early extinguishment of debt from the redemption of $400 million of the 2018 IPALCO Notes during the third quarter of 2017. This decrease was partially offset by an increase in the income tax benefit of $4.7 million, which was primarily due to the change in pretax nonoperating income during the comparable periods.

Interest and Other Charges

2016 versus 2015

Interest and other charges decreased $7.1 million, or 7%, during 2016, primarily due to an $11.1 million increase in the allowance for borrowed funds used during construction as a result of increased construction activity; partially offset by higher interest on long-term debt of $4.7 million. The increase in long-term debt was primarily a result of IPL’s first mortgage bonds debt issuances of $350 million (4.05% Series, due May 2046) in May 2016 and $260 million (4.70% Series, due September 2045) in September 2015; partially offset by the termination of IPL’s $91.9 million 364-day delayed draw term loan in May 2016.

2015 versus 2014

Interest and other charges decreased $9.0 million, or 8%, during 2015 primarily due to (i) a $7.8 million change in the allowance for borrowed funds used during construction as a result of increased construction activity and (ii) lower interest on long-term debt of $1.2 million.

Comparison of three months ended September 30, 2017 and three months ended September 30, 2016

Interest and other charges increased $2.6 million during the three months ended September 30, 2017 compared to the same period in the prior year, primarily due to higher interest on long-term debt of $1.6 million due to the 2024 IPALCO Notes issued in August 2017 and the redemption of 2018 IPALCO Notes in September 2017.

Comparison of nine months ended September 30, 2017 and nine months ended September 30, 2016

Interest and other charges increased $7.4 million during the nine months ended September 30, 2017 compared to the same period in the prior year, primarily due to higher interest on long-term debt of $6.5 million mostly as a result of IPL’s first mortgage bonds debt issuance of $350 million (4.05% Series, due May 2046) in May 2016 and, to a lesser extent, IPALCO’s

debt issuance of $405 million 2024 IPALCO Notes in August 2017 and the redemption of 2018 IPALCO Notes in September 2017.

KEY TRENDS AND UNCERTAINTIES

During the remainder of 2017 and beyond, we expect that our consolidated financial results will be driven primarily by retail demand, weather, generating unit availability, outage costs and, to a lesser extent, wholesale prices. In addition, IPL’s financial results will likely be driven by many other factors including, but not limited to, the following:

•

rate case outcomes;

•

the timely completion of major construction projects and recovery of capital expenditures through base rate growth; and

•

the passage of new legislation, implementation of regulations or other changes in regulation.

If favorable outcomes related to these factors do not occur, or if the challenges described below and elsewhere in this section impact us more significantly than we currently anticipate, or if commodities move more unfavorably, then these adverse factors (or other adverse factors unknown to us) may impact our operating margin, net income and cash flows. We continue to monitor our operations and address challenges as they arise. For a discussion of the risks related to our business, see“Business” and“Risk Factors” of this prospectus.

Operational

In December 2016, we received approval of our DSM programs through 2017; however, the IURC denied shareholder incentives for the DSM programs implemented pursuant to this order, which we expect will have an adverse impact on our results. IPL received shareholder incentives of approximately $7.7 million in 2016. See Note 2, “Regulatory Matters – DSM” to the Financial Statements for further discussion of our DSM programs.

Regulatory Environment

For a discussion of the regulatory environment related to our business, see“Business – Regulatory Matters”,Note 2, “Regulatory Matters” to the Financial Statements and“Business – Environmental Matters” of this prospectus.

CAPITAL RESOURCES AND LIQUIDITY

As of September 30, 2017, on a consolidated basis, we had unrestricted cash and cash equivalents of $26.3 million and available borrowing capacity of $129.5 million under our $250 million unsecured revolving credit facility after accounting for 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 27, 2018. In December 2015, we received an order from the IURC granting us authority through December 31, 2018 to, among other things, issue up to $650 million in aggregate principal amount of long-term debt and refinance up to $196.5 million in existing indebtedness. As of September 30, 2017, we have $106.5 million of total debt issuance authority remaining under this order. This order also grants us authority to have up to $500 million of long-term credit agreements and liquidity facilities outstanding at any one time, of which $250 million remains available under the order as of September 30, 2017. As an alternative to the sale of all or a portion of $65 million in principal of the long-term debt mentioned above, we have the authority to issue up to $65 million of new preferred stock, all of which authority remains available under the order as of September 30, 2017. 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 facility 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 U.S. Investments and CDPQ. Sources for principal payments on outstanding indebtedness and nonrecurring capital expenditures are expected to be obtained from: (i) existing cash balances; (ii) cash generated from operating activities; (iii) borrowing capacity on our committed credit facility; and (iv) additional debt financing. From time to time, we may elect to repurchase our outstanding debt through cash purchases,

privately negotiated transactions or otherwise when management believes such repurchases are favorable to make. The amounts involved in any such repurchases may be material.

Cash Flows

The following tables provide a summary of our cash flows:

	Years ended December 31,									$ Change
	2016			2015			2014			2016 vs. 2015			2015 vs. 2014
	*(in thousands)*									*(in thousands)*
Net cash provided by operating activities	$	324,591		$	252,425		$	253,997		$	72,166		$	(1,572	)
Net cash used in investing activities	(608,688		)	(695,117		)	(397,358		)	86,429			(297,759		)
Net cash provided by financing activities	297,529			437,280			151,227			(139,751		)	286,053
Net increase (decrease) in cash	13,432			(5,412		)	7,866			18,844			(13,278		)
Cash and cash equivalents at beginning of period	21,521			26,933			19,067			(5,412		)	7,866
Cash and cash equivalents at end of period	$	34,953		$	21,521		$	26,933		$	13,432		$	(5,412	)


	Nine months ended September 30,
	2017			2016			$ Change

Net cash provided by operating activities	$	216,106		$	249,068		$	(32,962	)
Net cash used in investing activities	(175,509		)	(530,153		)	354,644
Net cash (used in) provided by financing activities	(49,223		)	310,867			(360,090		)
Net decrease in cash	(8,626		)	29,782			(38,408		)
Cash and cash equivalents at beginning of period	34,953			21,521			13,432
Cash and cash equivalents at end of period	$	26,327		$	51,303		$	(24,976	)

Operating Activities

The following tables summarize the key components of our consolidated operating cash flows:

	Years ended December 31,									$ Change
	2016			2015			2014			2016 vs. 2015			2015 vs. 2014
	*(in thousands)*									*(in thousands)*
Net income	$	131,060		$	59,524		$	77,968		$	71,536		$	(18,444	)
Depreciation and amortization	216,019			201,475			188,477			14,544			12,998
Amortization (deferral) of regulatory assets	6,377			(8,731		)	1,123			15,108			(9,854		)
Amortization of debt premium	200			596			942			(396		)	(346		)
Deferred income taxes and investment tax credit adjustments	34,012			31,566			47,455			2,446			(15,889		)
Loss on early extinguishment of debt	—			21,956			—			(21,956		)	21,956
Allowance for equity funds used during construction	(27,140		)	(14,996		)	(7,136		)	(12,144		)	(7,860		)
Adjusted net income	360,528			291,390			308,829			69,138			(17,439		)
Net change in operating assets and liabilities	(35,937		)	(38,965		)	(54,832		)	3,028			15,867
Net cash provided by operating activities	$	324,591		$	252,425		$	253,997		$	72,166		$	(1,572	)

	Nine months ended September 30,
	2017			2016			$ Change

Net income	$	83,868		$	104,733		$	(20,865	)
Depreciation and amortization	156,103			166,031			(9,928		)
(Deferral) amortization of regulatory assets	3,241			3,123			118
Amortization of debt premium	(14,546		)	15,680			(30,226		)
Deferred income taxes and investment tax credit adjustments	8,875			—			8,875
Allowance for equity funds used during construction	(19,576		)	(20,125		)	549
Net income, adjusted for non-cash items	217,965			269,442			(51,477		)
Net change in operating assets and liabilities	(1,859		)	(20,374		)	18,515
Net cash provided by operating activities	$	216,106		$	249,068		$	(32,962	)

2016 versus 2015

The net change in consolidated operating assets and liabilities for the year ended December 31, 2016 compared to the year ended December 31, 2015 was driven by the following (in thousands):

Increase from fuel, materials and supplies primarily due to lower coal purchases in 2016	$	51,806
Increase from accounts payable and accrued expenses primarily due to timing of payments	14,384
Decrease from accounts receivable primarily due to an increase in Retail revenues at the end of 2016 as compared to the end of 2015	(45,962		)
Decrease from short-term and long-term regulatory assets and liabilities, primarily due to changes in the deferred fuel regulatory asset (liability) resulting from the 2016 rate order	(15,046		)
Other	(2,154		)
Net change in operating assets and liabilities	$	3,028

2015 versus 2014

The net change in consolidated operating assets and liabilities for the year ended December 31, 2016 compared to the year ended December 31, 2015 was driven by the following (in thousands):

Increase from accounts payable and accrued expenses primarily due to timing of payments	$	23,606
Increase from short-term and long-term regulatory assets and liabilities	21,272
Increase from accounts receivable primarily due to a decrease in Retail revenues at the end of 2015 as compared to the end of 2014	11,843
Decrease from fuel, materials and supplies primarily due to a build up of inventory in 2015 partially attributed to milder than expected weather	(23,466		)
Decrease from pension and other postretirement benefit expenses	(18,515		)
Other	1,127
Net change in operating assets and liabilities	$	15,867

Nine months ended September 30, 2017 versus nine months ended September 30, 2016

The net change in consolidated operating assets and liabilities for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016 was driven by changes in the following (in thousands):

Increase from short-term and long-term regulatory assets and liabilities primarily due to the collection of deferred MISO expenses	$	47,806
Decrease from fuel, materials and supplies primarily due to higher coal purchases	(36,331		)
Increase from accounts receivable due to higher collections	32,499
Decrease from accounts payable and accrued expenses due to timing of payments	(9,558		)
Decrease from accrued interest due to higher payments	(8,403		)
Decrease from income taxes receivable or payable due to higher payments	(7,020		)
Other- net	(478		)
Net change in operating assets and liabilities	$	18,515

Investing Activities

During the year ended December 31, 2016, net cash used in investing activities was primarily related to capital expenditures of $607.7 million (which includes $15.5 million of payments for financed capital expenditures).

During the year ended December 31, 2015, net cash used in investing activities was primarily related to capital expenditures of $686.1 million (which includes $13.2 million of payments for financed capital expenditures).

During the year ended December 31, 2014, net cash used in investing activities was primarily related to capital expenditures of $381.6 million.

During the nine months ended September 30, 2017, net cash used in investing activities was primarily related to capital expenditures of $163.7 million (which excludes $9.8 million of payments for financed capital expenditures).

During the nine months ended September 30, 2016, net cash used in investing activities was primarily related to capital expenditures of $516.9 million (which excludes $15.0 million of payments for financed capital expenditures).

Financing Activities

During the year ended December 31, 2016, net cash provided by financing activities primarily relates to net borrowings of $230.8 million and equity capital contributions of $213.0 million from shareholders for funding needs related to IPL’s environmental and replacement generation projects; partially offset by dividends to shareholders of $123.0 million.

During the year ended December 31, 2015, net cash provided by financing activities primarily relates to net borrowings of $318.0 million and an equity capital contribution of $214.4 million from CDPQ in April 2015 for funding needs related to IPL’s environmental and replacement generation projects; partially offset by dividends to shareholders of $69.5 million.

During the year ended December 31, 2014, net cash provided by financing activities primarily relates to net borrowings of $128.4 million and an equity capital contribution of $106.4 million from AES in June 2014 for funding needs related to IPL’s environmental and replacement generation projects; partially offset by dividends to AES of $78.4 million.

During the nine months ended September 30, 2017, net cash used in financing activities primarily relates to dividends to shareholders of $75.5 million and payments for financed capital expenditures of $9.8 million; partially offset by net borrowings of $42.3 million.

During the nine months ended September 30, 2016, net cash provided by financing activities primarily relates to net borrowings of $205.8 million and equity capital contributions of $213.0 million from shareholders for funding needs related to IPL’s environmental and replacement generation projects; partially offset by dividends to shareholders of $86.4 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 $173.5 million (which includes $9.8 million of payments for finance capital expenditures) and $531.9 million (which includes $15.0 million of payments for finance capital expenditures) during the first nine months of 2017 and 2016, respectively. Our capital expenditures totaled $607.7 million (which includes $15.5 million of payments for financed capital expenditures), $686.1 million (which includes $13.2 million of payments for financed capital expenditures), and $381.6 million in 2016, 2015 and 2014, respectively. The decrease in capital expenditures of $358.4 million in the first nine months of 2017 versus 2016 was primarily driven by construction costs related to replacement generation and our environmental construction program. The increase in capital expenditures over the past few years has been primarily driven by construction costs related to replacement generation and our environmental construction program. Construction expenditures during the first nine months of 2017 and during 2016, 2015 and 2014 were financed primarily with internally generated cash provided by operations, borrowings on our credit facility, long-term borrowings and equity capital contributions.

Our capital expenditure program, including development and permitting costs, for the three-year period from 2017 to 2019 is currently estimated to cost approximately $550 million (excluding environmental compliance and replacement generation costs). It includes approximately $314 million for additions, improvements and extensions to transmission and distribution lines, substations, power factor and voltage regulating equipment, distribution transformers and street lighting facilities. The capital expenditure program also includes approximately $171 million for power plant-related projects and $65 million for other miscellaneous equipment.

IPL also plans to spend a total of $655 million (of which $601 million has been expended through September 30, 2017) on replacement generation costs through 2018 as a result of the retirement of existing facilities not equipped with advanced environmental control technologies required to comply with existing and expected regulations. The balance of $54 million is projected to be expended in 2017 and 2018. Please see “Business-Environmental Matters-Unit Retirements and Replacement Generation” for more details.

Other environmental expenditures include costs for compliance with the NPDES permit program under the CWA. The costs for NPDES at our Petersburg station for 2017 are expected to be $27 million (of which $16 million has been expended through September 30, 2017). IPL plans to spend a total of $224 million for this project (of which $203 million has been expended through September 30, 2017). Please see “Item 1. Business - Environmental Matters - Environmental Wastewater Requirements” as described in the audited Consolidated Financial Statements of IPALCO included in this prospectus for more details.

IPL also has projects underway related to environmental compliance for CCR and NAAQS SO2. The costs for these projects in the 2017 through 2019 forecast are expected to be $42 million. IPL plans to spend a total of $76 million for these projects (of which $45 million has been expended through September 30, 2017). Please see “Item 1. Business - Environmental Matters - NAAQS” as described in the audited Consolidated Financial Statements of IPALCO included in this prospectus for more details.

Other environmental capital spending for the period 2017 through 2019 includes spending for studies related to cooling water intake requirements in sections 316(a) and 316(b) of the CWA, NAAQS Ozone and Office of Surface Mining totaling $24 million. Please see “Item 1. Business - Environmental Matters - Cooling Water Intake Regulations” as described in the audited Consolidated Financial Statements of IPALCO included in this prospectus for more details.

Contractual Cash Obligations

Our non-contingent contractual obligations as of December 31, 2016 are set forth below:

	Payment due
	Total		Less Than 1 Year		1 – 3 Years		3 – 5 Years		More Than 5 Years
	*(In Millions)*
Long-term debt	$	2,528.4	$	24.6	$	400.0	$	590.0	$	1,513.8
Interest obligations⁽¹⁾	1,965.3		116.1		198.2		173.1		1,477.9
Purchase obligations⁽²⁾
Coal, gas, purchased power and
related transportation⁽³⁾	2,163.7		373.2		446.4		239.4		1,104.7
Other	55.0		8.7		12.7		8.7		24.9
Pension funding⁽⁴⁾	7.1		7.1		—		—		—
Total⁽⁵⁾	$	6,719.5	$	529.7	$	1,057.3	$	1,011.2	$	4,121.3

(1)

Represents interest payment obligations related to fixed and variable rate debt. Interest related to variable rate debt is calculated using the rate in effect at December 31, 2016.

(2)

Does not include purchase orders or normal purchases for goods or services: (1) for which there is not also an enforceable contract; or (2) which does not specify all significant terms, including fixed or minimum quantities. Does not include contractual commitments that can be terminated by us without penalty on notice of 90 days or less. Does not include all construction or related contracts that do not fit the parameters described for this table.

(3)

Does not include an additional $27.8 million, $119.6 million, $91.9 million and $91.9 million for years 2018, 2019, 2020 and 2021, respectively, for contractual obligations executed in 2017.

(4)

IPL elected to fund $7.1 million during January 2017. However, IPL may decide to contribute more than $7.1 million to meet certain funding thresholds. For years 2018 and thereafter, our contractual obligation for pension funding can fluctuate due to various factors. Please see Note 9,“Benefit Plans” to the Financial Statements for further discussion.

(5)

Does not include an uncertain tax liability of $6.6 million (tax and related interest) as of December 31, 2016 because it is not possible to determine in which future period or periods that the non-current income tax liability for uncertain tax positions might be paid.

Dividend Distributions

All of IPALCO’s outstanding common stock is held by AES U.S. Investments and CDPQ. During the first nine months of 2017 and 2016, IPALCO paid $75.5 million and $86.4 million, respectively, in dividends to its shareholders. During 2016, 2015 and 2014, IPALCO paid $123.0 million, $69.5 million, and $78.4 million, respectively, in dividends to its shareholders. Future distributions to our shareholders 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.

Capital Resources

IPALCO is a holding company, 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 2020 IPALCO Notes or 2024 IPALCO Notes; however, all of IPL’s common stock is pledged to secure these notes. Accordingly, IPALCO’s ability to make payments on the 2020 IPALCO Notes or 2024 IPALCO Notes depends on the ability of IPL to generate cash and distribute it to IPALCO.

Liquidity

We expect our existing sources of liquidity to remain sufficient to meet our anticipated operating needs. Our business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and carrying costs, potential margin requirements related to energy hedges, taxes and dividend payments. For 2017 and subsequent years, we expect to satisfy these requirements with a combination of cash from operations and funds from debt financing as our internal liquidity needs and market conditions warrant. We also expect that the borrowing capacity under bank credit facilities will continue to be available to manage working capital requirements during those periods. 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 millions	Type	Maturity	Commitment		Amounts available as of September 30, 2017
IPL	Revolving	October 2020	$	250.0	$129.5 million

IPL First Mortgage Bonds

In May 2016, IPL issued $350 million aggregate principal amount of first mortgage bonds, 4.05% Series, due May 2046, pursuant to Rule 144A and Regulation S under the Securities Act. For further discussion, please see Note 7, “Debt - IPL First Mortgage Bonds and Recent Indiana Finance Authority Bond Issuances” to the Financial Statements.

IPL Unsecured Notes

In May 2016, IPL repaid $91.9 million in outstanding borrowings under its 364-day delayed-draw term loan with a portion of the proceeds from its $350 million aggregate principal amount of first mortgage bonds as described above in“IPL First Mortgage Bonds and Recent Indiana Finance Authority Bond Issuances.”For further discussion, please see Note 7, “Debt - Unsecured Notes” to the Financial Statements.

IPALCO’s Senior Secured Notes

In August 2017, IPALCO completed the sale of the 2024 IPALCO Notes pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended. For further discussion, please see Note 5, “Debt - IPALCO’s Senior Secured Notes” to IPALCO’s financial statements as of September 30, 2017.

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 Agreement and other unsecured notes (as well as the amount of certain other fees in the Credit Agreement) 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. On April 13, 2016, S&P upgraded the Corporate Credit Rating of IPALCO and IPL to ‘BBB-’ from ‘BB+’ based on S&P’s one-notch upgrade of AES. At the same time, S&P affirmed the issue-level ratings at IPALCO and IPL. Our other credit ratings were affirmed in 2016 as noted below.

The following table presents the debt ratings and credit ratings (issuer/corporate rating) and outlook for IPALCO and IPL, along with the dates each rating was effective or affirmed.

Debt ratings	IPALCO	IPL	Outlook	Effective or Affirmed
Fitch Ratings	BB+^(a)	BBB+^(b)	Stable	December 2016
Moody's Investors Service	Baa3^(a)	A2^(b)	Stable	October 2016
S&P Global Ratings	BB+^(a)	BBB+^(b)	Stable	April 2016

Credit ratings	IPALCO	IPL	Outlook	Effective or Affirmed
Fitch Ratings	BB+	BBB-	Stable	December 2016
Moody's Investors Service	—	Baa1	Stable	October 2016
S&P Global Ratings	BBB-	BBB-	Stable	April 2016

(a)

Ratings relate to IPALCO's Senior Secured Notes.

(b)

Ratings relate to IPL's Senior Secured Bonds.

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. 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. As of September 30, 2017 and as of the filing of this prospectus, IPL was in compliance with these restrictions.

IPL is also restricted in its ability to pay dividends if it is in default under the terms of its Credit Agreement and its unsecured notes, 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. As of September 30, 2017 and as of the filing of this prospectus, IPL was in compliance with all covenants and no event of default existed.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

We prepare our consolidated financial statements in accordance with GAAP. As such, we are required to make certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period presented. Therefore, the possibility exists for materially different reported amounts under different conditions or assumptions. Significant accounting policies used in the preparation of the consolidated financial statements are described in Note 1, “Overview and Summary of Significant Accounting Policies” to the audited Consolidated Financial Statements of IPALCO included in this Prospectus. This section addresses only those accounting policies involving amounts material to our financial statements that require the most estimation, judgment or assumptions and should be read in conjunction with Note 1, “Overview and Summary of Significant Accounting Policies” to the audited Consolidated Financial Statements of IPALCO included in this prospectus.

Revenue Recognition

unlikely that materially different results will occur in future periods when revenue is billed. The effect on 2016 revenues and ending unbilled revenues of a one percentage point change in estimated line losses for the month of December 2016 is immaterial. An allowance for potential credit losses is maintained and amounts are written off when normal collection efforts have been exhausted.

Income Taxes

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

Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. We establish a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized.

Regulation

As a regulated utility, we apply the provisions of ASC 980 “Regulated Operations,” which gives recognition to the ratemaking and accounting practices of the IURC and the FERC. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds or future rate reductions to customers for previous overcollections or the deferral of revenues collected for costs that IPL expects to incur in the future. Specific regulatory assets and liabilities are disclosed in Note 5, “Regulatory Assets and Liabilities” to the audited Consolidated Financial Statements of IPALCO included in this prospectus.

The deferral of costs (as regulatory assets) is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific orders from the IURC, regulatory precedent and the current regulatory environment. To the extent recovery of costs is no longer deemed probable, related regulatory assets would be required to be expensed in current period earnings. Our regulatory assets and liabilities have been created pursuant to specific orders of the IURC or established regulatory practices, such as other utilities under the jurisdiction of the IURC being granted recovery of similar costs. It is probable, but not certain, that these regulatory assets will be recoverable, subject to IURC approval.

Pension Costs

We account for and disclose pension and postemployment benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postemployment plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost and funding requirements of the plans.

Effective January 1, 2016, we began applying a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and other post-retirement plan. Refer to Note 1, “Overview and Summary of Significant Accounting Policies” to the audited Consolidated Financial Statements of IPALCO included in this prospectus.

Impairment of Long-lived Assets

GAAP requires that we measure long-lived assets for impairment when indicators of impairment exist. If an asset is deemed to be impaired, we are required to write down the asset to its fair value with a charge to current earnings. We do not believe any of these utility plant assets are currently impaired. In making this assessment, we consider such factors as: the overall condition and generating and distribution capacity of the assets; the expected ability to recover additional expenditures in the assets; the anticipated demand and relative pricing of retail electricity in our service territory and wholesale electricity in the region; and the cost of fuel.

Contingencies

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

NEW ACCOUNTING STANDARDS

Please see Note 1, “Overview and Summary of Significant Accounting Policies” to the audited Consolidated Financial Statements of IPALCO included in this prospectus for a discussion of new accounting pronouncements and the potential impact to our results of operations, financial condition and cash flows.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Overview

The primary market risks to which we are exposed are those associated with environmental regulation, debt and equity investments, fluctuations in interest rates and the prices of fuel, wholesale power, SO2 allowances and certain raw materials. 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.

Wholesale Sales

We engage in wholesale power marketing activities that primarily involve the offering of utility-owned or contracted generation into the MISO day- ahead and real-time markets. Our ability to compete effectively in the wholesale market is dependent on a variety of factors, including our generating availability, the supply of wholesale power, the demand by load-serving entities, and the formation of IPL’s offers into the market. Our wholesale revenues are generated primarily from sales directly to the MISO energy market. The average price per MWh we sold in the wholesale market was $31.17, $28.02 and $34.71 in 2016, 2015 and 2014, respectively. The weighted average price of wholesale MWh we sold in the first nine months of 2017 was $32.98. A decline in wholesale prices can have a negative 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. However, the impact is limited as we are required to return to customers 50% of any wholesale margins above an established annual benchmark of $6.3 million. As a result of the retirement of the four coal-fired units at Eagle Valley, we expect our ability to have excess generation available for sale on the wholesale market will be adversely impacted until the CCGT is completed. Our wholesale revenues represented 3.4% of our total electric revenues over the past five years. As a result, we anticipate that a 10% change in the market price for wholesale electricity would not have a material impact on our results of operations.

Fuel

We have limited exposure to commodity price risk for the purchase of coal and natural gas, the primary fuels used by us for the production of electricity. We manage this risk for coal by providing for all of our current projected burn through 2017 and approximately 85% of our current projected burn for the three-year period ending December 31, 2019, under long-term contracts. Pricing provisions in some of our long-term contracts allow for price changes under certain circumstances. Fuel purchases made in 2017 have been and are expected to continue to be made at prices that are slightly higher than our weighted average price in 2016. Our exposure to fluctuations in the price of fuel is limited because pursuant to Indiana law, we may apply to the IURC for a change in our fuel charge every three months to recover our estimated fuel costs, which may be above or below the levels included in our basic rates. We must present evidence in each FAC proceeding that we have made every reasonable effort to acquire fuel and generate or purchase power or both so as to provide electricity to our retail customers at the lowest fuel cost reasonably possible.

Power Purchased

We depend on purchased power, in part, to meet our retail load obligations. As a result, we also have limited exposure to commodity price risk for the purchase of electric energy for our retail customers. Purchased power costs can be highly volatile. We are generally allowed to recover, through our FAC, the energy portion of purchased power costs incurred to meet jurisdictional retail load. In certain circumstances, we may not be allowed to recover a portion of purchased power costs

incurred to meet our jurisdictional retail load. See “-Regulatory Matters-FAC and Authorized Annual Jurisdictional Net Operating Income.”

Equity Market Risk

Our Pension Plans are impacted significantly by the economy as a result of the Pension Plans being significantly invested in common equity securities. The performance of the Pension Plans’ investments in such common equity securities and other instruments impacts our earnings as well as our funding liability. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $21.8 million reduction in fair value as of September 30, 2017 and approximately a $0.9 million increase to the 2017 pension expense. Please see Note 9, “Benefit Plans” to the audited Consolidated Financial Statements of IPALCO included in this prospectus for additional Pension Plan information.

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 Agreement bears interest at variable rates based either on the Prime interest rate or on the LIBOR. IPL’s Series 2015A and Series 2015B notes bear interest at variable rates based on the LIBOR. Fair values relating to financial instruments are dependent upon prevalent market rates of interest, primarily the LIBOR. At September 30, 2017, we had approximately $2,418.8 million principal amount of fixed rate debt and $210.5 million principal amount of variable rate debt outstanding. In regards to our fixed rate debt, the interest rate risk with respect to long-term debt primarily relates to the potential impact a decrease in interest rates has on the fair value of our fixed-rate debt and not on our financial condition or results of operations.

Variable rate debt at September 30, 2017 was comprised of $90.0 million under our Series 2015A and Series 2015B notes and $120.5 million under our Credit Agreement. Based on amounts outstanding as of September 30, 2017, the effect of a 25 basis point change in the applicable rates on our variable-rate debt would change our annual interest expense and cash paid for interest by $0.2 million and $(0.2 million), respectively.

The following table shows our consolidated indebtedness (in millions) by maturity as of September 30, 2017:

	2017		2018		2019		2020		2021		Thereafter		Total		Fair Value
Fixed-rate	$	—	$	—	$	—	$	405.0	$	95.0	$	1,918.8	$	2,418.8	$	2,609.3
Variable-rate	—		120.5		—		90.0		—		—		210.5		210.5
Total Indebtedness	$	—	$	120.5	$	—	$	495.0	$	95.0	$	1,918.8	$	2,629.3	$	2,819.8
Weighted Average Interest Rates by Maturity	N/A		2.77%		N/A		3.13%		3.88%		4.71%		4.29%

For further discussion of our fair value of our indebtedness and book value of our indebtedness please see Note 4, “Fair Value” and Note 7, “Debt” to the audited Consolidated Financial Statements of IPALCO incorporated into this prospectus.

Retail Energy Market

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

Counterparty Credit Risk

At times, we may utilize forward purchase contracts to manage the risk associated with power purchases, and could be exposed to counterparty credit risk in these contracts. We manage this exposure to counterparty credit risk by entering into contracts with companies that are expected to fully perform under the terms of the contract. Individual credit limits are generally

implemented for each counterparty to further mitigate credit risk. We may also require a counterparty to provide collateral in the event certain financial benchmarks are not maintained, or certain credit ratings are not maintained.

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

BUSINESS

OVERVIEW

IPALCO Enterprises, Inc. is a holding company incorporated under the laws of the state of Indiana. Our principal subsidiary is IPL, a regulated electric utility operating in the state of Indiana. Substantially all of our business consists of the generation, transmission, distribution and sale of electric energy conducted through IPL. Our business segments are electric and “all other.” Our total electric revenues and net income for the fiscal year ended December 31, 2016 were $1.3 billion and $131.1 million, respectively, and for the nine months ended September 30, 2017 were $1.0 billion and $83.9 million, respectively. The book value of our total assets as of September 30, 2017 was $4.7 billion. All of our operations are conducted within the United States of America and principally within the state of Indiana.

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 a part of this prospectus.

IPL

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 490,000 retail customers in the city of Indianapolis and neighboring cities, towns and communities, and adjacent rural areas all within the state of Indiana, with 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 four generating stations, all within the state of Indiana. IPL’s largest generating station, Petersburg, is coal-fired. The second largest station, Harding Street, has converted its coal-fired units to natural gas and uses natural gas and fuel oil to power combustion turbines. In addition, IPL began the operation of a 20 MW battery energy storage unit at this location in May 2016, which provides frequency response. The third station, Eagle Valley, retired its coal-fired units in April 2016. The CCGT at Eagle Valley is expected to be completed in the first half of 2018 with a rated output of 671 MW. The fourth station, Georgetown, is a small peaking station that uses natural gas to power combustion turbines. As of September 30, 2017, IPL’s net electric generation capacity for winter is 2,996 MW and net summer capacity is 2,881 MW. IPL’s transmission and distribution facilities are further described below under “-Properties.”

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 kWh sales, after adjustments for weather variations, have historically been impacted by changes in service territory economic activity as well as the number of retail customers we have. For the ten years ended 2016, IPL’s retail kWh sales decreased at a compound annual rate of 0.7%. Conversely, the number of our retail customers grew at a compound annual rate of 0.4% during that same period. Going forward, we expect modest retail kWh sales growth annually, which is negatively impacted by our demand-side management programs and other energy efficiency mandates. Please see “Business-Regulatory Matters-DSM” for more details. IPL’s electricity sales for 2012 through 2017, and for the nine months ended September 30, 2017 are set forth in the table of statistical information included at the end of this section.

IPL is a transmission company member of RFC. RFC is one of eight Regional Reliability Councils under the NERC, which has been designated as the Electric Reliability Organization under the 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, 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 FTRs market settlement statements for each operating day (see “-Regulatory Matters-MISO Operations” below for more details).

EMPLOYEES

As of October 25, 2017, IPL had 1,356 employees of whom 1,270 were full time. Of the total employees, 873 were represented by the IBEW in two bargaining units: a physical unit and a clerical-technical unit. In February 2017, the membership of the IBEW clerical-technical unit ratified a three-year labor agreement with us that expires on February 17, 2020. In December

2015, the IBEW physical unit ratified a three-year agreement with us that expires on December 10, 2018. 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 September 30, 2017, neither IPALCO nor any of its majority-owned subsidiaries other than IPL had any employees.

SERVICE COMPANY

Effective January 1, 2014, the Service Company began providing services including operations, accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the U.S. SBU, including among other companies, IPALCO and IPL. The Service Company allocates the costs for these services based on cost drivers designed to result in fair and equitable allocations. This includes ensuring that the regulated utilities served, including IPL, are not subsidizing costs incurred for the benefit of other businesses. Total costs incurred by the Service Company on behalf of IPALCO were $25.3 million, $27.4 million, $23.2 million and $22.0 million during the first nine months of 2017 and the years 2016, 2015 and 2014, respectively. Total costs incurred by IPALCO on behalf of the Service Company during the first nine months of 2017 and the years 2016, 2015 and 2014 were $7.9 million, $9.2 million, $7.5 million and $5.6 million, respectively. IPALCO had a prepaid balance with the Service Company of $6.9 million, $3.4 million and $1.2 million as of September 30, 2017, December 31, 2016 and December 31, 2015, respectively.

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 IPL. The following is a description of these material properties.

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

We own and operate four generating stations, all within the state of Indiana. Our largest generating station, Petersburg, is coal-fired. The second largest station, Harding Street, has converted its coal-fired units to natural gas and uses natural gas and fuel oil to power combustion turbines; approximately 90 MW of old oil-fired units were retired at Harding Street in recent years. In addition, IPL began the operation of a 20 MW battery energy storage unit at this location in May 2016. The third station, Eagle Valley, retired its coal-fired units in April 2016 and several small oil-fired units prior to this date. The CCGT at Eagle Valley is expected to be completed in the first half of 2018 with a rated output of 671 MW. The fourth station, Georgetown, is a small peaking station that uses natural gas to power combustion turbines. For electric generation, the net winter design capacity is 2,996 MW and net summer design capacity is 2,881 MW. Our highest summer peak level of 3,139 MW was recorded in August 2007 and the highest winter peak level of 2,971 MW was recorded in January 2009.

Our sources of electric generation are as follows:

Fuel	Name	Number of Units	Winter Capacity (MW)	Summer Capacity (MW)	Location
Coal	Petersburg	4	1,709	1,709	Pike County, Indiana
	Total	4	1,709	1,709
Gas	Harding Street	6	1,026	963	Marion County, Indiana
	Georgetown	2	200	158	Marion County, Indiana
	Total	8	1,226	1,121
Oil	Petersburg	3	8	8	Pike County, Indiana
	Harding Street	3	53	43	Marion County, Indiana
	Total	6	61	51
Grand Total⁽¹⁾		18	2,996	2,881

(1)

In April 2016, we retired the four coal-fired units at Eagle Valley. The CCGT at the Eagle Valley Station is expected to be completed in the first half of 2018. The CCGT is one unit with an expected winter and summer capacity of approximately 644 to 685 MW.

Net electrical generation during 2016, at our Petersburg, Harding Street, Eagle Valley and Georgetown plants accounted for approximately 80.7%, 17.6%, 0.9% and 0.8%, respectively, of our total net generation. After completion of the CCGT at the Eagle Valley Station, we expect net electrical generation to change accordingly.

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 408 circuit miles of 138,000 volt lines. The distribution system consists of 4,885 circuit miles of underground primary and secondary cables and 6,115 circuit miles of overhead primary and secondary wire. Underground street lighting facilities include 767 circuit miles of underground cable. Also included in the system are 138 substations. Depending on the voltage levels at the substation, some substations may be considered both a bulk power substation and a distribution substation. There are 73 bulk power substations and 117 distribution substations; 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. Our plants generally have enough capacity to meet the daily 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

IPL’s mortgage and deed of trust secures first mortgage bonds issued by IPL. Pursuant to the terms of the mortgage and deed of trust, substantially all property owned by IPL is subject to a direct first mortgage lien securing indebtedness of $1,608.8 million at September 30, 2017. In addition, IPALCO has outstanding $810 million of Senior Secured Notes which are secured by its pledge of all of the outstanding common stock of IPL.

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 provided through MISO’s tariff.

As a member of MISO, 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 the fuel portion of its costs from MISO, including all specifically identifiable ancillary services market costs, and all operational, administrative and other costs from MISO. The majority of certain operational, administrative and other costs deferred under the authority of the IURC are being recovered per specific rate order; recovery for the remaining costs is probable but timing not yet determined. Total MISO costs deferred as long-term regulatory assets were $104.5 million, $114.4 million and $128.6 million as of September 30, 2017, December 31, 2016 and December 31, 2015, 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.

See also Note 2, “Regulatory Matters” to the Financial Statements for additional details on the regulatory oversight of the FERC and the IURC.

REGULATORY MATTERS

General

IPL is a regulated public utility principally engaged in providing electric service to the Indianapolis metropolitan area. 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, which has had and will continue to have a significant impact on our operations and financial statements for the foreseeable future. We maintain our books and records consistent with GAAP reflecting the impact of regulation. See Note 1, “Overview and Summary of Significant Accounting Policies” to the Financial Statements.

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. In addition, IPL’s rates include various adjustment mechanisms including, but not limited to: (i) a rider to reflect changes in fuel and purchased power costs to meet IPL’s retail load requirements, referred to as the FAC, and (ii) a rider for the timely recovery of costs (including a return) incurred to comply with environmental laws and regulations referred to as the ECCRA. IPL also received approval (in its March 2016 IURC order) to implement three new rate riders for current recovery from customers of ongoing MISO costs and capacity costs, and for sharing with customers 50% of wholesale sales margins above and below an established annual benchmark of $6.3 million. Additionally, the capacity rider provides that IPL will share with customers 50% of any capacity sales. Each of these tariff rate components may be set and approved by the IURC in separate proceedings at different points in time (the FAC proceedings occur on a quarterly basis, the ECCRA proceedings occur on a semi-annual basis, and the proceedings for the three new rate riders occur on an 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.

Please see the discussion in Note 2, “Regulatory Matters” to the Financial Statements, which is incorporated by reference herein for a more comprehensive discussion of regulatory matters impacting us.

ENVIRONMENTAL MATTERS

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 New Source Review NOV from the EPA (see “-New Source Review and Other CAA NOVs” below), we do not believe any currently open environmental investigations will result in fines material to our results of operations, financial condition and cash flows.

Under certain environmental laws, we could be held responsible for costs relating to contamination at our past or present facilities and at thirdparty 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 hazardous air pollutants regulated under the CAA emitted from coal and oil-fired electric utilities, known as “MATS”, became effective. IPL management developed a plan to comply with this rule. Our remaining coal-fired capacity has acid gas scrubbers or comparable control technologies; however, there are other improvements to such control technologies that were necessary to achieve compliance. Under the CAA, compliance with MATS was required by April 16, 2015; however, the compliance period for

certain units, or groups of units, was extendable by state permitting authorities (for up to one additional year) or through a CAA administrative order from the EPA (for another additional year). In December 2012, IDEM granted an extension to April 16, 2016 covering all coal-fired units at Harding Street and Eagle Valley (Harding Street and Eagle Valley ceased coal combustion prior to this date), in addition to Unit 3 and Unit 4 at Petersburg. In February 2013, IDEM granted a three-month extension on Petersburg Unit 2 to July 16, 2015. All four Petersburg units are currently equipped to comply with the MATS rule.

On August 14, 2013, the IURC approved IPL’s MATS plan, which included investing up to $511 million in the installation of new pollution control equipment on IPL’s five largest base load generating units. These units are located at IPL’s Petersburg and Harding Street generating stations. The IURC also approved IPL’s request to recover operating and construction costs for this equipment (including a return) through a rate adjustment mechanism, with certain stipulations. IPL plans to spend a total of $454 million for this project as approximately $57 million of costs will largely be avoided as a result of the approval for IPL’s plans to refuel Harding Street Station Unit 7 from coal to natural gas (see “-Unit Retirements and Replacement Generation” below).

Several lawsuits challenging the EPA’s MATS rule were filed by other parties and consolidated into a single proceeding before the D.C. Circuit. In April 2014, the D.C. Circuit issued an opinion upholding the MATS rule. Numerous states and two trade groups petitioned the U.S. Supreme Court to review this opinion. On June 29, 2015, the U.S. Supreme Court remanded MATS to the D.C. Circuit due to the EPA’s failure to consider costs before deciding to regulate power plants under Section 112 of the CAA. On December 15, 2015, the D.C. Circuit issued an order remanding MATS to the EPA without vacatur while the EPA works to account for costs of the rule pursuant to the U.S. Supreme Court’s decision. The EPA published its final appropriate and necessary findings on April 25, 2016. In June 2016, several lawsuits were filed appealing that finding in the D.C. Circuit, and those appeals remain ongoing. Further proceedings are expected; however, in the meantime, MATS remains in effect. We currently cannot predict the outcome of this litigation, or its impact, if any, on our MATS compliance planning or ultimate costs.

Waste Management and CCR

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 asbestos, CCR, 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 CCR, we do not usually physically dispose of waste materials on our property, but instead they are usually shipped off site for final disposal, treatment or recycling. Some of our CCRs are beneficially used on-site and off-site, including as a raw material for production of wallboard, concrete or cement and as agricultural soil amendment, and some are disposed off-site in permitted disposal facilities. A small amount of CCR, 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.

The EPA’s final CCR rule became effective on October 19, 2015. Generally, the rule regulates CCR as nonhazardous solid waste and establishes national minimum criteria for existing and new CCR landfills and existing and new CCR surface impoundments (ash ponds), including location restrictions, design and operating criteria, groundwater-monitoring and corrective action, and closure requirements and post closure care. On December 16, 2016, President Obama signed into law the Water Infrastructure Improvements for the Nation Act (WIN Act), which includes provisions to implement the CCR rule through a state permitting program, or if the state chooses not to participate, a possible federal permit program.

The existing ash ponds at Petersburg have not yet been able to meet certain structural stability requirements set forth in the CCR rule. As such, IPL would be required to cease use of the ash ponds by April 17, 2017. However, IDEM has granted IPL a variance extending that deadline to April 11, 2018. In order to handle the bottom ash material that would otherwise be sluiced to the ash ponds, IPL is installing a dry bottom ash handling system at an estimated cost of approximately $47 million. On May 31, 2016, IPL filed its CCR compliance plans with the IURC.

On April 26, 2017, the IURC approved IPL’s CCR compliance request to install a bottom ash dewatering system at its Petersburg generating station and to recover 80% of qualifying costs through a rate adjustment mechanism with the remainder recorded as a regulatory asset for recovery in a subsequent rate case. The approved capital cost of the CCR compliance plan is approximately $47 million.

On September 13, 2017, EPA indicated that it would reconsider certain provisions of the CCR Rule raised by Petitioners. It is too early to determine whether this may have a material impact on our business, financial condition or results of operations.

Environmental Wastewater Requirements

In August 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 Section 402 of the CWA. These permits set new water quality-based effluent discharge limits for the Petersburg and Harding Street facilities, as well as monitoring and other requirements designed to protect human and aquatic life, with full compliance with the new effluent limitations required by October 2015. In April 2013, IPL received an extension to the compliance deadline through September 29, 2017 for IPL’s Harding Street and Petersburg facilities through agreed orders with IDEM.

IPL conducted studies to determine the operational changes and control equipment necessary to comply with the new limitations. In developing its compliance plans, IPL made assumptions about the outcomes and implications of Federal rulemakings with respect to CCR (final rule effective in October 2015), cooling water intake (final rule effective in October 2014) and wastewater ELG (final rule effective in January 2016).

On October 16, 2014, IPL filed its wastewater compliance plans with the IURC. On July 29, 2015, the IURC issued a CPCN, granting IPL authority to convert Unit 7 at the Harding Street Station from coal-fired to natural gas-fired at a cost of up to $70.9 million (the IURC later approved IPL’s updated cost estimate for the Harding Street Station refuels including $64.3 million for Unit 7), and also to install and operate wastewater treatment technologies at Harding Street Station and Petersburg Generation Station in southern Indiana at a cost of up to $325.7 million. The IURC order also granted IPL authority for timely rate recovery for 80% of the costs of these projects and authority to defer the remaining 20% as a regulatory asset to be considered for recovery through IPL’s next basic rate case proceeding. However, there can be no assurances that we will be successful in that regard.

In November 2015, the EPA published its final ELG rule to reduce toxic pollutants discharged into waterways by power plants. In addition to the wastewater treatment technologies being installed and operated for compliance with the requirements of the October 2012 NPDES permit described above, the final ELG rule will require closed loop or dry bottom ash handling at Petersburg. The original compliance date may have been as early as November 2018 or as late as December 2023, subject to the discretion of IDEM. However, on September 13, 2017, EPA published a final rule delaying certain compliance dates of the ELG. IPL is installing a dry bottom ash handling system in response to the CCR rule described above in advance of the ELG compliance date. As such, the impact of the ELG rule is not expected to be material. Industry groups have filed challenges to the ELG rule, which are pending before the U.S. Court of Appeals for the Fifth Circuit (the “Fifth Circuit”). Environmental groups have moved to intervene in these cases on behalf of the EPA. On April 24, 2017, the Fifth Circuit granted the EPA’s request to hold these challenges in abeyance during review of the rule and possible rulemaking. The Trump administration issued a stay of certain compliance deadlines in the ELG rule, which was published in theFederal Register on April 25, 2017. On May 3, 2017, environmental groups filed legal challenges to the stay. On September 18, 2017, EPA published a final rule in theFederal Register delaying certain compliance dates of the ELG and withdrew the stay issued by the Trump Administration on April 25, 2017.

On June 29, 2015, the EPA and the U.S. Army Corps of Engineers published a rule defining federal jurisdiction over waters of the U.S. This rule, which became effective in August 2015, may expand or otherwise change the number and types of waters or features subject to federal permitting. In October 2015, the U.S. Court of Appeals for the Sixth Circuit (the “Sixth Circuit”) issued an order to temporarily stay the “Waters of the United States” rule nationwide. The Sixth Circuit’s stay remains in place pending the outcome of various legal challenges, including a challenge to the U.S. Supreme Court that will determine whether the Sixth Circuit has jurisdiction over the rule. On June 27, 2017, the EPA proposed a rule that would rescind the “Waters of the U.S.” rule and re-codify the definition of “Waters of the United States” that existed prior to the 2015 rule. We cannot predict the outcome of this judicial or regulatory process, but if the “Waters of the United States” rule is ultimately implemented in its current or substantially similar form and survives the legal challenges, it could have a material impact on our business, financial condition or results of operations.

In June 2016, the EPA published the final national chronic aquatic life criterion for the pollutant, Selenium, in fresh water. IPL’s NPDES permits may be updated to include Selenium water quality based effluent limits based on a site specific evaluation process which includes determining if there is a reasonable potential to exceed the revised final Selenium water quality standards for the specific receiving water body utilizing actual and/or projected discharge information for the IPL generating facilities. As a result, it is not yet possible to predict the potential impacts of this criteria at this time. However, 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 this regard.

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 international, 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 and cash flows.

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

▪

The geographic scope of legislation and/or regulation (e.g., international, 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 federal 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.

Except as noted in the discussion below, at this time, we cannot estimate the costs of compliance with existing, proposed or potential international, 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 or regulations, if adopted, could vary drastically from current proposals. Any international, 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 considered or 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 applicable state or regional initiatives may be pursued in the future, particularly in connection with the CPP (discussed below).

In January 2011, the EPA began regulating GHG emissions from certain stationary sources under the regulations formerly-called “Tailoring Rule.” The regulations were 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. Sources subject to PSD can be required to implement BACT. In June 2014, the U.S. Supreme Court ruled that the EPA had exceeded its statutory authority in issuing the Tailoring Rule by regulating under the PSD program sources based solely on their GHG emissions. However, the U.S. Supreme Court also held that the EPA could impose GHG BACT requirements for sources already required to implement PSD for certain other pollutants when GHG increases exceed a “significance” threshold. Currently, the EPA uses a 75,000 ton per year GHG threshold to determine if increases are significant. On October 3, 2016, the EPA published a proposed rule that would set a GHG significant emissions increase threshold of 75,000 tons per year, that, if exceeded as part of a major modification that otherwise triggered PSD, would require GHG BACT. Therefore, if future modifications to IPL’s sources require PSD review for other pollutants and GHG increases exceed the EPA’s GHG significance thresholds, such modifications may also trigger GHG BACT requirements. 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.

On October 23, 2015, the EPA’s final CO2 emission rules for existing power plants (the CPP) were published in the Federal Register with an effective date of December 22, 2015. Additionally, the final NSPS for CO2 emissions from new, modified and reconstructed fossil-fuel-fired power plants were published in the Federal Register on October 23, 2015 and became effective immediately. Some states and industry groups filed petitions for review on both the CPP and the NSPS rules, and environmental groups moved to intervene in both cases on behalf of the EPA.

The CPP provides for interim emissions performance rates that must be achieved beginning in 2022 and final emissions performance rates that must be achieved by 2030. Prior to the rule’s publication in the Federal Register, fifteen states, including Indiana, filed a petition in the D.C. Circuit seeking a stay of the CPP, which was denied by the Court in September 2015. On October 23, 2015, several states and industry groups filed petitions in the D.C. Circuit challenging the CPP as published in the Federal Register, including a twenty-four state consortium that includes Indiana. These state petitioners and industry groups challenging the rule, which have been consolidated by the D.C. Circuit under the lead case,West Virginia v. EPA, filed motions with the D.C. Circuit requesting a stay of the rule. That request was denied on January 21, 2016. The states later petitioned the U.S. Supreme Court requesting a stay on January 26, 2016. On February 9, 2016, the U.S. Supreme Court issued orders staying the implementation of the CPP pending resolution of challenges to the rule. Absent the stay, state implementation plans pursuant to the CPP would have been due by September 2016. Oral arguments before the D.C. Circuit took place on September 27, 2016. We are currently reviewing the rules, considering the stay and assessing the impact of both on our operations. Our business, financial condition or results of operations could be materially and adversely affected by these rules.

On the international level, on December 12, 2015, 195 nations, including the U.S., finalized the text of an international climate change accord in Paris, France (the “Paris Agreement”), which agreement was signed and officially entered into on April 22, 2016. The Paris Agreement calls for countries to set their own GHG emissions targets, make these emissions targets more stringent over time and be transparent about the GHG emissions reporting and the measures each country will use to achieve its GHG emissions targets. A long-term goal of the Paris Agreement is to limit global temperature increase to well below two degrees Celsius from temperatures in the pre-industrial era. The U.S. has proposed that implementation of the CPP fulfill much of its intended reductions under the Paris Agreement, but additional GHG emissions reduction laws, regulations or other initiatives may be required in the future in connection with the Paris Agreement.

Based on the above, there is some uncertainty with respect to the impact of GHG rules on IPL. The GHG BACT requirements will not apply at least until we construct a new major source or make a major modification of an existing major source, and the NSPS will not require us to comply with an emissions standard until we construct a new electric generating unit. The planned CCGT at Eagle Valley is currently expected to comply with the applicable GHG BACT requirements and the final NSPS limit. Other than the CCGT discussed above, we do not have any other planned major modifications of an existing source or plans to construct a new major source at this time which are expected to be subject to these regulations. Furthermore, the EPA, states, and other utilities are still evaluating potential impacts of the CPP in our industry. In light of these uncertainties, we cannot predict the impact of the EPA’s current and future GHG regulations on our consolidated results of operations, cash flows, or financial condition, but it could be material.

Both the GHG NSPS and the CPP are being challenged by several states and industry groups in the D.C. Circuit. The challenges to the CPP have been fully briefed and argued but oral arguments have not yet taken place on the GHG NSPS and challenges to both rules are currently being held in abeyance. Additionally, by order of the U.S. Supreme Court, the CPP has been stayed pending resolution of the challenges to the rule. On October 16, 2017, the EPA published a proposed rule to repeal

the CPP in its entirety on the legal basis that the rule exceeds the EPA’s statutory authority. The EPA will accept comments until January 16, 2018.

Due to the future uncertainty of the CPP, we cannot at this time determine the impact on our operations or consolidated financial results, but we believe the cost to comply with the CPP, should it be upheld and implemented in its current or a substantially similar form, could be material. The GHG NSPS remains in effect at this time, and, absent further action from the EPA that rescinds or substantively revises the NSPS, it could impact our plans to construct and/or modify or reconstruct electric generating units in some locations, which may have a material impact on our business, financial condition or results of operations.

Unit Retirements and Replacement Generation

In addition to the five oil-fired peaking units IPL retired in the second quarter of 2013, the four coal-fired units at Eagle Valley were retired in April 2016. To replace this generation, IPL received approval from the IURC in May 2014 for a CPCN to build a 644 to 685 MW CCGT at its Eagle Valley Station site in Indiana and refuel its Harding Street Station Units 5 and 6 from coal to natural gas (approximately 100 MW net capacity each) with a total budget of $649 million. The current estimated cost of these projects is $632 million. IPL was granted authority to accrue post in-service allowance for debt and equity funds used during construction, and to defer the recognition of depreciation expense of the CCGT and refueling project. The costs to build and operate the CCGT and the refueling project, other than fuel costs, will not be recoverable by IPL through rates until the conclusion of a base rate case proceeding with the IURC after construction is completed. The CCGT is expected to be completed in the first half of 2018, and the refueling project was completed in December 2015.

In July 2015, IPL received approval from the IURC for a CPCN to refuel Harding Street Station Unit 7 from coal to natural gas (about 410 MW net capacity). The IURC order granted IPL authority for timely rate recovery for 80% of the costs of this project and authority to defer the remaining 20% as a regulatory asset to be considered for recovery through IPL’s next basic rate case proceeding. The Harding Street Station Unit 7 conversion was completed in the second quarter of 2016.

New Source Review and Other CAA NOVs

In October 2009, IPL received a 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 at the time, dating back to 1986. The alleged violations primarily pertain to the PSD and nonattainment New Source Review requirements under the CAA. In addition, on October 1, 2015, IPL received a NOV from the EPA pursuant to CAA Section 113(a) alleging violations of the CAA, the Indiana SIP, and the Title V operating permit related to alleged particulate matter and opacity violations at IPL Petersburg Unit 3. Also, on February 5, 2016, EPA issued a NOV pursuant to CAA Section 113(a) alleging violations of New Source Review and other CAA regulations, the Indiana SIP, and the Title V operating permit at Petersburg Generating Station. Since receiving the letters, IPL management has met with the EPA staff regarding possible resolutions of the NOVs. Settlements and litigated outcomes of similar New Source Review 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 these cases could have a material impact on our business. It is too early to determine whether these NOVs could have a material impact on our business, financial condition or results of operations. We would seek recovery of any operating or capital expenditures, but not fines or penalties, related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that we would be successful in this regard. IPL has recorded a contingent liability related to these New Source Review and other CAA NOV matters.

CSAPR

In March 2005 the EPA signed the federal CAIR, which imposed restrictions against polluting the air of downwind states. At the time, CAIR established a two-phase regional “cap and trade” program for SO2 and NOx emissions that requires the largest reduction in air pollution in more than a decade. CAIR covered 27 states, including Indiana, and the District of Columbia.

In August 2011, the EPA published a rule to replace CAIR that will require the further reduction of SO2 and NOx emissions from power plants in 28 states, including Indiana, which contribute to ozone and/or fine particle pollution in other states. This rule, which is known as the 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 CAIR remain in place while CSAPR was stayed. In August 2012, the U.S. Court of Appeals issued a ruling vacating the CSAPR. The Court ruling also required the EPA to continue administering CAIR.

In June 2013, the U.S. Supreme Court agreed to review the D.C. Circuit’s decision to vacate the CSAPR and in April 2014, reversed the 2012 decision by the D.C. Circuit, reinstating CSAPR, and remanded the case to the D.C. Circuit for further proceedings consistent with the U.S. Supreme Court decision. In June 2014, the U.S. Department of Justice, on behalf of the EPA, filed a motion with the D.C. Circuit to lift the stay on CSAPR and on October 23, 2014, the D.C. Circuit lifted the stay. On November 21, 2014, EPA announced a NODA and a final interim rule that addressed allocations of emission allowances to certain units for compliance with the CSAPR. These allowance allocations, which superseded the allocations announced in a 2011 NODA, reflected the changes to CSAPR made in subsequent rulemakings, as well as “re-vintaging” of previously recorded allowances so as to account for the impact of the tolling of the CSAPR deadlines pursuant to an order issued by the D.C. Circuit. On July 28, 2015, the D.C. Circuit held invalid the 2014 SO2 and ozone-season NOx emissions budgets for certain states (not including Indiana). It rejected all of the petitioners’ other challenges to the rule. The budgets remain in place pending reconsideration.

On October 26, 2016, the EPA published a final rule to update the CSAPR to address the 2008 ozone NAAQS (“CSAPR Update Rule”). The CSAPR Update Rule found that NOx ozone season emissions in 22 states (including Indiana) affect the ability of downwind states to attain and maintain the 2008 ozone NAAQS, and accordingly, the EPA issued federal implementation plans that both generally provide updated CSAPR NOx ozone season emission budgets for electric generating units within these states and that implement these budgets through modifications to the CSAPR NOx ozone season allowance trading program. Implementation began in the 2017 ozone season (May through September 2017). Legal challenges to this rule have been filed. Affected facilities will receive fewer ozone season NOx allowances in 2017 and later, possibly resulting in the need to purchase additional allowances. At this time, we cannot predict what the impact will be with respect to these new standards and requirements, but it could be material.

NAAQS

Under the CAA, the EPA sets 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, which may include imposing operating limits on individual plants. The EPA is required to review NAAQS 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 80 parts per billion to 75 parts per billion. In July 2013, the U.S. Circuit Court of Appeals upheld the 75 parts per billion standard. In December 2013, eight northeastern states petitioned the EPA to add nine upwind states, including Indiana, to the Ozone Transport Region, a group of states required to impose enhanced restrictions on ozone emissions.

In October 2016, six northeastern states filed a lawsuit to compel EPA to act on the December 2013 petition. If the petition is granted, our facilities could be subject to such enhanced requirements. Those states settled with EPA in December 2016 in a settlement requiring EPA to announce its proposed decision on the December 2013 petition by January 2017, and issue a final decision by October 2017. Additionally, on November 16, 2016, Maryland submitted a petition to the EPA pursuant to Section 126 of the CAA requesting that new limitations on NOx emissions from 36 upwind generating units, including IPL Petersburg Generating Station Units 2 and 3, on the basis that they are contributing significantly to Maryland’s ability to meet the 2008 ozone NAAQS. On January 3, 2017, the EPA issued an extension to its 60-day deadline for response to July 15, 2017. On September 27, 2017, the State of Maryland filed a complaint against EPA for failing to address its November 2016 CAA petition for such federal agency to determine that 36 electric generating units in five upwind states, including two Petersburg units, emit pollutants that contribute to non-attainment of NAAQS for ozone in Maryland, as described further in the audited Consolidated Financial Statements of IPALCO included in this prospectus. If this petition is granted, our Petersburg Generating Station Unit 2 and 3 could be subject to additional requirements. We would seek recovery of any resulting capital expenditures; however, there is no guarantee we would be successful in this regard.

On October 1, 2015, the EPA released a final rule lowering the NAAQS for ozone to 70 parts per billion from 75 parts per billion. The rule was published in the Federal Register on October 26, 2015. None of our operations are located in areas expected to be designated as nonattainment areas. Environmental groups have petitioned the D.C. Circuit to review the rule, arguing that the standard should have been set at 60 parts per billion. Industry groups have filed to oppose this position.

Fine Particulate Matter. On January 15, 2013, the EPA published the 2012 annual PM2.5 standard of 12 micrograms per cubic meter of air and the 24-hour PM2.5 standard of 35 micrograms per cubic meter of air. On January 15, 2015, the EPA published its final attainment designations for the 2012 PM2.5 standard. In addition to the PM2.5 standard, there is also a 24-hour PM10 standard of 150 micrograms per cubic meter of air. No IPL operations are currently located in nonattainment areas.

NO_X and SO₂. 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. On August 5, 2013, EPA published in the Federal Register its final designation, which include portions of Marion, Morgan, and Pike counties as nonattainment with respect to the one-hour SO2 standard.

On September 30, 2015, IDEM published its final rule establishing reduced SO2 limits for IPL facilities in accordance with the new one-hour standard, for the areas in which IPL’s Harding Street, Petersburg, and Eagle Valley generating stations operate with compliance required by January 1, 2017. The rule will not impact IPL’s Eagle Valley or Harding Street generating stations as these facilities have ceased coal combustion in advance of the compliance date. However, improvements to the existing FGD systems at Petersburg station are required to meet the emission limits imposed by the rule. IPL estimates costs for compliance at Petersburg station at approximately $29 million for measures that enhance the performance and integrity of the FGD systems. On May 31, 2016, IPL filed its SO2 NAAQS compliance plans with the IURC. On April 26, 2017, the IURC approved IPL’s request for NAAQS SO2 compliance at its Petersburg generation station with 80% of qualifying costs recovered through a rate adjustment mechanism and the remainder recorded as a regulatory asset for recovery in a subsequent rate case. The approved capital cost of the NAAQS SO2 compliance plan is approximately $29 million.

Based on these current and potential national ambient air quality standards, the state of Indiana will be required to determine whether certain areas within the state meet the NAAQS. With respect to Marion, Morgan and Pike Counties, as well as any other areas determined to be in “nonattainment,” the state of Indiana will 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 ozone, fine particulate matter or SO2. 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.

PCBs

On April 7, 2010, the EPA published an Advance Notice of Proposed Rulemaking announcing that it is reassessing existing regulations governing the use and distribution in commerce of PCBs. While this reassessment is in the early stages and the EPA is seeking information from potentially affected parties on how it should proceed, revised regulations may have a material effect. While a proposed rule is possible, this PCB rulemaking is not included in the EPA’s most recent Regulatory Plan or Semiannual Regulatory Agenda. At present, we are unable to predict the impact, if any, this initiative will have on our results of operations, financial condition or cash flows.

Cooling Water Intake Regulations

We use water as a coolant at our generating facilities. Under the CWA, cooling water intake structures are required to reflect the BTA for minimizing adverse environmental impact. On August 15, 2014, the EPA published its final standards to protect fish and other aquatic organisms drawn into cooling water systems at large power plants and other facilities that withdraw from waters of the U.S. greater than two million gallons per day, of which more than 25% is used for cooling. The final rule became effective on October 14, 2014. These standards, based on Section 316(b) of the CWA, require affected facilities to choose amongst seven BTA options to reduce fish impingement. In addition, facilities that withdraw water from a source water body above a minimum actual volume must conduct studies to assist permitting authorities to determine whether and what site- specific controls, if any, would be required to reduce entrainment of aquatic organisms. This decision process would include public input as part of a permit renewal or permit modification. It is possible this process could result in the need to install closed-cycle cooling systems (closed-cycle cooling towers), or other technology. Finally, the standards require that new units added to an existing facility must reduce both impingement and entrainment that achieves one of two alternatives under national BTA standards. IPL’s NPDES permits will be updated with the requirements of this rule, including any source-specific requirements arising from the evaluation process described above. As a result, it is not yet possible to predict the total impacts of this final rule at this time, including any challenges to such final rule and the outcome of any such challenges. However, 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 this regard.

Other

In response to Executive Orders, the EPA is currently evaluating various existing regulations to be considered for repeal, replacement, or modification. We cannot predict at this time the likely outcome of the EPA’s review of other existing regulations or what impact it may have on our business.

The DOE issued a Notice of Proposed Rule Making on September 29, 2017, which directed the FERC to exercise its authority to set just and reasonable rates that recognize the “resiliency” value provided by generation plants with certain characteristics, including having 90-days or more of on-site fuel and operating in markets where they do not receive rate base treatment through state ratemaking. Nuclear and coal-fired generation plants are most likely to be able to meet the requirements. As proposed, the DOE would value resiliency through rates that recover “compensable costs” that are defined to include the recovery of operating and fuel expenses, debt service and a fair return on equity. The FERC is proceeding on an expedited basis, as requested by the DOE, but the timing and outcome of the proposed rule, including effects on wholesale energy markets, remains uncertain.

Summary

Environmental laws and regulations presently require us to incur material capital expenditures and operating costs. We expect to incur or have incurred material costs, both in capital expenditures and ongoing operating and maintenance costs, to comply with the MATS rule (up to $454 million in capital expenditures), NPDES permit requirements at our Petersburg plant (up to $224 million in capital expenditures), the CCR rule (a dry bottom ash handling system at an estimated cost of approximately $47 million), and, to a lesser extent to which we cannot predict, other expected environmental regulations related to: CSAPR; cooling water intake; NAAQS; EPA’s proposed and final regulations related to GHG emissions from power plants; and PCBs. In addition, the combination of existing and expected environmental regulations, the IURC's approval of our replacement generation plan and other economic factors have resulted in us retiring or refueling several of our existing, primarily coal-fired, generating units between 2013 and 2017 (the total estimated costs of these projects is $632 million, as discussed in “Unit Retirements and Replacement Generation” above). 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 this regard. In addition, environmental laws and regulations 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. Depending on 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 this regard.

ENERGY SUPPLY

Approximately 84% of the total kWh we generated in 2016 was from coal as compared to approximately 97% and 99% in 2015 and 2014, respectively. Our existing coal contracts provide for all of our current projected requirements in 2017 and approximately 85% in total for the three-year period ending December 31, 2019. We have long-term coal contracts with three suppliers and a spot contract with one other supplier. Approximately 53% of our existing coal under contract for the three-year period ending December 31, 2019 comes from one supplier. We have one contract with this supplier, which employs non-unionized labor, for the provision of coal from three separate mines.

Historically, we used coal as a fuel source at Petersburg, Harding Street Station and Eagle Valley. After the Harding Street Station Unit 7 conversion was completed in the second quarter of 2016, we no longer burn coal at Harding Street. The coal-fired units at Eagle Valley were retired in April 2016 and we no longer burn coal at Eagle Valley.

Pricing provisions in some of our long-term coal contracts allow for price changes under certain circumstances. Substantially all of our coal is currently mined in the state of Indiana, and all of our coal supply 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. Our present inventory is within our target range.

Natural gas and fuel oil provided the remaining kWh generation for these respective periods. Natural gas is used in our steam boiler units at Harding Street Station (Units 5 and 6 beginning in December 2015 and Unit 7 beginning in the second quarter of 2016) and combustion turbines. IPL sources natural gas from the wholesale market delivered to our plants by interstate pipeline and local distribution companies. IPL holds firm pipeline transportation commitments on Texas Gas Transmission interstate pipeline and has firm redelivery contracts with the local distribution companies that serve IPL plants. We do not maintain a natural gas inventory; however, our experience has been that natural gas is readily available at liquid supply points on interstate

pipelines, and we expect this availability to continue in the future. Fuel oil is used for start-up and flame stabilization in coal-fired generating units, as primary fuel in two older combustion turbines, and as an alternate fuel in two other combustion turbines.

As a result of the Harding Street Station refueling projects and the retirement of coal-fired units at Eagle Valley in April 2016, we experienced an increase in the percentage of generation from natural gas. The generation fuel mix from coal and natural gas will continue to change as the relative prices of the commodities change. Another step change will occur when the CCGT at the Eagle Valley Station is completed, expected in the first half of 2018. At the completion of these projects, we expect approximately two-thirds of the total kWh we generate to be from coal and approximately one-third to be from natural gas.

Additionally, we meet the electricity demands of our retail customers with energy purchased under power purchase agreements and by purchases in MISO. We are committed under long-term power purchase agreements to purchase all energy from two wind projects that have a combined maximum output capacity of 300 MW. We have 97 MW of solar-generated electricity in our service territory under long-term contracts in 2017, of which 95 MW was in operation as of December 31, 2016. We also purchase up to 8 MW of energy from a combined heat and power facility located in Indianapolis, Indiana.

Total electricity sold to our retail customers in 2016 came from the following sources: 65.5% from IPL-owned coal-fired steam generation, 11.7% from IPL-owned natural gas-fired units, and 22.8% from power purchased under power purchase agreements and from the wholesale power market.

STATISTICAL INFORMATION ON OPERATIONS

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

	Nine Months Ended September 30,				Twelve Months Ended December 31,
	2017		2016		2016		2015		2014		2013		2012
Operating Revenues (in thousands):
Residential	$	399,101	$	399,289	$	532,564	$	480,969	$	485,779	$	472,630	$	466,294
Small commercial and industrial	155,145		157,965		208,928		192,232		193,213		185,241		183,681
Large commercial and industrial	428,904		421,348		557,491		526,461		527,719		504,038		510,669
Public lighting	7,424		7,627		10,023		10,823		10,811		10,743		10,872
Revenues – retail customers	990,574		986,229		1,309,006		1,210,485		1,217,522		1,172,652		1,171,516
Wholesale	5,904		8,391		15,804		19,307		83,208		62,734		37,822
Miscellaneous	17,570		17,753		22,620		20,607		20,944		20,348		20,439
Total utility operating revenues	$	1,014,048	$	1,012,373	$	1,347,430	$	1,250,399	$	1,321,674	$	1,255,734	$	1,229,777

kWh Sales (in millions):
Residential	3,559		3,911		5,152		5,062		5,269		5,243		5,144
Small commercial and industrial	1358		1407		1,850		1,837		1,888		1,882		1,862
Large commercial and industrial	4,971		5,081		6,620		6,757		6,778		6,841		6,945
Public lighting	37		37		57		53		59		63		64
Sales – retail customers	9,925		10,436		13,679		13,709		13,994		14,029		14,015
Wholesale	179		257		507		689		2,397		2,005		1,308
Total kWh sold	10,104		10,693		14,186		14,398		16,391		16,034		15,323

Retail Customers at End of Period:
Residential	437,351		432,716		435,622		431,182		427,866		424,201		419,867
Small commercial and industrial	48,616		48,144		48,204		47,919		47,534		47,360		47,108
Large commercial and industrial	4,760		4,807		4,763		4,737		4,749		4,727		4,645
Public lighting	1392		953		955		953		945		935		957
Total retail customers	492,119		486,620		489,544		484,791		481,094		477,223		472,577

LEGAL PROCEEDINGS

In the normal course of business, we are subject to various lawsuits, actions, claims, and other proceedings. We are also from time to time involved in other reviews, investigations and proceedings by governmental and regulatory agencies regarding our business, certain of which may result in adverse judgments, settlements, fines, penalties, injunctions or other relief. We have accrued in our audited consolidated financial statements for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. We believe the amounts provided in our Financial Statements, as prescribed by GAAP, for these matters are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters (including those matters noted below), and to comply with applicable laws and regulations will not exceed the amounts reflected in our Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided for in our Financial Statements cannot be reasonably determined, but could be material.

Please see “Business-Environmental Matters,” Note 2, “Regulatory Matters” and Note 10, “Commitments and Contingencies” to the Audited Consolidated Financial Statements of IPALCO, included in this prospectus, 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.

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

As of September 30, 2017, all of the outstanding common stock of IPALCO is owned by AES U.S. Investments (82.35%) and CDPQ (17.65%). As a result, our stock is not listed for trading on any stock exchange.

Dividends

During the first nine months of 2017 and 2016, IPALCO paid $75.5 million and $86.4 million, respectively, in dividends to its shareholders. During the years ended December 31, 2016, 2015 and 2014, we paid dividends to our shareholders totaling $123.0 million, $69.5 million and $78.4 million, respectively. Future distributions to our shareholders will be determined at the discretion of our Board of Directors and will depend primarily on dividends received from IPL and such other factors as our Board of Directors deems relevant. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources” of this prospectus for a discussion of limitations on dividends from IPL. In order for us to make any dividend payments to our shareholders, 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.

MANAGEMENT

Set forth below is certain information regarding each of IPALCO’s current directors as of September 30, 2017, including the qualifications of such persons to serve as directors. Directors are elected annually to serve until their successors are duly elected and qualified or until their earlier death, disqualification, resignation or removal from office. Please see “-Nomination of Directors” below for a discussion of certain rights with respect to the nomination and election of directors held by certain of IPALCO’s shareholders.

Directors

Barry J. Bentley, 52, has been a Director of IPALCO since March 2017. Mr. Bentley is Market Business Leader, US Utilities of the United States Strategic Business Unit (“US SBU”) of AES, which includes IPALCO and Indianapolis Power & Light Company (“IPL”), IPALCO’s principal operating subsidiary. Mr. Bentley also serves as a Director of AES U.S. Investments and DPL Inc. (“DPL”) and The Dayton Power and Light Company (“DP&L”), which are also owned by AES. Mr. Bentley brings extensive experience in energy company operations to the Board of Directors. Prior to assuming his current role, Mr. Bentley served as the Vice President of Customer Operations of the US SBU until June 2017. Since joining AES, Mr. Bentley has held several other positions, including Senior Vice President of Customer Operations for IPL and was responsible for IPL’s transmission and distribution system, Customer Service, Strategic Accounts, and Supply Chain. He also was a Senior Investment Associate with IPALCO. Prior to joining AES, Mr. Bentley served as Principal with EnerTech Capital Partners, a venture capital firm in Wayne, Pennsylvania focused on early stage venture investments in energy and telecommunications. Mr. Bentley received a B.S. in Electrical Engineering at Purdue University in 1988 and has participated in executive education programs at the University of Michigan and the Darden School of Business. He is a member of the executive committee of the board of directors for the Indianapolis Symphony Orchestra and a member of the Indiana University Purdue University of Indianapolis (IUPUI) Dean’s Industry Advisory Council and serves on the executive committee of the board of directors of the Midwest Energy Association.

Renaud Faucher, 53, has been a Director of IPALCO since February 2015, when he was nominated by CDPQ to serve on IPALCO’s Board of Directors. Mr. Faucher also serves as a Director of AES U.S. Investments. Mr. Faucher brings extensive experience in construction, project management and finance to the Board of Directors. Mr. Faucher joined CDPQ in 2006, and he is currently Regional Director North America, Asset Management in the infrastructure group. From 1998 to 2006, he held different positions within wholly owned international subsidiaries of Hydro-Québec as Director Investments, Vice President Finance and Vice President Risk Management. From 1992 to 1998, Mr. Faucher worked on the financing and management of independent power plants across Canada. From 1986 to 1990, Mr. Faucher worked as a project engineer on the construction of large infrastructure projects in Canada and Europe, including the Channel Tunnel project. Mr. Faucher currently sits on the boards of Colonial Pipeline, Noverco and Gaz Metro and has served as the President of Noverco since February 2016. Previously, Mr. Faucher was a member of the LLC committee of Cross-Sound Cable Company LLC (a submarine power cable between Connecticut and Long Island), a director of Sedna (a long-term health care services provider in Québec), of Southern Star Central Gas Pipeline (an interstate pipeline in the United States), of Noverco (a holding company with investments in Gaz Metro and Enbridge), of AviAlliance Capital (formerly Hochtief Airport Capital in Germany), on the Supervisory Board of Budapest Airport, on Heathrow Airport Holdings and on the members committee of Invenergy Wind LLC. Mr. Faucher holds a Bachelor's in Civil Engineering from École Polytechnique de Montréal, as well as an M.B.A. from Concordia University and a DESS (specialized graduate diploma) in Accounting from ESG-UQAM. He is also a Chartered Professional Accountant (CPA, CMA).

Paul L. Freedman, 47, has been a Director of IPALCO since February 2015. Mr. Freedman joined AES in 2007, and currently serves as Chief of Staff to the Chief Executive Officer of AES. Mr. Freedman has held several positions at AES including Assistant General Counsel, Senior Corporate Counsel and General Counsel North America Generation. Mr. Freedman also serves as a director or officer of other AES affiliates, including as a Director of AES U.S. Investments, DP&L and AES Gener. Mr. Freedman brings to the Board of Directors his legal and industry experience together with his experience at AES in a wide range of areas, including commercial transactions, financings, corporate strategy, regulatory and environmental matters, and corporate governance. Prior to joining AES, Mr. Freedman was Chief Counsel for credit programs at the U.S. Agency for International Development and he previously worked as an associate at the law firms of White & Case, LLP and Freshfields. Mr. Freedman received a B.A. from Columbia University and a J.D. from the Georgetown University Law Center.

Craig L. Jackson, 45, has been a Director of IPALCO since February 2015. Mr. Jackson is Chief Financial Officer of IPALCO and the US SBU and serves as Vice President and Chief Financial Officer of IPL. Mr. Jackson has served in various capacities within the utility finance and accounting sectors, including with DPL and its affiliates. Mr. Jackson joined DPL in 2004 and has held various positions of increasing responsibility in the finance and accounting organizations at DPL. Mr. Jackson has served as DPL’s Chief Financial Officer since July 2012. Mr. Jackson also has served as DP&L’s Chief Financial Officer since May 2012, as a Director since May 2015, and as Vice President since July 2015 and serves as a director or officer

of other AES affiliates, including as a Director and the Chief Financial Officer of AES U.S. Investments. Mr. Jackson brings substantial finance and accounting experience with regulated utilities to the Board of Directors. Mr. Jackson received a B.S. in business administration from Bloomsburg University and an M.B.A. from Wright State University. Mr. Jackson serves on the board of directors of The DP&L Foundation and Rebuilding Together Indianapolis.

Frédéric Lesage, 50, has been a Director of IPALCO since September 2017 and is also a member of the Board of Directors of AES U.S. Investments. Mr. Lesage brings extensive experience in project management and operations to the Board. Mr. Lesage joined CDPQ in 2017 and is currently Director of Asset Management in the infrastructure group. From 2015 to 2017, Mr. Lesage was the Chief Executive Officer of FL Investments and Advisory Inc., assisting businesses with strategic and organizational matters, and, from 2007 to 2014, he held various positions within TAQA - ABU Dhabi National Energy Co., a $30 billion energy and water operator, including Chief Strategy Officer, Regional President and Managing Director, and Group Vice-President, and served on the company’s Executive Committee. Previously, Mr. Lesage served as a management consultant and lawyer. Mr. Lesage holds a Bachelor’s degree in Law from Université De Montréal and an M.B.A. from Richard Ivey School of Business.

Thomas M. O’Flynn, 57, has been a Director of IPALCO since February 2015 and is the Chairman of the Board. Mr. O’Flynn has served as Executive Vice President and Chief Financial Officer of AES since September 2012 and serves as a director or officer of other AES affiliates, including as the Chairman of the Board of AES U.S. Investments. Mr. O’Flynn brings to the Board of Directors his perspective as a senior financial executive well versed in finance and accounting. Previously, Mr. O’Flynn served as Senior Advisor to the private equity group of Blackstone in the power and utility sector from 2010 to 2012. During this period, Mr. O’Flynn also served as Chief Operating Officer and Chief Financial Officer of Transmission Developers, Inc., a Blackstone-controlled company that develops innovative power transmission projects in an environmentally responsible manner. From 2001 to 2009, he served as the Chief Financial Officer of PSEG, a New Jersey-based merchant power and utility company. He also served as President of PSEG Energy Holdings from 2007 to 2009. From 1986 to 2001, Mr. O’Flynn was in the Global Power and Utility Group of Morgan Stanley. He served as a Managing Director for his last five years at Morgan Stanley and served as the head of the North American Power Group from 2000 to 2001. At Morgan Stanley, he was responsible for senior client relationships and led a number of large merger, financing, restructuring and advisory transactions. Mr. O’Flynn also served on the Board of Silver Ridge Power, a joint venture between AES and Riverstone Holdings LLC from September 2012 through July 2014. Mr. O’Flynn has a B.A. in Economics from Northwestern University and an M.B.A. from the University of Chicago. He is also currently on the board of directors of the New Jersey Performing Arts Center and was the inaugural Chairman of the Institute for Sustainability and Energy at Northwestern University, of which he is still an active Board member.

Bradley Scott, 51, has been a Director of IPALCO since March 2017. Mr. Scott joined AES in 2003, and currently serves as Operations Director for the US Central Complex and the Senior Vice President of Power Supply for IPL. Mr. Scott brings over 27 years of experience in energy generation to the Board of Directors, and has held several other positions at AES, including Regional Director for PJM Interconnection, LLC (“PJM”), Plant Manager of IPL’s Petersburg Generating Station, Director of Plant Performance, and Plant Manager of AES Redondo Beach, AES Deepwater and AES Placerita. Mr. Scott also serves as an officer or director of other AES affiliates, including as a Director of AES U.S. Investments. Mr. Scott received a B.S. in Mechanical Engineering from Rochester Institute of Technology.

Richard A. Sturges, 54, has been a Director of IPALCO since February 2015. Mr. Sturges brings over 18 years of experience in the electric industry to the Board of Directors. Since joining AES in 2006, Mr. Sturges has held several positions including Director of Finance for North America, Director and Vice President Portfolio Management and, currently, Vice President Mergers & Acquisitions. Mr. Sturges also serves as an officer or director of other AES affiliates, including as a Director of AES U.S. Investments. Previously, Mr. Sturges served as Director, Finance for National Energy and Gas Transmission, Inc. Mr. Sturges holds a Bachelor of Engineering Science from Johns Hopkins University and a Masters in Public and Private Management from Yale University.

Margaret E. Tigre, 40, has been a Director of IPALCO since February 2015. Ms. Tigre also serves as a director or officer of other AES affiliates, including as a Director of AES U.S. Investments. Ms. Tigre brings more than 19 years of financial experience, including ten years in the electric industry, to the Board of Directors. Since joining AES in 2007, Ms. Tigre has held several positions including Chief of Staff to the Chief Executive Officer, Vice President Corporate Tax and, currently, Senior Vice President, Finance and Chief Corporate Tax Officer. Ms. Tigre currently serves as an alternate Director for AES Gener and served as a member of the Board of AES Gener from October 2014 through April 2015. Ms. Tigre holds a B.S. from George Mason University.

Kenneth J. Zagzebski, 58, has been a Director of IPALCO and IPL since March 2009. Since April 2011, Mr. Zagzebski has served as President and Chief Executive Officer of IPALCO. Mr. Zagzebski served as interim President and Chief Executive Officer of IPL from July 1, 2015 to June 1, 2016, and as President and Chief Executive Officer of IPL from April

2011 until June 2013 and March 2014, respectively. Mr. Zagzebski is President of the US SBU and a Vice President of AES. He is also President, Chief Executive Officer and a Director of DPL, a Director of DP&L, and an officer or director of other AES affiliates, including a Director and the President of AES U.S. Investments and a Director of sPower. Mr. Zagzebski joined IPL as Senior Vice President of Customer Operations in September 2007 and was responsible for the Power Delivery, Customer Services and Enterprise Information Systems business groups. Mr. Zagzebski also served as a member of the Board of AES SUL, LLC from April 2012 through January 2013 and AES Electropaulo S.A. from December 2011 through February 2013. Mr. Zagzebski has more than 30 years of industry experience in diverse executive management, business development and financial roles, including Vice President and Chief Operating Officer for Field Operations at Xcel Energy. His background also includes experience in international energy as Executive Director of NRG Energy Asia-Pacific region, from 1997 to September 1999 where he was responsible for the company’s Asia-Pacific investments. Mr. Zagzebski’s broad industry experience and extensive knowledge and understanding of IPL and IPALCO allow him to provide invaluable insight to the Board of Directors. Mr. Zagzebski has a Bachelor’s degree from the University of Wisconsin, Eau Claire, and an M.B.A. from the Carlson School of Management at the University of Minnesota. Mr. Zagzebski currently Chairs the Marian University Educators College Board of Visitors and serves on the board of directors of the YMCA of Greater Indianapolis and the board of directors of the Central Indiana Corporate Partnership.

EXECUTIVE OFFICERS

Set forth below is certain information regarding each of our current executive officers as of September 30, 2017. IPALCO was acquired by AES in March 2001, and is currently a majority-owned subsidiary of AES U.S. Investments. IPL is our primary operating subsidiary. AES manages its business through a geographically focused strategic business unit (“SBU”) platform. AES businesses in the United States, including IPALCO and IPL, are part of the US SBU; however, the US SBU is not a legal entity. AES U.S. Services, LLC (the “Service Company”), another subsidiary of AES, is a service company established in late 2013 to provide operational and corporate services on behalf of companies that are part of the US SBU, including among other companies, IPALCO and IPL. As a result of this structure, IPALCO and IPL do not directly employ all of the executives responsible for the management of our business.

Officers are elected at the annual meeting of the Board of Directors, and hold office until a successor is duly elected and qualified or until earlier death, resignation or removal from office. There are no family relationships among our Directors and Executive Officers.

Name	Age	Position
Kenneth Zagzebski	58	Director, President and Chief Executive Officer of IPALCO Director, IPL Interim President and Chief Executive Officer of IPL until June 2016 President, US SBU
Craig Jackson	45	Director and Chief Financial Officer of IPALCO Vice President and Chief Financial Officer of IPL Chief Financial Officer, US SBU
Jennifer Killer	42	Vice President, Human Resources, US SBU
Mark Miller	56	Chief Operating Officer, US SBU
Rafael Sanchez	43	President and Chief Executive Officer of IPL
Judi Sobecki	46	Secretary and General Counsel of IPALCO and the US SBU Vice President, Secretary and General Counsel of IPL

Biographical information for Messrs. Zagzebski and Jackson is presented under “-Directors” above.

Jennifer Killer,42, is Vice President, Human Resources for the US SBU, which includes IPALCO and IPL. Previously, Ms. Killer served as Vice President, Human Resources, Global Functions of AES from January 2014 until June 2016. Since joining AES in 2007, Ms. Killer has held several other positions including Director of Human Resources, Global Functions; Director of Global Compensation and Benefits; and Director of Global Human Resources Operations. Ms. Killer also serves as an officer of other AES affiliates. Prior to joining AES, Ms. Killer worked as a human resources manager for Intelsat General Corporation, and as a human resources manager, compensation and benefits analyst and recruiter for PanAmSat Corporation. Ms. Killer received a B.A. from Boston College and an M.B.A. from Fairfield University.

Mark E. Miller, 56, is Chief Operating Officer for the US SBU. Mr. Miller joined AES in June 1989 and has helped manage numerous AES generation and distribution businesses in the last 27 years in six international markets, including as the UK country manager from 2009-2014 where he was responsible for commercial operations and development efforts in the Irish electricity market and the UK renewables sector. Mr. Miller brings substantial background in power plant operations across a range of technologies and energy sector commercial activities. In his most recent role as East Complex Manager for the US SBU, Mr. Miller was responsible for a portfolio of coal, wind and energy storage assets operating in the PJM market. Mr. Miller also serves as a director or officer of other AES affiliates. Prior to joining AES, Mr. Miller served 10 years in the U.S. Navy and is a graduate of the Naval Nuclear Program.

Rafael Sanchez,43, is President and Chief Executive Officer of IPL and also serves as a Director of IPL. Previously, Mr. Sanchez served as Senior Vice President of Strategic Planning for IPL from February 2016 to June 2016. Prior to joining AES, Mr. Sanchez was a partner at Bingham Greenebaum Doll, LLP and served as Vice President of Business Development and Legal Affairs for Fineline Printing Group. Mr. Sanchez also served on the IPL Advisory Board for the last five years. Mr. Sanchez received a B.S. from the University of Puerto Rico and a J.D. from the Indiana University Maurer School of Law. Mr. Sanchez currently serves as the Secretary for the Indianapolis Chamber of Commerce, Co-Chair for Plan 2020, Immediate Past Chair for Cancer Support Community and serves on the executive committee for the United Way of Central Indiana and board of directors of the Indiana Chamber of Commerce and Indiana Latino Institute.

Judi Sobecki, 46, is Secretary and General Counsel of IPALCO and the US SBU and also serves as Vice President, Secretary and General Counsel of IPL. Ms. Sobecki oversees all legal matters for AES’ U.S. operations, including IPL and IPALCO. She also leads the U.S. environmental policy team, which represents AES and its affiliates before environmental enforcement agencies. Ms. Sobecki also serves as General Counsel and Secretary of DPL and Vice President, General Counsel and Secretary of DP&L, leads the regulatory affairs teams at IPL and DP&L and serves as an officer of other AES affiliates, including as the General Counsel and Secretary of IPALCO’s parent company, AES U.S. Investments. Previously, Ms. Sobecki served as Assistant General Counsel, Regulatory for the US SBU. In that role, she supported all of AES’ U.S. businesses in connection with state public utility commission regulatory matters. Ms. Sobecki joined DP&L in 2007 as Senior Counsel, leading the legal regulatory efforts for DP&L. Prior to joining DP&L, Ms. Sobecki spent over 10 years in a private law practice as a civil trial lawyer, with many of those years representing DP&L in a variety of matters. Ms. Sobecki received a B.S. from Kent State University and a J.D. from Case Western Reserve University.

Code of Ethics

The AES Code of Business Conduct (“Code of Conduct”), adopted by the AES Board of Directors, is intended to govern, as a requirement of employment, the actions of AES employees, including employees of its subsidiaries and affiliates, including the CEO, CFO and Controller of IPL and IPALCO. The Ethics and Compliance Department of AES provides training, information, and certification programs for employees of AES and its subsidiaries (including IPL and IPALCO) related to the Code of Conduct. The Ethics and Compliance Department also has programs in place to prevent and detect criminal conduct, promote an organizational culture that encourages ethical behavior and a commitment to compliance with the law, and to monitor and enforce AES policies. The Code of Conduct is located in its entirety on the AES website (www.aes.com). Any person may obtain a copy of the Code of Conduct without charge by making a written request to: Corporate Secretary, IPALCO Enterprises, Inc., One Monument Circle, Indianapolis, IN 46204. If any amendments (other than technical, administrative or other non-substantive amendments) to, or waivers from, the Code of Conduct are made, AES will disclose such amendments or waivers on its website. Except for such Code of Conduct, the information contained on or accessible through the AES website is not incorporated by reference into this Amendment or the Annual Report on Form 10-K.

Corporate Governance

The Board of Directors has not established any committees, including an audit committee, a compensation committee or a nominating committee, or any committee performing similar functions. The functions of those committees are undertaken by the Board. The Board may designate from among its members an executive committee and one or more other committees in the future.

IPALCO’s securities are not quoted on an exchange that has requirements that a majority of the Board be independent, and IPALCO is not currently otherwise subject to any law, rule or regulation requiring that all or any portion of the Board include “independent” directors, nor is IPALCO required to establish or maintain an Audit Committee, Audit Committee Financial Expert or other committee.

Nomination of Directors

As of September 30, 2017, IPALCO had not effected any material changes to the procedures by which shareholders may recommend nominees to the Board of Directors. IPALCO’s articles of incorporation and bylaws do not provide formal procedures for shareholders to recommend nominees to the Board of Directors. Except as described below, the Board of Directors has determined that it is in the best position to evaluate IPALCO’s requirements as well as the qualifications of each candidate when the Board considers a nominee for a position on the Board.

AES U.S. Investments, IPALCO and CDPQ are parties to a Shareholders’ Agreement dated February 11, 2015 (the “Shareholder’s Agreement”).

The Shareholders’ Agreement provides AES U.S. Investments the right to nominate nine directors of the IPALCO Board and CDPQ the right to nominate two directors of the IPALCO Board. CDPQ most recently exercised its right in connection with the nomination of Messr. Faucher to the Board of Directors in March 2017 and Messr. Lesage to the Board of Directors in September 2017, and AES U.S. Investments exercised its right in connection with the nomination of the other directors of the Board. See “Shareholders’ Agreement” in this prospectus.

COMPENSATION DISCUSSION AND ANALYSIS

The purpose of this compensation discussion and analysis is to provide information about the material elements of compensation that were paid or awarded to, or earned by, our named executive officers (“NEOs”) in 2016. The compensation paid to our NEOs for 2016 is set forth in the “Summary Compensation Table” below. Our NEOs for 2016 were:

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Kenneth Zagzebski, our President and Chief Executive Officer, President of the US SBU, and interim President and Chief Executive Officer of IPL until June 2016;

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Craig Jackson, our Chief Financial Officer, Chief Financial Officer of the US SBU and Vice President and Chief Financial Officer of IPL;

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Andrew Horrocks, Chief Operating Officer of the US SBU until March 2017;

•

Michael Mizell, Midwest Market Business Leader of the US SBU until February 2017; and

•

Salil Pradhan, Vice President, Commercial Operations of the US SBU until August 2017.

Mr. Zagzebski is also a Vice President of AES, and, as discussed below, his 2016 compensation was determined in accordance with AES’ compensation practices and policies.

In this Compensation Discussion and Analysis (“CD&A”), an explanation of how non-GAAP measures are calculated from the audited financial statements are either included under the heading “Non-GAAP Measures” or in the description of the applicable program in this prospectus.

Background

In order to better understand our compensation programs for our NEOs, we think that it is helpful to better understand how the management of IPALCO is operated within the AES family of companies. IPALCO was acquired by AES in March 2001 and is a majority-owned subsidiary of AES U.S. Investments, and has a minority interest holder, CDPQ, as of February 11, 2015. IPL is our primary operating subsidiary. Most of the key members of our management team are employed by other AES companies and perform roles for both IPALCO and other AES entities.

AES manages its business through a geographically-focused SBU platform. AES’ businesses in the United States, including IPALCO and IPL, are part of the US SBU; however, the US SBU is not a legal entity. AES also has an indirectly wholly-owned subsidiary, the Service Company, which was established in late 2013. The Service Company provides services, including operations, accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the US SBU, including, among other companies, IPALCO and IPL. As a result of this structure, IPALCO and IPL do not directly employ all of the executives responsible for the management of our business. In 2016, our NEOs were all executive officers of one or more of IPALCO, IPL and the Service Company.

The Service Company allocates the costs for services provided based on cost drivers designed to result in fair and equitable allocations pursuant to a Cost Alignment and Allocation Manual (the “CAAM”). As a result, the costs associated with our executive compensation for those officers performing work for other entities are also allocated pursuant to the terms of the CAAM, based on the amount of time that each executive officer devotes to our business. The executive compensation reported in this Amendment reflects the entire compensation paid or awarded to, or earned by, each NEO for their services on behalf of one or more of IPALCO, IPL and the Service Company and not just the portion of such compensation that is allocated to IPALCO and IPL.

Our Executive Compensation Philosophy and Objectives

Our compensation philosophy is consistent with AES’ compensation philosophy, which emphasizes pay-for-performance. Our compensation philosophy is to provide compensation opportunities to each of our NEOs that are commensurate with his or her position, experience, and scope of responsibilities, to furnish incentives sufficient for each NEO to meet and exceed short-term and long-term corporate objectives and to provide executive compensation and incentives that will attract, motivate, and retain a highly skilled management team.

Consistent with this philosophy and our goal of aligning our executives’ compensation with company performance, the key features of our executive compensation program include the following:

•

Our compensation program allocates a significant portion of each NEO’s total compensation to short- and long-term performance goals. As such, payouts are dependent upon the strategic, financial, and operational performance of AES and the US SBU, which includes IPALCO and IPL, and the performance of the AES stock price;

•

Our compensation program is continually reviewed to ensure that it meets our objectives and executive compensation philosophy and remains competitive; and

•

We generally do not provide perquisites to our NEOs. Similar to prior years, Mr. Horrocks received certain expatriate benefits in 2016, as described in further detail below.

In order to meet these objectives, our total compensation structure includes a mix of short-term compensation, in the form of base salaries and annual cash bonuses, and long-term compensation, in the form of AES equity-based and cash-based performance awards. As part of their total compensation packages, Messrs. Jackson and Mizell participate in the retirement program of DP&L, The Dayton Power and Light Company Retirement Income Plan (the “DP&L Retirement Income Plan”), as more fully described herein.

Our Compensation Process

The Chief Operating Officer of AES (the “AES COO”) works with the Chief Human Resources Officer of AES (the “AES CHRO”) to design and review the compensation for our CEO.

Our CEO, the AES COO and the AES CHRO (together, the “Executive Compensation Review Team”) have the responsibility of reviewing and administering compensation for the other officers of the Service Company, IPALCO, and IPL, including for our NEOs. The Vice President of Human Resources of the US SBU (the “VP of HR”) works with our CEO during the compensation process. Neither our CEO nor the VP of HR participates with respect to his or her own compensation. The Executive Compensation Review Team, with assistance from the US SBU human resources team, determines the appropriate pay grade for these NEOs at the date of hire based upon each individual’s position, responsibilities, skills and experience, and reassesses each NEO’s position within the applicable pay grade at the end of each year.

The pay grades comprising our compensation framework are established by the US SBU human resources team in conjunction with the AES human resources team and include specific base salary ranges and short-term bonus and long-term compensation targets for each pay grade. The US SBU human resources team use survey data from the Hay Group, Willis Towers Watson and other sources with regard to looking at the overall pay structure at a very high level. The structure is compared annually to market data from various sources, including the Hay Group and Willis Towers Watson to assess the external competitiveness of the base salary ranges and incentive targets for the pay grades. During our performance review cycle, the Executive Compensation Review Team measures the specific amount and resulting incentive compensation for our NEOs (except that neither our CEO nor the VP of HR participates with respect to his or her own compensation) based on (i) the operational and financial performance of the US SBU and AES, and (ii) the NEO’s target opportunity for his applicable pay grade.

Awards of short-term compensation are made in the form of annual cash bonuses to our NEOs under the AES Performance Incentive Plan (the “PI Plan”) and are determined by the Executive Compensation Review Team in the first quarter of the year following the review period as described below. Awards of long-term compensation were made to our NEOs under the AES 2003 Long Term Compensation Plan, as amended and restated (the “LTC Plan”), and are determined by the Board of Directors of AES based upon the recommendations of the Executive Compensation Review Team in the last quarter of each year as described below.

The use and weight of cash versus non-cash, fixed versus variable and short- versus long-term components of executive compensation is generally dictated by the applicable pay grade for each NEO, as described above. As we are not subject to the federal proxy rules, we are not required to hold a shareholder advisory vote on our executive compensation, or a “Say-on-Pay” vote.

Our CEO’s compensation is higher than the compensation paid to our other NEOs, largely due to the scope of his position and his overall responsibility for the strategy and direction of IPALCO, IPL and the US SBU, as well as his overall influence on near- and long-term performance of IPALCO, IPL and the US SBU, in general. In comparison to our other NEOs, our CEO’s total compensation is more heavily weighted towards incentive compensation.

Elements of Compensation

The fundamental elements of our compensation program are:

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base salary;

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performance-based, short-term annual cash bonuses under the PI Plan;

•

cash-based incentive awards granted under the LTC Plan;

•

equity incentive awards granted under the LTC Plan in AES equity, for which there is a public market; and

•

other broad-based benefits, such as retirement and health and welfare benefits.

The pay grades comprising our compensation framework provide specific allocations of cash versus equity compensation and short- and long-term compensation. The Executive Compensation Review Team sets each individual element of total compensation within the parameters of the pay grade applicable to each particular NEO, as set forth below.

2016 Compensation Determinations

Base Salary

Base salary represents the “fixed” component of our executive compensation program for our NEOs. We provide our NEOs with base salaries in order to provide fixed cash compensation that is competitive and reflects experience, responsibility, and expertise. Base salaries are reviewed annually in the last quarter of each year and are adjusted as appropriate within the base ranges of the applicable pay grade. Base salary is also reviewed for an executive officer if there is a promotion or a newly appointed executive officer. Internal company salary guidance regarding annual base pay adjustments is also taken into consideration, and adjustments to base salaries are made when needed to reflect individual performance, retention considerations and address internal equity. Please see the “Salary” column of the Summary Compensation Table below for the base salary amounts paid to our NEOs for the years indicated.

2016 Performance Incentive Plan Payouts

In addition to base salaries, in 2016 we provided performance-based, annual cash bonuses under the PI Plan. Each pay grade has a corresponding PI Plan target opportunity, which is assessed annually. Each NEO's opportunity corresponds to the opportunity applicable to his pay grade. These awards are paid based on the achievement of AES and US SBU safety, financial, and operational key performance indicators (“KPIs”), and strategic objectives, which were established in the first quarter of 2016. The PI Plan is structured in a manner that provides our NEOs a direct incentive to achieve such KPIs and objectives.

AES’ performance is a key factor in determining whether awards will be made under the PI Plan for the relevant fiscal year. In 2016, payments under the PI Plan were determined based on the AES and US SBU 2016 performance measures as described in the tables below. Performance measures were based upon management's business goals for the US SBU for 2016. Individual awards are paid out at 0-200% of the target applicable to each pay grade depending on scores achieved relative to the performance measures.

While goals are set for specific safety measures, as described in the tables below, the Compensation Committee of the AES Board of Directors (the “AES Compensation Committee”) approves a safety score for AES based on its qualitative assessment of performance, and our Executive Compensation Review Team, with input from the US SBU management team, approves a safety score for the US SBU based on its qualitative assessment of performance.

Targets for the 2016 financial measures for AES and the SBU were equal to 2016 budget, subject to pre-established guidelines for adjusting the targets in the event of certain events during the year. No adjustments were made in 2016. US SBU actual financial results correlate directly to the applicable financial metrics score. Operational KPIs measure how effectively and reliably we operate our plants and meet our customers’ electricity needs. For AES and the US SBU, each KPI is weighted and has a threshold, target and maximum performance goal set at the beginning of the year. The final index score may range from 0% to 200%.

We also set goals with respect to the following strategic objectives: construction, new growth projects and the AES Energy Star Program, an internal initiative to increase efficiencies. The AES Compensation Committee approves the score for AES on a formulaic basis considering actual performance relative to pre-set Megawatts (“MW”) growth targets as well as construction program schedules and budgets, and our Executive Compensation Review Team, with input from the US SBU management team, approves a score for the US SBU based on its assessment of performance on its US SBU strategic objectives.

AES 2016 Actual Results: The AES Compensation Committee determined to pay the 2016 corporate performance score based on actual results of the pre-established performance measures as shown below. As a result, the AES performance score for 2016 was determined to be 112%, as follows:

Measurement Category	Target Goal	Actual Result	Weight	Final Score (as % of Target)
Safety	Serious Safety Incidents • No serious safety incidents in the workplace Lost Time Incident Case Rate ("LTI") • AES People: Edison Electric Institute Top Decile • Operational Contractors: Edison Electric Institute Top Decile • Construction Contractors: Bureau of Labor Statistics Top Quartile Proactive Safety Measures • Achieve 2016 goals	Serious Safety Incidents • One or more serious incidents occurred Lost Time Incident Case Rate ("LTI") • AES People: Unfavorable to target • Operational Contractors: Unfavorable to target • Construction Contractors: Favorable to target Proactive Safety Measures • Exceeded safety walk and meeting goals	10%	0% (qualitative assessment)
Financial	• Adjusted EPS* (15% weight): $1.00 • Proportional Free Cash Flow* (20% weight): $1,175 million • Parent Free Cash Flow* (15% weight): $575 million	• Adjusted EPS: $0.98 • Proportional Free Cash Flow: $1,417 million • Parent Free Cash Flow: $579 million	50%	139%
Operational KPIs	Generation KPIs • Commercial availability (32.8% weight) • Equivalent forced outage factor (24% weight) • Equivalent availability factor (21.8% weight) • Heat rate (17% weight) • Days sales outstanding (4.4% weight) Distribution KPIs • System Average Interruption Duration Index (43.3% weight) • System Average Interruption Frequency Index (30% weight) • Non-technical losses (3.7% weight) • Customer Satisfaction Index (12.3% weight) • Days sales outstanding (10.7% weight)	• Operational KPI Score of 111	10%	111%
Strategic Objectives	Construction (10% weight) • Advance construction program on time / on budget AES Energy Star Program (10% weight) • Run rate cost savings and revenue enhancements of $50M New Growth Projects (10% weight) • 750 MWs of new growth projects or acquisitions in 2016	Advance Construction Programs • On time score: 79% • On budget score: 82% AES Energy Star Program (10% weight) • Run rate cost savings and revenue enhancements of $65M New Growth Projects • 754 MWs of new growth projects or acquisitions	30%	104%

Overall AES Performance Score 112%

* An explanation of how non-GAAP measures are calculated from the audited financial statements are either included under the heading “Non-GAAP Measures” or in the description of the applicable program in this prospectus.

US SBU 2016 Performance: The US SBU performance for 2016 was assessed based on a number of factors, which are described in the following chart. Taking these factors together as a whole, the US SBU performance for 2016 was determined to be 109%.

Measurement Category	Target Goal	Actual Result	Weight	Final Score (as % of Target)
Safety	• Zero fatalities • Zero LTI Rate for AES people and operational contractors • OSHA Incident Rate (Edison Electric Institute top quartile) • Safety meeting attendance (95%) • Safety Events - Learning • Opportunities (563) • Safety walks (12,352)	• Fatalities occurred • 2016 LTI case rate below target • OSHA incident rate unfavorable to target • Monthly safety meeting attendance exceeded target • Safety events were below target • Number of safety walks exceeded target	10%	0% (qualitative assessment)
Financial	• Adjusted Pretax Contribution* (30% weight): $391.2 million • Proportional Free Cash Flow* (40% weight): $593.5 million • Subsidiary Distributions* (30% weight): $268.5 million	• Adjusted Pretax Contribution: $352.1 million • Proportional Free Cash Flow: $642.0 million • Subsidiary Distributions: $295.6 million	50%	117%
Operational KPIs	Distribution KPIs • System Average Interruption Duration Index (50% weight) • System Average Interruption Frequency Index (30% weight) • Customer satisfaction (10% weight) • Days sales outstanding (10% weight) Generation KPIs Thermal • Equivalent forced outage factor (26.1% weight) • Commercial availability (39.2% weight) • Equivalent Availability Factor (16.6% weight) • Heat rate (Btu/kWh) (18.1% weight) Wind • Equivalent forced outage factor (40% weight) • Net capacity factor (10% weight) • Commercial availability (50% weight) Distributed Energy • Commercial availability (100% weight) Battery Energy Storage System (BESS) • Equivalent forced outage factor (16.6% weight) • Commercial availability (18.1% weight) • Equivalent Availability Factor (16.6% weight)	• Distribution KPIs exceeded target • With the exception of commercial availability which was above target, Thermal Generation KPIs were below target • Wind Generation KPIs were below target • Distributed Energy KPI was above target • BESS KPIs were below target	10%	118%
Strategic Objectives	• AES Energy Star Program (10% weight) • IPL Environmental Projects (5% weight) • Southland Development (5% weight) • Renewable Growth (5% weight) • DPL ESP Case (5% weight)	AES Energy Star Progress:95% of target • Satisfactory participation and exceeded targets IPL Environmental Projects Progress:75% of target • Progressed on schedule and budget and exceeded safety performance (with the esception of IPL CCGT) Southland Development Progress: 140% of target Renewable Growth Progress: 200% of target DPL ESP Case Progress: 80% of target	30%	114% (qualitative assessment)

Overall US SBU Performance Score 109%

Our NEOs receive bonus amounts based on a bonus payout factor formula that considers both AES corporate performance (25%) and US SBU performance as a whole (75%), which includes IPALCO and IPL.

The Executive Compensation Review Team determines the individual bonus amounts for each NEO (other than our CEO) within this framework.

The VP of HR works with our CEO with regard to such determinations except with respect to her own compensation. The NEO’s individual contributions to the success of the US SBU in achieving the performance objectives outlined above and the performance of the NEO’s respective division or line of business are also reviewed in such determinations but did not materially affect the resulting compensation of our NEOs, with the exception of Mr. Mizell as further described below. The AES COO and the AES CHRO determine the bonus amount for Mr. Zagzebski based upon the same considerations. For 2016, the resulting annual incentive cash awards for all of our NEOs with the exception of Mr. Mizell were slightly above their respective target annual incentive opportunities. Based on his responsibility and the delayed regulatory outcomes we experienced in Indiana and Ohio, Mr. Mizell’s annual incentive was set at 93.5% of his target.

The following table sets forth the amounts of the annual incentive cash awards under the PI Plan earned by our NEOs in 2016, which were paid in early 2017.

			Actual 2016 Annual Incentive Cash Award
NEO	2016 Target Annual Incentive ($)(1)	2016 Target Annual Incentive (% of base salary)	Dollar Value	% of Target Annual Incentive
Kenneth Zagzebski	$347,181	85%	$400,995	115.5%
Craig Jackson	$166,296	60%	$186,584	112.2%
Andrew Horrocks	$106,828⁽¹⁾	50%	$ 117,510	109.9%
Michael Mizell	$164,705	60%	$153,999	93.5%
Salil Pradhan	$128,500	50%	$ 134,282	104.5%

(1)

Based on annual base salary rate.

Long Term Compensation

We grant a mix of cash- and equity-based awards under the LTC Plan. These awards attract and retain key individuals who are critical to the success of our business and align the interests of our NEOs with those of stockholders over the long term. Grants to our NEOs under the LTC Plan, whether in cash or stock, vest over a three-year period and are determined based on a percentage of the individual’s base salary. In 2016, our NEOs other than our CEO received awards- 50% in cash in the form of Performance Units and 50% in stock in the form of Restricted Stock Units. Our CEO received awards - 40% granted in the form of Performance Cash Units that vest in cash, 40% granted in the form of Performance Stock Units that vest in AES stock, and 20% granted in the form of Restricted Stock Units that vest in AES stock. No stock options were granted in 2016.

Performance Units, or PUs, represent the right to receive cash subject to performance- and service-based vesting conditions. Each unit granted has a $1 target value. If performance is below 75% of target, 0% of the units vest. Maximum performance is attained at 125% of target, which would trigger a vesting of 200% of the granted units. Between these levels, straight-line interpolation is used to determine the vesting percentage for the award. PUs vest in equal installments over a three-year period. Performance is based on EBITDA less Maintenance and Environmental Capital Expenditures of AES (“CapEx”) (“EBITDA less CapEx”), calculated as described below, versus target achieved over the three-year measurement period. If the required performance metric is achieved, awards, to the extent service vested, are paid out in the calendar year immediately following the date on which the performance period ends. The AES Compensation Committee approved an EBITDA less CapEx target for the 2016 PUs that was considered to be highly challenging and will require improvement over prior performance.

EBITDA less CapEx is a measure of long-term cash generation driven by increasing revenue, reducing costs, improving productivity, and efficiently utilizing capital. Growth-related CapEx is excluded, since the EBITDA less CapEx measure is intended to assess AES operating efficiency and the amount of cash generated for capital allocation. In addition, environmental capital projects that generate a regulated rate of return are excluded from the definition of CapEx. EBITDA less CapEx consists of Gross Margin, plus Depreciation and Amortization, plus Intercompany Management Fees; minus Selling, General and Administrative Expenses to equal EBITDA. An adjustment is made to reduce EBITDA by Maintenance and Environmental CapEx. The Environmental CapEx for this adjustment is reduced by those projects with tracker returns that, through a regulatory mechanism, provide for the recovery of, and return on, certain utility investments. As a final step in the calculation, the total EBITDA less CapEx is adjusted by AES’ ownership percentage (which reflects AES’ direct or indirect ownership in a particular business).

The following table illustrates the vesting percentage at each EBITDA less CapEx level for targets set for the PUs for the 2016-2018 performance period:

Performance Level	Vesting Percentage
Below 75% of Performance Target	0%
Equal to 100% of Performance Target	100%
Equal to or greater than 125% of Performance Target	200%

Between the EBITDA less CapEx levels listed in the above table, straight-line interpolation is used to determine the vesting percentage for the award. The ability to earn PUs is also generally subject to the continued employment of the NEO through the vesting date.

Performance Stock Units Based on Proportional Free Cash Flow:Performance stock units represent the right to receive a single share of AES Common Stock subject to performance- and service-based vesting conditions. Performance stock units granted in 2016 are eligible to vest subject to AES’ three-year cumulative Proportional Free Cash Flow. Proportional Free Cash Flow is a measure of long-term cash generation driven by increasing revenue, reducing costs, improving productivity and efficiently utilizing capital.

The Proportional Free Cash Flow target is set for the three-year performance period and is subject to pre-defined, objective adjustments during the three-year performance period based on changes to AES’ portfolio, such as an asset divestiture or sale of a portion of equity in a subsidiary.

The final value of the performance stock unit award depends upon the level of Proportional Free Cash Flow achieved over the three-year measurement period as well as AES’ share price performance over the period since the award is stock-settled. If a threshold level of Proportional Free Cash Flow is achieved, units vest and are settled in the calendar year that immediately follows the end of the performance period.

The following table illustrates the vesting percentage at each Proportional Free Cash Flow level for targets set for the 2016-2018 performance period:

Performance Level	Vesting Percentage
Below 75% of Performance Target	0%
Equal to 87.5% of Performance Target	50%
Equal to 100% of Performance Target	100%
Equal to or greater than 125% of Performance Target	200%

Between the Proportional Free Cash Flow levels listed in the above table, straight-line interpolation is used to determine the vesting percentage for the award. The ability to earn performance stock units is also generally subject to the continued employment of the NEO. The AES Compensation Committee approved a Proportional Free Cash Flow target for the 2016 performance stock unit that was considered to be challenging and will require improvement over prior performance.

Performance Cash Units Based on AES Total Stockholder Return: Performance cash units represent the right to receive a cash-based payment subject to performance- and service-based vesting conditions. Performance cash units granted in 2016 are eligible to vest subject to AES’ Total Stockholder Return from January 1, 2016 through December 31, 2018 relative to companies in three different indices. The indices and their weightings are as follows:

•

S&P 500 Utilities Index - 50%

•

S&P 500 Index - 25%

•

MSCI Emerging Markets Index - 25%

We use Total Stockholder Return as a performance measure to align our CEO’s compensation with stockholders’ interests since the ability to earn the award is linked directly to stock price and dividend performance over a period of time.

Total Stockholder Return is defined as the appreciation in stock price and dividends paid over the performance period as a percent of the beginning stock price. To determine share price appreciation, we use a 90-day average stock price for AES, the S&P 500 Utilities Index companies, the S&P 500 Index companies, and the MSCI Emerging Markets Index companies at the beginning and end of the three-year performance period. This avoids short-term volatility impacting the calculation.

The value of each performance cash unit is equal to $1.00, and the number of performance cash units that vest depends upon AES’ percentile rank against the companies in the indices. If AES’ Total Stockholder Return is above the threshold percentile rank established for the performance period, a percentage of the units vest and are settled in cash in the calendar year that immediately follows the end of the performance period. The following table illustrates the vesting percentage at each percentile rank for the 2016-2018 performance period:

AES 3-Year Total Stockholder Return Percentile Rank	Vesting Percentage
Below 30th percentile	0	%
Equal to 30th percentile	50	%
Equal to 50th percentile	100	%
Equal to 70th percentile	150	%
Equal to or above the 90th percentile	200	%

Between the percentile ranks listed in the above table, straight-line interpolation is used to determine the vesting percentage for the award. The ability to earn these performance cash units is also generally subject to the continued employment of the NEO.

Restricted Stock Units, or RSUs, represent the right to receive a single share of AES Common Stock subject to service-based vesting conditions. AES grants RSUs to assist in retaining executives and also to increase their ownership of AES Common Stock, which further aligns executives’ interests with those of AES stockholders. RSUs vest based on continued service with AES in three equal installments, beginning on the first anniversary of the grant date. Each NEO (other than Mr. Zagzebski) received 50% of his 2016 long-term compensation in the form of RSUs. Mr. Zagzebski received 20% of his long-term compensation in the form of RSUs. Further details on 2016 RSU grants can be found in the Grants of Plan-Based Awards Table of this prospectus.

2016 Long Term Compensation Grants

As in previous years, the allocation of long-term compensation components granted in 2016 was based on a review of market practice conducted by AES and is aligned with the objective of fostering the long-term corporate performance of AES, as our parent company, and rewarding individual performance.

The following table sets forth the target grant value for grants under the LTC Plan made to our NEOs in 2016. The target grant values are based on the Black-Scholes value of the stock options, assuming the options are exercised at the end of the full contractual term and the grant date closing stock price of AES Common Stock for PSUs and RSUs.

	February 2015 Long-Term Compensation Expected Target Grant Value
Name	As % of Base Salary	Dollar Amount
Kenneth Zagzebski	150%	$	556,976
Craig Jackson	65%	$	174,907
Andrew Horrocks	55%	$	127,867
Michael Mizell	65%	$	173,233
Salil Pradhan	60%	$	150,000

As discussed in “Our Compensation Process” above, the long-term compensation target grant values are generally dictated by the NEOs applicable AES pay grade. Further detail on all long-term compensation grants to our NEOs can be found in the Summary Compensation Table and the Grants of Plan-Based Awards Table of this prospectus.

Prior Year Performance Unit Vesting in 2016

All NEOs, except for Messrs. Zagzebski and Pradhan, received a grant of PUs in February 2014. PUs are not a component of Mr. Zagzebski’s CEO compensation package, and Mr. Pradhan had not yet joined the US SBU in 2014. PUs represent the right to receive cash, subject to performance- and service-based vesting conditions. The 2014 PU grant vested based on the same vesting conditions as the PUs granted in 2016 (a performance vesting condition based on EBITDA less CapEx target, together with a three-year service-based vesting condition), which terms are described in further detail above.

The PUs paid out at 70.02% of target based on AES’ actual EBITDA less CapEx result of $6,619M , which was 92.5% of the target EBITDA less CapEx goal. Thus, the total payout for this award for the NEOs, other than Messrs. Zagzebski and Valdez, is shown in the following table:

	Target Number of Performance Units	% of Target Vested Based on:
NEO	Target Number of Performance Units	Cumulative EBITDA less CapEx		Final Vested Value
Craig Jackson	81,250	70.02	%	$	56,891
Michael Mizell	81,250	70.02	%	$	56,891
Andrew Horrocks	68,737	70.02	%	$	48,130

Further details on the 2014-2016 PU payouts can be found in the Summary Compensation Table of this prospectus.

Prior Year Performance Stock Units Vesting in 2016

Mr. Zagzebski received a grant of PSUs in February 2014 for the 2014-2016 performance period. For the 2014-2016 PSUs, 50% of the target number of shares was based on AES Total Stockholder Return relative to the S&P 500 Utility companies for the period from January 1, 2014 to December 31, 2016. The remaining 50% of the target number of units was based on the achievement of AES’ cumulative EBITDA less CapEx target for the 2014-2016 performance period.

There was no payout for the 50% portion of the PSU awarded based on Total Stockholder Return because AES did not attain the performance threshold, which was Total Stockholder Return equal to the 30^th percentile of S&P 500 Utility companies. The 50% portion of the PSU awarded based on AES’ EBITDA less CapEx, which was calculated in the same manner as the 2016 PSUs as described above, paid out at 70% of the target number of shares based on AES’ actual EBITDA less CapEx result of $6,619M, which was 92.5% of the target EBITDA less CapEx goal. Thus, the total payout for the 2014-2016 PSUs for Mr. Zagzebski was 35% of the original target number of PSUs as shown in the following table:

	Target Number of Performance Stock Units	% of Target Vested Based on:		Final Shares Vested
NEO	Target Number of Performance Stock Units	Relative AES Total Stockholder Return	Cumulative EBITDA less CapEx	Number Of Shares	% of Original Target
Kenneth Zagzebski	13,756	0%	70%	4,816	35%

SeeLong-Term Compensation-Performance Units above for a description of EBITDA less CapEx.

Further details on the 2014-2016 PSU payout to Mr. Zagzebski can be found in the Option Exercises and Stock Vested Table of this prospectus.

Other Relevant Compensation Elements and Policies

Perquisites

We generally do not provide any perquisites to our NEOs. In 2016 and consistent with prior years, Mr. Horrocks, who is a U.K. citizen, received certain expatriate benefits, such as auto allowance, home visits, housing and gross-up of U.S. taxes.

Retirement and Other Broad-Based Employee Benefits

Our NEOs, as well as our other employees, are eligible for the following benefits: participation in a defined contribution (401(k)) plan, group health insurance (including medical, dental, and vision), long- and short-term disability insurance, basic life insurance and paid time off. Messrs. Jackson and Mizell participate in the DP&L Retirement Income Plan. Our NEOs are eligible to participate in the AES Restoration Supplemental Retirement Plan (the “RSRP”), a nonqualified deferred compensation plan, which is intended to restore benefits that are limited under our broad-based retirement plans due to statutory limits imposed by the United States Internal Revenue Code (the “Code”). Contributions to the RSRP are included with All Other Compensation column of the Summary Compensation Table of this prospectus.

Severance and Change in Control Arrangements

AES maintains certain severance and change in control arrangements, including the AES Corporation Severance Plan (the “Severance Plan”) and change in control provisions in the long-term compensation award agreements. Upon a change in control of AES, unvested long-term compensation awards held by our NEOs would only fully vest and become payable immediately should a double-trigger occur. The double-trigger only allows for vesting if a qualifying termination occurs in connection with the change in control. Any PUs, PSUs and PCUs would vest based on attainment of target levels of performance. In addition, all NEOs are entitled to payments and benefits under the Severance Plan, in the event of qualifying terminations of employment, both related and unrelated to a change in control. Finally, upon a termination of service or in the event of a change in control, participants’ account balances in the RSRP (described in the 2016 Nonqualified Deferred Compensation Table below) would be paid out, either as a lump-sum payment or according to the participant’s election. Please see “Potential Payments upon Termination and Change in Control” below for a more detailed summary of these payments and benefits.

Employment Agreements and Other Arrangements

Our NEOs do not have any employment agreements or other arrangements, except as disclosed herein.

Non-GAAP Measures

In this CD&A we reference certain non-GAAP measures, including Adjusted Earnings Per Share (Adjusted EPS), Adjusted Pretax Contribution (Adjusted PTC), Subsidiary Distributions, Proportional Free Cash Flow, and Parent Free Cash Flow, which are publicly disclosed in AES’ periodic filings with the SEC or in other materials posted on the AES website. These measures are reconciled to the nearest GAAP measure as described below.

Adjusted Earnings Per Share (Adjusted EPS). The GAAP measure most comparable to Adjusted EPS is diluted earnings per share from continuing operations. AES defines Adjusted EPS as diluted earnings per share from continuing operations excluding gains or losses of both consolidated entities and entities accounted for under the equity method due to (a) unrealized gains or losses related to derivative transactions, (b) unrealized foreign currency gains or losses, (c) gains or losses due to dispositions and acquisitions of business interests, (d) losses due to impairments, and (e) costs due to the early retirement of debt.

Adjusted Pretax Contribution (Adjusted PTC). The GAAP measure most comparable to Adjusted PTC is income from continuing operations attributable to AES. AES uses Adjusted PTC as its primary segment performance measure. AES defines Adjusted PTC as pretax income from continuing operations attributable to AES excluding gains or losses of the consolidated entity due to (a) unrealized gains or losses related to derivative transactions, (b) unrealized foreign currency gains or losses, (c) gains or losses due to dispositions and acquisitions of business interests, (d) losses due to impairments, and (e) costs due to the early retirement of debt. Adjusted PTC also includes net equity in earnings of affiliates on an after-tax basis, adjusted for the aforementioned items.

Subsidiary Distributions. The GAAP measure most comparable to Subsidiary Distributions is net cash provided by operating activities. The difference between Subsidiary Distributions and net cash provided by operating activities consists of cash generated from operating activities that is retained at the subsidiaries for a variety of reasons, which are both discretionary and non-discretionary in nature. Subsidiary Distributions are important to AES because AES is a holding company that does not derive any significant direct revenues from its own activities, but instead relies on its subsidiaries’ business activities and the resultant distributions to fund its debt service, investment and other cash needs.

Proportional Free Cash Flow. The GAAP measure most comparable to Proportional Free Cash Flow is cash flows from operating activities. AES defines Proportional Free Cash Flow as cash flows from operating activities less maintenance capital expenditures (including non-recoverable environmental capital expenditures), adjusted for the estimated impact of noncontrolling interests. Environmental capital expenditures that are expected to be recovered through regulatory, contractual or other mechanisms are excluded. An example of recoverable environmental capital expenditures is IPL's investment in MATS-related environmental upgrades that are recovered through a tracker.

Parent Free Cash Flow. Parent Free Cash Flow is Subsidiary Distributions less cash used for interest costs, development, general and administrative activities and tax payments by AES.

Compensation Risk

We believe that the applicable compensation programs and policies are designed and administered with the appropriate mix of compensation elements and balance current and long-term performance objectives, cash and equity compensation, and

risks and rewards associated with our executives’ roles. As a result, we believe that the risks arising from our employee compensation program are not reasonably likely to have a material adverse effect on the Company.

SUMMARY COMPENSATION TABLE (2016, 2015 and 2014)

Name and Principal Position (a)	Year (b)	Salary ($) (c)(1)		Stock Awards ($) (d)(2)		Option Awards ($) (e)(3)		Non-Equity Incentive Plan Compensation ($) (f)(4)		Change In Pension Value ($) (g)(5)		All Other Compensation ($) (h)(6)		Total ($) (i)
Kenneth Zagzebski President and CEO	2016	$	407,163	$	512,419	$	—	$	400,995	$	—	$	26,600	$	1,347,177
	2015	$	370,984	$	258,307	$	107,272	$	307,169	$	—	$	36,557	$	1,080,289
	2014	$	360,219	$	285,596	$	100,171	$	545,927	$	—	$	34,323	$	1,326,236

Craig Jackson CFO	2016	$	276,881	$	87,457	$	—	$	243,475	$	72,471	$	9,275	$	689,559
	2015	$	268,731	$	83,682	$	—	$	198,023	$	12,829	$	9,275	$	572,540
	2014	$	257,299	$	81,255	$	—	$	219,477	$	132,286	$	16,492	$	706,809

Andrew Horrocks COO, US SBU	2016	$	260,871	$	63,932	$	—	$	165,640	$	—	$	158,420	$	648,863
	2015	$	252,273	$	65,443	$	—	$	155,723	$	—	$	51,917	$	525,356
	2014	$	237,994	$	68,732	$	—	$	203,577	$	—	$	234,458	$	744,761

Michael Mizell Midwest Market Business Leader, US SBU	2016	$	274,232	$	86,619	$	—	$	210,890	$	8,892	$	9,275	$	590,008
	2015	$	266,236	$	83,682	$	—	$	191,476	$	6,632	$	9,275	$	557,301
	2014	$	257,299	$	81,255	$	—	$	175,728	$	8,798	$	20,787	$	543,867

Salil Pradhan Vice President Commercial Operations, US SBU	2016	$	257,758	$	74,998	$	—	$	134,282	$	—	$	13,250	$	480,288

(1)

The base salary earned by each NEO during fiscal years 2016, 2015 or 2014, as applicable. Compensation information for a NEO is given for the earliest of the last three completed years that the officer was a NEO of the Company and all subsequent completed years. The compensation disclosed in this table represents the full amount of compensation paid to each NEO and is not limited to the portion of each NEO’s compensation allocated to and paid by IPALCO. The increase in our CEO’s salary for 2016 relative to the 2015 level exceeded the increases for our other NEOs largely due to the increase in initiatives for the US SBU.

(2)

Aggregate grant date fair value of performance stock units and performance cash units granted to Mr. Zagzebski in the year, and restricted stock units granted to all NEOs in the year, which are computed in accordance with Financial Accounting Standards Board (“FASB”), Accounting Standards Codification (“ASC”) Topic 718, “Compensation - Stock Compensation” (“FASB ASC Topic 718”), disregarding any estimate of forfeitures related to service-based vesting conditions. A discussion of the relevant assumptions made in the valuation may be found in the financial statements, footnote 17 to the financial statements, or Management’s Discussion & Analysis, as appropriate, contained in the AES Annual Report on Form 10-K for the year ended December 31, 2016 (“AES Form 10-K”), which also includes information for 2014 and 2015. Assuming the maximum market and financial performance conditions are achieved, and in the case of performance stock units the share price at grant, the maximum value of performance stock units and performance cash units granted in fiscal year 2016, and payable upon completion of the 2016-2018 performance period is $445,582 and $445,580, respectively.

(3)

Aggregate grant date fair value of stock options granted in the year, which are computed in accordance with FASB ASC Topic 718. The aggregate grant date fair value disregards any estimates of forfeitures related to service-based vesting conditions. A discussion of the relevant assumptions made in the valuation may be found in the financial statements, footnote 17 to the financial statements, or Management’s Discussion & Analysis, as appropriate, contained in the AES Form 10-K, which also includes information for 2014 and 2015. No stock options were granted in 2016.

(4)

The value of all non-equity incentive plan awards earned during the 2016, 2015, and 2014 fiscal years and paid in 2017, 2016, and 2015, respectively, which includes awards earned under our PI Plan (our annual incentive plan) and awards earned for the three-year performance periods ending December 31, 2016, 2015 and 2014, respectively, for our cash-based performance units granted under the LTC Plan. The following chart shows the breakdown of awards under these two plans for each NEO.

Name	Year	Annual Incentive Plan Award		Payouts for Performance Unit Award		Total Non- Equity Incentive Plan Compensation
Kenneth Zagzebski	2016	$	400,995	$	—	$	400,995
	2015	$	307,169	$	—	$	307,169
	2014	$	411,900	$	134,027	$	545,927

Craig Jackson	2016	$	186,584	$	56,891	$	243,475
	2015	$	137,132	$	60,891	$	198,023
	2014	$	199,691	$	19,786	$	219,477

Andrew Horrocks	2016	$	117,510	$	48,130	$	165,640
	2015	$	97,703	$	58,020	$	155,723
	2014	$	135,348	$	68,229	$	203,577

Michael Mizell	2016	$	153,999	$	56,891	$	210,890
	2015	$	142,893	$	48,583	$	191,476
	2014	$	175,728	$	—	$	175,728

Salil Pradhan	2016	$	134,282	$	—	$	134,282

(5)

Messrs. Jackson and Mizell participate in the DP&L Retirement Income Plan. The pension plan change in value for Messrs. Jackson and Mizell is provided for the years indicated. Details of this pension plan are set forth in the Pension Benefits table. Messrs. Zagzebski, Horrocks and Pradhan do not participate in an employer sponsored pension plan.

(6)

All Other Compensation includes employer contributions to both qualified and nonqualified defined contribution retirement plans. The following chart shows the breakdown of contributions under these plans for each NEO. For 2016, other compensation for Mr. Horrocks includes (i) compensation he received as an expatriate such as auto allowance ($4800), home visits (including airfare and miscellaneous costs) ($28,265), housing ($37,019), Indiana state tax payments ($29,754), and tax preparation services ($7,044) and (ii) contributions of $38,288 made by AES to Mr. Horrocks’ U.K. pension plan. Mr. Horrocks also received a gross-up of taxes for 2016, which was fully offset by amounts deducted from his compensation by AES in 2016 and as such these amounts are not included in the table. For 2015, other compensation for Mr. Horrocks is compensation he received as an expatriate such as auto allowance ($4,800), home visits ($5,767), housing ($37,019), and tax preparation services ($4,331). Mr. Horrocks also received a gross-up of U.S. taxes for 2015, which was fully offset by amounts deducted from his compensation by AES in 2015 and as such these amounts are not included in the table. For 2014, (i) other compensation for Messrs. Jackson and Mizell includes relocation and related expenses for relocating to Indianapolis, Indiana, and (ii) other compensation for Mr. Horrocks includes relocation and related expenses for relocating to the United States, together with compensation he receives as an expatriate such as auto allowance, home visits, housing, and tax preparation services. Mr. Horrocks also received a gross-up of taxes for 2014 that exceeded amounts deducted from his compensation by AES in 2014 by $45,287, which amount is included in the table for 2014 compensation.

Name	Year	Employer Contribution to Qualified Defined Contribution Plans		Employer Contribution to Nonqualified Defined Contribution Plans		Other		Total Other Compensation
Kenneth Zagzebski	2016	$	13,250	$	13,350	$	—	$	26,600
	2015	$	21,050	$	15,507	$	—	$	36,557
	2014	$	28,300	$	6,023	$	—	$	34,323

Craig Jackson	2016	$	9,275	$	—	$	—	$	9,275
	2015	$	9,275	$	—	$	—	$	9,275
	2014	$	8,723	$	—	$	7,769	$	16,492

Andrew Horrocks	2016	$	13,250	$	—	$	145,170	$	158,420
	2015	$	—	$	—	$	51,917	$	51,917
	2014	$	—	$	21,919	$	212,539	$	234,458

Michael Mizell	2016	$	9,275	$	—	$	—	$	9,275
	2015	$	9,275	$	—	$	—	$	9,275
	2014	$	9,100	$	—	$	11,687	$	20,787

Salil Pradhan	2016	$	13,250			$	—	$	13,250

GRANTS OF PLAN-BASED AWARDS (2016)

The following table provides information about the plan based cash and equity awards made to the NEOs in 2016.

				Estimated Future Payouts Under Non-Equity Incentive Plan Awards						Estimated Future Payouts Under Equity Incentive Plan Awards (3)			All Other Stock Awards:	Grant Date Fair Value
Name	Grant Date	Units		Threshold ($)		Target ($)		Maximum ($)		Threshold(#)	Target (#)	Maximum (#)	Number of Shares of Stock or Units(#)(4)	of Stock and Option Awards ($)(6)


Kenneth Zagzebski			$	—	$	315,619	$	631,239	(1)
	19-Feb-16									—	23,676	47,352		$	222,791
	19-Feb-16												11,838	$	111,396
	19-Feb-16									111,395	222,790	445,580		$	178,232
Craig Jackson			$	—	$	161,453	$	322,906	(1)
	19-Feb-16	87,454	$	43,727	$	87,454	$	174,908	(2)
	19-Feb-16												9,294	$	87,457
Andrew Horrocks			$	—		116,243		232,485	(1)
	19-Feb-16	63,934	$	31,967		63,934		127,868	(2)
	19-Feb-16												6,794	$	63,932
Michael Mizell			$	—	$	159,908	$	319,816	(1)
	19-Feb-16	86,617	$	43,309	$	86,617	$	173,234	(2)
	19-Feb-16												9,205	$	86,619
Salil Pradhan			$	—	$	84,375	$	168,750	(1)
	19-Feb-16	75,000	$	37,500	$	75,000	$	150,000	(2)
	19-Feb-16												7,970	$	74,998

(1)

Each NEO received an award under the PI Plan (our annual cash incentive plan) in 2016. The first row of data for each NEO shows the threshold, target and maximum award under the PI Plan. For the PI Plan, the threshold award is 0% of the target award, and the maximum award is 200% of the target award. The extent to which awards are payable depends upon AES’ performance against goals established in the first quarter of the fiscal year. This award was paid in the first quarter of 2017 and the actual payout amounts are shown in footnote 4 to the Summary Compensation Table.

(2)

Each NEO other than Mr. Zagzebski received a grant of performance units on February 19, 2016, which were awarded under the LTC Plan and are paid in cash. These units vest based on both market and financial performance conditions, and service conditions. The financial performance condition is based on the EBITDA less CapEx metric for the three-year period ending December 31, 2018 (as more fully described in the CD&A of this Amendment). The second row of data for each NEO other than Mr. Zagzebski shows the threshold, target and maximum award. At threshold, the vesting percentage is 50%. At maximum performance, the vesting percentage is 200%. Straight-line interpolation is applied for performance between the threshold and target and between the target and maximum.

(3)

Mr. Zagzebski received a grant of performance stock units on February 19, 2016 awarded under the LTC Plan. These units vest based on the financial performance condition of Proportional Free Cash Flow for the three year period ending December 31, 2018(as more fully described in the CD&A of this Amendment). The second row of data for Mr. Zagzebski shows the total number of AES shares at threshold, target and maximum. At threshold, the vesting percentage is 0%. At maximum performance, the vesting percentage is 200%. Straight-line interpolation is applied for performance between the threshold and target and between the target and maximum.

With respect to the service-based condition, voluntary termination or termination for cause prior to the end of the three-year performance period will result in the forfeiture of all outstanding performance stock units. Involuntary termination or a qualified retirement, which requires the NEO to reach 60 years of age and seven years of service with the Company, allow prorated time-vesting in increments of one-third or two-thirds vesting if the NEO has completed one or two years of service from the grant date, respectively. Service-based vesting is contingent on at least one of the two performance conditions being achieved at a minimum of threshold performance.

Mr. Zagzebski also received Performance Cash Units on February 19, 2016 awarded under the LTC Plan. These units vest based on AES’ Total Stockholder Return as compared to the Total Stockholder Return of the S&P 500 Utility companies, the S&P 500 Index, and the MSCI Emerging Markets Index for the three-year period ending December 31, 2018 (as more fully described in the CD&A of this Amendment). The fourth row of data for Mr. Zagzebski shows the number of units at threshold, target and maximum, where $1.00 is the per unit value. At threshold against each of the three indices, the vesting percentage is 50%. At maximum performance, the vesting percentage is 200%. Straight line interpolation is applied for performance between the threshold and target and between the target and maximum.

(4)

Each NEO received restricted stock units on February 19, 2016 awarded under the LTC Plan. These units vest on a service-based condition in which one-third of the restricted stock units vest on each of the first three anniversaries of the grant.

(5)

Aggregate grant date fair value of performance stock units, performance cash units, and restricted stock units granted in the year which are computed in accordance with Financial Accounting Standards Board (“FASB”), Accounting Standards Codification (“ASC”) Topic 718, “Compensation-Stock Compensation” (“FASB ASC Topic 718”) disregarding any estimates of forfeitures related to service-based vesting conditions. A discussion of the relevant assumptions made in the valuation may be found in AES’ financial statements, footnotes to the financial statements (footnote 17), or

Management’s Discussion & Analysis, as appropriate, contained in AES’ Form 10-K which also includes information for 2014 and 2015. Assuming the maximum market and financial performance conditions are achieved, and in the case of performance stock units the share price at grant, the maximum value of performance stock units and performance cash units granted in fiscal year 2016, and payable upon completion of the 2016-2018 performance period, is shown in the Summary Compensation Table notes.

Descriptions of the compensation elements included in the Summary Compensation Table and Grants of Plan-Based Awards Table, including the Performance Incentive Plan and Long Term Compensation Plan and awards made thereunder are set forth in the CD&A of this prospectus.

OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END (2016)

The following table contains information concerning exercisable and unexercisable stock options and unvested stock awards with respect to AES stock granted to the NEOs that were outstanding on December 31, 2016. The market value of stock awards is based on the closing price of a share of AES Common Stock on December 31, 2016 of $11.62. The NEOs do not hold any equity in IPALCO. This table excludes the following column which is not applicable based on award types currently outstanding: Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options.

	Option Awards					Stock Awards
Name (a)	Number of Securities Underlying Unexercised Options (#) Exercisable (b)	Number of Securities Underlying Unexercised Options (#) Unexercisable (c)		Option Exercise Price ($) (e)	Option Expiration Date (f)	Number of Shares or Units of Stock That Have Not Vested (#) (g)(4)	Market Value of Shares or Units of Stock That Have Not Vested ($) (h)		Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#) (i)(5)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($) (j)
Kenneth Zagzebski	4,902	—		$18.87	22-Feb-18
	35,401	—		$11.17	15-Feb-23
	20,175	10,888	(1)	$14.63	21-Feb-24
	17,274	34,548	(2)	$11.89	20-Feb-25
	(3)					18,322	$	212,902	54,866	$	657,543
									445,580	$	445,580
Craig Jackson						15,838	$	184,038	—	—
Andrew Horrocks	3,544	—		$22.28	23-Feb-17
	3,690	—		$18.87	22-Feb-18
	(3)
						12,030	$	139,789
Michael Mizell						15,749	$	183,003
Salil Pradhan						7,970	$	92,611

(1)

Option grant made on February 21, 2014 vests in one final installment on February 21, 2017.

(2)

Option grant made on February 20, 2015 vests in two installments on February 20, 2017 and February 20, 2018.

(3)

No stock options were granted in 2016.

(4)

Included in this column are grants of restricted stock units that vest in three equal installments on the first three anniversaries of grant. These awards include:

A restricted stock unit grant made to all NEOs, except for Mr. Pradhan, on February 21, 2014 that that vests in one final installment on February 21, 2017.

A restricted stock unit grant made to all NEOs, except for Mr. Pradhan, on February 20, 2015 that vests in two remaining installments on February 20, 2017 and February 20, 2018.

A restricted stock unit grant made to all NEOs on February 19, 2016 that vests in three installments on February 19, 2017, February 19, 2018, and February 19, 2019.

Performance stock units earned and vested but not yet paid, as of December 31, 2016 are not reflected in this table. However, they are reflected in the Options and Stock Vested table.

(5)

Included in this column are: (i) performance stock units granted to Mr. Zagzebski on February 20, 2015 which vest based on market and financial performance conditions (AES three-year cumulative Total Stockholder Return relative to S&P 500 Utility companies and EBITDA less CapEx, each weighted 50%) and three-year service conditions (but only when and to the extent the market and financial performance conditions are met); and (ii) performance stock units granted to Mr. Zagzebski on February 19, 2016 which vest based on financial performance condition of AES’ three-year cumulative Proportional Free Cash Flow, and three-year service conditions (but only when and to the extent financial performance conditions are met).

Based on AES’ performance through the end of fiscal year 2016 relative to the performance criteria, the AES current period to-date results for the ongoing performance periods are between threshold and target, and, thus, the target number of performance stock units granted in 2015 and 2016 is included above.

Performance cash units granted to Mr. Zagzebski on February 19, 2016 which vest based on market performance conditions (AES three-year cumulative Total Stockholder Return relative to S&P 500 Utility companies, S&P 500 companies, and MSCI Emerging Market index companies) and three-year service conditions (but only when and to the extent the market performance conditions are met).

Based on AES’ performance through the end of fiscal year 2016 relative to the performance criteria, our current period-to-date results for ongoing performance period are between target and maximum and thus the maximum number of performance cash units granted in 2016 is included above.

OPTION EXERCISES AND STOCK VESTED (2016)

The following table contains information concerning the exercise of AES stock options and the vesting of performance stock unit and restricted stock unit awards by the NEOs during 2016.

	Option Awards		Stock Awards (1)
Name (a)	Number of Shares Acquired on Exercise (#)(b)	Value Realized on Exercise ($)(c)	Number of Shares Acquired on Vesting (#)(d)	Value Realized on Vesting ($)(e)
Kenneth Zagzebski	—	—	11,136	$	114,915
Craig Jackson	—	—	6,301	$	58,788
Andrew Horrocks	—	—	5,405	$	50,380
Michael Mizell	—	—	5,876	$	54,890
Salil Pradhan	—	—	—	$	—

(1)

Vesting of stock awards in 2016 consisted of four separate grants, as set forth in the following tables:

Number of Shares Acquired on Vesting (#)

Name	2/21/2014 PSUs (i)	2/15/2013 RSUs (ii)	2/21/2014 RSUs (iii)	2/20/2015 RSUs (iv)	Total
Kenneth Zagzebski	4,816	2,162	1,834	2,324	11,136
Craig Jackson	—	2,104	1,851	2,346	6,301
Andrew Horrocks	—	2,005	1,566	1,834	5,405
Michael Mizell	—	1,679	1,851	2,346	5,876
Salil Pradhan	—	—	—	—	—

Value Realized on Vesting ($)

Name	2/21/2014 PSUs (i)	2/15/2013 RSUs (ii)	2/21/2014 RSUs (iii)	2/20/2015 RSUs (iv)	Total
Kenneth Zagzebski	55,962	19,826	17,258	21,869	114,9154
Craig Jackson	—	19,294	17,418	22,076	58,788
Andrew Horrocks	—	18,386	14,736	17,258	50,380
Michael Mizell	—	15,396	17,418	22,076	54,890
Salil Pradhan	—	—	—	—	—

(i) The February 21, 2014 performance stock unit grant vested based on two conditions. The first was based on AES Total Stockholder Return (50%) relative to companies in the S&P 500 Utilities Index and the second was based on AES EBITDA less CapEx financial metric (50%) for the three year period ended December 31, 2016 which resulted in a payout of 35.010% of target. Final certification of results and distribution of shares occurred in the first quarter of 2017. For purposes of this Amendment, the performance stock units vested at that performance level as of December 31, 2016 at the closing stock price of $11.62.

(ii) The February 15, 2013 restricted stock unit grant vests in three equal installments on the anniversary of the grant. The vesting of the third installment occurred on February 15, 2016 at a vesting price of $9.17.

(iii) The February 21, 2014 restricted stock unit grant vests in three equal installments on the anniversary of the grant. The vesting of the second installment occurred on February 21, 2016 at a vesting price of $9.41.

(iv) The February 20, 2015 restricted stock unit grant vests in three equal installments on the anniversary of the grant. The vesting of the first installment occurred on February 20, 2016 at a vesting price of $9.41.

PENSION BENEFITS (2016)

The following table provides information with respect to the DP&L Retirement Income Plan, which is the only defined benefit pension plan in which any of the NEOs participate. During 2016, no payments or benefits were paid to any of the NEOs under the DP&L Retirement Income Plan.

Name (a)	Plan Name (b)	Number of Years Credited Service (#) (c)(2)	Present Value of Accumulated Benefit ($) (d)(3)(4)
Kenneth Zagzebski (1)	—	—	$	—
Craig Jackson	DP&L Retirement Income Plan	16	$	435,273
Andrew Horrocks (1)	—	—	$	—
Michael Mizell	DP&L Retirement Income Plan	4	$	30,658
Salil Pradhan (1)	—	—	$	—

(1)

Messrs. Zagzebski, Horrocks and Pradhan do not participate in an employer-sponsored pension plan.

(2)

Assumes 1,000 hours earned in plan years 2000-2016 for Mr. Jackson, and for plan years 2013-2016 for Mr. Mizell.

(3)

Based on the census data as reported by DPL for valuation purposes and the following assumptions:

Measurement Date	12/31/2016	12/31/2015	12/31/2014	12/31/2013
Discount Rate	4.28%	4.49%	4.02%	4.86%
Cash Balance Interest Credit	3.79%	3.79%	3.80%	3.79%
Post-retirement Mortality	MRP 2007 projected generationally with MSS-2016	MRP 2007 projected generationally with MSS-2007	MRP 2007 projected generationally with MSS-2007	RP 2000 projected generationally with Scale AA
Pre-retirement Mortality	None	None	None	None
Withdrawal	None	None	None	None
Retirement Age - Pre - 2011	62	62	62	62
Form of Payment - Pre - 2011 hires	Single Life Annuity	Single Life Annuity	Single Life Annuity	Single Life Annuity
Retirement Age - Post - 2010	65	65	65	65
Form of Payment - Post - 2010 hires	Lump Sum	Lump Sum	Lump Sum	Lump Sum

Additionally, these calculations assume census information as follows:

	Date of Birth	Date of Hire
Mr. Jackson	9/29/1972	2/14/2000
Mr. Mizell	4/27/1967	11/13/2012

Compensation:
Year	Mr. Jackson		Mr. Mizell		IRS Maximum Compensation

2016	$	265,000	$	265,000	$	265,000
2015	$	265,000	$	265,000	$	265,000
2014	$	260,000	$	260,000	$	260,000
2013	$	244,635	$	250,000	$	255,000
2012	$	222,692	$	4,808	$	250,000
2011	$	200,877	N/A		$	245,000

(4)

For Mr. Jackson, the Present Value of Accumulated Benefit calculations includes the $187.50 monthly supplemental benefit payable from age 62 to age 65. For Mr. Mizell, the Present Value of Accumulated Benefits equals the cash balance account at December 31, 2016.

Employee Retirement Plans

The DP&L Retirement Income Plan is a qualified defined benefit plan that provides retirement benefits to employees of DP&L and its affiliates who are participating employers who meet the participation requirements, including Messrs. Jackson and Mizell. DP&L is a sister company to IPALCO and NEOs may receive benefits under DP&L plans because they previously were employed there. The DP&L Retirement Income Plan covers both union (unit) and nonunion (management) employees. Plan provisions differ by union, management pre-2011 hires (Legacy), and management post-2010 hires. Mr. Jackson is in the management - pre-2011 hires, and Mr. Mizell is in the management - post-2010 hires. Messrs. Jackson and Mizell are not currently eligible for early retirement benefits under the DP&L Retirement Income Plan.

Management - pre-2011 hires. Participants must be at least 21 years old and have completed at least one year of service to be eligible for the DP&L Retirement Income Plan. Participants earn a year of service for each plan year during which they work 1,000 hours beginning with the plan year which includes their participation date. In general, employees receive pension benefits in an amount equal to (a) 1.25% of the average of the employee’s highest three consecutive annual base salaries for the five years immediately preceding the employee’s termination of employment, plus 0.45% of such average pay in excess of the employee’s 35-year average of Social Security wages, multiplied by (b) the employee’s years of service (not exceeding 30 years). Generally, an employee’s normal pension retirement benefits are fully available on his or her 65^th birthday. If an employee is no longer employed by a participating employer prior to vesting in the DP&L Retirement Income Plan (five years), the employee forfeits his or her pension benefits. Early retirement benefits are available to employees at any time once they reach age 55 and have completed 10 years of vesting service. However, if pension payments start before age 62, the monthly benefit is reduced by 3/12% for each month before age 62. Participants retiring early receive an additional $187.50 per month until age 65. Generally, pension benefits under the DP&L Retirement Income Plan are paid in monthly installments upon retirement; however, such benefits may be paid in a lump sum depending on the amount of pension benefits available to the employee. Employees have a right to choose a surviving spouse benefit option. If this option is chosen, pension benefits to the employee are reduced.

Management - post-2010 hires. Participants must be at least 21 years old and have completed at least one year of service to be eligible for the DP&L Retirement Income Plan. Participants earn a year of service for each plan year during which they work 1,000 hours beginning with the plan year which includes their participation date. The pension benefit is based on a cash balance formula. Both a pay credit and an interest credit are added to the participant’s beginning of year cash balance account for each year he or she earns a year of service. Pay credits range from 3% to 7%, depending on years of service earned after 12/31/2010. The interest credit is based on the greater of 3.79% and the 30-year Treasury Security yield with a 2-month look back, both adjusted to reflect quarterly allocations. Generally, an employee’s normal retirement benefit is fully available on his or her 65^th birthday. If an employee is no longer employed by a participating employer prior to vesting in the DP&L Retirement Income Plan (three years), the employee forfeits his or her pension benefits. A vested cash balance employee who terminates is eligible to receive his or her vested account and to elect an annuity starting date immediately, but not earlier than the termination date. Generally, pension benefits under the DP&L Retirement Income Plan are paid in monthly installments upon retirement; however, the cash balance account may be paid in a lump sum equal to the cash balance account. Preretirement death benefits are paid to the surviving spouse of a cash balance participant.

NONQUALIFIED DEFERRED COMPENSATION (2016)

The following table contains information for the NEOs for each of our plans that provides for the deferral of compensation that is not tax-qualified.

Name (a)(1)	Executive Contributions in Last Fiscal Year ($) (b)		Employer Contributions in Last Fiscal Year ($) (c)(2)		Aggregate Earnings in Last Fiscal Year ($) (d)		Aggregate Withdrawals/Distributions ($) (e)		Aggregate Balance at Last FYE ($) (f)(3)
Kenneth Zagzebski	$	2,600	$	13,350	$	9,932	$	—	$	51,437
Craig Jackson	$	—	$	—	$	—	$	—	$	—
Andrew Horrocks	$	—	$	—	$	—	$	—	$	—
Michael Mizell	$	26	$	—	$	1	$	—	$	27
Salil Pradhan	$	202,903	$	—	$	26,109	$	—	$	347,688

(1)

Messrs. Jackson and Horrocks are eligible to participate in the AES Corporation Restoration Supplemental Retirement Plan (RSRP) but do not currently participate in this plan. Because Messrs. Jackson and Mizell do not participate in the AES 401(k) plan, they are not eligible to receive an employer match on RSRP contributions.

(2)

Represents employer contributions to the RSRP in 2016. The amount reported in this column, as well as the employer’s additional contributions to the AES or DPL 401(k) plans, are included in the amounts reported in the 2016 row of the “All Other Compensation” column of the Summary Compensation Table. Mr. Pradhan was not eligible for an employer match in 2016 because matching contribution to his AES 401(k) for fiscal year 2016 were not limited pursuant to the Code as described in the narrative description relating to the Nonqualified Deferred Compensation table below.

(3)

In the 2014 and 2015 rows of the Summary Compensation Table, the amounts of $6,023 and $15,507 were previously reported for Mr. Zagzebski.

Narrative Disclosure Relating to the Nonqualified Deferred Compensation Table

The AES Corporation Restoration Supplemental Retirement Plan (RSRP)

The Code places statutory limits on the amount that participants, such as our NEOs, can contribute to the AES Corporation Retirement Savings Plan (the “AES 401(k) Plan”). As a result of these regulations, matching contributions made to the AES 401(k) Plan accounts of certain of our NEOs who participated in that plan in fiscal year 2016 were limited. To address the fact that participant and employer contributions are restricted by the statutory limits imposed by the Code, our NEOs and other highly compensated employees are eligible to participate in the RSRP, which is designed primarily to restore benefits limited under our broad-based retirement plans due to statutory limits imposed by the Code.

Under the AES 401(k) Plan, eligible employees, including certain of our NEOs, can elect to defer a portion of their compensation into the AES 401(k) Plan, subject to certain statutory limitations imposed by the Code such as the limitations imposed by Sections 402(g) and 401(a)(17) of the Code. The Company matches, dollar-for-dollar, the first five% of compensation that an individual contributes to the AES 401(k) Plan. In addition, individuals who participate in the RSRP may defer up to 80% of their compensation (excluding bonuses) and up to 100% of their annual bonus under the RSRP. The Company provides a matching contribution to the RSRP for individuals who actively defer and who are also subject to the statutory limits described above.

On an annual basis, AES may choose to make a discretionary retirement savings contribution (a “profit-sharing contribution”) to all eligible participants in the AES 401(k) Plan. The profit-sharing contribution, made in the form of AES Common Stock, is provided to individuals as a percentage of their compensation, subject to certain statutory limitations imposed by the Code, such as the limitations imposed by Sections 401(a)(17) and 415 of the Code.

Eligible individuals participating in the RSRP also receive a supplemental profit-sharing contribution. The amount of the supplemental profit-sharing contribution is equal to the difference between the profit-sharing contribution provided by the Company under the AES 401(k) Plan and the profit-sharing contribution that would have been made by the Company under the AES 401(k) Plan if no Code limits applied.

Participants in the RSRP may designate up to four separate deferral accounts, each of which may have a different distribution date and a different distribution option. A participant may elect to have distributions made in a lump-sum payment or annually over a period of two to 15 years. All distributions are made in cash.

Individuals have the ability to select from a list of hypothetical investments, which currently includes an AES stock hypothetical investment option. The investment options are functionally equivalent to the investments made available to all

participants in the AES 401(k) Plan. Individuals may change their hypothetical investments within the time periods that are permitted by the AES Compensation Committee, provided that they are entitled to change such designations at least quarterly.

Earnings or losses are credited to the deferral accounts based on the amount that would have been earned or lost if the amounts had actually been invested.

Individual RSRP account balances are always 100% vested.

POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE IN CONTROL (2016)

The following table contains estimated payments and benefits to each of the NEOs in connection with a termination of employment, both related and unrelated to a change in control, or a change in control of AES. The following amounts assume that a termination or change in control of AES occurred on December 31, 2016, and, where applicable, uses the closing price of AES Common Stock of $11.62 (as reported on the NYSE on December 30, 2016). None of the NEOs would be entitled to compensation upon a change in control of IPALCO.

For each NEO, the payments and benefits detailed in the table below are in addition to any payments and benefits under our plans and arrangements that are offered or provided generally to all salaried employees on a non-discriminatory basis and any accumulated vested benefits for each NEO, including those set forth in the Pension Benefits (2016), and any stock options vested as of December 31, 2016 (which are set forth in the Outstanding Equity Awards at Fiscal Year-End Table (2016).

	Termination
Name	Voluntary or for Cause	Without Cause		In Connection with Change in Control		Death	Disability	Change in Control Only (No Termination)
Kenneth Zagzebski
Cash Severance (1)	$0	$408,449		$816,898		$0	$0	$0
Accelerated Vesting of LTC (2)	$0	$0		$913,390		$913,390	$913,390	$0
Benefits Continuation (3)	$0	$16,202		$24,303		$0	$0	$0
Outplacement Assistance (4)	$0	$25,000		$25,000		$0	$0	$0
Total	$0	$449,651		$1,779,590		$913,390	$913,390	$0
Craig Jackson
Cash Severance (1)	$0	$277,160		$554,320		$0	$0	$0
Accelerated Vesting of LTC (2)	$0	$0		$355,180		$355,180	$355,180	$0
Benefits Continuation (3)	$0	$14,907		$22,361		$0	$0	$0
Outplacement Assistance (4)	$0	$25,000		$25,000		$0	$0	$0
Total	$0	$317,067		$956,861		$355,180	$355,180	$0
Andrew Horrocks
Cash Severance (1)	$0	$	209,546	$	209,546	$0	$0	$0
Accelerated Vesting of LTC (2)	$0	$0		$247,861		$247,861	$247,861	$0
Benefits Continuation (3)	$0	$	9,901	$	9,901	$0	$0	$0
Outplacement Assistance (4)	$0	$0		$0		$0	$0	$0
Total	$0	$219,447		$467,308		$247,861	$247,861	$0
Michael Mizell
Cash Severance (1)	$0	$274,508		$549,016		$0	$0	$0
Accelerated Vesting of LTC (2)	$0	$0		$324,436		$324,436	$324,436	$0
Benefits Continuation (3)	$0	$16,202		$24,303		$0	$0	$0
Outplacement Assistance (4)	$0	$25,000		$25,000		$0	$0	$0
Total	$0	$315,710		$922,755		$324,436	$324,436	$0
Salil Pradhan
Cash Severance (1)	$0	$	84,018	$	84,018	$0	$0	$0
Accelerated Vesting of LTC (2)	$0	$0		$142,623		$142,623	$142,623	$0
Benefits Continuation (3)	$0	$	5,297	$	5,297	$0	$0	$0
Outplacement Assistance (4)	$0	$0		$0		$0	$0	$0
Total	$0	$89,315		$231,938		$142,623	$142,623	$0

(1)

In addition to the amounts reflected in the above table, a pro rata bonus, to the extent earned, would be payable to Messrs. Zagzebski, Jackson and Mizell upon a termination without cause or a qualifying termination following a change in control. Pro rata bonus amounts are not included in the above table because, as of December 31, 2016, the service and performance conditions under AES’ 2016 annual incentive plan would have been satisfied, so such amounts would be paid irrespective of whether a termination or change in control occurs. Amounts for NEOs are based upon annual base salary rates.

(2)

Accelerated vesting of Long-Term Compensation (“LTC”) includes:

•

For Messr. Zagzebski, the in-the-money value of unvested stock options granted in February 2014 and 2015;

•

For Mr. Zagzebski, the value of outstanding performance stock units granted in February 2015 and 2016 at the target payout level;

•

The value of outstanding restricted stock units granted in February 2014, 2015 and 2016; and

•

The value of unvested performance units granted in February 2015 and 2016, at the target payout level.

The following table provides further detail on accelerated vesting of LTC awards by award type.

Name	Zagzebski		Jackson		Horrocks		Mizell		Pradhan
Long-Term Award Type:
Stock Options	$	—	$	—	$	—	$	—	$	—
Performance Cash Units	$	222,790	$	—	$	—	$	—	$	—
Performance Stock Units	$	477,698	$	—	$	—	$	—	$	—
Restricted Stock Units	$	212,902	$	184,038	$	139,789	$	183,003	$	92,611
Performance Units	$	—	$	171,142	$	108,072	$	141,433	$	50,012
Total Accelerated LTC Vesting	$	913,390	$	355,180	$	247,861	$	324,436	$	142,623

(3)

Upon a termination without cause or a qualifying termination following a change in control, the NEO may receive continued medical, dental and vision benefits. The value of this benefits continuation is based on the share of premiums paid by the employer on each NEO’s behalf in 2016, based on the coverage in place at the end of December 2016. For the benefit continuation period, each NEO is responsible for paying the portion of premiums previously paid as an employee.

(4)

Upon a termination without cause or a qualifying termination following a change in control, Messrs. Zagzebski, Jackson and Mizell are eligible for outplacement benefits. The estimated value of this benefit is $25,000.

Additional Information Relating to Potential Payments upon Termination of Employment or Change in Control

The following narrative outlining our compensatory arrangements with our NEOs is in addition to other summaries of their terms found in the CD&A of this prospectus.

Potential Payments upon Termination under the AES Corporation Severance Plan

The Severance Plan provides for certain payments and benefits to participants upon the Involuntary Termination or Termination for Good Reason of their employment under certain circumstances, including the execution of a release by the participant pursuant to the terms of the Severance Plan. All of our NEOs were entitled to the benefits provided by the Severance Plan in 2016.

Certain employees, including the NEOs are eligible for severance benefits, including salary continuation, applicable benefits and severance payments under the Severance Plan if the employee separates from service due to Involuntarily Termination or for Good Reason (each as defined below). Benefits are not available under the Severance Plan if the individual’s employment is terminated in connection with certain events as set forth herein, including voluntary resignation, separation from service for Cause, due to death or disability, the sale of a business, or in connection with a voluntary transfer of employment or the decline of a new job position located within 50 miles of the employee’s current work site.

Upon the termination of his or her employment under the above circumstances, our NEOs, other than Messrs. Horrocks and Pradhan, would be entitled to receive the following:

•

Salary continuation payments equal to the NEO’s annual base salary, which would be paid over time in accordance with our payroll practices and the terms of the Severance Plan;

•

An additional payment equal to a pro rata portion of the NEO’s annual cash bonus, to the extent earned, based upon the time the NEO was employed during the year in which his or her employment terminates, provided that applicable performance conditions are met;

•

In the event that the NEO elects COBRA coverage under the health plan in which he or she participates, we would pay an amount of the premium he or she pays for such coverage (for up to 12 months) equal to the premium we pay for active employees. The Company would also provide the NEO with continuation of dental and vision benefit programs, with the NEO paying the same portion of the premiums as were previously paid as an employee;

•

The NEO will be provided with outplacement services provided by an independent agency, provided that the benefit is incurred by and may not extend beyond December 31 of the second calendar year following the calendar year in which the termination occurred; and

•

In the event that termination of the NEO’s employment occurs due to the circumstances described above and within two years after a “change in control,” the amount of the NEO’s salary continuation payment will be doubled, and the length of the healthcare benefit continuation period will also be doubled, but can never be more than 18 months.

In the event of a qualifying termination under the Severance Plan, Mr. Horrocks would be entitled to 11.5 months’ prorated annual compensation and continuation of health, dental and vision benefits during this 11.5-month period, and Mr. Pradhan would be entitled to 4-months’ prorated annual compensation and continuation of health, dental and vision benefits during this 4-month period.

The obligation to provide these payments and benefits to the NEOs under the Severance Plan would be conditioned upon the execution and delivery of a written release of claims against the Company and AES. At our discretion, the release may also contain such noncompetition, nonsolicitation and nondisclosure provisions as we may consider necessary or appropriate.

Payment of Long-Term Compensation Awards in the Event of Termination or Change in Control as Determined by the Provisions Set Forth in the 2003 Long Term Compensation Plan (for all NEOs)

The vesting of performance stock units, performance cash units, restricted stock units, stock options and performance units and the ability of our NEOs to exercise or receive payments under those awards may be accelerated upon (1) the termination of a NEO’s employment or (2) as a result of a change in control. The vesting conditions are defined by the provisions set forth in the 2003 Long Term Compensation Plan as outlined below:

Performance Stock Units, Performance Cash Units, Restricted Stock Units and Performance Units. Our CEO holds outstanding performance stock units and performance cash units. All of our NEOs hold outstanding restricted stock units, and all of our NEOs, except for Mr. Zagzebski hold outstanding performance units. If a NEO’s employment is terminated by reason of death or disability prior to the third anniversary of the grant date of a performance stock unit, performance cash unit, or a restricted stock unit, the performance stock units (at target), the performance cash units (at target) and/or restricted stock units will immediately vest and be delivered. If a NEO separates from service prior to the end of a performance period due to death or disability, all performance units will vest on such termination date and a cash amount equal to $1 for each performance unit generally will be paid to the NEO on such date or as soon as practicable thereafter.

If the NEO’s employment is terminated for any reason other than death or disability prior to the third anniversary of the grant date of a restricted stock unit, the NEO will forfeit all restricted stock units for which the service-based vesting condition has not been met.

The performance stock unit grants and performance cash unit grants provide that voluntary termination or termination for cause prior to the end of the three-year performance period will result in the forfeiture of all outstanding performance stock units and performance cash units.

Involuntary termination other than for cause or a qualified retirement, which requires the NEO to reach 60 years of age and have at least seven years of service with the employer, allow prorated time-vesting in increments of one-third or two-thirds vesting if the NEO has completed one or two years of service from the grant date, respectively.

With respect to performance units, if a NEO separates from service prior to (i) the payment date due to cause or (ii) the final vesting date by reason of a voluntary separation from service by the NEO, any unvested performance units will be forfeited in full and cancelled by the Company on such termination date; provided, however, that if a NEO separates from service for any other reason (including due to qualified retirement), the NEO will be eligible to receive the value of his or her vested performance units, as of the date of the separation from service, on the payment date and in accordance with the terms of the applicable performance unit award agreement.

If a change in control occurs prior to the payment date of a performance stock unit, performance cash unit, restricted stock unit award, or performance unit award, outstanding performance stock units and performance cash units (at target), restricted stock units, and performance units will only become fully vested should a double-trigger occur. The double-trigger only allows for vesting if a qualifying termination occurs in connection with the change in control.

Stock Options. Messrs. Zagzebski and Horrocks each hold outstanding stock options. If a NEO’s employment is terminated by reason of death or disability, the stock options shall be immediately accelerated and become fully vested, exercisable, and payable, but such options will expire one year after the termination date or, if earlier, on the original expiration date of such stock option had the NEO remained employed through such date.

If the NEO’s employment is terminated for cause, all unvested stock options will be forfeited, and all vested stock options will expire three months after the termination date or, if earlier, on the original expiration date of such stock option.

If the NEO’s employment is terminated for any other reason, all of the unvested stock options will be forfeited and all vested stock options will expire 180 days after the termination date or, if earlier, on the original expiration date of such stock option.

In the event of a change in control, all of the NEO’s stock options will only become fully vested should a double-trigger occur. The double-trigger only allows for vesting if a qualifying termination occurs in connection with the change in control. However, the AES Compensation Committee may cancel outstanding stock options (1) for consideration equal to an amount to which the NEO would otherwise be entitled to receive in the change in control transaction if the NEO exercised the stock options, less the exercise price of such stock options, or, (2) if the amount determined pursuant to (1) would be negative, for no consideration. Any such payment may be made in cash, securities, or other property.

The AES Corporation Restoration Supplemental Retirement Plan (RSRP)

In the event of a termination of the NEO’s employment (other than by reason of death) prior to reaching retirement eligibility, or, in the event of a change in control, the balances of all of the NEO’s deferral accounts under the RSRP will be paid in a lump sum. In the event of a NEO’s death or retirement, the balances in the NEO’s deferral accounts will be paid according to his or her elections if the NEO was 59 1/2 or more years old at the time of his or her death or retirement. In the event of the NEO’s death or retirement before age 59 1/2, the value of the deferral account will be paid in a lump sum.

Definition of Terms

The following definitions are provided in the AES Corporation Severance Plan (the “Severance Plan”) and related Benefits Schedule used in this description:

“Cause” generally means termination of service due to the employee’s dishonesty, insubordination; continued and repeated failure to perform his or her assigned duties or willful misconduct in the performance of such duties; intentionally engaging in unsatisfactory job performance; failing to make a good faith effort to bring unsatisfactory job performance to an acceptable level; violation of the policies, procedures, work rules or recognized standards of behavior; misconduct related to his or her employment; or a charge, indictment or conviction of, or a plea of guilty ornolo contendere to, a felony.

“Change in Control” generally means the occurrence of one or more of the following events: (i) a transfer or sale of all or substantially all of AES’ assets, (ii) a person (other than someone in AES Management) becomes the beneficial owner of more than 35% of AES outstanding stock, (iii) during any one year period, individuals who at the beginning of such period constitute the Board of AES (together with any new Director whose election or nomination was approved by a majority of the Directors who were either in office at the beginning of such period or who were so approved, excluding anyone who became a Director as a result of a threatened or actual proxy contest or solicitation, including through the use of proxy access procedures as may be provided in the AES bylaws) cease to constitute a majority of the Board, or (iv) the consummation of a merger or similar transaction involving AES securities representing 65% or more of the then-outstanding voting stock of the corporation resulting from such transaction are held subsequent to such transaction by beneficial owners of AES immediately prior to such transaction in substantially the same proportions as their ownership immediately prior to such transaction.

“Good Reason” or“Good Reason Termination” generally means, without an employee’s written consent, his or her separation from service (for reasons other than death, Disability or Cause, as such terms are defined in the Severance Plan) by any employee due to the following events, within two years of the consummation of a Change in Control: (i) the relocation of an employee’s principal place of employment to a location that is more than 50 miles from his or her previous principal place of employment; (ii) a material diminution in the duties or responsibilities of any employee; and (iii) a material reduction in the base salary or annual incentive opportunity of an employee.

“Involuntary Termination” generally means an involuntary separation from service due to a reduction in force, the permanent job elimination, the restructuring or reorganization of a business unit, division, department, or other business segment, a termination by mutual consent due to unsatisfactory job performance with our agreement that the employee is entitled to benefits, or declining an offer to relocate to a new job position more than 50 miles from the employee’s current location.

The following definition is provided in the RSRP of the terms used in this description:

“Change in Control” means the occurrence of one or more of the following events: (i) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all, or substantially all, of the assets of AES to any Person or Group (as that term is used in Section 13(d)(3) of the Exchange Act) of Persons; (ii) a Person or Group (as so defined) of Persons (other than AES Management of the Company on the date of the adoption of the RSRP or their affiliates) shall have become the beneficial owner of more than 35% of the outstanding voting stock of AES; or (iii) during any one-year period, individuals who at the beginning of such period constitute the Board of AES (together with any new Director whose election or nomination was approved by a majority of the Directors then in office who were either Directors at the beginning of such period or who were previously so approved, but excluding under all circumstances any such new Director whose initial assumption of office occurs as a result of an actual or threatened election contest or other actual or threatened solicitation of proxies or consents by or on behalf of any individual, corporation, partnership or other entity or group) cease to constitute a majority of the Board of Directors. Notwithstanding the foregoing or any provision of the RSRP to the contrary, the foregoing definition of change-in-control shall be interpreted, administered and construed in manner necessary to ensure that the occurrence of any such event shall result in a change-in-control only if such event qualifies as a change in the ownership or effective control of a corporation, or a change in the ownership of a substantial portion of the assets of a corporation, as applicable, within the meaning of Treas. Reg. § 1.409A-3(i)(5).

The following definition is provided in the 2003 Long Term Compensation Plan of the terms used in this description:

“Change-in-Control” means the occurrence of one or more of the following events: (i) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all, or substantially all, of the assets of AES to any Person or Group (as that term is used in Section 13(d) (3) of the Exchange Act) of Persons, (ii) a Person or Group (as so defined) of Persons (other than AES Management on the date of the adoption of the 2003 Long Term Compensation Plan or their affiliates) shall have become the beneficial owner of more than 35% of the outstanding voting stock of AES, or (iii) during any one-year period, individuals who at the beginning of such period constitute the Board of AES (together with any new Director whose election or nomination was approved by a majority of the Directors then in office who were either Directors at the beginning of such period or who were previously so approved, but excluding under all circumstances any such new Director whose initial assumption of office occurs as a result of an actual or threatened election contest or other actual or threatened solicitation of proxies or consents by or on behalf of any individual, corporation, partnership or other entity or group) cease to constitute a majority of the Board. Notwithstanding the foregoing or any provision of the 2003 Long Term Compensation Plan to the contrary, if an award is subject to Section 409A (and not excepted therefrom) and a Change of Control is a distribution event for purposes of an award, the foregoing definition of Change-in-Control shall be interpreted, administered and construed in manner necessary to ensure that the occurrence of any such event shall result in a Change of Control only if such event qualifies as a change in the ownership or effective control of a corporation, or a change in the ownership of a substantial portion of the assets of a corporation, as applicable, within the meaning of Treas. Reg. § 1.409A-3(i)(5).

Director Compensation

None of our current directors receives any compensation for his or her services on the Board. No director who served on our Board for any part of 2016 that is or was also an employee of IPL, AES, or any of its affiliates, received any additional payment for their services on the Board. Information regarding the compensation received by current and former directors in their capacities as employees of our affiliates is set forth in “Item 13. Certain Relationships, Related Transactions and Director Independence” of this Amendment. We did not have any non-employee directors who received compensation for their services on the Board in 2016.

Compensation Committee Interlocks and Insider Participation

The Board of Directors of IPALCO does not have a compensation committee. Please see the CD&A in this Amendment for a discussion of the process undertaken in setting executive compensation, including the persons who, during the last completed fiscal year, participated in the NEO compensation process. In the case of our executive officers who are also members of our Board of Directors, they did not participate in the deliberations and/or approvals regarding their own compensation.

For information regarding the board memberships and, officer and employee positions held by our executive officers and directors with AES and other companies affiliated with IPALCO, see the biographies of our executive officers and directors included under “Item 10. Directors, Executive Officers and Corporate Governance” and the disclosures relating to these individuals included under “Item 13. Certain Relationships, Related Transactions and Director Independence,” each set forth in this prospectus and incorporated by reference herein as to this information.

CERTAIN RELATIONSHIPS, RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Insurance, Employee Benefit Plans and Tax Arrangements with AES

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 $3.1 million, $2.7 million, and $3.2 million in 2016, 2015 and 2014, respectively, and is recorded in “Other operating expenses” on the accompanying Consolidated Statements of Operations. As of September 30, 2017, December 31, 2016 and 2015, we had prepaid approximately $0.8 million, $2.0 million and $2.2 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 $23.2 million, $24.5 million, and $20.1 million in 2016, 2015 and 2014, respectively, and is recorded in “Other operating expenses” on the accompanying Consolidated Statements of Operations. We had no prepaids for coverage under this plan as of September 30, 2017, December 31, 2016 and 2015, respectively.

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 payable and receivable balance under this agreement of $1.0 million and $2.8 million as of December 31, 2016 and 2015, respectively, which is recorded in “Accrued income taxes” and “Prepayments and other current assets” on the accompanying Consolidated Balance Sheets, respectively. As of September 30, 2017, we had a receivable balance of $8.3 million, which is included in “Prepayments and the current assets” on the accompanying Consolidated Balance Sheets.

Long-Term Compensation Plan

During 2016, 2015 and 2014, 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, however no stock options were granted in 2016. Total deferred compensation expense recorded during 2016, 2015 and 2014 was $0.9 million, $0.7 million and $0.7 million, respectively, and was $0.7 million for the nine months ended September 30, 2017, and was included in “Other operating expenses” on IPL’s Consolidated Statements of Operations. 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 Note 9,“Benefit Plans” to the audited consolidated financial statements of IPL for a description of benefits awarded to IPL employees by AES under the RSP.

Service Company

Total costs incurred by IPL on behalf of the Service Company during 2016, 2015 and 2014 were $9.2 million, $7.5 million and $5.6 million, respectively. IPL had a prepaid balance with the Service Company of $3.4 million and $1.2 million as of December 31, 2016 and 2015, respectively.Total costs incurred by the Service Company on behalf of IPL were $25.0 million, $26.9 million, $22.6 million and $22.0 million during the nine months ended September 30, 2017, 2016, 2015 and 2014, respectively. Total costs incurred by IPL on behalf of the Service Company during the nine months ended September 30, 2017, 2016, 2015 and 2014 were $7.9 million, $9.2 million, $7.5 million and $5.6 million, respectively. IPL had a prepaid balance with the Service Company of $6.9 million, $3.4 million and $1.2 million as of September 30, 2017, December 31, 2016 and 2015, respectively.

Shareholders’ Agreement

AES US Investments, IPALCO and CDP Infrastructure Fund GP, a wholly owned subsidiary of La Caisse de dépȏt et placement du Québec (the “Investor”), are parties to a Shareholders’ Agreement (the “Shareholders’ Agreement”) dated February 11, 2015. The Shareholders’ Agreement provides the Investor with the right to nominate two directors of the IPALCO Board of Directors. The Investor’s right to nominate two directors of the IPALCO Board of Directors is subject to the conditions and adjustments set forth in the Shareholders’ Agreement, such as certain minimum ownership thresholds below which the Investor will be entitled to nominate only one director or no directors. The Shareholders’ Agreement contains restrictions on IPALCO taking certain major decisions without the prior affirmative vote of a majority of the IPALCO Board of Directors. In addition, for so long as the Investor holds at least 5% of the IPALCO shares, the Investor will have review and consultation rights with respect to certain actions of IPALCO. Certain transfer restrictions and other transfer rights also apply to the Investor and AES US Investments under the Shareholders’ Agreement, including certain rights of first offer, drag along rights, tag along rights, put rights and rights of first refusal. The Shareholders’ Agreement will terminate at the earliest of: (a) the mutual written consent of the parties, (b) the date on which only one or none of the shareholders holds shares of IPALCO, (c) on December 31, 2016, if the Investor has not made any capital contribution at such time other than the initial amount invested on February 11, 2015 or (d) the dissolution of IPALCO. Subsequent to the entry into the Shareholders’ Agreement, the Investor made an additional capital contribution on April 1, 2015; therefore, clause (c) of the termination provision detailed in the immediately preceding sentence is no longer applicable.

Related Person Policies and Procedures

IPL and IPALCO utilize a due diligence questionnaire with business partners, vendors and suppliers as part of the corporate compliance program to ensure that the highest ethical and legal standards are upheld in all business transactions. The corporate compliance program includes a “know your business partner” program which requires us to conduct due diligence on prospective business partners prior to entering into a business agreement.

The due diligence questionnaire gathers information on owners, principals, members of the Board of Directors, officers, employees, affiliates and family members in order to determine if a related person transaction exists. Any due diligence questionnaire that indicates a potential issue with a related party is brought to the attention of the Office of the General Counsel for further due diligence and analysis.

Other

In 2014, IPL engaged a third party vendor as part of its replacement generation construction projects. A member of the AES Board of Directors is also currently a member of the Supervisory Board of this vendor. IPL had billings from this vendor of $198.5 million, $232.0 million and $80.3 million during 2016, 2015 and 2014, respectively. IPL had a payable balance to this vendor of $6.4 million, $2.3 million and $34.0 million as of September 30, 2017, December 31, 2016 and 2015, respectively.

Additionally, transactions with various other related parties were $3.9 million, $2.4 million and $1.1 million as of December 31, 2016, 2015 and 2014, respectively. These expenses were primarily recorded in “Other operating expenses” on the accompanying Consolidated Statements of Operations.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following two tables set forth information regarding the beneficial ownership of IPALCO’s Common Stock and the AES’ Common Stock as of September 30, 2017 by (a) each current Director of IPALCO and each NEO set forth in the Summary Compensation Table in this Amendment, (b) all Directors and Executive Officers of IPALCO as a group and (c) all persons who are known by IPALCO to be the beneficial owner of more than five percent (5%) of the Common Stock of IPALCO. Under SEC Rule 13d-3 of the Exchange Act, “beneficial ownership” includes shares for which the individual, directly or indirectly, has or shares voting power (which includes the power to vote or direct the voting of the shares) or investment power (which includes the power to dispose or direct the disposition of the shares), whether or not the shares are held for individual benefit. Under these rules, more than one person may be deemed the beneficial owner of the same securities and a person may be deemed to be a beneficial owner of securities as to which such person has no economic interest. Except as otherwise indicated in the footnotes below, each of the beneficial owners has, to the best of our knowledge, sole voting and investment power with respect to the indicated shares of IPALCO and AES Common Stock.

Except as otherwise indicated, the address for each person below is c/o IPALCO Enterprises, Inc. One Monument Circle, Indianapolis, Indiana 46204.

(a) Common Stock of IPALCO(1)

Name and Address of Beneficial Holder	Amount and Nature of Beneficial Ownership	Percent of IPALCO Common Stock Outstanding
AES U.S. Investments, Inc.	89,685,177	82.35	%
CDP Infrastructure Fund, GP
1000, Place Jean-Paul-Riopelle
Montréal (Québec) H2Z 2B3	19,222,141	17.65	%
All Directors and Executive Officers as a Group (14 people)	0	0	%

(b) Common Stock of The AES Corporation (share amounts are as of September 30, 2017, unless noted otherwise):

Name/Address	Position Held With the Company	Shares of Common Stock Beneficially Owned (2)(3)(4)	Percent of Class (2)(3)
Barry J. Bentley	Director	16,004	*
Renaud Faucher	Director	0	0%
Paul L. Freedman	Director	18,855	*
Andrew J. Horrocks	Executive Officer	19,671	*
Craig L. Jackson	Director and Executive Officer	29,465	*
Frédéric Lesage	Director	0	0%
Michael S. Mizell	Executive Officer	15,961	*
Thomas M. O’Flynn	Director	906,788	*
Salil Pradhan	Executive Officer	13,891	*
Bradley Scott	Director	16,606	*
Richard A. Sturges	Director	39,501	*
Margaret E. Tigre	Director	63,303	*
Kenneth J. Zagzebski	Director and Executive Officer	160,634	*
All Directors and Executive Officers as a Group (14 people)		1,308,632	*

*Shares held represent less than 1% of the total number of outstanding shares of AES Common Stock.

(1)

Pursuant to the terms of the Shareholders’ Agreement, AES U.S. Investments and CDPQ have agreed that, during the term of the Shareholders’ Agreement, each of AES U.S. Investments and CDPQ shall vote, or act by written consent with respect to, all shares of IPALCO beneficially owned by them for the election to the Board of Directors of the individuals nominated by AES U.S. Investments and CDPQ. For additional information regarding

the Shareholders’ Agreement, including the number of directors that may be nominated by AES and CDPQ, please refer to “Shareholders’ Agreement” under Item 13 of this prospectus.

(2)

The shares of AES Common Stock beneficially owned are reported on the basis of SEC regulations governing the determination of beneficial ownership of securities. Under the SEC rules, shares of AES Common Stock, which are subject to options, units or other securities that are exercisable or convertible into shares of AES Common Stock within 60 days of September 30, 2017, are deemed to be outstanding and beneficially owned by the persons holding such options, units or other securities. Such underlying shares of Common Stock are deemed to be outstanding for the purpose of computing such person’s ownership percentage, but not deemed to be outstanding for the purpose of computing the percentage ownership of any other person.

(3)

Includes (a) the following shares issuable upon exercise of options outstanding as of September 30, 2017 that are able to be exercised within 60 days of September 30, 2017: Mr. Bentley - 2,832 shares; Mr. Faucher - 0 shares; Mr. Freedman - 2,042 shares; Mr. Lesage - 0 shares; Mr. O’Flynn - 609,979 shares; Mr. Scott - 2,485 shares; Mr. Sturges - 3,132 shares; Ms. Tigre - 45,927 shares; Mr. Zagzebski - 105,114 shares; Mr. Jackson - 0 shares; all directors and executive officers as a group - 774,202 shares; (b) the following units issuable under the AES 2003 Long Term Compensation Plan: Mr. Bentley - 13,102 shares; Mr. Freedman - 14,518 shares; Mr. O’Flynn - 170,419 shares; Mr. Scott - 11,641 shares; Mr. Sturges - 15,877 shares; Ms. Tigre - 16,312 shares; Mr. Zagzebski - 18,092 shares; Mr. Jackson - 16,092 shares; all directors and executive officers as a group - 314,632 shares; (c) the following shares held in The AES Retirement Savings Plan or IPL Thrift Plan: Mr. Bentley - 70 shares; Mr. Freedman - 2,295 shares; Mr. O’Flynn - 9,028 shares; Mr. Scott - 0 shares; Mr. Sturges - 4,730 shares; Ms. Tigre - 1,064 shares; Mr. Zagzebski - 12,335 shares; Mr. Jackson - 0 shares; all directors and executive officers as a group - 35,252 shares.

(4)

Mr. Horrocks, Mr. Mizell and Mr. Pradhan departed their positions as executive officers of IPALCO on March, 2017, February 2017 and August 2017, respectively. Their holdings are provided as of such dates and include (a) the following shares issuable upon exercise of options outstanding as of the applicable departure date that are able to be exercised within 60 days of such date: Mr. Horrocks - 3,690 shares; Mr. Mizell - 0 shares; Mr. Pradhan - 0 shares; (b) the following units issuable under the AES Long Term Compensation Plan: Mr. Horrocks - 11,290 shares; Mr. Mizell - 15,961 shares; Mr. Pradhan -11,777 shares; (c) the following shares held in The AES Retirement Savings Plan: Mr. Horrocks - 1,293 shares; Mr. Mizell - 0 shares; Mr. Pradhan - 496 shares.

Change in Control

IPALCO was acquired by AES in March 2001, and currently is majority-owned by AES U.S. Investments, with a minority interest held by CDPQ, a wholly owned subsidiary of La Caisse de dépȏt et placement du Québec. AES U.S. Investments is owned by AES U.S. Holdings, LLC (85%) and CDPQ (15%). AES U.S. Holdings, LLC is wholly owned by AES. The interest in AES U.S. Holdings, LLC has been pledged by AES under the terms of its credit agreement providing for its senior secured credit facility. Any exercise of remedies under this pledge could result at a subsequent date in a change in control of IPALCO.

Equity Securities under Compensation Plans

As described in this prospectus, there are no equity compensation plans under which equity securities of IPALCO are authorized for issuance. All equity compensation plans provide for the issuance of AES Common Stock. For information regarding AES’ LTC Plan, see the “Securities Authorized for Issuance under Equity Compensation Plans (as of December 31, 2016)” table in the AES Form 10-K.

DESCRIPTION OF THE NOTES

In this Description of Notes, “IPALCO,” “the Company,” “we,” “us” and “our” refer only to IPALCO Enterprises, Inc., and any successor obligor on the notes, and not to any of its subsidiaries. You can find the definitions of certain terms used in this description under “—Certain Definitions.”

We will issue the notes under an indenture between us and U.S. Bank National Association, as trustee. The terms of the notes include those stated in the indenture and those made part of the indenture by reference to the Trust Indenture Act of 1939, as amended (the “Trust Indenture Act”).

The following is a summary of the material provisions of the indenture. Because this is a summary, it may not contain all the information that is important to you. You should read the indenture in its entirety. Copies of the indenture are available as described under “Where You Can Find More Information.”

Basic Terms of Notes

The notes

•

are secured by a pledge by us of all the outstanding common stock of Indianapolis Power & Light Company, subject to any requirement that the IURC and FERC consent to or approve the exercise of remedies by the collateral agent, as described below under the caption “—Collateral”;

•

are our secured senior obligations;

•

rank equally with all our other existing and future secured senior obligations (to the extent secured by the same collateral);

•

rank senior, to the extent of the value of the collateral, to any of our existing and future unsubordinated and unsecured obligations;

•

are senior to all our existing and future subordinated indebtedness;

•

rank junior to all Indebtedness and other liabilities of IPL and our other subsidiaries;

•

are issued in an original aggregate principal amount of $405.0 million;

•

mature on September 1, 2024; and

•

bear interest commencing the date of issue at 3.70%, payable semiannually on each March 1 and September 1, commencing March 1, 2018, to holders of record on the February 15 or August 15 immediately preceding the interest payment date.

Interest will be computed on the basis of a 360-day year of twelve 30-day months.

Because we are a holding company, our rights and the rights of our creditors, including holders of the notes, in respect of claims on the assets of each of our subsidiaries upon any liquidation or administration are structurally subordinated to, and therefore will be subject to the prior claims of, each such subsidiary’s preferred stockholders and creditors (including trade creditors of and holders of debt issued by such subsidiary). At September 30, 2017, our direct and indirect subsidiaries had total long-term debt, current liabilities and preferred stock of approximately $2.1 billion, all of which would be effectively senior to the notes.

Our ability to pay interest on the notes is dependent upon the receipt of dividends and other distributions from our direct and indirect subsidiaries, including IPL in particular. The availability of distributions from our subsidiaries is subject to the satisfaction of various covenants and conditions contained in the applicable subsidiaries’ existing and future financing documents.

We may from time to time, without notice to or the consent of the holders of the notes, create and issue additional debt securities under the indenture governing the notes having the same terms as, and ranking equally with, the notes in all respects (except for the offering price and issue date), provided that such debt securities are fungible with the previously issued and outstanding debt securities for U.S. federal income tax purposes.

Collateral

The notes will be secured through a pledge by us of all the outstanding common stock of Indianapolis Power & Light Company and any proceeds thereof (the “Pledged Stock”), subject to any requirement that the IURC and FERC consent to or approve the exercise of remedies by the collateral agent as described below. The lien on the Pledged Stock will be shared equally and ratably with our existing senior secured notes, and, subject to certain limitations, we may secure other Indebtedness equally and ratably with the notes. As of September 30, 2017, we had $810 million aggregate principal amount of senior secured notes outstanding.

We will be able to vote, as we see fit in our sole discretion, the Pledged Stock, unless an Event of Default (as defined herein) has occurred and is continuing.

If we meet the conditions to our defeasance option or our covenant defeasance option with respect to the notes, as described below under the caption “—Defeasance and Discharge,” or the indenture is otherwise discharged, the lien on the Pledged Stock will terminate with respect to the notes.

If an Event of Default occurs and is continuing under the indenture, the collateral agent, on behalf of the holders of the notes in addition to any rights or remedies available to it under the pledge agreement, may take such action as it deems advisable to protect and enforce its right in the collateral, including the institution of foreclosure proceedings, subject to any requirement that the IURC and FERC consent to or approve the exercise of remedies by the collateral agent as described below. Such foreclosure proceedings, the enforcement of the pledge agreement and the right to take other actions with respect to the Pledged Stock will be controlled by holders of a majority of the aggregate principal amount of the then outstanding obligations which are equally and ratably secured by the Pledged Stock. The proceeds received by the collateral agent from any foreclosure will be applied by the collateral agent, first, to pay the expenses of such foreclosure and fees and other amounts then payable to the collateral agent under the pledge agreement and, thereafter, to pay the notes on a pro rata basis based on the aggregate amount outstanding of the obligations that are equally and ratably secured by the Pledged Stock. There can be no assurance that any proceeds from the foreclosure of the Pledged Stock will be sufficient to satisfy the amounts due under the notes.

Regulatory considerations may affect the ability of the collateral agent to exercise certain rights with respect to the Pledged Stock upon the occurrence of an Event of Default. Because IPL is a regulated public utility, such foreclosure proceedings, the enforcement of the pledge agreement and the right to take other actions with respect to the Pledged Stock may be limited and subject to regulatory approval. IPL is subject to regulation at the state level by the IURC. At the federal level, it is subject to regulation by FERC. See “Business—Regulatory Matters”. Regulation by the IURC and FERC includes regulation with respect to the change of control, transfer or ownership of utility property. In particular, such foreclosure proceedings, the enforcement of the pledge agreement and the right to take other actions with respect to the Pledged Stock could require (1) FERC approval to the extent such actions resulted in a change in control or a transfer of the ownership of the Pledged Stock and (2) IURC approval to the extent such actions resulted in a transfer of the ownership of the Pledged Stock to another Indiana utility. There can be no assurance that any such regulatory approval can be obtained on a timely basis, or at all.

The notes are not secured by any lien on, or other security interest in, any of our other properties or assets of our subsidiaries. The security interest in the Pledged Stock will not alter the effective subordination of the notes to the creditors of our subsidiaries.

Optional Redemption

The notes will be redeemable prior to July 1, 2024 (two months prior to the maturity date), at any time in whole or from time to time in part, at our option at a redemption price equal to the greater of:

(1)

100% of the principal amount of the notes being redeemed; and

(2)

the sum of the present values of the remaining scheduled payments of principal and interest on the notes being redeemed that would be due if such notes matured on the applicable Par Call Date (as defined below) (excluding interest accrued to the date of redemption) discounted to the date of redemption on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate (as defined herein) plus 30 basis points;

plus, for (1) or (2) above, whichever is applicable, accrued interest on such notes to, but not including, the date of redemption.

At any time on or after July 1, 2024, the notes will be redeemable in whole or in part, at our option, at a redemption price equal to 100% of the principal amount of the notes to be redeemed plus accrued and unpaid interest on the notes to be redeemed to, but not including, the date of redemption.

Definitions

“Comparable Treasury Issue” means the United States Treasury security selected by the Quotation Agent as having a maturity comparable to the remaining term of the notes to be redeemed (assuming, for this purpose, that such notes matured on the applicable Par Call Date) that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of the notes.

“Comparable Treasury Price” means, with respect to any redemption date, (i) the average of five Reference Treasury Dealer Quotations for such redemption date, after excluding the highest and lowest such Reference Treasury Dealer Quotations, or (ii) if we obtain fewer than five such Reference Treasury Dealer Quotations, the average of all such quotations.

“Par Call Date” means July 1, 2024, the date that is two months prior to the maturity date of the notes.

“Quotation Agent” means any Reference Treasury Dealer appointed by us.

“Reference Treasury Dealer” means (i) Morgan Stanley & Co. LLC (or its affiliate that is a Primary Treasury Dealer) and its successors; provided, however, that if any of the foregoing shall cease to be a primary U.S. Government securities dealer in New York City (a “Primary Treasury Dealer”), we will substitute therefor another Primary Treasury Dealer, and (ii) any other Primary Treasury Dealers selected by us.

“Reference Treasury Dealer Quotations” means, with respect to each Reference Treasury Dealer and any redemption date, the average, as determined by the Quotation Agent, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the Quotation Agent by such Reference Treasury Dealer at 5:00 p.m., New York City time, on the third business day preceding such redemption date.

“Treasury Rate” means, with respect to any redemption date, the rate per annum equal to the semiannual equivalent yield to maturity of the Comparable Treasury Issue, assuming a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such redemption date.

The redemption price will be calculated by the Quotation Agent and we, the trustee and any paying agent for the notes will be entitled to rely on such calculation.

Notice of redemption must be given not less than 30 days nor more than 60 days prior to the date of redemption. If fewer than all the notes are to be redeemed, selection of notes for redemption will be made by the trustee by lot or by any other method the trustee in its sole discretion deems appropriate.

Unless we default in payment of the redemption price from and after the redemption date, the notes or portions of them called for redemption will cease to bear interest, and the holders of the notes will have no right in respect to such notes except the right to receive the redemption price for them.

No Mandatory Redemption or Sinking Fund

There will be no mandatory redemption or sinking fund payments for the notes.

Repurchase at the Option of Holders

If a Change of Control Triggering Event (as defined herein) occurs, unless we have exercised our right to redeem the notes as described above, holders of notes will have the right to require us to repurchase all or any part (no note of a principal amount of $2,000 or less will be repurchased in part) of their notes pursuant to the offer described below (the “Change of Control Offer”) on the terms set forth in the notes. In the Change of Control Offer, we will be required to offer payment in cash equal to 101% of the aggregate principal amount of notes repurchased plus accrued and unpaid interest, if any, on the notes repurchased, to, but not including, the date of purchase (the “Change of Control Payment”). Within 30 days following any Change of Control Triggering Event, we will be required to send a notice to holders of notes describing the transaction or transactions that constitute the Change of Control Triggering Event and offering to repurchase the notes on the date specified in the notice, which date will be no earlier than 30 days and no later than 60 days from the date such notice is mailed (the “Change of Control Payment Date”), pursuant to the procedures required by the notes and described in such notice. We must comply with the requirements of Rule 14e-1 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with the repurchase of the notes as a result of a Change of Control Triggering Event. To the extent that the provisions of any securities laws or regulations conflict with the Change of Control provisions of the notes, we will be required to comply with the

applicable securities laws and regulations and will not be deemed to have breached our obligations under the Change of Control provisions of the notes by virtue of such conflicts.

On the Change of Control Payment Date, we will be required, to the extent lawful, to:

•

accept for payment all notes or portions of notes properly tendered pursuant to the Change of Control Offer;

•

deposit with the paying agent, which shall initially be the trustee, an amount equal to the Change of Control Payment in respect of all notes or portions of notes properly tendered; and

•

deliver or cause to be delivered to the trustee the notes properly accepted.

The definitions of Change of Control (as defined herein) and Parent Company Change of Control (as defined herein) include a phrase relating to the direct or indirect sale, lease, transfer, conveyance or other disposition of “all or substantially all” of the properties or assets of us and our subsidiaries taken as a whole. Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a holder of notes to require us to repurchase its notes as a result of a sale, lease, transfer, conveyance or other disposition of less than all of the assets of us and our subsidiaries taken as a whole to another person may be uncertain.

For purposes of the foregoing discussion of a repurchase at the option of holders, the following definitions are applicable:

“Change of Control” means the occurrence of any of the following: (1) the direct or indirect sale, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the properties or assets of the Company and its subsidiaries taken as a whole to any person (as such term is used in Section 13(d) of the Exchange Act) other than the Company or one of its subsidiaries; (2) the consummation of any transaction (including, without limitation, any merger or consolidation), other than any transaction the result of which is a Parent Company Change of Control, the result of which is that any person (as such term is used in Section 13(d) of the Exchange Act) other than a Permitted Holder (as defined herein) becomes the beneficial owner, directly or indirectly, of more than 50% of the then outstanding number of shares of the Company’s Voting Stock; or (3) the first day on which a majority of the members of the Company’s Board of Directors are not Continuing Directors of the Company.

“Change of Control Triggering Event” means the occurrence of a Rating Event and either (a) a Change of Control, or (b) a Parent Company Change of Control.

“Continuing Directors” means, as of any date of determination, any member of the applicable Board of Directors who (1) was a member of such Board of Directors on the date of the issuance of the notes; or (2) was nominated for election or elected to such Board of Directors with the approval of a majority of the Continuing Directors who were members of such Board of Directors at the time of such nomination or election (either by vote of the Board of Directors or by approval of the stockholders, or, if applicable, after receipt of a proxy statement in which such member was named as a nominee for election as a director, without objection to such nomination).

“Fitch” means Fitch Ratings, Inc.

“Moody’s” means Moody’s Investors Service, Inc.

“Parent Company” means The AES Corporation, a Delaware corporation.

“Parent Company Change of Control” means the occurrence of any of the following: (1) the direct or indirect sale, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the properties or assets of the Parent Company and its subsidiaries taken as a whole to any person (as such term is used in Section 13(d) of the Exchange Act) other than the Parent Company or one of its subsidiaries; (2) the consummation of any transaction (including, without limitation, any merger or consolidation) the result of which is that any person (as such term is used in Section 13(d) of the Exchange Act) becomes the beneficial owner, directly or indirectly, of more than 50% of the then outstanding number of shares of the Parent Company’s Voting Stock; or (3) the first day on which a majority of the members of the Parent Company’s Board of Directors are not Continuing Directors of the Parent Company.

“Permitted Holder” means, at any time, the Parent Company and its affiliates. In addition, any person or group whose acquisition of beneficial ownership constitutes a Change of Control in respect of which a Change of Control Offer is made in accordance with the requirements of the indenture will thereafter, together with its affiliates, constitute an additional Permitted Holder.

“Rating Agencies” means (a) each of Fitch, Moody’s and S&P, and (b) if any of Fitch, Moody’s or S&P ceases to rate the notes or fails to make a rating of the notes publicly available for reasons outside of our control, a “nationally recognized statistical rating organization” (within the meaning of Rule 15c3-1(c)(2)(vi)(F) under the Exchange Act) selected by us as a replacement Rating Agency for a former Rating Agency.

“Rating Event” means (x) the rating on the notes is lowered and (y) the notes are rated below an investment grade rating, in either case, by two of the three Rating Agencies on any day within the period (the “Trigger Period”) commencing on the earlier of (a) the occurrence of a Change of Control or a Parent Company Change of Control and (b) public notice of the occurrence of a Change of Control or a Parent Company Change of Control or our intention to effect a Change of Control or the Parent Company’s intention to effect a Parent Company Change of Control and ending 60 days following the consummation of such Change of Control or Parent Company Change of Control (which Trigger Period will be extended so long as the rating of the notes is under publicly announced consideration for a possible downgrade by any of the Rating Agencies); provided, however, that a Rating Event otherwise arising by virtue of a particular reduction in rating will not be deemed to have occurred in respect of a particular Change of Control or a particular Parent Company Change of Control (and thus will not be deemed a Rating Event for purposes of the definition of Change of Control Triggering Event) if the Rating Agency making the reduction in rating to which this definition would otherwise apply publicly announces or informs the trustee in writing at our request that the reduction was not the result, in whole or in part, of any event or circumstance comprised of or arising as a result of, or in respect of, the applicable Change of Control or Parent Company Change of Control (whether or not the applicable Change of Control or Parent Company Change of Control has occurred at the time of the Rating Event).

“S&P” means Standard & Poor’s Financial Services LLC, a division of S&P Global, Inc., and its successors.

“Voting Stock” of any specified person means the capital stock of such person that is at the time entitled to vote generally in the election of the Board of Directors of such person.

Ranking

Structural Subordination. Substantially all of our operations are conducted through our subsidiaries. Claims of creditors of our subsidiaries, including trade creditors, secured creditors and creditors holding debt and guarantees issued by those subsidiaries, and claims of preferred and minority stockholders (if any) of those subsidiaries generally will have priority with respect to the assets and earnings of those subsidiaries over the claims of our creditors, including holders of the notes. The notes therefore will be effectively subordinated to creditors (including trade creditors) and preferred and minority stockholders (if any) of our subsidiaries. As of September 30, 2017, our direct and indirect subsidiaries had total long-term debt, current liabilities and preferred stock of approximately $2.1 billion, all of which would be effectively senior to the notes. Moreover, the indenture does not impose any limitation on the incurrence by subsidiaries of additional liabilities or the issuance of additional preferred stock or minority interests.

The notes will rank equally in right of payment with all existing and future secured senior obligations and, to the extent of the value of the collateral, senior to any of our existing or future unsecured obligations and our subordinated obligations.

Moreover, as a holding company, we do not directly own any assets, other than our ownership interests in our subsidiaries. None of our subsidiaries is obligated under the notes and none of our subsidiaries will guarantee the notes. Our principal asset is our ownership interest in Indianapolis Power & Light Company. IPL is a regulated public utility, and is subject to regulation at both the state and federal level. At the state level, it is subject to regulation by the IURC. At the federal level, it is subject to regulation by FERC. See “Business-Regulatory Matters”. Regulation by the IURC and FERC includes regulation with respect to the change of control, transfer or ownership of utility property. Accordingly, if the trustee under the indenture or the holders of the notes institute proceedings against us with respect to the notes, the remedies available to them may be limited and may be subject to the approval by the IURC and FERC.

Covenants

Except as otherwise set forth under “—Defeasance and Discharge” below, for so long as any notes remain outstanding or any amount remains unpaid on any of the notes, we will comply with the terms of the covenants set forth below.

Payment of Principal and Interest

We will duly and punctually pay the principal of and interest on the notes in accordance with the terms of the notes and the indenture.

Merger, Consolidation, Sale, Lease or Conveyance

The indenture will provide that we will not (i)(a) consolidate with or merge with or into any other person, or permit any person to merge into or consolidate with us, or convey, transfer or lease our consolidated properties and assets substantially as an entirety (in one transaction or in a series of related transactions), (b) convey, transfer or lease our consolidated electric transmission and distribution assets and operations substantially as an entirety (in one transaction or in a series of related transactions), or (c) convey, transfer or lease all or substantially all of our consolidated electric generation assets and operations (in one transaction or a series of transactions), to any person or (ii) permit any of our subsidiaries to enter into any such transaction or series of transactions if it would result in the disposition of (x) our consolidated properties and assets substantially as an entirety, (y) our consolidated electric transmission and distribution assets and operations substantially as an entirety or (z) all or substantially all of our consolidated electric generation assets and operations unless, in each case:

•

we will be the surviving entity; or

•

the successor corporation or person that acquires all or substantially all of our assets:

•

will be an entity organized under the laws of the United States of America, one of its States or the District of Columbia; and

•

expressly assumes by supplemental indenture our obligations under the notes and the indenture; provided, however, that in the event following a conveyance, transfer or lease of our consolidated properties and assets substantially as an entirety or a conveyance, transfer or lease of all or substantially all of our consolidated electric generation assets and operations, we continue to own, directly or indirectly, our consolidated electric transmission and distribution assets and operations that we held immediately preceding such conveyance, transfer or lease substantially as an entirety, the notes and the indenture shall remain the obligations of us and shall not be assumed by the surviving person; and,

•

in each case, immediately after the merger, consolidation, sale, lease or conveyance, we, that person or the surviving entity will not be in default under the indenture.

In addition to the indenture limitations, regulatory approval would be required for such transactions.

Limitations on Liens

Liens on the Indianapolis Power & Light Company Stock.

We may not secure any Indebtedness of any person, other than IPALCO Indebtedness, by a Lien (as defined herein) upon any common stock of Indianapolis Power & Light Company.

Liens on Property or Assets other than the IPL Stock

Neither we nor any Significant Subsidiary (as defined herein) may issue, assume or guarantee any Indebtedness secured by a Lien upon any property or assets (other than any capital stock of Indianapolis Power & Light Company or cash or cash equivalents) of us or such Significant Subsidiary, as applicable, without effectively providing that the outstanding notes (together with, if we so determine, any other indebtedness or obligation then existing or thereafter created ranking equally with the notes) will be secured equally and ratably with (or prior to) such Indebtedness so long as such Indebtedness is so secured.

The foregoing limitation on Liens will not, however, apply to:

(1)

Liens in existence on the date of original issue of the notes;

(2)

any Lien created or arising over any property which is acquired, constructed or created by us or any of our Significant Subsidiaries, but only if:

(a)

such Lien secures only principal amounts (not exceeding the cost of such acquisition, construction or creation) raised for the purposes of such acquisition, construction or creation, together with any costs, expenses, interest and fees incurred in relation to that property or a guarantee given in respect of that property;

(b)

such Lien is created or arises on or before 180 days after the completion of such acquisition, construction or creation; and

(c)

such Lien is confined solely to the property so acquired, constructed or created;

100

(3)

(a)

rights of financial institutions to offset credit balances in connection with the operation of cash management programs established for our benefit and/or a Significant Subsidiary or in connection with the issuance of letters of credit for our benefit and/or a Significant Subsidiary;

(b)

any Lien on accounts receivable securing our Indebtedness and/or a Significant Subsidiary incurred in connection with the financing of such accounts receivable;

(c)

any Lien incurred or deposits made in the ordinary course of business, including, but not limited to, (1) any mechanic’s, materialmen’s, carrier’s, workmen’s, vendors’ and other like Liens and (2) any Liens securing amounts in connection with workers’ compensation, unemployment insurance and other types of social security;

(d)

any Lien upon specific items of inventory or other goods of us and/or a Significant Subsidiary and the proceeds thereof securing obligations of us and/or a Significant Subsidiary in respect of bankers’ acceptances issued or created for the account of such person to facilitate the purchase, shipment or storage of such inventory or other goods;

(e)

any Lien incurred or deposits made securing the performance of tenders, bids, leases, trade contracts (other than for borrowed money), statutory obligations, surety bonds, appeal bonds, government contracts, performance bonds, return-of-money bonds, letters of credit not securing borrowings and other obligations of like nature incurred in the ordinary course of business;

(f)

any Lien created by us or a Significant Subsidiary under or in connection with or arising out of a Currency, Interest Rate or Commodity Agreement (as defined herein) or any transactions or arrangements entered into in connection with the hedging or management of risks relating to the electricity or natural gas distribution industry, including a right of set off or right over a margin call account or any form of cash or cash collateral or any similar arrangement for obligations incurred in respect of Currency, Interest Rate or Commodity Agreements;

(g)

any Lien arising out of title retention or like provisions in connection with the purchase of goods and equipment in the ordinary course of business; and

(h)

any Lien securing reimbursement obligations under letters of credit, guaranties and other forms of credit enhancement given in connection with the purchase of goods and equipment in the ordinary course of business;

(4)

Liens in favor of us or a subsidiary of ours;

(5)

(a) Liens on any property or assets acquired from an entity which is merged with or into us or a Significant Subsidiary or any Liens on the property or assets of any entity existing at the time such entity becomes a subsidiary of ours and, in either case, is not created in anticipation of the transaction, unless the Lien was created to secure or provide for the payment of any part of the purchase price of that entity;

(b)

any Lien on any property or assets existing at the time of its acquisition and which is not created in anticipation of such acquisition, unless the Lien was created to secure or provide for the payment of any part of the purchase price of such property or assets; and

(c)

any Lien created or outstanding on or over any asset of any entity which becomes a Significant Subsidiary on or after the date of the issuance of the notes, where the Lien is created prior to the date on which that entity becomes a Significant Subsidiary;

(6)

(a) Liens required by any contract, statute or regulation in order to permit us or a Significant Subsidiary to perform any contract or subcontract made by it with or at the request of a governmental entity or any governmental department, agency or instrumentality, or to secure partial, progress, advance or any other payments by us or a Significant Subsidiary to such governmental unit under the provisions of any contract, statute or regulation;

(b)

any Lien securing industrial revenue, development, pollution control, solid waste disposal or similar bonds issued by or for our benefit or a Significant Subsidiary, provided that such industrial revenue, development, pollution control or similar bonds do not provide recourse generally to us and/or such Significant Subsidiary; and

(c)

any Lien securing taxes or assessments or other applicable governmental charges or levies;

101

(7)

any Lien which arises under any order of attachment, restraint or similar legal process arising in connection with court proceedings and any Lien which secures the reimbursement obligation for any bond obtained in connection with an appeal taken in any court proceeding, so long as the execution or other enforcement of such Lien arising under such legal process is effectively stayed and the claims secured by that Lien are being contested in good faith and, if appropriate, by appropriate legal proceedings, and any Lien in favor of a plaintiff or defendant in any action before a court or tribunal as security for costs and/or expenses;

(8)

any extension, renewal or replacement (or successive extensions, renewals or replacements), as a whole or in part, of any Liens referred to in the foregoing clauses, for amounts not exceeding the principal amount of the Indebtedness secured by the Lien so extended, renewed or replaced, provided that such extension, renewal or replacement Lien is limited to all or a part of the same property or assets that were covered by the Lien extended, renewed or replaced (plus improvements on such property or assets);

(9)

any Lien created in connection with Project Finance Debt (as defined herein);

(10)

any Lien created by IPL or its subsidiaries securing Indebtedness of IPL or its subsidiaries;

(11)

any Lien created in connection with the securitization of some or all of the assets of IPL and the associated issuance of Indebtedness as authorized by applicable state or federal law in connection with the restructuring of jurisdictional electric or gas businesses; and

(12)

any Lien on stock created in connection with a mandatorily convertible or exchangeable stock or debt financing, provided that any such financing may not be secured by or otherwise involve the creation of a Lien on any capital stock of IPL or any successor entity to IPL.

Reports and Other Information

At any time that we are not subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act, or do not otherwise report on an annual and quarterly basis on forms provided for such annual and quarterly reporting pursuant to rules and regulations promulgated by the SEC, the indenture requires us to make available to the trustee and to holders of the notes, without cost to any holder:

(1)

within 90 days after the end of each fiscal year, audited financial statements; and

(2)

within 45 days after the end of each of the first three fiscal quarters of each fiscal year, quarterly unaudited financial statements.

Events of Default

An Event of Default with respect to the notes is defined in the indenture as being:

(1)

default for 30 days in the payment of any interest on the notes;

(2)

default in the payment of principal of or any premium on, the notes at maturity, upon redemption, upon required purchase, upon acceleration or otherwise;

(3)

default in the performance, or breach, of any covenant or obligation in the indenture and continuance of the default or breach for a period of 30 days after written notice specifying the default is given to us by the trustee or to us and the trustee by the holders of at least 25% in aggregate principal amount of the notes;

(4)

default in the payment of the principal of any bond, debenture, note or other evidence of indebtedness, in each case for money borrowed, issued by us, or in the payment of principal under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness for Borrowed Money, of us or any Significant Subsidiary if such Indebtedness for Borrowed Money is not Project Finance Debt and provides for recourse generally to us or any Significant Subsidiary, which default for payment of principal is in an aggregate principal amount exceeding $40.0 million when such indebtedness becomes due and payable (whether at maturity, upon redemption or acceleration or otherwise), if such default shall continue unremedied or unwaived for more than 30 business days and the time for payment of such amount has not been expressly extended (until such time as such payment default is remedied, cured or waived);

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(5)

a court having jurisdiction enters a decree or order for:

•

relief in respect of us or any of our Significant Subsidiaries in an involuntary case under any applicable bankruptcy, insolvency, or other similar law now or hereafter in effect;

•

appointment of a receiver, liquidator, assignee, custodian, trustee, sequestrator, or similar official of us or any of our Significant Subsidiaries or for all or substantially all of the property and assets of us or any of our Significant Subsidiaries; or

•

the winding up or liquidation of our affairs or any of our Significant Subsidiaries;

and, in either case, such decree or order remains unstayed and in effect for a period of 60 consecutive days;

(6)

we or any of our Significant Subsidiaries:

•

commences a voluntary case under any applicable bankruptcy, insolvency, or other similar law now or hereafter in effect, or consents to the entry of an order for relief in an involuntary case under any such law;

•

consents to the appointment of or taking possession by a receiver, liquidator, assignee, custodian, trustee, sequestrator, or similar official of us or any of our Significant Subsidiaries or for all or substantially all of the property and assets of us or any of our Significant Subsidiaries; or

•

effects any general assignment for the benefit of creditors; or

(7)

the collateral agent fails to have a perfected security interest in the Pledged Stock of IPL for a period of 10 days.

If an Event of Default (other than an Event of Default specified in clause (5) or (6) with respect to us) occurs with respect to the notes and continues, then the trustee or the holders of at least 25% in principal amount of the notes then outstanding may, by written notice to us, and the trustee at the request of at least 25% in principal amount of the notes then outstanding will, declare the principal, premium, if any, and accrued interest on the outstanding notes to be immediately due and payable. Upon a declaration of acceleration, the principal, premium, if any, and accrued interest shall be immediately due and payable.

If an Event of Default specified in clause (5) or (6) above occurs with respect to us, the principal, premium, if any, and accrued interest on the notes shall be immediately due and payable, without any declaration or other act on the part of the trustee or any holder.

The holders of at least a majority in principal amount of the notes may, by written notice to us and to the trustee, waive all past defaults with respect to the notes and rescind and annul a declaration of acceleration with respect to the notes and its consequences if:

•

all existing Events of Default applicable to the notes other than the nonpayment of the principal, premium, if any, and interest on the notes that have become due solely by that declaration of acceleration, have been cured or waived; and

•

the rescission would not conflict with any judgment or decree of a court of competent jurisdiction.

No holder of the notes will have any right to institute any proceeding, judicial or otherwise, with respect to the indenture, or for the appointment of a receiver or trustee, or for any other remedy under the indenture, unless:

•

such holder has previously given written notice to the trustee of a continuing Event of Default with respect to the notes;

•

the holders of not less than 25% in principal amount of the notes shall have made written request to a responsible officer of the trustee to institute proceedings in respect of such Event of Default in its own name as trustee;

•

such holder or holders have offered the trustee indemnity satisfactory to the trustee against the costs, expenses and liabilities to be incurred in compliance with such request;

•

the trustee, for 60 days after its receipt of such notice, request and offer of indemnity, has failed to institute any such proceeding; and

•

no direction inconsistent with such written request has been given to the trustee during such 60-day period by the holders of a majority in principal amount of the outstanding notes.

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However, these limitations do not apply to the right of any holder of a note to receive payment of the principal, premium, if any, or interest on, that note or to bring suit for the enforcement of any payment, on or after the due date expressed in the notes, which right shall not be impaired or affected without the consent of the holder.

The indenture requires that certain of our officers certify, on or before a date not more than 120 days after the end of each fiscal year, that to the best of those officers’ knowledge, we have fulfilled all our obligations under the indenture. We are also obligated to notify the trustee of any default or defaults in the performance of any covenants or agreements under the indenture; provided, however, that a failure by us to deliver such notice of a default shall not constitute a default under the indenture, if we have remedied such default within any applicable cure period.

No Liability of Directors, Officers, Employees, Incorporators and Stockholders

No director, officer, employee, incorporator or stockholder of us, as such, will have any liability for any of our obligations under the notes or the indenture or for any claim based on, in respect of, or by reason of, such obligations. Each holder of notes by accepting a note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the notes. This waiver may not be effective to waive liabilities under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

Amendments and Waivers

Amendments Without Consent of Holders

We and the trustee may amend or supplement the indenture or the notes without notice to or the consent of any holder:

(1)

to cure any ambiguity, defect or inconsistency in the indenture or the notes;

(2)

to comply with “—Merger, Consolidation, Sale, Lease or Conveyance;”

(3)

to comply with any requirements of the SEC in connection with the qualification of the indenture under the Trust Indenture Act;

(4)

to evidence and provide for the acceptance of appointment hereunder by a successor trustee;

(5)

to provide for any guarantee of the notes, to secure the notes or to confirm and evidence the release, termination or discharge of any guarantee of or lien securing the notes when such release, termination or discharge is permitted by the indenture;

(6)

to provide for or confirm the issuance of additional notes; or

(7)

to make any other change that does not materially and adversely affect the rights of any holder.

Amendments With Consent of Holders

(a)

Except as otherwise provided in “–Events of Default” or paragraph (b), we and the trustee may amend the indenture with respect to the notes with the written consent of the holders of a majority in principal amount of the outstanding notes and the holders of a majority in principal amount of the outstanding notes may waive future compliance by us with any provision of the indenture with respect to the notes.

(b)

Notwithstanding the provisions of paragraph (a), without the consent of each holder of notes, an amendment or waiver may not:

(1)

reduce the principal amount of or change the stated maturity of any installment of principal of the notes;

(2)

reduce the rate of or change the stated maturity of any interest payment on the notes;

(3)

reduce the amount payable upon the redemption of the notes, in respect of an optional redemption, change the times at which the notes may be redeemed or, once notice of redemption has been given, the time at which they must thereupon be redeemed;

(4)

make the notes payable in money other than that stated in the notes;

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(5)

impair the right of any holder of notes to receive any principal payment or interest payment on such holder’s notes, on or after the stated maturity thereof, or to institute suit for the enforcement of any such payment

(6)

make any change in the percentage of the principal amount of the notes required for amendments or waivers; or

(7)

modify or change any provision of the indenture affecting the ranking of the notes in a manner adverse to the holders of the notes.

It is not necessary for holders to approve the particular form of any proposed amendment, supplement or waiver, but is sufficient if their consent approves the substance thereof.

Neither we nor any of our Subsidiaries or affiliates may, directly or indirectly, pay or cause to be paid any consideration, whether by way of interest, fee or otherwise, to any holder for or as an inducement to any consent, waiver or amendment of any of the terms or provisions of the indenture or the notes unless such consideration is offered to be paid or agreed to be paid to all holders of the notes that consent, waive or agree to amend such term or provision within the time period set forth in the solicitation documents relating to the consent, waiver or amendment.

Defeasance and Discharge

The indenture provides that we are deemed to have paid and will be discharged from all obligations in respect of the notes on the 123rd day after the deposit referred to below has been made, and that the provisions of the indenture will no longer be in effect with respect to the notes (except for, among other matters, certain obligations to register the transfer or exchange of the notes, to replace stolen, lost or mutilated notes, to maintain paying agencies and to hold monies for payment in trust) if, among other things,

(1)

we have deposited with the trustee, in trust, money and/or U.S. Government Obligations (as defined herein) that, through the payment of interest and principal in respect thereof, will provide money in an amount sufficient to pay the principal, premium, if any, and accrued interest on the notes, on the due date thereof or earlier redemption (irrevocably provided for under arrangements satisfactory to the trustee), as the case may be, in accordance with the terms of the indenture;

(2)

we have delivered to the trustee either:

•

an opinion of counsel to the effect that beneficial owners of notes will not recognize income, gain or loss for federal income tax purposes as a result of the exercise of our option under this “Defeasance and Discharge” provision and will be subject to federal income tax on the same amount and in the same manner and at the same times as would have been the case if the deposit, defeasance and discharge had not occurred, which opinion of counsel must be based upon a ruling of the Internal Revenue Service to the same effect unless there has been a change in applicable federal income tax law or related treasury regulations after the date of the indenture, or

•

a ruling directed to the Company received from the Internal Revenue Service to the same effect as the aforementioned opinion of counsel;

(3)

we have delivered to the trustee an opinion of counsel to the effect that the creation of the defeasance trust does not violate the Investment Company Act of 1940, as amended, and after the passage of 123 days following the deposit, the trust fund will not be subject to the effect of Section 547 of the U.S. Bankruptcy Code or Section 15 of the New York Debtor and Creditor Law;

(4)

immediately after giving effect to that deposit on a pro forma basis, no Event of Default has occurred and is continuing on the date of the deposit or during the period ending on the 123rd day after the date of the deposit, and the deposit will not result in a breach or violation of, or constitute a default under, any other agreement or instrument to which we are a party or by which we are bound; and

(5)

if at that time any notes are listed on a national securities exchange, we have delivered to the trustee an opinion of counsel to the effect that the notes will not be delisted as a result of a deposit, defeasance and discharge.

As more fully described in the indenture, the indenture also provides for defeasance of certain covenants.

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Concerning the Trustee

U.S. Bank National Association is the trustee under the indenture. The trustee is a full service financial institution which currently lends to affiliates of the Company. The trustee also provides various investment banking services to certain of our affiliates in the ordinary course of business.

Except during the continuance of an Event of Default, the trustee needs to perform only those duties that are specifically set forth in the indenture and no others, and no implied covenants or obligations will be read into the indenture against the trustee. In case an Event of Default has occurred and is continuing, the trustee shall exercise those rights and powers vested in it by the indenture and use the same degree of care and skill in their exercise as a prudent man would exercise or use under the circumstances in the conduct of his own affairs. No provision of the indenture will require the trustee to expend or risk its own funds or otherwise incur any financial liability in the performance of its duties or in the exercise of its rights or powers thereunder. The trustee shall be under no obligation to exercise any of the rights or powers vested in it by the indenture at the request or direction of any of the holders pursuant to the indenture, unless such holders shall have offered to the trustee security or indemnity satisfactory to the trustee against the costs, expenses and liabilities which might be incurred by it in compliance with such request or direction.

The indenture and provisions of the Trust Indenture Act incorporated by reference therein contain limitations on the rights of the trustee, should it become a creditor of us, to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The trustee is permitted to engage in other transactions with us and our affiliates; provided that if it acquires any conflicting interest it must either eliminate the conflict within 90 days, apply to the SEC for permission to continue or resign.

Form, Denomination and Registration of Notes

Except as set forth below, the notes will be issued in registered, global form in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof.

The Global Notes will be deposited upon issuance with the trustee as custodian for DTC in New York, New York, and registered in the name of DTC or its nominee, in each case for credit to an account of a direct or indirect participant in DTC as described below. The Global Notes may be transferred, in whole and not in part, only to another nominee of DTC or to a successor of DTC or its nominee. Beneficial interests in the Regulation S Global Notes may be may be held through the Euroclear System (“Euroclear”) and Clearstream Banking, S.A. (“Clearstream”) (as indirect participants in DTC). Beneficial interests in the Global Notes may be exchanged for Notes in certificated form. See “—Exchange of Global Notes for Certificated Notes.”

In addition, transfers of beneficial interests in the Global Notes will be subject to the applicable rules and procedures of DTC and its direct or indirect participants (including, if applicable, those of Euroclear and Clearstream), which may change from time to time.

Depository Procedures

The following description of the operations and procedures of DTC, Euroclear and Clearstream are provided solely as a matter of convenience. These operations and procedures are solely within the control of the respective settlement systems and are subject to changes by them. We take no responsibility for these operations and procedures and urge investors to contact the system or their participants directly to discuss these matters.

DTC has advised us that DTC is a limited-purpose trust company created to hold securities for its participating organizations (collectively, the “Participants”) and to facilitate the clearance and settlement of transactions in those securities between Participants through electronic book-entry changes in accounts of its Participants. The Participants include securities brokers and dealers (including the initial purchasers), banks, trust companies, clearing corporations and certain other organizations. Access to DTC’s system is also available to other entities such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a Participant, either directly or indirectly (collectively, the “Indirect Participants”). Persons who are not Participants may beneficially own securities held by or on behalf of DTC only through the Participants or the Indirect Participants. The ownership interests in, and transfers of ownership interests in, each security held by or on behalf of DTC are recorded on the records of the Participants and Indirect Participants. DTC has also advised us that, pursuant to procedures established by it:

(1)

upon deposit of the Global Notes, DTC will credit the accounts of Participants designated by the initial purchasers with portions of the principal amount of the Global Notes; and

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(2)

ownership of these interests in the Global Notes will be shown on, and the transfer of ownership thereof will be effected only through, records maintained by DTC (with respect to the Participants) or by the Participants and the Indirect Participants (with respect to other owners of beneficial interest in the Global Notes).

The laws of some states require that certain persons take physical delivery in definitive form of securities that they own. Consequently, the ability to transfer beneficial interests in a Global Note to such persons will be limited to that extent. Because DTC can act only on behalf of the Participants, which in turn act on behalf of the Indirect Participants, the ability of a person having beneficial interests in a Global Note to pledge such interests to persons that do not participate in the DTC system, or otherwise take actions in respect of such interests, may be affected by the lack of a physical certificate evidencing such interests.

Except as described below, owners of interests in the Global Notes will not have notes registered in their names, will not receive physical delivery of notes in certificated form and will not be considered the registered owners or “holders” thereof under the indenture for any purpose.

Payments in respect of the principal of, and interest and premium, if any, on a Global Note registered in the name of DTC or its nominee will be payable to DTC in its capacity as the registered holder under the indenture. Under the terms of the indenture, we and the trustee will treat the persons in whose names the notes, including the Global Notes, are registered as the owners thereof for the purpose of receiving payments and for all other purposes. Consequently, neither we, the trustee, nor any agent of ours or the trustee’s has or will have any responsibility or liability for:

(1)

any aspect of DTC’s records or any Participant’s or Indirect Participant’s records relating to or payments made on account of beneficial ownership interest in the Global Notes or for maintaining, supervising or reviewing any of DTC’s records or any Participant’s or Indirect Participant’s records relating to the beneficial ownership interests in the Global Notes; or

(2)

any other matter relating to the actions and practices of DTC or any of its Participants or Indirect Participants.

DTC has advised us that its current practice, upon receipt of any payment in respect of securities such as the notes (including principal and interest), is to credit the accounts of the relevant Participants with the payment on the payment date unless DTC has reason to believe it will not receive payment on such payment date. Each relevant Participant is credited with an amount proportionate to its beneficial ownership of an interest in the principal amount of the relevant security as shown on the records of DTC. Payments by the Participants and the Indirect Participants to the beneficial owners of the notes will be governed by standing instructions and customary practices and will be the responsibility of the Participants or the Indirect Participants and will not be the responsibility of DTC, the trustee or us. Neither we nor the trustee will be liable for any delay by DTC or any of its Participants in identifying the beneficial owners of the notes, and we and the trustee may conclusively rely on and will be protected in relying on instructions from DTC or its nominee for all purposes. Subject to the transfer restrictions set forth under “Notice to Investors,” transfers between Participants in DTC will be effected in accordance with DTC’s procedures, and will be settled in same-day funds, and transfers between participants in Euroclear and Clearstream will be effected in accordance with their respective rules and operating procedures.

Subject to compliance with the transfer restrictions applicable to the notes described herein, crossmarket transfers between the Participants in DTC, on the one hand, and Euroclear or Clearstream participants, on the other hand, will be effected through DTC in accordance with DTC’s rules on behalf of Euroclear or Clearstream, as the case may be, by its respective depositary; however, such cross-market transactions will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counterparty in such system in accordance with the rules and procedures and within the established deadlines (Brussels time) of such system. Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to its respective depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the relevant Global Note in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear participants and Clearstream participants may not deliver instructions directly to the depositories for Euroclear or Clearstream.

DTC has advised us that it will take any action permitted to be taken by a holder of the notes only at the direction of one or more Participants to whose account DTC has credited the interests in the Global Notes and only in respect of such portion of the aggregate principal amount of the notes as to which such Participant or Participants has or have given such direction. However, if there is an Event of Default under the notes, DTC reserves the right to exchange the Global Notes for legended notes in certificated form, and to distribute such notes to its Participants.

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Exchange of Global Notes for Certificated Notes

A Global Note is exchangeable for definitive notes in registered certificated form (“Certificated Notes”) if:

(1)

DTC (a) notifies us that it is unwilling or unable to continue as depositary for the Global Notes or (b) has ceased to be a clearing agency registered under the Exchange Act, and in each case we fail to appoint a successor depositary within 90 days of that notice or becoming aware that DTC is no longer so registered or willing or able to act as a depositary;

(2)

we determine not to have the Notes represented by a Global Note and provide written notice thereof to the trustee; provided that in no event shall a Temporary Regulation S Global Note be exchanged for certificated Notes prior to the expiration of the distribution compliance period and the receipt of any required Regulation S Certification; or

(3)

there shall have occurred and be continuing a Default or Event of Default with respect to the notes.

In all cases, certificated Notes delivered in exchange for any Global Note or beneficial interests in Global Notes will be in registered form, registered in the names, and issued in any approved denominations, requested by or on behalf of the depositary (in accordance with its customary procedures) and will bear the applicable restrictive legend referred to in “Notice to Investors,” unless that legend is not required by applicable law.

Governing Law

The indenture and the notes shall be governed by, and construed in accordance with, the laws of the State of New York.

Certain Definitions

Set forth below are certain defined terms used in the indenture. We refer you to the indenture for a full disclosure of all such terms, as well as any other capitalized terms used in this section of the offering prospectus for which no definition is provided.

“Capitalized Lease Obligations” means all lease obligations of us and our subsidiaries which, under GAAP, are or will be required to be capitalized, in each case taken at the amount of the lease obligation accounted for as indebtedness in conformity with those principles.

“Currency, Interest Rate or Commodity Agreements” means an agreement or transaction involving any currency, interest rate or energy price or volumetric swap, cap or collar arrangement, forward exchange transaction, option, warrant, forward rate agreement, futures contract or other derivative instrument of any kind for the hedging or management of foreign exchange, interest rate or energy price or volumetric risks, it being understood, for purposes of this definition, that the term “energy” will include, without limitation, coal, gas, oil and electricity.

“DTC” means The Depository Trust Company.

“Excluded Subsidiary” means any subsidiary of us:

(1)

in respect of which neither we nor any subsidiary of ours (other than another Excluded Subsidiary) has undertaken any legal obligation to give any guarantee for the benefit of the holders of any Indebtedness for Borrowed Money (other than to another member of the Group) other than in respect of any statutory obligation and the subsidiaries of which are all Excluded Subsidiaries; and

(2)

which has been designated as such by us by written notice to the trustee; provided that we may give written notice to the trustee at any time that any Excluded Subsidiary is no longer an Excluded Subsidiary whereupon it shall cease to be an Excluded Subsidiary.

“GAAP” means generally accepted accounting principles in the United States as in effect from time to time.

“Group” means IPALCO and its subsidiaries and “member of the Group” shall be construed accordingly.

“Indebtedness” means, with respect to us or any of our subsidiaries at any date of determination (without duplication):

(1)

all Indebtedness for Borrowed Money (excluding any credit which is available but undrawn);

(2)

all obligations in respect of letters of credit (including reimbursement obligations with respect to letters of credit);

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(3)

all obligations to pay the deferred and unpaid purchase price of property or services, which purchase price is due more than six months after the date of placing such property in service or taking delivery and title to the property or the completion of such services, except trade payables;

(4)

all Capitalized Lease Obligations;

(5)

all indebtedness of other persons secured by a mortgage, charge, lien, pledge or other security interest on any asset of us or any of our subsidiaries, whether or not such indebtedness is assumed; provided that the amount of such Indebtedness must be the lesser of: (a) the fair market value of such asset at such date of determination and (b) the amount of the secured indebtedness;

(6)

all indebtedness of other persons of the types specified in the preceding clauses (1) through (5), to the extent such indebtedness is guaranteed by us or any of our subsidiaries; and

(7)

to the extent not otherwise included in this definition, net obligations under Currency, Interest Rate or Commodity Agreements.

The amount of Indebtedness at any date will be the outstanding balance at such date of all unconditional obligations as described above and, upon the occurrence of the contingency giving rise to the obligation, the maximum liability of any contingent obligations of the types specified in the preceding clauses (1) through (7) at such date; provided that the amount outstanding at any time of any Indebtedness issued with original issue discount is the face amount of such Indebtedness less the remaining unamortized portion of the original issue discount of such Indebtedness at such time as determined in conformity with GAAP.

“Indebtedness for Borrowed Money” means any indebtedness (whether being principal, premium, interest or other amounts) for:

•

money borrowed;

•

payment obligations under or in respect of any trade acceptance or trade acceptance credit; or

•

any notes, bonds, loan stock or other debt securities offered, issued or distributed whether by way of public offer, private placement, acquisition consideration or otherwise and whether issued for cash or in whole or in part for a consideration other than cash;

provided, however, in each case, that such term will exclude:

•

any indebtedness relating to any accounts receivable securitizations;

•

any Indebtedness of the type permitted to be secured by Liens pursuant to clause (12) under the caption “—Limitation on Liens” described above; and

•

any Preferred Securities which are issued and outstanding on the date of original issue of the notes or any extension, renewal or replacement (or successive extensions, renewals or replacements), as a whole or in part, of any such existing Preferred Securities, for amounts not exceeding the principal amount or liquidation preference of the Preferred Securities so extended, renewed or replaced.

“IPALCO Indebtedness” means any Indebtedness of the Company; provided that the aggregate outstanding principal amount of such Indebtedness that is secured by a Lien upon any common stock of Indianapolis Power & Light Company may not exceed $1.4 billion and that the proceeds of such secured Indebtedness may not be used to pay any dividend to the Parent Company and, provided further, that the aggregate outstanding principal amount of such Indebtedness shall be calculated exclusive of secured Indebtedness that is being concurrently redeemed, repaid, defeased or otherwise retired with the proceeds of an offering of secured Indebtedness.

“Lien” means any mortgage, lien, pledge, security interest or other encumbrance; provided, however, that the term “Lien” does not mean any easements, rights-of-way, restrictions and other similar encumbrances and encumbrances consisting of zoning restrictions, leases, subleases, restrictions on the use of property or defects in title.

“Preferred Securities” means, without duplication, any trust preferred or preferred securities or related debt or guaranties of us or any of our subsidiaries.

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“Project Finance Debt” means:

•

any Indebtedness to finance or refinance the ownership, acquisition, development, design, engineering, procurement, construction, servicing, management and/or operation of any project or asset in respect of which the person or persons to whom any such Indebtedness is or may be owed by the relevant borrower (whether or not a member of the Group) has or have no recourse whatsoever to any member of the Group (other than an Excluded Subsidiary) for the repayment of that Indebtedness other than: (i) recourse to such member of the Group for amounts limited to the cash flow or net cash flow (other than historic cash flow or historic net cash flow) from, or ownership interests or other investments in, such project or asset; and/or (ii) recourse to such member of the Group for the purpose only of enabling amounts to be claimed in respect of such Indebtedness in an enforcement of any encumbrance given by such member of the Group over such project or asset or the income, cash flow or other proceeds deriving from the project (or given by any shareholder or the like, or other investor in, the borrower or in the owner of such project or asset over its shares or the like in the capital of, or other investment in, the borrower or in the owner of such project or asset) to secure such Indebtedness, provided that the extent of such recourse to such member of the Group is limited solely to the amount of any recoveries made on any such enforcement; and/or (iii) recourse to such borrower generally, or directly or indirectly to a member of the Group, under any form of assurance, indemnity, undertaking or support, which recourse is limited to a claim for damages (other than liquidated damages and damages required to be calculated in a specified way) for breach of an obligation (not being a payment obligation or an obligation to procure payment by another or an indemnity in respect of a payment obligation, or any obligation to comply or to procure compliance by another with any financial ratios or other tests of financial condition) by the person against which such recourse is available.

“Significant Subsidiary” means, at any particular time, any subsidiary of ours whose gross assets or gross revenues (having regard to our direct and/or indirect beneficial interest in the shares, or the like, of that subsidiary) represent at least 25% of the consolidated gross assets or, as the case may be, consolidated gross revenues of us.

“Subsidiary” means, with respect to any person, any corporation, association, partnership, limited liability company or other business entity of which 50% or more of the total voting power of shares of capital stock or other interests (including partnership interests) entitled (without regard to the occurrence of any contingency) to vote in the election of directors, managers or trustees is at the time owned, directly or indirectly, by (1) such person, (2) such person and one or more subsidiaries of such person or (3) one or more subsidiaries of such person.

“U.S. Government Obligation” means any:

(1)

security which is: (a) a direct obligation of the United States for the payment of which the full faith and credit of the United States is pledged or (b) an obligation of a person controlled or supervised by and acting as an agency or instrumentality of the United States the payment of which is unconditionally guaranteed as a full faith and credit obligation by the United States, which, in the case of clause (a) or (b), is not callable or redeemable at the option of the issuer of the obligation, and

(2)

depositary receipt issued by a bank (as defined in the Securities Act) as custodian with respect to any security specified in clause (1) above and held by such bank for the account of the holder of such depositary receipt or with respect to any specific payment of principal of or interest on any such security held by any such bank, provided that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depositary receipt from any amount received by the custodian in respect of the U.S. Government Obligation or the specific payment of interest on or principal of the U.S. Government Obligation evidenced by such depositary receipt.

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THE EXCHANGE OFFER

General

We hereby offer to exchange a like principal amount of new notes for any or all outstanding old notes on the terms and subject to the conditions set forth in this prospectus and accompanying letter of transmittal. We often refer to this offer as the “exchange offer.” You may tender some or all of your outstanding old notes pursuant to this exchange offer. As of the date of this prospectus, $405,000,000 aggregate principal amount of the old notes is outstanding. Our obligation to accept old notes for exchange pursuant to the exchange offer is subject to certain conditions set forth hereunder.

Purpose and Effect of the Exchange Offer

In connection with the offering of the old notes, which was consummated on August 22, 2017, we entered into a registration rights agreement with the initial purchasers of the old notes, under which we agreed:

(1) to use our reasonable best efforts to cause to be filed a registration statement with respect to an offer to exchange the old notes for a new issue of securities, with terms substantially the same as of the old notes but registered under the Securities Act;

(2) to use our best efforts to cause the registration statement to be declared effective by the SEC on or prior to 365 days after the closing of the old notes offering; and

(3) to use our reasonable best efforts to consummate the exchange offer and issue the new notes within 30 business days after the registration statement is declared effective.

The registration rights agreement provides that, in the event that the registration statement is not effective on or prior to the date that is 365 days after the closing date of the old notes offering or consummate the exchange offer within 30 days after the effectiveness of the registration statement for the exchange offer, the interest rate for the notes will increase by a rate of 0.50% per annum from the effectiveness deadline until the exchange offer registration statement or the shelf registration statement is declared effective. Once we complete this exchange offer, we will no longer be required to pay additional interest on the old notes. The additional interest rate for the old notes will not any time exceed 0.50% per annum notwithstanding our failure to meet more than one of these requirements.

The exchange offer is not being made to, nor will we accept tenders for exchange from, holders of old notes in any jurisdiction in which the exchange offer or acceptance of the exchange offer would violate the securities or blue sky laws of that jurisdiction. Furthermore, each holder of old notes that wishes to exchange their old notes for new notes in this exchange offer will be required to make certain representations as set forth herein.

Terms of the Exchange Offer; Period for Tendering old notes

This prospectus and the accompanying letter of transmittal contain the terms and conditions of the exchange offer. Upon the terms and subject to the conditions included in this prospectus and in the accompanying letter of transmittal, which together are the exchange offer, we will accept for exchange old notes which are properly tendered on or prior to the expiration date, unless you have previously withdrawn them.

•

When you tender to us old notes as provided below, our acceptance of the old notes will constitute a binding agreement between you and us upon the terms and subject to the conditions in this prospectus and in the accompanying letter of transmittal.

•

For each $2,000 principal amount of old notes (and $1,000 principal amount of old notes in excess thereof) surrendered to us in the exchange offer, we will give you $2,000 principal amount of new notes (and $1,000 principal amount of new notes in excess thereof). Outstanding notes may only be tendered in denominations of $2,000 and integral multiples of $1,000 in excess thereof, provided that no notes of $2,000 or less will be redeemed in part.

•

We will keep the exchange offer open for not less than 20 business days, or longer if required by applicable law, after the date that we first mail notice of the exchange offer to the holders of the old notes. We are sending this prospectus, together with the letter of transmittal, on or about the date of this prospectus to all of the registered holders of old notes at their addresses listed in the trustee’s security register with respect to the old notes.

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•

The exchange offer expires at 11:59 p.m., New York City time, on January 4, 2018;provided,however, that we, in our sole discretion, may extend the period of time for which the exchange offer is open. The term “expiration date” means January 4, 2018 or, if extended by us, the latest time and date to which the exchange offer is extended.

•

As of the date of this prospectus, $405,000,000 in aggregate principal amount of the old notes were outstanding. The exchange offer is not conditioned upon any minimum principal amount of old notes being tendered.

•

Our obligation to accept old notes for exchange in the exchange offer is subject to the conditions that we describe in the section called “Conditions to the Exchange Offer” below.

•

We expressly reserve the right, at any time, to extend the period of time during which the exchange offer is open, and thereby delay acceptance of any old notes, by giving oral or written notice of an extension to the exchange agent and notice of that extension to the holders as described below. During any extension, all old notes previously tendered will remain subject to the exchange offer unless withdrawal rights are exercised. Any old notes not accepted for exchange for any reason will be returned without expense to the tendering holder promptly following the expiration or termination of the exchange offer.

•

We expressly reserve the right to amend or terminate the exchange offer, and not to accept for exchange any old notes that we have not yet accepted for exchange, if any of the conditions of the exchange offer specified below under “Conditions to the Exchange Offer” are not satisfied. In the event of a material change in the exchange offer, including the waiver of a material condition, we will extend the offer period if necessary so that at least five business days remain in the exchange offer following notice of the material change.

•

We will give oral or written notice of any extension, amendment, termination or non-acceptance described above to holders of the old notes promptly. If we extend the expiration date, we will give notice by means of a press release or other public announcement no later than 9:00 a.m., New York City time, on the business day after the previously scheduled expiration date. Without limiting the manner in which we may choose to make any public announcement and subject to applicable law, we will have no obligation to publish, advertise or otherwise communicate any public announcement other than by issuing a release to the Dow Jones News Service or other similar news service.

•

Holders of old notes do not have any appraisal or dissenters’ rights in connection with the exchange offer.

•

Old notes which are not tendered for exchange or are tendered but not accepted in connection with the exchange offer will remain outstanding and be entitled to the benefits of the indenture, but will not be entitled to any further registration rights under the registration rights agreement.

•

We intend to conduct the exchange offer in accordance with the applicable requirements of the Exchange Act and the rules and regulations of the SEC thereunder.

•

By executing, or otherwise becoming bound by, the letter of transmittal, you will be making the representations described below to us. See “—Resale of the New Notes.”

Important rules concerning the exchange offer

You should note that:

•

All questions as to the validity, form, eligibility, time of receipt and acceptance of old notes tendered for exchange will be determined by IPALCO Enterprises, Inc. in its sole discretion, which determination shall be final and binding.

•

We reserve the absolute right to reject any and all tenders of any particular old notes not properly tendered or to not accept any particular old notes which acceptance might, in our judgment or the judgment of our counsel, be unlawful.

•

We also reserve the absolute right to waive any defects or irregularities or conditions of the exchange offer as to any particular old notes either before or after the expiration date, including the right to waive the ineligibility of any holder who seeks to tender old notes in the exchange offer. Unless we agree to waive any defect or irregularity in connection with the tender of old notes for exchange, you must cure any defect or irregularity within any reasonable period of time as we shall determine.

•

Our interpretation of the terms and conditions of the exchange offer as to any particular old notes either before or after the expiration date shall be final and binding on all parties.

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•

Neither IPALCO Enterprises, Inc., the exchange agent nor any other person shall be under any duty to give notification of any defect or irregularity with respect to any tender of old notes for exchange, nor shall any of them incur any liability for failure to give any notification.

Procedures for Tendering old notes

What to submit and how

If you, as the registered holder of an old note, wish to tender your old notes for exchange in the exchange offer, you must contact a DTC participant to complete the book-entry transfer procedures described below, or otherwise complete and transmit a properly completed and duly executed letter of transmittal to U.S. Bank National Association at the address set forth below under “Exchange Agent” on or prior to the expiration date.

In addition,

(1) certificates for old notes must be received by the exchange agent along with the letter of transmittal or

(2) a timely confirmation of a book-entry transfer of old notes, if such procedure is available, into the exchange agent’s account at DTC using the procedure for book-entry transfer described below, must be received by the exchange agent prior to the expiration date, or

(3) you must comply with the guaranteed delivery procedures described below.

The method of delivery of old notes, letters of transmittal and notices of guaranteed delivery is at your election and risk. If delivery is by mail, we recommend that registered mail, properly insured, with return receipt requested, be used. In all cases, sufficient time should be allowed to assure timely delivery. No letters of transmittal or old notes should be sent to IPALCO Enterprises, Inc.

How to sign your letter of transmittal and other documents

Signatures on a letter of transmittal or a notice of withdrawal, as the case may be, must be guaranteed unless the old notes being surrendered for exchange are tendered

(1)

by a registered holder of the old notes who has not completed the box entitled “Special Issuance Instructions” or “Special Delivery Instructions” on the letter of transmittal or

(2)

for the account of an eligible institution.

If signatures on a letter of transmittal or a notice of withdrawal, as the case may be, are required to be guaranteed, the guarantees must be by any of the following eligible institutions:

•

a firm which is a member of a registered national securities exchange or a member of the Financial Industry Regulatory Authority, Inc. or

•

a commercial bank or trust company having an office or correspondent in the United States

If the letter of transmittal is signed by a person or persons other than the registered holder or holders of old notes, the old notes must be endorsed or accompanied by appropriate powers of attorney, in either case signed exactly as the name or names of the registered holder or holders that appear on the old notes and with the signature guaranteed.

If the letter of transmittal or any old notes or powers of attorney are signed by trustees, executors, administrators, guardians, attorneys-in-fact, officers or corporations or others acting in a fiduciary or representative capacity, the person should so indicate when signing and, unless waived by IPALCO Enterprises, Inc., proper evidence satisfactory to IPALCO Enterprises, Inc. of its authority to so act must be submitted.

Acceptance of old notes for Exchange; Delivery of New Notes

Once all of the conditions to the exchange offer are satisfied or waived, we will accept, promptly after the expiration date, all old notes properly tendered and will issue the new notes promptly after the expiration of the exchange offer. See “—Conditions to the Exchange Offer” below. For purposes of the exchange offer, our giving of oral or written notice of our acceptance to the exchange agent will be considered our acceptance of the exchange offer.

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In all cases, we will issue new notes in exchange for old notes that are accepted for exchange only after timely receipt by the exchange agent of:

•

certificates for old notes, or

•

a timely book-entry confirmation of transfer of old notes into the exchange agent’s account at DTC using the book-entry transfer procedures described below, and

•

a properly completed and duly executed letter of transmittal.

If we do not accept any tendered old notes for any reason included in the terms and conditions of the exchange offer or if you submit certificates representing old notes in a greater principal amount than you wish to exchange, we will return any unaccepted or non-exchanged old notes without expense to the tendering holder or, in the case of old notes tendered by book-entry transfer into the exchange agent’s account at DTC using the book-entry transfer procedures described below, non-exchanged old notes will be credited to an account maintained with DTC promptly following the expiration or termination of the exchange offer.

Book-Entry Transfer

The exchange agent will make a request to establish an account with respect to the old notes at DTC for purposes of the exchange offer promptly after the date of this prospectus. Any financial institution that is a participant in DTC’s systems may make book-entry delivery of old notes by causing DTC to transfer old notes into the exchange agent’s account in accordance with DTC’s Automated Tender Offer Program procedures for transfer. However, the exchange for the old notes so tendered will only be made after timely confirmation of book-entry transfer of old notes into the exchange agent’s account, and timely receipt by the exchange agent of an agent’s message, transmitted by DTC and received by the exchange agent and forming a part of a book-entry confirmation. The agent’s message must state that DTC has received an express acknowledgment from the participant tendering old notes that are the subject of that book-entry confirmation that the participant has received and agrees to be bound by the terms of the letter of transmittal, and that we may enforce the agreement against that participant.

Although delivery of old notes may be effected through book-entry transfer into the exchange agent’s account at DTC, the letter of transmittal, or a facsimile copy, properly completed and duly executed, with any required signature guarantees, must in any case be delivered to and received by the exchange agent at its address listed under “—Exchange Agent” on or prior to the expiration date.

If your old notes are held through DTC, you must complete a form called “instructions to registered holder and/or book-entry participant,” which will instruct the DTC participant through whom you hold your securities of your intention to tender your old notes or not tender your old notes. Please note that delivery of documents to DTC in accordance with its procedures does not constitute delivery to the exchange agent and we will not be able to accept your tender of notes until the exchange agent receives a letter of transmittal and a book-entry confirmation from DTC with respect to your notes. A copy of that form is available from the exchange agent.

Guaranteed Delivery Procedures

If you are a registered holder of old notes and you want to tender your old notes but your old notes are not immediately available, or time will not permit your old notes to reach the exchange agent before the expiration date, or the procedure for book-entry transfer cannot be completed on a timely basis, a tender may be effected if

•

the tender is made through an eligible institution,

•

prior to the expiration date, the exchange agent receives, by facsimile transmission, mail or hand delivery, from that eligible institution a properly completed and duly executed letter of transmittal and notice of guaranteed delivery, substantially in the form provided by us, stating:

•

the name and address of the holder of old notes;

•

the amount of old notes tendered;

•

the tender is being made by delivering that notice; and

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•

guaranteeing that within three New York Stock Exchange trading days after the date of execution of the notice of guaranteed delivery, the certificates of all physically tendered old notes, in proper form for transfer, or a book-entry confirmation, as the case may be, will be deposited by that eligible institution with the exchange agent, and

•

the certificates for all physically tendered old notes, in proper form for transfer, or a book-entry confirmation, as the case may be, are received by the exchange agent within three New York Stock Exchange trading days after the date of execution of the Notice of Guaranteed Delivery.

Withdrawal Rights

You can withdraw your tender of old notes at any time on or prior to the expiration date.

For a withdrawal to be effective, a written notice of withdrawal must be received by the exchange agent at one of the addresses listed below under “Exchange Agent.” Any notice of withdrawal must specify:

•

the name of the person having tendered the old notes to be withdrawn,

•

the old notes to be withdrawn,

•

the principal amount of the old notes to be withdrawn,

•

if certificates for old notes have been delivered to the exchange agent, the name in which the old notes are registered, if different from that of the withdrawing holder,

•

if certificates for old notes have been delivered or otherwise identified to the exchange agent, then, prior to the release of those certificates, you must also submit the serial numbers of the particular certificates to be withdrawn and a signed notice of withdrawal with signatures guaranteed by an eligible institution unless you are an eligible institution, and

•

if old notes have been tendered using the procedure for book-entry transfer described above, any notice of withdrawal must specify the name and number of the account at DTC to be credited with the withdrawn old notes and otherwise comply with the procedures of that facility.

Please note that all questions as to the validity, form, eligibility and time of receipt of notices of withdrawal will be determined by us, and our determination shall be final and binding on all parties. Any old notes so withdrawn will be considered not to have been validly tendered for exchange for purposes of the exchange offer.

If you have properly withdrawn old notes and wish to re-tender them, you may do so by following one of the procedures described under “Procedures for Tendering old notes” above at any time on or prior to the expiration date.

Conditions to the Exchange Offer

Notwithstanding any other provisions of the exchange offer, we will not be required to accept for exchange, or to issue new notes in exchange for, any old notes and may terminate or amend the exchange offer, if at any time before the expiration of the exchange offer, that acceptance or issuance would violate applicable law or any interpretation of the staff of the SEC.

That condition is for our sole benefit and may be asserted by us regardless of the circumstances giving rise to that condition. Our failure at any time to exercise the foregoing rights shall not be considered a waiver by us of that right. Our rights described in the prior paragraph are ongoing rights which we may assert at any time and from time to time prior to the expiration of the exchange offer.

In addition, we will not accept for exchange any old notes tendered, and no new notes will be issued in exchange for any old notes, if at that time any stop order shall be threatened or in effect with respect to the exchange offer to which this prospectus relates or the qualification of the indenture under the Trust Indenture Act.

Exchange Agent

U.S. Bank National Association has been appointed as the exchange agent for the exchange offer. All executed letters of transmittal should be directed to the exchange agent at one of the addresses set forth below. Questions and requests for assistance, requests for additional copies of this prospectus or of the letter of transmittal and requests for notices of guaranteed delivery should be directed to the exchange agent, addressed as follows:

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Deliver To:

By Registered, Regular or Certified Mail or Overnight Delivery:

U.S. Bank National Association

Attn: Corporate Trust-Specialized Finance
111 Fillmore Avenue E
St. Paul, Minnesota 55107

Delivery to an address other than as listed above or transmission of instructions via facsimile other than as listed above does not constitute a valid delivery.

Fees and Expenses

The principal solicitation is being made by mail; however, additional solicitation may be made by telegraph, telephone or in person by our officers, regular employees and affiliates. We will not pay any additional compensation to any of our officers and employees who engage in soliciting tenders. We will not make any payment to brokers, dealers, or others soliciting acceptances of the exchange offer. However, we will pay the exchange agent reasonable and customary fees for its services and will reimburse it for its reasonable out-of-pocket expenses in connection with the exchange offer.

The estimated cash expenses to be incurred in connection with the exchange offer, including legal, accounting, SEC filing, printing and exchange agent expenses, will be paid by us and are estimated in the aggregate to be $0.3 million.

Accounting Treatment

We will record the new notes in our accounting records at the same carrying value as the old notes, which is the aggregate principal amount as reflected in our accounting records on the date of exchange. Accordingly, we will not recognize any gain or loss for accounting purposes upon the consummation of this exchange offer. We will capitalize the expenses of this exchange offer and amortize them over the life of the notes.

Transfer Taxes

Holders who tender their old notes for exchange will not be obligated to pay any transfer taxes in connection therewith, except that holders who instruct us to register new notes in the name of, or request that old notes not tendered or not accepted in the exchange offer be returned to, a person other than the registered tendering holder will be responsible for the payment of any applicable transfer tax thereon.

Resale of the New Notes

Under existing interpretations of the staff of the SEC contained in several no-action letters to third parties, the new notes would in general be freely transferable after the exchange offer without further registration under the Securities Act. The relevant no-action letters include theExxon Capital Holdings Corporation letter, which was made available by the SEC on May 13, 1988, and theMorgan Stanley & Co. Incorporated letter, made available on June 5, 1991.

However, any purchaser of old notes who is an “affiliate” of IPALCO Enterprises, Inc. or who intends to participate in the exchange offer for the purpose of distributing the new notes

(1)

will not be able to rely on the interpretation of the staff of the SEC,

(2)

will not be able to tender its old notes in the exchange offer, and

(3)

must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any sale or transfer of the securities unless that sale or transfer is made using an exemption from those requirements.

By executing, or otherwise becoming bound by, the Letter of Transmittal each holder of the old notes will represent that:

(1)

it is not our “affiliate”,

(2)

any new notes to be received by it were acquired in the ordinary course of its business, and

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(3)

it has no arrangement or understanding with any person to participate, and is not engaged in and does not intend to engage, in the “distribution,” within the meaning of the Securities Act, of the new notes.

In addition, in connection with any resales of new notes, any broker-dealer participating in the exchange offer who acquired securities for its own account as a result of market-making or other trading activities must deliver a prospectus meeting the requirements of the Securities Act. The SEC has taken the position in the Shearman & Sterling no-action letter, which it made available on July 2, 1993, that participating broker-dealers may fulfill their prospectus delivery requirements with respect to the new notes, other than a resale of an unsold allotment from the original sale of the old notes, with the prospectus contained in the exchange offer registration statement. Under the registration rights agreement, we are required to allow participating broker-dealers and other persons, if any, subject to similar prospectus delivery requirements to use this prospectus as it may be amended or supplemented from time to time, in connection with the resale of new notes.

Failure to Exchange

Holders of old notes who do not exchange their old notes for new notes under the exchange offer will remain subject to the restrictions on transfer of such old notes as set forth in the legend printed on the notes as a consequence of the issuance of the old notes pursuant to the exemptions from, or in transactions not subject to, the registration requirements of the Securities Act and applicable state securities laws, and otherwise set forth in the confidential offering memorandum distributed in connection with the private offering of the old notes.

Other

Participating in the exchange offer is voluntary, and you should carefully consider whether to accept. You are strongly urged to consult your financial, legal and tax advisors in making your own decision on what action to take.

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MATERIAL UNITED STATES TAX CONSEQUENCES OF THE EXCHANGE OFFER

The exchange of old notes for new notes in the exchange offer will not result in any United States federal income tax consequences to holders. When a holder exchanges an old security for a new security in the exchange offer, the holder will have the same adjusted basis and holding period in the new security as in the old security immediately before the exchange.

Persons considering the exchange of outstanding notes for exchange notes should consult their own tax advisors concerning the United States federal income tax consequences in light of their particular situations as well as any consequences arising under the laws of any other taxing jurisdiction.

PLAN OF DISTRIBUTION

Each broker-dealer that receives new notes for its own account in the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of new notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where old notes were acquired as a result of market-making activities or other trading activities. We have agreed that, for a period of 90 days after the expiration date, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any resale of new notes received by it in exchange for old notes.

We will not receive any proceeds from any sale of new notes by broker-dealers.

New notes received by broker-dealers for their own account in the exchange offer may be sold from time to time in one or more transactions:

•

in the over-the-counter market;

•

in negotiated transactions;

•

through the writing of options on the new notes; or

•

a combination of those methods of resale,

at market prices prevailing at the time of resale, at prices related to prevailing market prices or negotiated prices.

Any resale may be made:

•

directly to purchasers; or

•

to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any broker-dealer or the purchasers of any new notes.

Any broker-dealer that resells new notes that were received by it for its own account in the exchange offer and any broker or dealer that participates in a distribution of those new notes may be considered to be an “underwriter” within the meaning of the Securities Act. Any profit on any resale of those new notes and any commission or concessions received by any of those persons may be considered to be underwriting compensation under the Securities Act. The letter of transmittal states that, by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be considered to admit that it is an “underwriter” within the meaning of the Securities Act.

For a period of 90 days after the expiration date, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests those documents in the letter of transmittal. We have agreed to pay all expenses incident to the exchange offer, other than commissions or concessions of any brokers or dealers and will indemnify the holders of the securities, including any broker-dealers, against some liabilities, including liabilities under the Securities Act.

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VALIDITY OF SECURITIES

Davis Polk & Wardwell LLP will opine for us on whether the new notes are valid and binding obligations of IPALCO Enterprises, Inc. and will rely on the opinion of Barnes & Thornburg LLP with respect to certain matters under the laws of the State of Indiana.

EXPERTS

The consolidated financial statements and related schedules of IPALCO Enterprises, Inc. and subsidiaries as of December 31, 2016 and 2015, and for each of the three years in the period ended December 31, 2016, appearing in this Prospectus and Registration Statement have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The consolidated financial statements and related schedule of Indianapolis Power & Light Company and subsidiary as of December 31, 2016 and 2015, and for each of the three years in the period ended December 31, 2016, appearing in this Prospectus and Registration Statement have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC, Washington, D.C. 20549, a registration statement on Form S-4 under the Securities Act with respect to our offering of the new notes. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules thereto. For further information with respect to the company and the new notes, reference is made to the registration statement and the exhibits and any schedules filed therewith. Statements contained in this prospectus as to the contents of any contract or other document referred to are not necessarily complete and in each instance, if such contract or document is filed as an exhibit, reference is made to the copy of such contract or other document filed as an exhibit to the registration statement, each statement being qualified in all respects by such reference. A copy of the registration statement, including the exhibits and schedules thereto, may be read and copied at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet website that contains reports, proxy statements and other information about issuers, like us, that file electronically with the SEC. The address of that site is at http://www.sec.gov.

If for any reason we are not required to comply with the reporting requirements of the Securities Exchange Act of 1934, as amended, or we do not otherwise report on an annual or quarterly basis on forms provided for such annual and quarterly reporting pursuant to rules and regulations promulgated by the SEC, we are still required under the indenture to deliver (which may be accomplished through posting on the internet) to the trustee and to holders of the notes, without any cost to any holder: (1) within 90 days after the end of each fiscal year, audited financial statements and (2) within 45 days after the end of each of the first three fiscal quarters of each fiscal year, quarterly unaudited financial statements. We are also required under the indenture to provide without charge upon the written request of (1) a holder of any notes or (2) a prospective holder of any of the notes who is a “qualified institutional buyer” within the meaning of Rule 144A and is designated by an existing holder of any of the notes with the information with respect to the Company required to be delivered under Rule 144A(d)(f) under the Securities Act to enable resales of the notes to be made pursuant to Rule 144A. Any such requests should be directed to us at: IPALCO Enterprises, Inc., One Monument Circle, Indianapolis, Indiana 46204, Phone: (317) 261-8261, Attention: Treasurer.

We also maintain an Internet site at http://www.iplpower.com. Our website and the information contained therein or connected thereto shall not be deemed to be a part of this prospectus or the registration statement of which it forms a part.

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INDEX TO FINANCIAL STATEMENTS AND SCHEDULES

IPALCO Enterprises, Inc. and Subsidiaries - Consolidated Financial Statements (as of December 31, 2016)

Report of Independent Registered Public Accounting Firm	F-2
Consolidated Statements of Operations for the Years Ended December 31, 2016, 2015 and 2014	F-3
Consolidated Balance Sheets as of December 31, 2016 and 2015	F-4
Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014	F-5
Consolidated Statements of Common Shareholder’s Equity and Noncontrolling Interest for the Years Ended December 31, 2016, 2015 and 2014	F-6
Notes to Consolidated Financial Statements for the Years Ended December 31, 2016, 2015 and 2014	F-7

Indianapolis Power & Light Company and Subsidiary - Consolidated Financial Statements (as of December 31, 2016)

Report of Independent Registered Public Accounting Firm	F-38
Consolidated Statements of Operations for the Years Ended December 31, 2016, 2015 and 2014	F-39
Consolidated Balance Sheets as of December 31, 2016 and 2015	F-40
Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014	F-41
Consolidated Statements of Common Shareholder’s Equity for the Years Ended December 31, 2016, 2015 and 2014	F-42
Notes to Consolidated Financial Statements for the Years Ended December 31, 2016, 2015 and 2014	F-43

IPALCO Enterprises, Inc. and Subsidiaries - Condensed Consolidated Financial Statements (as of September 30, 2017)

Unaudited Condensed Consolidated Statements of Operations for the Three Months and Nine Months Ended September 30, 2017 and 2016	F-73
Unaudited Condensed Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016	F-74
Unaudited Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2017 and 2016	F-75
Notes to Unaudited Condensed Consolidated Financial Statements for the Three Months and Nine Months Ended September 30, 2017 and 2016	F-76

Indianapolis Power & Light Company and Subsidiary - Condensed Consolidated Financial Statements (as of September 30, 2017)

Unaudited Condensed Consolidated Statements of Operations for the Three Months and Nine Months Ended September 30, 2017 and 2016	F-87
Unaudited Condensed Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016	F-88
Unaudited Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2017 and 2016	F-89
Notes to Unaudited Condensed Consolidated Financial Statements for the Three Months and Nine Months Ended September 30, 2017 and 2016	F-90

IPALCO Enterprises, Inc. and Subsidiaries - Financial Statement Schedules (as of December 31, 2016)

Schedule I - Condensed Financial Information of Registrant	F-100
Schedule II - Valuation and Qualifying Accounts and Reserves	F-106

Indianapolis Power & Light Company and Subsidiary - Financial Statement Schedule (as of December 31, 2016)

Schedule II - Valuation and Qualifying Accounts And Reserves	F-106

F-1

PART II

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders 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, 2016 and 2015, and the related consolidated statements of operations, common shareholders’ equity and noncontrolling interest, and cash flows for each of the three years in the period ended December 31, 2016. Our audits also included the financial statement schedules listed in the Index at Item 15a for each of the three years in the period ended December 31, 2016. 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 December 31, 2016 audit in accordance with the standards of the Public Company Accounting Oversight Board (United States) and in accordance with auditing standards generally accepted in the United States of America. We conducted our December 31, 2015 audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as 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, 2016 and 2015, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, 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 consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ ERNST & YOUNG LLP

Indianapolis, Indiana

February 24, 2017

F-2

IPALCO ENTERPRISES, INC. and SUBSIDIARIES

Consolidated Statements of Operations

For the Years Ended December 31, 2016, 2015 and 2014

(In Thousands)

	2016			2015			2014
UTILITY OPERATING REVENUES	$	1,347,430		$	1,250,399		$	1,321,674

UTILITY OPERATING EXPENSES:
Fuel	276,171			315,600			411,217
Other operating expenses	245,130			224,282			218,932
Power purchased	170,466			145,064			116,648
Maintenance	130,385			131,574			113,248
Depreciation and amortization	218,444			188,267			185,263
Taxes other than income taxes	45,262			43,617			45,218
Income taxes - net	73,161			57,284			70,235
Total utility operating expenses	1,159,019			1,105,688			1,160,761
UTILITY OPERATING INCOME	188,411			144,711			160,913

OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used during construction	27,140			15,302			7,381
Loss on early extinguishment of debt	—			(21,956		)	—
Miscellaneous income and (deductions) - net	(2,311		)	(2,994		)	(2,236		)
Income tax benefit applicable to nonoperating income	11,952			25,718			22,191
Total other income and (deductions) - net	36,781			16,070			27,336

INTEREST AND OTHER CHARGES:
Interest on long-term debt	111,611			106,936			108,104
Other interest	2,240			2,063			1,865
Allowance for borrowed funds used during construction	(23,866		)	(12,809		)	(4,963		)
Amortization of redemption premiums and expense on debt	4,147			5,067			5,275
Total interest and other charges - net	94,132			101,257			110,281
NET INCOME	131,060			59,524			77,968

LESS: PREFERRED DIVIDENDS OF SUBSIDIARY	3,213			3,213			3,213
NET INCOME APPLICABLE TO COMMON STOCK	$	127,847		$	56,311		$	74,755

See notes to consolidated financial statements.

F-3

IPALCO ENTERPRISES, INC. and SUBSIDIARIES

Consolidated Balance Sheets

(In Thousands)

	December 31, 2016			December 31, 2015
ASSETS
UTILITY PLANT:
Utility plant in service	$	4,997,846		$	4,890,063
Less accumulated depreciation	2,030,497			2,228,440
Utility plant in service - net	2,967,349			2,661,623
Construction work in progress	898,330			766,406
Spare parts inventory	14,237			12,336
Property held for future use	1,002			1,002
Utility plant - net	3,880,918			3,441,367
OTHER ASSETS:
Nonutility property - at cost, less accumulated depreciation	512			517
Intangible assets - net	11,976			10,016
Other long-term assets	5,916			5,664
Other assets - net	18,404			16,197
CURRENT ASSETS:
Cash and cash equivalents	34,953			21,521
Accounts receivable and unbilled revenue (less allowance
for doubtful accounts of $2,365 and $2,498, respectively)	154,586			124,167
Fuel inventories - at average cost	30,237			66,834
Materials and supplies - at average cost	60,648			57,997
Regulatory assets	33,912			8,002
Prepayments and other current assets	33,504			26,063
Total current assets	347,840			304,584
DEFERRED DEBITS:
Regulatory assets	450,710			448,200
Miscellaneous	4,409			6,821
Total deferred debits	455,119			455,021
TOTAL	$	4,702,281		$	4,217,169
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common shareholders' equity:
Paid in capital	$	596,810		$	383,448
Accumulated deficit	(25,627		)	(30,515		)
Total common shareholders' equity	571,183			352,933
Cumulative preferred stock of subsidiary	59,784			59,784
Long-term debt (Note 7)	2,474,840			2,153,276
Total capitalization	3,105,807			2,565,993
CURRENT LIABILITIES:
Short-term and current portion of long-term debt (Note 7)	74,650			166,655
Accounts payable	119,511			155,428
Accrued expenses	18,754			19,482
Accrued real estate and personal property taxes	18,930			17,712
Regulatory liabilities	7,704			28,169
Accrued interest	32,541			31,690
Customer deposits	29,780			30,719
Other current liabilities	19,467			12,623
Total current liabilities	321,337			462,478
DEFERRED CREDITS AND OTHER LONG-TERM LIABILITIES:
Regulatory liabilities	670,294			639,516
Deferred income taxes - net	449,730			397,394
Non-current income tax liability	6,634			7,147
Unamortized investment tax credit	2,410			3,910
Accrued pension and other postretirement benefits	64,139			80,734
Asset retirement obligations	80,568			58,986
Miscellaneous	1,362			1,011
Total deferred credits and other long-term liabilities	1,275,137			1,188,698
COMMITMENTS AND CONTINGENCIES (Note 10)
TOTAL	$	4,702,281		$	4,217,169

See notes to consolidated financial statements.

F-4

IPALCO ENTERPRISES, INC. and SUBSIDIARIES

Consolidated Statements of Cash Flows

For the Years Ended December 31, 2016, 2015 and 2014

(In Thousands)

	2016			2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	131,060		$	59,524		$	77,968
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	216,019			201,475			188,477
Amortization (deferral) of regulatory assets	6,377			(8,731		)	1,123
Amortization of debt premium	200			596			942
Deferred income taxes and investment tax credit adjustments - net	34,012			31,566			47,455
Loss on early extinguishment of debt	—			21,956			—
Allowance for equity funds used during construction	(27,140		)	(14,996		)	(7,136		)
Change in certain assets and liabilities:
Accounts receivable	(30,420		)	15,542			3,699
Fuel, materials and supplies	33,434			(18,372		)	5,094
Income taxes receivable or payable	(1,603		)	—			590
Financial transmission rights	(243		)	2,086			(1,947		)
Accounts payable and accrued expenses	13,668			(716		)	(24,322		)
Accrued real estate and personal property taxes	1,218			(1,465		)	(47		)
Accrued interest	850			965			1,034
Pension and other postretirement benefit expenses	(16,595		)	(15,730		)	2,785
Short-term and long-term regulatory assets and liabilities	(38,026		)	(22,980		)	(44,252		)
Prepaids and other current assets	(1,779		)	(4,949		)	1,725
Other - net	3,559			6,654			809
Net cash provided by operating activities	324,591			252,425			253,997
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures - utility	(592,243		)	(672,849		)	(381,626		)
Project development costs	(1,356		)	(8,980		)	(9,657		)
Cost of removal, net of salvage	(13,403		)	(12,064		)	(6,036		)
Other	(1,686		)	(1,224		)	(39		)
Net cash used in investing activities	(608,688		)	(695,117		)	(397,358		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt borrowings	298,000			388,850			105,000
Short-term debt repayments	(414,850		)	(272,000		)	(105,000		)
Long-term borrowings, net of discount	387,662			753,350			128,358
Retirement of long-term debt and early tender premium	(40,000		)	(552,179		)	—
Dividends on common stock	(122,959		)	(69,487		)	(78,400		)
Issuance of common stock	134,276			214,366			—
Equity contributions from shareholders	78,738			—			106,400
Preferred dividends of subsidiary	(3,213		)	(3,213		)	(3,213		)
Deferred financing costs paid	(4,499		)	(8,824		)	(1,724		)
Payments for financed capital expenditures	(15,473		)	(13,215		)	—
Other	(153		)	(368		)	(194		)
Net cash provided by financing activities	297,529			437,280			151,227
Net change in cash and cash equivalents	13,432			(5,412		)	7,866
Cash and cash equivalents at beginning of period	21,521			26,933			19,067
Cash and cash equivalents at end of period	$	34,953		$	21,521		$	26,933

Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized)	$	89,098		$	95,137		$	103,938
Income taxes	$	28,800		$	—		$	—
	As of December 31,
	2016			2015			2014
Non-cash investing activities:
Accruals for capital expenditures	$	36,249		$	79,553		$	37,293

See notes to consolidated financial statements.

F-5

IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Common Shareholders' Equity
and Noncontrolling Interest
*(In Thousands)*

	Paid in Capital		Accumulated Deficit			Total Common Shareholders' Equity			Cumulative Preferred Stock of Subsidiary
Balance at January 1, 2014	$	61,468	$	(13,694	)	$	47,774		$	59,784
Net income			74,755			74,755			3,213
Preferred stock dividends									(3,213		)
Distributions to AES			(78,400		)	(78,400		)
Contributions from AES	106,400					106,400
Other	742					742
Balance at December 31, 2014	$	168,610	$	(17,339	)	$	151,271		$	59,784
Net income			56,311			56,311			3,213
Preferred stock dividends									(3,213		)
Distributions to shareholders			(69,487		)	(69,487		)
Issuance of common stock	214,366					214,366
Other	472					472
Balance at December 31, 2015	$	383,448	$	(30,515	)	$	352,933		$	59,784
Net income			127,847			127,847			3,213
Preferred stock dividends									(3,213		)
Distributions to shareholders			(122,959		)	(122,959		)
Contributions from shareholders	78,738					78,738
Issuance of common stock	134,276					134,276
Other	348					348
Balance at December 31, 2016	$	596,810	$	(25,627	)	$	571,183		$	59,784

See notes to consolidated financial statements.

F-6

IPALCO ENTERPRISES, INC. and SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2016, 2015 and 2014

1. OVERVIEW AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

IPALCO is a holding company incorporated under the laws of the state of Indiana. IPALCO, acquired by AES in March 2001, is owned by AES U.S. Investments (82.35%) and CDPQ (17.65%) (see Note 6, “Equity – Equity Transactions” for details). AES U.S. Investments is owned by AES U.S. Holdings, LLC (85%) and CDPQ (15%). IPALCO owns all of the outstanding common stock of IPL. Substantially all of IPALCO’s business consists of generating, transmitting, distributing and selling of electric energy conducted through its principal subsidiary, IPL. IPL was incorporated under the laws of the state of Indiana in 1926. IPL has approximately 490,000 retail customers in the city of Indianapolis and neighboring cities, towns and communities, and adjacent rural areas all within the state of Indiana, with 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 four generating stations all within the state of Indiana. Our largest generating station, Petersburg, is coal-fired. The second largest station, Harding Street, has converted its coal-fired units to natural gas and uses natural gas and fuel oil to power combustion turbines; approximately 90 MW of old oil-fired units were retired at Harding Street in recent years. In addition, IPL began the operation of a 20 MW battery energy storage unit at this location in May 2016. The third station, Eagle Valley, retired its coal-fired units in April 2016 and several small oil-fired units prior to this date. The CCGT at Eagle Valley is expected to be completed in the first half of 2018 with a rated output of 671 MW. The fourth station, Georgetown, is a small peaking station that uses natural gas to power combustion turbines. IPL’s net electric generation capacity for winter is 2,993 MW and net summer capacity is 2,878 MW.

IPALCO’s other direct subsidiary is Mid-America. Mid-America is the holding company for IPALCO’s unregulated activities, which have not been material to the financial statements in the periods covered by this report. 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.

Principles of Consolidation

IPALCO’s consolidated financial statements are prepared in accordance with GAAP and in conjunction with the rules and regulations of the SEC. 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 Operations.

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. See“Intangible Assets” below for additional information.

Regulatory Accounting

The retail utility operations of IPL are subject to the jurisdiction of the IURC. IPL’s wholesale power transactions are subject to the jurisdiction of the FERC. These agencies regulate IPL’s utility business operations, tariffs, accounting, depreciation allowances, services, issuances of securities and the sale and acquisition of utility properties. The financial statements of IPL are based on GAAP, including the provisions of FASB ASC 980“Regulated Operations,” which gives recognition to the

F-7

ratemaking and accounting practices of these agencies. See also Note 5, “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 certain 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. At December 31, 2016 and 2015, customer accounts receivable include unbilled energy revenues of $57.0 million and $42.1 million, respectively, on a base of annual revenue of $1.3 billion in 2016 and 2015. An allowance for potential credit losses is maintained and amounts are written off when normal collection efforts have been exhausted. Our provision for doubtful accounts included in“Other operating expenses” on the accompanying Consolidated Statements of Operations was $4.1 million, $4.3 million and $4.9 million for the years ended December 31, 2016, 2015 and 2014, 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 March 2016. IPL is permitted to recover actual costs of purchased power and fuel consumed, subject to certain restrictions. This is accomplished through quarterly 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. See also Note 2, “Regulatory Matters” for a discussion of other costs that IPL is permitted to recover through periodic rate adjustment proceedings and the status of current rate adjustment proceedings.

In addition, we are one of many transmission system owner members of 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, 2016 and 2015, total loss contingencies accrued were $11.6 million and $5.6 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. Approximately 66% 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 10, 2018, and the contract with the clerical-technical unit expires February 17, 2020. Additionally, IPL has long-term coal contracts with three suppliers, with about 39% of our existing coal under contract for the three-year period ending December 31, 2019 coming from one supplier. Substantially all of the coal is currently mined in the state of Indiana.

Allowance For Funds Used During Construction

F-8

construction with a corresponding credit to income. For the Eagle Valley CCGT, Harding Street refueling projects, and NPDES projects, IPL capitalized amounts using a pretax composite rate of 7.1%, 7.3% and 7.6% during 2016, 2015 and 2014, respectively. For all other construction projects, IPL capitalized amounts using pretax composite rates of 7.2%, 8.1% and 8.3% during 2016, 2015 and 2014, 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 4.3%, 4.2%, and 4.1% during 2016, 2015 and 2014, respectively. Depreciation expense was $213.4 million, $198.8 million, and $185.9 million for the years ended December 31, 2016, 2015 and 2014, respectively, which is net of depreciation expense that has been deferred as a regulatory asset.

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.” 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.

Impairment of Long-lived Assets

GAAP requires that we measure long-lived assets for impairment when indicators of impairment exist. If an asset is deemed to be impaired, we are required to write down the asset to its fair value with a charge to current earnings. The net book value of our utility plant assets was $3.9 billion and $3.4 billion as of December 31, 2016 and 2015, respectively. We do not believe any of these assets are currently impaired. In making this assessment, we consider such factors as: the overall condition and generating and distribution capacity of the assets; the expected ability to recover additional expenditures in the assets; the anticipated demand and relative pricing of retail electricity in our service territory and wholesale electricity in the region; and the cost of fuel.

Intangible Assets

Intangible assets primarily include capitalized software of $91.7 million and $102.5 million and its corresponding amortization of $79.7 million and $92.5 million, as of December 31, 2016 and 2015, respectively, previously classified within utility plant that were reclassified to intangibles at the applicable year end. Amortization expense was $5.9 million, $5.2 million and $5.2 million for the years ended December 31, 2016, 2015 and 2014, respectively. The estimated amortization expense over the remaining useful life of this capitalized software is $12.0 million ($5.9 million in 2017, $5.9 million in 2018 and $0.2 million in 2019). See“New Accounting Pronouncements – New Accounting Standards Adopted”below for additional information.

Income Taxes

Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. The Company establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. The Company’s tax positions are evaluated under a more likely than not recognition threshold and measurement analysis before they are recognized for financial statement reporting.

Uncertain tax positions have been classified as noncurrent income tax liabilities unless expected to be paid within one year. The Company’s policy for interest and penalties is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations.

F-9

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.

Cash and Cash Equivalents

Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents.

Pension and Postretirement Benefits

We recognize in our Consolidated Balance Sheets an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in the funded status, that would otherwise be recognized in AOCI, recorded as a regulatory asset as this can be recovered through future rates. All plan assets are recorded at fair value. We follow the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.

We account for and disclose pension and postretirement benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postretirement plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost and funding requirements of the plans.

Effective January 1, 2016, we began applying a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and postretirement plans. This approach is consistent with the requirements of ASC 715 and is considered to be preferential to the aggregated single rate discount approach, which has historically been used in the U.S., because it is more consistent with the philosophy of a full yield curve valuation.

The change in discount rate approach did not have an impact on the measurement of the benefit obligations at December 31, 2015, nor will it impact future remeasurements. This change in approach impacted the service cost and interest cost recorded in 2016 and will impact future years. It also impacted the actuarial gains and losses recorded in 2016 and will impact future years, as well as the amortization thereof.

The 2016 service costs and interest costs included in Note 9, “Benefit Plans” reflect the change in methodology described above. The impact of the change in approach on service costs and interest costs in 2016 is shown below:

$ in thousands	2016 Service Cost							2016 Interest Cost
	Disaggregated rate approach		Aggregate rate approach		Impact of change			Disaggregated rate approach		Aggregate rate approach		Impact of change
Pension	$	7,018	$	7,382	$	(364	)	$	25,815	$	31,142	$	(5,327	)

Repair and Maintenance Costs

Repair and maintenance costs are expensed as incurred.

Per Share Data

IPALCO is owned by AES U.S. Investments and CDPQ. IPALCO does not report earnings on a per-share basis.

F-10

New Accounting Pronouncements

The following table provides a brief description of recent accounting pronouncements that had and/or could have a material impact on the Company’s consolidated financial statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or are expected to have no material impact on the Company’s consolidated financial statements.

New Accounting Standards Adopted
ASU Number and Name	Description	Date of Adoption	Effect on the financial statements upon adoption
2016-19, Technical Corrections and Improvements	This standard clarifies that the license of internal-use software shall be accounted for as the acquisition of an intangible asset. Transition Method: retrospective. The adoption of the new guidance did not have an impact on net income, net assets or net equity.	December 31, 2016	The license fees and capitalized costs of internal-use software of $102.5 million and its corresponding amortization of $92.5 million previously classified within utility plant were reclassified to intangible assets as of December 31, 2015.
2015-03, 2015-15, Interest - Imputation of Interest (Subtopic 835-30)	These standards simplify the presentation of debt issuance costs by requiring that debt issuance costs related to a tranche of debt be presented on the balance sheet as a direct deduction from the carrying amount of that debt, consistent with debt discounts. Debt issuance costs related to a line-of-credit can still be presented as an asset and subsequently amortized over the term of the line-of-credit, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The recognition and measurement guidance for debt issuance costs are not affected by the standard. Transition method: retrospective.	January 1, 2016	Deferred financing costs of approximately $20.8 million previously classified within Deferred Debits were reclassified to reduce the related debt liabilities as of December 31, 2015.
2015-02, Consolidation - Amendments to the Consolidation Analysis (Topic 810)	The standard makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the VIE guidance. The standard amends the evaluation of whether (1) fees paid to a decision-maker or service providers represent a variable interest, (2) a limited partnership or similar entity has the characteristics of a VIE and (3) a reporting entity is the primary beneficiary of a VIE. Transition method: retrospective.	January 1, 2016	There were no changes to the consolidation conclusions.
2014-15, Presentation of Financial Statements - Going Concern (Subtopic 205-40: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern	This standard requires management to evaluate whether there are conditions or events, considered in aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. There are required disclosures if substantial doubt is identified including documentation of principal conditions or events that raised substantial doubt about the entity’s ability to continue as a going concern (before consideration of management’s plans), management’s evaluation of the significance of those conditions or events in relation to the entity’s ability to meet its obligations, and management’s plans that alleviated substantial doubt about the entity’s ability to continue as a going concern.	December 31, 2016	The Company adopted this standard and it had no impact on its consolidated financial statements.
New Accounting Standards Issued But Not Yet Effective
ASU Number and Name	Description	Date of Adoption	Effect on the financial statements upon adoption
2017-04, Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment	This standard simplifies the accounting for goodwill impairment by removing the requirement to calculate the implied fair value. Instead, it requires that an entity records an impairment charge based on the excess of a reporting unit's carrying amount over its fair value. Transition method: retrospective.	January 1, 2020. Early adoption is permitted as of January 1, 2017.	The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.
2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business	This standard provides guidance to assist the entities with evaluating when a set of transferred assets and activities is a business. Transition method: prospective.	January 1, 2018. Early adoption is permitted.	The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.
2016-18, Statement of Cash Flows (Topic 320): Restricted Cash (a consensus of the FASB Emerging Issues Task Force)	This standard requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. Transition method: retrospective.	January 1, 2018 Early adoption is permitted.	The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.
2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires that an entity recognizes the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. Transition method: modified retrospective.	January 1, 2018 Early adoption is permitted.	The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.

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2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Receipts and Cash Payments (a consensus of the Emerging Issues Task Force)	This standard provides specific guidance on how certain cash transactions are presented and classified in the statement of cash flows. Transition method: retrospective.	January 1, 2018. Early adoption is permitted.	The Company is currently evaluating the impact of adopting the standard, but does not anticipate a material impact on its consolidated financial statements.
2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments	The standard updates the impairment model for financial assets measured at amortized cost to an expected loss model rather than an incurred loss model. It also allows for the presentation of credit losses on available-for-sale debt securities as an allowance rather than a write down. Transition method: various.	January 1, 2020 Early adoption is permitted only as of January 1, 2019.	The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.
2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting	The standard simplifies the following aspects of accounting for share-based payment awards: accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: The recording of excess tax benefits and tax deficiencies arising from vesting or settlement will be applied prospectively. The elimination of the requirement that excess tax benefits be realized before they are recognized will be adopted on a modified retrospective basis with a cumulative adjustment to the opening balance sheet.	January 1, 2017	The primary effect of adoption will be the recognition of excess tax benefits in our provision for income taxes in the period when the awards vest or are settled, rather than in paid-in- capital in the period when the excess tax benefits are realized. We will continue to estimate the number of awards that are expected to vest in our determination of the related periodic compensation cost.
2016-02, Leases (Topic 842)	The standard creates Topic 842, Leases, which supersedes Topic 840, Leases. It introduces a lessee model that brings substantially all leases onto the balance sheet while retaining most of the principles of the existing lessor model in U.S. GAAP and aligning many of those principles with ASC 606, Revenue from Contracts with Customers. Transition method: modified retrospective approach with certain practical expedients.	January 1, 2019. Early adoption is permitted.	The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements. The Company intends to adopt the standard as of January 1, 2019.
2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20 Revenue from Contracts with Customers (Topic 606)	See discussion of the ASU below:	January 1, 2018. Earlier application is permitted only as of January 1, 2017.	The Company will adopt the standard on January 1, 2018; see below for the evaluation of the impact of its adoption on the consolidated financial statements.

ASU 2014-09 and its subsequent corresponding updates provide the principles an entity must apply to measure and recognize revenue. The core principle is that an entity shall recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Amendments to the standard were issued that provide further clarification of the principle and to provide certain transition expedients. The standard will replace most existing revenue recognition guidance in GAAP, including the guidance on recognizing other income upon the sale or transfer of non-financial assets (including in-substance real estate).

The standard requires retrospective application and allows either a full retrospective adoption in which all of the periods are presented under the new standard or a modified retrospective approach in which the cumulative effect of initially applying the guidance is recognized at the date of initial application. We are currently working towards adopting the standard using the full retrospective method. However, the Company will continue to assess this conclusion which is dependent on the final impact to the financial statements.

In 2016, the Company established a cross-functional implementation team and is in the process of evaluating changes to our business processes, systems and controls to support recognition and disclosure under the new standard.

The Company is currently evaluating certain contracts along with our tariff revenue and certain revenue arrangements with MISO (i.e., capacity and wholesale agreements). The Company expects additional contracts to be executed during 2017 that will require assessment under the new standard. Through this assessment, the Company has identified certain key issues that we are continuing to evaluate in order to complete our assessment of the full population of contracts and be able to assess the overall impact to the financial statements. These issues include: the application of the practical expedient for measuring progress toward satisfaction of a performance obligation, when variable quantities would be considered variable consideration versus an option to acquire additional goods and services, and how to measure progress toward completion for a performance obligation that is a bundle. We are continuing to work with various non-authoritative industry groups, and monitoring the FASB and Transition Resource Group (TRG) activity, as we finalize our accounting policy on these and other industry specific interpretative issues which are expected in 2017.

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2. 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, among other things, short-term borrowings not regulated by the IURC, the sale of electricity at wholesale, 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 EPA at the federal level, and the IDEM at the state level. Other significant regulatory agencies affecting IPL include, but are not limited to, the NERC, the U.S. Department of Labor and the IOSHA.

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 IURC, 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 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.

In March 2016, the IURC issued an order authorizing IPL to increase its basic rates and charges by $30.8 million annually. The order also authorized IPL to collect, over a ten year period, $117.7 million of previously deferred regulatory assets related to IPL’s participation in the regional transmission organization known as MISO. Such deferred costs will be amortized to expense over ten years. Accordingly, $11.8 million of IPL’s long-term MISO regulatory asset has been reclassified to current regulatory assets on the accompanying Consolidated Balance Sheets. The rate order also authorized an increase in IPL’s depreciation rates of $24.3 million annually compared to the twelve months ended June 30, 2014, which is the period upon which the rate increase was calculated. IPL also received approval to implement three new rate riders for current recovery from customers of ongoing MISO costs and capacity costs, and for sharing with customers 50% of wholesale sales margins above and below the established benchmark of $6.3 million. Additionally, the capacity rider provides that IPL will share with customers 50% of any capacity sales. The order approved recovery of IPL’s pension expenses and a return on IPL’s discretionary pension fundings. While the IURC noted in the order that they found IPL’s Service Company cost allocations to be reasonable, IPL was directed to request the FERC to review its Service Company allocations. Such review is currently underway. The IURC also closed their investigation into IPL’s underground network.

Some of the intervening parties in the IURC rate case filed petitions for reconsideration of the IURC’s March 2016 order with respect to certain issues. These petitions were subsequently denied by the IURC. In addition, certain intervening parties have filed notices of appeal of the order. No assurances can be given as to the timing or outcome of this proceeding.

In May 2014, IPL received an order from the IURC granting approval to build a 644 to 685 MW CCGT at Eagle Valley. The costs to build and operate the CCGT, other than fuel costs, will not be recoverable by IPL through rates until the conclusion of a base rate case proceeding with the IURC after construction is completed.

F-13

On December 22, 2016, IPL filed a petition with the IURC for authority to increase its basic rates and charges primarily to recover the cost of the new CCGT. The CCGT was previously expected to be completed in the first half of 2017, but is now expected to be completed in the first half of 2018. To address this change, on February 24, 2017, IPL filed a motion to withdraw the case without prejudice or alternatively amend the petition and case-in-chief, at a later date. No assurances can be given as to the timing or outcome of this proceeding.

FAC 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.

ECCRA

IPL may apply to the IURC for approval of a rate adjustment known as the ECCRA every six months to recover costs (including a return) to comply with certain environmental regulations applicable to IPL’s generating stations. The total amount of IPL’s equipment approved for ECCRA recovery as of December 31, 2016 was $676 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 2016 through February 2017 was $49.9 million. During the years ended December 31, 2016, 2015 and 2014, we made environmental compliance expenditures of $124.0 million, $252.2 million, and $176.3 million, respectively. The vast majority of such costs are recoverable through our ECCRA filings.

DSM

In March 2014, legislation, referred to as SEA 340, was approved that effectively ended the IURC’s energy efficiency targets established in a 2009 statewide Generic DSM Order. Although SEA 340 puts an end to established efficiency targets, IPL will continue to offer cost-effective energy efficiency and demand response programs as one of many resources to meet future demand for electricity.

In December 2014, we received approval from the IURC of our 2015-2016 DSM plan. The approval included cost recovery on a set of DSM programs to be offered in 2015-2016 that was similar to the 2014 set of programs. It also included the ability for us to receive performance incentives dependent upon the level of success of the programs. Additionally, we were granted authority to record a regulatory asset for recovery in a future base rate case proceeding for lost margins which result from decreased kWh related to implementation of these DSM programs. We began recovering lost margins in the second half of 2016 utilizing the cost of service allocations approved in the IURC’s March 2016 rate case order. In December 2016, we received approval from the IURC of our DSM programs through the end of 2017; however, the IURC denied shareholder incentives pursuant to this order. IPL received shareholder incentives of approximately $7.7 million in 2016.

Wind and Solar Power Purchase Agreements

We are committed under a power purchase agreement to purchase all wind-generated electricity through 2029 from a wind project in Indiana. We are also committed under another agreement to purchase all wind-generated electricity for 20 years from a project in Minnesota. The Indiana project has a maximum output capacity of approximately 100 MW. The Minnesota project, which began commercial operation in October 2011, has a maximum output capacity of approximately 200 MW. In addition, we have 97 MW of solar-generated electricity in our service territory under long-term contracts in 2017 (these long-term contracts expire ranging from 2021 to 2030), of which 95 MW was in operation as of December 31, 2016. We have authority from the IURC to recover the costs for all of these agreements through an adjustment mechanism administered within the FAC. In addition, IPL sells the renewable energy in the form of renewable energy credits generated from these facilities for the benefit of retail customers through the same rate adjustment mechanism.

F-14

3. UTILITY PLANT IN SERVICE

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

	As of December 31,
	2016		2015
	*(In Thousands)*
Production	$	2,923,349	$	3,009,143
Transmission	376,659		293,767
Distribution	1,433,044		1,371,029
General plant	264,794		216,124
Total utility plant in service	$	4,997,846	$	4,890,063

Substantially all of IPL’s property is subject to a $1,633.5 million direct first mortgage lien, as of December 31, 2016, securing IPL’s first mortgage bonds. IPL had no property under capital leases as of December 31, 2016 and 2015. Total non-contractually or legally required removal costs of utility plant in service at December 31, 2016 and 2015 were $705.6 million and $673.8 million, respectively; and total contractually or legally required removal costs of utility plant in service at December 31, 2016 and 2015 were $80.6 million and $59.0 million, respectively. Please see“ARO”below 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 SO₂ and mercury emissions are recoverable from jurisdictional retail customers as part of IPL’s CCT projects; however, since jurisdictional retail rates are subject to regulatory approval, there can be no assurance that all costs will be recovered in rates.

ARO

IPL’s ARO relates primarily to environmental issues involving asbestos-containing materials, 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:

	2016			2015
	*(In Millions)*
Balance as of January 1	$	59.0		$	59.1
Liabilities incurred	—			0.6
Liabilities settled	(3.2		)	(2.5		)
Revisions in estimated cash flows	21.6			(1.3		)
Accretion expense	3.2			3.1
Balance as of December 31	$	80.6		$	59.0

Revisions in estimated cash flows of $21.6 million were incurred in 2016 for adjustments recorded to the estimated ARO liability for IPL’s ash ponds. As of December 31, 2016 and 2015, IPL did not have any assets that are legally restricted for settling its ARO liability.

F-15

4. FAIR VALUE

The fair value of financial assets and liabilities approximate their reported carrying amounts. The estimated fair values of the Company’s assets and liabilities have been determined using available market information. As these amounts are estimates and based on hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

Fair Value Hierarchy and Valuation Techniques

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; and

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

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.

FTRs

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 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 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 Operations.

Other Financial Liabilities

As of December 31, 2016 and 2015, all 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.

F-16

Summary

The fair value of assets and liabilities at December 31, 2016 measured on a recurring basis and the respective category within the fair value hierarchy for IPALCO was determined as follows:

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
	Fair value at December 31, 2016		Based on quoted market prices in active markets		Other observable inputs		Unobservable inputs
	*(In Thousands)*
Financial assets:
Financial transmission rights	$	4,393	$	—	$	—	$	4,393
Total financial assets measured at fair value	$	4,393	$	—	$	—	$	4,393
Financial liabilities:
Other derivative liabilities	$	100	$	—	$	—	$	100
Total financial liabilities measured at fair value	$	100	$	—	$	—	$	100

The fair value of assets and liabilities at December 31, 2015 measured on a recurring basis and the respective category within the fair value hierarchy for IPALCO was determined as follows:

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
	Fair value at December 31, 2015		Based on quoted market prices in active markets		Other observable inputs		Unobservable inputs
	*(In Thousands)*
Financial assets:
Financial transmission rights	$	4,150	$	—	$	—	$	4,150
Total financial assets measured at fair value	$	4,150	$	—	$	—	$	4,150
Financial liabilities:
Other derivative liabilities	$	121	$	—	$	—	$	121
Total financial liabilities measured at fair value	$	121	$	—	$	—	$	121

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

	Derivative Financial Instruments, net Liability
	*(In Thousands)*
Balance at January 1, 2015	$	6,095
Unrealized gain recognized in earnings	47
Issuances	13,281
Settlements	(15,394		)
Balance at December 31, 2015	$	4,029
Unrealized gain recognized in earnings	46
Issuances	10,892
Settlements	(10,674		)
Balance at December 31, 2016	$	4,293

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Non-Recurring Fair Value Measurements

IPL’s ARO liabilities relate primarily to environmental issues involving asbestos-containing materials, ash ponds, landfills and miscellaneous contaminants associated with its generating plants, transmission system and distribution system. We use the cost approach to determine the fair value of IPL’s ARO liabilities, which is estimated by discounting expected cash outflows to their present value at the initial recording of the liabilities. Cash outflows are based on the approximate future disposal costs as determined by market information, historical information or other management estimates. These inputs to the fair value of the ARO liabilities would be considered Level 3 inputs under the fair value hierarchy. As of December 31, 2016 and 2015, ARO liabilities were $80.6 million and $59.0 million, respectively. See Note 3,“Utility Plant in Service” for a rollforward of the ARO liability.

Financial Instruments not Measured at Fair Value in the Consolidated Balance Sheets

Debt

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 (Level 2) for the periods ending:

	December 31, 2016				December 31, 2015
	Face Value		Fair Value		Face Value		Fair Value
	*(In Millions)*
Fixed-rate	$	2,438.5	$	2,543.5	$	2,088.4	$	2,225.3
Variable-rate	140.0		140.0		256.9		256.9
Total indebtedness	$	2,578.5	$	2,683.5	$	2,345.3	$	2,482.2

The difference between the face value and the carrying value of this indebtedness represents the following:

•

unamortized deferred financing costs of $22.2 million and $20.8 million at December 31, 2016 and 2015, respectively.

•

unamortized discounts of $6.8 million and $4.6 million at December 31, 2016 and 2015, respectively.

F-18

5. 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:

	2016		2015		Recovery Period
	*(In Thousands)*
Regulatory Assets
Current:
Undercollections of rate riders	$	19,959	$	8,002	Approximately 1 year⁽¹⁾
Costs being recovered through base rates	13,953		—		Approximately 1 year⁽¹⁾
Total current regulatory assets	$	33,912	$	8,002
Long-term:
Unrecognized pension and other
postretirement benefit plan costs	$	218,070	$	226,889	Various⁽²⁾
Income taxes recoverable through rates	51,131		35,765		Various
Deferred MISO costs	114,359		128,610		Through 2026⁽³⁾
Unamortized Petersburg Unit 4 carrying
charges and certain other costs	10,193		11,248		Through 2026⁽¹⁾⁽⁴⁾
Unamortized reacquisition premium on debt	22,501		23,268		Over remaining life of debt
Environmental projects	30,678		16,876		Through 2050⁽¹⁾⁽⁴⁾
Other miscellaneous	3,778		5,544		To be determined⁽¹⁾⁽⁵⁾
Total long-term regulatory assets	$	450,710	$	448,200
Total regulatory assets	$	484,622	$	456,202
Regulatory Liabilities
Current:
Overcollections of rate riders	$	3,311	$	24,019	Approximately 1 year⁽¹⁾
FTRs		4,393	4,150		Approximately 1 year⁽¹⁾
Total current regulatory liabilities	$	7,704	$	28,169
Long-term:
ARO and accrued asset removal costs	$	668,787	$	637,065	Not Applicable
Unamortized investment tax credit	1,507		2,451		Through 2021
Total long-term regulatory liabilities	$	670,294	$	639,516
Total regulatory liabilities	$	677,998	$	667,685

(1)

Recovered (credited) per specific rate orders

(2)

IPL receives a return on its discretionary funding

(3)

The majority of these costs are being recovered per specific rate order; recovery for the remaining costs is probable but timing not yet determined

(4)

Recovered with a current return

(5)

A portion of this amount will be recovered over the next two years

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Deferred Fuel

Deferred fuel costs are a component of current regulatory assets or liabilities (which is a result of IPL charging either more or less for fuel than our actual costs to our jurisdictional customers) 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.

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.

Income Taxes Recoverable Through Rates

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. The majority of these costs are being recovered per specific rate order; recovery for the remaining costs is probable but timing not yet determined. See Note 2, “Regulatory Matters.”

ARO and Accrued Asset Removal Costs

In accordance with ASC 410 and ASC 980, IPL recognizes the cost of removal component of its depreciation reserve that does not have an associated legal retirement obligation as a deferred liability. This amount is net of the portion of legal ARO costs that is currently being recovered in rates.

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6. EQUITY

Equity Transactions

On December 15, 2014, AES announced that it entered into an agreement with CDPQ, a long-term institutional investor headquartered in Quebec, Canada. Pursuant to the agreement, on February 11, 2015, CDPQ purchased from AES 15% of AES U.S. Investments and 100 shares of IPALCO’s common stock were issued to CDPQ. In addition, pursuant to the agreement, CDPQ invested approximately $349 million in IPALCO through 2016, in exchange for a 17.65% equity stake, funding existing growth and environmental projects at IPL.

After completion of these transactions, CDPQ’s direct and indirect interests in IPALCO total approximately 30%, AES owns 85% of AES U.S. Investments, and AES U.S. Investments owns 82.35% of IPALCO. There has been no significant change in management or operational control of AES U.S. Investments, IPALCO or IPL as a result of these transactions.

In connection with the initial closing under the agreement, CDPQ, AES U.S. Investments, and IPALCO entered into a Shareholders’ Agreement. The Shareholders’ Agreement established the general framework governing the relationship between and among CDPQ and AES U.S. Investments, and their respective successors and transferees, as shareholders of IPALCO. Pursuant to the Shareholders’ Agreement, the Board of Directors of IPALCO will initially consist of 11 directors, two nominated by CDPQ and 9 nominated by AES U.S. Investments. The Shareholders’ Agreement contains restrictions on IPALCO making certain major decisions without the prior affirmative vote of a majority of the Board of Directors of IPALCO. In addition, for so long as CDPQ holds at least 5% of IPALCO’s common shares, CDPQ will have review and consultation rights with respect to certain actions of IPALCO. Certain transfer restrictions and other transfer rights apply to CDPQ and AES U.S. Investments under the Shareholders’ Agreement, including certain rights of first offer, drag along rights, tag along rights, put rights and rights of first refusal.

On February 11, 2015, in connection with the initial closing under the Subscription Agreement and the entry into the Shareholders’ Agreement, IPALCO submitted the Third Amended and Restated Articles of Incorporation for filing with the Indiana Secretary of State, as approved and adopted by the IPALCO Board. The purpose of the Third Amended and Restated Articles of Incorporation is to amend, among other things, Article VI of the Second Amended and Restated Articles of Incorporation of IPALCO in order to effectuate changes to the size and composition of the IPALCO Board in furtherance of the terms and conditions of the IPALCO Shareholders’ Agreement.

Paid In Capital and Capital Stock

On June 27, 2014, IPALCO received equity capital contributions of $106.4 million from AES for funding needs related to IPL’s environmental and replacement generation projects. IPALCO then made the same equity capital contributions to IPL.

On February 11, 2015, IPALCO issued and sold 100 shares of IPALCO’s common stock to CDPQ under the Subscription Agreement. On April 1, 2015, IPALCO issued and sold 11,818,828 shares of IPALCO’s common stock to CDPQ for $214.4 million under the Subscription Agreement.

On March 1, 2016, IPALCO issued and sold 7,403,213 shares of IPALCO’s common stock to CDPQ for $134.3 million under the Subscription Agreement. After completion of these transactions, CDPQ’s direct and indirect interest in IPALCO is approximately 30%. On June 1, 2016, IPALCO received equity capital contributions of$64.8 million from AES U.S. Investments and $13.9 million from CDPQ. IPALCO then made the same investments in IPL. The proceeds were primarily used for funding needs related to IPL’s environmental and replacement generation projects. The capital contributions on June 1, 2016 were made on a proportional share basis and, therefore, did not change CDPQ’s or AES’ ownership interests in IPALCO.

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. 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. As of December 31, 2016 and as of the filing of this report, IPL was in compliance with these restrictions.

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IPL is also restricted in its ability to pay dividends if it is in default under the terms of its Credit Agreement and its unsecured notes, 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. As of December 31, 2016 and as of the filing of this report, IPL was in compliance with all covenants and no event of default existed.

Cumulative Preferred Stock

IPL has five separate series of cumulative preferred stock. Holders of preferred stock are entitled to receive dividends at rates per annum ranging from 4.0% to 5.65%. During each year ended December 31, 2016, 2015 and 2014, 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, 2016, 2015 and 2014, preferred stock consisted of the following:

	December 31, 2016			December 31,
	Shares Outstanding	Call Price		2016		2015		2014
	Shares Outstanding	Call Price		Par Value, plus premium, if applicable
				*(In Thousands)*
Cumulative $100 par value,
authorized 2,000,000 shares
4% Series	47,611	$	118.00	$	5,410	$	5,410	$	5,410
4.2% Series	19,331	103.00		1,933		1,933		1,933
4.6% Series	2,481	103.00		248		248		248
4.8% Series	21,930	101.00		2,193		2,193		2,193
5.65% Series	500,000	100.00		50,000		50,000		50,000
Total cumulative preferred stock	591,353			$	59,784	$	59,784	$	59,784

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7. DEBT

Long-Term Debt

The following table presents our long-term debt:

		December 31,
Series	Due	2016			2015
		*(In Thousands)*
IPL first mortgage bonds:
5.40%⁽¹⁾	August 2017	$	24,650		$	24,650
3.875%⁽²⁾	August 2021	55,000			55,000
3.875%⁽²⁾	August 2021	40,000			40,000
3.125%⁽²⁾	December 2024	40,000			40,000
6.60%	January 2034	100,000			100,000
6.05%	October 2036	158,800			158,800
6.60%	June 2037	165,000			165,000
4.875%	November 2041	140,000			140,000
4.65%	June 2043	170,000			170,000
4.50%	June 2044	130,000			130,000
4.70%	September 2045	260,000			260,000
4.05%	May 2046	350,000			—
Unamortized discount – net		(6,477		)	(4,242		)
Deferred financing costs⁽³⁾		(16,736		)	(13,703		)
Total IPL first mortgage bonds		1,610,237			1,265,505
IPL unsecured debt:
Variable⁽⁴⁾	December 2020	30,000			30,000
Variable⁽⁴⁾	December 2020	60,000			60,000
Deferred financing costs⁽³⁾		(456		)	—
Total IPL unsecured debt		89,544			90,000
Total Long-term Debt – IPL		1,699,781			1,355,505
Long-term Debt – IPALCO:
5.00% Senior Secured Notes	May 2018	400,000			400,000
3.45% Senior Secured Notes	July 2020	405,000			405,000
Unamortized discount – net		(273		)	(371		)
Deferred financing costs⁽³⁾		(5,018		)	(6,858		)
Total Long-term Debt – IPALCO		799,709			797,771
Total Consolidated IPALCO Long-term Debt		2,499,490			2,153,276
Less: Current Portion of Long-term Debt		24,650			—
Net Consolidated IPALCO Long-term Debt		$	2,474,840		$	2,153,276

(1)

First mortgage bonds are issued to the city of Petersburg, Indiana, to secure the loan of proceeds from tax-exempt bonds issued by the city.

(2)

First mortgage bonds are issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority.

(3)

The Company adopted ASU No. 2015-03 on January 1, 2016, which requires the use of the full retrospective approach with respect to the presentation of debt issuance costs, including deferred charges.

(4)

Unsecured notes are issued to the Indiana Finance Authority by IPL to facilitate the loan of proceeds from various tax-exempt notes issued by the Indiana Finance Authority. The notes have a final maturity date of December 2038, but are subject to a mandatory put in December 2020.

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Debt Maturities

Maturities on long-term indebtedness subsequent to December 31, 2016, are as follows:

Year	Amount
	*(In Thousands)*
2017	$	24,650
2018	400,000
2019	—
2020	495,000
2021	95,000
Thereafter	1,513,800
Total	$	2,528,450

Significant Transactions

IPL First Mortgage Bonds and Recent 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 $1,633.5 million as of December 31, 2016. 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, 2016.

In June 2014, IPL issued $130 million aggregate principal amount of first mortgage bonds, 4.50% Series, due June 2044. Net proceeds from this offering were approximately $126.8 million, after deducting the initial purchasers’ discounts, fees and expenses for the offering. The net proceeds from the offering were used: (i) to finance a portion of IPL’s construction program; (ii) to finance a portion of IPL’s capital costs related to environmental and replacement generation projects; and (iii) for other general corporate purposes.

In September 2015, IPL issued $260 million aggregate principal amount of first mortgage bonds, 4.70% Series, due September 2045, pursuant to Rule 144A and Regulation S under the Securities Act. Net proceeds from this offering were approximately $255.6 million, after deducting the initial purchasers’ discounts and fees and expenses for the offering. The net proceeds from the offering were used to finance a portion of IPL's construction program and capital costs related to environmental and replacement generation projects and for other general corporate purposes.

In December 2015, IPL refunded $131.9 million aggregate principal amount of first mortgage bonds, 4.90% Series, due January 2016 from the proceeds of unsecured notes with a syndication of banks. For further discussion, please see “IPL Unsecured Notes” below.

In May 2016, IPL issued $350 million aggregate principal amount of first mortgage bonds, 4.05% Series, due May 2046, pursuant to Rule 144A and Regulation S under the Securities Act. Net proceeds from this offering were approximately $343.6 million, after deducting the initial purchasers’ discounts and fees and expenses for the offering. The net proceeds from this offering were used to finance a portion of IPL’s construction program and capital costs related to environmental and replacement generation projects, to repay outstanding borrowings under IPL’s 364-day delayed-draw term loan and other short-term debt, and for other general corporate purposes.

In December 2016, the Indiana Finance Authority issued on behalf of IPL an aggregate principal amount of $40.0 million of 3.125% Environmental Facilities Refunding Revenue Bonds, Series 2016A (Indianapolis Power & Light Company Project) due December 2024. IPL issued $40.0 million aggregate principal amount of first mortgage bonds to the Indiana Finance Authority at 3.125% to secure the loan of proceeds from this series of bonds issued by the Indiana Finance Authority. Proceeds of the bonds were used to refund $40.0 million of Indiana Finance Authority Pollution Control Refunding Revenue Bonds Series 2006B (Indianapolis Power & Light Company Project) at a redemption price of 100%.

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IPL Unsecured Notes

In October 2015, IPL entered into an unsecured $91.9 million 364-day committed credit facility with a delayed draw feature at variable rates with a syndication of banks. It was drawn on in October and December 2015 to fund the October 2015 termination of IPL’s $50 million accounts receivable securitization program and to assist in the December 2015 refunding of $41.9 million of IPL’s outstanding aggregate principal amount of 4.90% Environmental Facilities Refunding Revenue Bonds (Indianapolis Power & Light Company Project) Series 2009A due in January 2016. This agreement had a maturity date of October 14, 2016, with interest incurred at variable rates as described in the credit agreement. This credit facility contained customary representations, warranties and covenants, including a leverage covenant consistent with the leverage covenant contained in IPL’s Credit Agreement. In May 2016, IPL repaid $91.9 million in outstanding borrowings under its 364-day delayed-draw term loan with a portion of the proceeds from its $350 million aggregate principal amount of first mortgage bonds as described above in“IPL First Mortgage Bonds.”

In December 2015, the Indiana Finance Authority issued on behalf of IPL an aggregate principal amount of $90 million of Environmental Facilities Refunding Revenue Notes due December 2038 (Indianapolis Power & Light Company Project). These unsecured notes were issued in two series: $30 million Series 2015A notes and $60 million 2015B notes. These notes were initially purchased by a syndication of banks who will hold the notes until the mandatory put date of December 22, 2020. The proceeds of the 2015A notes and the 2015B notes were loaned to IPL to assist it in refunding the $30 million Indiana Finance Authority Environmental Facilities Refunding Revenue Bonds (Indianapolis Power & Light Company Project) Series 2009B and $60 million Indiana Finance Authority Environmental Facilities Refunding Revenue Bonds (Indianapolis Power & Light Company Project) Series 2009C each series due January 1, 2016. These notes bear interest at a variable rate as described in the notes purchase and covenants agreement. The agreement contains customary representations, warranties and covenants, including a leverage covenant consistent with the leverage covenant contained in IPL’s Credit Agreement.

IPALCO’s Senior Secured Notes

In June 2015, IPALCO completed the sale of the 2020 IPALCO Notes pursuant to Rule 144A and Regulation S under the Securities Act. The 2020 IPALCO Notes were issued pursuant to an Indenture dated June 25, 2015, by and between IPALCO and U.S. Bank, National Association, as trustee. The 2020 IPALCO Notes were priced to the public at 99.929% of the principal amount. Net proceeds to IPALCO were approximately $399.5 million after deducting underwriting costs and estimated offering expenses. These costs are being amortized to the maturity date using the effective interest method. We used the net proceeds from this offering to fund the purchase of the 2016 IPALCO Notes validly tendered and to pay for a related consent solicitation, to redeem any 2016 IPALCO Notes that remained outstanding after the completion of the tender, and to pay certain related fees, expenses and make-whole premiums. Of the 2016 IPALCO Notes outstanding, $366.5 million were tendered in June 2015. The remainder, $33.5 million, was redeemed in July 2015. An early tender premium was paid related to the tender offer and a redemption premium was paid related to the redemption of the 2016 IPALCO Notes. A loss on early extinguishment of debt of $22.1 million for the 2016 IPALCO Notes is included as a separate line item within “Other Income and (Deductions)” in the accompanying Consolidated Statements of Operations.

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 June 25, 2015, to the Pledge Agreement between IPALCO and The Bank of New York Mellon Trust Company, N.A., dated November 14, 2001, as supplemented by a Pledge Agreement Supplement dated April 15, 2008 and a Pledge Agreement Supplement dated May 18, 2011, each by IPALCO in favor of the Collateral Agent. IPALCO also agreed to register the 2020 IPALCO Notes under the Securities Act by filing an exchange offer registration statement or, under specified circumstances, a shelf registration statement with the SEC pursuant to a Registration Rights Agreement that IPALCO entered into with J.P. Morgan Securities LLC and Morgan Stanley & Co. LLC, as representatives of the initial purchasers of the 2020 IPALCO Notes. IPALCO filed its registration statement on Form S-4 with respect to the 2020 IPALCO Notes with the SEC on September 28, 2015, and this registration statement was declared effective on October 15, 2015. The exchange offer was completed on November 16, 2015.

The 2018 IPALCO Notes and 2020 IPALCO Notes are secured by IPALCO’s pledge of all of the outstanding common stock of IPL.

Line of Credit

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indebtedness under the existing credit agreement; (iii) to support working capital; and (iv) for general corporate purposes. This agreement matures on October 16, 2020, and bears interest at variable rates as described in the Credit Agreement. It includes an uncommitted $150 million accordion feature to provide IPL with an option to request an increase in the size of the facility at any time prior to October 16, 2019, subject to approval by the lenders. Prior to execution, IPL and IPALCO had existing general banking relationships with the parties to the Credit Agreement. As of December 31, 2016 and 2015, IPL had $50.0 million and $75.0 million in outstanding borrowings on the committed line of credit, respectively.

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 27, 2018. In December 2015, IPL received an order from the IURC granting IPL authority through December 31, 2018 to, among other things, issue up to $650 million in aggregate principal amount of long-term debt and refinance up to $196.5 million in existing indebtedness. As of December 31, 2016, IPL has $106.5 million of total debt issuance authority remaining under this order. This order also grants IPL authority to have up to $500 million of long-term credit agreements and liquidity facilities outstanding at any one time, of which $250.0 million remains available under the order as of December 31, 2016. As an alternative to the sale of all or a portion of $65 million in principal of the long-term debt mentioned above, we have the authority to issue up to $65 million of new preferred stock, all of which authority remains available under the order as of December 31, 2016. 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

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. Pursuant to the terms of the Receivables Sale Agreement, the Purchasers agreed 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 took into account certain eligibility requirements and reserves relating to the receivables, or (2) $50 million. On October 16, 2015, IPL closed on a new unsecured $91.9 million 364-day committed credit facility with a syndication of banks. The first $50 million of the term loan was drawn at closing to fund the October 19, 2015 termination of IPL's $50 million accounts receivable securitization program. Please see “IPL Unsecured Notes” above for details.

8. 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 March 25, 2014, the State of Indiana amended Indiana Code 6-3-2-1 through Senate Bill 001, which phases in an additional 1.6% reduction to the state corporate income tax rate that was initially being reduced by 2%. While the statutory state income tax rate remained at 6.375% for the calendar year 2016, the deferred tax balances were adjusted according to the anticipated reversal of temporary differences. The change in required deferred taxes on plant and plant-related temporary differences resulted in a reduction to the associated regulatory asset of $0.8 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 $0.6 million. The statutory state corporate income tax rate will be 6.125% for 2017.

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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. Beginning in 2010 and thereafter, the deduction is equal to 9% of the taxable income attributable to qualifying production activity. The tax benefit associated with the Internal Revenue Code Section 199 domestic production deduction for the 2016 tax year is estimated to be $2.4 million. There was no tax benefit for tax years 2015 and 2014, primarily due to the election of the final tangible property regulations.

Income Tax Provision

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

	2016			2015			2014
	*(In Thousands)*
Charged to utility operating expenses:
Current income taxes:
Federal	$	50,482		$	18,661		$	944
State	12,080			5,758			110
Total current income taxes	62,562			24,419			1,054
Deferred income taxes:
Federal	11,885			29,165			58,114
State	215			5,019			12,498
Total deferred income taxes	12,100			34,184			70,612
Net amortization of investment credit	(1,501		)	(1,319		)	(1,431		)
Total charge to utility operating expenses	73,161			57,284			70,235
Charged to other income and deductions:
Current income taxes:
Federal	(30,558		)	(18,661		)	(459		)
State	(4,807		)	(5,758		)	(5		)
Total current income taxes	(35,365		)	(24,419		)	(464		)
Deferred income taxes:
Federal	20,998			(2,573		)	(18,082		)
State	2,415			1,274			(3,645		)
Total deferred income taxes	23,413			(1,299		)	(21,727		)
Net provision to other income and deductions	(11,952		)	(25,718		)	(22,191		)
Total federal and state income tax provisions	$	61,209		$	31,566		$	48,044

Effective and Statutory Rate Reconciliation

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:

	2016		2015		2014
Federal statutory tax rate	35.0	%	35.0	%	35.0	%
State income tax, net of federal tax benefit	4.1	%	4.7	%	4.8	%
Amortization of investment tax credits	(0.8	)%	(1.5	)%	(1.2	)%
Preferred dividends of subsidiary	0.6	%	1.3	%	0.9	%
Depreciation flow through and amortization	(0.5	)%	(0.3	)%	(0.3	)%
Additional funds used during construction - equity	(3.8	)%	(3.5	)%	(0.3	)%
Manufacturers’ Production Deduction (Sec. 199)	(1.3	)%	—	%	—	%
Other – net	(0.9	)%	0.2	%	0.2	%
Effective tax rate	32.4	%	35.9	%	39.1	%

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Deferred Income Taxes

The significant items comprising IPALCO’s net accumulated deferred tax liability recognized on the audited Consolidated Balance Sheets as of December 31, 2016 and 2015, are as follows:

	2016		2015
	*(In Thousands)*
Deferred tax liabilities:
Relating to utility property, net	$	569,204	$	541,369
Regulatory assets recoverable through future rates	180,608		178,187
Other	11,612		11,768
Total deferred tax liabilities	761,424		731,324
Deferred tax assets:
Investment tax credit	927		1,507
Regulatory liabilities including ARO	272,001		260,555
Employee benefit plans	27,358		38,159
Net operating loss	—		23,161
Other	11,408		10,548
Total deferred tax assets	311,694		333,930
Deferred income taxes – net	$	449,730	$	397,394

Uncertain Tax Positions

The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2016, 2015 and 2014:

	2016			2015			2014
	*(In Thousands)*
Unrecognized tax benefits at January 1	$	7,147		$	7,042		$	6,734
Gross increases – current period tax positions	724			962			975
Gross decreases – prior period tax positions	(1,237		)	(857		)	(667		)
Unrecognized tax benefits at December 31	$	6,634		$	7,147		$	7,042

The unrecognized tax benefits at December 31, 2016 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. There are no interest or penalties applicable to the periods contained in this report.

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9. BENEFIT PLANS

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 87% 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. 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 of base compensation. The IBEW clerical-technical union new hires receive an annual lump sum company contribution into the Thrift Plan in addition to the company match. Employer contributions to the Thrift Plan were $3.1 million, $3.1 million and $3.0 million for 2016, 2015 and 2014, respectively.

The RSP

Approximately 13% of IPL’s active employees are covered by the RSP, a qualified defined contribution plan containing a profit sharing component. All non-union new hires are covered under the RSP. 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 $1.0 million, $0.3 million and $1.5 million for 2016, 2015 and 2014, respectively.

Defined Benefit Plans

Approximately 79% of IPL’s active employees are covered by the qualified Defined Benefit Pension Plan; while approximately 8% of active employees are IBEW clerical-technical unit employees who are only eligible for the Thrift Plan, which is a defined contribution plan. The remaining 13% of active employees are covered by the RSP. The RSP is a qualified defined contribution plan containing a profit sharing component. All non-union new hires are covered under the RSP, while IBEW physical unit union new hires are covered under the Defined Benefit Pension Plan and Thrift Plan. The 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, in addition to the company match. The Defined Benefit Pension Plan is noncontributory and is funded by IPL through a trust. Benefits for non-union participants in the Defined Benefit Pension Plan are based on salary, years of service and accrued benefits at April 1, 2015. Benefits for eligible union participants 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. The total number of participants in the plan as of December 31, 2016 was 23. The plan is closed to new participants.

IPL also provides postretirement health care benefits to certain active or retired employees and the spouses of certain active or retired employees. Approximately 168 active employees and 15 retirees (including spouses) were receiving such benefits or entitled to future benefits as of January 1, 2016. The plan is unfunded. These postretirement health care benefits and the related unfunded obligation of $6.8 million and $4.5 million at December 31, 2016 and 2015, respectively, were not material to the consolidated financial statements in the periods covered by this report.

F-29

The following table presents information relating to the Pension Plans:

	Pension benefits as of December 31,
	2016			2015
	*(In Thousands)*
Change in benefit obligation:
Projected benefit obligation at January 1	$	723,887		$	748,421
Service cost	7,018			8,314
Interest cost	25,815			29,638
Actuarial loss (gain)	9,718			(31,989		)
Amendments (primarily increases in pension bands)	—			5,409
Settlements	—			(395		)
Benefits paid	(34,613		)	(35,511		)
Projected benefit obligation at December 31	731,825			723,887
Change in plan assets:
Fair value of plan assets at January 1	647,573			657,239
Actual return on plan assets	45,520			1,074
Employer contributions	15,950			25,166
Settlements	—			(395		)
Benefits paid	(34,613		)	(35,511		)
Fair value of plan assets at December 31	674,430			647,573
Unfunded status	$	(57,395	)	$	(76,314	)
Amounts recognized in the statement of financial position:
Noncurrent liabilities	$	(57,395	)	$	(76,314	)
Net amount recognized at end of year	$	(57,395	)	$	(76,314	)
Sources of change in regulatory assets⁽¹⁾:
Prior service cost arising during period	$	—		$	5,409
Net loss arising during period	7,690			11,757
Amortization of prior service cost	(5,183		)	(4,867		)
Amortization of loss	(13,896		)	(14,096		)
Total recognized in regulatory assets⁽¹⁾	$	(11,389	)	$	(1,797	)
Amounts included in regulatory assets⁽¹⁾:
Net loss	$	203,047		$	209,252
Prior service cost	20,658			25,842
Total amounts included in regulatory assets	$	223,705		$	235,094

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

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

	Pension benefits as of December 31,
	2016		2015
	*(In Thousands)*
Benefit obligation	$	731,825	$	723,887
Plan assets	674,430		647,573
Benefit obligation in excess of plan assets	$	57,395	$	76,314

IPL’s total benefit obligation in excess of plan assets was $57.4 million as of December 31, 2016 ($56.3 million Defined Benefit Pension Plan and $1.1 million Supplemental Retirement Plan).

F-30

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

	Pension benefits as of December 31,
	2016		2015
	*(In Thousands)*
Accumulated benefit obligation	$	720,901	$	712,297
Plan assets	674,430		647,573
Accumulated benefit obligation in excess of plan assets	$	46,471	$	64,724

IPL’s total accumulated benefit obligation in excess of plan assets was $46.5 million as of December 31, 2016 ($45.4 million Defined Benefit Pension Plan and $1.1 million Supplemental Retirement Plan).

Pension Benefits and Expense

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

Effective January 1, 2016 the Company applied a disaggregated discount rate approach for determining service cost and interest cost for its defined benefit pension plans and postretirement plans. Refer to Note 1, “Overview and Summary of Significant Accounting Policies” for further information relating to this change in estimate. The impact of the change in approach is a reduction in: (1) service costs of $0.4 million for pension plans in 2016 ($0.4 million Defined Benefit Pension Plan and $0.0 million Supplemental Retirement Plan), and (2) interest costs of $5.3 million for pension plans in 2016 ($5.3 million Defined Benefit Pension Plan and $0.0 million Supplemental Retirement Plan).

The 2016 net actuarial loss of $7.7 million is comprised of two parts: (1) a $9.7 million pension liability actuarial loss primarily due to a decrease in the discount rate used to value pension liabilities; partially offset by (2) a $2.0 million pension asset actuarial gain primarily due to higher than expected return on assets. The unrecognized net loss of $203.0 million in the Pension Plans 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 plan participants, since ASC 715 was adopted. During 2016, the accumulated net loss was decreased due to a combination of higher than expected return on pension assets, as well as the year 2016 amortization of accumulated loss, which was partially offset by lower discount rates used to value pension liabilities. 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 9.75 years based on estimated demographic data as of December 31, 2016. The projected benefit obligation of $731.8 million less the fair value of assets of $674.4 million results in an unfunded status of $(57.4) million at December 31, 2016.

F-31

	Pension benefits for years ended December 31,
	2016			2015				2014
	*(In Thousands)*
Components of net periodic benefit cost:
Service cost	$	7,018		$	8,314			$	7,231
Interest cost	25,815			29,638				31,154
Expected return on plan assets	(43,492		)	(44,819		)		(41,893		)
Amortization of prior service cost	5,183			4,867				4,853
Recognized actuarial loss	13,896			13,890				9,710
Recognized settlement loss	—			206			—	—
Total pension cost	8,420			12,096				11,055
Less: amounts capitalized	1,187			1,403				1,426
Amount charged to expense	$	7,233		$	10,693			$	9,629
Rates relevant to each year’s expense calculations:
Discount rate – defined benefit pension plan	4.42		%	4.06		%		4.92		%
Discount rate – supplemental retirement plan	4.19		%	3.82		%		4.64		%
Expected return on defined benefit pension plan assets	6.75		%	6.75		%		7.00		%
Expected return on supplemental retirement plan assets	6.75		%	6.75		%		7.00		%

Pension expense for the following year is determined as of the December 31 measurement date based on the fair value of the Pension Plans’ assets, the expected long-term rate of return on plan assets, a mortality table assumption that reflects the life expectancy of plan participants, and a discount rate used to determine the projected benefit obligation. For 2016, pension expense was determined using an assumed long-term rate of return on plan assets of 6.75%. As of the December 31, 2016 measurement date, IPL decreased the discount rate from 4.42% to 4.29% for the Defined Benefit Pension Plan and decreased the discount rate from 4.19% to 4.00% for the Supplemental Retirement Plan. The discount rate assumption affects the pension expense determined for 2017. In addition, IPL kept the expected long-term rate of return on plan assets at 6.75% effective January 1, 2017. The expected long-term rate of return assumption affects the pension expense determined for 2017. The effect on 2017 total pension expense of a 25 basis point increase and decrease in the assumed discount rate is $(1.2) million and $1.3 million, respectively.

In determining the discount rate to use for valuing liabilities we use the market yield curve on high-quality fixed income investments as of December 31, 2016. We project the expected benefit payments under the plan based on participant data and based on certain assumptions concerning mortality, retirement rates, termination rates, etc. The expected benefit payments for each year are discounted back to the measurement date using the appropriate spot rate for each half-year from the yield curve, thereby obtaining a present value of all expected future benefit payments using the yield curve. Finally, an equivalent single discount rate is determined which produces a present value equal to the present value determined using the full yield curve.

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 2017 plan year are $13.2 million and $4.2 million, respectively (Defined Benefit Pension Plan of $13.0 million and $4.2 million, respectively; and the Supplemental Retirement Plan of $0.2 million and $0.0 million, respectively).

Pension Plan Assets and Fair Value Measurements

Pension plan assets consist of investments in equities (domestic and international), fixed income securities, and short-term securities. Differences between actual portfolio returns and expected returns may result in increased or decreased pension costs in future periods. Pension costs are determined as of the plan’s measurement date of December 31, 2016. Pension costs are determined for the following year based on the market value of pension plan assets, expected level of employer contributions, a discount rate used to determine the projected benefit obligation and the expected long-term rate of return on plan assets.

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

F-32

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 1.

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.

A description of the valuation methodologies used for each major class of assets and liabilities measured at fair value follows:

•

All the Plan’s investments have quoted market prices and are categorized as Level 1 in the fair value hierarchy.

•

The Plan’s investments in U.S. Government agency fixed income securities 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 primary objective of the Plan is to provide a source of retirement income for its participants and beneficiaries, while the primary financial objective is to improve the unfunded status of the Plan. A secondary financial objective is, where possible, to minimize pension expense volatility. The objective is based on a long-term investment horizon, so that interim fluctuations should be viewed with appropriate perspective. There can be no assurance that these objectives will be met.

In establishing our expected long-term rate of return assumption, we utilize a methodology developed by the plan’s investment consultant who maintains a capital market assumption model that takes into consideration risk, return and correlation assumptions across asset classes. A combination of quantitative analysis of historical data and qualitative judgment is used to capture trends, structural changes and potential scenarios not reflected in historical data.

The result of the analyses is a series of inputs that produce a picture of how the plan consultant believes portfolios are likely to behave through time. Capital market assumptions are intended to reflect the behavior of asset classes observed over several market cycles. Stress assumptions are also examined, since the characteristics of asset classes are constantly changing. A dynamic model is employed to manage the numerous assumptions required to estimate portfolio characteristics under different base currencies, time horizons and inflation expectations.

The Plan consultant develops forward-looking, long-term capital market assumptions for risk, return and correlations for a variety of global asset classes, interest rates and inflation. These assumptions are created using a combination of historical analysis, current market environment assessment and by applying the consultant’s own judgment. The consultant then determines an equilibrium long-term rate of return. We then take into consideration the investment manager/consultant expenses, as well as any other expenses expected to be paid out of the Plan’s trust. Finally, we have the Plan’s actuary perform a tolerance test of the consultant’s equilibrium expected long-term rate of return. We use an expected long-term rate of return compatible with the actuary’s tolerance level.

The following table summarizes the Company’s target pension plan allocation for 2016:

Asset Category:	Target Allocations
Equity Securities	60%
Debt Securities	40%

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	Fair Value Measurements at
	December 31, 2016
	(in thousands)
			Quoted Prices in Active Markets for Identical Assets		Significant Observable Inputs
Asset Category	Total		(Level 1)		(Level 2)		%
Short-term investments	$	78	$	78	$	—	—	%
Mutual funds:
U.S. equities	329,877		329,877		—		49	%
International equities	58,833		58,833		—		9	%
Fixed income	230,926		230,926		—		34	%
Fixed income securities:
U.S. Treasury securities	54,716		54,716		—		8	%
Total	$	674,430	$	674,430	$	—	100	%


	Fair Value Measurements at
	December 31, 2015
	(in thousands)
			Quoted Prices in Active Markets for Identical Assets		Significant Observable Inputs
Asset Category	Total		(Level 1)		(Level 2)		%
Short-term investments	$	176	$	176	$	—	—	%
Mutual funds:
U.S. equities	318,368		318,368		—		49	%
International equities	60,751		60,751		—		10	%
Fixed income	215,325		215,325		—		33	%
Fixed income securities:
U.S. Treasury securities	52,953		52,953		—		8	%
Total	$	647,573	$	647,573	$	—	100	%

F-34

Pension Funding

We contributed $16.0 million, $25.2 million, and $54.1 million to the Pension Plans in 2016, 2015 and 2014, 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 ERISA, as amended by the Pension Protection Act of 2006, as well as targeted funding levels necessary to meet certain thresholds.

From an ERISA funding perspective, IPL’s funded target liability percentage was estimated to be 108%. In addition to the surplus, IPL must also contribute the normal service cost earned by active participants during the plan year. The funding of normal cost is expected to be about $7.1 million in 2017, which includes $2.2 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 seven-year period. IPL elected to fund $7.1 million in January 2017, which satisfies all funding requirements for the calendar year 2017. 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, 2016 and 2015 were $34.6 million and $35.7 million, respectively. Expected benefit payments are expected to be paid out of the Pension Plans as follows:

Year	Pension Benefits
	*(In Thousands)*
2017	$	39,624
2018	41,043
2019	42,527
2020	43,745
2021	45,084
2022 through 2026	235,759

10. COMMITMENTS AND CONTINGENCIES

Legal Loss Contingencies

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 and cash flows. Amounts accrued or expensed for legal or environmental contingencies collectively during the periods covered by this report have not been material to the Financial Statements.

Environmental Loss Contingencies

New Source Review

F-35

Since receiving the letters, IPL management has met with the EPA staff regarding possible resolutions of the NOVs. Settlements and litigated outcomes of similar New Source Review 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 these cases could have a material impact on our business. It is too early to determine whether these NOVs could have a material impact on our business, financial condition or results of operations. We would seek recovery of any operating or capital expenditures, but not fines or penalties, related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that we would be successful in this regard. IPL has recorded a contingent liability related to these New Source Review and other CAA NOV matters.

11. 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 $3.1 million, $2.7 million, and $3.2 million in 2016, 2015 and 2014, respectively, and is recorded in “Other operating expenses” on the accompanying Consolidated Statements of Operations. As of December 31, 2016 and 2015, we had prepaid approximately $2.0 million and $2.2 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 $23.2 million, $24.5 million, and $20.1 million in 2016, 2015 and 2014, respectively, and is recorded in “Other operating expenses” on the accompanying Consolidated Statements of Operations. We had no prepaids for coverage under this plan as of December 31, 2016 and 2015, respectively.

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 $2.1 million and $0.7 million as of December 31, 2016 and 2015, respectively, which is recorded in “Prepayments and other current assets” on the accompanying Consolidated Balance Sheets.

Long-term Compensation Plan

During 2016, 2015 and 2014, 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, however no stock options were granted in 2016. Total deferred compensation expense recorded during 2016, 2015 and 2014 was $0.9 million, $0.7 million and $0.7 million, respectively, and was included in “Other operating expenses” on IPALCO’s Consolidated Statements of Operations. 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 Note 9, “Benefit Plans” to the Financial Statements for a description of benefits awarded to IPL employees by AES under the RSP.

Service Company

Total costs incurred by the Service Company on behalf of IPALCO were $27.4 million, $23.2 million and $22.0 million during 2016, 2015 and 2014, respectively. Total costs incurred by IPALCO on behalf of the Service Company during 2016, 2015 and 2014 were $9.2 million, $7.5 million and $5.6 million, respectively. IPALCO had a prepaid balance with the Service Company of $3.4 million and $1.2 million as of December 31, 2016 and 2015, respectively.

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CDPQ

Please refer to Note 6, “Equity – Equity Transactions”for further details.

Other

In 2014, IPL engaged a third party vendor as part of its replacement generation construction projects. A member of the AES Board of Directors is also currently a member of the Supervisory Board of this vendor. IPL had billings from this vendor of $198.5 million, $232.0 million and $80.3 million during 2016, 2015 and 2014, respectively. IPL had a payable balance to this vendor of $2.3 million and $34.0 million as of December 31, 2016 and 2015, respectively.

Additionally, transactions with various other related parties were $3.9 million, $2.4 million and $1.1 million as of December 31, 2016, 2015 and 2014, respectively. These expenses were primarily recorded in “Other operating expenses” on the accompanying Consolidated Statements of Operations.

12. BUSINESS SEGMENT INFORMATION

Operating segments are components of an enterprise that engage in business activities from which it may earn revenues and incur expenses, 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 segment is its utility segment, with all other non-utility business activities aggregated separately. The non-utility category primarily includes the 2018 IPALCO Notes and the 2020 IPALCO Notes; approximately $8.3 million and $1.7 million of cash and cash equivalents, as of December 31, 2016 and 2015, respectively; long-term investments of $5.2 million as of December 31, 2016 and 2015; and income taxes and interest related to those items. All other assets represented less than 1% of IPALCO’s total assets as of December 31, 2016 and 2015. The accounting policies of the identified segment 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):

	2016						2015						2014
	Utility		All Other		Total		Utility		All Other		Total		Utility		All Other		Total
Operating revenues	$	1,347	—		$	1,347	$	1,250	—		$	1,250	$	1,322	—		$	1,322
Depreciation and amortization	218		—		218		188		—		188		185		—		185
Income taxes	73		(11	)	61		56		(25	)	32		69		(21	)	48
Net income	156		(25	)	131		102		(42	)	60		110		(32	)	78
Utility plant - net of depreciation⁽¹⁾	3,881		—		3,881		3,441		—		3,441		2,857		—		2,857
Capital expenditures	608		—		608		686		—		686		382		—		382

(1)

Utility plant - net of depreciation for 2014 was not restated to reclassify capitalized software and its corresponding accumulated amortization balances to Intangible Assets - net because it was impracticable to restate. This impacts Utility plant - net but has no impact on Total assets.

F-37

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, 2016 and 2015, and the related consolidated statements of operations, common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2016. Our audits also included the financial statement schedule listed in the Index at Item 15a for each of the three years in the period ended December 31, 2016. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Indianapolis Power & Light Company and subsidiary at December 31, 2016 and 2015, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, 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 consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ ERNST & YOUNG LLP

Indianapolis, Indiana

February 24, 2017

F-38

INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY

Consolidated Statements of Operations

For the Years Ended December 31, 2016, 2015 and 2014

(In Thousands)

	2016			2015			2014
OPERATING REVENUES	$	1,347,430		$	1,250,399		$	1,321,674

OPERATING EXPENSES:
Fuel	276,171			315,600			411,217
Other operating expenses	245,130			224,282			218,932
Power purchased	170,466			145,064			116,648
Maintenance	130,385			131,574			113,248
Depreciation and amortization	218,444			188,267			185,263
Taxes other than income taxes	45,262			43,617			45,218
Income taxes - net	73,161			57,284			70,235
Total operating expenses	1,159,019			1,105,688			1,160,761
OPERATING INCOME	188,411			144,711			160,913

OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used during construction	27,140			15,302			7,381
Miscellaneous income and (deductions) - net	(1,354		)	(2,019		)	(1,203		)
Income tax benefit applicable to nonoperating income	460			1,066			953
Total other income and (deductions) - net	26,246			14,349			7,131

INTEREST AND OTHER CHARGES:
Interest on long-term debt	77,638			65,277			59,104
Other interest	2,240			2,063			1,865
Allowance for borrowed funds used during construction	(23,866		)	(12,809		)	(4,963		)
Amortization of redemption premium and expense on debt	2,200			2,608			2,510
Total interest and other charges - net	58,212			57,139			58,516
NET INCOME	156,445			101,921			109,528

LESS: PREFERRED DIVIDEND REQUIREMENTS	3,213			3,213			3,213
NET INCOME APPLICABLE TO COMMON STOCK	$	153,232		$	98,708		$	106,315

See notes to consolidated financial statements.

F-39

INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY

Consolidated Balance Sheets

(In Thousands)

	December 31, 2016		December 31, 2015
ASSETS
UTILITY PLANT:
Utility plant in service	$	4,997,846	$	4,890,063
Less accumulated depreciation	2,030,497		2,228,440
Utility plant in service - net	2,967,349		2,661,623
Construction work in progress	898,330		766,406
Spare parts inventory	14,237		12,336
Property held for future use	1,002		1,002
Utility plant - net	3,880,918		3,441,367
OTHER ASSETS:
Intangible assets - net	11,976		10,016
At cost, less accumulated depreciation	1,263		947
Other assets - net	13,239		10,963
CURRENT ASSETS:
Cash and cash equivalents	26,607		19,852
Accounts receivable and unbilled revenue (less allowance for
doubtful accounts of $2,365 and $2,498, respectively)	154,586		124,167
Fuel inventories - at average cost	30,237		66,834
Materials and supplies - at average cost	60,649		57,998
Regulatory assets	33,912		8,002
Prepayments and other current assets	31,497		28,578
Total current assets	337,488		305,431
DEFERRED DEBITS:
Regulatory assets	450,710		448,200
Miscellaneous	4,409		6,819
Total deferred debits	455,119		455,019
TOTAL	$	4,686,764	$	4,212,780
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common shareholder's equity:
Common stock	$	324,537	$	324,537
Paid in capital	598,500		385,140
Retained earnings	434,993		415,227
Total common shareholder's equity	1,358,030		1,124,904
Cumulative preferred stock	59,784		59,784
Long-term debt (Note 7)	1,675,131		1,355,505
Total capitalization	3,092,945		2,540,193
CURRENT LIABILITIES:
Short-term and current portion of long-term debt (Note 7)	74,650		166,655
Accounts payable	119,506		155,411
Accrued expenses	18,742		19,466
Accrued real estate and personal property taxes	18,930		17,712
Regulatory liabilities	7,704		28,169
Accrued income taxes	984		—
Accrued interest	22,731		21,104
Customer deposits	29,780		30,719
Other current liabilities	26,167		22,323
Total current liabilities	319,194		461,559
DEFERRED CREDITS AND OTHER LONG-TERM LIABILITIES:
Deferred income taxes - net	449,220		419,731
Non-current income tax liability	6,634		7,147
Regulatory liabilities	670,294		639,516
Unamortized investment tax credit	2,410		3,910
Accrued pension and other postretirement benefits	64,139		80,734
Asset retirement obligations	80,568		58,986
Miscellaneous	1,360		1,004
Total deferred credits and other long-term liabilities	1,274,625		1,211,028
COMMITMENTS AND CONTINGENCIES (Note 10)
TOTAL	$	4,686,764	$	4,212,780

See notes to consolidated financial statements.

F-40

INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY

Consolidated Statements of Cash Flows

For the Years Ended December 31, 2016, 2015 and 2014

(In Thousands)

	2016			2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	156,445		$	101,921		$	109,528
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	214,169			199,551			186,614
Amortization (deferral) of regulatory assets	6,377			(8,731		)	1,123
Amortization of debt premium	103			60			40
Deferred income taxes and investment tax credit adjustments - net	11,165			33,756			67,831
Allowance for equity funds used during construction	(27,140		)	(14,996		)	(7,136		)
Change in certain assets and liabilities:
Accounts receivable	(30,420		)	15,542			3,699
Fuel, materials and supplies	33,434			(18,372		)	5,094
Income taxes receivable or payable	3,821			(2,544		)	1,171
Financial transmission rights	(243		)	2,086			(1,947		)
Accounts payable and accrued expenses	13,891			(356		)	(23,723		)
Accrued real estate and personal property taxes	1,218			(1,465		)	(47		)
Accrued interest	1,627			996			1,034
Pension and other postretirement benefit expenses	(16,595		)	(15,730		)	2,785
Short-term and long-term regulatory assets and liabilities	(38,026		)	(22,980		)	(44,252		)
Prepaids and other current assets	(1,910		)	(4,671		)	(170		)
Other - net	3,511			5,895			2,385
Net cash provided by operating activities	331,427			269,962			304,029
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(592,243		)	(672,849		)	(381,626		)
Project development costs	(1,356		)	(8,980		)	(9,657		)
Asset removal costs	(13,403		)	(12,064		)	(6,036		)
Other	(1,703		)	(1,224		)	(56		)
Net cash used in investing activities	(608,705		)	(695,117		)	(397,375		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt borrowings	298,000			388,850			105,000
Short-term debt repayments	(414,850		)	(272,000		)	(105,000		)
Long-term borrowings	387,662			348,638			128,358
Retirement of long-term debt	(40,000		)	(131,850		)	—
Dividends on common stock	(136,466		)	(103,747		)	(127,400		)
Dividends on preferred stock	(3,213		)	(3,213		)	(3,213		)
Equity contributions from IPALCO	213,014			214,364			106,400
Payments for financed capital expenditures	(15,473		)	(13,215		)	—
Other	(4,641		)	(3,819		)	(1,920		)
Net cash provided by financing activities	284,033			424,008			102,225
Net change in cash and cash equivalents	6,755			(1,147		)	8,879
Cash and cash equivalents at beginning of period	19,852			20,999			12,120
Cash and cash equivalents at end of period	$	26,607		$	19,852		$	20,999

Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized)	$	54,350		$	53,447		$	54,938
Income taxes	$	57,900		$	25,000		$	—
	As of December 31,
	2016			2015			2014
Non-cash investing activities:
Accruals for capital expenditures	$	36,249		$	79,553		$	37,293

See notes to consolidated financial statements.

F-41

INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY

Consolidated Statements of Common Shareholders’Equity

(In Thousands)

	Common Stock		Paid in Capital		Retained Earnings			Total
Balance at January 1, 2014	$	324,537	$	63,173	$	451,351		$	839,061
Net income					109,528			109,528
Preferred stock dividends					(3,213		)	(3,213		)
Cash dividends declared on common stock					(127,400		)	(127,400		)
Contributions from IPALCO			106,400					106,400
Other			733					733
Balance at December 31, 2014	$	324,537	$	170,306	$	430,266		$	925,109
Net income					101,921			101,921
Preferred stock dividends					(3,213		)	(3,213		)
Cash dividends declared on common stock					(113,747		)	(113,747		)
Contributions from IPALCO			214,364					214,364
Other			470					470
Balance at December 31, 2015	$	324,537	$	385,140	$	415,227		$	1,124,904
Net income					156,445			156,445
Preferred stock dividends					(3,213		)	(3,213		)
Cash dividends declared on common stock					(133,466		)	(133,466		)
Contributions from IPALCO			213,014					213,014
Other			346					346
Balance at December 31, 2016	$	324,537	$	598,500	$	434,993		$	1,358,030

See notes to consolidated financial statements.

F-42

INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2016, 2015 and 2014

1. OVERVIEW AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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. IPALCO, acquired by AES in March 2001, is owned by AES U.S. Investments and CDPQ. AES U.S. Investments is owned by AES (85%) and CDPQ (15%). IPL is engaged primarily in generating, transmitting, distributing and selling of electric energy to approximately 490,000 retail customers in the city of Indianapolis and neighboring cities, towns and communities, and adjacent rural areas all within the state of Indiana, with 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 four generating stations all within the state of Indiana. Our largest generating station, Petersburg, is coal-fired. The second largest station, Harding Street, has converted its coal-fired units to natural gas and uses natural gas and fuel oil to power combustion turbines; approximately 90 MW of old oil-fired units were retired at Harding Street in recent years. In addition, IPL began the operation of a 20 MW battery energy storage unit at this location in May 2016. The third station, Eagle Valley, retired its coal-fired units in April 2016 and several small oil-fired units prior to this date. The CCGT at Eagle Valley is expected to be completed in the first half of 2018 with a rated output of 671 MW. The fourth station, Georgetown, is a small peaking station that uses natural gas to power combustion turbines. IPL’s net electric generation capacity for winter is 2,993 MW and net summer capacity is 2,878 MW.

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. This program was terminated in October 2015 (see Note 7, “Debt – Accounts Receivable Securitization” for additional details).

Principles of Consolidation

IPL’s consolidated financial statements are prepared in accordance with GAAP and in conjunction with the rules and regulations of the SEC. The consolidated financial statements include the accounts of IPL and its unregulated subsidiary, IPL Funding. All intercompany items have been eliminated in consolidation. Certain costs for shared resources amongst IPL and IPALCO, such as labor and benefits, are allocated to each entity based on allocation methodologies that management believes to be reasonable. We have evaluated subsequent events through the date this report is issued.

Use of Management Estimates

Reclassifications

Certain prior period amounts have been reclassified to conform to the current year presentation. See“Intangible Assets” below for additional information.

Regulatory Accounting

Revenues and Accounts Receivable

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a systematic basis throughout the month. At the end of each month, amounts of energy delivered to certain 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. At December 31, 2016 and 2015, customer accounts receivable include unbilled energy revenues of $57.0 million and $42.1 million, respectively, on a base of annual revenue of $1.3 billion in 2016 and 2015. An allowance for potential credit losses is maintained and amounts are written off when normal collection efforts have been exhausted. Our provision for doubtful accounts included in “Other operating expenses”on the accompanying Consolidated Statements of Operations was $4.1 million, $4.3 million and $4.9 million for the years ended December 31, 2016, 2015 and 2014, respectively.

In addition, we are one of many transmission system owner members of 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 OPERATING REVENUES when in a net selling position and in 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, 2016 and 2015, total loss contingencies accrued were $11.6 million and $5.6 million, respectively, which were included in “Other Current Liabilities”on the accompanying Consolidated Balance Sheets.

Concentrations of Risk

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. For the Eagle Valley CCGT, Harding Street refueling projects, and NPDES projects, IPL capitalized amounts using a pretax composite rate of 7.1%, 7.3% and 7.6% during 2016, 2015 and 2014, respectively. For all other construction projects, IPL capitalized amounts using pretax composite rates of 7.2%, 8.1% and 8.3% during 2016, 2015 and 2014, respectively.

F-44

Utility Plant and Depreciation

Derivatives

We have only limited involvement with derivative financial instruments and do not use them for trading purposes. IPL accounts for its derivatives in accordance with ASC 815“Derivatives and Hedging.” 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.

Impairment of Long-lived Assets

GAAP requires that we measure long-lived assets for impairment when indicators of impairment exist. If an asset is deemed to be impaired, we are required to write down the asset to its fair value with a charge to current earnings. The net book value of our utility plant assets was $3.9 billion and $3.4 billion as of December 31, 2016 and 2015, respectively. We do not believe any of these assets are currently impaired. In making this assessment, we consider such factors as: the overall condition and generating and distribution capacity of the assets; the expected ability to recover additional expenditures in the assets; the anticipated demand and relative pricing of retail electricity in our service territory and wholesale electricity in the region; and the cost of fuel.

Intangible Assets

Income Taxes

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Cash and Cash Equivalents

Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents.

Pension and Postretirement Benefits

$ in thousands	2016 Service Cost							2016 Interest Cost
	Disaggregated rate approach		Aggregate rate approach		Impact of change			Disaggregated rate approach		Aggregate rate approach		Impact of change
Pension	$	7,018	$	7,382	$	(364	)	$	25,815	$	31,142	$	(5,327	)

Repair and Maintenance Costs

Repair and maintenance costs are expensed as incurred.

Per Share Data

IPALCO owns all of the outstanding common stock of IPL. IPL does not report earnings on a per-share basis.

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New Accounting Pronouncements

The following table provides a brief description of recent accounting pronouncements that had and/or could have a material impact on IPL’s consolidated financial statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or are expected to have no material impact on IPL’s consolidated financial statements.

New Accounting Standards Adopted
ASU Number and Name	Description	Date of Adoption	Effect on the financial statements upon adoption
2016-19, Technical Corrections and Improvements	This standard clarifies that the license of internal-use software shall be accounted for as the acquisition of an intangible asset. Transition Method: retrospective. The adoption of the new guidance did not have an impact on net income, net assets or net equity.	December 31, 2016	The license fees and capitalized costs of internal-use software of $102.5 million and its corresponding amortization of $92.5 million previously classified within utility plant were reclassified to intangible assets as of December 31, 2015.
2015-03, 2015-15, Interest - Imputation of Interest (Subtopic 835-30)	These standards simplify the presentation of debt issuance costs by requiring that debt issuance costs related to a tranche of debt be presented on the balance sheet as a direct deduction from the carrying amount of that debt, consistent with debt discounts. Debt issuance costs related to a line-of-credit can still be presented as an asset and subsequently amortized over the term of the line-of-credit, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The recognition and measurement guidance for debt issuance costs are not affected by the standard. Transition method: retrospective.	January 1, 2016	Deferred financing costs of approximately $13.9 million previously classified within Deferred Debits were reclassified to reduce the related debt liabilities as of December 31, 2015.
2015-02, Consolidation - Amendments to the Consolidation Analysis (Topic 810)	The standard makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the VIE guidance. The standard amends the evaluation of whether (1) fees paid to a decision-maker or service providers represent a variable interest, (2) a limited partnership or similar entity has the characteristics of a VIE and (3) a reporting entity is the primary beneficiary of a VIE. Transition method: retrospective.	January 1, 2016	There were no changes to the consolidation conclusions.
2014-15, Presentation of Financial Statements - Going Concern (Subtopic 205-40: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern	This standard requires management to evaluate whether there are conditions or events, considered in aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. There are required disclosures if substantial doubt is identified including documentation of principal conditions or events that raised substantial doubt about the entity’s ability to continue as a going concern (before consideration of management’s plans), management’s evaluation of the significance of those conditions or events in relation to the entity’s ability to meet its obligations, and management’s plans that alleviated substantial doubt about the entity’s ability to continue as a going concern.	December 31, 2016	IPL adopted this standard and it had no impact on its consolidated financial statements.
New Accounting Standards Issued But Not Yet Effective
ASU Number and Name	Description	Date of Adoption	Effect on the financial statements upon adoption
2017-04, Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment	This standard simplifies the accounting for goodwill impairment by removing the requirement to calculate the implied fair value. Instead, it requires that an entity records an impairment charge based on the excess of a reporting unit's carrying amount over its fair value. Transition method: retrospective.	January 1, 2020. Early adoption is permitted as of January 1, 2017.	IPL is currently evaluating the impact of adopting the standard on its consolidated financial statements.
2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business	This standard provides guidance to assist the entities with evaluating when a set of transferred assets and activities is a business. Transition method: prospective.	January 1, 2018. Early adoption is permitted.	IPL is currently evaluating the impact of adopting the standard on its consolidated financial statements.
2016-18, Statement of Cash Flows (Topic 320): Restricted Cash (a consensus of the FASB Emerging Issues Task Force)	This standard requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. Transition method: retrospective.	January 1, 2018 Early adoption is permitted.	IPL is currently evaluating the impact of adopting the standard on its consolidated financial statements.
2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires that an entity recognizes the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. Transition method: modified retrospective.	January 1, 2018 Early adoption is permitted.	IPL is currently evaluating the impact of adopting the standard on its consolidated financial statements.

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2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Receipts and Cash Payments (a consensus of the Emerging Issues Task Force)	This standard provides specific guidance on how certain cash transactions are presented and classified in the statement of cash flows. Transition method: retrospective.	January 1, 2018. Early adoption is permitted.	IPL is currently evaluating the impact of adopting the standard, but does not anticipate a material impact on its consolidated financial statements.
2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments	The standard updates the impairment model for financial assets measured at amortized cost to an expected loss model rather than an incurred loss model. It also allows for the presentation of credit losses on available-for-sale debt securities as an allowance rather than a write down. Transition method: various.	January 1, 2020 Early adoption is permitted only as of January 1, 2019.	IPL is currently evaluating the impact of adopting the standard on its consolidated financial statements.
2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting	The standard simplifies the following aspects of accounting for share-based payment awards: accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: The recording of excess tax benefits and tax deficiencies arising from vesting or settlement will be applied prospectively. The elimination of the requirement that excess tax benefits be realized before they are recognized will be adopted on a modified retrospective basis with a cumulative adjustment to the opening balance sheet.	January 1, 2017	The primary effect ofadoption will be the recognition of excess tax benefits in our provision for income taxes in the period when the awards vest or are settled, rather than in paid-in- capital in the period when the excess tax benefits are realized. We will continue to estimate the number of awards that are expected to vest in our determination of the related periodic compensation cost.
2016-02, Leases (Topic 842)	The standard creates Topic 842, Leases, which supersedes Topic 840, Leases. It introduces a lessee model that brings substantially all leases onto the balance sheet while retaining most of the principles of the existing lessor model in U.S. GAAP and aligning many of those principles with ASC 606, Revenue from Contracts with Customers. Transition method: modified retrospective approach with certain practical expedients.	January 1, 2019. Early adoption is permitted.	IPL is currently evaluating the impact of adopting the standard on its consolidated financial statements. The Company intends to adopt the standard as of January 1, 2019.
2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20 Revenue from Contracts with Customers (Topic 606)	See discussion of the ASU below:	January 1, 2018. Earlier application is permitted only as of January 1, 2017.	The Company will adopt the standard on January 1, 2018; see below for the evaluation of the impact of its adoption on the consolidated financial statements.

The standard requires retrospective application and allows either a full retrospective adoption in which all of the periods are presented under the new standard or a modified retrospective approach in which the cumulative effect of initially applying the guidance is recognized at the date of initial application. We are currently working towards adopting the standard using the full retrospective method. However, IPL will continue to assess this conclusion which is dependent on the final impact to the financial statements.

In 2016, IPL established a cross-functional implementation team and is in the process of evaluating changes to our business processes, systems and controls to support recognition and disclosure under the new standard.

IPL is currently evaluating certain contracts along with our tariff revenue and certain revenue arrangements with MISO (i.e., capacity and wholesale agreements). IPL expects additional contracts to be executed during 2017 that will require assessment under the new standard. Through this assessment, IPL has identified certain key issues that we are continuing to evaluate in order to complete our assessment of the full population of contracts and be able to assess the overall impact to the financial statements. These issues include: the application of the practical expedient for measuring progress toward satisfaction of a performance obligation, when variable quantities would be considered variable consideration versus an option to acquire additional goods and services, and how to measure progress toward completion for a performance obligation that is a bundle. We are continuing to work with various non-authoritative industry groups, and monitoring the FASB and Transition Resource Group (TRG) activity, as we finalize our accounting policy on these and other industry specific interpretative issues which are expected in 2017.

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2. REGULATORY MATTERS

General

Basic Rates and Charges

F-49

FAC and Authorized Annual Jurisdictional Net Operating Income

ECCRA

DSM

Wind and Solar Power Purchase Agreements

F-50

3. UTILITY PLANT IN SERVICE

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

	As of December 31,
	2016		2015
	*(In Thousands)*
Production	$	2,923,349	$	3,009,143
Transmission	376,659		293,767
Distribution	1,433,044		1,371,029
General plant	264,794		216,124
Total utility plant in service	$	4,997,846	$	4,890,063

ARO

	2016			2015
	*(In Millions)*
Balance as of January 1	$	59.0		$	59.1
Liabilities incurred	—			0.6
Liabilities settled	(3.2		)	(2.5		)
Revisions in estimated cash flows	21.6			(1.3		)
Accretion expense	3.2			3.1
Balance as of December 31	$	80.6		$	59.0

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4. FAIR VALUE

Fair Value Hierarchy and Valuation Techniques

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; and

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

FTRs

Other Financial Liabilities

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, 2016 and 2015, all 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.

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Summary

The fair value of assets and liabilities at December 31, 2016 measured on a recurring basis and the respective category within the fair value hierarchy for IPL was determined as follows:

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
	Fair value at December 31, 2016		Based on quoted market prices in active markets		Other observable inputs		Unobservable inputs
	*(In Thousands)*
Financial assets:
Financial transmission rights	$	4,393	$	—	$	—	$	4,393
Total financial assets measured at fair value	$	4,393	$	—	$	—	$	4,393
Financial liabilities:
Other derivative liabilities	$	100	$	—	$	—	$	100
Total financial liabilities measured at fair value	$	100	$	—	$	—	$	100

The fair value of assets and liabilities at December 31, 2015 measured on a recurring basis and the respective category within the fair value hierarchy for IPL was determined as follows:

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
	Fair value at December 31, 2015		Based on quoted market prices in active markets		Other observable inputs		Unobservable inputs
	*(In Thousands)*
Financial assets:
Financial transmission rights	$	4,150	$	—	$	—	$	4,150
Total financial assets measured at fair value	$	4,150	$	—	$	—	$	4,150
Financial liabilities:
Other derivative liabilities	$	121	$	—	$	—	$	121
Total financial liabilities measured at fair value	$	121	$	—	$	—	$	121

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	Derivative Financial Instruments, net Liability
	*(In Thousands)*
Balance at January 1, 2015	$	6,095
Unrealized gain recognized in earnings	47
Issuances	13,281
Settlements	(15,394		)
Balance at December 31, 2015	$	4,029
Unrealized gain recognized in earnings	46
Issuances	10,892
Settlements	(10,674		)
Balance at December 31, 2016	$	4,293

Non-Recurring Fair Value Measurements

Financial Instruments not Measured at Fair Value in the Consolidated Balance Sheets

Debt

The following table shows the face value and the fair value of fixed-rate and variable-rate indebtedness (Level 2) for the periods ending:

	December 31, 2016				December 31, 2015
	Face Value		Fair Value		Face Value		Fair Value
	*(In Millions)*
Fixed-rate	$	1,633.5	$	1,717.2	$	1,283.4	$	1,406.8
Variable-rate	140.0		140.0		256.9		256.9
Total indebtedness	$	1,773.5	$	1,857.2	$	1,540.3	$	1,663.7

The difference between the face value and the carrying value of this indebtedness represents the following:

•

unamortized deferred financing costs of $17.2 million and $13.7 million at December 31, 2016 and 2015, respectively.

•

unamortized discounts of $6.5 million and $4.2 million at December 31, 2016 and 2015, respectively.

F-54

5. REGULATORY ASSETS AND LIABILITIES

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

	2016			2015		Recovery Period
	*(In Thousands)*
Regulatory Assets
Current:
Undercollections of rate riders	$	19,959	8,002	$	8,002	Approximately 1 year⁽¹⁾
Costs being recovered through base rates	13,953			—		Approximately 1 year⁽¹⁾
Total current regulatory assets	$	33,912		$	8,002
Long-term:
Unrecognized pension and other
postretirement benefit plan costs	$	218,070		$	226,889	Various⁽²⁾
Income taxes recoverable through rates	51,131			35,765		Various
Deferred MISO costs	114,359			128,610		Through 2026⁽³⁾
Unamortized Petersburg Unit 4 carrying
charges and certain other costs	10,193			11,248		Through 2026⁽¹⁾⁽⁴⁾
Unamortized reacquisition premium on debt	22,501			23,268		Over remaining life of debt
Environmental projects	30,678			16,876		Through 2050⁽¹⁾⁽⁴⁾
Other miscellaneous	3,778			5,544		To be determined⁽¹⁾⁽⁵⁾
Total long-term regulatory assets	$	450,710		$	448,200
Total regulatory assets	$	484,622		$	456,202
Regulatory Liabilities
Current:
Overcollections of rate riders	$	3,311		$	24,019	Approximately 1 year⁽¹⁾
FTRs		4,393			4,150	Approximately 1 year⁽¹⁾
Total current regulatory liabilities	$	7,704		$	28,169
Long-term:
ARO and accrued asset removal costs	$	668,787		$	637,065	Not Applicable
Unamortized investment tax credit	1,507			2,451		Through 2021
Total long-term regulatory liabilities	$	670,294		$	639,516
Total regulatory liabilities	$	677,998		$	667,685

(1)

Recovered (credited) per specific rate orders

(2)

IPL receives a return on its discretionary funding

(3)

The majority of these costs are being recovered per specific rate order; recovery for the remaining costs is probable but timing not yet determined

(4)

Recovered with a current return

(5)

A portion of this amount will be recovered over the next two years

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Deferred Fuel

Unrecognized Pension and Postretirement Benefit Plan Costs

Income Taxes Recoverable Through Rates

Deferred MISO Costs

ARO and Accrued Asset Removal Costs

6. EQUITY

Paid In Capital and Capital Stock

On March 1, 2016, IPALCO issued and sold 7,403,213 shares of IPALCO’s common stock to CDPQ for $134.3 million under the Subscription Agreement. After completion of these transactions, CDPQ’s direct and indirect interest in IPALCO is approximately 30%. On June 1, 2016, IPALCO received equity capital contributions of $64.8 million from AES U.S. Investments and $13.9 million from CDPQ. IPALCO then made the same investments in IPL. The proceeds were primarily used for funding needs related to IPL’s environmental and replacement generation projects. The capital contributions on June 1, 2016 were made on a proportional share basis and, therefore, did not change CDPQ’s or AES’ ownership interests in IPALCO.

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All of the outstanding common stock of IPL is owned by IPALCO. IPL’s common stock is pledged under the 2018 IPALCO Notes and 2020 IPALCO Notes. There have been no changes in the capital stock of IPL during the three years ended December 31, 2016.

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. 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. As of December 31, 2016 and as of the filing of this report, IPL was in compliance with these restrictions.

IPL is also restricted in its ability to pay dividends if it is in default under the terms of its Credit Agreement and its unsecured notes, 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. As of December 31, 2016 and as of the filing of this report, IPL was in compliance with all covenants and no event of default existed.

Cumulative Preferred Stock

At December 31, 2016, 2015 and 2014, preferred stock consisted of the following:

	December 31, 2016			December 31,
	Shares Outstanding	Call Price		2016		2015		2014
	Shares Outstanding	Call Price		Par Value, plus premium, if applicable
				*(In Thousands)*
Cumulative $100 par value,
authorized 2,000,000 shares
4% Series	47,611	$	118.00	$	5,410	$	5,410	$	5,410
4.2% Series	19,331	103.00		1,933		1,933		1,933
4.6% Series	2,481	103.00		248		248		248
4.8% Series	21,930	101.00		2,193		2,193		2,193
5.65% Series	500,000	100.00		50,000		50,000		50,000
Total cumulative preferred stock	591,353			$	59,784	$	59,784	$	59,784

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7. DEBT

Long-Term Debt

The following table presents our long-term debt:

		December 31,
Series	Due	2016			2015
		*(In Thousands)*
IPL first mortgage bonds:
5.40%⁽¹⁾	August 2017	$	24,650		$	24,650
3.875%⁽²⁾	August 2021	55,000			55,000
3.875%⁽²⁾	August 2021	40,000			40,000
3.125%⁽²⁾	December 2024	40,000			40,000
6.60%	January 2034	100,000			100,000
6.05%	October 2036	158,800			158,800
6.60%	June 2037	165,000			165,000
4.875%	November 2041	140,000			140,000
4.65%	June 2043	170,000			170,000
4.50%	June 2044	130,000			130,000
4.70%	September 2045	260,000			260,000
4.05%	May 2046	350,000			—
Unamortized discount – net		(6,477		)	(4,242		)
Deferred financing costs⁽³⁾		(16,736		)	(13,703		)
Total IPL first mortgage bonds		1,610,237			1,265,505
IPL unsecured debt:
Variable⁽⁴⁾	December 2020	30,000			30,000
Variable⁽⁴⁾	December 2020	60,000			60,000
Deferred financing costs⁽³⁾		(456		)	—
Total IPL unsecured debt		89,544			90,000
Total Consolidated IPL Long-term Debt		1,699,781			1,355,505
Less: Current Portion of Long-term Debt		24,650			—
Net Consolidated IPL Long-term Debt		$	1,675,131		$	1,355,505

(1)

First mortgage bonds are issued to the city of Petersburg, Indiana, to secure the loan of proceeds from tax-exempt bonds issued by the city.

(2)

First mortgage bonds are issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority.

(3)

The Company adopted ASU No. 2015-03 on January 1, 2016, which requires the use of the full retrospective approach with respect to the presentation of debt issuance costs, including deferred charges.

(4)

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Debt Maturities

Maturities on long-term indebtedness subsequent to December 31, 2016, are as follows:

Year	Amount
	*(In Thousands)*
2017	$	24,650
2018	—
2019	—
2020	90,000
2021	95,000
Thereafter	1,513,800
Total	$	1,723,450

Significant Transactions

IPL First Mortgage Bonds and Recent Indiana Finance Authority Bond Issuances

In May 2016, IPL issued $350 million aggregate principal amount of first mortgage bonds, 4.05% Series, due May 2046, pursuant to Rule 144A and Regulation S under the Securities Act. Net proceeds from this offering were approximately $343.6 million, after deducting the initial purchasers’ discounts and fees and expenses for the offering. The net proceeds from this offering were used to finance a portion of IPL’s construction program and capital costs related to environmental and replacement generation projects, to repay outstanding borrowings under IPL’s 364-day delayed-draw term loan and other short-term debt, and for other general corporate purposes.

F-59

IPL Unsecured Notes

In October 2015, IPL entered into an unsecured $91.9 million 364-day committed credit facility with a delayed draw feature at variable rates with a syndication of banks. It was drawn on in October and December 2015 to fund the October 2015 termination of IPL’s $50 million accounts receivable securitization program and to assist in the December 2015 refunding of $41.9 million of IPL’s outstanding aggregate principal amount of 4.90% Environmental Facilities Refunding Revenue Bonds (Indianapolis Power & Light Company Project) Series 2009A due in January 2016. This agreement had a maturity date of October 14, 2016, with interest incurred at variable rates as described in the credit agreement. This credit facility contained customary representations, warranties and covenants, including a leverage covenant consistent with the leverage covenant contained in IPL’s Credit Agreement. In May 2016, IPL repaid $91.9 million in outstanding borrowings under its 364-day delayed-draw term loan with a portion of the proceeds from its$350 million aggregate principal amount of first mortgage bonds as described above in“IPL First Mortgage Bonds.”

Line of Credit

IPL entered into an amendment and restatement of its 5-year $250 million revolving credit facility in May 2014, and a further amendment and extension of the credit facility on October 16, 2015 (the “Credit Agreement”) with a syndication of banks. This Credit Agreement is an unsecured committed line of credit to be used: (i) to finance capital expenditures; (ii) to refinance indebtedness under the existing credit agreement; (iii) to support working capital; and (iv) for general corporate purposes. This agreement matures on October 16, 2020, and bears interest at variable rates as described in the Credit Agreement. It includes an uncommitted $150 million accordion feature to provide IPL with an option to request an increase in the size of the facility at any time prior to October 16, 2019, subject to approval by the lenders. Prior to execution, IPL had existing general banking relationships with the parties to the Credit Agreement. As of December 31, 2016 and 2015, IPL had $50.0 million and $75.0 million in outstanding borrowings on the committed line of credit, respectively.

Restrictions on Issuance of Debt

Credit Ratings

F-60

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. Pursuant to the terms of the Receivables Sale Agreement, the Purchasers agreed 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 took into account certain eligibility requirements and reserves relating to the receivables, or (2) $50 million. On October 16, 2015, IPL closed on a new unsecured $91.9 million 364-day committed credit facility with a syndication of banks. The first $50 million of the term loan was drawn at closing to fund the October 19, 2015 termination of IPL’s $50 million accounts receivable securitization program. Please see “IPL Unsecured Notes” above for details.

8. 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.

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. Beginning in 2010 and thereafter, the deduction is equal to 9% of the taxable income attributable to qualifying production activity. The tax benefit associated with the Internal Revenue Code Section 199 domestic production deduction for 2015 and 2014 was $1.7 million and $0.0 million, respectively. The benefit for 2016 is estimated to be $5.1 million.

F-61

Income Tax Provision

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

	2016			2015			2014
	*(In Thousands)*
Charged to utility operating expenses:
Current income taxes:
Federal	$	50,482		$	18,661		$	944
State	12,080			5,758			110
Total current income taxes	62,562			24,419			1,054
Deferred income taxes:
Federal	11,885			29,165			58,114
State	215			5,019			12,498
Total deferred income taxes	12,100			34,184			70,612
Net amortization of investment credit	(1,501		)	(1,319		)	(1,431		)
Total charge to utility operating expenses	73,161			57,284			70,235
Charged to other income and deductions:
Current income taxes:
Federal	(1,009		)	(1,715		)	329
State	(16		)	(240		)	69
Total current income taxes	(1,025		)	(1,955		)	398
Deferred income taxes:
Federal	552			740			(1,202		)
State	13			150			(148		)
Total deferred income taxes	565			890			(1,350		)
Net provision to other income and deductions	(460		)	(1,065		)	(952		)
Total federal and state income tax provisions	$	72,701		$	56,219		$	69,283

Effective and Statutory Rate Reconciliation

	2016		2015		2014
Federal statutory tax rate	35.0	%	35.0	%	35.0	%
State income tax, net of federal tax benefit	4.0	%	4.4	%	4.6	%
Amortization of investment tax credits	(0.7	)%	(0.8	)%	(0.8	)%
Depreciation flow through and amortization	(0.4	)%	(0.2	)%	(0.2	)%
Additional funds used during construction - equity	(3.2	)%	(1.9	)%	(0.2	)%
Manufacturers’ Production Deduction (Sec. 199)	(2.2	)%	(1.0	)%	—	%
Other – net	(0.8	)%	0.1	%	0.4	%
Effective tax rate	31.7	%	35.6	%	38.8	%

F-62

Deferred Income Taxes

The significant items comprising IPL’s net accumulated deferred tax liability recognized on the audited Consolidated Balance Sheets as of December 31, 2016 and 2015, are as follows:

	2016		2015
	*(In Thousands)*
Deferred tax liabilities:
Relating to utility property, net	$	569,204	$	541,369
Regulatory assets recoverable through future rates	180,608		178,187
Other	11,090		11,349
Total deferred tax liabilities	760,902		730,905
Deferred tax assets:
Investment tax credit	927		1,507
Regulatory liabilities including ARO	272,001		260,555
Employee benefit plans	27,358		38,159
Other	11,396		10,953
Total deferred tax assets	311,682		311,174
Deferred income taxes – net	$	449,220	$	419,731

Uncertain Tax Positions

The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2016, 2015 and 2014:

	2016			2015			2014
	*(In Thousands)*
Unrecognized tax benefits at January 1	$	7,147		$	7,042		$	6,734
Gross increases – current period tax positions	724			962			975
Gross decreases – prior period tax positions	(1,237		)	(857		)	(667		)
Unrecognized tax benefits at December 31	$	6,634		$	7,147		$	7,042

F-63

9. BENEFIT PLANS

Defined Contribution Plans

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

The Thrift Plan

The RSP

Defined Benefit Plans

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The following table presents information relating to the Pension Plans:

	Pension benefits as of December 31,
	2016			2015
	*(In Thousands)*
Change in benefit obligation:
Projected benefit obligation at January 1	$	723,887		$	748,421
Service cost	7,018			8,314
Interest cost	25,815			29,638
Actuarial loss (gain)	9,718			(31,989		)
Amendments (primarily increases in pension bands)	—			5,409
Settlements	—			(395		)
Benefits paid	(34,613		)	(35,511		)
Projected benefit obligation at December 31	731,825			723,887
Change in plan assets:
Fair value of plan assets at January 1	647,573			657,239
Actual return on plan assets	45,520			1,074
Employer contributions	15,950			25,166
Settlements	—			(395		)
Benefits paid	(34,613		)	(35,511		)
Fair value of plan assets at December 31	674,430			647,573
Unfunded status	$	(57,395	)	$	(76,314	)
Amounts recognized in the statement of financial position:
Noncurrent liabilities	$	(57,395	)	$	(76,314	)
Net amount recognized at end of year	$	(57,395	)	$	(76,314	)
Sources of change in regulatory assets⁽¹⁾:
Prior service cost arising during period	$	—		$	5,409
Net loss arising during period	7,690			11,757
Amortization of prior service cost	(5,183		)	(4,867		)
Amortization of loss	(13,896		)	(14,096		)
Total recognized in regulatory assets⁽¹⁾	$	(11,389	)	$	(1,797	)
Amounts included in regulatory assets⁽¹⁾:
Net loss	$	203,047		$	209,252
Prior service cost	20,658			25,842
Total amounts included in regulatory assets	$	223,705		$	235,094

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

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

	Pension benefits as of December 31,
	2016		2015
	*(In Thousands)*
Benefit obligation	$	731,825	$	723,887
Plan assets	674,430		647,573
Benefit obligation in excess of plan assets	$	57,395	$	76,314

IPL’s total benefit obligation in excess of plan assets was $57.4 million as of December 31, 2016 ($56.3 million Defined Benefit Pension Plan and $1.1 million Supplemental Retirement Plan).

F-65

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

	Pension benefits as of December 31,
	2016		2015
	*(In Thousands)*
Accumulated benefit obligation	$	720,901	$	712,297
Plan assets	674,430		647,573
Accumulated benefit obligation in excess of plan assets	$	46,471	$	64,724

Pension Benefits and Expense

F-66

	Pension benefits for years ended December 31,
	2016			2015			2014
	*(In Thousands)*
Components of net periodic benefit cost:
Service cost	$	7,018		$	8,314		$	7,231
Interest cost	25,815			29,638			31,154
Expected return on plan assets	(43,492		)	(44,819		)	(41,893		)
Amortization of prior service cost	5,183			4,867			4,853
Recognized actuarial loss	13,896			13,890			9,710
Recognized settlement loss	—			206			—
Total pension cost	8,420			12,096			11,055
Less: amounts capitalized	1,187			1,403			1,426
Amount charged to expense	$	7,233		$	10,693		$	9,629
Rates relevant to each year’s expense calculations:
Discount rate – defined benefit pension plan	4.42		%	4.06		%	4.92		%
Discount rate – supplemental retirement plan	4.19		%	3.82		%	4.64		%
Expected return on defined benefit pension plan assets	6.75		%	6.75		%	7.00		%
Expected return on supplemental retirement plan assets	6.75		%	6.75		%	7.00		%

Expected amortization

Pension Plan Assets and Fair Value Measurements

F-67

A description of the valuation methodologies used for each major class of assets and liabilities measured at fair value follows:

•

All the Plan’s investments have quoted market prices and are categorized as Level 1 in the fair value hierarchy.

•

The following table summarizes the Company’s target pension plan allocation for 2016:

Asset Category:	Target Allocations
Equity Securities	60%
Debt Securities	40%

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	Fair Value Measurements at
	December 31, 2016
	(in thousands)
			Quoted Prices in Active Markets for Identical Assets		Significant Observable Inputs
Asset Category	Total		(Level 1)		(Level 2)		%
Short-term investments	$	78	$	78	$	—	—	%
Mutual funds:
U.S. equities	329,877		329,877		—		49	%
International equities	58,833		58,833		—		9	%
Fixed income	230,926		230,926		—		34	%
Fixed income securities:
U.S. Treasury securities	54,716		54,716		—		8	%
Total	$	674,430	$	674,430	$	—	100	%

	Fair Value Measurements at
	December 31, 2015
	(in thousands)
			Quoted Prices in Active Markets for Identical Assets		Significant Observable Inputs
Asset Category	Total		(Level 1)		(Level 2)		%
Short-term investments	$	176	$	176	$	—	—	%
Mutual funds:
U.S. equities	318,368		318,368		—		49	%
International equities	60,751		60,751		—		10	%
Fixed income	215,325		215,325		—		33	%
Fixed income securities:
U.S. Treasury securities	52,953		52,953		—		8	%
Total	$	647,573	$	647,573	$	—	100	%

F-69

Pension Funding

Year	Pension Benefits
	*(In Thousands)*
2017	$	39,624
2018	41,043
2019	42,527
2020	43,745
2021	45,084
2022 through 2026	235,759

10. COMMITMENTS AND CONTINGENCIES

Legal Loss Contingencies

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 and cash flows. Amounts accrued or expensed for legal or environmental contingencies collectively during the periods covered by this report have not been material to IPL’s audited consolidated financial statements.

Environmental Loss Contingencies

New Source Review

F-70

Settlements and litigated outcomes of similar New Source Review 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 these cases could have a material impact on our business. It is too early to determine whether these NOVs could have a material impact on our business, financial condition or results of operations. We would seek recovery of any operating or capital expenditures, but not fines or penalties, related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that we would be successful in this regard. IPL has recorded a contingent liability related to these New Source Review and other CAA NOV matters.

11. 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 $3.1 million, $2.7 million, and $3.2 million in 2016, 2015 and 2014, respectively, and is recorded in “Other operating expenses” on the accompanying Consolidated Statements of Operations. As of December 31, 2016 and 2015, we had prepaid approximately $2.0 million and $2.2 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 $23.2 million, $24.5 million, and $20.1 million in 2016, 2015 and 2014, respectively, and is recorded in “Other operating expenses” on the accompanying Consolidated Statements of Operations. We had no prepaids for coverage under this plan as of December 31, 2016 and 2015, respectively.

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 payable and receivable balance under this agreement of $1.0 million and $2.8 million as of December 31, 2016 and 2015, respectively, which is recorded in “Accrued income taxes”and “Prepayments and other current assets” on the accompanying Consolidated Balance Sheets, respectively.

F-71

Long-term Compensation Plan

During 2016, 2015 and 2014, 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, however no stock options were granted in 2016. Total deferred compensation expense recorded during 2016, 2015 and 2014 was $0.9 million, $0.7 million and $0.7 million, respectively, and was included in “Other operating expenses” on IPL’s Consolidated Statements of Operations. 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 Note 9,“Benefit Plans” to the audited consolidated financial statements of IPL for a description of benefits awarded to IPL employees by AES under the RSP.

Service Company

Total costs incurred by the Service Company on behalf of IPL were $26.9 million, $22.6 million and $22.0 million during 2016, 2015 and 2014, respectively. Total costs incurred by IPL on behalf of the Service Company during 2016, 2015 and 2014 were $9.2 million, $7.5 million and $5.6 million, respectively. IPL had a prepaid balance with the Service Company of $3.4 million and $1.2 million as of December 31, 2016 and 2015, respectively.

Other

In 2014, IPL engaged a third party vendor as part of its replacement generation construction projects. A member of the AES Board of Directors is also currently a member of the Supervisory Board of this vendor. IPL had billings from this vendor of $198.5 million, $232.0 million and $80.3 million during 2016, 2015 and 2014, respectively. IPL had a payable balance to this vendor of $2.3 million and $34.0 million as of December 31, 2016 and 2015, respectively.

Additionally, transactions with various other related parties were $3.9 million, $2.4 million and $1.1 million as of December 31, 2016, 2015 and 2014, respectively. These expenses were primarily recorded in “Other operating expenses” on the accompanying Consolidated Statements of Operations.

12. BUSINESS 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.

F-72

IPALCO ENTERPRISES, INC. and SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Operations

(In Thousands)

	Three Months Ended,						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016

UTILITY OPERATING REVENUES	$	355,314		$	361,339		$	1,014,048		$	1,012,373

UTILITY OPERATING EXPENSES:
Fuel	77,061			80,451			210,521			200,115
Other operating expenses	62,776			59,548			188,288			178,991
Power purchased	44,470			39,464			141,058			132,333
Maintenance	29,706			25,918			96,032			92,919
Depreciation and amortization	52,711			54,876			156,099			166,027
Taxes other than income taxes	11,804			11,779			33,640			34,317
Income taxes - net	23,049			29,457			53,189			63,290
Total utility operating expenses	301,577			301,493			878,827			867,992
UTILITY OPERATING INCOME	53,737			59,846			135,221			144,381

OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used during construction	6,628			7,077			19,576			20,454
Loss on early extinguishment of debt	(8,875		)	—			(8,875		)	—
Miscellaneous income and (deductions) - net	(185		)	(299		)	(728		)	(1,433		)
Income tax benefit applicable to nonoperating income	8,308			4,485			15,492			10,748
Total other income and (deductions) - net	5,876			11,263			25,465			29,769

INTEREST AND OTHER CHARGES:
Interest on long-term debt	30,575			29,018			89,077			82,571
Other interest	466			367			1,263			1,730
Allowance for borrowed funds used during construction	(5,702		)	(6,549		)	(16,763		)	(18,007		)
Amortization of redemption premiums and expense on debt	1,081			1,017			3,241			3,123
Total interest and other charges - net	26,420			23,853			76,818			69,417
NET INCOME	33,193			47,256			83,868			104,733

LESS: PREFERRED DIVIDENDS OF SUBSIDIARY	803			803			2,410			2,410
NET INCOME APPLICABLE TO COMMON STOCK	$	32,390		$	46,453		$	81,458		$	102,323

See notes to unaudited condensed consolidated financial statements.

F-73

IPALCO ENTERPRISES, INC. and SUBSIDIARIES

Unaudited Condensed Consolidated Balance Sheets

(In Thousands)

	September 30,			December 31,
	2017			2016
ASSETS
UTILITY PLANT:
Utility plant in service	$	5,342,196		$	4,997,846
Less accumulated depreciation	2,110,899			2,030,497
Utility plant in service - net	3,231,297			2,967,349
Construction work in progress	703,231			898,330
Spare parts inventory	14,428			14,237
Property held for future use	1,002			1,002
Utility plant - net	3,949,958			3,880,918
OTHER ASSETS:
Nonutility property - at cost, less accumulated depreciation	504			512
Intangible assets - net	10,812			11,976
Other long-term assets	6,005			5,916
Other assets - net	17,321			18,404
CURRENT ASSETS:
Cash and cash equivalents	26,327			34,953
Accounts receivable and unbilled revenue (less allowance
for doubtful accounts of $2,842 and $2,365, respectively)	151,951			154,586
Fuel inventories - at average cost	34,162			30,237
Materials and supplies - at average cost	61,139			60,648
Regulatory assets	32,784			33,912
Prepayments and other current assets	30,964			33,504
Total current assets	337,327			347,840
DEFERRED DEBITS:
Regulatory assets	436,956			450,710
Miscellaneous	4,224			4,409
Total deferred debits	441,180			455,119
TOTAL	$	4,745,786		$	4,702,281
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common shareholders' equity:
Paid in capital	$	597,296		$	596,810
Accumulated deficit	(19,645		)	(25,627		)
Total common shareholders' equity	577,651			571,183
Cumulative preferred stock of subsidiary	59,784			59,784
Long-term debt (Note 5)	2,477,051			2,474,840
Total capitalization	3,114,486			3,105,807
CURRENT LIABILITIES:
Short-term and current portion of long-term debt (Note 5)	120,500			74,650
Accounts payable	107,809			119,511
Accrued expenses	23,196			18,754
Accrued real estate and personal property taxes	21,951			18,930
Regulatory liabilities	5,181			7,704
Accrued income taxes	3,054			—
Accrued interest	35,492			32,541
Customer deposits	30,600			29,780
Other current liabilities	10,451			19,467
Total current liabilities	358,234			321,337
DEFERRED CREDITS AND OTHER LONG-TERM LIABILITIES:
Regulatory liabilities	690,363			670,294
Deferred income taxes - net	445,539			449,730
Non-current income tax liability	6,687			6,634
Unamortized investment tax credit	1,376			2,410
Accrued pension and other postretirement benefits	48,310			64,139
Asset retirement obligations	80,077			80,568
Miscellaneous	714			1,362
Total deferred credits and other long-term liabilities	1,273,066			1,275,137
COMMITMENTS AND CONTINGENCIES (Note 8)
TOTAL	$	4,745,786		$	4,702,281

See notes to unaudited condensed consolidated financial statements.

F-74

IPALCO ENTERPRISES, INC. and SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Cash Flows

(In Thousands)

	Nine Months Ended
	September 30,
	2017			2016
CASH FLOWS FROM OPERATIONS:
Net income	$	83,868		$	104,733
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	156,103			166,031
Amortization of deferred financing costs and debt premium	3,241			3,123
Deferred income taxes and investment tax credit adjustments - net	(14,546		)	15,680
Loss on early extinguishment of debt	8,875			—
Allowance for equity funds used during construction	(19,576		)	(20,125		)
Change in certain assets and liabilities:
Accounts receivable	2,635			(29,864		)
Fuel, materials and supplies	(4,626		)	31,705
Income taxes receivable or payable	5,143			12,163
Financial transmission rights	(788		)	(3,279		)
Accounts payable and accrued expenses	(10,864		)	(1,306		)
Accrued real estate and personal property taxes	3,020			4,456
Accrued interest	2,951			11,354
Pension and other postretirement benefit expenses	(15,828		)	(23,573		)
Short-term and long-term regulatory assets and liabilities	21,183			(26,623		)
Prepaids and other current assets	156			(2,802		)
Other - net	(4,841		)	7,395
Net cash provided by operating activities	216,106			249,068
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures - utility	(163,714		)	(516,895		)
Project development costs	(1,315		)	(852		)
Cost of removal, net of salvage	(7,523		)	(10,881		)
Other	(2,957		)	(1,525		)
Net cash used in investing activities	(175,509		)	(530,153		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt borrowings	126,500			248,000
Short-term debt repayments	(80,650		)	(389,850		)
Long-term borrowings, net of discount	404,633			347,662
Retirement of long-term debt, including early payment premium	(408,152		)	—
Dividends on common stock	(75,476		)	(86,443		)
Issuance of common stock	—			134,276
Equity contributions from shareholders	—			78,738
Preferred dividends of subsidiary	(2,410		)	(2,410		)
Deferred financing costs paid	(3,652		)	(3,964		)
Payments for financed capital expenditures	(9,788		)	(14,990		)
Other	(228		)	(152		)
Net cash (used in) provided by financing activities	(49,223		)	310,867
Net change in cash and cash equivalents	(8,626		)	29,782
Cash and cash equivalents at beginning of period	34,953			21,521
Cash and cash equivalents at end of period	$	26,327		$	51,303

Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized)	$	70,395		$	54,911
Income taxes	$	47,100		$	24,700
	As of September 30,
	2017			2016
Non-cash investing activities:
Accruals for capital expenditures	$	33,184		$	37,357

See notes to unaudited condensed consolidated financial statements.

F-75

IPALCO ENTERPRISES, INC. and SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements

1. OVERVIEW AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

IPALCO is a holding company incorporated under the laws of the state of Indiana. IPALCO, acquired by AES in March 2001, is owned by AES U.S. Investments (82.35%) and CDPQ (17.65%). AES U.S. Investments is owned by AES U.S. Holdings, LLC (85%) and CDPQ (15%). IPALCO owns all of the outstanding common stock of IPL. Substantially all of IPALCO’s business consists of generating, transmitting, distributing and selling of electric energy conducted through its principal subsidiary, IPL. IPL was incorporated under the laws of the state of Indiana in 1926. IPL has approximately 490,000 retail customers in the city of Indianapolis and neighboring cities, towns and communities, and adjacent rural areas all within the state of Indiana, with 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 four generating stations, all within the state of Indiana. IPL’s largest generating station, Petersburg, is coal-fired. The second largest station, Harding Street, has converted its coal-fired units to natural gas and uses natural gas and fuel oil to power combustion turbines. In addition, IPL began the operation of a 20 MW battery energy storage unit at this location in May 2016, which provides frequency response. The third station, Eagle Valley, retired its coal-fired units in April 2016. The CCGT at Eagle Valley is expected to be completed in the first half of 2018 with a rated output of 671 MW. The fourth station, Georgetown, is a small peaking station that uses natural gas to power combustion turbines. As of September 30, 2017, IPL’s net electric generation capacity for winter is 2,996 MW and net summer capacity is 2,881 MW.

Principles of Consolidation

The accompanying Financial Statements include the accounts of IPALCO, IPL and Mid-America Capital Resources, Inc., a non-regulated wholly-owned subsidiary of IPALCO. All significant intercompany amounts have been eliminated. The accompanying Financial Statements are unaudited; however, they have been prepared in accordance with GAAP for interim financial information and in conjunction with the rules and regulations of the SEC. Accordingly, they do not include all of the disclosures required by GAAP for annual fiscal reporting periods. In the opinion of management, all adjustments of a normal recurring nature necessary for fair presentation have been included. 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. These unaudited Financial Statements have been prepared in accordance with the accounting policies described in IPALCO’s 2016 Form 10-K and should be read in conjunction therewith.

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 that 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.

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New Accounting Pronouncements

The following table provides a brief description of recent accounting pronouncements that had or may have a material impact on the Company’s Financial Statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or are expected to have no material impact on the Company’s Financial Statements.

New Accounting Standards Adopted
ASU Number and Name	Description	Date of Adoption	Effect on the financial statements upon adoption
2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting	The standard simplifies the following aspects of accounting for share-based payments awards: accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: The recognition of excess tax benefits and tax deficiencies arising from vesting or settlement were applied retrospectively. The elimination of the requirement that excess tax benefits be realized before they are recognized was adopted on a modified retrospective basis with a cumulative adjustment to the opening balance sheet.	January 1, 2017	The primary effect of adoption was the recognition of excess tax benefits in our provision for income taxes in the period when the awards vest or are settled, rather than in paid-in-capital in the period when the excess tax benefits are realized. We will continue to estimate the number of awards that are expected to vest in our determination of the related periodic compensation cost. The adoption of this standard did not have a material impact on the consolidated financial statements.
New Accounting Standards Issued But Not Yet Effective
ASU Number and Name	Description	Date of Adoption	Effect on the financial statements upon adoption
2017-08, Receivables - Nonrefundable Fees and Other Costs (Subtopic 310-20): Premium Amortization on Purchased Callable Debt Securities	This standard shortens the period of amortization of the premium on certain callable debt securities to the earliest call date. Transition method: modified retrospective.	January 1, 2019. Early adoption is permitted.	The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.
2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost	This standard changes the presentation of non-service cost expense associated with defined benefit plans and updates the guidance so that only the service cost component will be eligible for capitalization. Transition method: Prospective for presentation of non-service cost expense. Retrospective for the change in capitalization.	January 1, 2018. Early adoption is permitted.	The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements and does not plan to early adopt.
2017-05, Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Topic 610-20)	This standard clarifies the scope and application of ASC 610-20 on the sale, transfer, and derecognition of nonfinancial assets and in substance nonfinancial assets to non-customers, including partial sales. It also clarifies that the derecognition of business is under scope of ASC 810. Transition method: full or modified retrospective. The Company is in the process of identifying contracts that would not be completed as of January 1, 2018. Based on the assessment of contracts already executed as of September 30, 2017, the contracts that may require any type of assessment under the new standard is limited.	January 1, 2018. Earlier application is permitted only as of January 1, 2017.	The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements. The Company will adopt the standard on January 1, 2018 and plans to use the modified retrospective approach.
2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force)	This standard requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. Transition method: retrospective.	January 1, 2018 Early adoption is permitted.	The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.
2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires that an entity recognizes the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. Transition method: modified retrospective.	January 1, 2018 Early adoption is permitted.	The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.
2016-13, Financial Instruments -Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments	The standard updates the impairment model for financial assets measured at amortized cost to an expected loss model rather than an incurred loss model. It also allows for the presentation of credit losses on available-for-sale debt securities as an allowance rather than a write down. Transition method: various.	January 1, 2020 Early adoption is permitted only as of January 1, 2019.	The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.

F-77

2016-02, Leases (Topic 842)

This standard requires lesses to recognize assets and liabilities for most leases but recognize expenses in a manner similar to today's accounting. For Lessors, the guidance modifies the lease classification criteria and the accounting for sales-type and direct financing leases. The guidance also eliminates today’s real estate-specific provisions. Transition method: modified retrospective at the beginning of the earliest comparative period presented in the financial statements (January 1, 2017).

The Company has established a task force focused on the identification of contracts that would be under the scope of the new standard and on the assessment and measurement of the right-of-use asset and related liability. The implementation team is in the process of evaluating changes to our business processes, systems and controls to support recognition and disclosure under the new standard.

January 1, 2019. Early adoption is permitted.

The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements. The Company intends to adopt the standard as of January 1, 2019.

2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-13, Revenue from Contracts with Customers (Topic

606)

See discussion of this ASU below:

January 1, 2018. Earlier application is permitted only as of January 1, 2017.

The Company will adopt the standard on January 1, 2018; see below for the evaluation of the impact of its adoption on the consolidated financial statements.

In 2016, the Company established a cross-functional implementation team and is in the process of evaluating and implementing changes to our business processes, systems and controls to support recognition and disclosure under the new standard. At this time, we do not expect any significant impact on our financial systems or a material change to controls as a result of the implementation of the new revenue recognition standard.

The Company is assessing the standard on a contract-by-contract basis and is in the process of completing the contract assessments by applying the interpretations issued during 2017 on key issues. These issues include the application of the practical expedient for measuring progress towards satisfaction of a performance obligation, when variable quantities would be considered variable consideration versus an option to acquire additional goods and services and how to allocate variable consideration to one or more, but not all, distinct goods or services promised in a series of distinct goods or services that forms part of a single performance obligation. Additionally, the Company is working on the application of the standard to contracts that are under the scope of Service Concession Arrangements (Topic 853) and assessing the gross versus net presentation for spot energy sale and purchases. Through this assessment to date, the Company has not identified any situations where revenue recognized under ASC 606 could differ from that recognized under ASC 605 or where the presentation of sales to and purchases from the spot markets will change. The Company will continue its work to complete the assessment of the full population of contracts and determine the overall impact to the consolidated financial statements.

The standard requires retrospective application and allows either a full retrospective adoption in which all periods are presented under the new standard or a modified retrospective approach in which the cumulative effect of initially applying the guidance is recognized at the date of initial application. Although we had previously been working toward adopting the standard using the full retrospective method, given the limited situations we have thus far determined where revenue recognized under ASC 606 differs from that recognized under ASC 605, we now expect to use the modified retrospective approach. However, the Company will continue to assess this conclusion which is dependent on the final impact to the Financial Statements.

We are continuing to work with various non-authoritative industry groups, and monitoring the FASB and Transition Resource Group activity, as we finalize our accounting policy on these and other industry specific interpretative issues, which is expected in 2017.

F-78

2. REGULATORY MATTERS

Basic Rates and Charges

In March 2016, the IURC issued the 2016 Rate Order authorizing IPL to increase its basic rates and charges by $30.8 million annually. The order also authorized IPL to collect, over a ten year period, $117.7 million of previously deferred regulatory assets related to IPL’s participation in the regional transmission organization known as MISO. Such deferred costs are amortized to expense over ten years. Accordingly, $11.8 million of IPL’s long-term MISO regulatory asset is included within current regulatory assets on the accompanying Unaudited Condensed Consolidated Balance Sheets. The rate order also authorized an increase in IPL’s depreciation rates of $24.3 million annually compared to the twelve months ended June 30, 2014, which is the period upon which the rate increase was calculated. IPL also received approval to implement three new rate riders for current recovery from customers of ongoing MISO costs and capacity costs, and for sharing with customers 50% of wholesale sales margins above and below the established annual benchmark of $6.3 million. Additionally, the capacity rider provides that IPL will share with customers 50% of any capacity sales. The order approved recovery of IPL’s pension expenses and a return on IPL’s discretionary pension fundings. While the IURC noted in the order that they found IPL’s Service Company cost allocations to be reasonable, IPL was directed to request the FERC to review its Service Company allocations. In September 2017, the FERC completed its review, authorizing the Service Company’s allocation of costs of non-power goods and services to IPL. In the 2016 Rate Order, the IURC also closed their investigation into IPL’s underground network.

Some of the intervening parties in the IURC rate case filed petitions for reconsideration of the IURC’s 2016 Rate Order with respect to certain issues. These petitions were subsequently denied by the IURC. In addition, certain intervening parties filed notices of appeal of the order. On April 5, 2017, the Indiana Court of Appeals affirmed the IURC’s 2016 Rate Order.

On December 22, 2016, IPL filed a petition with the IURC for authority to increase its basic rates and charges primarily to recover the cost of the new CCGT. The CCGT was previously expected to be completed in the first half of 2017, but is now expected to be completed in the first half of 2018. To address this change, on February 24, 2017, IPL filed a motion to withdraw the case without prejudice or alternatively amend the petition and case-in-chief at a later date. On March 15, 2017, the IURC dismissed the rate case without prejudice. IPL expects to file a new base rate case with the IURC to coincide with the completion of the CCGT.

CCR

NAAQS

On April 26, 2017, the IURC approved IPL’s request for NAAQS SO2 compliance at its Petersburg generation station with 80% of qualifying costs recovered through a rate adjustment mechanism and the remainder recorded as a regulatory asset for recovery in a subsequent rate case. The approved capital cost of the NAAQS SO2 compliance plan is approximately $29 million.

F-79

3. FAIR VALUE

Fair Value Hierarchy

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

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

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

As of September 30, 2017 and December 31, 2016, all of IPALCO’s financial assets or liabilities adjusted to fair value on a recurring basis (excluding pension assets – see Note 7, “Benefit Plans”) were considered Level 3, based on the above fair value hierarchy. These primarily consisted of FTRs, which are used to offset MISO congestion charges. Because the benefit associated with FTRs is a flow-through to IPL’s jurisdictional customers, IPL records a regulatory liability matching the value of the FTRs. In addition, IPALCO had one financial asset, a nonutility investment accounted for using the cost method of accounting, which is measured at fair value on a non-recurring basis, again using Level 3 measurements. All of these financial assets and liabilities were not material to the Financial Statements in the periods covered by this report, individually or in the aggregate.

Non-Recurring Fair Value Measurements

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 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. IPL’s ARO liabilities relate primarily to environmental issues involving asbestos-containing materials, ash ponds, landfills and miscellaneous contaminants associated with its generating plants, transmission system and distribution system. We use the cost approach to determine the fair value of IPL’s ARO liabilities, which is estimated by discounting expected cash outflows to their present value at the initial recording of the liabilities. Cash outflows are based on the approximate future disposal costs as determined by market information, historical information or other management estimates. These inputs to the fair value of the ARO liabilities would be considered Level 3 inputs under the fair value hierarchy. As of September 30, 2017 and December 31, 2016, ARO liabilities were $80.1 million and $80.6 million, respectively.

Financial Instruments not Measured at Fair Value in the Consolidated Balance Sheets

Debt

F-80

The following table shows the face value and the fair value of fixed-rate and variable-rate indebtedness (Level 2) for the periods ending:

	September 30, 2017				December 31, 2016
	Face Value		Fair Value		Face Value		Fair Value
	*(In Millions)*
Fixed-rate	$	2,418.8	$	2,609.3	$	2,438.5	$	2,543.5
Variable-rate	210.5		210.5		140.0		140.0
Total indebtedness	$	2,629.3	$	2,819.8	$	2,578.5	$	2,683.5

The difference between the face value and the carrying value of this indebtedness represents the following:

•

unamortized deferred financing costs of $24.8 million and $22.2 million at September 30, 2017 and December 31, 2016, respectively; and

•

unamortized discounts of $6.9 million and $6.8 million at September 30, 2017 and December 31, 2016, respectively.

4. EQUITY

On March 1, 2016, IPALCO issued and sold 7,403,213 shares of IPALCO’s common stock to CDPQ for $134.3 million under the Subscription Agreement. After completion of these transactions, CDPQ’s direct and indirect interests in IPALCO total approximately 30%. On June 1, 2016, IPALCO received equity capital contributions of $64.8 million from AES U.S. Investments and $13.9 million from CDPQ. IPALCO then made the same investments in IPL. The proceeds were primarily used for funding needs related to IPL’s environmental and replacement generation projects. The capital contributions on June 1, 2016 were made on a proportional share basis and, therefore, did not change CDPQ’s or AES’ ownership interests in IPALCO.

F-81

5. DEBT

Long-Term Debt

The following table presents our long-term debt:

		September 30,			December 31,
Series	Due	2017			2016
		*(In Thousands)*
IPL first mortgage bonds:
5.40%⁽¹⁾	August 2017	$	—		$	24,650
3.875%⁽²⁾	August 2021	55,000			55,000
3.875%⁽²⁾	August 2021	40,000			40,000
3.125%⁽²⁾	December 2024	40,000			40,000
6.60%	January 2034	100,000			100,000
6.05%	October 2036	158,800			158,800
6.60%	June 2037	165,000			165,000
4.875%	November 2041	140,000			140,000
4.65%	June 2043	170,000			170,000
4.50%	June 2044	130,000			130,000
4.70%	September 2045	260,000			260,000
4.05%	May 2046	350,000			350,000
Unamortized discount – net		(6,384		)	(6,477		)
Deferred financing costs		(16,275		)	(16,736		)
Total IPL first mortgage bonds		1,586,141			1,610,237
IPL unsecured debt:
Variable⁽³⁾	December 2020	30,000			30,000
Variable⁽³⁾	December 2020	60,000			60,000
Deferred financing costs		(372		)	(456		)
Total IPL unsecured debt		89,628			89,544
Total Long-term Debt – IPL		1,675,769			1,699,781
Long-term Debt – IPALCO:
5.00% Senior Secured Notes	May 2018	—			400,000
3.45% Senior Secured Notes	July 2020	405,000			405,000
3.70% Senior Secured Notes	September 2024	405,000			—
Unamortized discount – net		(559		)	(273		)
Deferred financing costs		(8,159		)	(5,018		)
Total Long-term Debt – IPALCO		801,282			799,709
Total Consolidated IPALCO Long-term Debt		2,477,051			2,499,490
Less: Current Portion of Long-term Debt		—			24,650
Net Consolidated IPALCO Long-term Debt		$	2,477,051		$	2,474,840

(1)

First mortgage bonds issued to the city of Petersburg, Indiana, to secure the loan proceeds from various tax-exempt bonds issued by the city. IPL repaid these first mortgage bonds on August 1, 2017.

(2)

First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority.

(3)

Unsecured notes issued to the Indiana Finance Authority by IPL to facilitate the loan of proceeds from various tax-exempt notes issued by the Indiana Finance Authority. The notes have a final maturity date of December 2038, but are subject to a mandatory put in December 2020.

F-82

IPALCO’s Senior Secured Notes

In August 2017, IPALCO completed the sale of the $405 million 2024 IPALCO Notes pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended. The 2024 IPALCO Notes were issued pursuant to an Indenture dated August 22, 2017, by and between IPALCO and U.S. Bank, National Association, as trustee. The 2024 IPALCO Notes were priced to the public at 99.901% of the principal amount. Net proceeds to IPALCO were approximately $399.3 million after deducting underwriting costs and estimated offering expenses. These costs are being amortized to the maturity date using the effective interest method. We used the net proceeds from this offering, together with cash on hand, to redeem the $400 million 2018 IPALCO Notes on September 21, 2017, and to pay certain related fees, expenses and make-whole premiums. A loss on early extinguishment of debt of $8.9 million for the 2018 IPALCO Notes is included as a separate line item within Other Income and (Deductions) in the accompanying Unaudited Condensed Consolidated Statements of Operations.

The 2024 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 also agreed to register the 2024 IPALCO Notes under the Securities Act by filing an exchange offer registration statement or, under specified circumstances, a shelf registration statement with the SEC pursuant to a Registration Rights Agreement that IPALCO entered into with Morgan Stanley & Co. LLC and PNC Capital Markets LLC, as representatives of the initial purchasers of the 2024 IPALCO Notes, dated August 22, 2017.

Line of Credit

As of September 30, 2017 and December 31, 2016, IPL had $120.5 million and $50.0 million in outstanding borrowings on the committed line of credit, respectively.

6. INCOME TAXES

IPALCO’s effective combined state and federal income tax rates were 31.3% and 31.6% for the three and nine months ended September 30, 2017, respectively, as compared to 35.0% and 33.9% for the three and nine months ended September 30, 2016, respectively. The decrease in the effective tax rates versus the comparable periods was primarily due to the manufacturer’s production deduction (Internal Revenue Code Section 199) that had been previously limited due to a Net Operating Loss carryover, and the allowance for equity funds used during construction as a percentage of pretax income.

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7. BENEFIT PLANS

The following table (in thousands) presents information for the nine months ended September 30, 2017, relating to the Pension Plans:

Net unfunded status of plans:
Net unfunded status at December 31, 2016, before tax adjustments	$	(57,395	)
Net benefit cost components reflected in net unfunded status during first quarter:
Service cost	(1,836		)
Interest cost	(6,327		)
Expected return on assets	11,167
Actuarial valuation adjustment	80
Employer contributions	7,211
Net unfunded status at March 31, 2017, before tax adjustments	$	(47,100	)
Net benefit cost components reflected in net unfunded status during second quarter:
Service cost	(1,836		)
Interest cost	(6,326		)
Expected return on assets	11,168
Net unfunded status at June 30, 2017, before tax adjustments	$	(44,094	)
Net benefit cost components reflected in net unfunded status during third quarter:
Service cost	(1,836		)
Interest cost	(6,326		)
Expected return on assets	11,168
Net unfunded status at September 30, 2017, before tax adjustments	$	(41,088	)

Regulatory assets related to pensions⁽¹⁾:
Regulatory assets at December 31, 2016, before tax adjustments	$	223,705
Amount reclassified through net benefit cost:
Amortization of prior service cost	(1,060		)
Amortization of net actuarial loss	(3,300		)
Settlements⁽²⁾	(146		)
Actuarial valuation adjustment	(80		)
Regulatory assets at March 31, 2017, before tax adjustments	$	219,119
Amount reclassified through net benefit cost:
Amortization of prior service cost	(1,060		)
Amortization of net actuarial loss	(3,299		)
Regulatory assets at June 30, 2017, before tax adjustments	$	214,760
Amount reclassified through net benefit cost:
Amortization of prior service cost	(1,060		)
Amortization of net actuarial loss	(3,298		)
Regulatory assets at September 30, 2017, before tax adjustments	$	210,402

(1)

Amounts that would otherwise be charged/credited to Accumulated Other Comprehensive Income or Loss upon application of ASC 715, “Compensation – Retirement Benefits,” are recorded as a regulatory asset or liability because IPL has historically recovered and currently recovers pension and other postretirement benefit expenses in rates. These are unrecognized amounts not yet recognized as components of net periodic benefit costs.

(2)

The settlement loss of $0.1 million for the three months ended March 31, 2017 was the result of a lump sum distribution paid out of the Supplemental Retirement Plan.

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Pension Expense

The following table presents net periodic benefit cost information relating to the Pension Plans combined:

	For the Three Months Ended,						For the Nine Months Ended,
	September 30,						September 30,
	2017			2016			2017			2016
	*(In Thousands)*						*(In Thousands)*
Components of net periodic benefit cost:
Service cost	$	1,836		$	1,754		$	5,508		$	5,263
Interest cost	6,326			6,454			18,979			19,362
Expected return on plan assets	(11,168		)	(10,873		)	(33,503		)	(32,620		)
Amortization of prior service cost	1,060			1,296			3,180			3,888
Amortization of actuarial loss	3,298			3,474			9,897			10,422
Settlements	—			—			146			—
Net periodic benefit cost	$	1,352		$	2,105		$	4,207		$	6,315

In addition, IPL provides postretirement health care benefits to certain active or retired employees and the spouses of certain active or retired employees. These postretirement health care benefits and the related unfunded obligation of $7.3 million and $6.8 million at September 30, 2017 and December 31, 2016, respectively, were not material to the Financial Statements in the periods covered by this report.

8. COMMITMENTS AND CONTINGENCIES

Legal Loss Contingencies

Environmental Loss Contingencies

New Source Review and Other CAA NOVs

In October 2009, IPL received a 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 at the time, dating back to 1986. The alleged violations primarily pertain to the PSD and nonattainment New Source Review requirements under the CAA. In addition, on October 1, 2015, IPL received a NOV from the EPA pursuant to CAA Section 113(a) alleging violations of the CAA, the Indiana SIP, and the Title V operating permit related to alleged particulate matter and opacity violations at IPL Petersburg Unit 3. Also, on February 5, 2016, the EPA issued a NOV pursuant to CAA Section 113(a) alleging violations of New Source Review and other CAA regulations, the Indiana SIP, and the Title V operating permit at Petersburg Generating Station. Since receiving the letters, IPL management has met with the EPA staff regarding possible resolutions of the NOVs. Settlements and litigated outcomes of similar New Source Review 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 these cases could have a material impact on our business. It is too early to determine whether these NOVs could have a material impact on our business, financial condition or results of operations. We would seek recovery of any operating or capital expenditures, but not fines or penalties, related to air pollution control

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technology to reduce regulated air emissions; however, there can be no assurances that we would be successful in this regard. IPL has recorded a contingent liability related to these New Source Review cases and other CAA NOV matters.

9. SEGMENT INFORMATION

Operating segments are components of an enterprise that engage in business activities from which it may earn revenues and incur expenses, 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 segment is its utility segment, with all other nonutility business activities aggregated separately. The nonutility category primarily includes the 2018 IPALCO Notes, the 2020 IPALCO Notes and the 2024 IPALCO Notes; approximately $9.2 million and $8.3 million of cash and cash equivalents as of September 30, 2017 and December 31, 2016, respectively; long-term investments of $4.9 million and $5.2 million at September 30, 2017 and December 31, 2016, respectively; and income taxes and interest related to those items. All other assets represented less than 1% of IPALCO’s total assets as of September 30, 2017 and December 31, 2016. Net income for the utility segment was $105.5 million and $122.0 million for the nine-month periods ended September 30, 2017 and 2016, respectively, and $43.8 million and $51.9 million for the three-month periods ended September 30, 2017 and 2016, respectively. The accounting policies of the identified segment 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.

F-86

INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY

Unaudited Condensed Consolidated Statements of Operations

(In Thousands)

	Three Months Ended,						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016

UTILITY OPERATING REVENUES	$	355,314		$	361,339		$	1,014,048		$	1,012,373

UTILITY OPERATING EXPENSES:
Fuel	77,061			80,451			210,521			200,115
Other operating expenses	62,776			59,548			188,288			178,991
Power purchased	44,470			39,464			141,058			132,333
Maintenance	29,706			25,918			96,032			92,919
Depreciation and amortization	52,711			54,876			156,099			166,027
Taxes other than income taxes	11,804			11,779			33,640			34,317
Income taxes - net	23,049			29,457			53,189			63,290
Total utility operating expenses	301,577			301,493			878,827			867,992
UTILITY OPERATING INCOME	53,737			59,846			135,221			144,381

OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used during construction	6,628			7,077			19,576			20,454
Miscellaneous income and (deductions) - net	(328		)	(264		)	(988		)	(648		)
Income tax benefit applicable to nonoperating income	109			107			363			291
Total other income and (deductions) - net	6,409			6,920			18,951			20,097

INTEREST AND OTHER CHARGES:
Interest on long-term debt	21,015			20,526			62,530			57,092
Other interest	466			367			1,263			1,730
Allowance for borrowed funds used during construction	(5,702		)	(6,549		)	(16,763		)	(18,007		)
Amortization of redemption premiums and expense on debt	551			517			1,674			1,670
Total interest and other charges - net	16,330			14,861			48,704			42,485
NET INCOME	43,816			51,905			105,468			121,993

LESS: PREFERRED DIVIDEND REQUIREMENTS	803			803			2,410			2,410
NET INCOME APPLICABLE TO COMMON STOCK	$	43,013		$	51,102		$	103,058		$	119,583

See notes to unaudited condensed consolidated financial statements.

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INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY

Unaudited Condensed Consolidated Balance Sheets

(In Thousands)

	September 30,		December 31,
	2017		2016
ASSETS
UTILITY PLANT:
Utility plant in service	$	5,342,196	$	4,997,846
Less accumulated depreciation	2,110,899		2,030,497
Utility plant in service - net	3,231,297		2,967,349
Construction work in progress	703,231		898,330
Spare parts inventory	14,428		14,237
Property held for future use	1,002		1,002
Utility plant - net	3,949,958		3,880,918
OTHER ASSETS:
Intangible assets - net	10,812		11,976
At cost, less accumulated depreciation	1,565		1,263
Other assets - net	12,377		13,239
CURRENT ASSETS:
Cash and cash equivalents	17,142		26,607
Accounts receivable and unbilled revenue (less allowance
for doubtful accounts of $2,842 and $2,365, respectively)	151,951		154,586
Fuel inventories - at average cost	34,162		30,237
Materials and supplies - at average cost	61,140		60,649
Regulatory assets	32,784		33,912
Prepayments and other current assets	31,543		31,497
Total current assets	328,722		337,488
DEFERRED DEBITS:
Regulatory assets	436,956		450,710
Miscellaneous	4,111		4,409
Total deferred debits	441,067		455,119
TOTAL	$	4,732,124	$	4,686,764
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common shareholders' equity:
Common stock	$	324,537	$	324,537
Paid in capital	598,985		$	598,500
Retained Earnings	443,535		434,993
Total common shareholder's equity	1,367,057		1,358,030
Cumulative preferred stock	59,784		59,784
Long-term debt (Note 5)	1,675,769		1,675,131
Total capitalization	3,102,610		3,092,945
CURRENT LIABILITIES:
Short-term and current portion of long-term debt (Note 5)	120,500		74,650
Accounts payable	107,624		119,506
Accrued expenses	21,959		18,742
Accrued real estate and personal property taxes	21,951		18,930
Regulatory liabilities	5,181		7,704
Accrued income taxes	8,265		984
Accrued interest	30,885		22,731
Customer deposits	30,600		29,780
Other current liabilities	10,151		26,167
Total current liabilities	357,116		319,194
DEFERRED CREDITS AND OTHER LONG-TERM LIABILITIES:
Deferred income taxes - net	444,870		449,220
Non-current income tax liability	6,687		6,634
Regulatory liabilities	690,363		670,294
Unamortized investment tax credit	1,376		2,410
Accrued pension and other postretirement benefits	48,310		64,139
Asset retirement obligations	80,077		80,568
Miscellaneous	715		1,360
Total deferred credits and other long-term liabilities	1,272,398		1,274,625
COMMITMENTS AND CONTINGENCIES (Note 8)
TOTAL	$	4,732,124	$	4,686,764

See notes to unaudited condensed consolidated financial statements.

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INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY

Unaudited Condensed Consolidated Statements of Cash Flows

(In Thousands)

	Nine Months Ended
	September 30,
	2017			2016
CASH FLOWS FROM OPERATIONS:
Net income	$	105,468		$	121,993
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	156,103			166,031
Amortization of deferred financing costs and debt premium	1,674			1,670
Deferred income taxes and investment tax credit adjustments - net	(14,705		)	(6,992		)
Allowance for equity funds used during construction	(19,576		)	(20,125		)
Change in certain assets and liabilities:
Accounts receivable	2,635			(29,864		)
Fuel, materials and supplies	(4,626		)	31,705
Income taxes receivable or payable	7,281			22,791
Financial transmission rights	(788		)	(3,279		)
Accounts payable and accrued expenses	(9,339		)	(1,108		)
Accrued real estate and personal property taxes	3,020			4,456
Accrued interest	8,154			10,623
Pension and other postretirement benefit expenses	(15,828		)	(23,573		)
Short-term and long-term regulatory assets and liabilities	21,183			(26,623		)
Prepaids and other current assets	86			(3,122		)
Other - net	(6,053		)	7,736
Net cash provided by operating activities	234,689			252,319
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures - utility	(163,714		)	(516,895		)
Project development costs	(1,315		)	(852		)
Cost of removal, net of salvage	(7,523		)	(10,881		)
Other	(3,402		)	(1,542		)
Net cash used in investing activities	(175,954		)	(530,170		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt borrowings	126,500			248,000
Short-term debt repayments	(80,650		)	(389,850		)
Long-term borrowings, net of discount	—			347,662
Dividends on common stock	(101,516		)	(100,966		)
Dividends on preferred stock	(2,410		)	(2,410		)
Equity contribution from IPALCO	—			213,014
Payments for financed capital expenditures	(9,788		)	(14,990		)
Other	(336		)	(4,106		)
Net cash (used in) provided by financing activities	(68,200		)	296,354
Net change in cash and cash equivalents	(9,465		)	18,503
Cash and cash equivalents at beginning of period	26,607			19,852
Cash and cash equivalents at end of period	$	17,142		$	38,355

Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized)	$	38,645		$	30,162
Income taxes	$	60,250		$	47,200
	As of September 30,
	2017			2016
Non-cash investing activities:
Accruals for capital expenditures	$	33,184		$	37,357

See notes to unaudited condensed consolidated financial statements.

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INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY

Notes to Unaudited Condensed Consolidated Financial Statements

1. OVERVIEW AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

IPL (“the Company”) was incorporated under the laws of the state of Indiana in 1926. All of the outstanding common stock of IPL is owned by IPALCO. IPALCO, acquired by AES in March 2001, is owned by AES U.S. Investments and CDPQ. IPL is engaged primarily in generating, transmitting, distributing and selling of electric energy to approximately 490,000 retail customers in the city of Indianapolis and neighboring cities, towns and communities, and adjacent rural areas all within the state of Indiana, with 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 four generating stations, all within the state of Indiana. IPL’s largest generating station, Petersburg, is coal-fired. The second largest station, Harding Street, has converted its coal-fired units to natural gas and uses natural gas and fuel oil to power combustion turbines. In addition, IPL began the operation of a 20 MW battery energy storage unit at this location in May 2016, which provides frequency response. The third station, Eagle Valley, retired its coal-fired units in April 2016. The CCGT at Eagle Valley is expected to be completed in the first half of 2018 with a rated output of 671 MW. The fourth station, Georgetown, is a small peaking station that uses natural gas to power combustion turbines. As of September 30, 2017, IPL’s net electric generation capacity for winter is2,996 MW and net summer capacity is 2,881 MW.

Principles of Consolidation

The accompanying Unaudited Condensed Consolidated Financial Statements include the accounts of IPL and its unregulated subsidiary, IPL Funding. All significant intercompany amounts have been eliminated. The accompanying financial statements are unaudited; however, they have been prepared in accordance with GAAP for interim financial information. Accordingly, they do not include all of the disclosures required by GAAP for annual fiscal reporting periods. In the opinion of management, all adjustments of a normal recurring nature necessary for fair presentation have been included. 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. These unaudited financial statements have been prepared in accordance with the accounting policies described in IPL’s consolidated financial statements included in IPALCO’s Annual Report on Form 10-K for the year ended December 31, 2016 and should be read in conjunction therewith. We have evaluated subsequent events through November 1, 2017, the date of this report.

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 that 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.

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New Accounting Pronouncements

The following table provides a brief description of recent accounting pronouncements that had or may have a material impact on IPL’s consolidated financial statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or are expected to have no material impact on the Company’s consolidated financial statements.

New Accounting Standards Adopted
ASU Number and Name	Description	Date of Adoption	Effect on the financial statements upon adoption
2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting	The standard simplifies the following aspects of accounting for share-based payments awards: accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: The recognition of excess tax benefits and tax deficiencies arising from vesting or settlement were applied retrospectively. The elimination of the requirement that excess tax benefits be realized before they are recognized was adopted on a modified retrospective basis with a cumulative adjustment to the opening balance sheet.	January 1, 2017	The primary effect of adoption was the recognition of excess tax benefits in our provision for income taxes in the period when the awards vest or are settled, rather than in paid-in-capital in the period when the excess tax benefits are realized. We will continue to estimate the number of awards that are expected to vest in our determination of the related periodic compensation cost. The adoption of this standard did not have a material impact on the consolidated financial statements.
New Accounting Standards Issued But Not Yet Effective
ASU Number and Name	Description	Date of Adoption	Effect on the financial statements upon adoption
2017-08, Receivables - Nonrefundable Fees and Other Costs (Subtopic 310-20): Premium Amortization on Purchased Callable Debt Securities	This standard shortens the period of amortization of the premium on certain callable debt securities to the earliest call date. Transition method: modified retrospective.	January 1, 2019. Early adoption is permitted.	The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.
2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost	This standard changes the presentation of non-service cost expense associated with defined benefit plans and updates the guidance so that only the service cost component will be eligible for capitalization. Transition method: Prospective for presentation of non-service cost expense. Retrospective for the change in capitalization.	January 1, 2018. Early adoption is permitted.	The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements and does not plan to early adopt.
2017-05, Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Topic 610-20)	This standard clarifies the scope and application of ASC 610-20 on the sale, transfer, and derecognition of nonfinancial assets and in substance nonfinancial assets to non-customers, including partial sales. It also clarifies that the derecognition of business is under scope of ASC 810. Transition method: full or modified retrospective. The Company is in the process of identifying contracts that would not be completed as of January 1, 2018. Based on the assessment of contracts already executed as of September 30, 2017, the contracts that may require any type of assessment under the new standard is limited.	January 1, 2018. Earlier application is permitted only as of January 1, 2017.	The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements. The Company will adopt the standard on January 1, 2018 and plans to use the modified retrospective approach.
2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force)	This standard requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. Transition method: retrospective.	January 1, 2018 Early adoption is permitted.	The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.
2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires that an entity recognizes the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. Transition method: modified retrospective.	January 1, 2018 Early adoption is permitted.	The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.
2016-13, Financial Instruments -Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments	The standard updates the impairment model for financial assets measured at amortized cost to an expected loss model rather than an incurred loss model. It also allows for the presentation of credit losses on available-for-sale debt securities as an allowance rather than a write down. Transition method: various.	January 1, 2020 Early adoption is permitted only as of January 1, 2019.	The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.

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2016-02, Leases (Topic 842)

This standard requires lessees to recognize assets and liabilities for most leases but recognize expenses in a manner similar to today's accounting. For Lessors, the guidance modifies the lease classification criteria and the accounting for sales-type and direct financing leases. The guidance also eliminates today's real estate-specific provisions. Transition method: modified retrospective at the beginning of the earliest comparative period presented in the financial statements (January 1, 2017).

January 1, 2019. Early adoption is permitted.

The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements. The Company intends to adopt the standard as of January 1, 2019.

2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-13, Revenue from Contracts with Customers (Topic 606)

See discussion of this ASU below:

January 1, 2018. Earlier application is permitted only as of January 1, 2017.

The Company will adopt the standard on January 1, 2018; see below for the evaluation of the impact of its adoption on the consolidated financial statements.

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2. REGULATORY MATTERS

Basic Rates and Charges

On December 22, 2016, IPL filed a petition with the IURC for authority to increase its basic rates and charges primarily to recover the cost of the new CCGT. The CCGT was previously expected to be completed in the first half of 2017, but is now expected to be completed in the first half of 2018. To address this change, on February 24, 2017, IPL filed a motion to withdraw the case without prejudice or alternatively amend the petition and case-in-chief at a later date. On March 15, 2017, the IURC dismissed the rate case without prejudice. IPL expects to file a new base rate case with the IURC to coincide with the completion of the CCGT.

CCR

On April 26, 2017, the IURC approved IPL’s CCR compliance request to install a bottom ash dewatering system at its Petersburg generating station and to recover80% of qualifying costs through a rate adjustment mechanism with the remainder recorded as a regulatory asset for recovery in a subsequent rate case. The approved capital cost of the CCR compliance plan is approximately $47 million.

NAAQS

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3. FAIR VALUE

Fair Value Hierarchy

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

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

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 non-recurring basis, which have been adjusted to fair value during the periods covered by this report. As of September 30, 2017 and December 31, 2016, all of IPL’s financial assets or liabilities adjusted to fair value on a recurring basis (excluding pension assets - see Note 7, “Benefit Plans”) were considered Level 3, based on the above fair value hierarchy. These primarily consisted of FTRs, which are used to offset MISO congestion charges. Because the benefit associated with FTRs is a flow-through to IPL’s jurisdictional customers, IPL records a regulatory liability matching the value of the FTRs. All of these financial assets and liabilities were not material to the financial statements in the periods covered by this report, individually or in the aggregate.

Non-Recurring Fair Value Measurements

Financial Instruments not Measured at Fair Value in the Consolidated Balance Sheets

Debt

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The following table shows the face value and the fair value of fixed-rate and variable-rate indebtedness (Level 2) for the periods ending:



	September 30, 2017				December 31, 2016
	Face Value		Fair Value		Face Value		Fair Value
	*(In Millions)*
Fixed-rate	$	1,608.8	$	1,789.4	$	1,633.5	$	1,717.2
Variable-rate		210.5		210.5		140.0		140.0
Total indebtedness	$	1,819.3	$	1,999.9	$	1,773.5	$	1,857.2

The difference between the face value and the carrying value of this indebtedness represents the following:

•

unamortized deferred financing costs of $16.6 million and $17.2 million at September 30, 2017 and December 31, 2016, respectively; and

•

unamortized discounts of $6.4 million and $6.5 million at September 30, 2017 and December 31, 2016, respectively.

4. EQUITY

On March 1, 2016, IPALCO issued and sold 7,403,213 shares of IPALCO’s common stock to CDPQ for $134.3 million under the Subscription Agreement. After completion of these transactions, CDPQ’s direct and indirect interests in IPALCO total approximately 30%. On June 1, 2016, IPALCO received equity capital contributions of $64.8 million from AES U.S. Investments and $13.9 million from CDPQ. IPALCO then made the same investments in IPL. The proceeds were primarily used for funding needs related to IPL’s environmental and replacement generation projects. The capital contributions on June 1, 2016 were made on a proportional share basis and, therefore, did not change CDPQ’s or AES’ ownership interests in IPALCO.

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5. DEBT

Long-Term Debt

The following table presents our long-term debt:

		September 30,			December 31,
Series	Due	2017			2016
		*(In Thousands)*
IPL first mortgage bonds:
5.40%⁽¹⁾	August 2017	$	—		$	24,650
3.875%⁽²⁾	August 2021	55,000			55,000
3.875%⁽²⁾	August 2021	40,000			40,000
3.125%⁽²⁾	December 2024	40,000			40,000
6.60%	January 2034	100,000			100,000
6.05%	October 2036	158,800			158,800
6.60%	June 2037	165,000			165,000
4.875%	November 2041	140,000			140,000
4.65%	June 2043	170,000			170,000
4.50%	June 2044	130,000			130,000
4.70%	September 2045	260,000			260,000
4.05%	May 2046	350,000			350,000
Unamortized discount – net		(6,384		)	(6,477		)
Deferred financing costs		(16,275		)	(16,736		)
Total IPL first mortgage bonds		1,586,141			1,610,237
IPL unsecured debt:
Variable⁽³⁾	December 2020	30,000			30,000
Variable⁽³⁾	December 2020	60,000			60,000
Deferred financing costs		(372		)	(456		)
Total IPL unsecured debt		89,628			89,544
Total Consolidated Long-term Debt		1,675,769			1,699,781
Less: Current Portion of Long-term Debt		—			24,650
Net Consolidated IPL Long-term Debt		$	1,675,769		$	1,675,131

(1)

First mortgage bonds issued to the city of Petersburg, Indiana, to secure the loan proceeds from various tax-exempt bonds issued by the city. IPL repaid these first mortgage bonds on August 1, 2017.

(2)

First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority.

(3)

Line of Credit

As of September 30, 2017 and December 31, 2016, IPL had $120.5 million and $50.0 million in outstanding borrowings on the committed line of credit, respectively.

6. INCOME TAXES

IPL’s effective combined state and federal income tax rates were 34.4% and 33.4% for the three and nine months ended September 30, 2017, respectively, as compared to 36.1% and 34.1% for the three and nine months ended September 30, 2016, respectively. The decrease in the effective tax rates versus the comparable periods was primarily due to the manufacturer’s production deduction (Internal Revenue Code Section 199) that had been previously limited due to a Net Operating Loss carryover, and the allowance for equity funds used during construction as a percentage of pretax income.

F-96

7. BENEFIT PLANS

The following table (in thousands) presents information for the nine months ended September 30, 2017, relating to the Pension Plans:

Net unfunded status of plans:
Net unfunded status at December 31, 2016, before tax adjustments	$	(57,395	)
Net benefit cost components reflected in net unfunded status during first quarter:
Service cost	(1,836		)
Interest cost	(6,327		)
Expected return on assets	11,167
Actuarial valuation adjustment	80
Employer contributions	7,211
Net unfunded status at March 31, 2017, before tax adjustments	$	(47,100	)
Net benefit cost components reflected in net unfunded status during second quarter:
Service cost	(1,836		)
Interest cost	(6,326		)
Expected return on assets	11,168
Net unfunded status at June 30, 2017, before tax adjustments	$	(44,094	)
Net benefit cost components reflected in net unfunded status during third quarter:
Service cost	(1,836		)
Interest cost	(6,326		)
Expected return on assets	11,168
Net unfunded status at September 30, 2017, before tax adjustments	$	(41,088	)

Regulatory assets related to pensions⁽¹⁾:
Regulatory assets at December 31, 2016, before tax adjustments	$	223,705
Amount reclassified through net benefit cost:
Amortization of prior service cost	(1,060		)
Amortization of net actuarial loss	(3,300		)
Settlements⁽²⁾	(146		)
Actuarial valuation adjustment	(80		)
Regulatory assets at March 31, 2017, before tax adjustments	$	219,119
Amount reclassified through net benefit cost:
Amortization of prior service cost	(1,060		)
Amortization of net actuarial loss	(3,299		)
Regulatory assets at June 30, 2017, before tax adjustments	$	214,760
Amount reclassified through net benefit cost:
Amortization of prior service cost	(1,060		)
Amortization of net actuarial loss	(3,298		)
Regulatory assets at September 30, 2017, before tax adjustments	$	210,402

(1)

(2)

The settlement loss of $0.1 million for the three months ended March 31, 2017 was the result of a lump sum distribution paid out of the Supplemental Retirement Plan.

F-97

Pension Expense

The following table presents net periodic benefit cost information relating to the Pension Plans combined:

	For the Three Months Ended,						For the Nine Months Ended,
	September 30,						September 30,
	2017			2016			2017			2016
	*(In Thousands)*						*(In Thousands)*
Components of net periodic benefit cost:
Service cost	$	1,836		$	1,754		$	5,508		$	5,263
Interest cost	6,326			6,454			18,979			19,362
Expected return on plan assets	(11,168		)	(10,873		)	(33,503		)	(32,620		)
Amortization of prior service cost	1,060			1,296			3,180			3,888
Amortization of actuarial loss	3,298			3,474			9,897			10,422
Settlements	—			—			146			—
Net periodic benefit cost	$	1,352		$	2,105		$	4,207		$	6,315

8. COMMITMENTS AND CONTINGENCIES

Legal Loss Contingencies

Environmental Loss Contingencies

New Source Review and Other CAA NOVs

In October 2009, IPL received a 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 at the time, dating back to 1986. The alleged violations primarily pertain to the PSD and nonattainment New Source Review requirements under the CAA. In addition, on October 1, 2015, IPL received a NOV from the EPA pursuant to CAA Section 113(a) alleging violations of the CAA, the Indiana SIP, and the Title V operating permit related to alleged particulate matter and opacity violations at IPL Petersburg Unit 3. Also, on February 5, 2016, the EPA issued a NOV pursuant to CAA Section 113(a) alleging violations of New Source Review and other CAA regulations, the Indiana SIP, and the Title V operating permit at Petersburg Generating Station. Since receiving the letters, IPL management has met with the EPA staff regarding possible resolutions of the NOVs. Settlements and litigated outcomes of similar New Source Review 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 these cases could have a material impact on our business. It is too early to determine whether these NOVs could have a material impact on our business, financial condition or results of operations. We would seek recovery of any operating or capital expenditures, but not fines or penalties, related to air pollution control

F-98

F-99

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 above.

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF REGISTRANT

IPALCO ENTERPRISES, INC.

Schedule I – Condensed Financial Information of Registrant

Unconsolidated Balance Sheets

(In Thousands)

	December 31,
	2016			2015
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	7,370		$	774
Prepayments and other current assets	10,076			10,608
Total current assets	17,446			11,382
OTHER ASSETS:
Investment in subsidiaries	1,360,235			1,127,098
Other investments	3,247			3,316
Deferred tax asset – long term	101			22,702
Total other assets	1,363,583			1,153,116
TOTAL	$	1,381,029		$	1,164,498
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common shareholders' equity:
Paid in capital	$	596,810		$	383,448
Accumulated deficit	(25,627		)	(30,515		)
Total common shareholders' equity	571,183			352,933
Long-term debt	799,709			797,771
Total capitalization	1,370,892			1,150,704
CURRENT LIABILITIES:
Accounts payable and accrued expenses	359			383
Accrued income taxes	—			2,857
Accrued interest	9,776			10,552
Total current liabilities	10,135			13,792
DEFERRED CREDITS AND OTHER LONG-TERM LIABILITIES	2			2
TOTAL	$	1,381,029		$	1,164,498

See notes to Schedule I.

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IPALCO ENTERPRISES, INC.

Schedule I – Condensed Financial Information of Registrant

Unconsolidated Statements of Operations

(In Thousands)

	2016			2015			2014
Equity in earnings of subsidiaries	$	153,232		$	98,708		$	106,252
Loss on early extinguishment of debt	—			(21,956		)	—
Income tax benefit – net	11,483			24,650			21,227
Interest on long-term debt	(33,973		)	(41,659		)	(49,000		)
Amortization of redemption premiums and expense on debt	(1,947		)	(2,459		)	(2,765		)
Other – net	(948		)	(973		)	(959		)
NET INCOME	$	127,847		$	56,311		$	74,755

See notes to Schedule I.

F-101

IPALCO ENTERPRISES, INC.

Schedule I – Condensed Financial Information of Registrant

Unconsolidated Statements of Cash Flows

(In Thousands)

	2016			2015			2014
CASH FLOWS FROM OPERATIONS:
Net income	$	127,847		$	56,311		$	74,755
Adjustments to reconcile net income to net cash
provided by operating activities:
Equity in earnings of subsidiaries	(153,232		)	(98,708		)	(106,252		)
Cash dividends received from subsidiary companies	136,466			106,997			127,400
Amortization of debt issuance costs and discounts	1,947			2,459			2,765
Deferred income taxes – net	22,601			(2,190		)	(20,445		)
Charges related to early extinguishment of debt	—			21,956			—
Change in certain assets and liabilities:
Income taxes receivable or payable	(5,425		)	2,465			(501		)
Accounts payable and accrued expenses	(800		)	(391		)	(599		)
Other – net	145			639			255
Net cash provided by operating activities	129,549			89,538			77,378
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in subsidiaries	(212,997		)	(214,366		)	(106,383		)
Net cash used in investing activities	(212,997		)	(214,366		)	(106,383		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Long-term borrowings, net of discount	—			404,712			—
Retirement of long-term debt and early tender premium	—			(420,329		)	—
Dividends on common stock	(122,959		)	(69,487		)	(78,400		)
Issuance of common stock	134,276			214,366			—
Equity contributions from shareholders	78,738			—			106,400
Other	(11		)	(5,445		)	—
Net cash provided by financing activities	90,044			123,817			28,000
Net change in cash and cash equivalents	6,596			(1,011		)	(1,005		)
Cash and cash equivalents at beginning of period	774			1,785			2,790
Cash and cash equivalents at end of period	$	7,370		$	774		$	1,785

See notes to Schedule I.

F-102

IPALCO ENTERPRISES, INC.

Schedule I - Condensed Financial Information of Registrant

Unconsolidated Statements of Common Shareholders' Equity (Deficit)

(In Thousands)

	Paid in Capital		Accumulated Deficit			Total
Balance at January 1, 2014	$	61,468	$	(13,694	)	$	47,774
Net income			74,755			74,755
Distributions to AES			(78,400		)	(78,400		)
Contributions from AES	106,400					106,400
Other	742					742
Balance at December 31, 2014	$	168,610	$	(17,339	)	$	151,271
Net income			56,311			56,311
Distributions to shareholders			(69,487		)	(69,487		)
Issuance of common stock	214,366					214,366
Other	472					472
Balance at December 31, 2015	$	383,448	$	(30,515	)	$	352,933
Net income			127,847			127,847
Distributions to shareholders			(122,959		)	(122,959		)
Contributions from shareholders	78,738					78,738
Issuance of common stock	134,276					134,276
Other	348					348
Balance at December 31, 2016	$	596,810	$	(25,627	)	$	571,183

See notes to Schedule I.

F-103

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 has accounted for the earnings of its subsidiaries on the equity method in the unconsolidated condensed financial information.

2. EQUITY

Equity Transactions

On December 15, 2014, AES announced that it entered into an agreement with CDPQ, a long-term institutional investor headquartered in Quebec, Canada. Pursuant to the agreement, on February 11, 2015 CDPQ purchased from AES 15% of AES U.S. Investments and 100 shares of IPALCO’s common stock were issued to CDPQ. In addition, pursuant to the agreement, CDPQ invested approximately $349 million in IPALCO through 2016, in exchange for a 17.65% equity stake, funding existing growth and environmental projects at IPL.

Paid In Capital and Capital Stock

On February 11, 2015, IPALCO issued and sold 100 shares of IPALCO’s common stock to CDPQ under the Subscription Agreement. On April 1, 2015, IPALCO issued and sold 11,818,828 shares of IPALCO's common stock to CDPQ for $214.4 million under the Subscription Agreement.

On March 1, 2016, IPALCO issued and sold 7,403,213 shares of IPALCO’s common stock to CDPQ for $134.3 million under the Subscription Agreement. After completion of these transactions, CDPQ’s direct and indirect interest in IPALCO is 30%. On June 1, 2016, IPALCO received equity capital contributions of (i) $64.8 million from AES U.S. Investments and (ii) $13.9 million from CDPQ. IPALCO then made the same investments in IPL. The proceeds were primarily used for funding needs related to IPL’s environmental and replacement generation projects. The capital contributions on June 1, 2016 were made on a proportional share basis and, therefore, did not change CDPQ’s or AES’ ownership interests in IPALCO.

F-104

3. DEBT

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

		December 31,
Series	Due	2016			2015
		*(In Thousands)*
Long-Term Debt
5.00% Senior Secured Notes	May 2018	$	400,000		$	400,000
3.45% Senior Secured Notes	July 2020	405,000			405,000
Unamortized discount – net		(273		)	(371		)
Deferred financing costs – net⁽¹⁾		(5,018		)	(6,858		)
Total Long-term Debt		799,709			797,771
Less: Current Portion of Long-term Debt		—			—
Net Long-term Debt		$	799,709		$	797,771

(1)

The Company adopted ASU No. 2015-03 on January 1, 2016, which requires the use of the full retrospective approach with respect to the presentation of debt issuance costs, including deferred charges.

Long-term Debt

IPALCO’s Senior Secured Notes

In June 2015, IPALCO completed the sale of the 2020 IPALCO Notes pursuant to Rule 144A and Regulation S under the Securities Act. The 2020 IPALCO Notes were issued pursuant to an Indenture dated June 25, 2015, by and between IPALCO and U.S. Bank, National Association, as trustee. The 2020 IPALCO Notes were priced to the public at 99.929% of the principal amount. Net proceeds to IPALCO were approximately $399.5 million after deducting underwriting costs and estimated offering expenses. These costs are being amortized to the maturity date using the effective interest method. We used the net proceeds from this offering to fund the purchase of the 2016 IPALCO Notes validly tendered and to pay for a related consent solicitation, to redeem any 2016 IPALCO Notes that remained outstanding after the completion of the tender, and to pay certain related fees, expenses and make-whole premiums. Of the 2016 IPALCO Notes outstanding, $366.5 million were tendered in June 2015. The remainder, $33.5 million, was redeemed in July 2015. An early tender premium was paid related to the tender offer and a redemption premium was paid related to the redemption of the 2016 IPALCO Notes. A loss on early extinguishment of debt of $22.1 million for the 2016 IPALCO Notes is included as a separate line item in the accompanying Unconsolidated Statements of Operations.

The 2018 IPALCO Notes and 2020 IPALCO Notes are secured by IPALCO’s pledge of all of the outstanding common stock of IPL.

F-105

SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

IPALCO ENTERPRISES, INC. and SUBSIDIARIES

Valuation and Qualifying Accounts and Reserves

Years ended December 31, 2016, 2015 and 2014

(In Thousands)

Column A – Description	Column B		Column C – Additions				Column D – Deductions		Column E
	Balance at Beginning of Period		Charged to Income		Charged to Other Accounts		Net Write-offs		Balance at End of Period
Year ended December 31, 2016
Accumulated Provisions Deducted from
Assets – Doubtful Accounts	$	2,498	$	4,122	$	—	$	4,255	$	2,365
Year ended December 31, 2015
Accumulated Provisions Deducted from
Assets – Doubtful Accounts	$	2,076	$	4,273	$	—	$	3,851	$	2,498
Year ended December 31, 2014
Accumulated Provisions Deducted from
Assets –Doubtful Accounts	$	1,982	$	4,852	$	—	$	4,758	$	2,076

INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY

Valuation and Qualifying Accounts and Reserves

Years ended December 31, 2016, 2015 and 2014

(In Thousands)

Column A – Description	Column B		Column C – Additions				Column D – Deductions		Column E
	Balance at Beginning of Period		Charged to Income		Charged to Other Accounts		Net Write-offs		Balance at End of Period
Year ended December 31, 2016
Accumulated Provisions Deducted from
Assets – Doubtful Accounts	$	2,498	$	4,122	$	—	$	4,255	$	2,365
Year ended December 31, 2015
Accumulated Provisions Deducted from
Assets – Doubtful Accounts	$	2,076	$	4,273	$	—	$	3,851	$	2,498
Year ended December 31, 2014
Accumulated Provisions Deducted from
Assets –Doubtful Accounts	$	1,982	$	4,852	$	—	$	4,758	$	2,076

F-106

IPALCO ENTERPRISES, INC.

Offer to Exchange

3.70% Senior Secured Notes due 2024
for
New 3.70% Senior Secured Notes due 2024

Until March 5, 2018 all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters with respect to their unsold allotments or subscriptions.

PROSPECTUS

December 6, 2017

Ipalco Enterprises 424B3Prospectus supplement