IPALCO ENTERPRISES, INC. - FORM 10-K

Attached files

file	filename
EX-32 - EXHIBIT 32 - IPALCO ENTERPRISES, INC.	a10-kexhibit32.htm
EX-31.2 - EXHIBIT 31.2 - IPALCO ENTERPRISES, INC.	a10-kexhibit312.htm
EX-31.1 - EXHIBIT 31.1 - IPALCO ENTERPRISES, INC.	a10-kexhibit311.htm
EX-21 - EXHIBIT 21 - IPALCO ENTERPRISES, INC.	a10-kexhibit21.htm
EX-4.3 - EXHIBIT 4.3 - IPALCO ENTERPRISES, INC.	a10-kexhibit43.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)

þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE

ACT OF 1934

For the fiscal year ended December 31, 2016

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE

ACT OF 1934

Commission file number 1-8644

IPALCO ENTERPRISES, INC.

(Exact name of registrant as specified in its charter)



Indiana		35-1575582
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
One Monument Circle Indianapolis, Indiana		46204
(Address of principal executive offices)		(Zip Code)

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

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

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

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

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

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

(The registrant is a voluntary filer. The registrant has filed all applicable reports under Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months.)

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨

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

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

Large accelerated filer ¨ Accelerated filer ¨

Non-accelerated filer þ Smaller reporting company ¨

(Do not check if a smaller reporting company)

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

At February 24, 2017, 108,907,318 shares of IPALCO Enterprises, Inc. common stock were outstanding, of which 89,685,177 shares were owned by AES U.S. Investments, Inc. and 19,222,141 shares were owned by CDP Infrastructure Fund GP, a wholly-owned subsidiary of La Caisse de dépôt et placement du Québec.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of registrant’s Proxy Statement for its annual meeting of stockholders are incorporated by reference in Part III.

IPALCO ENTERPRISES, INC.

Annual Report on Form 10-K

For Fiscal Year Ended December 31, 2016

Table of Contents



Item No.		Page No.

	DEFINED TERMS	4

	PART I
1.	Business	7
1A.	Risk Factors	20
1B.	Unresolved Staff Comments	31
2.	Properties	31
3.	Legal Proceedings	31
4.	Mine Safety Disclosures	31
PART II
5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities	31
6.	Selected Financial Data	32
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
7A.	Quantitative and Qualitative Disclosures About Market Risk	47
8.	Financial Statements and Supplementary Data	50
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	121
9A.	Controls and Procedures	121
9B.	Other Information	122

PART III
10.	Directors, Executive Officers and Corporate Governance	122
11.	Executive Compensation	122
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	122
13.	Certain Relationships and Related Transactions, and Director Independence	122
14.	Principal Accounting Fees and Services	123

PART IV
15.	Exhibits, Financial Statements and Financial Statement Schedules	125
16.	Form 10-K Summary	133

SIGNATURES		134



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

2016 IPALCO Notes	$400 million of 7.25% Senior Secured Notes due April 1, 2016
2018 IPALCO Notes	$400 million of 5.00% Senior Secured Notes due May 1, 2018
2020 IPALCO Notes	$405 million of 3.45% Senior Secured Notes due July 15, 2020
AES	The AES Corporation
AES U.S. Investments	AES U.S. Investments, 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
Dodd-Frank Act	Dodd-Frank Wall Street Reform and Consumer Protection Act
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
Financial Statements	Audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in Part II of this Form 10-K
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
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
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
Securities Act	Securities Act of 1933, as Amended
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

PART I

Throughout this document, the terms “the Company,” “we,” “us,” and “our” refer to IPALCO and its consolidated subsidiaries.

FORWARD‑LOOKING STATEMENTS

This Annual Report on Form 10-K includes “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995 including, in particular, the statements about our plans, strategies and prospects under the headings “Item 1. Business,” “Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Forward-looking statements express an expectation or belief and contain a projection, plan or assumption with regard to, among other things, our future revenues, income, expenses or capital structure. Such statements of future events or performance are not guarantees of future performance and involve estimates, assumptions and uncertainties. The words “could,” “may,” “predict,” “anticipate,” “would,” “believe,” “estimate,” “expect,” “forecast,” “project,” “objective,” “intend,” “continue,” “should,” “plan,” and similar expressions, or the negatives thereof, are intended to identify forward-looking statements, unless the context requires otherwise.

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.

Most of these factors affect us through our consolidated subsidiary, IPL. All of the above factors are difficult to predict, contain uncertainties that may materially affect actual results, and many are beyond our control. See “Item 1A. Risk Factors” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Form 10-K 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. Except as required by the federal securities laws, we undertake no obligation to publicly update or review any forward-looking information, whether as a result of new information, future events or otherwise. If one or more forward-looking statements are updated, no inference should be drawn that additional updates will be made with respect to those or other forward-looking statements.

ITEM 1. BUSINESS

OVERVIEW

IPALCO 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. The book value of our total assets as of December 31, 2016 was $4.7 billion. All of our operations are conducted within the U.S. and principally within the state of Indiana. Please see Note 12, “Business Segment Information” to the Financial Statements.

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 areas within the state of Indiana; the most distant point being about 40 miles from Indianapolis. IPL has an exclusive right to provide electric service to those customers. IPL’s service area covers about 528 square miles with an estimated population of approximately 939,000. IPL’s generation, transmission and distribution facilities, and changes to our sources of electric generation, are further described below under “Properties.” There have been no significant changes in the services rendered by IPL during 2016.

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, are impacted by changes in service territory economic activity, as well as the number of retail customers we have. For the ten years ending in 2016, IPL’s retail kWh sales have 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 flat retail kWh sales growth annually, which is negatively impacted by our DSM programs and other energy efficiency mandates. Please see Note 2, “Regulatory Matters – DSM” to the Financial Statements for more details. IPL’s electricity sales for 2012 through 2016 are set forth in the table of statistical information included at the end of this section.

IPL is a transmission company member of RF. RF is one of eight Regional Reliability Councils under the NERC, which has been designated as the Electric Reliability Organization under the EPAct. RF seeks to preserve and enhance electric service reliability and security for the interconnected electric systems within the RF geographic area by setting and enforcing electric reliability standards. RF members cooperate under agreements to augment the reliability of its members’ electricity supply systems in the RF 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 RF. In addition, IPL is one of many transmission system owner members of MISO, a regional transmission organization that 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 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 “MISO Operations” below for more details).

EMPLOYEES

As of January 31, 2017, IPL had 1,355 employees of whom 1,269 were full time. Of the total employees, 863 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 January 31, 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. Please see Note 11, “Related Party Transactions – Service Company” to the Financial Statements and “Item 13. Certain Relationships and Related Transactions, and Director Independence” of this Form 10-K for additional details.

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 2,993 MW and net summer design capacity is 2,878 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	1,706	1,706	Pike County, Indiana
	Total	4	1,706	1,706
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	2,993	2,878


(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.

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 $114.4 million and $128.6 million as of 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.

For additional discussion of the regulatory environment related to our business, see the discussion in Note 2, “Regulatory Matters” to the Financial Statements, which is incorporated by reference herein.

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

MATS

In April 2012, the EPA’s rule to establish maximum achievable control technology standards for 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 coal-fired 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 plans to install 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. IPL is seeking approval for a CPCN to install the bottom ash dewatering system at its Petersburg generating station. We expect to recover through our environmental rate adjustment mechanism any operating or capital expenditures related to the installation of this system. Recovery of these costs is sought through an Indiana statute that allows for 80% recovery of qualifying costs through a rate adjustment mechanism with the remainder recorded as a regulatory asset to be considered for recovery in the next base rate case proceeding. However, there can be no assurances that we will be successful in that regard. In light of the uncertainties at this time, we cannot predict the

impact of these requirements on our consolidated results of operations, cash flows, or financial condition, but it is expected to be material.

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.

On November 3, 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 compliance date may be as early as November 2018 or as late as December 2023, and is subject to the discretion of IDEM. IPL plans to install 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 Fifth Circuit Court of Appeals. Environmental groups have moved to intervene in these cases on behalf of the EPA.

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 on August 28, 2015, may expand or otherwise change the number and types of waters or features subject to federal permitting. On the day the rule was published, several states sued to challenge the rule. Since then, other states and industry groups have also sued. On October 9, 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order staying the rule nationwide pending completion of that Court’s review of the rule. In January 2016, the U.S. Congress passed a resolution seeking to block implementation of the rule, which resolution was vetoed by President Obama. In January 2017, the U.S. Supreme Court granted certiorari to reconsider the Sixth Circuit's decision that such circuit, rather than U.S. district courts, have jurisdiction to hear challenges to this rule. We cannot at this time determine the timing or impact of this regulation, litigation or legislation, but 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 CO₂emission 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. A ruling is expected in early 2017. 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.

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 will start 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. We cannot predict the outcome of the petition but its impact could be material. We would seek recovery of any 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. Attainment and nonattainment determinations with respect to the ozone NAAQS are expected by October 1, 2017. 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.

NOx 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 will be 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. IPL is seeking approval for a CPCN for these measures at its Petersburg generating station. We expect to recover through our environmental rate adjustment mechanism any operating or capital expenditures related to compliance with the rule. Recovery of these costs is sought through an Indiana statute that allows for 80% recovery of qualifying costs through a rate adjustment mechanism with the remainder recorded as a regulatory asset to be considered for recovery in the next base rate case proceeding. However, there can be no assurances that we will be successful in that regard. In light of the uncertainties at this time, we cannot predict the impact of the rule on our consolidated results of operations, cash flows, or financial condition, but it is expected to be material.

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. A proposed rule is possible in 2017. At present, we are unable to predict the impact 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.

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 65% 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 39% 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 in 2016. 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. IPL sells the renewable energy purchased from these wind and solar facilities in the form of renewable energy credits for the benefit of our retail customers. 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:



	Year Ended December 31,
	2016		2015		2014		2013		2012
Operating Revenues (In Thousands):
Residential	$	532,564	$	480,969	$	485,779	$	472,630	$	466,294
Small commercial and industrial	208,928		192,232		193,213		185,241		183,681
Large commercial and industrial	557,491		526,461		527,719		504,038		510,669
Public lighting	10,023		10,823		10,811		10,743		10,872
Retail electric revenues	1,309,006		1,210,485		1,217,522		1,172,652		1,171,516
Wholesale	15,804		19,307		83,208		62,734		37,822
Miscellaneous	22,620		20,607		20,944		20,348		20,439
Total utility operating revenues	$	1,347,430	$	1,250,399	$	1,321,674	$	1,255,734	$	1,229,777
kWh Sales (In Millions):
Residential	5,152		5,062		5,269		5,243		5,144
Small commercial and industrial	1,850		1,837		1,888		1,882		1,862
Large commercial and industrial	6,620		6,757		6,778		6,841		6,945
Public lighting	57		53		59		63		64
Sales – retail customers	13,679		13,709		13,994		14,029		14,015
Wholesale	507		689		2,397		2,005		1,308
Total kWh sold	14,186		14,398		16,391		16,034		15,323
Retail Customers at End of Year:
Residential	435,622		431,182		427,866		424,201		419,867
Small commercial and industrial	48,204		47,919		47,534		47,360		47,108
Large commercial and industrial	4,763		4,737		4,749		4,727		4,645
Public lighting	955		953		945		935		957
Total retail customers	489,544		484,791		481,094		477,223		472,577

HOW TO CONTACT IPALCO

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

ITEM 1A. RISK FACTORS

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

Our electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and/or maintenance expenses, increased fuel or purchased power costs and other significant liabilities for which we may not have adequate insurance coverage.

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


•	increased prices for fuel and fuel transportation as existing contracts expire or as such contracts are adjusted through price re-opener provisions or automatic adjustments;


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


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


•	shortages of or delays in obtaining equipment;


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


•	labor disputes or work stoppages by employees;


•	accidents and injuries;


•	reliability of our suppliers;


•	inability to comply with regulatory or permit requirements;


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


•	construction delays and cost overruns;


•	disruptions in the delivery of electricity;


•	the availability of qualified personnel;


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


•	operator error; and


•	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 Note 2, “Regulatory Matters – FAC and Authorized Annual Jurisdictional Net Operating Income” to the Financial Statements 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 65% 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 report, 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 39% 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 and 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 could 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 “Item 1. Business - Environmental Matters” for additional information of 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 “Item 1. 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 that were retired in the second quarter of 2013 and the Eagle Valley coal-fired generation units that were retired in 2016, the combination of existing and expected environmental regulations has resulted in us retiring or refueling other generating units by 2017, as described in “Item 1. Business - Environmental Matters - Unit Retirements and Replacement Generation.” Our units are

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.

Please see “Item 1. Business - Environmental Matters” for additional information of environmental matters impacting us.

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, or 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. See also “Item 1. Business - MISO Operations and “Item 1. Business - Regulatory Matters – Retail Ratemaking.”

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 Financial Statements for information regarding indebtedness. See also “Item 7A. Quantitative and Qualitative Disclosure 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), and the expected completion of the CCGT (first half of 2018), we expect our ability to have excess generation available for sale on the wholesale market will be adversely impacted.

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. In particular, the projected economic growth and total employment in Indianapolis are important to the realization of our forecasts for annual energy sales.

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

As of December 31, 2016, we had on a consolidated basis $2.5 billion of indebtedness and total common shareholders’ equity of $571.2 million. IPL had $1,633.5 million of first mortgage bonds outstanding as of December 31, 2016, 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. This level of indebtedness and related security could have important consequences, including the following:


•	increasing our vulnerability to general adverse economic and industry conditions;


•	requiring 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;


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


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

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

We have variable rate debt that bears interest based on a prevailing rate that is reset based on a market index that can be affected by market demand, supply, market interest rates and other market conditions. We also maintain both cash on deposit and investments in cash equivalents from time to time that could be impacted by interest rate fluctuations. As such, any event which impacts market interest rates could have a material effect on our results of operations, financial condition and cash flows. In addition, ratings agencies issue credit ratings on us and our debt that affect our borrowing costs under our financial arrangements and affect our potential pool of investors and funding sources. Our credit ratings also govern the collateral provisions of certain of our contracts. If the rating agencies were to downgrade our credit ratings, our borrowing costs would likely further increase, our potential pool of investors and funding resources could be reduced, and we could be required to post additional cash collateral under selected contracts. These events would likely reduce our liquidity and profitability and could have a material adverse effect on our results of operations, financial condition and cash flows.

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 Financial Statements included in this Form 10-K 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.

Our tariff rates for electric service to retail customers consist of basic rates and charges and various adjustment mechanisms which are set and approved by the IURC after public hearings. Pursuant to statute, the IURC is to conduct a periodic review of the basic rates and charges of all Indiana utilities at least once every four years, but the IURC has the authority to review the rates of any Indiana utility at any time. Proceedings to review our basic rates and charges involve IPL, the IURC, the Indiana Office of Utility Consumer Counselor and other interested stakeholders. For information about IPL’s significant rate case

proceedings, please see Note 2, “Regulatory Matters - Basic Rates and Charges” to the Financial Statements. 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 which may require us to expend significant funds to address. 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. Asbestos and other regulated substances are, and may continue to be, present at our facilities. We have been named as a defendant in asbestos litigation, which at this time is not expected to be material to us. The presence of asbestos and other regulated substances at these facilities could result in additional litigation being brought against us, which could have a material adverse effect on our results of operations, financial condition and cash flows. Please see Note 2, “Regulatory Matters” and Note 10, “Commitments and Contingencies” to the Financial Statements 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 adverse 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 “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity” for a discussion of these restrictions. See Note 7, “Debt” to the Financial Statements 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Information relating to our properties is contained in “Item 1. Business – Properties.”

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 $1,633.5 million at December 31, 2016. In addition, IPALCO has outstanding $805 million of Senior Secured Notes which are secured by its pledge of all of the outstanding common stock of IPL.

ITEM 3. 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 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 “Item 1. Business – Environmental Matters” herein, Note 2, “Regulatory Matters” and Note 10, “Commitments and Contingencies” to the Financial Statements for a summary of significant legal proceedings involving us.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

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

As of February 24, 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 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 “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity” of this Form 10-K 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.

Dividend and Capital Structure Restrictions

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 facility or unsecured notes, which could happen if IPL fails to comply with certain covenants. These covenants, among other things, require IPL to maintain total debt to total capitalization not in excess of 0.65 to 1. 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.

IPL’s amended articles of incorporation also require that, so long as any shares of preferred stock are outstanding, the net income of IPL, as specified in the articles, be at least one and one-half times the total interest on the funded debt and the pro forma dividend requirements on the outstanding, and any proposed, preferred stock before any additional preferred stock is issued. IPL’s mortgage and deed of trust requires that net earnings as calculated thereunder be at least two and one-half times the annual interest requirements before additional bonds can be authenticated on the basis of property additions. As of December 31, 2016, these requirements would not materially restrict IPL’s ability to issue additional preferred stock or first mortgage bonds in the ordinary course of prudent business operations.

ITEM 6. SELECTED FINANCIAL DATA

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



	Year Ended December 31,
	2016		2015		2014		2013		2012
	(In Thousands)
Statement of Operations Data:
Utility operating revenues	$	1,347,430	$	1,250,399	$	1,321,674	$	1,255,734	$	1,229,777
Utility operating income	188,411		144,711		160,913		150,746		162,900
Allowance for funds used during construction	51,006		28,111		12,344		6,848		2,146
Net income	131,060		59,524		77,968		64,049		71,996
Balance Sheet Data (end of period):
Total assets	$	4,702,281	$	4,217,169	$	3,652,522	$	3,257,989	$	3,268,932
Common shareholders’ equity (deficit)	571,183		352,933		151,271		47,774		(3,219		)
Cumulative preferred stock of subsidiary	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
Other Data:
Utility capital expenditures⁽¹⁾	$	607,716	$	686,064	$	381,626	$	242,124	$	129,747

(1) Capital expenditures includes $15.5 million and $13.2 million of payments for financed capital expenditures in 2016 and 2015, respectively.

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

The following discussion and analysis should be read in conjunction with our Financial Statements and the notes thereto. 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 “Item 1A. Risk Factors.” For a list of certain abbreviations or acronyms in this discussion, see “Defined Terms” at the beginning of this Form 10-K.

OVERVIEW

The most important matters on which we focus in evaluating our financial condition and operating performance and allocating our resources include: (i) recurring factors which have significant impacts on operating performance such as: regulatory action, environmental matters, weather and weather-related damage in our service area, our ability to sell power in the wholesale market at a profit, and the local economy; (ii) our progress on performance improvement strategies designed to maintain high standards in several operating areas (including safety, 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 Note 2, “Regulatory Matters” to the Financial Statements and “Environmental Matters” in “Item 1. Business.”

Weather and Weather-Related Damage in our Service Area

Extreme high and low temperatures in our service area have a significant impact on revenues as many of our retail customers use electricity to power air conditioners, electric furnaces and heat pumps. The 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. 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 markets, and at other times we will have electric generation available for sale in the wholesale market in competition with other utilities and power generators. During the past five 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 customers.

As a result of the retirement of the coal-fired units at Eagle Valley (April 2016) and the expected completion of the CCGT (first half of 2018), 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.

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, “Item 1. Business - Regulatory Matters - Retail Ratemaking” and “Item 1. Business - MISO Operations” 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.

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 their 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.

Our performance in production reliability was slightly better than our target in 2016. Both our planned and unplanned outage rates associated with our generation plants in 2016 were consistent with outage rates that we experienced in 2015 partially due to scheduled outages at our Petersburg Plant to complete required maintenance.

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 “Item 1. Business” of this report 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.

Utility Operating Expenses

2016 versus 2015

The following table illustrates our 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 our 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.

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.

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.

KEY TRENDS AND UNCERTAINTIES

During 2017 and beyond, we expect that our financial results will be driven primarily by retail demand, weather, energy efficiency 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 recovery of capital expenditures through base rate growth; and


•	the passage of new legislation or implementation of regulations.

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 “Item 1. Business” and “Item 1A. Risk Factors” of this Form 10-K.

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 “Item 1. Business – Regulatory Matters”, Note 2, “Regulatory Matters” to the Financial Statements and “Item 1. Business – Environmental Matters” of this Form 10-K.

Macroeconomic and Political

The outcome of the 2016 U.S. elections could result in significant changes to U.S. tax laws, and environmental and energy policies, the impact of which is uncertain.

CAPITAL RESOURCES AND LIQUIDITY

As of December 31, 2016, we had unrestricted cash and cash equivalents of $35.0 million and available borrowing capacity of $200 million under our $250 million unsecured revolving credit facility after outstanding borrowings and existing letters of credit. All of IPL’s long-term borrowings must first be approved by the IURC and the aggregate amount of IPL’s short-term indebtedness must be approved by the FERC. We have approval from FERC to borrow up to $500 million of short-term indebtedness outstanding at any time through July 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 December 31, 2016, 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 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. 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. In addition, due to current and expected future environmental regulations and replacement generation projects, equity capital from AES and CDPQ was used as a significant funding source during the first half of 2016 and in recent years. In March 2016 and April 2015, IPALCO received equity capital contributions of $134.3 million and $214.4 million, respectively, from the issuance of 7,403,213 and 11,818,828 shares of common stock, respectively, to CDPQ for funding needs primarily related to existing environmental and replacement generation projects at IPL, which IPALCO then made the same investments in IPL. 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.

Cash Flows

The following table provides 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	)

Operating Activities

The following table summarizes 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	)

2016 versus 2015

The net change in 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 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

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.

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.

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 $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 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 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 $632 million (of which $596 million has been expended through December 31, 2016) on replacement generation costs through 2017 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 $36 million is projected to be expended in 2017. Please see “Item 1. Business – Environmental Matters – Unit Retirements and Replacement Generation” for more details.

Also, as a result of environmental regulations, IPL completed the refueling of Unit 7 at our Harding Street station in the second quarter of 2016, converting from coal-fired to natural gas-fired. The 2017 cost of the projects necessary to complete this conversion, including costs for NPDES, MATS compliance and dry ash handling, are expected to be $14 million (IPL plans to spend a total of $101 million on this project, including amounts already expended through December 31, 2016). Please see “Item 1. 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 $37 million. IPL plans to spend a total of $224 million for this

project (of which $187 million has been expended through December 31, 2016). Please see “Item 1. Business - Environmental Matters - Environmental Wastewater Requirements” 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 to 2019 forecast are expected to be $61 million. IPL plans to spend a total of $95 million for these projects (of which $34 million has been expended through December 31, 2016). Please see “Item 1. Business - Environmental Matters - Waste Management and CCR” and “Item 1. Business - Environmental Matters - NAAQS” for more details.

Other environmental capital spending for the period 2017-2019 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” for more details.

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 2018 IPALCO Notes or the 2020 IPALCO Notes; however, all of IPL’s common stock is pledged to secure these notes. Accordingly, IPALCO’s ability to make payments on the 2018 IPALCO Notes and the 2020 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

At the filing date of this annual report on Form 10-K, we had the following amounts available under the revolving credit facility:

$ in millions

Type

Maturity

Commitment

Amounts available as of February 24, 2017

IPL

Revolving

October 2020

250.0

195.0

IPL First Mortgage Bonds

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.” For further discussion, please see Note 7, “Debt - Unsecured Notes” to the Financial Statements.

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.

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	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 ⁽³⁾	7.1		7.1		—		—		—
Total ⁽⁴⁾	$	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)	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.


(4)	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 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.

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 Financial Statements. 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 Financial Statements.

Revenue Recognition

Revenues related to the sale of energy are generally recognized when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is accrued. In making our estimates of unbilled revenue, we use complex models that consider various factors including daily generation volumes; known amounts of energy usage by nearly all residential, small commercial and industrial customers; estimated line losses; and estimated customer rates based on prior period billings. Given the use of these models, and that customers are billed on a monthly cycle, we believe it is unlikely that materially different results will occur in future periods when revenue is billed. 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 Financial Statements.

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 Financial Statements for further information.

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 Financial Statements for information about significant contingencies involving us.

NEW ACCOUNTING STANDARDS

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE 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. 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 65% 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 Note 2, “Regulatory Matters – FAC and Authorized Annual Jurisdictional Net Operating Income” to the Financial Statements.

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 $38.9 million reduction in fair value as of December 31, 2016 and approximately a $6.6 million increase to the 2017 pension expense. Please see Note 9, “Benefit Plans” to the Financial Statements 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 December 31, 2016, we had approximately $2,438.5 million principal amount of fixed rate debt and $140.0 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 December 31, 2016 was comprised of $90.0 million under our Series 2015A and Series 2015B notes and $50.0 million under our Credit Agreement. Based on amounts outstanding as of December 31, 2016, 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 $0.4 million and $(0.4 million), respectively.

The following table shows our consolidated indebtedness (in millions) by maturity as of December 31, 2016:



	2017		2018		2019		2020		2021		Thereafter		Total		Fair Value
Fixed-rate	$	24.7	$	400.0	$	—	$	405.0	$	95.0	$	1,513.8	$	2,438.5	$	2,543.5
Variable-rate	50.0		—		—		90.0		—		—		140.0		140.0
Total Indebtedness	$	74.7	$	400.0	$	—	$	495.0	$	95.0	$	1,513.8	$	2,578.5	$	2,683.5
Weighted Average Interest Rates by Maturity	3.459%		5.000%		N/A		3.051%		3.875%		4.976%		4.525%

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 Financial Statements.

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.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS



	Page No.
IPALCO Enterprises, Inc. and Subsidiaries – Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm – 2016, 2015 and 2014	51
Consolidated Statements of Operations for the years ended December 31, 2016, 2015 and 2014	52
Consolidated Balance Sheets as of December 31, 2016 and 2015	53
Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015 and 2014	54
Consolidated Statements of Common Shareholders’ Equity and Noncontrolling Interest
for the years ended December 31, 2016, 2015 and 2014	55
Notes to Consolidated Financial Statements	56

Indianapolis Power & Light Company and Subsidiary – Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm – 2016, 2015 and 2014	87
Consolidated Statements of Operations for the years ended December 31, 2016, 2015 and 2014	88
Consolidated Balance Sheets as of December 31, 2016 and 2015	89
Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015 and 2014	90
Consolidated Statements of Common Shareholder’s Equity for the years ended
December 31, 2016, 2015 and 2014	91
Notes to Consolidated Financial Statements	92

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



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.



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.



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.



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.

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

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

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.

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.

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.



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.

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.

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.

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 reduceSO₂ 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

ASC 410 “Asset Retirement and Environmental Obligations” addresses financial accounting and reporting for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal operation. A legal obligation for purposes of ASC 410 is an obligation that a party is required to settle as a result of an existing law, statute, ordinance, written or oral contract or the doctrine of promissory estoppel.

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.

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.

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

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.

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

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.

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.

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

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.

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%.

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

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.

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	%

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.

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.

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).

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.



	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

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%



	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	%

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

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.

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.

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



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.



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.



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.



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.

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

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.

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

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.

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.



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 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.	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.

2. REGULATORY MATTERS

General

Basic Rates and Charges

FAC and Authorized Annual Jurisdictional Net Operating Income

ECCRA

DSM

Wind and Solar Power Purchase Agreements

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

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



	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.

101

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.

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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.

105

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

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)	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	—
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

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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.”

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

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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.

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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	%

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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

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).

113

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

114



	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

115

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 following table summarizes the Company’s target pension plan allocation for 2016:



Asset Category:	Target Allocations
Equity Securities	60%
Debt Securities	40%

116



	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	%

117

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

118

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.

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.

119

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

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.

120

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

The Company maintains disclosure controls and procedures that are designed to ensure that information required to be

disclosed in the reports that the Company files or submits under the Securities Exchange Act of 1934, as amended (the

“Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and

forms, and that such information is accumulated and communicated to the CEO and CFO, as appropriate, to allow timely

decisions regarding required disclosures.

The Company carried out the evaluation required by Rules 13a-15(b) and 15d-15(b), under the supervision and with the

participation of our management, including the CEO and CFO, of the effectiveness of our “disclosure controls and

procedures” (as defined in the Exchange Act Rules 13a-15(e) and 15d-15(e)). Based upon this evaluation, the CEO and CFO

concluded that as of December 31, 2016, our disclosure controls and procedures were effective.

Management’s Report on Internal Control over Financial Reporting

Management of the Company is responsible for establishing and maintaining adequate internal control over financial

reporting, as defined in Rule 13a-15(f) under the Exchange Act. The Company’s internal control over financial reporting is a

process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial

statements for external purposes in accordance with GAAP and includes those policies and procedures that:

• pertain to the maintenance of records that in reasonable detail, accurately and fairly reflect the transactions and

dispositions of the assets of the Company;

• provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements

in accordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with

authorizations of management and directors of the Company; and

• provide reasonable assurance that unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements are prevented or detected timely.

Management, including our CEO and CFO, does not expect that our internal controls will prevent or detect all errors and

all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance

that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are

resource constraints, and the benefits of controls must be considered relative to their costs. In addition, any evaluation of the

effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of

changes in business conditions, or that the degree of compliance with the policies or procedures deteriorates.

Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2016. In

making this assessment, management used the criteria established in Internal Control – Integrated Framework issued by the

COSO in 2013. Based on this assessment, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2016.

Changes in Internal Control Over Financial Reporting:

There were no changes that occurred during the quarter ended December 31, 2016 that have materially affected, or are

reasonably likely to materially affect, our internal control over financial reporting.

121

ITEM 9B. OTHER INFORMATION

Not applicable.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required to be furnished pursuant to this item with respect to Directors and Executive Officers of IPALCO will be set forth under the captions “Directors” and “Executive Officers” in IPALCO’s Proxy Statement to be furnished to shareholders in connection with the solicitation of proxies by our Board of Directors, which information is incorporated herein by reference.

The information required to be furnished pursuant to this item for IPALCO with respect to the identification of the Audit Committee, the Audit Committee financial expert and the registrant’s code of ethics will be set forth under the caption “Corporate Governance” in the Proxy Statement, which information is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION

The information required to be furnished pursuant to this item for IPALCO will be set forth under the caption “Executive Compensation” in the Proxy Statement, which information is incorporated herein by reference.

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

The information required to be furnished pursuant to this item for IPALCO will be set forth under the caption “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” in the Proxy Statement, which information is incorporated herein by reference.

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

The information required to be furnished pursuant to this item for IPALCO will be set forth under the caption “Certain Relationships and Related Transactions and Director Independence” in the Proxy Statement, which information is incorporated herein by reference.

122

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

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

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

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

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



	Years Ended December 31,
	2016		2015
Audit Fees	$	928,250	$	936,080
Audit Related Fees:
Fees for the audit of IPL’s employee benefit plans	63,940		57,500
Assurance services for debt offering documents	145,300		191,375
Fees for tax services	—		—
Other	17,500		5,000
Total Principal Accounting Fees and Services	$	1,154,990	$	1,189,955

123

ITEM 15. EXHIBITS, FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

(a) Index to the financial statements, supplementary data and financial statement schedules



IPALCO Enterprises, Inc. and Subsidiaries – Consolidated Financial Statements	Page
Report of Independent Registered Public Accounting Firm – 2016, 2015 and 2014	51
Consolidated Statements of Operations for the years ended December 31, 2016, 2015 and 2014	52
Consolidated Balance Sheets as of December 31, 2016 and 2015	53
Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015 and 2014	54
Consolidated Statements of Common Shareholders’ Equity for the years ended December 31,
2016, 2015 and 2014	55
Notes to Consolidated Financial Statements	56
Schedule I – Condensed Financial Information of Registrant	127
Schedule II – Valuation and Qualifying Accounts and Reserves	133

Indianapolis Power & Light Company and Subsidiary – Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm – 2016, 2015 and 2014	87
Consolidated Statements of Operations for the years ended December 31, 2016, 2015 and 2014	88
Consolidated Balance Sheets as of December 31, 2016 and 2015	89
Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015 and 2014	90
Consolidated Statements of Common Shareholder’s Equity for the years ended December 31,
2016, 2015 and 2014	91
Notes to Consolidated Financial Statements	92
Schedule II – Valuation and Qualifying Accounts and Reserves	133

124



(b) Exhibits

Exhibit No.	Document
3.1	Third Amended and Restated Articles of Incorporation of IPALCO Enterprises, Inc. (Incorporated by reference to Exhibit No 3.1 to IPALCO’s Form 8-K dated as of February 18, 2015)
3.2	Amended and Restated By-Laws of IPALCO Enterprises, Inc. (Incorporated by reference to Exhibit No. 3.2 to IPALCO’s Form 8-K dated as of February 18, 2015)
4.1*	Pledge Agreement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company, N.A. dated as of November 14, 2001
4.2*	Mortgage and Deed of Trust, dated as of May 1, 1940, between IPL and the Bank of New York Mellon Trust Company, NA, as successor in interest to American National Bank & Trust Company of Chicago, Trustee
4.3	The following supplemental indentures to the Mortgage and Deed of Trust referenced in 4.2 above: Third Supplemental Indenture, dated as of April 1, 1949 Tenth Supplemental Indenture, dated as of October 1, 1960 Eighteenth Supplemental Indenture, dated as of February 15, 1974 Thirty-Seventh Supplemental Indenture, dated as of October 1, 1993 Forty-Eighth Supplemental Indenture, dated as of January 1, 2004 Fifty-Third Supplemental Indenture, dated as of October 1, 2006 Fifty-Fourth Supplemental Indenture, dated as of June 1, 2007 Fifty-Eighth Supplemental Indenture, dated as of August 1, 2011 *Fifty-Ninth Supplemental Indenture, dated as of August 1, 2011 Sixtieth Supplemental Indenture, dated as of November 1, 2011 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s December 31, 2011 10-K)
	Sixty-First Supplemental Indenture, dated as of June 1, 2013 (Incorporated by reference to Exhibit No. 4.1 to IPALCO’s June 30, 2013 Form 10-Q)
	Sixty-Second Supplemental Indenture, dated as of June 1, 2014 (Incorporated by reference to Exhibit No. 4.1 to IPALCO’s June 30, 2014 Form 10-Q)
	Sixty-Third Supplemental Indenture, dated as of September 1, 2015 (Incorporated by reference to Exhibit No. 4.1 to IPALCO’s September 30, 2015 Form 10-Q)
	Sixty-Fourth Supplemental Indenture, dated as of May 1, 2016 (Incorporated by reference to Exhibit No. 4.1 to IPALCO’s June 30, 2016 Form 10-Q)
	Sixty-Fifth Supplemental Indenture, dated as of December 1, 2016
4.5*	Pledge Agreement Supplement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company, N.A., as successor Collateral Agent, dated as of April 15, 2008, to the Pledge Agreement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company dated as of November 14, 2001
4.6*	Pledge Agreement Supplement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company, N.A., dated as of May 18, 2011 to the Pledge Agreement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company, N.A., dated as of November 14, 2001
4.7*	Indenture between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company, N.A., as Trustee, dated as of May 18, 2011 for the 5.00% Senior Secured Notes due 2018
4.8	Indenture between IPALCO Enterprises, Inc. and U.S. Bank, National Association, as Trustee, dated June 25, 2015 for IPALCO's 3.45% Senior Secured Notes due 2020 (Incorporated by reference to Exhibit No. 4.1 to IPALCO’s June 30, 2015 Form 10-Q)
4.9	Pledge Agreement Supplement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company, N.A., as Collateral Agent, dated June 25, 2015 to the Pledge Agreement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company dated November 14, 2001, as amended (Incorporated by reference to Exhibit No. 4.2 to IPALCO’s June 30, 2015 Form 10-Q)
10.1*	Interconnection Agreement, dated as of April 1, 2008, between American Electric Power Service Corporation, as agent for Indiana Michigan Power Company, and IPL
10.2*	Interconnection Agreement, dated as of December 2, 1968, between IPL and Southern Indiana Gas and Electric Company as modified through Modification Number 11
10.3*	Interconnection Agreement dated December 1, 1981, between IPL and Hoosier Energy Rural Electric Cooperative, Inc., as modified through Modification 6
10.4*	Tenth Supplemental Agreement to Interconnection Agreement between IPL and PSI Energy, Inc., dated as of June 26, 2002, amending and completely restating prior agreements

125



10.5	$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 (Incorporated by reference to Exhibit No. 10.1 to IPALCO’s March 31, 2014 10-Q)
10.6	Subscription Agreement by and between IPALCO and CDP Infrastructure Fund GP, a wholly owned subsidiary of La Caisse de dépôt et placement du Québec, dated December 14, 2014 (Incorporated by reference to Exhibit 10.10 to IPALCO's December 31, 2014 10-K/A)
10.7	IPALCO Shareholders’ Agreement by and among AES U.S. Investments, Inc., IPALCO Enterprises, Inc. and CDP Infrastructure Fund GP dated as of February 11, 2015 (Incorporated by reference to Exhibit No. 10.1 to IPALCO’s March 31, 2015 10-Q)
10.8	First Amendment to Credit Agreement by and among IPL, the Lenders party thereto, Fifth Third Bank, as syndication agent, BMO Harris Bank N.A., as documentation agent and PNC Bank, National Association, as administrative agent, dated as of October 16, 2015 (Incorporated by reference to Exhibit No. 10.1 to IPALCO’s September 30, 2015 10-Q)
10.9	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 (Incorporated by reference to Exhibit 10.10 to IPALCO’s December 31, 2015 10-K)
10.10	Note Purchase and Covenants Agreement by and among Indianapolis Power & Light Company the Lenders Party Hereto 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 (Incorporated by reference to Exhibit 10.11 to IPALCO’s December 31, 2015 10-K)
10.11	Second Amendment dated as of April 22, 2016 to Credit Agreement by and among IPL, the Lenders party thereto, Fifth Third Bank, as syndication agent, BMO Harris Bank N.A., as document agent and PNC Bank, National Association, as administrative agent, dated as of May 6, 2014, as amended by First Amendment thereto dated as of October 16, 2015 (Incorporated by reference to Exhibit No. 10.1 to IPALCO’s June 30, 2016 10-Q)
10.12	First Amendment dated as of April 29, 2016 to Note Purchase and Covenants Agreement by and among IPL, 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 (Incorporated by reference to Exhibit No. 10.3 to IPALCO’s June 30, 2016 10-Q)
21	Subsidiaries of IPALCO Enterprises, Inc. (Incorporated by reference to Exhibit No. 21 to IPALCO’s December 31, 2014 10-K)
31.1	Certification by Chief Executive Officer required by Rule 13a-14(a) or 15d-14(a).
31.2	Certification by Principal Financial Officer required by Rule 13a-14(a) or 15d-14(a).
32	Certification required by Rule 13a-14(b) or 15d-14(b).
101.INS	XBRL Instance Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.SCH	XBRL Taxonomy Extension Schema Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.LAB	XBRL Taxonomy Extension Label Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)

* Incorporated by reference to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011.

126

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

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF REGISTRANT



IPALCO ENTERPRISES, INC.
Schedule 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.

127



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.

128



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.

129



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.

130

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.

131

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.

132

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

Item 16. Form 10-K Summary

None.

133

SIGNATURES

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

IPALCO ENTERPRISES, INC.

(Registrant)

Date: February 24, 2017 /s/ Kenneth J. Zagzebski

Kenneth J. Zagzebski

Chief Executive Officer

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



Signature	Capacity	Date
/s/ Kenneth J. Zagzebski	Chief Executive Officer and Director (Principal Executive Officer)	February 24, 2017
Kenneth J. Zagzebski		February 24, 2017
/s/ Thomas M. O’Flynn	Director and Chairman	February 24, 2017
Thomas M. O'Flynn	Director and Chairman	February 24, 2017
/s/ Margaret E. Tigre	Director	February 24, 2017
Margaret E. Tigre	Director	February 24, 2017
/s/ Richard A. Sturges	Director	February 24, 2017
Richard A. Sturges	Director	February 24, 2017
/s/ Paul L. Freedman	Director	February 24, 2017
Paul L. Freedman	Director	February 24, 2017
/s/ Michael S. Mizell	Director	February 24, 2017
Michael S. Mizell	Director	February 24, 2017
/s/ Andrew J. Horrocks	Director	February 24, 2017
Andrew J. Horrocks	Director	February 24, 2017
/s/ Olivier Renault	Director	February 24, 2017
Olivier Renault	Director	February 24, 2017
/s/ Renaud Faucher	Director	February 24, 2017
Renaud Faucher	Director	February 24, 2017
/s/ Craig L. Jackson	Chief Financial Officer and Director (Principal Financial Officer)	February 24, 2017
Craig L. Jackson		February 24, 2017
/s/ Kurt A. Tornquist	Controller (Principal Accounting Officer)	February 24, 2017
Kurt A. Tornquist	Controller (Principal Accounting Officer)	February 24, 2017

________________________________________________________________________________________________________________________________

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

No annual report or proxy material has been sent to security holders.

134

Exhibit 31.1

Certification Pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities and Exchange Act of 1934

I, Kenneth J. Zagzebski, certify that:


1.	I have reviewed this annual report on Form 10-K of IPALCO Enterprises, Inc. (the “registrant”);


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s Board of Directors (or persons performing the equivalent functions):


(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 24, 2017 /s/ Kenneth J. Zagzebski

Kenneth J. Zagzebski

Chief Executive Officer

135

Exhibit 31.2

Certification Pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities and Exchange Act of 1934

I, Craig L. Jackson, certify that:


1.	I have reviewed this annual report on Form 10-K of IPALCO Enterprises, Inc. (the “registrant”);


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s Board of Directors (or persons performing the equivalent functions):


(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 24, 2017 /s/ Craig L. Jackson

Craig L. Jackson

Chief Financial Officer

136

Exhibit 32

Certification Pursuant to Rule 13a-14(b) or 15d-14(b) of the Securities and Exchange Act of 1934 and Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

The certification set forth below is being submitted in connection with the Annual Report on Form 10-K for the year ended December 31, 2016 (the “Report”) for the purpose of complying with Rule 13a-14(b) or Rule 15d-14(b) of the Securities Exchange Act of 1934 and Section 1350 of Chapter 63 of Title 18 of the United States Code.

Kenneth J. Zagzebski, Chief Executive Officer, and Craig L. Jackson, Chief Financial Officer of IPALCO Enterprises, Inc. (“IPALCO”), each certifies that, to the best of his knowledge:


1.	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and


2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of IPALCO.

Date: February 24, 2017 /s/ Kenneth J. Zagzebski

Kenneth J. Zagzebski

Chief Executive Officer

Date: February 24, 2017 /s/ Craig L. Jackson

Craig L. Jackson

Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to IPALCO and will be retained by IPALCO and furnished to the SEC or its staff upon request.

137

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IPALCO ENTERPRISES, INC. Reports

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