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, 2017

or

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

ACT OF 1934

Commission file number1-8644

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¨Noþ

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 ¨Noþ

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

(Prior to December 5, 2017, IPALCO Enterprises, Inc. was a voluntary filer in 2017. On December 5, 2017, the Securities Exchange Commission declared effective the IPALCO Enterprises, Inc. Registration Statement on Form S-4, originally filed on November 13, 2017. IPALCO Enterprises, Inc. 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 website, 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, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act:

Large accelerated filer ¨                           Accelerated filer ¨

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

Emerging growth company ¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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

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At February 26, 2018, 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 PartIII.

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IPALCO ENTERPRISES, INC.

Annual Report on Form 10-K

ForFiscalYear EndedDecember 31, 2017

Table of Contents

Item No.		Page No.
	DEFINED TERMS	4
	PART I
1.	Business	7
1A.	Risk Factors	19
1B.	Unresolved Staff Comments	30
2.	Properties	30
3.	Legal Proceedings	30
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	48
8.	Financial Statements and Supplementary Data	50
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	125
9A.	Controls and Procedures	125
9B.	Other Information	126
PART III
10.	Directors, Executive Officers and Corporate Governance	126
11.	Executive Compensation	126
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	126
13.	Certain Relationships and Related Transactions, and Director Independence	126
14.	Principal Accounting Fees and Services	127
PART IV
15.	Exhibits, Financial Statements and Financial Statement Schedules	129
16.	Form 10-K Summary	138
SIGNATURES		139

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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
2016 Rate Order	The order issued in March 2016 by the IURC authorizing IPL to increase its basic rates and charges by $30.8 million annually.
2018 IPALCO Notes	$400 million of 5.00% Senior Secured Notes due May 1, 2018
2020 IPALCO Notes	$405 million of 3.45% Senior Secured Notes due July 15, 2020
2024 IPALCO Notes	$405 million of 3.70% Senior Secured Notes due September 1, 2024
AES	The AES Corporation
AES 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
DOE	U.S. Department of Energy
DSM	Demand Side Management
ECCRA	Environmental Compliance Cost Recovery Adjustment
ELG	Effluent Limitation Guidelines
EPA	U.S. Environmental Protection Agency
EPAct	Energy Policy Act of 2005
ERISA	Employee Retirement Income Security Act of 1974
FAC	Fuel Adjustment Charge
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FGDs	Flue-Gas Desulfurizations

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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
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
TCJA	Tax Cuts and Jobs Act
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

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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.  Marketfor Registrant’s Common Equity, Related Stockholder Mattersand Issuer Purchaseof 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:

• growth in our service territory and changes in demand and demographic patterns;

▪ 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

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▪ 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 Analysisof 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 “utility” and “all other.” Our total electric revenues and net income for the year ended December 31, 2017 were $1.3 billion and $108.8 million, respectively. The book value of our total assets as of December 31, 2017 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 941,000. 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 2017. 

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 2017, IPL’s retail kWh sales have decreased at a compound annual rate of 1.5%. Conversely, the number of our retail customers grew at a compound annual rate of 0.5% 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 2013 through 2017 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, 2018, IPL had 1,354 employees of whom 1,268 were full time. Of the total employees, 868 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

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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, 2018, 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, which provides frequency response. The third station, Eagle Valley, retired its coal-fired units in April 2016 and several small oil-fired units prior to this date. The CCGT at Eagle Valley is expected to be completed in the first half of 2018 with a rated output of 671 MW. The fourth station, Georgetown, is a small peaking station that uses natural gas to power combustion turbines. For electric generation, the net winter design capacity is 2,996 MW and net summer design capacity is 2,881 MW. Our highest summer peak level of 3,139 MW was recorded in August 2007 and the highest winter peak level of 2,971 MW was recorded in January 2009.

Our sources of electric generation are as follows:

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

(1) In April 2016, we retired the four coal-fired units at Eagle Valley. The CCGT at the Eagle Valley Station is expected to be completed in the first half of 2018. Upon completion, the CCGT will have an expected winter and summer capacity of approximately 644 to 685 MW.

Net electrical generation during 2017, at our Petersburg, Harding Street and Georgetown plants accounted for approximately 87.4%, 11.9% and 0.7%, respectively, of our total net generation. After completion of the CCGT at the Eagle Valley Station, we expect net electrical generation to change accordingly going forward.

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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 4,919 circuit miles of underground primary and secondary cables and 6,111 circuit miles of overhead primary and secondary wire. Underground street lighting facilities include 771 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, shared cost of transmission expansion, resource adequacy, 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 its ongoing costs from MISO. IPL’s MISO costs were deferred under the authority of the IURC and the majority of such costs are being recovered per specific rate order; recovery for the remaining costs is probable but timing not yet determined. The unamortized balance of total MISO costs deferred as long-term regulatory assets were $101.6 million and $114.4 million as of December 31, 2017 and 2016, 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 Statementsfor additional details on the regulatory oversight of the FERC and the IURC.

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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 the 2016 Rate Order) to implement three new rate riders for current recovery from customers ofongoing 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

We are subject to various federal, state, regional and local environmental protection and health and safety laws and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of hazardous materials; the emission and discharge of hazardous and other materials into the environment; and the health and safety of our employees. These laws and regulations often require a lengthy and complex process of obtaining and renewing permits and other governmental authorizations from federal, state and local agencies. Violation of these laws, regulations or permits can result in substantial fines, other sanctions, suspension or revocation of permits and/or facility shutdowns. There can be no assurance that we have been or will be at all times in full compliance with such laws, regulations and permits.

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

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management developed and implemented a plan, which was approved by the IURC, to comply with this rule and all four Petersburg units have been and remain in compliance with the MATS rule since applicable deadlines.

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 worked 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 the Federal Register. Several lawsuits were filed appealing that finding in the D.C. Circuit. On April 27, 2017, the U.S. Court of Appeals for the D.C. Circuit ordered that these challenges be held in abeyance pending further order from the court as the EPA reconsiders the finding. Further rulemakings and/or proceedings are possible; 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. In addition, the results of required groundwater monitoring data could require corrective actions to be taken. On September 13, 2017, EPA indicated that it would reconsider certain provisions of the CCR Rule in response to two petitions it received to reconsider the final rule. On November 7, 2017, EPA requested that legal challenges be held in abeyance and certain provisions of the rule be remanded without vacatur. It is too early to determine whether the results of groundwater monitoring data or the outcome of CCR litigation or a potential CCR Remand Rule may have a material impact on our business, financial condition or results of operations.

The existing ash ponds at Petersburg did not meet certain structural stability requirements set forth in the CCR rule. As such, IPL would have been 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.

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

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. The extended compliance deadline was September 29, 2017 for IPL’s Harding Street and Petersburg facilities. The deadline for Petersburg to commission a portion of the treatment system was subsequently extended to April 11, 2018.

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IPL developed and implemented its wastewater compliance plans, which were approved by the IURC. The IURC order 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 for recovery through IPL’s next basic rate case proceeding.

In November 2015, the EPA published its final ELG rule to reduce toxic pollutants discharged into waterways by power plants. In addition to the wastewater treatment technologies being installed and operated for compliance with the requirements of the October 2012 NPDES permit described above, the final ELG rule will require closed loop or dry bottom ash handling at Petersburg. IPL has installed 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 filed challenges to the ELG rule, which are pending before the U.S. Court of Appeals for the Fifth Circuit (the “Fifth Circuit”). Environmental groups moved to intervene in these cases on behalf of the EPA. On April 24, 2017, the Fifth Circuit granted the EPA’s request to hold these challenges in abeyance during review of the rule and possible rulemaking. On August 14, 2017, EPA requested that the litigation involving certain provisions remain held in abeyance pending EPA’s reconsideration and possible rulemaking. The Trump administration issued a stay of certain compliance deadlines in the ELG rule, which was published in the Federal Register on April 25, 2017. On May 3, 2017, environmental groups filed legal challenges to the stay. On September 18, 2017, EPA published a final rule in the Federal Register delaying certain compliance dates of the ELG and withdrew the stay issued by the Trump Administration on April 25, 2017.

On June 29, 2015, the EPA and the U.S. Army Corps of Engineers published a rule defining federal jurisdiction over waters of the U.S. This rule, which initially became effective in August 2015, may expand or otherwise change the number and types of waters or features subject to CWA permitting. In October 2015, the U.S. Court of Appeals for the Sixth Circuit (the “Sixth Circuit”) issued an order to temporarily stay the “Waters of the United States” rule nationwide, but the applicability of that stay is now in question because the U.S. Supreme Court, on January 22, 2018, ruled that the Sixth Circuit did not have jurisdiction over the appeal. On a separate track, beginning on June 27, 2017, the EPA proposed a rule that would rescind the “Waters of the U.S.” rule and re-codify the definition of “Waters of the United States” that existed prior to the 2015 rule. On November 22, 2017, EPA published a proposed rule to delay the original effective date of the 2015 “Waters of the United States” rule by two years from the date of the final action of the proposal, which would allow the EPA to create a new rule in the interim period without the 2015 rule taking effect. We cannot predict the outcome of this judicial or regulatory process, but if the “Waters of the United States” rule is ultimately implemented in its current or substantially similar form and survives the legal challenges, it could have a material impact on our business, financial condition or results of operations.

In June 2016, the EPA published the final national chronic aquatic life criterion for the pollutant, Selenium, in fresh water. IPL’s NPDES permits may be updated to include Selenium water quality based effluent limits based on a site specific evaluation process, which includes determining if there is a reasonable potential to exceed the revised final Selenium water quality standards for the specific receiving water body utilizing actual and/or projected discharge information for the IPL generating facilities. As a result, it is not yet possible to predict the potential impacts of this criteria at this time. However, if additional capital expenditures are necessary, they could be material. We would seek recovery of these capital expenditures; however, there is no guarantee we would be successful in this regard.

Climate ChangeLegislation 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 ofGHGs 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 mandatedGHG 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;

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▪ 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 any 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).

The EPA regulates 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 December 22, 2015, the EPA’s final CO₂ emission rules for existing power plants, the CPP, became effective. The CPP provides for interim emissions performance rates that must be achieved beginning in 2022 and final emissions performance rates that must be achieved starting in 2030. Under the CPP, states are required to meet state-wide emission rate standards or equivalent mass-based standards, with the goal being a 32% reduction in total U.S. power sector emissions from 2005 levels by 2030. The CPP would require states to submit, by 2016, implementation plans to meet the standards or a request for an

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extension to 2018. If a state fails to develop and submit an approvable implementation plan, the EPA will finalize a federal plan for that state. The full impact of the CPP would depend on the following:

• whether and how the states in which the Company’s U.S. businesses operate respond to the CPP;

• whether the states adopt an emissions trading regime and, if so, which trading regime;

• how other states respond to the CPP, which will affect the size and robustness of any emissions trading market; and

• how other companies may respond in the face of increased carbon costs.

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. Several states and industry groups challenged the NSPS for CO₂ in the D.C. Circuit Court. Pursuant to a court order issued in August 2017, the litigation is being held in indefinite abeyance pending further court order.

In addition, several states and industry groups filed petitions in the D.C. Circuit Court challenging the CPP and requested a stay of the rule while the challenge was considered. The D.C. Circuit Court denied the stay and granted requests to consider the challenges on an expedited basis. On February 9, 2016, the U.S. Supreme Court issued orders staying implementation of the CPP pending resolution of challenges to the rule. On March 28, 2017, the EPA filed a motion in the D.C. Circuit Court to hold the challenges to both the CPP and the GHG NSPS in abeyance in light of an Executive Order signed the same day. On April 28, 2017, the D.C. Circuit Court issued orders holding the challenges to both rules in abeyance for 60 days, with subsequent extensions granted by the court. The most recent extension of the CPP litigation was set to expire in January 2018 but, on January 10, 2018, the EPA filed a status report requesting that the court continue to hold the case in abeyance pending the conclusion of further rulemaking on the CPP. On October 16, 2017, the EPA published in the Federal Register a proposed rule that would rescind the CPP. On December 28, 2017, the EPA published an Advance Notice of Proposed Rulemaking to solicit comments as EPA considers a potential rule to establish emission guidelines to replace the CPP and limit GHG emissions from existing electric generating units under Section 111(d) of the CAA. Some states and environmental groups have opposed the EPA’s most recent request to continue to hold the CPP appeals in abeyance and the D.C. Circuit Court has not yet acted upon the EPA’s request.

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

We will likely not know the answers to the above questions regarding the CPP until later in 2018 or potentially 2019. As the first compliance period would not end until 2025, and because we cannot predict whether the CPP will survive the legal challenges or be repealed or replaced through rulemaking, it is too soon to determine the CPP’s potential impact on our business, operations or financial condition, but any such impact could be material.

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. had proposed that implementation of the CPP would fulfill much of its intended reductions under the Paris Agreement, but in August 2017, the U.S. informed the United Nations it would withdraw from the Paris Agreement, but would continue to participate in related meetings during the withdrawal process which is expected to take until through 2020.

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 GHG regulations 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.

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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 $655 million. The current estimated cost of these projects is $655 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 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. At this time, we cannot 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

Following implementation of and legal challenges of EPA’s March 2005 federal CAIR, the federal CSAPR became effective in January 2015 requiring 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. On October 26, 2016, the EPA published a final rule to update the CSAPR to address the 2008 ozone NAAQS (“CSAPR Update Rule”). The CSAPR Update Rule found that NOx ozone season emissions in 22 states (including Indiana) affect the ability of downwind states to attain and maintain the 2008 ozone NAAQS, and accordingly, the EPA issued federal implementation plans that both generally provide updated CSAPR NOx ozone season emission budgets for electric generating units within these states and that implement these budgets through modifications to the CSAPR NOx ozone season allowance trading program. Implementation began in the 2017 ozone season (May through September 2017). Legal challenges to this rule have been filed. Affected facilities 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 in future years, 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 ambient ozone from 80 parts per billion to 75 parts per billion. In July 2013, the U.S. Circuit Court of Appeals upheld the

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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 NOx emissions. On November 3, 2017, the EPA published a final rule denying the petition. On December 26, 2017, eight northeastern states filed a petition for review challenging the final rule denying the petition. If Indiana were added to the Ozone Transport Region, our facilities could be subject to enhanced restrictions on NOx emissions.

On October 26, 2015, the EPA published a final rule lowering the NAAQS for ozone to 70 parts per billion from 75 parts per billion. Attainment EPA published its final designations for the areas in which our operations are located on November 16, 2017. None of our operations are located in areas designated as nonattainment.

Additionally, on November 16, 2016, Maryland submitted a petition to the EPA pursuant to Section 126 of the CAA requesting that new limitations on NOx emissions from 36 upwind generating units, including IPL Petersburg Generating Station Units 2 and 3, on the basis that they are contributing significantly to Maryland’s ability to meet the 2008 ozone NAAQS. On January 3, 2017, the EPA issued an extension to its 60-day deadline for response to July 15, 2017. On September 27, 2017, the State of Maryland filed a complaint against the EPA for failing to address its November 2016 CAA petition for such federal agency to determine that 36 electric generating units in five upwind states, including two Petersburg units, emit pollutants that contribute to non-attainment of NAAQS for ozone in Maryland. If this petition is granted, our Petersburg Generating Station Unit 2 and 3 could be subject to additional requirements. We would seek recovery of any resulting capital expenditures; however, there is no guarantee we would be successful in this regard.

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 were required to meet the emission limits imposed by the rule. On April 26, 2017, the IURC approved IPL’s request for NAAQS SO2 compliance at its Petersburg generation station with 80% of qualifying costs recovered through a rate adjustment mechanism and the remainder recorded as a regulatory asset for recovery in a subsequent rate case. The approved capital cost of the NAAQS SO2 compliance plan is approximately $29 million.

Based on these current and potential national ambient air quality standards, the state of Indiana will be required to determine whether certain areas within the state meet the NAAQS. With respect to Marion, Morgan and Pike Counties, as well as any other areas determined to be in “nonattainment,” the state of Indiana will be required to modify its State Implementation Plan to detail how the state will regain its attainment status. As part of this process, it is possible that the IDEM or the EPA may require reductions of emissions from our generating stations to reach attainment status for ozone, fine particulate matter or SO2. At this time, we cannot predict what the impact will be to IPL with respect to these new ambient standards, but it could be material.

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

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added to an existing facility must reduce both impingement and entrainment that achieves one of two alternatives under national BTA standards. IPL’s NPDES permits will be updated with the requirements of this rule, including any source-specific requirements arising from the evaluation process described above. As a result, it is not yet possible to predict the total impacts of this final rule at this time, including any challenges to such final rule and the outcome of any such challenges. However, if additional capital expenditures are necessary, they could be material. We would seek recovery of these capital expenditures; however, there is no guarantee we would be successful in this regard. 

Other

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

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 $431 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; and EPA’s proposed and final regulations related to GHG emissions from power plants. 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 $655 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 88% of the total kWh we generated in 2017 was from coal as compared to approximately 84% and 97% in 2016 and 2015, respectively. Our existing coal contracts provide for all of our current projected requirements in 2018 and approximately 75% in total for the three-year period ending December 31, 2020. We have long-term coal contracts with four suppliers. Approximately 50% of our existing coal under contract for the three-year period ending December 31, 2020 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 from coal to natural gas 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 2017. 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. 

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As a result of the Harding Street Station refueling projects and the retirement of coal-fired units at Eagle Valley in April 2016, we have experienced and expect to continue experiencing 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 the CCGT project, 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 2018, of which 95 MW was in operation as of December 31, 2017. 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 2017 came from the following sources: 66.9% from IPL-owned coal-fired steam generation, 8.9% from IPL-owned natural gas-fired units, and 24.2% from power purchased under power purchase agreements (primarily wind and solar) and from the wholesale power market.

STATISTICAL INFORMATION ON OPERATIONS

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

	Years Ended December 31,
	2017		2016		2015		2014		2013
Operating Revenues(In Thousands):
Residential	$	541,054	$	532,564	$	480,969	$	485,779	$	472,630
Small commercial and industrial	205,473		208,928		192,232		193,213		185,241
Large commercial and industrial	561,194		557,491		526,461		527,719		504,038
Public lighting	9,906		10,023		10,823		10,811		10,743
Retail electric revenues	1,317,627		1,309,006		1,210,485		1,217,522		1,172,652
Wholesale	8,574		15,804		19,307		83,208		62,734
Miscellaneous	23,387		22,620		20,607		20,944		20,348
Total utility operating revenues	$	1,349,588	$	1,347,430	$	1,250,399	$	1,321,674	$	1,255,734
kWh Sales(In Millions):
Residential	4,915		5,152		5,062		5,269		5,243
Small commercial and industrial	1,800		1,850		1,837		1,888		1,882
Large commercial and industrial	6,448		6,620		6,757		6,778		6,841
Public lighting	53		57		53		59		63
Sales – retail customers	13,216		13,679		13,709		13,994		14,029
Wholesale	268		507		689		2,397		2,005
Total kWh sold	13,484		14,186		14,398		16,391		16,034
Retail Customers at End of Year:
Residential	439,741		435,622		431,182		427,866		424,201
Small commercial and industrial	48,684		48,204		47,919		47,534		47,360
Large commercial and industrial	4,705		4,763		4,737		4,749		4,727
Public lighting	959		955		953		945		935
Total retail customers	494,089		489,544		484,791		481,094		477,223

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 website address is www.iplpower.com. The information on our website is not incorporated by reference into this report.

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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 inunscheduled plant outages, unanticipated operation and/or maintenance expenses, increased fuel or purchased power costsand other significant liabilitiesfor 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.

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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 88% of the energy we produced in 2017 was generated by coal as compared to approximately 84% and 97% in 2016 and 2015, respectively. While we have approximately 75% in total of our current coal requirements for the three-year period ending December 31, 2020 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

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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 four suppliers, with about 50% of our existing coal under contract for the three-year period ending December 31, 2020 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 GHGemissions 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 2017, IPL emitted approximately 12 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

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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 IPL retired in the second quarter of 2013, the four coal-fired units at Eagle Valley were retired in April 2016, as described in “Item 1. Business - Environmental Matters - Unit Retirements and Replacement Generation.” Our units were primarily coal-fired and

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the units that have been retired and/or converted 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

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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 expand or otherwise change our transmission system according to decisions made by MISO in addition to 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 Disclosures about Market Risk” for information related to market risks.

Wholesale power marketing activities may add volatility to earnings.

We engage in wholesale power marketing activities that primarily involve the offering of utility-owned or contracted generation into the MISO day-ahead and real-time markets. As part of these strategies, we may also execute energy contracts that are integrated with portfolio requirements around power supply and delivery. The earnings from wholesale marketing activities may vary based on fluctuating prices for electricity and the amount of electric generating capacity, beyond that needed to meet firm service requirements. Beginning April 1, 2016, wholesale margins above and below an established annual benchmark of $6.3 million that is included in IPL’s base rates are shared with our customers at 50%. Accordingly, 50% of any margin above or below $6.3 million is returned to or recovered from IPL’s customers through a rider. In order to reduce the risk of volatility in earnings from wholesale marketing activities, we may at times enter into forward contracts to hedge such risk. If we do not

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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 2017, 2016 or 2015.

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

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

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

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

Current and future conditions in the economy may adversely affect our customers, suppliers and other counterparties, which may adversely affect our results ofoperations, financial conditionand 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, 2017, we had on a consolidated basis $2.6 billion of indebtedness and total common shareholders’ equity of $572.3 million. IPL had $1,608.8 million of first mortgage bonds outstanding as of December 31, 2017, which are secured by the pledge of substantially all of the assets of IPL under the terms of IPL’s mortgage and deed of trust. This level of indebtedness and related security could have important consequences, including the following:

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

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• 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 Planscould materially and adversely impact our results of operations, financial condition and cashflows.

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 harmour results ofoperations, financial conditionand 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.

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

Further, our construction program calls for extensive expenditures for capital improvements and additions, including the installation of environmental upgrades, improvements to generation, transmission and distribution facilities, as well as other initiatives. As a result, we have engaged, and will continue to engage, numerous contractors and have entered into a number of agreements to acquire the necessary materials and/or obtain the required construction related services. In addition, some contracts provide for us to assume the risk of price escalation and availability of certain metals and key components. This could force us to enter into alternative arrangements at then-current market prices that may exceed our contractual prices and cause construction delays. It could also subject us to enforcement action by regulatory authorities to the extent that such a contractor failure resulted in a failure by IPL to comply with requirements or expectations, particularly with regard to the cost of the project. As a result of these events, we might incur losses or delays in completing construction.

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

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

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

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

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

As an electric utility, we are subject to extensive regulation at both the federal and state level. For example, at the federal level, we are regulated by the FERC and the NERC and, at the state level, we are regulated by the IURC. The regulatory power of the IURC over IPL is both comprehensive and typical of the traditional form of regulation generally imposed by state public utility commissions. We face the risk of unexpected or adverse regulatory action. Regulatory discretion is reasonably broad in Indiana. We are subject to regulation by the IURC as to our services and facilities, the valuation of property, the construction, purchase, or lease of electric generating facilities, the classification of accounts, rates of depreciation, the increase or decrease in retail rates and charges, the issuance of securities and incurrence of long-term debt, the acquisition and sale of some public utility properties or securities and certain other matters.

IPL’s tariff rates for electric service to retail customers consist of basic rates and charges which are set and approved by the IURC after public hearings. In addition, IPL’s rates typically 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

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current recovery from customers of ongoing MISO costs and capacity costs, and for sharing with retail customers 50% of wholesale sales margins above and below an established annual benchmark of $6.3 million. Additionally, the capacity rider provides that IPL will share with customers 50% of any capacity sales. Each of such tariff rate components may be set and approved by the IURC in separate proceedings at different points in time (currently the FAC proceedings occur on a quarterly basis, the ECCRA proceedings occur on a semiannual basis, and the proceedings for the three new rate riders occur on an annual basis). These components function somewhat independently of one another, but the overall structure of our rates and charges would be subject to review at the time of any review of our basic rates and charges.

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

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

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

Future events, including the advent of retail competition within IPL’s service territory, could result in the deregulation of part of IPL’s existing regulated business. In addition to effects on our business that could result from any deregulation, such as a loss of customers and increased costs to retain or attract customers upon deregulation, adjustments to IPL’s accounting records may be required to eliminate the historical impact of regulatory accounting. Such adjustments, as required by FASB ASC 980 “Regulated Operations,” could eliminate the effects of any actions of regulators that have been recognized as assets and liabilities. Required adjustments could include the expensing of any unamortized net regulatory assets, the elimination of certain tax liabilities, and a write down of any impaired utility plant balances. We expect IPL to meet the criteria for the application of ASC 980 for the foreseeable future.

We may be subject to material litigation, regulatory proceedings, administrative proceedings, audits, settlements, investigations and claims from time to time 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” andNote 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-

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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 ofoperations, financial conditionand 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. Pursuant to NERC requirements, we have a robust cybersecurity plan in place and are subject to regular audits by an independent auditor approved by NERC. We routinely test our systems and facilities against these regulatory requirements in order to measure compliance, assess potential security risks, and identify areas for improvement. In addition, we provide cybersecurity training for our employees and perform exercises designed to raise employee awareness of cyber risks on a regular basis. Despite our efforts, if our systems or facilities were to be breached or disabled, we may be unable to recover them in a timely manner 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, including personally identifiable information and personal financial 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.

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Tax legislation initiatives or challenges to our tax positions could adversely affect our results of operations and financial condition.

We are subject to the tax laws and regulations of the U.S. federal, state and local governments. From time to time, legislative measures may be enacted that could adversely affect our overall tax positions regarding income or other taxes. There can be no assurance that our effective tax rate or tax payments will not be adversely affected by these legislative measures.

For example, the U.S. federal government recently enacted tax reform that, among other things, reduces U.S. federal corporate income tax rates, imposes limits on tax deductions for interest expense and changes the rules related to capital expenditure cost recovery. There are a number of uncertainties and ambiguities as to the interpretation and application of many of the provisions of the newly enacted tax reform measure. Given the unpredictability of these possible changes and their potential interdependency, it remains difficult to assess the overall effect such tax changes will have on our earnings and cash flow, and the extent to which such changes could adversely impact our results of operations. As the impacts of the new law are determined, and as yet-to-be released regulations and other guidance interpreting the new law are issued, our financial results could be materially impacted.

In addition, U.S. federal, state and local tax laws and regulations are extremely complex and subject to varying interpretations. There can be no assurance that our tax positions will be sustained if challenged by relevant tax authorities and if not sustained, there could be a material impact on our results of operations.

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’s 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 $1,608.8 million at December 31, 2017. In addition, IPALCO has outstanding $810.0 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.

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ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

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

As of February 26, 2018, 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, 2017, 2016 and 2015, we paid dividends to our shareholders totaling $105.1 million,  $123.0 million and $69.5 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

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, 2017 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, 2017 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, 2017, 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.

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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. 

	Years Ended December 31,
	2017		2016		2015		2014		2013
	(In Thousands)
Statement of Operations Data:
Utility operating revenues	$	1,349,588	$	1,347,430	$	1,250,399	$	1,321,674	$	1,255,734
Utility operating income	$	176,564	$	188,881	$	145,276	$	160,913	$	150,746
Allowance for funds used during construction	$	48,100	$	51,006	$	28,111	$	12,344	$	6,848
Net income	$	108,793	$	131,060	$	59,524	$	77,968	$	64,049
Balance Sheet Data (end of period):
Total assets	$	4,740,561	$	4,702,281	$	4,217,169	$	3,652,522	$	3,257,989
Common shareholders’ equity	$	572,276	$	571,183	$	352,933	$	151,271	$	47,774
Cumulative preferred stock of subsidiary	$	59,784	$	59,784	$	59,784	$	59,784	$	59,784
Long-term debt (less current maturities)	$	2,477,538	$	2,474,840	$	2,153,276	$	1,935,717	$	1,805,638
Other Data:
Utility capital expenditures(1)	$	228,861	$	607,716	$	686,064	$	381,626	$	242,124

(1) Capital expenditures includes $10.6 million, $15.5 million and $13.2 million of payments for financed capital expenditures in 2017, 2016 and 2015, respectively.

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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 andWeather-RelatedDamage in ourServiceArea

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 $2.1 million, $3.9 million and $3.6 million in 2017, 2016 and 2015, 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.

OurAbility toSellPower in theWholesaleMarket at aProfit

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 2.9% 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), our ability to have excess generation available for sale on the wholesale market was adversely impacted in 2016, and we expect will continue to be adversely impacted until the expected completion of the CCGT in the first half of 2018.

Our ability to be dispatched in the MISO market to sell power is primarily impacted by the locational market price of electricity and our variable generation costs. The amount of electricity we have available for wholesale sales is impacted by our retail load requirements, generation capacity and unit availability. Our goal is to make wholesale sales when it is profitable to do so. 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

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and therefore our revenues from wholesale sales can fluctuate significantly from year to year. The weighted average price of wholesale MWh we sold was $31.99, $31.17 and $28.02 in 2017, 2016 and 2015, respectively.

OperationalExcellence

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 sustainable high level of performance in these areas simultaneously as compared to our peers. We monitor our performance in these areas, and where practical and meaningful, compare performance in some areas to peer utilities. Because 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 2017 our safety performance met 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 in the Midwest Midsize category, as measured by J.D. Power in their 2017 Electric Utility Residential Customer Satisfaction Study. IPL was also recognized as a 2017 Utility Environmental Champion by Market Strategies International, Cogent Reports in their Utility Trusted Brand and Customer Engagement Study (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 consistent with our target in 2017. Both our planned and unplanned outage rates associated with our generation plants in 2017 were consistent with outage rates that we experienced in 2016 partially due to scheduled outages at our Petersburg and Harding Street plants to complete required maintenance during these respective periods.

The IPL delivery reliability metric for Customer Average Interruption Duration Index (“CAIDI”) was favorable to our target in 2017; however, System Average Interruption Frequency Index (“SAIFI”) was unfavorable and the System Average Interruption Duration Index (“SAIDI”) was slightly unfavorable to target in 2017. In 2016, IPL ranked at or within top decile nationally and top quartile in CAIDI reliability performance. In addition, IPL had the best SAIFI reliability performance excluding major events in 2016 as compared to the four Indiana investor-owned utilities and the second best SAIDI and CAIDI performance.

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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

2017 versus 2016

Utility operating revenues increased in 2017 from the prior year by $2.2 million, which resulted from the following changes (dollars in thousands):

	2017		2016		Change			Percentage Change
Utility Operating Revenues:
Retail Revenues	$	1,317,627	$	1,309,006	$	8,621		0.7	%
Wholesale Revenues	8,574		15,804		(7,230		)	(45.7	)%
Miscellaneous Revenues	23,387		22,620		767			3.4	%
Total Utility Operating Revenues	$	1,349,588	$	1,347,430	$	2,158		0.2	%
Heating Degree Days:
Actual	4,555		4,752		(197		)	(4.1	)%
30-year Average	5,322		5,270
Cooling Degree Days:
Actual	1,133		1,454		(321		)	(22.1	)%
30-year Average	1,113		1,143

The increase in retail revenues of $8.6 million was primarily due to a net increase in the weighted average price per kWh sold ($37.2 million), partially offset by a 3% decrease in the volume of kWh sold ($23.9 million) and the one-time impact in the prior period of recognizing, in IPL’s unbilled revenue calculation, the increase in IPL’s base rates relating to revenues that were previously charged through IPL’s environmental cost recovery rate adjustment mechanism, or rider ($3.8 million). While billed through a rider, such revenues relating to environmental cost recovery were not includable in our unbilled calculation. The $37.2 million increase in the weighted average price of retail kWh sold was primarily due to: (i) a $19.0 million increase in billings related to the MISO, Capacity, and Off System Sales riders, (ii), a $7.2 million increase in fuel revenues, (iii) a $3.0 million increase related to environmental rate adjustment mechanism revenues, (iv) the impact of implementing the 2016 Rate Order in April 2016 (see Note 2, “Regulatory Matters” to the Financial Statements) and (v) favorable block rate and other retail rate variances; partially offset by (vi) a decrease in DSM program rate adjustment mechanism revenues of $6.2 million. The favorable block rate variances are mostly attributed to our declining block rate structure, which generally provides for residential and commercial customers to be charged a higher per kWh rate at lower consumption levels. Therefore, as volumes decrease, the weighted average price per kWh increases. The majority of the increases in environmental rate adjustment mechanism revenues are offset by increased operating expenses, including depreciation and amortization. The $23.9 million decrease in the volume of kWh sold was primarily due to milder weather in our service territory during 2017 versus the prior year (as demonstrated by the 4% decrease in heating degree days and 22% decrease in cooling degree days, as shown above).

The decrease in wholesale revenues of $7.2 million was primarily due to a 47% decrease in the quantity of kWh sold as IPL’s generation units were called upon by MISO to produce electricity less often during 2017 versus 2016, largely due to unit availability. We made 268.1 million kWh in wholesale sales during 2017 compared to 506.7 million kWh during 2016. Our ability to be dispatched in the MISO market is primarily driven by the locational marginal price of electricity and variable generation costs. The amount of electricity available for wholesale sales is impacted by our retail load requirements, generation capacity and unit availability. Currently, 50% of IPL’s wholesale margins above and below an established annual benchmark of $6.3 million are shared with our retail customers through a rate rider.

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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. Our goal is to make wholesale sales when it is profitable to do so. 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.

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Utility Operating Expenses

2017 versus 2016

The following table illustrates our primary operating expense changes from 2016 to 2017 (in millions):

2016 Operating Expenses	$	1,158.5
Increase in power purchased	19.4
Increase in non-purchased power MISO costs	11.9
Decrease in depreciation and amortization costs	(10.2		)
Decrease in income taxes - net	(7.5		)
Decrease in DSM program costs	(7.4		)
Increase in severance costs	5.7
Increase in fuel costs	5.4
Decrease in legal costs	(2.8		)
Other miscellaneous variances – individually immaterial	—
2017 Operating Expenses	$	1,173.0

The increase in purchased power costs of $19.4 million was primarily due to (i) an increase in amortization of previously deferred capacity expense ($5.8 million), (ii) a 1% increase in the market price of purchased power ($5.5 million), (iii) an increase in MISO non-fuel market participation costs ($4.7 million) and (iv) a 3% increase in the volume of power purchased during the period ($4.2 million). The volume of power we purchase each period is primarily influenced by our retail demand, generating unit capacity and outages, and the fact that at times it is less expensive for us to buy power in the market than to produce it ourselves. The market price of purchased power is influenced primarily by changes in the market price of delivered fuel (primarily natural gas), the price of environmental emissions allowances, the supply of and demand for electricity, and the time of day in which power is purchased. The MISO non-fuel market participation costs, which include both current period costs and amortization of previously deferred costs, were included in IPL’s customer billing rates beginning April 1, 2016. Such costs were deferred as a regulatory asset prior to April 1, 2016, and are now being amortized to expense over a ten-year period. Similar to fuel and purchased power costs described above, we are generally permitted to recover underestimated capacity expenses to serve our retail customers in future rates through regulatory proceedings. These variances are deferred when incurred and amortized into expense in the same period that our rates are adjusted to reflect these variances.

MISO non-purchased power costs (primarily transmission related expenses) increased $11.9 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 decrease in depreciation and amortization costs of $10.2 million was primarily due to an $11.0 million decrease in regulatory deferrals and amortization related to environmental projects.

The decrease in income taxes - net of $7.5 million was primarily due to the tax effect of the decrease in pretax net operating income and the manufacturer’s production deduction (Internal Revenue Code Section 199) that had been previously limited due to a Net Operating Loss carryover. On December 22, 2017, the U.S. federal government enacted the TCJA, which includes provisions to, among other things, reduce the federal corporate income tax rate from 35% to 21% and eliminate the manufacturer’s production deduction, beginning January 1, 2018. These changes are likely to result in a net reduction in income tax expenses beginning in 2018. See Note 8, “Income Taxes” to the Financial Statements for further details. On January 3, 2018, the IURC opened a generic investigation to review and consider the impacts from the TCJA and how any resulting benefits should be realized by customers. The IURC’s order opening this investigation directed Indiana utilities to apply regulatory accounting treatment, such as the use of regulatory assets and regulatory liabilities, for all estimated impacts resulting from the TCJA. The ultimate result of the generic investigation cannot be determined at this time. See Note 2, “Regulatory Matters” to the Financial Statements for further details.

The decrease in DSM program costs of $7.4 million, which are included in “Other operating expenses” on our Consolidated Statements of Operations, was due to (i) a $3.6 million decrease in program costs, primarily the result of timing differences in spending patterns, and (ii) $3.7 million is from DSM deferrals in 2016 that were recorded in “Utility operating revenues” on our Consoli

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dated Statements of Operations that beginning in 2017 were recorded in “Other Operating Expenses.” These program costs are recoverable through customer rates and are offset by a decrease in DSM revenues.

The increase in severance costs of $5.7 million was primarily due to restructuring activities initiated in 2017.

The increase in fuel costs of $5.4 million was primarily due to (i) a $32.2 million increase in deferred fuel costs, which includes the one-time favorable impact of a $14.2 million credit in the prior period of recognizing in IPL’s deferred fuel calculation the increase in base rates relating to fuel revenues that were previously charged through a rate adjustment mechanism or rider, and (ii) a $9.0 million increase due to the higher price of natural gas we consumed versus the comparable period; partially offset by (iii) a $25.2 million decrease in the quantity of fuel consumed versus the comparable period and (iv) a $10.5 million decrease due to the lower price of coal we consumed versus the comparable period. We are generally permitted to recover underestimated fuel and purchased power costs to serve our retail customers in future rates through quarterly FAC proceedings. These variances are deferred when incurred and amortized into expense in the same period that our rates are adjusted to reflect these variances.

The decrease in legal costs of $2.8 million was primarily due to lower costs recorded in 2017 for injuries & damages versus the comparable period.

2016 versus 2015

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

2015 Operating Expenses	$	1,105.1
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	(2.2		)
2016 Operating Expenses	$	1,158.5

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

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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 (which are primarily transmission related expenses) 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.

Other Income and Deductions

2017 versus 2016

Other income and deductions decreased$3.4 million, from income of $36.8 million in 2016 to income of $33.4 million in 2017, reflecting a 9%decrease. The decrease was primarily due to an $8.9 million loss on early extinguishment of debt from the redemption of $400 million 2018 IPALCO Notes during the third quarter of 2017. This decrease was partially offset by an increase in the income tax benefit of $4.7 million, which was primarily due to the change in pretax nonoperating income during the comparable periods.

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.

Interest and Other Charges

2017 versus 2016

Interest and other charges increased$6.5 million, or 7%, during 2017, primarily due to higher interest of $5.6 million on long-term debt mostly as a result of IPL’s first mortgage bonds debt issuances of $350 million (4.05% Series, due May 2046) in May 2016.

2016 versus 2015

Interest and other charges decreased$7.2 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.

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KEY TRENDS AND UNCERTAINTIES

During 2018 and beyond, we expect that our financial results will be driven primarily by retail demand, weather, generating unit availability, outage costs and, to a lesser extent, wholesale prices. In addition, IPL’s financial results will likely be driven by many other factors including, but not limited to, the following:

▪ rate case outcomes;

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

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

If favorable outcomes related to these factors do not occur, or if the challenges described below and elsewhere in this section impact us more significantly than we currently anticipate, or if commodities move more unfavorably, then these adverse factors (or other adverse factors unknown to us) may impact our operating margin, net income and cash flows. We continue to monitor our operations and address challenges as they arise. For a discussion of the risks related to our business, see “Item 1. Business” and “Item 1A. Risk Factors” of this Form 10-K.

Regulatory and Environmental

For a discussion of the regulatory environment related to our business, see “Item 1. Business – Regulatory Matters”, Note 2, “Regulatory Matters” to the Financial Statementsand “Item 1. Business – Environmental Matters” of this Form 10-K.

Macroeconomic and Political

U.S. Tax Law Reform

On December 22, 2017, the U.S. federal government enacted the TCJA. The legislation significantly revised the U.S. corporate income tax system by, among other things, lowering corporate income tax rates and introducing new limitations on interest expense deductions beginning in 2018. These changes will materially impact our effective tax rate in future periods. Specific provisions of the TCJA and their potential impacts on the Company are noted below. Our interpretation of the TCJA may change as the U.S. Treasury and the Internal Revenue Service issue additional guidance. Such changes may be material.

Lower Tax Rate - The corporate tax rate decreased from 35% to 21% beginning in 2018. In addition to deferred tax remeasurement impacts, the lower tax rate will result in the recognition, at December 31, 2017, of a regulatory liability at IPL. The regulatory liability will reflect deferred taxes that will flow back to ratepayers over time. For further details, see “Deferred Income Taxes Recoverable/Payable Through Rates” of Note 5, “Regulatory Assets and Liabilities,” and Note 8, “Income Taxes” to the Financial Statements of this Form 10-K.

Limitation on Interest Expense Deductions - The TCJA introduced a new limitation on the deductibility of net interest expense beginning January 1, 2018. The deduction will be limited to interest income, plus 30 percent of tax basis EBITDA through 2021 (30 percent of EBIT beginning January 1, 2022). This determination is made at the consolidated group level, although it applies separately to partnerships. The limitation does not apply to interest expense attributable to regulated utility property. The U.S. Treasury and Internal Revenue Service are expected to provide guidance to clarify how the exception will apply to regulated utility holding companies. Depending on the guidance implementing the limitation, this could materially impact our effective tax rate.

Cost Recovery - The TCJA amended depreciation rules to provide full expensing (100% bonus depreciation) for assets that commence construction and are placed in service before January 1, 2023. This provision phases down by 20% ratably thereafter through 2027. The immediate full expensing provision is elective but it does not apply to regulated utility property. This change is not expected to impact the Company’s effective tax rate; however, if elected, it could impact taxable income and cash taxes in future periods.

State Taxes - The reaction of the state of Indiana to federal tax reform is still evolving. Indiana and its municipalities could amend their tax legislation in response to the TCJA.

SAB 118 - As further explained in Note, 8, “Income Taxes” to the Financial Statements of this Form 10-K, we have included certain reasonable estimates of the impact of U.S. tax law reform subject to potential adjustments in future periods.

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Other - On January 3, 2018, the IURC opened a generic investigation to review and consider the impacts from the TCJA and how any resulting benefits should be realized by customers. See “Taxes” of Note 2, “Regulatory Matters”, “Deferred Income Taxes Recoverable/Payable Through Rates” of Note 5, “Regulatory Assets and Liabilities” and Note 8, “Income Taxes” to the Financial Statements of this Form 10-K for further information.

CAPITAL RESOURCES AND LIQUIDITY

As of December 31, 2017, we had unrestricted cash and cash equivalents of $30.7 million and available borrowing capacity of $102 million under our $250 million unsecured revolving credit facility after accounting for outstanding borrowings and existing letters of credit. All of IPL’s long-term borrowings must first be approved by the IURC and the aggregate amount of IPL’s short-term indebtedness must be approved by the FERC. We have approval from FERC to borrow up to $500 million of short-term indebtedness outstanding at any time through July 27, 2018. In December 2015, we received an order from the IURC granting us authority through December 31, 2018 to, among other things, issue up to $650 million in aggregate principal amount of long-term debt and refinance up to $196.5 million in existing indebtedness. As of December 31, 2017, we have $106.5 million of total debt issuance authority remaining under this order. This order also grants us authority to have up to $500 million of long-term credit agreements and liquidity facilities outstanding at any one time, of which $250 million remains available under the order as of December 31, 2017. As an alternative to the sale of all or a portion of $65 million in principal of the long-term debt mentioned above, we have the authority to issue up to $65 million of new preferred stock, all of which authority remains available under the order as of December 31, 2017. We also have restrictions on the amount of new debt that may be issued due to contractual obligations of AES and by financial covenant restrictions under our existing debt obligations. We do not believe such restrictions will be a limiting factor in our ability to issue debt in the ordinary course of prudent business operations.

We believe that existing cash balances, cash generated from operating activities and borrowing capacity on our committed credit facility will be adequate for the foreseeable future to meet anticipated operating expenses, interest expense on outstanding indebtedness, recurring capital expenditures and to pay dividends to AES U.S. Investments and CDPQ. Sources for principal payments on outstanding indebtedness and nonrecurring capital expenditures are expected to be obtained from: (i) existing cash balances; (ii) cash generated from operating activities; (iii) borrowing capacity on our committed credit facility; and (iv) additional debt financing. From time to time, we may elect to repurchase our outstanding debt through cash purchases, privately negotiated transactions or otherwise when management believes such repurchases are favorable to make. The amounts involved in any such repurchases may be material.

Cash Flows

The following table provides a summary of our cash flows:

	Years ended December 31,									$ Change
	2017			2016			2015			2017 vs. 2016			2016 vs. 2015
	(in thousands)									(in thousands)
Net cash provided by operating activities	$	285,260		$	324,591		$	252,425		$	(39,331	)	$	72,166
Net cash used in investing activities	(236,432		)	(608,688		)	(695,117		)	372,256			86,429
Net cash (used in) provided by financing activities	(53,100		)	297,529			437,280			(350,629		)	(139,751		)
Net change in cash and cash equivalents	(4,272		)	13,432			(5,412		)	(17,704		)	18,844
Cash and cash equivalents at beginning of period	34,953			21,521			26,933			13,432			(5,412		)
Cash and cash equivalents at end of period	$	30,681		$	34,953		$	21,521		$	(4,272	)	$	13,432

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Operating Activities

The following table summarizes the key components of our consolidated operating cash flows:

	Years ended December 31,									$ Change
	2017			2016			2015			2017 vs. 2016			2016 vs. 2015
	(in thousands)									(in thousands)
Net income	$	108,793		$	131,060		$	59,524		$	(22,267	)	$	71,536
Depreciation and amortization	208,209			218,449			188,272			(10,240		)	30,177
Amortization of debt premium	4,202			4,147			5,067			55			(920		)
Deferred income taxes and investment tax credit adjustments	(3,506		)	34,012			31,566			(37,518		)	2,446
Loss on early extinguishment of debt	8,875			—			21,956			8,875			(21,956		)
Allowance for equity funds used during construction	(25,798		)	(27,140		)	(14,996		)	1,342			(12,144		)
Net income, adjusted for non-cash items	300,775			360,528			291,389			(59,753		)	69,139
Net change in operating assets and liabilities	(15,515		)	(35,937		)	(38,964		)	20,422			3,027
Net cash provided by operating activities	$	285,260		$	324,591		$	252,425		$	(39,331	)	$	72,166

2017 versus 2016

The net change in operating assets and liabilities for the year ended December 31, 2017 compared to the year ended December 31, 2016 was driven by the following (in thousands):

Increase from short-term and long-term regulatory assets and liabilities, primarily due to the collection of deferred MISO costs in 2017 and due to 2016 changes in the deferred fuel regulatory asset (liability) resulting from the 2016 rate order	$	55,037
Increase from accounts receivable, primarily due to a decrease in Retail revenues at the end of 2017 as compared to the end of 2016	27,429
Decrease from fuel, materials and supplies, primarily due to higher coal purchases in 2017	(38,776		)
Decrease from accounts payable and accrued expenses, primarily due to timing of payments	(19,013		)
Other	(4,255		)
Net change in operating assets and liabilities	$	20,422

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	(2,155		)
Net change in operating assets and liabilities	$	3,027

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Investing Activities

During the year ended December 31, 2017, net cash used in investing activities was primarily related to capital expenditures of $228.9 million (which includes $10.6 million of payments for financed capital expenditures).

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).

Financing Activities

During the year ended December 31, 2017, net cash used in financing activities primarily relates to dividends to shareholders of $105.1 million; partially offset by net borrowings of $69.8 million.

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.

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 $228.9 million (which includes $10.6 million of payments for financed capital expenditures), $607.7 million (which includes $15.5 million of payments for financed capital expenditures), and $686.1 million (which includes $13.2 million of payments for financed capital expenditures) in 2017, 2016 and 2015, respectively. Construction expenditures during 2017, 2016 and 2015 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 2018 to 2020 is currently estimated to cost approximately $614 million (excluding environmental compliance and replacement generation costs). It includes approximately $330 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 $194 million for power plant-related projects and $90 million for other miscellaneous equipment.

IPL also plans to spend a total of $655 million (of which $618 million has been expended through December 31, 2017) on replacement generation costs through 2018 as a result of the retirement of existing facilities not equipped with advanced environmental control technologies required to comply with existing and expected regulations. The balance of $37 million is projected to be expended in 2018. 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. IPL spent a total of $101 million on this project, including costs for NPDES, MATS compliance and dry ash handling. 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 2018 are expected to be $13 million. IPL plans to spend a total of $224 million for this project (of which $211 million has been expended through December 31, 2017). The remaining costs are projected to be expended in 2018. Please see “Item 1. Business - Environmental Matters - Environmental Wastewater Requirements” for more details.

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IPL also has projects underway related to environmental compliance for CCR and NAAQS SO2. The costs for these projects in the 2018 to 2020 forecast are expected to be $23 million. IPL plans to spend a total of $76 million for these projects (of which $53 million has been expended through December 31, 2017). 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 2018-2020 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 $68 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 2020 IPALCO Notes or the 2024 IPALCO Notes; however, all of IPL’s common stock is pledged to secure these notes. Accordingly, IPALCO’s ability to make payments on the 2020 IPALCO Notes and the 2024 IPALCO Notes depends on the ability of IPL to generate cash and distribute it to IPALCO.  

Liquidity

We expect our existing sources of liquidity to remain sufficient to meet our anticipated operating needs. Our business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and carrying costs, potential margin requirements related to energy hedges, taxes and dividend payments. For 2018 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

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, as discussed in Note 7, “Debt - Line of Credit” to the Financial Statements. 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.

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 at February 26, 2018
IPL	Revolving	October 2020	$	250.0	$	96.0

IPL First Mortgage Bonds

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

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. For further discussion, please see Note 7, “Debt - IPL First Mortgage Bonds” to the Financial Statements.

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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.

IPALCO’s Senior Secured Notes

In August 2017, IPALCO completed the sale of the $405 million 2024 IPALCO Notes pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended. Net proceeds from this offering were used to fund the purchase of the $400 million 2018 IPALCO Notes. For further discussion, please see Note 7, “Debt - IPALCO’s Senior Secured 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. On December 12, 2017, Fitch affirmed the issue-level ratings at IPALCO and IPL while raising the outlook from Stable to Positive.

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)	Positive	December 2017
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-	Positive	December 2017
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.

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Contractual Cash Obligations

Our non-contingent contractual obligations as of December 31, 2017 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	$	2,508.8	$	—	$	495.0	$	95.0	$	1,918.8
Interest obligations (1)	1,949.3		113.4		219.1		184.3		1,432.5
Purchase obligations (2)
Coal, gas, purchased power and
related transportation	1,904.5		292.2		474.8		291.5		846.0
Other	57.2		11.8		21.3		7.3		16.8
Pension funding (3)	30.0		30.0		—		—		—
Total (4)	$	6,449.8	$	447.4	$	1,210.2	$	578.1	$	4,214.1

(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, 2017.

(2) Does not include contracts which do not specify all significant terms, including fixed or minimum quantities (except for requirements contracts for which budgeted amounts are included). 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 $30.0 million during January 2018. However, IPL may decide to contribute more than $30.0 million to meet certain funding thresholds. For years 2019 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 $4.7 million (tax and related interest) as of December 31, 2017 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 2017, 2016 and 2015, IPALCO paid $105.1 million, $123.0 million, and $69.5 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 ofSignificant 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 ofSignificant 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 2017 revenues and

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ending unbilled revenues of a one percentage point change in estimated line losses for the month of December 2017 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.

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, “RegulatoryAssetsand 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.

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, “Commitmentsand Contingencies” to the Financial Statements for information about significant contingencies involving us.  

NEW ACCOUNTINGSTANDARDS

Please see Note 1, “Overview and Summary ofSignificant 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.

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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 $31.99, $31.17 and $28.02 in 2017, 2016 and 2015, 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 2.9% 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 2018 and approximately 75% of our current projected burn for the three-year period ending December 31, 2020, under long-term contracts. Pricing provisions in some of our long-term contracts allow for price changes under certain circumstances. Fuel purchases made in 2018 have been and are expected to continue to be made at prices that are slightly higher than our weighted average price in 2017. 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 –FACand AuthorizedAnnualJurisdictional 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 $22.1 million reduction in fair value as of December 31, 2017 and approximately a $7.4 million increase to the 2018 pension expense. Please see Note 9, “Benefit Plans” to the Financial Statements for additional Pension Plan information.

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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, 2017, we had approximately $2,418.8 million principal amount of fixed rate debt and $238.0 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, 2017 was comprised of $90.0 million under our Series 2015A and Series 2015B notes and $148.0 million under our Credit Agreement. Based on amounts outstanding as of December 31, 2017, the effect of a 25 basis point change in the applicable rates on our variable-rate debt would change our annual interest expense and cash paid for interest by $0.6 million and $(0.6 million), respectively.

The following table shows our consolidated indebtedness (in millions) by maturity as of December 31, 2017:

	2018		2019		2020		2021		2022		Thereafter		Total		Fair Value
Fixed-rate	$	—	$	—	$	405.0	$	95.0	$	—	$	1,918.8	$	2,418.8	$	2,655.0
Variable-rate	148.0		—		90.0		—		—		—		238.0		238.0
Total Indebtedness	$	148.0	$	—	$	495.0	$	95.0	$	—	$	1,918.8	$	2,656.8	$	2,893.0
Weighted Average Interest Rates by Maturity	2.635%		N/A		3.142%		3.875%		N/A		4.706%		4.270%

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. 

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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 – 2017, 2016 and 2015	51
Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015	52
Consolidated Balance Sheets as of December 31, 2017 and 2016	53
Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015	54
Consolidated Statements of Common Shareholders’ Equity and Noncontrolling Interest
for the years ended December 31, 2017, 2016 and 2015	55
Notes to Consolidated Financial Statements	56
Indianapolis Power & Light Company and Subsidiary – Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm – 2017, 2016 and 2015	89
Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015	90
Consolidated Balance Sheets as of December 31, 2017 and 2016	91
Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015	92
Consolidated Statements of Common Shareholder’s Equity for the years ended
December 31, 2017, 2016 and 2015	93
Notes to Consolidated Financial Statements	94

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Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of IPALCO Enterprises, Inc.                                

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of IPALCO Enterprises, Inc. and subsidiaries (the Company) as of December 31, 2017 and 2016, 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, 2017, and the related notes and schedules (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2017 and 2016, and the results of its operations and its cash flows for the three years in the period ended December 31, 2017 in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our December 31, 2017 and 2016 audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America and our December 31, 2015 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2008.

Indianapolis, Indiana

February 26, 2018

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IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Operations
For the Years Ended December 31, 2017, 2016 and 2015
(In Thousands)
	2017			2016			2015
UTILITY OPERATING REVENUES	$	1,349,588		$	1,347,430		$	1,250,399
UTILITY OPERATING EXPENSES:
Fuel	281,542			276,171			315,600
Other operating expenses	253,496			244,660			223,717
Power purchased	189,847			170,466			145,064
Maintenance	129,734			130,385			131,574
Depreciation and amortization	208,204			218,444			188,267
Taxes other than income taxes	44,580			45,262			43,617
Income taxes - net	65,621			73,161			57,284
Total utility operating expenses	1,173,024			1,158,549			1,105,123
UTILITY OPERATING INCOME	176,564			188,881			145,276
OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used during construction	25,798			27,140			15,302
Loss on early extinguishment of debt	(8,875		)	—			(21,956		)
Miscellaneous income and (deductions) - net	(234		)	(2,311		)	(2,994		)
Income tax benefit applicable to nonoperating income	16,670			11,952			25,718
Total other income and (deductions) - net	33,359			36,781			16,070
INTEREST AND OTHER CHARGES:
Interest on long-term debt	117,162			111,611			106,936
Other interest	2,068			2,710			2,628
Allowance for borrowed funds used during construction	(22,302		)	(23,866		)	(12,809		)
Amortization of redemption premiums and expense on debt	4,202			4,147			5,067
Total interest and other charges - net	101,130			94,602			101,822
NET INCOME	108,793			131,060			59,524
LESS: PREFERRED DIVIDENDS OF SUBSIDIARY	3,213			3,213			3,213
NET INCOME APPLICABLE TO COMMON STOCK	$	105,580		$	127,847		$	56,311

See notes to consolidated financial statements.

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IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Balance Sheets
(In Thousands)
	December 31, 2017			December 31, 2016
ASSETS
UTILITY PLANT:
Utility plant in service	$	5,385,053		$	4,997,846
Less accumulated depreciation	2,129,617			2,030,497
Utility plant in service - net	3,255,436			2,967,349
Construction work in progress	711,396			898,330
Spare parts inventory	13,157			14,237
Property held for future use	1,002			1,002
Utility plant - net	3,980,991			3,880,918
OTHER ASSETS:
Nonutility property - at cost, less accumulated depreciation	502			512
Intangible assets - net	16,036			11,976
Other long-term assets	6,185			5,916
Other assets - net	22,723			18,404
CURRENT ASSETS:
Cash and cash equivalents	30,681			34,953
Accounts receivable and unbilled revenue (less allowance
for doubtful accounts of $2,830 and $2,365, respectively)	157,577			154,586
Fuel inventories - at average cost	32,393			30,237
Materials and supplies - at average cost	63,623			60,648
Regulatory assets	35,341			33,912
Prepayments and other current assets	34,094			33,504
Total current assets	353,709			347,840
DEFERRED DEBITS:
Regulatory assets	378,904			450,710
Miscellaneous	4,234			4,409
Total deferred debits	383,138			455,119
TOTAL	$	4,740,561		$	4,702,281
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common shareholders' equity:
Paid in capital	$	597,467		$	596,810
Accumulated deficit	(25,191		)	(25,627		)
Total common shareholders' equity	572,276			571,183
Cumulative preferred stock of subsidiary	59,784			59,784
Long-term debt (Note 7)	2,477,538			2,474,840
Total capitalization	3,109,598			3,105,807
CURRENT LIABILITIES:
Short-term and current portion of long-term debt (Note 7)	148,000			74,650
Accounts payable	125,297			119,511
Accrued expenses	27,926			18,754
Accrued real estate and personal property taxes	18,145			18,930
Regulatory liabilities	2,532			7,704
Accrued interest	34,332			32,541
Customer deposits	31,306			29,780
Other current liabilities	10,392			19,467
Total current liabilities	397,930			321,337
DEFERRED CREDITS AND OTHER LONG-TERM LIABILITIES:
Regulatory liabilities	851,754			670,294
Deferred income taxes - net	245,257			449,730
Non-current income tax liability	4,651			6,634
Unamortized investment tax credit	954			2,410
Accrued pension and other postretirement benefits	50,070			64,139
Asset retirement obligations	79,535			80,568
Miscellaneous	812			1,362
Total deferred credits and other long-term liabilities	1,233,033			1,275,137
COMMITMENTS AND CONTINGENCIES (Note 10)
TOTAL	$	4,740,561		$	4,702,281

See notes to consolidated financial statements.

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IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Cash Flows
For the Years Ended December 31, 2017, 2016 and 2015
(In Thousands)
	2017			2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	108,793		$	131,060		$	59,524
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	208,209			218,449			188,272
Amortization (deferral) of regulatory assets	—			—			—
Amortization of deferred financing costs and debt premium	4,202			4,147			5,067
Deferred income taxes and investment tax credit adjustments - net	(3,506		)	34,012			31,566
Loss on early extinguishment of debt	8,875			—			21,956
Allowance for equity funds used during construction	(25,798		)	(27,140		)	(14,996		)
Change in certain assets and liabilities:
Accounts receivable	(2,991		)	(30,420		)	15,542
Fuel, materials and supplies	(5,342		)	33,434			(18,372		)
Income taxes receivable or payable	(12,592		)	(1,603		)	—
Financial transmission rights	1,861			(243		)	2,086
Accounts payable and accrued expenses	(5,345		)	13,668			(716		)
Accrued real estate and personal property taxes	(785		)	1,218			(1,465		)
Accrued interest	1,791			850			965
Pension and other postretirement benefit expenses	(14,069		)	(16,595		)	(15,730		)
Short-term and long-term regulatory assets and liabilities	17,011			(38,026		)	(22,980		)
Prepaids and other current assets	6,141			(1,779		)	(4,949		)
Other - net	(1,195		)	3,559			6,655
Net cash provided by operating activities	285,260			324,591			252,425
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures - utility	(218,224		)	(592,243		)	(672,849		)
Project development costs	(1,729		)	(1,356		)	(8,980		)
Cost of removal, net of salvage	(12,195		)	(13,403		)	(12,064		)
Other	(4,284		)	(1,686		)	(1,224		)
Net cash used in investing activities	(236,432		)	(608,688		)	(695,117		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt borrowings	202,500			298,000			388,850
Short-term debt repayments	(129,150		)	(414,850		)	(272,000		)
Long-term borrowings, net of discount	404,633			387,662			753,350
Retirement of long-term debt and early tender premium	(408,152		)	(40,000		)	(552,179		)
Dividends on common stock	(105,144		)	(122,959		)	(69,487		)
Issuance of common stock	—			134,276			214,366
Equity contributions from shareholders	—			78,738			—
Preferred dividends of subsidiary	(3,213		)	(3,213		)	(3,213		)
Deferred financing costs paid	(3,709		)	(4,499		)	(8,824		)
Payments for financed capital expenditures	(10,637		)	(15,473		)	(13,215		)
Other	(228		)	(153		)	(368		)
Net cash (used in) provided by financing activities	(53,100		)	297,529			437,280
Net change in cash and cash equivalents	(4,272		)	13,432			(5,412		)
Cash and cash equivalents at beginning of period	34,953			21,521			26,933
Cash and cash equivalents at end of period	$	30,681		$	34,953		$	21,521
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized)	$	94,781		$	89,098		$	95,137
Income taxes	$	65,050		$	28,800		$	—
	As of December 31,
	2017			2016			2015
Non-cash investing activities:
Accruals for capital expenditures	$	45,322		$	36,249		$	79,553

See notes to consolidated financial statements.

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IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Common Shareholders' Equity
and Noncontrolling Interest
For the Years Ended December 31, 2017, 2016 and 2015
(In Thousands)
	Paid in Capital		Accumulated Deficit			Total Common Shareholders' Equity			Cumulative Preferred Stock of Subsidiary
Balance at January 1, 2015	$	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
Net income			105,580			105,580			3,213
Preferred stock dividends									(3,213		)
Distributions to shareholders			(105,144		)	(105,144		)
Other	657					657
Balance at December 31, 2017	$	597,467	$	(25,191	)	$	572,276		$	59,784

See notes to consolidated financial statements.

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IPALCO ENTERPRISES, INC. and SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31,2017, 2016 and2015

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, which provides frequency response. 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. As of December 31, 2017, IPL’s net electric generation capacity for winter is 2,996 MW and net summer capacity is 2,881 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.

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.

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Revenuesand 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, 2017 and 2016, customer accounts receivable include unbilled energy revenues of $61.6 million and $57.0 million, respectively, on a base of annual revenue of $1.3 billion in 2017 and 2016. 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 $5.9 million, $4.1 million and $4.3 million for the years ended December 31, 2017, 2016 and 2015, 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, 2017 and 2016, total loss contingencies accrued were $4.1 million and $11.6 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 67% 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 four suppliers, with about 50% of our existing coal under contract for the three-year period ending December 31, 2020 coming from one supplier. Substantially all of the coal is currently mined in the state of Indiana.

Allowance For Funds Used During Construction

In accordance with the Uniform System of Accounts prescribed by FERC, IPL capitalizes an allowance for the net cost of funds (interest on borrowed funds and a reasonable rate of return on equity funds) used for construction purposes during the period of construction with a corresponding credit to income. For the Eagle Valley CCGT, Harding Street refueling projects, and NPDES projects, IPL capitalized amounts using a pretax composite rate of 6.6%, 7.1% and 7.3% during 2017, 2016 and 2015,

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respectively. For all other construction projects, IPL capitalized amounts using pretax composite rates of 6.6%, 7.2% and 8.1% during 2017, 2016 and 2015, 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 4.1%, 4.3%, and 4.2% during 2017, 2016 and 2015, respectively. Depreciation expense was $209.8 million, $209.5 million, and $194.4 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Derivatives

We have only limited involvement with derivative financial instruments and do not use them for trading purposes. IPALCO accounts for its derivatives in accordance with ASC 815 “Derivatives and Hedging.” 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 $4.0 billion and $3.9 billion as of December 31, 2017 and 2016, 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 $99.4 million and $91.7 million and its corresponding amortization of $83.4 million and $79.7 million, as of December 31, 2017 and 2016, respectively. Amortization expense was $4.3 million, $5.9 million and $5.2 million for the years ended December 31, 2017, 2016 and 2015, respectively. The estimated amortization expense over the remaining useful life of this capitalized software is $16.0 million ($3.2 million annually over the next 5 years).

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.

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Cash and Cash Equivalents

Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents.

Pension and Postretirement Benefits

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. Consistent with the requirements of ASC 715, we apply a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and postretirement plans.

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.

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New Accounting Standards Adopted
ASU Number and Name	Description	Date of Adoption	Effect on the financial statements upon adoption
2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting	The standard simplifies the following aspects of accounting for share-based payments awards: accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: The recognition of excess tax benefits and tax deficiencies arising from vesting or settlement were applied retrospectively. The elimination of the requirement that excess tax benefits be realized before they are recognized was adopted on a modified retrospective basis.	January 1, 2017	The primary effect of adoption was the recognition of excess tax benefits in our provision for income taxes in the period when the awards vest or are settled, rather than in paid-in-capital in the period when the excess tax benefits are realized. We will continue to estimate the number of awards that are expected to vest in our determination of the related periodic compensation cost. The adoption of this standard did not have a material impact on the consolidated financial statements.
New Accounting Standards Issued But Not Yet Effective
ASU Number and Name	Description	Date of Adoption	Effect on the financial statements upon adoption
2017-08, Receivables - Nonrefundable Fees and Other Costs (Subtopic 310-20): Premium Amortization on Purchased Callable Debt Securities	This standard shortens the period of amortization of the premium on certain callable debt securities to the earliest call date. Transition method: modified retrospective.	January 1, 2019. Early adoption is permitted.	The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.
2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost	This standard changes the presentation of non-service cost associated with defined benefit plans and updates the guidance so that only the service cost component will be eligible for capitalization. Transition method: Retrospective for presentation of non-service cost expense. Prospective for the change in capitalization.	January 1, 2018. Early adoption is permitted.	The Company expects the adoption of this standard to result in a $(2.1) million and $0.9 million reclassification of non-service pension costs (credits) from Other operating expenses to Miscellaneous income and (deductions) - net for 2017 and 2016, respectively. The Company plans to adopt the standard as of January 1, 2018.
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 has performed a preliminary evaluation, and the adoption of this standard is not expected to have a material impact on the 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. For trade and other receivables, held-to-maturity debt securities, loans and other instruments, entities will be required to use a new forward-looking “expected loss” model that generally will result in the earlier recognition of allowance for losses. For available-for-sale debt securities with unrealized losses, entities will measure credit losses as it is done today, except that the losses will be recognized as an allowance rather than a reduction in the amortized cost of the securities. 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.
2016-02, 2018-01, Leases (Topic 842)	See discussion of the ASUs below.	January 1, 2019. Early adoption is permitted.	The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements and intends to adopt the standard as of January 1, 2019.
2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-10, 2017-13, Revenue from Contracts with Customers (Topic 606)	See discussion of the ASUs below.	January 1, 2018. Early adoption 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 provides 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.

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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.

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. At this time, we do not expect any significant impact on our financial systems or a material change to controls as a result of the implementation of the new revenue recognition standard.

The Company is assessing the standard on a contract-by-contract basis and applying the interpretations reached during 2017 on key issues. This includes the application of the practical expedient for measuring progress towards satisfaction of a performance obligation, when variable quantities would be considered variable consideration versus an option to acquire additional goods and services and how to allocate variable consideration to one or more, but not all, distinct goods or services promised in a series of distinct goods or services that forms part of a single performance obligation. Additionally, the Company has been working on the application of the standard to contracts that are under the scope of Service Concession Arrangements (Topic 853) and assessing the gross versus net presentation for spot energy sale and purchases. Through this assessment to date, the Company has not identified any situations where revenue recognized under ASC 606 could differ from that recognized under ASC 605 or where the presentation of sales to and purchases from the spot markets will change. Given the limited impact, the Company expects to use the modified retrospective approach.

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 interpretive issues.

ASU 2016-02 and its subsequent corresponding updates require lessees to recognize assets and liabilities for most leases but recognize expenses in a manner similar to today’s accounting. For lessors, the guidance modifies the lease classification criteria and the accounting for sales-type and direct financing leases. The guidance also eliminates today’s real estate-specific provisions.

The standard requires modified retrospective adoption at the beginning of the earliest comparative period presented in the financial statements (January 1, 2017). The FASB proposed amending the standard to give another option for transition. The proposed transition method would allow entities to not apply the new lease standard in the comparative periods presented in their financial statements in the year of adoption. Under the proposed transition method, the entity would apply the transition provisions on January 1, 2019 (i.e., the effective date). At transition, lessees and lessors are permitted to make an election to apply a package of practical expedients that allow them not to reassess: (1) whether any expired or existing contracts are or contain leases, (2) lease classification for any expired or existing leases, and (3) whether initial direct costs for any expired or existing leases qualify for capitalization under ASC 842. These three practical expedients must be elected as a package and must be consistently applied to all leases. Furthermore, entities are also permitted to make an election to use hindsight    when determining lease term and lessees can elect to use hindsight when assessing the impairment of right-of-use assets.

The Company has established a task force focused on the identification of contracts that would be under the scope of the new standard and on the assessment and measurement of the right-of-use asset and related liability. Additionally, the implementation team has been working on the identification and selection of a lease accounting system that would support the implementation and the subsequent accounting. The implementation team is in the process of evaluating changes to our business processes, systems and controls to support recognition and disclosure under the new standard.

As the Company has preliminarily concluded that at transition it would be using the package of practical expedients, the main impact expected as of the effective date is the recognition of the right to use asset and the related liability in the financial statements for all those contracts that contain a lease and for which the Company is the lessee. However, income statement presentation and the expense recognition patter will not change.

Under ASC 842, it is expected that fewer contracts will contain a lease. However, due to the elimination of today's real estate-specific guidance and changes to certain lessor classification criteria, more leases will qualify as sales-type leases and direct financing leases. Under these two models, a lessor will derecognize the asset and will recognize a lease receivable. According to ASC 842, the lease receivable does not include variable payments that depend on the use of the asset (e.g. Mwh produced by a facility). Therefore, the lease receivable could be lower than the carrying amount of the underlying asset at lease commencement, In such circumstances, the difference between the initially recognized lease receivable and the carrying amount of the underlying is recognized as a selling loss at lease commencement. The Company is assessing situations for which this guidance would apply.

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2. REGULATORY MATTERS

General

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

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

IPL is also affected by the regulatory jurisdiction of the EPA at the federal level, and the IDEM at the state level. Other significant regulatory agencies affecting IPL include, but are not limited to, the NERC, the U.S. Department of Labor and the IOSHA.  

Basic Rates and Charges

Our basic rates and charges represent the largest component of our annual revenues. Our basic rates and charges are determined after giving consideration, on a pro-forma basis, to all allowable costs for ratemaking purposes including a fair return on the fair value of the utility property used and useful in providing service to customers. These basic rates and charges are set and approved by the IURC after public hearings. Such proceedings, which have occurred at irregular intervals, involve IPL, the IURC, the Indiana Office of Utility Consumer Counselor, and other interested stakeholders. Pursuant to statute, the IURC is to conduct a periodic review of the basic rates and charges of all Indiana utilities at least once every four years, but the IURC has the authority to review the rates of any Indiana utility at any time. Once set, the basic rates and charges authorized do not assure the realization of a fair return on the fair value of property.

Our declining block rate structure generally provides for residential and commercial customers to be charged a lower per kWh rate at higher consumption levels. Therefore, as volumes increase, the weighted average price per kWh decreases. Numerous factors including, but not limited to, weather, inflation, customer growth and usage, the level of actual operating and maintenance expenditures, capital expenditures including those required by environmental regulations, fuel costs, and generating unit availability, can affect the return realized.

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. The CCGT was originally expected to be completed in the first half of 2017 and that timing was changed in 2017 to an expected completion in the first half of 2018.

IPL filed a petition with the IURC on December 21, 2017, for authority to increase its basic rates and charges to coincide with the expected completion of the CCGT in the first half of 2018. IPL’s proposed revenue increase was $124.5 million annually, or 9.1%. On February 16, 2018, IPL filed an update to such petition to reflect the federal income tax law changes passed, which reduced the revenue increase IPL is seeking to $96.7 million, or 7.1%. An order on this proceeding will likely be issued by the IURC by the first quarter of 2019.

In March 2016, the IURC issued the 2016 Rate Order authorizing IPL to increase its basic rates and charges by $30.8 million annually. The order also authorized IPL to collect, over a ten year period, $117.7 million of previously deferred regulatory assets related to IPL’s participation in the regional transmission organization known as MISO. Such deferred costs are amortized to expense over ten years. Accordingly, $11.8 million of IPL’s long-term MISO regulatory asset is included within current regulatory assets on the accompanying 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 ofongoing 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. In September 2017, the FERC

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completed its review, authorizing the Service Company’s allocation of costs of non-power goods and services to IPL. In the 2016 Rate Order, the IURC also closed their investigation into IPL’s underground network.

Some of the intervening parties in the IURC rate case filed petitions for reconsideration of the IURC’s March 2016 order with respect to certain issues. These petitions were subsequently denied by the IURC. In addition, certain intervening parties filed notices of appeal of the order. On April 5, 2017, the Indiana Court of Appeals affirmed the IURC’s March 2016 order.

CCR

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

NAAQS

On April 26, 2017, the IURC approved IPL’s request for NAAQS SO2 compliance at its Petersburg generation station with 80% of qualifying costs recovered through a rate adjustment mechanism and the remainder recorded as a regulatory asset for recovery in a subsequent rate case. The approved capital cost of the NAAQS SO2 compliance plan is approximately $29 million. This project is expected to be fully in service in the first quarter of 2019.

Other

The DOE issued a Notice of Proposed Rule Making on September 29, 2017, which directed the FERC to exercise its authority to set just and reasonable rates that recognize the “resiliency” value provided by generation plants with certain characteristics, including having 90-days or more of on-site fuel and operating in markets where they do not receive rate base treatment through state ratemaking. Nuclear and coal-fired generation plants would have been most likely to be able to meet the requirements. As proposed, the DOE would value resiliency through rates that recover “compensable costs” that were defined to include the recovery of operating and fuel expenses, debt service and a fair return on equity. On January 8, 2018, the FERC issued an order terminating this docket stating that it failed to satisfy the legal requirements of Section 206 of the Federal Power Act of 1935. The FERC initiated a new docket to take additional steps to explore resilience issues in RTOs/ISOs. The goal of this new proceeding is to: (1) develop a common understanding among the FERC, State Commissions, RTOs/ISOs, transmission owners, and others as to what resilience of the bulk power system means and requires; (2) understand how each RTO and ISO assesses resilience in its geographic footprint; and (3) use this information to evaluate whether additional action regarding resilience is appropriate at this time. It is not possible to predict the impact of this proceeding on our business, financial condition or results of operations.

FACand Authorized Annual Jurisdictional Net Operating Income

IPL may apply to the IURC for a change in IPL’s fuel charge every three months to recover IPL’s estimated fuel costs, including the energy portion of purchased power costs, which may be above or below the levels included in IPL’s basic rates and charges. IPL must present evidence in each FAC proceeding that it has made every reasonable effort to acquire fuel and generate or purchase power or both so as to provide electricity to its retail customers at the lowest fuel cost reasonably possible.

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

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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, 2017 was $772 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 2017 through February 2018 was $48.0 million. During the years ended December 31, 2017, 2016 and 2015, we made environmental compliance expenditures of $59.1 million, $158.9 million, and $252.6 million, respectively. The vast majority of such costs are recoverable through our ECCRA filings.

DSM

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 $10.7 million in 2016.  

On February 7, 2018, the IURC approved a settlement agreement establishing a new three year DSM plan for IPL through 2020. The approval included cost recovery of programs as well as performance incentives, depending on the level of success of the programs. The order also approved recovery of lost revenues, consistent with the provisions of the settlement agreement.

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 through 2031 from a project in Minnesota. The Indiana project has a maximum output capacity of approximately 100 MW and the Minnesota project 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 2018 (these long-term contracts expire ranging from 2021 to 2032), of which 95 MW was in operation as of December 31, 2017. We have authority from the IURC to recover the costs for all of these agreements through an adjustment mechanism administered within the FAC. If and when IPL sells the renewable energy attributes (in the form of renewable energy credits) generated from these facilities, the proceeds are passed back to IPL’s retail customers through the FAC.

Taxes

On January 3, 2018, the IURC opened a generic investigation to review and consider the impacts from the TCJA and how any resulting benefits should be realized by customers. The IURC’s order opening this investigation directed Indiana utilities to apply regulatory accounting treatment, such as the use of regulatory assets and regulatory liabilities, for all estimated impacts resulting from the TCJA. On February 16, 2018, the IURC issued an order establishing two phases of the investigation. The first phase directs respondent utilities (including IPL) to make a filing by March 25, 2018 to adjust respondents’ rates and charges for service, the impact of a lower federal income tax rate. The IURC will hold an attorney’s conference on May 3, 2018 to establish the phase two procedural schedule to discuss the remaining issues from the TCJA, including treatment of deferred taxes and how these benefits will be realized by customers. The Company is reviewing the IURC’s initial order and the ultimate result of the generic investigation cannot be determined at this time, although it could be material. See also Note 8, “Income Taxes” for further information.

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3.  UTILITY PLANT IN SERVICE

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

	As of December 31,
	2017		2016
	(In Thousands)
Production	$	3,249,563	$	2,923,349
Transmission	380,881		376,659
Distribution	1,487,380		1,433,044
General plant	267,229		264,794
Total utility plant in service	$	5,385,053	$	4,997,846

Substantially all of IPL’s property is subject to a $1,608.8 million direct first mortgage lien, as of December 31, 2017, securing IPL’s first mortgage bonds. IPL had no property under capital leases as of December 31, 2017 and 2016. Total non-contractually or legally required removal costs of utility plant in service at December 31, 2017 and 2016 were $737.1 million and $705.6 million, respectively; and total contractually or legally required removal costs of utility plant in service at December 31, 2017 and 2016 were $79.5 million and $80.6 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:

	2017			2016
	(In Millions)
Balance as of January 1	$	80.6		$	59.0
Liabilities incurred	—			—
Liabilities settled	(5.3		)	(3.2		)
Revisions in estimated cash flows	—			21.6
Accretion expense	4.2			3.2
Balance as of December 31	$	79.5		$	80.6

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, 2017 and 2016, IPL did not have any assets that are legally restricted for settling its ARO liability.    

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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, 2017 and 2016, 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.

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Summary

The fair value of assets and liabilities at December 31, 2017 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, 2017		Based on quoted market prices in active markets		Other observable inputs		Unobservable inputs
	(In Thousands)
Financial assets:
Financial transmission rights	$	2,532	$	—	$	—	$	2,532
Total financial assets measured at fair value	$	2,532	$	—	$	—	$	2,532
Financial liabilities:
Other derivative liabilities	$	78	$	—	$	—	$	78
Total financial liabilities measured at fair value	$	78	$	—	$	—	$	78

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

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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, 2016	$	4,029
Unrealized gain recognized in earnings	46
Issuances	10,892
Settlements	(10,674		)
Balance at December 31, 2016	4,293
Unrealized gain recognized in earnings	23
Issuances	9,647
Settlements	(11,509		)
Balance at December 31, 2017	$	2,454

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, 2017 and 2016, ARO liabilities were $79.5 million and $80.6 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, 2017				December 31, 2016
	Face Value		Fair Value		Face Value		Fair Value
	(In Millions)
Fixed-rate	$	2,418.8	$	2,655.0	$	2,438.5	$	2,543.5
Variable-rate	238.0		238.0		140.0		140.0
Total indebtedness	$	2,656.8	$	2,893.0	$	2,578.5	$	2,683.5

The difference between the face value and the carrying value of this indebtedness represents the following:

• unamortized deferred financing costs of $24.4 million and $22.2 million at December 31, 2017 and 2016, respectively.

• unamortized discounts of $6.9 million and $6.8 million at December 31, 2017 and 2016, respectively.

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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:

	2017		2016		Recovery Period
	(In Thousands)
Regulatory Assets
Current:
Undercollections of rate riders	$	22,990	$	19,959	Approximately 1 year(1)
Costs being recovered through base rates	12,351		13,953		Approximately 1 year(1)
Total current regulatory assets	35,341		33,912
Long-term:
Unrecognized pension and other
postretirement benefit plan costs	205,573		218,070		Various(2)
Deferred income taxes recoverable through rates	—		51,131		Various
Deferred MISO costs	101,562		114,359		Through 2026(3)
Unamortized Petersburg Unit 4 carrying
charges and certain other costs	9,139		10,193		Through 2026(1)(4)
Unamortized reacquisition premium on debt	21,109		22,501		Over remaining life of debt
Environmental projects	40,434		30,678		Through 2050(1)(4)
Other miscellaneous	1,087		3,778		To be determined(1)(5)
Total long-term regulatory assets	378,904		450,710
Total regulatory assets	$	414,245	$	484,622
Regulatory Liabilities
Current:
Overcollections of rate riders	$	—	$	3,311	Approximately 1 year(1)
FTRs	2,532		4,393		Approximately 1 year(1)
Total current regulatory liabilities	2,532		7,704
Long-term:
ARO and accrued asset removal costs	696,973		668,787		Not Applicable
Deferred income taxes payable through rates	154,461		—		Various
Unamortized investment tax credit	320		1,507		Through 2021
Total long-term regulatory liabilities	851,754		670,294
Total regulatory liabilities	$	854,286	$	677,998

(1) Recovered (credited) per specific rate orders

(2) IPL receives a return on its discretionary funding

(3) The majority of these costs are being recovered per specific rate order; recovery for the remaining costs is probable but timing not yet determined

(4) Recovered with a current return

(5) A portion of this amount will be recovered over the next two years

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Deferred Fuel

Deferred fuel costs are a component of current regulatory assets or liabilities (which is a result of IPL charging either more or less for fuel than our actual costs to our jurisdictional customers) and are expected to be recovered through future FAC proceedings. IPL records deferred fuel in accordance with standards prescribed by the FERC. The deferred fuel adjustment is the result of variances between estimated fuel and purchased power costs in IPL’s FAC and actual fuel and purchased power costs. IPL is generally permitted to recover underestimated fuel and purchased power costs in future rates through the FAC proceedings and therefore the costs are deferred when incurred and amortized into fuel expense in the same period that IPL’s rates are adjusted to reflect these costs. 

Unrecognized Pension and Postretirement Benefit Plan Costs

In accordance with ASC 715 “Compensation – Retirement Benefits” and ASC 980, we recognize a regulatory asset equal to the unrecognized actuarial gains and losses and prior service costs. Pension expenses are recorded based on the benefit plan’s actuarially determined pension liability and associated level of annual expenses to be recognized. The other postretirement benefit plan’s deferred benefit cost is the excess of the other postretirement benefit liability over the amount previously recognized.

Deferred Income Taxes Recoverable/Payable Through Rates

A deferred income tax asset or liability is created from a difference in timing of income recognition between tax laws and accounting methods. As a regulated utility, IPL includes in ratemaking the impacts of current income taxes and changes in deferred income tax liabilities or assets.

The regulatory asset of $51.1 million as of December 31, 2016 represents the portion of IPL’s net deferred income tax liability that IPL believed would be recovered through future rates, without interest, based upon established regulatory practices. That asset as of December 31, 2016 was based upon a future federal income tax rate of 35% and was offset by a deferred income tax liability.

On December 22, 2017, the U.S.federal government enacted the TCJA, which includes a provision to, among other things, reduce the federal corporate income tax rate from 35% to 21%, beginning January 1, 2018. As required by GAAP, on December 31, 2017, IPL and IPALCO remeasured their deferred income tax assets and liabilities using the new tax rate. The Company believes that the impact of the reduction of the income tax rate on deferred income taxes will be used in future ratemaking to reduce jurisdictional retail rates. Accordingly, we now have a net regulatory liability of $154.5 million as of December 31, 2017.

Deferred MISOCosts

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.”

AROandAccrued Asset Removal Costs

In accordance with ASC 410 and ASC 980, IPL recognizes the cost of removal component of its depreciation reserve that does not have an associated legal retirement obligation as a deferred liability. This amount is net of the portion of legal ARO costs that is currently being recovered in rates.

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6. EQUITY

Equity Transactions

On December 15, 2014, AES announced that it entered into an agreement with CDPQ, a long-term institutional investor headquartered in Quebec, Canada.  Pursuant to the agreement, on February 11, 2015, CDPQ purchased from AES 15% of AES U.S. Investments and 100 shares of IPALCO’s common stock were issued to CDPQ. In addition, pursuant to the agreement, CDPQ invested approximately $349 million in IPALCO through 2016, in exchange for a 17.65% equity stake, funding existing growth and environmental projects at IPL. 

After completion of these transactions, CDPQ’s direct and indirect interests in IPALCO total approximately 30%, AES owns 85% of AES U.S. Investments, and AES U.S. Investments owns 82.35% of IPALCO. There has been no significant change in management or operational control of AES U.S. Investments, IPALCO or IPL as a result of these transactions. 

In connection with the initial closing under the agreement, CDPQ, AES U.S. Investments, and IPALCO entered into a Shareholders’ Agreement. The Shareholders’ Agreement established the general framework governing the relationship between and among CDPQ and AES U.S. Investments, and their respective successors and transferees, as shareholders of IPALCO. Pursuant to the Shareholders’ Agreement, the Board of Directors of IPALCO will initially consist of 11 directors, two nominated by CDPQ and 9 nominated by AES U.S. Investments. The Shareholders’ Agreement contains restrictions on IPALCO making certain major decisions without the prior affirmative vote of a majority of the Board of Directors of IPALCO. In addition, for so long as CDPQ holds at least 5% of IPALCO’s common shares, CDPQ will have review and consultation rights with respect to certain actions of IPALCO. Certain transfer restrictions and other transfer rights apply to CDPQ and AES U.S. Investments under the Shareholders’ Agreement, including certain rights of first offer, drag along rights, tag along rights, put rights and rights of first refusal.

On February 11, 2015, in connection with the initial closing under the Subscription Agreement and the entry into the Shareholders’ Agreement, IPALCO submitted the Third Amended and Restated Articles of Incorporation for filing with the Indiana Secretary of State, as approved and adopted by the IPALCO Board. The purpose of the Third Amended and Restated Articles of Incorporation is to amend, among other things, Article VI of the Second Amended and Restated Articles of Incorporation of IPALCO in order to effectuate changes to the size and composition of the IPALCO Board in furtherance of the terms and conditions of the IPALCO Shareholders’ Agreement.

Paid In Capital and Capital Stock

On 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, 2017 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

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maintain a ratio of total debt to total capitalization not in excess of 0.65 to 1. As of December 31, 2017 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, 2017, 2016 and 2015, 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, 2017, 2016 and 2015, preferred stock consisted of the following:

	December 31, 2017			December 31,
	Shares Outstanding	Call Price		2017		2016		2015
				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	2017			2016
		(In Thousands)
IPL first mortgage bonds:
5.40% (1)	August 2017	$	—		$	24,650
3.875% (2)	August 2021	55,000			55,000
3.875% (2)	August 2021	40,000			40,000
3.125% (2)	December 2024	40,000			40,000
6.60%	January 2034	100,000			100,000
6.05%	October 2036	158,800			158,800
6.60%	June 2037	165,000			165,000
4.875%	November 2041	140,000			140,000
4.65%	June 2043	170,000			170,000
4.50%	June 2044	130,000			130,000
4.70%	September 2045	260,000			260,000
4.05%	May 2046	350,000			350,000
Unamortized discount – net		(6,353		)	(6,477		)
Deferred financing costs		(16,168		)	(16,736		)
Total IPL first mortgage bonds		1,586,279			1,610,237
IPL unsecured debt:
Variable (3)	December 2020	30,000			30,000
Variable (3)	December 2020	60,000			60,000
Deferred financing costs		(344		)	(456		)
Total IPL unsecured debt		89,656			89,544
Total Long-term Debt – IPL		1,675,935			1,699,781
Long-term Debt – IPALCO:
5.00% Senior Secured Notes	May 2018	—			400,000
3.45% Senior Secured Notes	July 2020	405,000			405,000
3.70% Senior Secured Notes	September 2024	405,000			—
Unamortized discount – net		(534		)	(273		)
Deferred financing costs		(7,863		)	(5,018		)
Total Long-term Debt – IPALCO		801,603			799,709
Total Consolidated IPALCO Long-term Debt		2,477,538			2,499,490
Less: Current Portion of Long-term Debt		—			24,650
Net Consolidated IPALCO Long-term Debt		$	2,477,538		$	2,474,840

(1) First mortgage bonds issued to the city of Petersburg, Indiana, to secure the loan of proceeds from tax-exempt bonds issued by the city. IPL repaid these first mortgage bonds on August 1, 2017.

(2) First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority.

(3) Unsecured notes issued to the Indiana Finance Authority by IPL to facilitate the loan of proceeds from various tax-exempt notes issued by the Indiana Finance Authority. The notes have a final maturity date of December 2038, but are subject to a mandatory put in December 2020.

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Debt Maturities

Maturities on long-term indebtedness subsequent to December 31, 2017, are as follows:

Year	Amount
	(In Thousands)
2018	$	—
2019	—
2020	495,000
2021	95,000
2022	—
Thereafter	1,918,800
Total	$	2,508,800

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 $1,608.8 million as of December 31, 2017. 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, 2017.

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%.

On August 1, 2017, IPL repaid $24.7 million in outstanding borrowings of 5.40% IPL first mortgage bonds that were due in August 2017.

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IPL Unsecured Notes

In October 2015, IPL entered into an unsecured $91.9 million364-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.

IPALCO 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.

In August 2017, IPALCO completed the sale of the $405 million 2024 IPALCO Notes pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended. The 2024 IPALCO Notes were issued pursuant to an Indenture dated August 22, 2017, by and between IPALCO and U.S. Bank, National Association, as trustee. The 2024 IPALCO Notes were priced to the public at 99.901% of the principal amount. Net proceeds to IPALCO were approximately $399.3 million after deducting underwriting costs and estimated offering expenses. These costs are being amortized to the maturity date using the effective interest method. We used the net proceeds from this offering, together with cash on hand, to redeem the $400 million 2018 IPALCO Notes on September 21, 2017, and to pay certain related fees, expenses and make-whole premiums. A loss on early extinguishment of debt of $8.9 million for the 2018 IPALCO Notes is included as a separate line item within “Other Income and (Deductions)” in the accompanying Consolidated Statements of Operations.

The 2020 IPALCO Notes and 2024 IPALCO Notes are secured by IPALCO’s pledge of all of the outstanding common stock of IPL. The lien on the pledged shares is shared equally and ratably with IPALCO’s existing senior secured notes. IPALCO also agreed to register the 2024 IPALCO Notes under the Securities Act by filing an exchange offer registration statement or, under

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specified circumstances, a shelf registration statement with the SEC pursuant to a Registration Rights Agreement that IPALCO entered into with Morgan Stanley & Co. LLC and PNC Capital Markets LLC, as representatives of the initial purchasers of the 2024 IPALCO Notes, dated August 22, 2017. IPALCO filed its registration statement on Form S-4 with respect to the 2024 IPALCO Notes with the SEC on November 13, 2017, and this registration statement was declared effective on December 5, 2017. The exchange offer was completed on January 12, 2018.

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 and IPALCO had existing general banking relationships with the parties to the Credit Agreement. As of December 31, 2017 and 2016, IPL had $148.0 million and $50.0 million in outstanding borrowings on the committed line of credit, respectively.

Restrictions on Issuance ofDebt 

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, 2017, 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, 2017. As an alternative to the sale of all or a portion of $65 million in principal of the long-term debt mentioned above, we have the authority to issue up to $65 million of new preferred stock, all of which authority remains available under the order as of December 31, 2017. IPL also has restrictions on the amount of new debt that may be issued due to contractual obligations of AES and by financial covenant restrictions under our existing debt obligations. Under such restrictions, IPL is generally allowed to fully draw the amounts available on its credit facility, refinance existing debt and issue new debt approved by the IURC and issue certain other indebtedness.

Credit Ratings

Our ability to borrow money or to refinance existing indebtedness and the interest rates at which we can borrow money or refinance existing indebtedness are affected by our credit ratings. In addition, the applicable interest rates on IPL’s Credit Agreement and other unsecured notes 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.

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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 6.125% for the calendar year 2017, 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 $1.3 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 $0.1 million. The statutory state corporate income tax rate will be 5.875% for 2018.

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 through the 2017 tax year, 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 2017 tax year is estimated to be $3.9 million. The tax benefit associated with the Internal Revenue Code Section 199 domestic production deduction for the tax year 2016 was $2.9 million. There was no tax benefit for tax year 2015, primarily due to the election of the final tangible property regulations. Due to the recently enacted TCJA (as described below), the 2017 tax year will be the final year for this deduction.

U.S. Tax Reform

On December 22, 2017, the U.S. federal government enacted the TCJA. The TCJA significantly changes U.S. corporate income tax law.

The Company recognized the income tax effects of the TCJA in accordance with Staff Accounting Bulletin No. 118 (“SAB 118”) which provides SEC guidance on the application of ASC 740, Income Taxes, in the reporting period in which the TCJA was signed into law. Accordingly, the Company’s financial statements reflect the income tax effects of U.S. tax reform for which the accounting is complete and provisional amounts for those impacts for which the accounting under ASC 740 is incomplete, but a reasonable estimate could be determined.

The Company has calculated its best estimate of the impact of the TCJA in its income tax provision for the year ended December 31, 2017 in accordance with its understanding of the TCJA and guidance available as of the date of this filing, and as a result recognized $0.2 million of discrete tax expense in the fourth quarter of 2017.

This total results from the remeasurement of certain deferred tax assets and liabilities from 35% to 21%. The most material deferred taxes to be remeasured related to property, plant and equipment. The remeasurement of deferred tax assets and liabilities related to regulated utility property of $215.5 million was recorded as a regulatory liability, which was a non-cash adjustment. Additional time is required to finalize remeasurement effects in accordance with GAAP.

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Income Tax Provision

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

	2017			2016			2015
	(In Thousands)
Charged to utility operating expenses:
Current income taxes:
Federal	$	56,512		$	50,482		$	18,661
State	12,586			12,080			5,758
Total current income taxes	69,098			62,562			24,419
Deferred income taxes:
Federal	(1,668		)	11,885			29,165
State	(354		)	215			5,019
Total deferred income taxes	(2,022		)	12,100			34,184
Net amortization of investment credit	(1,455		)	(1,501		)	(1,319		)
Total charge to utility operating expenses	65,621			73,161			57,284
Charged to other income and deductions:
Current income taxes:
Federal	(13,970		)	(30,558		)	(18,661		)
State	(2,670		)	(4,807		)	(5,758		)
Total current income taxes	(16,640		)	(35,365		)	(24,419		)
Deferred income taxes:
Federal	(52		)	20,998			(2,573		)
State	22			2,415			1,274
Total deferred income taxes	(30		)	23,413			(1,299		)
Net provision to other income and deductions	(16,670		)	(11,952		)	(25,718		)
Total federal and state income tax provisions	$	48,951		$	61,209		$	31,566

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: 

	2017		2016		2015
Federal statutory tax rate	35.0	%	35.0	%	35.0	%
State income tax, net of federal tax benefit	4.1	%	4.1	%	4.7	%
Amortization of investment tax credits	(0.9	)%	(0.8	)%	(1.5	)%
Preferred dividends of subsidiary	0.7	%	0.6	%	1.3	%
Depreciation flow through and amortization	(0.1	)%	(0.5	)%	(0.3	)%
Additional funds used during construction - equity	(4.1	)%	(3.8	)%	(3.5	)%
Manufacturers’ Production Deduction (Sec. 199)	(2.5	)%	(1.3	)%	—	%
Other – net	(0.5	)%	(0.9	)%	0.2	%
Effective tax rate	31.7	%	32.4	%	35.9	%

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Deferred Income Taxes

The significant items comprising IPALCO’s net accumulated deferred tax liability recognized on the audited Consolidated Balance Sheets as of December 31, 2017 and 2016, are as follows:

	2017		2016
	(In Thousands)
Deferred tax liabilities:
Relating to utility property, net	$	475,911	$	569,204
Regulatory assets recoverable through future rates	66,661		180,608
Other	6,654		11,612
Total deferred tax liabilities	549,226		761,424
Deferred tax assets:
Investment tax credit	240		927
Regulatory liabilities including ARO	278,529		272,001
Employee benefit plans	18,564		27,358
Other	6,636		11,408
Total deferred tax assets	303,969		311,694
Deferred income taxes – net	$	245,257	$	449,730

Uncertain Tax Positions

The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2017, 2016 and 2015: 

	2017			2016			2015
	(In Thousands)
Unrecognized tax benefits at January 1	$	6,634		$	7,147		$	7,042
Gross increases – current period tax positions	470			724			962
Gross decreases – prior period tax positions	(2,453		)	(1,237		)	(857		)
Unrecognized tax benefits at December 31	$	4,651		$	6,634		$	7,147

The unrecognized tax benefits at December 31, 2017 represent tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, other than interest and penalties, the timing of the deductions will not affect the annual effective tax rate but would accelerate the tax payments to an earlier period.

Tax-related interest expense and income is reported as part of the provision for federal and state income taxes. Penalties, if incurred, would also be recognized as a component of tax expense. There are no interest or penalties applicable to the periods contained in this report.

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9. BENEFIT PLANS

Defined Contribution Plans

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

The Thrift Plan

Approximately 85% of IPL’s active employees are covered by the Thrift Plan, a qualified defined contribution plan. All union new hires are covered under the Thrift Plan. 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 $3.4 million, $3.1 million and $3.1 million for 2017, 2016 and 2015, respectively.

The RSP

Approximately 15% 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 $1.8 million, $1.0 million and $0.3 million for 2017, 2016 and 2015, respectively.

Defined Benefit Plans

Approximately 78% of IPL’s active employees are covered by the qualified Defined Benefit Pension Plan; while approximately 7% 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 15% 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, 2017 was 22. 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 163 active employees and 6 retirees (including spouses) were receiving such benefits or entitled to future benefits as of January 1, 2017. The plan is unfunded. These postretirement health care benefits and the related unfunded obligation of$7.0 million and $6.8 million at December 31, 2017 and 2016, respectively, were not material to the consolidated financial statements in the periods covered by this report.

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The following table presents information relating to the Pension Plans: 

	Pension benefits as of December 31,
	2017			2016
	(In Thousands)
Change in benefit obligation:
Projected benefit obligation at January 1	$	731,825		$	723,887
Service cost	7,344			7,018
Interest cost	25,305			25,815
Actuarial loss	52,451			9,718
Amendments (primarily increases in pension bands)	900			—
Settlements	(266		)	—
Benefits paid	(35,451		)	(34,613		)
Projected benefit obligation at December 31	782,108			731,825
Change in plan assets:
Fair value of plan assets at January 1	674,430			647,573
Actual return on plan assets	93,022			45,520
Employer contributions	7,212			15,950
Settlements	(266		)	—
Benefits paid	(35,451		)	(34,613		)
Fair value of plan assets at December 31	738,947			674,430
Unfunded status	$	(43,161	)	$	(57,395	)
Amounts recognized in the statement of financial position:
Noncurrent liabilities	$	(43,161	)	$	(57,395	)
Net amount recognized at end of year	$	(43,161	)	$	(57,395	)
Sources of change in regulatory assets(1):
Prior service cost arising during period	$	900		$	—
Net loss arising during period	4,101			7,690
Amortization of prior service cost	(4,240		)	(5,183		)
Amortization of loss	(13,341		)	(13,896		)
Total recognized in regulatory assets(1)	$	(12,580	)	$	(11,389	)
Amounts included in regulatory assets(1):
Net loss	$	193,807		$	203,047
Prior service cost	17,318			20,658
Total amounts included in regulatory assets	$	211,125		$	223,705

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

Information for Pension Plans with aprojectedbenefit obligation in excess of plan assets

	Pension benefits as of December 31,
	2017		2016
	(In Thousands)
Benefit obligation	$	782,108	$	731,825
Plan assets	738,947		674,430
Benefit obligation in excess of plan assets	$	43,161	$	57,395

IPL’s total benefit obligation in excess of plan assets was $43.2 million as of December 31, 2017 ($42.4 million Defined Benefit Pension Plan and $0.8 million Supplemental Retirement Plan).

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

	Pension benefits as of December 31,
	2017		2016
	(In Thousands)
Accumulated benefit obligation	$	769,678	$	720,901
Plan assets	738,947		674,430
Accumulated benefit obligation in excess of plan assets	$	30,731	$	46,471

IPL’s total accumulated benefit obligation in excess of plan assets was $30.7 million as of December 31, 2017 ($29.9 million Defined Benefit Pension Plan and $0.8 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.

The 2017 net actuarial loss of $4.1 million is comprised of two parts: (1) a $52.5 million pension liability actuarial loss primarily due to a decrease in the discount rate used to value pension liabilities; partially offset by (2) a $48.4 million pension asset actuarial gain primarily due to higher than expected return on assets. The unrecognized net loss of $193.8 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 2017, the accumulated net loss was decreased due to a combination of higher than expected return on pension assets, as well as the year 2017 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 9.91 years based on estimated demographic data as of December 31, 2017. The projected benefit obligation of $782.1 million less the fair value of assets of $738.9 million results in an unfunded status of $(43.2) million at December 31, 2017.

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	Pension benefits for years ended December 31,
	2017			2016				2015
	(In Thousands)
Components of net periodic benefit cost:
Service cost	$	7,344		$	7,018			$	8,314
Interest cost	25,305			25,815				29,638
Expected return on plan assets	(44,672		)	(43,492		)		(44,819		)
Amortization of prior service cost	4,240			5,183				4,867
Recognized actuarial loss	13,195			13,896				13,890
Recognized settlement loss	146			—			—	206
Total pension cost	5,558			8,420				12,096
Less: amounts capitalized	845			1,187				1,403
Amount charged to expense	$	4,713		$	7,233			$	10,693
Rates relevant to each year’s expense calculations:
Discount rate – defined benefit pension plan	4.29		%	4.42		%		4.06		%
Discount rate – supplemental retirement plan	4.00		%	4.19		%		3.82		%
Expected return on defined benefit pension plan assets	6.75		%	6.75		%		6.75		%
Expected return on supplemental retirement plan assets	6.75		%	6.75		%		6.75		%

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 2017, pension expense was determined using an assumed long-term rate of return on plan assets of 6.75%. As of the December 31, 2017 measurement date, IPL decreased the discount rate from 4.29% to 3.67% for the Defined Benefit Pension Plan and decreased the discount rate from 4.00% to 3.60% for the Supplemental Retirement Plan. The discount rate assumption affects the pension expense determined for 2018. In addition, IPL decreased the expected long-term rate of return on plan assets from 6.75% to 5.45% effective January 1, 2018. The expected long-term rate of return assumption affects the pension expense determined for 2018. The effect on 2018 total pension expense of a 25 basis point increase and decrease in the assumed discount rate is $(1.4) million and $1.4 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, 2017. 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 2018 plan year are $11.6 million and $4.0 million, respectively (Defined Benefit Pension Plan of $11.4 million and $4.0 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, 2017. 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

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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).

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 2017:

Asset Category:	Target Allocations
Equity Securities	30%
Debt Securities	70%

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	Fair Value Measurements at
	December 31, 2017
	(in thousands)
			Quoted Prices in Active Markets for Identical Assets		Significant Observable Inputs
Asset Category	Total		(Level 1)		(Level 2)		%
Short-term investments	$	115	$	115	$	—	—	%
Mutual funds:
U.S. equities	162,144		162,144		—		22	%
International equities	58,536		58,536		—		8	%
Fixed income	415,868		415,868		—		56	%
Fixed income securities:
U.S. Treasury securities	102,284		102,284		—		14	%
Total	$	738,947	$	738,947	$	—	100	%

	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	%

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Pension Funding

We contributed $7.2 million, $16.0 million, and $25.2 million to the Pension Plans in 2017, 2016 and 2015, 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 110%. 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 $7.3 million in 2018, which includes $1.7 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 $30.0 million in January 2018, which satisfies all funding requirements for the calendar year 2018. 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, 2017, 2016 and 2015 were $35.5 million,$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)
2018	$	40,598
2019	$	42,325
2020	$	43,657
2021	$	45,077
2022	$	46,030
2023 through 2027	$	237,296

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

We are subject to various federal, state, regional and local environmental protection and health and safety laws and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of hazardous materials; the emission and discharge of hazardous and other materials into the environment; and the health and safety of our employees. These laws and regulations often require a lengthy and complex process of obtaining and renewing permits and other governmental authorizations from federal, state and local agencies. Violation of these laws, regulations or permits can result in substantial fines, other sanctions, permit revocation and/or facility shutdowns. We cannot assure that we have been or will be at all times in full compliance with such laws, regulations and permits.

New Source Review

In October 2009, IPL received a NOV and Finding of Violation from the EPA pursuant to the CAA Section 113(a). The NOV alleges violations of the CAA at IPL’s three primarily coal-fired electric generating facilities at the time, dating back to 1986. The alleged violations primarily pertain to the PSD and nonattainment New Source Review requirements under the CAA. In addition, on October 1, 2015, IPL received a NOV from the EPA pursuant to CAA Section 113(a) alleging violations of the CAA, the Indiana SIP, and the Title V operating permit related to alleged particulate matter and opacity violations at IPL Petersburg Unit 3. Also, on February 5, 2016, the EPA issued a NOV pursuant to CAA Section 113(a) alleging violations of

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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. At this time, we cannot 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 cases 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, but does take a $5 million per occurrence deductible.  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 paid to AES Global Insurance Company and all claims are paid from a trust fund funded by and owned by AES Global Insurance Company, but controlled by the third-party administrator. IPL also has third-party insurance in which the premiums are paid directly to the third-party insurers. The cost to IPL of coverage under this program with AES Global Insurance Company was approximately $3.1 million, $3.1 million, and $2.7 million in 2017, 2016 and 2015, respectively, and is recorded in “Other operating expenses” on the accompanying Consolidated Statements of Operations. As of December 31, 2017 and 2016, we had prepaid approximately $1.9 million and $2.0 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 $24.9 million, $23.2 million, and $24.5 million in 2017, 2016 and 2015, 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, 2017 and 2016, 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 $14.7 million and $2.1 million as of December 31, 2017 and 2016, respectively, which is recorded in “Prepayments and other current assets” on the accompanying Consolidated Balance Sheets.

Long-term Compensation Plan

During 2017, 2016 and 2015, 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. Total deferred compensation expense recorded during 2017, 2016 and 2015 was $0.8 million, $0.9 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.

ServiceCompany

Total costs incurred by the Service Company on behalf of IPALCO were $34.4 million, $27.4 million and $23.2 million during 2017, 2016 and 2015, respectively. Total costs incurred by IPALCO on behalf of the Service Company during 2017, 2016 and

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2015 were $10.7 million, $9.2 million and $7.5 million, respectively. IPALCO had a prepaid balance with the Service Company of $3.1 million and $3.4 million as of December 31, 2017 and 2016, 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 and $232.0 million during 2016 and 2015, respectively. IPL had a payable balance to this vendor of $2.3 million as of December 31, 2016. This vendor continued to perform services throughout 2017 but did not bill IPL as certain milestones were not met under the terms of the contract.

Additionally, transactions with various other related parties were $2.4 million, $3.9 million and $2.4 million during 2017, 2016 and 2015, 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 2020 IPALCO Notes and the 2024 IPALCO Notes; approximately $18.3 million and $8.3 million of cash and cash equivalents, as of December 31, 2017 and 2016, respectively; long-term investments of $5.1 million as of December 31, 2017 and 2016; 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, 2017 and 2016. 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):

	2017							2016							2015
	Utility		All Other			Total		Utility		All Other			Total		Utility		All Other			Total
Operating revenues	$	1,350	$	—		$	1,350	$	1,347	$	—		$	1,347	$	1,250	$	—		$	1,250
Depreciation and amortization	$	208	$	—		$	208	$	218	$	—		$	218	$	188	$	—		$	188
Income taxes	$	66	$	(17	)	$	49	$	73	$	(11	)	$	61	$	56	$	(25	)	$	32
Net income	$	137	$	(28	)	$	109	$	156	$	(25	)	$	131	$	102	$	(42	)	$	60
Utility plant - net of depreciation (1)	$	3,981	$	—		$	3,981	$	3,881	$	—		$	3,881	$	3,441	$	—		$	3,441
Capital expenditures	$	229	$	—		$	229	$	608	$	—		$	608	$	686	$	—		$	686

\

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Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Indianapolis Power & Light Company                                

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Indianapolis Power & Light Company and subsidiary (the Company) as of December 31, 2017 and 2016, 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, 2017, and the related notes and schedules (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2017 and 2016, and the results of its operations and its cash flows for the three years in the period ended December 31, 2017 in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our December 31, 2017 and 2016 audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America and our December 31, 2015 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2008.

Indianapolis, Indiana

February 26, 2018

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INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY
Consolidated Statements of Operations
For the Years Ended December 31, 2017, 2016 and 2015
(In Thousands)
	2017			2016			2015
OPERATING REVENUES	$	1,349,588		$	1,347,430		$	1,250,399
OPERATING EXPENSES:
Fuel	281,542			276,171			315,600
Other operating expenses	253,496			244,660			223,717
Power purchased	189,847			170,466			145,064
Maintenance	129,734			130,385			131,574
Depreciation and amortization	208,204			218,444			188,267
Taxes other than income taxes	44,580			45,262			43,617
Income taxes - net	65,621			73,161			57,284
Total operating expenses	1,173,024			1,158,549			1,105,123
OPERATING INCOME	176,564			188,881			145,276
OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used during construction	25,798			27,140			15,302
Miscellaneous income and (deductions) - net	(537		)	(1,354		)	(2,019		)
Income tax benefit applicable to nonoperating income	30			460			1,066
Total other income and (deductions) - net	25,291			26,246			14,349
INTEREST AND OTHER CHARGES:
Interest on long-term debt	83,375			77,638			65,277
Other interest	2,068			2,710			2,628
Allowance for borrowed funds used during construction	(22,302		)	(23,866		)	(12,809		)
Amortization of redemption premium and expense on debt	2,199			2,200			2,608
Total interest and other charges - net	65,340			58,682			57,704
NET INCOME	136,515			156,445			101,921
LESS: PREFERRED DIVIDEND REQUIREMENTS	3,213			3,213			3,213
NET INCOME APPLICABLE TO COMMON STOCK	$	133,302		$	153,232		$	98,708

See notes to consolidated financial statements.

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INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY
Consolidated Balance Sheets
(In Thousands)
	December 31, 2017		December 31, 2016
ASSETS
UTILITY PLANT:
Utility plant in service	$	5,385,053	$	4,997,846
Less accumulated depreciation	2,129,617		2,030,497
Utility plant in service - net	3,255,436		2,967,349
Construction work in progress	711,396		898,330
Spare parts inventory	13,157		14,237
Property held for future use	1,002		1,002
Utility plant - net	3,980,991		3,880,918
OTHER ASSETS:
Intangible assets - net	16,036		11,976
At cost, less accumulated depreciation	1,630		1,263
Other assets - net	17,666		13,239
CURRENT ASSETS:
Cash and cash equivalents	12,342		26,607
Accounts receivable and unbilled revenue (less allowance for
for doubtful accounts of $2,830 and $2,365, respectively)	157,577		154,586
Fuel inventories - at average cost	32,393		30,237
Materials and supplies - at average cost	63,624		60,649
Regulatory assets	35,341		33,912
Prepayments and other current assets	36,475		31,497
Total current assets	337,752		337,488
DEFERRED DEBITS:
Regulatory assets	378,904		450,710
Miscellaneous	4,234		4,409
Total deferred debits	383,138		455,119
TOTAL	$	4,719,547	$	4,686,764
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common shareholder's equity:
Common stock	$	324,537	$	324,537
Paid in capital	599,157		598,500
Retained earnings	442,779		434,993
Total common shareholder's equity	1,366,473		1,358,030
Cumulative preferred stock	59,784		59,784
Long-term debt (Note 7)	1,675,935		1,675,131
Total capitalization	3,102,192		3,092,945
CURRENT LIABILITIES:
Short-term and current portion of long-term debt (Note 7)	148,000		74,650
Accounts payable	125,162		119,506
Accrued expenses	27,046		18,742
Accrued real estate and personal property taxes	18,145		18,930
Regulatory liabilities	2,532		7,704
Accrued income taxes	—		984
Accrued interest	22,486		22,731
Customer deposits	31,306		29,780
Other current liabilities	10,092		26,167
Total current liabilities	384,769		319,194
DEFERRED CREDITS AND OTHER LONG-TERM LIABILITIES:
Deferred income taxes - net	244,812		449,220
Non-current income tax liability	4,651		6,634
Regulatory liabilities	851,754		670,294
Unamortized investment tax credit	954		2,410
Accrued pension and other postretirement benefits	50,070		64,139
Asset retirement obligations	79,535		80,568
Miscellaneous	810		1,360
Total deferred credits and other long-term liabilities	1,232,586		1,274,625
COMMITMENTS AND CONTINGENCIES (Note 10)
TOTAL	$	4,719,547	$	4,686,764

See notes to consolidated financial statements.

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INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY
Consolidated Statements of Cash Flows
For the Years Ended December 31, 2017, 2016 and 2015
(In Thousands)
	2017			2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	136,515		$	156,445		$	101,921
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	208,209			218,449			188,272
Amortization of deferred financing costs and debt premium	2,199			2,200			2,608
Deferred income taxes and investment tax credit adjustments - net	(3,441		)	11,165			33,756
Allowance for equity funds used during construction	(25,798		)	(27,140		)	(14,996		)
Change in certain assets and liabilities:
Accounts receivable	(2,991		)	(30,420		)	15,542
Fuel, materials and supplies	(5,342		)	33,434			(18,372		)
Income taxes receivable or payable	(17,968		)	3,821			(2,544		)
Financial transmission rights	1,861			(243		)	2,086
Accounts payable and accrued expenses	(3,512		)	13,891			(356		)
Accrued real estate and personal property taxes	(785		)	1,218			(1,465		)
Accrued interest	(245		)	1,627			996
Pension and other postretirement benefit expenses	(14,069		)	(16,595		)	(15,730		)
Short-term and long-term regulatory assets and liabilities	17,011			(38,026		)	(22,980		)
Prepaids and other current assets	6,185			(1,910		)	(4,671		)
Other - net	(1,864		)	3,511			5,895
Net cash provided by operating activities	295,965			331,427			269,962
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(218,224		)	(592,243		)	(672,849		)
Project development costs	(1,729		)	(1,356		)	(8,980		)
Asset removal costs	(12,195		)	(13,403		)	(12,064		)
Other	(4,730		)	(1,703		)	(1,224		)
Net cash used in investing activities	(236,878		)	(608,705		)	(695,117		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt borrowings	202,500			298,000			388,850
Short-term debt repayments	(129,150		)	(414,850		)	(272,000		)
Long-term borrowings	—			387,662			348,638
Retirement of long-term debt	—			(40,000		)	(131,850		)
Dividends on common stock	(132,516		)	(136,466		)	(103,747		)
Dividends on preferred stock	(3,213		)	(3,213		)	(3,213		)
Equity contributions from IPALCO	—			213,014			214,364
Payments for financed capital expenditures	(10,637		)	(15,473		)	(13,215		)
Other	(336		)	(4,641		)	(3,819		)
Net cash (used in) provided by financing activities	(73,352		)	284,033			424,008
Net change in cash and cash equivalents	(14,265		)	6,755			(1,147		)
Cash and cash equivalents at beginning of period	26,607			19,852			20,999
Cash and cash equivalents at end of period	$	12,342		$	26,607		$	19,852
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized)	$	63,031		$	54,350		$	53,447
Income taxes	$	87,000		$	57,900		$	25,000
	As of December 31,
	2017			2016			2015
Non-cash investing activities:
Accruals for capital expenditures	$	45,322		$	36,249		$	79,553

See notes to consolidated financial statements.

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INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY
Consolidated Statements of Common Shareholder's Equity
For the Years Ended December 31, 2017, 2016 and 2015
(In Thousands)
	Common Stock		Paid in Capital		Retained Earnings			Total
Balance at January 1, 2015	$	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
Net income					136,515			136,515
Preferred stock dividends					(3,213		)	(3,213		)
Cash dividends declared on common stock					(125,516		)	(125,516		)
Other			657					657
Balance at December 31, 2017	$	324,537	$	599,157	$	442,779		$	1,366,473

See notes to consolidated financial statements.

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INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2017, 2016 and 2015

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, which provides frequency response. 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. As of December 31, 2017, IPL’s net electric generation capacity for winter is 2,996 MW and net summer capacity is 2,881 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.

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

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.

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

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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, 2017 and 2016, customer accounts receivable include unbilled energy revenues of $61.6 million and $57.0 million, respectively, on a base of annual revenue of $1.3 billion in 2017 and 2016. An allowance for potential credit losses is maintained and amounts are written off when normal collection efforts have been exhausted. IPL’s provision for doubtful accounts included in “Other operating expenses” on the accompanying Consolidated Statements of Operations was $5.9 million, $4.1 million and $4.3 million for the years ended December 31, 2017, 2016 and 2015, 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, “RegulatoryMatters” 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, IPL is one of many transmission system owner members of MISO, a regional transmission organization which maintains functional control over the combined transmission systems of its members and manages one of the largest energy markets in the U.S. 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, 2017 and 2016, total loss contingencies accrued were $4.1 million and $11.6 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 67% 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 four suppliers, with about 50% of our existing coal under contract for the three-year period ending December 31, 2020 coming from one supplier. Substantially all of the coal is currently mined in the state of Indiana.

Allowance For Funds Used During Construction

In accordance with the Uniform System of Accounts prescribed by FERC, IPL capitalizes an allowance for the net cost of funds (interest on borrowed funds and a reasonable rate of return on equity funds) used for construction purposes during the period of construction with a corresponding credit to income. For the Eagle Valley CCGT, Harding Street refueling projects, and NPDES projects, IPL capitalized amounts using a pretax composite rate of 6.6%, 7.1% and 7.3% during 2017, 2016 and 2015, respectively. For all other construction projects, IPL capitalized amounts using pretax composite rates of 6.6%, 7.2% and 8.1% during 2017, 2016 and 2015, respectively.

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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 4.1%, 4.3%, and 4.2% during 2017, 2016 and 2015, respectively. Depreciation expense was $209.8 million, $209.5 million, and $194.4 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Derivatives

IPL has 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

IPL maintains 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 IPL measures long-lived assets for impairment when indicators of impairment exist. If an asset is deemed to be impaired, IPL is required to write down the asset to its fair value with a charge to current earnings. The net book value of IPL’s utility plant assets was $4.0 billion and $3.9 billion as of December 31, 2017 and 2016, respectively. IPL does not believe any of these assets are currently impaired. In making this assessment, IPL considers 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 its service territory and wholesale electricity in the region; and the cost of fuel.

Intangible Assets

Intangible assets primarily include capitalized software of $99.4 million and $91.7 million and its corresponding amortization of $83.4 million and $79.7 million, as of December 31, 2017 and 2016, respectively. Amortization expense was $4.3 million, $5.9 million and $5.2 million for the years ended December 31, 2017, 2016 and 2015, respectively. The estimated amortization expense over the remaining useful life of this capitalized software is $16.0 million ($3.2 million annually over the next 5 years).

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. IPL 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. IPL’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. IPL’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.

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Cash and Cash Equivalents

Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents.

Pension and Postretirement Benefits

IPL recognizes in its 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. IPL follows 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.

IPL accounts for and discloses 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. Consistent with the requirements of ASC 715, IPL applies a disaggregated discount rate approach for determining service cost and interest cost for its defined benefit pension plans and postretirement plans.

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.

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New Accounting Standards Adopted
ASU Number and Name	Description	Date of Adoption	Effect on the financial statements upon adoption
2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting	The standard simplifies the following aspects of accounting for share-based payments awards: accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: The recognition of excess tax benefits and tax deficiencies arising from vesting or settlement were applied retrospectively. The elimination of the requirement that excess tax benefits be realized before they are recognized was adopted on a modified retrospective basis.	January 1, 2017	The primary effect of adoption was the recognition of excess tax benefits in IPL’s 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. IPL will continue to estimate the number of awards that are expected to vest in its determination of the related periodic compensation cost. The adoption of this standard did not have a material impact on the consolidated financial statements.
New Accounting Standards Issued But Not Yet Effective
ASU Number and Name	Description	Date of Adoption	Effect on the financial statements upon adoption
2017-08, Receivables - Nonrefundable Fees and Other Costs (Subtopic 310-20): Premium Amortization on Purchased Callable Debt Securities	This standard shortens the period of amortization of the premium on certain callable debt securities to the earliest call date. Transition method: modified retrospective.	January 1, 2019. Early adoption is permitted.	IPL is currently evaluating the impact of adopting the standard on its consolidated financial statements.
2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost	This standard changes the presentation of non-service cost associated with defined benefit plans and updates the guidance so that only the service cost component will be eligible for capitalization. Transition method: Retrospective for presentation of non-service cost expense. Prospective for the change in capitalization.	January 1, 2018. Early adoption is permitted.	IPL expects the adoption of this standard to result in a $(2.1) million and $0.9 million reclassification of non-service pension costs (credits) from Other operating expenses to Miscellaneous income and (deductions) - net for 2017 and 2016, respectively. IPL plans to adopt the standard as of January 1, 2018.
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 has performed a preliminary evaluation, and the adoption of this standard is not expected to have a material impact on the 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. For trade and other receivables, held-to-maturity debt securities, loans and other instruments, entities will be required to use a new forward-looking “expected loss” model that generally will result in the earlier recognition of allowance for losses. For available-for-sale debt securities with unrealized losses, entities will measure credit losses as it is done today, except that the losses will be recognized as an allowance rather than a reduction in the amortized cost of the securities. 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.
2016-02, 2018-01, Leases (Topic 842)	See discussion of the ASUs below.	January 1, 2019. Early adoption is permitted.	IPL is currently evaluating the impact of adopting the standard on its consolidated financial statements and intends to adopt the standard as of January 1, 2019.
2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-10, 2017-13, Revenue from Contracts with Customers (Topic 606)	See discussion of the ASUs below:	January 1, 2018. Early adoption is permitted only as of January 1, 2017.	IPL 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 provides 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.

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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.

In 2016, IPL established a cross-functional implementation team and is in the process of evaluating changes to its business processes, systems and controls to support recognition and disclosure under the new standard. At this time, IPL does not expect any significant impact on its financial systems or a material change to controls as a result of the implementation of the new revenue recognition standard.

IPL is assessing the standard on a contract-by-contract basis and applying the interpretations reached during 2017 on key issues. The application of the practical expedient for measuring progress towards satisfaction of a performance obligation, when variable quantities would be considered variable consideration versus an option to acquire additional goods and services and how to allocate variable consideration to one or more, but not all, distinct goods or services promised in a series of distinct goods or services that forms part of a single performance obligation. Additionally, IPL has been working on the application of the standard to contracts that are under the scope of Service Concession Arrangements (Topic 853) and assessing the gross versus net presentation for spot energy sale and purchases. Through this assessment to date, IPL has not identified any situations where revenue recognized under ASC 606 could differ from that recognized under ASC 605 or where the presentation of sales to and purchases from the spot markets will change. Given the limited impact, IPL expects to use the modified retrospective approach.

IPL is 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 interpretive issues.

ASU 2016-02 and its subsequent corresponding updates require lessees to recognize assets and liabilities for most leases but recognize expenses in a manner similar to today’s accounting. For lessors, the guidance modifies the lease classification criteria and the accounting for sales-type and direct financing leases. The guidance also eliminates today’s real estate-specific provisions.

The standard requires modified retrospective adoption at the beginning of the earliest comparative period presented in the financial statements (January 1, 2017). The FASB proposed amending the standard to give another option for transition. The proposed transition method would allow entities to not apply the new lease standard in the comparative periods presented in their financial statements in the year of adoption. Under the proposed transition method, the entity would apply the transition provisions on January 1, 2019 (i.e., the effective date). At transition, lessees and lessors are permitted to make an election to apply a package of practical expedients that allow them not to reassess: (1) whether any expired or existing contracts are or contain leases, (2) lease classification for any expired or existing leases, and (3) whether initial direct costs for any expired or existing leases qualify for capitalization under ASC 842. These three practical expedients must be elected as a package and must be consistently applied to all leases. Furthermore, entities are also permitted to make an election to use hindsight when determining lease term and lessees can elect to use hindsight when assessing the impairment of right-of-use assets.

IPL has established a task force focused on the identification of contracts that would be under the scope of the new standard and on the assessment and measurement of the right-of-use asset and related liability. Additionally, the implementation team has been working on the identification and selection of a lease accounting system that would support the implementation and the subsequent accounting. The implementation team is in the process of evaluating changes to our business processes, systems and controls to support recognition and disclosure under the new standard.

As IPL has preliminarily concluded that at transition it would be using the package of practical expedients, the main impact expected as of the effective date is the recognition of the right to use asset and the related liability in the financial statements for all those contracts that contain a lease and for which the Company is the lessee. However, income statement presentation and the expense recognition patter will not change.

Under ASC 842, it is expected that fewer contracts will contain a lease. However, due to the elimination of today's real estate-specific guidance and changes to certain lessor classification criteria, more leases will qualify as sales-type leases and direct financing leases. Under these two models, a lessor will derecognize the asset and will recognize a lease receivable. According to ASC 842, the lease receivable does not include variable payments that depend on the use of the asset (e.g. Mwh produced by a facility). Therefore, the lease receivable could be lower than the carrying amount of the underlying asset at lease commencement, In such circumstances, the difference between the initially recognized lease receivable and the carrying amount of the underlying is recognized as a selling loss at lease commencement. IPL is assessing situations for which this guidance would apply.

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2. REGULATORY MATTERS

General

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

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

IPL is also affected by the regulatory jurisdiction of the EPA at the federal level, and the IDEM at the state level. Other significant regulatory agencies affecting IPL include, but are not limited to, the NERC, the U.S. Department of Labor and the IOSHA.

Basic Rates and Charges

IPL’s basic rates and charges represent the largest component of its annual revenues. IPL’s 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.

IPL’s 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, and generating unit availability, can affect the return realized.

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. The CCGT was originally expected to be completed in the first half of 2017 and that timing was changed in 2017 to an expected completion in the first half of 2018.

IPL filed a petition with the IURC on December 21, 2017, for authority to increase its basic rates and charges to coincide with the expected completion of the CCGT in the first half of 2018. IPL’s proposed revenue increase was $124.5 million annually, or 9.1%. On February 16, 2018, IPL filed an update to such petition to reflect the federal income tax law changes passed, which reduced the revenue increase IPL is seeking to $96.7 million, or7.1%. An order on this proceeding will likely be issued by the IURC by the first quarter of 2019.

In March 2016, the IURC issued the 2016 Rate Order authorizing IPL to increase its basic rates and charges by $30.8 million annually. The order also authorized IPL to collect, over a ten year period, $117.7 million of previously deferred regulatory assets related to IPL’s participation in the regional transmission organization known as MISO. Such deferred costs are amortized to expense over ten years. Accordingly, $11.8 million of IPL’s long-term MISO regulatory asset is included within current regulatory assets on the accompanying 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 ofongoing 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. In September 2017, the FERC

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completed its review, authorizing the Service Company’s allocation of costs of non-power goods and services to IPL. In the 2016 Rate Order, the IURC also closed their investigation into IPL’s underground network.

Some of the intervening parties in the IURC rate case filed petitions for reconsideration of the IURC’s March 2016 order with respect to certain issues. These petitions were subsequently denied by the IURC. In addition, certain intervening parties filed notices of appeal of the order. On April 5, 2017, the Indiana Court of Appeals affirmed the IURC’s March 2016 order.

CCR

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

NAAQS

On April 26, 2017, the IURC approved IPL’s request for NAAQS SO2 compliance at its Petersburg generation station with 80% of qualifying costs recovered through a rate adjustment mechanism and the remainder recorded as a regulatory asset for recovery in a subsequent rate case. The approved capital cost of the NAAQS SO2 compliance plan is approximately $29 million. This project is expected to be fully in service in the first quarter of 2019.

Other

The DOE issued a Notice of Proposed Rule Making on September 29, 2017, which directed the FERC to exercise its authority to set just and reasonable rates that recognize the “resiliency” value provided by generation plants with certain characteristics, including having 90-days or more of on-site fuel and operating in markets where they do not receive rate base treatment through state ratemaking. Nuclear and coal-fired generation plants would have been most likely to be able to meet the requirements. As proposed, the DOE would value resiliency through rates that recover “compensable costs” that were defined to include the recovery of operating and fuel expenses, debt service and a fair return on equity. On January 8, 2018, the FERC issued an order terminating this docket stating that it failed to satisfy the legal requirements of Section 206 of the Federal Power Act of 1935. The FERC initiated a new docket to take additional steps to explore resilience issues in RTOs/ISOs. The goal of this new proceeding is to: (1) develop a common understanding among the FERC, State Commissions, RTOs/ISOs, transmission owners, and others as to what resilience of the bulk power system means and requires; (2) understand how each RTO and ISO assesses resilience in its geographic footprint; and (3) use this information to evaluate whether additional action regarding resilience is appropriate at this time. It is not possible to predict the impact of this proceeding on our business, financial condition or results of operations.

FACand Authorized Annual Jurisdictional Net Operating Income

IPL may apply to the IURC for a change in IPL’s fuel charge every three months to recover IPL’s estimated fuel costs, including the energy portion of purchased power costs, which may be above or below the levels included in IPL’s basic rates and charges. IPL must present evidence in each FAC proceeding that it has made every reasonable effort to acquire fuel and generate or purchase power or both so as to provide electricity to its retail customers at the lowest fuel cost reasonably possible.

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

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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, 2017 was $772 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 2017 through February 2018 was $48.0 million. During the years ended December 31, 2017, 2016 and 2015, we made environmental compliance expenditures of $59.1 million, $158.9 million, and $252.6 million, respectively. The vast majority of such costs are recoverable through IPL’s ECCRA filings.

DSM

In December 2014, IPL received approval from the IURC of its 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 IPL to receive performance incentives dependent upon the level of success of the programs. Additionally, IPL was 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. IPL 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, IPL received approval from the IURC of its DSM programs through the end of 2017; however, the IURC denied shareholder incentives pursuant to this order. IPL received shareholder incentives of approximately $10.7 million in 2016.

On February 7, 2018, the IURC approved a settlement agreement establishing a new three year DSM plan for IPL through 2020. The approval included cost recovery of programs as well as performance incentives, depending on the level of success of the programs. The order also approved recovery of lost revenues, consistent with the provisions of the settlement agreement.

Wind and Solar Power Purchase Agreements

IPL is committed under a power purchase agreement to purchase all wind-generated electricity through 2029 from a wind project in Indiana. IPL is also committed under another agreement to purchase all wind-generated electricity through 2031 from a project in Minnesota. The Indiana project has a maximum output capacity of approximately 100 MW and the Minnesota project has a maximum output capacity of approximately 200 MW. In addition, IPL has 97 MW of solar-generated electricity in its service territory under long-term contracts in 2018 (these long-term contracts expire ranging from 2021 to 2032), of which 95 MW was in operation as of December 31, 2017. IPL has authority from the IURC to recover the costs for all of these agreements through an adjustment mechanism administered within the FAC. If and when IPL sells the renewable energy attributes (in the form of renewable energy credits) generated from these facilities, the proceeds are passed back to IPL’s retail customers through the FAC.

Taxes

On January 3, 2018, the IURC opened a generic investigation to review and consider the impacts from the TCJA and how any resulting benefits should be realized by customers. The IURC’s order opening this investigation directed Indiana utilities to apply regulatory accounting treatment, such as the use of regulatory assets and regulatory liabilities, for all estimated impacts resulting from the TCJA. On February 16, 2018, the IURC issued an order establishing two phases of the investigation. The first phase directs respondent utilities (including IPL) to make a filing by March 25, 2018 to adjust respondents’ rates and charges for service, the impact of a lower federal income tax rate. The IURC will hold an attorney’s conference on May 3, 2018 to establish the phase two procedural schedule to discuss the remaining issues from the TCJA, including treatment of deferred taxes and how these benefits will be realized by customers. IPL is reviewing the IURC’s initial order and the ultimate result of the generic investigation cannot be determined at this time, although it could be material. See also Note 8, “Income Taxes” for further information.

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3. UTILITY PLANT IN SERVICE

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

	As of December 31,
	2017		2016
	(In Thousands)
Production	$	3,249,563	$	2,923,349
Transmission	380,881		376,659
Distribution	1,487,380		1,433,044
General plant	267,229		264,794
Total utility plant in service	$	5,385,053	$	4,997,846

Substantially all of IPL’s property is subject to a $1,608.8 million direct first mortgage lien, as of December 31, 2017, securing IPL’s first mortgage bonds. IPL had no property under capital leases as of December 31, 2017 and 2016. Total non-contractually or legally required removal costs of utility plant in service at December 31, 2017 and 2016 were $737.1 million and $705.6 million, respectively; and total contractually or legally required removal costs of utility plant in service at December 31, 2017 and 2016 were $79.5 million and $80.6 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:

	2017			2016
	(In Millions)
Balance as of January 1	$	80.6		$	59.0
Liabilities incurred	—			—
Liabilities settled	(5.3		)	(3.2		)
Revisions in estimated cash flows	—			21.6
Accretion expense	4.2			3.2
Balance as of December 31	$	79.5		$	80.6

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, 2017 and 2016, IPL did not have any assets that are legally restricted for settling its ARO liability.

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4. FAIR VALUE

The fair value of financial assets and liabilities approximate their reported carrying amounts. The estimated fair values of IPL’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, IPL has categorized its 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 IPL’s financial instruments. IPL’s 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 IPL 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 IPL’s Consolidated Statements of Operations.

Other Financial Liabilities

As of December 31, 2017 and 2016, all of IPL’s financial assets or liabilities measured at fair value on a recurring basis were considered Level 3, based on the fair value hierarchy.

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Summary

The fair value of assets and liabilities at December 31, 2017 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, 2017		Based on quoted market prices in active markets		Other observable inputs		Unobservable inputs
	(In Thousands)
Financial assets:
Financial transmission rights	$	2,532	$	—	$	—	$	2,532
Total financial assets measured at fair value	$	2,532	$	—	$	—	$	2,532
Financial liabilities:
Other derivative liabilities	$	78	$	—	$	—	$	78
Total financial liabilities measured at fair value	$	78	$	—	$	—	$	78

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

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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, 2016	$	4,029
Unrealized gain recognized in earnings	46
Issuances	10,892
Settlements	(10,674		)
Balance at December 31, 2016	4,293
Unrealized gain recognized in earnings	23
Issuances	9,647
Settlements	(11,509		)
Balance at December 31, 2017	$	2,454

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. IPL uses the cost approach to determine the fair value of its 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, 2017 and 2016, ARO liabilities were $79.5 million and $80.6 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 IPL’s 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, 2017				December 31, 2016
	Face Value		Fair Value		Face Value		Fair Value
	(In Millions)
Fixed-rate	$	1,608.8	$	1,837.8	$	1,633.5	$	1,717.2
Variable-rate	238.0		238.0		140.0		140.0
Total indebtedness	$	1,846.8	$	2,075.8	$	1,773.5	$	1,857.2

The difference between the face value and the carrying value of this indebtedness represents the following:

• unamortized deferred financing costs of $16.5 million and $17.2 million at December 31, 2017 and 2016, respectively.

• unamortized discounts of $6.4 million and $6.5 million at December 31, 2017 and 2016, respectively.

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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:

	2017			2016		Recovery Period
	(In Thousands)
Regulatory Assets
Current:
Undercollections of rate riders	$	22,990	8,002	$	19,959	Approximately 1 year(1)
Costs being recovered through base rates	12,351			13,953		Approximately 1 year(1)
Total current regulatory assets	35,341			33,912
Long-term:
Unrecognized pension and other
postretirement benefit plan costs	205,573			218,070		Various(2)
Deferred income taxes recoverable through rates	—			51,131		Various
Deferred MISO costs	101,562			114,359		Through 2026(3)
Unamortized Petersburg Unit 4 carrying
charges and certain other costs	9,139			10,193		Through 2026(1)(4)
Unamortized reacquisition premium on debt	21,109			22,501		Over remaining life of debt
Environmental projects	40,434			30,678		Through 2050(1)(4)
Other miscellaneous	1,087			3,778		To be determined(1)(5)
Total long-term regulatory assets	378,904			450,710
Total regulatory assets	$	414,245		$	484,622
Regulatory Liabilities
Current:
Overcollections of rate riders	$	—		$	3,311	Approximately 1 year(1)
FTRs	2,532			4,393		Approximately 1 year(1)
Total current regulatory liabilities	2,532			7,704
Long-term:
ARO and accrued asset removal costs	696,973			668,787		Not Applicable
Deferred income taxes payable through rates	154,461			—		Various
Unamortized investment tax credit	320			1,507		Through 2021
Total long-term regulatory liabilities	851,754			670,294
Total regulatory liabilities	$	854,286		$	677,998

(1) Recovered (credited) per specific rate orders

(2) IPL receives a return on its discretionary funding

(3) The majority of these costs are being recovered per specific rate order; recovery for the remaining costs is probable but timing not yet determined

(4) Recovered with a current return

(5) A portion of this amount will be recovered over the next two years

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Deferred Fuel

Deferred fuel costs are a component of current regulatory assets or liabilities (which is a result of IPL charging either more or less for fuel than our actual costs to our jurisdictional customers) and are expected to be recovered through future FAC proceedings. IPL records deferred fuel in accordance with standards prescribed by the FERC. The deferred fuel adjustment is the result of variances between estimated fuel and purchased power costs in IPL’s FAC and actual fuel and purchased power costs. IPL is generally permitted to recover underestimated fuel and purchased power costs in future rates through the FAC proceedings and therefore the costs are deferred when incurred and amortized into fuel expense in the same period that IPL’s rates are adjusted to reflect these costs.

Unrecognized Pension and Postretirement Benefit Plan Costs

In accordance with ASC 715 “Compensation – Retirement Benefits” and ASC 980, IPL recognizes a regulatory asset equal to the unrecognized actuarial gains and losses and prior service costs. Pension expenses are recorded based on the benefit plan’s actuarially determined pension liability and associated level of annual expenses to be recognized. The other postretirement benefit plan’s deferred benefit cost is the excess of the other postretirement benefit liability over the amount previously recognized.

Deferred Income Taxes Recoverable/Payable Through Rates

A deferred income tax asset or liability is created from a difference in timing of income recognition between tax laws and accounting methods. As a regulated utility, IPL includes in ratemaking the impacts of current income taxes and changes in deferred income tax liabilities or assets.

The regulatory asset of $51.1 million as of December 31, 2016 represents the portion of IPL’s net deferred income tax liability that IPL believed would be recovered through future rates, without interest, based upon established regulatory practices. That asset as of December 31, 2016 was based upon a future federal income tax rate of 35% and was offset by a deferred income tax liability.

On December 22, 2017, the U.S. federal government enacted the TCJA, which includes a provision to, among other things, reduce the federal corporate income tax rate from 35% to 21%, beginning January 1, 2018. As required by GAAP, on December 31, 2017, IPL remeasured their deferred income tax assets and liabilities using the new tax rate. IPL believes that the impact of the reduction of the income tax rate on deferred income taxes will be used in future ratemaking to reduce jurisdictional retail rates. Accordingly, IPL now has a net regulatory liability of $154.5 million as of December 31, 2017.

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.”

AROand 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

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 approximately 30%. On June 1, 2016, IPALCO received equity capital contributions of $64.8 million from AES U.S.

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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.

All of the outstanding common stock of IPL is owned by IPALCO. IPL’s common stock is pledged under the 2020 IPALCO Notes and 2024 IPALCO Notes. There have been no changes in the capital stock of IPL during the three years ended December 31, 2017.

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, 2017 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, 2017 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, 2017, 2016 and 2015, 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, 2017, 2016 and 2015, preferred stock consisted of the following:

	December 31, 2017			December 31,
	Shares Outstanding	Call Price		2017		2016		2015
				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 IPL’s long-term debt:

		December 31,
Series	Due	2017			2016
		(In Thousands)
IPL first mortgage bonds:
5.40% (1)	August 2017	$	—		$	24,650
3.875% (2)	August 2021	55,000			55,000
3.875% (2)	August 2021	40,000			40,000
3.125% (2)	December 2024	40,000			40,000
6.60%	January 2034	100,000			100,000
6.05%	October 2036	158,800			158,800
6.60%	June 2037	165,000			165,000
4.875%	November 2041	140,000			140,000
4.65%	June 2043	170,000			170,000
4.50%	June 2044	130,000			130,000
4.70%	September 2045	260,000			260,000
4.05%	May 2046	350,000			350,000
Unamortized discount – net		(6,353		)	(6,477		)
Deferred financing costs		(16,168		)	(16,736		)
Total IPL first mortgage bonds		1,586,279			1,610,237
IPL unsecured debt:
Variable (3)	December 2020	30,000			30,000
Variable (3)	December 2020	60,000			60,000
Deferred financing costs		(344		)	(456		)
Total IPL unsecured debt		89,656			89,544
Total Consolidated IPL Long-term Debt		1,675,935			1,699,781
Less: Current Portion of Long-term Debt		—			24,650
Net Consolidated IPL Long-term Debt		$	1,675,935		$	1,675,131

(1) First mortgage bonds issued to the city of Petersburg, Indiana, to secure the loan of proceeds from tax-exempt bonds issued by the city. IPL repaid these first mortgage bonds on August 1, 2017.

(2) First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority.

(3) Unsecured notes issued to the Indiana Finance Authority by IPL to facilitate the loan of proceeds from various tax-exempt notes issued by the Indiana Finance Authority. The notes have a final maturity date of December 2038, but are subject to a mandatory put in December 2020.

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Debt Maturities

Maturities on long-term indebtedness subsequent to December 31, 2017, are as follows:

Year	Amount
	(In Thousands)
2018	$	—
2019	—
2020	90,000
2021	95,000
2022	—
Thereafter	1,513,800
Total	$	1,698,800

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 $1,608.8 million as of December 31, 2017. 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, 2017.

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%.

On August 1, 2017, IPL repaid $24.7 million in outstanding borrowings of 5.40% IPL first mortgage bonds that were due in August 2017.

IPL Unsecured Notes

In October 2015, IPL entered into an unsecured $91.9 million364-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

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$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.

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, 2017 and 2016, IPL had $148.0 million and $50.0 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, 2017, 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, 2017. As an alternative to the sale of all or a portion of $65 million in principal of the long-term debt mentioned above, we have the authority to issue up to $65 million of new preferred stock, all of which authority remains available under the order as of December 31, 2017. 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

IPL’s ability to borrow money or to refinance existing indebtedness and the interest rates at which IPL can borrow money or refinance existing indebtedness are affected by IPL’s credit ratings. In addition, the applicable interest rates on IPL’s Credit Agreement and other unsecured notes are dependent upon the credit ratings of IPL. Downgrades in the credit ratings of AES and/or IPALCO could result in IPL’s credit ratings being downgraded.

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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. 

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 6.125% for the calendar year 2017, 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 $1.3 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 $0.1 million. The statutory state corporate income tax rate will be 5.875% for 2018.

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 through the 2017 tax year, 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 2017 tax year is estimated to be $4.8 million. The tax benefit associated with the Internal Revenue Code Section 199 domestic production deduction for 2016 and 2015 was $5.7 million and$1.7 million, respectively. Due to the recently enacted TCJA (as described below), the 2017 tax year will be the final year for this deduction.

U.S. Tax Reform

On December 22, 2017, the U.S. federal government enacted the TCJA. The TCJA significantly changes U.S. corporate income tax law.

IPL recognized the income tax effects of the TCJA in accordance with Staff Accounting Bulletin No. 118 (“SAB 118”) which provides SEC guidance on the application of ASC 740, Income Taxes, in the reporting period in which the TCJA was signed into law. Accordingly, IPL’s financial statements reflect the income tax effects of U.S. tax reform for which the accounting is complete and provisional amounts for those impacts for which the accounting under ASC 740 is incomplete, but a reasonable estimate could be determined.

IPL has calculated its best estimate of the impact of the TCJA in its income tax provision for the year ended December 31, 2017 in accordance with its understanding of the TCJA and guidance available as of the date of this filing. The change in required deferred taxes on non-operating related temporary differences resulted in an immaterial tax benefit.

This total results from the remeasurement of certain deferred tax assets and liabilities from 35% to 21%. The most material deferred taxes to be remeasured related to property, plant and equipment. The remeasurement of deferred tax assets and liabilities related to regulated utility property of $215.5 million was recorded as a regulatory liability, which was a non-cash adjustment. Additional time is required to finalize remeasurement effects in accordance with GAAP.

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Income Tax Provision

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

	2017			2016			2015
	(In Thousands)
Charged to utility operating expenses:
Current income taxes:
Federal	$	56,512		$	50,482		$	18,661
State	12,586			12,080			5,758
Total current income taxes	69,098			62,562			24,419
Deferred income taxes:
Federal	(1,668		)	11,885			29,165
State	(354		)	215			5,019
Total deferred income taxes	(2,022		)	12,100			34,184
Net amortization of investment credit	(1,455		)	(1,501		)	(1,319		)
Total charge to utility operating expenses	65,621			73,161			57,284
Charged to other income and deductions:
Current income taxes:
Federal	(135		)	(1,009		)	(1,715		)
State	70			(16		)	(240		)
Total current income taxes	(65		)	(1,025		)	(1,955		)
Deferred income taxes:
Federal	34			552			740
State	1			13			150
Total deferred income taxes	35			565			890
Net provision to other income and deductions	(30		)	(460		)	(1,065		)
Total federal and state income tax provisions	$	65,591		$	72,701		$	56,219

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:

	2017		2016		2015
Federal statutory tax rate	35.0	%	35.0	%	35.0	%
State income tax, net of federal tax benefit	4.0	%	4.0	%	4.4	%
Amortization of investment tax credits	(0.7	)%	(0.7	)%	(0.8	)%
Depreciation flow through and amortization	(0.1	)%	(0.4	)%	(0.2	)%
Additional funds used during construction - equity	(3.1	)%	(3.2	)%	(1.9	)%
Manufacturers’ Production Deduction (Sec. 199)	(2.4	)%	(2.2	)%	(1.0	)%
Other – net	(0.2	)%	(0.8	)%	0.1	%
Effective tax rate	32.5	%	31.7	%	35.6	%

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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, 2017 and 2016, are as follows:

	2017		2016
	(In Thousands)
Deferred tax liabilities:
Relating to utility property, net	$	475,911	$	569,204
Regulatory assets recoverable through future rates	66,661		180,608
Other	6,256		11,090
Total deferred tax liabilities	548,828		760,902
Deferred tax assets:
Investment tax credit	240		927
Regulatory liabilities including ARO	278,529		272,001
Employee benefit plans	18,564		27,358
Other	6,683		11,396
Total deferred tax assets	304,016		311,682
Deferred income taxes – net	$	244,812	$	449,220

Uncertain Tax Positions

The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2017, 2016 and 2015:

	2017			2016			2015
	(In Thousands)
Unrecognized tax benefits at January 1	$	6,634		$	7,147		$	7,042
Gross increases – current period tax positions	470			724			962
Gross decreases – prior period tax positions	(2,453		)	(1,237		)	(857		)
Unrecognized tax benefits at December 31	$	4,651		$	6,634		$	7,147

The unrecognized tax benefits at December 31, 2017 represent tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, other than interest and penalties, the timing of the deductions will not affect the annual effective tax rate but would accelerate the tax payments to an earlier period.

Tax-related interest expense and income is reported as part of the provision for federal and state income taxes. Penalties, if incurred, would also be recognized as a component of tax expense. There are no interest or penalties applicable to the periods contained in this report.

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9. BENEFIT PLANS

Defined Contribution Plans

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

The Thrift Plan

Approximately 85% of IPL’s active employees are covered by the Thrift Plan, a qualified defined contribution plan. All union new hires are covered under the Thrift Plan. 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 $3.4 million, $3.1 million and $3.1 million for 2017, 2016 and 2015, respectively. 

The RSP

Approximately 15% 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 $1.8 million, $1.0 million and $0.3 million for 2017, 2016 and 2015, respectively.

Defined Benefit Plans

Approximately 78% of IPL’s active employees are covered by the qualified Defined Benefit Pension Plan; while approximately 7% 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 15% 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, 2017 was 22. 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 163 active employees and 6 retirees (including spouses) were receiving such benefits or entitled to future benefits as of January 1, 2017. The plan is unfunded. These postretirement health care benefits and the related unfunded obligation of$7.0 million and $6.8 million at December 31, 2017 and 2016, respectively, were not material to the consolidated financial statements in the periods covered by this report.

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The following table presents information relating to the Pension Plans:

	Pension benefits as of December 31,
	2017			2016
	(In Thousands)
Change in benefit obligation:
Projected benefit obligation at January 1	$	731,825		$	723,887
Service cost	7,344			7,018
Interest cost	25,305			25,815
Actuarial loss	52,451			9,718
Amendments (primarily increases in pension bands)	900			—
Settlements	(266		)	—
Benefits paid	(35,451		)	(34,613		)
Projected benefit obligation at December 31	782,108			731,825
Change in plan assets:
Fair value of plan assets at January 1	674,430			647,573
Actual return on plan assets	93,022			45,520
Employer contributions	7,212			15,950
Settlements	(266		)	—
Benefits paid	(35,451		)	(34,613		)
Fair value of plan assets at December 31	738,947			674,430
Unfunded status	$	(43,161	)	$	(57,395	)
Amounts recognized in the statement of financial position:
Noncurrent liabilities	$	(43,161	)	$	(57,395	)
Net amount recognized at end of year	$	(43,161	)	$	(57,395	)
Sources of change in regulatory assets(1):
Prior service cost arising during period	$	900		$	—
Net loss arising during period	4,101			7,690
Amortization of prior service cost	(4,240		)	(5,183		)
Amortization of loss	(13,341		)	(13,896		)
Total recognized in regulatory assets(1)	$	(12,580	)	$	(11,389	)
Amounts included in regulatory assets(1):
Net loss	$	193,807		$	203,047
Prior service cost	17,318			20,658
Total amounts included in regulatory assets	$	211,125		$	223,705

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

Information for Pension Plans with aprojectedbenefit obligation in excess of plan assets

	Pension benefits as of December 31,
	2017		2016
	(In Thousands)
Benefit obligation	$	782,108	$	731,825
Plan assets	738,947		674,430
Benefit obligation in excess of plan assets	$	43,161	$	57,395

IPL’s total benefit obligation in excess of plan assets was $43.2 million as of December 31, 2017 ($42.4 million Defined Benefit Pension Plan and $0.8 million Supplemental Retirement Plan).

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

	Pension benefits as of December 31,
	2017		2016
	(In Thousands)
Accumulated benefit obligation	$	769,678	$	720,901
Plan assets	738,947		674,430
Accumulated benefit obligation in excess of plan assets	$	30,731	$	46,471

IPL’s total accumulated benefit obligation in excess of plan assets was $30.7 million as of December 31, 2017 ($29.9 million Defined Benefit Pension Plan and $0.8 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.

The 2017 net actuarial loss of $4.1 million is comprised of two parts: (1) a $52.5 million pension liability actuarial loss primarily due to a decrease in the discount rate used to value pension liabilities; partially offset by (2) a $48.4 million pension asset actuarial gain primarily due to higher than expected return on assets. The unrecognized net loss of $193.8 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 2017, the accumulated net loss was decreased due to a combination of higher than expected return on pension assets, as well as the year 2017 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 9.91 years based on estimated demographic data as of December 31, 2017. The projected benefit obligation of $782.1 million less the fair value of assets of $738.9 million results in an unfunded status of $(43.2) million at December 31, 2017.

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	Pension benefits for years ended December 31,
	2017			2016			2015
	(In Thousands)
Components of net periodic benefit cost:
Service cost	$	7,344		$	7,018		$	8,314
Interest cost	25,305			25,815			29,638
Expected return on plan assets	(44,672		)	(43,492		)	(44,819		)
Amortization of prior service cost	4,240			5,183			4,867
Recognized actuarial loss	13,195			13,896			13,890
Recognized settlement loss	146			—			206
Total pension cost	5,558			8,420			12,096
Less: amounts capitalized	845			1,187			1,403
Amount charged to expense	$	4,713		$	7,233		$	10,693
Rates relevant to each year’s expense calculations:
Discount rate – defined benefit pension plan	4.29		%	4.42		%	4.06		%
Discount rate – supplemental retirement plan	4.00		%	4.19		%	3.82		%
Expected return on defined benefit pension plan assets	6.75		%	6.75		%	6.75		%
Expected return on supplemental retirement plan assets	6.75		%	6.75		%	6.75		%

Pension expense for the following year is determined as of the December 31measurement 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 2017, pension expense was determined using an assumed long-term rate of return on plan assets of 6.75%. As of the December 31, 2017 measurement date, IPL decreased the discount rate from 4.29% to 3.67% for the Defined Benefit Pension Plan and decreased the discount rate from 4.00% to 3.60% for the Supplemental Retirement Plan. The discount rate assumption affects the pension expense determined for 2018. In addition, IPL decreased the expected long-term rate of return on plan assets from 6.75% to 5.45% effective January 1, 2018. The expected long-term rate of return assumption affects the pension expense determined for 2018. The effect on 2018 total pension expense of a 25 basis point increase and decrease in the assumed discount rate is $(1.4) million and $1.4 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, 2017. 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 2018 plan year are $11.6 million and $4.0 million, respectively (Defined Benefit Pension Plan of $11.4 million and $4.0 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, 2017. 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

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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).

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 IPL’s 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. IPL then takes into consideration the investment manager/consultant expenses, as well as any other expenses expected to be paid out of the Plan’s trust. Finally, IPL has the Plan’s actuary perform a tolerance test of the consultant’s equilibrium expected long-term rate of return. IPL uses an expected long-term rate of return compatible with the actuary’s tolerance level.

The following table summarizes IPL’s target pension plan allocation for 2017: 

Asset Category:	Target Allocations
Equity Securities	30%
Debt Securities	70%

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	Fair Value Measurements at
	December 31, 2017
	(in thousands)
			Quoted Prices in Active Markets for Identical Assets		Significant Observable Inputs
Asset Category	Total		(Level 1)		(Level 2)		%
Short-term investments	$	115	$	115	$	—	—	%
Mutual funds:
U.S. equities	162,144		162,144		—		22	%
International equities	58,536		58,536		—		8	%
Fixed income	415,868		415,868		—		56	%
Fixed income securities:
U.S. Treasury securities	102,284		102,284		—		14	%
Total	$	738,947	$	738,947	$	—	100	%

	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	%

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Pension Funding

IPL contributed $7.2 million, $16.0 million, and $25.2 million to the Pension Plans in 2017, 2016 and 2015, 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 110%. 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 $7.3 million in 2018, which includes $1.7 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 $30.0 million in January 2018, which satisfies all funding requirements for the calendar year 2018. 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, 2017, 2016 and 2015 were $35.5 million, $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)
2018	$	40,598
2019	$	42,325
2020	$	43,657
2021	$	45,077
2022	$	46,030
2023 through 2027	$	237,296

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

IPL is subject to various federal, state, regional and local environmental protection and health and safety laws and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of hazardous materials; the emission and discharge of hazardous and other materials into the environment; and the health and safety of our employees. These laws and regulations often require a lengthy and complex process of obtaining and renewing permits and other governmental authorizations from federal, state and local agencies. Violation of these laws, regulations or permits can result in substantial fines, other sanctions, permit revocation and/or facility shutdowns. IPL cannot assure that it has been or will be at all times in full compliance with such laws, regulations and permits.

New Source Review

In October 2009, IPL received a NOV and Finding of Violation from the EPA pursuant to the CAA Section 113(a). The NOV alleges violations of the CAA at IPL’s three primarily coal-fired electric generating facilities at the time, dating back to 1986. The alleged violations primarily pertain to the PSD and nonattainment New Source Review requirements under the CAA. In addition, on October 1, 2015, IPL received a NOV from the EPA pursuant to CAA Section 113(a) alleging violations of the CAA, the Indiana SIP, and the Title V operating permit related to alleged particulate matter and opacity violations at IPL Petersburg Unit 3. Also, on February 5, 2016, the EPA issued a NOV pursuant to CAA Section 113(a) alleging violations of New Source Review and other CAA regulations, the Indiana SIP, and the Title V operating permit at Petersburg Generating

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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. At this time, IPL cannot determine whether these NOVs could have a material impact on its business, financial condition or results of operations. IPL 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 IPL would be successful in this regard. IPL has recorded a contingent liability related to these New Source Review cases 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, but does take a $5 million per occurrence deductible. 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 paid to AES Global Insurance Company and all claims are paid from a trust fund funded by and owned by AES Global Insurance Company, but controlled by the third-party administrator. IPL also has third-party insurance in which the premiums are paid directly to the third-party insurers. The cost to IPL of coverage under this program with AES Global Insurance Company was approximately $3.1 million, $3.1 million, and $2.7 million in 2017, 2016 and 2015, respectively, and is recorded in “Other operating expenses” on the accompanying Consolidated Statements of Operations. As of December 31, 2017 and 2016, IPL had prepaid approximately $1.9 million and $2.0 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 $24.9 million, $23.2 million, and $24.5 million in 2017, 2016 and 2015, respectively, and is recorded in “Other operating expenses” on the accompanying Consolidated Statements of Operations. IPL had no prepaids for coverage under this plan as of December 31, 2017 and 2016, respectively. 

AES files federal and state income tax returns which consolidate IPALCO and its subsidiaries, including IPL. Under a tax sharing agreement with IPALCO, IPL is responsible for the income taxes associated with its own taxable income and records the provision for income taxes using a separate return method. IPL had a receivable and payable balance under this agreement of $17.0 million and $1.0 million as of December 31, 2017 and 2016, respectively, which is recorded in “Prepayments and other current assets” and “Accrued income taxes” on the accompanying Consolidated Balance Sheets, respectively.

Long-term Compensation Plan

During 2017, 2016 and 2015, 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. Total deferred compensation expense recorded during 2017, 2016 and 2015 was $0.8 million, $0.9 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.

ServiceCompany

Total costs incurred by the Service Company on behalf of IPL were $34.1 million, $26.9 million and $22.6 million during 2017, 2016 and 2015, respectively. Total costs incurred by IPL on behalf of the Service Company during 2017, 2016 and 2015 were

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$10.7 million, $9.2 million and $7.5 million, respectively. IPL had a prepaid balance with the Service Company of $3.1 million and $3.4 million as of December 31, 2017 and 2016, respectively.

Other

In 2014, IPL engaged a third party vendor as part of its replacement generation construction projects. A member of the AES Board of Directors is also currently a member of the Supervisory Board of this vendor. IPL had billings from this vendor of$198.5 million and $232.0 million during 2016 and 2015, respectively. IPL had a payable balance to this vendor of $2.3 million as of December 31, 2016. This vendor continued to perform services throughout 2017 but did not bill IPL as certain milestones were not met under the terms of the contract.

Additionally, transactions with various other related parties were $2.4 million, $3.9 million and $2.4 million during 2017, 2016 and 2015, respectively. These expenses were primarily recorded in “Other operating expenses” on the accompanying Consolidated Statements of Operations.

12. BUSINESS SEGMENT INFORMATION

Operating segments are components of an enterprise for which separate financial information is available and is evaluated regularly by the chief operating decision maker in assessing performance and deciding how to allocate resources. All of IPL’s current business consists of the generation, transmission, distribution and sale of electric energy, and therefore IPL had only one reportable segment.

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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, 2017, 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, 2017. 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, 2017.

Changes in Internal Control Over Financial Reporting:

There were no changes that occurred during the quarter ended December 31, 2017 that have materially affected, or are

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

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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.

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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,
	2017		2016
Audit Fees	$	1,028,800	$	928,250
Audit Related Fees:
Fees for the audit of IPL’s employee benefit plans	60,000		63,940
Assurance services for debt offering documents	117,600		145,300
Fees for tax services	—		—
Other	17,000		17,500
Total Principal Accounting Fees and Services	$	1,223,400	$	1,154,990

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PART IV

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 – 2017, 2016 and 2015	51
Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015	52
Consolidated Balance Sheets as of December 31, 2017 and 2016	53
Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015	54
Consolidated Statements of Common Shareholders’ Equity for the years ended December 31,
2017, 2016 and 2015	55
Notes to Consolidated Financial Statements	56
Schedule I – Condensed Financial Information of Registrant	132
Schedule II – Valuation and Qualifying Accounts and Reserves	138
Indianapolis Power & Light Company and Subsidiary – Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm – 2017, 2016 and 2015	89
Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015	90
Consolidated Balance Sheets as of December 31, 2017 and 2016	91
Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015	92
Consolidated Statements of Common Shareholder’s Equity for the years ended December 31,
2017, 2016 and 2015	93
Notes to Consolidated Financial Statements	94
Schedule II – Valuation and Qualifying Accounts and Reserves	138

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(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 (Incorporated by reference to Exhibit No 4.1 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
4.2	Mortgage and Deed of Trust, dated as of May 1, 1940, between IPL and the Bank of New York Mellon Trust Company, NA, as successor in interest to American National Bank & Trust Company of Chicago, Trustee (Incorporated by reference to Exhibit No. 4.2 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
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 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
	Tenth Supplemental Indenture, dated as of October 1, 1960 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
	Eighteenth Supplemental Indenture, dated as of February 15, 1974 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
	Forty-Eighth Supplemental Indenture, dated as of January 1, 2004 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
	Fifty-Third Supplemental Indenture, dated as of October 1, 2006 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
	Fifty-Fourth Supplemental Indenture, dated as of June 1, 2007 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
	Fifty-Eighth Supplemental Indenture, dated as of August 1, 2011 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
	Fifty-Ninth Supplemental Indenture, dated as of August 1, 2011 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
	Sixtieth Supplemental Indenture, dated as of November 1, 2011 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s December 31, 2011 Form 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. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on September 28, 2015)
	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 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s December 31, 2016 Form 10-K)
4.5	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 4.1 to IPALCO’s Current Report on Form 8-K filed with the SEC on June 25, 2015)
4.6	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 4.2 to IPALCO’s Current Report on Form 8-K filed on June 25, 2015)
4.7	Indenture between IPALCO Enterprises, Inc. and U.S. Bank, National Association, as Trustee, dated August 22, 2017 for IPALCO’s 3.70% Senior Secured Notes due 2024 (Incorporated by reference to Exhibit No. 4.1 to IPALCO’s August 22, 2017 Form 8-K)

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4.8	Pledge Agreement Supplement between IPALCO Enterprises, Inc. and The Bank of New York Mellon trust Company, N.A., as Collateral Agent, dated August 22, 2017 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 August 22, 2017 Form 8-K)
10.1	Interconnection Agreement, dated April 1, 2008, between American Electric Power Service Corporation, as agent for Indiana Michigan Power Company, and IPL (Incorporated by reference to Exhibit No. 10.1 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
10.2	Interconnection Agreement, dated December 2, 1969, between IPL and Southern Indiana Gas and Electric Company as modified through Modification Number 11 (Incorporated by reference to Exhibit No. 10.2 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
10.3	Interconnection Agreement dated December 1, 1981, between IPL and Hoosier Energy Rural Electric Cooperative, Inc., as modified through Modification 6 (Incorporated by reference to Exhibit No. 10.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
10.4	Tenth Supplemental Agreement to the Interconnection Agreement between IPL and PSI Energy, Inc., dated as of June 26, 2002, amending and completely restating prior agreements (Incorporated by reference to Exhibit No. 10.4 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
10.5	$250,000,000 Revolving Credit Facilities Amended and Restated Credit Agreement by and among Indianapolis Power & Light Company, The Lenders Party Hereto, PNC Bank, National Association, as Administrative Agent, PNC Capital Markets LLC, as Sole Bookrunner and Sole Lead Arranger, 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 10.1 to IPALCO’s March 31, 2014 Form 10-Q).
10.6	Subscription Agreement by and between IPALCO and CDP Infrastructure Fund GP, a wholly owned subsidiary of La Caisse de dépȏt 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’s Shareholders’ Agreement by and among AES U.S. Investments, Inc., IPALCO Enterprises, Inc. and CDPQ 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)
10.13	The AES Corporation 2003 Long Term Compensation Plan, as amended and restated, dated April 23, 2015 (Incorporated by reference to Exhibit 99.1 of The AES Corporation’s Form 8-K filed on April 23, 2015)
10.14	The AES Corporation Performance Incentive Plan, as amended and restated on April 23, 2015 (Incorporated by reference to Exhibit 99.2 of The AES Corporation’s Form 8-K filed on April 23, 2015)
10.15	The AES Corporation Severance Plan, as amended and restated on August 4, 2017 (Incorporated by reference to Exhibit 10.1 of The AES Corporation’s Form 10-Q for the quarter ended June 30, 2017)

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10.16	The AES Corporation Restoration Supplemental Retirement Plan, as amended and restated, dated December 29, 2008 (Incorporated by reference to Exhibit 10.15 of The AES Corporation’s Form 10-K for the year ended December 31, 2008)
10.17	Amendment to The AES Corporation Restoration Supplemental Retirement Plan, dated December 9, 2011 (Incorporated by reference to Exhibit 10.17A of The AES Corporation’s Form 10-K for the year ended December 31, 2012)
10.18	Form of AES Performance Stock Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan (Incorporated by reference to Exhibit 10.13 of The AES Corporation’s Form 10-K for the year ended December 31, 2015)
10.19	Form of AES Restricted Stock Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan (Incorporated by reference to Exhibit 10.14 of The AES Corporation’s Form 10-K for the year ended December 31, 2015)
10.20	Form of AES Performance Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan (Incorporated by reference to Exhibit 10.15 of The AES Corporation’s Form 10-K for the year ended December 31, 2015)
10.21	Form of AES Nonqualified Stock Option Award Agreement under The AES Corporation 2003 Long Term Compensation Plan (Incorporated by reference to Exhibit 10.4 of The AES Corporation’s Form 10-Q for the quarter ended June 30, 2015)
10.22	Form of AES Performance Cash Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan (Incorporated by reference to Exhibit 10.17 of The AES Corporation’s Form 10-K for the year ended December 31, 2015)
21	Subsidiaries of IPALCO Enterprises, Inc. (Incorporated by reference to Exhibit 21 of IPALCO’s December 31, 2016 Form 10-K)
31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
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)

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(c) Financial Statement Schedules

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

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF REGISTRANT

IPALCO ENTERPRISES, INC.
Schedule I – Condensed Financial Information of Registrant
Unconsolidated Balance Sheets
(In Thousands)
	December 31,
	2017			2016
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	16,383		$	7,370
Prepayments and other current assets	9			10,076
Total current assets	16,392			17,446
OTHER ASSETS:
Investment in subsidiaries	1,369,100			1,360,235
Other investments	3,585			3,247
Deferred tax asset – long term	22			101
Total other assets	1,372,707			1,363,583
TOTAL	$	1,389,099		$	1,381,029
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common shareholders' equity:
Paid in capital	$	597,467		$	596,810
Accumulated deficit	(25,191		)	(25,627		)
Total common shareholders' equity	572,276			571,183
Long-term debt	801,603			799,709
Total capitalization	1,373,879			1,370,892
CURRENT LIABILITIES:
Accounts payable and accrued expenses	1,102			359
Accrued income taxes	2,304			—
Accrued interest	11,813			9,776
Total current liabilities	15,219			10,135
DEFERRED CREDITS AND OTHER LONG-TERM LIABILITIES	1			2
TOTAL	$	1,389,099		$	1,381,029

See notes to Schedule I.

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IPALCO ENTERPRISES, INC.
Schedule I – Condensed Financial Information of Registrant
Unconsolidated Statements of Operations
(In Thousands)
	2017			2016			2015
Equity in earnings of subsidiaries	$	133,725		$	153,232		$	98,708
Loss on early extinguishment of debt	(8,875		)	—			(21,956		)
Income tax benefit – net	16,495			11,483			24,650
Interest on long-term debt	(33,787		)	(33,973		)	(41,659		)
Amortization of redemption premiums and expense on debt	(2,003		)	(1,947		)	(2,459		)
Other – net	25			(948		)	(973		)
NET INCOME	$	105,580		$	127,847		$	56,311

See notes to Schedule I.

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IPALCO ENTERPRISES, INC.
Schedule I – Condensed Financial Information of Registrant
Unconsolidated Statements of Cash Flows
(In Thousands)
	2017			2016			2015
CASH FLOWS FROM OPERATIONS:
Net income	$	105,580		$	127,847		$	56,311
Adjustments to reconcile net income to net cash
provided by operating activities:
Equity in earnings of subsidiaries	(133,725		)	(153,232		)	(98,708		)
Cash dividends received from subsidiary companies	132,516			136,466			106,997
Amortization of deferred financing costs and debt premium	2,003			1,947			2,459
Deferred income taxes – net	78			22,601			(2,190		)
Charges related to early extinguishment of debt	8,875			—			21,956
Change in certain assets and liabilities:
Income taxes receivable or payable	5,377			(5,425		)	2,465
Accounts payable and accrued expenses	203			(800		)	(391		)
Other – net	370			145			639
Net cash provided by operating activities	121,277			129,549			89,538
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in subsidiaries	—			(212,997		)	(214,366		)
Net cash used in investing activities	—			(212,997		)	(214,366		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Long-term borrowings, net of discount	404,633			—			404,712
Retirement of long-term debt and early tender premium	(408,152		)	—			(420,329		)
Dividends on common stock	(105,144		)	(122,959		)	(69,487		)
Issuance of common stock	—			134,276			214,366
Equity contributions from shareholders	—			78,738			—
Other	(3,601		)	(11		)	(5,445		)
Net cash (used in) provided by financing activities	(112,264		)	90,044			123,817
Net change in cash and cash equivalents	9,013			6,596			(1,011		)
Cash and cash equivalents at beginning of period	7,370			774			1,785
Cash and cash equivalents at end of period	$	16,383		$	7,370		$	774

See notes to Schedule I.

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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, 2015	$	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
Net income			105,580			105,580
Distributions to shareholders			(105,144		)	(105,144		)
Other	657					657
Balance at December 31, 2017	$	597,467	$	(25,191	)	$	572,276

See notes to Schedule I.

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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. 

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 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.

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3. DEBT

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

			December 31,
Series	Due		2017			2016
			(In Thousands)
Long-Term Debt
5.00% Senior Secured Notes	May 2018		$	—		$	400,000
3.45% Senior Secured Notes	July 2020	—	405,000			405,000
3.70% Senior Secured Notes	September 2024	—	405,000			—
Unamortized discount – net			(534		)	(273		)
Deferred financing costs – net			(7,863		)	(5,018		)
Total Long-term Debt			801,603			799,709
Less: Current Portion of Long-term Debt			—			—
Net Long-term Debt			$	801,603		$	799,709

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.

IPALCO 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.

In August 2017, IPALCO completed the sale of the $405 million 2024 IPALCO Notes pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended. The 2024 IPALCO Notes were issued pursuant to an Indenture dated August 22, 2017, by and between IPALCO and U.S. Bank, National Association, as trustee. The 2024 IPALCO Notes were priced to the public at 99.901% of the principal amount. Net proceeds to IPALCO were approximately $399.3 million after deducting underwriting costs and estimated offering expenses. These costs are being amortized to the maturity date using the effective interest method. We used the net proceeds from this offering, together with cash on hand, to redeem the $400 million 2018 IPALCO Notes on September 21, 2017, and to pay certain related fees, expenses and make-whole premiums. A loss on early extinguishment of debt of $8.9 million for the 2018 IPALCO Notes is included as a separate line item in the accompanying Unconsolidated Statements of Operations.

The 2020 IPALCO Notes and 2024 IPALCO Notes are secured by IPALCO’s pledge of all of the outstanding common stock of IPL. The lien on the pledged shares is shared equally and ratably with IPALCO’s existing senior secured notes. IPALCO also agreed to register the 2024 IPALCO Notes under the Securities Act by filing an exchange offer registration statement or, under specified circumstances, a shelf registration statement with the SEC pursuant to a Registration Rights Agreement that IPALCO entered into with Morgan Stanley & Co. LLC and PNC Capital Markets LLC, as representatives of the initial purchasers of the

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2024 IPALCO Notes, dated August 22, 2017. IPALCO filed its registration statement on Form S-4 with respect to the 2024 IPALCO Notes with the SEC on November 13, 2017, and this registration statement was declared effective on December 5, 2017. The exchange offer was completed on January 12, 2018.

SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Valuation and Qualifying Accounts and Reserves
For the Years Ended December 31, 2017, 2016 and 2015
(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, 2017
Accumulated Provisions Deducted from
Assets – Doubtful Accounts	$	2,365	$	5,854	$	—	$	5,389	$	2,830
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

INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY
Valuation and Qualifying Accounts and Reserves
For the Years Ended December 31, 2017, 2016 and 2015
(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, 2017
Accumulated Provisions Deducted from
Assets – Doubtful Accounts	$	2,365	$	5,854	$	—	$	5,389	$	2,830
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

ITEM 16. FORM 10-K SUMMARY

None.

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SIGNATURES

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

IPALCO ENTERPRISES, INC.

(Registrant)

Date:    February 26, 2018/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 26, 2018
Kenneth J. Zagzebski
/s/ Thomas M. O’Flynn	Director and Chairman	February 26, 2018
Thomas M. O’Flynn
/s/ Paul L. Freedman	Director	February 26, 2018
Paul L. Freedman
/s/ Barry J. Bentley	Director	February 26, 2018
Barry J. Bentley
/s/ Vincent W. Mathis	Director	February 26, 2018
Vincent W. Mathis
/s/ Mark E. Miller	Director	February 26, 2018
Mark E. Miller
/s/ Julian Nebreda	Director	February 26, 2018
Julian Nebreda
/s/ Gustavo Pimenta	Director	February 26, 2018
Gustavo Pimenta
/s/ Frédéric Lesage	Director	February 26, 2018
Frédéric Lesage
/s/ Renaud Faucher	Director	February 26, 2018
Renaud Faucher
/s/ Craig L. Jackson	Chief Financial Officer and Director (Principal Financial Officer)	February 26, 2018
Craig L. Jackson
/s/ Kurt A. Tornquist	Controller (Principal Accounting Officer)	February 26, 2018
Kurt A. Tornquist

________________________________________________________________________________________________________________________________

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.

139