Ipalco Enterprises 10K 2018 Annual report

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, 2018

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-8644

IPALCO ENTERPRISES, INC.

(Exact name of registrant as specified in its charter)



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

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

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

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

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

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

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

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 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	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

At February 26, 2019, 108,907,318 shares of IPALCO Enterprises, Inc. common stock, no par value, were outstanding, of which 89,685,177 shares were owned by AES U.S. Investments, Inc. and 19,222,141 shares were owned by CDP Infrastructure Fund GP, a wholly-owned subsidiary of La Caisse de dépôt et placement du Québec.

DOCUMENTS INCORPORATED BY REFERENCE

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

IPALCO ENTERPRISES, INC.

Annual Report on Form 10-K

For Fiscal Year Ended December 31, 2018

Table of Contents



Item No.		Page No.

	DEFINED TERMS	4

	PART I
1.	Business	7
1A.	Risk Factors	20
1B.	Unresolved Staff Comments	33
2.	Properties	33
3.	Legal Proceedings	33
4.	Mine Safety Disclosures	33
PART II
5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities	33
6.	Selected Financial Data	35
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
7A.	Quantitative and Qualitative Disclosures About Market Risk	52
8.	Financial Statements and Supplementary Data	54
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	132
9A.	Controls and Procedures	132
9B.	Other Information	133

PART III
10.	Directors, Executive Officers and Corporate Governance	133
11.	Executive Compensation	133
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	133
13.	Certain Relationships and Related Transactions, and Director Independence	133
14.	Principal Accounting Fees and Services	134

PART IV
15.	Exhibits, Financial Statements and Financial Statement Schedules	136
16.	Form 10-K Summary	144

SIGNATURES		145



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 Base Rate Order	The order issued in March 2016 by the IURC authorizing IPL to, among other things, 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
2018 Base Rate Order	The order issued in October 2018 by the IURC authorizing IPL to, among other things, increase its basic rates and charges by $43.9 million annually
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 million IPL Revolving Credit Facilities Amended and Restated 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
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
ISO	Independent System Operator
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
NO_x	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
PM2.5	Fine particulate matter or particulate matter with an aerodynamic diameter less than or equal to a nominal 2.5 micrometers
PSD	Prevention of Significant Deterioration
Purchasers	Citibank, N.A. and its affiliate, CRC Funding, LLC
Receivables Sale Agreement	Second Amended and Restated Receivables Sale Agreement, dated as of June 25, 2009, as amended, as described herein
RF	ReliabilityFirst
RSP	AES Retirement Savings Plan
RTO	Regional Transmission Organization
SEA	Senate Enrolled Act
SEC	Securities and Exchange Commission
Securities Act	Securities Act of 1933, as Amended
Service Company	AES US Services, LLC
SIP	State Implementation Plan
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
Term Loan	$65 million IPALCO Term Loan Facility Credit Agreement, dated as of October 31, 2018
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
VEBA	Voluntary Employees' Beneficiary Association

PART I

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

We encourage investors, the media, our customers and others interested in the Company to review the information we post at https://www.iplpower.com.

FORWARD‑LOOKING STATEMENTS

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

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


▪	impacts of weather on retail sales;


▪	growth in our service territory and changes in retail demand and demographic patterns;


▪	weather-related damage to our electrical system;


▪	commodity and other input costs;


▪	performance of our suppliers;


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


▪	regulatory actions and outcomes, including, but not limited to, the review and approval of our 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, and liabilities related to, current and future environmental laws and requirements;


▪	interest rates and the use of interest rate hedges, 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 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;


▪	cyber-attacks and information security breaches;


▪	catastrophic events such as fires, explosions, 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, our continued ability to recover 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;


▪	product development, technology changes, and changes in prices of products and technologies; and


▪	the risks and other factors discussed in this report and other IPALCO filings with the SEC.

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

ITEM 1. BUSINESS

OVERVIEW

IPALCO is a holding company incorporated under the laws of the state of Indiana. Our principal subsidiary is IPL, a regulated electric utility operating in the state of Indiana. Substantially all of our business consists of the generation, transmission, distribution and sale of electric energy conducted through IPL. Our business segments are “utility” and “all other.” 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 more than 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 950,000. 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 2018.

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.

EMPLOYEES

As of January 31, 2019, IPL had 1,213 employees of whom 1,137 were full time. Of the total employees, 826 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 2018, the IBEW physical unit ratified a three-year agreement with us that expires on December 6, 2021. 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, 2019, neither IPALCO nor any of its majority-owned subsidiaries other than IPL had any employees.

SERVICE COMPANY

The Service Company provides services including operations, accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the 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, uses natural gas and fuel oil to power combustion turbines, In addition, IPL operates a 20 MW battery energy storage unit at this location, which provides frequency response. The third station, Eagle Valley, is a newly constructed 671 MW CCGT natural gas plant. IPL took operational control and commenced commercial operations of this CCGT plant in April 2018. 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 3,667 MW and net summer design capacity is 3,552 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
	Eagle Valley	1	671	671	Morgan County, Indiana
	Georgetown	2	200	158	Marion County, Indiana
	Total	9	1,897	1,792
Oil	Petersburg	3	8	8	Pike County, Indiana
	Harding Street	3	53	43	Marion County, Indiana
	Total	6	61	51
Grand Total		19	3,667	3,552

Net electrical generation during 2018 at our Petersburg, Harding Street, Eagle Valley and Georgetown plants accounted for approximately 68.8%, 10.4%, 20.0% and 0.8%, respectively, of our total net generation. Even though the capacity of our Harding Street plant far exceeds that of the Eagle Valley plant, we expect the generation at Eagle Valley to continue to far exceed that of Harding Street due to the relatively cheaper cost to produce electricity at Eagle Valley.

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 4,961 circuit miles of underground primary and secondary cables and 6,110 circuit miles of

overhead primary and secondary wire. Underground street lighting facilities include 773 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.

SEASONALITY

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 and the number of retail customers we have, as well as DSM energy efficiency programs implemented by IPL. For the ten years ending in 2018, IPL’s retail kWh sales have decreased at a compound annual rate of 0.8%. Conversely, the number of our retail customers grew at a compound annual rate of 0.6% during that same period. Going forward, we expect flat or modest retail kWh sales growth annually, which will continue to be negatively impacted by our DSM programs. Please see Note 2, “Regulatory Matters – DSM” to the Financial Statements for more details. IPL’s electricity sales for 2014 through 2018 are set forth in the table of statistical information included at the end of this section.

Weather and Weather-Related Damage in our Service Area

Extreme high and low temperatures in our service area have a significant impact on revenues as many of our retail customers use electricity to power air conditioners, electric furnaces and heat pumps. The impact is partially mitigated by our declining block rate structure, which generally provides for residential and commercial customers to be charged a lower per kWh rate at higher consumption levels. Therefore, as volumes increase, the weighted average price per kWh decreases. The effect is generally more significant with high temperatures than with low temperatures as many of our customers use gas heat. In addition, before the 2018 Base Rate Order was implemented on December 5, 2018, IPL had the opportunity to share 50% of wholesale margins above a stated benchmark, so extreme temperatures generally provided additional income by selling power on the wholesale market (see below). However, beginning December 5, 2018, 100% of wholesale margins are passed to customers through a rider.

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 $2.8 million, $2.1 million and $3.9 million in 2018, 2017 and 2016, respectively. In our 2016 and 2018 Base Rate Orders, we received approval for a storm damage restoration reserve account that allows us to defer major storm costs over a benchmark that meet certain criteria considered to be severe, for recovery in a future basic rate proceeding. Because IPL's basic rates and charges include an annual amount for recovery for such severe storm costs, if actual severe storm costs are below that level, IPL will record a regulatory liability for the shortfall to be passed to customers in a future basic rate proceeding. Conversely, if IPL's major storm costs are above the level in basic rates, IPL will defer the excess for future recovery.

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 and such costs are being recovered per specific rate orders. The unamortized balance of total MISO costs deferred as regulatory assets was $95.5 million and $115.3 million as of December 31, 2018 and 2017, 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 with the FERC or IURC.

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

REGULATION

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, (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, (iii) a rider to reflect changes in ongoing MISO costs, referred to as the Regional Transmission Organization Adjustment, (iv) a rider to reflect changes in net capacity sales above and below an established annual benchmark of $11.3 million, referred to as the Capacity Adjustment, (v) a rider for passing through to customers wholesale sales margins above and below an established annual benchmark of $16.3 million (beginning December 5, 2018), referred to as the Off-System Sales Margin Adjustment, and (vi) cost recovery, lost margin recoveries and performance incentives from our DSM programs. Each of these 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 and IPL's other rider proceedings all 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 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. 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 Note 10, “Commitments and Contingencies - Environmental Loss Contingencies - New Source Review and other CAA NOVs” to the Financial Statements for additional details), 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 hazardous substances or for other environmental damage. Our costs of complying with current and future environmental and health and safety laws, and our liabilities arising from past or future releases of, or exposure to, hazardous substances may adversely affect our business, results of operations, financial condition and cash flows. A discussion of the legislative and regulatory initiatives most likely to affect us follows.

MATS

In April 2012, the EPA’s rule to establish maximum achievable control technology standards for hazardous air pollutants regulated under the CAA emitted from coal and oil-fired electric utilities, known as “MATS”, became effective. IPL management developed 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. In June 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. In December 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 in the Federal Register in April 2016. Several lawsuits were filed appealing that finding in the D.C. Circuit. In April 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. On February 7, 2019, the EPA published a proposed rule finding that it is not “appropriate and necessary” to regulate hazardous air pollutant emissions from coal- and oil-fired electric generating units (EGUs), but that EPA would not remove the source category from the CAA Section 112(c) list of source categories and would not change the MATS requirements. Further rulemakings and/or proceedings are possible; however, in the meantime, MATS remains in effect. We currently cannot predict the outcome of the regulatory or judicial process, 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. 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 in October 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 ash ponds, including location restrictions, design and operating criteria, groundwater monitoring, corrective action and closure requirements and post-closure care. On December 16, 2016, President Obama signed into law the Water Infrastructure Improvements for the Nation Act ("WIIN Act"), which includes provisions to implement the CCR rule through a state permitting program, or if the state chooses not to participate, a possible federal permit program.

The EPA has indicated that they will implement a phased approach to amending the CCR rule. In July 2018, the EPA published final CCR Rule Amendments (Phase One, Part One) in the Federal Register. As a result of EPA statements published during this rulemaking, IPL Petersburg is expected to incur additional operational costs and pond closure costs. In August 2018, the U.S. Court of Appeals for the District of Columbia issued a decision in certain CCR litigation matters, which may result in additional revisions to the CCR Rule. In October 2018, some environmental groups filed a petition for review challenging EPA's final CCR rule amendments (Phase One, Part One).

IPL was not able to meet certain location restrictions set in the CCR Rule for ash ponds at the Harding Street and Eagle Valley generating stations by the deadline of October 17, 2018. As a result, the ash ponds, which are currently being used for managing non-CCR wastewaters will be required to close by October 31, 2020 in accordance with the revised deadline established in the final CCR rule amendment (Phase One, Part One).

The existing ash ponds at Petersburg did not meet certain structural stability requirements set forth in the CCR rule. As such, IPL was ultimately required to cease use of all existing ash ponds at Petersburg, and did so as of November 11, 2018. To comply with the CCR rule, IPL installed a dry bottom ash handling system at a cost of approximately $46 million, which was completed in the third quarter of 2017.

The CCR rule, current or proposed amendments to the CCR rule, the results of groundwater monitoring data or the outcome of CCR-related litigation could have a material impact on our business, financial condition and results of operations.

Environmental Wastewater Requirements

NPDES permits regulate specific industrial wastewater and storm water discharges to the waters of Indiana under Section 402 of the CWA. IDEM issued NPDES permit renewals to the IPL Petersburg and Harding Street generating stations, which became effective in October 2012 and set new water quality-based effluent discharge limits as well as monitoring and other requirements designed to protect human and aquatic life. IPL developed and implemented a wastewater compliance plan to meet the new limits.

In November 2015, the EPA published its final ELG rule to reduce toxic pollutants discharged into waterways by power plants. The wastewater treatment technologies installed and operated for compliance with the requirements of the October 2012 NPDES permit described above and the dry bottom ash handling system installed for compliance with the CCR Rule at Petersburg meet the requirements of the final ELG rule.

In June 2015, the EPA and the U.S. Army Corps of Engineers published a rule defining federal jurisdiction over waters of the U.S., known as the "Waters of the U.S." rule. 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. However, on February 6, 2018, EPA published a final rule to delay the original effective date of the 2015 “Waters of the U.S.” rule to February 6, 2020, which allows the EPA to create a new rule in the interim period without the 2015 rule taking effect. In connection with this effort to create a new rule, in July 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 U.S.” that existed prior to the 2015 rule. On July 12, 2018, the agencies finalized a supplemental notice of proposed rulemaking clarifying that the proposal is to permanently repeal the 2015 rule, and on February 14, 2019 the EPA and the U.S. Army Corps of Engineers published a proposed rule to revise the definition of the "Waters of the U.S." We are still reviewing this proposed rule, and it is too early to determine whether it might have a material impact on our business, financial condition and results of operations. In addition, while we cannot predict the outcome of the judicial or regulatory process, if the “Waters of the U.S.” rule is ultimately implemented in its 2015 form or a substantially similar form and

survives the legal challenges, it could have a material impact on our business, financial condition and 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. 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.

Climate Change Legislation and Regulation

One byproduct of burning coal and other fossil fuels is the emission of GHGs, including CO₂. We face certain risks related to existing and potential international, federal, state, regional and local GHG legislation and regulations, including risks related to increased capital expenditures or other compliance costs which could have a material adverse effect on our results of operations, financial condition and cash flows.

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


▪	The geographic scope of legislation and/or regulation (e.g., international, federal, regional, state), which entities are subject to the legislation and/or regulation (e.g., electricity generators, load-serving entities, electricity deliverers, etc.), the enactment date of the legislation and/or regulation and the compliance deadlines set forth therein;


▪	The level of reductions of GHGs being sought by the regulation and/or legislation (e.g., 10%, 20%, 50%, etc.) and the year selected as a baseline for determining the amount or percentage of mandated GHG reduction (e.g., 10% reduction from 1990 emission levels, 20% reduction from 2000 emission levels, etc.);


▪	The legislative and/or regulatory structure (e.g., a GHG cap-and-trade program, a carbon tax, GHG emission limits, etc.);


▪	In any cap-and-trade program, the mechanism used to determine the price of emission allowances or offsets to be auctioned by designated governmental authorities or representatives;


▪	The price of offsets and emission allowances in the secondary market, including any price floors or price caps on the costs of offsets and emission allowances;


▪	The operation of and emissions from regulated units;

▪

The permissibility of using offsets to meet reduction requirements and the requirements of such offsets (e.g., type of offset projects allowed, the amount of offsets that can be used for compliance purposes, any geographic limitations regarding the origin or location of creditable offset projects), as well as the methods required to determine whether the offsets have resulted in reductions in GHG emissions and that those reductions are permanent (i.e., the verification method);


▪	Whether the use of proceeds of any auction conducted by responsible governmental authorities is reinvested in developing new energy technologies, is used to offset any cost impact on certain energy consumers or is used to address issues unrelated to power;


▪	How the price of electricity is determined, including whether the price includes any costs resulting from any new climate change legislation and the potential to transfer compliance costs pursuant to legislation, market or contract, to other parties;


▪	Any impact on fuel demand and volatility that may affect the market clearing price for power;


▪	The effects of any legislation or regulation on the operation of power generation facilities that may in turn affect reliability;


▪	The availability and cost of carbon control technology;


▪	Whether 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 the “Tailoring Rule.” The regulations were implemented pursuant to two CAA programs: the Title V Operating Permit program and the program requiring a permit if undergoing certain new construction or major modifications, the PSD program. Obligations relating to Title V permits include recordkeeping and monitoring requirements. Sources subject to PSD can be required to implement BACT. In June 2014, the U.S. Supreme Court ruled that the EPA had exceeded its statutory authority in issuing the Tailoring Rule by regulating under the PSD program sources based solely on their GHG emissions. However, the U.S. Supreme Court also held that the EPA could impose GHG BACT requirements for sources already required to implement PSD for certain other pollutants when GHG increases exceed a “significance” threshold. Currently, the EPA uses a 75,000 ton per year GHG threshold to determine if increases are significant. On October 3, 2016, the EPA published a proposed rule that would set a GHG significant emissions increase threshold of 75,000 tons per year, that, if exceeded as part of a major modification that otherwise triggered PSD, would require GHG BACT. Therefore, if future modifications to IPL’s sources require PSD review for other pollutants and GHG increases exceed the EPA’s GHG significance thresholds, such modifications may also trigger GHG BACT requirements. The EPA has issued guidance on what BACT entails for the control of GHG and individual states are now required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis.

On October 23, 2015, the EPA finalized CO₂ emission rules for existing power plants under CAA Section 111(d) (called the CPP). 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. 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. On December 6, 2018, EPA released a pre-publication version of proposed revisions to the final NSPS for new, modified and reconstructed coal-fired electric utility steam generating units. The EPA proposed that the Best System of Emissions Reduction (BSER) for these units is highly efficient generation that would be equivalent to supercritical steam conditions for larger units and sub-critical steam conditions for smaller units, and not partial carbon capture and sequestration (CCS), which had been the BSER for these units in the 2015 final NSPS. The EPA did not include revisions for natural-gas combined cycle or simple cycle units in the December 6, 2018 proposal.

In addition, on February 9, 2016, the U.S. Supreme Court issued orders staying implementation of the CPP pending resolution of challenges to the rule. Challenges to the CPP are being held in abeyance at this time. 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.

On August 31, 2018, the EPA published in the Federal Register proposed Emission Guidelines for Greenhouse Gas Emissions from Existing Electric Utility Generating Units, known as the Affordable Clean Energy (ACE) Rule. In addition, the EPA proposed associated revisions to implementing regulations and the New Source Review program. The proposed ACE Rule would replace the CPP and proposes to determine that heat rate improvement measures are the BSER for existing coal-fired electric generating units.

Due to the uncertainty of the CPP or a potential replacement rule such as ACE, it is too early to determine the potential impact, but any rule could have a material impact on our business, financial condition and results of operations. We would seek recovery of any resulting capital expenditures; however, there is no guarantee we would be successful in this regard.

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. We do not have any 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, and financial condition, but it could be material.

Unit Retirements and Replacement Generation

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. 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 are reflected in the basic rates and charges from IPL's 2018 Base Rate Order effective on December 5, 2018. The CCGT was completed in April 2018, and the refueling project was completed in December 2015. The total cost of these projects was approximately $638 million ($597 million for the Eagle Valley CCGT and $41 million for the refueling project).

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, and the costs of this conversion are now reflected in the basic rates and charges from IPL's 2018 Base Rate Order.

New Source Review and Other CAA NOVs

See Note 10, “Commitments and Contingencies - Environmental Loss Contingencies - New Source Review and other CAA NOVs” to the Financial Statements for additional details.

CSAPR

Following implementation and legal challenges of the EPA’s March 2005 federal CAIR, the federal CSAPR became effective in January 2015 requiring the further reduction of SO₂and NO_xemissions from power plants in 28 states, including Indiana, which contribute to ozone and/or fine particle pollution in other states. In October 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 NO_x 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 NO_x ozone season emission budgets for electric generating units within these states and that implement these budgets through modifications to the CSAPR NO_x 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. With respect to these new standards and requirements, there has not been a significant impact to date, however at this time we cannot predict what the impact will be 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, NO_x, ozone and SO₂, which result from fossil-fuel 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. In October 2015, the EPA published a final rule lowering the NAAQS for ozone to 70 parts per billion from 75 parts per billion. The 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.

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 NO_x emissions. In November 2017, the EPA published a final rule denying the petition. In December 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 NO_x emissions.

In March 2018, the state of New York submitted a petition to the EPA pursuant to Section 126 of the CAA requesting new limitations on NO_x emissions from dozens of upwind generating stations, including IPL's Petersburg, Harding Street, and Eagle Valley stations on the basis that they are contributing significantly to New York’s ability to meet the 2008 ozone NAAQS. On May 11, 2018, EPA published an extension of their deadline to respond from May 13, 2018 to November 9, 2018 and has not yet taken action. On February 7, 2019, New York notified EPA of its intent to sue EPA for failing to respond to New York's petition. If this petition is granted, our units could be subject to additional requirements, which could be material. We would seek recovery of any resulting capital expenditures; however, there is no guarantee we would be successful.

Additionally, on November 16, 2016, the state of Maryland submitted a petition to the EPA pursuant to Section 126 of the CAA requesting new limitations on NO_x emissions from 36 upwind generating units, including IPL's 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 October 5, 2018, the EPA published a denial of Maryland’s petition. The States of Maryland and Delaware, in addition to environmental groups, have a filed petition with the U.S. Court of Appeals for the District of Columbia challenging the EPA’s denial. If the Section 126 petition is ultimately granted, our Petersburg generating station units 2 and 3 could be subject to additional requirements, which could be material. We would seek recovery of any resulting capital expenditures; however, there is no guarantee we would be successful.

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

NO_x and SO₂. In 2010, a one-hour primary NAAQS became effective for NO_x and a new one-hour SO₂ primary NAAQS also became effective. In 2013, the 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.

In 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. Improvements to the existing FGD systems at Petersburg station were required to meet the emission limits imposed by the rule. The rule has not impacted IPL’s Eagle Valley or Harding Street generating stations as these facilities ceased coal combustion in advance of the compliance date. On August 15, 2018, EPA proposed to approve Indiana's State Implementation Plan addressing attainment of the 2010 SO₂ standard for certain locations including those of IPL's Harding Street and Petersburg Generating Stations. 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 is 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 stations. Under the CWA, cooling water intake structures are required to reflect the BTA for minimizing adverse environmental impact. In 2014, the EPA's final standards became effective to protect fish and other aquatic organisms drawn into cooling water systems at large power plants and other facilities. 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, certain facilities 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. It is possible this process, which includes permitting and public input, could result in the need to install closed-cycle cooling systems (closed-cycle cooling towers) or other technology. Finally, the standards require that new units added to an existing facility must reduce both impingement and entrainment that achieves one of two alternatives under national BTA standards. IPL’s NPDES permits will be updated with the requirements of this rule, including any source-specific requirements arising from the evaluation process described above. As a result, it is not yet possible to predict the total impacts of this final rule, 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.

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. See “Capital Expenditures” discussion in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Capital Requirements" for additional details regarding our environmental capital projects. 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 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.

ENERGY SUPPLY

Approximately 69% of the total kWh we generated in 2018 was from coal as compared to approximately 88% and 84% in 2017 and 2016, respectively. Our existing coal contracts provide for all of our current projected requirements in 2019 and approximately 60% in total for the three-year period ending December 31, 2021. We have long-term coal contracts with four suppliers. Approximately 46% of our existing coal under contract for the three-year period ending December 31, 2021 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 the Petersburg, Harding Street and Eagle Valley stations. However, the Harding Street station unit 7 conversion from coal to natural gas was completed in the second quarter of 2016 and the coal-fired units at Eagle Valley were retired in April 2016, and, as a result, we no longer burn coal at Harding Street or 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 2018. 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), our CCGT at Eagle Valley 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. IPL has established physical natural gas hedges for approximately 50% of the expected consumption at Eagle Valley during the 2019 winter period. We do not maintain a natural gas inventory; however, our experience has been that natural gas is readily available at liquid supply points on interstate pipelines, and we expect this availability to continue in the future. Fuel oil is used for start-up and flame stabilization in coal-fired generating units, as primary fuel in two older combustion turbines, and as an alternate fuel in two other combustion turbines.

As a result of the completion of the CCGT at the Eagle Valley Station in April 2018, the Harding Street Station refueling projects and the retirement of coal-fired units at Eagle Valley in the second quarter of 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. Currently, approximately two-thirds of the total kWh we generate is from coal and approximately one-third is 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 2019, of which 95 MW was in operation as of December 31, 2018. 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 2018 came from the following sources: 57.0% from IPL-owned coal-fired steam generation, 25.9% from IPL-owned natural gas-fired units, and 17.1% 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,
	2018		2017		2016		2015		2014
Revenues (In Thousands):
Residential	$	599,037	$	551,022	$	541,174	$	488,582	$	493,620
Small commercial and industrial	219,175		205,473		208,928		192,232		193,213
Large commercial and industrial	568,408		561,194		557,491		526,461		527,719
Public lighting	9,845		9,906		10,023		10,823		10,811
Retail electric revenues	1,396,465		1,327,595		1,317,616		1,218,098		1,225,363
Wholesale	38,789		8,574		15,804		19,307		83,208
Miscellaneous	15,251		13,419		14,010		12,994		13,103
Total revenues	$	1,450,505	$	1,349,588	$	1,347,430	$	1,250,399	$	1,321,674
kWh Sales (In Millions):
Residential	5,335		4,915		5,152		5,062		5,269
Small commercial and industrial	1,907		1,800		1,850		1,837		1,888
Large commercial and industrial	6,558		6,448		6,620		6,757		6,778
Public lighting	51		53		57		53		59
Sales – retail customers	13,851		13,216		13,679		13,709		13,994
Wholesale	1,241		268		507		689		2,397
Total kWh sold	15,092		13,484		14,186		14,398		16,391
Retail Customers at End of Year:
Residential	443,184		439,741		435,622		431,182		427,866
Small commercial and industrial	49,239		48,684		48,204		47,919		47,534
Large commercial and industrial	4,680		4,705		4,763		4,737		4,749
Public lighting	976		959		955		953		945
Total retail customers	498,079		494,089		489,544		484,791		481,094

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.

ITEM 1A. RISK FACTORS

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

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

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


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


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


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


•	shortages of or delays in obtaining equipment;


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


•	labor disputes or work stoppages by employees;


•	accidents and injuries;


•	reliability of our suppliers;


•	inability to comply with regulatory or permit requirements;


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


•	construction delays and cost overruns;


•	disruptions in the delivery of electricity;


•	the availability of qualified personnel;


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


•	operator error; and


•	catastrophic events.

The above risks could result in unscheduled plant outages, unanticipated operation and/or maintenance expenses, increased capital expenditures, and/or increased fuel and purchased power costs, any of which could have a material adverse effect on our results of operations, financial condition and cash flows. These risks are partially mitigated by IPL's ability to generally pass fuel and purchased power costs through to customers through the FAC. If unexpected plant outages occur frequently and/or for extended periods of time, however, this could result in adverse regulatory action.

Additionally, as a result of the above risks and other potential hazards associated with the power generation industry, we may from time to time become exposed to significant liabilities for which we may not have adequate insurance coverage. Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. 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 adversely affect our financial results or 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.

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.

We may be negatively affected by a lack of growth or a decline in the number of customers or in customer usage.

Customer growth and customer usage are affected by a number of factors outside our control, such as energy efficiency and DSM measures, population changes, job and income growth, housing starts, new business formation and the overall level of economic activity. A lack of growth, or a decline, in the number of customers in our service territory or in customer demand for electricity could have a material adverse effect on our results of operations, financial condition and cash flows and may cause us to fail to fully realize anticipated benefits from investments and expenditures.

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 and a substantial amount of our coal supply comes from one supplier.

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 and charges. 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 69% of the energy we produced in 2018 was generated by coal as compared to approximately 88% and 84% in 2017 and 2016, respectively. While we have approximately 60% in total of our current coal requirements for the three-year period ending December 31, 2021 under long-term contracts as of the date of this report, the balance is yet to be purchased and will be purchased under a combination of long-term contracts, short-term contracts and on the spot market. Prices can be highly volatile in both the short-term market and on the spot market. The coal market has experienced significant price volatility in the last several years. We are now in a global market for coal in which our domestic price is increasingly affected by international supply disruptions and demand balance. Coal exports from the U.S. have increased significantly at times in recent years. In addition, domestic developments such as government-imposed direct costs and permitting issues that affect mining costs and supply availability, and the variable demand of retail customer load and the performance of our generation fleet have an impact on our fuel procurement operations. In addition, pricing provisions in some of our coal contracts with terms of one year or more allow for price changes under certain circumstances.

Because of our substantial dependence on coal to meet customer demand for electricity, our business and operations could be materially adversely affected by unexpected price volatility in the coal market, price increases pursuant to the provisions of certain of our long-term coal contracts, and the continued regulatory and political scrutiny of coal. As discussed below, regulators, politicians and non-governmental organizations have expressed concern about GHG emissions and are taking actions which, in addition to the potential physical risk associated with climate change, could have a material adverse impact on our results of operations, financial condition and cash flows. Our dependence on coal also means that the output of our coal-fired generation units can be greatly affected by the costs of other fuels combusted by generation facilities that compete with our coal-fired generation units. Natural gas prices over the last several years have been relatively low and some gas-fired generators that previously were primarily used during periods of peak and intermediate electric demand have run even during periods of relatively low demand. This has caused many coal-fired generators, including ours, to run fewer hours during these periods of base-load demand.

In addition, substantially all of our coal supply is currently mined in the state of Indiana, and all of our coal supply is currently mined by unaffiliated suppliers or third parties. Our current goal is to carry a 25-50 day system supply of coal to offset unforeseen occurrences such as equipment breakdowns and transportation or mine delays. IPL has long-term contracts with four suppliers, with about 46% of our existing coal under contract for the three-year period ending December 31, 2021 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.

Concerns about GHG emissions and the potential risks associated with climate change have led to increased regulation and other actions that could impact our business.

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. In 2018, 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.

There currently is no U.S. federal legislation imposing mandatory GHG emission reductions (including for CO2) that affects our electric power generation facilities. However, in 2015, the EPA promulgated a rule establishing NSPS for CO₂ emissions for newly constructed and modified/reconstructed fossil-fueled EUSGUs larger than 25 MW. Also in 2015, EPA promulgated the CPP, which requires interim reductions by preexisting EUSGUs beginning in 2022, with full compliance achieved by 2030. These actions have been challenged in Court and the current Administration has announced plans to significantly amend or rescind the rules. In 2016, the EPA adopted regulations pertaining to GHG emissions that require new and existing sources of GHG emissions to potentially obtain new source review permits from the EPA prior to construction or modification, but only if such sources also must obtain a new source review permit for increases in other regulated pollutants.

For further discussion of the regulation of GHG emissions in the U.S., including the U.S. Supreme Court's issued order staying implementation of the CPP, and the EPA's proposal to rescind the CPP, see "Item 1. Business -Environmental Matters - Climate Change Legislation and Regulation."

In December 2015, the Parties to the United Nations Framework Convention on Climate Change convened for the 21st Conference of the Parties and the resulting Paris Agreement established a long-term goal of keeping the increase in global average temperature well below 2°C above pre-industrial levels. We anticipate that the Paris Agreement will continue the trend toward efforts to de-carbonize the global economy and to further limit GHG emissions.

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. Our cost of compliance could be substantial. Although we would seek recovery of costs associated with new climate change or GHG regulations, our inability to fully or timely recover such costs could have a material adverse effect on our results of operations, financial condition and cash flows. Additionally, concerns over GHG emissions and their effect on the environment have led, and could lead further, to reduced demand for coal-fired power, which could have a material adverse effect on our results of operations, financial condition and cash flows.

Furthermore, according to the Intergovernmental Panel on Climate Change, physical risks from climate change could include, but are not limited to, increased runoff and earlier spring peak discharge in many glacier and snow-fed rivers, warming of lakes and rivers, an increase in sea level, changes and variability in precipitation and in the intensity and frequency of extreme weather events. Physical impacts may have the potential to significantly affect our business and operations. For example, extreme weather events could result in increased downtime and operation and maintenance costs at our electric power generation facilities and our support facilities. Variations in weather conditions, primarily temperature and humidity, would also be expected to affect the energy needs of customers. A decrease in energy consumption could decrease our revenues. In addition, while revenues would be expected to increase if the energy consumption of customers increased, such increase could prompt the need for additional investment in generation capacity. Changes in the temperature of lakes and rivers and changes in precipitation that result in drought could adversely affect the operations of our fossil-fuel fired electric power generation facilities. If any of the foregoing risks materialize, costs may increase or revenues may decrease and there could be a material adverse effect on our results of operations, financial condition and cash flows.

If any of the foregoing risks materialize, costs may increase or revenues may decrease and there could be a material adverse effect on our business and on our consolidated results of operations, financial condition, cash

flows and reputation. 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, rules 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, rules and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of regulated materials, including CCR; 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. Such laws, rules and regulations tend to become stricter over time, and we could also become subject to additional environmental laws, rules and regulations and other requirements in the future. Environmental laws, rules and regulations also generally require us to comply with inspections and obtain and comply with a wide variety of environmental licenses, permits, and other governmental authorizations. These laws and regulations often require a lengthy and complex process of obtaining and renewing licenses, permits and other governmental authorizations from federal, state and local agencies. If we are not able to timely comply with inspections and obtain, maintain or comply with all environmental laws, rules and regulations, and all licenses, permits, 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, rules, 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. 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 strictly, jointly and severally liable for human exposure to 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, rules and regulations or other environmental requirements. We cannot assure that we will be successful in defending against any claim of noncompliance. Any actual or alleged violation of environmental laws, rules, regulations and other requirements also may require us to expend significant resources to defend against any such alleged violations and expose us to unexpected costs. 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 Note 10, “Commitments and Contingencies - Environmental Loss Contingencies - New Source Review and other CAA NOVs” to the Financial Statements. These NOVs could also result in fines, which could be material. IPL retired four coal-fired units at Eagle Valley in April 2016, as described in “Item 1. Business - Environmental Matters - Unit Retirements and Replacement Generation.” The primarily coal-fired 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.

In addition, we are subject to potentially significant remediation expenses, enforcement initiatives, private party lawsuits and reputational risk associated with CCR. CCR, which consists of bottom ash, fly ash, and air pollution control wastes generated at our current and former coal-fired generation plant sites, is currently handled and/or has been handled in the past in the following ways: placement in on-site CCR ponds; disposal and beneficial use in on-site and off-site permitted, engineered landfills; use in various beneficial use applications, including encapsulated uses and structural fill; and use in permitted off-site mine reclamation. CCR currently remains on-site at several of our facilities, including in CCR ponds. The U.S. EPA's final CCR rule, which became effective in October 2015 and is currently subject to litigation and undergoing revisions by EPA, regulates CCR as nonhazardous solid waste and establishes national minimum criteria for existing and new CCR landfills, impoundments and ponds, including location restrictions, design and operating criteria, groundwater monitoring, corrective action and closure requirements and post-closure care. On December 16, 2016, President Obama signed the WIIN Act into law, which includes provisions to implement the CCR rule through a state permitting program, or if the state chooses not to participate, a possible federal permit program. The primary enforcement mechanisms for the CCR rule could be actions commenced by U.S. EPA, or states and private lawsuits. Compliance with the CCR rule; amendments to the CCR rule; or other federal, state, or foreign rules or programs addressing CCR may require us to incur substantial costs. In addition, we may face CCR-related lawsuits that may expose us to unexpected potential costs or liabilities.

Furthermore, CCR-related litigation may also expose us to unexpected costs. In addition, CCR and its production at our facilities, have been the subject of interest from environmental non-governmental organizations and the media. Any of the foregoing could have a material adverse effect on our business, financial condition, results of operations, reputation and prospects.

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 certain severe storm damage costs, if we are unable to fully recover such costs in a timely manner, it could have a material adverse effect on our results of operations, financial condition and cash flows.

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

We are a member of MISO, a FERC-regulated regional transmission organization. MISO serves the electrical transmission needs of a 15-state area including much of the Mid-U.S. and Canada and maintains functional operational control over our electric transmission facilities, as well as that of the other utility members of MISO. We retain control over our distribution facilities. As a result of membership in MISO and its operational control, our continued ability to import power, when necessary, and export power to the wholesale market has been, and may continue to be, impacted. We offer our generation and bid our load into this market on a day-ahead basis and settle differences in real time. Given the nature of MISO’s policies regarding use of transmission facilities, and its administration of the energy and ancillary services markets, it is difficult to predict near-term operational impacts. We cannot assure MISO’s reliable operation of the regional transmission system, or the impact of its operation of the energy and ancillary services markets.

The rules governing the various regional power markets may also change from time to time which could affect our costs and revenues and have a material adverse effect on our results of operations, financial condition and cash flows. We may 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 - Regulation – 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, financial condition and prospects, the overall supply and demand in the credit markets, our credit ratings, credit capacity, the cost of financing, the financial condition, performance and prospects of other companies in our industry or with similar financial circumstances 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.

Our transmission and distribution system is subject to operational 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, equipment or process failure, catastrophic events, such as fires and/or explosions, facility outages, labor disputes, accidents or injuries, operator error, or inoperability of key infrastructure internal or external to us and events occurring on third party systems that interconnect to and affect our system. The failure of our transmission and distribution system to fully operate and 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. Also, as a result of the above risks and other potential risks and hazards associated with transmission and distribution operations, we may from time to time become exposed to significant liabilities for which we may not have adequate insurance coverage. 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. Otherwise, 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. Further, any increased costs or adverse changes in the insurance markets may cause delays or inability in maintaining insurance coverage on terms similar to those presently available to us or at all. A successful claim for which we are not fully insured could have an adverse impact on our results of operations, financial condition and cash flows.

Current and future conditions in the economy may adversely affect our customers, suppliers and other counterparties, which may adversely affect our results of operations, financial condition and cash flows.

Our business, results of operations, financial condition and cash flows have been and will continue to be affected by general economic conditions. Slowing economic growth, credit market conditions, fluctuating consumer and business confidence, fluctuating commodity prices, and other challenges 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 or result in their declaring bankruptcy or similar insolvency-like proceedings. 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, 2018, we had on a consolidated basis $2,649.1 million of indebtedness and total common shareholders’ equity of $573.3 million. IPL had $1,713.8 million of first mortgage bonds outstanding as of December 31, 2018, which are secured by the pledge of substantially all of the assets of IPL under the terms of IPL’s mortgage and deed of trust. This level of indebtedness and related security could have important consequences, including the following:


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


•	requiring us to dedicate a substantial portion of our cash flow from operations to make payments on our indebtedness, thereby reducing the availability of our cash flow to fund other corporate purposes;


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


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

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

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

Economic conditions relating to the asset performance and interest rates of the Pension Plans could materially and adversely impact our results of operations, financial condition and cash flows.

Pension costs are based upon a number of actuarial assumptions, including an expected long-term rate of return on pension plan assets, level of employer contributions, the expected life span of pension plan beneficiaries and the discount rate used to determine the present value of future pension obligations. Any of these assumptions could prove to be wrong, resulting in a shortfall of our Pension Plans’ assets compared to pension obligations under the Pension Plans. Further, the performance of the capital markets affects the values of the assets that are held in trust to satisfy future obligations under the Pension Plans. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. A decline in the market value of the Pension Plans’ assets will increase the funding requirements under the Pension Plans if the actual asset returns do not recover these declines in value in the foreseeable future. Future pension funding requirements, and the timing of funding payments, may also be subject to changes in legislation. We are responsible for funding any shortfall of our Pension Plans’ assets compared to obligations under the Pension Plans, and a significant increase in our pension liabilities could materially and adversely impact our results of operations, financial condition, and cash flows. We are subject to the Pension Protection Act of 2006, which requires underfunded pension plans to improve their funding ratios within prescribed intervals based on the level of their underfunding. As a result, our required contributions to these plans, at times, have increased and may increase in the future. In addition, our pension and postemployment benefit plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the discounted liabilities increase benefit expense and funding requirements. Further, changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase the funding requirements for the obligations related to the pension and other postemployment benefit plans. Declines in market values and

increased funding requirements could have a material adverse effect on our results of operations, financial condition and cash flows. Please see Note 9, “Benefit Plans” to the Financial Statements included in this Form 10-K for further discussion.

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

We enter into transactions with and rely on many counterparties in connection with our business, including for the purchase and delivery of inventory, including fuel and equipment components, for our capital improvements and additions and to provide professional services, such as actuarial calculations, payroll processing and various consulting services. If any of these counterparties fails to perform its obligations to us or becomes unavailable, our business plans may be materially disrupted, we may be forced to discontinue or delay certain operations if a cost-effective alternative is not readily available or we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices and cause delays. Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than the relief provided by these mitigation provisions. Any of the foregoing could result in regulatory actions, cost overruns, delays or other losses, any of which (or a combination of which) could have a material adverse effect on our results of operations, financial condition and cash flows.

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

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

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

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

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

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

As an electric utility, we are subject to extensive regulation at both the federal and state level. For example, at the federal level, we are regulated by the FERC and the NERC and, at the state level, we are regulated by the IURC. The regulatory power of the IURC over IPL is both comprehensive and typical of the traditional form of regulation generally imposed by state public utility commissions. We face the risk of unexpected or adverse regulatory action. Regulatory discretion is reasonably broad in Indiana. We are subject to regulation by the IURC as to our services and facilities, the valuation of property, the construction, purchase, or lease of electric generating facilities, the classification of accounts, rates of depreciation, the increase or decrease in retail rates and charges, the issuance of securities and 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, (iii) a rider to reflect changes in ongoing MISO costs, referred to as the Regional Transmission Organization Adjustment, (iv) a rider to reflect changes in net capacity sales above and below an established annual benchmark of $11.3 million, referred to as the Capacity Adjustment, (v) a rider for passing through to customers wholesale sales margins above and below an established annual benchmark of $16.3 million (beginning December 5, 2018), referred to as the Off-System Sales Margin Adjustment, and (vi) cost recovery, lost margin recoveries and performance incentives from our DSM programs. Each of these 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, and IPL's other rider proceedings all 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 those stated above. 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, and we have been named as a defendant in asbestos litigation. The continued presence of asbestos and other regulated substances at these facilities could result in additional litigation being brought against us, which could have a material adverse effect on our results of operations, financial condition and cash flows. Please see Note 2, “Regulatory Matters” and Note 10, “Commitments and Contingencies” to the Financial Statements for a summary of significant regulatory matters and legal proceedings involving us.

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

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

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

We are subject to collective bargaining agreements with employees who are members of a union. Approximately 68% 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 cyber-security 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 cyber-security 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 network and system monitoring, identification and deployment of secure technologies, and certain other measures to comply with mandatory regulatory reliability standards. Pursuant to NERC requirements, we have a robust cyber-security 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 cyber-security training for our employees and perform exercises designed to raise employee awareness of cyber risks on a regular basis. To date, cyber-attacks on our business and operations have not had a material impact on our operations or financial results. 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.

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 in 2017 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 and finalized, 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 $1,713.8 million at December 31, 2018. In addition, IPALCO has outstanding $875.0 million of debt obligations which are secured by its pledge of all of the outstanding common stock of IPL.

ITEM 3. LEGAL PROCEEDINGS

In the normal course of business, we are subject to various lawsuits, actions, claims, and other proceedings. We are also from time to time involved in other reviews, investigations and proceedings by governmental and regulatory agencies regarding our business, certain of which may result in adverse judgments, settlements, fines, penalties, injunctions or other relief. We have accrued in our Financial Statements for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. We believe the amounts provided in our Financial Statements, as prescribed by GAAP, for these matters are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters (including those matters noted below), and to comply with applicable laws and regulations will not exceed the amounts reflected in our Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided for in our Financial Statements, cannot be reasonably determined, but could be material. Please see “Item 1. Business – Environmental Matters” herein, Note 2, “Regulatory Matters” and Note 10, “Commitments and Contingencies” to the Financial Statements for a summary of significant legal proceedings involving us.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

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

As of February 26, 2019, 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, 2018, 2017 and 2016, we paid dividends to our shareholders totaling $130.2 million, $105.1 million and $123.0 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, 2018 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 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, 2018 and as of the filing of this report, IPL was in compliance with all covenants and no event of default existed.

IPALCO is also restricted in its ability to pay dividends if it is in default under the terms of its Term Loan, which could happen if IPALCO fails to comply with certain covenants. These covenants, among other things, require IPALCO to maintain a ratio of total debt to total capitalization not in excess of 0.67 to 1. As of December 31, 2018 and as of the filing of this report, IPALCO 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, 2018, these requirements would not materially restrict IPL’s ability to issue additional preferred stock or first mortgage bonds in the ordinary course of prudent business operations.

ITEM 6. SELECTED FINANCIAL DATA

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



	Years Ended December 31,
	2018		2017		2016		2015		2014
	(In Thousands)
Statement of Operations Data:
Revenues	$	1,450,505	$	1,349,588	$	1,347,430	$	1,250,399	$	1,321,674
Operating income	$	236,358	$	239,198	$	261,829	$	204,483	$	233,517
Allowance for funds used during construction	$	33,803	$	48,100	$	51,006	$	28,111	$	12,344
Earnings from operations before income tax	$	147,474	$	157,744	$	192,270	$	91,090	$	126,013
Net income	$	134,025	$	108,793	$	131,060	$	59,524	$	77,968
Balance Sheet Data (end of period):
Total assets	$	4,862,053	$	4,740,561	$	4,702,281	$	4,217,169	$	3,652,522
Long-term debt (less current maturities)	$	2,649,064	$	2,477,538	$	2,474,840	$	2,153,276	$	1,935,717
Common shareholders’ equity	$	573,266	$	572,276	$	571,183	$	352,933	$	151,271
Cumulative preferred stock of subsidiary	$	59,784	$	59,784	$	59,784	$	59,784	$	59,784
Other Data:
Capital expenditures⁽¹⁾	$	235,764	$	228,861	$	607,716	$	686,064	$	381,626

(1) Capital expenditures includes $11.4 million, $10.6 million, $15.5 million, $13.2 million and $0 of payments for financed capital expenditures in

2018, 2017, 2016, 2015 and 2014, respectively.

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

The following discussion and analysis should be read in conjunction with our Financial Statements and the notes thereto. The following discussion contains forward-looking statements. Our actual results may differ materially from the results suggested by these forward-looking statements. Please see “Forward-Looking Statements” and “Item 1A. Risk Factors.” For a list of certain abbreviations or acronyms in this discussion, see “Defined Terms” at the beginning of this Form 10-K.

EXECUTIVE SUMMARY

Compared with the prior year, the results for the year ended December 31, 2018 reflect lower earnings from operations before income tax of $10.3 million, or 7%, primarily due to factors including, but not limited to:


•	higher maintenance expense due to the timing and duration of plant outages; and


•	lower allowance for equity funds used during construction as a result of decreased construction activity.

These were partially offset by:


•	increased retail margins due to favorable weather in our service territory; and


•	increased wholesale margins due to the commencement of commercial operations of the newly constructed CCGT plant at Eagle Valley in April 2018.

OVERVIEW OF 2018 RESULTS AND STRATEGIC PERFORMANCE

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, and the local economy; (ii) our progress on performance improvement and growth strategies designed to maintain high standards in several operating areas (including safety, customer satisfaction, 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.”

Operational Excellence

Our objective is to optimize IPL’s performance in the U.S. utility industry by focusing on the following areas: safety, operations (reliability and customer satisfaction), financial and enterprise-wide performance (efficiency and cost savings, talent management/people, capital allocation/sustainability and corporate social responsibility). We set and measure these objectives carefully, balancing them in a way and to a degree necessary to ensure a 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. 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 category, as measured by J.D. Power in their 2018 Electric Utility Residential Customer Satisfaction Study. IPL was also named a 2018 Utility Customer Champion by Cogent Reports in their 2018 Utility Trusted Brand and Customer Engagement: Residential Study (out of 132 utility brands surveyed). We believe these favorable ratings reflect our competitive rates, strong reliability, corporate citizenship, and focus on excellence in customer service.

Our performance in production reliability was consistent with our target in 2018. Both our planned and unplanned outage rates associated with our generation plants in 2018 were consistent with outage rates that we experienced in 2017 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 2018; however, System Average Interruption Frequency Index (“SAIFI”) and the System Average Interruption Duration Index (“SAIDI”) were unfavorable to target in 2018. In 2017, IPL ranked at or within top decile nationally in both SAIDI and CAIDI reliability performance. In addition, IPL had the best CAIDI reliability performance excluding major events in 2017 as compared to the four Indiana investor-owned utilities and the second best SAIDI and SAIFI performance.

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.

Revenues

2018 versus 2017

Revenues increased in 2018 from the prior year by $100.9 million, which resulted from the following changes (dollars in thousands):



	2018		2017		Change		Percentage Change
Revenues:
Retail Revenues	$	1,396,465	$	1,327,595	$	68,870	5.2	%
Wholesale Revenues	38,789		8,574		30,215		352.4	%
Miscellaneous Revenues	15,251		13,419		1,832		13.7	%
Total Revenues	$	1,450,505	$	1,349,588	$	100,917	7.5	%
Heating Degree Days⁽¹⁾:
Actual	5,417		4,555		862		18.9	%
30-year Average	5,367		5,322
Cooling Degree Days⁽¹⁾:
Actual	1,625		1,133		492		43.4	%
30-year Average	1,066		1,113

⁽¹⁾Heating and cooling degree-days are a measure of the relative heating or cooling required for a home or business. The heating degrees in a day are calculated as the degrees that the average actual daily temperature is below 65 degrees Fahrenheit. For example, if the average temperature on March 20th was 40 degrees Fahrenheit, the heating degrees for that day would be the 25 degree difference between 65 degrees and 40 degrees. Similarly, cooling degree days in a day are calculated as the degrees that the average actual daily temperature is above 65 degrees Fahrenheit.

Retail Revenues

The increase in retail revenues of $68.9 million was primarily due to a 5% increase in the volume of kWh sold ($41.8 million) and a net increase in the weighted average price per kWh sold ($27.1 million) as follows (in millions):



Volume:
Increase in the volume of kWh sold was primarily due to favorable weather in our service territory during 2018 versus the comparable period (as demonstrated by the 19% increase in heating degree days and 43% increase in cooling degree days, as shown above)	$	41.8
Price:
Increase in environmental rate adjustment mechanism revenues mostly due to the timing of environmental projects (the majority of the increases in environmental revenues are offset by increased operating expenses)	31.8
Increase in DSM program rate adjustment mechanism revenues mostly due to timing of DSM program costs (the majority of the increases in DSM revenues are offset by increased operating expenses)	24.5
Increase in fuel revenues	8.0
Decrease due to the deferral of revenue as a regulatory liability to adjust for the impacts of the TCJA on customer rates and charges for service in 2018	(23.8		)
Decrease in MISO, Capacity and Off System Sales Margin rider revenues	(1.7		)
Unfavorable block rate and other retail rate variances, primarily attributable to our declining block rate structure, which generally provides for residential and commercial customers to be charged a lower per kWh rate at higher consumption levels. Therefore, as volumes increase, the weighted average price per kWh decreases. These unfavorable variances were partially offset by new basic rates and charges that were effective on December 5, 2018 as a result of implementing the 2018 Base Rate Order.	(11.7		)
Net increase in the weighted average price of retail kWh sold	$	27.1

Net increase in retail revenues	$	68.9

Wholesale Revenues

The increase in wholesale revenues of $30.2 million was primarily due to an increase in the quantity of kWh sold primarily due to increased generation as a result of the commencement of commercial operations of the newly constructed CCGT plant at Eagle Valley in April 2018. We sold 1,241.4 million kWh in the wholesale market during 2018 compared to only 268.1 million kWh during 2017. 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. For most of 2018 and 2017, 50% of IPL's annual wholesale margins above (or below) an established benchmark of $6.3 million were shared with customers through the Off System Sales Margin rider (in accordance with the 2016 Base Rate Order). Effective on December 5, 2018 with the implementation of the 2018 Base Rate Order, 100% of annual wholesale margins earned above (or below) the benchmark of $16.3 million shall be passed back (or charged) to customers through the Off System Sales Margin rider.

2017 versus 2016

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
Revenues:
Retail Revenues	$	1,327,595	$	1,317,616	$	9,979		0.8	%
Wholesale Revenues	8,574		15,804		(7,230		)	(45.7	)%
Miscellaneous Revenues	13,419		14,010		(591		)	(4.2	)%
Total 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

Retail Revenues

The increase in retail revenues of $10.0 million was primarily due to the following (in millions):



Volume:
Decrease in the volume of kWh sold was primarily due to unfavorable weather in our service territory during 2017 versus the comparable period (as demonstrated by the 4% decrease in heating degree days and 22% decrease in cooling degree days, as shown above)	$	(23.9	)
Price:
Increase in MISO, Capacity and Off System Sales Margin rider revenues	19.0
Increase in fuel revenues	7.2
Increase in environmental rate adjustment mechanism revenues	3.0
Decrease in DSM program rate adjustment mechanism revenues	(6.2		)
The impact of implementing the 2016 Base Rate Order in April 2016 and favorable block rate and other retail rate variances, primarily attributable 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.	14.7
Net increase in the weighted average price of retail kWh sold	37.7
Other:
One-time impact in the prior period of recognizing, in IPL's unbilled revenue calculation, the increase in IPL's basic rates and charges relating to revenues that were previously charged through IPL's environmental cost recovery rate adjustment mechanism, or rider. While billed through a rider, such revenues relating to environmental cost recovery were not includable in our unbilled calculation.	(3.8		)

Net increase in retail revenues	$	10.0

Wholesale Revenues

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. In 2017 and for most of 2016, 50% of IPL’s wholesale margins above and below an established annual benchmark of $6.3 million were shared with our retail customers through a rate rider, as authorized in the 2016 Base Rate Order.

Cost of Revenues

2018 versus 2017

The following table illustrates our changes in Cost of revenues from 2017 to 2018 (in thousands):



	Years Ended
	December 31,
	2018		2017		$ Change			% Change
Cost of revenues:
Fuel	$	331,701	$	281,542	$	50,159		17.8	%
Power purchased	164,542		189,847		(25,305		)	(13.3	)%
Total cost of revenues	$	496,243	$	471,389	$	24,854		5.3	%

The increase in fuel costs of $50.2 million was primarily due to (i) a $63.7 million increase in the quantity of fuel consumed versus the comparable period, primarily due to increased generation as a result of the commencement of commercial operations of the newly constructed CCGT plant at Eagle Valley in April 2018 and (ii) a $1.6 million increase due to the higher price of coal we consumed versus the comparable period; partially offset by (iii) a $11.3 million decrease from deferred fuel costs and (iv) a $4.1 million decrease due to the lower price of natural gas we consumed versus the comparable period. We are generally permitted to recover underestimated fuel and purchased power costs to serve our retail customers in future rates through quarterly FAC proceedings. These variances are deferred when incurred and amortized into expense in the same period that our rates are adjusted to reflect these variances.

The decrease in purchased power costs of $25.3 million was primarily due to (i) a 26% decrease in the volume of power purchased during the period ($40.5 million); partially offset by (ii) a $19.1 million increase in the market price of purchased power. The volume of power purchased each period is primarily influenced by retail demand, generating unit capacity and outages, and the fact that at times it is less expensive to buy power in the market than to produce it. The primary driver for the $40.5 million volume decrease is the commenced commercial operations of the CCGT plant at Eagle Valley in April 2018 (as discussed above), which is generally called upon by MISO whenever it is available due to its relatively low cost to produce electricity. The market price of purchased power is influenced primarily by changes in the market price of delivered fuel (primarily natural gas), the supply of and demand for electricity, and the time of day during which power is purchased. In addition, capacity expense (including deferrals) decreased by $4.0 million in the comparable periods primarily due to the CCGT plant at Eagle Valley commencing commercial operations in 2018.

2017 versus 2016

The following table illustrates our changes in Cost of revenues from 2016 to 2017 (in thousands):



	Years Ended
	December 31,
	2017		2016		$ Change		% Change
Cost of revenues:
Fuel	$	281,542	$	276,171	$	5,371	1.9	%
Power purchased	189,847		170,466		19,381		11.4	%
Total cost of revenues	$	471,389	$	446,637	$	24,752	5.5	%

The increase in fuel costs of $5.4 million was primarily due to (i) a $32.2 million increase from 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 basic rates and charges 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.

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).

Operating Expenses

2018 versus 2017

The following table illustrates our changes in Operating expenses from 2017 to 2018 (in thousands):



	Years Ended
	December 31,
	2018		2017		$ Change		% Change
Operating expenses:
Operation and maintenance	$	431,515	$	385,876	$	45,639	11.8	%
Depreciation and amortization	232,332		208,451		23,881		11.5	%
Taxes other than income taxes	53,952		44,644		9,308		20.8	%
Other operating expenses	105		30		75		250.0	%
Total operating expenses	$	717,904	$	639,001	$	78,903	12.3	%

The increase in Operation and maintenance expense of $45.6 million was primarily due to the following:


•	increase in DSM program costs of $21.5 million mostly as a result of increased amortization of previously deferred costs driven by the implementation of new rates beginning in July 2018 and differences in spending patterns (these program costs are recoverable through customer rates and are offset by an increase in DSM revenues);

•

increase in maintenance expense of $20.7 million primarily due to the timing and duration of outages during these respective periods (including a 63-day scheduled outage at our 535 MW Petersburg Generating Station Unit 2 that occurred during the first half of 2018 and an extended outage at our 535 MW Petersburg Generating Station Unit 3 that began in September of 2018; partially offset by outages in the prior period);


•	increase in deferred environmental project expenses of $11.8 million due to differences between the amount of recoverable expenses incurred in the period and the inclusion of such expenses in billing rates through IPL's environmental rider (these project expenses are recoverable through customer rates and are offset by an increase in environmental revenues); and

•

increase in MISO non-purchased power costs (primarily transmission related expenses) of $7.5 million. 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.

These increases were partially offset by:


•	decrease in salaries and other compensation costs of $14.3 million primarily due to the impact of restructuring activities initiated in the fourth quarter of 2017, including a $6.9 million decrease in severance expense.

The increase in Depreciation and amortization expense of $23.9 million was primarily related to the impact of additional assets placed in service.

The increase in Taxes other than income taxes of $9.3 million was primarily due to higher tax expense for real estate and personal property taxes of $8.1 million as a result of (i) an increase in the assessed property tax value, (ii) prior period true-up adjustments and (iii) an increase in property tax rates.

2017 versus 2016

The following table illustrates our changes in Operating expenses from 2016 to 2017 (in thousands):



	Years Ended
	December 31,
	2017		2016		$ Change			% Change
Operating expenses:
Operation and maintenance	$	385,876	$	375,113	$	10,763		2.9	%
Depreciation and amortization	208,451		218,449		(9,998		)	(4.6	)%
Taxes other than income taxes	44,644		45,326		(682		)	(1.5	)%
Other operating expenses	30		76		(46		)	(60.5	)%
Total operating expenses	$	639,001	$	638,964	$	37		—	%

The increase in Operations and maintenance expense of $10.8 million was primarily due to the following:


•	increase in MISO non-purchased power costs (primarily transmission related expenses) of $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 following the 2016 Base Rate Order; and


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

These increases were partially offset by:

•

decrease in DSM program costs of $7.4 million due to (i) a $3.6 million decrease in program costs, primarily the result of timing differences in spending patterns, and (ii) a $3.7 million decrease from DSM deferrals in 2016 that were recorded in “Revenues” on our Consolidated Statements of Operations that beginning in 2017 were recorded in “Operating Expenses” (these program costs are recoverable through customer rates and are offset by a decrease in DSM revenues); and


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

The decrease in Depreciation and amortization expense of $10.0 million was primarily due to an $11.0 million decrease due to changes in regulatory deferrals and amortization related to environmental projects.

Other Income / (Expense), Net

2018 versus 2017

The following table illustrates our changes in Other income / (expense), net from 2017 to 2018 (in thousands):



	Years Ended
	December 31,
	2018			2017			$ Change			% Change
Other income/(expense), net
Allowance for equity funds used during construction	$	8,477		$	25,798		$	(17,321	)	(67.1	)%
Interest expense	(95,509		)	(101,130		)	5,621			(5.6	)%
Loss on early extinguishment of debt	—			(8,875		)	8,875			(100.0	)%
Other income / (expense), net	(1,852		)	2,753			(4,605		)	(167.3	)%
Total other income/(expense), net	$	(88,884	)	$	(81,454	)	$	(7,430	)	9.1	%

The $7.4 million decrease in total Other income / (expense), net was primarily due to the $17.3 million decrease in allowance for equity funds used during construction due to decreased construction activity (primarily the Eagle Valley CCGT, which commenced commercial operations in April 2018). In addition, the $4.6 million decrease in Other income/(expense), net was primarily due to an increase in defined benefit plan costs of $2.7 million (mostly due to a lower return on plan assets). These were partially offset by a loss on early extinguishment of debt of $8.9 million in 2017, which was due to the redemption of $400 million 2018 IPALCO Notes during the third quarter of 2017. Additionally, interest expense decreased $5.6 million primarily due to a $3.0 million increase in the allowance for borrowed funds used during construction on the CCGT plant at Eagle Valley that was placed into service in April 2018 and lower interest on long-term debt of $2.2 million.

2017 versus 2016

The following table illustrates our changes in Other income/(expense), net from 2016 to 2017 (in thousands):



	Years Ended
	December 31,
	2017			2016			$ Change			% Change
Other income/(expense), net
Allowance for equity funds used during construction	$	25,798		$	27,140		$	(1,342	)	(4.9	)%
Interest expense	(101,130		)	(94,602		)	(6,528		)	6.9	%
Loss on early extinguishment of debt	(8,875		)	—			(8,875		)	(100.0	)%
Other income / (expense), net	2,753			(2,097		)	4,850			(231.3	)%
Total other income/(expense), net	$	(81,454	)	$	(69,559	)	$	(11,895	)	17.1	%

The $11.9 million decrease in total Other income/(expense), net was primarily due to the loss on early extinguishment of debt of $8.9 million, which was due to the redemption of $400 million 2018 IPALCO Notes during the third quarter of 2017. Additionally, Interest expense increased $6.5 million primarily due to higher interest expense 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 and a decrease in Allowance for equity funds used during construction of $1.3 million due to decreased construction activity. This was partially offset by an increase in Other income/(expense), net of $4.9 million primarily due to a decrease in defined benefit plan costs of $3.0 million (mostly due to a higher return on plan assets).

Income Tax Expense - Net

2018 versus 2017

The following table illustrates our changes in income tax expense - net from 2017 to 2018 (in thousands):



	Years Ended
	December 31,
	2018		2017		$ Change			% Change
Income tax expense - net	$	13,449	$	48,951	$	(35,502	)	(72.5	)%

The decrease in income tax expense - net of $35.5 million was primarily due to (i) the decrease in the federal corporate income tax rate to 21% from 35% as a result of the passage of the TCJA, which was signed into law in December 2017, (ii) tax benefits associated with the amortization of the impact of the lower income tax rate resulting from the TCJA on our deferred tax balances and (iii) lower Earnings from operations before income tax.

2017 versus 2016

The following table illustrates our changes in income tax expense - net from 2016 to 2017 (in thousands):



	Years Ended
	December 31,
	2017		2016		$ Change			% Change
Income taxes expense - net	$	48,951	$	61,210	$	(12,259	)	(20.0	)%

The decrease in income tax expense - net of $12.3 million was primarily due to lower Earnings from operations before income tax in 2017 compared to 2016, as well a higher manufacturer’s production deduction (Internal Revenue Code Section 199) in 2017 compared to 2016, as it had been previously limited due to a Net Operating Loss carryover.

KEY TRENDS AND UNCERTAINTIES

During 2019 and beyond, we expect that our financial results will be driven primarily by retail demand, weather, and outage costs. In addition, our financial results will likely be driven by many other factors including, but not limited to:


▪	regulatory outcomes;


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


▪	timely recovery of capital expenditures; and


▪	to a lesser extent, wholesale and capacity prices.

If favorable outcomes related to these factors do not occur, or if the challenges described below and elsewhere in this report 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 Environment

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

Macroeconomic and Political

U.S. Tax Law Reform

In December 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 impacted our 2018 effective tax rate and 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 resulted in the recognition, at December 31, 2017, of a regulatory liability at IPL. The regulatory liability reflects 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.

SAB 118 - As further explained in Note 8, “Income Taxes” to the Financial Statements of this Form 10-K. we have concluded our analysis of the implementation impacts of the TCJA and included adjustments to our previous estimates in accordance with the guidance of SAB 118.

Limitation on Interest Expense Deductions - The TCJA introduced a new limitation on the deductibility of net interest expense beginning January 1, 2018. The deduction is 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 have released proposed regulations to clarify how the exception will apply to regulated utility holding companies. These proposed regulations are prospective; the Company has not adopted them for 2018.

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 state of Indiana has largely conformed the TCJA.

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.

LIBOR Phase Out

In July 2017, the U.K. Financial Conduct Authority announced the phase out of LIBOR by the end of 2021. The Alternative Reference Rate Committee within the Federal Reserve is responsible for the transition from LIBOR to a new benchmark replacement rate. While AES maintains financial instruments that use LIBOR as an interest rate benchmark, the full impact of the phase out is uncertain until a new replacement benchmark is determined and

implementation plans are more fully developed.

CAPITAL RESOURCES AND LIQUIDITY

As of December 31, 2018, we had unrestricted cash and cash equivalents of $33.2 million and available borrowing capacity of $250 million under our $250 million unsecured revolving Credit Agreement 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 26, 2020. In December 2018, we received an order from the IURC granting us authority through December 31, 2021 to, among other things, issue up to $350 million in aggregate principal amount of long-term debt and refinance up to $185 million in existing indebtedness, all of which authority remains available under the order as of December 31, 2018. 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, 2018. 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, 2018. 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 Agreement 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 Agreement; 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
	2018			2017			2016			2018 vs. 2017			2017 vs. 2016
	(in thousands)									(in thousands)
Net cash provided by operating activities	$	381,012		$	285,260		$	324,591		$	95,752		$	(39,331	)
Net cash used in investing activities	(253,952		)	(236,432		)	(608,688		)	(17,520		)	372,256
Net cash (used in) provided by financing activities	(124,142		)	(53,100		)	297,529			(71,042		)	(350,629		)
Net change in cash and cash equivalents	2,918			(4,272		)	13,432			7,190			(17,704		)
Cash, cash equivalents and restricted cash at beginning of period	30,681			34,953			21,521			(4,272		)	13,432
Cash and cash equivalents at end of period	$	33,599		$	30,681		$	34,953		$	2,918		$	(4,272	)

Operating Activities

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



	Years ended December 31,									$ Change
	2018			2017			2016			2018 vs. 2017			2017 vs. 2016
	(in thousands)									(in thousands)
Net income	$	134,025		$	108,793		$	131,060		$	25,232		$	(22,267	)
Depreciation and amortization	232,332			208,451			218,449			23,881			(9,998		)
Amortization of debt premium	3,975			4,202			4,147			(227		)	55
Deferred income taxes and investment tax credit adjustments	(15,735		)	(3,506		)	34,012			(12,229		)	(37,518		)
Loss on early extinguishment of debt	—			8,875			—			(8,875		)	8,875
Allowance for equity funds used during construction	(8,477		)	(25,798		)	(27,140		)	17,321			1,342
Net income, adjusted for non-cash items	346,120			301,017			360,528			45,103			(59,511		)
Net change in operating assets and liabilities	34,892			(15,757		)	(35,937		)	50,649			20,180
Net cash provided by operating activities	$	381,012		$	285,260		$	324,591		$	95,752		$	(39,331	)

2018 versus 2017

The net change in operating assets and liabilities for the year ended December 31, 2018 compared to the year ended December 31, 2017 was driven by the following (in thousands):



Increase from short-term and long-term regulatory assets and liabilities, primarily due to proceeds IPL received pursuant to a settlement agreement and an increase to regulatory liabilities to record the impacts of the TCJA on customer rates	$	59,636
Decrease from accrued pension and other postretirement benefits due to higher employer contributions	(16,671		)
Increase from accounts payable, primarily due to timing of payments	16,592
Decrease from accrued and other current liabilities, primarily due to higher severance and bonus payments in 2018	(10,629		)
Other	1,721
Net change in operating assets and liabilities	$	50,649

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 Base 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	27,259
Decrease from inventories, due to lower coal purchases	(38,776		)
Decrease from accounts payable, primarily due to timing of payments	(26,081		)
Other	2,741
Net change in operating assets and liabilities	$	20,180

Investing Activities

During the year ended December 31, 2018, net cash used in investing activities was primarily related to capital expenditures of $224.3 million. In addition, Cost of removal and regulatory recoverable ARO payments were $29.5 million. The primary drivers of these expenditures include $133.3 million on maintenance projects, $50.9 million on transmission and distribution projects, $12.0 million on NPDES compliance, $11.5 million on the Eagle Valley CCGT plant, and $10.5 million on NAAQS compliance.

During the year ended December 31, 2017, net cash used in investing activities was primarily related to capital expenditures of $218.2 million. In addition, Cost of removal and regulatory recoverable ARO payments were $16.8 million. The primary drivers of these expenditures include $105.9 million on maintenance projects, $36.2 million on transmission and distribution projects, $32.2 million on NPDES compliance, $25.1 million on the Eagle Valley CCGT plant, and $5.1 million on NAAQS compliance.

During the year ended December 31, 2016, net cash used in investing activities was primarily related to capital expenditures of $592.2 million. In addition, Cost of removal and regulatory recoverable ARO payments were $16.1 million.The primary drivers of these expenditures include $223.8 million on the Eagle valley CCGT plant, $130.6 million on maintenance projects, $88.4 million on NPDES compliance, $52.9 million on transmission and distribution projects, and $31.8 million on MATS compliance.

Financing Activities

During the year ended December 31, 2018, net cash used in financing activities primarily relates to dividends to shareholders of $130.2 million and payments for financed capital expenditures of $11.4 million; partially offset by net borrowings of $21.9 million.

During the year ended December 31, 2017, net cash used in financing activities primarily relates to dividends to shareholders of $105.1 million and $10.6 million of payments for financed capital expenditures; 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 and $15.5 million of payments for financed capital expenditures.

Capital Requirements

Capital Expenditures

Our capital expenditure program, including development and permitting costs, for the three-year period from 2019 through 2021 is currently estimated to cost approximately $771 million (excluding environmental compliance), and includes estimates as follows (amounts in millions):



	For the three-year period
	from 2019 through 2021
Transmission and distribution related additions, improvements and extensions	$	486	⁽¹⁾
Power plant-related projects	214
Other miscellaneous equipment	71
Total estimated costs of capital expenditure program	$	771

⁽¹⁾Additions, improvements and extensions to transmission and distribution lines, substations, power factor and voltage regulating equipment, distribution transformers and street lighting facilities

Additionally, IPL plans to spend $40 million on environmental compliance costs for the three-year period 2019 through 2021 (amounts in millions):



	Total Estimated Costs		Total Costs Expended		Remaining Costs
	of Project ⁽¹⁾		Through December 31, 2018 ⁽¹⁾		of Project
NAAQS Ozone ⁽²⁾	$	25	$	—	$	25
NAAQS SO₂ ⁽³⁾	$	29	$	22	$	7
Cooling water intake regulations ⁽⁴⁾	$	8	$	—	$	8

⁽¹⁾Reflects total costs from project inception.
⁽²⁾Includes costs for compliance with the NAAQS Ozone rules.
⁽³⁾IPL plans to spend a total of $29 million through 2019 for projects underway related to environmental compliance for NAAQS SO₂.
⁽⁴⁾Includes spending for studies related to cooling water intake requirements in sections 316(b).

Please see “Item 1. Business - Environmental Matters" for additional details on each of these projects.

Additionally, Indiana Code 8-1-39 was approved by the Indiana Legislature in 2013, which allows electric and natural gas utilities to submit 7-year infrastructure improvement plans for IURC approval. Once a 7-year plan receives IURC approval, the utility may request periodic rate adjustments to recover costs (including a return) associated with the plan. The rate adjustment is referred to as the Transmission, Distribution, and Storage System Improvement Charge (TDSIC). IPL is currently evaluating future investments under this law.

Capital Resources

As IPALCO is a holding company, substantially all of its cash is generated by the operating activities of its subsidiaries, principally IPL. None of its subsidiaries, including IPL, are obligated under or have guaranteed to make payments with respect to the Term Loan, 2020 IPALCO Notes or the 2024 IPALCO Notes; however, all of IPL’s common stock is pledged to secure these debt obligations. Accordingly, IPALCO’s ability to make payments on the Term Loan, 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 2019 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

Significant Debt Transactions

For further discussion of our significant debt transactions, please see Note 7, “Debt” to the Financial Statements of this Form 10-K.

Line of Credit

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

$ in millions

Type

Maturity

Commitment

Amounts available at February 26, 2019

IPL

Revolving

October 2020

250.0

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.

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	BBB ^(a)	A^(b)	Stable	November 2018
Moody's Investors Service	Baa3^(a)	A2^(b)	Stable	November 2018
S&P Global Ratings	BBB-^(a)	A-^(b)	Stable	March 2018

Credit ratings	IPALCO	IPL	Outlook	Effective or Affirmed
Fitch Ratings	BBB-	BBB+	Stable	November 2018
Moody's Investors Service	—	Baa1	Stable	November 2018
S&P Global Ratings	BBB	BBB	Stable	March 2018


(a)	Ratings relate to IPALCO's Senior Secured Notes.


(b)	Ratings relate to IPL's Senior Secured Bonds.

We cannot predict whether our current credit ratings or the credit ratings of IPL will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. A security rating is not a recommendation to buy, sell or hold securities. Such ratings may be subject to revision or withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating.

Contractual Cash Obligations

Our non-contingent contractual obligations as of December 31, 2018 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	$	2,678.8	$	—	$	560.0	$	95.0	$	2,023.8
Interest obligations ⁽¹⁾	1,964.8		116.8		206.8		190.9		1,450.3
Purchase obligations ⁽²⁾
Coal, gas, purchased power and
related transportation	1,608.2		257.5		401.3		212.1		737.3
Other	55.9		13.6		18.5		7.9		15.9
Total ⁽³⁾	$	6,307.7	$	387.9	$	1,186.6	$	505.9	$	4,227.3


(1)	Represents interest payment obligations related to fixed and variable rate debt. Interest related to variable rate debt is calculated using the rate in effect at December 31, 2018.

(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)	Does not include an uncertain tax liability of $7.1 million (tax and related interest) as of December 31, 2018 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

For further discussion of our dividend distributions, please see "Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities - Dividends" of this Form 10-K.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

Revenue Recognition

Revenues related to the sale of energy are generally recognized when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is accrued. In making our estimates of unbilled revenue, we use complex models that consider various factors including daily generation volumes; known amounts of energy usage by nearly all residential, small commercial and industrial customers; estimated line losses; and estimated customer rates based on prior period billings. Given the use of these models, and that customers are billed on a monthly cycle, we believe it is unlikely that materially different results will occur in future periods when revenue is billed. The effect on 2018 revenues and ending unbilled revenues of a one percentage point change in estimated line losses for the month of December 2018 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, “Regulatory Assets and Liabilities” to the Financial Statements.

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

Pension Costs

We account for and disclose pension and postemployment benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postemployment plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost and funding requirements of the plans. Effective January 1, 2016, we began applying a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and other post-retirement plan.

Contingencies

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

NEW ACCOUNTING STANDARDS

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Overview

The primary market risks to which we are exposed are those associated with environmental regulation, debt and equity investments, fluctuations in interest rates and the prices of 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. Our U.S. Risk Management Committee (U.S. RMC), comprised of members of senior management, is responsible for establishing risk management policies and the monitoring and reporting of risk exposures related to our operations. The U.S. RMC meets on a regular basis with the objective of identifying, assessing and quantifying material risk issues and developing strategies to manage these risks.

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 $31.26, $31.99 and $31.17 in 2018, 2017 and 2016, respectively. For the periods presented in the Financial Statements of this Form 10-K, a decline in wholesale prices could have had 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. However, after the implementation of the 2018 Base Rate Order in December 2018, the impact is limited as the order provides that annual wholesale margins earned above (or below) a benchmark of $16.3 million shall be passed back (or charged) to customers through a rate adjustment mechanism. Our wholesale revenues represented 2.5% 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 2019 and approximately 60% of our current projected burn for the three-year period ending December 31, 2021, under long-term contracts. In addition, IPL has established physical natural gas hedges for approximately 50% of the expected consumption at Eagle Valley during the 2019 winter period. Pricing provisions in some of our long-term contracts allow for price changes under certain circumstances. Fuel purchases made in 2019 have been and are expected to continue to be made at prices that are slightly higher than our weighted average price in 2018. Our exposure to fluctuations in the price of fuel is limited because pursuant to Indiana law, we may apply to the IURC for a change in our fuel charge every three months to recover our estimated fuel costs, which may be above or below the levels included in our basic rates. We must present evidence in each FAC proceeding that we have made every reasonable effort to acquire fuel and generate or purchase power or both so as to provide electricity to our retail customers at the lowest fuel cost reasonably possible.

Power Purchased

We depend on purchased power, in part, to meet our retail load obligations. As a result, we also have limited exposure to commodity price risk for the purchase of electric energy for our retail customers. Purchased power costs can be highly volatile. We are generally allowed to recover, through our FAC, the energy portion of purchased power costs incurred to meet jurisdictional retail load. In certain circumstances, we may not be allowed to recover a portion of purchased power costs incurred to meet our jurisdictional retail load. See Note 2, “Regulatory Matters - FAC and Authorized Annual Jurisdictional Net Operating Income” to the Financial Statements.

Equity Market Risk

Our Pension Plans are impacted significantly by the economy as a result of the Pension Plans being significantly invested in common equity securities. The performance of the Pension Plans’ investments in such common equity securities and other instruments impacts our earnings as well as our funding liability. A hypothetical 10% decrease

in prices quoted by stock exchanges would result in a $5.4 million reduction in fair value as of December 31, 2018 and approximately a $0.8 million increase to the 2019 pension expense. Please see Note 9, “Benefit Plans” to the Financial Statements for additional Pension Plan information.

Interest Rate Risk

We use long-term debt as a significant source of capital in our business, which exposes us to interest rate risk. We do not enter into market risk sensitive instruments for trading purposes. We manage our exposure to interest rate risk through the use of fixed-rate debt and by refinancing existing long-term debt at times when it is deemed economic and prudent. In addition, IPL’s Credit Agreement and IPALCO's Term Loan bear 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, 2018, we had approximately $2,523.8 million principal amount of fixed rate debt and $155.0 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, 2018 was comprised of $90.0 million under IPL's Series 2015A and Series 2015B notes and $65.0 million under IPALCO's Term Loan. Based on amounts outstanding as of December 31, 2018, the effect of a 25 basis point change in the applicable rates on our variable-rate debt would change our annual interest expense and cash paid for interest by $0.4 million and $(0.4 million), respectively.

The following table shows our consolidated indebtedness (in millions) by maturity as of December 31, 2018:



	2019		2020		2021		2022		2023		Thereafter		Total		Fair Value
Fixed-rate	$	—	$	405.0	$	95.0	$	—	$	—	$	2,023.8	$	2,523.8	$	2,649.3
Variable-rate	—		155.0		—		—		—		—		155.0		155.0
Total Indebtedness	$	—	$	560.0	$	95.0	$	—	$	—	$	2,023.8	$	2,678.8	$	2,804.3
Weighted Average Interest Rates by Maturity	N/A		3.324%		3.875%		N/A		N/A		4.715%		4.395%

For further discussion of our fair value of our indebtedness and book value of our indebtedness please see Note 4, “Fair Value” and Note 7, “Debt” to the Financial Statements.

Retail Energy Market

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

Counterparty Credit Risk

At times, we may utilize forward purchase contracts to manage the risk associated with power purchases, and could be exposed to counterparty credit risk in these contracts. We manage this exposure to counterparty credit risk by entering into contracts with companies that are expected to fully perform under the terms of the contract. Individual credit limits are generally implemented for each counterparty to further mitigate credit risk. We may also require a counterparty to provide collateral in the event certain financial benchmarks are not maintained, or certain credit ratings are not maintained.

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

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS



	Page No.
IPALCO Enterprises, Inc. and Subsidiaries – Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm – 2018, 2017 and 2016	55
Consolidated Statements of Operations for the years ended December 31, 2018, 2017 and 2016	56
Consolidated Balance Sheets as of December 31, 2018 and 2017	57
Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016	58
Consolidated Statements of Common Shareholders’ Equity and Noncontrolling Interest
for the years ended December 31, 2018, 2017 and 2016	59
Notes to Consolidated Financial Statements	60

Indianapolis Power & Light Company and Subsidiary – Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm – 2018, 2017 and 2016	94
Consolidated Statements of Operations for the years ended December 31, 2018, 2017 and 2016	95
Consolidated Balance Sheets as of December 31, 2018 and 2017	96
Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016	97
Consolidated Statements of Common Shareholder’s Equity for the years ended
December 31, 2018, 2017 and 2016	98
Notes to Consolidated Financial Statements	99

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, 2018 and 2017, 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, 2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018 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 audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. 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, 2019



IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Operations
For the Years Ended December 31, 2018, 2017 and 2016
(In Thousands)
	2018			2017			2016
REVENUES	$	1,450,505		$	1,349,588		$	1,347,430

COST OF REVENUES:
Fuel	331,701			281,542			276,171
Power purchased	164,542			189,847			170,466
Total cost of revenues	496,243			471,389			446,637

GROSS MARGIN	954,262			878,199			900,793

OPERATING EXPENSES:
Operation and maintenance	431,515			385,876			375,113
Depreciation and amortization	232,332			208,451			218,449
Taxes other than income taxes	53,952			44,644			45,326
Other operating expenses	105			30			76
Total operating expenses	717,904			639,001			638,964

OPERATING INCOME	236,358			239,198			261,829

OTHER INCOME / (EXPENSE), NET:
Allowance for equity funds used during construction	8,477			25,798			27,140
Interest expense	(95,509		)	(101,130		)	(94,602		)
Loss on early extinguishment of debt	—			(8,875		)	—
Other income / (expense), net	(1,852		)	2,753			(2,097		)
Total other income and (expense), net	(88,884		)	(81,454		)	(69,559		)

EARNINGS FROM OPERATIONS BEFORE INCOME TAX	147,474			157,744			192,270

Less: income tax expense - net	13,449			48,951			61,210
NET INCOME	134,025			108,793			131,060

Less: dividends on preferred stock	3,213			3,213			3,213
NET INCOME APPLICABLE TO COMMON STOCK	$	130,812		$	105,580		$	127,847

See notes to consolidated financial statements.



IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Balance Sheets
(In Thousands)
	December 31, 2018			December 31, 2017
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	33,199		$	30,681
Restricted cash	400			—
Accounts receivable, net	167,559			157,614
Inventories	99,668			96,016
Regulatory assets, current	28,399			35,341
Prepayments and other current assets	29,346			34,057
Total current assets	358,571			353,709
NON-CURRENT ASSETS:
Property, plant and equipment	6,201,078			5,399,851
Less: Accumulated depreciation	2,256,215			2,129,754
	3,944,863			3,270,097
Construction work in progress	111,723			711,396
Total net property, plant and equipment	4,056,586			3,981,493
OTHER NON-CURRENT ASSETS:
Intangible assets - net	40,848			16,036
Regulatory assets, non-current	395,077			378,904
Other non-current assets	10,971			10,419
Total other non-current assets	446,896			405,359
TOTAL ASSETS	$	4,862,053		$	4,740,561
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Short-term and current portion of long-term debt (Note 7)	$	—		$	148,000
Accounts payable	134,931			125,297
Accrued taxes	21,325			18,145
Accrued interest	34,790			34,332
Customer deposits	32,700			31,306
Regulatory liabilities, current	51,024			2,532
Accrued and other current liabilities	27,787			38,318
Total current liabilities	302,557			397,930
NON-CURRENT LIABILITIES:
Long-term debt (Note 7)	2,649,064			2,477,538
Deferred income tax liabilities	253,085			245,257
Taxes payable	4,658			4,651
Regulatory liabilities, non-current	870,255			851,754
Accrued pension and other postretirement benefits	19,329			50,070
Asset retirement obligations	129,451			79,535
Other non-current liabilities	604			1,766
Total non-current liabilities	3,926,446			3,710,571
Total liabilities	4,229,003			4,108,501
COMMITMENTS AND CONTINGENCIES (Note 10)
SHAREHOLDERS' EQUITY:
Paid in capital	597,824			597,467
Accumulated deficit	(24,558		)	(25,191		)
Total common shareholders' equity	573,266			572,276
Preferred stock of subsidiary	59,784			59,784
Total shareholders' equity	633,050			632,060
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	4,862,053		$	4,740,561

See notes to consolidated financial statements.



IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Cash Flows
For the Years Ended December 31, 2018, 2017 and 2016
(In Thousands)
	2018			2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	134,025		$	108,793		$	131,060
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	232,332			208,451			218,449
Amortization of deferred financing costs and debt premium	3,975			4,202			4,147
Deferred income taxes and investment tax credit adjustments - net	(15,735		)	(3,506		)	34,012
Loss on early extinguishment of debt	—			8,875			—
Allowance for equity funds used during construction	(8,477		)	(25,798		)	(27,140		)
Change in certain assets and liabilities:
Accounts receivable	(9,944		)	(3,028		)	(30,287		)
Inventories	(3,652		)	(5,342		)	33,434
Accounts payable	3,675			(12,917		)	13,164
Accrued and other current liabilities	(10,532		)	97			5,748
Accrued taxes	3,180			(785		)	1,218
Accrued interest	458			1,791			850
Pension and other postretirement benefit expenses	(30,740		)	(14,069		)	(16,595		)
Short-term and long-term regulatory assets and liabilities	76,647			17,011			(38,026		)
Prepayments and other current assets	4,711			(553		)	(7,573		)
Other - net	1,089			2,038			2,130
Net cash provided by operating activities	381,012			285,260			324,591
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(224,335		)	(218,224		)	(592,243		)
Project development costs	(1,127		)	(1,729		)	(1,356		)
Cost of removal and regulatory recoverable ARO payments	(29,543		)	(16,802		)	(16,106		)
Other	1,053			323			1,017
Net cash used in investing activities	(253,952		)	(236,432		)	(608,688		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt borrowings	100,000			202,500			298,000
Short-term debt repayments	(248,000		)	(129,150		)	(414,850		)
Long-term borrowings, net of discount	169,936			404,633			387,662
Retirement of long-term debt, including early payment premium	—			(408,152		)	(40,000		)
Dividends on common stock	(130,179		)	(105,144		)	(122,959		)
Issuance of common stock	—			—			134,276
Equity contributions from shareholders	—			—			78,738
Preferred dividends of subsidiary	(3,213		)	(3,213		)	(3,213		)
Deferred financing costs paid	(1,067		)	(3,709		)	(4,499		)
Payments for financed capital expenditures	(11,429		)	(10,637		)	(15,473		)
Other	(190		)	(228		)	(153		)
Net cash (used in) provided by financing activities	(124,142		)	(53,100		)	297,529
Net change in cash, cash equivalents and restricted cash	2,918			(4,272		)	13,432
Cash, cash equivalents and restricted cash at beginning of period	30,681			34,953			21,521
Cash, cash equivalents and restricted cash at end of period	$	33,599		$	30,681		$	34,953

Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized)	$	90,975		$	94,781		$	89,098
Income taxes	28,275			65,050			28,800
Non-cash investing activities:
Accruals for capital expenditures	$	47,553		$	45,322		$	36,249

See notes to consolidated financial statements.



IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Common Shareholders' Equity
and Noncontrolling Interest
For the Years Ended December 31, 2018, 2017 and 2016
(In Thousands)
	Paid in Capital		Accumulated Deficit			Total Common Shareholders' Equity			Cumulative Preferred Stock of Subsidiary
Balance at January 1, 2016	$	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
Net income	—		130,812			130,812			3,213
Preferred stock dividends	—		—			—			(3,213		)
Distributions to shareholders	—		(130,179		)	(130,179		)	—
Other	357		—			357			—
Balance at December 31, 2018	$	597,824	$	(24,558	)	$	573,266		$	59,784

See notes to consolidated financial statements.

IPALCO ENTERPRISES, INC. and SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2018, 2017 and 2016

1. OVERVIEW AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

IPALCO is a holding company incorporated under the laws of the state of Indiana. IPALCO, acquired by AES in March 2001, is owned by AES U.S. Investments (82.35%) and CDPQ (17.65%). AES U.S. Investments is owned by AES U.S. Holdings, LLC (85%) and CDPQ (15%). IPALCO owns all of the outstanding common stock of IPL. Substantially all of IPALCO’s business consists of generating, transmitting, distributing and selling of electric energy conducted through its principal subsidiary, IPL. IPL was incorporated under the laws of the state of Indiana in 1926. IPL has more than 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, uses natural gas and fuel oil to power combustion turbines. In addition, IPL operates a 20 MW battery energy storage unit at this location, which provides frequency response. The third station, Eagle Valley, is a newly constructed 671 MW CCGT natural gas plant. IPL took operational control and commenced commercial operations of this CCGT plant in April 2018. The fourth station, Georgetown, is a small peaking station that uses natural gas to power combustion turbines. As of December 31, 2018, IPL’s net electric generation capacity for winter is 3,667 MW and net summer capacity is 3,552 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.

Financial Statement Presentation

During 2018, we adopted a change in presentation on our Consolidated Balance Sheets and Consolidated Statements of Operations from a utility format to a traditional format. These changes combined or revised the order of certain balance sheet and income statement line items and resulted in the movement of certain immaterial balances within the Consolidated Statements of Operations and Consolidated Balance Sheets, but did not result in any material changes to the classification of any such amounts or have any impact on net assets or net income. Certain amounts from prior periods have been reclassified to conform to the current period presentation.

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.

Regulatory Accounting

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.

Cash, Cash Equivalents and Restricted Cash

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. Restricted cash includes cash which is restricted as to withdrawal or usage. The nature of the restrictions includes restrictions imposed by agreements related to deposits held as collateral. The following table provides a summary of cash, cash equivalents and restricted cash amounts as shown on the Consolidated Statements of Cash Flows:



	As of December 31,
	2018		2017
	(In Thousands)
Cash, cash equivalents and restricted cash
Cash and cash equivalents	$	33,199	$	30,681
Restricted cash	400		—
Total cash, cash equivalents and restricted cash	$	33,599	$	30,681

Revenues and Accounts Receivable

Revenues related to the sale of energy are generally recognized when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to certain customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is accrued. In making its estimates of unbilled revenue, IPL uses complex models that consider various factors including daily generation volumes; known amounts of energy usage by nearly all residential, small commercial and industrial customers; estimated line losses; and estimated customer rates based on prior period billings. Given the use of these models, and that customers are billed on a monthly cycle, we believe it is unlikely that materially different results will occur in future periods when revenue is billed. 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 “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations was $6.0 million, $5.9 million and $4.1 million for the years ended December 31, 2018, 2017 and 2016, 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 December 2018. 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. See Note 13, "Revenue" for additional information of MISO sales and other revenue streams.

The following table summarizes our accounts receivable balances at December 31:



	As of December 31,
	2018			2017
	(In Thousands)
Accounts receivable, net
Customer receivables	$	91,426		$	94,168
Unbilled revenue	68,893			61,599
Amounts due from related parties	5,720			37
Other	4,341			4,640
Provision for uncollectible accounts	(2,821		)	(2,830		)
Total accounts receivable, net	$	167,559		$	157,614

Inventories

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 net realizable value, using the average cost. The following table summarizes our inventories balances at December 31:



	As of December 31,
	2018		2017
	(In Thousands)
Inventories
Fuel	$	32,457	$	32,393
Materials and supplies	67,211		63,623
Total inventories	$	99,668	$	96,016

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 4.2%, 4.1%, and 4.3% during 2018, 2017 and 2016, respectively. Depreciation expense was $235.2 million, $209.8 million, and $209.5 million for the years ended December 31, 2018, 2017 and 2016, respectively. "Depreciation and amortization" expense on the accompanying Consolidated Statements of Operations is presented net of regulatory deferrals of depreciation expense and also includes amortization of intangible assets and amortization of previously deferred regulatory costs.

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 6.4%, 6.6% and 7.1% during 2018, 2017 and 2016, respectively. For all other construction projects, IPL capitalized amounts using pretax composite rates of 6.4%, 6.6% and 7.2% during 2018, 2017 and 2016, respectively.

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 $4.1 billion and $4.0 billion as of December 31, 2018 and 2017, 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 $129.7 million and $99.4 million and its corresponding accumulated amortization of $88.8 million and $83.4 million, as of December 31, 2018 and 2017, respectively. Amortization expense was $5.5 million, $4.3 million and $5.9 million for the years ended December 31, 2018, 2017 and 2016, respectively. The estimated amortization expense of this capitalized software is $30.2 million over the next 5 years ($5.7 million in 2019,$6.9 million in 2020, $6.9 million in 2021, $6.9 million in 2022 and $3.8 million in 2023).

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, 2018 and 2017, total loss contingencies accrued were $4.6 million and $4.1 million, respectively, which were included in “Accrued and 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 68% 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 6, 2021, and the contract with the clerical-technical unit expires February 17, 2020. Additionally, IPL has long-term coal contracts with four suppliers, with about 46% of our existing coal under contract for the three-year period ending December 31, 2021 coming from one supplier. Substantially all of the coal is currently mined in the state of Indiana.

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.

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 tax assets or liabilities which are includable in allowable costs for ratemaking purposes in future years are recorded as regulatory assets or liabilities 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.

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 Adopted in 2018

The following table provides a brief description of recent accounting pronouncements that had an impact on the Company’s consolidated financial statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or did not have a material impact on the Company’s consolidated financial statements.



New Accounting Standards Adopted
ASU Number and Name	Description	Date of Adoption	Effect on the financial statements upon adoption
2018-15, Intangibles— Goodwill and Other— Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract	This standard aligns the accounting for implementation costs incurred for a cloud computing arrangement that is a service with the requirement for capitalizing implementation costs associated with developing or obtaining internal-use software. Transition method: retrospective or prospective.	October 1, 2018	The Company elected to early-adopt this standard on a prospective basis, effective for fiscal year 2018. The adoption of this standard did not have a material impact on the financial statements.
2018-14, Compensation— Retirement Benefits— Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework	This standard modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. Transition method: retrospective.	Early adoption elected, January 1, 2018.	Impact limited to changes in financial statement disclosures.
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 costs 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 and prospective for the change in capitalization.	January 1, 2018	The adoption of this standard resulted in a $(2.0) million and $1.0 million reclassification of non-service pension costs (credits) from Operating Expenses - Operations and maintenance to Other income/(expense), net for 2017 and 2016, respectively.
2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force)	This standard requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. Transition method: retrospective.	January 1, 2018	No material impact upon adoption of the standard.
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	See impact upon adoption of the standard below.

Adoption of ASC Topic 606, “Revenue from Contracts with Customers”

On January 1, 2018, the Company adopted ASU 2014-09, “Revenue from Contracts with Customers”, and its subsequent corresponding updates (“ASC 606”). Under this standard, 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. The Company applied the modified retrospective method of adoption to those contracts that were not completed as of January 1, 2018. Results for reporting periods beginning January 1, 2018 are presented under ASC 606, while prior period amounts were not adjusted and continue to be reported in accordance with our historic accounting under the previous revenue recognition standard. For contracts that were modified before January 1, 2018, the Company reflected the aggregate effect of all modifications when identifying the satisfied and unsatisfied performance obligations, determining the transaction price and allocating the transaction price.

There was no cumulative effect to our January 1, 2018 Consolidated Balance Sheet resulting from the adoption of ASC 606.

New Accounting Pronouncements Issued But Not Yet Effective

The following table provides a brief description of recent accounting pronouncements that could have a material impact on the Company’s consolidated financial statements once adopted. Accounting pronouncements not listed below were assessed and determined to be either not applicable or are expected to have no material impact on the Company’s consolidated financial statements.



New Accounting Standards Issued But Not Yet Effective
ASU Number and Name	Description	Date of Adoption	Effect on the financial statements upon adoption
2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities	The standard updates the hedge accounting model to expand the ability to hedge nonfinancial and financial risk components, reduce complexity, and ease certain documentation and assessment requirements. When facts and circumstances are the same as at the previous quantitative test, a subsequent quantitative effectiveness test is not required. The standard also eliminates the requirement to separately measure and report hedge ineffectiveness. For cash flow hedges, this means that the entire change in the fair value of a hedging instrument will be recorded in other comprehensive income and amounts deferred will be reclassified to earnings in the same income statement line as the hedged item. Transition method: modified retrospective with the cumulative effect adjustment recorded to the opening balance of retained earnings as of the initial application date. Prospective for presentation and disclosures.	January 1, 2019. Early adoption is permitted.	The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.
2018-19, 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, 2018-10, 2018-11, 2018-20, Leases (Topic 842)	See discussion of the ASUs below.	January 1, 2019. Early adoption is permitted.	The Company adopted the standard on January 1, 2019; see below for the evaluation of the impact of its adoption on its consolidated financial statements.

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

The standard must be adopted using a modified retrospective approach. The FASB has provided an optional transition method, which the Company has elected, that allows entities to continue to apply the guidance in ASC 840 Leases to the comparative periods presented in the year of adoption. Under this transition method, the Company will apply the transition provisions starting on January 1, 2019.

The Company has elected to apply a package of practical expedients that allow lessees and lessors 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. The Company has also elected to apply an optional transition practical expedient for land easements that allows an entity to continue applying its current accounting policy for all land easements that exist before the standard's effective date that were not previously accounted for under ASC 840.

The Company established a task force focused on the identification of contracts that are under the scope of the new standard and the assessment and measurement of their corresponding right-of-use assets and related liabilities. Additionally, the implementation team has been working on the configuration of a lease accounting tool that will support the implementation and the subsequent accounting. The implementation team has also evaluated changes to our business processes, systems and controls to support recognition and disclosure under the new standard.

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 includes the fair value of the plant after the contract period but does not include any variable payment such as margin on the sale of energy. Therefore, the lease receivable could be significantly different 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 asset is recognized as a gain/loss at lease commencement.

The adoption of ASC 842 did not have a material impact on our consolidated financial statements.

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.

Base Rate Orders

On October 31, 2018, the IURC issued an order approving an uncontested settlement agreement previously filed with the IURC by IPL for a $43.9 million, or 3.2%, increase to annual revenues (the "2018 Base Rate Order"). The 2018 Base Rate Order includes recovery through rates of the CCGT at Eagle Valley completed in the first half of 2018, as well as other construction projects and changes to operating income since the 2016 Base Rate Order (See below). New basic rates and charges became effective on December 5, 2018. The 2018 Base Rate Order also provides customers approximately $50 million in benefits, to be flowed to customers over a two-year period via the ECCRA rate adjustment mechanism beginning in March 2019. This liability is recorded in "Regulatory liabilities, non-current" as of December 31, 2018 on the accompanying Consolidated Balance Sheets. In addition, the 2018 Base Rate Order provides that annual wholesale margins earned above (or below) the benchmark of $16.3 million shall be passed back (or charged) to customers through a rate adjustment mechanism. Similarly, the 2018 Base Rate Order provides that all capacity sales above (or below) a benchmark of $11.3 million shall be passed back (or charged) to customers through a rate adjustment mechanism. The 2018 Base Rate Order also approved changes to IPL's depreciation and amortization rates (including no longer deferring depreciation on the CCGT at Eagle Valley) which altogether represent a net increase of approximately $28.7 million annually.

In March 2016, the IURC issued the 2016 Base 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. The rate order also authorized an increase in IPL’s depreciation rates of $24.3 million annually compared to the twelve months ended June 30, 2014, which is the period upon which the rate increase was calculated. IPL also received approval to implement three new rate riders for current recovery from customers of ongoing MISO costs and capacity costs, and for sharing with customers 50% of wholesale sales margins above and below the established benchmark of $6.3 million.

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 was 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 was 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 and results of operations.

FAC and Authorized Annual Jurisdictional Net Operating Income

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

ECCRA

IPL may apply to the IURC for approval of a rate adjustment known as the ECCRA periodically 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, 2018 was $12.1 million. The jurisdictional revenue requirement approved by the IURC to be included in IPL’s rates for the six-month period ending February 2019 was $16.2 million. This amount is significantly lower than prior ECCRA periods as a result of having the vast majority of the ECCRA projects rolled into IPL’s basic rates and charges effective December 5, 2018 as a result of the 2018 Base Rate Order. Further, the ECCRA jurisdictional revenue requirement starting March 2019 is expected to be a negative amount to reflect certain one-time credits IPL is required to pass through to its customers over a two-year period (totaling$50.2 million) as a result of the 2018 Base Rate Order. The only equipment still remaining in the ECCRA as of December 31, 2018 are certain projects associated with NAAQS compliance.

DSM

Through various rate orders from the IURC, IPL has been able to recover its costs of implementing various DSM programs throughout the periods covered by this report. In 2016 and 2018, IPL also had the ability to receive performance incentives, dependent upon the level of success of the programs. Performance incentives included in revenues for the years ended December 31, 2018, 2017 and 2016 were $3.8 million, $0.0 million and $10.7 million, respectively.

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 96.4 MW of solar-generated electricity in our service territory under long-term contracts in 2019 (these long-term contracts have expiration dates ranging from 2021 to 2033), of which 95.9 MW was in operation as of December 31, 2018. 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 (“Phase I”) directed respondent utilities (including IPL) to make a filing to remove from respondents’ rates and charges for service, the impact of a lower federal income tax rate. The second phase (“Phase II”) was established to address remaining issues from the TCJA, including treatment of deferred taxes and how these benefits will be realized by customers. On August 29, 2018, the IURC approved a settlement agreement filed by IPL and various other parties to resolve the Phase I issues of the TCJA tax expense via a credit through the ECCRA rate adjustment mechanism of $9.5 million. The 2018 Base Rate Order described above resolved the Phase II and all other issues regarding the TCJA impact on IPL's rates and includes an additional credit of $14.3 million to be paid by IPL to its customers through the ECCRA rate adjustment mechanism over two years beginning in March 2019. See also Note 8, “Income Taxes - U.S. Tax Reform” for further information.

3. PROPERTY, PLANT AND EQUIPMENT

The original cost of property, plant and equipment segregated by functional classifications follows:



	As of December 31,
	2018		2017
	(In Thousands)
Production	$	3,927,847	$	3,226,951
Transmission	394,621		380,851
Distribution	1,533,828		1,487,146
General plant	344,782		304,903
Total property, plant and equipment	$	6,201,078	$	5,399,851

Substantially all of IPL’s property is subject to a $1,713.8 million direct first mortgage lien, as of December 31, 2018, securing IPL’s first mortgage bonds. IPL had no property under capital leases as of December 31, 2018 and 2017. Total non-contractually or legally required removal costs of utility plant in service at December 31, 2018 and 2017 were $761.1 million and $737.1 million, respectively; and total contractually or legally required removal costs of property, plant and equipment at December 31, 2018 and 2017 were $129.5 million and $79.5 million, respectively. Please see “ARO” below for further information.

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:



	2018			2017
	(In Thousands)
Balance as of January 1	$	79,535		$	80,568
Liabilities settled	(8,932		)	(5,276		)
Revisions to cash flow and timing estimates	54,811			—
Accretion expense	4,037			4,243
Balance as of December 31	$	129,451		$	79,535

In 2018, IPL recorded additional ARO liabilities of $54.8 million to reflect revisions to cash flow and timing estimates due to accelerated ash pond closure dates, revised estimated closure costs after review of updates to the CCR rule

and revised estimated costs associated with our coal storage areas, landfills, and asbestos remediation. As of December 31, 2018 and 2017, IPL did not have any assets that are legally restricted for settling its ARO liability.

4. FAIR VALUE

The fair value of financial assets and liabilities approximate their reported carrying amounts. The estimated fair values of the Company’s assets and liabilities have been determined using available market information. As these amounts are estimates and based on hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

Fair Value Hierarchy and Valuation Techniques

ASC 820 defined and established a framework for measuring fair value and expands disclosures about fair value measurements for financial assets and liabilities that are adjusted to fair value on a recurring basis and/or financial assets and liabilities that are measured at fair value on a nonrecurring basis, which have been adjusted to fair value during the period. In accordance with ASC 820, we have categorized our financial assets and liabilities that are adjusted to fair value, based on the priority of the inputs to the valuation technique, following the three-level fair value hierarchy prescribed by ASC 820 as follows:

Level 1 - unadjusted quoted prices for identical assets or liabilities in an active market;

Level 2 - inputs from quoted prices in markets where trading occurs infrequently or quoted prices of instruments with similar attributes in active markets; and

Level 3 - unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability.

Whenever possible, quoted prices in active markets are used to determine the fair value of our financial instruments. Our financial instruments are not held for trading or other speculative purposes. The estimated fair value of financial instruments has been determined by using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

VEBA Assets

IPL has VEBA investments that are to be used to fund certain employee postretirement health care benefit plans. These assets are primarily comprised of open-ended mutual funds, which are valued using the net assets value per unit. These investments are recorded at fair value within "Other non-current assets" on the accompanying Consolidated Balance Sheets and classified as equity securities. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” was effective as of January 1, 2018. This ASU requires the change in the fair value of equity instruments to be recorded in income. Equity Instruments were defined to include all mutual funds, regardless of the underlying investments. Therefore, all changes to fair value on the VEBA investments will be included in income in the period that the changes occur. These changes to fair value were not material for the years ended December 31, 2018, 2017, or 2016. Any unrealized gains or losses are recorded in our Consolidated Statements of Operations.

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, 2018 and 2017, IPALCO's other financial liabilities measured at fair value on a recurring basis were considered Level 3, based on the fair value hierarchy.

Summary

The fair value of assets and liabilities at December 31, 2018 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, 2018		Based on quoted market prices in active markets		Other observable inputs		Unobservable inputs
	(In Thousands)
Financial assets:
VEBA investments:
Money market funds	$	21	$	21	$	—	$	—
Mutual funds	2,565		—		2,565		—
Total VEBA investments	2,586		21		2,565		—
Financial transmission rights	3,099		—		—		3,099
Total financial assets measured at fair value	$	5,685	$	21	$	2,565	$	3,099
Financial liabilities:
Other derivative liabilities	$	53	$	—	$	—	$	53
Total financial liabilities measured at fair value	$	53	$	—	$	—	$	53

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:
VEBA investments:
Money market funds	$	10	$	10	$	—	$	—
Mutual funds	2,581		—		2,581		—
Total VEBA investments	2,591		10		2,581		—
Financial transmission rights	2,532		—		—		2,532
Total financial assets measured at fair value	$	5,123	$	10	$	2,581	$	2,532
Financial liabilities:
Other derivative liabilities	$	78	$	—	$	—	$	78
Total financial liabilities measured at fair value	$	78	$	—	$	—	$	78

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):



	Reconciliation of Financial Instruments Classified as Level 3
	(In Thousands)
Balance at January 1, 2017	$	4,293
Unrealized gain recognized in earnings	23
Issuances	9,647
Settlements	(11,509		)
Balance at December 31, 2017	$	2,454
Unrealized gain recognized in earnings	24
Issuances	9,295
Settlements	(8,727		)
Balance at December 31, 2018	$	3,046

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 using market based rates 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. In 2018, IPL recorded additional ARO liabilities of $54.8 million to reflect revisions to cash flow and timing estimates due to accelerated ash pond closure dates and revised estimated closure costs after review of updates to the CCR rule and revised estimated costs associated with IPL's coal storage areas. As of December 31, 2018 and 2017, ARO liabilities were $129.5 million and $79.5 million, respectively. See Note 3, “Property, Plant and Equipment - ARO” 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, 2018				December 31, 2017
	Face Value		Fair Value		Face Value		Fair Value
	(In Thousands)
Fixed-rate	$	2,523,800	$	2,649,265	$	2,418,800	$	2,655,012
Variable-rate	155,000		155,000		238,000		238,000
Total indebtedness	$	2,678,800	$	2,804,265	$	2,656,800	$	2,893,012

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


•	unamortized deferred financing costs of $23.0 million and $24.4 million at December 31, 2018 and 2017, respectively.


•	unamortized discounts of $6.7 million and $6.9 million at December 31, 2018 and 2017, respectively.

5. REGULATORY ASSETS AND LIABILITIES

Regulatory assets represent deferred costs or credits that have been included as allowable costs or credits for ratemaking purposes. IPL has recorded regulatory assets or liabilities relating to certain costs or credits as authorized by the IURC or established regulatory practices in accordance with ASC 980. IPL is amortizing non tax-related regulatory assets to expense over periods ranging from 1 to 28 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:



	2018		2017		Recovery Period
	(In Thousands)
Regulatory Assets
Current:
Undercollections of rate riders	$	13,217	$	22,990	Approximately 1 year⁽¹⁾
Costs being recovered through basic rates and charges	15,182		12,351		Approximately 1 year⁽¹⁾
Total current regulatory assets	28,399		35,341
Long-term:
Unrecognized pension and other
postretirement benefit plan costs	195,559		205,573		Various⁽²⁾
Income taxes recoverable from customers	103		—		Various
Deferred MISO costs	88,052		101,562		Through 2026⁽¹⁾
Unamortized Petersburg Unit 4 carrying
charges and certain other costs	8,084		9,139		Through 2026⁽¹⁾⁽³⁾
Unamortized reacquisition premium on debt	19,714		21,109		Over remaining life of debt
Environmental projects	81,204		40,434		Through 2046⁽¹⁾⁽³⁾
Other miscellaneous	2,361		1,087		Various⁽⁴⁾
Total long-term regulatory assets	395,077		378,904
Total regulatory assets	$	423,476	$	414,245
Regulatory Liabilities
Current:
Overcollections and other credits being passed
to customers through rate riders	$	47,925	$	—	Approximately 1 year⁽¹⁾
FTRs	3,099		2,532		Approximately 1 year⁽¹⁾
Total current regulatory liabilities	51,024		2,532
Long-term:
ARO and accrued asset removal costs	707,662		696,973		Not applicable
Income taxes payable to customers through rates	141,058		154,461		Various
Long-term portion of credits being passed to customers
through rate riders	21,341		—		Through 2021
Other miscellaneous	194		320		To be determined
Total long-term regulatory liabilities	870,255		851,754
Total regulatory liabilities	$	921,279	$	854,286


(1)	Recovered (credited) per specific rate orders


(2)	IPL receives a return on its discretionary funding


(3)	Recovered with a current return

(4) The majority of these costs are being recovered in basic rates and charges through 2026. For the remainder, recovery is probable, but the

timing is not yet determined.

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.

On December 22, 2017, the U.S. federal government enacted the TCJA, which, among other things, reduced 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 impact of the reduction of the income tax rate on deferred income taxes was utilized in the 2018 Base Rate Order to reduce jurisdictional retail rates. Accordingly, we have a net regulatory deferred income tax liability of $141.1 million and $154.5 million as of December 31, 2018 and 2017, respectively.

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. These costs are being recovered per specific rate order. See Note 2, “Regulatory Matters.”

Environmental Costs

These consist of various costs incurred to comply with environmental regulations. These costs were approved for recovery either through IPL's ECCRA proceedings or in the 2018 Base Rate Order. Amortization periods vary, but all costs should be recovered by 2046.

ARO and Accrued Asset Removal Costs

In accordance with ASC 410 and ASC 980, IPL recognizes the amount collected in customer rates for costs of removal that do not have an associated legal retirement obligation as a deferred regulatory liability. This amount is net of the portion of legal ARO costs that is also currently being recovered in rates.

6. EQUITY

Paid In Capital and Capital Stock

On March 1, 2016, IPALCO issued and sold 7,403,213 shares of IPALCO’s common stock to CDPQ for $134.3 million under the Subscription Agreement. After completion of this transaction, CDPQ’s direct (approximately 17.65%) and indirect (approximately 12.35%) interest in IPALCO was 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 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, 2018 and as of the filing of this report, IPL was in compliance with all covenants and no event of default existed.

During the years ended December 31, 2018, 2017 and 2016, IPALCO paid dividends to its shareholders totaling $130.2 million, $105.1 million and $123.0 million, respectively.

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, 2018, 2017 and 2016, 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, 2018, 2017 and 2016, preferred stock consisted of the following:



	December 31, 2018			December 31,
	Shares Outstanding	Call Price		2018		2017		2016
	Shares Outstanding	Call Price		Par Value, plus premium, if applicable
				(In Thousands)
Cumulative $100 par value,
authorized 2,000,000 shares
4% Series	47,611	$	118.00	$	5,410	$	5,410	$	5,410
4.2% Series	19,331	$	103.00	1,933		1,933		1,933
4.6% Series	2,481	$	103.00	248		248		248
4.8% Series	21,930	$	101.00	2,193		2,193		2,193
5.65% Series	500,000	$	100.00	50,000		50,000		50,000
Total cumulative preferred stock	591,353			$	59,784	$	59,784	$	59,784

7. DEBT

Long-Term Debt

The following table presents our long-term debt:



		December 31,
Series	Due	2018			2017
		(In Thousands)
IPL first mortgage bonds:
3.875% ⁽¹⁾	August 2021	$	55,000		$	55,000
3.875% ⁽¹⁾	August 2021	40,000			40,000
3.125% ⁽¹⁾	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
4.875%	November 2048	105,000			—
Unamortized discount – net		(6,272		)	(6,353		)
Deferred financing costs		(17,115		)	(16,168		)
Total IPL first mortgage bonds		1,690,413			1,586,279
IPL unsecured debt:
Variable ⁽²⁾	December 2020	30,000			30,000
Variable ⁽²⁾	December 2020	60,000			60,000
Deferred financing costs		(229		)	(344		)
Total IPL unsecured debt		89,771			89,656
Total long-term debt – IPL		1,780,184			1,675,935
Long-term debt – IPALCO:
Term Loan	July 2020	65,000			—
3.45% Senior Secured Notes	July 2020	405,000			405,000
3.70% Senior Secured Notes	September 2024	405,000			405,000
Unamortized discount – net		(424		)	(534		)
Deferred financing costs		(5,696		)	(7,863		)
Total long-term debt – IPALCO		868,880			801,603
Total consolidated IPALCO long-term debt		2,649,064			2,477,538
Less: current portion of long-term debt		—			—
Net consolidated IPALCO long-term debt		$	2,649,064		$	2,477,538


(1)	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.


(2)	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.

Debt Maturities

Maturities on long-term indebtedness subsequent to December 31, 2018, are as follows:



Year	Amount
	(In Thousands)
2019	$	—
2020	560,000
2021	95,000
2022	—
2023	—
Thereafter	2,023,800
Total	$	2,678,800

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 $1,713.8 million as of December 31, 2018. 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, 2018.

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%.

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

In November 2018, IPL issued $105 million aggregate principal amount of first mortgage bonds, 4.875% Series, due November 2048, pursuant to Rule 144A and Regulation S under the Securities Act. Net proceeds from this offering were approximately $103.5 million, after deducting the initial purchasers’ discounts and fees and expenses for the offering. The net proceeds from this offering were used to repay amounts due under IPL's Credit Agreement and for general corporate purposes.

IPALCO Term Loan

On October 31, 2018, IPALCO closed on a new Term Loan consisting of a $65 million credit facility maturing July 1, 2020. The Term Loan is variable rate and is secured by IPALCO’s pledge of all the outstanding common stock of IPL. The lien on the pledged shares is shared equally and ratably with IPALCO’ existing senior secured notes. The Term Loan proceeds were used to repay amounts under IPL's Credit Agreement and for general corporate purposes.

IPALCO’s Senior Secured Notes

In August 2017, IPALCO completed the sale of the $405 million 2024 IPALCO Notes pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended. The 2024 IPALCO Notes were issued pursuant to an Indenture dated August 22, 2017, by and between IPALCO and U.S. Bank, National Association, as trustee. The 2024 IPALCO Notes were priced to the public at 99.901% of the principal amount. Net proceeds to IPALCO were approximately $399.3 million after deducting underwriting costs and estimated offering expenses. These costs are being amortized to the maturity date using the effective interest method. We used the net proceeds from this offering, together with cash on hand, to redeem the $400 million 2018 IPALCO Notes on September 21, 2017, and to pay certain related fees, expenses and make-whole premiums. A loss on early extinguishment of debt of $8.9 million for the 2018 IPALCO Notes is included as a separate line item within “Other Income/(Expense), Net” 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 Term Loan. 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 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 support working capital; and (iii) 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, 2018 and 2017, IPL had $0.0 million and $148.0 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 26, 2020. In December 2018, IPL received an order from the IURC granting IPL authority through December 31, 2021 to, among other things, issue up to $350 million in aggregate principal amount of long-term debt and refinance up to $185.0 million in existing indebtedness, all of which authority remains available under the order as of December 31, 2018. 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, 2018. 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, 2018. 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 Agreement, refinance existing debt and issue new debt approved by the IURC and issue certain other indebtedness.

Credit Ratings

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.

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. IPALCO made tax sharing payments to AES of $28.3 million, $65.1 million and $28.8 million in 2018, 2017 and 2016 respectively.

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 5.875% for the calendar year 2018, 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 5.625% for 2019.

In tax years prior to 2018, Internal Revenue Code Section 199 permitted 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 tax years 2017 and 2016 was $3.9 million and $2.9 million, respectively. Due to the recently enacted TCJA (as described below), the 2017 tax year was 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. Notable items impacting the effective tax rate for the 2018 tax year related to the TCJA include a rate reduction in the corporate tax rate to 21% from 35% and an increase in the estimated flow-through depreciation partially offset by the repeal of the manufacturer’s production deduction.

In 2017, 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 reflected the income tax effects of U.S. tax reform for which the accounting was complete and provisional amounts for those impacts for which the accounting under ASC 740 was incomplete, but a reasonable estimate could be determined.

The Company has completed its calculation of the impact of the TCJA in its income tax provision during the year ended December 31, 2018 in accordance with its understanding of the TCJA and guidance available as of the date of this filing, and as a result recognized $0.0 million and $0.2 million of discrete tax expense in the fourth quarters of 2018 and 2017, respectively.

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 $7.7 million and $215.5 million in 2018 and 2017, respectively, was recorded as a regulatory liability, which was a non-cash adjustment.

Income Tax Provision

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



	2018			2017			2016
	(In Thousands)
Components of income tax expense:
Current income taxes:
Federal	$	20,341		$	42,542		$	19,925
State	8,843			9,916			7,273
Total current income taxes	29,184			52,458			27,198
Deferred income taxes:
Federal	(15,150		)	(1,720		)	32,883
State	326			(332		)	2,630
Total deferred income taxes	(14,824		)	(2,052		)	35,513
Net amortization of investment credit	(911		)	(1,455		)	(1,501		)
Total income tax expense	$	13,449		$	48,951		$	61,210

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:



	2018		2017		2016
Federal statutory tax rate	21.0	%	35.0	%	35.0	%
State income tax, net of federal tax benefit	5.6	%	4.1	%	4.1	%
Amortization of investment tax credits	(0.6	)%	(0.9	)%	(0.8	)%
Research and development credit	(1.9	)%	—	%	—	%
Preferred dividends of subsidiary	0.3	%	0.7	%	0.6	%
Depreciation flow through and amortization	(15.6	)%	(0.1	)%	(0.5	)%
Additional funds used during construction - equity	0.3	%	(4.1	)%	(3.8	)%
Manufacturers’ Production Deduction (Sec. 199)	—	%	(2.5	)%	(1.3	)%
Other – net	—	%	(1.2	)%	(1.5	)%
Effective tax rate	9.1	%	31.0	%	31.8	%

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, 2018 and 2017, are as follows:



	2018		2017
	(In Thousands)
Deferred tax liabilities:
Relating to utility property, net	$	378,460	$	475,911
Regulatory assets recoverable through future rates	67,721		66,661
Other	12,161		6,654
Total deferred tax liabilities	458,342		549,226
Deferred tax assets:
Investment tax credit	11		240
Regulatory liabilities including ARO	184,413		278,529
Employee benefit plans	8,335		18,564
Other	12,498		6,636
Total deferred tax assets	205,257		303,969
Deferred income taxes – net	$	253,085	$	245,257

Uncertain Tax Positions

The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2018, 2017 and 2016:



	2018		2017			2016
	(In Thousands)
Unrecognized tax benefits at January 1	$	7,049	$	6,634		$	7,147
Gross increases – current period tax positions	—		470			724
Gross decreases – prior period tax positions	7		(55		)	(1,237		)
Unrecognized tax benefits at December 31	$	7,056	$	7,049		$	6,634

The unrecognized tax benefits at December 31, 2018 represent tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, other than interest and penalties, the timing of the deductions will not affect the annual effective tax rate but would accelerate the tax payments to an earlier period.

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

9. BENEFIT PLANS

Defined Contribution Plans

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

The Thrift Plan

Approximately 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 $3.3 million, $3.4 million and $3.1 million for 2018, 2017 and 2016, respectively.

The RSP

Approximately 15% of IPL’s active employees are covered by the RSP, a qualified defined contribution plan containing a match, nondiscretionary and 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 eligible compensation. Each participant’s contribution is matched in amounts up to, but not exceeding, 5% of the participant’s eligible compensation. Starting in 2017, the RSP also includes a 4% nondiscretionary contribution based as a percentage of each participant's eligible compensation. Finally, the RSP included a profit sharing component through 2016 whereby IPL contributed a percentage of each employee’s annual salary into the plan on a pre-tax basis. The profit sharing percentage was determined by the AES Board of Directors on an annual basis. Employer contributions (by IPL) relating to the RSP were $1.7 million, $1.8 million and $1.0 million for 2018, 2017 and 2016, respectively.

Defined Benefit Plans

Approximately 80% of IPL’s active employees are covered by the qualified Defined Benefit Pension Plan; while approximately 5% 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, 2018 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 156 active employees and 10 retirees (including spouses) were receiving such benefits or entitled to future benefits as of January 1, 2018. The plan is unfunded. These postretirement health care benefits and the related unfunded obligation of $6.7 million and $7.0 million at December 31, 2018 and 2017, respectively, were not material to the consolidated financial statements in the periods covered by this report.

The following table presents information relating to the Pension Plans:



	Pension benefits as of December 31,
	2018			2017
	(In Thousands)
Change in benefit obligation:
Projected benefit obligation at January 1	$	782,108		$	731,825
Service cost	8,450			7,344
Interest cost	25,220			25,305
Actuarial (gain)/loss	(62,303		)	52,451
Amendments (primarily increases in pension bands)	5,446			900
Settlements	—			(266		)
Curtailments⁽¹⁾	450			—
Benefits paid	(62,143		)	(35,451		)
Projected benefit obligation at December 31	697,228			782,108
Change in plan assets:
Fair value of plan assets at January 1	738,947			674,430
Actual return on plan assets	(22,404		)	93,022
Employer contributions	30,085			7,212
Settlements	—			(266		)
Benefits paid	(62,143		)	(35,451		)
Fair value of plan assets at December 31	684,485			738,947
Unfunded status	$	(12,743	)	$	(43,161	)
Amounts recognized in the statement of financial position:
Noncurrent liabilities	$	(12,743	)	$	(43,161	)
Net amount recognized at end of year	$	(12,743	)	$	(43,161	)
Sources of change in regulatory assets⁽²⁾:
Prior service cost arising during period	$	5,446		$	900
Net loss arising during period	902			4,101
Amortization of prior service cost	(4,618		)	(4,240		)
Amortization of loss	(11,403		)	(13,341		)
Total recognized in regulatory assets	$	(9,673	)	$	(12,580	)
Amounts included in regulatory assets:
Net loss	$	183,306		$	193,807
Prior service cost	18,146			17,318
Total amounts included in regulatory assets	$	201,452		$	211,125


(1)	As a result of the announced AES restructuring in the first quarter of 2018, we recognized a plan curtailment of $1.2 million in the first quarter of 2018.

(2)

Amounts that would otherwise be charged/credited to Accumulated Other Comprehensive Income or Loss upon application of ASC 715, “Compensation – Retirement Benefits,” are recorded as a regulatory asset or liability because IPL has historically recovered and currently recovers pension and other postretirement benefit expenses in rates. These are unrecognized amounts not yet recognized as components of net periodic benefit costs.

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



	Pension benefits as of December 31,
	2018		2017
	(In Thousands)
Benefit obligation	$	697,228	$	782,108
Plan assets	684,485		738,947
Benefit obligation in excess of plan assets	$	12,743	$	43,161

IPL’s total benefit obligation in excess of plan assets was $12.7 million as of December 31, 2018 ($11.6 million Defined Benefit Pension Plan and $1.1 million Supplemental Retirement Plan).

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



	Pension benefits as of December 31,
	2018		2017
	(In Thousands)
Accumulated benefit obligation	$	687,136	$	769,678
Plan assets	684,485		738,947
Accumulated benefit obligation in excess of plan assets	$	2,651	$	30,731

IPL’s total accumulated benefit obligation in excess of plan assets was $2.7 million as of December 31, 2018 ($1.6 million Defined Benefit Pension Plan and $1.1 million Supplemental Retirement Plan).

Significant Gains and Losses Related to Changes in the Benefit Obligation for the Period

As shown in the table above, an actuarial gain of $62.3 million decreased the benefit obligation for the year ended December 31, 2018 and an actuarial loss of $52.5 million increased the benefit obligation for the year ended December 31, 2017. The actuarial gain in 2018 was primarily due to an increase in the discount rate, while the actuarial loss in 2017 was primarily due to a decrease in the discount rate.

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 2018 net actuarial loss of $0.9 million recognized in regulatory assets is comprised of two parts: (1) a $63.2 million pension asset actuarial loss primarily due to lower than expected return on assets; partially offset by (2) a $62.3 million pension liability actuarial gain primarily due to an increase in the discount rate used to value pension liabilities. The unrecognized net loss of $183.3 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 2018, the accumulated net loss declined due to higher discount rates used to value pension liabilities; which was partially offset by a combination of lower than expected return on pension assets, as well as the year 2018 amortization of accumulated loss. The unrecognized net loss, to the extent that it exceeds 10% of the greater of the benefit obligation or the assets, will be amortized and included as a component of net periodic benefit cost in future years. The amortization period is approximately 10.17 years based on estimated demographic data as of December 31, 2018. The projected benefit obligation of $697.2 million less the fair value of assets of $684.5 million results in an unfunded status of $12.7 million at December 31, 2018.



	Pension benefits for years ended December 31,
	2018			2017			2016
	(In Thousands)
Components of net periodic benefit cost:
Service cost	$	8,450		$	7,344		$	7,018
Interest cost	25,220			25,305			25,815
Expected return on plan assets	(40,801		)	(44,672		)	(43,492		)
Amortization of prior service cost	3,837			4,240			5,183
Recognized actuarial loss	11,403			13,195			13,896
Recognized settlement loss	1,230			146			—
Total pension cost	9,339			5,558			8,420
Less: amounts capitalized	1,223			845			1,187
Amount charged to expense	$	8,116		$	4,713		$	7,233
Rates relevant to each year’s expense calculations:
Discount rate – defined benefit pension plan	3.67		%	4.29		%	4.42		%
Discount rate – supplemental retirement plan	3.60		%	4.00		%	4.19		%
Expected return on defined benefit pension plan assets	5.45		%	6.75		%	6.75		%
Expected return on supplemental retirement plan assets	5.45		%	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 2018, pension expense was determined using an assumed long-term rate of return on plan assets of 5.45%. As of the December 31, 2018 measurement date, IPL increased the discount rate from 3.67% to 4.36% for the Defined Benefit Pension Plan and increased the discount rate from 3.60% to 4.24% for the Supplemental Retirement Plan. The discount rate assumptions affect the pension expense determined for 2019. In addition, IPL reduced the expected long-term rate of return on plan assets from 5.45% to 4.50% effective January 1, 2019. The expected long-term rate of return assumption affects the pension expense determined for 2019. The effect on 2019 total pension expense of a 25 basis point increase and decrease in the assumed discount rate is $(1.2) million and $1.2 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, 2018. 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.

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 reduced pension costs in future periods. Pension costs are determined as of the plans' measurement date of December 31, 2018. Pension costs are determined for the following year based on the market value of pension plan assets, expected employer contributions, a discount rate used to determine the projected benefit obligation and the expected long-term rate of return on plan assets.

Fair value is defined under ASC 820 as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). The fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

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 Plans’ 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 Plans’ investments have quoted market prices and are categorized as Level 1 in the fair value hierarchy.


•	The Plans’ 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 Plans’ 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 Plans’. 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 Plans’ 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 Plans’ trust. Finally, we have the Plans’ 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 2018:



Asset Category:	Target Allocations
Equity Securities	10%
Debt Securities	90%



	Fair Value Measurements at
	December 31, 2018
	(in thousands)
			Quoted Prices in Active Markets for Identical Assets		Significant Observable Inputs
Asset Category	Total		(Level 1)		(Level 2)		%
Short-term investments	$	3,597	$	3,597	$	—	1	%
Mutual funds:
U.S. equities	1,906		1,906		—		—	%
International equities	52,354		52,354		—		8	%
Fixed income	497,323		497,323		—		72	%
Fixed income securities:
U.S. Treasury securities	129,305		129,305		—		19	%
Total	$	684,485	$	684,485	$	—	100	%



	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		—		80	%
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	%

Pension Funding

We contributed $30.1 million, $7.2 million, and $16.0 million to the Pension Plans in 2018, 2017 and 2016, 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 114%. In general, IPL must contribute the normal service cost earned by active participants during the plan year; however, this amount can be offset by any surplus or credit balance carried by the Pension Plan. The normal cost is expected to be approximately $8.3 million in 2019 (including $2.8 million for plan expenses), which is expected to be fully offset by the surplus amount. Each year thereafter, if the Pension Plans’ underfunding increases to more than the present value of the remaining annual installments, the excess is separately amortized over a seven-year period. IPL does not expect to make an employer contribution for the calendar year 2019. 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, 2018, 2017 and 2016 were $62.1 million, $35.5 million and $34.6 million, respectively. Expected benefit payments are expected to be paid out of the Pension Plans as follows:



Year	Pension Benefits
	(In Thousands)
2019	$	39,780
2020	41,400
2021	42,956
2022	44,051
2023	44,659
2024 through 2028	230,608

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 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. 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 and other CAA NOVs

In October 2009, IPL received a NOV and Finding of Violation from the EPA pursuant to the CAA Section 113(a). The NOV alleges violations of the CAA at IPL’s three primarily coal-fired electric generating facilities at the time, dating back to 1986. The alleged violations primarily pertain to the PSD and nonattainment New Source Review requirements under the CAA. In addition, on October 1, 2015, IPL received a NOV from the EPA pursuant to CAA Section 113(a) alleging violations of the CAA, the Indiana SIP, and the Title V operating permit related to alleged particulate matter and opacity violations at IPL Petersburg Unit 3. Also, on February 5, 2016, the EPA issued a NOV pursuant to CAA Section 113(a) alleging violations of New Source Review and other CAA regulations, the Indiana SIP, and the Title V operating permit at Petersburg Generating Station. Since receiving the letters, IPL management has met with the EPA staff regarding possible resolutions of the NOVs. Settlements and litigated outcomes of similar New Source Review cases have required companies to pay civil penalties, install additional pollution control technology on coal-fired electric generating units, retire existing generating units, and invest in additional environmental projects. A similar outcome in these cases could have a material impact on our business. At this time, we cannot determine whether these NOVs could have a material impact on our business, financial condition and 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. 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 $3.1 million in 2018, 2017 and 2016, respectively, and is recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations. As of December 31, 2018 and 2017, we had prepaid approximately $1.6 million and $1.9 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 $21.5 million, $24.9 million, and $23.2 million in 2018, 2017 and 2016, respectively, and is recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations. We had no prepaids for coverage under this plan as of December 31, 2018 and 2017, 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 $13.8 million and $14.7 million as of December 31, 2018 and 2017, respectively, which is recorded in “Prepayments and other current assets” on the accompanying Consolidated Balance Sheets.

Long-term Compensation Plan

During 2018, 2017 and 2016, 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. Restricted stock units vest ratably over a three-year period. The performance units payable in cash vest at the end of the three-year performance period and are subject to certain AES performance criteria. Total deferred compensation expense recorded during 2018, 2017 and 2016 was $0.5 million, $0.8 million and $0.9

million, respectively, and was included in “Operating expenses - Operation and maintenance” on IPALCO’s Consolidated Statements of Operations. The value of these benefits is being recognized over the 36 month vesting period and a portion is recorded as miscellaneous deferred credits with the remainder recorded as “Paid in capital” on IPALCO’s Consolidated Balance Sheets in accordance with ASC 718 “Compensation – Stock Compensation.”

See also Note 9, “Benefit Plans” to the Financial Statements for a description of benefits awarded to IPL employees by AES under the RSP.

Service Company

Total costs incurred by the Service Company on behalf of IPALCO were $44.5 million, $34.4 million and $27.4 million during 2018, 2017 and 2016, respectively. Total costs incurred by IPALCO on behalf of the Service Company during 2018, 2017 and 2016 were $10.1 million, $10.7 million and $9.2 million, respectively. These costs were included in “Operating expenses - Operation and maintenance” on IPALCO’s Consolidated Statements of Operations. IPALCO had a payable balance with the Service Company of $3.8 million as of December 31, 2018, which is recorded in “Accounts payable” on the accompanying Consolidated Balance Sheets. IPALCO had a prepaid balance with the Service Company of $3.1 million as of December 31, 2017, which is recorded in “Prepayments and other current assets” on the accompanying Consolidated Balance Sheets.

CDPQ

Please refer to Note 6, “Equity – Equity Transactions” for further details.

Other

A member of the AES Board of Directors is also a member of the Supervisory Board of a third party vendor that IPL engaged in 2014 for certain construction projects. As the transactions with this vendor related to capital projects, there was no direct impact on the Consolidated Statements of Operations for the periods presented. Over the life of the project, IPL had total net charges from this vendor of $474.9 million. This vendor completed its service in 2018.

Additionally, transactions with various other related parties were $5.7 million, $2.4 million and $3.9 million during 2018, 2017 and 2016, respectively. These expenses were primarily recorded in “Operating expenses - Operation and maintenance” 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 "All Other" non-utility category primarily includes the Term Loan, 2020 IPALCO Notes and 2024 IPALCO Notes; approximately $6.4 million and $18.3 million of cash and cash equivalents, as of December 31, 2018 and 2017, respectively; long-term investments of $4.0 million and $5.1 million as of December 31, 2018 and 2017, respectively; 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, 2018 and 2017. The accounting policies of the identified segment are consistent with those policies and procedures described in the summary of significant accounting policies.

The following table provides information about IPALCO’s business segments (in thousands):



	2018							2017							2016
	Utility		All Other			Total		Utility		All Other			Total		Utility		All Other			Total
Revenues	$	1,450,505	$	—		$	1,450,505	$	1,349,588	$	—		$	1,349,588	$	1,347,430	$	—		$	1,347,430
Depreciation and amortization	$	232,332	$	—		$	232,332	$	208,451	$	—		$	208,451	$	218,449	$	—		$	218,449
Interest expense	$	64,472	$	31,037		$	95,509	$	65,340	$	35,790		$	101,130	$	58,682	$	35,920		$	94,602
Earnings from operations before income tax	$	178,953	$	(31,479	)	$	147,474	$	202,106	$	(44,362	)	$	157,744	$	229,147	$	(36,877	)	$	192,270
Capital expenditures	$	235,764	$	—		$	235,764	$	228,861	$	—		$	228,861	$	607,716	$	—		$	607,716

	As of December 31, 2018							As of December 31, 2017							As of December 31, 2016
Total assets	$	4,851,712	$	10,341		$	4,862,053	$	4,719,547	$	21,014		$	4,740,561	$	4,686,764	$	15,517		$	4,702,281

13. REVENUE

Revenue is primarily earned from retail and wholesale electricity sales and electricity transmission and distribution delivery services. Revenue is recognized upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Revenue is recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities.

Retail revenues - IPL energy sales to utility customers are based on the reading of meters at the customer’s location that occurs on a systematic basis throughout the month. IPL sells electricity directly to end-users, such as homes and businesses, and bills customers directly. Retail revenues have a single performance obligation, as the promise to transfer energy and other distribution and/or transmission services are not separately identifiable from other promises in the contracts and, therefore, are not distinct. Additionally, as the performance obligation is satisfied over time as energy is delivered, and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series.

In exchange for the exclusive right to sell or distribute electricity in our service area, IPL is subject to rate regulation by federal and state regulators. This regulation sets the framework for the prices (“tariffs”) that IPL is allowed to charge customers for electric services. Since tariffs are approved by the regulator, the price that IPL has the right to bill corresponds directly with the value to the customer of IPL’s performance completed in each period. Therefore, revenue under these contracts is recognized using an output method measured by the MWhs delivered each month at the approved tariff. Customer payments are typically due on a monthly basis.

Wholesale revenues - Power produced at the generation stations in excess of our retail load is sold into the MISO market. Such sales are made at either the day-ahead or real-time hourly market price, and these sales are classified as wholesale revenues. We sell to and purchase power from MISO, and such sales and purchases are settled and accounted for on a net hourly basis.

In the MISO market, wholesale revenue is recorded at the spot price based on the quantities of MWh delivered in each hour during each month. As a member of MISO, we are obligated to declare the availability of our energy production into the wholesale energy market, but we are not obligated to commit our previously declared availability. As such, contract terms end as the energy for each day is delivered to the market in the case of the day-ahead market and for each hour in the case of the real-time market.

Miscellaneous revenues - Miscellaneous revenues are mainly comprised of MISO transmission revenues. MISO transmission revenues are earned when IPL’s power lines are used in transmission of energy by power producers other than IPL. As IPL owns and operates transmission lines in central and southern Indiana, demand charges collected from network customers by MISO are allocated to the appropriate transmission owners (including IPL) and recognized as transmission revenues. Capacity revenues are also included in miscellaneous revenues, but these were not material for the period presented.

operator has the right to bill corresponds directly with the value to the customer of IPL’s performance completed in each period as the price paid is the transmission operators allocation of the tariff rate (as approved by the regulator) charged to network participants.

IPL’s revenue from contracts with customers was $1,428.9 million for the year ended December 31, 2018. The following table presents our revenue from contracts with customers and other revenue (in thousands):



	For the Year Ended,
	December 31, 2018
Retail Revenues
Retail revenue from contracts with customers	$	1,380,042
Other retail revenues ⁽¹⁾	16,423
Wholesale Revenues	38,789
Miscellaneous Revenues
Transmission and other revenue from contracts with customers	10,057
Other miscellaneous revenues ⁽²⁾	5,194
Total Revenues	$	1,450,505

(1) Other retail revenue represents alternative revenue programs not accounted for under ASC 606

(2) Other miscellaneous revenue includes lease and other miscellaneous revenues not accounted for under ASC 606

The balances of receivables from contracts with customers are $160.8 million and $155.7 million as of December 31, 2018 and January 1, 2018, respectively. Payment terms for all receivables from contracts with customers are typically within 30 days.

The Company has elected to apply the optional disclosure exemptions under ASC 606. Therefore, the Company has not included disclosure pertaining to revenue expected to be recognized in any future year related to remaining performance obligations, as we exclude contracts with an original length of one year or less, contracts for which we recognize revenue based on the amount we have the right to invoice for services performed, and contracts with variable consideration allocated entirely to a wholly unsatisfied performance obligation when the consideration relates specifically to our efforts to satisfy the performance obligation and depicts the amount to which we expect to be entitled.

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, 2018 and 2017, 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, 2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018 in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

/s/ Ernst & Young LLP

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

Indianapolis, Indiana

February 26, 2019



INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY
Consolidated Statements of Operations
For the Years Ended December 31, 2018, 2017 and 2016
(In Thousands)
	2018			2017			2016
REVENUES	$	1,450,505		$	1,349,588		$	1,347,430

COST OF REVENUES:
Fuel	331,701			281,542			276,171
Power purchased	164,542			189,847			170,466
Total cost of revenues	496,243			471,389			446,637

GROSS MARGIN	954,262			878,199			900,793

OPERATING EXPENSES:
Operations and maintenance	431,020			385,308			374,202
Depreciation and amortization	232,332			208,451			218,449
Taxes other than income taxes	53,941			44,628			45,306
Other operating expenses	105			30			—
Total operating expenses	717,398			638,417			637,957

OPERATING INCOME	236,864			239,782			262,836

OTHER INCOME/(EXPENSE), NET:
Allowance for equity funds used during construction	8,477			25,798			27,140
Interest expense	(64,472		)	(65,340		)	(58,682		)
Other income/(expense), net	(1,916		)	1,866			(2,148		)
Total other income/(expense), net	(57,911		)	(37,676		)	(33,690		)

EARNINGS FROM OPERATIONS BEFORE INCOME TAX	178,953			202,106			229,146

Less: income tax expense - net	21,590			65,591			72,701
NET INCOME	157,363			136,515			156,445

LESS: PREFERRED DIVIDEND REQUIREMENTS	3,213			3,213			3,213
NET INCOME APPLICABLE TO COMMON STOCK	$	154,150		$	133,302		$	153,232

See notes to consolidated financial statements.



INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY
Consolidated Balance Sheets
(In Thousands)
	December 31, 2018		December 31, 2017
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	26,834	$	12,342
Restricted cash	400		—
Accounts receivable, net	167,869		157,702
Inventories	99,669		96,017
Regulatory assets, current	28,399		35,341
Prepayments and other current assets	29,071		36,350
Total current assets	352,242		337,752
NON-CURRENT ASSETS:
Property, plant and equipment	6,201,078		5,399,851
Less: Accumulated depreciation	2,256,215		2,129,754
	3,944,863		3,270,097
Construction work in progress	111,723		711,396
Total net property, plant and equipment	4,056,586		3,981,493
OTHER NON-CURRENT ASSETS:
Intangible assets - net	40,848		16,036
Regulatory assets, non-current	395,077		378,904
Other non-current assets	6,959		5,362
Total other non-current assets	442,884		400,302
TOTAL ASSETS	$	4,851,712	$	4,719,547
LIABILITIES AND SHAREHOLDER'S EQUITY
CURRENT LIABILITIES:
Short-term and current portion of long-term debt (Note 7)	$	—	$	148,000
Accounts payable	135,144		125,162
Accrued taxes	21,325		18,145
Accrued interest	23,312		22,486
Customer deposits	32,700		31,306
Regulatory liabilities, current	51,024		2,532
Accrued and other current liabilities	41,984		37,138
Total current liabilities	305,489		384,769
NON-CURRENT LIABILITIES:
Long-term debt (Note 7)	1,780,184		1,675,935
Deferred income tax liabilities	252,729		244,812
Taxes payable	4,658		4,651
Regulatory liabilities, non-current	870,255		851,754
Accrued pension and other postretirement benefits	19,329		50,070
Asset retirement obligations	129,451		79,535
Other non-current liabilities	604		1,764
Total non-current liabilities	3,057,210		2,908,521
Total liabilities	3,362,699		3,293,290
COMMITMENTS AND CONTINGENCIES (Note 10)
SHAREHOLDER'S EQUITY:
Common stock	324,537		324,537
Paid in capital	664,513		599,157
Retained earnings	440,179		442,779
Total shareholder's equity	1,429,229		1,366,473
Cumulative preferred stock	59,784		59,784
Total shareholder's equity	1,489,013		1,426,257
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY	$	4,851,712	$	4,719,547

See notes to consolidated financial statements.



INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY
Consolidated Statements of Cash Flows
For the Years Ended December 31, 2018, 2017 and 2016
(In Thousands)
	2018			2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	157,363		$	136,515		$	156,445
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	232,332			208,451			218,449
Amortization of deferred financing costs and debt premium	2,011			2,199			2,200
Deferred income taxes and investment tax credit adjustments - net	(15,646		)	(3,441		)	11,165
Allowance for equity funds used during construction	(8,477		)	(25,798		)	(27,140		)
Change in certain assets and liabilities:
Accounts receivable	(10,167		)	(3,031		)	(30,022		)
Inventories	(3,652		)	(5,342		)	33,434
Accounts payable	4,080			(5,048		)	16,158
Accrued and other current liabilities	(9,655		)	(7,771		)	2,754
Accrued taxes	3,180			(785		)	1,218
Accrued interest	826			(245		)	1,627
Pension and other postretirement benefit expenses	(30,740		)	(14,069		)	(16,595		)
Short-term and long-term regulatory assets and liabilities	76,647			17,011			(38,026		)
Prepayments and other current assets	7,279			(4,938		)	(3,316		)
Other - net	582			2,257			3,076
Net cash provided by operating activities	405,963			295,965			331,427
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(224,335		)	(218,224		)	(592,243		)
Project development costs	(1,127		)	(1,729		)	(1,356		)
Cost of removal and regulatory recoverable ARO payments	(29,543		)	(16,802		)	(16,106		)
Other	—			(123		)	1,000
Net cash used in investing activities	(255,005		)	(236,878		)	(608,705		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt borrowings	100,000			202,500			298,000
Short-term debt repayments	(248,000		)	(129,150		)	(414,850		)
Long-term borrowings, net of discount	104,936			—			387,662
Retirement of long-term debt	—			—			(40,000		)
Dividends on common stock	(142,250		)	(132,516		)	(136,466		)
Dividends on preferred stock	(3,213		)	(3,213		)	(3,213		)
Equity contributions from IPALCO	65,000			—			213,014
Payments for financed capital expenditures	(11,429		)	(10,637		)	(15,473		)
Other	(1,110		)	(336		)	(4,641		)
Net cash (used in) provided by financing activities	(136,066		)	(73,352		)	284,033
Net change in cash, cash equivalents and restricted cash	14,892			(14,265		)	6,755
Cash, cash equivalents and restricted cash at beginning of period	12,342			26,607			19,852
Cash, cash equivalents and restricted cash at end of period	$	27,234		$	12,342		$	26,607

Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized)	$	61,310		$	63,031		$	54,350
Income taxes	33,750			87,000			57,900
Non-cash investing activities:
Accruals for capital expenditures	$	47,553		$	45,322		$	36,249

See notes to consolidated financial statements.



INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY
Consolidated Statements of Common Shareholder's Equity
For the Years Ended December 31, 2018, 2017 and 2016
(In Thousands)
	Common Stock		Paid in Capital		Retained Earnings			Total
Balance at January 1, 2016	$	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
Net income	—		—		157,363			157,363
Preferred stock dividends	—		—		(3,213		)	(3,213		)
Cash dividends declared on common stock	—		—		(156,750		)	(156,750		)
Contributions from IPALCO			65,000					65,000
Other	—		356		—			356
Balance at December 31, 2018	$	324,537	$	664,513	$	440,179		$	1,429,229

See notes to consolidated financial statements.

INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2018, 2017 and 2016

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 more than 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, uses natural gas and fuel oil to power combustion turbines. In addition, IPL operates a 20 MW battery energy storage unit at this location, which provides frequency response. The third station, Eagle Valley, is a newly constructed 671 MW CCGT natural gas plant. IPL took operational control and commenced commercial operations of this CCGT plant in April 2018. The fourth station, Georgetown, is a small peaking station that uses natural gas to power combustion turbines. As of December 31, 2018, IPL’s net electric generation capacity for winter is 3,667 MW and net summer capacity is 3,552 MW.

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 Corporation, which was dissolved in 2018 and was immaterial to the consolidated financial statements in the periods covered by this report. 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.

Financial Statement Presentation

During 2018, IPL adopted a change in presentation on its Consolidated Balance Sheets and Consolidated Statements of Operations from a utility format to a traditional format. These changes revised the order of certain balance sheet line items and resulted in the movement of certain balances within the Consolidated Statements of Operations and Consolidated Balance Sheets, but did not result in any material changes to the classification of any such amounts between line items or have any impact on net assets or net income. Certain amounts from prior periods have been reclassified to conform to the current period presentation.

Use of Management Estimates

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.

Cash, Cash Equivalents and Restricted Cash



	As of December 31,
	2018		2017
	(In Thousands)
Cash, cash equivalents and restricted cash
Cash and cash equivalents	$	26,834	$	12,342
Restricted cash	400		—
Total cash, cash equivalents and restricted cash	$	27,234	$	12,342

Revenues and Accounts Receivable

Revenues related to the sale of energy are generally recognized when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to certain customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is accrued. In making its estimates of unbilled revenue, IPL uses complex models that consider various factors including daily generation volumes; known amounts of energy usage by nearly all residential, small commercial and industrial customers; estimated line losses; and estimated customer rates based on prior period billings. Given the use of these models, and that customers are billed on a monthly cycle, we believe it is unlikely that materially different results will occur in future periods when revenue is billed. 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 “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations was $6.0 million, $5.9 million and $4.1 million for the years ended December 31, 2018, 2017 and 2016, respectively.

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. See Note 13, "Revenue" for additional information of MISO sales and other revenue streams.

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The following table summarizes our accounts receivable balances at December 31:



	As of December 31,
	2018			2017
	(In Thousands)
Accounts receivable, net
Customer receivables	$	91,426		$	94,168
Unbilled revenue	68,893			61,599
Amounts due from related parties	6,030			125
Other	4,341			4,640
Provision for uncollectible accounts	(2,821		)	(2,830		)
Total accounts receivable, net	$	167,869		$	157,702

Inventories

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 net realizable value, using the average cost. The following table summarizes our inventories balances at December 31:



	As of December 31,
	2018		2017
	(In Thousands)
Inventories
Fuel	$	32,457	$	32,393
Materials and supplies	67,212		63,624
Total inventories	$	99,669	$	96,017

Utility Plant and Depreciation

Allowance For Funds Used During Construction

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 $4.1 billion and $4.0 billion as of December 31, 2018 and 2017, respectively. IPL does not believe any of these assets are currently impaired. In making this assessment, IPL

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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 $129.7 million and $99.4 million and its corresponding accumulated amortization of $88.8 million and $83.4 million, as of December 31, 2018 and 2017, respectively. Amortization expense was $5.5 million, $4.3 million and $5.9 million for the years ended December 31, 2018, 2017 and 2016, respectively. The estimated amortization expense of this capitalized software is $30.2 million over the next 5 years ($5.7 million in 2019, $6.9 million in 2020, $6.9 million in 2021, $6.9 million in 2022 and $3.8 million in 2023).

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, 2018 and 2017, total loss contingencies accrued were $4.6 million and $4.1 million, respectively, which were included in “Accrued and Other Current Liabilities” on the accompanying Consolidated Balance Sheets.

Concentrations of Risk

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.

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.

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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.

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New Accounting Pronouncements Adopted in 2018

The following table provides a brief description of recent accounting pronouncements that had an impact on IPL's consolidated financial statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or did not have a material impact on IPL's consolidated financial statements.



New Accounting Standards Adopted
ASU Number and Name	Description	Date of Adoption	Effect on the financial statements upon adoption
2018-15, Intangibles— Goodwill and Other— Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract	This standard aligns the accounting for implementation costs incurred for a cloud computing arrangement that is a service with the requirement for capitalizing implementation costs associated with developing or obtaining internal-use software. Transition method: retrospective or prospective.	October 1, 2018	IPL elected to early-adopt this standard on a prospective basis, effective for fiscal year 2018. The adoption of this standard did not have a material impact on the financial statements.
2018-14, Compensation— Retirement Benefits— Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework	This standard modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. Transition method: retrospective.	Early adoption elected, January 1, 2018.	Impact limited to changes in financial statement disclosures.
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 costs 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 and prospective for the change in capitalization.	January 1, 2018	The adoption of this standard resulted in a $(2.0) million and $1.0 million reclassification of non-service pension costs (credits) from Operating Expenses - Operations and maintenance to Other income/(expense), net for 2017 and 2016, respectively.
2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force)	This standard requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. Transition method: retrospective.	January 1, 2018	No material impact upon adoption of the standard.
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	See impact upon adoption of the standard below.

Adoption of ASC Topic 606, “Revenue from Contracts with Customers”

On January 1, 2018, IPL adopted ASU 2014-09, “Revenue from Contracts with Customers”, and its subsequent corresponding updates (“ASC 606”). Under this standard, 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. IPL applied the modified retrospective method of adoption to those contracts that were not completed as of January 1, 2018. Results for reporting periods beginning January 1, 2018 are presented under ASC 606, while prior period amounts were not adjusted and continue to be reported in accordance with our historic accounting under the previous revenue recognition standard. For contracts that were modified before January 1, 2018, IPL reflected the aggregate effect of all modifications when identifying the satisfied and unsatisfied performance obligations, determining the transaction price and allocating the transaction price.

There was no cumulative effect to IPL's January 1, 2018 Consolidated Balance Sheet resulting from the adoption of ASC 606.

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New Accounting Pronouncements Issued But Not Yet Effective

The following table provides a brief description of recent accounting pronouncements that could have a material impact on IPL's consolidated financial statements once adopted. Accounting pronouncements not listed below were assessed and determined to be either not applicable or are expected to have no material impact on IPL's consolidated financial statements.



New Accounting Standards Issued But Not Yet Effective
ASU Number and Name	Description	Date of Adoption	Effect on the financial statements upon adoption
2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities	The standard updates the hedge accounting model to expand the ability to hedge nonfinancial and financial risk components, reduce complexity, and ease certain documentation and assessment requirements. When facts and circumstances are the same as at the previous quantitative test, a subsequent quantitative effectiveness test is not required. The standard also eliminates the requirement to separately measure and report hedge ineffectiveness. For cash flow hedges, this means that the entire change in the fair value of a hedging instrument will be recorded in other comprehensive income and amounts deferred will be reclassified to earnings in the same income statement line as the hedged item. Transition method: modified retrospective with the cumulative effect adjustment recorded to the opening balance of retained earnings as of the initial application date. Prospective for presentation and disclosures.	January 1, 2019. Early adoption is permitted.	IPL is currently evaluating the impact of adopting the standard on its consolidated financial statements.
2018-19, 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, 2018-10, 2018-11, 2018-20, Leases (Topic 842)	See discussion of the ASUs below.	January 1, 2019. Early adoption is permitted.	IPL adopted the standard on January 1, 2019; see below for the evaluation of the impact of its adoption on its consolidated financial statements.

The standard must be adopted using a modified retrospective approach. The FASB has provided an optional transition method, which IPL has elected, that allows entities to continue to apply the guidance in ASC 840 Leases to the comparative periods presented in the year of adoption. Under this transition method, IPL will apply the transition provisions starting on January 1, 2019.

IPL has elected to apply a package of practical expedients that allow lessees and lessors 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. IPL has also elected to apply an optional transition practical expedient for land easements that allows an entity to continue applying its current accounting policy for all land easements that exist before the standard's effective date that were not previously accounted for under ASC 840.

IPL established a task force focused on the identification of contracts that are under the scope of the new standard and the assessment and measurement of their corresponding right-of-use assets and related liabilities. Additionally, the implementation team has been working on the configuration of a lease accounting tool that will support the implementation and the subsequent accounting. The implementation team has also evaluated changes to our business processes, systems and controls to support recognition and disclosure under the new standard.

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The adoption of ASC 842 did not have a material impact on IPL's consolidated financial statements.

2. REGULATORY MATTERS

General

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.

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Base Rate Orders

On October 31, 2018, the IURC issued an order approving an uncontested settlement agreement previously filed with the IURC by IPL for a $43.9 million, or 3.2%, increase to annual revenues (the "2018 Base Rate Order"). The 2018 Base Rate Order includes recovery through rates of the CCGT at Eagle Valley completed in the first half of 2018, as well as other construction projects and changes to operating income since the 2016 Base Rate Order (See below). New basic rates and charges became effective on December 5, 2018. The 2018 Base Rate Order also provides customers approximately$50 million in benefits, to be flowed to customers over a two-year period via the ECCRA rate adjustment mechanism beginning in March 2019. This liability is recorded in "Regulatory liabilities, non-current" as of December 31, 2018 on the accompanying Consolidated Balance Sheets. In addition, the 2018 Base Rate Order provides that annual wholesale margins earned above (or below) the benchmark of $16.3 million shall be passed back (or charged) to customers through a rate adjustment mechanism. Similarly, the 2018 Base Rate Order provides that all capacity sales above (or below) a benchmark of $11.3 million shall be passed back (or charged) to customers through a rate adjustment mechanism. The 2018 Base Rate Order also approved changes to IPL's depreciation and amortization rates (including no longer deferring depreciation on the CCGT at Eagle Valley) which altogether represent a net increase of approximately $28.7 million annually.

CCR

NAAQS

Other

107

FAC and Authorized Annual Jurisdictional Net Operating Income

ECCRA

IPL may apply to the IURC for approval of a rate adjustment known as the ECCRA periodically 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, 2018 was $12.1 million. The jurisdictional revenue requirement approved by the IURC to be included in IPL’s rates for the six-month period ending February 2019 was $16.2 million. This amount is significantly lower than prior ECCRA periods as a result of having the vast majority of the ECCRA projects rolled into IPL’s basic rates and charges effective December 5, 2018 as a result of the 2018 Base Rate Order. Further, the ECCRA jurisdictional revenue requirement starting March 2019 is expected to be a negative amount to reflect certain one-time credits IPL is required to pass through to its customers over a two-year period (totaling $50.2 million) as a result of the 2018 Base Rate Order. The only equipment still remaining in the ECCRA as of December 31, 2018 are certain projects associated with NAAQS compliance.

DSM

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 96.4 MW of solar-generated electricity in its service territory under long-term contracts in 2019 (these long-term contracts have expiration dates ranging from 2021 to 2033), of which 95.9 MW was in operation as of December 31, 2018. 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

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3. PROPERTY, PLANT AND EQUIPMENT

The original cost of property, plant and equipment segregated by functional classifications follows:



	As of December 31,
	2018		2017
	(In Thousands)
Production	$	3,927,847	$	3,226,951
Transmission	394,621		380,851
Distribution	1,533,828		1,487,146
General plant	344,782		304,903
Total property, plant and equipment	$	6,201,078	$	5,399,851

ARO



	2018			2017
	(In Thousands)
Balance as of January 1	$	79,535		$	80,568
Liabilities settled	(8,932		)	(5,276		)
Revisions to cash flow and timing estimates	54,811			—
Accretion expense	4,037			4,243
Balance as of December 31	$	129,451		$	79,535

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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.

VEBA Assets

FTRs

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Other Financial Liabilities

As of December 31, 2018 and 2017, IPL’s other financial liabilities measured at fair value on a recurring basis were considered Level 3, based on the fair value hierarchy.

Summary

The fair value of assets and liabilities at December 31, 2018 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, 2018		Based on quoted market prices in active markets		Other observable inputs		Unobservable inputs
	(In Thousands)
Financial assets:
VEBA investments:
Money market funds	$	21	$	21	$	—	$	—
Mutual funds	2,565		—		2,565		—
Total VEBA investments	2,586		21		2,565		—
Financial transmission rights	3,099		—		—		3,099
Total financial assets measured at fair value	$	5,685	$	21	$	2,565	$	3,099
Financial liabilities:
Other derivative liabilities	$	53	$	—	$	—	$	53
Total financial liabilities measured at fair value	$	53	$	—	$	—	$	53

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:
VEBA investments:
Money market funds	$	10	$	10	$	—	$	—
Mutual funds	2,581		—		2,581		—
Total VEBA investments	2,591		10		2,581		—
Financial transmission rights	2,532		—		—		2,532
Total financial assets measured at fair value	$	5,123	$	10	$	2,581	$	2,532
Financial liabilities:
Other derivative liabilities	$	78	$	—	$	—	$	78
Total financial liabilities measured at fair value	$	78	$	—	$	—	$	78

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	Reconciliation of Financial Instruments Classified as Level 3
	(In Thousands)
Balance at January 1, 2017	$	4,293
Unrealized gain recognized in earnings	23
Issuances	9,647
Settlements	(11,509		)
Balance at December 31, 2017	2,454
Unrealized gain recognized in earnings	24
Issuances	9,295
Settlements	(8,727		)
Balance at December 31, 2018	$	3,046

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 using market based rates 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. In 2018, IPL recorded additional ARO liabilities of $54.8 million to reflect revisions to cash flow and timing estimates due to accelerated ash pond closure dates and revised estimated closure costs after review of updates to the CCR rule and revised estimated costs associated with IPL's coal storage areas. As of December 31, 2018 and 2017, ARO liabilities were $129.5 million and $79.5 million, respectively. See Note 3, “Property, Plant and Equipment - ARO” 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, 2018				December 31, 2017
	Face Value		Fair Value		Face Value		Fair Value
	(In Thousands)
Fixed-rate	$	1,713,800	$	1,846,916	$	1,608,800	$	1,837,771
Variable-rate	90,000		90,000		238,000		238,000
Total indebtedness	$	1,803,800	$	1,936,916	$	1,846,800	$	2,075,771

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


•	unamortized deferred financing costs of $17.3 million and $16.5 million at December 31, 2018 and 2017, respectively.


•	unamortized discounts of $6.3 million and $6.4 million at December 31, 2018 and 2017, respectively.

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5. REGULATORY ASSETS AND LIABILITIES

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



	2018		2017		Recovery Period
	(In Thousands)
Regulatory Assets
Current:
Undercollections of rate riders	$	13,217	$	22,990	Approximately 1 year⁽¹⁾
Costs being recovered through basic rates and charges	15,182		12,351		Approximately 1 year⁽¹⁾
Total current regulatory assets	28,399		35,341
Long-term:
Unrecognized pension and other
postretirement benefit plan costs	195,559		205,573		Various⁽²⁾
Deferred income taxes recoverable through rates	103		—		Various
Deferred MISO costs	88,052		101,562		Through 2026⁽¹⁾
Unamortized Petersburg Unit 4 carrying
charges and certain other costs	8,084		9,139		Through 2026⁽¹⁾⁽³⁾
Unamortized reacquisition premium on debt	19,714		21,109		Over remaining life of debt
Environmental projects	81,204		40,434		Through 2046⁽¹⁾⁽³⁾
Other miscellaneous	2,361		1,087		Various⁽⁴⁾
Total long-term regulatory assets	395,077		378,904
Total regulatory assets	$	423,476	$	414,245
Regulatory Liabilities
Current:
Overcollection or rate riders and other credits being passed
to customers through rate riders	$	47,925	$	—	Approximately 1 year⁽¹⁾
FTRs	3,099		2,532		Approximately 1 year⁽¹⁾
Total current regulatory liabilities	51,024		2,532
Long-term:
ARO and accrued asset removal costs	707,662		696,973		Not applicable
Deferred income taxes payable through rates	141,058		154,461		Various
Long-term portion or credits being passed to customers
through rate riders	21,341		—		Through 2021
Other miscellaneous	194		320		To be determined
Total long-term regulatory liabilities	870,255		851,754
Total regulatory liabilities	$	921,279	$	854,286


(1)	Recovered (credited) per specific rate orders


(2)	IPL receives a return on its discretionary funding


(3)	Recovered with a current return

(4) The majority of these costs are being recovered in basic rates and charges through 2026. For the remainder, recovery is probable, but the

timing is not yet determined.

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Deferred Fuel

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

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. 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 has a net regulatory deferred income tax liability of $141.1 million and $154.5 million as of December 31, 2018 and 2017, respectively.

Deferred MISO Costs

Environmental Costs

ARO and Accrued Asset Removal Costs

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6. EQUITY

Paid In Capital and Capital Stock

On October 31, 2018, IPALCO closed on a new Term Loan consisting of a$65 million credit facility maturing July 1, 2020. The Term Loan is variable rate and is secured by IPALCO’s pledge of all the outstanding common stock of IPL. The lien on the pledged shares is shared equally and ratably with IPALCO’ existing senior secured notes. The Term Loan proceeds were used to repay amounts under IPL's Credit Agreement and for general corporate purposes.

IPL had capital contributions from IPALCO of $65.0 million, $0.0 million and $213.0 million for the years ended December 31, 2018, 2017 and 2016, respectively.

All of the outstanding common stock of IPL is owned by IPALCO. IPL’s common stock is pledged under the Term Loan, 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, 2018.

Dividend Restrictions

During the years ended December 31, 2018, 2017 and 2016, IPL declared dividends to its shareholder totaling $156.8 million, $125.5 million, and $133.5 million, respectively.

Cumulative Preferred Stock

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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, 2018, 2017 and 2016, preferred stock consisted of the following:



	December 31, 2018			December 31,
	Shares Outstanding	Call Price		2018		2017		2016
	Shares Outstanding	Call Price		Par Value, plus premium, if applicable
				(In Thousands)
Cumulative $100 par value,
authorized 2,000,000 shares
4% Series	47,611	$	118.00	$	5,410	$	5,410	$	5,410
4.2% Series	19,331	$	103.00	1,933		1,933		1,933
4.6% Series	2,481	$	103.00	248		248		248
4.8% Series	21,930	$	101.00	2,193		2,193		2,193
5.65% Series	500,000	$	100.00	50,000		50,000		50,000
Total cumulative preferred stock	591,353			$	59,784	$	59,784	$	59,784

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7. DEBT

Long-Term Debt

The following table presents IPL’s long-term debt:



		December 31,
Series	Due	2018			2017
		(In Thousands)
IPL first mortgage bonds:
3.875% ⁽¹⁾	August 2021	55,000			55,000
3.875% ⁽¹⁾	August 2021	40,000			40,000
3.125% ⁽¹⁾	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
4.875%	November 2048	105,000			—
Unamortized discount – net		(6,272		)	(6,353		)
Deferred financing costs		(17,115		)	(16,168		)
Total IPL first mortgage bonds		1,690,413			1,586,279
IPL unsecured debt:
Variable ⁽²⁾	December 2020	30,000			30,000
Variable ⁽²⁾	December 2020	60,000			60,000
Deferred financing costs		(229		)	(344		)
Total IPL unsecured debt		89,771			89,656
Total consolidated IPL long-term debt		1,780,184			1,675,935
Less: current portion of long-term debt		—			—
Net consolidated IPL long-term debt		$	1,780,184		$	1,675,935


(1)	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.


(2)	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, 2018, are as follows:



Year	Amount
	(In Thousands)
2019	$	—
2020	90,000
2021	95,000
2022	—
2023	—
Thereafter	1,618,800
Total	$	1,803,800

Significant Transactions

IPL First Mortgage Bonds and Recent Indiana Finance Authority Bond Issuances

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

Line of Credit

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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, 2018 and 2017, IPL had $0.0 million and $148.0 million in outstanding borrowings on the committed line of credit, respectively.

Restrictions on Issuance of Debt

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.

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. IPL made tax sharing payments to IPALCO of $33.8 million, $87.0 million and $57.9 million in 2018, 2017 and 2016 respectively.

In tax years prior to 2018, Internal Revenue Code Section 199 permitted 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 2017 and 2016 was $4.8 million and $5.7 million, respectively. Due to the recently enacted TCJA (as described below), the 2017 tax year was the final year for this deduction.

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U.S. Tax Reform

In 2017, 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 reflected the income tax effects of U.S. tax reform for which the accounting was complete and provisional amounts for those impacts for which the accounting under ASC 740 was incomplete, but a reasonable estimate could be determined.

IPL has completed its calculation of the impact of the TCJA in its income tax provision during the year ended December 31, 2018 in accordance with its understanding of the TCJA and guidance available as of the date of this filing, and as a result recognized $0.0 million and $0.2 million of discrete tax expense in the fourth quarters of 2018 and 2017, respectively.

Income Tax Provision

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



	2018			2017			2016
	(In Thousands)
Components of income tax expense:
Current income taxes:
Federal	$	26,021		$	56,377		$	49,473
State	11,215			12,656			12,064
Total current income taxes	37,236			69,033			61,537
Deferred income taxes:
Federal	(15,080		)	(1,634		)	12,437
State	345			(353		)	228
Total deferred income taxes	(14,735		)	(1,987		)	12,665
Net amortization of investment credit	(911		)	(1,455		)	(1,501		)
Total income tax expense	$	21,590		$	65,591		$	72,701

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Effective and Statutory Rate Reconciliation



	2018		2017		2016
Federal statutory tax rate	21.0	%	35.0	%	35.0	%
State income tax, net of federal tax benefit	5.6	%	4.0	%	4.0	%
Amortization of investment tax credits	(0.5	)%	(0.7	)%	(0.7	)%
Research and development credit	(1.6	)%	—	%	—	%
Depreciation flow through and amortization	(12.6	)%	(0.1	)%	(0.4	)%
Additional funds used during construction - equity	0.3	%	(3.1	)%	(3.2	)%
Manufacturers’ Production Deduction (Sec. 199)	—	%	(2.4	)%	(2.2	)%
Other – net	(0.1	)%	(0.2	)%	(0.8	)%
Effective tax rate	12.1	%	32.5	%	31.7	%

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, 2018 and 2017, are as follows:



	2018		2017
	(In Thousands)
Deferred tax liabilities:
Relating to utility property, net	$	378,527	$	475,911
Regulatory assets recoverable through future rates	67,653		66,661
Other	11,812		6,256
Total deferred tax liabilities	457,992		548,828
Deferred tax assets:
Investment tax credit	11		240
Regulatory liabilities including ARO	184,413		278,529
Employee benefit plans	8,335		18,564
Other	12,504		6,683
Total deferred tax assets	205,263		304,016
Deferred income taxes – net	$	252,729	$	244,812

Uncertain Tax Positions

The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2018, 2017 and 2016:



	2018		2017			2016
	(In Thousands)
Unrecognized tax benefits at January 1	$	7,049	$	6,634		$	7,147
Gross increases – current period tax positions	—		470			724
Gross decreases – prior period tax positions	7		(55		)	(1,237		)
Unrecognized tax benefits at December 31	$	7,056	$	7,049		$	6,634

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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.

9. BENEFIT PLANS

Defined Contribution Plans

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

The Thrift Plan

The RSP

Defined Benefit Plans

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The following table presents information relating to the Pension Plans:



	Pension benefits as of December 31,
	2018			2017
	(In Thousands)
Change in benefit obligation:
Projected benefit obligation at January 1	$	782,108		$	731,825
Service cost	8,450			7,344
Interest cost	25,220			25,305
Actuarial (gain)/loss	(62,303		)	52,451
Amendments (primarily increases in pension bands)	5,446			900
Curtailments⁽¹⁾	450			—
Settlements	—			(266		)
Benefits paid	(62,143		)	(35,451		)
Projected benefit obligation at December 31	697,228			782,108
Change in plan assets:
Fair value of plan assets at January 1	738,947			674,430
Actual return on plan assets	(22,404		)	93,022
Employer contributions	30,085			7,212
Settlements	—			(266		)
Benefits paid	(62,143		)	(35,451		)
Fair value of plan assets at December 31	684,485			738,947
Unfunded status	$	(12,743	)	$	(43,161	)
Amounts recognized in the statement of financial position:
Noncurrent liabilities	$	(12,743	)	$	(43,161	)
Net amount recognized at end of year	$	(12,743	)	$	(43,161	)
Sources of change in regulatory assets⁽²⁾:
Prior service cost arising during period	$	5,446		$	900
Net loss arising during period	902			4,101
Amortization of prior service cost	(4,618		)	(4,240		)
Amortization of loss	(11,403		)	(13,341		)
Total recognized in regulatory assets	$	(9,673	)	$	(12,580	)
Amounts included in regulatory assets:
Net loss	$	183,306		$	193,807
Prior service cost	18,146			17,318
Total amounts included in regulatory assets	$	201,452		$	211,125


(1)	As a result of the announced AES restructuring in the first quarter of 2018, we recognized a plan curtailment of $1.2 million in the first quarter of 2018.

(2)

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



	Pension benefits as of December 31,
	2018		2017
	(In Thousands)
Benefit obligation	$	697,228	$	782,108
Plan assets	684,485		738,947
Benefit obligation in excess of plan assets	$	12,743	$	43,161

IPL’s total benefit obligation in excess of plan assets was $12.7 million as of December 31, 2018 ($11.6 million Defined Benefit Pension Plan and $1.1 million Supplemental Retirement Plan).

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



	Pension benefits as of December 31,
	2018		2017
	(In Thousands)
Accumulated benefit obligation	$	687,136	$	769,678
Plan assets	684,485		738,947
Accumulated benefit obligation in excess of plan assets	$	2,651	$	30,731

Significant Gains and Losses Related to Changes in the Benefit Obligation for the Period

Pension Benefits and Expense

The 2018 net actuarial loss of $0.9 million recognized in regulatory assets is comprised of two parts: (1) a $63.2 million pension asset actuarial loss primarily due to lower than expected return on assets; partially offset by (2) a $62.3 million pension liability actuarial gain primarily due to an increase in the discount rate used to value pension liabilities. The unrecognized net loss of $183.3 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 2018, the accumulated net loss declined due to higher discount rates used to value pension liabilities, which was partially offset by a combination of lower than expected return on pension assets, as well as the year 2018 amortization of accumulated loss. 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

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approximately 10.17 years based on estimated demographic data as of December 31, 2018. The projected benefit obligation of $697.2 million less the fair value of assets of $684.5 million results in an unfunded status of $12.7 million at December 31, 2018.



	Pension benefits for years ended December 31,
	2018			2017			2016
	(In Thousands)
Components of net periodic benefit cost:
Service cost	$	8,450		$	7,344		$	7,018
Interest cost	25,220			25,305			25,815
Expected return on plan assets	(40,801		)	(44,672		)	(43,492		)
Amortization of prior service cost	3,837			4,240			5,183
Recognized actuarial loss	11,403			13,195			13,896
Recognized settlement loss	1,230			146			—
Total pension cost	9,339			5,558			8,420
Less: amounts capitalized	1,223			845			1,187
Amount charged to expense	$	8,116		$	4,713		$	7,233
Rates relevant to each year’s expense calculations:
Discount rate – defined benefit pension plan	3.67		%	4.29		%	4.42		%
Discount rate – supplemental retirement plan	3.60		%	4.00		%	4.19		%
Expected return on defined benefit pension plan assets	5.45		%	6.75		%	6.75		%
Expected return on supplemental retirement plan assets	5.45		%	6.75		%	6.75		%

Pension Plan Assets and Fair Value Measurements

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A description of the valuation methodologies used for each major class of assets and liabilities measured at fair value follows:


•	All the Plans’ investments have quoted market prices and are categorized as Level 1 in the fair value hierarchy.


•	The Plans’ 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.

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 Plans’ 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 Plans’ trust. Finally, IPL has the Plans’ 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 2018:



Asset Category:	Target Allocations
Equity Securities	10%
Debt Securities	90%

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	Fair Value Measurements at
	December 31, 2018
	(in thousands)
			Quoted Prices in Active Markets for Identical Assets		Significant Observable Inputs
Asset Category	Total		(Level 1)		(Level 2)		%
Short-term investments	$	3,597	$	3,597	$	—	1	%
Mutual funds:
U.S. equities	1,906		1,906		—		—	%
International equities	52,354		52,354		—		8	%
Fixed income	497,323		497,323		—		72	%
Fixed income securities:
U.S. Treasury securities	129,305		129,305		—		19	%
Total	$	684,485	$	684,485	$	—	100	%



	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	%

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Pension Funding

IPL contributed $30.1 million, $7.2 million, and $16.0 million to the Pension Plans in 2018, 2017 and 2016, 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 114%. In general, IPL must contribute the normal service cost earned by active participants during the plan year; however, this amount can be offset by any surplus or credit balance carried by the Pension Plan. The normal cost is expected to be approximately $8.3 million in 2019 (including $2.8 million for plan expenses), which is expected to be fully offset by the surplus amount. Each year thereafter, if the Pension Plans' underfunding increases to more than the present value of the remaining annual installments, the excess is separately amortized over a seven-year period. IPL does not expect to make an employer contribution for the calendar year 2019. 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.



Year	Pension Benefits
	(In Thousands)
2019	$	39,780
2020	41,400
2021	42,956
2022	44,051
2023	44,659
2024 through 2028	230,608

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 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. 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.

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New Source Review and other CAA NOVs

In October 2009, IPL received a NOV and Finding of Violation from the EPA pursuant to the CAA Section 113(a). The NOV alleges violations of the CAA at IPL’s three primarily coal-fired electric generating facilities at the time, dating back to 1986. The alleged violations primarily pertain to the PSD and nonattainment New Source Review requirements under the CAA. In addition, on October 1, 2015, IPL received a NOV from the EPA pursuant to CAA Section 113(a) alleging violations of the CAA, the Indiana SIP, and the Title V operating permit related to alleged particulate matter and opacity violations at IPL Petersburg Unit 3. Also, on February 5, 2016, the EPA issued a NOV pursuant to CAA Section 113(a) alleging violations of New Source Review and other CAA regulations, the Indiana SIP, and the Title V operating permit at Petersburg Generating Station. Since receiving the letters, IPL management has met with the EPA staff regarding possible resolutions of the NOVs. Settlements and litigated outcomes of similar New Source Review cases have required companies to pay civil penalties, install additional pollution control technology on coal-fired electric generating units, retire existing generating units, and invest in additional environmental projects. A similar outcome in these cases could have a material impact on our business. At this time, IPL cannot determine whether these NOVs could have a material impact on its business, financial condition and 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. 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 $3.1 million in 2018, 2017 and 2016, respectively, and is recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations. As of December 31, 2018 and 2017, IPL had prepaid approximately $1.6 million and $1.9 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 $21.5 million, $24.9 million, and $23.2 million in 2018, 2017 and 2016, respectively, and is recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations. IPL had no prepaids for coverage under this plan as of December 31, 2018 and 2017, 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 under this agreement of $13.5 million and $17.0 million as of December 31, 2018 and 2017, respectively, which is recorded in “Prepayments and other current assets” on the accompanying Consolidated Balance Sheets, respectively.

Long-term Compensation Plan

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Total deferred compensation expense recorded during 2018, 2017 and 2016 was $0.5 million, $0.8 million and $0.9 million, respectively, and was included in “Operating expenses - Operation and maintenance” on IPL’s Consolidated Statements of Operations. The value of these benefits is being recognized over the 36 month vesting period and a portion is recorded as miscellaneous deferred credits with the remainder recorded as “Paid in capital” on IPL’s Consolidated Balance Sheets in accordance with ASC 718 “Compensation – Stock Compensation.”

See also Note 9, “Benefit Plans” to the audited consolidated financial statements of IPL for a description of benefits awarded to IPL employees by AES under the RSP.

Service Company

Total costs incurred by the Service Company on behalf of IPL were $44.1 million, $34.1 million and $26.9 million during 2018, 2017 and 2016, respectively. Total costs incurred by IPL on behalf of the Service Company during 2018, 2017 and 2016 were $10.1 million, $10.7 million and $9.2 million, respectively. These costs were included in “Operating expenses - Operation and maintenance” on IPL’s Consolidated Statements of Operations. IPL had a payable balance with the Service Company of $3.8 million as of December 31, 2018, which is recorded in “Accounts payable” on the accompanying Consolidated Balance Sheets. IPL had a prepaid balance with the Service Company of $3.1 million as of December 31, 2017, which is recorded in “Prepayments and other current assets” on the accompanying Consolidated Balance Sheets.

Other

12. BUSINESS SEGMENT INFORMATION

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

13. REVENUE

130

Transmission revenues have a single performance obligation, as transmission services represent a distinct service. Additionally, as the performance obligation is satisfied over time and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series. The price that the transmission operator has the right to bill corresponds directly with the value to the customer of IPL’s performance completed in each period as the price paid is the transmission operators allocation of the tariff rate (as approved by the regulator) charged to network participants.

IPL’s revenue from contracts with customers was $1,428.9 million for the year ended December 31, 2018. The following table presents IPL's revenue from contracts with customers and other revenue (in thousands):



	For the Year Ended,
	December 31, 2018
Retail Revenues
Retail revenue from contracts with customers	$	1,380,042
Other retail revenues ⁽¹⁾	16,423
Wholesale Revenues	38,789
Miscellaneous Revenues
Transmission and other revenue from contracts with customers	10,057
Other miscellaneous revenues ⁽²⁾	5,194
Total Revenues	$	1,450,505

(1) Other retail revenue represents alternative revenue programs not accounted for under ASC 606

(2) Other miscellaneous revenue includes lease and other miscellaneous revenues not accounted for under ASC 606

IPL has elected to apply the optional disclosure exemptions under ASC 606. Therefore, IPL has not included disclosure pertaining to revenue expected to be recognized in any future year related to remaining performance obligations, as we exclude contracts with an original length of one year or less, contracts for which we recognize revenue based on the amount we have the right to invoice for services performed, and contracts with variable consideration allocated entirely to a wholly unsatisfied performance obligation when the consideration relates specifically to our efforts to satisfy the performance obligation and depicts the amount to which IPL expects to be entitled.

131

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, 2018, 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, 2018. 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, 2018.

Changes in Internal Control Over Financial Reporting:

There were no changes that occurred during the quarter ended December 31, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

132

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.

133

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,
	2018		2017
Audit Fees	$	929,600	$	1,028,800
Audit Related Fees:
Fees for the audit of IPL’s employee benefit plans	60,000		60,000
Assurance services for debt offering documents	68,000		117,600
Fees for tax services	—		—
Other	17,000		17,000
Total Principal Accounting Fees and Services	$	1,074,600	$	1,223,400

134

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 – 2018, 2017 and 2016	55
Consolidated Statements of Operations for the years ended December 31, 2018, 2017 and 2016	56
Consolidated Balance Sheets as of December 31, 2018 and 2017	57
Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016	58
Consolidated Statements of Common Shareholders’ Equity for the years ended December 31, 2018, 2017 and 2016	59
Notes to Consolidated Financial Statements	60
Schedule I – Condensed Financial Information of Registrant	139
Schedule II – Valuation and Qualifying Accounts and Reserves	144

Indianapolis Power & Light Company and Subsidiary – Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm – 2018, 2017 and 2016	94
Consolidated Statements of Operations for the years ended December 31, 2018, 2017 and 2016	95
Consolidated Balance Sheets as of December 31, 2018 and 2017	96
Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016	97
Consolidated Statements of Common Shareholder’s Equity for the years ended December 31, 2018, 2017 and 2016	98
Notes to Consolidated Financial Statements	99
Schedule II – Valuation and Qualifying Accounts and Reserves	144

135



(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)
	Sixty-Sixth Supplemental Indenture, dated as of November 1, 2018
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)
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)

136



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)
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)
10.23	Consulting Agreement dated December 31, 2018, between Craig L. Jackson and AES US Services, LLC and its subsidiaries and affiliates including The Dayton Power and Light Company and IPL.
21	Subsidiaries of IPALCO Enterprises, Inc.
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

137



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)

138

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,
	2018			2017
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	4,409		$	16,383
Prepayments and other current assets	15,246			9
Total current assets	19,655			16,392
OTHER NON-CURRENT ASSETS:
Investment in subsidiaries	1,431,856			1,369,100
Deferred tax asset – long term	112			22
Other non-current assets	2,539			3,585
Total other non-current assets	1,434,507			1,372,707
TOTAL ASSETS	$	1,454,162		$	1,389,099
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable	$	326		$	222
Accrued taxes	243			2,304
Accrued interest	11,444			11,813
Accrued and other current liabilities	3			880
Total current liabilities	12,016			15,219
NON-CURRENT LIABILITIES:
Long-term debt	868,880			801,603
Other non-current liabilities	—			1
Total non-current liabilities	868,880			801,604
Total liabilities	880,896			816,823
SHAREHOLDERS' EQUITY
Paid in capital	597,824			597,467
Accumulated deficit	(24,558		)	(25,191		)
Total shareholders' equity	573,266			572,276
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	1,454,162		$	1,389,099

See notes to Schedule I.

139



IPALCO ENTERPRISES, INC.
Schedule I – Condensed Financial Information of Registrant
Unconsolidated Statements of Operations
(In Thousands)
	2018			2017			2016
OTHER INCOME / (EXPENSE), NET:
Equity in earnings of subsidiaries	$	154,150		$	133,725		$	153,232
Interest expense	(31,038		)	(35,791		)	(35,920		)
Loss on early extinguishment of debt	—			(8,875		)	—
Other income / (expense), net	(443		)	26			(948		)
Total other income / (expense), net	122,669			89,085			116,364
EARNINGS FROM OPERATIONS BEFORE INCOME TAX	122,669			89,085			116,364
Less: income tax expense / (benefit)	(8,143		)	(16,495		)	(11,483		)
NET INCOME	$	130,812		$	105,580		$	127,847

See notes to Schedule I.

140



IPALCO ENTERPRISES, INC.
Schedule I – Condensed Financial Information of Registrant
Unconsolidated Statements of Cash Flows
(In Thousands)
	2018			2017			2016
CASH FLOWS FROM OPERATIONS:
Net income	$	130,812		$	105,580		$	127,847
Adjustments to reconcile net income to net cash
provided by operating activities:
Equity in earnings of subsidiaries	(154,150		)	(133,725		)	(153,232		)
Cash dividends received from subsidiary companies	142,250			132,516			136,466
Amortization of deferred financing costs and debt premium	1,964			2,003			1,947
Deferred income taxes – net	(89		)	78			22,601
Charges related to early extinguishment of debt	—			8,875			—
Change in certain assets and liabilities:
Accounts payable	(405		)	(1,833		)	(23		)
Accrued and other current liabilities	(1,244		)	7,413			(6,202		)
Other – net	(1,838		)	370			145
Net cash provided by operating activities	117,300			121,277			129,549
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in subsidiaries	(65,000		)	—			(212,997		)
Other	1,053			—			—
Net cash used in investing activities	(63,947		)	—			(212,997		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Long-term borrowings, net of discount	65,000			404,633			—
Retirement of long-term debt and early tender premium	—			(408,152		)	—
Dividends on common stock	(130,179		)	(105,144		)	(122,959		)
Issuance of common stock	—			—			134,276
Equity contributions from shareholders	—			—			78,738
Other	(148		)	(3,601		)	(11		)
Net cash (used in) provided by financing activities	(65,327		)	(112,264		)	90,044
Net change in cash and cash equivalents	(11,974		)	9,013			6,596
Cash and cash equivalents at beginning of period	16,383			7,370			774
Cash and cash equivalents at end of period	$	4,409		$	16,383		$	7,370

See notes to Schedule I.

141



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, 2016	$	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
Net income	—		130,812			130,812
Distributions to shareholders	—		(130,179		)	(130,179		)
Other	357		—			357
Balance at December 31, 2018	$	597,824	$	(24,558	)	$	573,266

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

Paid In Capital and Capital Stock

On March 1, 2016, IPALCO issued and sold 7,403,213 shares of IPALCO’s common stock to CDPQ for $134.3 million under the Subscription Agreement. After completion of these transactions, CDPQ’s direct and indirect interest in IPALCO was 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.

3. DEBT

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



			December 31,
Series	Due		2018			2017
			(In Thousands)
Long-Term Debt
Term Loan	July 2020		$	65,000		$	—
3.45% Senior Secured Notes	July 2020	—	405,000			405,000
3.70% Senior Secured Notes	September 2024	—	405,000			405,000
Unamortized discount – net			(424		)	(534		)
Deferred financing costs – net			(5,696		)	(7,863		)
Total long-term debt			868,880			801,603
Less: current portion of long-term debt			—			—
Net long-term debt			$	868,880		$	801,603

Long-Term Debt

IPALCO Term Loan

On October 31, 2018, IPALCO closed on a new Term Loan consisting of a $65 million credit facility maturing July 1, 2020. The term Loan is variable rate and is secured by IPALCO’s pledge of all the outstanding common stock of IPL. The lien on the pledged shares is shared equally and ratably with IPALCO’s existing senior secured notes. The Term Loan proceeds were used to repay amounts due under IPL's Credit Agreement and for general corporate purposes.

IPALCO’s Senior Secured Notes

143

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.

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, 2018, 2017 and 2016
(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, 2018
Accumulated Provisions Deducted from
Assets – Doubtful Accounts	$	2,830	$	6,008	$	—	$	6,017	$	2,821
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



INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY
Valuation and Qualifying Accounts and Reserves
For the Years Ended December 31, 2018, 2017 and 2016
(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, 2018
Accumulated Provisions Deducted from
Assets – Doubtful Accounts	$	2,830	$	6,008	$	—	$	6,017	$	2,821
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

ITEM 16. FORM 10-K SUMMARY

None.

144

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, 2019 /s/ Barry J. Bentley

Barry J. Bentley

Interim President and Chief Executive Officer

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



Signature	Capacity	Date
/s/ Barry J. Bentley	Interim President and Chief Executive Officer, and Director (Principal Executive Officer)	February 26, 2019
Barry J. Bentley		February 26, 2019
/s/ Kenneth J. Zagzebski	Director and Chairman	February 26, 2019
Kenneth J. Zagzebski	Director and Chairman	February 26, 2019
/s/ Thomas O'Flynn	Director	February 26, 2019
Thomas O'Flynn	Director	February 26, 2019
/s/ Paul L. Freedman	Director	February 26, 2019
Paul L. Freedman	Director	February 26, 2019
/s/ Mark E. Miller	Director	February 26, 2019
Mark E. Miller	Director	February 26, 2019
/s/ Julian Nebreda	Director	February 26, 2019
Julian Nebreda	Director	February 26, 2019
/s/ Gustavo Pimenta	Director	February 26, 2019
Gustavo Pimenta	Director	February 26, 2019
/s/ Lisa Krueger	Director	February 26, 2019
Lisa Krueger	Director	February 26, 2019
/s/ Frédéric Lesage	Director	February 26, 2019
Frédéric Lesage	Director	February 26, 2019
/s/ Renaud Faucher	Director	February 26, 2019
Renaud Faucher	Director	February 26, 2019
/s/ Gustavo Garavaglia	Chief Financial Officer (Principal Financial Officer)	February 26, 2019
Gustavo Garavaglia	Chief Financial Officer (Principal Financial Officer)	February 26, 2019
/s/ Karin M. Nyhuis	Controller (Principal Accounting Officer)	February 26, 2019
Karin M. Nyhuis	Controller (Principal Accounting Officer)	February 26, 2019

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.

145

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Ipalco Enterprises 10-K2018 FY Annual report

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