10-K

10-K 1 ipalco10k20151231.htm 10-K 10-K

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, 2015

¨ 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 ¨ No þ

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 þ No ¨

Prior to October 15, 2015, IPALCO Enterprises, Inc. was a voluntary filer. On October 15, 2015, the Securities and Exchange Commission declared effective the IPALCO Enterprises, Inc. Registration Statement on Form S-4, originally filed on September 28, 2015. IPALCO Enterprises, Inc. has filed all applicable reports under Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months.

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

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

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

Large accelerated filer ¨ Accelerated filer ¨

Non-accelerated filer þ Smaller reporting company ¨

(Do not check if a smaller reporting company)

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

At February 23, 2016, 101,504,105 shares of IPALCO Enterprises, Inc. common stock were outstanding. All of such shares were owned by AES U.S. Investments, Inc., except for 11,818,928 shares owned by CDP Infrastructure Fund GP, a wholly-owned subsidiary of La Caisse de dépôt et placement du Québec.

DOCUMENTS INCORPORATED BY REFERENCE

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

IPALCO ENTERPRISES, INC.

Annual Report on Form 10-K

For Fiscal Year Ended December 31, 2015

Table of Contents



Item No.		Page No.

	DEFINED TERMS	4

	PART I
1.	Business	7
1A.	Risk Factors	21
1B.	Unresolved Staff Comments	32
2.	Properties	32
3.	Legal Proceedings	32
4.	Mine Safety Disclosures	32
PART II
5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities	33
6.	Selected Financial Data	33
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
7A.	Quantitative and Qualitative Disclosures About Market Risk	47
8.	Financial Statements and Supplementary Data	50
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	119
9A.	Controls and Procedures	119
9B.	Other Information	120

PART III
10.	Directors, Executive Officers and Corporate Governance	120
11.	Executive Compensation	120
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	120
13.	Certain Relationships and Related Transactions, and Director Independence	120
14.	Principal Accounting Fees and Services	121

PART IV
15.	Exhibits, Financial Statements and Financial Statement Schedules	123

SIGNATURES		132



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

2016 IPALCO Notes	$400 million of 7.25% Senior Secured Notes due April 1, 2016
2018 IPALCO Notes	$400 million of 5.00% Senior Secured Notes due May 1, 2018
2020 IPALCO Notes	$405 million of 3.45% Senior Secured Notes due July 15, 2020
AES	The AES Corporation
AES U.S. Investments	AES U.S. Investments, Inc.
ARO	Asset Retirement Obligations
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
BACT	Best Achievable Control Technology
BTA	Best Technology Available
CAA	U.S. Clean Air Act
CAIR	Clean Air Interstate Rule
CCR	Coal Combustion Residuals
CCGT	Combined Cycle Gas Turbine
CCT	Clean Coal Technology
CDPQ	CDP Infrastructure Fund GP, a wholly-owned subsidiary of La Caisse de dépôt et placement du Québec
CO2	Carbon Dioxide
COSO	Committee of Sponsoring Organizations of the Treadway Commission
CPCN	Certificate of Public Convenience and Necessity
CPP	Clean Power Plan
Credit Agreement	$250,000,000 Revolving Credit Facilities Amended and Restated Credit Agreement by and among Indianapolis Power & Light Company, the Lenders Party thereto, PNC Bank, National Association, as Administrative Agent, PNC Capital Markets LLC, as Sole Bookrunner and Sole Lead Arranger, Fifth Third Bank, as Syndication Agent and BMO Harris Bank N.A., as Documentation Agent, Dated as of May 6, 2014, and as Amended under the First Amendment to Credit Agreement, Dated as of October 16, 2015.
CSAPR	Cross-State Air Pollution Rule
CWA	U.S. Clean Water Act
Defined Benefit Pension Plan	Employees’ Retirement Plan of Indianapolis Power & Light Company
DSM	Demand Side Management
ECCRA	Environmental Compliance Cost Recovery Adjustment
ELGs	Effluent Limitation Guidelines
EPA	U.S. Environmental Protection Agency
EPAct	Energy Policy Act of 2005
ERISA	Employee Retirement Income Security Act of 1974
FAC	Fuel Adjustment Clause
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FGDs	Flue-Gas Desulfurizations
FTRs	Financial Transmission Rights
GAAP	Generally accepted accounting principles in the United States
GHG	Greenhouse Gas
IBEW	International Brotherhood of Electrical Workers
IDEM	Indiana Department of Environmental Management
IOSHA	Indiana Occupational Safety and Health Administration



IPALCO	IPALCO Enterprises, Inc.
IPL	Indianapolis Power & Light Company
IPL Funding	IPL Funding Corporation
IURC	Indiana Utility Regulatory Commission
kWh	Kilowatt hours
LIBOR	London InterBank Offer Rate
MATS	Mercury and Air Toxics Standards
Mid-America	Mid-America Capital Resources, Inc.
MISO	Midcontinent Independent System Operator, Inc.
MW	Megawatts
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Corporation
NOV	Notice of Violation
NOx	Nitrogen Oxides
NPDES	National Pollutant Discharge Elimination System
NSPS	New Source Performance Standards
PCBs	Polychlorinated Biphenyls
Pension Plans	Employees’ Retirement Plan of Indianapolis Power & Light Company and Supplemental Retirement Plan of Indianapolis Power & Light Company
PSD	Prevention of Significant Deterioration
Purchasers	Citibank, N.A. and its affiliate, CRC Funding, LLC
RCRA	Resource Conservation and Recovery Act
Receivables Sale Agreement	Second Amended and Restated Receivables Sale Agreement, dated as of June 25, 2009, as amended, as described herein
RF	ReliabilityFirst
RSP	AES Retirement Savings Plan
SEA	Senate Enrolled Act
SEC	Securities and Exchange Commission
Securities Act	Securities Act of 1933, as Amended
Service Company	AES U.S. Services, LLC
SO2	Sulfur Dioxides
Supplemental Retirement Plan	Supplemental Retirement Plan of Indianapolis Power & Light Company
Third Amended and Restated Articles of Incorporation	Third Amended and Restated Articles of Incorporation of IPALCO Enterprises, Inc.
Thrift Plan	Employees’ Thrift Plan of Indianapolis Power & Light Company
U.S.	United States of America
U.S. SBU	AES U.S. Strategic Business Unit
VIE	Variable Interest Entity

PART I

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

FORWARD‑LOOKING STATEMENTS

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

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


▪	fluctuations in customer growth and demand;


▪	impacts of weather on retail sales and wholesale prices;


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


▪	weather-related damage to our electrical system;


▪	fuel, commodity and other input costs;


▪	generating unit availability and capacity;


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


▪	purchased power costs and availability;


▪	availability and price of capacity;


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


▪	federal and state legislation and regulations;


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


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


▪	changes in financial or regulatory accounting policies;


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


▪	interest rates, inflation rates and other costs of capital;


▪	the availability of capital;


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


▪	level of creditworthiness of counterparties to contracts and transactions;


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


▪	facility or equipment maintenance, repairs and capital expenditures;


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


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


▪	local economic conditions;


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


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


▪	industry restructuring, deregulation and competition;


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


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


▪	the use of derivative contracts;


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


▪	other factors listed or discussed in “Item 1A. Risk Factors” and/or “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Form 10-K.

Most of these factors affect us through our consolidated subsidiary, IPL. All such factors are difficult to predict, contain uncertainties that may materially affect actual results and many are beyond our control. Except as required by the federal securities laws, we undertake no obligation to publicly update or review any forward-looking information, whether as a result of new information, future events or otherwise. If one or more forward-looking statements are updated, no inference should be drawn that additional updates will be made with respect to those or other forward-looking statements.

ITEM 1. BUSINESS

OVERVIEW

IPALCO is a holding company incorporated under the laws of the state of Indiana. Our principal subsidiary is IPL, a regulated electric utility operating in the state of Indiana. Substantially all of our business consists of the generation, transmission, distribution and sale of electric energy conducted through IPL. Our business segments are electric and “all other.” Our total electric revenues and net income for the fiscal year ended December 31, 2015 were $1.3 billion and $59.5 million, respectively. The book value of our total assets as of December 31, 2015 was $4.2 billion. All of our operations are conducted within the U.S. and principally within the state of Indiana. Please see Note 12, “Business Segment Information” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K.

IPL

IPALCO owns all of the outstanding common stock of IPL. IPL was incorporated under the laws of the state of Indiana in 1926. IPL is engaged primarily in generating, transmitting, distributing and selling electric energy to approximately 480,000 customers in the city of Indianapolis and neighboring areas within the state of Indiana; with 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 934,000. 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, is converting its coal-fired units to natural gas and uses natural gas and fuel oil to power combustion turbines. The third station, Eagle Valley, is coal-fired, and we plan to retire its coal-fired units in the second quarter of 2016. The fourth station, Georgetown, is a small peaking station that uses natural gas to power combustion turbines. IPL’s net electric generation capacity for winter is 3,259 MW and net summer capacity is 3,141 MW. 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 2015.

The electric utility business is affected by seasonal weather patterns throughout the year and, therefore, the operating revenues and associated operating expenses are not generated evenly by month during the year. IPL’s business is not dependent on any single customer or group of customers. Additionally, retail kWh sales, after adjustments for weather variations, have historically been impacted by changes in service territory economic activity as well as the number of retail customers we have. For the ten years ending in 2015, IPL’s retail kWh sales have decreased at a compound annual rate of 1.0%. Conversely, the number of our retail customers grew at a compound annual rate of 0.4% during that same period. Going forward, we expect modest retail kWh sales growth annually, which is negatively impacted by our DSM programs and other energy efficiency mandates. Please see “– Regulatory Matters – DSM” below for more details. IPL’s electricity sales for 2011 through 2015 are set forth in the table of statistical information included at the end of this section.

IPL is a transmission company member of RF. RF is one of eight Regional Reliability Councils under the NERC, which has been designated as the Electric Reliability Organization under the EPAct. RF seeks to preserve and enhance electric service reliability and security for the interconnected electric systems within the RF geographic area by setting and enforcing electric reliability standards. RF members cooperate under agreements to augment the reliability of its members’ electricity supply systems in the RF region through coordination of the planning and operation of the members’ generation and transmission facilities. Smaller electric utility systems, independent power producers and power marketers can participate as full members of RF. In addition, IPL is one of many transmission system owner members of MISO, a regional transmission organization which maintains functional control over the combined transmission systems of its members and manages one of the largest energy markets in the U.S. IPL participates in MISO’s energy and operating reserves markets and each asset owner receives separate day-ahead, real-time, and FTRs market settlement statements for each operating day (see “– MISO Operations” for more details).

EMPLOYEES

As of January 31, 2016, IPL had 1,400 employees of whom 1,307 were full time. Of the total employees, 878 were represented by the IBEW in two bargaining units: a physical unit and a clerical-technical unit. In February 2014, the membership of the IBEW clerical-technical unit ratified a three-year labor agreement with us that expires on February 20, 2017. In December 2015, the IBEW physical unit ratified a three-year agreement with us that expires on December 10, 2018. Both collective bargaining agreements shall continue in full force and effect from year to year unless either party provides prior written notice at least sixty (60) days prior to the expiration, or anniversary thereof, of its desire to amend or terminate the agreement. As of January 31, 2016, neither IPALCO nor any of its majority-owned subsidiaries other than IPL had any employees.

SERVICE COMPANY

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 and a building in Indianapolis which 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, is converting its coal-fired units to natural gas and uses natural gas and fuel oil to power combustion turbines. The third station, Eagle Valley, is coal-fired, and we plan to retire its coal-fired units in the second quarter of 2016. 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 3,259 MW and net summer design capacity is 3,141 MW. Our highest summer peak level of 3,139 MW was recorded in August 2007 and the highest winter peak level of 2,971 MW was recorded in January 2009.

Our sources of electric generation are as follows:



Fuel	Name	Number of Units	Winter Capacity (MW)	Summer Capacity (MW)	Location
Coal	Petersburg	4	1,706	1,706	Pike County, Indiana
	Harding Street⁽¹⁾	1	431	431	Marion County, Indiana
	Eagle Valley⁽²⁾	4	263	260	Morgan County, Indiana
	Total	9	2,400	2,397
Gas	Harding Street⁽¹⁾	5	595	532	Marion County, Indiana
	Georgetown	2	200	158	Marion County, Indiana
	Total	7	795	690
Oil	Petersburg	3	8	8	Pike County, Indiana
	Harding Street	3	53	43	Marion County, Indiana
	Eagle Valley	1	3	3	Morgan County, Indiana
	Total	7	64	54
Grand Total		23	3,259	3,141


(1)	In December 2015, we completed our project to refuel Harding Street Station Units 5 and 6 from coal to natural gas. We expect to complete the refueling of Harding Street Station Unit 7 in the second quarter of 2016. Once Unit 7 is refueled, Harding Street Station will no longer use coal as a fuel source.


(2)	We plan to retire the four coal-fired units at Eagle Valley in the second quarter of 2016. The CCGT at the Eagle Valley Station is expected to be placed into service in April 2017. The CCGT is one unit with an expected winter and summer capacity of approximately 644 to 685 MW.

Net electrical generation during 2015, at the Petersburg, Harding Street, Eagle Valley and Georgetown plants accounted for approximately 71.1%, 26.4%, 1.8% and 0.7%, respectively, of our total net generation. After the completion of the Harding Street Station Unit 7 refueling project, coal unit retirements at Eagle Valley and completion of the CCGT, we expect net electrical generation to change accordingly.

Our electric system is directly interconnected with the electric systems of Indiana Michigan Power Company, Vectren Corporation, Hoosier Energy Rural Electric Cooperative, Inc., and the electric system jointly owned by Duke Energy Indiana, Indiana Municipal Power Agency and Wabash Valley Power Association, Inc. Our transmission system includes 458 circuit miles of 345,000 volt lines and 377 circuit miles of 138,000 volt lines. The distribution system consists of 4,912 circuit miles of underground primary and secondary cables and 6,123 circuit miles of overhead primary and secondary wire. Underground street lighting facilities include 762 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. Currently, our plants generally have enough capacity to meet the needs of our retail customers when all of our units are available. During periods when our generating capacity is not sufficient to meet our retail demand, or when MISO provides a lower cost alternative to some of our available generation, we purchase power on the MISO wholesale market.

MISO OPERATIONS

IPL is one of many transmission system owner members in MISO. MISO is a regional transmission organization which maintains functional control over the combined transmission systems of its members and manages one of the largest energy and ancillary services markets in the U.S. MISO policies are developed, in part, through a stakeholder process in which we are an active participant. We focus our participation in this process primarily on items that could impact our customers, results of operations, financial condition and cash flows. Additionally, we attempt to influence MISO and FERC policy by filing comments with MISO, the FERC or the IURC.

MISO has functional control of our transmission facilities and our transmission operations are integrated with those of MISO. Our participation and authority to sell wholesale power at market-based rates are subject to the FERC jurisdiction. Transmission service over our facilities is provided through MISO’s tariff.

As a member of MISO, we offer our available electricity production of each of our generation assets into the MISO day-ahead and real-time markets. MISO dispatches generation assets in economic order considering transmission constraints and other reliability issues to meet the total demand in the MISO region. MISO settles hourly offers and bids based on locational marginal prices, which is pricing for energy at a given location based on a market clearing price that takes into account physical limitations, generation, and demand throughout the MISO region. MISO evaluates the market participants’ energy offers and demand bids optimizing for energy and ancillary services products to economically and reliably dispatch the entire MISO system. The IURC has authorized IPL to recover, through FAC proceedings, the fuel portion of its costs from MISO, including all specifically identifiable ancillary services market costs, and to defer certain operational, administrative and other costs from MISO and seek recovery in IPL’s current basic rate case proceeding. Total MISO costs deferred as long-term regulatory assets were $128.6 million and $110.5 million as of December 31, 2015 and December 31, 2014, respectively.

We have preserved our right to withdraw from MISO by tendering our Notice of Withdrawal (subject to the FERC and the IURC approval). We have made no decision to seek withdrawal from MISO at this time. We will continue to assess the relative costs and benefits of being a MISO member, as well as actively advocate for our positions through the existing MISO stakeholder process and in filings at the FERC or IURC.

REGULATORY MATTERS

General

IPL is a regulated public utility principally engaged in providing electric service to the Indianapolis metropolitan area. IPL is subject to regulation by the IURC with respect to the following: our services and facilities; retail rates and charges; the valuation of property; the construction, purchase, or lease of electric generating facilities; the classification of accounts; rates of depreciation; the issuance of securities (other than indebtedness payable less than twelve months after the date of issue); the acquisition and sale of some public utility properties or securities; and certain other matters. The regulatory power of the IURC

over our business is both comprehensive and typical of the traditional form of regulation generally imposed by state public utility commissions.

In addition, IPL is subject to the jurisdiction of the 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 non-regulated entities. 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 audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K.

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

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.

Retail Ratemaking

IPL’s tariff rates for electric service to retail customers consist of basic rates and charges which are set and approved by the IURC after public hearings (see below). In addition, IPL’s rates include various adjustment mechanisms including, but not limited to: (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 incurred to comply with environmental laws and regulations referred to as the ECCRA. Each of these tariff rate components may be set and approved by the IURC in separate proceedings at different points in time. For example, FAC proceedings occur on a quarterly basis and the ECCRA proceedings occur on a semi-annual basis. These components function somewhat independently of one another, but the overall structure of our rates and charges would be subject to review at the time of any review of our basic rates and charges.

Basic Rates and Charges

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 invested property.

Our basic rates and charges were last adjusted in 1996; however, IPL filed a petition with the IURC on December 29, 2014, for authority to increase its basic rates and charges. IPL's proposed rate increase, filed as part of IPL's rebuttal testimony in this proceeding, is $63.3 million, or 5.3%. An order on this proceeding will likely be issued by the IURC early in 2016. The petition also includes requests to implement rate adjustment mechanisms for short term recovery of fluctuations in the following costs: (1) capacity purchase costs; (2) off-systems sales margins; and (3) MISO non-fuel charges (MISO fuel charges are already included in the FAC rate mechanism as described below). No assurances can be given as to the timing or outcome of this proceeding. See “– Rate Case and Downtown Underground Network Investigation” below for further details.

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

Rate Case and Downtown Underground Network Investigation

As discussed above, IPL filed a petition with the IURC on December 29, 2014, for authority to increase its basic rates and charges. In response to underground network incidents that occurred in the downtown Indianapolis area, the IURC issued an order on March 20, 2015 opening an investigation of our ongoing investment in, and operation and maintenance of, our network facilities. In 2015, the IURC combined this pending investigation with our petition filed in 2014 proposing to increase our basic rates and charges. The outcome of the rate case and/or downtown underground network investigation cannot be predicted.

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.

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.

ECCRA

IPL may apply to the IURC for approval of a rate adjustment known as the ECCRA every six months to recover costs to comply with certain environmental regulations applicable to our generating stations. The total amount of IPL’s equipment approved for ECCRA recovery as of December 31, 2015 was $978 million. The jurisdictional revenue requirement that was approved by the IURC to be included in IPL’s rates for the six-month period from September 2015 through February 2016 was $82.0 million. During the years ended December 31, 2015, 2014 and 2013, we made environmental compliance expenditures of $252.2 million, $176.3 million, and $126.6 million, respectively. The vast majority of such costs are recoverable through our ECCRA filings. Also, see “– Environmental Matters” below for discussion of recovery of costs to comply with current and expected environmental laws and regulations.

DSM

In March 2014, legislation, referred to as the SEA 340, was approved that effectively ended the IURC’s energy efficiency targets established in a 2009 statewide Generic DSM Order. Although SEA 340 puts an end to established efficiency targets, IPL will continue to offer cost-effective energy efficiency and demand response programs as one of many resources to meet future demand for electricity.

In December 2014, we received approval from the IURC of our 2015-2016 DSM plan. The approval includes cost recovery on a set of DSM programs to be offered in 2015-2016 that is similar to the 2014 set of programs. Similar to the current DSM framework, we are eligible to receive performance incentives dependent upon the level of success of the programs. Additionally, we were granted authority to record a regulatory asset for recovery in a future base rate case proceeding for lost margins which result from decreased kWh related to implementation of these DSM programs.

In May 2015, SEA 412 became law in Indiana. Among other things, SEA 412 requires the IURC to adopt rules regarding the submission of an integrated resource plan. The IURC rulemaking required by SEA 412 is currently in progress. SEA 412 also requires certain electricity suppliers to submit energy efficiency plans to the IURC at least once every three years.

Wind and Solar Power Purchase Agreements

We are committed under a power purchase agreement to purchase all wind-generated electricity through 2029 from a wind project in Indiana. We are also committed under another agreement to purchase all wind-generated electricity for 20 years from a project in Minnesota. The Indiana project has a maximum output capacity of approximately 100 MW. The Minnesota project, which began commercial operation in October 2011, has a maximum output capacity of approximately 200 MW. In addition, we have 97 MW of solar-generated electricity in our service territory under long-term contracts in 2016, of which 95 MW was

in operation as of December 31, 2015. We have authority from the IURC to recover the costs for all of these agreements through an adjustment mechanism administered within the FAC.

MISO Transmission Expansion Cost Sharing

MISO transmission system owner members including IPL share the costs of transmission expansion projects with other MISO transmission system owner members after such projects are approved by the MISO board of directors. As required by FERC, IPL participates in a regional transmission planning process with MISO and other MISO transmission providers to produce a regional transmission plan. Upon approval by the MISO board of directors the transmission system owner members must make a good faith effort to build and/or pay for the approved projects they submitted. Costs allocated to IPL for the projects of other transmission system owner members are collected by MISO per their tariff. These charges are difficult to estimate and amounted to $12.1 million in 2015. It is probable, but not certain, that these costs will be recovered through IPL's tariff, subject to IURC approval. Through December 31, 2015, we have deferred as a long-term regulatory asset $19.7 million of MISO transmission expansion costs.

ENVIRONMENTAL MATTERS

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

From time to time, we are subject to enforcement actions for claims of noncompliance with environmental laws and regulations. IPL cannot assure that it will be successful in defending against any claim of noncompliance. However, with the possible exception of the New Source Review NOV from the EPA (see “New Source Review and Other CAA NOVs” below), we do not believe any currently open environmental investigations will result in fines material to our results of operations, financial condition and cash flows.

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

MATS

In April 2012, the EPA’s rule to establish maximum achievable control technology standards for each hazardous air pollutant regulated under the CAA emitted from coal and oil-fired electric utilities, known as “MATS”, became effective. IPL management has developed a plan to comply with this rule. Most of our coal-fired capacity has acid gas scrubbers or comparable control technologies; however, there are other improvements to such control technologies that are necessary to achieve compliance. Under the CAA, compliance with MATS was required by April 16, 2015; however, the compliance period for certain units, or groups of units, was extendable by state permitting authorities (for up to one additional year) or through a CAA administrative order from the EPA (for another additional year). In December 2012, IDEM granted an extension to April 16, 2016 covering all coal-fired units at Harding Street and Eagle Valley (we do not expect there will be any such coal-fired units at Harding Street and Eagle Valley after the second quarter of 2016), in addition to Unit 3 and Unit 4 at Petersburg. In February 2013, IDEM granted a three-month extension on Petersburg Unit 2 to July 16, 2015, and that unit, in addition to Petersburg Unit 1, which did not receive an extension, are currently equipped to comply with the MATS rule.

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

Several lawsuits challenging the EPA's MATS rule have been filed by other parties and consolidated into a single proceeding before the U.S. Court of Appeals for the District of Columbia Circuit. In April 2014, the U.S. Court of Appeals issued an opinion upholding the MATS rule. Numerous states and two trade groups petitioned the U.S. Supreme Court to review this opinion. On June 29, 2015, the U.S. Supreme Court remanded MATS to the D.C. Circuit due to the EPA's failure to consider costs before deciding to regulate power plants under Section 112 of the CAA. On December 15, 2015, the D.C. Circuit issued an order remanding MATS to the EPA without vacatur while the EPA works to account for costs of the rule pursuant to the U.S. Supreme Court's decision. The EPA published its revised appropriate and necessary finding on December 1, 2015 and plans to finalize it by April 15, 2016. Further proceedings are expected; however, in the meantime MATS remains in effect. We currently cannot predict the outcome of this litigation, or its impact, if any, on our MATS compliance planning or ultimate costs.

On June 20, 2014, IPL contemporaneously filed a waiver request or in the alternative, a complaint with the FERC requesting a waiver or changes to MISO rules that will allow IPL to keep 216 MW of reliable capacity available at its Eagle Valley generating station from June 1, 2015 through April 15, 2016. Both of these filings request that the FERC either waive or reform certain requirements of the MISO tariff for failing to address the specific circumstances resulting from compliance with MATS. IPL maintains that MISO has not addressed several aspects of the issue created by the disconnect between the MATS compliance deadline (April 16, 2016) and the end of the MISO planning year for capacity purposes (June 1, 2016). On October 15, 2014, this waiver request was approved by the FERC.

Environmental Wastewater Requirements

In August 2012, IDEM issued NPDES permits to the IPL Petersburg, Harding Street, and Eagle Valley generating stations, which became effective in October 2012. NPDES permits regulate specific industrial wastewater and storm water discharges to the waters of Indiana under Section 402 of the CWA. These permits set new water quality-based effluent discharge limits for the Petersburg and Harding Street facilities, as well as monitoring and other requirements designed to protect human and aquatic life, with full compliance with the new effluent limitations required by October 2015. In April 2013, IPL received an extension to the compliance deadline through September 29, 2017 for IPL’s Harding Street and Petersburg facilities through agreed orders with IDEM.

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

On October 16, 2014, IPL filed its wastewater compliance plans with the IURC. On July 29, 2015, IPL received approval for a CPCN from the IURC to convert Unit 7 at the Harding Street Station from coal-fired to natural gas-fired, and also to install and operate wastewater treatment technologies at Harding Street Station and Petersburg Generation Station in southern Indiana. IPL plans to invest $319 million in these projects to help ensure compliance with the wastewater treatment requirements by September 29, 2017.

On November 3, 2015, the EPA published its final ELG Rule to reduce toxic pollutants discharged into waterways by power plants. In addition to the wastewater treatment technologies being installed and operated for compliance with the requirements of the October 2012 NPDES permit described above, the final ELG Rule will require closed loop or dry bottom ash handling at Petersburg. The compliance date may be as early as November 2018 or as late as December 2023, and is subject to discretion of IDEM. Industry groups have filed challenges to the ELG Rule, which are pending before the Fifth Circuit Court of Appeals. Environmental groups have moved to intervene in these cases on behalf of the EPA. The impact of the ELG Rule is expected to be material.

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

On June 29, 2015, the EPA and the U.S. Army Corps of Engineers published a rule defining federal jurisdiction over waters of the U.S. This rule, which became effective on August 28, 2015, may expand or otherwise change the number and types of waters or features subject to federal permitting. On the day the rule was published, several states sued to challenge the rule. Since then, other states and industry groups have also sued. On October 9, 2015, the U.S. Court of Appeals for the Sixth Circuit

issued an order staying the rule nationwide pending completion of the Court's review of the rule. In January 2016, the U.S. Congress passed a resolution seeking to block implementation of the rule, which resolution was vetoed by President Obama. We cannot at this time determine the timing or impact of this regulation, litigation or legislation, but it could have a material impact on our business, financial condition or results of operations.

Climate Change Legislation and Regulation

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

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


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


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


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


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


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


▪	The operation of and emissions from regulated units;

▪

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


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


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


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


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


▪	The availability and cost of carbon control technology;


▪	Whether federal legislation regulating GHG emissions will preclude the EPA from regulating GHG emissions under the CAA or preempt private nuisance suits or other litigation by third parties;


▪	Any opportunities to change the use of fuel at the generation facilities or opportunities to increase efficiency; and


▪	Our ability to recover any resulting costs from our customers and the timing of such recovery.

Except as noted in the discussion below, at this time, we cannot estimate the costs of compliance with existing, proposed or potential international, federal, state or regional GHG emissions reductions legislation or initiatives due in part to the fact that many of these proposals are in earlier stages of development and any final laws or regulations, if adopted, could vary drastically from current proposals. Any international, federal, state or regional legislation adopted in the U.S. that would require the reduction of GHG emissions could have a material adverse effect on our business and/or results of operations, financial condition and cash flows.

The U.S. Congress has considered several different draft bills pertaining to GHG legislation, including comprehensive GHG legislation that would impact many industries and more limited legislation focusing only on the utility and electric generation industry. Although no legislation pertaining to GHG emissions has been passed to date by the U.S. Congress, similar legislation may be considered or passed by the U.S. Congress in the future. In addition, in the past Midwestern state governors (including

the Governor of Indiana) and the premier of Manitoba, Canada committed to reduce GHG emissions through the implementation of a cap-and-trade program pursuant to the Midwestern Greenhouse Gas Reduction Accord. Though the participating states and province are no longer pursuing this commitment, similar state or regional initiatives may be pursued in the future, particularly in connection with the CPP (discussed below).

In January 2011, the EPA began regulating GHG emissions from certain stationary sources under the formerly-called “Tailoring Rule.” The regulations were implemented pursuant to two CAA programs: the Title V Operating Permit program and the program requiring a permit if undergoing certain new construction or major modifications, the PSD program. Obligations relating to Title V permits include recordkeeping and monitoring requirements. Sources subject to PSD can be required to implement BACT. In June 2014, the U.S. Supreme Court ruled that the EPA had exceeded its statutory authority in issuing the Tailoring Rule by regulating under the PSD program sources based solely on their GHG emissions. However, the U.S. Supreme Court also held that the EPA could impose GHG BACT requirements for sources already required to implement PSD for certain other pollutants when GHG increases exceed a “significance” threshold. Currently, the EPA uses a 75,000 ton per year GHG threshold to determine if increases are significant. However, the EPA is expected to issue a rule in 2016 that would set a GHG significant emissions increase threshold 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. In December 2010, the Indiana Air Pollution Control Board adopted a final rule implementing the Tailoring Rule in Indiana, and the rule was published in the Indiana Register in March 2011.

On October 23, 2015, the EPA's final CO₂emission rules for existing power plants (called the Clean Power Plan or “CPP”) were published in the Federal Register with an effective date of December 22, 2015. Additionally, the final NSPS for CO₂ emissions from new, modified and reconstructed fossil-fuel-fired power plants were published in the Federal Register on October 23, 2015 and are effective immediately. Some states and industry groups filed petitions for review on both the CPP and the NSPS rules, and environmental groups moved to intervene in both cases on behalf of the EPA.

The CPP provides for interim emissions performance rates that must be achieved beginning in 2022 and final emissions performance rates that must be achieved by 2030. Prior to the rule's publication in the Federal Register, fifteen states, including Indiana, filed a petition in the U.S. Court of Appeals for the D.C. Circuit seeking a stay of the CPP, which was denied by the Court in September 2015. On October 23, 2015, several states and industry groups filed petitions in the D.C. Circuit Court of Appeals challenging the CPP as published in the Federal Register, including a twenty-four state consortium that includes Indiana. These state petitioners and industry groups challenging the rule, which have been consolidated by the D.C. Circuit Court under the lead case, West Virginia v. EPA, have filed motions with the D.C. Circuit Court requesting a stay of the rule. That request was denied on January 21, 2016 and oral arguments were set for June 2, 2016. The states later petitioned the U.S. Supreme Court requesting a stay on January 26, 2016. On February 9, 2016, the U.S. Supreme Court issued orders staying the implementation of the CPP pending resolution of challenges to the rule. Additional legal challenges to the CPP and NSPS are expected. We are currently reviewing the rules, considering the stay and assessing the impact of both on our operations. Our business, financial condition or results of operations could be materially and adversely affected by these rules.

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

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

Unit Retirements and Replacement Generation

In the second quarter of 2013, IPL retired five oil-fired peaking units with an average life of approximately 61 years (approximately 168 MW net capacity in total). Although these units represented approximately 5% of IPL’s generating capacity, they were seldom dispatched by MISO in recent years due to their relatively higher production cost and in some instances repairs were needed. In accordance with FERC accounting guidelines and standard utility practice for composite depreciation, these retirements were recorded as a reduction of $19.8 million to both “Utility Plant in Service” and “Accumulated Depreciation” on our consolidated balance sheets, with no gain or loss recognized.

In addition to the generating units IPL retired in the second quarter of 2013, IPL plans to retire the four coal-fired units at Eagle Valley in the second quarter of 2016. To replace this generation, IPL filed a petition and case-in-chief with the IURC in April 2013 seeking a CPCN to build a 550 to 725 MW CCGT at its Eagle Valley Station site in Indiana and to refuel Harding Street Station Units 5 and 6 from coal to natural gas (approximately 100 MW net capacity each). In May 2014, IPL received an order on the CPCN from the IURC authorizing the refueling project and granting approval to build a 644 to 685 MW CCGT at a total budget of $649 million. The current estimated cost of these projects is $632 million. IPL requested and was granted authority to accrue a 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 until such time that we are allowed to collect both a return and depreciation expense on the CCGT and refueling project. The CCGT is expected to be placed into service in April 2017, and the refueling project was completed in December 2015. The costs to build and operate the CCGT and the refueling project, other than fuel costs, will not be recoverable by IPL through rates until the conclusion of a base rate case proceeding with the IURC after the assets have been placed in service.

On October 3, 2014, IPL filed a petition and case-in-chief with the IURC seeking a CPCN to refuel Harding Street Station Unit 7 from coal to natural gas (about 410 MW net capacity). This conversion is part of IPL’s overall wastewater compliance plan for its power plants and was approved by the IURC (as discussed in “Environmental Wastewater Requirements” above). We expect the Harding Street Station Unit 7 conversion to be complete in the second quarter of 2016.

New Source Review and Other CAA NOVs

In October 2009, IPL received a NOV and Finding of Violation from the EPA pursuant to the Federal Clean Air Act Section 113(a). The NOV alleges violations of the Federal Clean Air Act at IPL’s three primarily coal-fired electric generating facilities dating back to 1986. The alleged violations primarily pertain to the PSD and nonattainment New Source Review requirements under the Federal Clean Air Act. Since receiving the letter, IPL management has met with the EPA staff regarding possible resolutions of the NOV. At this time, we cannot predict the ultimate resolution of this matter. Additionally, on February 5, 2016, EPA issued a NOV pursuant to CAA Section 113(a) alleging violations of New Source Review and other CAA regulations, the Indiana SIP, and the Title V operating permit at Petersburg Generating Station. IPL is currently reviewing the NOV and allegations. 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 this case could have a material impact on our business. We would seek recovery of any operating or capital expenditures, but not fines or penalties, related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that we would be successful in this regard. IPL has recorded a contingent liability related to the October 2009 NOV matter and continues to evaluate the February 5, 2016 NOV.

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. Since receiving the letter, IPL management has met with EPA staff regarding possible resolutions to this NOV. It is too early to determine whether the NOVs could have a material impact on our business, financial condition or results of operations. We would seek recovery of any operating or capital expenditures, but not fines or penalties, related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that we would be successful in this regard.

CSAPR

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

On July 6, 2011, the EPA announced a new rule to replace CAIR, that will require further reduction of SO2 and NOx emissions from power plants in 28 states, including Indiana, that contribute to ozone and/or fine particle pollution in other states. This rule, known as the CSAPR, required initial compliance by January 1, 2012 for SO2 and annual NOx reductions, and May 1, 2012 for ozone season reductions. On December 30, 2011, the U.S. Court of Appeals for the District of Columbia issued an order staying implementation of CSAPR pending resolution of legal challenges to the rule. The Court further ordered that CAIR remain in place while CSAPR was stayed. In August 2012, the U.S. Court of Appeals issued a ruling vacating CSAPR. The Court ruling also required EPA to continue administering CAIR.

In June 2013, the U.S. Supreme Court agreed to review the D.C. Circuit Court’s decision to vacate the CSAPR and in April 2014, reversed the 2012 decision by the D.C. Circuit Court, reinstating CSAPR, and remanded the case to the D.C. Circuit Court for further proceedings consistent with the U.S. Supreme Court decision. In June 2014, the U.S. Department of Justice, on behalf of the EPA, filed a motion with the D.C. Circuit Court to lift the stay on CSAPR and on October 23, 2014, the D.C. Circuit Court lifted the stay. On November 21, 2014, EPA announced a Notice of Data Availability and a final interim rule that addresses allocations of emission allowances to certain units for compliance with the CSAPR. These allowance allocations, which supersede the allocations announced in a 2011 NODA, reflect the changes to CSAPR made in subsequent rulemakings, as well as “re-vintaging” of previously recorded allowances so as to account for the impact of the tolling of the CSAPR deadlines pursuant to an order issued by the D.C. Circuit Court. On July 28, 2015, the D.C. Circuit Court held invalid the 2014 SO2 and ozone-season NOx emissions budgets for certain states (not including Indiana). It rejected all of the petitioners’ other challenges to the rule. The budgets remain in place pending reconsideration. On December 3, 2015, EPA published the proposed CSAPR Update Rule to address interstate air quality impacts with respect to the 2008 Ozone NAAQS. It is too early to determine whether this proposed update rule may have a material impact on IPL. While we are currently unable to determine the full impact of the reinstatement of CSAPR, the rule and future revisions may have a material impact on IPL.

NAAQS

Under the CAA, the EPA sets NAAQS for six criteria pollutants considered harmful to public health and the environment, including particulate matter, NOx, ozone and SO2, which result from coal combustion. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS, which may include imposing operating limits on individual plants. The EPA is required to review NAAQS at five-year intervals.

Ozone. Over the past several years, the EPA has tightened the NAAQS for ground level ozone by lowering the standard for daily emissions of ozone from 80 parts per billion to 75 parts per billion. In July 2013, the U.S. Circuit Court of Appeals upheld the 75 parts per billion standard. In December 2013 eight northeastern states petitioned the EPA to add nine upwind states, including Indiana, to the Ozone Transport Region, a group of states required to impose enhanced restrictions on ozone emissions. If the petition is granted, our facilities could be subject to such enhanced requirements.

On October 1, 2015, the EPA released a final rule lowering the NAAQS for ozone to 70 parts per billion from 75 parts per billion. The rule was published in the Federal Register on October 26, 2015. Attainment and nonattainment determinations with respect to the ozone NAAQS are expected by October 1, 2017. Environmental groups have petitioned the D.C. Circuit Court to review the rule, arguing that the standard should have been set at 60 parts per billion. Industry groups have filed to oppose this position. We are currently reviewing the rule and assessing the impact on our operations. We cannot at this time determine the impact of this regulation or litigation, but it could be material to our business, financial condition or results of operations.

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

NOx and SO2. On April 12, 2010, a one-hour primary NAAQS became effective for NOx. Additionally, on August 23, 2010, a new one-hour SO2 primary NAAQS became effective. The final rule implementing the one-hour SO2 NAAQS also requires an increased amount of ambient SO2 monitoring sites. On August 5, 2013, EPA published in the Federal Register its final

designation, which include portions of Marion, Morgan, and Pike counties as nonattainment with respect to the one-hour SO2 standard.

On September 30, 2015, IDEM published its final rule establishing reduced SO2 limits for IPL facilities in accordance with a new one-hour standard of 75 parts per billion, for the areas in which IPL’s Harding Street, Petersburg, and Eagle Valley Generating Stations operate. The expected compliance date for these requirements is January 1, 2017. No impact is expected for Eagle Valley or Harding Street Generating Stations because these facilities will cease coal combustion prior to the compliance date. It is expected that improvements to the existing FGDs at Petersburg will be required in order to comply. IPL has engaged an engineering firm to further assess potential compliance measures and associated costs and timing. While costs associated with the proposed rule cannot accurately be predicted at this time, they could be material.

Based on these current and potential ambient standards, the state of Indiana will be required to determine whether certain areas within the state meet the NAAQS. 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.

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 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, waste materials are not usually physically disposed of on our property, but are shipped off site for final disposal, treatment or recycling. Approximately 30% of our CCR are beneficially used off-site as a raw material for production of wallboard, concrete or cement and as agricultural soil amendment and approximately 70% is 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.

On June 21, 2010, the EPA published in the Federal Register a proposed rule that establishes regulation of coal combustion residuals under the RCRA, which consisted of two options pursuant to which CCRs could be regulated as special waste under Subtitle C of RCRA or as non-hazardous solid waste under Subtitle D of RCRA. On December 19, 2014, the EPA announced the final CCR rule, which is to regulate CCRs under the less restrictive non-hazardous solid waste designation. The EPA published in the Federal Register a final rule on April 17, 2015, and it became effective on October 19, 2015. Generally, the rule establishes national minimum criteria for existing and new CCR landfills and existing and new CCR surface impoundments (ash ponds), including location restrictions, design and operating criteria, groundwater-monitoring and corrective action, and closure requirements and post closure care. We continue to assess the impact of the final rule on our operations. Our business, financial condition or results of operations could be materially and adversely affected by this rule.

PCBs

On April 7, 2010, the EPA published an Advance Notice of Proposed Rulemaking announcing that it is reassessing existing regulations governing the use and distribution in commerce of PCBs. While this reassessment is in the early stages and the EPA is seeking information from potentially affected parties on how it should proceed, revised regulations may have a material effect. A proposed rule is expected in 2016, with a final rule expected in 2017. At present, we are unable to predict the impact this initiative will have on our results of operations, financial condition or cash flows.

Cooling Water Intake Regulations

We use water as a coolant at our generating facilities. Under the CWA, cooling water intake structures are required to reflect the BTA for minimizing adverse environmental impact. On August 15, 2014, the EPA published its final standards to protect fish and other aquatic organisms drawn into cooling water systems at large power plants and other facilities that withdraw from waters of the U.S. greater than two million gallons per day of which more than 25% is used for cooling. The final rule became effective on October 14, 2014. These standards, based on Section 316(b) of the CWA, require affected facilities to choose amongst seven BTA options to reduce fish impingement. In addition, facilities that withdraw water from a source water body above a minimum actual volume must conduct studies to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms. This decision process would include

public input as part of a permit renewal or permit modification. It is possible this process could result in the need to install closed-cycle cooling systems (closed-cycle cooling towers), or other technology. Finally, the standards require that new units added to an existing facility must reduce both impingement and entrainment that achieves one of two alternatives under national BTA standards. IPL’s NPDES permits will be updated with the requirements of this rule, including any source-specific requirements arising from the evaluation process described above. As a result, it is not yet possible to predict the total impacts of this final rule at this time, including any challenges to such final rule and the outcome of any such challenges. However, if additional capital expenditures are necessary, they could be material. We would seek recovery of these capital expenditures; however, there is no guarantee we would be successful in this regard.

Summary

Environmental laws and regulations presently require us to incur material capital expenditures and operating costs. We expect to incur material costs, both in capital expenditures and ongoing operating and maintenance costs, to comply with the MATS rule (up to $454 million in capital expenditures), NPDES permit requirements at our Petersburg plant (up to $224 million in capital expenditures), and plans to refuel Unit 7 at Harding Street converting from coal-fired to natural gas-fired (up to $108 million in capital expenditures; which includes costs for NPDES, MATS preservation and dry ash handling), and, to a lesser extent to which we cannot predict, other expected environmental regulations related to: CSAPR; CCRs; cooling water intake; NAAQS; EPA’s regulations related to GHG emissions from power plants; ELGs and PCBs. In addition, the combination of existing and expected environmental regulations, the IURC's approval of our replacement generation plan and other economic factors have resulted in us retiring or refueling several of our existing, primarily coal-fired, generating units between 2013 and 2017 (the total estimated costs of these projects is $632 million, as discussed in “Unit Retirements and Replacement Generation” above). We would expect to seek recovery of both capital and operating costs related to all such compliance, although there can be no assurances that we would be successful in this regard. In addition, environmental laws and regulations are complex, change frequently and have tended to become more stringent over time. As a result, our operating expenses and continuing capital expenditures associated with environmental matters may increase. More stringent standards may also limit our operating flexibility and have a negative impact on our wholesale volumes and margins. Depending on the level and timing of recovery allowed by the IURC, these costs could materially and adversely affect our results of operations, financial condition and cash flows. We may seek recovery of any operating or capital expenditures; however, there can be no assurances that we would be successful in this regard.

ENERGY SUPPLY

Approximately 97% of the total kWh we generated in 2015 was from coal as compared to approximately 99% in both 2014 and 2013. Our existing coal contracts provide for all of our current projected requirements in 2016 and 2017 and approximately 85% in total for the three-year period ending December 31, 2018. We have long-term coal contracts with four suppliers. Approximately 53% of our existing coal under contract for the three-year period ending December 31, 2018 comes from one supplier. We have one contract with this supplier, which employs non-unionized labor, for the provision of coal from three separate mines.

Historically, we used coal as a fuel source at Petersburg, Harding Street Station and Eagle Valley. When the Harding Street Station Unit 7 conversion is complete, which we anticipate will be in the second quarter of 2016, we will no longer burn coal at Harding Street. When the coal-fired units at Eagle Valley are retired, which we anticipate will occur in the second quarter of 2016, we will no longer burn coal at Eagle Valley. Since we will only burn coal at Petersburg, it is likely that the coal supply will come from a limited number of suppliers.

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. However, our system-wide inventory levels were beyond the 50-day high end of the inventory target range as of December 31, 2015. Mild weather and soft markets have recently combined for a coal burn significantly below expectations. We are actively managing our inventory levels and expect to bring the coal inventory back into our target range as soon as is practicable.

Natural gas and fuel oil provided the remaining kWh generation. Natural gas is used in our combustion turbines (and Units 5 and 6 at Harding Street Station beginning in December 2015). The Harding Street Station Unit 7 conversion is expected to be completed in the second quarter of 2016 and will also use natural gas. 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 combustion turbines.

With the completion of the Harding Street Station refueling projects for Units 5, 6 and 7, the total kWh we expect to generate from coal and natural gas will continue to change. This will change again when the coal-fired units at Eagle Valley are retired, which we anticipate will occur in the second quarter of 2016, and the CCGT at the Eagle Valley Station is placed in service, expected in April 2017. At the completion of these projects, we expect approximately 50% of the total kWh we generate to be from coal, and approximately 50% to be from natural gas.

Additionally, we meet the electricity demands of our retail customers with power purchased under wind and solar energy power purchase agreements and by purchases in MISO. We are committed under long-term power purchase agreements to purchase all wind-generated electricity 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 2016, of which 95 MW was in operation as of December 31, 2015.

Total electricity sold to our retail customers in 2015 came from the following sources: IPL-owned coal-fired steam generation of 80.5%, IPL-owned natural gas-fired units of 2.6%, wind power purchases of 5.0%, solar power purchases of 0.9%, and the remaining 11.0% from the wholesale power market. With the Harding Street Station units 5, 6 and 7 conversions, Eagle Valley retirements and the CCGT, we expect the sources of electricity to change accordingly over the next 12 to 15 months.

STATISTICAL INFORMATION ON OPERATIONS

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



	Year Ended December 31,
	2015		2014		2013		2012		2011
Operating Revenues (In Thousands):
Residential	$	480,969	$	485,779	$	472,630	$	466,294	$	438,204
Small commercial and industrial	192,232		193,213		185,241		183,681		174,934
Large commercial and industrial	526,461		527,719		504,038		510,669		482,223
Public lighting	10,823		10,811		10,743		10,872		10,910
Retail electric revenues	1,210,485		1,217,522		1,172,652		1,171,516		1,106,271
Wholesale	19,307		83,208		62,734		37,822		43,181
Miscellaneous	20,607		20,944		20,348		20,439		22,472
Total utility operating revenues	$	1,250,399	$	1,321,674	$	1,255,734	$	1,229,777	$	1,171,924
kWh Sales (In Millions):
Residential	5,062		5,269		5,243		5,144		5,266
Small commercial and industrial	1,837		1,888		1,882		1,862		1,887
Large commercial and industrial	6,757		6,778		6,841		6,945		7,012
Public lighting	53		59		63		64		64
Sales – retail customers	13,709		13,994		14,029		14,015		14,229
Wholesale	689		2,397		2,005		1,308		1,418
Total kWh sold	14,398		16,391		16,034		15,323		15,647
Retail Customers at End of Year:
Residential	431,182		427,866		424,201		419,867		417,153
Small commercial and industrial	47,919		47,534		47,360		47,108		46,974
Large commercial and industrial	4,737		4,749		4,727		4,645		4,630
Public lighting	953		945		935		957		954
Total retail customers	484,791		481,094		477,223		472,577		469,711

HOW TO CONTACT IPALCO

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

ITEM 1A. RISK FACTORS

Investors should consider carefully the following risk factors that could cause our business, operating results and financial condition to be materially adversely affected. New risks may emerge at any time, and we cannot predict those risks or estimate the extent to which they may affect our business or financial performance. These risk factors should be read in conjunction with the other detailed information concerning IPALCO and IPL set forth in the Notes to the audited Consolidated Financial Statements in “Item 8. Financial Statements and Supplementary Data” and in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” herein. The risks and uncertainties described below are not the only ones we face.

Our electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and/or maintenance expenses, increased fuel or purchased power costs and other significant liabilities for which we may 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 such as fires, explosions, cyber-attacks, terrorist acts, sabotage, acts of war, pandemic events, or natural disasters such as floods, earthquakes (including seismic activity from the Wabash Valley seismic zone, an area of significant seismic activity in the central U.S.), tornadoes, severe winds, ice or snow storms, droughts, or other similar occurrences affecting our generating facilities, as well as our transmission and distribution systems.

The above risks could result in unscheduled plant outages, unanticipated operation and/or maintenance expenses, increased capital expenditures, and/or increased fuel and purchased power costs, any of which could have a material adverse effect on our results of operations, financial condition and cash flows. If unexpected plant outages occur frequently and/or for extended periods of time, this could result in adverse regulatory action and/or reduced wholesale revenues.

Additionally, as a result of the above risks and other potential hazards associated with the power generation industry, we may from time to time become exposed to significant liabilities for which we may not have adequate insurance coverage. Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. The control and management of these risks depend upon adequate development and training of personnel and on the existence of operational procedures, preventative maintenance plans and specific programs supported by quality control systems which reduce, but do not eliminate, the possibility of the occurrence and impact of these risks.

The hazardous activities described above can also cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in our being named as a defendant in lawsuits asserting claims for substantial damages, environmental cleanup costs, personal injury and fines and/or penalties. We maintain an amount of insurance protection that we believe is adequate, but there can be no assurance that our insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. A successful claim for which we are not fully insured could hurt our financial results and materially harm our financial condition. In addition, except for IPL’s large substations, transmission and distribution assets are not covered by insurance and are considered to be outside the scope of

property insurance. Further, due to rising insurance costs and changes in the insurance markets, we cannot provide assurance that insurance coverage will continue to be available on terms similar to those presently available to us or at all. Any such losses not covered by insurance could have a material adverse effect on our financial condition, results of operations and cash flows.

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

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

We are currently obligated to supply electric energy to retail customers in our service territory. Even though rate regulation is premised on full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the IURC will agree that all of our costs have been prudently incurred or are recoverable. There also is no assurance that the regulatory process in which rates are determined will always result in rates that will produce a full or timely recovery of our costs and authorized return. From time to time, the demand for electric energy required to meet our service obligations could exceed our available electric generating capacity. When our retail customer demand exceeds our generating capacity for units operating under MISO economic dispatch, recovery of our cost to purchase electric energy in the MISO market to meet that demand is subject to a stipulation and settlement agreement. The agreement includes a benchmark which compares hourly purchased power costs to daily natural gas prices. Purchased power costs above the benchmark must meet certain criteria in order for us to fully recover them from our retail customers, such as consideration of the capacity of units available but not selected by the MISO economic dispatch. We may not always have the ability to pass all of the purchased power costs on to our customers, and even if we are able to do so, there may be a significant delay between the time the costs are incurred and the time the costs are recovered. Since these situations most often occur during periods of peak demand, the market price for electric energy at the time we purchase it could be very high, and we may not be allowed to recover all of such costs through our FAC. Even if a supply shortage were brief, we could suffer substantial losses that could adversely affect our results of operations, financial condition and cash flows. Please see “Item 1. Business - Regulatory Matters - FAC and Authorized Annual Jurisdictional Net Operating Income” for additional details regarding the benchmark and the process to recover fuel costs.

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

The availability and cost of fuel and other commodities has 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 majority of our supply of coal 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. In addition, we may generally recover the energy portion of our purchased power costs in these quarterly FAC proceedings subject to a benchmark (as discussed in “Item 1. Business - Regulatory Matters”). 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 in the future 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 97% of the energy we produced in 2015 was generated by coal as compared to approximately 99% in both 2014 and 2013. While we have approximately 85% in total of our current coal requirements for the three-year period ending December 31, 2018 under long-term contracts, the balance is yet to be purchased and will be purchased under a combination of long-term contracts, short-term contracts and on the spot market. Prices can be highly volatile in both the short-term market and on the spot market. 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 consolidated 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 are now running 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 mined by unaffiliated suppliers or third parties. Our goal is to carry a 25-50 day system supply of coal to offset unforeseen occurrences such as equipment breakdowns and transportation or mine delays. Moreover, a majority of our existing coal under contract for the three-year period ending December 31, 2018 comes from a single 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.

Regulators, politicians and non-governmental organizations have expressed concern about GHG emissions and are taking actions which, in addition to the potential physical risks associated with climate change, could have a material adverse impact on our consolidated results of operations, financial condition and cash flows.

One byproduct of burning coal and other fossil fuels is the emission of GHGs, including CO₂. At the federal, state and regional levels, policies are under development or have been developed to regulate GHG emissions, including by effectively putting a cost on such emissions to create financial incentives to reduce them. In 2015, IPL emitted approximately 14 million tons of CO₂ from our power plants. IPL uses CO₂ emission estimation methodologies supported by “The Greenhouse Gas Protocol” reporting standard on GHG emissions. Our CO₂ emissions are calculated from actual fuel heat inputs and fuel type CO₂ emission factors.

Any existing or future international, federal, state or regional legislation or regulation of GHG emissions could have a material adverse impact on our financial performance. The actual impact on our financial performance will depend on a number of factors, including among others, the degree and timing of GHG emissions reductions required under any such legislation or regulations, the price and availability of offsets, the extent to which market-based compliance options are available, the extent to which we would be entitled to receive GHG emissions allowances without having to purchase them in an auction or on the open market and the impact of such legislation or regulation on our ability to recover costs incurred through rate increases or otherwise. As a result of these factors, our cost of compliance could be substantial and could have a material adverse impact on our results of operations, financial condition and cash flows. Such legislation and regulations could also impair the value of our generation stations or make some of these stations uneconomical to maintain or operate and could raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing generation stations. Although we may seek recovery of costs associated with new climate change or GHG regulations, our inability to fully or timely recover such costs could have a material adverse effect on our results of operations, financial condition and cash flows. Additionally,

concerns over GHG emissions and their effect on the environment could lead to reduced demand for coal-fired power, which could have a material adverse effect on our consolidated 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 consolidated results of operations, financial condition and cash flows.

In addition to the rules already in effect, regulatory initiatives regarding GHG emissions may be implemented in the future, although at this time we cannot predict if, how, or to what extent such initiatives would affect us. Generally, we believe costs to comply with any regulations implemented to reduce GHG emissions, including those already promulgated, would be deemed as part of the costs of providing electricity to our customers and as such, we would seek recovery for such costs in our rates. However, no assurance can be given as to whether the IURC will approve such requests. Finally, concerns over GHG emissions and their effect on the environment could lead to reduced demand for coal-fired power, which could have a material adverse effect on our consolidated results of operations, financial condition and cash flows. Please see “Item 1. Business - Environmental Matters” for a more comprehensive discussion of environmental matters impacting us, including those relating to regulation of GHG emissions.

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

We are subject to various federal, state, regional and local environmental protection and health and safety laws and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of regulated materials, including ash; the use and discharge of water used in generation boilers and for cooling purposes; the emission and discharge of hazardous and other materials into the environment; and the health and safety of our employees. We could also become subject to additional environmental laws and regulations and other requirements in the future. These laws and regulations often require a lengthy and complex process of obtaining and renewing permits and other governmental authorizations from federal, state and local agencies. A violation of these laws, regulations or permits can result in substantial fines, other sanctions, permit revocation and/or facility shutdowns. In addition, any alleged violation of these laws, regulations and other requirements may require us to expend significant resources to defend against any such alleged violations. Compliance with these laws, regulations and other requirements requires us to expend significant funds and resources and could at some point become prohibitively expensive or result in our shutting down (temporarily or permanently) or altering the operation of our facilities. Environmental laws and regulations also generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. If we are not able to timely obtain, maintain or comply with all licenses, permits, inspections and approvals required to operate our business, then our operations could be prevented, delayed or subject to additional costs. Failure to comply with environmental laws, regulations and other requirements may result in the imposition of fines and penalties or other sanctions and the imposition of stricter environmental standards and controls and other injunctive measures affecting operating assets. Under certain environmental laws, we could also be held responsible for costs relating to contamination at our past or present facilities and at third-party waste disposal sites. We could also be held liable for human exposure to such hazardous substances or for other environmental damage. From time to time we are subject to enforcement and litigation actions for claims of noncompliance with environmental laws and regulations. We cannot assure that we will be successful in defending against any claim of noncompliance. Any alleged violation of these laws, regulations and other requirements may require us to expend significant resources to defend against any such alleged violations. Our costs and liabilities relating to environmental matters could have a material adverse effect on our results of operations, financial condition and cash flows.

The amount of capital expenditures required to comply with environmental laws or regulations could be impacted by the outcome of the EPA’s NOVs described in “Item 1. Business - Environmental Matters - New Source Review and Other CAA NOVs.” These NOVs could also result in fines, which could be material. In addition to the five oil-fired peaking units that were retired in the second quarter of 2013, the combination of existing and expected environmental regulations has resulted in us

retiring or refueling several other generating units by 2017, as described in “Item 1. Business - Environmental Matters - Unit Retirements and Replacement Generation.” Our units are primarily coal-fired and the units that are currently being retired and/or converted are not equipped with the advanced environmental control technologies needed to comply with existing and expected regulations.

Please see “Item 1. Business - Environmental Matters” for a more comprehensive discussion 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 Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was signed into law. The Dodd-Frank Act contains significant requirements relating to derivatives, including, among others, a requirement that certain transactions be cleared on exchanges that would necessitate the posting of cash collateral for these transactions. We are considered an end-user under the Dodd-Frank Act and therefore are exempt from most of the collateral and margining requirements. We are required to report any bilateral derivative contracts, unless our counterparty is a major swap participant or has elected to report on our behalf. Even though we qualify for an exception from these requirements, our counterparties that do not qualify for the exception may pass along any increased costs incurred by them through higher prices and reductions in unsecured credit limits or be unable to enter into certain transactions with us. The occurrence of any of these events could have an adverse effect on our results of operations, financial condition and cash flows.

Our business is sensitive to weather and seasonal variations.

Weather conditions significantly affect the demand for electric power, and accordingly, our business is affected by variations in general weather conditions and unusually severe weather. As a result of these factors, our operating revenues and associated operating expenses are not generated evenly by month during the year. We forecast electric sales on the basis of normal weather, which represents a long-term historical average. Significant variations from normal weather (such as warmer winters and cooler summers) could have a material impact on our revenue, operating income and net income and cash flows. In addition, severe or unusual weather, such as tornadoes and ice or snow storms, may cause outages and property damage that may require us to incur additional costs that may not be insured or recoverable from customers. While we are permitted to seek recovery of storm damage costs, if we are unable to fully recover such costs in a timely manner, it could have a material adverse effect on our results of operations, financial condition and cash flows.

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

We are a member of MISO, a FERC-regulated regional transmission organization. MISO serves the electrical transmission needs of a 15-state area including much of the Mid-U.S. and Canada and maintains functional operational control over our electric transmission facilities as well as that of the other utility members of MISO. We retain control over our distribution facilities. As a result of membership in MISO and its operational control, our continued ability to import power, when necessary, and export power to the wholesale market has been, and may continue to be, impacted. We offer our generation and

bid our load into this market on a day-ahead basis and settle differences in real time. Given the nature of MISO’s policies regarding use of transmission facilities, and its administration of the energy and ancillary services markets, it is difficult to predict near-term operational impacts. We cannot assure MISO’s reliable operation of the regional transmission system, or the impact of its operation of the energy and ancillary services markets.

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

To the extent that we rely, at least in part, on the performance of MISO to maintain the reliability of our transmission system, it puts us at some risk for the performance of MISO. In addition, actions taken by MISO to secure the reliable operation of the entire transmission system operated by MISO could result in voltage reductions, rolling blackouts, or sustained system-wide blackouts on IPL’s transmission and distribution system, any of which could have a material adverse effect on our results of operations, financial condition and cash flows. See also “Item 1. Business - Regulatory Matters” and “Item 1. Business - MISO Operations.”

If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties, which likely would not be recoverable from customers through regulated rates.

As an owner and operator of a bulk power transmission system, IPL is subject to mandatory reliability standards promulgated by the NERC and enforced by the FERC. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and is guided by reliability and market interface principles. Compliance with reliability standards may subject us to higher operating costs or increased capital expenditures. Although we expect to recover costs and expenditures from customers through regulated rates, there can be no assurance that the IURC will approve full recovery in a timely manner. If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties, which likely would not be recoverable from customers through regulated rates and could have a material adverse effect on our results of operations, financial condition and cash flows.

We rely on access to the financial markets. General economic conditions and disruptions in the financial markets could adversely affect our ability to raise capital on favorable terms or at all, and cause increases in our interest expense.

From time to time we rely on access to the capital and credit markets as a source of liquidity for capital requirements not satisfied by operating cash flows. These capital and credit markets experience volatility and disruption from time to time and the ability of corporations to raise capital can be negatively impacted. Disruptions in the capital and credit markets make it harder and more expensive to raise capital. It is possible that our ability to raise capital on favorable terms or at all could be adversely affected by future market conditions, and we may be unable to access adequate funding to refinance our debt as it becomes due or finance capital expenditures. The extent of any impact will depend on several factors, including our operating cash flows, the overall supply and demand in the credit markets, our credit ratings, credit capacity, the cost of financing, and other general economic and business conditions. It may also depend on the performance of credit counterparties and financial institutions with which we do business. Access to funds under our existing financing arrangements is also dependent on the ability of our counterparties to meet their financing commitments. Our inability to obtain financing on reasonable terms, or at all, with creditworthy counterparties could adversely affect our results of operations, financial condition and cash flows. If our available funding is limited or we are forced to fund our operations at a higher cost, these conditions may require us to curtail our business activities and increase our cost of funding, both of which could reduce our profitability.

See Note 7, “Debt” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K for information regarding indebtedness. See also “Item 7A. Quantitative and Qualitative Disclosure about Market Risk” for information related to market risks.

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

As of December 31, 2015, we had on a consolidated basis $2.3 billion of indebtedness and total common shareholder’s equity of $352.9 million. IPL had $1,283.5 million of first mortgage bonds outstanding as of December 31, 2015, 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.

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

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

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

Our business, results of operations, financial condition and cash flows have been and will continue to be affected by general economic conditions. Slowing global economic growth, credit market conditions, fluctuating consumer and business confidence, fluctuating commodity prices, and other challenges currently affecting the general economy, have caused and may continue to cause some of our customers to experience deterioration of their businesses, cash flow shortages, and difficulty obtaining financing. As a result, existing customers may reduce their electricity consumption and may not be able to fulfill their payment obligations to us in the normal, timely fashion. In addition, some existing commercial and industrial customers may discontinue their operations. Sustained downturns, recessions or a sluggish economy generally affect the markets in which we operate and negatively influence our energy operations. A contracting, slow or sluggish economy could reduce the demand for energy in areas in which we are doing business. For example, during economic downturns, our commercial and industrial customers may see a decrease in demand for their products, which in turn may lead to a decrease in the amount of energy they require. Furthermore, projects which may result in potential new customers may be delayed until economic conditions improve. Our suppliers could also be affected by the economic downturn resulting in supply delays or unavailability. 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.

Some of our suppliers, customers and other counterparties, and others with whom we transact business may be experiencing financial difficulties, which may impact their ability to fulfill their obligations to us. For example, our counterparties on forward purchase contracts and financial institutions involved in our credit facility may become unable to fulfill their contractual obligations. We may not be able to enter into replacement agreements on terms as favorable as our existing agreements. If the general economic slowdown continues for significant periods or deteriorates significantly, our results of operations, financial condition and cash flows could be materially adversely affected.

Wholesale power marketing activities may add volatility to earnings.

We engage in wholesale power marketing activities that primarily involve the offering of utility-owned or contracted generation into the MISO day-ahead and real-time markets. As part of these strategies, we may also execute energy contracts that are integrated with portfolio requirements around power supply and delivery. The earnings from wholesale marketing activities may vary based on fluctuating prices for electricity and the amount of electric generating capacity, beyond that needed to meet firm service requirements. In order to reduce the risk of volatility in earnings from wholesale marketing activities, we may at times enter into forward contracts to hedge such risk. If we do not accurately forecast future commodities prices or if our hedging procedures do not operate as planned we may experience losses. We did not use such hedges in 2015, 2014 or 2013.

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

As a result of the expected refueling of Harding Street Station Unit 7 (second quarter of 2016), the expected retirement of the coal-fired units at Eagle Valley (second quarter of 2016), and the April 2017 expected in-service date for the CCGT, we expect our ability to have excess generation available for sale on the wholesale market will be adversely impacted during 2016 through the first quarter of 2017.

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

Pension costs are based upon a number of actuarial assumptions, including an expected long-term rate of return on pension plan assets, level of employer contributions, the expected life span of pension plan beneficiaries and the discount rate used to determine the present value of future pension obligations. Any of these assumptions could prove to be wrong, resulting in a shortfall of our Pension Plans’ assets compared to pension obligations under the Pension Plans. Further, the performance of the capital markets affects the values of the assets that are held in trust to satisfy future obligations under the Pension Plans. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. A decline in the market value of the Pension Plans’ assets will increase the funding requirements under the Pension Plans if the actual asset returns do not recover these declines in value in the foreseeable future. Future pension funding requirements, and the timing of funding payments, may also be subject to changes in legislation. We are responsible for funding any shortfall of our Pension Plans’ assets compared to obligations under the Pension Plans, and a significant increase in our pension liabilities could materially and adversely impact our results of operations, financial condition, and cash flows. We are subject to the Pension Protection Act of 2006, which requires underfunded pension plans to improve their funding ratios within prescribed intervals based on the level of their underfunding. As a result, our required contributions to these plans, at times, have increased and may increase in the future. In addition, our pension and postemployment benefit plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the discounted liabilities increase benefit expense and funding requirements. Further, changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase the funding requirements for the obligations related to the pension and other postemployment benefit plans. Declines in market values and increased funding requirements could have a material adverse effect on our results of operations, financial condition and cash flows. Please see Note 9, “Benefit Plans” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K for further discussion.

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

We enter into transactions with and rely on many counterparties in connection with our business, including for the purchase and delivery of inventory, including fuel and equipment components, for our capital improvements and additions and to provide

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

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

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

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

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

Our Consolidated 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 Consolidated Financial Statements, management is required to make estimates and assumptions. Actual results could differ significantly from those estimates.

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

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

Our tariff rates for electric service to retail customers consist of basic rates and charges and various adjustment mechanisms which are set and approved by the IURC after public hearings. Pursuant to statute, the IURC is to conduct a periodic review of the basic rates and charges of all Indiana utilities at least once every four years, but the IURC has the authority to review the rates of any Indiana utility at any time. Proceedings to review our basic rates and charges involve IPL, the IURC, the Indiana Office of Utility Consumer Counselor and other interested stakeholders. Our basic rates and charges were last adjusted in 1996; however, IPL filed a petition with the IURC on December 29, 2014, for authority to increase its basic rates and charges. For additional information about this proceeding, please see “Item 1. Business - Regulatory Matters”. No assurances can be given as to the outcome of this proceeding. In addition, we must seek approval from the IURC through such public proceedings of our tracking mechanism factors to reflect changes in our fuel costs to generate electricity or purchased power costs and for the timely recovery of costs incurred during construction and operation of CCT facilities constructed to comply with environmental laws and regulations, recovery of costs associated with providing mandatory DSM programs, and for certain other costs. There can be no assurance that we will be granted approval of tracking mechanism factors that we request from the IURC. 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.

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

We may be subject to material litigation, regulatory proceedings, administrative proceedings, audits, settlements, investigations and claims from time to time which may require us to expend significant funds to address. There can be no assurance that the outcome of these matters will not have a material adverse effect on our business, results of operations, financial condition and cash flows. Asbestos and other regulated substances are, and may continue to be, present at our facilities. We have been named as a defendant in asbestos litigation, which at this time is not expected to be material to us. The presence of asbestos and other regulated substances at these facilities could result in additional litigation being brought against us, which could have a material adverse effect on our results of operations, financial condition and cash flows. Please see Note 2, “Regulatory Matters” and Note 10, “Commitments and Contingencies” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K for a summary of significant regulatory matters and legal proceedings involving us.

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 65% of our employees are represented by a union in two bargaining units: a physical unit and a clerical-technical unit. While we believe that we maintain a satisfactory relationship with our employees, it is possible that labor disruptions affecting some or all of our operations could occur during the period of the collective bargaining agreements or at the expiration of the collective bargaining agreements before new agreements are negotiated. We may not be able to successfully train new personnel as current workers with significant knowledge and expertise retire. We also may be unable to staff our business with qualified personnel in the event of significant absenteeism related to a pandemic illness. Work stoppages by, or poor relations or ineffective negotiations with, our employees or other workforce issues could have a material adverse effect on our results of operations, financial condition and cash flows.

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

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

In the course of our business, we also store and use customer, employee, and other personal information and other confidential and sensitive information. If our 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 audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K for information regarding indebtedness. In addition, IPL is regulated by the IURC, which possesses broad oversight powers to ensure that the needs of utility customers are being met. The IURC could impose additional restrictions on the ability of IPL to distribute, loan or advance cash to IPALCO pursuant to these broad powers. While we do not expect any of the foregoing restrictions to significantly affect IPL’s ability to pay funds to IPALCO in the future, a significant limitation on IPL’s ability to pay dividends or loan or advance funds to IPALCO would have a material adverse effect on IPALCO’s results of operations, financial condition and cash flows.

Our ownership by AES subjects us to potential risks that are beyond our control.

All of IPL’s common stock is owned by IPALCO, all of whose common stock is owned by AES U.S. Investments (88.4%) and CDPQ (11.6%). Due to our relationship with AES, any adverse developments and announcements concerning them may impair our ability to access the capital markets and to otherwise conduct business. In particular, downgrades in AES’s credit ratings could result in IPL or IPALCO’s credit ratings being downgraded.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

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

Mortgage Financing on Properties

IPL's mortgage and deed of trust secures first mortgage bonds issued by IPL. Pursuant to the terms of the mortgage and deed of trust, substantially all property owned by IPL is subject to a direct first mortgage lien securing indebtedness of $1,283.5 million at December 31, 2015. In addition, IPALCO has outstanding $805 million of Senior Secured Notes which are secured by its pledge of all of the outstanding common stock of IPL.

ITEM 3. LEGAL PROCEEDINGS

We are involved in certain claims, suits and legal proceedings in the normal course of business. We have accrued 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, based upon information we currently possess and taking into account established reserves for estimated liabilities and our insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material adverse effect on our financial statements, with the possible exception of the New Source Review NOV from the EPA (please see Note 10, “Commitments and Contingencies - Environmental Loss Contingencies - New Source Review” in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K for details). It is reasonably possible, however, that some matters could be decided unfavorably to us and could require us to pay damages or make expenditures in amounts that could be material but cannot be estimated as of December 31, 2015.

Please see “Item 1. Business – Environmental Matters,” and Note 2, “Regulatory Matters” and Note 10, “Commitments and Contingencies” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K for a summary of significant legal proceedings involving us.

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

For most of 2015 and as of February 23, 2016, all of the outstanding common stock of IPALCO has been owned by AES U.S. Investments (88.4%) and CDPQ (11.6%). As a result, our stock is not listed for trading on any stock exchange.

Dividends

During the years ended December 31, 2015, 2014 and 2013, we paid dividends to our shareholders totaling $69.5 million, $78.4 million and $59.5 million, respectively. Future distributions to our shareholders will be determined at the discretion of our board of directors and will depend primarily on dividends received from IPL and such other factors as our board of directors deems relevant. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity” of this Form 10-K for a discussion of limitations on dividends from IPL. In order for us to make any dividend payments to our shareholders, we must, at the time and as a result of such dividends, either maintain certain credit ratings on our senior long-term debt or be in compliance with leverage and interest coverage ratios contained in IPALCO’s Articles of Incorporation. We do not believe this requirement will be a limiting factor in paying dividends in the ordinary course of prudent business operations.

ITEM 6. SELECTED FINANCIAL DATA

The following table presents our selected consolidated financial data which should be read in conjunction with our audited Consolidated Financial Statements and the related notes thereto and “Item 7. 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 are also included in this table.



	Year Ended December 31,
	2015		2014		2013		2012			2011
	(In Thousands)
Statement of Operations Data:
Utility operating revenues	$	1,250,399	$	1,321,674	$	1,255,734	$	1,229,777		$	1,171,924
Utility operating income	144,711		160,913		150,746		162,900			152,653
Allowance for funds used during construction	28,111		12,344		6,848		2,146			6,624
Net income	59,524		77,968		64,049		71,996			60,575
Balance Sheet Data (end of period):
Utility plant – net	$	3,451,383	$	2,856,634	$	2,553,261	$	2,425,610		$	2,441,347
Total assets	4,237,925		3,667,818		3,274,065		3,285,347			3,271,652
Common shareholders' equity (deficit)	352,933		151,271		47,774		(3,219		)	(5,846		)
Cumulative preferred stock of subsidiary	59,784		59,784		59,784		59,784			59,784
Long-term debt (less current maturities)	2,173,837		1,951,013		1,821,713		1,651,120			1,760,316
Other Data:
Utility capital expenditures⁽¹⁾	$	686,064	$	381,626	$	242,124	$	129,747		$	209,851

(1) Capital expenditures in 2015 includes $13.2 million of payments for financed capital expenditures.

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

The following discussion and analysis should be read in conjunction with our audited Consolidated Financial Statements and the notes thereto included in “Item 8. Financial Statements and Supplementary Data” of this Form 10-K. The following discussion contains forward-looking statements. Our actual results may differ materially from the results suggested by these forward-looking statements. Please see “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.

BUSINESS OVERVIEW

The most important matters on which we focus in evaluating our financial condition and operating performance and allocating our resources include: (i) recurring factors which have significant impacts on operating performance such as: regulatory action, environmental matters, weather and weather-related damage in our service area, our ability to sell power in the wholesale market at a profit, and the local economy; (ii) our progress on performance improvement strategies designed to maintain high standards in several operating areas (including safety, operations, financial and enterprise-wide performance, talent management/people, capital allocation/sustainability and corporate social responsibility) simultaneously; and (iii) our short-term and long-term financial and operating strategies. For a discussion of how we are impacted by regulation and environmental matters, please see “Regulatory Matters” and “Environmental Matters” in “Item 1. Business.”

Market Developments

We are one of many transmission system owner members in MISO. MISO is a regional transmission organization which maintains functional control over the combined transmission systems of its members and manages one of the largest energy and ancillary services markets in the U.S. IPL offers the available electricity production of each of its generation assets into the MISO day-ahead and real-time markets. MISO dispatches generation assets in economic order considering transmission constraints and other reliability issues to meet the total demand in the MISO region. The increased interconnection of renewable energy to the MISO transmission system and participation of renewable energy resources in the MISO energy markets have decreased the economic dispatch of energy from coal resources. Additionally, the use of enhanced technologies to recover natural gas from shale deposits has increased natural gas supply and reserves, which has placed downward pressure on natural gas prices and, therefore, on wholesale power prices.

Weather and Weather-Related Damage in our Service Area

Extreme high and low temperatures in our service area have a significant impact on revenues as many of our retail customers use electricity to power air conditioners, electric furnaces and heat pumps. The impact is partially mitigated by our declining block rate structure, which generally provides for residential and commercial customers to be charged a lower per kWh rate at higher consumption levels. Therefore, as volumes increase, the weighted average price per kWh decreases. The effect is generally more significant with high temperatures than with low temperatures as many of our customers use gas heat. In addition, because extreme temperatures have the effect of increasing demand for electricity, the wholesale price for electricity generally increases during periods of extreme hot or cold weather and, therefore, if we have available capacity not needed to serve our retail load, we may be able to generate additional income by selling power on the wholesale market (see below).

Storm activity can also have an adverse effect on our operating performance. Severe storms often damage transmission and distribution equipment, thereby causing power outages, which reduce revenues and increase repair costs. Storm-related operating expenses (primarily repairs and maintenance) were $3.6 million, $4.6 million and $0.9 million in 2015, 2014 and 2013, respectively.

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

At times, we will purchase power in the wholesale markets, and at other times we will have electric generation available for sale in the wholesale market in competition with other utilities and power generators. During the past five years, wholesale revenues averaged 4.0% of our total electric revenues. A decline in wholesale prices can have a significant 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. Consistent with other similar IURC orders, our rate case petition includes requests to implement rate adjustment mechanisms for short term recovery of fluctuations in certain costs (please see “Item 1. Business – Regulatory Matters – Basic Rates and Charges” for further details).

Our ability to be dispatched in the MISO market to sell power is primarily impacted by the locational market price of electricity and our variable generation costs. The amount of electricity we have available for wholesale sales is impacted by our retail load requirements, our generation capacity and our unit availability. From time to time, we must shut generating units down to perform maintenance or repairs. Generally, maintenance is scheduled during the spring and fall months when demand for power is lowest. Occasionally, it is necessary to shut units down for maintenance or repair during periods of high power demand, or we could experience an unscheduled outage during that time. See also, “Item 1. Business - Regulatory Matters” and “Item 1. Business - MISO Operations” for information about our participation in MISO that impacts both revenues and costs associated with our energy service to our utility customers. The price of wholesale power in the MISO market, as well as our variable generating costs can be volatile and therefore our revenues from wholesale sales can fluctuate significantly from year to year. The weighted average price of wholesale MWh we sold was $28.02, $34.71 and $31.29 in 2015, 2014 and 2013, respectively.

Local Economy

For the ten years ending 2015, our total retail kWh sales decreased at a compound annual rate of 1.0%. In contrast, for the ten years ending 2008, the compound annual rate was an increase of 1.2%. This decline over the past few years illustrates the impact of the weak economic environment, as well as the continued implementation of IPL’s energy efficiency program initiatives.

Operational Excellence

Our objective is to optimize IPL’s performance in the U.S. utility industry by focusing on the following areas: safety, operations (reliability and customer satisfaction), financial and enterprise-wide performance (efficiency and cost savings, talent management/people, capital allocation/sustainability and corporate social responsibility). We set and measure these objectives carefully, balancing them in a way and to a degree necessary to ensure a sustainably high level of performance in these areas simultaneously as compared to our peers. We monitor our performance in these areas, and where practical and meaningful, compare performance in some areas to peer utilities. Because some of our financial and enterprise-wide performance measures are company-specific performance goals, they are not benchmarked.

Our safety performance is measured by our lost work day cases, severity rate, and IOSHA recordable incidents. In 2015 our safety performance remained consistent with 2014 and is near our goal of being within the top quartile in our industry. We are committed to excellence in safety and have implemented various programs to increase safety awareness and improve work practices with special emphasis placed on mitigating the hazards associated with high-risk work activities commonly experienced in the industry. In addition, emphasis is placed on contractor and construction safety as we are undertaking several major construction projects including construction of the Eagle Valley CCGT Plant. Our special emphasis on construction safety was recognized by IOSHA in 2015 when our Petersburg MATS construction project was awarded Star certification, the highest level of recognition in IOSHA's Voluntary Protection Program, and was the first mobile site recognized by the state program.

IPL has the best satisfaction rating amongst Indiana investor-owned utilities, as measured by the J.D. Power 2015 Electric Utility Residential Study. In addition, IPL ranked third in Business Customer Satisfaction among Midwest Mid-Size Utilities in both the 2016 and 2015 J.D. Power Electric Utility Business Customer Satisfaction Study. In June 2015, IPL was one of only three Midwest electric utilities achieving the Most Trusted Brand Status by Cogent Reports, a division of Market Strategies International. In addition, IPL was ranked in the top ten utilities overall for community outreach. We believe these favorable ratings reflect our relatively low rates, strong reliability, corporate citizenship, and focus on excellence in customer service.

Our performance in production reliability was slightly worse than our target in 2015. Both our planned and unplanned outage rates associated with our generation plants in 2015 were consistent with outage rates that we experienced in 2014 partially due to scheduled outages at our Petersburg Plant to complete required maintenance.

The IPL delivery reliability metrics for System Average Interruption Duration Index (“SAIDI”) and System Average Interruption Frequency Index (“SAIFI”) were better than our target in 2015. In 2014, IPL ranked near the top decile nationally in both SAIDI and SAIFI reliability performance. In addition, IPL had the best SAIDI and SAIFI reliability performance excl

uding major events in 2014 as compared to the four Indiana investor-owned utilities and the second best Customer Average Interruption Duration Index (“CAIDI”) performance among the Indiana investor-owned utilities.

Short-Term and Long-Term Financial and Operating Strategies

Our financial management plan is closely integrated with our operating strategies. Key aspects of our financial planning include rigorous budgeting and analysis, maintaining sufficient levels of liquidity and a prudent dividend policy at both our subsidiary and holding company levels. This strategy allows us to remain flexible in the face of evolving environmental legislation and regulatory initiatives in our industry, as well as weak economic conditions.

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.

Comparison of year ended December 31, 2015 and year ended December 31, 2014

Utility Operating Revenues

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



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

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

The decrease in wholesale revenues of $63.9 million was primarily due to a 71% decrease in the quantity of kWh sold ($59.3 million) and a 19% decrease in the weighted average price per kWh sold ($4.6 million) as IPL's coal-fired generation was not called upon by MISO to produce electricity as often during 2015 versus 2014. Our ability to be dispatched in the MISO market is primarily driven by the locational marginal price of electricity and variable generation costs. The amount of electricity available for wholesale sales is impacted by our retail load requirements, our generation capacity and unit availability. Unit availability was unfavorably impacted by increased planned and forced outages during 2015 versus 2014. As discussed in

“Business Overview - Our Ability to Sell Power in the Wholesale Market at a Profit” above, we expect unit availability will be adversely impacted by our construction program and planned unit retirements during 2016 and early 2017.

Utility Operating Expenses

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




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

The $95.6 million decrease in fuel costs was primarily due to (i) a $52.3 million decrease in the quantity of fuel consumed as the result of a decrease in total kWh sales volume in the comparable period, (ii) a $21.4 million decrease in the price of natural gas we consumed during the comparable period, (iii) a $17.1 million decrease in the recognition of deferred fuel costs as the result of variances between estimated fuel and purchased power costs in our FAC and actual fuel and purchased power costs, (iv) a $4.0 million decrease in the price of oil we consumed during the comparable period, and (v) a $0.8 million decrease in the price of coal we consumed during the comparable period. We are generally permitted to recover underestimated fuel and purchased power costs to serve our retail customers in future rates through the FAC proceedings and, therefore, the costs are deferred when incurred and amortized into expense in the same period that our rates are adjusted to reflect these costs.

The $28.4 million increase in purchased power costs was primarily due to a 136% increase in the volume of power purchased during the period ($129.3 million), partially offset by a 42% decrease in the market price of purchased power ($102.4 million). The volume of power we purchase each period is primarily influenced by our retail demand, our generating unit capacity and outages, and the fact that at times it is less expensive for us to buy power in the market than to produce it ourselves. The market price of purchased power is influenced primarily by changes in the market price of delivered fuel (primarily natural gas), the price of environmental emissions allowances, the supply of and demand for electricity, and the time of day in which power is purchased.

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

Other Income and Deductions

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

Interest and Other Charges

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

Comparison of year ended December 31, 2014 and year ended December 31, 2013

Utility Operating Revenues

Utility operating revenues increased in 2014 from the prior year by $65.9 million, which resulted from the following changes (dollars in thousands):



	2014		2013		Change			Percentage Change
Utility Operating Revenues:
Retail Revenues	$	1,217,522	$	1,172,652	$	44,870		3.8	%
Wholesale Revenues	83,208		62,734		20,474			32.6	%
Miscellaneous Revenues	20,944		20,348		596			2.9	%
Total Utility Operating Revenues	$	1,321,674	$	1,255,734	$	65,940		5.3	%
Heating Degree Days:
Actual	6,238		5,647		591			10.5	%
30-year Average	5,240		5,474
Cooling Degree Days:
Actual	900		1,160		(260		)	(22.4	)%
30-year Average	1,154		1,048

The increase in retail revenues of $44.9 million was primarily due to a net increase in the weighted average price per kWh sold ($45.9 million), partially offset by a slight decrease in the volume of kWh sold ($1.0 million). The $45.9 million increase in the weighted average price of retail kWh sold was primarily due to increases in (i) fuel revenues of $43.9 million and (ii) environmental rate adjustment mechanism revenues of $7.3 million; partially offset by a decrease in DSM program rate adjustment mechanism revenues of $3.5 million. The increase in fuel revenues was offset by increases in fuel and purchased power costs as described below. Likewise, the vast majority of the increases in environmental rate adjustment mechanism revenues are offset by increased operating expenses, including depreciation and amortization, while the decreases in DSM rate adjustment mechanism revenues are offset by decreased operating expenses. The $1.0 million decrease in the volume of electricity sold was primarily due to cooler temperatures in our service territory during the summer of 2014 versus the comparable period (as demonstrated by the 22% decrease in cooling degree days, as shown above).

The increase in wholesale revenues of $20.5 million was primarily due to a 20% increase in the quantity of kWh sold ($12.3 million) and an 11% increase in the weighted average price per kWh sold ($8.2 million) as IPL’s coal-fired generation was called upon by MISO to produce electricity more often during 2014 versus 2013. We believe the higher market prices in 2014 were heavily influenced by the impact the colder temperatures during the beginning of the year had on demand for electricity in the MISO wholesale market. Our ability to be dispatched in the MISO market is primarily impacted by the locational marginal price of electricity and variable generation costs. The amount of electricity available for wholesale sales is impacted by our retail load requirements, our generation capacity and unit availability.

Utility Operating Expenses

The following table illustrates our primary operating expense changes from 2013 to 2014 (in millions):




2013 Operating Expenses	$	1,105.0
Increase in fuel costs	34.8
Increase in power purchased	22.4
Decrease in pension expenses	(15.9		)
Increase in income taxes – net	11.7
Decrease in DSM program costs	(3.6		)
Increase in salaries, wages and benefits (excluding pension expenses)	3.6
Increase in depreciation and amortization costs	3.0
Other miscellaneous variances – individually immaterial	(0.2		)
2014 Operating Expenses	$	1,160.8

The $34.8 million increase in fuel costs was primarily due to (i) a $14.3 million increase in the price of coal we consumed during the comparable periods, (ii) a $10.6 million increase in the recognition of deferred fuel costs as the result of variances between estimated fuel and purchase power costs in our FAC and actual fuel and purchased power costs, (iii) a $4.6 million increase in the quantity of fuel consumed as the result of an increase in total electricity sales volume in the comparable periods, and (iv) a $4.1 million increase in the price of natural gas we consumed during the comparable periods. We are generally permitted to recover underestimated fuel and purchased power costs to serve our retail customers in future rates through the FAC proceedings and, therefore, the costs are deferred when incurred and amortized into expense in the same period that our rates are adjusted to reflect these costs.

The $22.4 million increase in purchased power costs was primarily due to a 50% increase in the market price of purchased power ($39.7 million), partially offset by a 22% decrease in the volume of power purchased during the period ($17.5 million). The market price of purchased power is influenced primarily by changes in the market price of delivered fuel (primarily natural gas), the price of environmental emissions allowances, the supply of and demand for electricity, and the time of day in which power is purchased. In the comparable periods, the increase in natural gas prices had the largest impact on the market price of purchased power. The volume of power we purchase each period is primarily influenced by our retail demand, our generating unit capacity and outages, and the fact that at times it is less expensive for us to buy power in the market than to produce it ourselves.

The $15.9 million decrease in pension expenses, which is included in “Other operating expenses” on our Consolidated Statements of Income, is primarily due to a $13.0 million decrease in the recognized actuarial loss. The $11.7 million increase in income taxes – net was primarily due to the tax effect of the increase in pretax net operating income, for the reasons previously described. The decrease in DSM program costs of $3.6 million, which are included in “Other operating expenses” on our Consolidated Statements of Income and are recoverable through customer rates, is correlated to a decrease in DSM program rate adjustment mechanism retail revenues. The increase in salaries, wages and benefits (excluding pension expenses) of $3.6 million is primarily due to both employee headcount and rate increases. The increase in depreciation and amortization costs of $3.0 million was primarily due to additional assets placed in service.

Other Income and Deductions

Other income and deductions increased $5.0 million from income of $22.3 million in 2013 to income of $27.3 million in 2014, reflecting a 22% increase. The increase was primarily due to a $3.1 million increase in the allowance for equity funds used during construction as a result of increased construction activity.

Interest and Other Charges

Interest and other charges increased $1.3 million, or 1%, during 2014 primarily due to higher interest on long-term debt of $3.5 million mostly as a result of IPL’s debt issuance in June 2014 of $130 million aggregate principal amount of first mortgage bonds, 4.50% Series, due June 2044. This increase was partially offset by a $2.4 million change in the allowance for borrowed funds used during construction as a result of increased construction activity.

CAPITAL RESOURCES AND LIQUIDITY

Overview

As of December 31, 2015, we had unrestricted cash and cash equivalents of $21.5 million and available borrowing capacity of $174.5 million under our $250.0 million unsecured revolving credit facility after outstanding borrowings and existing letters of credit. All of IPL’s long-term borrowings must first be approved by the IURC and the aggregate amount of IPL’s short-term indebtedness must be approved by the FERC. We have approval from FERC to borrow up to $500 million of short-term indebtedness outstanding at any time through July 28, 2016. In December 2015, we received an order from the IURC granting us authority through December 31, 2018 to, among other things, issue up to $650 million in aggregate principal amount of long-term debt (inclusive of $260 million of IPL's first mortgage bonds issued in September 2015), refinance up to $196.5 million in existing indebtedness (inclusive of $90 million of IPL unsecured notes issued in December 2015), have up to $500 million of long-term credit agreements and liquidity facilities outstanding at any one time, and, as an alternative to the sale of all or a portion of $65 million in principal of the long-term debt mentioned above, issue up to $65 million of new preferred stock. We also have restrictions on the amount of new debt that may be issued due to contractual obligations of AES and by financial covenant restrictions under our existing debt obligations. We do not believe such restrictions will be a limiting factor in our ability to issue debt in the ordinary course of prudent business operations.

We believe that existing cash balances, cash generated from operating activities and borrowing capacity on our committed credit facility will be adequate for the foreseeable future to meet anticipated operating expenses, interest expense on outstanding indebtedness, recurring capital expenditures and to pay dividends to AES U.S. Investments and CDPQ. Sources for principal payments on outstanding indebtedness and nonrecurring capital expenditures are expected to be obtained from: (i) existing cash balances; (ii) cash generated from operating activities; (iii) borrowing capacity on our committed credit facility; and (iv) additional debt financing. In addition, due to current and expected future environmental regulations and replacement generation projects, it is expected that equity capital will continue to be used as a significant funding source, as it was in 2015, 2014, and 2013 (see below). AES has approved significant equity investments in IPL for its proposed nonrecurring capital expenditures through 2017; however, AES is under no contractual obligation to provide such equity capital and there can be no assurance we will receive capital contributions in the amounts or at the times funding may be required. In June 2014 and July 2013, IPALCO received equity capital contributions of $106.4 million and $49.1 million, respectively, from AES for funding needs related to IPL’s environmental and replacement generation projects, which IPALCO then made the same investment in IPL. In addition, in April 2015, IPALCO received an equity capital contribution of $214.4 million from the issuance of 11,818,828 shares of common stock to CDPQ for funding needs primarily related to IPL's environmental construction program, which IPALCO then made the same investment in IPL. CDPQ has committed to approximately $135 million of additional investments in IPALCO through 2016, which will be used primarily to help fund existing environmental and replacement generation projects at IPL.

Cash Flow

Our principal sources of funds in 2015 were net cash provided by operating activities of $252.4 million, net borrowings of $318.0 million, and an equity capital contribution of $214.4 million from CDPQ in April 2015 for funding needs related to IPL's environmental and replacement generation projects. Net cash provided by operating activities is net of cash paid for interest of $95.1 million and pension funding of $25.2 million. The principal uses of funds in 2015 included capital expenditures of $686.1 million (which includes $13.2 million of payments for financed capital expenditures) and dividends to shareholders of $69.5 million. The increase in capital expenditures of $304.5 million in 2015 versus 2014 was primarily driven by spending for IPL’s environmental and replacement generation projects.

Our principal sources of funds in 2014 were net cash provided by operating activities of $254.0 million, net borrowings of $128.4 million, and an equity capital contribution of $106.4 million from AES in June 2014 for funding needs related to IPL’s environmental and replacement generation projects. Net cash provided by operating activities is net of cash paid for interest of $103.9 million and pension funding of $54.1 million. Net cash provided by operating activities in 2014 was $42.6 million higher than in 2013 primarily due to favorable adjustments in deferred income taxes attributed to the cumulative effect of accelerated deductions related to repairs of tangible property. The principal uses of funds in 2014 included capital expenditures of $381.6 million and dividends to AES of $78.4 million. The increase in capital expenditures of $139.5 million in 2014 versus 2013 was primarily driven by spending for IPL’s environmental and replacement generation projects.

Our principal sources of funds in 2013 were net cash provided by operating activities of $211.4 million, net borrowings of $59.4 million, and an equity capital contribution of $49.1 million from AES in July of 2013 for funding needs related to IPL’s environmental construction program. Net cash provided by operating activities is net of cash paid for interest of $106.2 million and pension funding of $49.7 million. The principal uses of funds in 2013 included capital expenditures of $242.1 million and

dividends to AES of $59.5 million. The increase in capital expenditures of $112.4 million in 2013 versus 2012 was primarily driven by spending to comply with the MATS rule (please see “Item 1. Business – Environmental Matters – MATS” for more details).

Capital Requirements

Capital Expenditures

Our construction program is composed of capital expenditures necessary for prudent utility operations and compliance with environmental laws and regulations, along with discretionary investments designed to replace aging equipment or improve overall performance. Our capital expenditures totaled $686.1 million (which includes $13.2 million of payments for financed capital expenditures), $381.6 million, and $242.1 million in 2015, 2014 and 2013, respectively. The increase in capital expenditures over the past few years has been primarily driven by construction costs related to replacement generation and our environmental construction program. Construction expenditures during 2015, 2014 and 2013 were financed primarily with internally generated cash provided by operations, borrowings on our credit facility, long-term borrowings, equity capital contributions and, to a lesser extent, federal grants for IPL’s Smart Energy Projects.

Our capital expenditure program, including development and permitting costs, for the three-year period from 2016 to 2018 is currently estimated to cost approximately $541 million (excluding environmental compliance and replacement generation costs). It includes approximately $294 million for additions, improvements and extensions to transmission and distribution lines, substations, power factor and voltage regulating equipment, distribution transformers and street lighting facilities. The capital expenditure program also includes approximately $178 million for power plant-related projects and $69 million for other miscellaneous equipment.

IPL also plans to spend a total of $632 million (of which $353 million has been expended through December 31, 2015) on replacement generation costs through 2018 as a result of the retirement of existing facilities not equipped with advanced environmental control technologies required to comply with existing and expected regulations. The balance of $279 million is projected to be expended in the three-year period from 2016 to 2018. Please see “Item 1. Business – Environmental Matters – Unit Retirements and Replacement Generation” for more details.

In addition to the amounts listed above, IPL plans to spend additional amounts related to environmental compliance, including $53 million for the three-year period from 2016 to 2018 to comply with the MATS rule. IPL plans to spend a total of $454 million for this project (of which $401 million has been expended for this project through December 31, 2015). Please see “Item 1. Business – Environmental Matters – MATS” for more details.

Other environmental expenditures include costs for compliance with the NPDES permit program under the CWA. The costs for NPDES at our Petersburg Plant for 2016 to 2018 are expected to be $97 million. IPL plans to spend a total of $224 million for this project (of which $127 million has been expended through December 31, 2015). Also, as a result of environmental regulations, IPL plans to refuel Unit 7 at Harding Street converting from coal-fired to natural gas-fired. The 2016 to 2018 cost of the projects necessary to complete this conversion, including costs for NPDES, MATS compliance and dry ash handling, are expected to be $57 million (IPL plans to spend a total of $101 million on this project, including amounts already expended through December 31, 2015). IPL has also included in the 2016 to 2018 forecast $149 million related to environmental compliance for CCR and NAAQS regulations and studies related to cooling water intake requirements in sections 316(a) and 316(b) of the CWA. Please see “Item 1. Business – Environmental Matters – Environmental Wastewater Requirements” for more details.

IPL also plans on spending $17 million for the three-year period from 2016 to 2018 for an energy storage facility at its Harding Street station. The total cost of this project is expected to be $26 million (of which $9 million has been expended through December 31, 2015).

Capital Resources

IPALCO is a holding company, accordingly substantially all of its cash is generated by the operating activities of its subsidiaries, principally IPL. None of its subsidiaries, including IPL, is obligated under or has guaranteed to make payments with respect to the 2018 IPALCO Notes or the 2020 IPALCO Notes; however, all of IPL’s common stock is pledged to secure these notes. Accordingly, IPALCO’s ability to make payments on the 2018 IPALCO Notes and the 2020 IPALCO Notes depends on the ability of IPL to generate cash and distribute it to IPALCO.

While we believe that our sources of liquidity will be adequate to meet our needs, this belief is based on a number of material assumptions, including, without limitation, assumptions about weather, economic conditions, our credit ratings and those of AES and IPL, regulatory constraints, environmental regulation, pension obligations and equity capital contributions. If and to the extent these assumptions prove to be inaccurate, our sources of liquidity may be affected. Moreover, changes in these factors or in the bank or other credit markets could reduce available credit or our ability to renew existing credit facilities on acceptable terms. The absence of adequate liquidity could adversely affect our ability to operate our business, and our results of operations, financial condition and cash flows.

Indebtedness

Line of Credit

IPL First Mortgage Bonds

In September 2015, IPL issued $260 million aggregate principal amount of first mortgage bonds, 4.70% Series, due September 2045, pursuant to Rule 144A and Regulation S under the Securities Act. For further discussion, please see Note 7, “Debt - IPL First Mortgage Bonds” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data.” In December 2015, IPL refunded the January 2016 maturity of its outstanding $131.9 million aggregate principal amount of 4.90% IPL first mortgage bonds previously classified as short-term indebtedness. For further discussion, please see “– IPL Unsecured Notes” below.

IPL Unsecured Notes

In October 2015, IPL entered into an unsecured $91.9 million 364-day committed credit facility with a delayed draw feature at variable rates with a syndication of banks. This agreement matures on October 14, 2016 and bears interest at variable rates as described in the credit agreement. It was drawn on in October and December 2015 to fund the October 2015 termination of IPL’s $50 million accounts receivable securitization program and to assist in the December 2015 refunding of $41.9 million of IPL’s outstanding aggregate principal amount of 4.90% IPL first mortgage bonds due in January 2016. For further discussion, please Note 7, “Debt - Unsecured Notes” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data.”

In December 2015, the Indiana Finance Authority issued on behalf of IPL an aggregate principal amount of $90 million of Environmental Facilities Refunding Revenue Notes due December 2038 (Indianapolis Power & Light Company Project). These unsecured notes were issued in two series: $30 million Series 2015A notes and $60 million 2015B notes. These notes were initially purchased by a syndication of banks who will hold the notes until the mandatory put date of December 22, 2020. The notes bear interest at a variable rate as described in the notes documents. The proceeds of the 2015A notes and the 2015B notes were loaned to IPL to assist in refunding the $30 million Indiana Finance Authority Environmental Facilities Refunding Revenue Bonds (Indianapolis Power & Light Company Project) Series 2009B and $60 million Indiana Finance Authority Environmental Facilities Refunding Revenue Bonds (Indianapolis Power & Light Company Project) Series 2009C, each series due January 1, 2016. For further discussion, please see Note 7, “Debt - Unsecured Notes” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data.”

IPALCO's Senior Secured Notes

In June 2015, IPALCO completed the sale of the 2020 IPALCO Notes pursuant to Rule 144A and Regulation S under the Securities Act. Net proceeds from this offering were used to fund the purchase of the 2016 IPALCO Notes. For further discussion, please see Note 7, “Debt - IPALCO's Senior Secured Notes.”

Credit Ratings

Agreement and other unsecured notes (as well as the amount of certain other fees on the Credit Agreement and the 364-day 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. Any reduction in our debt or credit ratings may adversely affect the trading price of our outstanding debt securities.

The credit ratings of IPALCO and IPL as of February 23, 2016, are as follows:



	Moody’s		S&P		Fitch Ratings

IPALCO Issuer Rating/Corporate Credit
Rating/Long-term Issuer Default Rating		-		BB+		BB+
IPALCO Senior Secured Notes		Baa3		BB+		BB+
IPL Issuer Rating/Corporate Credit Rating/Long-
term Issuer Default Rating		Baa1		BB+		BBB-
IPL Senior Secured		A2		BBB+		BBB+

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

Dividend and Capital Structure Restrictions

IPL’s mortgage and deed of trust and its amended articles of incorporation contain restrictions on IPL’s ability to issue certain securities or pay cash dividends. So long as any of the several series of bonds of IPL issued under its mortgage remains outstanding, and subject to certain exceptions, IPL is restricted in the declaration and payment of dividends, or other distribution on shares of its capital stock of any class, or in the purchase or redemption of such shares, to the aggregate of its net income, as defined in the mortgage, after December 31, 1939. The amount which these mortgage provisions would have permitted IPL to declare and pay as dividends at December 31, 2015, exceeded IPL’s retained earnings at that date. In addition, pursuant to IPL’s articles, no dividends may be paid or accrued and no other distribution may be made on IPL’s common stock unless dividends on all outstanding shares of IPL preferred stock have been paid or declared and set apart for payment.

IPL is also restricted in its ability to pay dividends if it is in default under the terms of its credit facility 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, in order to pay dividends. As of December 31, 2015 and as of the filing of this report, IPL was in compliance with all covenants and no event of default existed.

IPL’s amended articles of incorporation also require that, so long as any shares of preferred stock are outstanding, the net income of IPL, as specified in the articles, be at least one and one-half times the total interest on the funded debt and the pro forma dividend requirements on the outstanding, and any proposed, preferred stock before any additional preferred stock is issued. IPL’s mortgage and deed of trust requires that net earnings as calculated thereunder be at least two and one-half times the annual interest requirements before additional bonds can be authenticated on the basis of property additions. As of December 31, 2015, 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.

Contractual Cash Obligations

Our non-contingent contractual obligations as of December 31, 2015 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	$	2,178.4	$	—	$	424.6	$	495.0	$	1,258.8
Interest obligations ⁽¹⁾	1,654.7		104.2		192.1		160.7		1,197.7
Purchase obligations ⁽²⁾
Coal, gas, purchased power and
related transportation	2,855.2		292.3		508.1		234.7		1,820.1
Other	68.0		10.0		11.6		10.6		35.8
Pension funding ⁽³⁾	15.9		15.9		—		—		—
Total ⁽⁴⁾	$	6,772.2	$	422.4	$	1,136.4	$	901.0	$	4,312.4


(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, 2015.

(2)

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

(3)

IPL elected to fund $15.9 million during January 2016. However, IPL may decide to contribute more than $15.9 million to meet certain funding thresholds. For years 2017 and thereafter, our contractual obligation for pension funding can fluctuate due to various factors. Please see “Pension Plans” below and Note 9, “Benefit Plans” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K for further discussion.


(4)	Does not include an uncertain tax liability of $7.1 million (tax and related interest) as of December 31, 2015 because it is not possible to determine in which future period or periods that the non-current income tax liability for uncertain tax positions might be paid.

Dividend Distributions

All of IPALCO’s outstanding common stock is held by AES U.S. Investments and CDPQ. During 2015, 2014 and 2013, IPALCO paid $69.5 million, $78.4 million, and $59.5 million, respectively, in dividends to its shareholders. Future distributions to AES U.S. Investments and CDPQ will be determined at the discretion of our board of directors and will depend primarily on dividends received from IPL. Dividends from IPL are affected by IPL’s actual results of operations, financial condition, cash flows, capital requirements, regulatory considerations, and such other factors as IPL’s board of directors deems relevant.

Pension Plans

We contributed $25.2 million, $54.1 million, and $49.7 million to the Pension Plans in 2015, 2014 and 2013, 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 112%. In addition to the surplus, IPL must also contribute the normal service cost earned by active participants during the plan year. The ERISA funding of normal cost is expected to be about $7.1 million in 2016, which includes $2.3 million for plan expenses. Each year thereafter, if the plan’s underfunding increases to more than the present value of the remaining annual installments, the excess is separately amortized over a seven-year period. IPL elected to fund $15.9 million in January 2016, which satisfies all funding requirements for the calendar year 2016. 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, 2015, 2014 and 2013 were $35.7 million, $32.6 million, and $51.0 million, respectively.

See also “– Critical Accounting Estimates - Pension Costs” and Note 9, “Benefit Plans” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K for further discussion of Pension Plans.

CRITICAL ACCOUNTING ESTIMATES

General

We prepare our consolidated financial statements in accordance with GAAP. As such, we are required to make certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period presented. Therefore, the possibility exists for materially different reported amounts under different conditions or assumptions. Significant accounting policies used in the preparation of the consolidated financial statements are described in Note 1, “Overview and Summary of Significant Accounting Policies” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K. This section addresses only those accounting policies involving amounts material to our financial statements that require the most estimation, judgment or assumptions and should be read in conjunction with Note 1, “Overview and Summary of Significant Accounting Policies” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K.

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 assets have been included as allowable costs for ratemaking purposes, as authorized by the IURC or established regulatory practices. Regulatory liabilities generally represent obligations to make refunds or future rate reductions to customers for previous overcollections or the deferral of revenues collected for costs that IPL expects to incur in the future. Specific regulatory assets and liabilities are disclosed in Note 5, “Regulatory Assets and Liabilities” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K.

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 a specific order 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.

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 2015 revenues and ending unbilled revenues of a one percentage point increase and decrease in the estimated line losses for the month of December 2015 is ($0.4 million) and $0.4 million, respectively. At December 31, 2015 and 2014, customer accounts receivable include unbilled energy revenues of $42.1 million and $48.4 million, respectively, on a base of annual revenue of $1.3 billion in 2015 and 2014. An allowance for potential credit losses is maintained and amounts are written off when normal collection efforts have been exhausted.

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 will apply a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and other post-retirement plan. Refer to Note 1, “Overview and Summary of Significant Acc

ounting Policies” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K for further information.

Impairment of Long-lived Assets

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

Income Taxes

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

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

Contingencies

We accrue for loss contingencies when the amount of the loss is probable and estimable. We are subject to various environmental regulations, and are involved in certain legal proceedings. If our actual environmental and/or legal obligations are different from our estimates, the recognition of the actual amounts may have a material impact on our results of operations, financial condition and cash flows; although that has not been the case during the periods covered by this report. Please see Note 10, “Commitments and Contingencies” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K for information about significant contingencies involving us.

NEW ACCOUNTING STANDARDS

Please see Note 1, “Overview and Summary of Significant Accounting Policies” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K for a discussion of new accounting pronouncements and the potential impact to our results of operations, financial condition and cash flows.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Overview

The primary market risks to which we are exposed are those associated with environmental regulation, debt and equity investments, fluctuations in interest rates and the prices of fuel, wholesale power, SO2 allowances and certain raw materials. We sometimes use financial instruments and other contracts to hedge against such fluctuations, including, on a limited basis, financial and commodity derivatives. We generally do not enter into derivative instruments for trading or speculative purposes.

Environmental Regulation

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 $28.02, $34.71 and $31.29 in 2015, 2014 and 2013, respectively. During the past five years, wholesale revenues represented 4.0% of our total electric revenues on average. A decline in wholesale prices can have a significant impact on earnings, because most of our nonfuel costs are fixed in the short term and lower wholesale prices can result in lower wholesale volumes sold.

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 $37.9 million reduction in fair value as of December 31, 2015 and approximately a $6.4 million increase to the 2016 pension expense. Please see Note 9, “Benefit Plans” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K 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 364-day unsecured note 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, 2015, we had approximately $2,088.4 million principal amount of fixed rate debt and $256.9 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, 2015 was comprised of $91.9 million under IPL’s 364-day unsecured note, $90.0 million under its Series 2015A and Series 2015B notes and $75.0 million under its Credit Agreement. Based on amounts outstanding as of December 31, 2015, the effect of a 25 basis point change in the applicable rates on our variable-rate debt would increase or decrease our annual interest expense and cash paid for interest by $0.6 million and $(0.6 million), respectively.

The following table shows our consolidated indebtedness (in millions) by maturity as of December 31, 2015:



	2016		2017		2018		2019		2020		Thereafter		Total		Fair Value
Fixed-rate debt	$	—	$	24.6	$	400.0	$	—	$	405.0	$	1,258.8	$	2,088.4	$	2,225.3
Variable-rate debt	166.9		—		—		—		90.0		—		256.9		256.9
Total Indebtedness	$	166.9	$	24.6	$	400.0	$	—	$	495.0	$	1,258.8	$	2,345.3	$	2,482.2
Weighted Average Interest Rates by Maturity	1.68%		5.40%		5.00%		N/A		3.03%		5.20%		4.46%

For further discussion of our fair value of our indebtedness and book value of our indebtedness please see Note 4, “Fair Value” and Note 7, “Debt” to the audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in this Form 10-K.

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 2016 and 2017 and approximately 85% of our current projected burn for the three-year period ending December 31, 2018, under long-term contracts. Pricing provisions in some of our long-term contracts allow for price changes under certain circumstances. Fuel purchases made in 2016 are expected to be made at prices that are slightly higher than our weighted average price in 2015. 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 “Item 1. Business – Regulatory Matters – FAC and Authorized Annual Jurisdictional Net Operating Income.”

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 – 2015, 2014 and 2013	51
Consolidated Statements of Income for the years ended December 31, 2015, 2014 and 2013	52
Consolidated Balance Sheets as of December 31, 2015 and 2014	53
Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013	54
Consolidated Statements of Common Shareholders' Equity (Deficit) and Noncontrolling Interest
for the years ended December 31, 2015, 2014 and 2013	55
Notes to Consolidated Financial Statements	56

Indianapolis Power & Light Company and Subsidiary – Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm – 2015, 2014 and 2013	87
Consolidated Statements of Income for the years ended December 31, 2015, 2014 and 2013	88
Consolidated Balance Sheets as of December 31, 2015 and 2014	89
Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013	90
Consolidated Statements of Common Shareholder’s Equity for the years ended
December 31, 2015, 2014 and 2013	91
Notes to Consolidated Financial Statements	92

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of

IPALCO Enterprises, Inc.

We have audited the accompanying consolidated balance sheets of IPALCO Enterprises, Inc. and Subsidiaries (the Company) as of December 31, 2015 and 2014, and the related consolidated statements of income, common shareholders' equity (deficit) and noncontrolling interest, and cash flows for each of the three years in the period ended December 31, 2015. Our audits also included the financial statement schedules listed in the Index at Item 15a. These financial statements and schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of IPALCO Enterprises, Inc. and Subsidiaries at December 31, 2015 and 2014, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.

/s/ ERNST & YOUNG LLP

Indianapolis, Indiana

February 23, 2016



IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Income
For the Years Ended December 31, 2015, 2014 and 2013
(In Thousands)
	2015			2014			2013
UTILITY OPERATING REVENUES	$	1,250,399		$	1,321,674		$	1,255,734

UTILITY OPERATING EXPENSES:
Fuel	315,600			411,217			376,450
Other operating expenses	224,282			218,932			235,082
Power purchased	145,064			116,648			94,265
Maintenance	131,574			113,248			112,913
Depreciation and amortization	188,267			185,263			182,305
Taxes other than income taxes	43,617			45,218			45,425
Income taxes - net	57,284			70,235			58,548
Total utility operating expenses	1,105,688			1,160,761			1,104,988
UTILITY OPERATING INCOME	144,711			160,913			150,746

OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used during construction	15,302			7,381			4,331
Loss on early extinguishment of debt	(21,956		)	—			(35		)
Miscellaneous income and (deductions) - net	(2,994		)	(2,236		)	(2,845		)
Income tax benefit applicable to nonoperating income	25,718			22,191			20,806
Total other income and (deductions) - net	16,070			27,336			22,257

INTEREST AND OTHER CHARGES:
Interest on long-term debt	106,936			108,104			104,602
Other interest	2,063			1,865			1,794
Allowance for borrowed funds used during construction	(12,809		)	(4,963		)	(2,517		)
Amortization of redemption premiums and expense on debt	5,067			5,275			5,075
Total interest and other charges - net	101,257			110,281			108,954
NET INCOME	59,524			77,968			64,049

LESS: PREFERRED DIVIDENDS OF SUBSIDIARY	3,213			3,213			3,213
NET INCOME APPLICABLE TO COMMON STOCK	$	56,311		$	74,755		$	60,836

See notes to consolidated financial statements.



IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Balance Sheets
(In Thousands)
	December 31, 2015			December 31, 2014
ASSETS
UTILITY PLANT:
Utility plant in service	$	4,992,594		$	4,658,023
Less accumulated depreciation	2,320,955			2,264,606
Utility plant in service - net	2,671,639			2,393,417
Construction work in progress	766,406			447,399
Spare parts inventory	12,336			14,816
Property held for future use	1,002			1,002
Utility plant - net	3,451,383			2,856,634
OTHER ASSETS:
Nonutility property - at cost, less accumulated depreciation	517			522
Other long-term assets	5,664			6,221
Other assets - net	6,181			6,743
CURRENT ASSETS:
Cash and cash equivalents	21,521			26,933
Accounts receivable and unbilled revenue (less allowance
for doubtful accounts of $2,498 and $2,076, respectively)	124,167			139,709
Fuel inventories - at average cost	66,834			47,550
Materials and supplies - at average cost	57,997			60,185
Deferred tax asset - current	—			61,782
Regulatory assets	8,002			93
Prepayments and other current assets	26,063			23,161
Total current assets	304,584			359,413
DEFERRED DEBITS:
Regulatory assets	448,200			419,193
Miscellaneous	27,577			25,835
Total deferred debits	475,777			445,028
TOTAL	$	4,237,925		$	3,667,818
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common shareholders' equity:
Paid in capital	$	383,448		$	168,610
Accumulated deficit	(30,515		)	(17,339		)
Total common shareholders' equity	352,933			151,271
Cumulative preferred stock of subsidiary	59,784			59,784
Long-term debt (Note 7)	2,173,837			1,951,013
Total capitalization	2,586,554			2,162,068
CURRENT LIABILITIES:
Short-term debt (Note 7)	166,850			50,000
Accounts payable	155,428			110,623
Accrued expenses	19,482			25,187
Accrued real estate and personal property taxes	17,712			19,177
Regulatory liabilities	28,169			27,943
Accrued interest	31,690			30,726
Customer deposits	30,719			28,337
Other current liabilities	12,623			12,881
Total current liabilities	462,673			304,874
DEFERRED CREDITS AND OTHER LONG-TERM LIABILITIES:
Regulatory liabilities	639,516			610,917
Deferred income taxes - net	397,394			421,127
Non-current income tax liability	7,147			7,042
Unamortized investment tax credit	3,910			5,229
Accrued pension and other postretirement benefits	80,734			96,464
Asset retirement obligations	58,986			59,098
Miscellaneous	1,011			999
Total deferred credits and other long-term liabilities	1,188,698			1,200,876
COMMITMENTS AND CONTINGENCIES (Note 10)
TOTAL	$	4,237,925		$	3,667,818

See notes to consolidated financial statements.



IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Cash Flows
For the Years Ended December 31, 2015, 2014 and 2013
(In Thousands)
	2015			2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	59,524		$	77,968		$	64,049
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	201,475			188,477			182,663
(Deferral) amortization of regulatory assets	(8,731		)	1,123			3,686
Amortization of debt premium	596			942			865
Deferred income taxes and investment tax credit adjustments - net	31,566			47,455			(10,284		)
Loss on early extinguishment of debt	21,956			—			377
Allowance for equity funds used during construction	(14,996		)	(7,136		)	(4,088		)
Gain on sale of nonutility property	—			—			(297		)
Change in certain assets and liabilities:
Accounts receivable	15,542			3,699			(1,900		)
Fuel, materials and supplies	(18,372		)	5,094			(10,337		)
Income taxes receivable or payable	—			590			3,026
Financial transmission rights	2,086			(1,947		)	(1,869		)
Accounts payable and accrued expenses	(716		)	(24,322		)	16,124
Accrued real estate and personal property taxes	(1,465		)	(47		)	(181		)
Accrued interest	965			1,034			(2,288		)
Pension and other postretirement benefit expenses	(15,730		)	2,785			(180,337		)
Short-term and long-term regulatory assets and liabilities	(22,980		)	(44,252		)	148,169
Prepaids and other current assets	(4,949		)	1,725			(2,986		)
Other - net	6,654			809			6,983
Net cash provided by operating activities	252,425			253,997			211,375
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures - utility	(672,849		)	(381,626		)	(242,124		)
Project development costs	(8,980		)	(9,657		)	(6,047		)
Proceeds from the sales of assets	—			—			225
Grants under the American Recovery and Reinvestment Act of 2009	—			—			923
Cost of removal, net of salvage	(12,064		)	(6,036		)	(7,553		)
Other	(1,224		)	(39		)	57
Net cash used in investing activities	(695,117		)	(397,358		)	(254,519		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt borrowings	388,850			105,000			150,500
Short-term debt repayments	(272,000		)	(105,000		)	(150,500		)
Long-term borrowings, net of discount	753,350			128,358			169,728
Retirement of long-term debt and early tender premium	(552,179		)	—			(110,377		)
Dividends on common stock	(69,487		)	(78,400		)	(59,500		)
Issuance of common stock	214,366			—			—
Equity contributions from AES	—			106,400			49,091
Preferred dividends of subsidiary	(3,213		)	(3,213		)	(3,213		)
Deferred financing costs paid	(8,824		)	(1,724		)	(1,996		)
Payments for financed capital expenditures	(13,215		)	—			—
Other	(368		)	(194		)	(9		)
Net cash provided by financing activities	437,280			151,227			43,724
Net change in cash and cash equivalents	(5,412		)	7,866			580
Cash and cash equivalents at beginning of period	26,933			19,067			18,487
Cash and cash equivalents at end of period	$	21,521		$	26,933		$	19,067

Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized)	$	95,137		$	103,938		$	106,175
Income taxes	$	—		$	—		$	45,000
	As of December 31,
	2015			2014			2013
Non-cash investing activities:
Accruals for capital expenditures	$	79,553		$	37,293		$	17,957

See notes to consolidated financial statements.



IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Common Shareholders' Equity (Deficit)
and Noncontrolling Interest
(In Thousands)
	Paid in Capital		Accumulated Deficit			Total Common Shareholders' Equity (Deficit)			Cumulative Preferred Stock of Subsidiary
Balance at January 1, 2013	$	11,811	$	(15,030	)	$	(3,219	)	$	59,784
Net income			60,836			60,836			3,213
Preferred stock dividends									(3,213		)
Distributions to AES			(59,500		)	(59,500		)
Contributions from AES	49,091					49,091
Other	566					566
Balance at December 31, 2013	$	61,468	$	(13,694	)	$	47,774		$	59,784
Net income			74,755			74,755			3,213
Preferred stock dividends									(3,213		)
Distributions to AES			(78,400		)	(78,400		)
Contributions from AES	106,400					106,400
Other	742					742
Balance at December 31, 2014	$	168,610	$	(17,339	)	$	151,271		$	59,784
Net income			56,311			56,311			3,213
Preferred stock dividends									(3,213		)
Distributions to shareholders			(69,487		)	(69,487		)
Issuance of common stock	214,366					214,366
Other	472					472
Balance at December 31, 2015	$	383,448	$	(30,515	)	$	352,933		$	59,784

See notes to consolidated financial statements.

IPALCO ENTERPRISES, INC. and SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2015, 2014 and 2013

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 (88.4%) and CDPQ (11.6%), IPALCO’s minority interest holder (see Note 6, “Equity - Equity Transactions” for details). AES U.S. Investments is owned by AES U.S. Holdings, LLC (85%) and CDPQ (15%). IPALCO owns all of the outstanding common stock of IPL. Substantially all of IPALCO’s business consists of generating, transmitting, distributing and selling of electric energy conducted through its principal subsidiary, IPL. IPL was incorporated under the laws of the state of Indiana in 1926. IPL has approximately 480,000 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, is converting its coal-fired units to natural gas and uses natural gas and fuel oil to power combustion turbines. The third station, Eagle Valley, is coal-fired and we plan to retire its coal-fired units in the second quarter of 2016. The fourth station, Georgetown, is a small peaking station that uses natural gas to power combustion turbines. IPL’s net electric generation capacity for winter is 3,259 MW and net summer capacity is 3,141 MW.

IPALCO’s other direct subsidiary is Mid-America. Mid-America is the holding company for IPALCO’s unregulated activities, which have not been material to the financial statements in the periods covered by this report. IPALCO’s regulated business is conducted through IPL. IPALCO has two business segments: utility and nonutility. The utility segment consists of the operations of IPL and everything else is included in the nonutility segment.

Principles of Consolidation

IPALCO’s consolidated financial statements are prepared in accordance with GAAP and in conjunction with the rules and regulations of the SEC. The consolidated financial statements include the accounts of IPALCO, its regulated utility subsidiary, IPL, and its unregulated subsidiary, Mid-America. All intercompany items have been eliminated in consolidation. Certain costs for shared resources amongst IPL and IPALCO, such as labor and benefits, are allocated to each entity based on allocation methodologies that management believes to be reasonable. We have evaluated subsequent events through the date this report is issued.

All income of Mid-America, as well as nonoperating income of IPL, are included below UTILITY OPERATING INCOME in the accompanying Consolidated Statements of Income.

Use of Management Estimates

The preparation of financial statements in conformity with GAAP requires that management make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. The reported amounts of revenues and expenses during the reporting period may also be affected by the estimates and assumptions management is required to make. Actual results may differ from those estimates.

Reclassifications

Certain prior period amounts have been reclassified to conform to the current year presentation.

Regulatory Accounting

The retail utility operations of IPL are subject to the jurisdiction of the IURC. IPL’s wholesale power transactions are subject to the jurisdiction of the FERC. These agencies regulate IPL’s utility business operations, tariffs, accounting, depreciation allowances, services, issuances of securities and the sale and acquisition of utility properties. The financial statements of IPL are based on GAAP, including the provisions of FASB ASC 980 “Regulated Operations,” which gives recognition to the ratemaking and accounting practices of these agencies. See also Note 5, “Regulatory Assets and Liabilities” for a discussion of specific regulatory assets and liabilities.

Revenues and Accounts Receivable

Revenues related to the sale of energy are generally recognized when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to certain customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is accrued. In making its estimates of unbilled revenue, IPL uses complex models that consider various factors including daily generation volumes; known amounts of energy usage by nearly all residential, small commercial and industrial customers; estimated line losses; and estimated customer rates based on prior period billings. Given the use of these models, and that customers are billed on a monthly cycle, we believe it is unlikely that materially different results will occur in future periods when revenue is billed. At December 31, 2015 and 2014, customer accounts receivable include unbilled energy revenues of $42.1 million and $48.4 million, respectively, on a base of annual revenue of $1.3 billion in 2015 and 2014. An allowance for potential credit losses is maintained and amounts are written off when normal collection efforts have been exhausted. Our provision for doubtful accounts included in “Other operating expenses” on the accompanying Consolidated Statements of Income was $4.3 million, $4.9 million and $3.8 million for the years ended December 31, 2015, 2014 and 2013, respectively.

IPL’s basic rates include a provision for fuel costs as established in IPL’s most recent rate proceeding, which last adjusted IPL’s rates in 1996. IPL is permitted to recover actual costs of purchased power and fuel consumed, subject to certain restrictions. This is accomplished through quarterly FAC proceedings, in which IPL estimates the amount of fuel and purchased power costs in future periods. Through these proceedings, IPL is also permitted to recover, in future rates, underestimated fuel and purchased power costs from prior periods, subject to certain restrictions, and therefore the over or underestimated costs are deferred or accrued and amortized into fuel expense in the same period that IPL’s rates are adjusted. See also Note 2, “Regulatory Matters,” for a discussion of other costs that IPL is permitted to recover through periodic rate adjustment proceedings and the status of current rate adjustment proceedings.

In addition, we are one of many transmission system owner members of MISO, a regional transmission organization which maintains functional control over the combined transmission systems of its members and manages one of the largest energy markets in the U.S. In the MISO market, IPL offers its generation and bids its demand into the market on an hourly basis. MISO settles these hourly offers and bids based on locational marginal prices, which is pricing for energy at a given location based on a market clearing price that takes into account physical limitations, generation, and demand throughout the MISO region. MISO evaluates the market participants’ energy offers and demand bids to economically and reliably dispatch the entire MISO system. IPL accounts for these hourly offers and bids, on a net basis, in UTILITY OPERATING REVENUES when in a net selling position and in UTILITY OPERATING EXPENSES – Power Purchased when in a net purchasing position.

Contingencies

IPALCO accrues for loss contingencies when the amount of the loss is probable and estimable. IPL is subject to various environmental regulations, and is involved in certain legal proceedings. If IPL’s actual environmental and/or legal obligations are different from our estimates, the recognition of the actual amounts may have a material impact on our results of operations, financial condition and cash flows; although that has not been the case during the periods covered by this report. As of December 31, 2015 and 2014, total loss contingencies accrued were $5.6 million and $5.2 million, respectively, which were included in “Other Current Liabilities” on the accompanying Consolidated Balance Sheets.

Concentrations of Risk

Substantially all of IPL’s customers are located within the Indianapolis area. In addition, approximately 65% of IPL’s full-time employees are covered by collective bargaining agreements in two bargaining units: a physical unit and a clerical-technical unit. IPL’s contract with the physical unit expires on December 10, 2018, and the contract with the clerical-technical unit expires February 20, 2017. Additionally, IPL has long-term coal contracts with four suppliers, with about 53% of our existing coal under contract for the three-year period ending December 31, 2018 coming from one supplier. Substantially all of the coal is currently mined in the state of Indiana.

Allowance For Funds Used During Construction

In accordance with the Uniform System of Accounts prescribed by FERC, IPL capitalizes an allowance for the net cost of funds (interest on borrowed funds and a reasonable rate of return on equity funds) used for construction purposes during the period of construction with a corresponding credit to income. IPL capitalized amounts using pretax composite rates of 8.1%, 8.3% and 8.6% during 2015, 2014 and 2013, respectively. For the Eagle Valley CCGT, Harding Street refueling projects, and NPDES projects, IPL capitalized amounts using a pretax composite rate of 7.3% and 7.6% during 2015 and 2014, respectively.

Utility Plant and Depreciation

Utility plant is stated at original cost as defined for regulatory purposes. The cost of additions to utility plant and replacements of retirement units of property are charged to plant accounts. Units of property replaced or abandoned in the ordinary course of business are retired from the plant accounts at cost; such amounts, less salvage, are charged to accumulated depreciation. Depreciation is computed by the straight-line method based on functional rates approved by the IURC and averaged 4.2%, 4.1%, and 4.0% during 2015, 2014 and 2013, respectively. Depreciation expense was $198.8 million, $185.9 million, and $180.0 million for the years ended December 31, 2015, 2014 and 2013, respectively, which includes depreciation expense that has been deferred as a regulatory asset.

Derivatives

We have only limited involvement with derivative financial instruments and do not use them for trading purposes. IPALCO accounts for its derivatives in accordance with ASC 815 “Derivatives and Hedging.” In addition, IPL has entered into contracts involving the physical delivery of energy and fuel. Because these contracts qualify for the normal purchases and normal sales scope exception in ASC 815, IPL has elected to account for them as accrual contracts, which are not adjusted for changes in fair value.

Fuel, Materials and Supplies

We maintain coal, fuel oil, materials and supplies inventories for use in the production of electricity. These inventories are accounted for at the lower of cost or market, using the average cost.

Impairment of Long-lived Assets

GAAP requires that we measure long-lived assets for impairment when indicators of impairment exist. If an asset is deemed to be impaired, we are required to write down the asset to its fair value with a charge to current earnings. The net book value of our utility plant assets was $3.5 billion and $2.9 billion as of December 31, 2015 and 2014, 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, such as CCT projects; the anticipated demand and relative pricing of retail electricity in our service territory and wholesale electricity in the region; and the cost of fuel.

Income Taxes

Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. The Company establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. The Company’s tax positions are evaluated under a more likely than not recognition threshold and measurement analysis before they are recognized for financial statement reporting.

Uncertain tax positions have been classified as noncurrent income tax liabilities unless expected to be paid within one year. The Company’s policy for interest and penalties is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations.

Income taxes payable which are includable in allowable costs for ratemaking purposes in future years are recorded as regulatory assets with a corresponding deferred tax liability. Investment tax credits that reduced federal income taxes in the years they arose have been deferred and are being amortized to income over the useful lives of the properties in accordance with regulatory treatment.

Cash and Cash Equivalents

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

Pension and Postretirement Benefits

regulatory asset as this can be recovered through future rates. All plan assets are recorded at fair value. We follow the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.

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

Effective January 1, 2016, we will apply a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and postretirement plans. This approach is consistent with the requirements of ASC 715 and is considered to be preferential to the aggregated single rate discount approach, which has historically been used in the U.S., because it is more consistent with the philosophy of a full yield curve valuation.

The change in discount rate approach did not have an impact on the measurement of the benefit obligations at December 31, 2015, nor will it impact future remeasurements. This change in approach will impact the service cost and interest cost recorded in 2016 and future years. It will also impact the actuarial gains and losses recorded in future years, as well as the amortization thereof.

The expected 2016 service costs and interest costs included in Note 9, “Benefit Plans” reflect the change in methodology described above. The impact of the change in approach on expected service costs in 2016 is shown below:



$ in thousands	Expected 2016 Service Cost							Expected 2016 Interest Cost
	Disaggregated rate approach		Aggregate rate approach		Impact of change			Disaggregated rate approach		Aggregate rate approach		Impact of change
Pension	$	7,018	$	7,382	$	(364	)	$	25,634	$	30,916	$	(5,282	)

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’s minority interest holder. IPALCO does not report earnings on a per-share basis.

New Accounting Pronouncements

ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606)

In May 2014, the FASB issued ASU No. 2014-09 which clarifies principles for recognizing revenue and will result in a common revenue standard for GAAP and International Financial Reporting Standards. The objective of the new standard is to provide a single and comprehensive revenue recognition model for all contracts with customers to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The standard requires an entity to recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, which deferred the effective date of ASU 2014-09 by one year, resulting in the new revenue standard being effective for annual reporting periods beginning after December 15, 2017 and interim periods therein. Early adoption is now permitted only as of the original effective date for public entities (that is, no earlier than 2017 for calendar year-end entities). The standard permits the use of either a full retrospective or modified retrospective approach. The Company has not yet selected a transition method and is currently evaluating the impact of adopting the standard on its consolidated financial statements.

ASU No. 2015-02, Consolidation - Amendments to the Consolidation Analysis (Topic 810)

annual periods beginning after December 15, 2015 and interim periods therein. Early adoption is permitted. The Company does not expect this standard to have an impact on its consolidated financial statements upon adoption.

ASU No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30)

In April 2015, the FASB issued ASU No. 2015-03, which simplifies the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. The standard is effective for annual reporting periods beginning after December 15, 2015 and interim periods therein, and requires the use of the full retrospective approach. Early adoption is permitted for financial statements that have not been previously issued. As of December 31, 2015, the Company had approximately $20.8 million in deferred financing costs classified in other noncurrent assets that would be reclassified to reduce the related debt liabilities upon adoption of ASU No. 2015-03.

ASU No. 2015-05, Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer's Accounting for Fees Paid in a Cloud Computing Arrangement

In April 2015, the FASB issued ASU No. 2015-05, which clarifies how customers in cloud computing arrangements should determine whether the arrangement includes a software license and eliminates the existing requirement for customers to account for software licenses they acquired by analogizing to the accounting guidance on leases. The standard is effective for annual reporting periods beginning after December 15, 2015 and interim periods therein. Early adoption is permitted. The standard permits the use of a prospective or retrospective approach. The Company expects to utilize the prospective approach upon adoption of this standard, which is not expected to have a material impact on its consolidated financial statements.

ASU No. 2015-11, Simplifying the Measurement of Inventory (Topic 330)

In July 2015, the FASB issued ASU No. 2015-11, which simplifies the subsequent measurement of inventory. It replaces the current lower of cost or market test with a lower of cost or net realizable value test. The standard is effective for public entities for annual reporting periods beginning after December 15, 2016, and interim periods therein. Early adoption is permitted. The new guidance must be applied prospectively. As the Company already uses the net realizable value to make lower of cost or market determinations, there will be no impact on its consolidated financial statements upon adoption of this standard.

ASU No. 2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements

In August 2015, the FASB issued ASU No. 2015-15, which clarifies that the SEC Staff would not object to an entity presenting debt issuance costs related to line-of-credit arrangements as an asset that is subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. This standard should be adopted concurrent with adoption of ASU 2015-03 (which is described above). As of December 31, 2015, the Company had deferred financing costs related to lines of credit of approximately $0.3 million recorded within Deferred Debits that would not be reclassified upon adoption of this standard.

ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments

In September 2015, the FASB issued ASU 2015-16, which simplifies the measurement-period adjustments in business combinations. It eliminates the requirement that an acquirer in a business combination account for measurement-period adjustments retrospectively. An acquirer will recognize a measurement-period adjustment during the period in which it determines the amount of the adjustment. The standard is effective for public entities for annual reporting periods beginning after December 15, 2015, and interim periods therein. Early adoption is permitted for financial statements that have not been issued. The new guidance should be applied prospectively to adjustments to provisional amounts that occur after the effective date of this standard. The Company will adopt this standard on January 1, 2016, which is not expected to have a material impact on the Company's consolidated financial statements.

ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes

deferred tax liabilities from one jurisdiction against deferred tax assets of another jurisdiction. Additionally, the current requirement that deferred tax liabilities and assets of a tax-paying component of an entity be offset and presented as a single amount is not affected by the update. As the Company elected to apply this ASU prospectively, prior periods were not adjusted.

ASU No. 2016-01, Financial Instruments - Overall (Topic 825-10): Recognition and Measurement of Financial Assets

and Financial Liabilities

In January 2016, the FASB issued ASU 2016-01, which was designed to improve the recognition and measurement of

financial instruments through targeted changes to existing GAAP. The guidance requires equity investments (except those that

are accounted for under the equity method of accounting or result in consolidation of the investee) to be measured at fair value

with changes in fair value recognized in net income; that entities use the exit price notion when measuring financial instrument

fair values; that an entity separate presentation of financial assets and liabilities by measurement category and form of financial

asset on the Balance Sheets or Notes to the financial statements; that an entity present separately in other comprehensive

income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit

risk (or “own credit”) when the entity has elected to measure the liability at fair value in accordance with the fair value option

for financial instruments. Also, the standard eliminates the requirement for public entities to disclose the methods and

significant assumptions used to estimate the fair value required to be disclosed for financial instruments measured at amortized

cost on the Balance Sheets. The standard is effective beginning with interim periods starting after December 31, 2017 and

cannot be applied early. The Company is currently evaluating the applicability and materiality of the standard, but doesn't

anticipate a material impact on the Company's 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 short-term borrowing not regulated by the IURC, the sale of electricity at wholesale and the transmission of electric energy in interstate commerce, the classification of accounts, reliability standards, and the acquisition and sale of utility property in certain circumstances as provided by the Federal Power Act. As a regulated entity, IPL is required to use certain accounting methods prescribed by regulatory bodies which may differ from those accounting methods required to be used by unregulated entities.

IPL is also affected by the regulatory jurisdiction of the 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 were last adjusted in 1996; however, IPL filed a petition with the IURC on December 29, 2014, for authority to increase its basic rates and charges. IPL's proposed increase, filed as part of IPL's rebuttal testimony in this proceeding, is $63.3 million annually, or 5.3%. An order on this proceeding will likely be issued by the IURC early in 2016. The petition also includes requests to implement rate adjustment mechanisms for short-term recovery of fluctuations in the following costs: (1) capacity purchase costs; (2) off-systems sales margins; and (3) MISO non-fuel charges (MISO fuel charges are already included in the FAC rate mechanism as described below). No assurances can be given as to the timing or outcome of this proceeding. See “Rate Case and Downtown Underground Network Investigation” below for further details.

Rate Case and Downtown Underground Network Investigation

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 every six months to recover costs 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, 2015 was $978 million. The jurisdictional revenue requirement that was approved by the IURC to be included in IPL’s rates for the six-month period from September 2015 through February 2016 was $82.0 million. During the years ended December 31, 2015, 2014 and 2013, we made environmental compliance expenditures of $252.2 million, $176.3 million, and $126.6 million, respectively. The vast majority of such costs are recoverable through our ECCRA filings.

DSM

Wind and Solar Power Purchase Agreements

MISO Transmission Expansion Cost Sharing

3. UTILITY PLANT IN SERVICE

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



	As of December 31,
	2015		2014
	(In Thousands)
Production	$	3,111,674	$	2,862,579
Transmission	293,767		268,594
Distribution	1,371,029		1,323,190
General plant	216,124		203,660
Total utility plant in service	$	4,992,594	$	4,658,023

Substantially all of IPL’s property is subject to a $1,283.5 million direct first mortgage lien, as of December 31, 2015, securing IPL’s first mortgage bonds. Property under capital leases as of December 31, 2015 and 2014 was insignificant. Total non-contractually or legally required removal costs of utility plant in service at December 31, 2015 and 2014 were $673.8 million and $636.8 million, respectively; and total contractually or legally required removal costs of utility plant in service at December 31, 2015 and 2014 were $59.0 million and $59.1 million, respectively. Please see “– ARO” below for further information.

IPL anticipates material additional costs to comply with various pending and final federal legislation and regulations and it is IPL’s intent to seek recovery of any additional costs. The majority of the expenditures for construction projects designed to reduceSO₂ and mercury emissions are recoverable from jurisdictional retail customers as part of IPL’s CCT projects; however, since jurisdictional retail rates are subject to regulatory approval, there can be no assurance that all costs will be recovered in rates.

ARO

IPL’s ARO relates primarily to environmental issues involving asbestos, ash ponds, landfills and miscellaneous contaminants associated with its generating plants, transmission system and distribution system. The following is a reconciliation of the ARO legal liability year end balances:



	2015			2014
	(In Millions)
Balance as of January 1	$	59.1		$	41.4
Liabilities incurred	0.6			—
Liabilities settled	(2.5		)	—
Revisions in estimated cash flows	(1.3		)	15.4
Accretion expense	3.1			2.3
Balance as of December 31	$	59.0		$	59.1

As of December 31, 2015 and 2014, IPL did not have any assets that are legally restricted for settling its ARO liability.

4. FAIR VALUE

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

Fair Value Hierarchy and Valuation Techniques

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

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

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

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

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

FTRs

In connection with IPL’s participation in MISO, in the second quarter of each year IPL is granted financial instruments that can be converted into cash or FTRs based on IPL’s forecasted peak load for the period. FTRs are used in the MISO market to hedge IPL’s exposure to congestion charges, which result from constraints on the transmission system. IPL converts all of these financial instruments into FTRs. IPL’s FTRs are valued at the cleared auction prices for FTRs in MISO’s annual auction. Because of the infrequent nature of this valuation, the fair value assigned to the FTRs is considered a Level 3 input under the fair value hierarchy required by ASC 820. An offsetting regulatory liability has been recorded as these revenues or costs will be flowed through to customers through the FAC. As such, there is no impact on our Consolidated Statements of Income.

Other Financial Liabilities

As of December 31, 2015 and 2014, all of IPALCO's financial assets or liabilities measured at fair value on a recurring basis were considered Level 3, based on the fair value hierarchy.

Summary

The fair value of assets and liabilities at December 31, 2015 measured on a recurring basis and the respective category within the fair value hierarchy for IPALCO was determined as follows:



Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
	Fair value at December 31, 2015		Based on quoted market prices in active markets		Other observable inputs		Unobservable inputs
	(In Thousands)
Financial assets:
Financial transmission rights	$	4,150	$	—	$	—	$	4,150
Total financial assets measured at fair value	$	4,150	$	—	$	—	$	4,150
Financial liabilities:
Other derivative liabilities	$	121	$	—	$	—	$	121
Total financial liabilities measured at fair value	$	121	$	—	$	—	$	121

The fair value of assets and liabilities at December 31, 2014 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, 2014		Based on quoted market prices in active markets		Other observable inputs		Unobservable inputs
	(In Thousands)
Financial assets:
Financial transmission rights	$	6,235	$	—	$	—	$	6,235
Total financial assets measured at fair value	$	6,235	$	—	$	—	$	6,235
Financial liabilities:
Other derivative liabilities	$	140	$	—	$	—	$	140
Total financial liabilities measured at fair value	$	140	$	—	$	—	$	140

The following table sets forth a reconciliation of financial instruments, measured at fair value on a recurring basis, classified as Level 3 in the fair value hierarchy (note, amounts in this table indicate carrying values, which approximate fair values):



	Derivative Financial Instruments, net Liability
	(In Thousands)
Balance at January 1, 2014	$	4,133
Unrealized gain recognized in earnings	16
Issuances	15,710
Settlements	(13,764		)
Balance at December 31, 2014	$	6,095
Unrealized gain recognized in earnings	47
Issuances	13,281
Settlements	(15,394		)
Balance at December 31, 2015	$	4,029

Non-Recurring Fair Value Measurements

ASC 410 “Asset Retirement and Environmental Obligations” addresses financial accounting and reporting for legal obligations associated with the retirement of long-lived assets that result from 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 liabilities relate primarily to environmental issues involving asbestos-containing materials, ash ponds, landfills and miscellaneous contaminants associated with its generating plants, transmission system and distribution system. We use the cost approach to determine the fair value of IPL’s ARO liabilities, which is estimated by discounting expected cash outflows to their present value at the initial recording of the liabilities. Cash outflows are based on the approximate future disposal costs as determined by market information, historical information or other management estimates. These inputs to the fair value of the ARO liabilities would be considered Level 3 inputs under the fair value hierarchy. As of December 31, 2015 and 2014, ARO liabilities were $59.0 million and $59.1 million, respectively. See Note 3, “Utility Plant in Service,” for a rollforward of the ARO liability.

Financial Instruments not Measured at Fair Value in the Consolidated Balance Sheets

Debt

The fair value of our outstanding fixed-rate debt has been determined on the basis of the quoted market prices of the specific securities issued and outstanding. In certain circumstances, the market for such securities was inactive and therefore the valuation was adjusted to consider changes in market spreads for similar securities. Accordingly, the purpose of this disclosure is not to approximate the value on the basis of how the debt might be refinanced.

The following table shows the face value and the fair value of fixed-rate and variable-rate indebtedness (Level 2) for the periods ending:



	December 31, 2015				December 31, 2014
	Face Value		Fair Value		Face Value		Fair Value
	(In Millions)
Fixed-rate	$	2,088.4	$	2,225.3	$	1,955.3	$	2,231.2
Variable-rate	256.9		256.9		50.0		50.0
Total indebtedness	$	2,345.3	$	2,482.2	$	2,005.3	$	2,281.2

The difference between the face value and the carrying value of this indebtedness represents unamortized discounts of $4.6 million and $4.3 million at December 31, 2015 and 2014, respectively.

5. REGULATORY ASSETS AND LIABILITIES

Regulatory assets represent deferred costs or credits that have been included as allowable costs or credits for ratemaking purposes. IPL has recorded regulatory assets or liabilities relating to certain costs or credits as authorized by the IURC or established regulatory practices in accordance with ASC 980. IPL is amortizing non tax‑related regulatory assets to expense over periods ranging from 1 to 35 years. Tax-related regulatory assets represent the net income tax costs to be considered in future regulatory proceedings generally as the tax-related amounts are paid.

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



	2015		2014		Recovery Period
	(In Thousands)
Regulatory Assets
Current:
Environmental projects	$	8,002	$	93	Through 2016⁽¹⁾
Total current regulatory assets	$	8,002	$	93
Long-term:
Unrecognized pension and other
postretirement benefit plan costs	$	226,889	$	229,590	Various
Income taxes recoverable through rates	35,765		31,335		Various
Deferred MISO costs	128,610		110,500		To be determined⁽²⁾
Unamortized Petersburg Unit 4 carrying
charges and certain other costs	11,248		12,302		Through 2026^{(1) (3)}
Unamortized reacquisition premium on debt	23,268		24,585		Over remaining life of debt
Environmental projects	16,876		7,671		Through 2021⁽¹⁾
Other miscellaneous	5,544		3,210		To be determined⁽²⁾
Total long-term regulatory assets	$	448,200	$	419,193
Total regulatory assets	$	456,202	$	419,286
Regulatory Liabilities
Current:
Deferred fuel	$	19,746	$	17,837	Through 2016⁽¹⁾
FTRs	4,150		6,235		Through 2016⁽¹⁾
DSM program costs	4,273		2,001		Through 2016⁽¹⁾
Environmental projects	—		1,870		Through 2016⁽¹⁾
Total current regulatory liabilities	$	28,169	$	27,943
Long-term:
ARO and accrued asset removal costs	$	637,065	$	607,628	Not Applicable
Unamortized investment tax credit	2,451		3,289		Through 2021
Total long-term regulatory liabilities	$	639,516	$	610,917
Total regulatory liabilities	$	667,685	$	638,860


(1)	Recovered (credited) per specific rate orders


(2)	Recovery is probable but timing not yet determined


(3)	Recovered with a current return

Deferred Fuel

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

Deferred fuel was a regulatory liability of $19.7 million and $17.8 million as of December 31, 2015 and 2014, respectively. The deferred fuel liability increased $1.9 million in 2015 as a result of IPL charging more for fuel than our actual costs to our jurisdictional customers.

Unrecognized Pension and Postretirement Benefit Plan Costs

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

Income Taxes Recoverable Through Rates

This amount represents the portion of deferred income taxes that we believe will be recovered through future rates, based upon established regulatory practices, which permit the recovery of current taxes. Accordingly, this regulatory asset is offset by a deferred tax liability and is expected to be recovered, without interest, over the period underlying book-tax timing differences reverse and become current taxes.

Deferred MISO Costs

These consist of administrative costs for transmission services, transmission expansion cost sharing, and certain other operational and administrative costs from the MISO market. IPL received orders from the IURC that granted authority for IPL to defer such costs and seek recovery in a future basic rate case. Recovery of these costs is believed to be probable, but not certain. See Note 2, “Regulatory Matters.”

ARO and Accrued Asset Removal Costs

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

6. EQUITY

Equity Transactions

On December 15, 2014, AES announced that it entered into an agreement with CDPQ, a long-term institutional investor headquartered in Quebec, Canada. Pursuant to the agreement, on February 11, 2015 CDPQ purchased from AES 15% of AES U.S. Investments and 100 shares of IPALCO’s common stock were issued to CDPQ. In addition, CDPQ agreed to invest approximately $349 million in IPALCO through 2016 (of which $214.4 million has been contributed through December 31, 2015), in exchange for a 17.65% equity stake, funding existing growth and environmental projects at IPL.

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

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

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

Paid In Capital and Capital Stock

On June 27, 2014, and July 31, 2013, IPALCO received equity capital contributions of $106.4 million and $49.1 million, respectively, from AES for funding needs related to IPL’s environmental and replacement generation projects. IPALCO then made the same equity capital contributions to IPL.

On April 1, 2015, IPALCO issued and sold 11,818,828 shares of IPALCO's common stock to CDPQ for $214.4 million for funding needs primarily related to IPL's environmental construction program. IPALCO then made the same investment in IPL. As a result of this transaction, CDPQ's direct ownership interest in IPALCO is 11.6% and CDPQ's combined direct and indirect ownership interest in IPALCO is 24.9%.

There have been no changes to IPALCO’s capital stock balances during the three years ended December 31, 2015.

Dividend Restrictions

maintain a ratio of total debt to total capitalization not in excess of 0.65 to 1, in order to pay dividends. As of December 31, 2015 and as of the filing of this report, IPL was in compliance with all covenants and no event of default existed.

Cumulative Preferred Stock

IPL has five separate series of cumulative preferred stock. Holders of preferred stock are entitled to receive dividends at rates per annum ranging from 4.0% to 5.65%. During each year ended December 31, 2015, 2014 and 2013, 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, 2015, 2014 and 2013, preferred stock consisted of the following:



	December 31, 2015			December 31,
	Shares Outstanding	Call Price		2015		2014		2013
	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	2015			2014
		(In Thousands)
IPL first mortgage bonds (see below):
4.90% ⁽¹⁾	January 2016	$	—		$	30,000
4.90% ⁽¹⁾	January 2016	—			41,850
4.90% ⁽¹⁾	January 2016	—			60,000
5.40% ⁽²⁾	August 2017	24,650			24,650
3.875% ⁽¹⁾	August 2021	55,000			55,000
3.875% ⁽¹⁾	August 2021	40,000			40,000
4.55% ⁽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			—
Unamortized discount – net		(4,242		)	(2,940		)
Total IPL first mortgage bonds		1,279,208			1,152,360
IPL unsecured debt:
Variable ⁽³⁾	December 2020	30,000			—
Variable ⁽³⁾	December 2020	60,000			—
Total IPL unsecured debt		90,000			—
Total Long-term Debt – IPL		1,369,208			1,152,360
Long-term Debt – IPALCO:
7.25% Senior Secured Notes	April 2016	—			400,000
5.00% Senior Secured Notes	May 2018	400,000			400,000
3.45% Senior Secured Notes	July 2020	405,000			—
Unamortized discount – net		(371		)	(1,347		)
Total Long-term Debt – IPALCO		804,629			798,653
Total Consolidated IPALCO Long-term Debt		2,173,837			1,951,013
Less: Current Portion of Long-term Debt		—			—
Net Consolidated IPALCO Long-term Debt		$	2,173,837		$	1,951,013


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


(2)	First mortgage bonds are issued to the city of Petersburg, Indiana, to secure the loan proceeds from various tax-exempt instruments issued by the city.


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

Debt Maturities

Maturities on long-term indebtedness subsequent to December 31, 2015, are as follows:



Year	Amount
	(In Thousands)
2016	$	—
2017	24,650
2018	400,000
2019	—
2020	495,000
Thereafter	1,258,800
Total	$	2,178,450

Significant Transactions

IPL First Mortgage Bonds

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 $1,283.5 million as of December 31, 2015. 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, 2015.

In June 2013, IPL issued $170 million aggregate principal amount of first mortgage bonds, 4.65% Series, due June 2043. Net proceeds from this offering were approximately $167.9 million, after deducting the initial purchasers’ discounts, fees and expenses for the offering payable by IPL. The net proceeds from the offering were used in June 2013 to finance the redemption of $110 million aggregate principal amount of IPL first mortgage bonds, 6.30% Series, due July 2013, and to pay related fees, expenses and applicable redemption prices. We used all remaining proceeds to finance a portion of our environmental construction program and for other general corporate purposes.

In June 2014, IPL issued $130 million aggregate principal amount of first mortgage bonds, 4.50% Series, due June 2044. Net proceeds from this offering were approximately $126.8 million, after deducting the initial purchasers’ discounts, fees and expenses for the offering payable by IPL. The net proceeds from the offering were used: (i) to finance a portion of IPL’s construction program; (ii) to finance a portion of IPL’s capital costs related to environmental and replacement generation projects; and (iii) for other general corporate purposes.

In September 2015, IPL issued $260 million aggregate principal amount of first mortgage bonds, 4.70% Series, due September 2045, pursuant to Rule 144A and Regulation S under the Securities Act. Net proceeds from this offering were approximately $255.6 million, after deducting the initial purchasers’ discounts and fees and expenses for the offering payable by IPL. The net proceeds from the offering were used to finance a portion of IPL's construction program and capital costs related to environmental and replacement generation projects and for other general corporate purposes.

In December 2015, IPL refunded $131.9 million aggregate principal amount of first mortgage bonds, 4.90% Series, due January 2016 from the proceeds of unsecured notes with a syndication of banks. For further discussion, please see “– IPL Unsecured Notes” below.

IPL Unsecured Notes

In October 2015, IPL entered into an unsecured $91.9 million 364-day committed credit facility with a delayed draw feature at variable rates with a syndication of banks. It was drawn on in October and December 2015 to fund the October 2015 termination of IPL’s $50 million accounts receivable securitization program and to assist in the December 2015 refunding of $41.9 million of IPL's outstanding aggregate principal amount of 4.90% Environmental Facilities Refunding Revenue Bonds (Indianapolis Power & Light Company Project) Series 2009A due in January 2016. This agreement matures on October 14, 2016, and bears interest at variable rates as described in the credit agreement. This credit facility contain customary

representations, warranties and covenants, including a leverage covenant consistent with the leverage covenant contained in IPL's Credit Agreement.

In December 2015, the Indiana Finance Authority issued on behalf of IPL an aggregate principal amount of $90 million of Environmental Facilities Refunding Revenue Notes due December 2038 (Indianapolis Power & Light Company Project). These unsecured notes were issued in two series: $30 million Series 2015A notes and $60 million 2015B notes. These notes were initially purchased by a syndication of banks who will hold the notes until the mandatory put date of December 22, 2020. The proceeds of the 2015A notes and the 2015B notes were loaned to IPL to assist it in refunding the $30 million Indiana Finance Authority Environmental Facilities Refunding Revenue Bonds (Indianapolis Power & Light Company Project) Series 2009B and $60 million Indiana Finance Authority Environmental Facilities Refunding Revenue Bonds (Indianapolis Power & Light Company Project) Series 2009C each series due January 1, 2016. These notes bear interest at a variable rate as described in the notes purchase and covenants agreement. The agreement contains customary representations, warranties and covenants, including a leverage covenant consistent with the leverage covenant contained in IPL's Credit Agreement.

IPALCO’s Senior Secured Notes

In June 2015, IPALCO completed the sale of the 2020 IPALCO Notes pursuant to Rule 144A and Regulation S under the Securities Act. The 2020 IPALCO Notes were issued pursuant to an Indenture dated June 25, 2015, by and between IPALCO and U.S. Bank, National Association, as trustee. The 2020 IPALCO Notes were priced to the public at 99.929% of the principal amount. Net proceeds to IPALCO were approximately $399.5 million after deducting underwriting costs and estimated offering expenses. These costs are being amortized to the maturity date using the effective interest method. We used the net proceeds from this offering to fund the purchase of the 2016 IPALCO Notes validly tendered and to pay for a related consent solicitation, to redeem any 2016 IPALCO Notes that remained outstanding after the completion of the tender, and to pay certain related fees, expenses and make-whole premiums. Of the 2016 IPALCO Notes outstanding, $366.5 million were tendered in June 2015. The remainder, $33.5 million, was redeemed in July 2015. An early tender premium was paid related to the tender offer and a redemption premium was paid related to the redemption of the 2016 IPALCO Notes. A loss on early extinguishment of debt of $22.1 million for the 2016 IPALCO Notes is included as a separate line item within “Other Income and (Deductions)” in the accompanying Consolidated Statements of Operations.

The 2020 IPALCO Notes are secured by IPALCO's pledge of all of the outstanding common stock of IPL. The lien on the pledged shares is shared equally and ratably with IPALCO's existing senior secured notes. IPALCO has entered into a Pledge Agreement Supplement with the Bank of New York Mellon Trust Company, N.A., as Collateral Agent, dated June 25, 2015, to the Pledge Agreement between IPALCO and The Bank of New York Mellon Trust Company, N.A., dated November 14, 2001, as supplemented by a Pledge Agreement Supplement dated April 15, 2008 and a Pledge Agreement Supplement dated May 18, 2011, each by IPALCO in favor of the Collateral Agent. IPALCO also agreed to register the 2020 IPALCO Notes under the Securities Act by filing an exchange offer registration statement or, under specified circumstances, a shelf registration statement with the SEC pursuant to a Registration Rights Agreement that IPALCO entered into with J.P. Morgan Securities LLC and Morgan Stanley & Co. LLC, as representatives of the initial purchasers of the 2020 IPALCO Notes. IPALCO filed its registration statement on Form S-4 with respect to the 2020 IPALCO Notes with the SEC on September 28, 2015, and this registration statement was declared effective on October 15, 2015. The exchange offer was completed on November 16, 2015.

The 2018 IPALCO Notes and 2020 IPALCO Notes are secured by IPALCO’s pledge of all of the outstanding common stock of IPL.

Line of Credit

IPL entered into an amendment and restatement of its 5-year $250 million revolving credit facility in May 2014, and a further amendment and extension of the credit facility on October 16, 2015 (the “Credit Agreement”) with a syndication of banks. This Credit Agreement is an unsecured committed line of credit to be used: (i) to finance capital expenditures; (ii) to refinance indebtedness under the existing credit agreement; (iii) to support working capital; and (iv) for general corporate purposes. This agreement matures on October 16, 2020, and bears interest at variable rates as described in the Credit Agreement. It includes an uncommitted $150 million accordion feature to provide IPL with an option to request an increase in the size of the facility at any time prior to October 16, 2019, subject to approval by the lenders. Prior to execution, IPL and IPALCO had existing general banking relationships with the parties in this agreement. As of December 31, 2015 and 2014, IPL had $75.0 million and $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 28, 2016. In December 2015, IPL received an order from the IURC granting IPL authority through December 31, 2018 to, among other things, issue up to $650 million in aggregate principal amount of long-term debt (inclusive of $260 million of first mortgage bonds issued in September 2015), refinance up to $196.5 million in existing indebtedness (inclusive of $90 million of unsecured notes issued in December 2015), have up to $500 million of long-term credit agreements and liquidity facilities outstanding at any one time, and, as an alternative to the sale of all or a portion of $65 million in principal amount of the long-term debt mentioned above, issue up to $65 million of new preferred stock. IPL also has restrictions on the amount of new debt that may be issued due to contractual obligations of AES and by financial covenant restrictions under our existing debt obligations. Under such restrictions, IPL is generally allowed to fully draw the amounts available on its credit facility, refinance existing debt and issue new debt approved by the IURC and issue certain other indebtedness.

Credit Ratings

Our ability to borrow money or to refinance existing indebtedness and the interest rates at which we can borrow money or refinance existing indebtedness are affected by our credit ratings. In addition, the applicable interest rates on IPL’s Credit Agreement and other unsecured notes (as well as the amount of certain other fees on the Credit Agreement and the 364-day 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.

Accounts Receivable Securitization

IPL formed IPL Funding in 1996 as a special-purpose entity to purchase receivables originated by IPL pursuant to a receivables purchase agreement between IPL and IPL Funding. IPL Funding also entered into a sale facility as defined in the Receivables Sale Agreement, which matured as extended on October 24, 2012. At that time, the Purchasers replaced The Royal Bank of Scotland plc and Windmill Funding Corporation as Agent and Investor, respectively. On October 20, 2014, Citibank, as the sole Liquidity Provider, and CRC Funding entered into a Transfer Supplement pursuant to which Citibank assigned to CRC Funding, and CRC Funding assumed, all of Citibank’s Commitment and Purchase Interest, and accordingly, CRC Funding was both the Investor and a Liquidity Provider, referred to as the “Purchaser.”

Pursuant to the terms of the Receivables Sale Agreement, the Purchasers agree to purchase from IPL Funding, on a revolving basis, interests in the pool of receivables purchased from IPL up to the lesser of (1) an amount determined pursuant to the sale facility that took into account certain eligibility requirements and reserves relating to the receivables, or (2) $50 million. That amount was $0 million and $50 million as of December 31, 2015 and 2014, respectively. As collections reduce accounts receivable included in the pool, IPL Funding sells ownership interests in additional receivables acquired from IPL to return the ownership interests sold to the maximum amount permitted by the sale facility. IPL Funding is included in the Consolidated Financial Statements of IPALCO.

On October 16, 2015, IPL closed on a new unsecured $91.9 million 364-day committed credit facility with a syndication of banks. The first $50 million of the term loan was drawn at closing to fund the October 19, 2015 termination of IPL's $50 million accounts receivable securitization program. Please see “– IPL Unsecured Notes” above for details.

8. INCOME TAXES

IPALCO follows a policy of comprehensive interperiod income tax allocation. Investment tax credits related to utility property have been deferred and are being amortized over the estimated useful lives of the related property.

AES files federal and state income tax returns which consolidate IPALCO and its subsidiaries. Under a tax sharing agreement with AES, IPALCO is responsible for the income taxes associated with its own taxable income and records the provision for income taxes as if IPALCO and its subsidiaries each filed separate income tax returns. IPALCO is no longer subject to U.S. or state income tax examinations for tax years through March 27, 2001, but is open for all subsequent periods.

On March 25, 2014, the State of Indiana amended Indiana Code 6-3-2-1 through Senate Bill 001, which phases in an additional 1.6% reduction to the state corporate income tax rate that was initially being reduced by 2%. While the statutory state income tax rate remained at 6.75% for the calendar year 2015, 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 $1.0 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 $0.4 million.

On September 13, 2013, the Internal Revenue Service released final regulations addressing the acquisition, production and improvement of tangible property and proposed regulations addressing the disposition of property. These regulations replace previously issued temporary regulations and are effective for tax years beginning on or after January 1, 2014. IPL management has opted to fully implement the new regulations effective with its 2014 income tax return. IPL has recorded the tax effect of a $245.9 million favorable Internal Revenue Code Section 481(a) adjustment to its balance sheet as a result of the regulations. This amount represents the cumulative effective of accelerated deductions related to repairs of tangible property through December 31, 2013. The adjustment does not impact the income statement.

Internal Revenue Code Section 199 permits taxpayers to claim a deduction from taxable income attributable to certain domestic production activities. IPL’s electric production activities qualify for this deduction. Beginning in 2010 and thereafter, the deduction is equal to 9% of the taxable income attributable to qualifying production activity. There was no tax benefit associated with the Internal Revenue Code Section 199 domestic production deduction for tax years 2015 and 2014, primarily due to the election of the final tangible property regulations. The tax benefit associated with tax year 2013 was $3.7 million.

In 2015, IPALCO elected to early adopt ASU No. 2015-17, “Balance Sheet Classification of Deferred Taxes,” under the prospective method. To simplify presentation of deferred income taxes, ASU 2015-17 requires that deferred tax liabilities and assets be classified as non-current in a statement of financial position, removing the previous requirement to report both current and non-current deferred tax liabilities and assets separately. By early adopting under the prospective method, previous reporting periods have not been retrospectively adjusted.

Income Tax Provision

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



	2015			2014			2013
	(In Thousands)
Charged to utility operating expenses:
Current income taxes:
Federal	$	18,661		$	944		$	53,937
State	5,758			110			15,191
Total current income taxes	24,419			1,054			69,128
Deferred income taxes:
Federal	29,165			58,114			(8,048		)
State	5,019			12,498			(1,031		)
Total deferred income taxes	34,184			70,612			(9,079		)
Net amortization of investment credit	(1,319		)	(1,431		)	(1,501		)
Total charge to utility operating expenses	57,284			70,235			58,548
Charged to other income and deductions:
Current income taxes:
Federal	(18,661		)	(459		)	(16,909		)
State	(5,758		)	(5		)	(4,193		)
Total current income taxes	(24,419		)	(464		)	(21,102		)
Deferred income taxes:
Federal	(2,573		)	(18,082		)	246
State	1,274			(3,645		)	50
Total deferred income taxes	(1,299		)	(21,727		)	296
Net provision to other income and deductions	(25,718		)	(22,191		)	(20,806		)
Total federal and state income tax provisions	$	31,566		$	48,044		$	37,742

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:



	2015		2014		2013
Federal statutory tax rate	35.0	%	35.0	%	35.0	%
State income tax, net of federal tax benefit	4.7	%	4.8	%	6.7	%
Amortization of investment tax credits	(1.5	)%	(1.2	)%	(1.5	)%
Preferred dividends of subsidiary	1.3	%	0.9	%	1.1	%
Depreciation flow through and amortization	(0.3	)%	(0.3	)%	(0.3	)%
Additional funds used during construction - equity	(3.5	)%	(0.3	)%	0.6	%
Manufacturers’ Production Deduction (Sec. 199)	—	%	—	%	(3.8	)%
Other – net	0.2	%	0.2	%	0.5	%
Effective tax rate	35.9	%	39.1	%	38.3	%

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, 2015 and 2014, are as follows:



	2015		2014
	(In Thousands)
Deferred tax liabilities:
Relating to utility property, net	$	541,369	$	539,318
Regulatory assets recoverable through future rates	178,187		161,697
Other	11,768		14,211
Total deferred tax liabilities	731,324		715,226
Deferred tax assets:
Investment tax credit	1,507		2,019
Regulatory liabilities including ARO	260,555		247,118
Employee benefit plans	38,159		45,091
Net operating loss	23,161		51,364
Other	10,548		10,289
Total deferred tax assets	333,930		355,881
Net deferred tax liability	397,394		359,345
Less: deferred tax asset - current	—		(61,782		)
Deferred income taxes – net	$	397,394	$	421,127

Uncertain Tax Positions

The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2015, 2014 and 2013:



	2015			2014			2013
	(In Thousands)
Unrecognized tax benefits at January 1	$	7,042		$	6,734		$	6,138
Gross increases – current period tax positions	962			975			986
Gross decreases – prior period tax positions	(857		)	(667		)	(390		)
Unrecognized tax benefits at December 31	$	7,147		$	7,042		$	6,734

The unrecognized tax benefits at December 31, 2015 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 84% of IPL’s active employees are covered by the Thrift Plan, a qualified defined contribution plan. All union new hires are covered under the Thrift Plan. Participants elect to make contributions to the Thrift Plan based on a percentage of their base compensation. Each participant’s contribution is matched up to certain thresholds of base compensation. The IBEW clerical-technical union new hires receive an annual lump sum company contribution into the Thrift Plan in addition to the company match. Employer contributions to the Thrift Plan were $3.1 million, $3.0 million and $3.0 million for 2015, 2014 and 2013, respectively.

The RSP

Approximately 16% of IPL’s active employees are covered by the RSP, a qualified defined contribution plan containing a profit sharing component. All non-union new hires are covered under the RSP. Participants elect to make contributions to the RSP based on a percentage of their taxable compensation. Each participant’s contribution is matched in amounts up to, but not exceeding, 5% of the participant’s taxable compensation. In addition, the RSP has a profit sharing component whereby IPL contributes a percentage of each employee’s annual salary into the plan on a pre-tax basis. The profit sharing percentage is determined by the AES board of directors on an annual basis. Employer payroll-matching and profit sharing contributions (by IPL) relating to the RSP were $0.3 million, $1.5 million and $1.8 million for 2015, 2014 and 2013, respectively. The decrease in the 2015 net contributions is a result of truing up prior year estimated profit sharing contributions.

Defined Benefit Plans

Approximately 77% of IPL’s active employees are covered by the qualified Defined Benefit Pension Plan; while approximately 7% of active employees are IBEW clerical-technical unit employees who are only eligible for the Thrift Plan, which is a defined contribution plan. The remaining 16% 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. Effective April 1, 2015, benefits for non-union participants in the Defined Benefit Pension Plan are based on salary and years of service. 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, 2015 was 24. 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 171 active employees and 27 retirees (including spouses) were receiving such benefits or entitled to future benefits as of January 1, 2015. The plan is unfunded. These postretirement health care benefits and the related obligation were not material to the consolidated financial statements in the periods covered by this report.

The following table presents information relating to the Pension Plans:



	Pension benefits as of December 31,
	2015			2014
	(In Thousands)
Change in benefit obligation:
Projected benefit obligation at January 1	$	748,421		$	650,713
Service cost	8,314			7,231
Interest cost	29,638			31,154
Actuarial (gain) loss	(31,989		)	90,693
Amendments (primarily increases in pension bands)	5,409			1,233
Settlements	(395		)	—
Benefits paid	(35,511		)	(32,603		)
Projected benefit obligation at December 31	723,887			748,421
Change in plan assets:
Fair value of plan assets at January 1	657,239			561,586
Actual return on plan assets	1,074			74,147
Employer contributions	25,166			54,109
Settlements	(395		)	—
Benefits paid	(35,511		)	(32,603		)
Fair value of plan assets at December 31	647,573			657,239
Unfunded status	$	(76,314	)	$	(91,182	)
Amounts recognized in the statement of financial position:
Noncurrent liabilities	$	(76,314	)	$	(91,182	)
Net amount recognized at end of year	$	(76,314	)	$	(91,182	)
Sources of change in regulatory assets ⁽¹⁾:
Prior service cost arising during period	$	5,409		$	1,233
Net loss arising during period	11,757			58,439
Amortization of prior service cost	(4,867		)	(4,853		)
Amortization of loss	(14,096		)	(9,710		)
Total recognized in regulatory assets ⁽¹⁾	$	(1,797	)	$	45,109
Amounts included in regulatory assets ⁽¹⁾:
Net loss	$	209,252		$	211,592
Prior service cost	25,842			25,299
Total amounts included in regulatory assets	$	235,094		$	236,891

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

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



	Pension benefits as of December 31,
	2015		2014
	(In Thousands)
Benefit obligation	$	723,887	$	748,421
Plan assets	647,573		657,239
Benefit obligation in excess of plan assets	$	76,314	$	91,182

IPL’s total benefit obligation in excess of plan assets was $76.3 million as of December 31, 2015 ($75.3 million Defined Benefit Pension Plan and $1.0 million Supplemental Retirement Plan).

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



	Pension benefits as of December 31,
	2015		2014
	(In Thousands)
Accumulated benefit obligation	$	712,297	$	734,328
Plan assets	647,573		657,239
Accumulated benefit obligation in excess of plan assets	$	64,724	$	77,089

IPL’s total accumulated benefit obligation in excess of plan assets was $64.7 million as of December 31, 2015 ($63.7 million Defined Benefit Pension Plan and $1.0 million Supplemental Retirement Plan).

Pension Benefits and Expense

Reported expenses relevant to the Defined Benefit Pension Plan are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience, including the performance of plan assets and actual benefits paid out in future years. Pension costs associated with the Defined Benefit Pension Plan are impacted by the level of contributions made to the plan, earnings on plan assets, the adoption of new mortality tables, and employee demographics, including age, job responsibilities, salary and employment periods. Changes made to the provisions of the Defined Benefit Pension Plan may impact current and future pension costs. Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the corporate bond discount rates, as well as, the adoption of a new mortality table used in determining the projected benefit obligation and pension costs.

Effective January 1, 2016 the Company will apply a disaggregated discount rate approach for determining service cost and interest cost for its defined benefit pension plans and postretirement plans. Refer to Note 1, “Overview and Summary of Significant Accounting Policies” for further information relating to this change in estimate. The impact of the change in approach is a reduction in: (1) expected service costs of $0.4 million for pension plans in 2016 ($0.4 million Defined Benefit Pension Plan and $0.0 million Supplemental Retirement Plan), and (2) expected interest costs of $5.3 million for pension plans in 2016 ($5.3 million Defined Benefit Pension Plan and $0.0 million Supplemental Retirement Plan).

The 2015 net actuarial loss of $11.8 million is comprised of two parts: (1) a $43.8 million pension asset actuarial loss primarily due to lower than expected return on assets; partially offset by (2) a $32.0 million pension liability actuarial gain primarily due to an increase in the discount rate used to value pension liabilities. The unrecognized net loss of $209.3 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 2015, the accumulated net loss was decreased due to a combination of higher discount rates used to value pension liabilities; as well as, the year 2015 amortization of accumulated loss, which was partially offset by a lower than expected return on pension assets. The unrecognized net loss, to the extent that it exceeds 10% of the greater of the benefit obligation or the assets, will be amortized and included as a component of net periodic benefit cost in future years. The amortization period is approximately 9.77 years based on estimated demographic data as of December 31, 2015. The projected benefit obligation of $723.9 million, less the fair value of assets of $647.6 million results in an unfunded status of $(76.3) million at December 31, 2015.



	Pension benefits for years ended December 31,
	2015			2014				2013
	(In Thousands)
Components of net periodic benefit cost:
Service cost	$	8,314		$	7,231			$	9,195
Interest cost	29,638			31,154				28,363
Expected return on plan assets⁽¹⁾	(44,819		)	(41,893		)		(38,287		)
Amortization of prior service cost	4,867			4,853				4,916
Recognized actuarial loss	13,890			9,710				22,735
Recognized settlement loss	206			—			—	—
Total pension cost	12,096			11,055				26,922
Less: amounts capitalized	1,403			1,426				2,881
Amount charged to expense	$	10,693		$	9,629			$	24,041
Rates relevant to each year’s expense calculations:
Discount rate – defined benefit pension plan	4.06		%	4.92		%		3.80		%
Discount rate – supplemental retirement plan	3.82		%	4.64		%		3.41		%
Expected return on defined benefit pension plan assets	6.75		%	7.00		%		7.25		%
Expected return on supplemental retirement plan assets	6.75		%	7.00		%		7.25		%

(1)

For purposes of calculating the expected return on pension plan assets under GAAP, the market-related value of assets (MRVA) is used. GAAP requires that the difference between actual plan asset returns and estimated plan asset returns be amortized into the MRVA equally over a period not to exceed five years. We use a methodology under which we include the difference between actual and estimated asset returns in the MRVA equally over a three year period. The MRVA used in the calculation of expected return on pension plan assets was approximately $643.0 million in 2015, $652.2 million in 2014, and $556.4 million in 2013.

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. 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. For 2015, pension expense was determined using an assumed long-term rate of return on plan assets of 6.75%. As of the December 31, 2015 measurement date, IPL increased the discount rate from 4.06% to 4.42% for the Defined Benefit Pension Plan and increased the discount rate from 3.82% to 4.19% for the Supplemental Retirement Plan. The discount rate assumption affects the pension expense determined for 2016. In addition, IPL kept the expected long-term rate of return on plan assets at 6.75% effective January 1, 2016. The expected long-term rate of return assumption affects the pension expense determined for 2016. The effect on 2016 total pension expense of a 25 basis point increase and decrease in the assumed discount rate is $(1.3) million and $1.4 million, respectively.

In determining the discount rate to use for valuing liabilities we use the market yield curve on high-quality fixed income investments as of December 31, 2015. We project the expected benefit payments under the plan based on participant data and based on certain assumptions concerning mortality, retirement rates, termination rates, etc. The expected benefit payments for each year are discounted back to the measurement date using the appropriate spot rate for each half-year from the yield curve, thereby obtaining a present value of all expected future benefit payments using the yield curve. Finally, an equivalent single discount rate is determined which produces a present value equal to the present value determined using the full yield curve.

Expected amortization

The estimated net loss and prior service cost for the Pension Plans that will be amortized from the regulatory asset into net periodic benefit cost over the 2016 plan year are $13.9 million and $5.2 million, respectively (Defined Benefit Pension Plan of $13.7 million and $5.2 million, respectively; and the Supplemental Retirement Plan of $0.2 million and $0.0 million, respectively).

Pension Plan Assets and Fair Value Measurements

Pension plan assets consist of investments in equities (domestic and international), fixed income securities, and short-term securities. Differences between actual portfolio returns and expected returns may result in increased or decreased pension costs

in future periods. Pension costs are determined as of the plan’s measurement date of December 31, 2015. Pension costs are determined for the following year based on the market value of pension plan assets, expected level of employer contributions, a discount rate used to determine the projected benefit obligation and the expected long-term rate of return on plan assets.

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

Purchases and sales of securities are recorded on a trade-date basis. Interest income is recorded as earned. Dividends are recorded on the ex-dividend date. Net appreciation includes the Plan’s gains and losses on investments bought and sold, as well as held, during the year.

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


•	Other than common/collective trust funds, hedge funds and non U.S. treasury debt securities, all the Plan’s investments have quoted market prices and are categorized as Level 1 in the fair value hierarchy.

•

The Plan’s hedge fund investment is valued at net asset value of units held by the Plan. Unit value is determined primarily by references to the fund’s underlying assets, which are principally investments in another hedge fund which invests in U.S. and international equities. The Plan may redeem its ownership interest in the hedge fund at net asset value, with 60 days’ notice, on quarterly terms.

•

The Plan’s investments in common/collective trust funds are valued at the net asset value of the units of the common/collective trust funds held by the Plan at year-end. The Plan may redeem its units of the common/collective trust funds at net asset value daily. The objective of the common/collective trust funds the Plan is invested in is to track the performance of the Russell 1000 Growth or Russell 1000 Value index. These net asset values have been determined based on the market value of the underlying equity securities held by the common/collective trust funds.


•	The Plan’s investments in corporate bonds, municipal bonds, and 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 Plan’s investments in hedge funds, common/collective trust funds, and non U.S. treasury debt securities have been recorded at fair value and are all categorized as Level 2 investments in the fair value hierarchy.

The primary objective of the Plan is to provide a source of retirement income for its participants and beneficiaries, while the primary financial objective is to improve the unfunded status of the Plan. A secondary financial objective is, where possible, to minimize pension expense volatility. The objective is based on a long-term investment horizon, so that interim fluctuations should be viewed with appropriate perspective. There can be no assurance that these objectives will be met.

In establishing our expected long-term rate of return assumption, we utilize a methodology developed by the plan’s investment consultant who maintains a capital market assumption model that takes into consideration risk, return and correlation assumptions across asset classes. A combination of quantitative analysis of historical data and qualitative judgment is used to capture trends, structural changes and potential scenarios not reflected in historical data.

The result of the analyses is a series of inputs that produce a picture of how the plan consultant believes portfolios are likely to behave through time. Capital market assumptions are intended to reflect the behavior of asset classes observed over several market cycles. Stress assumptions are also examined, since the characteristics of asset classes are constantly changing. A dynamic model is employed to manage the numerous assumptions required to estimate portfolio characteristics under different base currencies, time horizons and inflation expectations.

The Plan consultant develops forward-looking, long-term capital market assumptions for risk, return and correlations for a variety of global asset classes, interest rates and inflation. These assumptions are created using a combination of historical analysis, current market environment assessment and by applying the consultant’s own judgment. The consultant then determines an equilibrium long-term rate of return. We then take into consideration the investment manager/consultant expenses, as well as any other expenses expected to be paid out of the Plan’s trust. Finally, we have the plan’s actuary perform a

tolerance test of the consultant’s equilibrium expected long-term rate of return. We use an expected long-term rate of return compatible with the actuary’s tolerance level.

The following table summarizes the Company’s target pension plan allocation for 2015:



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



	Fair Value Measurements at
	December 31, 2015
	(in thousands)
			Quoted Prices in Active Markets for Identical Assets		Significant Observable Inputs
Asset Category	Total		(Level 1)		(Level 2)		%
Short-term investments	$	176	$	176	$	—	—	%
Mutual funds:
U.S. equities	318,368		318,368		—		49	%
International equities	60,751		60,751		—		10	%
Fixed income	215,325		215,325		—		33	%
Fixed income securities:
U.S. Treasury securities	52,953		52,953		—		8	%
Total	$	647,573	$	647,573	$	—	100	%



	Fair Value Measurements at
	December 31, 2014
	(in thousands)
			Quoted Prices in Active Markets for Identical Assets		Significant Observable Inputs
Asset Category	Total		(Level 1)		(Level 2)		%
Short-term investments	$	2,575	$	2,575	$	—	—	%
Mutual funds:
U.S. equities	325,370		325,370		—		50	%
International equities	56,662		56,662		—		9	%
Fixed income	205,409		205,409		—		31	%
Fixed income securities:
U.S. Treasury securities	66,913		66,913		—		10	%
Hedge funds	310		—		310		—	%
Total	$	657,239	$	656,929	$	310	100	%

Pension Funding

From an ERISA funding perspective, IPL’s funded target liability percentage was estimated to be 112%. In addition to the surplus, IPL must also contribute the normal service cost earned by active participants during the plan year. The funding of normal cost is expected to be about $7.1 million in 2016, which includes $2.3 million for plan expenses. Each year thereafter, if the plan’s underfunding increases to more than the present value of the remaining annual installments, the excess is separately amortized over a seven-year period. IPL elected to fund $15.9 million in January 2016, which satisfies all funding requirements for the calendar year 2016. 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, 2015 and 2014 were $35.7 million and $32.6 million, respectively. Expected benefit payments are expected to be paid out of the Pension Plans as follows:



Year	Pension Benefits
	(In Thousands)
2016	$	38,289
2017	39,909
2018	41,213
2019	42,638
2020	43,920
2021 through 2025	233,449

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 IPALCO’s audited Consolidated Financial Statements.

Environmental Loss Contingencies

New Source Review

coal-fired electric generating units, retire existing generating units, and invest in additional environmental projects. A similar outcome in this case could have a material impact on our business. We would seek recovery of any operating or capital expenditures, but not fines or penalties, related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that we would be successful in this regard. IPL has recorded a contingent liability related to this matter.

11. RELATED PARTY TRANSACTIONS

IPL participates in a property insurance program in which IPL buys insurance from AES Global Insurance Company, a wholly‑owned subsidiary of AES. IPL is not self-insured on property insurance with the exception of a $5 million self-insured retention per occurrence. Except for IPL’s large substations, IPL does not carry insurance on transmission and distribution assets, which are considered to be outside the scope of property insurance. AES and other AES subsidiaries, including IPALCO, also participate in the AES global insurance program. IPL pays premiums for a policy that is written and administered by a third-party insurance company. The premiums paid to this third-party administrator by the participants are deposited into a trust fund owned by AES Global Insurance Company, but controlled by the third-party administrator. The cost to IPL of coverage under this program was approximately $2.7 million, $3.2 million, and $3.1 million in 2015, 2014 and 2013, respectively, and is recorded in “Other operating expenses” on the accompanying Consolidated Statements of Income. As of December 31, 2015 and 2014, we had prepaid approximately $2.2 million and $3.1 million, respectively, which is recorded in “Prepayments and other current assets” on the accompanying Consolidated Balance Sheets.

IPL participates in an agreement with Health and Welfare Benefit Plans LLC, an affiliate of AES, to participate in a group benefits program, including but not limited to, health, dental, vision and life benefits. Health and Welfare Benefit Plans LLC administers the financial aspects of the group insurance program, receives all premium payments from the participating affiliates, and makes all vendor payments. The cost of coverage under this program was approximately $24.5 million, $20.1 million, and $22.3 million in 2015, 2014 and 2013, respectively, and is recorded in “Other operating expenses” on the accompanying Consolidated Statements of Income. As of December 31, 2015 and 2014 we had prepaid approximately $0 million and $0.1 million for coverage under this plan, which is recorded in “Prepayments and other current assets” on the accompanying Consolidated Balance Sheets.

AES files federal and state income tax returns which consolidate IPALCO and its subsidiaries. Under a tax sharing agreement with AES, IPALCO is responsible for the income taxes associated with its own taxable income and records the provision for income taxes using a separate return method. IPALCO had a receivable balance under this agreement of $0.7 million as of December 31, 2015 and 2014, respectively, which is recorded in “Prepayments and other current assets” on the accompanying Consolidated Balance Sheets.

Long-term Compensation Plan

During 2015, 2014 and 2013, many of IPL’s non-union employees received benefits under the AES Long-term Compensation Plan, a deferred compensation program. This type of plan is a common employee retention tool used in our industry. Benefits under this plan are granted in the form of performance units payable in cash and AES restricted stock units and options to purchase shares of AES common stock. All such components vest over a three-year period and the terms of the AES restricted stock unit issued prior to 2011 also include a two year minimum holding period after the awards vest. Awards made in 2011 and for subsequent years will not be subject to a two year holding period. In addition, the performance units payable in cash are subject to certain AES performance criteria. Total deferred compensation expense recorded during 2015, 2014 and 2013 was $0.7 million, $0.7 million and $1.1 million, respectively, and was included in “Other Operating Expenses” on IPALCO’s Consolidated Statements of Income. The value of these benefits is being recognized over the 36 month vesting period and a portion is recorded as miscellaneous deferred credits with the remainder recorded as “Paid in capital” on IPALCO’s Consolidated Balance Sheets in accordance with ASC 718 “Compensation – Stock Compensation.”

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

Service Company

Effective January 1, 2014, the Service Company began providing services including operations, accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the U.S. SBU, including among other companies, IPALCO and IPL. The Service Company allocates the costs for these services based on cost drivers designed to result in fair and equitable allocations. This includes ensuring that the regulated utilities served, including IPL, are not subsidizing costs incurred for the benefit of non-regulated businesses. Total costs incurred by the Service Company on behalf of IPALCO were $23.2 million and $22.0 million during 2015 and 2014, respectively. Total costs incurred by IPALCO on behalf of the Service Company during 2015 and 2014 were $7.5 million and $5.6 million, respectively. IPALCO had a prepaid balance with the Service Company of $1.2 million and $0.4 million as of December 31, 2015 and 2014, respectively.

CDPQ

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

Other

In 2014, IPL engaged a third party vendor as part of its replacement generation construction projects. A member of the AES Board of Directors is also currently a member of the Supervisory Board of this vendor. IPL had billings from this vendor of $232.0 million and $80.3 million during 2015 and 2014, respectively. IPL had a payable balance to this vendor of $34.0 million and $11.9 million as of December 31, 2015 and 2014, respectively.

12. BUSINESS SEGMENT INFORMATION

Operating segments are components of an enterprise that engage in business activities from which it may earn revenues and incur expenses, for which separate financial information is available, and is evaluated regularly by the chief operating decision maker in assessing performance and deciding how to allocate resources. Substantially all of our business consists of the generation, transmission, distribution and sale of electric energy conducted through IPL which is a vertically integrated electric utility. IPALCO’s reportable business segment is its utility segment, with all other non-utility business activities aggregated separately. The non-utility category primarily includes the 2018 IPALCO Notes and the 2020 IPALCO Notes; approximately $1.7 million and $5.9 million of cash and cash equivalents, as of December 31, 2015 and 2014, respectively; long-term investments of $5.2 million and $5.1 million at December 31, 2015 and 2014, 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, 2015 and 2014. The accounting policies of the identified segment are consistent with those policies and procedures described in the summary of significant accounting policies. Intersegment sales, if any, are generally based on prices that reflect the current market conditions.

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



	2015						2014						2013
	Utility		All Other		Total		Utility		All Other		Total		Utility		All Other		Total
Operating revenues	$	1,250	—		$	1,250	$	1,322	—		$	1,322	$	1,256	—		$	1,256
Depreciation and amortization	188		—		188		185		—		185		182		—		182
Income taxes	56		(25	)	32		69		(21	)	48		58		(20	)	38
Net income	102		(42	)	60		110		(32	)	78		97		(33	)	64
Utility plant - net of depreciation	3,451		—		3,451		2,857		—		2,857		2,553		—		2,553
Capital expenditures	686		—		686		382		—		382		242		—		242

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of

Indianapolis Power & Light Company

We have audited the accompanying consolidated balance sheets of Indianapolis Power & Light Company and subsidiary (the Company) as of December 31, 2015 and 2014, and the related consolidated statements of income, common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2015. Our audits also included the financial statement schedule listed in the Index at Item 15a. These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Indianapolis Power & Light Company and subsidiary at December 31, 2015 and 2014, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ ERNST & YOUNG LLP

Indianapolis, Indiana

February 23, 2016



INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY
Consolidated Statements of Income
For the Years Ended December 31, 2015, 2014 and 2013
(In Thousands)
	2015			2014			2013
OPERATING REVENUES	$	1,250,399		$	1,321,674		$	1,255,734

OPERATING EXPENSES:
Fuel	315,600			411,217			376,450
Other operating expenses	224,282			218,932			235,082
Power purchased	145,064			116,648			94,265
Maintenance	131,574			113,248			112,913
Depreciation and amortization	188,267			185,263			182,305
Taxes other than income taxes	43,617			45,218			45,425
Income taxes - net	57,284			70,235			58,548
Total operating expenses	1,105,688			1,160,761			1,104,988
OPERATING INCOME	144,711			160,913			150,746

OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used during construction	15,302			7,381			4,331
Miscellaneous income and (deductions) - net	(2,019		)	(1,203		)	(1,981		)
Income tax benefit applicable to nonoperating income	1,066			953			828
Total other income and (deductions) - net	14,349			7,131			3,178

INTEREST AND OTHER CHARGES:
Interest on long-term debt	65,277			59,104			55,602
Other interest	2,063			1,865			1,794
Allowance for borrowed funds used during construction	(12,809		)	(4,963		)	(2,517		)
Amortization of redemption premium and expense on debt	2,608			2,510			2,493
Total interest and other charges - net	57,139			58,516			57,372
NET INCOME	101,921			109,528			96,552

LESS: PREFERRED DIVIDEND REQUIREMENTS	3,213			3,213			3,213
NET INCOME APPLICABLE TO COMMON STOCK	$	98,708		$	106,315		$	93,339

See notes to consolidated financial statements.



INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY
Consolidated Balance Sheets
(In Thousands)
	December 31, 2015		December 31, 2014
ASSETS
UTILITY PLANT:
Utility plant in service	$	4,992,594	$	4,658,023
Less accumulated depreciation	2,320,955		2,264,606
Utility plant in service - net	2,671,639		2,393,417
Construction work in progress	766,406		447,399
Spare parts inventory	12,336		14,816
Property held for future use	1,002		1,002
Utility plant - net	3,451,383		2,856,634
OTHER ASSETS:
At cost, less accumulated depreciation	947		1,648
CURRENT ASSETS:
Cash and cash equivalents	19,852		20,999
Accounts receivable and unbilled revenue (less allowance for
doubtful accounts of $2,498 and $2,076, respectively)	124,167		139,709
Fuel inventories - at average cost	66,834		47,550
Materials and supplies - at average cost	57,998		60,185
Deferred tax asset - current	—		41,551
Regulatory assets	8,002		93
Prepayments and other current assets	28,578		23,031
Total current assets	305,431		333,118
DEFERRED DEBITS:
Regulatory assets	448,200		419,193
Miscellaneous	20,718		21,284
Total deferred debits	468,918		440,477
TOTAL	$	4,226,679	$	3,631,877
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common shareholder's equity:
Common stock	$	324,537	$	324,537
Paid in capital	385,140		170,306
Retained earnings	415,227		430,266
Total common shareholder's equity	1,124,904		925,109
Cumulative preferred stock	59,784		59,784
Long-term debt (Note 7)	1,369,208		1,152,360
Total capitalization	2,553,896		2,137,253
CURRENT LIABILITIES:
Short-term debt (Note 7)	166,850		50,000
Accounts payable	155,411		110,606
Accrued expenses	19,466		25,084
Accrued real estate and personal property taxes	17,712		19,177
Regulatory liabilities	28,169		27,943
Accrued interest	21,104		20,108
Customer deposits	30,719		28,337
Other current liabilities	22,323		12,581
Total current liabilities	461,754		293,836
DEFERRED CREDITS AND OTHER LONG-TERM LIABILITIES:
Deferred income taxes - net	419,731		421,044
Non-current income tax liability	7,147		7,042
Regulatory liabilities	639,516		610,917
Unamortized investment tax credit	3,910		5,229
Accrued pension and other postretirement benefits	80,734		96,464
Asset retirement obligations	58,986		59,098
Miscellaneous	1,005		994
Total deferred credits and other long-term liabilities	1,211,029		1,200,788
COMMITMENTS AND CONTINGENCIES (Note 10)
TOTAL	$	4,226,679	$	3,631,877

See notes to consolidated financial statements.



INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY
Consolidated Statements of Cash Flows
For the Years Ended December 31, 2015, 2014 and 2013
(In Thousands)
	2015			2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	101,921		$	109,528		$	96,552
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	199,551			186,614			180,917
(Deferral) amortization of regulatory assets	(8,731		)	1,123			3,686
Amortization of debt premium	60			40			30
Deferred income taxes and investment tax credit adjustments - net	33,756			67,831			(10,594		)
Allowance for equity funds used during construction	(14,996		)	(7,136		)	(4,088		)
Gains on sales of assets	—			—			(297		)
Change in certain assets and liabilities:
Accounts receivable	15,542			3,699			(1,900		)
Fuel, materials and supplies	(18,372		)	5,094			(10,337		)
Income taxes receivable or payable	(2,544		)	1,171			3,510
Financial transmission rights	2,086			(1,947		)	(1,869		)
Accounts payable and accrued expenses	(356		)	(23,723		)	16,290
Accrued real estate and personal property taxes	(1,465		)	(47		)	(181		)
Accrued interest	996			1,034			(2,288		)
Pension and other postretirement benefit expenses	(15,730		)	2,785			(180,338		)
Short-term and long-term regulatory assets and liabilities	(22,980		)	(44,252		)	148,169
Prepaids and other current assets	(4,671		)	(170		)	(2,917		)
Other - net	5,895			2,385			7,195
Net cash provided by operating activities	269,962			304,029			241,540
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(672,849		)	(381,626		)	(242,124		)
Project development costs	(8,980		)	(9,657		)	(6,047		)
Proceeds from sales of assets	—			—			225
Grants under the American Recovery and Reinvestment Act of 2009	—			—			923
Asset removal costs	(12,064		)	(6,036		)	(7,553		)
Other	(1,224		)	(56		)	39
Net cash used in investing activities	(695,117		)	(397,375		)	(254,537		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt borrowings	388,850			105,000			150,500
Short-term debt repayments	(272,000		)	(105,000		)	(150,500		)
Long-term borrowings	348,638			128,358			169,728
Retirement of long-term debt	(131,850		)	—			(110,377		)
Dividends on common stock	(103,747		)	(127,400		)	(90,150		)
Dividends on preferred stock	(3,213		)	(3,213		)	(3,213		)
Equity contributions from IPALCO	214,364			106,400			49,091
Payments for financed capital expenditures	(13,215		)	—			—
Other	(3,819		)	(1,920		)	(2,004		)
Net cash provided by financing activities	424,008			102,225			13,075
Net change in cash and cash equivalents	(1,147		)	8,879			78
Cash and cash equivalents at beginning of period	20,999			12,120			12,042
Cash and cash equivalents at end of period	$	19,852		$	20,999		$	12,120

Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized)	$	53,447		$	54,938		$	57,175
Income taxes	$	25,000		$	—		$	64,950
	As of December 31,
	2015			2014			2013
Non-cash investing activities:
Accruals for capital expenditures	$	79,553		$	37,293		$	17,957

See notes to consolidated financial statements.



INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY
Consolidated Statements of Common Shareholder's Equity
(In Thousands)
	Common Stock		Paid in Capital		Retained Earnings			Total
Balance at January 1, 2013	$	324,537	$	13,536	$	448,162		$	786,235
Net income					96,552			96,552
Preferred stock dividends					(3,213		)	(3,213		)
Cash dividends declared on common stock					(90,150		)	(90,150		)
Contributions from IPALCO			49,091					49,091
Other			546					546
Balance at December 31, 2013	$	324,537	$	63,173	$	451,351		$	839,061
Net income					109,528			109,528
Preferred stock dividends					(3,213		)	(3,213		)
Cash dividends declared on common stock					(127,400		)	(127,400		)
Contributions from IPALCO			106,400					106,400
Other			733					733
Balance at December 31, 2014	$	324,537	$	170,306	$	430,266		$	925,109
Net income					101,921			101,921
Preferred stock dividends					(3,213		)	(3,213		)
Cash dividends declared on common stock					(113,747		)	(113,747		)
Contributions from IPALCO			214,364					214,364
Other			470					470
Balance at December 31, 2015	$	324,537	$	385,140	$	415,227		$	1,124,904

See notes to consolidated financial statements.

INDIANAPOLIS POWER & LIGHT COMPANY and SUBSIDIARY

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2015, 2014 and 2013

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, IPALCO’s minority interest holder. AES U.S. Investments is owned by AES (85%) and CDPQ (15%). IPL is engaged primarily in generating, transmitting, distributing and selling of electric energy to approximately 480,000 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, is converting its coal-fired units to natural gas and uses natural gas and fuel oil to power combustion turbines. The third station, Eagle Valley, is coal-fired, and IPL plans to retire its coal-fired units in the second quarter of 2016. The fourth station, Georgetown, is a small peaking station that uses natural gas to power combustion turbines. IPL’s net electric generation capacity for winter is 3,259 MW and net summer capacity is 3,141 MW.

IPL Funding is a special-purpose entity and a wholly-owned subsidiary of IPL and is included in the audited Consolidated Financial Statements of IPL. IPL formed IPL Funding in 1996 to sell, on a revolving basis, up to $50 million of the retail accounts receivable and related collections of IPL to third-party purchasers in exchange for cash (see Accounts Receivable Securitization in Note 7, “Debt”).

Principles of Consolidation

IPL’s consolidated financial statements are prepared in accordance with GAAP and in conjunction with the rules and regulations of the SEC. The consolidated financial statements include the accounts of IPL and its unregulated subsidiary, IPL Funding. All intercompany items have been eliminated in consolidation. Certain costs for shared resources amongst IPL and IPALCO, such as labor and benefits, are allocated to each entity based on allocation methodologies that management believes to be reasonable. We have evaluated subsequent events through the date this report is issued.

Use of Management Estimates

Reclassifications

Certain prior period amounts have been reclassified to conform to the current year presentation.

Regulatory Accounting

Revenues and Accounts Receivable

customer rates based on prior period billings. Given the use of these models, and that customers are billed on a monthly cycle, we believe it is unlikely that materially different results will occur in future periods when revenue is billed. At December 31, 2015 and 2014, customer accounts receivable include unbilled energy revenues of $42.1 million and $48.4 million, respectively, on a base of annual revenue of $1.3 billion in 2015 and 2014. An allowance for potential credit losses is maintained and amounts are written off when normal collection efforts have been exhausted. Our provision for doubtful accounts included in “Other operating expenses” on the accompanying Consolidated Statements of Income was $4.3 million, $4.9 million and $3.8 million for the years ended December 31, 2015, 2014 and 2013, respectively.

In addition, we are one of many transmission system owner members of MISO, a regional transmission organization which maintains functional control over the combined transmission systems of its members and manages one of the largest energy markets in the U.S. In the MISO market, IPL offers its generation and bids its demand into the market on an hourly basis. MISO settles these hourly offers and bids based on locational marginal prices, which is pricing for energy at a given location based on a market clearing price that takes into account physical limitations, generation, and demand throughout the MISO region. MISO evaluates the market participants’ energy offers and demand bids to economically and reliably dispatch the entire MISO system. IPL accounts for these hourly offers and bids, on a net basis, in OPERATING REVENUES when in a net selling position and in OPERATING EXPENSES – Power Purchased when in a net purchasing position.

Contingencies

IPL accrues for loss contingencies when the amount of the loss is probable and estimable. IPL is subject to various environmental regulations, and is involved in certain legal proceedings. If IPL’s actual environmental and/or legal obligations are different from our estimates, the recognition of the actual amounts may have a material impact on our results of operations, financial condition and cash flows; although that has not been the case during the periods covered by this report. As of December 31, 2015 and 2014, total loss contingencies accrued were $5.6 million and $5.2 million, respectively, which were included in “Other Current Liabilities” on the accompanying Consolidated Balance Sheets.

Concentrations of Risk

Allowance For Funds Used During Construction

Utility Plant and Depreciation

$180.0 million for the years ended December 31, 2015, 2014 and 2013, respectively, which includes depreciation expense that has been deferred as a regulatory asset.

Derivatives

We have only limited involvement with derivative financial instruments and do not use them for trading purposes. IPL accounts for its derivatives in accordance with ASC 815 “Derivatives and Hedging.” In addition, IPL has entered into contracts involving the physical delivery of energy and fuel. Because these contracts qualify for the normal purchases and normal sales scope exception in ASC 815, IPL has elected to account for them as accrual contracts, which are not adjusted for changes in fair value.

Fuel, Materials and Supplies

We maintain coal, fuel oil, materials and supplies inventories for use in the production of electricity. These inventories are accounted for at the lower of cost or market, using the average cost.

Impairment of Long-lived Assets

GAAP requires that we measure long-lived assets for impairment when indicators of impairment exist. If an asset is deemed to be impaired, we are required to write down the asset to its fair value with a charge to current earnings. The net book value of our utility plant assets was $3.5 billion and $2.9 billion as of December 31, 2015 and 2014, 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, such as CCT projects; the anticipated demand and relative pricing of retail electricity in our service territory and wholesale electricity in the region; and the cost of fuel.

Income Taxes

Cash and Cash Equivalents

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

Pension and Postretirement Benefits

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 postretirerment 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.



$ in thousands	Expected 2016 Service Cost							Expected 2016 Interest Cost
	Disaggregated rate approach		Aggregate rate approach		Impact of change			Disaggregated rate approach		Aggregate rate approach		Impact of change
Pension	$	7,018	$	7,382	$	(364	)	$	25,634	$	30,916	$	(5,282	)

Repair and Maintenance Costs

Repair and maintenance costs are expensed as incurred.

Per Share Data

IPALCO owns all of the outstanding common stock of IPL. IPL does not report earnings on a per-share basis.

New Accounting Pronouncements

ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606)

ASU No. 2015-02, Consolidation - Amendments to the Consolidation Analysis (Topic 810)

In February 2015, the FASB issued ASU 2015-02, which makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the VIE guidance. The standard amends the evaluation of whether (1) fees paid to a decision-maker or service providers represent a variable interest, (2) a limited partnership or similar entity has the characteristics of a VIE and (3) a reporting entity is the primary beneficiary of a VIE. The standard is effective for annual periods beginning after December 15, 2015 and interim periods therein. Early adoption is permitted. The Company does not expect this standard to have an impact on its consolidated financial statements upon adoption.

ASU No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30)

In April 2015, the FASB issued ASU No. 2015-03, which simplifies the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. The standard is effective for annual reporting periods beginning after December 15, 2015 and interim periods therein, and requires the use of the full retrospective approach. Early adoption is permitted for financial statements that have not been previously issued. As of December 31, 2015, the Company had approximately $13.9 million in deferred financing costs classified in other noncurrent assets that would be reclassified to reduce the related debt liabilities upon adoption of ASU No. 2015-03.

ASU No. 2015-05, Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer's Accounting for Fees Paid in a Cloud Computing Arrangement

ASU No. 2015-11, Simplifying the Measurement of Inventory (Topic 330)

ASU No. 2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements

ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments

ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes

Effective December 31, 2015, the Company prospectively adopted ASU No. 2015-17, which requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. As a result, each jurisdiction will now only have one net noncurrent deferred tax asset or liability. The guidance does not change the existing requirement that only permits offsetting within a jurisdiction; that is, companies will remain prohibited from offsetting deferred tax liabilities from one jurisdiction against deferred tax assets of another jurisdiction. Additionally, the current requirement that deferred tax liabilities and assets of a tax-paying component of an entity be offset and presented as a single amount is not affected by the update. As the Company elected to apply this ASU prospectively, prior periods were not adjusted.