Ipalco Enterprises 10-Q 2018 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2018

or

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

Commission file number1-8644

IPALCO ENTERPRISES, INC.

(Exact name of registrant as specified in its charter)

Indiana	35-1575582
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
One Monument Circle Indianapolis, Indiana	46204
(Address of principal executive offices)	(Zip Code)
Registrant’s telephone number, including area code: 317-261-8261

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¨Noþ

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YesþNo ☐

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

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes¨Noþ

At August 6, 2018, 108,907,318 shares of IPALCO Enterprises, Inc. common stock were outstanding, of which 89,685,177 shares were owned by AES U.S. Investments, Inc. and 19,222,141 shares were owned by CDP Infrastructure Fund GP, a wholly-owned subsidiary of La Caisse de dépôt et placement du Québec.

DOCUMENTS INCORPORATED BY REFERENCE

None.

IPALCO ENTERPRISES, INC.

QUARTERLYREPORT ON FORM 10-Q 

ForQuarterEndedJune 30, 2018

TABLE OF CONTENTS

Item No.		Page No.
	DEFINED TERMS	3
	FORWARD-LOOKING STATEMENTS	4
	PART I - FINANCIAL INFORMATION
1.	Financial Statements
	Unaudited Condensed Consolidated Statements of Operations for the Three and Six Months ended
	June 30, 2018 and 2017	6
	Unaudited Condensed Consolidated Balance Sheets as of June 30, 2018 and December 31, 2017	7
	Unaudited Condensed Consolidated Statements of Cash Flows for the Six Months ended
	June 30, 2018 and 2017	8
	Notes to Unaudited Condensed Consolidated Financial Statements	9
	Note 1 - Overview and Summary of Significant Accounting Policies	9
	Note 2 - Regulatory Matters	12
	Note 3 - Fair Value	13
	Note 4 - Debt	14
	Note 5 - Income Taxes	15
	Note 6 - Benefit Plans	16
	Note 7 - Commitments and Contingencies	17
	Note 8 - Business Segment Information	18
	Note 9 - Revenue	18
2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
3.	Quantitative and Qualitative Disclosure About Market Risk	32
4.	Controls and Procedures	32
	PART II - OTHER INFORMATION
1.	Legal Proceedings	33
1A.	Risk Factors	33
2.	Unregistered Sales of Equity Securities and Use of Proceeds	33
3.	Defaults Upon Senior Securities	33
4.	Mine Safety Disclosures	33
5.	Other Information	33
6.	Exhibits	34
	SIGNATURES	35

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DEFINED TERMS
The following is a list of frequently used abbreviations or acronyms that are found in this Form 10-Q:
2017 Form 10-K	IPALCO’s Annual Report on Form 10-K for the year ended December 31, 2017, as amended
2020 IPALCO Notes	$405 million of 3.45% Senior Secured Notes due July 15, 2020
2024 IPALCO Notes	$405 million of 3.70% Senior Secured Notes due September 1, 2024
AES	The AES Corporation
AES U.S. Investments	AES U.S. Investments, Inc.
ARO	Asset Retirement Obligations
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
CAA	U.S. Clean Air Act
CCGT	Combined Cycle Gas Turbine
CCR	Coal Combustion Residuals
CDPQ	CDP Infrastructure Fund GP, a wholly-owned subsidiary of La Caisse de dépôt et placement du Québec
Credit Agreement	$250 million Revolving Credit Facilities Amended and Restated Credit Agreement, dated as of October 16, 2015
CWA	U.S. Clean Water Act
DOE	U.S. Department of Energy
DSM	Demand Side Management
ECCRA	Environmental Compliance Cost Recovery Adjustment
EPA	U.S. Environmental Protection Agency
FAC	Fuel Adjustment Clause
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Financial Statements	Unaudited Condensed Consolidated Financial Statements of IPALCOin “Item 1. Financial Statements” included in Part I – Financial Information of this Form 10-Q
FTRs	Financial Transmission Rights
GAAP	Generally Accepted Accounting Principles in the United States
GHG	Greenhouse Gas
IDEM	Indiana Department of Environmental Management
IPALCO	IPALCO Enterprises, Inc.
IPL	Indianapolis Power & Light Company
IURC	Indiana Utility Regulatory Commission
kWh	Kilowatt hours
MISO	Midcontinent Independent System Operator, Inc.
MW	Megawatts
MWh	Megawatt hours
NAAQS	National Ambient Air Quality Standards
NOV	Notice of Violation
NOx	Nitrogen Oxide
NPDES	National Pollutant Discharge Elimination System
Pension Plans	Employees’ Retirement Plan of Indianapolis Power & Light Company and Supplemental Retirement Plan of Indianapolis Power & Light Company
PSD	Prevention of Significant Deterioration
RTO	Regional Transmission Organization
SEC	Securities and Exchange Commission
SIP	State Implementation Plan
SO2	Sulfur Dioxide
TCJA	Tax Cuts and Jobs Act
U.S.	United States of America

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

FORWARD‑LOOKING STATEMENTS

This Quarterly Report on Form 10-Q 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 heading “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part I – Financial Information of this Form 10-Q. Forward-looking statements express an expectation or belief and contain a projection, plan or assumption with regard to, among other things, our future revenues, income, expenses or capital structure. Such statements of future events or performance are not guarantees of future performance and involve estimates, assumptions and uncertainties. The words “could,” “may,” “predict,” “anticipate,” “would,” “believe,” “estimate,” “expect,” “forecast,” “project,” “objective,” “intend,” “continue,” “should,” “plan,” and similar expressions, or the negatives thereof, are intended to identify forward-looking statements unless the context requires otherwise.

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

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

• impacts of weather on retail sales and wholesale prices;

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

• weather-related damage to our electrical system;

• fuel, commodity and other input costs;

• performance of our suppliers;

• generating unit availability and capacity;

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

• purchased power costs and availability;

• availability and price of capacity;

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

• federal and state legislation and regulations;

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

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

• changes in financial or regulatory accounting policies;

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

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

• the availability of capital;

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

• level of creditworthiness of counterparties to contracts and transactions;

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

• facility or equipment maintenance, repairs and capital expenditures;

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

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

• local economic conditions;

• cyber attacks and information security breaches;

• catastrophic events such as fires, explosions, 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;

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• the use of derivative contracts; and

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

All of the above factors are difficult to predict, contain uncertainties that may materially affect actual results, and many are beyond our control. See “Item 1A. Risk Factors” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in IPALCO’s 2017 Form 10-K for a more detailed discussion of the foregoing and certain other factors that could cause actual results to differ materially from those reflected in any forward-looking statements. Except as required by the federal securities laws, we undertake no obligation to publicly update or review any forward-looking information, whether as a result of new information, future events or otherwise. If one or more forward-looking statements are updated, no inference should be drawn that additional updates will be made with respect to those or other forward-looking statements.

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PART I– FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS 

IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Unaudited Condensed Consolidated Statements of Operations
(In Thousands)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
UTILITY OPERATING REVENUES	$	359,678		$	321,825		$	714,182		$	658,734
UTILITY OPERATING EXPENSES:
Fuel	93,979			62,725			161,836			133,460
Other operating expenses	66,059			61,939			134,242			126,399
Power purchased	36,119			47,567			92,313			96,588
Maintenance	37,841			36,299			71,339			66,326
Depreciation and amortization	59,286			50,844			114,612			103,388
Taxes other than income taxes	15,483			9,562			29,255			21,836
Income taxes - net	6,986			14,187			16,082			30,140
Total utility operating expenses	315,753			283,123			619,679			578,137
UTILITY OPERATING INCOME	43,925			38,702			94,503			80,597
OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used during construction	2,278			6,523			7,380			12,948
Miscellaneous income and (deductions) - net	(232		)	355			(1,892		)	344
Income tax benefit applicable to nonoperating income	1,055			3,414			3,106			7,184
Total other income and (deductions) - net	3,101			10,292			8,594			20,476
INTEREST AND OTHER CHARGES:
Interest on long-term debt	28,770			29,381			57,505			58,502
Other interest	491			430			949			797
Allowance for borrowed funds used during construction	(6,437		)	(5,579		)	(12,877		)	(11,061		)
Amortization of redemption premiums and expense on debt	956			1,083			1,971			2,160
Total interest and other charges - net	23,780			25,315			47,548			50,398
NET INCOME	23,246			23,679			55,549			50,675
LESS: PREFERRED DIVIDENDS OF SUBSIDIARY	804			804			1,607			1,607
NET INCOME APPLICABLE TO COMMON STOCK	$	22,442		$	22,875		$	53,942		$	49,068
See notes to unaudited condensed consolidated financial statements.

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IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Unaudited Condensed Consolidated Balance Sheets
(In Thousands)
	June 30,			December 31,
	2018			2017
ASSETS
UTILITY PLANT:
Utility plant in service	$	6,132,265		$	5,385,053
Less accumulated depreciation	2,186,684			2,129,617
Utility plant in service - net	3,945,581			3,255,436
Construction work in progress	78,065			711,396
Spare parts inventory	13,734			13,157
Property held for future use	1,002			1,002
Utility plant - net	4,038,382			3,980,991
OTHER ASSETS:
Nonutility property - at cost, less accumulated depreciation	418			502
Intangible assets - net	18,154			16,036
Other long-term assets	4,349			6,185
Other assets - net	22,921			22,723
CURRENT ASSETS:
Cash and cash equivalents	13,544			30,681
Accounts receivable and unbilled revenue (less allowance
for doubtful accounts of $2,953 and $2,830, respectively)	167,833			157,577
Fuel inventories - at average cost	28,703			32,393
Materials and supplies - at average cost	67,236			63,623
Regulatory assets	18,201			35,341
Prepayments and other current assets	29,395			34,094
Total current assets	324,912			353,709
DEFERRED DEBITS:
Regulatory assets	380,529			378,904
Miscellaneous	4,177			4,234
Total deferred debits	384,706			383,138
TOTAL	$	4,770,921		$	4,740,561
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common shareholders' equity:
Paid in capital	$	597,671		$	597,467
Accumulated deficit	(22,516		)	(25,191		)
Total common shareholders' equity	575,155			572,276
Cumulative preferred stock of subsidiary	59,784			59,784
Long-term debt (Note 4)	2,479,319			2,477,538
Total capitalization	3,114,258			3,109,598
CURRENT LIABILITIES:
Short-term and current portion of long-term debt (Note 4)	125,000			148,000
Accounts payable	121,265			125,297
Accrued expenses	18,965			27,926
Accrued real estate and personal property taxes	21,583			18,145
Regulatory liabilities	14,570			2,532
Accrued income taxes	4,059			—
Accrued interest	34,079			34,332
Customer deposits	31,720			31,306
Other current liabilities	10,513			10,392
Total current liabilities	381,754			397,930
DEFERRED CREDITS AND OTHER LONG-TERM LIABILITIES:
Regulatory liabilities	898,410			851,754
Deferred income taxes - net	242,738			245,257
Non-current income tax liability	4,633			4,651
Unamortized investment tax credit	499			954
Accrued pension and other postretirement benefits	17,257			50,070
Asset retirement obligations	110,896			79,535
Miscellaneous	476			812
Total deferred credits and other long-term liabilities	1,274,909			1,233,033
COMMITMENTS AND CONTINGENCIES (Note 7)
TOTAL	$	4,770,921		$	4,740,561
See notes to unaudited condensed consolidated financial statements.

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IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Unaudited Condensed Consolidated Statements of Cash Flows
(In Thousands)
	Six Months Ended
	June 30,
	2018			2017
CASH FLOWS FROM OPERATIONS:
Net income	$	55,549		$	50,675
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	114,603			103,204
Amortization of deferred financing costs and debt premium	1,971			2,160
Deferred income taxes and investment tax credit adjustments - net	(11,140		)	(11,749		)
Allowance for equity funds used during construction	(7,380		)	(12,948		)
Change in certain assets and liabilities:
Accounts receivable	(10,256		)	12,975
Fuel, materials and supplies	77			(2,210		)
Income taxes receivable or payable	18,740			205
Financial transmission rights	(5,421		)	(4,085		)
Accounts payable and accrued expenses	(24,660		)	(16,344		)
Accrued real estate and personal property taxes	3,437			(1,335		)
Accrued interest	(253		)	143
Accrued pension and other postretirement benefits	(32,812		)	(12,982		)
Short-term and long-term regulatory assets and liabilities	71,777			14,527
Prepaids and other current assets	(4,562		)	(711		)
Other - net	1,965			(2,292		)
Net cash provided by operating activities	171,635			119,233
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures - utility	(97,132		)	(118,099		)
Project development costs	(365		)	(753		)
Cost of removal and regulatory recoverable ARO payments	(9,853		)	(5,206		)
Other	(894		)	(1,166		)
Net cash used in investing activities	(108,244		)	(125,224		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt borrowings	75,000			78,500
Short-term debt repayments	(98,000		)	(20,000		)
Dividends on common stock	(51,267		)	(50,100		)
Preferred dividends of subsidiary	(1,607		)	(1,607		)
Deferred financing costs paid	—			(108		)
Payments for financed capital expenditures	(4,463		)	(8,526		)
Other	(191		)	(227		)
Net cash used in financing activities	(80,528		)	(2,068		)
Net change in cash and cash equivalents	(17,137		)	(8,059		)
Cash and cash equivalents at beginning of period	30,681			34,953
Cash and cash equivalents at end of period	$	13,544		$	26,894
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized)	$	45,578		$	47,996
Income taxes	$	5,000		$	34,500
Non-cash investing activities:
Accruals for capital expenditures	$	34,976		$	21,453
See notes to unaudited condensed consolidated financial statements.

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IPALCO ENTERPRISES, INC. and SUBSIDIARIES

Notes toUnauditedCondensed Consolidated Financial Statements

1. OVERVIEW AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

IPALCO is a holding company incorporated under the laws of the state of Indiana. IPALCO is owned by AES U.S. Investments (82.35%) and CDPQ (17.65%). AES U.S. Investments is owned by AES U.S. Holdings, LLC (85%) and CDPQ (15%). IPALCO owns all of the outstanding common stock of IPL. Substantially all of IPALCO’s business consists of generating, transmitting, distributing and selling of electric energy conducted through its principal subsidiary, IPL. IPL was incorporated under the laws of the state of Indiana in 1926. IPL has approximately 490,000 retail customers in the city of Indianapolis and neighboring cities, towns and communities, and adjacent rural areas all within the state of Indiana, with the most distant point being approximately forty miles from Indianapolis. IPL has an exclusive right to provide electric service to those customers. IPL owns and operates four generating stations, all within the state of Indiana. IPL’s largest generating station, Petersburg, is coal-fired. The second largest station, Harding Street, uses natural gas and fuel oil to power combustion turbines. In addition, IPL operates a 20 MW battery energy storage unit at this location, which provides frequency response. The third station, Eagle Valley, is a newly constructed 671 MW CCGT natural gas plant. IPL took operational control and commenced commercial operations of this CCGT plant in April 2018. The fourth station, Georgetown, is a small peaking station that uses natural gas to power combustion turbines. As of June 30, 2018, IPL’s net electric generation capacity for winter is 3,667 MW and net summer capacity is 3,552 MW.

Principles of Consolidation

The accompanying Financial Statements include the accounts of IPALCO, IPL and Mid-America Capital Resources, Inc., a non-regulated wholly-owned subsidiary of IPALCO. All significant intercompany amounts have been eliminated. The accompanying Financial Statements are unaudited; however, they have been prepared in accordance with GAAP for interim financial information and in conjunction with the rules and regulations of the SEC. Accordingly, they do not include all of the disclosures required by GAAP for annual fiscal reporting periods. In the opinion of management, all adjustments of a normal recurring nature necessary for fair presentation have been included. The electric utility business is affected by seasonal weather patterns throughout the year and, therefore, the operating revenues and associated operating expenses are not generated evenly by month during the year. These unaudited Financial Statements have been prepared in accordance with the accounting policies described in IPALCO’s 2017 Form 10-K and should be read in conjunction therewith.

Use of Management Estimates

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

Reclassifications

Certain immaterial amounts from prior periods have been reclassified to conform to the current year presentation.

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ARO

In June 2018, IPL recorded additional ARO liabilities of $32.4 million to reflect revisions to cash flow and timing estimates for accelerated ash pond closure dates and revised estimated closure costs after review of the proposed update to the CCR rule. The following is a reconciliation of the ARO legal liability for the six months ended June 30, 2018 (in thousands):

Balance as of January 1, 2018	$	79,535
Revisions to cash flow and timing estimates	32,393
Liabilities settled	(3,124		)
Accretion expense	2,092
Balance as of June 30, 2018	$	110,896

New Accounting Pronouncements Adopted in 2018

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

New Accounting Standards Adopted
ASU Number and Name	Description	Date of Adoption	Effect on the financial statements upon adoption
2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost	This standard changes the presentation of non-service costs associated with defined benefit plans and updates the guidance so that only the service cost component will be eligible for capitalization. Transition method: retrospective for presentation of non-service cost expense and prospective for the change in capitalization.	January 1, 2018	The adoption of this standard resulted in a $(1.0) million reclassification of non-service pension costs (credits) from Other operating expenses to Miscellaneous income and (deductions) - net for the six months ended June 30, 2017.
2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-10, 2017-13, Revenue from Contracts with Customers (Topic 606)	See discussion of the ASUs below.	January 1, 2018	See impact upon adoption of the standard below.

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

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

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

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New Accounting Pronouncements Issued But Not Yet Effective

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

New Accounting Standards Issued But Not Yet Effective
ASU Number and Name	Description	Date of Adoption	Effect on the financial statements upon adoption
2017-08, Receivables - Nonrefundable Fees and Other Costs (Subtopic 310-20): Premium Amortization on Purchased Callable Debt Securities	This standard shortens the period of amortization for the premium on certain callable debt securities to the earliest call date. Transition method: modified retrospective.	January 1, 2019. Early adoption is permitted.	The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.
2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments	The standard updates the impairment model for financial assets measured at amortized cost. For trade and other receivables, held-to-maturity debt securities, loans and other instruments, entities will be required to use a new forward-looking “expected loss” model that generally will result in the earlier recognition of allowance for losses. For available-for-sale debt securities with unrealized losses, entities will measure credit losses as it is done today, except that the losses will be recognized as an allowance rather than a reduction in the amortized cost of the securities. Transition method: various.	January 1, 2020 Early adoption is permitted only as of January 1, 2019.	The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.
2016-02, 2018-01, Leases (Topic 842)	See discussion of the ASUs below.	January 1, 2019. Early adoption is permitted.	The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.

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

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

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

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

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Under ASC 842, it is expected that fewer contracts will contain a lease. Under the new rules, all operating leases will be recorded as right-of-use assets with an off-setting lease liability.

2. REGULATORY MATTERS

Basic Rates and Charges

IPL filed a petition with the IURC on December 21, 2017, for authority to increase its basic rates and charges to coincide with the completion of the CCGT plant at Eagle Valley in the first half of 2018. IPL’s proposed revenue increase was $124.5 million annually, or 9.1%. On February 16, 2018, IPL filed an update to such petition to reflect the federal income tax law changes, which reduced the revenue increase IPL was seeking to $96.7 million, or 7.1%. On July 19, 2018, IPL filed an uncontested settlement agreement with the IURC which resolves all pending issues. The settlement agreement provides for an increase to annual revenues of $43.9 million, or 3.2%. The settlement agreement provides customers approximately $50 million in benefits, which include tax reform benefits to be flowed to customers over a two-year period via a rate adjustment mechanism. These benefits to date are recorded in long-term regulatory liabilities as ofJune 30, 2018. The settlement hearing is scheduled for August 9, 2018. IPL has requested the IURC enter an order approving the settlement agreement so that IPL may complete the compliance filing process and place new rates into effect December 5, 2018.

DSM

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

Taxes

On January 3, 2018, the IURC opened a generic investigation to review and consider the impacts from the TCJA and how any resulting benefits should be realized by customers. The IURC’s order opening this investigation directed Indiana utilities to apply regulatory accounting treatment, such as the use of regulatory assets and regulatory liabilities, for all estimated impacts resulting from the TCJA. On February 16, 2018, the IURC issued an order establishing two phases of the investigation. The first phase (“Phase I”) directs respondent utilities (including IPL) to make a filing to remove from respondents’ rates and charges for service, the impact of a lower federal income tax rate. The second phase (“Phase II”) was established to address remaining issues from the TCJA, including treatment of deferred taxes and how these benefits will be realized by customers. On March 5, 2018, IPL filed a motion to be dismissed from the generic investigation and to address these matters in its pending general rate case. The IURC approved IPL’s request with regard to Phase II issues, but denied the request for Phase I. On July 6, 2018, IPL entered into a settlement agreement with the parties to the proceeding to resolve the Phase I issues of the TCJA tax expense via a credit through the ECCRA filing of $9.5 million. The TCJA settlement agreement is subject to IURC approval. The hearing on the settlement commenced on August 6, 2018. The settlement agreement in the pending rate case resolves the Phase II and all other issues regarding the TCJA impact on IPL's rates.

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3. FAIR VALUE

Fair Value Hierarchy

As of June 30, 2018 and December 31, 2017, all of IPALCO’s financial assets or liabilities adjusted to fair value on a recurring basis (excluding pension assets – see Note 6, “Benefit Plans”) were considered Level 3, based on the fair value hierarchy. These primarily consisted of FTRs, which are used to offset MISO congestion charges. Because the benefit associated with FTRs is a flow-through to IPL’s customers, IPL records a regulatory liability matching the value of the FTRs. These financial assets and liabilities were not material to the Financial Statements in the periods covered by this report, individually or in the aggregate. See Note 5, “Regulatory Assets and Liabilities” in IPALCO’s 2017 Form 10-K for more information.

Non-Recurring Fair Value Measurements

IPL’s ARO liabilities relate primarily to environmental issues involving asbestos-containing materials, ash ponds, landfills and miscellaneous contaminants associated with its generating plants, transmission system and distribution system. We use the cost approach to determine the fair value of IPL’s ARO liabilities, which is estimated by discounting expected cash outflows to their present value using market based rates at the initial recording of the liabilities. Cash outflows are based on the approximate future disposal costs as determined by market information, historical information or other management estimates. These inputs to the fair value of the ARO liabilities would be considered Level 3 inputs under the fair value hierarchy. In June 2018, IPL recorded additional ARO liabilities of $32.4 million to reflect accelerated ash pond closure dates and revised estimated closure costs after review of the proposed update to the CCR rule. As of June 30, 2018 and December 31, 2017, ARO liabilities were $110.9 million and $79.5 million, respectively. 

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:  

	June 30, 2018				December 31, 2017
	Face Value		Fair Value		Face Value		Fair Value
	(In Thousands)
Fixed-rate	$	2,418,800	$	2,546,237	$	2,418,800	$	2,655,000
Variable-rate	215,000		215,000		238,000		238,000
Total indebtedness	$	2,633,800	$	2,761,237	$	2,656,800	$	2,893,000

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

• unamortized deferred financing costs of $22.7 million and $24.4 million at June 30, 2018 and December 31, 2017, respectively; and

• unamortized discounts of $6.8 million and $6.9 million at June 30, 2018 and December 31, 2017, respectively.

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4. DEBT

Long-Term Debt

The following table presents our long-term debt:

		June 30,			December 31,
Series	Due	2018			2017
		(In Thousands)
IPL first mortgage bonds:
3.875% (1)	August 2021	$	55,000		$	55,000
3.875% (1)	August 2021	40,000			40,000
3.125% (1)	December 2024	40,000			40,000
6.60%	January 2034	100,000			100,000
6.05%	October 2036	158,800			158,800
6.60%	June 2037	165,000			165,000
4.875%	November 2041	140,000			140,000
4.65%	June 2043	170,000			170,000
4.50%	June 2044	130,000			130,000
4.70%	September 2045	260,000			260,000
4.05%	May 2046	350,000			350,000
Unamortized discount – net		(6,288		)	(6,353		)
Deferred financing costs		(15,911		)	(16,168		)
Total IPL first mortgage bonds		1,586,601			1,586,279
IPL unsecured debt:
Variable (2)	December 2020	30,000			30,000
Variable (2)	December 2020	60,000			60,000
Deferred financing costs		(287		)	(344		)
Total IPL unsecured debt		89,713			89,656
Total Long-term Debt – IPL		1,676,314			1,675,935
Long-term Debt – IPALCO:
3.45% Senior Secured Notes	July 2020	405,000			405,000
3.70% Senior Secured Notes	September 2024	405,000			405,000
Unamortized discount – net		(479		)	(534		)
Deferred financing costs		(6,516		)	(7,863		)
Total Long-term Debt – IPALCO		803,005			801,603
Total Consolidated IPALCO Long-term Debt		$	2,479,319		$	2,477,538

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

(2) Unsecured notes issued to the Indiana Finance Authority by IPL to facilitate the loan of proceeds from various tax-exempt notes issued by the Indiana Finance Authority. These notes were issued in two series: $30 million Series 2015A notes and $60 million 2015B notes. The notes have a final maturity date of December 2038, but are subject to a mandatory put in December 2020.

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IPALCO’s Senior Secured Notes

On November 13, 2017, IPALCO filed with the SEC a registration statement on Form S-4 with respect to an exchange of registered notes for its previously unregistered 2024 IPALCO Notes. This registration statement was declared effective on December 5, 2017, and the exchange offer was completed on January 12, 2018.

Line of Credit

As of June 30, 2018 and December 31, 2017, IPL had $125.0 million and $148.0 million in outstanding borrowings on the committed line of credit, respectively.

5. INCOME TAXES

U.S. Tax Reform

On December 22, 2017, the U.S. federal government enacted the TCJA. The TCJA significantly changes U.S. corporate income tax law. Notable items impacting the effective tax rate for the 2018 tax year related to the TCJA include a rate reduction in the corporate tax rate to 21% from 35% and an increase in the estimated flow-through depreciation partially offset by the repeal of the manufacturer’s production deduction.

Effective Tax Rate

IPALCO’s effective combined state and federal income tax rates were 20.9% and 19.4% for the three and six months ended June 30, 2018, respectively, as compared to 32.0% and 31.9% for the three and six months ended June 30, 2017, respectively. The decreases in the effective tax rates versus the comparable periods were primarily due to the impact of the TCJA (as explained above). Partially offsetting the decreases to the effective tax rates were increases caused by the lower allowance for equity funds used during construction in 2018.

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6. BENEFIT PLANS

The following table (in thousands) presents information for the six months ended June 30, 2018, relating to the Pension Plans:

Net unfunded status of plans:
Net unfunded status at December 31, 2017	$	(43,161	)
Net benefit cost components reflected in net unfunded status during first quarter:
Service cost	(2,113		)
Interest cost	(6,305		)
Expected return on assets	10,200
Curtailment(1)	(449		)
Employer contributions	30,000
Net unfunded status at March 31, 2018	$	(11,828	)
Net benefit cost components reflected in net unfunded status during first quarter:
Service cost	(2,113		)
Interest cost	(6,305		)
Expected return on assets	10,200
Net unfunded status at June 30, 2018	$	(10,046	)
Regulatory assets related to pensions(2):
Regulatory assets at December 31, 2017	$	211,125
Amount reclassified through net benefit cost:
Amortization of prior service cost	(959		)
Amortization of net actuarial loss	(2,851		)
Curtailment(1)	(781		)
Regulatory assets at March 31, 2018	$	206,534
Amount reclassified through net benefit cost:
Amortization of prior service cost	(960		)
Amortization of net actuarial loss	(2,850		)
Regulatory assets at June 30, 2018	$	202,724

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

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

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Pension Expense

The following table presents net periodic benefit cost information relating to the Pension Plans combined:

	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
	(In Thousands)						(In Thousands)
Components of net periodic benefit cost:
Service cost	$	2,113		$	1,836		$	4,226		$	3,672
Interest cost	6,305			6,326			12,610			12,653
Expected return on plan assets	(10,200		)	(11,168		)	(20,400		)	(22,335		)
Amortization of prior service cost	960			1,060			1,919			2,120
Amortization of actuarial loss	2,850			3,299			5,701			6,599
Curtailments and settlements(1)	—			—			1,230			146
Net periodic benefit cost	$	2,028		$	1,353		$	5,286		$	2,855

(1) As a result of the announced AES restructuring in the first quarter of 2018, we recognized a plan curtailment of $1.2 million for the six months ended June 30, 2018. The settlement loss of $0.1 million for the six months ended June 30, 2017 was the result of a lump sum distribution paid out of the Supplemental Retirement Plan.

In addition, IPL provides postretirement health care benefits to certain active or retired employees and the spouses of certain active or retired employees. These postretirement health care benefits and the related unfunded obligation of $7.3 million and $7.0 million at June 30, 2018 and December 31, 2017, respectively, were not material to the Financial Statements in the periods covered by this report.

7. COMMITMENTS AND CONTINGENCIES

Legal Loss Contingencies

IPALCO and IPL are involved in litigation arising in the normal course of business. While the results of such litigation cannot be predicted with certainty, management believes that the final outcome will not have a material adverse effect on IPALCO’s results of operations, financial condition and cash flows. Amounts accrued or expensed for legal or environmental contingencies collectively during the periods covered by this report have not been material to the Financial Statements.

Environmental Loss Contingencies

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

New Source Review and Other CAA NOVs

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

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has met with the EPA staff regarding possible resolutions of the NOVs. Settlements and litigated outcomes of similar New Source Review cases have required companies to pay civil penalties, install additional pollution control technology on coal-fired electric generating units, retire existing generating units, and invest in additional environmental projects. A similar outcome in these cases could have a material impact on our business. At this time, we cannot determine whether these NOVs could have a material impact on our business, financial condition or results of operations. We would seek recovery of any operating or capital expenditures, but not fines or penalties, related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that we would be successful in this regard. IPL has recorded a contingent liability related to these New Source Review cases and other CAA NOV matters.

8. 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 nonutility business activities aggregated separately. The “All Other” nonutility category primarily includes the 2020 IPALCO Notes and the 2024 IPALCO Notes; approximately $6.3 million and $18.3 million of cash and cash equivalents as of June 30, 2018 and December 31, 2017, respectively; long-term investments of $4.0 million and $5.1 million at June 30, 2018 and December 31, 2017, respectively; and income taxes and interest related to those items. All other assets represented less than 1% of IPALCO’s total assets as of June 30, 2018 and December 31, 2017. The accounting policies of the identified segment are consistent with those policies and procedures described in the summary of significant accounting policies.

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

	Three Months Ended							Three Months Ended
	June 30, 2018							June 30, 2017
	Utility		All Other			Total		Utility		All Other			Total
Operating revenues	$	359,678	$	—		$	359,678	$	321,825	$	—		$	321,825
Income taxes	$	6,953	$	(1,022	)	$	5,931	$	14,162	$	(3,389	)	$	10,773
Interest and other charges - net	$	16,138	$	7,642		$	23,780	$	16,301	$	9,014		$	25,315
Net income	$	29,952	$	(6,706	)	$	23,246	$	29,381	$	(5,702	)	$	23,679
	Six Months Ended							Six Months Ended
	June 30, 2018							June 30, 2017
	Utility		All Other			Total		Utility		All Other			Total
Operating revenues	$	714,182	$	—		$	714,182	$	658,734	$	—		$	658,734
Income taxes	$	16,009	$	(3,033	)	$	12,976	$	29,886	$	(6,930	)	$	22,956
Interest and other charges - net	$	32,206	$	15,342		$	47,548	$	32,374	$	18,024		$	50,398
Net income	$	68,061	$	(12,512	)	$	55,549	$	61,652	$	(10,977	)	$	50,675
	As of June 30, 2018							As of December 31, 2017
	Utility		All Other			Total		Utility		All Other			Total
Total assets	$	4,760,649	$	10,272		$	4,770,921	$	4,719,547	$	21,014		$	4,740,561

9. REVENUE

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

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

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

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

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

Miscellaneous revenues - Miscellaneous revenues are mainly comprised of MISO transmission revenues. MISO transmission revenues are earned when IPL’s power lines are used in transmission of energy by power producers other than IPL. As IPL owns and operates transmission lines in central Indiana, demand charges collected from network customers by MISO are allocated to the appropriate transmission owners (including IPL) and recognized as transmission revenues.

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

IPL’s revenue from contracts with customers was $357.5 million for the three months ended June 30, 2018 and $709.7 million for the six months ended June 30, 2018, respectively. The following table presents our revenue from contracts with customers and other revenue (in thousands):

	For the Three Months Ended,		For the Six Months Ended,
	June 30, 2018		June 30, 2018
Retail Revenues
Retail revenue from contracts with customers	$	336,782	$	685,282
Other retail revenues (1)	919		1,838
Wholesale Revenues	17,652		19,163
Miscellaneous Revenues
Transmission and other revenue from contracts with customers	3,033		5,275
Other miscellaneous revenues (2)	1,292		2,624
Total Revenues	$	359,678	$	714,182

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

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

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The balances of receivables from contracts with customers are $165.2 million and $155.7 million as of June 30, 2018 and January 1, 2018, respectively. Payment terms for all receivables from contracts with customers are typically within 30 days.

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

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the Financial Statements and the notes thereto included in “Item 1. Financial Statements” included in Part I – Financial Information of this Form 10-Q.

FORWARD-LOOKING INFORMATION

The following discussion may contain forward-looking statements regarding us, our business, prospects and

our results of operations that are subject to certain risks and uncertainties posed by many factors and events that

could cause our actual business, prospects and results of operations to differ materially from those that may be

anticipated by such forward-looking statements. Factors that could cause or contribute to such differences include,

but are not limited to, those described in “Item 1A. Risk Factors” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in IPALCO’s 2017 Form 10-K and subsequent filings with the SEC. Readers are cautioned not to place undue reliance on these forward-looking statements which speak only as of the date of this report. We undertake no obligation to revise any forward-looking statements in order to reflect events or circumstances that may subsequently arise. If we do update one or more forward-looking statements, no inference should be drawn that we will make additional updates with respect to those or other forward-looking statements. Readers are urged to carefully review and consider the various disclosures made by us in this report and in our other reports filed with the SEC that advise of the risks and factors that may affect our business.

OVERVIEW OF OUR BUSINESS

IPALCO is a holding company incorporated under the laws of the state of Indiana. Our principal subsidiary is IPL, a regulated electric utility operating in the state of Indiana. Substantially all of our business consists of the generation, transmission, distribution and sale of electric energy conducted through IPL. Our business segments are “utility” and “all other.” For additional information regarding our business, see Item 1. Business” of our 2017 Form 10-K.

EXECUTIVE SUMMARY

Compared with the second quarter of the prior year, the results for the three months ended June 30, 2018 reflect lower net income of $0.4 million, or 2%, primarily due to factors including, but not limited to:

• higher tax expense for real estate and personal property taxes;

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

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

These were partially offset by:

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

Compared with the first half of the prior year, the results for the six months ended June 30, 2018 reflect higher net income of $4.9 million, or 10%, primarily due to factors including, but not limited to:

• increased retail margins due to favorable weather in our service territory during the first half of 2018 versus the comparable period; and

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

These were partially offset by:

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

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

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RESULTS OF OPERATIONS

The electric utility business is affected by seasonal weather patterns throughout the year and, therefore, operating revenues and associated expenses are not generated evenly by month during the year. 

Comparison of three months ended June 30, 2018 and three months ended June 30, 2017

Utility Operating Revenues

Utility operating revenues during the three months ended June 30, 2018 increased by $37.9 million compared to the same period in 2017, which resulted from the following changes (dollars in thousands):

	Three Months Ended
	June 30,							Percentage
	2018		2017			Change		Change
Utility operating revenues:
Retail revenues	$	337,701	$	316,923	(1)	$	20,778	6.6%
Wholesale revenues	17,652		1,802			15,850		879.6%
Miscellaneous revenues	4,325		3,100		(1)	1,225		39.5%
Total utility operating revenues	$	359,678	$	321,825		$	37,853	11.8%
(1) Prior period amounts have been reclassified to conform to the current year presentation
Heating degree days:
Actual	542		355			187		52.7%
30-year average	524		503
Cooling degree days:
Actual	575		314			261		83.1%
30-year average	309		332

The increase in retail revenues of $20.8 million was primarily due to an 8% increase in the volume of kWh sold ($16.9 million) and a net increase in the weighted average price per kWh sold ($3.9 million). The $16.9 million increase in the volume of kWh sold was primarily due to favorable weather in our service territory during the second quarter of 2018 versus the comparable period (as demonstrated by the 83% increase in cooling degree days and 53% increase in heating degree days, as shown above). The $3.9 million increase in the weighted average price of retail kWh sold was primarily due to: (i) a $12.6 million increase in environmental rate adjustment mechanism revenues and (ii) an $8.2 million increase in fuel revenues; offset by (iii) a $4.4 million decrease due to the deferral of revenue as a regulatory liability to adjust for the impacts of the TCJA on customer rates and charges for service in 2018, (iv) a $2.1 million decrease in DSM program rate adjustment mechanism revenues, (v) a $0.5 million decrease in billings for the MISO, Capacity and Off System Sales riders and (vi) unfavorable block rate and other retail rate variances of $9.9 million. The unfavorable block rate variances are primarily attributable to our declining block rate structure, which generally provides for residential and commercial customers to be charged a lower per kWh rate at higher consumption levels. Therefore, as volumes increase, the weighted average price per kWh decreases.

The increase in wholesale revenues of $15.9 million was primarily due to an increase in the quantity of kWh sold primarily due to increased generation capacity and unit availability as a result of the commencement of commercial operations of the newly constructed CCGT plant at Eagle Valley in April 2018. We sold 545.5 million kWh in the wholesale market during the second quarter of 2018 compared to only 55.6 million kWh during the second quarter of 2017. Our ability to be dispatched in the MISO market is primarily driven by the locational marginal price of electricity and variable generation costs. The amount of electricity available for wholesale revenues is impacted by

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our retail load requirements, generation capacity and unit availability. Currently, 50% of IPL’s wholesale margins above and below an established annual benchmark of $6.3 million are shared with our retail customers through a rate rider.

Utility Operating Expenses

The following table illustrates our changes in operating expenses during the three months ended June 30, 2018 compared to the same period in 2017 (dollars in thousands):

	Three Months Ended
	June 30,
	2018		2017		$ Change			% Change
Utility operating expenses:
Fuel	$	93,979	$	62,725	$	31,254		49.8	%
Other operating expenses	66,059		61,939		4,120			6.7	%
Power purchased	36,119		47,567		(11,448		)	(24.1	)%
Maintenance	37,841		36,299		1,542			4.2	%
Depreciation and amortization	59,286		50,844		8,442			16.6	%
Taxes other than income taxes	15,483		9,562		5,921			61.9	%
Income taxes - net	6,986		14,187		(7,201		)	(50.8	)%
Total utility operating expenses	$	315,753	$	283,123	$	32,630		11.5	%

The $31.3 million increase in fuel expense was primarily due to (i) a $38.0 million increase in the quantity of fuel consumed versus the comparable period, primarily due to increased generation capacity and unit availability as a result of the commencement of commercial operations of the newly constructed CCGT plant at Eagle Valley in April 2018 as well as the increase in retail demand versus the comparable period and (ii) a $4.1 million increase in deferred fuel costs; partially offset by (iii) an $11.3 million decrease due to the lower price of natural gas we consumed versus the comparable period. We are generally permitted to recover underestimated fuel and purchased power costs to serve our retail customers in future rates through quarterly FAC proceedings. These variances are deferred when incurred and amortized into expense in the same period that our rates are adjusted to reflect these variances.

The $4.1 million increase in other operating expenses was primarily due to (i) a $4.8 million increase in deferred environmental project expenses due to increases recorded in expenses in the current period to offset over-collection of ECCRA revenues, and new expenses recognized in the current period as two large NPDES projects went into service in September of 2017 and are now included in billing rates through IPL's environmental rider, (ii) higher MISO non-purchased power costs (primarily transmission related expenses) of $3.2 million; partially offset by (iv) lower salaries expense of $4.4 million.

The $11.4 million decrease in purchased power costs was primarily due to (i) a 57% decrease in the volume of power purchased during the period ($23.1 million); partially offset by (ii) a $7.3 million increase in the market price of purchased power and (iii) a $3.9 million increase in deferred purchased power costs. The volume of power purchased each period is primarily influenced by retail demand, generating unit capacity and outages, and the fact that at times it is less expensive to buy power in the market than to produce it. The primary driver for the $23.1 million volume decrease in the second quarter of 2018 is primarily attributable to the CCGT plant at Eagle Valley coming on line in April 2018 (as discussed above). 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 which power is purchased. We are generally permitted to defer and recover underestimated purchased power costs to serve our retail customers in future rates through quarterly FAC proceedings. These variances are deferred when incurred and amortized into fuel expense in the same period that our rates are adjusted to reflect these variances.

The $1.5 million increase in maintenance expenses was primarily due to the timing and duration of outages (including a 63-day scheduled outage at our 415 MW Petersburg Generating Station Unit 2 that occurred during the first half of 2018).

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The $8.4 million increase in depreciation and amortization costs was primarily related to the impact of additional assets placed in service.

The $5.9 million increase in taxes other than income taxes was primarily due to higher tax expense for real estate & personal property taxes of $5.4 million mostly as a result of (i) an increase in the assessed property tax value, (ii) prior period true-up adjustments and (iii) an increase in property tax rates.

The $7.2 million decrease in income taxes - net was primarily due to the decrease in the federal corporate income tax rate to 21% from 35% as a result of the passage of the TCJA, which was signed into law in December 2017.

Other Income and Deductions

Other income and deductions decreased $7.2 million, from income of $10.3 million for the three months ended June 30, 2017, to income of $3.1 million for the same period in 2018, reflecting a 70% decrease. This decrease was primarily due to (i) a $4.2 million decrease in the allowance for equity funds used during construction as a result of decreased construction activity and (ii) a decrease in the income tax benefit of $2.4 million, which was primarily due to a lower tax rate due to the passage of the TCJA (as discussed above) as well as the change in pretax nonoperating income during the comparable periods.

Interest and Other Charges

Interest and other charges decreased $1.5 million, or 6%, for the three months ended June 30, 2018, primarily due to immaterial drivers.

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Comparison of six months ended June 30, 2018 and six months ended June 30, 2017

Utility Operating Revenues

Utility operating revenues during the six months ended June 30, 2018 increased by $55.4 million compared to the same period in 2017, which resulted from the following changes (dollars in thousands):

	Six Months Ended
	June 30,							Percentage
	2018		2017			Change		Change
Utility operating revenues:
Retail revenues	$	687,120	$	647,827	(1)	$	39,293	6.1%
Wholesale revenues	19,163		4,374			14,789		338.1%
Miscellaneous revenues	7,899		6,533		(1)	1,366		20.9%
Total utility operating revenues	$	714,182	$	658,734		$	55,448	8.4%
(1) Prior period amounts have been reclassified to conform to the current year presentation
Heating degree days:
Actual	3,337		2,559			778		30.4%
30-year average	3,297		3,283
Cooling degree days:
Actual	580		316			264		83.5%
30-year average	309		335

The increase in retail revenues of $39.3 million was primarily due to an 8% increase in the volume of kWh sold ($34.5 million) and a net increase in the weighted average price per kWh sold ($4.8 million). The $34.5 million increase in the volume of kWh sold was primarily due to favorable weather in our service territory during the first half of 2018 versus the comparable period (as demonstrated by the 30% increase in heating degree days and 84% increase in cooling degree days, as shown above). The $4.8 million increase in the weighted average price of retail kWh sold was primarily due to: (i) an $18.2 million increase in environmental rate adjustment mechanism revenues, (ii) a $13.7 million increase in fuel revenues, (iii) a $1.9 million increase in billings for the MISO, Capacity and Off System Sales riders and (iv) a $1.5 million increase in DSM program rate adjustment mechanism revenues; partially offset by (v) an $11.0 million decrease due to the deferral of revenue as a regulatory liability to adjust for the impacts of the TCJA on customer rates and charges for service in 2018 and (vi) unfavorable block rate and other retail rate variances of $19.5 million. The unfavorable block rate variances are primarily attributable to our declining block rate structure, which generally provides for residential and commercial customers to be charged a lower per kWh rate at higher consumption levels. Therefore, as volumes increase, the weighted average price per kWh decreases.

The increase in wholesale revenues of $14.8 million was primarily due to a 320% increase in the quantity of kWh sold primarily due to increased generation capacity and unit availability as a result of the commencement of commercial operations of the newly constructed CCGT plant at Eagle Valley in April 2018. We sold 592.8 million kWh in the wholesale market during the first half of 2018 compared to only 141.2 million kWh during the first half of 2017. Our ability to be dispatched in the MISO market is primarily driven by the locational marginal price of electricity and variable generation costs. The amount of electricity available for wholesale sales is impacted by our retail load requirements, generation capacity and unit availability. Currently, 50% of IPL’s wholesale margins above and below an established annual benchmark of $6.3 million are shared with our retail customers through a rate rider.

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Utility Operating Expenses

The following table illustrates our changes in operating expenses during the six months ended June 30, 2018 compared to the same period in 2017 (dollars in thousands):

	Six Months Ended
	June 30,
	2018		2017		$ Change			% Change
Utility operating expenses:
Fuel	$	161,836	$	133,460	$	28,376		21.3	%
Other operating expenses	134,242		126,399		7,843			6.2	%
Power purchased	92,313		96,588		(4,275		)	(4.4	)%
Maintenance	71,339		66,326		5,013			7.6	%
Depreciation and amortization	114,612		103,388		11,224			10.9	%
Taxes other than income taxes	29,255		21,836		7,419			34.0	%
Income taxes - net	16,082		30,140		(14,058		)	(46.6	)%
Total utility operating expenses	$	619,679	$	578,137	$	41,542		7.2	%

The $28.4 million increase in fuel costs was primarily due to a $42.5 million increase in the quantity of fuel consumed versus the comparable period, primarily due to increased generation capacity and unit availability as a result of the commencement of commercial operations of the newly constructed CCGT plant at Eagle Valley in April 2018 as well as the increase in retail demand versus the comparable period; partially offset by (ii) a $9.0 million decrease due to the lower price of natural gas we consumed versus the comparable period and (iii) a $5.7 million decrease in deferred fuel costs. We are generally permitted to recover underestimated fuel and purchased power costs to serve our retail customers in future rates through quarterly FAC proceedings. These variances are deferred when incurred and amortized into expense in the same period that our rates are adjusted to reflect these variances.

The $7.8 million increase in other operating expenses was primarily due to (i) higher MISO non-purchased power costs (primarily transmission related expenses) of $4.6 million, (ii) a $4.6 million increase in deferred environmental project expenses due to increases recorded in expenses in the current period to offset over-collection of ECCRA revenues, and new expenses recognized in the current period as two large NPDES projects went into service in September of 2017 and are now included in billing rates through IPL's environmental rider and (iii) higher DSM program costs of $2.4 million primarily as a result of timing differences in spending patterns (these program costs are recoverable through customer rates and are offset by an increase in DSM revenues); partially offset by (iv) lower salaries expense of $3.6 million.

The $4.3 million decrease in purchased power costs was primarily due to (i) a 17% decrease in the volume of power purchased during the period ($13.5 million); partially offset by (ii) a $7.2 million increase in the market price of purchased power and (iii) a 1.0 million increase in deferred purchased power costs. The volume of power purchased each period is primarily influenced by retail demand, generating unit capacity and outages, and the fact that at times it is less expensive to buy power in the market than to produce it. The primary driver for the $13.5 million volume decrease in the first half of 2018 is primarily attributable to the CCGT plant at Eagle Valley coming on line in April 2018 (as discussed above). 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 during which power is purchased. We are generally permitted to defer and recover underestimated purchased power costs to serve our retail customers in future rates through quarterly FAC proceedings. These variances are deferred when incurred and amortized into fuel expense in the same period that our rates are adjusted to reflect these variances.

The $5.0 million increase in maintenance expenses was primarily due to the timing and duration of outages (including a 63-day scheduled outage at our 415 MW Petersburg Generating Station Unit 2 that occurred during the first half of 2018).

The $11.2 million increase in depreciation and amortization costs was primarily related to the impact of additional assets placed in service.

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The $7.4 million increase in taxes other than income taxes was primarily due to higher tax expense for real estate & personal property taxes of $6.4 million mostly as a result of (i) an increase in the assessed property tax value, (ii) prior period true-up adjustments and (iii) an increase in property tax rates.

The $14.1 million decrease in income taxes - net was primarily due to the decrease in the federal corporate income tax rate to 21% from 35% as a result of the passage of the TCJA, which was signed into law in December 2017.

Other Income and Deductions

Other income and deductions decreased $11.9 million, from income of $20.5 million for the six months ended June 30, 2017, to income of $8.6 million for the same period in 2018, reflecting a 58% decrease. This decrease was primarily due to (i) a $5.6 million decrease in the allowance for equity funds used during construction as a result of decreased construction activity, (ii) a decrease in the income tax benefit of $4.1 million, which was primarily due to a lower tax rate due to the passage of the TCJA (as discussed above) as well as the change in pretax nonoperating income during the comparable period and (iii) a $1.2 million one-time pension curtailment charge recorded in March 2018.

Interest and Other Charges

Interest and other charges decreased $2.9 million, or 6%, for the six months ended June 30, 2018, primarily due to (i) a $1.8 million increase in the allowance for borrowed funds used during construction primarily due to an increase in carrying charges for the CCGT plant at Eagle Valley that was placed into service in April 2018 and (ii) lower interest on long-term debt of $1.0 million.

KEY TRENDS AND UNCERTAINTIES

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

• rate case outcomes;

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

• timely recovery of capital expenditures.

If favorable outcomes related to these factors do not occur, or if the challenges described below and elsewhere in this section impact us more significantly than we currently anticipate, or if commodities move unfavorably, then these adverse factors, or other adverse factors unknown to us, may impact our operating margin, net income and cash flows. We continue to monitor our operations and address challenges as they arise. For a discussion of the risks related to our business, see “Item 1. Business” and “Item 1A. Risk Factors” as described in IPALCO’s 2017 Form 10-K.

Regulatory and Environmental

Please see Note 2, “Regulatory Matters” to the Financial Statements for an update on regulatory matters. We also are subject to numerous environmental laws and regulations in the jurisdictions in which we operate. We face certain risks and uncertainties related to these environmental laws and regulations, including existing and potential GHG legislation or regulations, and actual or potential laws and regulations pertaining to water discharges, waste management (including disposal or beneficial reuse of CCR) and certain air emissions, such as SO₂, NO_x, particulate matter and mercury. Such risks and uncertainties could result in increased capital expenditures or other compliance costs which could have a material adverse effect on our consolidated results of operations. Please see Note 7, “Commitments and Contingencies” to the Financial Statements for a description of certain environmental matters. In addition, the following discussion of the impact of environmental laws and regulations on the Company updates the discussion provided in “Item 1. Business - Regulatory Matters” and “Item 1. Business - Environmental Matters” in IPALCO’s 2017 Form 10-K.

The DOE issued a Notice of Proposed Rule Making on September 29, 2017, which directed the FERC to exercise its authority to set just and reasonable rates that recognize the “resiliency” value provided by generation plants with certain characteristics, including having 90-days or more of on-site fuel and operating in markets where they do not receive rate base treatment through state ratemaking. On January 8, 2018, the FERC terminated this proceeding

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and established a new one soliciting comments from the RTOs regarding resiliency. RTO responses were submitted on March 9, 2018, but the timing and outcome of this proceeding, including effects on wholesale energy markets, remain uncertain.

Waste Management and CCR

The EPA's final CCR rule became effective on October 19, 2015. Generally, the rule regulates CCR as nonhazardous solid waste and establishes national minimum criteria for existing and new CCR landfills and existing and new CCR surface impoundments (ash ponds), including location restrictions, design and operating criteria, groundwater monitoring, corrective action and closure requirements and post-closure care. The EPA has indicated that they will implement a phased approach to amending the CCR rule with Phase One being finalized no later than June 2019, and Phase Two no later than December 2019. On July 30, 2018, the EPA published final CCR Rule Amendments (Phase One, Part One) in the Federal Register. As a result of EPA interpretation published during this rulemaking, IPL Petersburg is expected to incur additional operational costs and pond closure costs. The CCR rule, current or proposed amendments to the CCR rule, the results of groundwater monitoring data or the outcome of CCR-related litigation could have a material impact on our business, financial condition or results of operations.

The existing ash ponds at Petersburg did not meet certain structural stability requirements set forth in the CCR rule. As such, IPL was ultimately required to cease use of the ash ponds by April 11, 2018. IDEM has granted IPL a variance extending that deadline to November 1, 2018 for a portion of the ash pond system.

See Note 3, “Fair Value - Non-recurring Fair Value Measurements” to the Financial Statements for additional details on the increase in IPL's ARO liabilities related to ash ponds during the six months ended June 30, 2018.

NAAQS

On March 12, 2018, the state of New York submitted a petition to the EPA pursuant to Section 126 of the CAA requesting new limitations on NOx emissions from dozens of upwind generating stations, including IPL Petersburg, Harding Street, and Eagle Valley on the basis that they are contributing significantly to New York’s ability to meet the 2008 ozone NAAQS. On May 11, 2018, EPA published an extension of their deadline to respond from May 13, 2018 to November 9, 2018. If this petition is granted, our units could be subject to additional requirements. We would seek recovery of any resulting capital expenditures; however, there is no guarantee we would be successful in this regard.

Additionally, on November 16, 2016, Maryland submitted a petition to the EPA pursuant to Section 126 of the CAA requesting that new limitations on NOx emissions from 36 upwind generating units, including IPL Petersburg Generating Station Units 2 and 3, on the basis that they are contributing significantly to Maryland’s ability to meet the 2008 ozone NAAQS. On June 8, 2018, the EPA published a proposal to deny Maryland’s petition. A final action on the petition is due September 15, 2018, and if denied, Maryland has indicated that it may seek further legal action. If this petition is ultimately granted, our Petersburg Generating Station Unit 2 and 3 could be subject to additional requirements. We would seek recovery of any resulting capital expenditures; however, there is no guarantee we would be successful in this regard.

CAPITAL RESOURCES AND LIQUIDITY

Overview

As of June 30, 2018, we had unrestricted cash and cash equivalents of $13.5 million and available borrowing capacity of $125.0 million under our $250 million unsecured revolving credit facility after accounting for outstanding borrowings and existing letters of credit. All of IPL’s long-term borrowings must first be approved by the IURC and the aggregate amount of IPL’s short-term indebtedness must be approved by the FERC. We have approval from FERC to borrow up to $500 million of short-term indebtedness outstanding at any time through July 26, 2020. In December 2015, we received an order from the IURC granting us authority through December 31, 2018 to, among other things, issue up to $650 million in aggregate principal amount of long-term debt and refinance up to $196.5 million in existing indebtedness. As of June 30, 2018, we have $106.5 million of total debt issuance authority remaining under this order. This order also grants us authority to have up to $500 million of long-term credit agreements and liquidity facilities outstanding at any one time, of which $250 million remains available under the order as of June 30, 2018. As an alternative to the sale of all or a portion of $65 million in principal of the long-term debt mentioned above, we have the authority to issue up to $65 million of new preferred stock, all of which authority

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remains available under the order as of June 30, 2018. We also have restrictions on the amount of new debt that may be issued due to contractual obligations of AES and by financial covenant restrictions under our existing debt obligations. We do not believe such restrictions will be a limiting factor in our ability to issue debt in the ordinary course of prudent business operations.

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

Cash Flows

The following table provides a summary of our cash flows (in thousands):

	Six months ended June 30,
	2018			2017			$ Change
Net cash provided by operating activities	$	171,635		$	119,233		$	52,402
Net cash used in investing activities	(108,244		)	(125,224		)	16,980
Net cash used in financing activities	(80,528		)	(2,068		)	(78,460		)
Net change in cash and cash equivalents	(17,137		)	(8,059		)	(9,078		)
Cash and cash equivalents at beginning of period	30,681			34,953			(4,272		)
Cash and cash equivalents at end of period	$	13,544		$	26,894		$	(13,350	)

Operating Activities

The following table summarizes the key components of our consolidated operating cash flows (in thousands):

	Six months ended June 30,
	2018			2017			$ Change
Net income	$	55,549		$	50,675		$	4,874
Depreciation and amortization	114,603			103,204			11,399
Amortization of deferred financing costs and debt premium	1,971			2,160			(189		)
Deferred income taxes and investment tax credit adjustments - net	(11,140		)	(11,749		)	609
Allowance for equity funds used during construction	(7,380		)	(12,948		)	5,568
Net income, adjusted for non-cash items	153,603			131,342			22,261
Net change in operating assets and liabilities	18,032			(12,109		)	30,141
Net cash provided by operating activities	$	171,635		$	119,233		$	52,402

The net change in operating assets and liabilities for the six months ended June 30, 2018 compared to the six months ended June 30, 2017 was driven by changes in the following (in thousands):

Increase from short-term and long-term regulatory assets and liabilities primarily due to proceeds IPL received pursuant to a settlement agreement and an increase to regulatory liabilities to record the impacts of the TCJA on customer rates	$	57,250
Decrease from accounts receivable due to lower collections	(23,231		)
Decrease from accrued pension and other postretirement benefits due to higher employer contributions	(19,830		)
Increase from income taxes receivable or payable due to lower tax sharing payments	18,535
Other - net	(2,583		)
Net change in operating assets and liabilities	$	30,141

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Investing Activities

During the six months ended June 30, 2018, net cash used in investing activities was primarily related to capital expenditures of $97.1 million. The primary drivers of these expenditures include $52.0 million on maintenance projects, $16.8 million on transmission and distribution projects, $8.8 million on NPDES compliance, $7.8 million on NAAQS compliance, and $7.7 million on the Eagle Valley CCGT plant.

During the six months ended June 30, 2017, net cash used in investing activities was primarily related to capital expenditures of $118.1 million. The primary drivers of these expenditures include $57.0 million on maintenance projects, $19.7 million on transmission and distribution projects, $17.6 million on NPDES compliance, $14.1 million on the Eagle Valley CCGT plant and $8.6 million on the Petersburg bottom ash project.

Financing Activities

During the six months ended June 30, 2018, net cash used in financing activities primarily relates to dividends paid to shareholders of $51.3 million, net repayments on debt of $23.0 million and payments for financed capital expenditures of $4.5 million.

During the six months ended June 30, 2017, net cash used in financing activities primarily relates to dividends paid to shareholders of $50.1 million and payments for financed capital expenditures of $8.5 million; offset by net borrowings of $58.5 million.

Capital Requirements

Capital Expenditures

Our capital expenditure program, including development and permitting costs, for the three-year period from 2018 through 2020 is currently estimated to cost approximately $614 million (excluding environmental compliance and replacement generation costs), and includes estimates as follows (amounts in millions):

	For the three-year period
	from 2018 through 2020
Additions, improvements and extensions	$	330	(1)
Power plant-related projects	194
Other miscellaneous equipment	90
Total estimated costs of capital expenditure program	$	614
(1) Additions, improvements and extensions to transmission and distribution lines, substations, power factor and voltage regulating equipment, distribution transformers and street lighting facilities

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Additionally, IPL plans to spend the following amounts on replacement generation and environmental compliance costs:

	Total Estimated Costs		Total Costs Expended		Remaining Costs
	of Project		Through June 30, 2018		of Project
Replacement generation (1)	$	642	$	640	$	2
NPDES (2)	224		222		2
CCR and NAAQS SO2 (3)	76		65		11
Cooling water intake regulations (4)	$	68	$	—	$	68
(1) IPL plans to spend a total of $642 million 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 expended regulations. With $640 million spent through June 30, 2018, the remaining $2 million is expected to be expended during the final six months of 2018.
(2) Includes costs for compliance with the NPDES permit program under the CWA. The costs for NPDES at our Petersburg station for 2018 are expected to be $13 million. The remaining costs are projected to be expended in 2018.
(3) IPL has projects underway related to environmental compliance for CCR and NAAQS SO2. The costs for the projects in the 2018 through 2020 forecast are expected to be $23 million.
(4) Includes spending for studies related to cooling water intake requirements in sections 316(a) and 316(b) of the CWA, NAAQS Ozone and Office of Surface Mining for the remainder of 2018 through 2020.

For additional details on each of these projects, see “Item 1. Business - Environmental Matters" in IPALCO’s 2017 Form 10-K.

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 $250 million unsecured revolving credit facility and other unsecured notes (as well as the amount of certain other fees in the Credit Agreement) are dependent upon the credit ratings of IPL. Downgrades in the credit ratings of AES could result in IPL’s and/or IPALCO’s credit ratings being downgraded. Any reduction in our debt or credit ratings may adversely affect the trading price of our outstanding debt securities.

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

Debt ratings	IPALCO	IPL	Outlook	Effective or Affirmed
Fitch Ratings	BB+ (a)	BBB+ (b)	Positive	December 2017
Moody’s Investors Service	Baa3 (a)	A2 (b)	Stable	October 2016
S&P Global Ratings	BBB- (a)	A- (b)	Stable	March 2018
Credit ratings	IPALCO	IPL	Outlook	Effective or Affirmed
Fitch Ratings	BB+	BBB-	Positive	December 2017
Moody’s Investors Service	—	Baa1	Stable	October 2016
S&P Global Ratings	BBB	BBB	Stable	March 2018

(a) Ratings relate to IPALCO’s Senior Secured Notes

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

We cannot predict whether our current debt and credit ratings or the debt and 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 Distributions

All of IPALCO’s outstanding common stock is held by AES U.S. Investments and CDPQ. During the first six months of 2018 and 2017, IPALCO paid $51.3 million and $50.1 million, respectively, in dividends to its shareholders.

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Future distributions to our shareholders will be determined at the discretion of our Board of Directors and will depend primarily on dividends received from IPL. Dividends from IPL are affected by IPL’s actual results of operations, financial condition, cash flows, capital requirements, regulatory considerations, and such other factors as IPL’s Board of Directors deems relevant.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK 

There have been no material changes to our quantitative and qualitative disclosure about market risk as previously disclosed in the 2017 Form 10-K.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures — The Company, under the supervision and with the participation of its management, including the Company’s Chief Executive Officer (“CEO”) and Chief Financial Officer “CFO”), evaluated the effectiveness of its “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) under the Securities Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, our CEO and CFO have concluded that our disclosure controls and procedures were effective as of June 30, 2018, to ensure that information required to be disclosed by the Company in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and

communicated to our management, including our CEO and CFO, as appropriate, to allow timely decisions regarding required disclosures.

Changes in Internal Controls over Financial Reporting — There were no changes that occurred during the fiscal quarter covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PARTII– OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

Please see Note 2, “Regulatory Matters” and Note 7, “Commitments and Contingencies” to the Financial Statements included in Part I - Financial Information of this Form 10-Q for a summary of certain legal proceedings involving us. In addition, our Form 10-K for the fiscal year ended December 31, 2017 and Form 10-Q for the quarter ended March 31, 2018, and the Notes to the Financial Statements included therein, contain descriptions of certain legal proceedings in which we are or were involved. The information included in, or incorporated by reference into, this Item 1 to Part II should be read in conjunction with such Form 10-K and Form 10-Q.

ITEM 1A.  RISK FACTORS

There have been no material changes to the risk factors as previously disclosed in the 2017 Form 10-K. 

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None. 

ITEM 4.  MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5.  OTHER INFORMATION

None.

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ITEM 6. EXHIBITS

Exhibit No.	Document
31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS	XBRL Instance Document (filed herewith as provided in Rule 406T of Regulation S-T)
101.SCH	XBRL Taxonomy Extension Schema Document (filed herewith as provided in Rule 406T of Regulation S-T)
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document (filed herewith as provided in Rule 406T of Regulation S-T)
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document (filed herewith as provided in Rule 406T of Regulation S-T)
101.LAB	XBRL Taxonomy Extension Label Linkbase Document (filed herewith as provided in Rule 406T of Regulation S-T)
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document (filed herewith as provided in Rule 406T of Regulation S-T)

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		IPALCO ENTERPRISES, INC.
Date:	August 6, 2018	/s/ Gustavo Pimenta
		Gustavo Pimenta
		Chief Financial Officer
		(PrincipalFinancialOfficer)
Date:	August 6, 2018	/s/ Karin M. Nyhuis
		Karin M. Nyhuis
		Controller
		(PrincipalAccountingOfficer)

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