Ipalco Enterprises 10Q 2012 Q3 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2012

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

Commission file number 1-8644

IPALCO ENTERPRISES, INC.
(Exact name of registrant as specified in its charter)


Indiana	35-1575582
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

One Monument Circle, Indianapolis, Indiana	46204
(Address of principal executive offices)	(Zip Code)

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

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

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

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


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

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

At November 6, 2012, 89,685,177 shares of IPALCO Enterprises, Inc. common stock were outstanding. All of such shares were owned by The AES Corporation.

THE REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS H(1)(a) AND (b) OF FORM 10-Q AND IS THEREFORE FILING THIS FORM WITH THE REDUCED DISCLOSURE FORMAT

IPALCO ENTERPRISES, INC.
QUARTERLY REPORT ON FORM 10-Q
For Quarter Ended September 30, 2012


TABLE OF CONTENTS

Item No.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

PART I - FINANCIAL INFORMATION
	1.	Financial Statements:
		Unaudited Condensed Consolidated Statements of Comprehensive Income for the Three Months and Nine Months ended September 30, 2012 and 2011
		Unaudited Condensed Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011
		Unaudited Condensed Consolidated Statements of Cash Flows for the Nine Months ended September 30, 2012 and 2011
		Unaudited Condensed Consolidated Statements of Common Shareholder’s Equity (Deficit) and Noncontrolling Interest for the Nine Months ended September 30, 2012 and 2011
		Notes to Unaudited Condensed Consolidated Financial Statements
	1B.	Defined Terms
	2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	3.	Quantitative and Qualitative Disclosure About Market Risk
	4.	Controls and Procedures

PART II - OTHER INFORMATION
	1.	Legal Proceedings
	1A.	Risk Factors
	2.	Unregistered Sales of Equity Securities and Use of Proceeds
	3.	Defaults Upon Senior Securities
	4.	Mine Safety Disclosures
	5.	Other Information
	6.	Exhibits

SIGNATURES

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, as amended (“Exchange Act”) 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 involve many risks and uncertainties and express an expectation or belief and contain a projection, plan or assumption with regard to, among other things, our future revenues, income, expenses or capital structure. Such statements of future events or performance are not guarantees of future performance and involve estimates, assumptions and uncertainties. The words “could,” “may,” “predict,” “anticipate,” “would,” “believe,” “estimate,” “expect,” “forecast,” “project,” “objective,” “intend,” “continue,” “should,” “plan,” and similar expressions, or the negatives thereof, are intended to identify forward-looking statements unless the context requires otherwise.

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

fluctuations in customer growth and demand;
impacts of weather on retail sales and wholesale prices;
impacts of renewable energy generation, natural gas prices and other market factors on wholesale prices;
weather-related damage to our electrical system;
fuel and other input costs;
generating unit availability and capacity;
transmission and distribution system reliability and capacity;
purchased power costs and availability;
regulatory action, including, but not limited to, the review of our basic rates and charges by the Indiana Utility Regulatory Commission (“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 and other post-retirement plans;
changes in financial or regulatory accounting policies;
environmental matters, including costs of compliance with current and future environmental laws and requirements;
interest rates and other costs of capital;
the availability of capital;
labor strikes or other workforce factors;
facility or equipment maintenance, repairs and capital expenditures;
local economic conditions, including the fact that the local and regional economies have struggled through the recession and weak economic climate the past few years and continue to face uncertainty for the foreseeable future;
acts of terrorism, acts of war, pandemic events or natural disasters such as floods, earthquakes, tornadoes, ice storms or other catastrophic events;
costs and effects of legal and administrative proceedings, audits, settlements, investigations and claims and the ultimate disposition of litigation;
issues related to our participation in the Midwest Independent Transmission System Operator, Inc. (“MISO”), including the cost associated with membership and the recovery of costs incurred; and
product development and technology changes.

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

PART I -FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS


IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Unaudited Condensed Consolidated Statements of Comprehensive Income
*(In Thousands)*

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2012		2011		2012		2011

UTILITY OPERATING REVENUES	$	324,478	$	320,550	$	918,241	$	889,658

UTILITY OPERATING EXPENSES:
Operation:
Fuel		83,795		90,719		242,366		253,474
Other operating expenses		55,224		50,467		162,266		151,999
Power purchased		34,561		25,107		99,080		65,446
Maintenance		20,728		30,078		71,857		91,476
Depreciation and amortization		44,936		42,089		132,211		124,417
Taxes other than income taxes		11,472		10,796		33,643		32,055
Income taxes-net		23,535		22,843		54,057		50,477
Total utility operating expenses		274,251		272,099		795,480		769,344
UTILITY OPERATING INCOME		50,227		48,451		122,761		120,314

OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used during construction		259		1,009		650		3,245
Loss on early extinguishment of debt		-		-		-		(15,378)
Miscellaneous income and (deductions) - net		(733)		(2,445)		(1,339)		9,812
Income tax benefit applicable to nonoperating income		5,284		6,270		15,726		19,748
Total other income and (deductions) - net		4,810		4,834		15,037		17,427

INTEREST AND OTHER CHARGES:
Interest on long-term debt		25,923		26,205		77,635		82,981
Other interest		499		446		1,419		1,339
Allowance for borrowed funds used during construction		(150)		(644)		(774)		(2,129)
Amortization of redemption premiums and expense on debt		1,224		1,158		3,657		3,466
Total interest and other charges-net		27,496		27,165		81,937		85,657
NET INCOME		27,541		26,120		55,861		52,084

LESS: PREFERRED DIVIDENDS OF SUBSIDIARY		803		803		2,410		2,410

NET INCOME APPLICABLE TO COMMON STOCK	$	26,738	$	25,317	$	53,451	$	49,674

ADD OTHER COMPREHENSIVE INCOME:
Gain on sale of available for sale investment		-		-		-		197

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK	$	26,738	$	25,317	$	53,451	$	49,871

See notes to unaudited condensed consolidated financial statements.


IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Unaudited Condensed Consolidated Balance Sheets
*(In Thousands)*

	September 30,		December 31,
	2012		2011
ASSETS
UTILITY PLANT:
Utility plant in service	$	4,355,881	$	4,313,015
Less accumulated depreciation		2,018,264		1,940,633
Utility plant in service - net		2,337,617		2,372,382
Construction work in progress		57,820		52,429
Spare parts inventory		14,916		15,534
Property held for future use		1,002		1,002
Utility plant - net		2,411,355		2,441,347

OTHER ASSETS:
Nonutility property - at cost, less accumulated depreciation		534		539
Other investments		5,274		5,029
Other assets - net		5,808		5,568

CURRENT ASSETS:
Cash and cash equivalents		33,112		27,283
Accounts receivable and unbilled revenue (less allowance for doubtful accounts of $3,143 and $2,081, respectively)		140,376		136,007
Fuel inventories - at average cost		55,477		52,694
Materials and supplies - at average cost		57,556		54,137
Deferred tax asset - current		10,951		12,352
Regulatory assets		4,970		7,424
Prepayments and other current assets		19,903		16,838
Total current assets		322,345		306,735

DEFERRED DEBITS:
Regulatory assets		471,362		485,932
Miscellaneous		31,359		32,070
Total deferred debits		502,721		518,002
TOTAL	$	3,242,229	$	3,271,652


CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common shareholder’s deficit:
Paid in capital	$	11,732	$	11,367
Accumulated deficit		(8,362)		(17,213)
Total common shareholder’s equity (deficit)		3,370		(5,846)
Cumulative preferred stock of subsidiary		59,784		59,784
Long-term debt		1,650,919		1,760,316
Total capitalization		1,714,073		1,814,254

CURRENT LIABILITIES:
Short-term and current portion of long-term debt		160,000		64,000
Accounts payable		62,006		81,206
Accrued expenses		21,760		24,138
Accrued real estate and personal property taxes		22,922		17,460
Regulatory liabilities		12,044		9,263
Accrued income taxes		14,200		2,864
Accrued interest		45,159		31,008
Customer deposits		24,295		23,142
Other current liabilities		10,985		11,372
Total current liabilities		373,371		264,453

DEFERRED CREDITS AND OTHER LONG-TERM LIABILITIES:
Regulatory liabilities		563,540		550,432
Accumulated deferred income taxes - net		334,394		351,161
Non-current income tax liability		5,707		5,354
Unamortized investment tax credit		8,562		9,761
Accrued pension and other postretirement benefits		224,276		258,171
Miscellaneous		18,306		18,066
Total deferred credits and other long-term liabilities		1,154,785		1,192,945

COMMITMENTS AND CONTINGENCIES (Note 6)
TOTAL	$	3,242,229	$	3,271,652

See notes to unaudited condensed consolidated financial statements.


IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Unaudited Condensed Consolidated Statements of Cash Flows
*(In Thousands)*

	Nine Months Ended,
	September 30,
	2012		2011

CASH FLOWS FROM OPERATIONS:
Net income	$	55,861	$	52,084
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		134,228		125,232
Amortization of regulatory assets		1,435		3,881
Deferred income taxes and investment tax credit adjustments - net		(13,427)		(19,073)
Loss on early extinguishment of debt		-		15,378
Allowance for equity funds used during construction		(503)		(3,113)
Gain on sale of nonutility property		-		(13,354)
Change in certain assets and liabilities:
Accounts receivable		(4,368)		7,047
Fuel, materials and supplies		(6,203)		(14,526)
Income taxes receivable or payable		11,759		21,302
Financial transmission rights		(1,558)		(2,865)
Accounts payable and accrued expenses		(16,966)		9,537
Accrued real estate and personal property taxes		5,462		4,566
Accrued interest		14,151		12,889
Pension and other postretirement benefit expenses		(33,895)		(24,422)
Short-term and long-term regulatory assets and liabilities		13,333		(4,604)
Other - net		(1,123)		6,040
Net cash provided by operating activities		158,186		175,999

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures - utility		(82,387)		(165,686)
Proceeds from sales and maturities of short-term investments		-		2,000
Proceeds from the sales of assets		1		13,467
Grants under the American Recovery and Reinvestment Act of 2009		3,833		6,644
Cost of removal, net of salvage		(7,225)		(9,273)
Other		(5,399)		(2,431)
Net cash used in investing activities		(91,177)		(155,279)

CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt borrowings		63,000		121,000
Short-term debt repayments		(77,000)		(121,000)
Long-term borrowings, net of discount		-		494,708
Retirement of long-term debt and early tender premium		-		(430,222)
Dividends on common stock		(44,600)		(56,831)
Preferred dividends of subsidiary		(2,410)		(2,410)
Deferred financing costs paid		(166)		(6,895)
Other		(4)		(592)
Net cash used in financing activities		(61,180)		(2,242)
Net change in cash and cash equivalents		5,829		18,478
Cash and cash equivalents at beginning of period		27,283		31,796
Cash and cash equivalents at end of period	$	33,112	$	50,274

Supplemental disclosures of cash flow information:

Cash paid during the period for:
Interest (net of amount capitalized)	$	64,108	$	70,781
Income taxes	$	40,000	$	28,500

See notes to unaudited condensed consolidated financial statements.


IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Unaudited Condensed Consolidated Statements of Common Shareholder’s
Equity (Deficit) and Noncontrolling Interest
*(In Thousands)*

	Paid in Capital		Accumulated Deficit		Accumulated Other Comprehensive Income (Loss)		Total Common Shareholder's Equity (Deficit)			Cumulative Preferred Stock of Subsidiary
2011
Beginning Balance	$	10,811	$	(15,344)	$	(197)	$	(4,730)	$	59,784
Comprehensive Income attributable to common stock:
Net income applicable to common stock				49,674				49,674
Gain on sale of available for sale investment (net of income tax expense of $134)						197		197

Distributions to AES				(56,831)				(56,831)
Contributions from AES		551						551
Balance at September 30, 2011	$	11,362	$	(22,501)	$	-	$	(11,139)	$	59,784

2012
Beginning Balance	$	11,367	$	(17,213)	$	-	$	(5,846)	$	59,784
Comprehensive Income attributable to common stock:
Net income applicable to common stock				53,451				53,451

Distributions to AES				(44,600)				(44,600)
Contributions from AES		365						365
Balance at September 30, 2012	$	11,732	$	(8,362)	$	-	$	3,370	$	59,784


See notes to unaudited condensed consolidated financial statements.

IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements

For a list of certain abbreviations or acronyms used in the Notes to Unaudited Condensed Consolidated Financial Statements, see “Item 1B. Defined Terms” included in Part I - Financial Information of this Form 10-Q.

1. ORGANIZATION

IPALCO Enterprises, Inc. (“IPALCO”) is a holding company incorporated under the laws of the state of Indiana. IPALCO is a wholly-owned subsidiary of The AES Corporation (“AES”). IPALCO was acquired by AES in March 2001. IPALCO owns all of the outstanding common stock of its subsidiaries. Substantially all of IPALCO’s business consists of the generation, transmission, distribution and sale of electric energy conducted through its principal subsidiary, Indianapolis Power & Light Company (“IPL”). IPL was incorporated under the laws of the state of Indiana in 1926. IPL has approximately 470,000 retail customers in the city of Indianapolis and neighboring cities, towns and communities, and adjacent rural areas all within the state of Indiana, 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 two primarily coal-fired generating plants, one combination coal and gas-fired plant and two combustion turbines at a separate site that are all used for generating electricity. IPL’s net electric generation design capability for winter and summer is 3,492 Megawatts (“MW”) and 3,353 MW, respectively.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The accompanying Unaudited Condensed Consolidated Financial Statements (the “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 accounting principles generally accepted in the United States of America for interim financial information and in conjunction with the rules and regulations of the Securities and Exchange Commission. Accordingly, they do not include all of the disclosures required by accounting principles generally accepted in the United States of America 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 Annual Report on Form 10-K for the year ended December 31, 2011 (“2011 Form 10-K”) and should be read in conjunction therewith. Certain prior period amounts have been reclassified to conform to current year presentation.

Use of Management Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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.

3. FAIR VALUE MEASUREMENTS

Fair Value Hierarchy

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

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

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

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

IPALCO had one financial asset measured at fair value on a nonrecurring basis, which has been adjusted to fair value during one of the periods covered by this report due to an impairment loss. During the third quarter of 2011, we recorded an impairment on this nonutility investment of $1.6 million, as the investment was deemed to be other than temporarily impaired. In making this determination, we considered, among other things, the amount and length of time of impairment of the individual investments held by the fund as well as the future outlook of such investments. Because the investment is not publicly traded and therefore does not have a quoted market price, the impairment loss was based on our best available estimate of the fair value of the investment, which included primarily unobservable estimates. The recorded value of the investment was $1.9 million at both December 31, 2011 and September 30, 2012.

As of September 30, 2012 and December 31, 2011, all of IPALCO’s financial assets or liabilities adjusted to fair value on a recurring basis (excluding pension assets - see Note 5, “Pension and Other Postretirement Benefits”) were considered Level 3, based on the above fair value hierarchy. These primarily consisted of financial transmission rights, which are used to offset MISO congestion charges. Because the benefit associated with financial transmission rights is a flow-through to IPL’s jurisdictional customers, IPL records a regulatory liability matching the value of the financial transmission rights. These financial assets and liabilities were not material to the financial statements in the periods covered by this report, individually or in the aggregate.

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

Cash Equivalents

As of September 30, 2012 and December 31, 2011, our cash equivalents consisted of money market funds. The fair value of cash equivalents uses Level 1 measurements and approximates their book value due to their short maturity, which was $6.4 million and $5.9 million as of September 30, 2012 and December 31, 2011, respectively.

Customer Deposits

Our customer deposits do not have defined maturity dates and therefore, fair value is estimated to be the amount payable on demand, which equaled book value. Customer deposits totaled $24.3 million and $23.1 million as of September 30, 2012 and December 31, 2011, respectively.

Indebtedness

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. As a result, these are considered Level 2 measurements and it is not the purpose of this disclosure 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 for the periods ending:


	September 30, 2012				December 31, 2011
	Face Value		Fair Value		Face Value		Fair Value
	*(In Millions)*
Fixed-rate	$	1,765.3	$	2,030.2	$	1,765.3	$	1,944.9
Variable-rate		50.0		50.0		64.0		64.0
Total indebtedness	$	1,815.3	$	2,080.2	$	1,829.3	$	2,008.9

The difference between the face value and the carrying value of our fixed-rate debt represents unamortized discounts of $4.4 million and $5.0 million at September 30, 2012 and December 31, 2011, respectively.

4. INDEBTEDNESS

Accounts Receivable Securitization

As disclosed in the 2011 Form 10-K, IPL and a wholly-owned subsidiary of IPL (IPL Funding Corporation) were parties to an arrangement whereby an investor agreed to purchase, on a revolving basis, up to a $50 million interest in a pool of IPL’s receivables. During 2012, this arrangement was extended to October 24, 2012. The purchased amount was $50 million as of both September 30, 2012 and December 31, 2011. On October 22, 2012, under an amended and restated sale agreement, which matures on October 21, 2013, Citibank, N.A. and its affiliate, CRC Funding, LLC, replaced The Royal Bank of Scotland plc and Windmill Funding Corporation as agent and investor, respectively. The terms of the new arrangement to IPL are substantially the same as that of the previous arrangement.

Restrictions on Issuance of Debt

On July 6, 2012, IPL received approval from the Federal Energy Regulatory Commission (“FERC”) to borrow up to $500 million of short-term indebtedness outstanding at any time through July 28, 2014.

IPALCO’s Senior Secured Notes

In May 2011, IPALCO completed the sale of $400 million aggregate principal amount of 5.00% Senior Secured Notes due 2018 (“2018 IPALCO Notes”) pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended. The 2018 IPALCO Notes were issued pursuant to an Indenture dated May 18, 2011, by and between IPALCO and The Bank of New York Mellon Trust Company, N.A., as trustee. In connection with this issuance, IPALCO conducted a tender offer to repurchase for cash any and all of IPALCO’s then outstanding $375 million of 8.625% (original coupon 7.625%) Senior Secured Notes due November 14, 2011 (“2011 IPALCO Notes”). As a result, IPALCO no longer has indebtedness with an interest rate that changes due to changes in its credit ratings, although IPL’s credit facilities continue to have certain fees that can be affected by its credit ratings. Additionally, IPALCO no longer has any debt with financial ratio maintenance covenants; although its articles of incorporation continue to contain the same financial ratios restricting dividend payments and intercompany loans to AES as were included in the 2011 IPALCO Notes.

The 2018 IPALCO Notes were priced to the public at 99.927% of par. Net proceeds to IPALCO were $394.7 million after deducting underwriting costs and the discount. These costs and other related financing costs are being amortized through 2018 using the effective interest method. We used the net proceeds to repurchase all of the outstanding 2011 IPALCO Notes through the tender offer and to subsequently redeem all of the remaining 2011 IPALCO Notes not tendered. The proceeds were also used to pay the early tender premium of $14.4 million and other fees and expenses related to the tender offer and the redemption of the 2011 IPALCO Notes, as well as other fees and expenses related to the issuance of the 2018 IPALCO Notes. The total loss on early extinguishment of debt of $15.4 million was included as a separate line item within Other Income and Deductions in the accompanying Unaudited Condensed Consolidated Statements of Income.

The 2018 IPALCO Notes are secured by IPALCO’s pledge of all of the outstanding common stock of IPL. The lien on the pledged shares will be shared equally and ratably with IPALCO’s existing senior secured notes. IPALCO has entered into a Pledge Agreement Supplement with The Bank of New York Mellon Trust Company, N.A., as Collateral Agent, dated May 18, 2011 to the Pledge Agreement between IPALCO and The Bank of New York Mellon Trust Company, N.A. as successor Collateral Agent dated November 14, 2001.

IPL First Mortgage Bonds

In the third quarter of 2012, we reclassified $110 million aggregate principal amount of 6.30% IPL first mortgage bonds due July 2013 from Long-term debt to Short-term and current portion of long-term debt on our Consolidated Balance Sheet as the debt is now due within one year. Management plans to refinance these bonds in 2013 with a new long-term issuance. There can be no assurance that we will be able to refinance these bonds on favorable terms.

In September 2011, the Indiana Finance Authority (“IFA”) issued on behalf of IPL an aggregate principal amount of $55.0 million of 3.875% Environmental Facilities Revenue Bonds (Indianapolis Power & Light Company Project) due August 2021. Also in September 2011, the IFA issued on behalf of IPL an aggregate principal amount of $40.0 million of 3.875% Environmental Facilities Refunding Revenue Bonds (Indianapolis Power & Light Company Project) due August 2021. IPL issued $95.0 million aggregate principal amount of first mortgage bonds to the IFA at 3.875% to secure the loan of proceeds from the two series of bonds issued by the IFA. Proceeds of these bonds were used to retire $40.0 million of existing 5.75% IPL first mortgage bonds, and for the construction, installation and equipping of pollution control facilities, solid waste disposal facilities and industrial development projects at IPL’s Petersburg Generating Station.

5. PENSION AND OTHER POSTRETIREMENT BENEFITS

The following tables (in thousands) present information relating to the Employees’ Retirement Plan of Indianapolis Power & Light Company and the Supplemental Retirement Plan of Indianapolis Power & Light Company (“Pension Plans”):


Net funded status of plans:
Net funded status at December 31, 2011, before tax adjustments	$	(252,877)
Net benefit cost components reflected in net funded status during first quarter:
Service cost		(1,997)
Interest cost		(7,558)
Expected return on assets		8,139
Employer contributions during quarter		7,400
Net funded status at March 31, 2012 before tax adjustments	$	(246,893)
Net benefit cost components reflected in net funded status during second quarter:
Service cost		(1,996)
Interest cost		(7,558)
Expected return on assets		8,138
Employer contributions during quarter		9,700
Net funded status at June 30, 2012 before tax adjustments	$	(238,609)
Net benefit cost components reflected in net funded status during third quarter:
Service cost		(1,997)
Interest cost		(7,558)
Expected return on assets		8,138
Employer contributions during quarter		21,500
Net funded status at September 30, 2012 before tax adjustments	$	(218,526)

Regulatory assets related to pensions ⁽¹⁾:
Regulatory assets at December 31, 2011, before tax adjustments	$	313,821
Amount reclassified through net benefit cost:
Amortization of prior service cost		(1,061)
Amortization of net actuarial loss		(4,868)
Regulatory assets at March 31, 2012 before tax adjustments	$	307,892
Amount reclassified through net benefit cost:
Amortization of prior service cost		(1,062)
Amortization of net actuarial loss		(4,867)
Regulatory assets at June 30, 2012 before tax adjustments	$	301,963
Amount reclassified through net benefit cost:
Amortization of prior service cost		(1,061)
Amortization of net actuarial loss		(4,868)
Regulatory assets at September 30, 2012 before tax adjustments	$	296,034

⁽¹⁾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 yet to be recognized as components of net periodic benefit costs.

Pension Expense

The following table presents Net Periodic Benefit Cost information relating to the Pension Plans combined:


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2012		2011		2012		2011
	*(In Thousands)*
Components of net periodic benefit cost:
Service cost	$	1,997	$	1,809	$	5,990	$	5,426
Interest cost		7,558		7,957		22,674		23,871
Expected return on plan assets		(8,138)		(8,042)		(24,415)		(24,126)
Amortization of prior service cost		1,061		1,086		3,184		3,259
Amortization of actuarial loss		4,868		3,326		14,603		9,979
Net periodic benefit cost	$	7,346	$	6,136	$	22,036	$	18,409

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 obligation were not material to the consolidated financial statements in the periods covered by this report.

6. COMMITMENTS AND CONTINGENCIES

Legal Loss Contingencies

IPL is a defendant in approximately twenty-five pending lawsuits alleging personal injury or wrongful death stemming from exposure to asbestos and asbestos containing products formerly located in IPL power plants. IPL has been named as a “premises defendant”, which means that IPL did not mine, manufacture, distribute or install asbestos or asbestos containing products. These suits have been brought on behalf of persons who worked for contractors or subcontractors hired by IPL. IPL has insurance which may cover some portions of these claims; currently, these cases are being defended by counsel retained by various insurers who wrote policies applicable to the period of time during which much of the exposure has been alleged.

It is possible that material additional loss with regard to the asbestos lawsuits could be incurred. At this time, an estimate of additional loss cannot be made. IPL has settled a number of asbestos related lawsuits for amounts which, individually and in the aggregate, were not material to IPL’s or IPALCO’s results of operations, financial condition, or cash flows. Historically, settlements paid on IPL’s behalf have been comprised of proceeds from one or more insurers along with comparatively smaller contributions by IPL. Additionally, several cases have been dismissed by the plaintiffs in the past few years without requiring a settlement. We are unable to estimate the number of, the effect of, or losses or range of loss which are reasonably possible from the pending lawsuits or any additional asbestos suits. Furthermore, we are unable to estimate the portion of a settlement amount, if any, that may be paid from any insurance coverage for any known or unknown claims. Accordingly, there is no assurance that the pending or any additional suits will not have a material adverse effect on IPALCO’s results of operations, financial condition, or cash flows.

In addition, 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, or 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 of IPALCO.

Environmental Loss Contingencies

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

New Source Review

In October 2009, IPL received a Notice of Violation and Finding of Violation (“NOV”) from the U.S. Environmental Protection Agency (“EPA”) pursuant to the Federal Clean Air Act (“CAA”) Section 113(a). The NOV alleges violations of the CAA at IPL’s three primarily coal-fired electric generating facilities dating back to 1986. The alleged violations primarily pertain to the Prevention of Significant Deterioration (“PSD”) and nonattainment New Source Review requirements under the CAA. Since receiving the letter, IPL management has met with the EPA staff regarding possible resolutions of the NOV. At this time, we cannot predict the ultimate resolution of this matter. However, settlements and litigated outcomes of similar cases have required companies to pay civil penalties, install additional pollution control technology on coal-fired electric generating units, retire existing generating units, and invest in additional environmental projects. A similar outcome in this case could have a material impact on our business. We would seek recovery of any operating or capital expenditures related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that we would be successful in that regard. IPL has recorded a contingent liability related to this matter.

7. INCOME TAXES

IPALCO’s effective combined state and federal income tax rates were 40.6% and 41.8%, respectively, for the three and nine months ended September 30, 2012 as compared to 39.6% and 38.2%, respectively, for the three and nine months ended September 30, 2011. The increase in the effective tax rate for the nine month period ended September 30, 2012 was primarily due to: (i) a state tax benefit of $1.1 million, recorded in the second quarter of 2011 upon enactment of lower state income tax rates and (ii) a $1.1 million discrete tax expense adjustment recorded in the first quarter of 2012.

8. SALE OF OATSVILLE COAL RESERVE

In June 2011, IPL completed the sale of coal rights and a small piece of land in Indiana (the “Oatsville Coal Reserve”) to Penn Virginia Operating Co., LLC for a sale price of $13.5 million. The property had a carrying value of $0.2 million. The total gain recognized on the sale of $13.3 million was included in Miscellaneous Income and (Deductions) - Net under Other Income and (Deductions) in the accompanying Unaudited Condensed Consolidated Statements of Income.

9. SEGMENT INFORMATION

Operating segments are components of an enterprise for which separate financial information is available and is evaluated regularly by the chief operating decision maker in assessing performance and deciding how to allocate resources. 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 segments are utility and nonutility. The nonutility category primarily includes the $400 million of 7.25% Senior Secured Notes due April 1, 2016 and the $400 million of 5.00% Senior Secured Notes due May 1, 2018; approximately $13.4 million and $6.7 million of nonutility cash and cash equivalents, as of September 30, 2012 and December 31, 2011, respectively; short-term and long-term nonutility investments of $4.7 million and $4.6 million at September 30, 2012 and December 31, 2011, respectively; and income taxes and interest related to those items. Nonutility assets represented less than 1% of IPALCO’s total assets as of September 30, 2012 and December 31, 2011. Net income for the utility segment was $79.6 million and $88.5 million for the nine month periods ended September 30, 2012 and 2011, respectively, and $35.5 million and $34.8 million for the three month periods ended September 30, 2012 and 2011, respectively. The accounting policies of the identified segments are consistent with those policies and procedures described in the summary of significant accounting policies. Intersegment sales, if any, are generally based on prices that reflect the current market conditions.

ITEM 1B. DEFINED TERMS


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

2011 Form 10-K	IPALCO’s Annual Report on Form 10-K for the year ended December 31, 2011
2011 IPALCO Notes	$375 million of 8.625% (original coupon 7.625%) Senior Secured Notes due November 14, 2011
2018 IPALCO Notes	$400 million of 5.00% Senior Secured Notes due May 1, 2018
AES	The AES Corporation
ASC	Financial Accounting Standards Board Accounting Standards Codification
CAA	Federal Clean Air Act
CPCN	Certificate of Public Convenience and Necessity
DSM	Demand Side Management
EPA	U.S. Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
The Financial Statements	The Unaudited Condensed Consolidated Financial Statements of IPALCO in "Item 1. Financial Statements" included in Part I - Financial Information of this Form 10-Q
Fitch	Fitch Ratings
GHG	Greenhouse Gas
IFA	Indiana Finance Authority
IPALCO	IPALCO Enterprises, Inc.
IPL	Indianapolis Power & Light Company
IURC	Indiana Utility Regulatory Commission
kWh	Kilowatt hours
MATS	Mercury and Air Toxics Standards
MW	Megawatt
MISO	Midwest Independent Transmission System Operator, Inc.
NOV	Notice of Violation and Finding of Violation
NPDES	National Pollution 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

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 our Unaudited Condensed Consolidated Financial Statements and the notes thereto included in “Item 1. Financial Statements” included in Part I - Financial Information of this Form 10-Q. The following discussion contains forward-looking statements. Our actual results may differ materially from the results suggested by these forward-looking statements. Please see “Cautionary Note Regarding Forward - Looking Statements” at the beginning of this Form 10-Q. For a list of certain abbreviations or acronyms used in this discussion, see “Item 1B. Defined Terms” included in Part I - Financial Information of this Form 10-Q.

MARKET DEVELOPMENTS

We are one of many transmission system owner members in MISO. MISO is a regional transmission organization which maintains functional control over the combined transmission systems of its members and manages one of the largest energy and ancillary services markets in the U.S. IPL offers the available electricity production of each of its generation assets into the MISO day-ahead and real-time markets. MISO dispatches generation assets in economic order considering transmission constraints and other reliability issues to meet the total demand in the MISO region.

The increased interconnection of renewable energy to the MISO transmission system and participation of renewable energy resources in the MISO energy markets have decreased the economic dispatch of energy from coal resources. Additionally, the use of enhanced technologies to recover natural gas from shale deposits has increased natural gas supply and reserves, which has placed downward pressure on natural gas prices and, therefore, on wholesale power prices. The combination of these factors significantly reduced the clearing price of electricity in the MISO market in 2012 as compared to 2011. These factors, combined with the unusually mild winter in the MISO footprint in 2012 and a weakened economy, resulted in clearing prices in the MISO market for much of the first half of 2012 at their lowest levels since the MISO energy market began in 2005. As a result, IPL’s coal-fired generation called upon by MISO to produce electricity during the 2012 winter and spring months was at its lowest levels since 2005. The hotter than normal summer temperatures in 2012 partially mitigated that trend, but wholesale sales volumes were still down from 2011, which was also hotter than normal during the summer.

The greatest impact of the depressed winter and spring MISO electricity prices was a reduction in the fuel portion of the retail rate to IPL’s customers, which did not impact net utility operating income due to the pass-through nature of fuel and purchased power cost under the fuel adjustment charge proceedings. There was also, however, a significant negative impact on our wholesale sales volumes, as well as our profit margin on wholesale sales. Accordingly, wholesale revenues are down $19.9 million, or 58%, in the first nine months of 2012 as compared to the same period in 2011, despite reductions in both planned and unplanned outage rates in 2012. The total impact to IPL is partially mitigated by the fact that wholesale revenues have typically represented only about 5% of total revenues in the years leading up to 2012.

In light of these circumstances, in March 2012, IPL management implemented a “ready reserve” plan for the Eagle Valley generation plant. This ready reserve plan means that IPL will do the work necessary to maintain the equipment at Eagle Valley and to be ready when the units are dispatched by MISO. In order to keep the plant prepared for intermittent use, we have retained a small team of people at Eagle Valley. The rest of IPL’s employees that were previously at Eagle Valley have mostly retired from IPL or been positioned in other areas of IPL until the plant’s units are needed. The units at the Eagle Valley generation plant were dispatched by MISO at various times since implementation of the ready reserve plan and they performed successfully. As a result of the ready reserve plan, we estimate operating and maintenance costs for Eagle Valley in the first nine months of 2012 were nearly $6 million less than what we would have otherwise expected. Eagle Valley remains part of IPL’s operating and capacity plan and will continue to be, until it is no longer economical to maintain the facility and/or meet environmental regulations. The Eagle Valley units represent approximately 10% of IPL’s total generating capacity and about 7% of actual electricity generated by IPL in each of the past two years.

RESULTS OF OPERATIONS

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

Comparison of three months ended September 30, 2012 and three months ended September 30, 2011

Utility Operating Revenues

Utility operating revenues during the three months ended September 30, 2012 increased by $3.9 million compared to the same period in 2011, which resulted from the following changes (in thousands):


	Three Months Ended September 30,				Change		Percentage Change
	2012		2011		Change		Percentage Change

Utility Operating Revenues:
Retail Revenues	$	315,673	$	307,011	$	8,662	2.8%
Wholesale Revenues		2,984		5,560		(2,576)	(46.3)%
Miscellaneous Revenues		5,821		7,979		(2,158)	(27.0)%
Total Utility Operating Revenues	$	324,478	$	320,550	$	3,928	1.2%

Heating Degree Days:
Actual		88		82		6	7.3%
30-year Average		81		81

Cooling Degree Days:
Actual		1,011		1,034		(23)	(2.2)%
30-year Average		725		725

The increase in retail revenues of $8.7 million was due to a 4.7% increase in the weighted average price per kilowatt hours (“kWh”) sold ($12.7 million), partially offset by a 1.8% decrease in the volume of kWh sold ($3.9 million). The $12.7 million increase in the weighted average price of kWh sold was primarily due to increases in: fuel revenues of $6.1 million; environmental rate adjustment mechanism revenues of $4.1 million; and Demand Side Management (“DSM”) program rate adjustment mechanism revenues of $2.2 million. The increase in fuel revenues is offset by increases in purchased power costs as described below. Likewise, the vast majority of the increases in environmental and DSM rate adjustment mechanism revenues are offset by increased operating expenses including depreciation and amortization. The $3.9 million decrease in the volume of electricity sold was primarily due to milder temperatures.

The decrease in wholesale revenues of $2.6 million was primarily due to a 44.9% decrease in the quantity of kWh sold ($2.5 million), which is explained in the preceding section entitled “Market Developments.” The $2.2 million decrease in miscellaneous revenues was primarily due to decreases in pole attachment rental revenues of $1.3 million and MISO transmission revenues of $1.0 million, both resulting primarily from changes in the estimated revenue accruals in 2011 related to prior periods.

Utility Operating Expenses

The following table illustrates our primary operating expense changes from the three months ended September 30, 2011 to the three months ended September 30, 2012 (in millions):



Operating expenses for the three months ended September 30, 2011	$	272.1
Increase in power purchased		9.5
Decrease in maintenance expenses		(9.4)
Decrease in fuel costs		(6.9)
Increase in depreciation and amortization costs		2.8
Increase in DSM program costs		1.9
Increase in pension expenses		1.2
Other miscellaneous variances		3.1
Operating expenses for the three months ended September 30, 2012	$	274.3

The $9.5 million increase in purchased power costs was primarily due to a 44% increase in the volume of power purchased during the period ($9.3 million). A portion of the volume increase can be attributed to power purchased as part of a power purchase agreement for approximately 200 MW of wind generated electricity from a project in Minnesota, which began commercial operation in October 2011. Additionally, at times the MISO market provides a lower cost alternative to serve a portion of our jurisdictional customers’ electricity demand. For the reasons described in the preceding section entitled “Market Developments,” this situation occurred with greater frequency in the third quarter of 2012 than in the third quarter of 2011.

Maintenance expenses for the three months ended September 30, 2012 decreased $9.4 million or 31% compared to the same period in 2011 primarily due to a major generating unit overhaul occurring in the prior year.

The $6.9 million decrease in fuel costs is primarily due to a $7.3 million decrease in the quantity of fuel consumed in the comparable periods, as IPL’s coal-fired generation was not called upon by MISO to produce electricity as often during 2012. The fuel cost decrease was also due to a $3.4 million decrease in deferred fuel costs as the result of variances between estimated fuel and purchased power costs in our fuel adjustment charges and actual fuel and purchased power costs. We are generally permitted to recover underestimated fuel and purchased power costs to serve our retail customers in future rates through the fuel adjustment charges proceedings and, therefore, the costs are deferred and amortized into expense in the same period that our rates are adjusted. These decreases were partially offset by a 7% increase in the price per ton of coal we consumed during the comparable periods ($5.5 million).

The increase in depreciation and amortization costs of $2.8 million was primarily due to additional utility plant assets placed in service, including the Petersburg unit 4 flue gas desulfurization enhancements project that was completed in the fourth quarter of 2011. Depreciation costs on this project are recoverable through customer rates. The increase in DSM program costs of $1.9 million, which are recoverable through customer rates, is attributed to the continued implementation of IPL’s energy efficiency program initiatives. The $1.2 million increase in pension expenses is due to increases in the components of net periodic benefit cost (see Note 5, “Pension and Other Postretirement Benefits” for details).

Other Income and Deductions

Other income and deductions remained relatively flat for the three months ended September 30, 2012 as compared to the same period in 2011 and included an impairment recorded on a minority ownership investment of $1.6 million in the prior period. This was partially offset by a $1.0 million decrease in the income tax benefit, which was primarily due to the change in pretax nonoperating income during the comparable periods, and a $0.8 million decrease in the allowance for equity funds used during construction as a result of decreased construction activity.

Comparison of nine months ended September 30, 2012 and nine months ended September 30, 2011

Utility Operating Revenues

Utility operating revenues during the nine months ended September 30, 2012 increased by $28.6 million compared to the same period in 2011, which resulted from the following changes (in thousands):


	Nine Months Ended September 30,				Change		Percentage Change
	2012		2011		Change		Percentage Change

Utility Operating Revenues:
Retail Revenues	$	888,843	$	837,767	$	51,076	6.1%
Wholesale Revenues		14,214		34,149		(19,935)	(58.4)%
Miscellaneous Revenues		15,184		17,742		(2,558)	(14.4)%
Total Utility Operating Revenues	$	918,241	$	889,658	$	28,583	3.2%

Heating Degree Days:
Actual		2,506		3,296		(790)	(24.0)%
30-year Average		3,534		3,505

Cooling Degree Days:
Actual		1,530		1,466		64	4.4%
30-year Average		1,027		1,027

The increase in retail revenues of $51.1 million was due to a 7.6% increase in the weighted average price per kWh sold ($59.0 million) and a nonrecurring charge against retail revenues related to prior periods recorded in March of 2011 ($5.0 million), partially offset by a 2.0% decrease in the volume of kWh sold ($12.9 million). The $59.0 million increase in the weighted average price of kWh sold was primarily due to increases in: fuel revenues of $35.5 million; environmental rate adjustment mechanism revenues of $9.7 million; favorable block rate variances of $7.3 million; and DSM program rate adjustment mechanism revenues of $6.6 million. The increase in fuel revenues is offset by increases in purchased power costs as described below. Likewise, the vast majority of the increases in environmental and DSM rate adjustment mechanism revenues are offset by increased operating expenses including depreciation and amortization. The favorable block rate variances of $7.3 million are mostly attributed to our declining block rate structure, which generally provides for residential and commercial customers to be charged at a lower per kWh rate at higher consumption levels. Therefore, as volumes decrease, the weighted average price per kWh increases. The $12.9 million decrease in the volume of electricity sold was primarily due to milder temperatures in our service territory during the winter of 2012 (demonstrated by the decrease in heating degree days, as shown in the table above).

The decrease in wholesale revenues of $19.9 million was primarily due to a 49.9% decrease in the quantity of kWh sold ($17.0 million) and a 16.9% decrease in the weighted average price per kWh sold ($2.9 million). The declines in the quantity and price of wholesale kWh sales are explained in the preceding section entitled “Market Developments.” The $2.6 million decrease in miscellaneous revenues was primarily due to decreases in MISO transmission revenues of $1.6 million and pole attachment rental revenues of $0.5 million, both resulting primarily from changes in the estimated revenue accruals in 2011 related to prior periods.

Utility Operating Expenses

The following table illustrates our primary operating expense changes from the nine months ended September 30, 2011 to the nine months ended September 30, 2012 (in millions):



Operating expenses for the nine months ended September 30, 2011	$	769.3
Increase in power purchased		33.6
Decrease in maintenance expenses		(19.6)
Decrease in fuel costs		(11.1)
Increase in depreciation and amortization costs		7.8
Increase in DSM program costs		6.4
Increase in pension expenses		3.6
Increase in income taxes - net		3.6
Other miscellaneous variances		1.9
Operating expenses for the nine months ended September 30, 2012	$	795.5

The $33.6 million increase in purchased power costs was primarily due to a 79% increase in the volume of power purchased during the period ($41.5 million). This increase was partially offset by a 6% decrease in the market price of power purchased during the period ($7.9 million). A portion of the volume increase can be attributed to power purchased as part of a power purchase agreement for approximately 200 MW of wind generated electricity from a project in Minnesota, which began commercial operation in October 2011. Additionally, at times the MISO market provides a lower cost alternative to serve a portion of our jurisdictional customers’ electricity demand. For the reasons described in the preceding section entitled “Market Developments,” this situation occurred with greater frequency in the first nine months of 2012 than in the first nine months of 2011.

Maintenance expenses for the nine months ended September 30, 2012 decreased $19.6 million or 21% compared to the same period in 2011 primarily due to the timing of major generating unit overhauls. We expect maintenance expenses to increase in 2013 with another major generating unit overhaul scheduled for next year.

The $11.1 million decrease in fuel costs is primarily due to a $35.9 million decrease in the quantity of fuel consumed due primarily to a decrease in total electricity sales volume in the comparable periods and an increase in power purchased, as described above. The fuel cost decrease was partially offset by a $12.7 million increase in deferred fuel costs as the result of variances between estimated fuel and purchased power costs in our fuel adjustment charges and actual fuel and purchased power costs. The decrease was also offset by an 8% increase in the price per ton of coal we consumed during the comparable periods ($15.7 million). We are generally permitted to recover underestimated fuel and purchased power costs to serve our retail customers in future rates through the fuel adjustment charges proceedings and, therefore, the costs are deferred and amortized into expense in the same period that our rates are adjusted.

The increase in depreciation and amortization costs of $7.8 million was primarily due to additional utility plant assets placed in service, including the Petersburg unit 4 flue gas desulfurization enhancements project that was completed in the fourth quarter of 2011. Depreciation costs on this project are recoverable through customer rates.

The increase in DSM program costs of $6.4 million, which are recoverable through customer rates, is attributed to the continued implementation of IPL’s energy efficiency program initiatives. The $3.6 million increase in pension expenses is due to increases in the components of net periodic benefit cost (see Note 5, “Pension and Other Postretirement Benefits” for details). The $3.6 million increase in income taxes - net was primarily due to the tax effect of the increase in pretax net operating income, for the reasons previously described, and a $1.1 million discrete tax adjustment recorded in the first quarter of 2012.

Other Income and Deductions

Other income and deductions decreased $2.4 million for the nine months ended September 30, 2012 as compared to the same period in 2011. This decrease is primarily due to: (i) a $13.3 million gain on sale of our Oatsville coal reserve in June of 2011; (ii) a $4.0 million decrease in the income tax benefit, which was primarily due to the change in pretax nonoperating income during the comparable periods; and (iii) a $2.6 million decrease in the allowance for equity funds used during construction as a result of decreased construction activity. These decreases were partially offset by a $15.4 million loss on early extinguishment of debt in May of 2011 related to the repurchase of $375 million of 8.625% 2011 IPALCO Notes, including a $14.4 million early tender premium.

Interest and Other Charges

Interest and other charges decreased $3.7 million for the nine months ended September 30, 2012 as compared to the same period in 2011. This decrease was primarily due to lower interest of $5.3 million on long-term debt as a result of various debt refinancing activities in 2011, including the refinancing in May of 2011 of $375 million of 8.625% 2011 IPALCO Notes with $400 million of 5.00% Senior Secured Notes due May 1, 2018. This decrease was partially offset by a $1.4 million decrease in the allowance for borrowed funds used during construction as a result of decreased construction activity.

LIQUIDITY AND CAPITAL RESOURCES

As of September 30, 2012, we had unrestricted cash and cash equivalents of $33.1 million. As of September 30, 2012, we also had available borrowing capacity of $246.9 million under our $250.0 million committed revolving credit facility after existing letters of credit. All of IPL’s long-term borrowings must first be approved by the IURC and the aggregate amount of IPL’s short-term indebtedness must be approved by the FERC. We have approval from FERC to borrow up to $500 million of short-term indebtedness outstanding at any time through July 28, 2014. As of September 30, 2012, we also have authority from the IURC to, among other things, issue up to $135 million in aggregate principal amount of long-term debt, to refinance up to $110 million in existing indebtedness through December 31, 2013, and to have up to $250 million of long-term credit agreements and liquidity facilities outstanding at any one time. 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. Sources for principal payments on outstanding indebtedness and nonrecurring capital expenditures are expected to be obtained from: (i) existing cash balances; (ii) cash generated from operating activities; (iii) borrowing capacity on our committed credit facility; and (iv) additional debt financing. In addition, due to existing and expected environmental regulations, it is currently expected that equity capital will also be used as a funding source.

Accounts Receivable Securitization

IPALCO’s Senior Secured Notes

IPL First Mortgage Bonds

Capital Requirements

Capital Expenditures

Our construction program is composed of capital expenditures necessary for prudent utility operations and compliance with environmental laws and regulations, along with discretionary investments designed to replace aging equipment or improve overall performance. Our capital expenditures totaled $82.4 million and $165.7 million for the nine months ended September 30, 2012 and 2011, respectively. Our capital expenditures decreased by $83.3 million in 2012 primarily due to the Petersburg unit 4 flue gas desulfurization enhancements project that was completed in the fourth quarter of 2011. Construction expenditures during the first nine months of 2012 and 2011 were financed with internally generated cash provided by operations, a portion of the net proceeds from the $95 million of IFA bonds described above issued in September 2011, borrowings on our credit facility and a federal grant for IPL’s Smart Energy Projects.

Our capital expenditure program, including development and permitting costs, for the three year period 2012-2014 is currently estimated to cost approximately $402 million excluding environmental compliance costs. It includes approximately $221 million for additions, improvements and extensions to transmission and distribution equipment, including Smart Energy Projects, $153 million for power plant related projects, and $28 million for other miscellaneous equipment. These estimates include amounts already spent in the first nine months of 2012. These amounts do not include the impacts of the MATS rule (see “Environmental Matters” - “MATS” below for further details).

Common Stock Dividends

All of IPALCO’s outstanding common stock is owned by AES. During the first nine months of 2012 and 2011 we paid $44.6 million and $56.8 million, respectively, in dividends to AES. Future distributions will be determined at the discretion of our board of directors and will depend primarily on dividends received from IPL. Dividends from IPL are affected by IPL’s actual results of operations, financial condition, cash flows, capital requirements, regulatory considerations, and such other factors as IPL’s board of directors deems relevant.

Pension Funding

We contributed $38.6 million and $29.9 million to the Pension Plans during the first nine months of 2012 and 2011, respectively. Funding for the qualified Employees’ Retirement Plan of Indianapolis Power & Light Company is based upon actuarially determined contributions that take into account the amount deductible for income tax purposes and the minimum contribution required under Employee Retirement Income Security Act of 1974, as amended by the Pension Protection Act of 2006, as well as targeted funding levels necessary to meet certain thresholds. Management does not currently expect any of the pension assets to be returned to us during 2012.

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 can be affected by our credit ratings. Any reduction in our debt or credit ratings may adversely affect the trading price of our outstanding debt securities. In April 2012, Fitch Ratings (“Fitch”) downgraded the Issuer Default Rating of IPALCO to ’BB+’ from ’BBB-’ and downgraded the instrument rating of IPALCO’s senior secured notes by one notch to ’BB+’ from ’BBB-’. In addition, Fitch affirmed the Issuer Default Rating of IPL at ’BBB-’ as well as affirmed IPL’s security ratings. In a press release announcing the downgrade, Fitch cited various factors to explain the downgrade, including, but not limited to: IPALCO’s highly leveraged capital structure, the sole support IPALCO receives from the upstream distributions from IPL, a rise in operating costs including pension expenses, significant levels of capital spending for environmental compliance at IPL and lower wholesale power pricing. Fitch forecasts the decline in credit metrics at IPALCO to be temporary over 2012 to 2015 and expects credit metrics to recover by 2016.

The credit ratings of IPALCO and IPL as of November 1, 2012 are as follows:


	Moody’s		S&P		Fitch

IPALCO Issuer Rating/Corporate Credit Rating/Long-term Issuer Default Rating		-		BBB-		BB+
IPALCO Senior Secured Notes		Ba1		BB+		BB+
IPL Issuer Rating/Corporate Credit Rating/Long term Issuer Default Rating		Baa2		BBB-		BBB-
IPL Senior Secured		A3		BBB		BBB+
IPL Senior Unsecured		Baa2		BBB-		BBB

The following discussion is an update to and should be read in conjunction with the discussion included in “Liquidity and Capital Resources - “ Environmental Matters” included in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our 2011 Form 10-K.

Regulatory Matters

Tree Trimming Practices Investigation

In July 2012, the IURC issued its final order in the tree trimming practices rulemaking, which was later approved by the Indiana governor and attorney general and became law in October 2012. IPL is implementing procedures to ensure it appropriately complies with the requirements of the new rule that addresses notification, dispute resolution and other activities associated with its vegetation management practices. The requirements of the new ruling are similar to current practices. However, the actual cost impact of the rule will not be known until we have experience operating under its terms.

Environmental Matters

The combination of existing and expected environmental regulations make it likely that we will temporarily or permanently retire several of our existing, primarily coal-fired, smaller and older generating units within the next several years. These units are not equipped with the advanced environmental control technologies needed to comply with existing and expected regulations, and collectively have made up less than 15% of our net electricity generation over the past five years. We are continuing to evaluate available options for replacing this generation, which include modifying one or more of the units to use natural gas as the fuel source, building new units, purchasing existing units, joint ownership of generating units, purchasing electricity and capacity from a third party, or some combination of these options. Accordingly, on June 28, 2012, IPL issued a request for proposals for 600 MW of replacement capacity and energy beginning in June 2017, which is intended to help us determine the best plan for replacement generation. Proposals from outside parties have been received and we are currently evaluating appropriate next steps. Our decision on which replacement options to pursue will be impacted by the alternatives available to comply with the EPA’s MATS rule, described in “MATS” below, as well as the ultimate timetable for implementation of the rule. We will seek and expect to recover our costs associated with replacing the retired units, but no assurance can be given as to whether the IURC would approve such a request.

MATS

In April 2012, the EPA’s rule to establish maximum achievable control technology standards for each hazardous air pollutant regulated under the CAA emitted from coal and oil-fired electric utilities, known as the Mercury and Air Toxics Standards or “MATS” became effective. IPL management has developed a plan to comply with this rule. Most of our coal-fired capacity has acid gas scrubbers or comparable control technologies; however, there are other improvements to such control technologies that are necessary to achieve compliance. Under the CAA, compliance is required by April 16, 2015; however, the compliance period for a unit, or group of units, may be extended by state permitting authorities (for one additional year) or through a CAA administrative order from the EPA (for another additional year). We expect to pursue an extension from the Indiana Department of Environmental Management, but there is no guarantee that we will be successful.

During the third quarter of 2012, we filed a petition and a request for a Certificate of Public Convenience and Necessity (“CPCN”) in the amount of $606 million of capital spend on clean coal technology to comply with the MATS rule. These filings detail the controls we plan to add to each of our five baseload units, including four at our Petersburg generating station and one at our Harding Street generating station. We are seeking and expect to recover through our environmental rate adjustment mechanism, all operating and capital expenditures related to compliance; however, there can be no assurance that we will be successful in that regard. Recovery of these costs is expected through an Indiana statute, which allows for 100% recovery of qualifying costs through a rate adjustment mechanism.

Several lawsuits challenging the MATS rule have been filed and consolidated into a single proceeding before the United States Court of Appeals for the District of Columbia Circuit. We cannot predict the outcome of this litigation.

National Pollution Discharge Elimination System

On August 28, 2012, IDEM issued National Pollution Discharge Elimination System (“NPDES”) permits to the IPL Petersburg, Harding Street, and Eagle Valley generating stations, which became effective in October 2012. NPDES permits regulate specific industrial wastewater and storm water discharges to the waters of Indiana under Sections 402 and 405 of the Federal Water Pollution Control Act. These permits set new levels of acceptable metal effluent water discharge, as well as monitoring and other requirements designed to protect aquatic life, with full compliance required by October 2015. IPL is conducting studies to determine what operational changes and/or additional equipment will be required to comply with the new limitation. In developing its compliance plans, IPL must make assumptions about the outcomes of future Federal rulemaking with respect to coal combustion byproducts, cooling water intake and wastewater effluents. In light of the uncertainties at this time, we cannot predict the impact of these regulations on our consolidated results of operations, cash flows, or financial condition, but it could be material.

We will seek and expect to recover through our environmental rate adjustment mechanism, any operating or capital expenditures related to compliance; however, there can be no assurances that we would be successful in that regard. Recovery of these costs is expected through an Indiana statute, which allows for 80% recovery of qualifying costs through a rate adjustment mechanism and the remainder through a base rate case proceeding.

Clean Air Interstate Rule and the Cross-State Air Pollution Rule

In August 2012, the U.S. Court of Appeals issued a ruling in EME Homer City Generation LLP v. EPA which vacated the Cross-State Air Pollution Rule. The Court ruling also requires EPA to continue administering the Clean Air Interstate Rule pending the promulgation of an EPA replacement. IPL will continue to meet its CAIR requirement by virtue of existing pollution control equipment combined with the purchase of emission allowances, when needed. In October 2012, the EPA filed a petition for rehearing en banc of this case, which if granted could affect the August 2012 Court ruling.

Climate Change - Regulation

As noted in our 2011 Form 10-K, in December 2010, the EPA announced that it had entered into a settlement agreement with several states and environmental groups that requires the EPA to promulgate New Source Performance Standards for Greenhouse Gas (“GHG”) emissions from electric generating units and certain emissions units from refineries. In April 2012, the EPA published such proposed regulations. The proposed rule would require certain new electric generating units to meet a standard of 1,000 pounds of carbon dioxide per megawatt-hour, a standard based on the emissions limitations achievable through natural gas combined cycle generation. The proposal anticipates that affected coal-fired units would need to install carbon capture and storage or other expensive carbon dioxide emission control technology to meet the standard. As proposed, the standard would not apply to our existing generating units, but rather would regulate construction of new generating units.

In June 2012, the U.S. Court of Appeals for the D.C. Circuit issued an order rejecting challenges to EPA’s GHG Endangerment Finding, the Tailpipe Rule, the Timing Rule, and the Tailoring Rule; each of which are rules promulgated by EPA under its CAA authority to regulate GHG emissions. Briefly, the Court upheld the Endangerment Finding and the Tailpipe Rule, and dismissed petitions challenging the Timing and Tailoring Rules for lack of standing. Accordingly, the PSD and Title V permitting requirements for electric utilities established by these rules will remain in place, subject to further potential judicial challenges. Our compliance obligations with respect to these rules are not expected to change as a result.

Summary

We expect to incur material costs to comply with MATS (up to $606 million, as discussed in “MATS” above) and, to a lesser extent to which we cannot predict, other expected environmental regulations related to: coal combustion byproducts; NPDES permits; wastewater effluent; cooling water intake; Polychlorinated Biphenyls-containing equipment; and National Ambient Air Quality Standards, both in terms of capital costs and ongoing operating and maintenance costs. We would expect to seek recovery of both capital and operating costs related to such compliance, although no assurances can be given that we would be successful.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

Not applicable pursuant to General Instruction H of the Form 10-Q.

ITEM 4. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports that we file or submit under the Securities Exchange Act of 1934, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and communicated to the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures.

Evaluation of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, of the effectiveness of our “disclosure controls and procedures” (as defined in the Exchange Rules 13a-15(e) and 15d-15(e) as required by paragraph (b) of the Exchange Act Rules 13a-15 or 15d-15) as of September 30, 2012. Our management, including the principal executive officer and principal financial officer, is engaged in a comprehensive effort to review, evaluate and improve our controls; however, management does not expect that our disclosure controls or our internal controls over financial reporting will prevent all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system’s objectives will be met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. In addition, any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or that the degree of compliance with the policies or procedures deteriorates. We have interests in certain unconsolidated entities. As we do not control or manage these entities, our disclosure controls and procedures with respect to such entities is generally more limited than those we maintain with respect to our consolidated subsidiaries.

Based upon the controls evaluation performed, the principal executive officer and principal financial officer have concluded that as of September 30, 2012, our disclosure controls and procedures were effective to provide reasonable assurance that material information relating to us and our consolidated subsidiaries is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures.

Changes in Internal Controls

In the course of our evaluation of disclosure controls and procedures, management considered certain internal control areas in which we have made and are continuing to make changes to improve and enhance controls. Based upon that evaluation, the principal executive officer and principal financial officer concluded that there were no changes in our internal controls over financial reporting identified in connection with the evaluation required by paragraph (d) of the Exchange Act Rules 13a-15 or 15d-15 that occurred during the nine months ended September 30, 2012 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Please see Note 6, “Commitments and Contingencies” to The Financial Statements for a summary of significant legal proceedings involving us. We are also subject to routine litigation, claims and administrative proceedings arising in the ordinary course of business.

ITEM 1A. RISK FACTORS

There have been no material changes to the risk factors as previously disclosed in IPALCO’s Annual Report on Form 10-K for the year ended December 31, 2011.

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.

ITEM 6. EXHIBITS


Exhibit No.	Document
31.1	Certification by Chief Executive Officer required by Rule 13a-14(a) or 15d-14(a)
31.2	Certification by Principal Financial Officer required by Rule 13a-14(a) or 15d-14(a)
32	Certification required by Rule 13a-14(b) or 15d-14(b)
101.INS	XBRL Instance Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.SCH	XBRL Taxonomy Extension Schema Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.LAB	XBRL Taxonomy Extension Label Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)

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.
		(Registrant)

Date:	November 6, 2012	/s/ Kelly M. Huntington
		Kelly M. Huntington
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer and Duly Authorized Officer)



Date:	November 6, 2012	/s/ Kurt A. Tornquist
		Kurt A. Tornquist
		Vice President and Controller
		(Principal Accounting Officer)

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Ipalco Enterprises 10-Q2012 Q3 Quarterly report

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