Form 10-Q

10-Q 1 sub10q.htm IPALCO 2011 Q3 FORM 10-Q Form 10-Q

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, 2011

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 3, 2011, 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, 2011

TABLE OF CONTENTS

Item No.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

PART I - FINANCIAL INFORMATION

  1.
Financial Statements:

Unaudited Condensed Consolidated Statements of Income for the Three Months and Nine Months ended September 30, 2011 and 2010

Unaudited Condensed Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010

Unaudited Condensed Consolidated Statements of Cash Flows for the Nine Months ended September 30, 2011 and 2010

Unaudited Condensed Consolidated Statements of Common Shareholder’s Deficit and Noncontrolling Interest for the Nine Months ended September 30, 2011 and 2010

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.
(Removed and Reserved)

  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;
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;
our ownership by The AES Corporation (“AES”);
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 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. (“Midwest ISO”), 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 Income
*(In Thousands)*

	Three Months Ended,				Nine Months Ended,
	September 30,				September 30,
	2011		2010		2011		2010

UTILITY OPERATING REVENUES	$	320,550	$	305,675	$	889,658	$	868,759

UTILITY OPERATING EXPENSES:
Operation:
Fuel		90,719		85,396		253,474		241,644
Other operating expenses		50,467		49,791		151,999		147,422
Power purchased		25,107		15,888		65,446		42,005
Maintenance		30,078		25,686		91,476		80,642
Depreciation and amortization		42,089		41,476		124,417		123,205
Taxes other than income taxes		10,796		10,353		32,055		29,608
Income taxes - net		22,843		24,823		50,477		64,328
Total utility operating expenses		272,099		253,413		769,344		728,854
UTILITY OPERATING INCOME		48,451		52,262		120,314		139,905

OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used during construction		1,009		1,076		3,245		2,610
Loss on early extinguishment of debt		-		-		(15,378)		-
Miscellaneous income and (deductions) - net		(2,445)		(451)		9,812		(1,866)
Income tax benefit applicable to nonoperating income		6,270		6,539		19,748		19,365
Total other income and (deductions) - net		4,834		7,164		17,427		20,109

INTEREST AND OTHER CHARGES:
Interest on long-term debt		26,205		28,640		82,981		86,028
Other interest		446		538		1,339		1,596
Allowance for borrowed funds used during construction		(644)		(638)		(2,129)		(1,602)
Amortization of redemption premiums and expense on debt		1,158		1,044		3,466		3,129
Total interest and other charges - net		27,165		29,584		85,657		89,151
NET INCOME		26,120		29,842		52,084		70,863

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

NET INCOME APPLICABLE TO COMMON STOCK	$	25,317	$	29,039	$	49,674	$	68,453

See notes to unaudited condensed consolidated financial statements.


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

	September 30,		December 31,
	2011		2010
ASSETS
UTILITY PLANT:
Utility plant in service	$	4,168,241	$	4,096,883
Less accumulated depreciation		1,942,458		1,878,747
Utility plant in service - net		2,225,783		2,218,136
Construction work in progress		181,404		129,634
Spare parts inventory		15,333		12,737
Property held for future use		1,002		1,002
Utility plant - net		2,423,522		2,361,509

OTHER ASSETS:
Investment in long-term debt securities		40,000		41,669
Nonutility property - at cost, less accumulated depreciation		540		688
Other investments		4,949		6,419
Other assets - net		45,489		48,776

CURRENT ASSETS:
Cash and cash equivalents		50,274		31,796
Accounts receivable and unbilled revenue (less allowance for doubtful accounts of $2,672 and $2,218, respectively)		133,491		140,538
Fuel - at average cost		51,622		37,369
Materials and supplies - at average cost		51,797		51,524
Deferred tax asset - current		11,732		11,313
Regulatory assets		9,290		-
Prepayments and other current assets		17,126		18,366
Total current assets		325,332		290,906

DEFERRED DEBITS:
Regulatory assets		400,030		416,749
Miscellaneous		25,143		20,040
Total deferred debits		425,173		436,789
TOTAL	$	3,219,516	$	3,137,980


CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common shareholder’s deficit:
Paid in capital		11,362		10,811
Accumulated deficit		(22,501)		(15,344)
Accumulated other comprehensive loss		-		(197)
Total common shareholder’s deficit		(11,139)		(4,730)
Cumulative preferred stock of subsidiary		59,784		59,784
Long-term debt		1,787,607		1,332,353
Total capitalization		1,836,252		1,387,407

CURRENT LIABILITIES:
Short-term and current portion of long-term debt		50,000		425,000
Accounts payable		87,281		83,351
Accrued expenses		20,826		23,016
Accrued real estate and personal property taxes		21,378		16,812
Regulatory liabilities		13,593		8,862
Accrued income taxes		15,284		-
Accrued interest		42,571		31,180
Customer deposits		22,385		20,772
Other current liabilities		11,540		10,286
Total current liabilities		284,858		619,279

DEFERRED CREDITS AND OTHER LONG-TERM LIABILITIES:
Regulatory liabilities		535,767		516,992
Accumulated deferred income taxes - net		343,205		373,244
Non-current income tax liability		5,031		4,757
Unamortized investment tax credit		10,179		11,433
Accrued pension and other postretirement benefits		174,867		199,288
Miscellaneous		29,357		25,580
Total deferred credits and other long-term liabilities		1,098,406		1,131,294

COMMITMENTS AND CONTINGENCIES (Note 7)
TOTAL	$	3,219,516	$	3,137,980

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,
	2011		2010

CASH FLOWS FROM OPERATIONS:
Net income	$	52,084	$	70,863
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		125,232		122,067
Amortization of regulatory assets		3,881		5,568
Deferred income taxes and investment tax credit adjustments - net		(19,073)		(16,270)
Loss on early extinguishment of debt		15,378		-
Allowance for equity funds used during construction		(3,113)		(2,458)
Gain on sale of nonutility property		(13,354)		-
Change in certain assets and liabilities:
Accounts receivable		7,047		(7,034)
Fuel, materials and supplies		(14,526)		757
Income taxes receivable or payable		21,302		15,483
Financial transmission rights		(2.865)		(2,277)
Accounts payable and accrued expenses		9,537		17,013
Accrued real estate and personal property taxes		4,566		(2,436)
Accrued interest		12,889		16,066
Pension and other postretirement benefit expenses		(24,422)		(16,341)
Short-term and long-term regulatory assets and liabilities		(4,604)		(4,419)
Other - net		6,040		3,935
Net cash provided by operating activities		175,999		200,517

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures - utility		(165,686)		(94,877)
Proceeds from sales and maturities of short-term investments		2,000		-
Proceeds from sales of assets		13,467		-
Grants under the American Recovery and Reinvestment Act of 2009		6,644		-
Other		(11,704)		(3,348)
Net cash used in investing activities		(155,279)		(98,225)

CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt borrowings		121,000		9,508
Short-term debt repayments		(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		(56,831)		(60,300)
Preferred dividends of subsidiary		(2,410)		(2,410)
Deferred financing costs paid		(6,895)		-
Other		(592)		(309)
Net cash used in financing activities		(2,242)		(53,511)
Net change in cash and cash equivalents		18,478		48,781
Cash and cash equivalents at beginning of period		31,796		48,022
Cash and cash equivalents at end of period	$	50,274	$	96,803

Supplemental disclosures of cash flow information:

Cash paid during the period for:
Interest (net of amount capitalized)	$	70,801	$	69,538
Income taxes	$	28,500	$	45,750

See notes to unaudited condensed consolidated financial statements.

IPALCO ENTERPRISES, INC. and SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Common Shareholder’s Deficit

and Noncontrolling Interest

(In Thousands)

Paid in Capital Accumulated Deficit Accumulated Other Comprehensive Loss Total Common Shareholder's Deficit Cumulative Preferred Stock of Subsidiary

2010

Beginning Balance
$ 9,820 $ (18,878) $ - $ (9,058) $ 59,784

Comprehensive Income attributable to common stock:

Net income applicable to common stock
68,453 68,453

Unrealized loss on available for sale investment (net of income tax benefit of $128)
(188) (188)

Total Comprehensive Income attributable to common stock
68,265

Distributions to AES
(60,300) (60,300)

Contributions from AES
698 698

Balance at September 30, 2010
$ 10,518 $ (10,725) $ (188) $ (395) $ 59,784

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

Total Comprehensive Income attributable to common stock
49,871

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

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, 2010 (“2010 Form 10-K”) and should be read in conjunction therewith.

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.

New Accounting Pronouncements

Fair Value Measurement (Topic 820)

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update Topic 820 “Fair Value Measurement Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. Generally Accepted Accounting Principles and International Financial Reporting Standards.” The amendments in this update result in common fair value measurement and disclosure requirements under U.S. Generally Accepted Accounting Principles and International Financial Reporting Standards. Consequently, the amendments change the terminology used to describe many of the requirements under U.S. Generally Accepted Accounting Principles for measuring fair value and for disclosing information about fair value measurements. For many of the requirements, the FASB does not intend for the amendments in this update to result in a change in the application of the requirements in Topic 820. Some of the amendments clarify the FASB’s intent about the application of existing fair value measurement requirements. Other amendments change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. The amendments in this update are effective for IPALCO beginning January 1, 2012 and are currently not expected to have a material effect on IPALCO’s consolidated financial statements.

Comprehensive Income (Topic 220)

In June 2011, the FASB issued Accounting Standards Update Topic 220 “Presentation of Comprehensive Income.” Under the amendments in this update, an entity has the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The amendments in this update are effective for IPALCO beginning January 1, 2012 and are currently not expected to have a material effect on IPALCO’s consolidated financial statements.

3. REGULATORY MATTERS

Environmental Compliance Cost Recovery Adjustment

On July 7, 2011, the IURC approved IPL’s modification of its Certificate of Public Convenience and Necessity for the construction cost estimates of the Petersburg Unit 4 Flue Gas Desulfurization Enhancements project as set forth in Cause No. 42170 ECR 16 S1. The modification was an $8.1 million increase of the project budget to $128.0 million. The order also made final the IURC’s interim approval of IPL’s environmental compliance cost recovery adjustment.

Tree Trimming Practices Investigation

On July 7, 2011, the IURC issued an additional tree trimming order which did not provide the relief we were seeking, but clarified utility customer notice requirements and the relationship of the order to property rights and tariff requirements. It also clarified that in cases of emergency or public safety, utilities may, without customer consent, remove more than 25% of a tree or trim beyond existing easement or right of way boundaries to remedy the situation. The IURC is currently in the process of promulgating formal rules to implement the order. IPL and other interested parties are participating in this rulemaking process. It is not possible to predict the outcome of the rulemaking process, but this could significantly increase our vegetation management costs and the costs of defending our vegetation management program in litigation, which could have a material impact on our consolidated financial statements.

Wind Power Purchase Agreements

IPL is committed under a power purchase agreement to purchase approximately 100 MW of wind generated electricity through 2029 from a wind project in Indiana. IPL is also committed under another agreement to purchase approximately 200 MW of wind generated electricity per year for 20 years from a project in Minnesota, which began commercial operation in October, 2011. IPL generally has authority from the IURC to recover the costs for both of these agreements through an adjustment mechanism administered within IPL’s fuel adjustment clause.

FERC Order 1000

On July 21, 2011, the FERC issued Order No. 1000, the Final Rule on Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities (“Order 1000”), amending the transmission planning and cost allocation requirements established in Order No. 890. Through Order 1000, the FERC: (1) requires public utility transmission providers to participate in a regional transmission planning process and produce a regional transmission plan; (2) requires public utility transmission providers to amend their open access transmission tariffs to describe how public policy requirements will be considered in local and regional transmission planning processes; (3) removes the federal right of first refusal for certain transmission facilities; and (4) seeks to improve coordination between neighboring transmission planning regions for interregional facilities.

The Midwest ISO’s approved tariff in part already complies with Order 1000. However, Order 1000 will result in changes to transmission expansion costs charged to IPL by the Midwest ISO. Such changes relate to public policy requirements for transmission expansion within the Midwest ISO footprint, such as to comply with renewable mandates of other states within the footprint. These charges are difficult to estimate, but are expected to be material to IPL within a few years, however, it is probable, but not certain, that these costs will be recoverable, subject to IURC approval. Through September 30, 2011, IPL has deferred as a regulatory asset $2.3 million of Midwest ISO transmission expansion costs.

4. FAIR VALUE MEASUREMENTS

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, 2011 and December 31, 2010, our cash equivalents consisted of money market funds. The fair value of cash equivalents approximates their book value due to their short maturity, which was $9.8 million and $12.7 million as of September 30, 2011 and December 31, 2010, respectively.

Investment in Debt Securities

As of September 30, 2011 and December 31, 2010, our investment in debt securities consisted of available-for-sale debt securities of $40.0 million and $41.7 million, respectively. Auction rate securities with a recorded value of $1.7 million as of December 31, 2010 were liquidated during the first quarter of 2011 at their face amount of $2.0 million. Variable rate demand notes of $40.0 million at both periods consisted of the $40 Million City of Petersburg, Indiana, Pollution Control Refunding Revenue Bonds Adjustable Rate Tender Securities Series 1995B, Indianapolis Power & Light Company Project (“1995B Bonds”), which IPL owns and is also liable for both the interest and principal payments thereon. We have estimated the fair value of the 1995B Bonds based primarily upon qualitative factors, such as IPL’s credit worthiness, and concluded the fair value approximates their face value.

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 $22.4 million and $20.8 million as of September 30, 2011 and December 31, 2010, 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. 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 for the periods ending:

September 30, 2011 December 31, 2010

Face Value Fair Value Face Value Fair Value

(In Millions)

Fixed-rate
$ 1,712.7 $ 1,845.2 $ 1,632.7 $ 1,719.8

Variable-rate
130.0 130.0 130.0 130.0

Total indebtedness
$ 1,842.7 $ 1,975.2 $ 1,762.7 $ 1,849.8

The difference between the face value and the carrying value of this indebtedness represents unamortized discounts of $5.0 million and $5.3 million at September 30, 2011 and December 31, 2010, respectively.

Fair Value Hierarchy

FASB 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. IPALCO had one financial asset measured at fair value on a nonrecurring basis, which has been adjusted to fair value during the periods covered by this report due to impairment losses. For the nine months ended September 30, 2011 and 2010, we recorded impairments on this nonutility investment of $1.6 million and $1.2 million, respectively, 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.

In accordance with ASC 820, we have categorized our financial assets and liabilities that are adjusted to fair value, based on the priority of the inputs to the valuation technique, following the three-level fair value hierarchy prescribed by ASC 820, as follows:

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

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

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

As of September 30, 2011 and December 31, 2010, all (excluding pension assets - see Note 5, “Pension and Other Postretirement Benefits”) of IPALCO’s financial assets or liabilities measured at fair value on a recurring basis were considered Level 3, based on the fair value hierarchy. The following table presents those financial assets and liabilities:

Fair Value Measurements Using Level 3 at

September 30, 2011 December 31, 2010

(In Thousands)

Financial assets:

Investments in debt securities
$ 40,000 $ 41,669

Financial transmission rights
5,023 2,158

Total financial assets measured at fair value
$ 45,023 $ 43,827

Financial liabilities:

Interest rate swap ⁽¹⁾
$ 13,606 $ 9,426

Other derivative liabilities
177 193

Total financial liabilities measured at fair value
$ 13,783 $ 9,619

⁽¹⁾ Increase is primarily due to valuation adjustments due to lower market interest rates.

The following tables present a reconciliation of financial instruments classified as Level 3 in the fair value hierarchy for the three and nine months ended September 30, 2011:


	Three Months Ended September 30, 2011
	Derivative Financial Instruments, net Asset (Liability)		Investments in Debt Securities		Total
	*(In Thousands)*
Balance at July 1, 2011	$	(2,118)	$	40,000	$	37,882
Unrealized gain recognized in earnings		24		-		24
Unrealized loss recognized as a regulatory liability		(3,062)		-		(3,062)
Unrealized loss recognized as a regulatory asset		(4,085)		-		(4,085)
Settlements		481		-		481
Balance at September 30, 2011	$	(8,760)	$	40,000	$	31,240


	Nine Months Ended September 30, 2011
	Derivative Financial Instruments, net Asset (Liability)		Investments in Debt Securities		Total
	*(In Thousands)*
Balance at January 1, 2011	$	(7,461)	$	41,669	$	34,208
Unrealized gain recognized in Other Comprehensive Income		-		331		331
Unrealized gain recognized in earnings		43		-		43
Unrealized loss recognized as a regulatory liability		(5,220)		-		(5,220)
Unrealized loss recognized as a regulatory asset		(5,679)		-		(5,679)
Issuances		8,085		-		8,085
Settlements		1,472		(2,000)		(528)
Balance at September 30, 2011	$	(8,760)	$	40,000	$	31,240

5. INDEBTEDNESS

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. These notes will be exchanged for new notes with identical terms and like principal amounts, which are registered with the Securities and Exchange Commission pursuant to a registration statement on Form S-4 declared effective in November 2011. 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 in the second quarter of 2011. A portion of 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 the Company’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 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.

6. PENSION AND OTHER POSTRETIREMENT BENEFITS

The following tables 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”), which are combined and shown as Pension Benefits. The following tables also present information relating to Other Postretirement Benefits:

Pension Benefits Other Postretirement Benefits

(In Thousands)

Net funded status of plans:

Net funded status at December 31, 2010, before tax adjustments
$ (194,797) $ (4,991)

Net benefit cost components reflected in net funded status during first quarter:

Service cost
(1,809) (94)

Interest cost
(7,957) (65)

Expected return on assets
8,042 -

Employer contributions during quarter
5,646 12

Net funded status at March 31, 2011, before tax adjustments
$ (190,875) $ (5,138)

Net benefit cost components reflected in net funded status during second quarter:

Service cost
(1,808) (95)

Interest cost
(7,957) (65)

Expected return on assets
8,042 -

Employer contributions during quarter
7,400 89

Net funded status at June 30, 2011, before tax adjustments
$ (185,198) $ (5,209)

Net benefit cost components reflected in net funded status during third quarter:

Service cost
(1,809) (95)

Interest cost
(7,957) (64)

Expected return on assets
8,042 -

Employer contributions during quarter
16,900 20

Net funded status at September 30, 2011, before tax adjustments
$ (170,022) $ (5,348)

Regulatory assets (liabilities) related to pensions ⁽¹⁾⁽²⁾:

Regulatory assets (liabilities) at December 31, 2010, before tax adjustments
$ 242,941 $ (7,570)

Amount reclassified through net benefit cost:

Amortization of prior service credit/(cost)
(1,086) 79

Amortization of net actuarial gain/(loss)
(3,326) 42

Regulatory assets (liabilities) at March 31, 2011, before tax adjustments
$ 238,529 $ (7,449)

Amount reclassified through net benefit cost:

Amortization of prior service credit/(cost)
(1,087) 78

Amortization of net actuarial gain/(loss)
(3,327) 43

Regulatory assets (liabilities) at June 30, 2011, before tax adjustments
$ 234,115 $ (7,328)

Amount reclassified through net benefit cost:

Amortization of prior service credit/(cost)
(1,086) 79

Amortization of net actuarial gain/(loss)
(3,326) 43

Regulatory assets (liabilities) at September 30, 2011, before tax adjustments
$ 229,703 $ (7,206)

⁽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.

⁽²⁾The regulatory liability related to Other Postretirement Benefits is netted against the regulatory assets related to Pension Benefits on the accompanying Unaudited Condensed Consolidated Balance Sheets.

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,
	2011		2010		2011		2010
	*(In Thousands)*
Components of net periodic benefit cost:
Service cost	$	1,809	$	1,648	$	5,426	$	4,942
Interest cost		7,957		7,892		23,871		23,685
Expected return on plan assets		(8,042)		(7,311)		(24,126)		(21,939)
Settlement loss recognized ⁽¹⁾		-		-		-		204
Amortization of prior service cost		1,086		869		3,259		2,607
Amortization of actuarial loss		3,326		2,959		9,979		8,879
Net periodic benefit cost		6,136		6,057	$	18,409	$	18,378

⁽¹⁾ Includes $204,000 settlement loss as a result of a lump sum distribution paid out of the Supplemental Pension Plan for the nine months ended September 30, 2010.

Other Postretirement Employee Benefits and Expense

The following table presents Net Periodic Benefit Cost information relating to other postretirement benefits:


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2011		2010		2011		2010
	*(In Thousands)*
Components of net periodic benefit cost:
Service cost	$	95	$	87	$	284	$	260
Interest cost		64		70		194		212
Amortization of prior service credit		(79)		(78)		(236)		(233)
Amortization of actuarial gain		(43)		(44)		(128)		(132)
Net periodic benefit cost	$	37	$	35	$	114	$	107

7. COMMITMENTS AND CONTINGENCIES

Legal Loss Contingencies

IPL is a defendant in approximately fifty 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, approximately 40 cases were dropped by plaintiffs in 2010 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.

IPL has been, and will continue to be, subject to routine audits with respect to its compliance with applicable reliability standards. In March 2010, one of the FERC-certified reliability organizations responsible for developing and maintaining reliability standards, ReliabilityFirst Corporation (“RFC”), conducted a compliance audit of IPL’s operations. In July 2010, RFC issued a Compliance Audit Report to IPL in which it alleged certain Possible Violations of reliability standards. IPL entered into a Settlement Agreement with RFC, which has been approved by both NERC and FERC, and agreed to a $70,000 settlement payment pursuant to the terms of the Settlement Agreement. IPL is in the process of implementing mitigation plans for each of the alleged violations, also pursuant to the terms of the Settlement Agreement.

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.

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 (“NOV”) and Finding of Violation from the U.S. Environmental Protection Agency (“EPA”) pursuant to the U.S. 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 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.

Contractual Contingency

Under IPL’s $40 million interest rate hedge agreement, an event of default by either party, including, but not limited to, insolvency of either IPL, the counterparty, or the insurer of the hedge (Ambac Assurance Corporation), could result in the termination of the agreement and the payment of settlement amounts, as defined in the agreement, between the parties. No such conditions presently exist. The fair value of this hedge as of September 30, 2011 and December 31, 2010 was a liability to IPL of approximately $13.6 million and $9.4 million, respectively.

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 included in Other Investments on the accompanying Unaudited Condensed Consolidated Balance Sheets at December 31, 2010. 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. INCOME TAXES

On May 10, 2011, the State of Indiana enacted House Bill 1004, which phases in over four years a 2% reduction to the state corporate income tax rate. While the statutory state income tax rate remains at 8.5% for 2011, the deferred tax balances were adjusted in the second quarter of 2011 according to the anticipated reversal of temporary differences. The change in required deferred taxes on plant and plant-related temporary differences resulted in a reduction of the associated regulatory asset of $11.2 million. The change in required deferred taxes on non-property related temporary differences which are not probable to cause a reduction in future base customer rates resulted in a tax benefit of $1.1 million.

IPALCO’s effective combined state and federal income tax rate was 38.2% for the nine months ended September 30, 2011 as compared to 39.6% for the nine months ended September 30, 2010. The rate decrease was primarily the result of the $1.1 million state income tax benefit described above. IPALCO’s effective combined state and federal income tax rate was 39.6% for the three months ended September 30, 2011 as compared to 38.6% for the three months ended September 30, 2010. The rate increase was primarily due to a favorable adjustment to the tax reserve recorded in the third quarter of 2010.

10. 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 IPALCO Notes; approximately $24.3 million and $8.5 million of nonutility cash and cash equivalents, as of September 30, 2011 and December 31, 2010, respectively; long-term nonutility investments of $4.6 million and $6.2 million at September 30, 2011 and December 31, 2010, respectively; and income taxes and interest related to those items. Nonutility assets represented approximately 1% of IPALCO’s total assets as of September 30, 2011 and December 31, 2010. Net income for the utility segment was $88.5 million and $100.3 million for the nine month periods ended September 30, 2011 and 2010, respectively, and $34.8 million and $39.5 million for the three month periods ended September 30, 2011 and 2010, 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:

1995B Bonds	$40 Million City of Petersburg, Indiana, Pollution Control Refunding Revenue Bonds Adjustable Rate Tender Securities Series 1995B, Indianapolis Power & Light Company Project
2010 Form 10-K	IPALCO’s Annual Report on Form 10-K for the year ended December 31, 2010
2011 IPALCO Notes	$375 million of 8.625% (original coupon 7.625%) Senior Secured Notes due November 14, 2011
2018 IPALCO Notes	$400 million Aggregate Principal Amount of 5.00% Senior Secured Notes due 2018
AES	The AES Corporation
ASC	Financial Accounting Standards Board Accounting Standards Codification
BTA	Best Technology Available
CAA	U.S. Clean Air Act
CPCN	Certificate of Public Convenience and Necessity
CSAPR	U.S. Cross-State Air Pollution Rule
CWA	U.S. Clean Water Act
EPA	U.S. Environmental Protection Agency
FASB	Financial Accounting Standards Board
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
IFA	Indiana Finance Authority
IPALCO	IPALCO Enterprises, Inc.
IPL	Indianapolis Power & Light Company
IURC	Indiana Utility Regulatory Commission
kWh	Kilowatt hours
MW	Megawatt
MACT	Maximum Achievable Control Technology
Midwest ISO	Midwest Independent Transmission System Operator, Inc.
NOV	Notice of Violation
Order 1000	Federal Energy Regulatory Commission Final Rule on Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities
Pension Plans	Employees’ Retirement Plan of Indianapolis Power & Light Company and Supplemental Retirement Plan of Indianapolis Power & Light Company
RFC	ReliabilityFirst Corporation

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.

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, 2011 and three months ended September 30, 2010

Utility Operating Revenues

Utility operating revenues during the three months ended September 31, 2011 increased by $14.9 million compared to the same period in 2010, which resulted from the following changes (dollars in thousands):

Three Months Ended September 30, Change Percentage Change

2011 2010

Utility Operating Revenues:

Retail Revenues $ 307,011 $ 292,741 $ 14,270 4.9%

Wholesale Revenues 5,560 8,021 (2,461) (30.7)%

Miscellaneous Revenues 7,979 4,913 3,066 62.4%

Total Utility Operating Revenues $ 320,550 $ 305,675 $ 14,875 4.9%

Heating Degree Days:

Actual 82 19 63 331.6%

30-year Average 81 81

Cooling Degree Days:

Actual 1,034 1,082 (48) (4.4)%

30-year Average 725 725

The $14.3 million increase in retail revenues was primarily due to a 6.5% increase in the weighted average price per kilowatt hours (“kWh”) sold ($17.7 million), partially offset by a 1.5% decrease in the volume of kWh sold ($3.4 million). The $17.7 million increase in the weighted average price of kWh sold was primarily due to a $16.5 million increase in fuel revenues. We believe the $3.4 million decrease in the volume of electricity sold was primarily due to the milder temperatures in our service territory in 2011 (as demonstrated by the 4% decrease in cooling degree days), as well as local economic conditions. The $2.5 million decrease in wholesale revenues was primarily due to a 26.0% decrease in the quantity of kWh sold ($2.1 million), which was primarily due to an increase in unscheduled outages and major generating unit overhauls. The $3.1 million increase in miscellaneous revenues was primarily due to increases in pole attachment rental revenues of $1.6 million and MISO transmission revenues of $1.3 million, both resulting primarily from changes in the estimated revenue accruals related to prior periods.

Utility Operating Expenses

The following table illustrates our primary operating expense changes from the three months ended September 30, 2010 to the three months ended September 30, 2011 (in millions):

Operating expenses for the three months ended September 30, 2010 $ 253.4

Increase in purchased power costs 9.2

Increase in fuel 5.3

Increase in maintenance costs 4.4

Decrease in income taxes - net (2.0)

Other miscellaneous variances - individually immaterial 1.8

Operating expenses for the three months ended September 30, 2011 $ 272.1

The $9.2 million increase in purchased power costs was primarily due to a 189% increase in the volume of power purchased during the period ($18.3 million), primarily due to an increase in unscheduled outages and major generating unit overhauls. This increase was partially offset by a 25% decrease in the market price of power purchased ($8.8 million).

The $5.3 million increase in fuel costs was primarily due to a 9% increase in the price per ton of coal we consumed during the comparable periods ($6.9 million) and a $5.5 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. These increases were partially offset by an $8.1 million decrease in the quantity of fuel consumed due primarily to a decrease in total electricity sales volume in the comparable periods.

Maintenance expenses for the three months ended September 30, 2011 increased $4.4 million or 17.1% compared to the same period in 2010 due to an increase in major generating unit overhauls. We expect maintenance expenses to continue to be higher through the end of 2011 and in 2013 as we continue to perform major generating unit overhauls and implement a plan to increase the level of maintenance activities on our five largest coal fired generating units to correct reliability problems encountered in the past two years as described in our 2010 Form 10-K under “Operating Excellence” included in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The $2.0 million decrease in income taxes - net was primarily due to a decrease in pretax net operating income for the reasons previously described. IPALCO’s effective combined state and federal income tax rates were 39.6% for the three months ended September 30, 2011 as compared to 38.6% for the three months ended September 30, 2010 (as discussed in Note 9, “Income Taxes” to the Financial Statements).

Other Income and Deductions

Other income and deductions decreased $2.3 million for the three months ended September 30, 2011 as compared to the same period in 2010. This decrease is primarily due to an impairment recorded on a minority ownership investment of $1.6 million in August 2011.

Interest and Other Charges

Interest and other charges decreased $2.4 million during 2011 primarily due to lower interest on long-term debt due to the refinancing of $375 million of 8.625% 2011 IPALCO Notes with $400 million of 5.00% 2018 IPALCO Notes in May of 2011.

Comparison of nine months ended September 30, 2011 and nine months ended September 30, 2010

Utility Operating Revenues

Utility operating revenues during the nine months ended September 30, 2011 increased by $20.9 million compared to the same period in 2010, which resulted from the following changes (dollars in thousands):

Nine Months Ended September 30, Change Percentage Change

2011 2010

Utility Operating Revenues:

Retail Revenues $ 837,767 $ 803,556 $ 34,211 4.3%

Wholesale Revenues 34,149 51,598 (17,449) (33.8)%

Miscellaneous Revenues 17,742 13,605 4,137 30.4%

Total Utility Operating Revenues $ 889,658 $ 868,759 $ 20,899 2.4%

Heating Degree Days:

Actual 3,296 3,216 80 2.5%

30-year Average 3,505 3,505

Cooling Degree Days:

Actual 1,466 1,593 (127) (8.0)%

30-year Average 1,027 1,027

The increase in retail revenues was due to a 6.9% increase in the weighted average price per kWh sold ($51.2 million), partially offset by a 1.9% decrease in the volume of kWh sold ($12.0 million) and a nonrecurring charge against retail revenues related to prior periods ($5.0 million). The $51.2 million increase in the weighted average price of kWh sold was primarily due to a $44.8 million increase in fuel revenues. We believe the $12.0 million decrease in the volume of electricity sold was primarily due to milder temperatures in our service territory in 2011 (as demonstrated by the 8.0% decrease in cooling degree days), as well as local economic conditions. The $17.4 million decrease in wholesale revenues was primarily due to a 32.3% decrease in the quantity of kWh sold ($16.7 million), which was primarily due to an increase in unscheduled outages and major generating unit overhauls. The $4.1 million increase in miscellaneous revenues was primarily due to increases in MISO transmission revenues of $1.6 million and pole attachment rental revenues of $1.6 million, both resulting primarily from changes in the estimated revenue accruals related to prior periods.

Utility Operating Expenses

The following table illustrates our primary operating expense changes from the nine months ended September 30, 2010 to the nine months ended September 30, 2011 (in millions):

Operating expenses for the nine months ended September 30, 2010 $ 728.9

Increase in purchased power costs 23.4

Increase in fuel costs 11.8

Increase in maintenance expenses 10.8

Increase in other operating expenses 4.6

Decrease in income taxes - net (13.9)

Other miscellaneous variances - individually immaterial 3.7

Operating expenses for the nine months ended September 30, 2011 $ 769.3

The $23.4 million increase in purchased power costs was primarily due to a 143% increase in the volume of power purchased during the period ($35.0 million), primarily due to an increase in unscheduled outages and major generating unit overhauls. This increase was partially offset by a 12% decrease in the market price of power purchased during the period ($11.3 million).

The $11.8 million increase in fuel costs is primarily due to (i) a 15% increase in the price per ton of coal we consumed during the comparable periods ($31.7 million); (ii) increases in the price of oil and gas consumed ($2.5 million); and (iii) a $1.7 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. These increases were partially offset by a $23.9 million decrease in the quantity of fuel consumed due primarily to a decrease in total electricity sales volume in the comparable periods.

Maintenance expenses for the nine months ended September 30, 2011 increased $10.8 million or 13.4% compared to the same period in 2010 primarily due to an increase in major generating unit overhauls. We expect maintenance expenses to continue to be higher through the end of 2011 and in 2013 as we continue to perform major generating unit overhauls and implement a plan to increase the level of maintenance activities on our five largest coal fired generating units to correct reliability problems encountered in the past two years as described in our 2010 Form 10-K under “Operating Excellence” included in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Other operating expenses for the nine months ended September 30, 2011 increased $4.6 million or 3.1% compared to the same period in 2010 primarily due to an increase of $3.2 million in expenses on demand side management programs versus the comparable period. These expenses are recoverable through retail rates, and are offset by an increase in retail revenues for demand side management programs.

The $13.9 million decrease in income taxes - net was primarily due to a decrease in pretax net operating income for the reasons previously described and, to a lesser extent, the benefit recorded related to the gradual decreases in enacted Indiana tax rates from 8.5% to 6.5% beginning July 1, 2012 through July 1, 2015 which are not probable to cause a reduction in future base customer rates. IPALCO’s effective combined state and federal income tax rates were 38.2% for the nine months ended September 30, 2011 as compared to 39.6% for the nine months ended September 30, 2010 (as discussed in Note 9, “Income Taxes” to the Financial Statements).

Other Income and Deductions

Other income and deductions decreased $2.7 million for the nine months ended September 30, 2011 as compared to the same period in 2010. This decrease is primarily due to (i) a $15.4 million loss on early extinguishment of debt related to the repurchase of the 2011 IPALCO Notes, including a $14.4 million early tender premium and (ii) $0.4 million of higher impairment recorded on a minority ownership investment compared to the same period in 2010. These decreases were partially offset by (i) a $13.3 million gain on sale of our Oatsville coal reserve (as discussed in Note 8, “Sale of Oatsville Coal Reserve” to the Financial Statements) and (ii) a $0.6 million increase in the allowance for equity funds used during construction as a result of increased construction activity.

Interest and Other Charges

Interest and other charges decreased $3.5 million during 2011 primarily due to (i) lower interest on long-term debt of $3.0 million due to the refinancing of $375 million of 8.625% 2011 IPALCO Notes with $400 million of 5.00% 2018 IPALCO Notes in May of 2011 and (ii) a $0.5 million increase in the allowance for borrowed funds used during construction as a result of increased construction activity.

LIQUIDITY AND CAPITAL RESOURCES

As of September 30, 2011, we had unrestricted cash and cash equivalents of $50.3 million. As of September 30, 2011, we also had available borrowing capacity of $209.3 million under our $250.0 million committed revolving credit facilities after outstanding borrowings, existing letters of credit and liquidity support for the 1995B Bonds. All of IPL’s long-term borrowings must first be approved by the IURC and the aggregate amount of IPL’s short-term indebtedness must be approved by the FERC. We have approval from FERC to borrow up to $500 million of short-term indebtedness outstanding at any time through July 27, 2012. As of September 30, 2011, we also have remaining authority from the IURC through December 31, 2013 to, among other things, issue up to $145 million of additional long-term debt and refinance up to $237.4 million in existing indebtedness, 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 currently 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 facilities 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 facilities; and (iv) additional debt financing. In addition, due to the uncertainty of future environmental regulations (see “Environmental Matters”), it is possible, but not certain, that equity capital may also be used as a funding source.

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 improve overall performance. Our capital expenditures totaled $165.7 million and $94.9 million for the nine months ended September 30, 2011 and 2010, respectively. Construction expenditures during the first nine months of 2011 and 2010 were financed primarily 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, and federal grants for IPL’s Smart Energy Projects.

Our capital expenditure program, including development and permitting costs, for the three year period 2011-2013 is currently estimated to cost approximately $489 million, including amounts already spent in the first nine months of 2011. It includes approximately $184 million for additions, improvements and extensions to transmission and distribution lines, substations, power factor and voltage regulating equipment, distribution transformers and street lighting facilities. The capital expenditure program also includes approximately $244 million for power plant related projects (including $64 million for construction projects designed to reduce sulfur dioxide); $31 million for IPL’s Smart Energy Projects; and $30 million for other miscellaneous equipment. The majority of the expenditures for construction projects designed to reduce sulfur dioxide and mercury emissions are recoverable through jurisdictional retail rate revenue through our ECCRA filings, subject to regulatory approval. These estimates do not include any additional amounts we may be required to spend in connection with resolution of the NOV described in “Environmental Matters” and, due to the uncertainty of future environmental regulations, they also do not include any costs related to compliance with other potential future regulations such as those described in “Environmental Matters” nor any costs for new generation that might be required when existing units are retired.

Contractual Cash Obligations

The 2010 Form 10-K contains a table, which details our contractual cash obligations. Significant changes to our contractual cash obligations since December 31, 2010 include the addition of $400 million of 5.00% Senior Secured Notes due 2018 and the removal of $375 million due 2011 for the 2011 IPALCO Notes. See “Liquidity and Capital Resources - IPALCO’s Senior Secured Notes” above for further details. Interest and long-term debt obligations as of September 30, 2011, including a correction to interest expense from how it was presented in the 2010 Form 10-K, is as follows:

Payment due

Total Less Than 1 Year 1-3 Years 3-5 Years More Than 5 Years

Long-term debt $ 1,792.7 $ 0.0 $ 110.0 $ 171.9 $ 1,510.8

Interest obligations ⁽¹⁾ $ 1,192.6 $ 103.5 $ 202.1 $ 191.3 $ 695.7

⁽¹⁾ Represents interest payment obligations related to fixed and variable rate debt. Interest related to variable rate debt is calculated using the rate in effect at September 30, 2011.

Common Stock Dividends

All of IPALCO’s outstanding common stock is owned by AES. During the first nine months of 2011 and 2010, we paid $56.8 million and $60.3 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 $29.9 million and $23.1 million to the Pension Plans during the first nine months of 2011 and 2010, 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 consideration of targeted funding levels necessary to meet certain thresholds. Management does not currently expect any of the pension assets to be returned to IPL during 2011.

Regulatory Matters

Environmental Compliance Cost Recovery Adjustment

Tree Trimming Practices Investigation

Wind Power Purchase Agreements

FERC Order 1000

On July 21, 2011, the FERC issued Order 1000, amending the transmission planning and cost allocation requirements established in Order No. 890. Through Order 1000, the FERC: (1) requires public utility transmission providers to participate in a regional transmission planning process and produce a regional transmission plan; (2) requires public utility transmission providers to amend their open access transmission tariffs to describe how public policy requirements will be considered in local and regional transmission planning processes; (3) removes the federal right of first refusal for certain transmission facilities; and (4) seeks to improve coordination between neighboring transmission planning regions for interregional facilities.

Environmental Matters

TThe combination of existing and expected environmental regulations make it likely that we will 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 expected regulations, and collectively make 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 includes building new units, purchasing existing units, joint ownership of generating units, purchasing electricity in the wholesale market, or some combination of these options. There is currently an excess of capacity in the MISO footprint. While this excess has been projected to remain for several years, MISO is currently reviewing their assessment. Our decision on which replacement options to pursue will be impacted by EPA’s final Utility Maximum Achievable Control Technology (“MACT”) rule, which is expected to be released in the fourth quarter of 2011, 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.

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

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

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 2010 Form 10-K.

New Source Review

In October 2009, IPL received an 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 dating back to 1986. The alleged violations primarily pertain to the prevention of significant deterioration 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.

Cross-State Air Pollution Rule (formerly known as Clean Air Interstate Rule)

On July 6, 2011, the EPA announced a new rule that will require the further reduction of SO2 and NOx emissions from power plants in 27 states, including Indiana, that contribute to ozone and/or fine particle pollution in other states. This rule replaces the Clean Air Interstate Rule that was remanded by the D.C. Circuit Court of Appeals in 2008. This rule, which was formerly identified in proposed regulations as the “Clean Air Transport Rule” and is now known as the U.S. Cross-State Air Pollution Rule (“CSAPR”), requires initial compliance by January 1, 2012 for SO2 and annual NOx reductions, and May 1, 2012 for ozone season reductions. If fully implemented in January 2014, the rule would require SO2 emission reductions of 73% and NOx reductions of 54% from 2005 levels. The new CSAPR was published in the Federal Register on August 8, 2011. Currently, IPL plans to operate previously-installed pollution control equipment, use low-sulfur coal, and purchase allowances when necessary to comply with CSAPR. SO2 and NOx allowance prices are currently expected to be significantly higher for the next few years. Because SO2 allowances are not recoverable, our allowance expense could be material if we need to purchase them. We are unable to predict whether or not we will need to purchase allowances as this will be significantly impacted by energy demand, wholesale prices and generating unit reliability. This rule also has the effect of increasing our costs to produce electricity, which will have a negative impact on our wholesale sales volumes and margins.

Clean Air Act and Hazardous Air Pollutants

As noted in our 2010 Form 10-K, as a result of prior EPA determinations and a D.C. Circuit Court ruling, the EPA is obligated under Section 112 of the CAA to develop a rule requiring pollution controls for hazardous air pollutants, including mercury, hydrogen chloride, hydrogen fluoride, and nickel species from coal and oil-fired power plants. Section 112 of the CAA requires that the rule establish MACT standards for each pollutant regulated under the rule. MACT is defined as the emission limitation achieved by the “best performing 12%” of sources in the source category. The EPA entered into a consent decree under which it is obligated to finalize the rule in the fourth quarter of 2011.

The EPA announced a proposed rule in March 2011 that was published in the Federal Register on May 3, 2011 and, if adopted, would establish national emissions standards for hazardous air pollutants from coal- and oil-fired electric utility steam generating units. The rule, as currently proposed, may require all coal-fired power plants to install acid gas control technology, upgrade particulate control devices and/or install some other type of mercury control technology, such as sorbent injection. The rule may also require installation of new emission monitoring equipment and/or implementation of additional monitoring methodologies. The EPA is reviewing public comments on the proposed rule, and such public comments will be considered by the EPA prior to promulgating a final rule.

Most of IPL’s coal-fired capacity has acid gas scrubbers or comparable control technologies, but as proposed there are other improvements to such control technologies that may be needed at some of our generators. Under the CAA, compliance is required within three years of the effective date of the rule; 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 determination by the President (for up to two additional years). At this time, we cannot predict the extent of the final regulations for hazardous air pollutants, but the cost of compliance with any such regulations could be material. 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.

National Ambient Air Quality Standards

In September 2009, the EPA announced it would reconsider the 2008 ozone National Ambient Air Quality Standards (“NAAQS”). In January 2010, the EPA proposed a rule that would significantly reduce both the primary and secondary NAAQS for ozone. The proposed rule would have established a primary standard at a level within the range of 0.060 to 0.070 parts per million (“ppm”) and a cumulative, seasonal secondary standard at a level within the range of 7 to 15 ppm-hours. In September 2011, President Obama withdrew the EPA’s proposed final rule to alter the 2008 ozone NAAQS. One of the reasons cited by the President in his decision to withdraw the standard was that the CAA required reconsideration of NAAQS every five years, and the ozone NAAQS will be reconsidered as required by the CAA in 2013. As a result, states will begin implementing the 0.075 parts per million daily ambient ozone standard. All counties in which we operate currently meet the 0.075 daily ambient ozone standard.

In addition to possible promulgation of new ozone standards, in December 2010, the EPA published a proposed rule that would rescind the EPA’s earlier interpretation of reasonable further progress (“RFP”) requirements for the 1997 eight-hour ozone NAAQS. It is not clear whether this rule was impacted by the President’s decision to withdraw the ozone NAAQS. If the rule is finalized, states that relied on emissions reductions from sources outside of a nonattainment area to meet RFP requirements would have to submit new RFP demonstrations. This rulemaking could impact several states’ attainment determinations. If Indiana determines that certain areas are in “nonattainment” of the NAAQS, Indiana would be required to develop a plan to reach “attainment” status, which may include requiring our generating facilities to accept limits to reduce our emissions.

Cooling Water Intake Regulations

We use water as a coolant at our generating facilities. Under the federal Clean Water Act (“CWA”), cooling water intake structures are required to reflect the Best Technology Available (“BTA”) for minimizing adverse environmental impact. In March 2011, the EPA announced its proposal for standards to protect fish and other aquatic organisms drawn into cooling water systems at large power plants and other industrial facilities. The proposal was published in the Federal Register in April 2011. The proposal, based on Section 316(b) of the CWA establishes BTA requirements regarding impingement mortality for all existing facilities that withdraw water from a source water body above a minimum volume and utilize at least 25% of the withdrawn water for cooling purposes. IPL believes in order to meet these BTA requirements, all cooling water intake structures associated with once through cooling processes will need to modify the existing traveling screens and add a fish return and handling system for each cooling system. The proposal would also require owners of facilities that withdraw very large amounts of water to perform comprehensive site-specific studies during the permitting process and/or may require closed-cycle cooling systems (closed-cycle cooling towers), or other technology. The proposal also establishes a public process, with opportunity for public input, by which the appropriate technology to reduce entrainment mortality would be implemented at each facility after considering site-specific factors. Under a consent decree filed in the U.S. District Court for the Southern District of New York, the EPA is required to issue a final rule by July 27, 2012. It is not possible to predict the total impacts of the final rule at this time, but if additional capital expenditures are necessary, they could be material. IPL would seek recovery of these capital expenditures; however, there is no guarantee we would be successful in that regard.

Senate Bill 251

In May 2011 Senate Bill 251 became a law in the State of Indiana. Senate Bill 251 is a comprehensive Bill which, among other things, provides Indiana utilities with a means for recovering 80% of costs incurred to comply with federal mandates through a periodic retail rate adjustment mechanism. This includes costs to comply with regulations from EPA, FERC, NERC, Department of Energy, etc., including capital intensive requirements and/or proposals described herein and in the IPALCO 2010 Form 10-K, such as cooling water intake regulations, waste management and coal combustion byproducts, wastewater effluent, MISO transmission expansion costs and polychlorinated biphenyls. It does not change existing legislation that allows for 100% recovery of clean coal technology designed to reduce air pollutants (Senate Bill 29).

Some of the most important features of Senate Bill 251 to IPL are as follows: Any energy utility in Indiana seeking to recover federally mandated costs incurred in connection with a compliance project shall apply to the IURC for a certificate of public convenience and necessity (“CPCN”) for the compliance project. It sets forth certain factors that the IURC must consider in determining whether to grant a CPCN. It further specifies that if the IURC approves a proposed compliance project and the projected federally mandated costs associated with the project, the following apply: (i) 80% of the approved costs shall be recovered by the energy utility through a periodic retail rate adjustment mechanism, (ii) 20% of the approved costs shall be deferred and recovered by the energy utility as part of the next general rate case filed by the energy utility with the IURC, and (iii) actual costs exceeding the projected federally mandated costs of the approved compliance project by more than 25% shall require specific justification and approval before being authorized in the energy utility's next general rate case. Senate Bill 251 also requires the IURC to adopt rules to establish a voluntary clean energy portfolio standard program. Such program will provide incentives to participating electricity suppliers to obtain specified percentages of electricity from clean energy sources in accordance with clean portfolio standard goals, including requiring at least 50% of the clean energy to originate from Indiana suppliers. The goals can also be met by purchasing clean energy credits.

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 15-d-15 (e) as required by paragraph (b) of the Exchange Act Rules 13a-15 or 15d-15) as of September 30, 2011. 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, 2011, 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, 2011 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 “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity And Capital Resources - Environmental Matters,” and Note 7, “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, 2010.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. (REMOVED AND RESERVED)

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS


Exhibit No.	Document
4.1^*	Fifty-Eighth Supplemental Indenture dated as of August 1, 2011.
4.2^*	Fifty-Ninth Supplemental Indenture dated as of August 1, 2011.
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).

^* Incorporated by reference to IPALCO’s Registration Statement on Form S-4 filed with the Securities and Exchange Commission on October 11, 2011.

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 3, 2011	/s/ Kelly M. Huntington
		Kelly M. Huntington
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer and Duly Authorized Officer)



Date:	November 3, 2011	/s/ Kurt A. Tornquist
		Kurt A. Tornquist
		Vice President and Controller
		(Principal Accounting Officer)


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


TABLE OF CONTENTS

Item No.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

PART I - FINANCIAL INFORMATION
	1.	Financial Statements:
		Unaudited Condensed Consolidated Statements of Income for the Three Months and Nine Months ended September 30, 2011 and 2010
		Unaudited Condensed Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010
		Unaudited Condensed Consolidated Statements of Cash Flows for the Nine Months ended September 30, 2011 and 2010
		Unaudited Condensed Consolidated Statements of Common Shareholder’s Deficit and Noncontrolling Interest for the Nine Months ended September 30, 2011 and 2010
		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.	(Removed and Reserved)
	5.	Other Information
	6.	Exhibits

SIGNATURES


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

	Paid in Capital		Accumulated Deficit		Accumulated Other Comprehensive Loss		Total Common Shareholder's Deficit			Cumulative Preferred Stock of Subsidiary
2010
Beginning Balance	$	9,820	$	(18,878)	$	-	$	(9,058)	$	59,784
Comprehensive Income attributable to common stock:
Net income applicable to common stock				68,453				68,453
Unrealized loss on available for sale investment (net of income tax benefit of $128)						(188)		(188)
Total Comprehensive Income attributable to common stock								68,265

Distributions to AES				(60,300)				(60,300)
Contributions from AES		698						698
Balance at September 30, 2010	$	10,518	$	(10,725)	$	(188)	$	(395)	$	59,784

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
Total Comprehensive Income attributable to common stock								49,871

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


See notes to unaudited condensed consolidated financial statements.


	September 30, 2011				December 31, 2010
	Face Value		Fair Value		Face Value		Fair Value
	*(In Millions)*
Fixed-rate	$	1,712.7	$	1,845.2	$	1,632.7	$	1,719.8
Variable-rate		130.0		130.0		130.0		130.0
Total indebtedness	$	1,842.7	$	1,975.2	$	1,762.7	$	1,849.8


	Pension Benefits		Other Postretirement Benefits
	*(In Thousands)*
Net funded status of plans:
Net funded status at December 31, 2010, before tax adjustments	$	(194,797)	$	(4,991)
Net benefit cost components reflected in net funded status during first quarter:
Service cost		(1,809)		(94)
Interest cost		(7,957)		(65)
Expected return on assets		8,042		-
Employer contributions during quarter		5,646		12
Net funded status at March 31, 2011, before tax adjustments	$	(190,875)	$	(5,138)
Net benefit cost components reflected in net funded status during second quarter:
Service cost		(1,808)		(95)
Interest cost		(7,957)		(65)
Expected return on assets		8,042		-
Employer contributions during quarter		7,400		89
Net funded status at June 30, 2011, before tax adjustments	$	(185,198)	$	(5,209)
Net benefit cost components reflected in net funded status during third quarter:
Service cost		(1,809)		(95)
Interest cost		(7,957)		(64)
Expected return on assets		8,042		-
Employer contributions during quarter		16,900		20
Net funded status at September 30, 2011, before tax adjustments	$	(170,022)	$	(5,348)

Regulatory assets (liabilities) related to pensions ⁽¹⁾⁽²⁾:
Regulatory assets (liabilities) at December 31, 2010, before tax adjustments	$	242,941	$	(7,570)
Amount reclassified through net benefit cost:
Amortization of prior service credit/(cost)		(1,086)		79
Amortization of net actuarial gain/(loss)		(3,326)		42
Regulatory assets (liabilities) at March 31, 2011, before tax adjustments	$	238,529	$	(7,449)
Amount reclassified through net benefit cost:
Amortization of prior service credit/(cost)		(1,087)		78
Amortization of net actuarial gain/(loss)		(3,327)		43
Regulatory assets (liabilities) at June 30, 2011, before tax adjustments	$	234,115	$	(7,328)
Amount reclassified through net benefit cost:
Amortization of prior service credit/(cost)		(1,086)		79
Amortization of net actuarial gain/(loss)		(3,326)		43
Regulatory assets (liabilities) at September 30, 2011, before tax adjustments	$	229,703	$	(7,206)

⁽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.
⁽²⁾The regulatory liability related to Other Postretirement Benefits is netted against the regulatory assets related to Pension Benefits on the accompanying Unaudited Condensed Consolidated Balance Sheets.


	Three Months Ended September 30,				Change		Percentage Change
	2011		2010		Change		Percentage Change

Utility Operating Revenues:
Retail Revenues	$	307,011	$	292,741	$	14,270	4.9%
Wholesale Revenues		5,560		8,021		(2,461)	(30.7)%
Miscellaneous Revenues		7,979		4,913		3,066	62.4%
Total Utility Operating Revenues	$	320,550	$	305,675	$	14,875	4.9%

Heating Degree Days:
Actual		82		19		63	331.6%
30-year Average		81		81

Cooling Degree Days:
Actual		1,034		1,082		(48)	(4.4)%
30-year Average		725		725



Operating expenses for the three months ended September 30, 2010	$	253.4
Increase in purchased power costs		9.2
Increase in fuel		5.3
Increase in maintenance costs		4.4
Decrease in income taxes - net		(2.0)
Other miscellaneous variances - individually immaterial		1.8
Operating expenses for the three months ended September 30, 2011	$	272.1


	Nine Months Ended September 30,				Change		Percentage Change
	2011		2010		Change		Percentage Change

Utility Operating Revenues:
Retail Revenues	$	837,767	$	803,556	$	34,211	4.3%
Wholesale Revenues		34,149		51,598		(17,449)	(33.8)%
Miscellaneous Revenues		17,742		13,605		4,137	30.4%
Total Utility Operating Revenues	$	889,658	$	868,759	$	20,899	2.4%

Heating Degree Days:
Actual		3,296		3,216		80	2.5%
30-year Average		3,505		3,505

Cooling Degree Days:
Actual		1,466		1,593		(127)	(8.0)%
30-year Average		1,027		1,027



Operating expenses for the nine months ended September 30, 2010	$	728.9
Increase in purchased power costs		23.4
Increase in fuel costs		11.8
Increase in maintenance expenses		10.8
Increase in other operating expenses		4.6
Decrease in income taxes - net		(13.9)
Other miscellaneous variances - individually immaterial		3.7
Operating expenses for the nine months ended September 30, 2011	$	769.3


	Payment due
	Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years

Long-term debt	$	1,792.7	$	0.0	$	110.0	$	171.9	$	1,510.8
Interest obligations ⁽¹⁾	$	1,192.6	$	103.5	$	202.1	$	191.3	$	695.7

⁽¹⁾ Represents interest payment obligations related to fixed and variable rate debt. Interest related to variable rate debt is calculated using the rate in effect at September 30, 2011.