Ipalco Enterprises 10-Q 2008 Q3 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2008

or

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 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 þ (Do not check if a smaller reporting company)	Smaller reporting company o

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

At November 6, 2008, 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
September 30, 2008

Table of Contents
Item No.			Page No.
PART I - FINANCIAL INFORMATION
	1.	Financial Statements:
		Unaudited Consolidated Statements of Income for the Three Months and Nine Months Ended September 30, 2008 and 2007	4
		Unaudited Consolidated Balance Sheets as of September 30, 2008 and December 31, 2007	5
		Unaudited Consolidated Statements of Cash Flows for the Nine Month Ended September 30, 2008 and 2007	6
		Notes to Unaudited Consolidated Financial Statements	7
	1B.	Defined Terms	21
	2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
	3.	Quantitative and Qualitative Disclosure About Market Risk	37
	4.	Controls and Procedures	37
PART II - OTHER INFORMATION
	1.	Legal Proceedings	38
	1A.	Risk Factors	38
	2.	Unregistered Sales of Equity Securities and Use of Proceeds	38
	3.	Defaults Upon Senior Securities	38
	4.	Submission of Matters to a Vote of Security Holders	38
	5.	Other Information	38
	6.	Exhibits	38
		Signatures	39

CAUTIONARY NOTE REGARDING FORWARD LOOKING STATEMENTS

This 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. including, in particular, the statements about our plans, strategies and prospects under the heading “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part I - Financial Information of this Form 10-Q. Forward-looking statements express an expectation or belief and contain a projection, plan or assumption with regard to, among other things, our future revenues, income 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 are intended to identify forward-looking statements.

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

• fluctuations in customer growth and demand;
• impacts of weather on retail sales and wholesale prices and 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;
• federal and state legislation;
• our ownership by The AES Corporation;
• changes in our credit ratings or the credit ratings of AES;
• performance of pension plan assets;
• 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;
• acts of terrorism, acts of war, pandemic events or natural disasters such as floods, earthquakes, tornadoes or other catastrophic events;
• costs and effects of legal and administrative proceedings, settlements, investigations and claims and the ultimate disposition of litigation;
• issues related to our participation in the Midwest Independent Transmission System Operator, Inc., including recovery of costs incurred; and
• product development and technology changes.

Most of these factors affect us through our consolidated subsidiary Indianapolis Power & Light Company. All such factors are difficult to predict, contain uncertainties that may materially affect actual results and many are beyond our control. Forward-looking statements speak only as of the date the statements are made. Except as required under the federal securities laws and rules and regulations of the Securities and Exchange Commission, we undertake no obligation to publicly update or review any forward-looking information, whether as a result of new information, future events or otherwise. We caution you not to unduly rely on the forward-looking statements when evaluating the information presented herein

PART I -FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Unaudited Consolidated Statements of Income
(In Thousands)
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
UTILITY OPERATING REVENUES	$	287,973	$	274,327	$	804,334	$	795,394
UTILITY OPERATING EXPENSES:
Operation:
Fuel		65,015		66,412		195,567		188,371
Other operating expenses		48,779		43,142		142,353		124,207
Power purchased		19,662		14,857		46,779		39,159
Maintenance		20,953		16,590		71,202		58,813
Depreciation and amortization		41,418		36,037		121,943		106,357
Taxes other than income taxes		10,123		10,318		31,008		31,304
Income taxes-net		27,403		30,034		61,445		85,744
Total utility operating expenses		233,353		217,390		670,297		633,955
UTILITY OPERATING INCOME		54,620		56,937		134,037		161,439
OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used during construction		323		1,359		755		3,603
Other - net		(389)		(29)		(3,288)		(312)
Income tax benefit - net		6,001		6,369		26,517		19,326
Total other income and (deductions) - net		5,935		7,699		23,984		22,617
INTEREST AND OTHER CHARGES:
Interest on long-term debt		28,680		29,458		101,703		85,225
Other interest		272		184		701		1,606
Allowance for borrowed funds used during construction		(287)		(1,197)		(977)		(3,115)
Amortization of redemption premiums and expense on debt		794		730		2,896		2,313
Preferred dividends of subsidiary		803		803		2,410		2,410
Total interest and other charges-net		30,262		29,978		106,733		88,439
NET INCOME AND TOTAL COMPREHENSIVE INCOME	$	30,293	$	34,658	$	51,288	$	95,617
See notes to unaudited consolidated financial statements.

IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Unaudited Consolidated Balance Sheets
(In Thousands)
	September 30,		December 31,
	2008		2007
ASSETS
UTILITY PLANT:
Utility plant in service	$	3,897,038	$	3,849,648
Less accumulated depreciation		1,649,805		1,572,684
Utility plant in service - net		2,247,233		2,276,964
Construction work in progress		78,273		68,678
Spare parts inventory		1,366		1,173
Property held for future use		591		591
Utility plant - net		2,327,463		2,347,406
OTHER ASSETS:
Nonutility property - at cost, less accumulated depreciation		699		702
Other investments		10,345		10,422
Other assets - net		11,044		11,124
CURRENT ASSETS:
Cash and cash equivalents		40,230		7,743
Short-term investments		36,250		2,100
Accounts receivable and unbilled revenue (less allowance for doubtful accounts of $1,993 and $1,882, respectively)		74,526		70,429
Fuel - at average cost		28,803		22,326
Materials and supplies - at average cost		56,437		53,387
Financial Transmission Rights (Note 5)		9,570		1,553
Net income tax receivable		-		7,044
Deferred tax asset - current		3,801		3,765
Regulatory assets		19,717		20,571
Prepayments and other current assets		10,811		8,235
Total current assets		280,145		197,153
DEFERRED DEBITS:
Regulatory assets		260,097		265,394
Miscellaneous		25,142		20,864
Total deferred debits		285,239		286,258
TOTAL	$	2,903,891	$	2,841,941
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common shareholder’s deficit:
Pain in Capital		7,878		6,778
Accumulated deficit		(21,298)		(18,016)
Total common shareholder’s deficit		(13,420)		(11,238)
Cumulative preferred stock of subsidiary		59,784		59,784
Long-term debt		1,665,938		1,271,558
Total capitalization		1,712,302		1,320,104
CURRENT LIABILITIES:
Short-term and current portion of long-term debt		47,380		376,000
Accounts payable		62,135		58,217
Accrued expenses		24,634		24,215
Accrued real estate and personal property taxes		32,489		20,278
Regulatory liabilities		10,059		2,774
Accrued income taxes		9,823		-
Accrued interest		43,637		23,889
Customer deposits		16,555		16,042
Other current liabilities		7,415		7,557
Total current liabilities		254,127		528,972
DEFERRED CREDITS AND OTHER LONG-TERM LIABILITIES:
Accumulated deferred income taxes - net		384,979		394,570
Non-current income tax liability		8,254		23,759
Regulatory liabilities		464,587		445,072
Unamortized investment tax credit		15,822		17,652
Accrued pension and other postretirement benefits		41,854		89,368
Miscellaneous		21,966		22,444
Total deferred credits and other long-term liabilities		937,462		992,865
COMMITMENTS AND CONTINGENCIES (Note 10)
TOTAL	$	2,903,891	$	2,841,941
See notes to unaudited consolidated financial statements.

IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Unaudited Consolidated Statements of Cash Flows
(In Thousands)
	Nine Months Ended
	September 30,
	2008		2007
CASH FLOWS FROM OPERATIONS:
Net income	$	51,288	$	95,617
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		115,529		104,910
Amortization of regulatory assets		10,266		4,736
Deferred income taxes and investment tax credit adjustments - net		(20,765)		(4,687)
Tender premium expensed as interest		13,852		-
Preferred dividends of subsidiary		2,410		2,410
Allowance for equity funds used during construction		(655)		(3,536)
Change in certain assets and liabilities:
Accounts receivable		(4,097)		(6,140)
Fuel, materials and supplies		(9,662)		3,500
Income taxes receivable or payable		16,867		4,122
Financial transmission rights		(8,017)		70
Accounts payable and accrued expenses		8,178		11,301
Accrued real estate and personal property taxes		12,212		(651)
Accrued interest		19,748		15,278
Pension and other postretirement benefit expenses		(47,926)		3,984
Short-term and long-term regulatory assets and liabilities		(3,520)		(9,223)
Other - net		(835)		(3,370)
Net cash provided by operating activities		154,873		218,321
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures - utility		(73,021)		(167,230)
Decrease in restricted cash		6		28,394
Purchase of environmental emissions allowances		(200)		(1,927)
Purchase of short-term investments		(111,336)		(277,105)
Proceeds from sales and maturities of short-term investments		77,425		254,369
Other		(2,469)		(7,547)
Net cash used in investing activities		(109,595)		(171,046)
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term borrowings (repayments) - net		46,380		(75,000)
Long-term borrowings		394,105		164,985
Retirement of long-term debt (including redemption premium)		(388,852)		(80,000)
Dividends on common stock		(54,158)		(49,578)
Preferred dividends of subsidiary		(2,410)		(2,410)
Other		(7,856)		(2,593)
Net cash cash used in financing activities		(12,791)		(44,596)
Net change in cash and cash equivalents		32,487		2,679
Cash and cash equivalents at beginning of period		7,743		8,645
Cash and cash equivalents at end of period	$	40,230	$	11,324
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized)	$	82,267	$	71,028
Income taxes	$	38,545	$	66,984
See notes to unaudited consolidated financial statements.

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

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

1. ORGANIZATION

IPALCO Enterprises, Inc. is a wholly-owned subsidiary of The AES Corporation. IPALCO owns all of the outstanding common stock of its subsidiaries. These include its regulated electric utility subsidiary, Indianapolis Power & Light Company, and its unregulated subsidiary, Mid-America Capital Resources, Inc. Substantially all of IPALCO’s business consists of the generation, transmission, distribution and sale of electric energy conducted through IPL. 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 a separately-sited gas-fired combustion turbine facility that are all used for generating electricity. IPL’s net electric generation capability for winter is 3,492 MW and net summer capability is 3,353 MW. Mid-America conducts IPALCO’s unregulated activities.

2. basis of presentation

The accompanying unaudited Consolidated Financial Statements include the accounts of IPALCO, IPL and Mid-America. 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 GAAP for annual fiscal reporting periods. In the opinion of management, all adjustments of a normal recurring nature necessary for fair presentation have been included. The electric utility business is affected by seasonal weather patterns throughout the year and, therefore, the operating revenues and associated operating expenses are not generated evenly by month during the year. These unaudited financial statements have been prepared in accordance with the accounting policies described in IPALCO’s Annual Report on Form 10-K for the year ended December 31, 2007 and should be read in conjunction therewith.

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

3. NEW ACCOUNTING PRONOUNCEMENTS

SFAS 157 “Fair Value Measurements”

In September 2006, the Financial Accounting Standard Board released SFAS 157 to define fair value, establish a framework for measuring fair value in accordance with GAAP, and expand disclosures about fair value measurements. SFAS 157 is effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued FASB Staff Position No. FAS 157-2 “Effective Date of FASB Statement No. 157,” which delays the effective date of SFAS 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). Effective January 1, 2008, IPALCO partially adopted SFAS 157. As permitted by the FASB Staff Position No. FAS 157-2 “Effective Date of FASB Statement No. 157,” IPALCO elected to defer the adoption of the nonrecurring fair value measurement disclosures of nonfinancial assets and liabilities, such as goodwill and asset retirement obligations. until January 1, 2009. The partial adoption of SFAS 157 did not have a material impact on IPALCO’s results of operations, cash flows or financial position. Please see Note 5 “Fair Value Measurements” for the additional disclosures required by SFAS 157. We are currently assessing the potential impact that the adoption of the remaining provisions of SFAS 157 may have on IPALCO’s financial statements.

FASB Staff Position No, 157-3: “Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active”

In October 2008, the FASB issued FSP 157-3 to clarify the application of SFAS 157 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. FSP 157-3 is effective upon issuance, including prior periods for which financial statements have not been issued, and therefore is effective for IPALCO at September 30, 2008. The adoption of FSP 157-3 did not have a material impact on IPALCO’s results of operation, cash flows or financial position.

SFAS 160 “Non-controlling Interests in Consolidated Financial Statements - an amendment of ARB No. 51”

In December 2007, the FASB issued SFAS 160, which requires all entities to report minority interests in subsidiaries as equity in the consolidated financial statements, and requires that transactions between entities and non-controlling interests be treated as equity. SFAS 160 is effective for IPALCO beginning January 1, 2009. The adoption of SFAS 160 is currently not expected to have a material effect on IPALCO’s consolidated financial position and results of operations.

SFAS 161 “Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133”

In March 2008, the FASB issued SFAS 161, which requires additional disclosures about the objectives of the derivative instruments and hedging activities, the method of accounting for such instruments under Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities” and its related interpretations, and a tabular disclosure of the effects of such instruments and related hedged items on IPALCO’s financial position, operations, and cash flows. SFAS 161 is effective for IPALCO beginning January 1, 2009. We are currently assessing the potential impact that the adoption of SFAS 161 may have on IPALCO’s financial statements.

4. Regulatory Matters

Basic Rates and Charges

IPL’s basic rates and charges are determined after giving consideration, on a pro-forma basis, to all allowable costs for ratemaking purposes including a fair return on the fair value of the utility property used and useful in providing service to customers. Pursuant to statute, the Indiana Utility Regulatory Commission is to conduct a periodic review of the basic rates and charges of all utilities at least once every four years, but the IURC has the authority to review the rates of any utility at any time it chooses. Once set, the basic rates and charges authorized do not assure the realization of a fair return on the fair value of property. IPL’s basic rates and charges were last adjusted in 1996.

Fuel Adjustment Charge and Authorized Jurisdictional Net Operating Income

IPL may apply to the IURC for a change in its fuel charge every three months to recover its estimated fuel costs, including the fuel portion of purchased power costs, which may be above or below the levels included in its basic rates and charges. Independent of the IURC’s ability to review basic rates and charges, Indiana law requires electric utilities under the jurisdiction of the IURC to meet operating expense and income test requirements as a condition for approval of requested changes in the FAC. Additionally, customer refunds may result if a utility’s rolling twelve month operating income, determined at quarterly measurement dates, exceeds a utility’s authorized annual jurisdictional net operating income and there are not sufficient applicable cumulative net operating income deficiencies against which the excess rolling twelve month jurisdictional net operating income can be offset.

In IPL’s five most recently approved FAC filings, the IURC found that IPL’s rolling annual jurisdictional retail electric net operating income was greater than the authorized annual jurisdictional net operating income. Because IPL has a cumulative net operating income deficiency, it has not been required to make customer refunds in its FAC proceedings. In IPL’s September 2008 FAC filing (FAC 81), which has not yet been approved by the IURC, IPL’s rolling annual jurisdictional retail electric net operating income was calculated to be less than the authorized annual jurisdictional net operating income by $7.9 million for the twelve months ended July 31, 2008. Even though IPL has a cumulative net operating income deficiency, the IURC may still review IPL’s basic rates and charges on a prospective basis at any time it chooses.

In December 2007, IPL received a letter from the staff of the IURC requesting information relevant to the IURC’s periodic review of IPL’s basic rates and charges and IPL subsequently provided information to the staff. Since IPL’s cumulative net operating income deficiency (described above) requires no customer refunds in the FAC process, the IURC staff was concerned that the higher than usual 2007 earnings may continue in the future. In an effort to allay staff’s concerns, IPL proposed in its March and June 2008 FAC filings (FAC 79 and 80) prospective credits to its retail customers totaling $30 million and $2 million, respectively. Consistent with these proposals, IPL recorded a $30 million deferred fuel regulatory liability in March 2008 and a $2 million deferred fuel regulatory liability in June 2008, with corresponding and respective reductions against revenues. All $32 million of proposed credits have been approved by the IURC and approximately $28.5 million have been applied through September 30, 2008 in the form of offsets against fuel charges that customers would have otherwise been billed during June through September 30, 2008.

In IPL’s March 2006 FAC proceeding (FAC 71), a consumer advocacy group representing some of IPL’s industrial customers requested that a sub-docket be established. IPL and the customer group entered into an agreement regarding the scope of the sub-docket which was approved by the IURC in its May 2006 order in IPL’s FAC 71 proceeding. The agreement defines the scope of the sub-docket as “any issue related to FAC 71” and includes illustrative examples including: review of the Midwest Independent Transmission System Operator, Inc. components of the cost of fuel, review of projection of the Midwest ISO components of the cost of fuel, review of allocation of fuel and other costs, and review of compliance with Indiana Code 8-1-2-42(d), all as they relate to FAC 71 only. A hearing was held in October 2008, at which time the parties submitted direct testimony into the record.

Through the sub-docket, the industrial group is seeking an IURC order requiring IPL to provide customer refunds for past charges and changes to future ratemaking. IPL believes it has meritorious defenses to the claims in the sub-docket, however, if the industrial group prevails, changes to ratemaking could have a material impact on our future results of operations and financial condition. Because of the uncertain outcome of the FAC 71 sub-docket, the IURC Orders in IPL’s FAC 71 proceeding and subsequent FAC proceedings (through FAC 80) approved IPL’s FAC factors on an interim basis, subject to refund. The IURC’s Orders in IPL’s FAC 77 through FAC 80 proceedings also set IPL’s FAC factor on an interim basis, subject to refund, pending the outcome of the Federal Energy Regulatory Commission proceeding regarding Revenue Sufficiency Guarantee Second Pass charges and any subsequent appeals or future order of the IURC. We cannot predict the outcome of the proceeding at this time.

Purchased power costs below an established benchmark are presumed to be recoverable fuel costs. In April 2008, the IURC issued a final order, which approved IPL’s joint petition filed along with another Indiana utility and the Indiana Office of Utility Consumer Counselor. This petition requested a new settlement mechanism for the recovery of fuel costs in the cost of purchased electricity. Under the former agreement, hourly purchased power costs were compared to a monthly standard. Under the new settlement agreement, hourly purchased power costs are compared to a daily benchmark to better reflect changes in natural gas prices that occur throughout the month. IPL believes that changes in natural gas prices typically influence the price at which it can purchase power. Therefore, IPL believes that the new benchmark will more closely track fluctuations in purchased power prices. The new benchmark expires in April 2010. Purchased power costs over the benchmark not recovered from IPL’s customers have not had a material impact on our results of operations or financial condition to date.

Federal Energy Regulatory Commission - Midwest ISO

Midwest ISO’s Energy and Ancillary Services Markets Tariff

As described in our 2007 Form 10-K, the Midwest ISO’s ASM were expected to be launched on September 9, 2008. In August 2008, the Midwest ISO requested a delay with the FERC for launching the ASM and as a result, the launch date has been rescheduled to January 6, 2009.

In January 2008, IPL and other investor-owned Indiana utilities operating in the Midwest ISO filed a joint petition requesting the IURC to issue an order approving operational changes necessary for joint petitioners to accommodate the ASM, and to determine the precise manner and timing of recovery or crediting of jurisdictional charges and revenues associated with the Midwest ISO ASM. In August 2008, the IURC approved the operational changes necessary for joint petitioners to accommodate the ASM. The IURC proceeding to determine the precise manner and timing of recovery or crediting of jurisdictional charges and revenues associated with the Midwest ISO ASM is pending and we cannot predict the outcome at this time.

Wind Power Purchase Agreement

In April 2008, IPL entered into a power purchase agreement for 20 years of approximately 100 MW of wind generated electricity with Hoosier Wind Project, LLC, a subsidiary of enXco, Inc. The contract was contingent, among other things, on the IURC approval of cost recovery via a cost recovery mechanism similar to the FAC and the extension of the federal production tax credit for qualified renewable energy producers. In April 2008, IPL filed the request with the IURC for such recovery. In October 2008, the IURC approved the request. Additionally, in October 2008, the federal production tax credit for qualified renewable energy producers was extended until January 1, 2010. Construction is expected to begin shortly and the operation of the facility is expected to begin in 2009. This agreement will help IPL to diversify the resources available to serve its customers in light of potential greenhouse gas and renewable portfolio standards legislation. Renewable portfolio standards, which would require a certain percentage of an electric utility’s electricity to come from renewable sources by a given date, have been considered at both the state and federal levels. However, it is currently unclear what future legislation related to renewable portfolio standards IPL might face.

5. FAIR VALUE MEASUREMENTS

SFAS 157 defines and establishes a framework for measuring fair value and expands disclosures about fair value measurements. In accordance with SFAS 157, we have categorized our financial assets and liabilities, based on the priority of the inputs to the valuation technique, into a three-level fair value hierarchy as set forth below. If the inputs used to measure the financial instruments fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument.

Financial assets and liabilities recorded on the unaudited Consolidated Balance Sheets are categorized based on the inputs to the valuation techniques as follows:

Level 1 - Financial assets and liabilities whose values are based on unadjusted quoted prices for identical assets or liabilities in an active market that the company has the ability to access at the measurement date (examples include active exchange-traded equity securities, listed derivatives, and most U.S. Government and agency securities).

Level 2 - Financial assets and liabilities whose values are based on quoted prices in markets where trading occurs infrequently or whose values are based on quoted prices of instruments with similar attributes in active markets. Level 2 inputs include the following:

• Quoted prices for identical or similar assets or liabilities in non-active markets (examples include corporate and municipal bonds which trade infrequently);
• Inputs other than quoted prices that are observable for substantially the full term of the asset or liability (examples include interest rate and currency swaps); and
• Inputs that are derived principally from or corroborated by observable market data for substantially the full term of the asset or liability (examples include certain securities and derivatives).

Level 3 - Financial assets and liabilities whose values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.

The following table presents the financial assets and liabilities we measure at fair value on a recurring basis, based on the fair value hierarchy as of September 30, 2008:

	Fair Value Measurements at June 30, 2008, Using
	Level 1		Level 2		Level 3
	(In Thousands)
Financial assets:
Short-term investments	$	-	$	36,250	$	-
Financial transmission rights		-		-		9,570
Total financial assets measured at fair value	$	-	$	36,250	$	9,570
Financial liabilities:
Interest rate swap	$	-	$	-	$	4,587
Other financial instruments		-		-		189
Total financial liabilities measured at fair value	$	-	$	-	$	4,776

The following table sets forth a reconciliation of financial instruments classified as Level 3 in the fair value hierarchy:

	Derivative Financial Instruments, net asset (liability)
	(In Thousands)
Balance at January 1, 2008	$	(4,671)
Unrealized gains (losses) recognized in earnings		(431)
Unrealized gain recognized as a regulatory liability		1,879
Issuances and settlements, net		8,017
Balance at June 30, 2008	$	4,794

Valuation Techniques

As of September 30, 2008, our available-for-sale securities consisted of $2.0 million of auction rate securities and $34.3 million of unsecured variable rate demand notes, which are included in short-term investments on our unaudited Consolidated Balance Sheets. We held $9.1 million of auction rate securities that experienced failed auctions during the first quarter of 2008. In the second and third quarter of 2008, $7.1 million of the auction rate securities were redeemed. We continue to hold $2.0 million of auction rate securities that experienced failed auctions during the first nine months of 2008. As described in our Form 10-Q for the quarterly period ended March 31, 2008, the auction rate securities were valued using quoted market prices, but due to the illiquid nature of such investments in the current market, we have classified them as Level 2. In September 2008, $34.3 million of the 1995B Bonds were tendered and failed the remarketing process. In accordance with the terms of the 1995B Bonds, the trustee is holding $34.3 million of the 1995B Bonds, which failed the remarketing process, on IPL’s behalf. See Note 7, “Indebtedness” for further discussion of the  1995B Bonds. Similar to the analysis performed on the auction rate securities, we have performed an impairment analysis on the 1995B Bonds and concluded no impairment exists and have, therefore, recorded them at their face value and have also classified them as Level 2 due to the illiquid market.

In connection with IPL’s participation in the Midwest ISO, in the second quarter of each year IPL is granted financial instruments that can be converted into cash or Financial Transmission Rights based on IPL’s forecasted peak load for the period. FTR’s are used in the Midwest ISO market to hedge IPL’s exposure to congestion charges, which result from constraints on the transmission system. IPL converted all of these financial instruments into FTR’s during the second quarter of 2008. IPL’s FTR’s are valued at the cleared auction prices for FTR’s in the Midwest ISO’s annual auction. The fair value assigned to the FTR’s is considered a Level 3 input under the fair value hierarchy required by SFAS 157. An offsetting regulatory liability has been recorded as management believes that these revenues or costs will be flowed through to customers through the FAC. As such, there is no impact on our unaudited Consolidated Statements of Income.

We do not believe any of the other financial instruments which we held as of September 30, 2008 are material to our results of operations or financial position either qualitatively or quantitatively. As described in our Form 10-K, IPL has one interest rate swap agreement, which is recognized on the unaudited Consolidated Balance Sheets at its estimated fair value as a liability. IPL entered into this agreement as a means of managing the interest rate exposure related to the 1995B Bonds. In accordance with Statement of Financial Accounting Standards No. 71, “Accounting for the Effect of Certain Types of Regulation,” IPL recognized a regulatory asset equal to the value of the interest rate swap, which is adjusted as that fair value changes. Therefore there is no impact to IPALCO’s unaudited Consolidated Statements of Income or Cash Flows for the changes in the fair value of the interest rate swap. This accounting treatment was considered in making our conclusion that the interest rate swap is not material to our financial condition.

6. REGULATORY ASSETS and Liabilities

Deferred Fuel

Deferred fuel costs are a component of current regulatory assets or liabilities and are expected to be recovered from or credited to retail customers through future FAC proceedings. IPL records deferred fuel in accordance with standards prescribed by the Federal Energy Regulatory Commission. The deferred fuel adjustment is the result of variances between estimated fuel and purchased power costs in IPL’s FAC and actual fuel and purchased power costs. IPL is generally permitted to recover underestimated fuel and purchased power costs in future rates through the FAC proceedings and therefore the costs are deferred and amortized into fuel expense in the same period that IPL’s rates are adjusted. Additionally, as discussed in Note 4, “Regulatory Matters,” in IPL’s FAC 79 and 80, the IURC approved IPL’s proposed prospective credits to its retail customers totaling $32 million. As a result, IPL has recorded $32 million as reductions against revenues with corresponding deferred fuel regulatory liabilities, which are being reduced as the credits are applied. As of September 30, 2008 and December 31, 2007, IPL had deferred fuel assets of $13.2 million, which are included in regulatory assets (current) on the accompanying unaudited Consolidated Balance Sheets.

Financial Transmission Rights

As discussed in Note 5, “Fair Value Measurements,” IPL has recorded a current regulatory liability on the accompanying unaudited Consolidated Balance Sheets related to FTRs that it has been granted by the Midwest ISO. The regulatory liability (current) balance related to FTRs was $9.6 million and $1.6 million at September 30, 2008 and December 31, 2007, respectively. The $8.0 million increase is primarily because IPL was granted $17.1 million of FTRs by the Midwest ISO in the second quarter of 2008, offset by subsequent usage of FTRs.

7. INDEBTEDNESS

IPL’s Variable Rate Debt

IPL has outstanding $131.9 million of variable rate IPL first mortgage bonds in the form of auction rate securities. While the securities have long term maturities, they are auctioned weekly. Beginning, in September 2008, the auctions failed on these securities and as a result, the interest rates were reset at the maximum rates of 12% per annum on each series of the IPL first mortgage bonds. IPL will continue to pay the maximum rate until there are successful auctions, unless it refinances the debt. IPL has filed a financing petition with the IURC requesting permission to refinance all of its auction rate securities as well as our obligation under the 1995B Bonds (see below). IPL anticipates receiving an order from the IURC before the end of the year and given the volatility in the market, IPL will evaluate its alternatives with regard to refinancing this debt at that time.

IPL is also liable for interest and principal on the 1995B Bonds issued in 1995 by the City of Petersburg in Indiana. Interest on the 1995B Bonds varies with the tax-exempt weekly rate reset through a remarketing process. These notes are classified as long-term liabilities because IPL maintains a $40.6 million long-term liquidity facility supporting the 1995B Bonds. The liquidity facility expires May 16, 2011 and bears interest at the prime rate, which was 5.0% per annum at September 30, 2008. The interest rate on the 1995B Bonds is synthetically fixed at 5.21% using a swap agreement. In September 2008, $34.3 million of the 1995B Bonds were tendered and failed the remarketing process. In accordance with the terms of the 1995B Bonds, the trustee drew $34.4 million against IPL’s committed liquidity facility to fund the tender and related accrued interest. As a result, the trustee is holding $34.3 million of the 1995B Bonds, which failed the remarketing process, on IPL’s behalf. All of the 1995B Bonds remain outstanding and IPL continues to pay interest on them, even though IPL is the beneficiary of the interest on the $34.3 million that failed remarketing. Additionally, IPL is liable for the draw on the liquidity facility. Our September 30, 2008 balance sheet reflects our obligation on the 1995B Bonds in long-term debt. Because management believes the 1995B Bonds will be remarketed or refinanced within one year, we are presenting the payable on the liquidity facility and our investment in the 1995B Bonds as current on our September 30, 2008 balance sheet.

IPALCO’s Senior Secured Notes

In April 2008, IPALCO completed the sale of $400 million aggregate principal amount of 7.25% Senior Secured Notes due April 1, 2016 pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended. The 2016 IPALCO Notes were issued pursuant to an Indenture dated April 15, 2008, by and between IPALCO and The Bank of New York Trust Company, N.A., as trustee. In connection with this issuance, IPALCO conducted a Tender Offer to repurchase for cash any and all of IPALCO’s outstanding 8.375% Senior Secured Notes due November 14, 2008 (original coupon 7.375%), of which $375 million were outstanding.

The 2016 IPALCO Notes were sold at 98.526% of par resulting in net proceeds of $394.1 million. The $5.9 million discount is being amortized through 2016 using the effective interest method. We used these net proceeds to repurchase all of the outstanding 2008 IPALCO Notes through the Tender Offer and subsequent redemption of all remaining notes not tendered. The proceeds were also used to pay the early tender premium of $13.9 million (included in Interest on long-term debt in the accompanying unaudited Consolidated Statements of Income) and other fees and expenses related to the Tender Offer and the redemption of the 2008 IPALCO Notes and the issuance of the 2016 IPALCO Notes.

In addition, IPALCO solicited and received consents to amend the applicable indenture with respect to the 2008 IPALCO Notes and entered into the Indenture Supplement dated April 15, 2008, with The Bank of New York Trust Company, N.A., as trustee, to the Indenture between the parties dated November 14, 2001. The Indenture Supplement amends the Original Indenture with respect to the 2008 IPALCO Notes to eliminate substantially all of the restrictive covenants, several affirmative covenants and certain events of default, modify the covenant regarding mergers, consolidations and sales of IPALCO’s assets and eliminate or modify certain other provisions.

The 2016 IPALCO Notes are secured by IPALCO’s pledge of all of the outstanding common stock of IPL. The lien on the pledged shares will be shared equally and ratably with IPALCO’s existing senior secured notes. IPALCO has entered into a Pledge Agreement Supplement with The Bank of New York Trust Company, N.A., as Collateral Agent, dated April 15, 2008 to the Pledge Agreement between IPALCO and The Bank of New York Trust Company, N.A. as successor Collateral Agent dated November 14, 2001.

8. INCOME TAXES

In May 2008, we received notification that the Joint Committee on Taxation completed their review of our method of capitalizing indirect service costs for tax years ended December 31, 2001 through December 31, 2004 and took no exception to the settlement as proposed by the U.S. Internal Revenue Service. The resolution of this tax position resulted in a decrease in our unrecognized tax benefits by approximately $14 million. The impact was recorded in the second quarter of 2008 by decreasing our non-current income tax liability by approximately $16 million, increasing our income taxes currently payable by approximately $6 million, increasing our accumulated deferred income taxes by approximately $9 million and decreasing income tax expense by approximately $1 million.

9. 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, 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, 2007, before tax adjustments	$	(78,634)	$	(10,137)
Net benefit cost components reflected in net funded status during quarter:
Service cost		(1,749)		(279)
Interest cost		(10,107)		(161)
Expected return on assets		10,497		-
Employer contributions during quarter		335		60
Net funded status at March 31, 2008, before tax adjustments		(79,658)		(10,517)
Net benefit cost components reflected in net funded status during quarter:
Service cost		(1,312)		(279)
Interest cost		(7,566)		(161)
Expected return on assets		7,858		-
SFAS 88 settlement accounting re-actuarial valuation - supplemental plan		(388)		-
Employer contributions during quarter		5,000		67
Net funded status at June 30, 2008, before tax adjustments		(76,066)		(10,890)
Net benefit cost components reflected in net funded status during quarter:
Service cost		(1,312)		(279)
Interest cost		(7,573)		(161)
Expected return on assets		7,857		-
SFAS 88 settlement accounting re-actuarial valuation - supplemental plan		(14)		-
Employer contributions during quarter		45,410		306
Net funded status at September 30, 2008, before tax adjustments	$	(31,698)	$	(11,024)
Regulatory assets (liabilities) related to pensions (1):
Regulatory assets (liabilities) at December 31, 2007, before tax adjustments	$	89,589	$	(1,465)
Amount reclassified through net benefit cost:
Amortization of net actuarial gain/(loss)		(456)		4
Amortization of prior service credit/(cost)		(956)		14
Regulatory assets (liabilities) at March 31, 2008, before tax adjustments		88,177		(1,447)
SFAS 88 settlement accounting re-actuarial valuation - supplemental plan		388		-
Amount reclassified through net benefit cost:
Amortization of net actuarial (loss) - SFAS 88 recognition		(429)		-
Amortization of net actuarial gain/(loss) - monthly amortization		(342)		5
Amortization of prior service credit/(cost) - monthly amortization		(717)		14
Regulatory assets (liabilities) at June 30, 2008, before tax adjustments		87,077		(1,428)
SFAS 88 settlement accounting re-actuarial valuation - supplemental plan		14		-
Amount reclassified through net benefit cost:
Amortization of net actuarial (loss) - SFAS 88 recognition		(116)		-
Amortization of net actuarial gain/(loss) - monthly amortization		(341)		4
Amortization of prior service credit/(cost) - monthly amortization		(717)		14
Regulatory assets (liabilities) at September 30, 2008, before tax adjustments	$	85,917	$	(1,410)
(1)Amounts that would otherwise be charged/credited to Accumulated Other Comprehensive Income or Loss upon application of Statement of Financial Accounting Standards No. 158 “Employers’ Accounting for Defined Benefits Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106, and 132R” 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.

Effective for fiscal years ending after December 15, 2008, Statement of Financial Accounting Standards No. 158 “Employers’ Accounting for Defined Benefits Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106, and 132R” requires plan assets and liabilities to be measured as of fiscal year-end. The Pension Plans had a measurement date of November 30 for the fiscal year ended December 31, 2007. Therefore, in accordance with SFAS 158, IPL has elected to change the Pension Plans’ measurement date from November 30 to December 31, effective December 31, 2008. SFAS 158 gives employers two methods for changing their measurement dates: (1) The “remeasurement method,” which would require assets and liabilities to be remeasured at the end of the preceding fiscal year (December 31, 2007) or (2) A simplified “13-month method,” that avoids a remeasurement at the start of the transition year.

Under either option, the plan must book an adjustment to retained earnings to reflect net periodic cost for the “gap period” (December 1, 2007 to December 31, 2007). IPL elected the simplified “13-month method” for remeasurement. The “gap period” adjustment is booked as an adjustment to retained earnings to reflect net periodic cost for the “gap period” of $0.4 million, net of income taxes, and Accumulated Other Comprehensive Income or Loss, to the extent it includes amortization components and does not flow through earnings or income. Under the 13-month method, no adjustment is required to Accumulated Other Comprehensive Income or Loss for gains and losses arising during the gap period. Amounts that would otherwise be charged/credited to Accumulated Other Comprehensive Income or Loss upon application of SFAS 158 are recorded as a regulatory asset or liability because IPL has historically recovered and currently recovers pension and other postretirement benefit expenses in rates. These are unrecognized amounts yet to be recognized as components of net periodic benefit costs.

Pension Expense

The following table presents the “gap period” adjustment that was booked to IPL’s January 1, 2008 beginning retained earnings. The information relates to the Pension Plans (combined):

	(In Thousands)
Components of net periodic benefit cost:
Service cost	$	437
Interest cost		2,527
Expected return on plan assets		(2,624)
Amortization of actuarial loss		114
Amortization of prior service cost		239
Net periodic benefit cost	$	693

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,
	2008		2007		2008		2007
	(In Thousands)
Components of net periodic benefit cost:
Service cost	$	1,312	$	1,472	$	3,936	$	4,415
Interest cost		7,573		7,152		22,719		21,456
Expected return on plan assets		(7,857)		(7,703)		(23,589)		(23,108)
Settlement loss recognized		116		-		546		-
Amortization of actuarial loss		341		1,409		1,025		4,227
Amortization of prior service cost		717		687		2,151		2,060
Net periodic benefit cost	$	2,202	$	3,017	$	6,788	$	9,050

In October 2008, the International Brotherhood of Electrical Workers Physical Bargaining Unit ratified a new four-year agreement with IPL. In addition to certain wage increases, the new agreement also provides for a 10.0% increase in retirement pension bands effective January 1, 2009, which will increase our future pension expense and funding requirements.

Other Postretirement Employee Benefits and Expense

The SFAS 158 measurement date requirement has no effect on the other postretirement benefit plan since the measurement date for that plan was December 31 for the fiscal year ended December 31, 2007. Therefore, no “gap period” adjustment is required for the other postretirement benefit plan.

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

	For the Three Months Ended, Septemeber 30,				For the Nine Months Ended, September 30,
	2008		2007		2008		2007
	(In Thousands)
Components of net periodic benefit cost:
Service cost	$	279	$	330	$	836	$	991
Interest cost		161		145		484		435
Amortization of actuarial loss		(4)		-		(13)		-
Amortization of prior service cost		(14)		2		(42)		5
Net periodic benefit cost	$	422	$	477	$	1,265	$	1,431

10. COMMITMENTS AND CONTINGENCIES

Please see Note 4, “Regulatory Matters - Fuel Adjustment Charge and Authorized Jurisdictional Net Operating Income” for a discussion of the deferred fuel regulatory liabilities recorded for credits to IPL’s retail customers.

Legal

As of September 30, 2008 and December 31, 2007, IPL was a defendant in approximately 113 and 114 pending lawsuits, respectively, 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” in 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 or IPALCO’s financial position, results of operations, 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. 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 Consolidated Financial Statements.

In November 2007, the International Brotherhood of Electrical Workers, Local Union No. 1395, and sixteen individual retirees, (the “Complainants”), filed a complaint at the IURC seeking enforcement of their interpretation of the 1995 final order and associated settlement agreement resolving IPL’s basic rate case. The Complainants are requesting that the IURC conduct an investigation of IPL’s failure to fund the Voluntary Employee Beneficiary Association Trust, at a level of approximately $19 million per year. The VEBA Trust was spun off to an independent trustee in 2001. The complaint seeks an IURC order requiring IPL to make contributions to place the VEBA Trust in the financial position in which allegedly it would have been had IPL not ceased making annual contributions to the VEBA Trust after its spin off. The Complaint also seeks an IURC order requiring IPL to resume making annual contributions to the VEBA Trust. IPL filed a motion to dismiss and both parties are seeking summary judgment in the IURC proceeding. To date, no procedural schedule for this proceeding has been established. IPL believes it has meritorious defenses to the Complainants' claims and it will assert them vigorously in response to the complaint; however, there can be no assurances that it will be successful in its efforts.

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 Consolidated Financial Statements.

Environmental

We are subject to various federal, state 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 you that we have been or will be at all times in full compliance with such laws, regulations and permits; however, we do not believe any currently open investigations will result in fines material to our results of operations or financial position.

Clean Air Interstate Rule

As discussed in our 2007 Form 10-K, in March 2005 the U.S. Environmental Protection Agency finalized the federal CAIR, which imposes restrictions against polluting the air of downwind states. The federal CAIR established a two-phase regional “cap and trade” program for SO₂ and NO_x emissions that would require the largest reduction in air pollution in more than a decade. The federal CAIR covered 28 eastern states, including Indiana, and the District of Columbia. In July 2008, the U.S. Court of Appeals for the D.C. Circuit vacated and remanded the federal CAIR to the EPA. However, in September 2008, the EPA appealed the ruling to the full bench (en banc) of the U.S. Court of Appeals for the D.C. Circuit. It is pending further action and the original decision is subject to further review. In October 2008, the full bench of the U.S. Court of Appeals for the D.C. Circuit issued an Order requesting that all of the petitioners answer two questions. The petitioners are to answer whether they would prefer a complete vacature of federal CAIR or whether they would prefer the Court stay its ruling that federal CAIR be vacated, and instead allow the EPA to create a new rule that addresses the Court’s initial concerns. At this time, it is not clear what impact this ruling will have on our business, results of operations or financial position.

In October 2008, the Indiana Department of Environmental Management indicated that it intends to propose an Indiana CAIR before the Indiana Air Pollution Control Board at its December 2008 meeting, to become effective if and when the U.S. Court of Appeals for the D.C. Circuit formally vacates the federal CAIR. The IDEM proposal, if adopted, will be issued under the State emergency rulemaking authority. IDEM has yet to issue a draft rule and therefore we cannot determine the potential impact on our business, results of operations or financial position.

Clean Air Mercury Rule

As discussed in our 2007 Form 10-K, in March 2005, the EPA finalized the federal CAMR that required utilities to reduce mercury emissions from new and existing coal fired power plants. The rule created “standards of performance” limiting mercury emissions from utilities and established a staged approach for reductions via a “cap and trade” program. In February 2008, the U.S. Court of Appeals for the D.C. Circuit vacated the federal CAMR, requiring the EPA to promulgate a new mercury emissions rule which presumably will not include a “cap and trade” program. Subsequently, in July 2008, the Indiana Office of the Attorney General issued an Advisory Letter No. 08-17 regarding implementation and enforcement of the Indiana CAMR, which resulted in the IDEM providing a formal opinion that the Indiana CAMR should not be enforced. As a result, IPL will not be required to meet either the mercury emission reduction requirements or install mercury monitors until such time as there is either judicial or regulatory finality. In October 2008, the EPA filed a petition with the U.S. Supreme Court requesting that it review the February 2008 decision.

Clean Coal Technology Filings

In April 2008, in response to an updated Plan filed by IPL, the IURC issued an Order approving recovery of capital expenditures of approximately $92.7 million over the next three years. The $92.7 million approved by the IURC includes $90.0 million to install and/or upgrade CCT to further reduce SO₂ and mercury emissions at IPL’s Petersburg generating station and $2.7 million for mercury emissions monitoring equipment at IPL’s coal-fired power plants. IPL currently estimates the installation and/or upgrade of CCT to further reduce SO₂ and mercury emissions at its Petersburg generating station will cost approximately $98.5 million. IPL intends to seek recovery of any costs incurred on this project above the currently authorized $90.0 million; however, there can be no assurance that such recovery will be granted. The IURC also approved the ratemaking treatment applicable to qualified pollution control property to be recovered through an Environmental Compliance Cost Recovery Adjustment, similar to that which IPL has received in previous environmental filings. Such treatment includes a return on the construction costs and recovery of depreciation expenses and operation and maintenance expenses associated with these projects. The IURC also granted IPL the authority to add the approved return on its environmental projects to IPL’s authorized annual jurisdictional net operating income in subsequent FAC proceedings.

Because the federal CAIR has been vacated, as discussed above, IPL is planning to delay the targeted in service date of CCT to further reduce SO₂ and mercury emissions at IPL’s Petersburg generating station from 2010 to 2011, with the majority of the construction expenditures occurring in 2010 and 2011. The installation of the mercury emissions monitoring equipment at IPL’s coal-fired power plants is also under review given that the mercury monitoring requirements under the Indiana CAMR are uncertain as a result of the federal CAMR being vacated and the opinion letter from the Indiana Office of Attorney General, as discussed above. Until there is greater regulatory clarity around its obligations, IPL has suspended its plan to install mercury monitors. 

11. RELATED PARTY TRANSACTIONS

In the first quarter of 2008, IPL exchanged 20,661 SO₂ environmental air emissions allowances for 20,718 SO₂ environmental air emissions allowances with wholly-owned subsidiaries of AES. Because the transactions lacked commercial substance and were between entities under common control, the exchanges have been accounted for by IPL at their historical cost. This transaction did not have a material impact on our results of operations or financial condition.

12. 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. Utility net income for the three months ended September 30, 2008 and 2007 was $41.2 million and $45.8 million, respectively and for the nine months ended September 30, 2008 and 2007 was $92.0 million and $128.1 million, respectively. The nonutility category primarily includes the 2008 IPALCO Notes, the $375 million of 8.625% (original coupon 7.625%) Senior Secured Notes due November 14, 2011 and the 2016 IPALCO Notes; approximately $5.4 million and $1.7 million of nonutility cash and cash equivalents, as of September 30, 2008 and December 31, 2007, respectively; short-term and long-term nonutility investments (including a 4.4% ownership interest in EnerTech Capital Partners II L.P.) of $9.5 million and $11.5 million at September 30, 2008 and December 31, 2007, respectively; and income taxes and interest related to those items. There was no nonutility operating income during the periods covered by this report. However, the nonutility operating segment had net losses of $10.1 million and $10.3 million for the three months ended September 30, 2008 and 2007, respectively and $38.3 million and $30.1 million for the nine months ended September 30, 2008 and 2007, respectively. Nonutility assets represented less than 1% of IPALCO’s total assets as of September 30, 2008 and December 31, 2007. There were no nonutility capital expenditures during the three months and nine months ended September 30, 2008 and 2007. 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 report on 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
2007 Form 10-K	IPALCO’s Annual Report on Form 10-K for the year ended December 31, 2007
2008 IPALCO Notes	$375 million of 8.375% (original coupon 7.375%) Senior Secured Notes due November 14, 2008
2016 IPALCO Notes	$400 million of 7.25% Senior Secured Notes due April 1, 2016
AES	The AES Corporation
ASM	Ancillary Services Market
BART	Best Available Retrofit Technology
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CCT	Clean Coal Technology
CO2	Carbon Dioxide
DSM	Demand-Side Management
EPA	U.S. Environmental Protection Agency
FAC	Fuel Adjustment Charges
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FSP 157-3	Financial Accounting Standards Board Staff Position No. 157-3 “Determining the Fair Value of a Financial Asset when the Market for That Asset is Not Active”
FTR	Financial Transmission Right
GAAP	Accounting Principles Generally Accepted in the United States of America
IDEM	Indiana Department of Environmental Management
Indenture Supplement	Indenture Supplement between IPALCO Enterprises, Inc. and The Bank of New York Trust Company, N.A., as Trustee, dated April 15, 2008, to the Indenture of Trust between IPALCO Enterprises, Inc. and The Bank of New York Trust Company dated November 14, 2001
IPALCO	IPALCO Enterprises, Inc.
IPL	Indianapolis Power & Light Company
IURC	Indiana Utility Regulatory Commission
kWh	Kilowatt hour
Mid-America	Mid-America Capital Resources, Inc.
Midwest ISO	Midwest Independent Transmission System Operator, Inc.
MW	Megawatt
NOx	Nitrogen Oxides
Original Indenture	Indenture of Trust between IPALCO Enterprises, Inc. and The Bank of New York Trust Company dated November 14, 2001
Pension Plans	Employees’ Retirement Plan of Indianapolis Power & Light Company and Supplemental Retirement Plan of Indianapolis Power & Light Company
SFAS 88	Statement of Financial Accounting Standards No. 88 “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits”
SFAS 157	Statement of Financial Accounting Standards No. 157 “Fair Value Measurements”
SFAS 158	Statement of Financial Accounting Standards No. 158 “Employers’ Accounting for Defined Benefits Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106, and 132R”
SFAS 160	Statement of Financial Accounting Standards No. 88 “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51”
SFAS 161	Statement of Financial Accounting Standards No. 161 “Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133”
SO2	Sulfur Dioxide
Tender Offer	A tender offer to repurchase for cash any and all of IPALCO’s outstanding 8.375% Senior Secured Notes due November 14, 2008 (original coupon 7.375%)
VEBA Trust	Voluntary Employee Beneficiary Association Trust

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 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.

Description of the Company

IPALCO Enterprises, Inc. is a holding company incorporated under the laws of the state of Indiana. Our principal subsidiary is Indianapolis Power & Light Company, a regulated utility operating in the state of Indiana. Substantially all of our business consists of the generation, transmission, distribution and sale of electric energy conducted through IPL. Our other direct subsidiary, Mid-America Capital Resources, Inc., is the holding company for our unregulated activities. Mid-America’s only significant investment is a small minority ownership interest in EnerTech Capital Partners II L.P., a venture capital fund, with a recorded value of $6.8 million as of September 30, 2008 and December 31, 2007. Our business segments are utility and nonutility.

We are primarily engaged in generating, transmitting, distributing and selling electric energy to approximately 470,000 retail customers in the city of Indianapolis and neighboring areas within the state of Indiana. We have an exclusive right to provide electric service to those customers. We own and operate four generating stations, all within the state of Indiana. More than 99% of our total electricity produced was generated from coal. Natural gas and fuel oil combined to provide the remaining kWh generation (primarily for peaking capacity). Our net electric generation capability for winter and summer is 3,492 MW and 3,353 MW, respectively. Our corporate mission is to serve our customers’ needs for electric power in ways that provide exceptional value to our customers, shareholders, people and communities

Material changes in our consolidated financial condition and results of operations, except where noted, are attributed to the operations of IPL. Consequently, the following discussion is centered on IPL.

IMPACTS OF WEAK ECONOMIC CONDITIONS

The United States and global economies are currently experiencing significant turmoil, including a crisis in the credit markets, high inflation rates and significant losses in the equity markets.

We believe that our core business benefits from relatively inelastic demand for electricity and from the fact that our retail sales are protected from competition as a result of our tariff. In addition, we have undertaken certain initiatives, including the refinancing of $375 million of 8.375% (original coupon 7.375%) Senior Secured Notes due November 14, 2008 in the second quarter of 2008, which have helped preserve our liquidity and improved our financial flexibility. For additional information on the refinancing, see “Liquidity and Capital Resources - Capital Resources - Indebtedness”. As a result of the refinancing described above, we do not have any long-term indebtedness maturing until 2011 nor do we have any major construction activity planned before 2010. Therefore, while we may seek to refinance certain additional securities described below, we do not anticipate a need for long-term financings until at least 2010. As a result of these initiatives and other factors, we believe that existing cash balances, short-term investments, cash generated from operating activities and borrowing capacity on our committed credit facility will be adequate on a short-term and long-term basis to meet anticipated operating expenses, interest expense on outstanding indebtedness and recurring capital expenditures.  See “Liquidity and Capital Resources” for further discussion of our liquidity position. Although there can be no assurance due to the challenging times currently faced by financial institutions, management believes that the participating banks under its facilities will be able to meet their funding commitments. However, if the credit crisis is protracted, deteriorates, or leads to a larger recession, such events could have a material adverse impact on our cash flows from operations and our financial position.

While not currently material to our liquidity or ability to service our debt, we nonetheless have been negatively impacted by the current weak economic conditions on several fronts. First, we have outstanding $131.9 million of variable rate IPL first mortgage bonds in the form of auction rate securities. While the securities have long term maturities, they are auctioned weekly. Beginning, in September 2008, the auctions failed on these securities and as a result, the interest rates were reset at the maximum rates of 12% per annum on each series of the IPL first mortgage bonds. We will continue to pay the maximum rate until there are successful auctions, unless we refinance the debt. We have filed a financing petition with the IURC requesting permission to refinance all of our auction rate securities as well as the 1995B Bonds (see below). We anticipate receiving an order from the IURC before the end of the year and given the volatility in the market, we will evaluate our alternatives with regard to refinancing this debt at that time.

Second, IPL is also liable for interest and principal on the 1995B Bonds issued in 1995 by the City of Petersburg in Indiana. Interest on the 1995B Bonds varies with the tax-exempt weekly rate reset through a remarketing process. These notes are classified as long-term liabilities because IPL maintains a $40.6 million long-term liquidity facility supporting the 1995B Bonds. The liquidity facility expires May 16, 2011 and bears interest at the prime rate, which was 5.0% per annum at September 30, 2008. The interest rate on the 1995B Bonds is synthetically fixed at 5.21% using a swap agreement. In September 2008, $34.3 million of the 1995B Bonds were tendered and failed the remarketing process. In October 2008, an additional $2.3 million of the 1995B Bonds were tendered and failed the remarketing process. In accordance with the terms of the 1995B Bonds, the trustee drew $36.7 million against IPL’s committed liquidity facility to fund the tender and related accrued interest. As a result, the trustee is holding $36.6 million of the 1995B Bonds, which failed the remarketing process, on IPL’s behalf. All of the 1995B Bonds remain outstanding and IPL continues to pay interest on them, even though IPL is the beneficiary of the interest on the $36.6 million that failed remarketing. Additionally, IPL is liable for the draw on the liquidity facility. Our September 30, 2008 balance sheet reflects our obligation on the 1995B Bonds in long-term debt. Because management believes the 1995B Bonds will be remarketed or refinanced within one year, we are presenting the payable on the liquidity facility and our investment in the 1995B Bonds as current on our September 30, 2008 balance sheet.

Third, as of December 31, 2007, we held approximately $400 million of investments in our pension fund. Those assets consisted of equity securities, fixed income securities, hedge funds and other alternative investments, and cash, with the majority being in equity securities. In accordance with pension accounting rules generally accepted in the United States of America, our pension expenses are based on assumptions made at the prior measurement date (November 30, 2007) regarding future discount rates, pension plan performance and escalation of costs. Our pension plan assets are currently performing well below the assumed long-term rate of return on plan assets of 7.75%. In fact, the financial market volatility may result in a potentially large decrease in the value of plan assets at the next remeasurement period, December 31, 2008. Any shortfall in pension plan performance will be amortized into expense over the 12 years beginning in 2009, which is the estimated average remaining working lifetime of the plan participants. Therefore, if our asset performance does not significantly improve before the December 31, 2008 remeasurement date, it will have the affect of increasing our pension expenses and funding requirements over the next several years, which may be material. We can not estimate the amount of the increase at this time, because a full remeasurement would need to be performed to make such an estimate. Our next remeasurement will occur on December 31, 2008. 

Finally, over the past few years, the demand for certain raw materials, including steel, copper and other commodities have escalated at rates well above the consumer price index and as a result, prices for these materials and the volatility of such prices have increased as well. These and other raw materials serve as inputs to many operating and maintenance processes fundamental to the electric utility industry and price increases have impacted our liquidity by increasing environmental capital expenditures for which we intend to seek recovery. To date, this escalation has been partially mitigated through strong sourcing and work management practices. However, such costs have in the past, and are likely to continue to, impact results of operations.

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, 2008 and three months ended September 30, 2007

Net income during the three months ended September 30, 2008 of $30.3 million decreased $4.4 million from net income of $34.7 million during the same period in 2007. The following discussion highlights significant factors contributing to this change.

Utility Operating Revenues

Utility operating revenues increased in 2008 during the three months ended September 30, 2008 compared to the same period in 2007 by $13.6 million, which resulted from the following changes (dollars in thousands):

	Three months ended September 30,				Change		Percent Change
	2008		2007
Utility Operating Revenue
Retail Revenues	$	273,385	$	258,767	$	14,618	5.6%
Wholesale Revenues		10,245		11,081		(836)	(7.5)%
Miscellaneous Revenues		4,343		4,479		(136)	(3.0)%
Total Utility Operating Revenues	$	287,973	$	274,327	$	13,646	5.0%
Heating Degree Days		9		19		(10)	(52.6)%
Cooling Degree Days		768		990		(222)	(22.4)%

The 5.0% increase in utility operating revenues was primarily due to a 5.6% increase in retail revenues. Retail revenues increased by $14.6 million primarily due to an 11.1% increase in the weighted average price per kWh sold ($26.9 million) partially offset by a 4.9% decrease in the quantity of kWh sold ($12.3 million). The increase in the weighted average price of kWhs sold was primarily due to a $14.9 million increase in revenues related to our Clean Coal Technology projects, and a $9.6 million increase in fuel revenues, which is offset with increased fuel and purchased power expenses attributable to serving our jurisdictional retail customers. There was also a $2.0 million increase in the weighted average price per kWh rate charged to our residential and commercial customers excluding fuel recovery and revenues related to our CCT projects. Our declining block rate structure generally provides for residential and commercial customers to be charged a lower price per kWh rate at higher consumption levels. Therefore, as volumes decrease, the weighted average price per kWh increases. The decrease in the quantity of retail kWhs sold was primarily due to the 22.4% decrease in cooling degree days during the comparable periods.

The 7.5% decrease in wholesale revenues is primarily due to a 36.1% decrease in the quantity of kWh sold ($4.0 million), partially offset by a 44.8% increase in the weighted average price per kWh sold ($3.2 million). The decrease in quantity was primarily due to the timing and duration of scheduled and forced generating unit maintenance outages. The quantity and price of wholesale kWh sales are also impacted by the ability of our generation to be dispatched by the Midwest Independent Transmission System Operator, Inc. at wholesale prices that are above our variable costs and the amount of electricity we have available to sell in the wholesale market. Our ability to be dispatched in the Midwest ISO market is primarily impacted by the locational market price of electricity and variable generation costs. The amount of electricity available for wholesale sales is impacted by our retail load requirements, our generation capacity and unit availability.

Utility Operating Expenses

The following table illustrates our primary operating expense changes from the three months ended September 30, 2007 to the three months ended September 30, 2008 (in millions):

Operating Expenses for the three months ended September 30, 2007	$	217.4
Increase in other operating expenses		5.6
Increase in depreciation and amortization		5.4
Increase in power purchased		4.8
Increase in maintenance expenses		4.4
Decrease in income taxes - net		(2.6)
Other		(1.6)
Operating Expenses for the three months ended September 30, 2008	$	233.4

The increase in other operating expenses was primarily due to increased operating expenses related to our CCT projects ($2.6 million), wages and employee benefits ($1.1 million), and contractor and consulting services ($0.6 million) and various other individually immaterial items. Also, as described previously under “Impact of Weak Economic Conditions” the performance of our pension assets through October 31, 2008 was well below the estimated performance used to accrue 2008 pension expenses. Unless debt and equity markets improve significantly in the final months of 2008, this will have the effect of increasing our pension expenses over the 12 years beginning in 2009, which is the estimated average remaining working lifetime of the plan participants. The increase could be offset in future years if plan performance is higher than future estimates. The amount of the increase will be determined as a part of our December 31, 2008 remeasurement and it may be material.

The $5.4 million increase in depreciation and amortization was primarily due to amortization of regulatory deferrals related to CCT placed into service in September 2007 at our Harding Street generating station ($3.3 million) and an increase in depreciation expense related to the Harding Street CCT project ($2.7 million).

The increase in power purchased was due to a 52.9% increase in the volume of power purchased during the period ($7.9 million) partially offset by a decrease in the market price of purchased power ($3.0 million). The volume of power purchased increased primarily due to the timing and duration of scheduled and forced outages in 2007 and 2008 and because at times in 2008 it was less expensive for us to buy power in the market than to produce it ourselves. The decreased market price of purchased power is influenced primarily by changes in the market price of delivered fuel (primarily natural gas), the price of environmental emissions allowances, the supply of and demand for electricity, and the time of day in which power is purchased.

The increase in maintenance expenses is primarily due to the timing of scheduled generating unit maintenance outages and an increase in maintenance on overhead lines primarily as a result of increased storm damage. The $2.6 million decrease in income tax expense was primarily due to a decrease in pretax net operating income.

Other Income and Deductions

Other income and deductions decreased $1.8 million from income of $7.7 million in 2007 to income of $5.9 million in 2008. This decrease is primarily due to a $1.0 million decrease in the allowance for equity funds used during construction primarily due to decreased capital expenditures in 2008 compared to 2007. There was also a decrease in the income tax benefit of $0.4 million and a decrease in Other-net deductions due to various individually immaterial items of $0.4 million.

Comparison of nine months ended September 30, 2008 and nine months ended September 30, 2007 

Net income during the nine months ended September 30, 2008 of $51.3 million decreased $44.3 million from net income of $95.6 million during the same period in 2007. The following discussion highlights significant factors contributing to this change in net income.

Utility Operating Revenues

Utility operating revenues decreased in 2008 during the nine months ended September 30, 2008 compared to the same period in 2007 by $8.9 million, which resulted from the following changes (dollars in thousands):

	Nine months ended September 30,				Change		Percent Change
	2008		2007
Utility Operating Revenue
Retail Revenues	$	746,306	$	734,621	$	11,685	1.6%
Wholesale Revenues		43,848		46,611		(2,763)	(5.9)%
Miscellaneous Revenues		14,180		14,162		18	0.1%
Total Utility Operating Revenues	$	804,334	$	795,394	$	8,940	1.1%
Heating Degree Days		3,418		3,261		157	4.8%
Cooling Degree Days		1,058		1,454		(396)	(27.2)%

The 1.1% increase in utility operating revenues was primarily due to a 1.6% increase in retail revenues. The increase was mitigated by the $32.0 million decrease in revenue associated with the deferred fuel regulatory liabilities recorded in 2008 for credits to our retail customers. See “Liquidity and Capital Resources - Regulatory Matters - Fuel Adjustment Charge and Authorized Jurisdictional Net Operating Income” for further information regarding the credit.

Excluding the effect of the $32.0 million of credits, retail revenues increased by 5.9% ($43.7 million) primarily due to an 8.8% increase in the weighted average price per kWh sold ($62.2 million), partially offset by a 2.7% decrease in the quantity of kWh sold ($18.6 million). The increase in the weighted average price of kWhs sold was primarily due to a $34.6 million increase in revenues related to our CCT projects, and a $23.3 million increase in fuel revenues, which is offset by increased fuel and purchased power expenses attributable to serving our jurisdictional retail customers (see discussion in “Utility Operating Expenses”). The decrease in the quantity of retail kWhs sold was primarily due to the 27.2% decrease in cooling degree days during the comparable periods.

The 5.9% decrease in wholesale revenues is primarily due to a 23.9% decrease in the quantity of kWh sold ($11.1 million), partially offset by a 23.5% increase in the weighted average price per kWh sold ($8.4 million). The decrease in quantity was primarily due to the timing and duration of generating unit scheduled and forced maintenance outages and such other factors as described above under “Comparison of three months ended September 30, 2008 and three months ended September 30, 2007 - Utility Operating Revenues.”

Utility Operating Expenses

The following table illustrates our primary operating expense changes from the nine months ended September 30, 2007 to the nine months ended September 30, 2008 (in millions):

Operating Expenses for the nine months ended September 30, 2007	$	634.0
Increase in other operating expenses		18.1
Increase in depreciation and amortization		15.6
Increase in maintenance expenses		12.4
Increase in power purchased		7.6
Increase in fuel		7.2
Decrease in income taxes - net		(24.3)
Decrease in taxes other than income taxes		(0.3)
Operating Expenses for the nine months ended September 30, 2008	$	670.3

The increase in other operating expenses was primarily due to increased operating expenses related to our CCT projects ($7.3 million), wages and employee benefits ($4.1 million), and contractor and consulting services ($3.2 million) and various other individually immaterial items. For a discussion of possible trends in pension expense, see “Comparison of three months ended September 30, 2008 and three months ended September 30, 2007 - Utility Operating Expenses.”

The $15.6 million increase in depreciation and amortization is primarily due to amortization of regulatory deferrals related to CCT placed into service in September 2007 at our Harding Street generating station ($5.4 million) and an increase in depreciation expense related to the Harding Street CCT project ($8.8 million). The increase in maintenance expenses is primarily due to the increased forced outages on our generating units and an increase in maintenance on overhead lines primarily as a result of increased storm damage.

The increase in power purchased was due to a 32.6% increase in the volume of power purchased during the period ($12.8 million) partially offset by a decrease in the market price of purchased power ($5.1 million). The volume of power purchased increased primarily due to the timing and duration of scheduled and forced outages in 2007 and 2008 and because at times in 2008 it was less expensive for us to buy power in the market than to produce it ourselves. The decreased market price of purchased power is influenced primarily by changes in the market price of delivered fuel (primarily natural gas), the price of environmental emissions allowances, the supply of and demand for electricity, and the time of day in which power is purchased.

The increase in fuel was primarily due to an increase in actual fuel costs of $9.0 million due to a 10.2% increase in the cost of coal resulting primarily from a price reopener on one of our large coal contracts, as well as increases in the diesel component for coal and transportation costs. This increase is partially offset by a 5.2% decrease in the quantity of coal consumed due to a decrease in generation of 5.2%. There was a $1.0 million increase in fuel due to increased ash disposal transportation costs. These increases are partially offset by a decrease in deferred fuel costs of $3.1 million. Deferred fuel costs are the result of variances between estimated fuel and purchased power costs in our Fuel Adjustment Charges and actual fuel and purchased power costs. We are generally permitted to recover underestimated fuel and purchased power costs in future rates through the FAC proceedings and therefore, the costs are deferred and amortized into expense in the same period that our rates are adjusted. (See also “Liquidity and Capital Resources - Regulatory Matters - Fuel Adjustment Charge and Authorized Jurisdictional Net Operating Income.”) Deferred fuel costs are recorded in Fuel on the accompanying unaudited Consolidated Statements of Income.   

The $24.3 million decrease in income tax expense was primarily due to a decrease in pretax net operating income.

Other Income and Deductions

Other income and deductions increased $1.4 million from income of $22.6 million in 2007 to income of $24.0 million in 2008. Included in this increase is a $7.2 million increase in the income tax benefit, primarily due to the increase in interest on long-term debt (see below). This increase is partially offset by a $3.0 million decrease in Other-net deductions due to various individually immaterial items and a $2.8 million decrease in the allowance for equity funds used during construction primarily due to decreased capital expenditures in 2008 compared to 2007.

Interest and Other Charges

Interest and other charges increased $18.3 million for the nine months ended September 30, 2008 from the same period in 2007. This increase is primarily due to a $13.9 million early tender premium related to the repurchase of the 2008 IPALCO Notes. There was also a $3.5 million increase in interest on long-term debt due to a weighted average increase in the amount of long-term debt we had outstanding in the comparable periods primarily due to additional borrowings to fund CCT construction activities.

Liquidity and Capital Resources

As of September 30, 2008, we had unrestricted cash and cash equivalents of $40.2 million and we also had available borrowing capacity of $95.7 million under our $150.0 million committed credit facility after outstanding borrowings, existing letters of credit and liquidity support for the 1995B Bonds, which are remarketed weekly. As of September 30, 2008, we have borrowed $34.4 million on our committed credit facility to support the 1995B Bonds, which have experienced unsuccessful remarketing, and the associated interest. See “Impacts of Weak Economic Conditions” for further information. All of IPL’s long-term borrowings must first be approved by the Indiana Utility Regulatory Commission and the aggregate amount of IPL’s short-term indebtedness must be approved by the Federal Energy Regulatory Commission. We have approval from FERC to borrow up to $500 million of short-term indebtedness outstanding at any time through July 27, 2010. However, we also have restrictions on the amount of new debt that may be issued due to contractual obligations of The AES Corporation and by financial covenant restrictions under our existing debt obligations. We do not believe such restrictions will be a limiting factor in our ability to issue debt in the ordinary course of prudent business operations.

We believe that existing cash balances, short-term investments, cash generated from operating activities and borrowing capacity on our committed credit facility will be adequate on a short-term and long-term basis to meet anticipated operating expenses, interest expense on outstanding indebtedness and recurring capital expenditures. Sources for principal payments on outstanding indebtedness and nonrecurring capital expenditures are expected to be obtained from: (i) existing cash balances; (ii) cash generated from operating activities; (iii) borrowing capacity on our committed credit facility; and (iv) additional debt financing. As described previously, the current weak economic conditions may limit our access to cash in the capital markets, however we do not have any indebtedness maturing until 2011 or any major construction activity planned before 2010. Therefore, we do not anticipate a need to access the debt capital markets until at least 2010, although we may still decide to refinance some existing variable rate debt if the terms are favorable.

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 $73.0 million and $167.2 million for the nine months ended September 30, 2008 and 2007, respectively. Included in these amounts are approximately $20.6 million and $88.6 million of expenditures for 2008 and 2007, respectively, on technology designed to reduce environmental emissions related to our CCT projects. Construction expenditures during the first nine months of 2008 were financed with internally generated cash provided by operations. Construction expenditures during the first nine months of 2007 were financed with internally generated cash provided by operations, borrowings on our credit facilities, a portion of proceeds from the June 2007 issuance of $165 million IPL first mortgage bonds, and $27.5 million in draws from the construction fund associated with the issuance in September 2006 of $60 million of IPL first mortgage bonds.

Our capital expenditure program for the three-year period 2008-2010 is currently estimated to cost approximately $414 million. 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 $135 million for power plant related projects; $57 million for construction projects designed to reduce SO₂ and mercury emissions; $14 million for investments associated with additional generation and $24 million for other miscellaneous equipment and furniture. The majority of the expenditures for construction projects designed to reduce SO₂ and mercury emissions are recoverable through jurisdictional retail rate revenue as part of our CCT projects, subject to regulatory approval. Capital expenditures are financed with a combination of internally generated funds and short-term and long-term borrowings.

Contractual Cash Obligations

Our Annual Report on Form 10-K for the year ended December 31, 2007 contains a table, which details our contractual cash obligations. Significant changes to our contractual cash obligations since December 31, 2007 include the addition of $400 million of 7.25% Senior Secured Notes due April 1, 2016 and the removal of $375 million of the 2008 IPALCO Notes. See “Capital Resources - Indebtedness” below for further discussion of our debt refinancing activity.

Dividends

All of IPALCO’s outstanding common stock is held by AES. During the first nine months of 2008 and 2007, we paid dividends to AES totaling $54.2 million and $49.6 million, respectively. 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, cash flows, financial condition, capital requirements, regulatory considerations, and such other factors as IPL’s board of directors deems relevant.

Pension Plans

See Note 9, “Pension and Other Postretirement Benefits” to the unaudited Consolidated Financial Statements of IPALCO in “Item 1. Financial Statements” included in Part I - Financial Information of this Form 10-Q for information regarding pension plans and other postretirement benefit plans.

Capital Resources

Indebtedness

In April 2008, IPALCO completed the sale of the 2016 IPALCO Notes pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended. The 2016 IPALCO Notes were issued pursuant to an Indenture dated April 15, 2008, by and between IPALCO and The Bank of New York Trust Company, N.A., as trustee. In connection with this issuance, IPALCO conducted a Tender Offer to purchase for cash any and all of the 2008 IPALCO Notes outstanding, of which $375 million were outstanding.

The 2016 IPALCO Notes were sold at 98.526% of par resulting in net proceeds of $394.1 million. The $5.9 million discount is being amortized through 2016 using the effective interest method. We used these net proceeds to repurchase all of the outstanding 2008 IPALCO Notes through the Tender Offer and subsequent redemption of all remaining notes not tendered. The proceeds were also used to pay the early tender premium of $13.9 million (included in Interest on long-term debt in the accompanying unaudited Consolidated Statements of Income) and other fees and expenses related to the Tender Offer and the redemption of the 2008 IPALCO Notes and the issuance of the 2016 IPALCO Notes.

In addition, we solicited and received consents to amend the applicable indenture with respect to the 2008 IPALCO Notes and entered into the Indenture Supplement dated April 15, 2008, with The Bank of New York Trust Company, N.A., as trustee, to the Indenture between the parties dated November 14, 2001. The Indenture Supplement amends the Original Indenture with respect to the 2008 IPALCO Notes to eliminate substantially all of the restrictive covenants, several affirmative covenants and certain events of default, modify the covenant regarding mergers, consolidations and sales of the IPALCO’s assets and eliminate or modify certain other provisions. 

The 2016 IPALCO Notes are secured by IPALCO’s pledge of all of the outstanding common stock of IPL. The lien on the pledged shares will be shared equally and ratably with IPALCO’s existing senior secured notes. IPALCO has entered into a Pledge Agreement Supplement with The Bank of New York Trust Company, N.A., as Collateral Agent, dated April 15, 2008 to the Pledge Agreement between IPALCO and The Bank of New York Trust Company, N.A. as successor Collateral Agent dated November 14, 2001.

See “Impacts of Weak Economic Conditions” for information regarding the 1995B Bonds.

Related Party Transactions

In the first quarter of 2008, IPL exchanged 20,661 SO₂ environmental air emissions allowances for 20,718 SO₂ environmental air emissions allowances with wholly-owned subsidiaries of AES. Because the transactions lacked commercial substance and were between entities under common control, the exchanges have been accounted for by IPL at their historical cost. This transaction did not have a material impact on our results of operations or financial condition.

Sales of Accounts Receivable

In May 2008, the receivables sales agreement included as part of our $50 million sale of accounts receivable was extended through May 26, 2009.

Regulatory Matters

Basic Rates and Charges

Our basic rates and charges are determined after giving consideration, on a pro-forma basis, to all allowable costs for ratemaking purposes including a fair return on the fair value of the utility property used and useful in providing service to customers. Pursuant to statute, the IURC is to conduct a periodic review of the basic rates and charges of all utilities at least once every four years, but the IURC has the authority to review the rates of any utility at any time it chooses. Once set, the basic rates and charges authorized do not assure the realization of a fair return on the fair value of property. IPL’s basic rates and charges were last adjusted in 1996.

Fuel Adjustment Charge and Authorized Jurisdictional Net Operating Income

We may apply to the IURC for a change in our fuel charge every three months to recover our estimated fuel costs, including the fuel portion of purchased power costs, which may be above or below the levels included in our basic rates and charges. Independent of the IURC’s ability to review basic rates and charges, Indiana law requires electric utilities under the jurisdiction of the IURC to meet operating expense and income test requirements as a condition for approval of requested changes in FAC. Additionally, customer refunds may result if a utility’s rolling twelve month operating income, determined at quarterly measurement dates, exceeds a utility’s authorized annual jurisdictional net operating income and there are not sufficient applicable cumulative net operating income deficiencies against which the excess rolling twelve month jurisdictional net operating income can be offset.

In our five most recently approved FAC filings, the IURC found that our rolling annual jurisdictional retail electric net operating income was greater than the authorized annual jurisdictional net operating income. Because we have a cumulative net operating income deficiency, we have not been required to make customer refunds in our FAC proceedings. In our September 2008 FAC filing (FAC 81), which has not yet been approved by the IURC, our rolling annual jurisdictional retail electric net operating income was calculated to be less than the authorized annual jurisdictional net operating income by $7.9 million for the twelve months ended July 31, 2008. Even though we have a cumulative net operating income deficiency, the IURC may still review our basic rates and charges on a prospective basis at any time it chooses.

In December 2007, we received a letter from the staff of the IURC requesting information relevant to the IURC’s periodic review of our basic rates and charges and we subsequently provided information to the staff. Since our cumulative net operating income deficiency (described above) requires no customer refunds in the FAC process, the IURC staff was concerned that the higher than usual 2007 earnings may continue in the future. In an effort to allay staff’s concerns, we proposed in our March and June 2008 FAC filings (FAC 79 and 80) prospective credits to our retail customers totaling $30 million and $2 million, respectively. Consistent with these proposals, we recorded a $30 million deferred fuel regulatory liability in March 2008 and a $2 million deferred fuel regulatory liability in June 2008, with corresponding and respective reductions against revenues. All $32 million of proposed credits have been approved by the IURC and approximately $28.5 million have been applied through September 30, 2008 in the form of offsets against fuel charges that customers would have otherwise been billed during June through September 30, 2008.

In our March 2006 FAC proceeding (FAC 71), a consumer advocacy group representing some of our industrial customers requested that a sub-docket be established. We and the customer group entered into an agreement regarding the scope of the sub-docket which was approved by the IURC in its May 2006 order in our FAC 71 proceeding. The agreement defines the scope of the sub-docket as “any issue related to FAC 71” and includes illustrative examples including: review of the Midwest ISO components of the cost of fuel, review of projection of the Midwest ISO components of the cost of fuel, review of allocation of fuel and other costs, and review of compliance with Indiana Code 8-1-2-42(d), all as they relate to FAC 71 only. A hearing was held in October 2008, at which time the parties submitted direct testimony into the record.

Through the sub-docket, the industrial group is seeking an IURC order requiring us to provide customer refunds for past charges and changes to future ratemaking. We believe we have meritorious defenses to the claims in the sub-docket, however, if the industrial group prevails, changes to ratemaking could have a material impact on our future results of operations and financial condition. Because of the uncertain outcome of the FAC 71 sub-docket, the IURC Orders in our FAC 71 proceeding and subsequent FAC proceedings (through FAC 80) approved our FAC factors on an interim basis, subject to refund. The IURC’s Orders in our FAC 77 through FAC 80 proceedings also set our FAC factor on an interim basis, subject to refund, pending the outcome of the FERC proceeding regarding Revenue Sufficiency Guarantee Second Pass charges and any subsequent appeals or future order of the IURC. We cannot predict the outcome of the proceeding at this time.

Purchased power costs below an established benchmark are presumed to be recoverable fuel costs. In April 2008, the IURC issued a final order, which approved our joint petition filed along with another Indiana utility and the Indiana Office of Utility Consumer Counselor. This petition requested a new settlement mechanism for the recovery of fuel costs in the cost of purchased electricity. Under the former agreement, hourly purchased power costs were compared to a monthly standard. Under the new settlement agreement, hourly purchased power costs are compared to a daily benchmark to better reflect changes in natural gas prices that occur throughout the month. We believe that changes in natural gas prices typically influence the price at which we can purchase power. Therefore, we believe that the new benchmark will more closely track fluctuations in purchased power prices. The new benchmark expires in April 2010. Purchased power costs over the benchmark not recovered from our customers have not had a material impact on our results of operations or financial condition to date.

Wind Power Purchase Agreement

In April 2008, we entered into a power purchase agreement for 20 years of approximately 100 MW of wind generated electricity with Hoosier Wind Project, LLC, a subsidiary of enXco, Inc. The contract was contingent, among other things, on the IURC approval of cost recovery via a cost recovery mechanism similar to the FAC and the extension of the federal production tax credit for qualified renewable energy producers. In April 2008, we filed the request with the IURC for such recovery. In October 2008, the IURC approved the request. Additionally, in October 2008, the federal production tax credit for qualified renewable energy producers was extended until January 1, 2010. Construction is expected to begin shortly and the operation of the facility is expected to begin in 2009. This agreement will help us to diversify the resources available to serve our customers in light of potential greenhouse gas and renewable portfolio standards legislation. Renewable portfolio standards, which would require a certain percentage of an electric utility’s electricity to come from renewable sources by a given date, have been considered at both the state and federal levels. However, it is currently unclear what future legislation related to renewable portfolio standards we might face.

Clean Coal Technology Filings

In April 2008, in response to an updated Plan we filed, the IURC issued an Order approving recovery of capital expenditures of approximately $92.7 million over the next three years. The $92.7 million approved by the IURC includes $90.0 million to install and/or upgrade CCT to further reduce SO₂ and mercury emissions at our Petersburg generating station and $2.7 million for mercury emissions monitoring equipment at our coal-fired power plants. We currently estimate the installation and/or upgrade of CCT to further reduce SO₂ and mercury emissions at our Petersburg generating station will cost approximately $98.5 million. We intend to seek recovery of any costs incurred on this project above the currently authorized $90.0 million; however, there can be no assurance that such recovery will be granted. The IURC also approved the ratemaking treatment applicable to qualified pollution control property to be recovered through an Environmental Compliance Cost Recovery Adjustment, similar to that which we have received in previous environmental filings. Such treatment includes a return on the construction costs and recovery of depreciation expenses and operation and maintenance expenses associated with these projects. The IURC also granted us the authority to add the approved return on our environmental projects to our authorized annual jurisdictional net operating income in subsequent FAC proceedings.

Because the federal Clean Air Interstate Rule has been vacated, as discussed in “Environmental Matters - Clean Air Interstate Rule,” we are planning to delay the targeted in service date of CCT to further reduce SO₂ and mercury emissions at our Petersburg generating station from 2010 to 2011, with the majority of the construction expenditures occurring in 2010 and 2011. The installation of the mercury emissions monitoring equipment at our coal-fired power plants is also under review given that the mercury monitoring requirements under the Indiana Clean Air Mercury Rules are uncertain as a result of the federal CAMR being vacated and the opinion letter from the Indiana Office of Attorney General, as discussed in “Environmental Matters - Clean Air Mercury Rule.” Until there is greater regulatory clarity around our obligations, we have suspended our plan to install mercury monitors.

Demand-Side Management

In 2004, the IURC initiated a generic investigation to consider and review DSM issues and programs in Indiana, including the overall effectiveness of DSM programs in the state and ways to improve DSM programs. DSM programs promote customer energy efficiency and encourage energy conservation, and allow customers to participate in time based pricing rate schedules and other demand response programs. In April 2008, the IURC issued a Phase I Order which found that Phase II of the proceeding shall be initiated to fully address the following issues: (1) Indiana’s low spending levels on DSM Programs and high per capita energy use; (2) possible development of a core group of “best practices” DSM programs; (3) the feasibility and associated costs and benefits of a statewide Third Party DSM Administrator; (4) development of a uniform energy efficiency/DSM database; (5) issues identified in the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007, including consideration of new technologies such as automated metering; and (6) the formation of an Oversight Board, to oversee the development of a more uniform statewide strategy with respect to DSM Programs. We cannot predict the outcome of the proceeding or its impact on us at this time, but it will likely require us to increase our level of DSM spending over the next few years. We plan to continue to seek recovery of existing and future DSM program costs.

Energy Policy Act of 2005

In July 2007, the IURC initiated a generic investigation to consider: whether existing Indiana law and the IURC processes are sufficient to ensure utilities develop a plan to minimize dependence on a single fuel source, what are the appropriate utility methods to ensure energy is generated using a diverse range of fuels and technologies, and whether the energy market provides sufficient incentive for utilities to diversify their fuel sources and increase their fossil fuel generating efficiency. In July 2008, an IURC Order indicated that no additional standards need to be promulgated at this time.

Federal Energy Regulatory Commission - Midwest ISO

Midwest ISO’s Energy and Ancillary Services Markets Tariff

As described in our 2007 Form 10-K, the Midwest ISO’s ASM were expected to be launched on September 9, 2008. In August 2008, the Midwest ISO requested a delay with the FERC for launching the ASM and as a result, the launch date has been rescheduled to January 6, 2009.

In January 2008, we and other investor-owned Indiana utilities operating in the Midwest ISO filed a joint petition requesting the IURC to issue an order approving operational changes necessary for joint petitioners to accommodate the ASM, and to determine the precise manner and timing of recovery or crediting of jurisdictional charges and revenues associated with the Midwest ISO ASM. In August 2008, the IURC approved the operational changes necessary for joint petitioners to accommodate the ASM. The IURC proceeding to determine the precise manner and timing of recovery or crediting of jurisdictional charges and revenues associated with the Midwest ISO ASM is pending and we cannot predict the outcome at this time.

Environmental Matters

We are subject to various federal, state 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 you that we have been or will be at all times in full compliance with such laws, regulations and permits, however, we do not believe any currently open investigations will result in fines material to our results of operations or financial position.

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 or financial condition.

Clean Air Interstate Rule

As discussed in our 2007 Form 10-K, in March 2005 the U.S. Environmental Protection Agency finalized the federal CAIR, which imposes restrictions against polluting the air of downwind states. The federal CAIR established a two-phase regional “cap and trade” program for SO₂ and NO_x emissions that would require the largest reduction in air pollution in more than a decade. The federal CAIR covered 28 eastern states, including Indiana, and the District of Columbia. In July 2008, the U.S. Court of Appeals for the D.C. Circuit vacated and remanded the federal CAIR to the EPA. However, in September 2008, the EPA appealed the ruling to the full bench (en banc) of the U.S. Court of Appeals for the D.C. Circuit. It is pending further action. In October 2008, the full bench of the U.S. Court of Appeals for the D.C. Circuit issued an Order requesting that all of the petitioners answer two questions. The petitioners are to answer whether they would prefer a complete vacature of federal CAIR or whether they would prefer the Court stay its ruling that federal CAIR be vacated, and instead allow the EPA to create a new rule that addresses the Court’s initial concerns. At this time, it is not clear what impact this ruling will have on our business, results of operations or financial position.

In October 2008, the Indiana Department of Environmental Management indicated that it intends to propose an Indiana CAIR before the Indiana Air Pollution Control Board at its December 2008 meeting to become effective if and when the U.S. Court of Appeals for the D.C. Circuit formally vacates the federal CAIR. The IDEM proposal, if adopted, will be issued under the State emergency rulemaking authority. IDEM has yet to issue a draft rule and therefore we cannot determine the potential impact on our business, results of operations or financial position.

Clean Air Mercury Rule

As discussed in our 2007 Form 10-K, in March 2005, the EPA finalized the federal CAMR that required utilities to reduce mercury emissions from new and existing coal fired power plants. The rule created “standards of performance” limiting mercury emissions from utilities and established a staged approach for reductions via a “cap and trade” program. In February 2008, the U.S. Court of Appeals for the D.C. Circuit vacated the federal CAMR, requiring the EPA to promulgate a new mercury emissions rule which presumably will not include a “cap and trade” program. Subsequently, in July 2008, the Indiana Office of the Attorney General issued an Advisory Letter No. 08-17 regarding implementation and enforcement of the Indiana CAMR, which resulted in the IDEM providing a formal opinion that the Indiana CAMR should not be enforced. As a result, IPL will not be required to meet either the mercury emission reduction requirements or install mercury monitors until such time as there is either judicial or regulatory finality. In October 2008, the EPA filed a petition with the U.S. Supreme Court requesting that it review the February 2008 decision.

Clean Coal Technology

Please see “Regulatory Matters - Clean Coal Technology Filings” and “Liquidity and Capital Resources - Capital Requirements - Capital Expenditures” for a discussion of our environmental technologies and related capital expenditures.

Carbon Dioxide

In 2007, our generating power plants emitted approximately 18.5 million tons of CO2. We continue to monitor developments with respect to the regulation of CO2 emissions under the Clean Air Act. Regulatory initiatives regarding CO2 may be implemented in the future, although at this time we cannot predict if, how, or to what extent such initiatives would affect us. Generally, we believe costs to comply with any regulations implemented to reduce greenhouse gas emissions would be deemed as part of the costs of providing electricity to our customers and as such, we would seek recovery for such costs in our rates. However, no assurance can be given as to whether the IURC will approve such requests. In light of potential greenhouse gas and renewable portfolio standards legislation, in April 2008, we entered into a 20 year 100 MW wind power purchase agreement, which will help us to diversify our sources of electricity available for sale. Please see “Regulatory Matters - Wind Purchase Power Agreement” above, for further discussion.

In July 2008, the EPA issued an advanced notice of proposed rulemaking soliciting comments on whether and how greenhouse gas emissions should be regulated under the CAA. The advanced notice of proposed rulemaking marks the EPA’s first rulemaking step to respond to the U.S. Supreme Court’s decision in Massachusetts v. EPA, which requires the EPA to decide under the CAA’s mobile source title whether greenhouse gases contribute to climate change, and if so, promulgate appropriate regulations, or explain why the EPA cannot make such an endangerment judgment at this time. However, currently, it is not clear what impact this proposed rulemaking will have on our business, results of operation or financial position.

New Source Review

Several years ago, as discussed in our 2007 Form 10-K, the EPA commenced an investigation of the fossil fuel-fired electric power generation industry to determine compliance with environmental requirements under the CAA associated with repairs, maintenance, modifications and operational changes made to facilities over the years. The EPA’s focus was on whether such changes were subject to New Source Review or new source performance standards, and whether best available control technology was or should have been installed. In the summer of 2000, we received two CAA Section 114 requests from the EPA regarding our maintenance modifications and operational activities over the previous twenty-five years. We responded to this information request in 2000 and 2001. To date, the EPA has yet to act directly on this request.

In September 2008, we received another CAA Section 114 information request. The request seeks various information regarding production levels and projects implemented at our generating stations, generally for the time period from January 1, 2001, to the date of the information request. These types of information requests have been used in the past to assist the EPA in determining whether a plant is in compliance with applicable standards under the CAA. At this time, we cannot predict what impact, if any, this request may have on our business, results of operation or financial position.

Regional Haze

The EPA published the final regional haze rule on July 1, 1999. This rule established planning and emissions reduction timelines for states to use to improve visibility in national parks throughout the United States. In 2001, the EPA signed a proposed rule to guide states in implementing the 1999 rule and in controlling power plant emissions that cause regional haze problems. The proposed rule set guidelines for states in setting Best Available Retrofit Technology at older power plants. In 2004, the EPA published a proposed rule with new BART provisions and reproposed the BART guidelines. In June 2005, the EPA finalized amendments to the 1999 regional haze rule. The EPA determined that states, such as Indiana, which adopt the federal CAIR “cap and trade” program for SO₂ and NO_x, will be allowed to apply federal CAIR controls as a substitute for controls required under BART. The Indiana Air Pollution Control Board has approved a final rule implementing BART which provides that sources in compliance with federal CAIR controls are also in compliance with BART requirements for SO₂ and NO_x. Because we intended to comply with SO₂ and NO_x “cap and trade” program under the federal CAIR, we believed that we would satisfy BART requirements. However, since the federal CAIR has been vacated, at this time, it is unclear whether compliance with federal CAIR or anticipated Indiana CAIR (as discussed above) requirements, will satisfy BART requirements.

NEW ACCOUNTING STANDARDS

See Note 3, “New Accounting Pronouncements” to the unaudited Consolidated Financial Statements of IPALCO in “Item 1. Financial Statements” included in Part I - Financial Information of this Form 10-Q for information regarding new accounting standards.

EMPLOYEES

In October 2008, the International Brotherhood of Electrical Workers Physical Bargaining Unit ratified a new four-year agreement with IPL effective as of September 29, 2008. The new agreement provides for wage increases of 4.0% effective September 29, 2008; 3.5% effective December 7, 2009; 3.5% effective December 6, 2010; and 4.0% effective December 5, 2011. In addition, the new agreement also provides for a 10.0% increase in retirement pension bands, which will increase our future pension expense and funding requirements.

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, 2008. 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, 2008, 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, 2008 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 - Environmental Matters,” and Note 10, “Commitments and Contingencies” to the unaudited Consolidated Financial Statements of IPALCO in “Item 1. Financial Statements” included in Part I - Financial Information of this Form 10-Q 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, 2007

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

EXHIBIT NO.	DOCUMENT
31.1	Certification by Chief Executive Officer required by Rule 13a-14(a) or 15d-14(a).
31.2	Certification by Principal Financial Officer required by Rule 13a-14(a) or 15d-14(a).
32	Certification required by Rule 13a-14(b) or 15d-14(b).

SIGNATURES

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

		IPALCO ENTERPRISES, INC.
		(Registrant)
Date:	November 6, 2008	/s/ Kirk B. Michael
		Kirk B. Michael
		Vice President and Chief Financial Officer
		(Principal Financial Officer)
Date:	November 6, 2008	/s/ Kurt A. Tornquist
		Kurt A. Tornquist
		Vice President and Controller
		(Principal Accounting Officer)