10q for VUHI

10-Q 1 vuhi10q_sep05.htm 10Q FOR VUHI 10q for VUHI

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2005

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

For the transition period from __________________ to __________________

Commission file number: 1-16739

VECTREN UTILITY HOLDINGS, INC.

(Exact name of registrant as specified in its charter)

INDIANA		35-2104850
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

One Vectren Square, Evansville, Indiana, 47708

(Address of principal executive offices)

(Zip Code)

812-491-4000

(Registrant's telephone number, including area code)

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 x No __

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes __ No x

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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.

Common Stock- Without Par Value	10	October 31, 2005
Class	Number of Shares	Date

Table of Contents

Item Number		Page Number
	PART I. FINANCIAL INFORMATION
1	Financial Statements (Unaudited)
	Vectren Utility Holdings, Inc and Subsidiary Companies
	Consolidated Condensed Balance Sheets	3-4
	Consolidated Condensed Statements of Income	5
	Consolidated Condensed Statements of Cash Flows	6
	Notes to Unaudited Consolidated Condensed Financial Statements	7
2	Management’s Discussion and Analysis of Results of Operations and Financial Condition	20
3	Quantitative and Qualitative Disclosures About Market Risk	32
4	Controls and Procedures	32

	PART II. OTHER INFORMATION
1	Legal Proceedings	33
6	Exhibits	33
	Signatures	34

Access to Information

Vectren Corporation makes available all SEC filings and recent annual reports free of charge, including those of its wholly owned subsidiary, Vectren Utility Holdings, Inc., through its website at www.vectren.com, or by request, directed to Investor Relations at the mailing address, phone number, or email address that follows:

Mailing Address:

One Vectren Square

Evansville, Indiana 47708

Phone Number:

(812) 491-4000

Investor Relations Contact:

Steven M. Schein

Vice President, Investor Relations

sschein@vectren.com

Definitions

AFUDC: allowance for funds used during construction	MMBTU: millions of British thermal units
APB: Accounting Principles Board	MW: megawatts
EITF: Emerging Issues Task Force	MWh / GWh: megawatt hours / thousands of megawatt hours (gigawatt hours)
FASB: Financial Accounting Standards Board	NOx: nitrogen oxide
FERC: Federal Energy Regulatory Commission	OUCC: Indiana Office of the Utility Consumer Counselor
IDEM: Indiana Department of Environmental Management	PUCO: Public Utilities Commission of Ohio
IURC: Indiana Utility Regulatory Commission	SFAS: Statement of Financial Accounting Standards
MCF / MMCF / BCF: thousands / millions / billions of cubic feet	USEPA: United States Environmental Protection Agency
MDth / MMDth: thousands / millions of dekatherms	Throughput: combined gas sales and gas transportation volumes

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited - In millions)


	September 30,			December 31,
		2005		2004

ASSETS

Current Assets
Cash & cash equivalents	$	3.2	$	5.7
Accounts receivable - less reserves of $2.3 &
$1.9, respectively		75.7		147.5
Receivables due from other Vectren companies		0.1		4.0
Accrued unbilled revenues		47.1		161.2
Inventories		69.4		53.0
Recoverable fuel & natural gas costs		17.1		17.7
Prepayments & other current assets		172.4		138.2
Total current assets		385.0		527.3

Utility Plant
Original cost		3,563.5		3,465.2
Less: accumulated depreciation & amortization		1,361.5		1,309.0
Net utility plant		2,202.0		2,156.2

Investments in unconsolidated affiliates		0.2		0.2
Other investments		20.3		19.6
Non-utility property - net		160.1		149.6
Goodwill - net		205.0		205.0
Regulatory assets		88.0		82.5
Other assets		6.5		7.3
TOTAL ASSETS	$	3,067.1	$	3,147.7

The accompanying notes are an integral part of these consolidated condensed financial statements.

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited - In millions)


	September 30,			December 31,
		2005		2004

LIABILITIES & SHAREHOLDER'S EQUITY

Current Liabilities
Accounts payable	$	67.8	$	97.3
Accounts payable to affiliated companies		77.3		98.8
Payables to other Vectren companies		14.3		15.8
Refundable fuel & natural gas costs		11.0		6.3
Accrued liabilities		105.7		110.0
Short-term borrowings		248.1		308.3
Long-term debt subject to tender		-		10.0
Total current liabilities		524.2		646.5

Long-Term Debt - Net of Current Maturities &
Debt Subject to Tender		951.6		941.3
Deferred Income Taxes & Other Liabilities
Deferred income taxes		250.6		240.8
Regulatory liabilities		266.0		251.7
Deferred credits & other liabilities		84.3		81.9
Total deferred credits & other liabilities		600.9		574.4

Commitments & Contingencies (Notes 7 - 9)

Cumulative, Redeemable Preferred Stock of a Subsidiary		-		0.1

Common Shareholder's Equity
Common stock (no par value)		593.0		592.9
Retained earnings		397.4		392.5
Total common shareholder's equity		990.4		985.4

TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,067.1	$	3,147.7

The accompanying notes are an integral part of these consolidated condensed financial statements.

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED CONDENSED STATEMENTS OF INCOME

(Unaudited - In millions)


		Three Months				Nine Months
		Ended September 30,				Ended September 30,
		2005		2004		2005		2004
OPERATING REVENUES
Gas utility	$	136.8	$	112.3	$	839.5	$	771.6
Electric utility		128.7		102.3		320.3		280.2
Other		0.2		0.1		0.5		0.5
Total operating revenues		265.7		214.7		1,160.3		1,052.3

OPERATING EXPENSES
Cost of gas sold		81.6		67.2		568.8		529.8
Fuel for electric generation		39.3		25.8		95.6		72.4
Purchased electric energy		8.8		5.3		14.7		16.6
Other operating		58.9		52.0		179.7		167.7
Depreciation & amortization		36.3		33.1		104.2		94.5
Taxes other than income taxes		10.1		9.6		43.6		42.4
Total operating expenses		235.0		193.0		1,006.6		923.4

OPERATING INCOME		30.7		21.7		153.7		128.9

OTHER INCOME - NET
Equity in earnings of unconsolidated affiliates		-		-		-		0.2
Other income - net		1.3		2.3		4.6		5.7
Total other income - net		1.3		2.3		4.6		5.9
Interest expense		17.5		16.7		50.8		50.2
INCOME BEFORE INCOME TAXES		14.5		7.3		107.5		84.6
Income taxes		5.6		2.8		42.7		32.7

NET INCOME	$	8.9	$	4.5	$	64.8	$	51.9

The accompanying notes are an integral part of these consolidated condensed financial statements.

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited - In millions)


Nine Months Ended September 30,
		2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	64.8		$	51.9
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization		104.2			94.5
Deferred income taxes & investment tax credits		4.6			28.6
Pension & postretirement periodic benefit cost		4.5			4.3
Equity in (earnings) losses of unconsolidated affiliates		-			(0.2	)
Net unrealized losses on derivative instruments		(1.4	)		1.0
Other non-cash charges - net		8.4			7.2
Changes in working capital accounts:
Accounts receivable, including to Vectren companies		183.4			121.3
Inventories		(16.1	)		(5.4	)
Recoverable fuel & natural gas costs		5.3			(18.2	)
Prepayments & other current assets		(27.9	)		(21.8	)
Accounts payable, including to Vectren companies		(52.5	)		(21.1	)
Accrued liabilities		(4.3	)		(9.9	)
Changes in noncurrent assets		0.8			(5.4	)
Changes in noncurrent liabilities		(12.6	)		(8.0	)
Net cash flows from operating activities		261.2			218.8
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Additional capital contribution		-			2.9
Requirements for:
Dividends to parent		(60.0	)		(60.0	)
Redemption of preferred stock of subsidiary		(0.1	)		(0.1	)
Retirement of long-term debt, including premiums paid		-			(12.7	)
Net change in short-term borrowings		(60.2	)		25.8
Net cash flows from financing activities		(120.3	)		(44.1	)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from other investing activities		-			3.5
Requirements for:
Capital expenditures, excluding AFUDC-equity		(143.4	)		(182.9	)
Net cash flows from investing activities		(143.4	)		(179.4	)
Net decrease in cash & cash equivalents		(2.5	)		(4.7	)
Cash & cash equivalents at beginning of period		5.7			8.1
Cash & cash equivalents at end of period	$	3.2		$	3.4

The accompanying notes are an integral part of these consolidated condensed financial statements.

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

(UNAUDITED)

1.	Organization and Nature of Operations

Vectren Utility Holdings, Inc. (Utility Holdings or the Company), an Indiana corporation, serves as the intermediate holding company for Vectren Corporation’s (Vectren) three operating public utilities: Indiana Gas Company, Inc. (Indiana Gas or Vectren North), Southern Indiana Gas and Electric Company (SIGECO or Vectren South), and the Ohio operations. Utility Holdings also has other assets that provide information technology and other services to the three utilities. Vectren is an energy and applied technology holding company headquartered in Evansville, Indiana. Both Vectren and Utility Holdings are exempt from registration pursuant to Section 3(a)(1) and 3(c) of the Public Utility Holding Company Act of 1935.

Indiana Gas provides energy delivery services to approximately 555,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 136,000 electric customers and approximately 110,000 natural gas customers located near Evansville in southwestern Indiana. SIGECO also owns and operates electric generation to serve its electric customers and optimizes those assets in the wholesale power market. Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana. The Ohio operations provide energy delivery services to approximately 315,000 natural gas customers located near Dayton in west central Ohio. The Ohio operations are owned as a tenancy in common by Vectren Energy Delivery of Ohio, Inc. (VEDO), a wholly owned subsidiary, (53% ownership) and Indiana Gas (47% ownership). The Ohio operations generally do business as Vectren Energy Delivery of Ohio.

2.	Basis of Presentation

The interim consolidated condensed financial statements included in this report have been prepared by the Company, without audit, as provided in the rules and regulations of the Securities and Exchange Commission. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been omitted as provided in such rules and regulations. The Company believes that the information in this report reflects all adjustments necessary to fairly state the results of the interim periods reported. These consolidated condensed financial statements and related notes should be read in conjunction with the Company’s audited annual consolidated financial statements for the year ended December 31, 2004, filed March 9, 2005 on Form 10-K. Certain amounts from the prior period reported in this Quarterly Report on Form 10-Q have been reclassified to conform to the 2005 financial statement presentation. Because of the seasonal nature of the Company’s utility operations, the results shown on a quarterly basis are not necessarily indicative of annual results.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

3.	Subsidiary Guarantor and Consolidating Information

The Company’s three operating utility companies, SIGECO, Indiana Gas, and VEDO, are guarantors of Utility Holdings’ $350.0 million in short-term credit facilities, of which $248.0 million is outstanding at September 30, 2005, and Utility Holdings’ $550.0 million unsecured senior notes outstanding at September 30, 2005. The guarantees are full and unconditional and joint and several, and Utility Holdings has no subsidiaries other than the subsidiary guarantors. However, as described in Note 1, Utility Holdings does have operations other than those of the subsidiary guarantors. Pursuant to Article 3-10 of Regulation S-X, disclosure of the results of operations and balance sheets of the subsidiary guarantors separate from the parent company’s operations is required. Following are consolidating financial statements including information on the combined operations of the subsidiary guarantors separate from the other operations of the parent company.

Consolidating Statement of Income for the three months ended September 30, 2005 (in millions):

	Subsidiary			Parent		Eliminations &
		Guarantors		Company		Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	136.8	$	-	$	-		$	136.8
Electric utility		128.7		-		-			128.7
Other		-		8.9		(8.7	)		0.2
Total operating revenues		265.5		8.9		(8.7	)		265.7
OPERATING EXPENSES
Cost of gas sold		81.6		-		-			81.6
Fuel for electric generation		39.3		-		-			39.3
Purchased electric energy		8.8		-		-			8.8
Other operating		67.5		-		(8.6	)		58.9
Depreciation & amortization		31.2		5.0		0.1			36.3
Taxes other than income taxes		9.9		0.2		-			10.1
Total operating expenses		238.3		5.2		(8.5	)		235.0
OPERATING INCOME		27.2		3.7		(0.2	)		30.7
OTHER INCOME (EXPENSE) - NET
Equity in earnings of consolidated companies		-		6.9		(6.9	)		-
Other income (expense) – net		0.9		9.3		(8.9	)		1.3
Total other income (expense) - net		0.9		16.2		(15.8	)		1.3
Interest expense		16.3		10.6		(9.4	)		17.5
INCOME BEFORE INCOME TAXES		11.8		9.3		(6.6	)		14.5
Income taxes		4.9		0.4		0.3			5.6
NET INCOME	$	6.9	$	8.9	$	(6.9	)	$	8.9

Consolidating Statement of Income for the three months ended September 30, 2004 (in millions):

		Subsidiary		Parent			Eliminations &
		Guarantors		Company			Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	112.3	$	-		$	-		$	112.3
Electric utility		102.3		-			-			102.3
Other		0.1		7.5			(7.5	)		0.1
Total operating revenues		214.7		7.5			(7.5	)		214.7
OPERATING EXPENSES
Cost of gas sold		67.2		-			-			67.2
Fuel for electric generation		25.8		-			-			25.8
Purchased electric energy		5.3		-			-			5.3
Other operating		57.6		1.9			(7.5	)		52.0
Depreciation & amortization		28.6		4.5			-			33.1
Taxes other than income taxes		9.4		0.2			-			9.6
Total operating expenses		193.9		6.6			(7.5	)		193.0
OPERATING INCOME		20.8		0.9			-			21.7
OTHER INCOME (EXPENSE) - NET
Equity in losses of consolidated companies		-		3.1			(3.1	)		-
Other income (expense) – net		1.3		9.2			(8.2	)		2.3
Total other income (expense) - net		1.3		12.3			(11.3	)		2.3
Interest expense		15.6		9.3			(8.2	)		16.7
INCOME BEFORE INCOME TAXES		6.5		3.9			(3.1	)		7.3
Income taxes		3.4		(0.6	)		-			2.8
NET INCOME	$	3.1	$	4.5		$	(3.1	)	$	4.5

Consolidating Statement of Income for the nine months ended September 30, 2005 (in millions):

		Subsidary		Parent		Eliminations &
		Guarantors		Company		Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	839.5	$	-	$	-		$	839.5
Electric utility		320.3		-		-			320.3
Other		-		27.1		(26.6	)		0.5
Total operating revenues		1,159.8		27.1		(26.6	)		1,160.3
OPERATING EXPENSES
Cost of gas sold		568.8		-		-			568.8
Fuel for electric generation		95.6		-		-			95.6
Purchased electric energy		14.7		-		-			14.7
Other operating		204.5		-		(24.8	)		179.7
Depreciation & amortization		90.1		13.9		0.2			104.2
Taxes other than income taxes		42.9		0.7		-			43.6
Total operating expenses		1,016.6		14.6		(24.6	)		1,006.6
OPERATING INCOME		143.2		12.5		(2.0	)		153.7
OTHER INCOME (EXPENSE) - NET
Equity in earnings of consolidated companies		-		58.6		(58.6	)		-
Other income (expense) – net		1.7		28.1		(25.2	)		4.6
Total other income (expense) - net		1.7		86.7		(83.8	)		4.6
Interest expense		47.8		30.5		(27.5	)		50.8
INCOME BEFORE INCOME TAXES		97.1		68.7		(58.3	)		107.5
Income taxes		38.5		3.9		0.3			42.7
NET INCOME	$	58.6	$	64.8	$	(58.6	)	$	64.8

Consolidating Statement of Income for the nine months ended September 30, 2004 (in millions):

		Subsidiary		Parent		Eliminations &
		Guarantors		Company		Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	771.6	$	-	$	-		$	771.6
Electric utility		280.2		-		-			280.2
Other		-		25.5		(25.0	)		0.5
Total operating revenues		1,051.8		25.5		(25.0	)		1,052.3
OPERATING EXPENSES
Cost of gas sold		529.8		-		-			529.8
Fuel for electric generation		72.4		-		-			72.4
Purchased electric energy		16.6		-		-			16.6
Other operating		190.4		0.4		(23.1	)		167.7
Depreciation & amortization		81.3		13.2		-			94.5
Taxes other than income taxes		41.6		0.8		-			42.4
Total operating expenses		932.1		14.4		(23.1	)		923.4
OPERATING INCOME		119.7		11.1		-			128.9
OTHER INCOME (EXPENSE) - NET
Equity in earnings of consolidated companies		-		46.1		(46.1	)		-
Equity in earnings of unconsolidated affiliates		-		0.2		-			0.2
Other income (expense) – net		2.0		25.8		(22.1	)		5.7
Total other income (expense) - net		2.0		72.1		(68.2	)		5.9
Interest expense		46.8		27.4		(24.0	)		50.2
INCOME BEFORE INCOME TAXES		74.9		55.8		(46.1	)		84.6
Income taxes		28.8		3.9		-			32.7
NET INCOME	$	46.1	$	51.9	$	(46.1	)	$	51.9

Consolidating Statement of Cash Flows for the nine months ended September 30, 2005 (in millions):

		Subsidiary			Parent
		Guarantors			Company			Eliminations			Consolidated

Net cash flows from operating activities	$	240.1		$	21.1		$	-		$	261.2

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from additional capital contribution		125.0			-			(125.0	)		-

Requirements for:
Dividends to parent		(60.0	)		(60.0	)		60.0			(60.0	)
Redemption of preferred stock of subsidiary		(0.1	)		-			-			(0.1	)
Net change in short-term borrowings		(188.3	)		(59.9	)		188.0			(60.2	)
Net cash flows from financing activities		(123.4	)		(119.9	)		123.0			(120.3	)

CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Consolidated subsidiary distributions		-			60.0			(60.0	)		-
Requirements for:
Capital expenditures, excluding AFUDC-equity		(118.8	)		(24.6	)		-			(143.4	)
Consolidated affiliate and other investments		-			(125.0	)		125.0			-
Net change in notes receivable to other Vectren companies		-			188.0			(188.0	)		-
Net cash flows from investing activities		(118.8	)		98.4			(123.0	)		(143.4	)
Net decrease in cash & cash equivalents		(2.1	)		(0.4	)					(2.5	)
Cash & cash equivalents at beginning of period		4.7			1.0						5.7
Cash & cash equivalents at end of period	$	2.6		$	0.6		$	-		$	3.2

Consolidating Statement of Cash Flows for the nine months ended September 30, 2004 (in millions):

		Subsidiary			Parent
		Guarantors			Company			Eliminations			Consolidated

Net cash flows from operating activities	$	192.5		$	16.5		$	9.8		$	218.8

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from additional capital contribution		-			2.9			-			2.9

Requirements for:
Dividends to parent		(60.0	)		(60.0	)		60.0			(60.0	)
Retirement of long-term debt		(2.9	)		-			(9.8	)		(12.7	)
Redemption of preferred stock of subsidiary		(0.1	)		-			-			(0.1	)
Net change in short-term borrowings		30.4			26.2			(30.8	)		25.8
Net cash flows from financing activities		(32.6	)		(30.9	)		19.4			(44.1	)

CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Consolidated subsidiary distributions		-			60.0			(60.0	)		-
Other investing activities		1.1			2.4			-			3.5
Requirements for:
Capital expenditures, excluding AFUDC-equity		(167.1	)		(15.8	)		-			(182.9	)
Net change in notes receivable to other Vectren companies		-			(30.8	)		30.8			-
Net cash flows from investing activities		(166.0	)		15.8			(29.2	)		(179.4	)
Net decrease in cash & cash equivalents		(6.1	)		1.4						(4.7	)
Cash & cash equivalents at beginning of period		7.4			0.7						8.1
Cash & cash equivalents at end of period	$	1.3		$	2.1		$	-		$	3.4

Consolidating Balance Sheet as of September 30, 2005 (in millions):

ASSETS		Subsidiary		Parent
		Guarantors		Company		Eliminations			Consolidated
Current Assets
Cash & cash equivalents	$	2.6	$	0.6	$	-		$	3.2
Accounts receivable - less reserves		75.6		0.1		-			75.7
Receivables due from other Vectren companies		0.1		136.4		(136.4	)		0.1
Accrued unbilled revenues		47.1		-		-			47.1
Inventories		69.4		-		-			69.4
Recoverable fuel & natural gas costs		17.1		-		-			17.1
Prepayments & other current assets		173.5		1.5		(2.6	)		172.4
Total current assets		385.4		138.6		(139.0	)		385.0
Utility Plant
Original cost		3,563.5		-		-			3,563.5
Less: accumulated depreciation & amortization		1,361.5		-		-			1,361.5
Net utility plant		2,202.0		-		-			2,202.0
Investments in consolidated subsidiaries		-		1,075.0		(1,075.0	)		-
Notes receivable from consolidated subsidiaries		-		443.1		(443.1	)		-
Investments in unconsolidated affiliates		0.2		-		-			0.2
Other investments		14.2		6.1		-			20.3
Non-utility property - net		5.2		154.9		-			160.1
Goodwill - net		205.0		-		-			205.0
Regulatory assets		82.9		5.1		-			88.0
Other assets		5.9		0.6		-			6.5
TOTAL ASSETS	$	2,900.8	$	1,823.4	$	(1,657.1	)	$	3,067.1

LIABILITIES & SHAREHOLDER'S EQUITY		Subsidiary		Parent
		Guarantors		Company		Eliminations			Consolidated
Current Liabilities
Accounts payable	$	63.5	$	4.3	$	-		$	67.8
Accounts payable to affiliated companies		77.0		0.3		-			77.3
Payables to other Vectren companies		21.6		-		(7.3	)		14.3
Refundable fuel & natural gas costs		11.0		-		-			11.0
Accrued liabilities		101.5		10.1		(5.9	)		105.7
Short-term borrowings		-		248.1		-			248.1
Short-term borrowings from other Vectren Companies		125.8		-		(125.8	)		-
Total current liabilities		400.4		262.8		(139.0	)		524.2
Long-Term Debt
Long-term debt - net of current maturities &
debt subject to tender		403.6		548.0		-			951.6
Long-term debt due to VUHI		443.1		-		(443.1	)		-
Total long-term debt - net		846.7		548.0		(443.1	)		951.6
Deferred Income Taxes & Other Liabilities
Deferred income taxes		238.1		12.5		-			250.6
Regulatory liabilities		261.0		5.0		-			266.0
Deferred credits & other liabilities		79.6		4.7		-			84.3
Total deferred credits & other liabilities		578.7		22.2		-			600.9
Common Shareholder's Equity
Common stock (no par value)		736.2		593.0		(736.2	)		593.0
Retained earnings		338.8		397.4		(338.8	)		397.4
Total common shareholder's equity		1,075.0		990.4		(1,075.0	)		990.4

TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	2,900.8	$	1,823.4	$	(1,657.1	)	$	3,067.1

Consolidating Balance Sheet as of December 31, 2004 (in millions):

ASSETS		Subsidiary		Parent
		Guarantors		Company		Eliminations			Consolidated
Current Assets
Cash & cash equivalents	$	4.7	$	1.0	$	-		$	5.7
Accounts receivable - less reserves		147.4		0.1		-			147.5
Receivables due from other Vectren companies		1.7		327.0		(324.7	)		4.0
Accrued unbilled revenues		161.2		-		-			161.2
Inventories		53.0		-		-			53.0
Recoverable fuel & natural gas costs		17.7		-		-			17.7
Prepayments & other current assets		136.4		4.1		(2.3	)		138.2
Total current assets		522.1		332.2		(327.0	)		527.3
Utility Plant
Original cost		3,465.2		-		-			3,465.2
Less: accumulated depreciation & amortization		1,309.0		-		-			1,309.0
Net utility plant		2,156.2		-		-			2,156.2
Investments in consolidated subsidiaries		-		951.6		(951.6	)		-
Notes receivable from consolidated subsidiaries		-		443.1		(443.1	)		-
Investments in unconsolidated affiliates		0.2		-		-			0.2
Other investments		13.5		6.1		-			19.6
Non-utility property - net		5.3		144.3		-			149.6
Goodwill - net		205.0		-		-			205.0
Regulatory assets		76.8		5.7		-			82.5
Other assets		3.8		3.5		-			7.3
TOTAL ASSETS	$	2,982.9	$	1,886.5	$	(1,721.7	)	$	3,147.7

LIABILITIES & SHAREHOLDER'S EQUITY		Subsidiary		Parent
		Guarantors		Company		Eliminations			Consolidated
Current Liabilities
Accounts payable	$	87.9	$	9.4	$	-		$	97.3
Accounts payable to affiliated companies		98.6		0.2		-			98.8
Payables to other Vectren companies		26.0		0.6		(10.8	)		15.8
Refundable fuel & natural gas costs		6.3		-		-			6.3
Accrued liabilities		100.8		11.6		(2.4	)		110.0
Short-term borrowings		0.3		308.0		-			308.3
Short-term borrowings from other Vectren Companies		313.8		-		(313.8	)		-
Long-term debt subject to tender		10.0		-		-			10.0
Total current liabilities		643.7		329.8		(327.0	)		646.5
Long-Term Debt
Long-term debt - net of current maturities &
debt subject to tender		393.4		547.9		-			941.3
Long-term debt due to VUHI		443.1		-		(443.1	)		-
Total long-term debt - net		836.5		547.9		(443.1	)		941.3
Deferred Income Taxes & Other Liabilities
Deferred income taxes		226.8		14.0		-			240.8
Regulatory liabilities		246.2		5.5		-			251.7
Deferred credits & other liabilities		78.0		3.9		-			81.9
Total deferred credits & other liabilities		551.0		23.4		-			574.4
Cumulative, Redeemable Preferred Stock of a Subsidiary		0.1		-		-			0.1
Common Shareholder's Equity
Common stock (no par value)		611.3		592.9		(611.3	)		592.9
Retained earnings		340.3		392.5		(340.3	)		392.5
Total common shareholder's equity		951.6		985.4		(951.6	)		985.4

TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	2,982.9	$	1,886.5	$	(1,721.7	)	$	3,147.7

4.	Transactions with Other Vectren Companies

Support Services and Purchases

Vectren and certain subsidiaries of Vectren provide corporate and general and administrative services to the Company including legal, finance, tax, risk management, and human resources, which includes charges for restricted stock compensation and for pension and other postretirement benefits not directly charged to subsidiaries. These costs have been allocated using various allocation techniques, primarily number of employees, number of customers and/or revenues. Allocations are based on cost. Utility Holdings received corporate allocations totaling $20.4 million and $17.0 million for the three months ended September 30, 2005 and 2004, respectively. Utility Holdings received corporate allocations totaling $63.4 million and $59.2 million for the nine months ended September 30, 2005 and 2004, respectively.

Vectren Fuels, Inc., a wholly owned subsidiary of Vectren, owns and operates coal mines from which SIGECO purchases fuel used for electric generation. Amounts paid for such purchases for the three months ended September 30, 2005 and 2004, totaled $25.7 million and $22.0 million, respectively. Amounts paid for such purchases for the nine months ended September 30, 2005 and 2004, totaled $74.0 million and $61.1 million, respectively.

Share-Based Incentive Plans

Utility Holdings does not have share-based compensation plans separate from Vectren. An insignificant number of Utility Holdings’ employees participate in Vectren’s share-based compensation plans.

5.	Financing Activities

Long-term Debt

In anticipation of a debt issuance, in October 2005, Utility Holdings filed a shelf registration statement with the Securities and Exchange Commission for $275 million aggregate principal amount of unsecured senior notes and previously executed forward starting interest rate swaps with a notional value of $75 million that expire in December 2005. When issued, the unsecured notes will be guaranteed by Utility Holdings’ three operating utility companies: SIGECO, Indiana Gas, and VEDO. These guarantees will be full and unconditional and joint and several.

Short-Term Facilities

In response to higher natural gas prices, Utility Holdings increased its available consolidated short-term borrowing capacity to $520 million, a $165 million increase over previous levels. In addition, Utility Holdings extended the maturity of its largest credit facility, which totals $515 million, through November, 2010. The amendments were completed on November 10, 2005.

6.	ProLiance Energy, LLC

ProLiance Energy, LLC (ProLiance), a nonregulated energy marketing affiliate of Vectren and Citizens Gas and Coke Utility (Citizens Gas), provides services to a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions located throughout the Midwest and Southeast United States. ProLiance’s customers include Vectren’s utilities and nonregulated gas supply operations and Citizens Gas. ProLiance’s primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services.

As part of a settlement agreement approved by the IURC during July 2002, the gas supply agreements with Indiana Gas and SIGECO, were approved and extended through March 31, 2007. Under the provisions of that agreement, the utilities may decide to conduct a “request for proposal” (RFP) for a new supply administrator, or they may decide to make an alternative proposal for procurement of gas supply. That decision will be made by December 2005. To the extent an RFP is conducted, ProLiance is fully expected to participate in the RFP process for service to the utilities after March 31, 2007.

As required by a June 14, 2005, PUCO order (See Note 9), VEDO solicited bids for its gas supply/portfolio administration services and has selected a different provider under a one year contract. ProLiance’s obligation to supply these services to VEDO ended October 31, 2005. The Company believes this change will not materially affect ProLiance’s or Vectren’s future earnings, financial position, or cash flows.

Transactions with ProLiance

Purchases from ProLiance for resale and for injections into storage for the three months ended September 30, 2005 and 2004, totaled $190.2 million and $160.7 million, respectively, and for the nine months ended September 30, 2005 and 2004, totaled $600.4 million and $562.9 million, respectively. Amounts owed to ProLiance at September 30, 2005, and December 31, 2004, for those purchases were $74.5 million and $97.7 million, respectively, and are included in Accounts payable to affiliated companies. Amounts charged by ProLiance for gas supply services are established by supply agreements with each utility.

7.	Commitments & Contingencies

The Company is party to various legal proceedings arising in the normal course of business. In the opinion of management, there are no legal proceedings, except those discussed herein, pending against the Company that are likely to have a material adverse effect on its financial position or results of operations.

United States Securities and Exchange Commission Inquiry into PUHCA Exemption

In July 2004, the Company received a letter from the SEC regarding its exempt status under the Public Utility Holding Company Act of 1935 (PUHCA). The letter asserts that the Company’s out of state electric power sales exceed the amount previously determined by the SEC to be acceptable in order to qualify for the exemption. There is pending a request by the Company for an order of exemption under Section 3(a)(1) of the PUHCA. The Company also claims the benefit of the exemption pursuant to Rule 2 under Section 3(a)(1) of the PUHCA by filing an annual statement on SEC Form U-3A-2. The Company has responded to the SEC inquiry and filed an amended Form U-3A-2 for the year ended December 31, 2003. The amendment changed the method of aggregating wholesale power sales and purchases outside of Indiana from that previously reported. The new method is to aggregate by delivery point. The amendment also submitted clarifications as to activity outside of Indiana related to gas utility operations. Form U-3A-2 for the year ended December 31, 2004 was filed on February 28, 2005.

On June 21, 2005, the Company amended its Form U-1 to further clarify its assertion that the Company qualifies for the PUHCA exemption and to request an order of exemption under Section 3(a)(1) of PUHCA.

On August 8, 2005, comprehensive energy legislation, the Domenici - Barton Energy Policy Act of 2005 (Energy Act), was signed into law. Among other things, the Energy Act provides for the repeal of PUHCA effective six months after its enactment, in February 2006. The Energy Act gives the FERC the ability to regulate holding companies previously subject to PUHCA. Although the Company cannot be certain how the FERC will implement any final regulations, such regulations, as they are currently proposed, are not expected to materially affect the Company’s financial position or operations.

8.	Environmental Matters

Clean Air Act

NOx SIP Call Matter

The Company has taken steps to comply with Indiana’s State Implementation Plan (SIP) of the Clean Air Act (the Act). These steps include installing Selective Catalytic Reduction (SCR) systems at Culley Generating Station Unit 3 (Culley), Warrick Generating Station Unit 4, and A.B. Brown Generating Station Units 1 and 2. SCR systems reduce flue gas NOx emissions to atmospheric nitrogen and water using ammonia in a chemical reaction. This technology is known to currently be the most effective method of reducing nitrogen oxide (NOx) emissions where high removal efficiencies are required.

The IURC has issued orders that approve:

·	the Company’s project to achieve environmental compliance by investing in clean coal technology;

·	a total capital cost investment for this project up to $250 million (excluding AFUDC and administrative overheads), subject to periodic review of the actual costs incurred;

·	a mechanism whereby, prior to an electric base rate case, the Company may recover through a rider that is updated every six months, an 8% return on its weighted capital costs for the project; and

·	ongoing recovery of operating costs, including depreciation and purchased emission allowances, related to the clean coal technology once the facility is placed into service.

Through September 30, 2005, capital investments approximating the level approved by the IURC have been made. Related annual operating expenses, including depreciation expense, are estimated to be between $24 million and $27 million.

The Company has achieved timely compliance through the reduction of the Company’s overall NOx emissions to levels compliant with Indiana’s NOx emissions budget allotted by the USEPA. Therefore, the Company has recorded no accrual for potential penalties that may result from noncompliance.

Clean Air Interstate Rule &Clean Air Mercury Rule

In March of 2005 USEPA finalized two new air emission reduction regulations. The Clean Air Interstate Rule (CAIR) is an allowance cap and trade program requiring further reductions in Nitrogen Oxides (NOx) and Sulfur Dioxide (SO₂) emissions from coal-burning power plants. The Clean Air Mercury Rule (CAMR) is an allowance cap and trade program requiring further reductions in mercury emissions from coal-burning power plants. Both sets of regulations require emission reductions in two phases. The first phase deadline for both rules is 2010 (2009 for NOx under CAIR), and the second phase deadline for compliance with the emission reductions required under CAIR is 2015, while the second phase deadline for compliance with the emission reduction requirements of CAMR is 2018. The Company is evaluating compliance options and fully expects to be in compliance by the required deadlines.

In May 2005, Vectren’s utility subsidiary, SIGECO, filed a new multi-emission compliance plan with the IURC. If approved, SIGECO’s coal-fired plants will be 100% scrubbed for SO₂, 90% scrubbed for NOx, and mercury emissions will be reduced to meet the new mercury reduction standards. On October 20, 2005, the Company and the OUCC filed with the IURC a settlement agreement concerning the regulatory treatment and recovery of the investment required by this plan. If the settlement agreement is approved, the Company will recover a return on its capital investments, which are expected to approximate $110 million, and related operating expenses through a rider mechanism. This rider mechanism will operate similar to the rider used to recover NOx-related capital investments and operating expenses. The Company expects a final order from the IURC related to this settlement agreement before the end of 2005.

Information Request

On January 23, 2001, SIGECO received an information request from the USEPA under Section 114 of the Clean Air Act for historical operational information on the Warrick and A.B. Brown generating stations. SIGECO has provided all information requested with the most recent correspondence provided on March 26, 2001.

Manufactured Gas Plants

In the past, Indiana Gas, SIGECO, and others operated facilities for the manufacture of gas. Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years. Under currently applicable environmental laws and regulations, Indiana Gas, SIGECO, and others may now be required to take remedial action if certain byproducts are found above the regulatory thresholds at these sites.

Indiana Gas has identified the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites for which it may have some remedial responsibility. Indiana Gas has completed a remedial investigation/feasibility study (RI/FS) at one of the sites under an agreed order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. Although Indiana Gas has not begun an RI/FS at additional sites, Indiana Gas has submitted several of the sites to the IDEM's Voluntary Remediation Program (VRP) and is currently conducting some level of remedial activities, including groundwater monitoring at certain sites, where deemed appropriate, and will continue remedial activities at the sites as appropriate and necessary.

In conjunction with data compiled by environmental consultants, Indiana Gas has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, Indiana Gas has recorded costs that it reasonably expects to incur totaling approximately $20.4 million.

The estimated accrued costs are limited to Indiana Gas’ proportionate share of the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26 sites with other potentially responsible parties (PRP), which serve to limit Indiana Gas’ share of response costs at these 19 sites to between 20% and 50%.

With respect to insurance coverage, Indiana Gas has received and recorded settlements from all known insurance carriers in an aggregate amount approximating $20.4 million.

Environmental matters related to manufactured gas plants have had no material impact on earnings since costs recorded to date approximate PRP and insurance settlement recoveries. While Indiana Gas has recorded all costs which it presently expects to incur in connection with activities at these sites, it is possible that future events may require some level of additional remedial activities which are not presently foreseen.

In October 2002, the Company received a formal information request letter from the IDEM regarding five manufactured gas plants owned and/or operated by SIGECO and not currently enrolled in the IDEM’s VRP. In response, SIGECO submitted to the IDEM the results of preliminary site investigations conducted in the mid-1990’s. These site investigations confirmed that based upon the conditions known at the time, the sites posed no risk to human health or the environment. Follow up reviews have been initiated by the Company to confirm that the sites continue to pose no such risk.

On October 6, 2003, SIGECO filed applications to enter four of the manufactured gas plant sites in IDEM's VRP. The remaining site is currently being addressed in the VRP by another Indiana utility. SIGECO added those four sites into the renewal of the global Voluntary Remediation Agreement that Indiana Gas has in place with IDEM for its manufactured gas plant sites. That renewal was approved by the IDEM on February 24, 2004. On July 13, 2004, SIGECO filed a declaratory judgment action against its insurance carriers seeking a judgment finding its carriers liable under the policies for coverage of further investigation and any necessary remediation costs that SIGECO may accrue under the VRP program. The total investigative costs, and if necessary, costs of remediation at the four SIGECO sites, as well as the amount of any PRP or insurance recoveries, cannot be determined at this time.

Jacobsville Superfund Site

On July 22, 2004, the USEPA listed the Jacobsville Neighborhood Soil Contamination site in Evansville, Indiana, on the National Priorities List under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). The USEPA has identified four sources of historic lead contamination. These four sources shut down manufacturing operations years ago. When drawing up the boundaries for the listing, the USEPA included a 250 acre block of properties surrounding the Jacobsville neighborhood, including the Company's Wagner Operations Center. The Company's property has not been named as a source of the lead contamination, nor does the USEPA's soil testing to date indicate that the Company’s property contains lead contaminated soils. The Company's own soil testing, completed during the construction of the Operations Center did not indicate that the Company’s property contains lead contaminated soils. At this time, the Company anticipates having only to conduct further soil testing, if required by the USEPA.

9.	Rate & Regulatory Matters

Normal Temperature Adjustment Order

On October 5, 2005, the IURC approved the establishment of a normal temperature adjustment (NTA) mechanism for Vectren Energy Delivery of Indiana. The Indiana Office of Utility Consumer Counselor (OUCC) had previously entered into a settlement agreement with Vectren Energy Delivery of Indiana providing for the NTA. The NTA affects the Company’s Indiana regulated residential and commercial natural gas customers and should mitigate weather risk in those customer classes during the October to April peak heating season. These Indiana customer classes represent approximately 60-65% of the Company’s total natural gas heating load.

The NTA mechanism will mitigate volatility in distribution charges created by fluctuations in weather by lowering customer bills when weather is colder than normal and increasing customer bills when weather is warmer than normal. The NTA will be applied to meters read and bills rendered after October 15, 2005. Each subsequent monthly bill for the seven month heating season will be adjusted using the NTA.

The order provides that the Company will make, on a monthly basis, a commitment of $125,000 to a universal service fund program or other low income assistance program for the duration of the NTA or until a general rate case.

Gas Utility Base Rate Settlements

On June 30, 2004, the IURC approved a $5.7 million base rate increase for SIGECO’s gas distribution business, and on November 30, 2004, approved a $24 million base rate increase for Indiana Gas’ gas distribution business. On April 13, 2005, the PUCO approved a $15.7 million base rate increase for VEDO’s gas distribution business. The new rate designs in all three territories include a larger service charge, which is intended to address to some extent earnings volatility related to weather. The base rate change in SIGECO’s service territory was implemented on July 1, 2004; the base rate change in Indiana Gas’ service territory was implemented on December 1, 2004; and the base rate change in VEDO’s service territory was implemented on April 14, 2005.

The orders also permit SIGECO and Indiana Gas to recover the on-going costs to comply with the Pipeline Safety Improvement Act of 2002. The Pipeline Safety Improvement Tracker provides for the recovery of incremental non-capital dollars, capped at $750,000 the first year and $500,000 thereafter for SIGECO and $2.5 million per year for Indiana Gas. Any costs incurred in excess of these annual caps are to be deferred for future recovery. VEDO’s new base rates provide for the recovery of on-going costs to comply with the Pipeline Safety Improvement Act of 2002 as well as the funding of conservation programs.

MISO

Since February, 2002 and with the IURC’s approval, the Company has been a member of the Midwest Independent System Operator, Inc. (MISO), a FERC approved regional transmission organization. The MISO serves the electrical transmission needs of much of the Midwest and maintains operational control over the Company’s electric transmission facilities as well as that of other Midwest utilities. Pursuant to an order from the IURC received in December 2001, certain MISO startup costs (referred to as Day 1 costs) have been deferred for future recovery in the next general rate case.

On April 1, 2005, the MISO energy market commenced operation (the Day 2 energy market). As a result of being a market participant, the Company now bids its owned generation into the Day Ahead and Real Time markets and procures power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market.

On June 1, 2005, Vectren, together with three other Indiana electric utilities, received regulatory authority from the IURC that allows recovery of fuel related costs and deferral of other costs associated with the Day 2 energy market. The order allows fuel related costs to be passed through to customers in Vectren’s existing fuel cost recovery proceedings. The other non-fuel and MISO administrative related costs are to be deferred for recovery as part of the next electric general rate case proceeding.

Gas Cost Recovery (GCR) Audit

On June 14, 2005, the PUCO issued an order disallowing the recovery of approximately $9.6 million of gas costs relating to the two year audit period ended November 2002. That audit period provided the PUCO staff its initial review of the portfolio administration arrangement between VEDO and ProLiance. The disallowance includes approximately $1.3 million relating to pipeline refunds and penalties and approximately $4.5 million of costs for winter delivery services purchased by VEDO to ensure reliability over the two year period. The PUCO also held that ProLiance should have credited to VEDO an additional $3.8 million more than credits actually received for the right to use VEDO’s gas transportation capacity periodically during the periods when it was not required for serving VEDO’s customers. The PUCO also directed VEDO to either submit its receipt of portfolio administration services to a request for proposal process or to in-source those functions.

During the fourth quarter of 2004, the Company recorded a reserve of $1.5 million for this matter. An additional pretax charge of $3.0 million was recorded in Cost of Gas Sold in the second quarter of 2005. The reserve reflects management’s assessment of the impact of the June 14 decision, an estimate of any current impact that decision may have on subsequent audit periods, and an estimate of a sharing in any final disallowance by Vectren’s partner in ProLiance.

Notwithstanding the additional charge, Vectren management believes that there exists a sound basis to challenge the aspects of the decision related to the $4.5 million winter delivery service issue and the $3.8 million portfolio administration issue. VEDO filed its request for rehearing on July 14, 2005, and on August 10, 2005, the PUCO granted rehearing to further consider the $3.8 million portfolio administration issue and all interest on the findings, but denied rehearing on all other aspects of the case. On October 7, 2005, the Company filed an appeal with the Ohio Supreme Court requesting that the $4.5 million disallowance related to the winter delivery service issue be reversed. A schedule to file briefs with the court has yet to be determined. In addition, the Company solicited and received bids for VEDO’s gas supply and portfolio administration services and has selected a third party provider, who began providing services to VEDO on November 1, 2005, under a one year contract.

Commodity Prices

Commodity prices for natural gas purchases are expected to increase for the 2005 - 2006 heating season, primarily due to tight supplies. Subject to compliance with applicable state laws, the Company's utility subsidiaries are allowed recovery of such changes in purchased gas costs from their retail customers through commission-approved gas cost adjustment mechanisms, and margin on gas sales should not be impacted. However, it is reasonably possible that as a result of this near term change in the commodity price for natural gas the Company’s utility subsidiaries will experience increased interest expense due to higher working capital requirements; increased uncollectible accounts expense and unaccounted for gas; and some level of price sensitive reduction in volumes sold. In response to higher gas prices, the Company increased its utility-related short-term credit facilities.

Indiana Decoupling/Conservation Filing

On October 25, 2005, Vectren Energy Delivery of Indiana filed with the IURC for approval of a conservation program and a conservation adjustment rider in its two Indiana service territories. If approved, the plan outlined in the petition will better align the interests of the Company with its customers through the promotion of natural gas conservation. The petition requests the use of a tracker mechanism to recover the costs of funding the design and implementation of conservation efforts, such as consumer education programs and rebates for high efficiency equipment. The conservation tracker works in tandem with a decoupling mechanism. The decoupling mechanism would allow the Company to recover the distribution portion of its rates from residential and commercial customers based on the level of customer usage established in each utility’s last general rate case. The Company proposed that both the conservation tracker and decoupling mechanism begin before the end of 2005. A pre-hearing conference with regard to this matter has not been scheduled.

10.

Impact of Recently Issued Accounting Guidance

SFAS No. 154

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections - a Replacement of APB Opinion No. 20 and FASB Statement No. 3” (SFAS 154). This statement changes the requirements for the accounting for and reporting of a change in accounting principle and applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement in the instance that the pronouncement does not include specific transition provisions. SFAS 154 requires retrospective application to prior periods’ financial statements of the direct effects caused by a change in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. Further, changes in depreciation, amortization or depletion methods for long-lived, nonfinancial assets are to be accounted for as a change in accounting estimate affected by a change in accounting principle. SFAS 154 is effective for accounting changes and corrections made in fiscal years beginning after December 15, 2005, with early adoption permitted. The adoption of this standard, beginning in fiscal year 2006, is not expected to have any material effect on the Company’s operating results or financial condition.

FIN 47

In March 2005, the FASB issued FASB Interpretation No. 47 (FIN 47), an interpretation of SFAS 143. The interpretation is effective for the Company no later than December 31, 2005. FIN 47 clarifies that a legal obligation to perform an asset retirement activity that is conditional on a future event is within SFAS 143’s scope. It also clarifies the meaning of the term “conditional asset retirement obligation” as a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. Accordingly, an entity is required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event if the liability’s fair value can be estimated reasonably. The interpretation provides examples of conditional asset retirement obligations that may need to be recognized under the provisions of FIN 47, including asbestos and utility pole removal and dismantling plant. The interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 requires the reassessment of whether a portion of accrued removal costs should be recharacterized as a liability under generally accepted accounting principles. FIN 47 may also require the accrual of additional liabilities and could result in increased near-term expense. The Company is currently assessing the impact this interpretation will have on its financial statements.

11.

Segment Reporting

Utility Holdings’ operations consist of regulated operations (the Gas Utility Services and Electric Utility Services operating segments), and other operations that provide information technology and other support services to those regulated operations. In total, there are three operating segments as defined by SFAS 131 “Disclosure About Segments of an Enterprise and Related Information” (SFAS 131). Gas Utility Services provides natural gas distribution and transportation services in nearly two-thirds of Indiana and to west central Ohio. Electric Utility Services provides electricity primarily to southwestern Indiana, and includes the Company’s power generating and marketing operations. For these regulated operations, the Company uses after tax operating income as a measure of profitability, consistent with regulatory reporting requirements. The Company cross manages its regulated operations as separated between Energy Delivery, which includes the gas and electric transmission and distribution functions, and Power Supply, which includes the power generating and marketing operations. For the Company’s other operations, it uses net income as the measure of profitability.

Information related to the Company’s business segments is summarized below:


		Three Months					Nine Months
		Ended September 30,						Ended September 30,
(In millions)		2005			2004			2005			2004
Revenues
Gas Utility Services	$	136.8		$	112.3		$	839.5		$	771.6
Electric Utility Services		128.7			102.3			320.3			280.2
Other Operations		8.9			7.5			27.1			25.5
Eliminations		(8.7	)		(7.4	)		(26.6	)		(25.0	)
Consolidated Revenues	$	265.7		$	214.7		$	1,160.3		$	1,052.3

Profitability Measure
Regulated Operating Income
(Operating Income Less Applicable Income Taxes)
Gas Utility Services	$	(2.5	)	$	(4.2	)	$	48.3		$	43.0
Electric Utility Services		24.7			21.7			56.5			48.2
Total Regulated Operating Income		22.2			17.5			104.8			91.2
Regulated other income - net		1.0			1.3			1.2			1.8
Regulated interest expense & preferred dividends		(16.2	)		(15.7	)		(47.3	)		(46.9	)
Regulated Net Income		7.0			3.1			58.7			46.1
Other Operations Net Income		1.9			1.4			6.1			5.8
Consolidated Net Income	$	8.9		$	4.5		$	64.8		$	51.9

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

Description of the Business

Utility Holdings generates revenue primarily from the delivery of natural gas and electric service to its customers. Utility Holdings’ primary source of cash flow results from the collection of customer bills and the payment for goods and services procured for the delivery of gas and electric services. Utility Holdings’ results are impacted by weather patterns in its Indiana and Ohio service territories and general economic conditions both in its service territories as well as nationally.

The Company has in place a disclosure committee that consists of senior management as well as financial management. The committee is actively involved in the preparation and review of the Company’s SEC filings.

Executive Summary of Consolidated Results of Operations

The following discussion and analysis should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto.

Utility Holdings earnings were $8.9 million for the quarter compared to $4.5 million in the prior year and $64.8 million for the nine months ended September 30, 2005 compared to $51.9 million in 2004. The improved performance is primarily due to gas base rate increases implemented in 2004 and early 2005 and higher electric revenues associated with recovery of pollution control investments. In addition, the year-to-date period reflects increased margins from generation asset optimization activities. Gas base rate increases added revenue of $8.1 million, or $4.8 million after tax, during the quarter and $25.1 million, or $14.9 million after tax, for the nine months ended September 30, 2005, compared to the prior year. Increased revenues associated with recovery of pollution control investments, net of related operating and depreciation expense, increased operating income $3.6 million or $2.1 million after tax, for the quarter and $7.4 million, or $4.4 million after tax, for the nine month period. The improved margins were partially offset by higher operating and depreciation expense. The year-to-date 2005 results also reflect a $3.0 million, $1.8 million after tax, charge recorded in the second quarter pursuant to the disallowance of Ohio gas costs.

Management estimates that the after tax impact of weather on third quarter 2005 was favorable $0.2 million and unfavorable $2.5 million in 2004. The unfavorable after tax impact of weather for the nine month periods ended September 30 is estimated to be $3.5 million and $4.9 million for 2005 and 2004, respectively.

Significant Fluctuations

Throughout this discussion, the terms Gas Utility margin and Electric Utility margin are used. Gas Utility margin and Electric Utility margin could be considered non-GAAP measures of income. Gas Utility margin is calculated as Gas Utility revenues less the Cost of gas. Electric Utility margin is calculated as Electric Utility revenues less Fuel for electric generation and Purchased electric energy. These measures exclude Other operating expenses, Depreciation and amortization, and Taxes other than income taxes, which are included in the calculation of operating income. The Company believes Gas Utility and Electric Utility margins are better indicators of relative contribution than revenues since gas prices and fuel costs can be volatile and are generally collected on a dollar for dollar basis from customers. Margins should not be considered an alternative to, or a more meaningful indicator of operating performance than, operating income or net income as determined in accordance with accounting principles generally accepted in the United States.

Margin

Margin generated from the sale of natural gas and electricity to small customers (generally residential and commercial customers) is seasonal and impacted by weather patterns in its service territory. Margin generated from sales to large customers (generally industrial and other contract and firm wholesale customers) is impacted by overall economic conditions. Margin is also impacted by the collection of state mandated taxes which fluctuate with gas costs and also some level of price sensitive fluctuation in volumes sold. Electric generating asset optimization activities are primarily affected by market conditions, the level of excess generating capacity, and electric transmission availability. Following is a discussion and analysis of margin generated from regulated utility operations.

Gas Utility Margin (Gas Utility Revenues less Cost of Gas Sold)

Gas Utility margin and throughput by customer type follows:


		Three Months					Nine Months
		Ended September 30,					Ended September 30,
(In millions)		2005		2004			2005		2004

Residential & Commercial	$	44.8	$	36.5		$	230.4	$	205.9
Industrial		9.1		8.8			34.4		32.9
Other		1.3		(0.2	)		5.9		3.0
Total gas utility margin	$	55.2	$	45.1		$	270.7	$	241.8

Sold & transported volumes in MMDth:
To residential & commercial customers		6.8		7.0			75.3		78.9
To industrial customers		17.4		17.1			63.4		62.4
Total throughput		24.2		24.1			138.7		141.3

Gas utility margins were $55.2 million and $270.7 million for the three and nine months ended September 30, 2005. This represents an increase in gas utility margin in the third quarter, a non-heating base load quarter, of $10.1 million and a year-to-date increase of $28.9 million compared to the same periods in 2004. The increases are primarily due to the favorable impact of gas base rate increases. Year-to-date results were also impacted by additional pass through expenses and revenue taxes recovered in margins of $2.4 million and $0.6 million, respectively, compared to last year. Year-to-date results reflect a $3.0 million additional charge recorded in the second quarter of 2005 as the estimated impact of the disallowance of Ohio gas costs ordered by the PUCO. In the fourth quarter of 2004, the Company had previously recorded a charge of $1.5 million with respect to the matters raised in the order.

For the nine month period, weather was 9% warmer than normal and similar to the prior year and decreased margin an estimated $0.7 million compared to 2004. Gas sold and transported volumes were 2% lower for the nine months ended September 30, 2005 as compared to last year primarily due to reduced residential volumes. The average cost per dekatherm of gas purchased for the nine months ended September 30, 2005, was $7.79 compared to $6.76 in 2004.

Electric Utility Margin (Electric Utility Revenues less Fuel for Electric Generation and Purchased Electric Energy)

Electric Utility margin by revenue type follows:


	Three Months				Nine Months
	Ended September 30,				Ended September 30,
(In millions)	2005		2004		2005		2004

Residential & commercial	$	54.4	$	45.5	$	131.2	$	120.2
Industrial		18.0		16.9		49.6		47.5
Municipalities & other		4.9		4.5		14.1		13.9
Total retail & firm wholesale		77.3		66.9		194.9		181.6
Asset optimization		3.3		4.3		15.1		9.6
Total electric utility margin	$	80.6	$	71.2	$	210.0	$	191.2

Retail & Firm Wholesale Margin

Electric retail and firm wholesale utility margins were $77.3 million and $194.9 million for the three and nine months ended September 30, 2005. This represents an increase over the prior year periods of $10.4 million and $13.3 million, respectively. The recovery of pollution control related investments and associated operating expenses and related depreciation increased margins $5.4 million quarter over quarter and $11.5 million for the nine month period. Cooling weather for the quarter and nine months ended was 14% and 7% warmer than normal, respectively. Cooling weather, compared to last year, was 50% and 19% warmer for the three and nine months ended September 30, 2005, respectively. The estimated increase in margins due to weather was $5.0 million and $3.2 million for the three and nine month periods, respectively, compared to the prior year. Retail residential and commercial volumes sold increased 15 percent during the quarter and 3 percent for the nine month period. Industrial sales volumes sold increased 5 percent during the quarter and 2 percent for the nine month period. During the nine months ended September 30, 2005, volumes sold to residential, commercial, and industrial customers were 4,738.4 GWh compared to 4,596.1 GWh in 2004.

Margin from Asset Optimization Activities

Periodically, generation capacity is in excess of that needed to serve native load and firm wholesale customers. The Company markets this unutilized capacity to optimize the return on its owned generation assets. Substantially all of these contracts are integrated with portfolio requirements around power supply and delivery and are short-term purchase and sale transactions that expose the Company to limited market risk.

Following is a reconciliation of asset optimization activity:


		Three Months						Nine Months
		Ended September 30,						Ended September 30,
(In millions)		2005			2004			2005			2004
Beginning of Period Net Balance Sheet Position	$	3.2		$	2.2		$	(0.6	)	$	(0.4	)
Statement of Income Activity
Net mark-to-market (losses) gains realized		(1.4	)		(1.8	)		1.4			(1.0	)
Net realized gains		4.7			6.1			13.7			10.6
Asset optimization margin		3.3			4.3			15.1			9.6
Net cash received & other adjustments		(4.9	)		(6.8	)		(12.9	)		(9.5	)
End of Period Net Balance Sheet Position	$	1.6		$	(0.3	)	$	1.6		$	(0.3	)

For the three and nine month periods ended September 30, net asset optimization margins were $3.3 million and $15.1 million, which represents a decrease for the quarter of $1.0 million and a year-to-date increase of $5.5 million, as compared to 2004. Increased retail load experienced during the three months ended September 30, 2005, reduced available wholesale capacity. The increase in year-to-date margin results primarily from an increase in available capacity and mark to market gains. The availability of excess capacity was reduced in 2004 by scheduled outages of owned generation related to the installation of environmental compliance equipment.

Operating Expenses

Other operating expenses for the three and nine months ended September 30, 2005, increased $6.9 million and $12.0 million, respectively, compared to 2004. The increases are primarily attributable to compensation and benefit costs increases, including allocated parent company costs for performance and share-based compensation, of $2.8 million for the quarter and $5.5 million year-to-date. Amortization of rate case expenses, expenses associated with Ohio “Choice” and integrity management programs and expenses recovered directly in margin such as bad debt expense in Ohio and NOx related operating expenses increased $1.7 million during the quarter and $5.2 million year to date. The quarter was also impacted by an additional $1.5 million of bad debt expense related to the Company’s Indiana service territories when compared to the prior year, bringing the year-to-date bad debt expense to $6.4 million in 2005, compared to $6.8 million in 2004.

Depreciation & Amortization

Depreciation expense increased $3.2 million and $9.7 million for the three and nine month periods ended September 30, 2005, as compared to 2004. In addition to depreciation on additions to plant in service, the increases were primarily due to incremental depreciation expense associated with environmental compliance equipment additions of $1.5 million for the quarter and $4.5 million for the year to date period, respectively,. Year-to-date 2004 was also $1.8 million lower due to an adjustment of Ohio depreciation rates and amortization of Indiana regulatory assets.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $0.5 million and $1.2 million for the three and nine months ended September 30, 2005, respectively, compared to 2004. The year-to-date increase is primarily attributable to revenue taxes resulting from higher revenues.

Income Taxes

For the three and nine months ended September 30, 2005, Federal and state income taxes increased $2.8 million and $10.0 million, respectively, primarily due to higher pre-tax income.

Environmental Matters

Clean Air Act

NOx SIP Call Matter

The IURC has issued orders that approve:

·	the Company’s project to achieve environmental compliance by investing in clean coal technology;

·	a total capital cost investment for this project up to $250 million (excluding AFUDC and administrative overheads), subject to periodic review of the actual costs incurred;

·	a mechanism whereby, prior to an electric base rate case, the Company may recover through a rider that is updated every six months, an 8% return on its weighted capital costs for the project; and

·	ongoing recovery of operating costs, including depreciation and purchased emission allowances, related to the clean coal technology once the facility is placed into service.

Clean Air Interstate Rule & Clean Air Mercury Rule

Information Request

Manufactured Gas Plants

With respect to insurance coverage, Indiana Gas has received and recorded settlements from all known insurance carriers in an aggregate amount approximating $20.4 million.

Jacobsville Superfund Site

On July 22, 2004, the USEPA listed the Jacobsville Neighborhood Soil Contamination site in Evansville, Indiana, on the National Priorities List under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). The USEPA has identified four sources of historic lead contamination. These four sources shut down manufacturing operations years ago. When drawing up the boundaries for the listing, the USEPA included a 250 acre block of properties surrounding the Jacobsville neighborhood, including Vectren's Wagner Operations Center. Vectren's property has not been named as a source of the lead contamination, nor does the USEPA's soil testing to date indicate that the Vectren property contains lead contaminated soils. Vectren's own soil testing, completed during the construction of the Operations Center, did not indicate that the Vectren property contains lead contaminated soils. At this time, Vectren anticipates only additional soil testing, if required by the USEPA.

Rate & Regulatory Matters

Gas Utility Base Rate Settlements

Normal Temperature Adjustment Settlement

MISO

As a result of MISO’s operational control over much of the Midwestern electric transmission grid, including SIGECO’s transmission facilities, SIGECO’s continued ability to import power, when necessary, and export power to the wholesale market has been, and may continue to be, impacted. Given the nature of MISO’s policies regarding use of transmission facilities, as well as ongoing FERC initiatives and uncertainties around Day 2 energy market operations, it is difficult to predict near term operational impacts. However, as stated above, it is believed that MISO’s regional operation of the transmission system will ultimately lead to reliability improvements.

The potential need to expend capital for improvements to the transmission system, both to SIGECO’s facilities as well as to those facilities of adjacent utilities, over the next several years will become more predictable as MISO completes studies related to regional transmission planning and improvements. Such expenditures may be significant.

Gas Cost Recovery (GCR) Audit

Indiana Decoupling/Conservation Filing

Other Operating Matters

United States Securities and Exchange Commission Inquiry into PUHCA Exemption

On August 8, 2005, comprehensive energy legislation, the Domenici - Barton Energy Policy Act of 2005 (Energy Act), was signed into law. Among other things, the Energy Act provides for the repeal of PUHCA effective six months after its enactment, in February 2006. The Energy Act gives the FERC the ability to regulate holding companies previously regulated by PUHCA. Although the Company cannot be certain how the FERC will implement any final regulations, such regulations, as they are currently proposed, are not expected to materially affect the Company’s financial position or operations.

Impact of Recently Issued Accounting Guidance

SFAS No. 154

FIN 47

Financial Condition

Within Vectren’s consolidated group, Utility Holdings funds the short-term and long-term financing needs of utility operations. Vectren does not guarantee Utility Holdings debt. Utility Holdings’ outstanding long-term and short-term borrowing arrangements are jointly and severally guaranteed by Indiana Gas, SIGECO, and VEDO. The guarantees are full and unconditional and joint and several, and Utility Holdings has no subsidiaries other than the subsidiary guarantors. Information about the subsidiary guarantors as a group is included in Note 3 to the condensed consolidated financial statements. Utility Holdings’ long-term and short-term obligations outstanding at September 30, 2005, totaled $550.0 million and $248.0 million, respectively. Additionally, prior to Utility Holdings formation, Indiana Gas and SIGECO funded their operations separately, and therefore, have long-term debt outstanding funded solely by their operations. Utility Holdings operations have historically funded almost all of Vectren’s common stock dividends.

Utility Holdings’ and Indiana Gas’ credit ratings on outstanding senior unsecured debt at September 30, 2005, are A-/Baa1 as rated by Standard and Poor's Ratings Services (Standard and Poor’s) and Moody’s Investors Service (Moody’s), respectively. SIGECO’s credit ratings on outstanding senior unsecured debt are A-/Baa1. SIGECO's credit ratings on outstanding secured debt are A/A3. Utility Holdings’ commercial paper has a credit rating of A-2/P-2. The current outlook of both Moody’s and Standard and Poor’s is stable and are categorized as investment grade. Standard and Poor’s revised its current outlook to stable from negative in January 2005 and in March 2005 revised SIGECO’s secured debt rating to A from A- and its unsecured debt to A- from BBB+. All other ratings are unchanged from December 31, 2004. A security rating is not a recommendation to buy, sell, or hold securities. The rating is subject to revision or withdrawal at any time, and each rating should be evaluated independently of any other rating. Standard and Poor’s and Moody’s lowest level investment grade rating is BBB- and Baa3, respectively.

The Company’s consolidated equity capitalization objective is 45-55% of total capitalization. This objective may have varied, and will vary, depending on particular business opportunities, capital spending requirements, and seasonal factors that affect the Company’s operation. The Company’s equity component was 51% of total permanent capitalization, including current maturities of long-term debt and long-term debt subject to tender, at both September 30, 2005, and December 31, 2004, respectively.

Financing Transactions

Long-term Borrowings
In anticipation of a debt issuance to occur in 2005 or early in 2006, Utility Holdings filed a shelf registration statement with the Securities and Exchange Commission for $275 million aggregate principal amount of unsecured senior notes in October 2005 and has executed forward starting interest rate swaps with a notional value of $75 million that expire in December 2005. When issued, the unsecured notes will be guaranteed by Utility Holdings’ three operating utility companies: SIGECO, Indiana Gas, and VEDO. These guarantees of Utility Holdings’ debt will be full and unconditional and joint and several.

Short-term Borrowings

Sources & Uses of Liquidity

Operating Cash Flow

The Company’s primary and historical source of liquidity to fund working capital requirements has been cash generated from operations, which for the nine months ended September 30, 2005 and 2004, was $261.2 million and $218.8 million, respectively. The increase of $42.4 million is primarily the result of higher earnings, depreciation and favorable changes in working capital accounts, partially offset by deferred tax expense.

Financing Cash Flow

Although working capital requirements are generally funded by cash flow from operations, the Company uses short-term borrowings to supplement working capital needs when accounts receivable balances are at their highest and gas storage is refilled. Additionally, short-term borrowings are required for capital projects and investments until they are permanently financed.

Cash flow required for financing activities was $120.3 million for the nine months ended September 30, 2005 compared to $44.1 million in 2004. Utility Holdings’ increased operating cash flow was used to fund the increased requirements, which includes the repayment of additional short-term borrowings.

Investing Cash Flow

Cash flow required for investing activities was $143.4 million for the nine months ended September 30, 2005 compared to $179.4 million in 2004. The decrease in requirements for investing activities reflects the completion of pollution control investments related to NOx compliance.

Available Sources of Liquidity

At September 30, 2005, the Company has $355.0 million of short-term borrowing capacity, of which approximately $107.0 million is available. On November 10, 2005, the Company increased its short-term borrowing capacity to $520 million, as discussed above.

Planned Capital Expenditures & Investments

Capital expenditures for the remainder of 2005 are estimated to be approximately $69.0 million.

Forward-Looking Information

A “safe harbor” for forward-looking statements is provided by the Private Securities Litigation Reform Act of 1995 (Reform Act of 1995). The Reform Act of 1995 was adopted to encourage such forward-looking statements without the threat of litigation, provided those statements are identified as forward-looking and are accompanied by meaningful cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement. Certain matters described in Management’s Discussion and Analysis of Results of Operations and Financial Condition are forward-looking statements. Such statements are based on management’s beliefs, as well as assumptions made by and information currently available to management. When used in this filing, the words “believe”, “anticipate”, “endeavor,”, “estimate”, “expect”, “objective”, “projection”, “forecast”, “goal” and similar expressions are intended to identify forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause the Company’s actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:

Factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unusual maintenance or repairs; unanticipated changes to fossil fuel costs; unanticipated changes to gas supply costs, or availability due to higher demand, shortages, transportation problems or other developments; environmental or pipeline incidents; transmission or distribution incidents; unanticipated changes to electric energy supply costs, or availability due to demand, shortages, transmission problems or other developments; or electric transmission or gas pipeline system constraints.

·	Increased competition in the energy environment including effects of industry restructuring and unbundling.

·	Regulatory factors such as unanticipated changes in rate-setting policies or procedures, recovery of investments and costs made under traditional regulation, and the frequency and timing of rate increases.

Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board; the Securities and Exchange Commission; the Federal Energy Regulatory Commission; state public utility commissions; state entities which regulate electric and natural gas transmission and distribution, natural gas gathering and processing, electric power supply; and similar entities with regulatory oversight.

·	Economic conditions including the effects of an economic downturn, inflation rates, commodity prices, and monetary fluctuations.

·	Increased natural gas commodity prices and the potential impact on customer consumption, uncollectible accounts expense, unaccounted for gas and interest expense.

·	Changing market conditions and a variety of other factors associated with physical energy and financial trading activities including, but not limited to, price, basis, credit, liquidity, volatility, capacity, interest rate, and warranty risks.

·	Direct or indirect effects on our business, financial condition or liquidity resulting from a change in credit ratings, changes in interest rates, and/or changes in market perceptions of the utility industry and other energy-related industries.

·	Employee or contractor workforce factors including changes in key executives, collective bargaining agreements with union employees, or work stoppages.

·	Legal and regulatory delays and other obstacles associated with mergers, acquisitions, and investments in joint ventures.

·	Costs and other effects of legal and administrative proceedings, settlements, investigations, claims, and other matters, including, but not limited to, those described in Management’s Discussion and Analysis of Results of Operations and Financial Condition.

·	Changes in Federal, state or local legislature requirements, such as changes in tax laws or rates, environmental laws and regulations.

The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of changes in actual results, changes in assumptions, or other factors affecting such statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to various business risks associated with commodity prices, interest rates, and counter-party credit. These financial exposures are monitored and managed by the Company as an integral part of its overall risk management program. The Company’s risk management program includes, among other things, the use of derivatives to mitigate risk. The Company also executes derivative contracts in the normal course of operations while buying and selling commodities to be used in operations and optimizing its generation assets.

The Company has in place a risk management committee that consists of senior management as well as financial and operational management. The committee is actively involved in identifying risks as well as reviewing and authorizing risk mitigation strategies.

Additional information on market-related risks are set forth in Item 7A Qualitative and Quantitative Disclosures About Market Risk included in the Vectren Utility Holdings, Inc. 2004 Form 10-K.

ITEM 4. CONTROLS AND PROCEDURES

Changes in Internal Controls over Financial Reporting

During the quarter ended September 30, 2005, there have been no changes to the Company’s internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal controls over financial reporting.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

As of September 30, 2005, the Company conducted an evaluation under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of the effectiveness and the design and operation of the Company's disclosure controls and procedures. Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer have concluded that the Company's disclosure controls and procedures are effective at providing reasonable assurance that material information relating to the Company required to be disclosed by the Company in its filings under the Securities Exchange Act of 1934 (Exchange Act) is brought to their attention on a timely basis.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The Company is party to various legal proceedings arising in the normal course of business. In the opinion of management, there are no legal proceedings pending against the Company that are likely to have a material adverse effect on its financial position or results of operations. See Notes 7, 8 and 9 of its unaudited consolidated condensed financial statements included in Part 1 Item 1 Financial Statements regarding the Clean Air Act and related legal proceedings.

ITEM 6. EXHIBITS

Exhibits

12 Computation of Ratio of Earnings to Fixed Charges

Certifications

31.1 Certification Pursuant To Section 302 of The Sarbanes-Oxley Act Of 2002- Chief Executive Officer

31.2 Certification Pursuant To Section 302 of The Sarbanes-Oxley Act Of 2002- Chief Financial Officer

32 Certification Pursuant To Section 906 of The Sarbanes-Oxley Act Of 2002

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.

VECTREN UTILITY HOLDINGS, INC.
Registrant




	November 10, 2005	/s/ Jerome A. Benkert, Jr.
		Jerome A. Benkert, Jr.
		Executive Vice President &
		Chief Financial Officer
		(Principal Financial Officer)



		/s/ M. Susan Hardwick
		M. Susan Hardwick
		Vice President & Controller
		(Principal Accounting Officer)