Vectren Utility Holdings 10Q filing for June 2005 quarter

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 June 30, 2005

o	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 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	July 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	19
3	Quantitative and Qualitative Disclosures About Market Risk	30
4	Controls and Procedures	30

	PART II. OTHER INFORMATION
1	Legal Proceedings	31
6	Exhibits	31
	Signatures	32

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

Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited - In millions)


	June 30,		December 31,
	2005		2004

ASSETS
Current Assets
Cash & cash equivalents	$	5.1	$	5.7
Accounts receivable - less reserves of $2.3 &
$1.9, respectively		84.1		147.5
Receivables due from other Vectren companies		0.2		4.0
Accrued unbilled revenues		41.5		161.2
Inventories		51.8		53.0
Recoverable fuel & natural gas costs		2.4		17.7
Prepayments & other current assets		92.1		138.2
Total current assets		277.2		527.3

Utility Plant
Original cost		3,524.6		3,465.2
Less: accumulated depreciation & amortization		1,343.0		1,309.0
Net utility plant		2,181.6		2,156.2

Investments in unconsolidated affiliates		0.2		0.2
Other investments		20.1		19.6
Non-utility property - net		160.8		149.6
Goodwill		205.0		205.0
Regulatory assets		87.5		82.5
Other assets		7.5		7.3
TOTAL ASSETS	$	2,939.9	$	3,147.7

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

Table of Contents

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited - In millions)


	June 30,		December 31,
	2005		2004

LIABILITIES & SHAREHOLDER'S EQUITY

Current Liabilities
Accounts payable	$	35.3	$	97.3
Accounts payable to affiliated companies		57.6		98.8
Payables to other Vectren companies		18.6		15.8
Refundable fuel & natural gas costs		21.8		6.3
Accrued liabilities		121.7		110.0
Short-term borrowings		141.0		308.3
Long-term debt subject to tender		-		10.0
Total current liabilities		396.0		646.5
Long-Term Debt - Net of Current Maturities &
Debt Subject to Tender		951.5		941.3
Deferred Income Taxes & Other Liabilities
Deferred income taxes		246.8		240.8
Regulatory liabilities & other removal costs		260.7		251.7
Deferred credits & other liabilities		83.6		81.9
Total deferred credits & other liabilities		591.1		574.4
Commitments & Contingencies (Notes 6 - 8)
Cumulative, Redeemable Preferred Stock of a Subsidiary		-		0.1
Common Shareholder's Equity
Common stock (no par value)		592.9		592.9
Retained earnings		408.4		392.5
Total common shareholder's equity		1,001.3		985.4
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	2,939.9	$	3,147.7

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

Table of Contents

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED CONDENSED STATEMENTS OF INCOME

(Unaudited - In millions, except per share data)


	Three Months				Six Months
	Ended June 30,				Ended June 30,
	2005		2004		2005		2004
OPERATING REVENUES
Gas utility	$	186.0	$	154.1	$	702.7	$	659.3
Electric utility		96.9		89.1		191.6		177.9
Other		0.1		0.2		0.3		0.5
Total operating revenues		283.0		243.4		894.6		837.7

OPERATING EXPENSES
Cost of gas sold		116.3		97.0		487.2		462.7
Fuel for electric generation		29.4		23.8		56.3		46.6
Purchased electric energy		3.6		6.8		5.9		11.2
Other operating		59.2		53.7		120.8		115.7
Depreciation & amortization		34.5		31.8		67.9		61.5
Taxes other than income taxes		11.7		10.4		33.5		32.7
Total operating expenses		254.7		223.5		771.6		730.4

OPERATING INCOME		28.3		19.9		123.0		107.3

OTHER INCOME (EXPENSE) - NET
Equity in earnings of
unconsolidated affiliates		-		0.1		-		0.2
Other income - net		1.1		1.4		3.3		3.2
Total other income (expense) - net		1.1		1.5		3.3		3.4
Interest expense		16.4		16.5		33.3		33.4
INCOME BEFORE INCOME TAXES		13.0		4.9		93.0		77.3
Income taxes		5.2		2.1		37.1		29.9
NET INCOME	$	7.8	$	2.8	$	55.9	$	47.4

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

Table of Contents

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited - In millions)


	Six Months Ended June 30,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	55.9		$	47.4
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization		67.9			61.5
Deferred income taxes & investment tax credits		4.0			17.6
Pension & postretirement periodic benefit cost		3.0			1.4
Equity in earnings of unconsolidated affiliates		-			(0.2	)
Net unrealized gain on derivative instruments		(2.8	)		(0.8	)
Other non-cash charges - net		5.9			5.3
Changes in working capital accounts:
Accounts receivable, including to Vectren companies
& accrued unbilled revenue		182.0			113.0
Inventories		1.2			12.5
Recoverable fuel & natural gas costs		30.8			(1.6	)
Prepayments & other current assets		47.3			49.2
Accounts payable, including to Vectren companies
& affiliated companies		(100.4	)		(32.7	)
Accrued liabilities		15.7			6.4
Changes in noncurrent assets		(3.7	)		(4.1	)
Changes in noncurrent liabilities		(7.2	)		(3.0	)
Net cash flows from operating activities		299.6			271.9
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from additional capital contribution		-			2.9
Requirements for:
Dividends to parent		(40.0	)		(39.9	)
Redemption of preferred stock of subsidiary		(0.1	)		(0.1	)
Net change in short-term borrowings		(167.3	)		(130.4	)
Net cash flows from financing activities		(207.4	)		(167.5	)
CASH FLOWS FROM INVESTING ACTIVITIES
Requirements for:
Capital expenditures, excluding AFUDC - equity		(92.8	)		(106.8	)
Net cash flows from investing activities		(92.8	)		(106.8	)
Net decrease in cash & cash equivalents		(0.6	)		(2.4	)
Cash & cash equivalents at beginning of period		5.7			8.1
Cash & cash equivalents at end of period	$	5.1		$	5.7

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

Table of Contents

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 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 $141.0 million is outstanding at June 30, 2005, and Utility Holdings’ $550.0 million unsecured senior notes outstanding at June 30, 2005. The guarantees are full and unconditional and joint and several, and Utility Holdings has no subsidiaries other than the subsidiary guarantors. However, 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.

Table of Contents

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


	Subsidiary		Parent
	Guarantors		Company		Eliminations			Consolidated
OPERATING REVENUES
Gas utility	$	186.0	$	-	$	-		$	186.0
Electric utility		96.9		-		-			96.9
Other		-		9.1		(9.0	)		0.1
Total operating revenues		282.9		9.1		(9.0	)		283.0
OPERATING EXPENSES
Cost of gas sold		116.3		-		-			116.3
Fuel for electric generation		29.4		-		-			29.4
Purchased electric energy		3.6		-		-			3.6
Other operating		68.1		-		(8.9	)		59.2
Depreciation & amortization		29.9		4.6		-			34.5
Taxes other than income taxes		11.5		0.2		-			11.7
Total operating expenses		258.8		4.8		(8.9	)		254.7
OPERATING INCOME		24.1		4.3		(0.1	)		28.3
OTHER INCOME (EXPENSE) - NET
Equity in losses of consolidated companies		-		5.3		(5.3	)		-
Equity in earnings of unconsolidated affiliates		-		-		-			-
Other income (expense) – net		0.7		9.3		(8.9	)		1.1
Total other income (expense) - net		0.7		14.6		(14.2	)		1.1
Interest expense		15.6		9.8		(9.0	)		16.4
INCOME BEFORE INCOME TAXES		9.2		9.1		(5.3	)		13.0
Income taxes		3.9		1.3		-			5.2
NET INCOME	$	5.3	$	7.8	$	(5.3	)	$	7.8

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


	Subsidiary		Parent
	Guarantors		Company			Eliminations			Consolidated
OPERATING REVENUES
Gas utility	$	154.1	$	-		$	-		$	154.1
Electric utility		89.1		-			-			89.1
Other		-		8.7			(8.5	)		0.2
Total operating revenues		243.2		8.7			(8.5	)		243.4
OPERATING EXPENSES
Cost of gas sold		97.0		-			-			97.0
Fuel for electric generation		23.8		-			-			23.8
Purchased electric energy		6.8		-			-			6.8
Other operating		63.8		(1.6	)		(8.5	)		53.7
Depreciation & amortization		27.3		4.5			-			31.8
Taxes other than income taxes		10.1		0.3			-			10.4
Total operating expenses		228.8		3.2			(8.5	)		223.5
OPERATING INCOME		14.4		5.5			-			19.9
OTHER INCOME (EXPENSE) - NET
Equity in losses of consolidated companies		-		-			-			-
Equity in earnings of unconsolidated affiliates		-		0.1			-			0.1
Other income (expense) – net		1.2		8.2			(8.0	)		1.4
Total other income (expense) - net		1.2		8.3			(8.0	)		1.5
Interest expense		15.5		9.0			(8.0	)		16.5
INCOME BEFORE INCOME TAXES		0.1		4.8			-			4.9
Income taxes		0.1		2.0			-			2.1
NET INCOME	$	-	$	2.8		$	-		$	2.8

Table of Contents

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


	Subsidiary		Parent
	Guarantors		Company		Eliminations			Consolidated
OPERATING REVENUES
Gas utility	$	702.7	$	-	$	-		$	702.7
Electric utility		191.6		-		-			191.6
Other		-		18.2		(17.9	)		0.3
Total operating revenues		894.3		18.2		(17.9	)		894.6
OPERATING EXPENSES
Cost of gas sold		487.2		-		-			487.2
Fuel for electric generation		56.3		-		-			56.3
Purchased electric energy		5.9		-		-			5.9
Other operating		136.9		-		(16.1	)		120.8
Depreciation & amortization		58.9		9.0		-			67.9
Taxes other than income taxes		33.0		0.5		-			33.5
Total operating expenses		778.2		9.5		(16.1	)		771.6
OPERATING INCOME		116.1		8.7		(1.8	)		123.0
OTHER INCOME (EXPENSE) - NET
Equity in earnings of consolidated companies		-		51.7		(51.7	)		-
Other income (expense) – net		0.7		19.0		(16.4	)		3.3
Total other income (expense) - net		0.7		70.7		(68.1	)		3.3
Interest expense		31.5		20.0		(18.2	)		33.3
INCOME BEFORE INCOME TAXES		85.3		59.4		(51.7	)		93.0
Income taxes		33.6		3.5		-			37.1
NET INCOME	$	51.7	$	55.9	$	(51.7	)	$	55.9

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


	Subsidiary		Parent
	Guarantors		Company			Eliminations			Consolidated
OPERATING REVENUES
Gas utility	$	659.3	$	-		$	-		$	659.3
Electric utility		177.9		-			-			177.9
Other		-		18.1			(17.6	)		0.5
Total operating revenues		837.2		18.1			(17.6	)		837.7
OPERATING EXPENSES
Cost of gas sold		462.7		-			-			462.7
Fuel for electric generation		46.6		-			-			46.6
Purchased electric energy		11.2		-			-			11.2
Other operating		132.8		(1.4	)		(15.7	)		115.7
Depreciation & amortization		52.7		8.8			-			61.5
Taxes other than income taxes		32.2		0.5			-			32.7
Total operating expenses		738.2		7.9			(15.7	)		730.4
OPERATING INCOME		99.0		10.2			(1.9	)		107.3
OTHER INCOME (EXPENSE) - NET
Equity in earnings of consolidated companies		-		43.0			(43.0	)		-
Equity in earnings of unconsolidated affiliates		-		0.2			-			0.2
Other income (expense) – net		0.6		16.6			(14.0	)		3.2
Total other income (expense) - net		0.6		59.8			(57.0	)		3.4
Interest expense		31.2		18.1			(15.9	)		33.4
INCOME BEFORE INCOME TAXES		68.4		51.9			(43.0	)		77.3
Income taxes		25.4		4.5			-			29.9
NET INCOME	$	43.0	$	47.4		$	(43.0	)	$	47.4

Table of Contents

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


	Subsidiary			Parent
	Guarantors			Company			Eliminations			Consolidated
NET CASH FLOWS FROM OPERATING ACTIVITIES	$	281.7		$	17.9		$	-		$	299.6
CASH FLOWS FROM FINANCING ACTIVITIES
Requirements for:
Dividends to parent		(40.0	)		(40.0	)		40.0			(40.0	)
Redemption of preferred stock of subsidiary		(0.1	)		-			-			(0.1	)
Net change in short-term borrowings		(138.4	)		(135.9	)		107.0			(167.3	)
Net cash flows from financing activities		(178.5	)		(175.9	)		147.0			(207.4	)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from consolidated subsidiary distributions		-			40.0			(40.0	)		-
Requirements for:
Capital expenditures, excluding AFUDC equity		(72.7	)		(20.1	)		-			(92.8	)
Net change in notes receivable to other Vectren companies		(31.1	)		138.1			(107.0	)		-
Net cash flows from investing activities		(103.8	)		158.0			(147.0	)		(92.8	)
Net decrease in cash & cash equivalents		(0.6	)		-						(0.6	)
Cash & cash equivalents at beginning of period		4.7			1.0						5.7
Cash & cash equivalents at end of period	$	4.1		$	1.0		$	-		$	5.1

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


	Subsidiary			Parent
	Guarantors			Company			Eliminations			Consolidated
NET CASH FLOWS FROM OPERATING ACTIVITIES	$	253.1		$	18.8		$	-		$	271.9
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from additional capital contribution		-			2.9			-			2.9
Requirements for:
Dividends to parent		(40.0	)		(39.9	)		40.0			(39.9	)
Redemption of preferred stock of subsidiary		(0.1	)		-			-			(0.1	)
Net change in short-term borrowings		(54.2	)		(67.8	)		(8.4	)		(130.4	)
Net cash flows from financing activities		(94.3	)		(104.8	)		31.6			(167.5	)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from consolidated subsidiary distributions		-			40.0			(40.0	)		-
Requirements for:
Capital expenditures, excluding AFUDC equity		(99.0	)		(7.8	)		-			(106.8	)
Net change in notes receivable to other Vectren companies		(61.8	)		53.4			8.4			-
Net cash flows from investing activities		(160.8	)		85.6			(31.6	)		(106.8	)
Net decrease in cash & cash equivalents		(2.0	)		(0.4	)					(2.4	)
Cash & cash equivalents at beginning of period		7.4			0.7						8.1
Cash & cash equivalents at end of period	$	5.4		$	0.3		$	-		$	5.7

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


ASSETS	Subsidiary		Parent
	Guarantors		Company		Eliminations			Consolidated
Current Assets
Cash & cash equivalents	$	4.1	$	1.0	$	-		$	5.1
Accounts receivable - less reserves		84.0		0.1		-			84.1
Receivables due from other Vectren companies		31.3		185.4		(216.5	)		0.2
Accrued unbilled revenues		41.5		-		-			41.5
Inventories		51.8		-		-			51.8
Recoverable fuel & natural gas costs		2.4		-		-			2.4
Prepayments & other current assets		94.2		0.7		(2.8	)		92.1
Total current assets		309.3		187.2		(219.3	)		277.2
Utility Plant
Original cost		3,524.6		-		-			3,524.6
Less: accumulated depreciation & amortization		1,343.0		-		-			1,343.0
Net utility plant		2,181.6		-		-			2,181.6
Investments in consolidated subsidiaries		-		963.3		(963.3	)		-
Notes receivable from consolidated subsidiaries		-		443.1		(443.1	)		-
Investments in unconsolidated affiliates		0.2		-		-			0.2
Other investments		14.0		6.1		-			20.1
Non-utility property - net		5.2		155.6		-			160.8
Goodwill		205.0		-		-			205.0
Regulatory assets		78.1		9.4		-			87.5
Other assets		4.7		2.8		-			7.5
TOTAL ASSETS	$	2,798.1	$	1,767.5	$	(1,625.7	)	$	2,939.9
LIABILITIES & SHAREHOLDER'S EQUITY		Subsidiary		Parent
		Guarantors		Company		Eliminations			Consolidated
Current Liabilities
Accounts payable	$	28.4	$	6.9	$	-		$	35.3
Accounts payable to affiliated companies		57.4		0.2		-			57.6
Payables to other Vectren companies		28.2		0.1		(9.7	)		18.6
Refundable fuel & natural gas costs		21.8		-		-			21.8
Accrued liabilities		108.7		15.8		(2.8	)		121.7
Short-term borrowings		-		141.0		-			141.0
Short-term borrowings from other Vectren companies		175.7		31.1		(206.8)			-
Total current liabilities		420.2		195.1		(219.3	)		396.0
Long-Term Debt
Long-term debt - net of current maturities &
debt subject to tender		403.3		548.2		-			951.5
Long-term debt due to VUHI		443.1		-		(443.1	)		-
Total long-term debt - net		846.4		548.2		(443.1	)		951.5
Deferred Income Taxes & Other Liabilities
Deferred income taxes		233.6		13.2		-			246.8
Regulatory liabilities & other removal costs		255.5		5.2		-			260.7
Deferred credits & other liabilities		79.1		4.5		-			83.6
Total deferred credits & other liabilities		568.2		22.9		-			591.1
Common Shareholder's Equity
Common stock (no par value)		611.3		592.9		(611.3	)		592.9
Retained earnings		352.0		408.4		(352.0	)		408.4
Total common shareholder's equity		963.3		1,001.3		(963.3	)		1,001.3
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	2,798.1	$	1,767.5	$	(1,625.7	)	$	2,939.9

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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		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 & other removal costs		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

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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 $21.1 million and $20.4 million for the three months ended June 30, 2005 and 2004, respectively. Utility Holdings received corporate allocations totaling $43.0 million and $42.2 million for the six months ended June 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 June 30, 2005 and 2004, totaled $24.7 million and $20.3 million, respectively. Amounts paid for such purchases for the six months ended June 30, 2005 and 2004, totaled $48.1 million and $39.1 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.	Transactions with 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.

Transactions with ProLiance

Purchases from ProLiance for resale and for injections into storage for the three months ended June 30, 2005 and 2004, totaled $192.8 million and $183.1 million, respectively, and for the six months ended June 30, 2005 and 2004, totaled $410.2 million and $402.2 million, respectively. Amounts owed to ProLiance at June 30, 2005, and December 31, 2004, for those purchases were $55.7 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.

6.	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.

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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.

7. 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 $244 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 June 30, 2005, capital investments approximating the level approved by the IURC have been made. Once all equipment is installed and operational, 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 the plan is approved, its coal-fired plants will be 100% scrubbed for sulfur dioxide (SO2), 90% scrubbed for nitrogen oxide (NOx), and mercury emissions will be reduced to meet the new mercury reduction standards. The Company has requested recovery of the capital investments, which are expected to approximate $110 million, and related operating expenses through a rider mechanism. This rider mechanism is expected to operate like the rider used to recover NOx-related capital investments and operating expenses.

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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.

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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.

8.	Rate & Regulatory Matters

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.

Normal Temperature Adjustment Settlement

Vectren Energy Delivery of Indiana and the Indiana Office of Utility Consumer Counselor (OUCC) entered into a settlement agreement providing for the establishment of a normal temperature adjustment (NTA) mechanism. The settlement, filed with the IURC on July 26, 2005, will affect the Company’s Indiana regulated gas customers and should mitigate the margin impact of weather for approximately 60-65% of the Company’s heating load during the October to April peak heating season.

If approved by the IURC, 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. If approved, the NTA is expected to be implemented in October 2005.

As part of the settlement, the Company will make on a monthly basis a commitment of $125,000 to Indiana’s Universal Service Fund program for the duration of the NTA. This program provides assistance to low income customers by providing bill discounts.

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.

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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 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 winter delivery services and the portfolio administration agreement, and also believes that any change to the existing portfolio administration agreement between ProLiance and VEDO would not be material to Vectren’s future earnings, financial position, or cash flows. VEDO filed its request for rehearing on July 14, and the matter is now pending before the PUCO.

9.	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.

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10.

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						Six Months
	Ended June 30,						Ended June 30,
(In millions)	2005			2004			2005			2004
Revenues
Gas Utility Services	$	186.0		$	154.1		$	702.7		$	659.3
Electric Utility Services		96.9			89.1			191.6			177.9
Other Operations		9.1			8.7			18.2			18.1
Eliminations		(9.0	)		(8.5	)		(17.9	)		(17.6	)
Consolidated Revenues	$	283.0		$	243.4		$	894.6		$	837.7

Profitability Measure
Regulated Operating Income
(Operating Income Less Applicable Income Taxes)
Gas Utility Services	$	5.7		$	1.1		$	50.8		$	47.2
Electric Utility Services		14.5			13.2			31.8			26.5
Total Regulated Operating Income		20.2			14.3			82.6			73.7
Regulated other income - net		0.3			1.2			0.2			0.5
Regulated interest expense & preferred dividends		(15.2	)		(15.5	)		(31.1	)		(31.2	)
Regulated Net Income		5.3			-			51.7			43.0
Other Operations Net Income		2.5			2.8			4.2			4.4
Consolidated Net Income	$	7.8		$	2.8		$	55.9		$	47.4

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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.

Earnings were $7.8 million for the quarter compared to $2.8 million in the prior year and $55.9 million for the six months ended June 30, 2005 compared to $47.4 million in 2004. The increased performance is primarily due to the implementation of new gas base rates in the Company’s Indiana and Ohio service territories, higher electric revenues associated with recovery of pollution control investments and increased margins from generation asset optimization activities. Gas base rate increases added revenue of $9.1 million, or $5.4 million after tax, during the quarter and $17.0 million, or $10.1 million after tax, for the six months ended June 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 $1.6 million or $0.9 million after tax, for the quarter and $3.9 million, or $2.3 million after tax, for the six month period. The improved margins were partially offset by higher operating and depreciation expense and a $3.0 million, $1.8 million after tax, charge recorded in the second quarter pursuant to the disallowance of Ohio gas costs. Weather, while slightly favorable for the quarter, is estimated to be unfavorable $1.2 million after tax year to date, compared to last year.

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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				Six Months
	Ended June 30,				Ended June 30,
(In millions)	2005		2004		2005		2004

Residential & Commercial	$	57.9	$	46.1	$	185.6	$	169.4
Industrial		9.7		9.2		25.3		24.1
Other		2.1		1.8		4.6		3.1
Total gas utility margin	$	69.7	$	57.1	$	215.5	$	196.6

Sold & transported volumes in MMDth:
To residential & commercial customers		13.5		12.8		68.5		71.9
To industrial customers		19.2		17.9		46.0		45.3
Total throughput		32.7		30.7		114.5		117.2

Gas utility margins were $69.7 million and $215.5 million for the three and six months ended June 30, 2005. This represents an increase compared to prior periods of $12.6 million and $18.9 million, respectively. The increases are primarily due to the favorable impact of gas base rate increases. Customer growth, net of some usage decline, and additional pass through of expenses and revenue taxes recovered in margins are also reflected in the increases.

The second quarter of 2005 includes a $3.0 million additional charge as the estimated impact of a disallowance of Ohio gas costs ordered by the Public Utilities Commission of Ohio. The company had previously recorded a charge of $1.5 million with respect to the matters raised in the order. Heating weather in the quarter was 20% cooler compared to 2004 and increased margin an estimated $2.3 million compared to 2004. For the six month period, weather was 8% warmer than normal and similar to the prior year. Gas sold and transported volumes were 2% lower for the six months ended June 30, 2005. The average cost per dekatherm of gas purchased for the six months ended June 30, 2005, was $7.41 compared to $6.72 in 2004.

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

Electric Utility margin by revenue type follows:


	Three Months					Six Months
	Ended June 30,					Ended June 30,
(In millions)	2005		2004			2005		2004

Residential & commercial	$	39.7	$	39.5		$	76.8	$	74.7
Industrial		16.3		16.1			31.6		30.6
Municipalities & other		5.1		4.7			9.2		9.5
Total retail & firm wholesale		61.1		60.3			117.6		114.8
Asset optimization		2.8		(1.8	)		11.8		5.3
Total electric utility margin	$	63.9	$	58.5		$	129.4	$	120.1

Retail & Firm Wholesale Margin

Electric retail and firm wholesale utility margins were $61.1 million and $117.6 million for the three and six months ended June 30, 2005. This represents an increase over the prior year periods of $0.8 million and $2.8 million, respectively. The recovery of pollution control related investments and associated operating expenses and related depreciation increased margins $3.6 million quarter over quarter and $6.2 million for the six month period. These increases were partially offset by cooler weather and other factors. Cooling weather for the quarter and six months ended was 7% and 8% cooler than normal, respectively, and 23% cooler than last year. The estimated decrease in margin due to weather was $1.4 million and $1.8 million for the three and six month periods, respectively, compared to the prior year. Due to these factors, volumes sold decreased 2% during the quarter and 1% during the six months ended June 30, 2005, to 2,929.5 GWh compared to 2,965.2 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						Six Months
	Ended June 30,						Ended June 30,
(In millions)	2005			2004			2005			2004
Beginning of Period Net Balance Sheet Position	$	2.4		$	3.4		$	(0.6	)	$	(0.4	)
Statement of Income Activity
Net mark-to-market gains (losses)		0.3			(2.0	)		2.8			0.8
Net realized gains		2.5			0.2			9.0			4.5
Net activity in electric utility margin		2.8			(1.8	)		11.8			5.3
Net cash received & other adjustments		(2.0	)		0.6			(8.0	)		(2.7	)
End of Period Net Balance Sheet Position	$	3.2		$	2.2		$	3.2		$	2.2

For the three and six month periods ended June 30, 2005, net asset optimization margins were $2.8 million and $11.8 million, which represents an increase of $4.6 million and $6.5 million, as compared to 2004. The additional 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.

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Operating Expenses

Other operating expenses for the three and six months ended June 30, 2005, increased $5.5 million and $5.1 million, respectively, compared to 2004. The increases are primarily attributable to compensation and benefit costs increases, including incentive and share-based compensation, of $2.5 million in the second quarter of 2005 due in part to timing and anticipated performance in relation to incentive metrics. For the quarter, NOx-related operating expenses increased $0.4 million and, for the six months, NOx related operating expenses decreased $0.7 million compared to last year. Other expenses recovered in margin related to Ohio bad debt and percent of income payment plan expenses increased $0.6 million in the quarter and $2.6 million year-to-date compared to the prior year. The remaining quarterly increase is primarily attributable to increased chemical costs for scrubbing SO₂, landfill maintenance costs and the amortization of rate case expenses.

Depreciation & Amortization

Depreciation expense increased $2.7 million and $6.4 million for the three and six month periods ended June 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 of $1.6 million for the quarter and $3.0 million for the year to date period, respectively, associated with environmental compliance equipment additions. 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 $1.3 million and $0.8 million for the three and six months ended June 30, 2005, respectively, compared to 2004. The increases are primarily attributable to revenue taxes resulting from higher revenues.

Income Taxes

For the three and six months ended June 30, 2005, Federal and state income taxes increased $3.1 million and $7.2 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 $244 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.

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Clean Air Interstate Rule & Clean Air Mercury Rule

Information Request

Manufactured Gas Plants

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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

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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

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Other Operating Matters

United States Securities and Exchange Commission Inquiry into PUHCA Exemption

Impact of Recently Issued Accounting Guidance

SFAS No. 154

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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 June 30, 2005, totaled $550.0 million and $141.0 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 June 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 June 30, 2005, and December 31, 2004, respectively.

The Company expects the majority of its capital expenditures, investments, and debt security redemptions to be provided by internally generated funds. However, due to significant utility capital expenditures and maturing debt, the Company may require additional permanent financing. In anticipation of a future debt issuance, the Company executed forward starting interest rate swaps with a notional value of $75 million that expire in December 2005.

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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 six months ended June 30, 2005 and 2004, was $299.6 million and $271.9 million , respectively. The increase of $27.7 million is primarily the result of higher earnings, depreciation and favorable changes in working capital accounts offset somewhat 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 of $207.4 million for the six months ended June 30, 2005 compared to $167.5 million in 2004.

Utility Holdings’ increased operating cash flow was used to fund the increased requirements, which includes the repayment of an additional $36.9 million in short-term borrowings, compared to 2004.

Investing Cash Flow

Cash flow required for investing activities was $92.8 million for the six months ended June 30, 2005 compared to $106.8 million in 2004. The decrease in requirements for investing activities reflects the near completion of pollution control investments addressing NOx compliance.

Available Sources of Liquidity

At June 30, 2005, the Company has $355 million of short-term borrowing capacity, of which approximately $214 million is available.

Planned Capital Expenditures & Investments

Capital expenditures for the remainder of 2005 are estimated to be approximately $120 million.

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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.

·	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.

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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.

These risks are not significantly different from the information set forth in Item 7A Quantitative and Qualitative Disclosures About Market Risk included in the Company’s 2004 Form 10-K and are therefore not presented herein.

ITEM 4. CONTROLS AND PROCEDURES

Changes in Internal Controls over Financial Reporting

Since February 2002, 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. 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.

In connection with the implementation of the Day 2 energy market, the Company implemented new processes and modified existing processes to facilitate participation within the MISO market. These processes focused primarily on billing settlements with the MISO.

Other than this change, during the quarter ended June 30, 2005, there have been no other 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 June 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.

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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 Note 7 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

3. Articles of Incorporation and By-Laws

3.4 Amended and Restated Code of By-Laws of Vectren Corporation as of May 1, 2005. (Incorporated by reference to

Exhibit 3.4 to the Quarterly Report on Form 10-Q for the period ended June 30, 2005 of Vectren Corporation, file

number 1-15467.)

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

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SIGNATURES

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

		VECTREN UTILITY HOLDINGS, INC.
		Registrant




August 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)

/s/ Jerome A. Benkert, Jr.		/s/ Niel C. Ellerbrook
(Signature of Authorized Officer)		(Signature of Authorized Officer)
Jerome A. Benkert, Jr.		Niel C. Ellerbrook
(Typed Name)		(Typed Name)
Executive Vice President & Chief Financial Officer		Chairman & Chief Executive Officer
(Title)		(Title)