Edgar Filing: VECTREN UTILITY HOLDINGS INC

vuhi10q.htm

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, 2007

[_]	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 __

Table of Contents

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

Large accelerated filer □ Accelerated filer □ Non-accelerated filer ý

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes □ No ý

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, 2007
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	4-5
	Consolidated Condensed Statements of Income	6
	Consolidated Condensed Statements of Cash Flows	7
	Notes to Unaudited Consolidated Condensed Financial Statements	8
2	Management’s Discussion and Analysis of Results of Operations and Financial Condition	22
3	Quantitative and Qualitative Disclosures About Market Risk	34
4	Controls and Procedures	34

	PART II. OTHER INFORMATION
1	Legal Proceedings	34
1A	Risk Factors	34
6	Exhibits	34
	Signatures	36

Access to Information

Vectren Corporation makes available all SEC filings and recent annual reports free of charge, including those of its wholly owned subsidiaries, 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

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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	OCC: Ohio Office of the Consumer Counselor
IDEM: Indiana Department of Environmental Management	OUCC: Indiana Office of the Utility Consumer Counselor
IURC: Indiana Utility Regulatory Commission	PUCO: Public Utilities Commission of Ohio
MCF / BCF: thousands / billions of cubic feet	SFAS: Statement of Financial Accounting Standards
MDth / MMDth: thousands / millions of dekatherms	USEPA: United States Environmental Protection Agency
MISO: Midwest Independent System Operator	Throughput: combined gas sales and gas transportation volumes

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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,
	2007		2006

ASSETS
Current Assets
Cash & cash equivalents	$	3.3	$	28.5
Accounts receivable - less reserves of $4.2 &
$2.5, respectively		96.7		134.8
Receivables due from other Vectren companies		0.4		0.3
Accrued unbilled revenues		38.1		121.4
Inventories		110.7		141.9
Recoverable fuel & natural gas costs		-		1.8
Prepayments & other current assets		84.9		103.2
Total current assets		334.1		531.9

Utility Plant
Original cost		3,925.5		3,820.2
Less: accumulated depreciation & amortization		1,475.8		1,434.7
Net utility plant		2,449.7		2,385.5

Investments in unconsolidated affiliates		0.2		0.2
Other investments		21.9		21.4
Nonutility property - net		169.1		163.1
Goodwill		205.0		205.0
Regulatory assets		125.0		116.8
Other assets		17.5		16.9
TOTAL ASSETS	$	3,322.5	$	3,440.8

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

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VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited – In millions)


	June 30,		December 31,
	2007		2006

LIABILITIES & SHAREHOLDER'S EQUITY

Current Liabilities
Accounts payable	$	59.6	$	136.2
Accounts payable to affiliated companies		43.7		68.2
Payables to other Vectren companies		22.1		25.3
Refundable fuel & natural gas costs		40.4		35.3
Accrued liabilities		136.2		115.8
Short-term borrowings		215.0		270.1
Current maturities of long-term debt		6.5		6.5
Long-term debt subject to tender		20.0		20.0
Total current liabilities		543.5		677.4
Long-Term Debt - Net of Current Maturities &
Debt Subject to Tender		1,025.5		1,025.3
Deferred Income Taxes & Other Liabilities
Deferred income taxes		258.8		282.2
Regulatory liabilities		302.7		291.1
Deferred credits & other liabilities		116.0		108.1
Total deferred credits & other liabilities		677.5		681.4
Commitments & Contingencies (Notes 8 - 10)
Common Shareholder's Equity
Common stock (no par value)		632.9		632.9
Retained earnings		442.6		422.9
Accumulated other comprehensive income		0.5		0.9
Total common shareholder's equity		1,076.0		1,056.7

TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,322.5	$	3,440.8

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

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VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED CONDENSED STATEMENTS OF INCOME

(Unaudited – In millions)


	Three Months				Six Months
	Ended June 30,				Ended June 30,
	2007		2006		2007		2006
OPERATING REVENUES
Gas utility	$	191.9	$	159.1	$	776.0	$	731.8
Electric utility		109.9		96.0		218.0		201.2
Other		0.5		0.5		0.9		0.9
Total operating revenues		302.3		255.6		994.9		933.9

OPERATING EXPENSES
Cost of gas sold		114.6		88.5		539.1		517.5
Cost of fuel & purchased power		38.4		30.9		79.0		69.0
Other operating		65.6		59.6		132.8		121.2
Depreciation & amortization		39.8		37.7		79.0		74.8
Taxes other than income taxes		14.1		11.6		38.3		34.4
Total operating expenses		272.5		228.3		868.2		816.9

OPERATING INCOME		29.8		27.3		126.7		117.0

OTHER INCOME - NET		2.2		1.9		4.9		2.8
INTEREST EXPENSE		18.6		18.2		38.0		38.2

INCOME BEFORE INCOME TAXES		13.4		11.0		93.6		81.6

INCOME TAXES		5.4		3.9		34.7		31.1

NET INCOME	$	8.0	$	7.1	$	58.9	$	50.5

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

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VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited – In millions)


	Six Months Ended June 30,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	58.9		$	50.5
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization		79.0			74.8
Deferred income taxes & investment tax credits		(2.2	)		(0.5	)
Expense portion of pension & postretirement periodic benefit cost		2.1			2.1
Provision for uncollectible acccounts		8.2			5.4
Other non-cash charges - net		1.8			3.2
Changes in working capital accounts:
Accounts receivable, including to Vectren companies
& accrued unbilled revenue		113.1			253.6
Inventories		31.2			14.1
Recoverable/refundable fuel & natural gas costs		6.9			42.7
Prepayments & other current assets		16.0			6.2
Accounts payable, including to Vectren companies
& affiliated companies		(101.1	)		(195.7	)
Accrued liabilities		7.4			(23.0	)
Changes in noncurrent assets		(9.6	)		(12.6	)
Changes in noncurrent liabilities		(5.7	)		2.4
Net cash flows from operating activities		206.0			223.2
CASH FLOWS FROM FINANCING ACTIVITIES
Requirements for:
Dividends to parent		(38.3	)		(37.3	)
Net change in short-term borrowings		(55.1	)		(96.5	)
Net cash flows from financing activities		(93.4	)		(133.8	)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from other investing activities		0.1			-
Requirements for:
Capital expenditures, excluding AFUDC - equity		(137.9	)		(96.5	)
Net cash flows from investing activities		(137.8	)		(96.5	)
Net decrease in cash & cash equivalents		(25.2	)		(7.1	)
Cash & cash equivalents at beginning of period		28.5			11.7
Cash & cash equivalents at end of period	$	3.3		$	4.6

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

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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 holding company headquartered in Evansville, Indiana. Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 2005.

Indiana Gas provides energy delivery services to approximately 565,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 141,000 electric customers and approximately 112,000 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 318,000 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, 2006, filed with the SEC February 27, 2007 on Form 10-K. 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’ $515 million in short-term credit facilities, of which $215 million is outstanding at June 30, 2007, and Utility Holdings’ $700 million unsecured senior notes outstanding at June 30, 2007. 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.

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Condensed Consolidating Statement of Income for the three months ended June 30, 2007 (in millions):


	Subsidiary		Parent
	Guarantors		Company		Eliminations			Consolidated
OPERATING REVENUES
Gas utility	$	191.9	$	-	$	-		$	191.9
Electric utility		109.9		-		-			109.9
Other		-		10.5		(10.0	)		0.5
Total operating revenues		301.8		10.5		(10.0	)		302.3
OPERATING EXPENSES
Cost of gas sold		114.6		-		-			114.6
Cost of fuel & purchased power		38.4		-		-			38.4
Other operating		74.9		-		(9.3	)		65.6
Depreciation & amortization		34.1		5.7		-			39.8
Taxes other than income taxes		13.8		0.3		-			14.1
Total operating expenses		275.8		6.0		(9.3	)		272.5
OPERATING INCOME		26.0		4.5		(0.7	)		29.8
OTHER INCOME (EXPENSE) - NET
Equity in earnings of consolidated companies		-		6.8		(6.8	)		-
Other income (expense) – net		1.8		10.6		(10.2	)		2.2
Total other income (expense) - net		1.8		17.4		(17.0	)		2.2
Interest expense		16.3		13.2		(10.9	)		18.6
INCOME BEFORE INCOME TAXES		11.5		8.7		(6.8	)		13.4
Income taxes		4.7		0.7		-			5.4
NET INCOME	$	6.8	$	8.0	$	(6.8	)	$	8.0

Condensed Consolidating Statement of Income for the three months ended June 30, 2006 (in millions):


	Subsidiary		Parent
	Guarantors		Company		Eliminations			Consolidated
OPERATING REVENUES
Gas utility	$	159.1	$	-	$	-		$	159.1
Electric utility		96.0		-		-			96.0
Other		-		9.2		(8.7	)		0.5
Total operating revenues		255.1		9.2		(8.7	)		255.6
OPERATING EXPENSES
Cost of gas sold		88.5		-		-			88.5
Cost of fuel & purchased power		30.9		-		-			30.9
Other operating		67.9		-		(8.3	)		59.6
Depreciation & amortization		32.3		5.4		-			37.7
Taxes other than income taxes		11.3		0.3		-			11.6
Total operating expenses		230.9		5.7		(8.3	)		228.3
OPERATING INCOME		24.2		3.5		(0.4	)		27.3
OTHER INCOME (EXPENSE) - NET
Equity in earnings of consolidated companies		-		6.1		(6.1	)		-
Other income (expense) – net		1.1		10.4		(9.6	)		1.9
Total other income (expense) - net		1.1		16.5		(15.7	)		1.9
Interest expense		15.8		12.4		(10.0	)		18.2
INCOME BEFORE INCOME TAXES		9.5		7.6		(6.1	)		11.0
Income taxes		3.4		0.5		-			3.9
NET INCOME	$	6.1	$	7.1	$	(6.1	)	$	7.1

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Condensed Consolidating Statement of Income for the six months ended June 30, 2007 (in millions):


	Subsidiary		Parent
	Guarantors		Company			Eliminations			Consolidated
OPERATING REVENUES
Gas utility	$	776.0	$	-		$	-		$	776.0
Electric utility		218.0		-			-			218.0
Other		-		20.2			(19.3	)		0.9
Total operating revenues		994.0		20.2			(19.3	)		994.9
OPERATING EXPENSES
Cost of gas sold		539.1		-			-			539.1
Cost of fuel & purchased power		79.0		-			-			79.0
Other operating		149.8		-			(17.0	)		132.8
Depreciation & amortization		67.4		11.6			-			79.0
Taxes other than income taxes		37.7		0.6			-			38.3
Total operating expenses		873.0		12.2			(17.0	)		868.2
OPERATING INCOME		121.0		8.0			(2.3	)		126.7
OTHER INCOME (EXPENSE) - NET
Equity in earnings of consolidated companies		-		55.5			(55.5	)		-
Other income (expense) – net		2.8		21.4			(19.3	)		4.9
Total other income (expense) - net		2.8		76.9			(74.8	)		4.9
Interest expense		32.9		26.7			(21.6	)		38.0
INCOME BEFORE INCOME TAXES		90.9		58.2			(55.5	)		93.6
Income taxes		35.4		(0.7	)		-			34.7
NET INCOME	$	55.5	$	58.9		$	(55.5	)	$	58.9

Condensed Consolidating Statement of Income for the six months ended June 30, 2006 (in millions):


	Subsidiary		Parent
	Guarantors		Company			Eliminations			Consolidated
OPERATING REVENUES
Gas utility	$	731.8	$	-		$	-		$	731.8
Electric utility		201.2		-			-			201.2
Other		-		18.4			(17.5	)		0.9
Total operating revenues		933.0		18.4			(17.5	)		933.9
OPERATING EXPENSES
Cost of gas sold		517.5		-			-			517.5
Cost of fuel & purchased power		69.0		-			-			69.0
Other operating		136.9		-			(15.7	)		121.2
Depreciation & amortization		64.2		10.6			-			74.8
Taxes other than income taxes		33.8		0.6			-			34.4
Total operating expenses		821.4		11.2			(15.7	)		816.9
OPERATING INCOME		111.6		7.2			(1.8	)		117.0
OTHER INCOME (EXPENSE) - NET
Equity in earnings of consolidated companies		-		48.3			(48.3	)		-
Other income (expense) – net		0.9		20.5			(18.6	)		2.8
Total other income (expense) - net		0.9		68.8			(66.9	)		2.8
Interest expense		33.0		25.6			(20.4	)		38.2
INCOME BEFORE INCOME TAXES		79.5		50.4			(48.3	)		81.6
Income taxes		31.2		(0.1	)		-			31.1
NET INCOME	$	48.3	$	50.5		$	(48.3	)	$	50.5

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Condensed Consolidating Statement of Cash Flows for the six months ended June 30, 2007 (in millions):


	Subsidiary			Parent
	Guarantors			Company			Eliminations			Consolidated

NET CASH FLOWS FROM OPERATING ACTIVITIES	$	170.5		$	35.5		$	-		$	206.0

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from additional capital contribution		-			-			-			-
Long-term Debt - net of issuance costs & hedging proceeds		-			-			-			-
Requirements for:
Dividends to parent		(38.3	)		(38.3	)		38.3			(38.3	)
Net change in short-term borrowings		(13.1	)		(32.7	)		(9.3	)		(55.1	)
Net cash flows from financing activities		(51.4	)		(71.0	)		29.0			(93.4	)

CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from consolidated subsidiary distributions		-			38.3			(38.3	)		-
Proceeds from other investing activities		-			0.1			-			0.1
Requirements for:
Capital expenditures, excluding AFUDC equity		(122.0	)		(15.9	)		-			(137.9	)
Consolidated subsidiary investments		-			-			-			-
Net change in notes receivable to other Vectren companies		-			(9.3	)		9.3			-
Net cash flows from investing activities		(122.0	)		13.2			(29.0	)		(137.8	)
Net decrease in cash & cash equivalents		(2.9	)		(22.3	)					(25.2	)
Cash & cash equivalents at beginning of period		5.7			22.8						28.5
Cash & cash equivalents at end of period	$	2.8		$	0.5		$	-		$	3.3

Condensed Consolidating Statement of Cash Flows for the six months ended June 30, 2006 (in millions):


	Subsidiary			Parent
	Guarantors			Company			Eliminations			Consolidated

NET CASH FLOWS FROM OPERATING ACTIVITIES	$	210.2		$	13.0		$	-		$	223.2

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from additional capital contribution		20.0			-			(20.0	)		-
Long-term Debt - net of issuance costs & hedging proceeds		150.0			-			(150.0	)		-
Requirements for:
Dividends to parent		(37.3	)		(37.3	)		37.3			(37.3	)
Net change in short-term borrowings		(264.6	)		(80.5	)		248.6			(96.5	)
Net cash flows from financing activities		(131.9	)		(117.8	)		115.9			(133.8	)

CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from consolidated subsidiary distributions		-			37.3			(37.3	)		-
Requirements for:
Capital expenditures, excluding AFUDC equity		(86.8	)		(9.7	)		-			(96.5	)
Consolidated subsidiary investments		-			(170.0	)		170.0			-
Net change in notes receivable to other Vectren companies		-			248.6			(248.6	)		-
Net cash flows from investing activities		(86.8	)		106.2			(115.9	)		(96.5	)
Net decrease in cash & cash equivalents		(8.5	)		1.4						(7.1	)
Cash & cash equivalents at beginning of period		11.0			0.7						11.7
Cash & cash equivalents at end of period	$	2.5		$	2.1		$	-		$	4.6

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Condensed Consolidating Balance Sheet as of June 30, 2007 (in millions):


ASSETS	Subsidiary		Parent
	Guarantors		Company		Eliminations			Consolidated
Current Assets
Cash & cash equivalents	$	2.8	$	0.5	$	-		$	3.3
Accounts receivable - less reserves		96.7		-		-			96.7
Receivables due from other Vectren companies		22.6		132.0		(154.2	)		0.4
Accrued unbilled revenues		38.1		-		-			38.1
Inventories		108.4		2.3		-			110.7
Recoverable fuel & natural gas costs		-		-		-			-
Prepayments & other current assets		80.6		11.7		(7.4	)		84.9
Total current assets		349.2		146.5		(161.6	)		334.1
Utility Plant
Original cost		3,925.5		-		-			3,925.5
Less: accumulated depreciation & amortization		1,475.8		-		-			1,475.8
Net utility plant		2,449.7		-		-			2,449.7
Investments in consolidated subsidiaries		-		1,146.5		(1,146.5	)		-
Notes receivable from consolidated subsidiaries		-		575.4		(575.4	)		-
Investments in unconsolidated affiliates		0.2		-		-			0.2
Other investments		16.0		5.9		-			21.9
Nonutility property - net		5.4		163.7		-			169.1
Goodwill		205.0		-		-			205.0
Regulatory assets		112.2		12.8		-			125.0
Other assets		16.9		0.6		-			17.5
TOTAL ASSETS	$	3,154.6	$	2,051.4	$	(1,883.5	)	$	3,322.5
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent
	Guarantors		Company		Eliminations			Consolidated
Current Liabilities
Accounts payable	$	54.6	$	5.0	$	-		$	59.6
Accounts payable to affiliated companies		43.7		-		-			43.7
Payables to other Vectren companies		34.0		-		(11.9	)		22.1
Refundable fuel & natural gas costs		40.4		-		-			40.4
Accrued liabilities		135.0		8.6		(7.4	)		136.2
Short-term borrowings		-		215.0		-			215.0
Short-term borrowings from
other Vectren companies		119.9		22.4		(142.3	)		-
Current maturities of long-term debt		6.5		-		-			6.5
Long-term debt subject to tender		20.0		-		-			20.0
Total current liabilities		454.1		251.0		(161.6	)		543.5
Long-Term Debt
Long-term debt - net of current maturities &
debt subject to tender		327.3		698.2		-			1,025.5
Long-term debt due to Utility Holdings		575.4		-		(575.4	)		-
Total long-term debt - net		902.7		698.2		(575.4	)		1,025.5
Deferred Income Taxes & Other Liabilities
Deferred income taxes		251.4		7.4		-			258.8
Regulatory liabilities		297.3		5.4		-			302.7
Deferred credits & other liabilities		102.6		13.4		-			116.0
Total deferred credits & other liabilities		651.3		26.2		-			677.5
Common Shareholder's Equity
Common stock (no par value)		776.3		632.9		(776.3	)		632.9
Retained earnings		369.7		442.6		(369.7	)		442.6
Accumulated other comprehensive income		0.5		0.5		(0.5	)		0.5
Total common shareholder's equity		1,146.5		1,076.0		(1,146.5	)		1,076.0
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,154.6	$	2,051.4	$	(1,883.5	)	$	3,322.5

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Condensed Consolidating Balance Sheet as of December 31, 2006 (in millions):


ASSETS	Subsidiary		Parent
	Guarantors		Company		Eliminations			Consolidated
Current Assets
Cash & cash equivalents	$	5.7	$	22.8	$	-		$	28.5
Accounts receivable - less reserves		134.8		-		-			134.8
Receivables due from other Vectren companies		6.1		146.0		(151.8	)		0.3
Accrued unbilled revenues		121.4		-		-			121.4
Inventories		139.6		2.3		-			141.9
Recoverable fuel & natural gas costs		1.8		-		-			1.8
Prepayments & other current assets		91.2		14.7		(2.7	)		103.2
Total current assets		500.6		185.8		(154.5	)		531.9
Utility Plant
Original cost		3,820.2		-		-			3,820.2
Less: accumulated depreciation & amortization		1,434.7		-		-			1,434.7
Net utility plant		2,385.5		-		-			2,385.5
Investments in consolidated subsidiaries		-		1,129.7		(1,129.7	)		-
Notes receivable from consolidated subsidiaries		-		575.3		(575.3	)		-
Investments in unconsolidated affiliates		0.2		-		-			0.2
Other investments		15.4		6.0		-			21.4
Nonutility property - net		5.2		157.9		-			163.1
Goodwill		205.0		-		-			205.0
Regulatory assets		103.3		13.5		-			116.8
Other assets		16.1		0.8		-			16.9
TOTAL ASSETS	$	3,231.3	$	2,069.0	$	(1,859.5	)	$	3,440.8
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent
	Guarantors		Company		Eliminations			Consolidated
Current Liabilities
Accounts payable	$	131.5	$	4.7	$	-		$	136.2
Accounts payable to affiliated companies		68.1		0.1		-			68.2
Payables to other Vectren companies		44.0		0.1		(18.8	)		25.3
Refundable fuel & natural gas costs		35.3		-		-			35.3
Accrued liabilities		107.3		11.2		(2.7	)		115.8
Short-term borrowings		-		270.1		-			270.1
Short-term borrowings from
other Vectren companies		133.0		-		(133.0	)		-
Current maturities of long-term debt		6.5		-		-			6.5
Long-term debt subject to tender		20.0		-		-			20.0
Total current liabilities		545.7		286.2		(154.5	)		677.4
Long-Term Debt
Long-term debt - net of current maturities &
debt subject to tender		327.3		698.0		-			1,025.3
Long-term debt due to Utility Holdings		575.3		-		(575.3	)		-
Total long-term debt - net		902.6		698.0		(575.3	)		1,025.3
Deferred Income Taxes & Other Liabilities
Deferred income taxes		265.9		16.3		-			282.2
Regulatory liabilities		285.0		6.1		-			291.1
Deferred credits & other liabilities		102.4		5.7		-			108.1
Total deferred credits & other liabilities		653.3		28.1		-			681.4
Common Shareholder's Equity
Common stock (no par value)		776.3		632.9		(776.3	)		632.9
Retained earnings		352.5		422.9		(352.5	)		422.9
Accumulated other comprehensive income		0.9		0.9		(0.9	)		0.9
Total common shareholder's equity		1,129.7		1,056.7		(1,129.7	)		1,056.7
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,231.3	$	2,069.0	$	(1,859.5	)	$	3,440.8

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4.	Excise and Utility Receipts Taxes

Excise taxes and a portion of utility receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes received as a component of operating revenues, which totaled $6.7 million and $6.0 million, respectively for the three months ended June 30, 2007 and 2006. For the six months ended June 30, 2007 and 2006, these taxes totaled $24.7 million and $23.2 million, respectively. Expenses associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.

5.	Comprehensive Income

Comprehensive income consists of the following:


	Three Months						Six Months
	Ended June 30,						Ended June 30,
(In millions)	2007			2006			2007			2006
Net income	$	8.0		$	7.1		$	58.9		$	50.5
Cash flow hedges
Unrealized losses		-			-			-			(3.7	)
Reclassifications to net income		(0.2	)		(0.4	)		(0.6	)		(1.4	)
Income tax benefit (expense)		0.1			0.1			0.2			2.1
Total comprehensive income	$	7.9		$	6.8		$	58.5		$	47.5

6.	Transactions with Other Vectren Companies

Support Services and Purchases

Vectren provides corporate and general and administrative services to the Company and allocates costs to the Company, including costs for share-based compensation and for pension and other postretirement benefits that are not directly charged to subsidiaries. These costs have been allocated using various allocators, including number of employees, number of customers and/or the level of payroll, revenue contribution and capital expenditures. Allocations are based on cost. Utility Holdings received corporate allocations totaling $21.8 million and $20.5 million for the three months ended June 30, 2007 and 2006, respectively. For the six months ended June 30, 2007 and 2006, Utility Holdings received corporate allocations totaling $42.3 million and $40.6 million, respectively.

Vectren Fuels, Inc.

Vectren Fuels, Inc., a wholly owned subsidiary of Vectren, owns and operates coal mines from which SIGECO purchases fuel used for electric generation. The Company has priced the coal consistent with letter agreements with the OUCC regarding the price of coal that is charged by Fuels to SIGECO. Amounts paid for such purchases for the three months ended June 30, 2007 and 2006, totaled $29.1 million and $31.2 million, respectively. For the six months ended June 30, 2007 and 2006, amounts paid for such purchases totaled $56.1 million and $62.5 million, respectively.

Miller Pipeline Corporation

Effective July 1, 2006, Vectren purchased the remaining 50% ownership in Miller Pipeline Corporation (Miller), making Miller a wholly owned subsidiary of Vectren. Prior to the transaction, Miller was 50% owned by Duke Energy Corporation. Miller performs natural gas and water distribution, transmission, and construction repair and rehabilitation primarily in the Midwest and the repair and rehabilitation of gas, water, and wastewater facilities nationwide. Miller’s customers include Utility Holdings’ utilities. Amounts paid by Utility Holdings to Miller for purchases of utility plant and other services for the three months ended June 30, 2007 and 2006, totaled $7.9 million and $5.2 million, respectively. Amounts paid for the six months ended June 30, 2007 and 2006, totaled $11.5 million and $9.1 million, respectively.

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7.	Transactions with ProLiance Energy, LLC

ProLiance Energy, LLC (ProLiance), a nonutility 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 Indiana utilities and nonutility gas supply operations as well as Citizens Gas. ProLiance’s primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services.

Purchases from ProLiance for resale and for injections into storage for the three months ended June 30, 2007 and 2006, totaled $137.8 million and $117.3 million, respectively and for the six months ended June 30, 2007 and 2006, totaled $341.3 million and $344.0 million, respectively. Amounts owed to ProLiance at June 30, 2007 and December 31, 2006, for those purchases were $43.7 million and $68.2 million, respectively, and are included in Accounts payable to affiliated companies in the Consolidated Balance Sheets. The Company purchased approximately 71 percent of its gas through ProLiance in 2007 and approximately 75 percent in 2006. Amounts charged by ProLiance for gas supply services are established by supply agreements with each utility which have been approved by the IURC through 2011.

8.	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 or cash flows.

9.	Environmental Matters

Clean Air/Climate Change

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 February 2006, the IURC approved a multi-emission compliance plan filed by the Company’s utility subsidiary, SIGECO. Once the plan is implemented, 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. The order, as previously agreed to by the OUCC and Citizens Action Coalition, allows SIGECO to recover an approximate 8% return on up to $110 million in capital investments through a rider mechanism which is updated every six months for actual costs incurred. The Company will also recover through a rider its operating expenses, including depreciation, once the equipment is placed into service. As of June 30, 2007, the Company has made capital investments of approximately $75 million related to this environmental requirement, of which $49.4 million was placed into service on January 1, 2007, and was included in rate base in the aforementioned rate case settlement. The Company may file periodic updates with the IURC requesting modification to the spending authority.

If legislation requiring reductions in carbon dioxide and other greenhouse gases is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel plants and other operations. At this time and in absence of final legislation, compliance costs and other effects associated with reductions in greenhouse gas emissions remain uncertain.

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Pursuant to an IURC order, SIGECO is studying renewable energy alternatives, and on April 9, 2007, filed a green power rider seeking authority to buy 30 MW of wind energy. Future filings with the IURC with regard to new generation and/or further environmental compliance plans will include evaluation of potential carbon requirements.

Environmental Remediation Efforts

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, those that operated these facilities may now be required to take remedial action if certain contaminants are found above the regulatory thresholds at these sites.

Indiana Gas 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 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.

Indiana Gas 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’ 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 under insurance policies in effect when these plants were in operation in an aggregate amount approximating $20.4 million.

In October 2002, SIGECO received a formal information request letter from the IDEM regarding five manufactured gas plants that it owned and/or operated and were not enrolled in the IDEM’s VRP. In October 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 in February 2004. SIGECO is also named in a lawsuit filed in federal district court in May 2007, involving another site subject to potential environmental remediation efforts.

SIGECO has 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 and/or related to the aforementioned site subject to the lawsuit. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, SIGECO has recorded costs that it reasonably expects to incur totaling approximately $7.7 million. With respect to insurance coverage, SIGECO has received and recorded settlements from insurance carriers under insurance policies in effect when these sites were in operation in an aggregate amount approximating the costs it expects to incur.

Environmental remediation costs related to Indiana Gas’ and SIGECO’s manufactured gas plants and other sites have had no material impact on results of operations or financial condition since costs recorded to date approximate PRP and insurance settlement recoveries. While the Company’s utilities have recorded all costs which they presently expect 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 and those costs may not be subject to PRP or insurance recovery.

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10.

Rate & Regulatory Matters

Vectren North (Indiana Gas Company, Inc.) Gas Base Rate Filing

In May 2007, the Company filed a petition with the IURC to adjust its gas base rates and charges in its North service territory. The petition requests an increase of approximately $41 million in rates to recover the ongoing cost of operating, maintaining and expanding the approximately 12,000-mile distribution and storage system used to serve more than 565,000 natural gas customers. Components of the increase include return on additional utility infrastructure investment, costs associated with federally mandated pipeline integrity, inspection and other reliability programs, and aging workforce. A hearing on the Company’s request before the IURC is scheduled for late August 2007.

Vectren South (SIGECO) Gas Base Rate Order Received

On August 1, 2007, the Company received an order from the IURC which approved, with a minor modification, the settlement agreement previously reached with the Indiana Office of the Utility Consumer Counselor (OUCC) and other interveners regarding its Vectren South gas rate case. The order provided for a base rate increase of $5.1 million and an allowed return on equity (ROE) of 10.15 percent, with an overall rate of return of 7.20 percent on rate base of $121.7 million. The order also includes removal of $2.6 million of costs from base rates to be recovered through existing tracking mechanisms.

Further, additional expenditures for a multi-year bare steel and cast iron capital replacement program will be afforded certain accounting treatment that mitigates earnings attrition from the investment between rate cases. The accounting treatment allows for the continuation of the accrual for allowance for funds used during construction (AFUDC) and the deferral of depreciation expense after the projects go in service but before they are included in base rates. To qualify for this treatment, the annual expenditures are limited to $3.0 million and the treatment cannot extend beyond three years on each project.

With this order, the company now has in place for its South gas territory weather normalization, a conservation and decoupling tariff, tracking of gas cost expense related to bad debts and unaccounted for gas through the existing gas cost adjustment mechanism, and tracking of pipeline integrity expense. The allowed ROE of 10.15 percent recognizes these various regulatory mechanisms.

Vectren South (SIGECO) Electric Base Rate Settlement

On April 20, 2007, the Company announced it had reached a settlement agreement with the OUCC and other interveners regarding the proposed changes to the base rates and charges for its electric distribution business in southwestern Indiana. The settlement agreement provides for an approximate $60.8 million electric rate increase to cover the Company’s cost of system growth, maintenance, safety and reliability. The settlement provides for, among other things: timely recovery of certain new electric transmission investments made, ongoing costs, and deferred costs associated with the Midwest Independent System Operator (MISO); operations and maintenance (O&M) expense increases related to managing the aging workforce, including the development of expanded apprenticeship programs and the creation of defined training programs to ensure proper knowledge transfer, safety and system stability; increased O&M expense necessary to maintain and improve system reliability; customer benefit from the sale of wholesale power by the Company sharing evenly with customers any profit earned above or below $10.5 million of wholesale power margin; recovery of and return on the investment in demand side management programs to help encourage conservation during peak load periods; and an overall rate of return of 7.32 percent and an ROE of 10.4 percent.

A hearing before the IURC was held on May 3, 2007, with the final briefing filed on May 18, 2007 and the Company is expecting an order in the late summer.

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Ohio and Indiana Lost Margin Recovery/Conservation Filings

In 2005, the Company filed conservation programs and conservation adjustment trackers in Indiana and Ohio designed to help customers conserve energy and reduce their annual gas bills. The programs allow the Company to recover costs of promoting the conservation of natural gas through conservation trackers that work in tandem with a lost margin recovery mechanism. These mechanisms are designed to allow the Company to recover the distribution portion of its rates from residential and commercial customers based on the level of customer revenues established in each utility’s last general rate case.

Indiana

In December 2006, the IURC approved a settlement agreement that provides for a five-year energy efficiency program. It allows the Company’s Indiana utilities to recover a majority of the costs of promoting the conservation of natural gas through conservation trackers that work in tandem with a lost margin recovery mechanism. The order was implemented in the North service territory in December 2006, and provides for recovery of 85 percent of the difference between weather-normalized revenues actually collected by the company and the revenues approved in the company’s recent rate case. Energy efficiency programs began in the South gas territory in December 2006, and lost margin recovery commenced in the South gas territory when new base rates were approved, allowing for recovery of 100 percent of the difference between weather normalized revenues actually collected by the Company and the revenues approved in that rate case. While most expenses associated with these programs are recoverable, in the first program year the Company is required to fund $1.5 million in program costs without recovery.

Ohio

In June 2007, the Public Utilities Commission of Ohio (PUCO) approved a settlement that provides for the implementation of a lost margin recovery mechanism and a related conservation program for the company’s Ohio operations. This order confirms the guidance the PUCO previously provided in a September 2006 decision. The conservation program, as outlined in the September 2006 PUCO order and as affirmed in this order, provides for a two year, $2 million total conservation program to be paid by the company, as well as a sales reconciliation rider intended to be a recovery mechanism for the difference between the weather normalized revenues actually collected by the company and the revenues approved by the PUCO in the company’s most recent rate case. Approximately 60 percent of the company’s Ohio customers are eligible for the conservation programs. The Ohio Consumer Counselor (OCC) and another intervener have requested a rehearing of the June 2007 order. In accordance with accounting authorization previously provided by the PUCO, the company began recognizing the impact of the September 2006 order on October 1, 2006, and has recognized cumulative revenues of $2.5 million, of which $1.2 million has been recorded in 2007. The OCC has appealed the PUCO’s accounting authorization and the case is currently pending before the Ohio Supreme Court. Since October 1, 2006, the Company has been ratably accruing its $2 million commitment.

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, which was filed in 2006.

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. The Company is typically in a net sales position with MISO and is only occasionally in a net purchase position. Net positions are determined on an hourly basis. When the Company is a net seller such net revenues are included in Electric Utility Revenues and when the Company is a net purchaser such net purchases are included in Cost of Fuel and Purchased Power.

On June 1, 2005, the Company, 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 the Company’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, which was filed in 2006. During 2006, the IURC reaffirmed the definition of certain costs as fuel related; the Company is following those guidelines.

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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.

If the aforementioned electric rate case settlement is approved, the Company will timely recover its investment in certain new electric transmission investments, ongoing costs, and deferred costs.

Ohio Gas Cost Recovery (GCR) Audit Proceedings

In 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 October 2002 and in 2006, an additional $0.8 million was disallowed related to the audit period ending October 2005. The initial audit period provided the PUCO staff its initial review of the portfolio administration arrangement between VEDO and ProLiance. Since November 1, 2005, the Company has used a provider other than ProLiance for these services.

Through a series of rehearings and appeals, including action by the Ohio Supreme Court in the first quarter of 2007, the Company was required to refund $8.6 million to customers. The Company had previously recorded the impact of the PUCO findings, including its estimate of the share of the ultimate disallowance to be received from its partner in ProLiance. The Company does not believe that Court decisions in the first quarter of 2007 will have any material future impact on the Company’s financial results.

Integrated Gasification Combined Cycle Project Involvement

In August 2007, the Company announced that it has determined to not participate in the proposed Edwardsport, Indiana, Integrated Gasification Combined Cycle (IGCC) generating plant with Duke Energy Indiana, Inc. (Duke). Based upon a review and analysis of the Company’s expected electric generation requirements, the expected demand for energy on the system may be more appropriately satisfied through the use of other alternatives, including additional natural gas peaking generation, purchased power, renewable resources and increased customer conservation. The Company has paid Duke approximately $3.0 million for engineering studies and related costs. By separate agreement with Duke, the Company expects to be reimbursed for all costs and expenses it has paid to Duke.

11.

Adoption of FIN 48

Utility Holdings does not file federal or state income tax returns separate from those filed by its parent, Vectren Corporation. Vectren and/or certain of its subsidiaries file income tax returns in the U.S. federal jurisdiction and various states. The Internal Revenue Service (IRS) has conducted its examination of Vectren’s U.S. federal income tax returns for tax years through December 31, 2004. The State of Indiana, Vectren’s primary state tax jurisdiction, has conducted examinations of state income tax returns for tax years through December 31, 2002. No examinations are currently ongoing.

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On January 1, 2007, the Company adopted FASB Interpretation No. 48 (FIN 48) “Accounting for Uncertainty in Income Taxes” an interpretation of SFAS 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of tax positions taken or expected to be taken in an income tax return. FIN 48 also provides guidance related to reversal of tax positions, balance sheet classification, interest and penalties, interim period accounting, disclosure and transition.

As a result of the implementation of FIN 48, the Company recognized an approximate $0.9 million increase in the liability for unrecognized tax benefits, which was accounted for as a reduction to the January 1, 2007 balance of Retained earnings. At adoption, the total amount of gross unrecognized tax benefits for uncertain tax positions, including positions impacting only the timing of tax benefits, was $7.0 million. During the six months ended June 30, 2007, this obligation did not change.

The amount of unrecognized tax benefits, which, if recognized, would impact the effective tax rate as of June 30, 2007, was $0.8 million. The remaining unrecognized tax benefit relates to tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.

From time to time, the Company may consider changes to filed positions that could decrease the liability for uncertain tax positions. However, it is not expected that such changes would have a significant impact on earnings and would only affect the timing of payments to taxing authorities.

The Company accrues interest and penalties associated with unrecognized tax benefits in Income taxes. The Company had approximately $0.2 million for the payment of interest and penalties accrued as of June 30, 2007.

12.

Segment Reporting

The Company segregates its operations into three groups: 1) Utility Group, 2) Nonutility Group, and 3) Corporate and Other.

The Company’s operations consist of the Company’s regulated operations and other operations that provide information technology and other support services to those regulated operations. The Company segregates its regulated operations into a Gas Utility Services operating segment and an Electric Utility Services operating segment. The Gas Utility Services segment provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio. The Electric Utility Services segment provides electric distribution services primarily to southwestern Indiana, and includes the Company’s power generating and marketing operations. The Company 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 wholesale marketing operations. In total, regulated operations supply natural gas and /or electricity to over one million customers. In total, the Company has three operating segments as defined by SFAS 131 “Disclosure About Segments of an Enterprise and Related Information” (SFAS 131). Net income is the measure of profitability used by management for all operations. Information related to the Company’s business segments is summarized below:


	Three Months						Six Months
	Ended June 30,						Ended June 30,
(In millions)	2007			2006			2007			2006
Revenues
Gas Utility Services	$	191.9		$	159.1		$	776.0		$	731.8
Electric Utility Services		109.9			96.0			218.0			201.2
Other Operations		10.5			9.2			20.2			18.4
Eliminations		(10.0	)		(8.7	)		(19.3	)		(17.5	)
Consolidated Revenues	$	302.3		$	255.6		$	994.9		$	933.9

Profitability Measure - Net Income
Gas Utility Services	$	(3.4	)	$	(3.1	)	$	34.5		$	29.0
Electric Utility Services		10.3			9.3			21.0			19.4
Other Operations		1.1			0.9			3.4			2.1
Total Net Income	$	8.0		$	7.1		$	58.9		$	50.5

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13.

Impact of Recently Issued Accounting Guidance

SFAS 159

In February 2007, the FASB issued Statement No. 159, The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115 (SFAS 159). SFAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value. Items eligible for the fair value measurement option include: financial assets and financial liabilities with certain exceptions; firm commitments that would otherwise not be recognized at inception and that involve only financial instruments; nonfinancial insurance contracts and warranties that the insurer can settle by paying a third party to provide those goods or services; and host financial instruments resulting from separation of embedded financial derivative instrument from a nonfinancial hybrid instrument. The fair value option may be applied instrument by instrument, with few exceptions, is irrevocable and is applied only to entire instruments. SFAS 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. Early adoption is permitted as of the beginning of a fiscal year that begins on or before November 15, 2007, provided the entity also elects to apply the provisions of FASB Statement no. 157, “Fair Value Measurements”, and with certain other requirements. SFAS 159 permits application to eligible items existing at the effective date. The Company is currently assessing the impact this statement will have on its financial statements and results of operations.

SFAS No. 157

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS 157). SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. This statement does not require any new fair value measurements; however, the standard will impact how other fair value based GAAP is applied. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years with early adoption encouraged. The Company is currently assessing the impact this statement will have on its financial statements and results of operations.

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

Description of the Business

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’ 2007 earnings for the quarter ended June 30, 2007 were $8.0 million compared to $7.1 million in 2006 and $58.9 million for the six months ended June 30, 2007 compared to $50.5 million in 2006. The increases in earnings resulted from increased residential and commercial usage, including lost margin recovery and favorable weather in the Ohio and electric territories. The increase was offset somewhat by higher operating costs, including depreciation expense.

In the Company’s electric and Ohio natural gas service territories that are not protected by weather normalization mechanisms, management estimates the margin impact of weather experienced during the second quarter of 2007 to be $1.4 million favorable compared to normal and $3.0 million favorable compared to the prior year. Year to date, management estimates the margin impact of weather experienced during 2007 to be $0.6 million favorable compared to normal and $6.6 million favorable compared to the prior year.

Utility Holdings generates revenue primarily from the delivery of natural gas and electric service to its customers. The 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. Results are impacted by weather patterns in its service territory and general economic conditions both in its Indiana and Ohio 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.

Significant Fluctuations

Throughout this discussion, the terms Gas Utility margin and Electric Utility margin are used. Gas Utility margin is calculated as Gas utility revenues less the Cost of gas. Electric Utility margin is calculated as Electric utility revenues less Cost of fuel & purchased power. 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.

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Sales of natural gas and electricity to residential and commercial customers are seasonal and are impacted by weather. Trends in average use among natural gas residential and commercial customers have tended to decline in recent years as more efficient appliances and furnaces are installed and the price of natural gas has increased. Normal temperature adjustment (NTA) and lost margin recovery mechanisms largely mitigate the effect on Gas Utility margin that would otherwise be caused by variations in volumes sold due to weather and changing consumption patterns. Indiana Gas’ territory has both an NTA since 2005 and lost margin recovery since December 2006. SIGECO’s natural gas territory has an NTA since 2005, and lost margin recovery began when new base rates went into effect August 1, 2007. The Ohio service territory has lost margin recovery since October 2006, but does not have weather normalization. Electric use among residential and commercial classes has remained relatively stable. SIGECO’s electric service territory does not have weather normalization and its tariffs generally do not provide for lost margin recovery.

Gas and electric margin generated from sales to large customers (generally industrial and other contract customers) is primarily impacted by overall economic conditions. Margin is also impacted by the collection of state mandated taxes, which fluctuate with gas and fuel costs, as well as other tracked expenses. Expenses subject to tracking mechanisms include Ohio bad debts and percent of income payment plan expenses, Indiana gas pipeline integrity management costs, costs to fund Indiana energy efficiency programs, and costs associated with operating environmental compliance equipment. 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)	2007		2006		2007		2006
Gas utility revenues	$	191.9	$	159.1	$	776.0	$	731.8
Cost of gas sold		114.6		88.5		539.1		517.5
Total gas utility margin	$	77.3	$	70.6	$	236.9	$	214.3
Margin attributed to:
Residential & commercial customers	$	63.6	$	57.0	$	203.9	$	181.7
Industrial customers		10.0		9.8		25.7		24.7
Other		3.7		3.8		7.3		7.9
Sold & transported volumes in MMDth attributed to:
Residential & commercial customers		13.9		11.4		68.7		56.7
Industrial customers		18.1		18.0		44.5		43.5
Total sold & transported volumes		32.0		29.4		113.2		100.2

For the three and six months ended June 30, 2007, gas utility margins were $77.3 million and $236.9 million, respectively, an increase of $6.7 million quarter over quarter and $22.6 million year over year. Residential and commercial customer usage, including lost margin recovery, increased margin $4.7 million during the quarter and $11.9 million year over year. Year to date, Ohio weather was 3 percent warmer than normal, but 11 percent colder than the prior year and resulted in an estimated increase in margin of approximately $2.4 million compared to 2006. Lastly, costs recovered dollar-for-dollar in margin associated with tracked expenses and revenue and usage taxes increased gas margin $2.0 million in the quarter and $7.9 million year over year. The average cost per dekatherm of gas purchased for the six months ended June 30, 2007, was $8.50 compared to $9.35 in 2006.

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Electric Utility Margin (Electric Utility revenues less Cost of fuel & purchased power)

Electric Utility margin by customer type follows:


	Three Months				Six Months
	Ended June 30,				Ended June 30,
(In millions)	2007		2006		2007		2006
Electric utility revenues	$	109.9	$	96.0	$	218.0	$	201.2
Cost of fuel & purchased power		38.4		30.9		79.0		69.0
Total electric utility margin	$	71.5	$	65.1	$	139.0	$	132.2
Margin attributed to:
Residential & commercial customers	$	43.6	$	38.4	$	83.4	$	76.3
Industrial customers		18.3		17.9		34.8		34.5
Municipal & other customers		5.2		6.8		10.3		12.3
Subtotal: retail & firm wholesale	$	67.1	$	63.1	$	128.5	$	123.1
Asset optimization	$	4.4	$	2.0	$	10.5	$	9.1

Electric volumes sold in GWh attributed to:
Residential & commercial customers		705.4		648.4		1,403.3		1,305.4
Industrial customers		676.7		671.3		1,303.7		1,309.2
Municipal & other		156.3		161.3		291.4		311.8
Total retail & firm wholesale volumes sold		1,538.4		1,481.0		2,998.4		2,926.4

Retail & Firm Wholesale Margin

Electric retail and firm wholesale utility margins were $67.1 million and $128.5 million for the three and six months ended June 30, 2007. These represent increases over the prior year periods of $4.0 million and $5.4 million, respectively. Management estimates the period over period increases in usage by residential and commercial customers due to weather to be $3.0 million in the quarter and $4.2 million year to date. Return on pollution control investments increased margin $0.9 million in the quarter and $1.2 million year over year.

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 and sells this unutilized generating and transmission capacity to optimize the return on its owned assets. On an annual basis, a majority of the margin generated from these activities is associated with wholesale off-system sales, and substantially all off-system sales occur into the MISO day-ahead market.

Following is a reconciliation of asset optimization activity:


	Three Months					Six Months
	Ended June 30,					Ended June 30,
(In millions)	2007		2006			2007		2006
Off-system sales	$	3.5	$	3.0		$	8.8	$	10.7
Transmission system sales		0.9		0.6			1.7		1.5
Other		-		(1.6	)		-		(3.1	)
Total asset optimization	$	4.4	$	2.0		$	10.5	$	9.1

For the three and six months ended June 30, 2007, net asset optimization margins were $4.4 million and $10.5 million, which represents increases of $2.4 million and $1.4 million, compared to 2006. The increases are primarily due to losses on financial contracts experienced in 2006 offset partially by lower availability of generating units for off system sales in 2007, due largely to the retirement of 50 MW of owned generation on December 31, 2006. Year to date off-system sales totaled 447.6 GWh in 2007, compared to 648.3 GWh in 2006.

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Other Operating Expenses

For the three and six months ended June 30, 2007, Other operating expenses were $65.6 million and $132.8 million, which represent increases of $6.0 million and $11.6 million, compared to 2006. Pass-through costs, including costs funding new Indiana energy efficiency programs that are recovered in utility margin, increased $1.6 million in the quarter and $6.4 million year over year. Increases in operating costs associated with lost margin recovery and conservation initiatives that are not directly recovered in margin were $0.5 million in the quarter and $1.1 million year over year. The remaining increases are primarily due to increased wage and benefit costs, and other operating cost increases, and the timing of expenses.

Depreciation & Amortization

Depreciation & amortization expense was $39.8 million and $79.0 million, respectively, for the three and six months ended June 30, 2007, an increase of $2.1 million and $4.2 million compared to the prior year periods. The increases were primarily due to increased utility plant.

Taxes Other Than Income Taxes

Taxes other than income taxes were $14.1 million and $38.3 million, respectively, for the three and six months ended June 30, 2007, an increase of $2.5 million and $3.9 million compared to the prior year periods. The increase results from increased property taxes and higher revenues subject to taxes.

Other Income-Net

Other-net reflects income of $2.2 million for the quarter and $4.9 million year to date, increases of $0.3 million and $2.1 million compared to prior year periods. The increase is attributable to an increase in capitalized interest on utility plant.

Interest Expense

For the three and six months ended June 30, 2007, Interest expense was $18.6 million and $38.0 million, respectively, which represents an increase in the quarter of $0.4 million and a year to date decrease of $0.2 million compared to 2006. The changes reflect higher interest rates associated with short-term borrowings in the second quarter of 2007 and are partially offset by the impact of financing transactions completed in October 2006, in which approximately $93 million in debt related proceeds were raised and used to retire debt outstanding with a higher interest rate.

Income Taxes

Federal and state income taxes were $5.4 million for the quarter and $34.7 million year to date, increases of $1.5 million and $3.6 million compared to the prior year periods. Year to date, the increase in income taxes is due to higher pretax income offset somewhat by a lower effective tax rate.

Environmental Matters

Clean Air/Climate Change

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.

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In February 2006, the IURC approved a multi-emission compliance plan filed by the Company’s utility subsidiary, SIGECO. Once the plan is implemented, 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. The order, as previously agreed to by the OUCC and Citizens Action Coalition, allows SIGECO to recover an approximate 8% return on up to $110 million in capital investments through a rider mechanism which is updated every six months for actual costs incurred. The Company will also recover through a rider its operating expenses, including depreciation, once the equipment is placed into service. As of June 30, 2007, the Company has made capital investments of approximately $75 million related to this environmental requirement, of which $49.4 million was placed into service on January 1, 2007, and was included in rate base in the aforementioned rate case settlement. The Company may file periodic updates with the IURC requesting modification to the spending authority.

Environmental Remediation Efforts

In October 2002, SIGECO received a formal information request letter from the IDEM regarding five manufactured gas plants that it owned and/or operated and were not enrolled in the IDEM’s VRP. In October 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 in February 2004. SIGECO is also named in lawsuit filed in federal district court in May 2007, involving another site subject to potential environmental remediation efforts.

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Rate and Regulatory Matters

Vectren North (Indiana Gas Company, Inc.) Gas Base Rate Filing

Vectren South (SIGECO) Gas Base Rate Order Received

Vectren South (SIGECO) Electric Base Rate Settlement

On April 20, 2007, the Company announced it had reached a settlement agreement with the OUCC and other interveners regarding the proposed changes to the base rates and charges for its electric distribution business in southwestern Indiana. The settlement agreement provides for an approximate $60.8 million electric rate increase to cover the Company’s cost of system growth, maintenance, safety and reliability. The settlement provides for, among other things: timely recovery of certain electric transmission investments made, ongoing costs, and deferred costs associated with the Midwest Independent System Operator (MISO); operations and maintenance (O&M) expense increases related to managing the aging workforce, including the development of expanded apprenticeship programs and the creation of defined training programs to ensure proper knowledge transfer, safety and system stability; increased O&M expense necessary to maintain and improve system reliability; customer benefit from the sale of wholesale power by the Company sharing evenly with customers any profit earned above or below $10.5 million of wholesale power margin; recovery of and return on the investment in demand side management programs to help encourage conservation during peak load periods; and an overall rate of return of 7.32 percent and an ROE of 10.4 percent.

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A hearing before the IURC was held on May 3, 2007, with the final briefing filed on May 18, 2007 and the Company is expecting an order in the late summer.

Ohio and Indiana Lost Margin Recovery/Conservation Filings

Indiana

Ohio

MISO

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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. The Company is typically in a net sales position with MISO and is only occasionally in a net purchase position. Net positions are determined on an hourly basis. When the Company is a net seller such net revenues are included in Electric Utility Revenues and when the Company is a net purchaser such net purchases are included in Cost of Fuel and Purchased Power.

On June 1, 2005, the Company, 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 the Company’s’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, which was filed in 2006. During 2006, the IURC reaffirmed the definition of certain costs as fuel related; the Company is following those guidelines.

If the aforementioned electric rate case settlement is approved, the Company will timely recover its investment in certain new electric transmission investments, ongoing costs, and deferred costs.

Gas Cost Recovery (GCR) Audit Proceedings

Integrated Gasification Combined Cycle Project Involvement

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Impact of Recently Issued Accounting Guidance

FIN 48

On January 1, 2007, the Company adopted FASB Interpretation No. 48 (FIN 48) “Accounting for Uncertainty in Income Taxes” an interpretation of SFAS 109, Accounting for Income Taxes. FIN 48 prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of tax positions taken or expected to be taken in an income tax return. FIN 48 also provides guidance related to reversal of tax positions, balance sheet classification, interest and penalties, interim period accounting, disclosure and transition.

At adoption, the total amount of gross unrecognized tax benefits for uncertain tax positions, including positions impacting only the timing of tax benefits was $7.0 million. The accumulation of this amount resulted in an adjustment to beginning Retained earnings of $0.9 million.

SFAS 159

SFAS No. 157

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, 2007, totaled $700 million and $215 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.

The credit ratings of the senior unsecured debt of Utility Holdings, SIGECO and Indiana Gas, at June 30, 2007, are A-/Baa1 as rated by Standard and Poor's Ratings Services (Standard and Poor’s) and Moody’s Investors Service (Moody’s), respectively. The credit ratings on SIGECO's 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. These ratings and outlooks have not changed since December 31, 2006. 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.

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The Company’s consolidated equity capitalization objective is 45-55% of long-term capitalization. This objective may have varied, and will vary, depending on particular business opportunities, capital spending requirements, execution of long-term financing plans and seasonal factors that affect the Company’s operations. The Company’s equity component was 51% and 50% of long-term capitalization at June 30, 2007, and December 31, 2006, respectively. Long-term capitalization includes long-term debt, including current maturities and debt subject to tender, as well as common shareholder’s equity.

Utility Holdings expects the majority of its capital expenditures, investments, and debt security redemptions to be provided by internally generated funds. However, due to significant capital expenditures, the Company may require additional permanent financing.

Sources & Uses of Liquidity

Operating Cash Flow

The Company's primary historical source of liquidity to fund working capital requirements has been cash generated from operations. Cash flow from operating activities of $206.0 million decreased $17.2 million during the six months ended June 30, 2007, compared to 2006 primarily as a result of changes in working capital accounts. Working capital changes generated cash of $73.5 million in 2007 compared to $97.9 million in 2006. Net income before non-cash charges of $147.8 million increased $12.3 million compared to the prior year.

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 financed on a long-term basis.

Cash flow required for financing activities of $93.4 million for the six months ended June 30, 2007, includes a net decrease of short-term borrowings of $55.1 million, $41.4 million less than amounts repaid during the six months ended June 30, 2006. This decrease resulted primarily from increased capital expenditures. Dividends paid increased $1.0 million year over year.

Investing Cash Flow

Cash flow required for investing activities was $137.8 million for the six months ended June 30, 2007, an increase of $41.3 million over the prior year. The increase is attributable to the higher expenditures for environmental compliance.

Available Sources of Liquidity

Short-term Borrowing Arrangements

At June 30, 2007, the Company has $520 million of short-term borrowing capacity, of which approximately $305 million is available.

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Potential Capital Contributions from Vectren

Equity Forward

As of June 30, 2007, Vectren Corporation has access to approximately $126 million in proceeds generated from an SEC-registered equity offering of its common stock. Vectren executed an equity forward sale agreement (equity forward) in connection with the offering, and therefore, did not receive proceeds at the time of the equity offering. The equity forward allowed Vectren to price the offering under market conditions existing at that time, and to better match the receipt of the offering proceeds with the implementation of new electric service territory base rates which provide a return on the new equity employed. The offering proceeds, when and if received, will likely be contributed to Utility Holdings and used to permanently finance its subsidiaries’ primarily electric utility capital expenditures. The equity forward must be settled prior to February 28, 2009.

Proceeds from Stock Plans

Vectren may periodically issue new common shares to satisfy dividend reinvestment plan, stock option plan, and other employee benefit plan requirements and contribute those proceeds to Utility Holdings.

Potential Uses of Liquidity

Planned Capital Expenditures

Capital expenditures for the remainder of 2007 are estimated to be approximately $170 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, regulatory or 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 the Company’s business, financial condition, liquidity and results of operations resulting from changes 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, aging workforce issues, or work stoppages.

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

·	Costs, fines, penalties and other effects of legal and administrative proceedings, settlements, investigations, claims, including, but not limited to, such matters involving inadvertent violations of state and federal laws.

·	Changes in federal, state or local legislative requirements, such as changes in tax laws or rates, environmental laws, including laws governing greenhouse gases, and other 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. 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 Utility Holdings 2006 Form 10-K and is therefore not presented herein.

ITEM 4. CONTROLS AND PROCEDURES

Changes in Internal Controls Over Financial Reporting

During the quarter ended June 30, 2007, 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 June 30, 2007, 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 as of June 30, 2007, to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is:

1) recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and

2) accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer,

as appropriate to allow timely decisions regarding required disclosure.

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. See the notes to the consolidated condensed financial statements regarding commitments and contingencies, environmental matters, and rate and regulatory matters. The consolidated condensed financial statements are included in Part 1 Item 1.

ITEM 1A. RISK FACTORS

The Company’s risk factors have not changed from the information set forth in Item 1A Risk Factors included in the Utility Holdings 2006 Form 10-K and are therefore not presented herein.

ITEM 6. EXHIBITS

Exhibits and Certifications

Exhibits

12. Ratio of Earnings to Fixed Charges

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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

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, 2007		/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 & Assistant Treasurer
			(Principal Accounting Officer)