Edgar Filing: VECTREN UTILITY HOLDINGS INC

vuhi_10q.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 September 30, 2008

[_]	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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer □ Accelerated filer □

Non-accelerated filer ý (Do not check if a smaller reporting company) Smaller reporting company □

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	October 31, 2008
Class	Number of Shares	Date

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

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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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	23
3	Quantitative and Qualitative Disclosures about Market Risk	38
4	Controls and Procedures	38

	PART II. OTHER INFORMATION
1	Legal Proceedings	38
1A	Risk Factors	39
6	Exhibits	39
	Signatures	40

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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)


	September 30,		December 31,
	2008		2007

ASSETS
Current Assets
Cash & cash equivalents	$	8.0	$	11.7
Accounts receivable - less reserves of $4.2 &
$2.7, respectively		86.4		137.1
Receivables due from other Vectren companies		0.3		17.9
Accrued unbilled revenues		35.0		140.6
Inventories		203.7		134.9
Recoverable fuel & natural gas costs		28.7		-
Prepayments & other current assets		133.6		93.3
Total current assets		495.7		535.5

Utility Plant
Original cost		4,226.4		4,062.9
Less: accumulated depreciation & amortization		1,590.6		1,523.2
Net utility plant		2,635.8		2,539.7

Investments in unconsolidated affiliates		0.2		0.2
Other investments		23.6		24.7
Nonutility property - net		180.6		176.2
Goodwill		205.0		205.0
Regulatory assets		141.5		151.7
Other assets		9.3		10.7
TOTAL ASSETS	$	3,691.7	$	3,643.7

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)


	September 30,		December 31,
	2008		2007

LIABILITIES & SHAREHOLDER'S EQUITY

Current Liabilities
Accounts payable	$	132.3	$	138.7
Accounts payable to affiliated companies		48.1		66.9
Payables to other Vectren companies		64.0		34.2
Refundable fuel & natural gas costs		6.9		27.2
Accrued liabilities		211.3		138.9
Short-term borrowings		113.2		385.9
Long-term debt subject to tender		80.0		-
Total current liabilities		655.8		791.8
Long-Term Debt - Net of Current Maturities &
Debt Subject to Tender		1,065.6		1,062.6
Deferred Income Taxes & Other Liabilities
Deferred income taxes		323.2		286.9
Regulatory liabilities		313.0		307.2
Deferred credits & other liabilities		101.1		104.8
Total deferred credits & other liabilities		737.3		698.9
Commitments & Contingencies (Notes 10 - 12)
Common Shareholder's Equity
Common stock (no par value)		763.0		638.2
Retained earnings		469.9		451.9
Accumulated other comprehensive income		0.1		0.3
Total common shareholder's equity		1,233.0		1,090.4

TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,691.7	$	3,643.7

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		Nine Months
			Ended September 30,		Ended September 30,
			2008	2007	2008	2007
OPERATING REVENUES
	Gas utility		$ 143.9	$ 114.0	$ 1,002.4	$ 890.0
	Electric utility		147.9	143.6	402.3	361.6
	Other		0.6	0.4	1.8	1.3
		Total operating revenues	292.4	258.0	1,406.5	1,252.9

OPERATING EXPENSES
	Cost of gas		80.2	52.9	686.0	592.0
	Cost of fuel & purchased power		48.7	50.5	143.2	129.5
	Other operating		69.2	65.6	217.7	198.4
	Depreciation & amortization		41.6	40.4	123.2	119.4
	Taxes other than income taxes		11.7	11.3	51.8	49.6
		Total operating expenses	251.4	220.7	1,221.9	1,088.9

OPERATING INCOME			41.0	37.3	184.6	164.0

OTHER INCOME - NET			0.7	1.3	4.9	6.2
INTEREST EXPENSE			19.6	20.8	59.5	58.8

INCOME BEFORE INCOME TAXES			22.1	17.8	130.0	111.4

INCOME TAXES			8.5	7.1	49.6	41.8

NET INCOME			$ 13.6	$ 10.7	$ 80.4	$ 69.6

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

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VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited – In millions)


					Nine Months Ended September 30,
					2008	2007
CASH FLOWS FROM OPERATING ACTIVITIES
	Net income				$ 80.4	$ 69.6
	Adjustments to reconcile net income to cash from operating activities:
		Depreciation & amortization			123.2	119.4
		Deferred income taxes & investment tax credits			39.0	4.1
		Expense portion of pension & postretirement periodic benefit cost			1.9	2.9
		Provision for uncollectible acccounts			11.8	11.5
		Other non-cash charges - net			8.9	3.1
		Changes in working capital accounts:
			Accounts receivable, including to Vectren companies
				& accrued unbilled revenue	162.1	121.4
			Inventories		(72.2)	(28.3)
			Recoverable/refundable fuel & natural gas costs		(49.0)	(7.5)
			Prepayments & other current assets		(43.6)	(18.2)
			Accounts payable, including to Vectren companies
				& affiliated companies	12.9	(59.9)
			Accrued liabilities		78.3	(15.5)
		Changes in noncurrent assets			3.2	(10.2)
		Changes in noncurrent liabilities			(14.8)	(19.3)
			Net cash flows from operating activities		342.1	173.1
CASH FLOWS FROM FINANCING ACTIVITIES
	Proceeds from:
		Capital contribution from parent			124.9	-
		Proceeds from long-term debt, net of issuance costs			171.1	-
	Requirements for:
		Dividends to parent			(62.4)	(57.4)
		Retirement of long-term debt, including premiums paid			(104.0)	(6.5)
	Net change in short-term borrowings				(272.7)	82.1
			Net cash flows from financing activities		(143.1)	18.2
CASH FLOWS FROM INVESTING ACTIVITIES
	Proceeds from other investing activities				2.5	0.3
	Requirements for:
		Capital expenditures, excluding AFUDC equity			(204.1)	(213.1)
		Other investing activities			(1.1)	-
			Net cash flows from investing activities		(202.7)	(212.8)
Net change in cash & cash equivalents					(3.7)	(21.5)
Cash & cash equivalents at beginning of period					11.7	28.5
Cash & cash equivalents at end of period					$ 8.0	$ 7.0

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 (VEDO or Vectren Ohio). 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 (Energy Act).

Indiana Gas provides energy delivery services to over 569,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to over 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 319,000 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 of Utility Holdings (53 percent ownership), and Indiana Gas (47 percent 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 normal and recurring 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, 2007, filed with the Securities and Exchange Commission February 28, 2008 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 $113 million is outstanding at September 30, 2008, and Utility Holdings’ $824 million unsecured senior notes outstanding at September 30, 2008. 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 Balance Sheet as of September 30, 2008 (in millions):


ASSETS			Subsidiary	Parent	Eliminations &
			Guarantors	Company	Reclassifications	Consolidated
Current Assets
	Cash & cash equivalents		$ 4.2	$ 3.8	$ -	$ 8.0
	Accounts receivable - less reserves		86.4	-	-	86.4
	Receivables due from other Vectren companies		96.9	232.5	(329.1)	0.3
	Accrued unbilled revenues		35.0	-	-	35.0
	Inventories		198.5	5.2	-	203.7
	Recoverable fuel & natural gas costs		28.7	-	-	28.7
	Prepayments & other current assets		125.2	12.3	(3.9)	133.6
		Total current assets	574.9	253.8	(333.0)	495.7
Utility Plant
Original cost			4,226.4	-	-	4,226.4
Less: accumulated depreciation & amortization			1,590.6	-	-	1,590.6
Net utility plant			2,635.8	-	-	2,635.8
Investments in consolidated subsidiaries			-	1,155.5	(1,155.5)	-
Notes receivable from consolidated subsidiaries			-	699.5	(699.5)	-
Investments in unconsolidated affiliates			0.2	-	-	0.2
Other investments			18.0	5.6	-	23.6
Nonutility property - net			4.4	176.2	-	180.6
Goodwill			205.0	-	-	205.0
Regulatory assets			116.0	25.5	-	141.5
Other assets			12.5	0.3	(3.5)	9.3
TOTAL ASSETS			$ 3,566.8	$ 2,316.4	$ (2,191.5)	$ 3,691.7
LIABILITIES & SHAREHOLDER'S EQUITY			Subsidiary	Parent	Eliminations &
			Guarantors	Company	Reclassifications	Consolidated
Current Liabilities
	Accounts payable		$ 128.9	$ 3.4	$ -	$ 132.3
	Accounts payable to affiliated companies		48.1	-	-	48.1
	Payables to other Vectren companies		87.8	1.2	(25.0)	64.0
	Refundable fuel & natural gas costs		6.9	-	-	6.9
	Accrued liabilities		199.7	15.5	(3.9)	211.3
	Short-term borrowings		0.2	113.0	-	113.2
	Short-term borrowings from
		other Vectren companies	208.4	95.7	(304.1)	-
	Long-term debt subject to tender		80.0	-	-	80.0
		Total current liabilities	760.0	228.8	(333.0)	655.8
Long-Term Debt
	Long-term debt - net of current maturities &
		debt subject to tender	243.1	822.5	-	1,065.6
	Long-term debt due to Utility Holdings		699.5	-	(699.5)	-
		Total long-term debt - net	942.6	822.5	(699.5)	1,065.6
Deferred Income Taxes & Other Liabilities
	Deferred income taxes		303.2	20.0	-	323.2
	Regulatory liabilities		308.1	4.9	-	313.0
	Deferred credits & other liabilities		97.4	7.2	(3.5)	101.1
		Total deferred credits & other liabilities	708.7	32.1	(3.5)	737.3
Common Shareholder's Equity
	Common stock (no par value)		776.3	763.0	(776.3)	763.0
	Retained earnings		379.1	469.9	(379.1)	469.9
	Accumulated other comprehensive income		0.1	0.1	(0.1)	0.1
		Total common shareholder's equity	1,155.5	1,233.0	(1,155.5)	1,233.0
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY			$ 3,566.8	$ 2,316.4	$ (2,191.5)	$ 3,691.7

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Condensed Consolidating Balance Sheet as of December 31, 2007 (in millions):


ASSETS			Subsidiary	Parent	Eliminations &
			Guarantors	Company	Reclassifications	Consolidated
Current Assets
	Cash & cash equivalents		$ 6.5	$ 5.2	$ -	$ 11.7
	Accounts receivable - less reserves		136.3	0.8	-	137.1
	Receivables due from other Vectren companies		0.1	276.6	(258.8)	17.9
	Accrued unbilled revenues		140.6	-	-	140.6
	Inventories		133.8	1.1	-	134.9
	Prepayments & other current assets		87.3	10.5	(4.5)	93.3
		Total current assets	504.6	294.2	(263.3)	535.5
Utility Plant
Original cost			4,062.9	-	-	4,062.9
Less: accumulated depreciation & amortization			1,523.2	-	-	1,523.2
Net utility plant			2,539.7	-	-	2,539.7
Investments in consolidated subsidiaries			-	1,147.0	(1,147.0)	-
Notes receivable from consolidated subsidiaries			-	589.4	(589.4)	-
Investments in unconsolidated affiliates			0.2	-	-	0.2
Other investments			18.9	5.8	-	24.7
Nonutility property - net			4.8	171.4	-	176.2
Goodwill			205.0	-	-	205.0
Regulatory assets			130.3	21.4	-	151.7
Other assets			14.8	0.5	(4.6)	10.7
TOTAL ASSETS			$ 3,418.3	$ 2,229.7	$ (2,004.3)	$ 3,643.7

LIABILITIES & SHAREHOLDER'S EQUITY			Subsidiary	Parent	Eliminations &
			Guarantors	Company	Reclassifications	Consolidated
Current Liabilities
	Accounts payable		$ 132.6	$ 6.1	$ -	$ 138.7
	Accounts payable to affiliated companies		66.9	-	-	66.9
	Payables to other Vectren companies		49.6	0.1	(15.5)	34.2
	Refundable fuel & natural gas costs		27.2	-	-	27.2
	Accrued liabilities		123.4	20.0	(4.5)	138.9
	Short-term borrowings		-	385.9	-	385.9
	Short-term borrowings from
		other Vectren companies	243.3	-	(243.3)	-
		Total current liabilities	643.0	412.1	(263.3)	791.8
Long-Term Debt
	Long-term debt - net of current maturities &
		debt subject to tender	364.2	698.4	-	1,062.6
	Long-term debt due to VUHI		589.4	-	(589.4)	-
		Total long-term debt - net	953.6	698.4	(589.4)	1,062.6
Deferred Income Taxes & Other Liabilities
	Deferred income taxes		270.0	16.9	-	286.9
	Regulatory liabilities		301.8	5.4	-	307.2
	Deferred credits & other liabilities		102.9	6.5	(4.6)	104.8
		Total deferred credits & other liabilities	674.7	28.8	(4.6)	698.9
Common Shareholder's Equity
	Common stock (no par value)		776.3	638.2	(776.3)	638.2
	Retained earnings		370.4	451.9	(370.4)	451.9
	Accumulated other comprehensive income		0.3	0.3	(0.3)	0.3
		Total common shareholder's equity	1,147.0	1,090.4	(1,147.0)	1,090.4

TOTAL LIABILITIES & SHAREHOLDER'S EQUITY			$ 3,418.3	$ 2,229.7	$ (2,004.3)	$ 3,643.7

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Condensed Consolidating Statement of Income for the three months ended September 30, 2008 (in millions):


	Subsidiary			Parent		Eliminations &
	Guarantors			Company		Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	143.9		$	-	$	-			143.9
Electric utility		147.9			-		-			147.9
Other		-		$	11.7		(11.1	)		0.6
Total operating revenues		291.8			11.7		(11.1	)		292.4
OPERATING EXPENSES
Cost of gas		80.2			-		-			80.2
Cost of fuel & purchased power		48.7			-		-			48.7
Other operating		79.0			1.0		(10.8	)		69.2
Depreciation & amortization		35.7			5.8		0.1			41.6
Taxes other than income taxes		11.3			0.4		-			11.7
Total operating expenses		254.9			7.2		(10.7	)		251.4
OPERATING INCOME		36.9			4.5		(0.4	)		41.0
OTHER INCOME (EXPENSE) - NET
Equity in earnings of consolidated companies		-			11.4		(11.4	)		-
Other income (expense) – net		(0.1	)		13.3		(12.5	)		0.7
Total other income (expense) - net		(0.1	)		24.7		(23.9	)		0.7
Interest expense		18.5			14.0		(12.9	)		19.6
INCOME BEFORE INCOME TAXES		18.3			15.2		(11.4	)		22.1
Income taxes		6.9			1.6		-			8.5
NET INCOME	$	11.4		$	13.6	$	(11.4	)	$	13.6

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


	Subsidiary			Parent			Eliminations &
	Guarantors			Company			Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	114.0		$	-		$	-		$	114.0
Electric utility		143.6			-			-			143.6
Other		-			10.1			(9.7	)		0.4
Total operating revenues		257.6			10.1			(9.7	)		258.0
OPERATING EXPENSES
Cost of gas		52.9			-			-			52.9
Cost of fuel & purchased power		50.5			-			-			50.5
Other operating		74.3			-			(8.7	)		65.6
Depreciation & amortization		34.5			5.8			0.1			40.4
Taxes other than income taxes		10.1			1.2			-			11.3
Total operating expenses		222.3			7.0			(8.6	)		220.7
OPERATING INCOME		35.3			3.1			(1.1	)		37.3
OTHER INCOME (EXPENSE) - NET
Equity in earnings of consolidated companies		-			10.2			(10.2	)		-
Other income (expense) – net		(0.2	)		12.1			(10.6	)		1.3
Total other income (expense) - net		(0.2	)		22.3			(20.8	)		1.3
Interest expense		17.7			14.8			(11.7	)		20.8
INCOME BEFORE INCOME TAXES		17.4			10.6			(10.2	)		17.8
Income taxes		7.2			(0.1	)		-			7.1
NET INCOME	$	10.2		$	10.7		$	(10.2	)	$	10.7

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Condensed Consolidating Statement of Income for the nine months ended September 30, 2008 (in millions):


	Subsidiary		Parent		Eliminations &
	Guarantors		Company		Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	1,002.4	$	-	$	-		$	1,002.4
Electric utility		402.3		-		-			402.3
Other		-		35.2		(33.4	)		1.8
Total operating revenues		1,404.7		35.2		(33.4	)		1,406.5
OPERATING EXPENSES
Cost of gas		686.0		-		-			686.0
Cost of fuel & purchased power		143.2		-		-			143.2
Other operating		250.1		-		(32.4	)		217.7
Depreciation & amortization		106.3		16.7		0.2			123.2
Taxes other than income taxes		50.7		1.0		0.1			51.8
Total operating expenses		1,236.3		17.7		(32.1	)		1,221.9
OPERATING INCOME		168.4		17.5		(1.3	)		184.6
OTHER INCOME (EXPENSE) - NET
Equity in earnings of consolidated companies		-		71.2		(71.2	)		-
Other income (expense) – net		2.7		37.8		(35.6	)		4.9
Total other income (expense) - net		2.7		109.0		(106.8	)		4.9
Interest expense		54.3		42.1		(36.9	)		59.5
INCOME BEFORE INCOME TAXES		116.8		84.4		(71.2	)		130.0
Income taxes		45.6		4.0		-			49.6
NET INCOME	$	71.2	$	80.4	$	(71.2	)	$	80.4

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


	Subsidiary		Parent			Eliminations &
	Guarantors		Company			Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	890.0	$	-		$	-		$	890.0
Electric utility		361.6		-			-			361.6
Other		-		30.3			(29.0	)		1.3
Total operating revenues		1,251.6		30.3			(29.0	)		1,252.9
OPERATING EXPENSES
Cost of gas		592.0		-			-			592.0
Cost of fuel & purchased power		129.5		-			-			129.5
Other operating		224.2		-			(25.8	)		198.4
Depreciation & amortization		101.8		17.3			0.3			119.4
Taxes other than income taxes		47.7		1.8			0.1			49.6
Total operating expenses		1,095.2		19.1			(25.4	)		1,088.9
OPERATING INCOME		156.4		11.2			(3.6	)		164.0
OTHER INCOME (EXPENSE) - NET
Equity in earnings of consolidated companies		-		65.6			(65.6	)		-
Other income (expense) – net		2.5		33.5			(29.8	)		6.2
Total other income (expense) - net		2.5		99.1			(95.4	)		6.2
Interest expense		50.6		41.6			(33.4	)		58.8
INCOME BEFORE INCOME TAXES		108.3		68.7			(65.6	)		111.4
Income taxes		42.7		(0.9	)		-			41.8
NET INCOME	$	65.6	$	69.6		$	(65.6	)	$	69.6

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Condensed Consolidating Statement of Cash Flows for the nine months ended September 30, 2008 (in millions):


	Subsidiary			Parent			Eliminations &
	Guarantors			Company			Reclassifications			Consolidated
NET CASH FLOWS FROM OPERATING ACTIVITIES	$	305.2		$	36.9		$	-		$	342.1

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from
Capital contribution from parent		-			124.9			-			124.9
Long-term debt, net of issuance costs		171.1			111.1			(111.1	)		171.1
Requirements for:
Dividends to parent		(62.4	)		(62.4	)		62.4			(62.4	)
Retirement of long-term debt, including premiums paid		(104.0	)		(1.0	)		1.0			(104.0	)
Net change in short-term borrowings, including to other
Vectren companies		(130.6	)		(177.0	)		34.9			(272.7	)
Net cash flows from financing activities		(125.9	)		(4.4	)		(12.8	)		(143.1	)

CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from
Consolidated subsidiary distributions		-			62.4			(62.4	)		-
Other investing activities		2.3			0.2			-			2.5
Requirements for:
Capital expenditures, excluding AFUDC equity		(182.8	)		(21.3	)		-			(204.1	)
Other investing activities		(1.1	)		-			-			(1.1	)
Net change in notes receivable to other Vectren companies		-			(75.2	)		75.2			-
Net cash flows from investing activities		(181.6	)		(33.9	)		12.8			(202.7	)
Net change in cash & cash equivalents		(2.3	)		(1.4	)		-			(3.7	)
Cash & cash equivalents at beginning of period		6.5			5.2			-			11.7
Cash & cash equivalents at end of period	$	4.2		$	3.8		$	-		$	8.0

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


	Subsidiary			Parent			Eliminations &
	Guarantors			Company			Reclassifications			Consolidated
NET CASH FLOWS FROM OPERATING ACTIVITIES	$	144.3		$	28.8		$	-		$	173.1

CASH FLOWS FROM FINANCING ACTIVITIES
Requirements for:
Dividends to parent		(57.4	)		(57.4	)		57.4			(57.4	)
Retirement of long-term debt		(6.5	)		-			-			(6.5	)
Net change in short-term borrowings		105.2			82.1			(105.2	)		82.1
Net cash flows from financing activities		41.3			24.7			(47.8	)		18.2

CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from consolidated subsidiary distributions		-			57.4			(57.4	)		-
Proceeds from other investing activities		-			0.3			-			0.3
Requirements for:
Capital expenditures, excluding AFUDC equity		(186.2	)		(26.9	)		-			(213.1	)
Net change in notes receivable to other Vectren companies		-			(105.2	)		105.2			-
Net cash flows from investing activities		(186.2	)		(74.4	)		47.8			(212.8	)
Net change in cash & cash equivalents		(0.6	)		(20.9	)					(21.5	)
Cash & cash equivalents at beginning of period		5.7			22.8						28.5
Cash & cash equivalents at end of period	$	5.1		$	1.9		$	-		$	7.0

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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 $5.2 million and $4.9 million, respectively for the three months ended September 30, 2008 and 2007. For the nine months ended September 30, 2008 and 2007, these taxes totaled $31.6 million and $29.6 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						Nine Months
	Ended September 30,						Ended September 30,
(In millions)	2008			2007			2008			2007
Net income		13.6			10.7			80.4			69.6
Cash flow hedges
Reclassifications to net income		(0.1	)		(0.1	)		(0.3	)		(0.7	)
Income tax benefit		-			-			0.2			0.3
Total comprehensive income	$	13.5		$	10.6		$	80.3		$	69.2

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 $20.9 million and $20.7 million for the three months ended September 30, 2008 and 2007, respectively. For the nine months ended September 30, 2008 and 2007, Utility Holdings received corporate allocations totaling $68.1 million and $63.0 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 September 30, 2008 and 2007, totaled $32.1 million and $30.3 million, respectively. For the nine months ended September 30, 2008 and 2007 amounts paid for such purchases totaled $91.9 million and $86.4 million, respectively.

Miller Pipeline Corporation

Miller Pipeline 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 and its subsidiaries for the three months ended September 30, 2008 and 2007 totaled $8.6 million and $16.6 million, respectively. Amounts paid for the nine months ended September 30, 2008 and 2007, totaled $25.4 million and $28.1 million, respectively.

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7.	Transactions with ProLiance Holdings, LLC

ProLiance Holdings, 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 the Company’s Indiana utilities and Vectren’s 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 September 30, 2008 and 2007 totaled $177.1 million and $111.0 million, respectively, and for the nine months ended September 30, 2008 and 2007 totaled $572.7 million and $452.3 million. Amounts owed to ProLiance at September 30, 2008 and December 31, 2007 for those purchases were $48.1 million and $66.9 million, respectively, and are included in Accounts payable to affiliated companies in the Consolidated Condensed Balance Sheets. The Company purchased approximately 72 percent and 70 percent of its gas through ProLiance during the nine months ended September 30, 2008 and 2007, respectively. Amounts charged by ProLiance for gas supply services are established by supply agreements with each Indiana utility which have been approved by the IURC through 2011. ProLiance no longer provides portfolio administration services to the Ohio operations.

8.	Debt Offering in 2008 and Transactions Involving Auction Rate Securities

Impacts on Short-Term Borrowings from Recent Events in Credit Markets

Historically, the Company has funded the short-term borrowing needs of its utility operations through the commercial paper market. The Company’s access to longer term commercial paper was significantly reduced as a result of the continued turmoil and volatility in the financial markets. As a result, the Company has met working capital requirements through a combination of A2/P2 commercial paper issuances and draws on its $515 million commercial paper back-up credit facilities. This credit facility expires in November of 2010.

Utility Holdings Debt Issuance

In March 2008, Utility Holdings issued at par $125 million in 6.25 percent senior unsecured notes due April 1, 2039 (2039 Notes). The 2039 Notes are guaranteed by Utility Holdings’ three utilities: SIGECO, Indiana Gas, and VEDO. These guarantees are full and unconditional and joint and several.

The 2039 Notes have no sinking fund requirements, and interest payments are due monthly. The notes may be called by Utility Holdings, in whole or in part, at any time on or after April 1, 2013, at 100 percent of principal amount plus accrued interest. During 2007, Utility Holdings entered into several interest rate hedges with an $80 million notional amount. Upon issuance of the notes, these instruments were settled resulting in the payment of approximately $9.6 million, which was recorded as a Regulatory asset pursuant to existing regulatory orders. The value paid is being amortized as an increase to interest expense over the life of the issue. The proceeds from the sale of the 2039 Notes less settlement of the hedging arrangements and payments of issuance costs amounted to approximately $111.1 million.

Auction Rate Mode Securities

In February 2008, SIGECO provided notice to the current holders of approximately $103 million of tax-exempt auction rate mode long-term debt of its plans to convert that debt from its current auction rate mode into a daily interest rate mode. In March 2008, the debt was tendered at 100 percent of the principal amount plus accrued interest. During March 2008, SIGECO remarketed approximately $61.8 million of these investments at interest rates that are fixed to maturity, receiving proceeds, net of issuance costs, of approximately $60.0 million. The terms are $22.6 million at 5.15 percent due in 2023, $22.2 million at 5.35 percent due in 2030 and $17.0 million at 5.45 percent due in 2041. The remaining $41.3 million continues to be held in treasury and is expected to be remarketed at some future date.

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9.	Capital Contribution from Vectren

On June 27, 2008, Vectren physically settled an equity forward agreement associated with a 2007 public offering of its common stock. Vectren transferred net proceeds of approximately $124.9 million to Utility Holdings, and Utility Holdings used the proceeds to repay short-term debt obligations incurred primarily to fund its capital expenditure program. The proceeds received were recorded as an increase to Common Stock in Common Shareholder’s Equity and are presented in the Statement of Cash Flows as a financing activity.

10.	Commitments & Contingencies

11.	Environmental Matters

Clean Air Act Initiatives

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. However, on February 8, 2008, the US Court of Appeals for the District of Columbia (the Court) vacated the federal CAMR regulations and on July 11, 2008, the same court vacated the federal CAIR regulations. The USEPA filed motions for reconsideration. The CAMR motion was denied, and the Court is yet to act on the CAIR motion. So, technically, CAIR, which requires more stringent NOx reductions beginning January 1, 2009 and SO2 reductions in 2010 with a second phase of reductions in 2015, remains in place until the Court acts. The Company anticipates the Court will act some time before the end of 2009. The Court's recent actions would suggest that it is considering staying the mandate and maintaining the effectiveness of the current CAIR regulatory requirements while USEPA addresses defects identified in the Court's original determination. At this time it is uncertain how these decisions will affect Indiana’s implementation plans for those regulations. There is a possibility Indiana will implement the more stringent CAIR reduction standards starting in January of 2009, even if the Court denies the motion to reconsider.

Utilization of the Company’s inventory of NOx and SO2 allowances may also be impacted by these decisions; however, most of these allowances were granted to the Company at zero cost, so a reduction in carrying value is not expected.

To comply with Indiana’s implementation plan of the Clean Air Act of 1990 and to comply with potential future regulations of mercury and further NOx and SO2 reductions, SIGECO has IURC authority to invest in clean coal technology. Using this authorization, SIGECO has invested approximately $307 million in pollution control equipment, including Selective Catalytic Reduction (SCR) systems and fabric filters. SCR technology is the most effective method of reducing NOx emissions where high removal efficiencies are required and fabric filters control particulate matter emissions. These investments were included in rate base for purposes of determining new base rates that went into effect on August 15, 2007. Prior to being included in base rates, return on investments made and recovery of related operating expenses were recovered through a rider mechanism.

Further, the IURC granted SIGECO authority to invest in an SO2 scrubber at its generating facility that is jointly owned with ALCOA (the Company’s portion is 150 MW). The order, as updated with an increased spending level, allows SIGECO to recover an approximate 8 percent return on up to $92 million, excluding AFUDC, in capital investments through a rider mechanism which is updated every nine months for actual costs incurred. The Company may file periodic updates with the IURC requesting modification to the spending authority. As of September 30, 2008, the Company has invested approximately $78 million in this project. The Company expects the SO2 scrubber will be operational by early 2009. At that time, operating expenses including depreciation expense associated with the scrubber are expected to be recovered through a rider mechanism.

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Once the SO2 scrubber is operational, SIGECO’s coal fired generating fleet will be 100 percent scrubbed for SO2 and 90 percent controlled for NOx. SIGECO's investments in scrubber, SCR and fabric filter technology allows for compliance with existing regulations that are unaffected by these recent court decisions and should position it to comply with future reasonable pollution control legislation, if and when, reductions in mercury and further reductions in NOx and SO2 are promulgated by USEPA and/or the District of Columbia US Court of Appeals rulings are overturned. It is also possible that CAMR and CAIR regulations being vacated will lead to increased support for the passage of a multi-pollutant bill in Congress. The Company is in position to comply with the NOx reduction requirements described in CAIR, if the Company were required to comply starting January 1, 2009.

Climate Change

There are currently several forms of legislation being circulated at the federal level addressing the climate change issue. These proposals generally involve either: 1) a “cap and trade” approach where there is a progressive cap on greenhouse gas emissions and an auctioning and subsequent trading of allowances among those that emit greenhouse gases or 2) a carbon tax. Currently no legislation has passed either house of Congress.

In the absence of federal legislation, several regional initiatives throughout the United States are in the process of establishing regional cap and trade programs. While no climate change legislation is pending in the State of Indiana, the State is an observer of the Midwestern Regional Greenhouse Gas Reduction Accord, and its legislature debated, but did not pass, renewable energy portfolio standards in 2007.

In April of 2007, the US Supreme Court determined that greenhouse gases meet the definition of "air pollutant" under the Clean Air Act and ordered the USEPA to determine whether greenhouse gas emissions from new motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. Should the USEPA find such endangerment, it is likely that major stationary sources will be subject to regulation under the Act. USEPA has recently released its Advanced Notice of Proposed Rulemaking in which the agency is soliciting comment as to whether it is appropriate or effective to regulate greenhouse gas emissions under the Act.

Impact of Legislative Actions and Other Initiatives is Unknown

If legislation requiring reductions in CO2 and other greenhouse gases or legislation mandating a renewable energy portfolio standard is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants. At this time and in the absence of final legislation, compliance costs and other effects associated with reductions in greenhouse gas emissions or obtaining renewable energy sources remain uncertain. The Company has gathered preliminary estimates of the costs to comply with a cap and trade approach to controlling greenhouse gas emissions. A preliminary investigation demonstrated costs to comply would be significant, first to operating expenses for the purchase of allowances, and later to capital expenditures as technology becomes available to control greenhouse gas emissions. However, these compliance cost estimates are very sensitive to highly uncertain assumptions, including allowance prices. Costs to purchase allowances that cap greenhouse gas emissions should be considered a cost of providing electricity, and as such, the Company believes recovery should be timely reflected in rates charged to customers. Approximately 20 percent of electric volumes sold in 2007 were delivered to municipal and other wholesale customers. As such, the Company has some flexibility to modify the level of these transactions to reduce overall emissions and reduce costs associated with complying with new environmental regulations.

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. Indiana Gas submitted the remainder 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.

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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 $21.5 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 percent and 50 percent.

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 $20.5 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 site subject to the May 2007 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 $8.2 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 of $8.0 million.

Environmental remediation costs related to Indiana Gas’ and SIGECO’s manufactured gas plants and other sites have had a minor 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.

12.	Rate & Regulatory Matters

Vectren Energy Delivery of Ohio, Inc. (VEDO) Gas Base Rate Case Filing

On September 9, 2008, the Company announced VEDO entered into a Stipulation and Recommendation (Stipulation) with the PUCO and other parties regarding the revenue requirement for VEDO's gas distribution business in 17 west central Ohio counties. In addition, the Stipulation, if approved, will provide for the continuation and enhancement of energy efficiency and conservation programs for residential and commercial customers.

The Stipulation provides for a nearly $14.8 million increase in VEDO's base distribution rates to cover the ongoing cost of operating, maintaining and expanding the approximate 5,200-mile distribution system used to serve more than 318,000 customers. Terms of the stipulation include: a rate increase of nearly $14.8 million, inclusive of the nearly $3 to $5 million annually currently recorded through the lost margin recovery mechanism; an overall rate of return of 8.89 percent on rate base of about $235 million; and an opportunity to recover costs of a program to accelerate replacement of cast iron and bare steel pipelines, as well as certain service risers and recovery of conservation costs. The Stipulation does not address the rate design that will be used to collect the agreed-upon revenue from VEDO's residential customers.

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The Stipulation has been filed with the PUCO who will now review and determine whether to approve those elements of the Stipulation before the base rate adjustment can become effective. The PUCO is expected to address the rate design question in the same decision. The Company has proposed, among other alternatives, the use of a straight fixed variable rate design which places all, or a most of, the fixed cost recovery in the customer service charge. In PUCO decisions in cases involving other Ohio utilities, it has approved such rate design. A straight fixed variable design can mitigate the effects of declining usage, similar to the Company’s current lost margin recovery mechanism, which is set to expire upon receipt of the new order. The Company has also proposed to base usage patterns on 10 year normal weather whereas current rates are based on 30 year normal weather.

Elements of the conservation programs, totaling up to $5 million, include: rebates on high-efficiency natural gas appliances, such as furnaces, programmable thermostats and water heaters as well as other tools and resources to help customers lower natural gas usage; and the continuation of VEDO's Project TEEM (Teaching Energy Efficiency Measures), which offers free home weatherization services to income-eligible customers. These programs will be monitored, reviewed, and adapted as deemed appropriate through the oversight of an existing collaborative, which includes representatives of VEDO, the Ohio Consumers' Counsel, the PUCO and the Ohio Partners for Affordable Energy.

The Company expects the PUCO to issue a decision in the fourth quarter of 2008.

Vectren Energy Delivery of Ohio, Inc. Begins Process to Exit the Merchant Function

On August 20, 2008, the PUCO approved an auction selecting qualified wholesale suppliers to provide the gas commodity to the Company for resale to its customers at auction-determined standard pricing. This auction, which is effective from October 1, 2008 through March 31, 2010, is the initial step in exiting the merchant function in the Company’s Ohio service territory. The approach eliminates the need for monthly gas cost recovery (GCR) filings and prospective PUCO GCR audits and eliminates risks of gas cost disallowances. At September 30, 2008, the Company was in the process of transferring its natural gas inventory at book value to the auction winning wholesale suppliers, and as of September 30, VEDO had received approximately $107 million from those wholesale suppliers. Because title to that inventory did not pass until October 1st, the inventory balance remains on the Company’s consolidated balance sheet at September 30. The cash received in advance of the transfer is recorded in Accrued liabilities. On October 1st, VEDO’s entire natural gas inventory was transferred. The PUCO has also provided for an Exit Transition Cost rider, which allows the Company to recover costs associated with the transition. As the cost of gas is currently passed through to customers through a PUCO approved recovery mechanism, the impact of exiting the merchant function should not have a material impact on Company earnings or financial condition.

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

On February 13, 2008, the Company received an order from the IURC which approved the settlement agreement reached in its Vectren North gas rate case. The order provided for a base rate increase of $16.3 million and a return on equity (ROE) of 10.2 percent, with an overall rate of return of 7.8 percent on rate base of approximately $793 million. The order also provides for the recovery of $10.6 million of costs through separate cost recovery mechanisms rather than base rates.

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 $20 million and the treatment cannot extend beyond four years on each project.

With this order, the Company has in place for its North gas territory weather normalization, a conservation and lost margin recovery tariff, tracking of gas cost expense related to a bad debt expense level based on historical experience and unaccounted for gas through the existing gas cost adjustment mechanism, and tracking of pipeline integrity management expense.

Vectren South (SIGECO) Electric Base Rate Order Received

On August 15, 2007, the Company received an order from the IURC which approved the settlement reached in Vectren South’s electric rate case. The order provided for an approximate $60.8 million electric rate increase to cover the Company’s cost of system growth, maintenance, safety and reliability. The order provided for, among other things: recovery of ongoing costs and deferred costs associated with the 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; benefit to customers from the sale of wholesale power by the Company sharing equally with customers any profit earned above or below $10.5 million of wholesale power margin; recovery of and return on the investment in past demand side management programs to help encourage conservation during peak load periods; timely recovery of the Company’s investment in certain new electric transmission projects that benefit the MISO infrastructure; an overall rate of return of 7.32 percent on rate base of approximately $1,044 million and an allowed ROE of 10.4 percent.

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Vectren South Gas Base Rate Order Received

On August 1, 2007, the Company received an order from the IURC which approved the settlement reached in Vectren South’s gas rate case. The order provided for a base rate increase of $5.1 million and a ROE of 10.15 percent, with an overall rate of return of 7.2 percent on rate base of approximately $122 million. The order also provided for the recovery of $2.6 million of costs through separate cost recovery mechanisms rather than base rates.

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 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 lost margin recovery tariff, tracking of gas cost expense related to a bad debt expense level based on historical experience and unaccounted for gas through the existing gas cost adjustment mechanism, and tracking of pipeline integrity management expense.

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.

Since April 1, 2005, the Company has been an active participant in the MISO energy markets, bidding its owned generation into the Day Ahead and Real Time markets and procuring 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. The Company also receives transmission revenue that results from other members’ use of the Company’s transmission system. These revenues are also included in Electric Utility revenues. Generally, costs charged by the MISO are recovered via base rates or tracking mechanisms.

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 a pending Day 3 ancillary services market (ASM), where MISO plans to provide bid-based regulation and contingency operating reserve markets, it is difficult to predict near term operational impacts. In September 2008, MISO announced that the ASM would begin January 6, 2009. The IURC has approved the Company’s participation in the ASM and has granted authority to defer costs associated with ASM

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The 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 is expected to be significant. The Company timely recovers its investment in certain new electric transmission projects that benefit the MISO infrastructure at a FERC approved rate of return.

13.	Segment Reporting

The Company’s operations consist of the 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 wholesale 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		Nine Months
				Ended September 30,		Ended September 30,
(In millions)				2008	2007	2008	2007
Revenues
	Gas Utility Services			$ 143.9	$ 114.0	$ 1,002.4	$ 890.0
	Electric Utility Services			147.9	143.6	402.3	361.6
	Other Operations			11.7	10.1	35.2	30.3
	Eliminations			(11.1)	(9.7)	(33.4)	(29.0)
		Consolidated Revenues		$ 292.4	$ 258.0	$ 1,406.5	$ 1,252.9


Profitability Measure - Net Income (Loss)
		Gas Utility Services		$ (10.7)	$ (8.4)	$ 29.7	$ 26.0
		Electric Utility Services		22.1	18.6	41.5	39.6
		Other Operations		2.2	0.5	9.2	4.0
			Total Net Income	$ 13.6	$ 10.7	$ 80.4	$ 69.6

14.	Fair Value Measurements

SFAS 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. SFAS 157 does not require any new fair value measurements; however, the standard will impact how other fair value based GAAP is applied. Subsequently, the FASB issued FSP FAS 157-2 which delays the effective date of SFAS 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually) to fiscal years beginning after November 15, 2008. The Company adopted SFAS 157 on January 1, 2008, except as it applies to those nonfinancial assets and nonfinancial liabilities as described in FSP FAS 157-2. The partial adoption of SFAS 157 did not materially impact the Company’s financial position, results of operations or cash flows. The Company is currently evaluating the potential impact the application of SFAS 157 to its nonfinancial assets and liabilities will have on its consolidated financial statements.

The Company measures certain financial instruments, primarily derivatives, at fair value on a recurring basis. SFAS 157 defines a hierarchy for disclosing fair value measurements based primarily on the level of public data used in determining fair value. Level 1 inputs include quoted market prices in active markets for identical assets or liabilities; Level 2 inputs include inputs other than Level 1 inputs that are directly or indirectly observable; and Level 3 inputs include unobservable inputs using estimates and assumptions developed in-house, which reflect what a market participant would use to determine fair value. At September 30, 2008, the Company had no material derivative contracts outstanding and none outstanding valued using Level 3 inputs. As of December 31, 2007, the Company had derivatives totaling $2.6 million in Prepayments and other current assets managing MISO related activities and $8.9 million in Accrued liabilities managing interest rate risk.

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SFAS 159

Also on January 1, 2008, the Company adopted SFAS 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. The Company did not choose to apply the option provided in SFAS 159 to any of its eligible items; therefore, its adoption did not have any impact on the Company’s financial statements or results of operations.

15.	Impact of Recently Issued Accounting Guidance

SFAS 141 (Revised 2007)

In December 2007, the FASB issued SFAS No. 141, “Business Combinations” (SFAS 141R). SFAS 141R establishes principles and requirements for how the acquirer of an entity (1) recognizes and measures the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree (2) recognizes and measures acquired goodwill or a bargain purchase gain and (3) determines what information to disclose in its financial statements in order to enable users to assess the nature and financial effects of the business combination. SFAS 141R applies to all transactions or other events in which one entity acquires control of one or more businesses and applies to all business entities. SFAS 141R applies prospectively to business combinations with an acquisition date on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. Early adoption is not permitted. The Company will adopt SFAS 141R on January 1, 2009, and because the provisions of this standard are applied prospectively, the impact to the Company cannot be determined until the transactions occur.

SFAS 161

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133” (SFAS 161). SFAS 161 enhances the current disclosures under SFAS 133 and requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation in order to better convey the purpose of derivative use in terms of the risks that the entity is intending to manage. Entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. Tabular disclosure of fair value amounts and gains and losses on derivative instruments and related hedged items is required. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early adoption encouraged. The Company will adopt SFAS 161 on January 1, 2009 and is currently assessing the impact this statement will have on its financial position and results of operations.

SFAS 162

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (SFAS No. 162). SFAS No. 162 identifies the sources of accounting principles and the framework for selecting principles used in the preparation of financial statements. SFAS No. 162 is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles”. The implementation of this standard will not have a material impact on its financial position 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.

The Company’s third quarter earnings were $13.6 million in 2008 compared to $10.7 million in 2007. Year to date, Utility Holdings earned $80.4 million compared to $69.6 million in 2007. The 27 percent quarter over quarter increase and 16 percent year to date increase is due primarily to base rate changes in the Indiana service territories and increased earnings from wholesale operations. Increases were offset somewhat by favorable weather in 2007 and increased operating costs associated with maintenance and reliability programs contemplated in the base rate cases.

In the Company’s electric and Ohio natural gas service territories which are not protected by weather normalization mechanisms, management estimates the impact of weather on margin compared to 30-year normal temperatures to be minor in both the three and nine months ended September 30, 2008. However, compared to the prior year, management estimates a $7.2 million unfavorable impact on margin in the quarter and an $8.0 million unfavorable impact on margin year to date.

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 an NTA mechanism. SIGECO’s electric service territory does not have an NTA mechanism but has recovery of past demand side management costs.

Gas and electric margin generated from sales to large customers (generally industrial and other contract customers) is primarily impacted by overall economic conditions and changes in demand for those customers’ products, particularly plastic related products. The recent economic downturn may have some negative impact on both gas and electric large customers, including customers in the automotive and ethanol industries. This impact may include tempered growth, significant conservation measures, and perhaps even plant closures. Deteriorating economic conditions may also lead to lower residential and commercial customer counts.

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, and costs to fund Indiana energy efficiency programs. Certain operating costs associated with operating environmental compliance equipment were also tracked prior to their recovery in base rates that went into effect on August 15, 2007. The latest Indiana service territory rate cases, implemented in 2007 and 2008 also provide for the tracking of MISO revenues and costs, as well as the gas cost component of bad debt expense and unaccounted for gas. Unaccounted for gas is also tracked in the Ohio service territory. 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)

Gas Utility margin and throughput by customer type follows:


	Three Months				Nine Months
	Ended September 30,				Ended September 30,
(In millions)	2008		2007		2008		2007
Gas utility revenues	$	143.9	$	114.0	$	1,002.4	$	890.0
Cost of gas sold		80.2		52.9		686.0		592.0
Total gas utility margin	$	63.7	$	61.1	$	316.4	$	298.0
Margin attributed to:
Residential & commercial customers	$	51.6	$	47.1	$	267.9	$	251.6
Industrial customers		10.2		9.5		38.0		35.2
Other		1.9		4.5		10.5		11.2
Sold & transported volumes in MMDth attributed to:
Residential & commercial customers		6.3		6.4		76.6		75.1
Industrial customers		18.4		18.0		67.5		62.5
Total sold & transported volumes		24.7		24.4		144.1		137.6

For the three and nine months ended September 30, 2008, gas utility margins were $63.7 million and $316.4 million, respectively, an increase of $2.6 million quarter over quarter and $18.4 million year to date compared to the prior year. The quarter over quarter increase was primarily due to $3.2 million of incremental margin increases associated with the Vectren North base rate increase, effective February 14, 2008. Year to date, the Vectren North rate case added $8.4 million in margin. Also impacting year to date results was the Vectren South base rate increase, effective August 1, 2007, increasing margin approximately $3.6 million. Year to date, Ohio weather is 5 percent colder than the prior year and results in an estimated increase in margin of approximately $1.6 million compared to 2007. Operating costs, including revenue and usage taxes recovered dollar-for-dollar in margin, increased gas margin $4.6 million. The average cost per dekatherm of gas purchased for the nine months ended September 30, 2008, was $10.14 compared to $8.19 in 2007.

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

Electric Utility margin by revenue type follows:


	Three Months				Nine Months
	Ended September 30,				Ended September 30,
(In millions)	2008		2007		2008		2007
Electric utility revenues	$	147.9	$	143.6	$	402.3	$	361.6
Cost of fuel & purchased power		48.7		50.5		143.2		129.5
Total electric utility margin	$	99.2	$	93.1	$	259.1	$	232.1
Margin attributed to:
Residential & commercial customers	$	65.5	$	64.5	$	165.4	$	147.9
Industrial customers		23.2		21.6		62.5		56.4
Municipal & other customers		1.5		4.4		9.0		14.7
Subtotal: retail & firm wholesale	$	90.2	$	90.5	$	236.9	$	219.0
Wholesale power marketing	$	9.0	$	2.6	$	22.2	$	13.1
Electric volumes sold in GWh attributed to:
Residential & commercial customers		833.8		954.4		2,195.6		2,357.7
Industrial customers		619.0		638.7		1,859.5		1,942.4
Municipal & other		4.3		192.1		58.3		483.5
Total retail & firm wholesale volumes sold		1,457.1		1,785.2		4,113.4		4,783.6

Retail Margin

Electric retail utility margins were $90.2 million and $236.9 million for the three and nine months ended September 30, 2008. Electric margin was generally flat quarter over quarter, but has increased approximately $17.9 million on a year to date basis compared to the prior year. The base rate increase that went into effect on August 15, 2007, produced incremental margin of $7.9 million during the quarter and $27.1 million year over year when netted with municipal contracts that were allowed to expire. Management estimates the year over year decreases in usage by residential and commercial customers due to weather, which was very warm the prior summer, to be $7.2 million in quarter and $9.6 million year over year. The remaining decrease in the quarter relates primarily to lower usage. Year to date, decreases in usage have been offset by increased pricing primarily related to recovery of pollution control investments.

Margin from Wholesale Power Marketing Activity

Periodically, generation capacity is in excess of that needed to serve native load. 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 into the MISO Day Ahead market.

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Further detail of Wholesale Power Marketing activity follows:


	Three Months				Nine Months
	Ended September 30,				Ended September 30,
(In millions)	2008		2007		2008		2007
Off-system sales	$	5.5	$	1.1	$	15.8	$	9.9
Transmission system sales		3.5		1.5		6.4		3.2
Total wholesale power marketing	$	9.0	$	2.6	$	22.2	$	13.1

For the three and nine months ended September 30, 2008, wholesale power marketing margins were $9.0 million and $22.2 million, representing increases of $6.4 million and $9.1 million, compared to 2007.

During the quarter, margin from off-system sales retained by the Company increased $4.4 million and has also increased $5.9 million year to date. During both the three and nine months ended September 30, 2008, the Company experienced higher wholesale power marketing margins due to the increase in off peak volumes available for sale off system, driven primarily by expiring municipal contracts, and increases in wholesale prices. The base rate case effective August 17, 2007, requires that wholesale power profit earned above or below $10.5 million be shared equally with customers, and 2008 results reflect the impact of that sharing. Year to date off-system sales totaled 1,111.4 GWh in 2008, compared to 544.1 GWh in 2007.

Beginning in June 2008, the Company started receiving returns from the MISO on projects constructed by the company in its service territory that benefit reliability throughout the MISO footprint. These returns primarily account for the quarterly and year to date increases of $2.0 million and $3.2 million, respectively, in transmission revenues.

Operating Expenses

Other Operating Expenses

For the three and nine months ended September 30, 2008, other operating expenses were $69.2 million and $217.7 million, which represent increases of $3.6 million and $19.3 million, compared to 2007. Costs in 2008 resulting from increased maintenance and other activities contemplated in rate cases, including amortization of prior deferred costs, totaled $9.1 million in the quarter and $25.6 million year over year. Operating costs that are directly recovered in utility margin increased $0.2 million in the quarter and $2.5 million year over year. Cost associated with lower performance compensation and share based compensation and other items partially offset these increases.

Depreciation & Amortization

For the three and nine months ended September 30, 2008, depreciation expense was $41.6 million and $123.2 million, which represents increases of $1.2 million and $3.8 million compared to 2007. The increases relate to the addition of plant and the amortization in 2008 associated with prior electric demand side management costs pursuant to the August 15, 2007, electric base rate order.

Taxes Other Than Income Taxes

For the three and nine months ended September 30, 2008, taxes other than income taxes were $11.7 million and $51.8 million, which represent increases of $0.4 million in the quarter and $2.2 million year over year. The increases are primarily due to increased revenues subject to revenue taxes.

Other Income-Net

Other-net reflects income of $0.7 million for the quarter and $4.9 million year to date, which represent decreases of $0.6 million in the quarter and $1.3 million year over year. The decreases are primarily due to lower amounts of AFUDC on utility plant and lower earnings associated with investments that fund deferred compensation arrangements.

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Interest Expense

For the three and nine months ended September 30, 2008, interest expense was $19.6 million and $59.5 million, which represents a decrease in the quarter of $1.2 million and an increase of $0.7 million year to date compared to 2007. The current quarter decrease reflects the impact of $124.9 million in additional equity proceeds received in June of 2008, which was used to reduce short-term borrowings. The year to date increase reflects the impact of long term financing transactions completed during the first quarter of 2008 including the issuance of $125 million in senior unsecured notes at 6.25 percent due in 2039 and the short term refinancing of approximately $103 million of auction rate mode debt. Of that amount, $62 million was remarketed in March 2008 at higher fixed interest rates, and the remaining $41.3 million will be remarketed at a future date. The impact of lower short-term interest rates early in 2008 and lower short-term balances has mostly offset increases. Due to recent events in the credit markets, for the remainder of 2008, and possibly longer, the Company is expecting higher interest rates on its outstanding borrowings and therefore interest expense may be negatively impacted. See the Financial Condition section for more information on the Company’s strategies to manage through current market conditions.

Income Taxes

Federal and state income taxes were $8.5 million for the quarter and $49.6 million year to date, which represent increases of $1.4 million in the quarter and $7.8 million year over year. The increases are due primarily to higher pretax income.

Environmental Matters

Clean Air Act Initiatives

Utilization of the Company’s inventory of NOx and SO2 allowances may also be impacted by these decisions; however, most of the these allowances were granted to the Company at zero cost, so a reduction in carrying value is not expected.

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Climate Change

The Company is committed to responsible environmental stewardship and conservation efforts as demonstrated by its proactive approach to balancing environmental and customer needs. While scientific uncertainties exist and the debate surrounding global climate change is ongoing, the growing understanding of the science of climate change would suggest a strong potential for adverse economic and social consequences should world-wide carbon dioxide (CO2) and other greenhouse gas emissions continue at present levels.

The need to reduce CO2 and other greenhouse gas emissions, yet provide affordable energy requires thoughtful balance. For these reasons, the Company supports a national climate change policy with the following elements:

·	An inclusive scope that involves all sectors of the economy and sources of greenhouse gases, and recognizes early actions and investments made to mitigate greenhouse gas emissions;

·	Provisions for enhanced use of renewable energy sources as a supplement to base load coal generation including effective energy conservation, demand side management and generation efficiency measures;

A flexible market-based cap and trade approach with zero cost allowance allocations to coal-fired electric generators. The approach should have a properly designed economic safety valve in order to reduce or eliminate extreme price spikes and potential price volatility. A long lead time must be included to align nearer-term technology capabilities and expanded generation efficiency and other enhanced renewable strategies, ensuring that generation sources will rely less on natural gas to meet short term carbon reduction requirements. This new regime should allow for adequate resource and generation planning and remove existing impediments to efficiency enhancements posed by the current New Source Review provisions of the Clean Air Act;

·	Inclusion of incentives for investment in advanced clean coal technology and support for research and development; and

·	A strategy supporting alternative energy technologies and biofuels and increasing the domestic supply of natural gas to reduce dependence on foreign oil and imported natural gas.

Current Initiatives to Increase Conservation and Reduce Emissions

The Company is committed to its policy on climate change and conservation. Evidence of this commitment includes:

·	Focusing the Company’s mission statement and purpose on corporate sustainability and the need to help customers conserve and manage energy costs;

·	Recently executing a 20 year contract to purchase 30MW of wind energy generated by a wind farm in Benton County, Indiana;

·	Evaluating other renewable energy projects to complement base load coal fired generation in advance of mandated renewable energy portfolio standards;

·	Implementing the Conservation Connection initiative in the Company’s Indiana and Ohio gas utility service territories;

·	Participation in an electric conservation and demand side management collaborative with the OUCC and other customer advocate groups;

·	Evaluating potential carbon requirements with regard to new generation, other fuel supply sources, and future environmental compliance plans;

·	Reducing the Company’s carbon footprint by measures such as purchasing hybrid vehicles, and optimizing generation efficiencies;

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Legislative Actions and Other Climate Change Initiatives

Impact of Legislative Actions and Other Initiatives is Unknown

Environmental Remediation Efforts

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Rate and Regulatory Matters

Vectren Energy Delivery of Ohio, Inc. (VEDO) Gas Base Rate Case Filing

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The Stipulation has been filed with the PUCO who will now review and determine whether to approve those elements of the Stipulation before the base rate adjustment can become effective. The PUCO is expected to address the rate design question in the same decision. The Company has proposed, among other alternatives, the use of a straight fixed variable rate design which places all or a most of the fixed cost recovery in the customer service charge. In PUCO decisions in cases involving other Ohio utilities, it has approved such rate design. A straight fixed variable design can mitigate the effects of declining usage, similar to the Company’s current lost margin recovery mechanism, which is set to expire upon receipt of the new order.

The Company expects the PUCO to issue a decision in the fourth quarter of 2008.

Vectren Energy Delivery of Ohio, Inc. Begins Process to Exit the Merchant Function

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

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Vectren South (SIGECO) Electric Base Rate Order Received

Vectren South Gas Base Rate Order Received

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 million and the treatment cannot extend beyond three years on each project.

MISO

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Impact of Recently Issued Accounting Guidance

SFAS 157

On January 1, 2008, the Company adopted SFAS No. 157, “Fair Value Measurements” (SFAS 157), except as it applies to those nonfinancial assets and nonfinancial liabilities. FSP FAS 157-2 delayed the effective date of SFAS 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value on a recurring basis (at least annually). This FSP deferred the effective date of Statement 157 for those items to fiscal years beginning after November 15, 2008.

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 impacts how other fair value based GAAP is applied. The partial adoption of SFAS 157 did not have a material impact on the Company’s financial position, results of operations or cash flows. Disclosures impacted by SFAS 157 are included in Note 14 to the consolidated financial statements. The adoption of the remaining components of SFAS 157 on January 1, 2009 is also not expected to be material on the Company’s financial position, results of operations or cash flows.

SFAS 159

SFAS 141 (Revised 2007)

SFAS 161

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SFAS 162

Financial Condition

Utility Holdings funds the short-term and long-term financing needs of utility operations. Vectren does not guarantee Utility Holdings’ debt. Utility Holdings’ outstanding long-term and short-term borrowing arrangements are jointly and severally guaranteed by Indiana Gas, SIGECO, and VEDO. The guarantees are full and unconditional and joint and several, and Utility Holdings has no subsidiaries other than the subsidiary guarantors. Information about the subsidiary guarantors as a group is included in Note 3 to the condensed consolidated financial statements. Utility Holdings’ long-term and short-term obligations outstanding at September 30, 2008, approximated $824 million and $113 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 been the primary source for Vectren’s common stock dividends.

The credit ratings of the senior unsecured debt of Utility Holdings and Indiana Gas, at September 30, 2008, 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, 2007. A security rating reflects only the view of a rating agency and is not a recommendation to buy, sell, or hold securities. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides circumstances warrant that change. Standard and Poor’s and Moody’s lowest level investment grade rating is BBB- and Baa3, respectively.

The Company’s consolidated equity capitalization objective is 45-55 percent 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 52 percent and 51 percent of long-term capitalization at September 30, 2008, and December 31, 2007, respectively. Long-term capitalization includes long-term debt, including current maturities and debt subject to tender, as well as common shareholder’s equity.

As of September 30, 2008, the Company was in compliance with all financial covenants.

Available Liquidity in Current Credit Conditions

Current credit market conditions in the United States and throughout the global financial system have resulted in substantial volatility in financial markets and the banking system. These and other economic events have severely constrained access to capital and have made it more costly.

As noted below, the Company recently completed permanent financing transactions, including issuing of $125 million in long-term debt and receiving a $125 million capital contribution from Vectren. These transactions have increased the level of unutilized short-term borrowing capacity. To the extent other traditional sources of liquidity are not available, this unutilized short-term debt capacity, when coupled with expected internally generated funds, should provide sufficient liquidity over the next twelve to twenty four months to fund the majority of anticipated capital expenditures, investments, and debt security redemptions.

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Regarding debt redemptions, there are none in 2009 and 2010. However, holders of certain debt instruments have the one-time option to put them to the Company. Debt subject to these put provisions total $80 million in 2009 and $10 million in 2010.

The Company continues to develop plans to issue additional long-term debt over the next twelve to twenty four months, assuming its A-/Baa1 investment grade credit ratings will allow it to access the capital markets, as the need arises. However, it is likely that such long-term debt issued during this period will be more expensive than in recent history. This permanent financing would reduce reliance on unutilized short-term capacity. The Company is developing contingency plans should access to capital become further restricted.

Consolidated Short-Term Borrowing Arrangements

At September 30, 2008, the Company has $520 million of short-term borrowing capacity, of which approximately $407 million is available. Of the $520 million in capacity, $515 million is available through November, 2010.

Credit facilities have historically been used primarily to support access to the commercial paper market. Recently, the Company’s access to longer term commercial paper was significantly reduced as a result of the continued turmoil and volatility in the financial markets. As a result, the Company has met working capital requirements through a combination of A2/P2 commercial paper issuances and draws on its $515 million commercial paper back-up credit facilities.

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. In 2008, new issuances for satisfying requirements associated with these plans has been insignificant to date but are estimated to be approximately $1.5 million for the remainder of 2008.

Potential Uses of Liquidity

Planned Capital Expenditures & Investments

Capital expenditures are estimated at $125 million for the remainder of 2008. The Company continues to assess capital spending in 2009 and beyond given current market conditions.

Historical Sources & Uses of Liquidity

Operating Cash Flow

The Company's primary source of liquidity to fund working capital requirements has been cash generated from operations, which totaled $342.1 million in 2008, compared to $173.1 million in 2007, an increase of $169.0 million.

Net income before non-cash charges of $265.2 million increased $54.6 million, compared to $210.6 million in 2007, and the increase is driven primarily by increased deferred taxes and higher earnings. Working capital changes generated cash of $88.5 million in 2008 compared to cash used of $8.0 million in 2007. The increase in cash from working capital results primarily from proceeds related to VEDO’s exit of the merchant function. VEDO collected approximately $107 million from wholesale suppliers in advance of transferring that natural gas inventory to them on October 1st. The remaining increase in operating cash flow is primarily due to cash collection of previously deferred regulatory assets.

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.

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Cash flow required for financing activities reflects the impact of recently executed long-term financing, increases in common stock dividends, and changes in short-term borrowings. Net requirements for financing activities were $143.1 million. The increase in net requirements for financing activities of $161.3 million during the nine months ended September 30, 2008, reflects the use of increased operating cash flow to repay short-term borrowings.

In 2008, Utility Holdings issued $125 million of senior unsecured securities and received $124.9 million capital contribution from Vectren. Those proceeds were used to refinance certain capital projects originally financed with short-term borrowings. Also, during the first quarter of 2008, the Company mitigated its exposure to auction rate debt markets. These transactions are more fully described below.

Capital Contribution from Vectren

Long-Term Debt Issuance

In March 2008, Utility Holdings issued $125 million in 6.25 percent senior unsecured notes due April 1, 2039 (2039 Notes) at par. The 2039 Notes are guaranteed by Utility Holdings’ three public utilities: SIGECO, Indiana Gas, and VEDO. These guarantees are full and unconditional and joint and several.

Auction Rate Mode Securities

In February 2008, SIGECO provided notice to the current holders of approximately $103 million of tax-exempt auction rate mode long-term debt of its plans to convert that debt from its current auction rate mode into a daily interest rate mode. In March 2008, the debt was tendered at 100 percent of the principal amount plus accrued interest and is shown as a retirement of debt in the consolidated statement of cash flows. During March 2008, SIGECO remarketed approximately $61.8 million of these investments at interest rates that are fixed to maturity, receiving proceeds, net of issuance costs, of approximately $60.0 million. The terms are $22.6 million at 5.15 percent due in 2023, $22.2 million at 5.35 percent due in 2030 and $17.0 million at 5.45 percent due in 2041. The remaining $41.3 million continues to be held in treasury and is expected to be remarketed at some future date.

Investing Cash Flow

Cash flow required for investing activities decreased period over period, using cash of $202.7 million and $212.8 million in the nine months ended September 30, 2008 and 2007, respectively. The decrease is primarily due to slightly lower capital expenditures.

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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 transportation and storage 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 industry, including the 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, and claims, including, but not limited to, such matters involving compliance with state and federal laws and interpretations of these laws.

·	Changes in or additions to federal, state or local legislative requirements, such as changes in or additions to tax laws or rates, environmental laws, including laws governing greenhouse gases, mandates of sources of renewable energy, 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 2007 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 September 30, 2008, there have been no changes to the Company’s internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal controls over financial reporting.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

As of September 30, 2008, 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 September 30, 2008, 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

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 and results of operations. 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.

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ITEM 1A. RISK FACTORS

In addition to those risk factors set forth in Item 1A Risk Factors included in the Utility Holdings 2007 Form 10-K, which are not presented herein, the Company is adding to and highlighting the following risk factors due to the recent market events.

Current levels of market volatility could have adverse impacts.

The capital and credit markets have been experiencing volatility and disruption. If the current levels of market disruption and volatility continue or worsen, there can be no assurance that the Company, or its parent company Vectren, will not experience adverse effects, which may be material. These effects may include, but are not limited to, difficulties in accessing the debt capital markets and the commercial paper market, increased borrowing costs associated with current debt obligations, higher interest rates in future financings, and a smaller potential pool of investors and funding sources. Finally, there is no assurance the Company’s parent, Vectren, will have access to the equity capital markets to obtain financing when necessary or desirable.

A general deterioration in economic conditions may have adverse impacts.

The current economic environment is challenging and uncertain. The consequences of a prolonged recession may include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. Further, the risks associated with industries in which the Company operates and serves become more acute in periods of a slowing economy or slow growth. Economic declines may be accompanied by a decrease in demand for natural gas and electricity. The recent economic downturn may have some negative impact on both gas and electric large customers, including customers in the automotive and ethanol industries. This impact may include tempered growth, significant conservation measures, and perhaps even plant closures. Deteriorating economic conditions may also lead to lower residential and commercial customer counts and thus lower Company revenues. Further, Vectren’s nonutility businesses may also be negatively impacted and those impacts could further adversely affect Utility Holdings ability to access the capital and credit markets.

ITEM 6. EXHIBITS

Exhibits and Certifications

Exhibits

12. Ratio of Earnings to Fixed Charges

Certifications

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

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

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

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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




November 7, 2008	/s/Jerome A. Benkert, Jr.
	Jerome A. Benkert, Jr.
	Executive Vice President and
	Chief Financial Officer
	(Principal Financial Officer)



	/s/M. Susan Hardwick
	M. Susan Hardwick
	Vice President, Controller and Assistant Treasurer
	(Principal Accounting Officer)