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 June 30, 2011

[_]	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, IN 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. xYes □ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

x Yes □ 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 x (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 xNo

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

Common Stock- Without Par Value	10	July 31, 2011
Class	Number of Shares	Date

Access to Information

Vectren Corporation makes available all SEC filings and recent annual reports, including those of its wholly owned subsidiaries, free of charge through its website at www.vectren.com as soon as reasonably practicable after electronically filing or furnishing the reports to the SEC, 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:

Robert L. Goocher

Treasurer and Vice President, Investor Relations

rgoocher@vectren.com

Definitions

AFUDC: allowance for funds used during construction	MW: megawatts
FASB: Financial Accounting Standards Board	MWh / GWh: megawatt hours / thousands of megawatt hours (gigawatt hours)
FERC: Federal Energy Regulatory Commission	OCC: Ohio Office of the Consumer Counselor
IDEM: Indiana Department of Environmental Management	OUCC: Indiana Office of the Utility Consumer Counselor
IURC: Indiana Utility Regulatory Commission	PUCO: Public Utilities Commission of Ohio
MCF / BCF: thousands / billions of cubic feet	USEPA: United States Environmental Protection Agency
MDth / MMDth: thousands / millions of dekatherms	Throughput: combined gas sales and gas transportation volumes
MISO: Midwest Independent System Operator	XBRL: eXtensible Business Reporting Language
MMBTU: millions of British thermal units

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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 Financial Condition and Results of Operations	22
3	Quantitative and Qualitative Disclosures About Market Risk	35
4	Controls and Procedures	35

	PART II. OTHER INFORMATION
1	Legal Proceedings	35
1A	Risk Factors	35
6	Exhibits	36
	Signatures	36

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited – In millions)


	June 30,		December 31,
	2011		2010
ASSETS
Current Assets
Cash & cash equivalents	$	13.3	$	2.4
Accounts receivable - less reserves of $6.9 & $4.5, respectively		68.4		106.7
Receivables due from other Vectren companies		0.2		0.1
Accrued unbilled revenues		38.3		127.8
Inventories		119.4		135.2
Recoverable fuel & natural gas costs		9.2		7.9
Prepayments & other current assets		50.2		83.4
Total current assets		299.0		463.5

Utility Plant
Original cost		4,890.0		4,791.7
Less: accumulated depreciation & amortization		1,897.3		1,836.3
Net utility plant		2,992.7		2,955.4

Investments in unconsolidated affiliates		0.2		0.2
Other investments		33.3		31.3
Nonutility plant - net		161.1		167.2
Goodwill - net		205.0		205.0
Regulatory assets		80.8		96.9
Other assets		3.5		5.0
TOTAL ASSETS	$	3,775.6	$	3,924.5

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

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VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited – In millions)


	June 30,		December 31,
	2011		2010
LIABILITIES & SHAREHOLDER'S EQUITY

Current Liabilities
Accounts payable	$	54.1	$	126.0
Accounts payable to affiliated companies		27.6		59.3
Payables to other Vectren companies		32.8		48.7
Accrued liabilities		135.3		135.9
Short-term borrowings		-		47.0
Current maturities of long-term debt		100.0		250.0
Long-term debt subject to tender		30.0		30.0
Total current liabilities		379.8		696.9

Long-Term Debt - Net of Current Maturities & Debt Subject to Tender		1,174.5		1,024.8
Deferred Income Taxes & Other Liabilities
Deferred income taxes		492.1		474.7
Regulatory liabilities		337.5		333.5
Deferred credits & other liabilities		57.3		79.2
Total deferred credits & other liabilities		886.9		887.4
Commitments & Contingencies (Notes 8 - 10)

Common Shareholder's Equity
Common stock (no par value)		774.6		774.6
Retained earnings		559.8		540.7
Accumulated other comprehensive income		-		0.1
Total common shareholder's equity		1,334.4		1,315.4

TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,775.6	$	3,924.5

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

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VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited – In millions)


	Three Months				Six Months
	Ended June 30,				Ended June 30,
	2011		2010		2011		2010
OPERATING REVENUES
Gas utility	$	134.0	$	122.9	$	490.7	$	591.0
Electric utility		159.3		151.0		305.7		295.9
Other		0.5		0.4		1.0		0.8
Total operating revenues		293.8		274.3		797.4		887.7

OPERATING EXPENSES
Cost of gas sold		48.8		41.5		243.9		339.3
Cost of fuel & purchased power		60.3		57.8		119.8		115.8
Other operating		78.2		71.2		165.1		152.8
Depreciation & amortization		47.9		46.8		96.1		93.3
Taxes other than income taxes		11.1		11.6		29.1		33.9
Total operating expenses		246.3		228.9		654.0		735.1

OPERATING INCOME		47.5		45.4		143.4		152.6

Other income - net		2.2		0.8		3.9		3.0

Interest expense		20.4		20.3		40.8		40.6

INCOME BEFORE INCOME TAXES		29.3		25.9		106.5		115.0

Income taxes		13.0		9.7		41.6		43.4

NET INCOME	$	16.3	$	16.2	$	64.9	$	71.6

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

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VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited – In millions)


	Six Months Ended June 30,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	64.9		$	71.6
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization		96.1			93.3
Deferred income taxes & investment tax credits		28.2			18.7
Expense portion of pension & postretirement periodic benefit cost		2.3			2.0
Provision for uncollectible accounts		7.1			9.9
Other non-cash expense - net		4.3			6.8
Changes in working capital accounts:
Accounts receivable, including to Vectren companies & accrued unbilled revenue		120.6			105.6
Inventories		15.8			4.5
Recoverable/refundable fuel & natural gas costs		(1.3	)		(24.2	)
Prepayments & other current assets		37.1			7.7
Accounts payable, including to Vectren companies & affiliated companies		(120.8	)		(127.1	)
Accrued liabilities		(0.2	)		8.5
Changes in noncurrent assets		(3.9	)		7.4
Changes in noncurrent liabilities		(32.6	)		(12.8	)
Net cash flows from operating activities		217.6			171.9
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Additional capital contribution		-			3.1
Requirements for:
Dividends to parent		(45.8	)		(39.5	)
Retirement of long-term debt		(0.5	)		(1.3	)
Net change in short-term borrowings, including from other Vectren companies		(47.0	)		(16.4	)
Net cash flows from financing activities		(93.3	)		(54.1	)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from other investing activities		0.3			2.9
Requirements for:
Capital expenditures, excluding AFUDC equity		(112.4	)		(111.4	)
Other investments		(1.3	)		(1.1	)
Net cash flows from investing activities		(113.4	)		(109.6	)
Net change in cash & cash equivalents		10.9			8.2
Cash & cash equivalents at beginning of period		2.4			6.2
Cash & cash equivalents at end of period	$	13.3		$	14.4

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

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VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1.	Organization & Nature of Operations

Vectren Utility Holdings, Inc. (the Company or Utility Holdings), an Indiana corporation, was formed on March 31, 2000 to serve 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, an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana and was organized on June 10, 1999. Both 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 approximately 565,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 141,000 electric customers and approximately 110,000 gas customers located near Evansville in southwestern Indiana. SIGECO also owns and operates electric generation assets 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 over 312,000 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 and include a review of subsequent events through the date the financial statements were issued. 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 information in this report reflects all adjustments which are, in the opinion of management, necessary to fairly state the interim periods presented, inclusive of adjustments that are normal and recurring in nature. 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, 2010, filed with the Securities and Exchange Commission on March 4, 2011, 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’ $350 million in short-term credit facilities, of which none is outstanding at June 30, 2011, and Utility Holdings’ $918 million unsecured senior notes outstanding at June 30, 2011. 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 Item 3-10 of Regulation S-X, disclosure of the results of operations and balance sheets of the subsidiary guarantors, which are 100 percent owned, 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. Pursuant to a tax sharing agreement, consolidating tax effects, which are calculated on a separate return basis, are reflected at the parent level.

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Condensed Consolidating Balance Sheet as of June 30, 2011 (in millions):



ASSETS	Subsidiary		Parent			Eliminations &
	Guarantors		Company			Reclassifications			Consolidated
Current Assets
Cash & cash equivalents	$	2.1	$	11.2		$	-		$	13.3
Accounts receivable - less reserves		68.4		-			-			68.4
Intercompany receivables		50.8		324.5			(375.3	)		-
Receivables due from other Vectren companies		-		0.2			-			0.2
Accrued unbilled revenues		38.3		-			-			38.3
Inventories		119.3		0.1			-			119.4
Recoverable fuel & natural gas costs		9.2		-			-			9.2
Prepayments & other current assets		50.4		4.0			(4.2	)		50.2
Total current assets		338.5		340.0			(379.5	)		299.0
Utility Plant
Original cost		4,890.0		-			-			4,890.0
Less: accumulated depreciation & amortization		1,897.3		-			-			1,897.3
Net utility plant		2,992.7		-			-			2,992.7
Investments in consolidated subsidiaries		-		1,257.5			(1,257.5	)		-
Notes receivable from consolidated subsidiaries		-		520.8			(520.8	)		-
Investments in unconsolidated affiliates		0.2		-			-			0.2
Other investments		28.2		5.1			-			33.3
Nonutility property - net		3.4		157.7			-			161.1
Goodwill - net		205.0		-			-			205.0
Regulatory assets		58.2		22.6			-			80.8
Other assets		42.2		3.4			(42.1	)		3.5
TOTAL ASSETS	$	3,668.4	$	2,307.1		$	(2,199.9	)	$	3,775.6

LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent			Eliminations &
	Guarantors		Company			Reclassifications			Consolidated
Current Liabilities
Accounts payable	$	51.2	$	2.9		$	-		$	54.1
Accounts payable to affiliated companies		27.6		-			-			27.6
Intercompany payables		17.7		0.7			(18.4	)		-
Payables to other Vectren companies		32.8		-			-			32.8
Accrued liabilities		122.0		17.4			(4.1	)		135.3
Intercompany short-term borrowings		59.4		50.0			(109.4	)		-
Current maturities of long-term debt		-		100.0			-			100.0
Current maturities of intercompany long-term debt		247.4		-			(247.4	)		-
Long-term debt subject to tender		30.0		-			-			30.0
Total current liabilities		588.1		171.0			(379.3	)		379.8
Long-Term Debt
Long-term debt - net of current maturities & debt subject to tender		357.1		817.4			-			1,174.5
Long-term debt due to VUHI		520.8		-			(520.8	)		-
Total long-term debt - net		877.9		817.4			(520.8	)		1,174.5
Deferred Income Taxes & Other Liabilities
Deferred income taxes		512.4		(20.3	)		-			492.1
Regulatory liabilities		334.6		2.9			-			337.5
Deferred credits & other liabilities		97.9		1.7			(42.3	)		57.3
Total deferred credits & other liabilities		944.9		(15.7	)		(42.3	)		886.9
Common Shareholder's Equity
Common stock (no par value)		787.8		774.6			(787.8	)		774.6
Retained earnings		469.7		559.8			(469.7	)		559.8
Total common shareholder's equity		1,257.5		1,334.4			(1,257.5	)		1,334.4
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,668.4	$	2,307.1		$	(2,199.9	)	$	3,775.6

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Condensed Consolidating Balance Sheet as of December 31, 2010 (in millions):


ASSETS	Subsidiary		Parent			Eliminations &
	Guarantors		Company			Reclassifications			Consolidated
Current Assets
Cash & cash equivalents	$	2.0	$	0.4		$	-		$	2.4
Accounts receivable - less reserves		106.7		-			-			106.7
Intercompany receivables		65.9		162.2			(228.1	)		-
Receivables due from other Vectren companies		0.1		-			-			0.1
Accrued unbilled revenues		127.8		-			-			127.8
Inventories		135.2		-			-			135.2
Recoverable fuel & natural gas costs		7.9		-			-			7.9
Prepayments & other current assets		97.2		2.4			(16.2	)		83.4
Total current assets		542.8		165.0			(244.3	)		463.5
Utility Plant
Original cost		4,791.7		-			-			4,791.7
Less: accumulated depreciation & amortization		1,836.3		-			-			1,836.3
Net utility plant		2,955.4		-			-			2,955.4
Investments in consolidated subsidiaries		-		1,239.1			(1,239.1	)		-
Notes receivable from consolidated subsidiaries		-		768.7			(768.7	)		-
Investments in unconsolidated affiliates		0.2		-			-			0.2
Other investments		26.1		5.2			-			31.3
Nonutility property - net		3.7		163.5			-			167.2
Goodwill - net		205.0		-			-			205.0
Regulatory assets		73.7		23.2			-			96.9
Other assets		21.5		1.7			(18.2	)		5.0
TOTAL ASSETS	$	3,828.4	$	2,366.4		$	(2,270.3	)	$	3,924.5

LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent			Eliminations &
	Guarantors		Company			Reclassifications			Consolidated
Current Liabilities
Accounts payable	$	116.0	$	10.0		$	-		$	126.0
Accounts payable to affiliated companies		59.3		-			-			59.3
Intercompany payables		16.9		-			(16.9	)		-
Payables to other Vectren companies		48.7		-			-			48.7
Accrued liabilities		124.3		27.8			(16.2	)		135.9
Short-term borrowings		-		47.0			-			47.0
Intercompany short-term borrowings		145.1		65.9			(211.0	)		-
Current maturities of long-term debt		-		250.0			-			250.0
Long-term debt subject to tender		30.0		-			-			30.0
Total current liabilities		540.3		400.7			(244.1	)		696.9
Long-Term Debt
Long-term debt - net of current maturities & debt subject to tender		357.1		667.7			-			1,024.8
Long-term debt due to VUHI		768.7		-			(768.7	)		-
Total long-term debt - net		1,125.8		667.7			(768.7	)		1,024.8
Deferred Income Taxes & Other Liabilities
Deferred income taxes		496.9		(22.1	)		(0.1	)		474.7
Regulatory liabilities		330.2		3.3			-			333.5
Deferred credits & other liabilities		96.1		1.4			(18.3	)		79.2
Total deferred credits & other liabilities		923.2		(17.4	)		(18.4	)		887.4
Common Shareholder's Equity
Common stock (no par value)		787.8		774.6			(787.8	)		774.6
Retained earnings		451.2		540.7			(451.2	)		540.7
Accumulated other comprehensive income		0.1		0.1			(0.1	)		0.1
Total common shareholder's equity		1,239.1		1,315.4			(1,239.1	)		1,315.4
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,828.4	$	2,366.4		$	(2,270.3	)	$	3,924.5

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Condensed Consolidating Statement of Income for the three months ended June 30, 2011 (in millions):


	Subsidiary		Parent		Eliminations &
	Guarantors		Company		Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	134.0	$	-	$	-		$	134.0
Electric utility		159.3		-		-			159.3
Other		-		11.0		(10.5	)		0.5
Total operating revenues		293.3		11.0		(10.5	)		293.8
OPERATING EXPENSES
Cost of gas sold		48.8		-		-			48.8
Cost of fuel & purchased power		60.3		-		-			60.3
Other operating		88.7		-		(10.5	)		78.2
Depreciation & amortization		40.9		6.8		0.2			47.9
Taxes other than income taxes		10.8		0.3		-			11.1
Total operating expenses		249.5		7.1		(10.3	)		246.3
OPERATING INCOME		43.8		3.9		(0.2	)		47.5
OTHER INCOME (EXPENSE)
Equity in earnings of consolidated companies		-		15.7		(15.7	)		-
Other – net		1.8		12.7		(12.3	)		2.2
Total other income (expense)		1.8		28.4		(28.0	)		2.2

Interest expense		18.8		14.1		(12.5	)		20.4

INCOME BEFORE INCOME TAXES		26.8		18.2		(15.7	)		29.3

Income taxes		11.1		1.9		-			13.0

NET INCOME	$	15.7	$	16.3	$	(15.7	)	$	16.3

Condensed Consolidating Statement of Income for the three months ended June 30, 2010 (in millions):


	Subsidiary		Parent		Eliminations &
	Guarantors		Company		Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	122.9	$	-	$	-		$	122.9
Electric utility		151.0		-		-			151.0
Other		-		11.1		(10.7	)		0.4
Total operating revenues		273.9		11.1		(10.7	)		274.3
OPERATING EXPENSES
Cost of gas		41.5		-		-			41.5
Cost of fuel & purchased power		57.8		-		-			57.8
Other operating		81.8		-		(10.6	)		71.2
Depreciation & amortization		40.1		6.6		0.1			46.8
Taxes other than income taxes		11.3		0.3		-			11.6
Total operating expenses		232.5		6.9		(10.5	)		228.9
OPERATING INCOME		41.4		4.2		(0.2	)		45.4
OTHER INCOME - NET
Equity in earnings of consolidated companies		-		14.4		(14.4	)		-
Other income – net		0.5		12.7		(12.4	)		0.8
Total other income - net		0.5		27.1		(26.8	)		0.8

Interest expense		18.7		14.2		(12.6	)		20.3

INCOME BEFORE INCOME TAXES		23.2		17.1		(14.4	)		25.9

Income taxes		8.8		0.9		-			9.7

NET INCOME	$	14.4	$	16.2	$	(14.4	)	$	16.2

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Condensed Consolidating Statement of Income for the six months ended June 30, 2011 (in millions):


	Subsidiary		Parent		Eliminations &
	Guarantors		Company		Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	490.7	$	-	$	-		$	490.7
Electric utility		305.7		-		-			305.7
Other		-		21.9		(20.9	)		1.0
Total operating revenues		796.4		21.9		(20.9	)		797.4
OPERATING EXPENSES
Cost of gas sold		243.9		-		-			243.9
Cost of fuel & purchased power		119.8		-		-			119.8
Other operating		186.0		-		(20.9	)		165.1
Depreciation & amortization		82.3		13.5		0.3			96.1
Taxes other than income taxes		28.3		0.7		0.1			29.1
Total operating expenses		660.3		14.2		(20.5	)		654.0
OPERATING INCOME		136.1		7.7		(0.4	)		143.4
OTHER INCOME (EXPENSE)
Equity in earnings of consolidated companies		-		60.7		(60.7	)		-
Other – net		3.3		25.5		(24.9	)		3.9
Total other income (expense)		3.3		86.2		(85.6	)		3.9

Interest expense		37.7		28.4		(25.3	)		40.8

INCOME BEFORE INCOME TAXES		101.7		65.5		(60.7	)		106.5

Income taxes		41.0		0.6		-			41.6

NET INCOME	$	60.7	$	64.9	$	(60.7	)	$	64.9

Condensed Consolidating Statement of Income for the six months ended June 30, 2010 (in millions):


	Subsidiary		Parent		Eliminations &
	Guarantors		Company		Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	591.0	$	-	$	-		$	591.0
Electric utility		295.9		-		-			295.9
Other		-		22.2		(21.4	)		0.8
Total operating revenues		886.9		22.2		(21.4	)		887.7
OPERATING EXPENSES
Cost of gas		339.3		-		-			339.3
Cost of fuel & purchased power		115.8		-		-			115.8
Other operating		174.0		-		(21.2	)		152.8
Depreciation & amortization		79.9		13.3		0.1			93.3
Taxes other than income taxes		33.1		0.8		-			33.9
Total operating expenses		742.1		14.1		(21.1	)		735.1
OPERATING INCOME		144.8		8.1		(0.3	)		152.6
OTHER INCOME - NET
Equity in earnings of consolidated companies		-		66.6		(66.6	)		-
Other income – net		2.5		25.5		(25.0	)		3.0
Total other income - net		2.5		92.1		(91.6	)		3.0

Interest expense		37.5		28.4		(25.3	)		40.6

INCOME BEFORE INCOME TAXES		109.8		71.8		(66.6	)		115.0

Income taxes		43.2		0.2		-			43.4

NET INCOME	$	66.6	$	71.6	$	(66.6	)	$	71.6

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Condensed Consolidating Statement of Cash Flows for the six months ended June 30, 2011 (in millions):


	Subsidiary			Parent
	Guarantors			Company			Eliminations			Consolidated
NET CASH FLOWS FROM OPERATING ACTIVITIES	$	218.7		$	(1.1	)	$	-		$	217.6
CASH FLOWS FROM FINANCING ACTIVITIES
Requirements for:
Dividends to parent		(42.2	)		(45.8	)		42.2			(45.8	)
Retirement of long-term debt, including premiums paid		(0.5	)		(0.5	)		0.5			(0.5	)
Net change in intercompany short-term borrowings		(85.7	)		(15.9	)		101.6			-
Net change in short-term borrowings		-			(47.0	)		-			(47.0	)
Net cash flows from financing activities		(128.4	)		(109.2	)		144.3			(93.3	)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from
Consolidated subsidiary distributions		-			42.2			(42.2	)		-
Other investing activities		0.2			0.1			-			0.3
Requirements for:
Capital expenditures, excluding AFUDC equity		(105.0	)		(7.4	)		-			(112.4	)
Other investing activities		(1.3	)		-			-			(1.3	)
Net change in long-term intercompany notes receivable		-			0.5			(0.5	)		-
Net change in short-term intercompany notes receivable		15.9			85.7			(101.6	)		-
Net cash flows from investing activities		(90.2	)		121.1			(144.3	)		(113.4	)
Net change in cash & cash equivalents		0.1			10.8			-			10.9
Cash & cash equivalents at beginning of period		2.0			0.4			-			2.4
Cash & cash equivalents at end of period	$	2.1		$	11.2		$	-		$	13.3

Condensed Consolidating Statement of Cash Flows for the six months ended June 30, 2010 (in millions):


	Subsidiary			Parent
	Guarantors			Company			Eliminations			Consolidated
NET CASH FLOWS FROM OPERATING ACTIVITIES	$	140.9		$	31.0		$	-		$	171.9
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from additional capital contribution from parent		3.1			3.1			(3.1	)		3.1
Requirements for:
Dividends to parent		(39.5	)		(39.5	)		39.5			(39.5	)
Retirement of long-term debt, including premiums paid		(1.3	)		(1.3	)		1.3			(1.3	)
Net change in intercompany short-term borrowings		(23.0	)		(18.7	)		41.7			-
Net change in short-term borrowings		-			(16.4	)		-			(16.4	)
Net cash flows from financing activities		(60.7	)		(72.8	)		79.4			(54.1	)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from
Consolidated subsidiary distributions		-			39.5			(39.5	)		-
Other investing activities		2.8			0.1			-			2.9
Requirements for:
Capital expenditures, excluding AFUDC equity		(101.9	)		(9.5	)		-			(111.4	)
Consolidated subsidiary investments		-			(3.1	)		3.1			-
Other investing activities		(1.1	)		-			-			(1.1	)
Net change in long-term intercompany notes receivable		-			1.3			(1.3	)		-
Net change in short-term intercompany notes receivable		18.7			23.0			(41.7	)		-
Net cash flows from investing activities		(81.5	)		51.3			(79.4	)		(109.6	)
Net change in cash & cash equivalents		(1.3	)		9.5			-			8.2
Cash & cash equivalents at beginning of period		5.6			0.6			-			6.2
Cash & cash equivalents at end of period	$	4.3		$	10.1		$	-		$	14.4

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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 $5.4 million and $5.0 million in the three months ended June 30, 2011 and 2010 respectively. For the six months ended June 30, 2011 and 2010, these taxes totaled $16.4 million and $20.2 million, respectively. Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.

5.	Accruals for Utility & Nonutility Plant

As of June 30, 2011 and December 31, 2010, the Company has accruals related to utility and nonutility plant purchases totaling approximately $13.0 million and $11.1 million, respectively.

6.	Transactions with Other Vectren Companies and Affiliates

Vectren Fuels, Inc.

Vectren Fuels, Inc., a wholly owned subsidiary of Vectren, owns coal mines from which SIGECO purchases coal used for electric generation. The price of coal that is charged by Vectren Fuels to SIGECO is priced consistent with contracts reviewed by the OUCC and on file with the IURC. Amounts purchased for the three months ended June 30, 2011 and 2010 totaled $42.5 million and $39.2 million, respectively, and for the six months ended June 30, 2011 and 2010 totaled $75.8 and $82.7 million, respectively. Amounts owed to Vectren Fuels at June 30, 2011 and December 31, 2010 are included in Payables to other Vectren companies.

Miller Pipeline, LLC

Miller Pipeline, LLC (Miller), a wholly owned subsidiary of Vectren, 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. Fees incurred by Utility Holdings and its subsidiaries totaled $8.6 million and $7.0 million for the three months ended June 30, 2011 and 2010, respectively, and for the six months ended June 30, 2011 and 2010 totaled $13.2 million and $11.3 million, respectively. Amounts owed to Miller at June 30, 2011 and December 31, 2010 are included in Payables to other Vectren companies.

Vectren Source

Vectren Source, a nonutility wholly owned subsidiary of Vectren, provides natural gas and other related products and services in the Midwest and Northeast United States to approximately 258,000 equivalent residential and commercial customers. This customer count reflects nearly 140,000 customers in VEDO’s service territory that have either voluntarily opted to choose their natural gas supplier or are supplied natural gas by Vectren Source but remain customers of the regulated utility as part of VEDO’s exit the merchant function process. Since January 2010, Vectren Source has sold gas commodity directly to customers in VEDO’s service territory and VEDO purchases receivables from Vectren Source to include those sales in one customer bill similar to the receivables purchased from Vectren Source related to customers that voluntarily chose Vectren Source as their supplier. As a result of a supplier choice auction held on January 18, 2011 in VEDO’s service territory, Vectren Source increased its customer base by 28,000 in second quarter of 2011. Total receivables purchased from Vectren Source in the three months ended June 30, 2011 and 2010, totaled $10.3 million and $6.6 million, respectively, and for the six months ended June 30, 2011 and 2010 totaled $41.3 million and $31.7 million, respectively.

As part of VEDO’s initial phase of exiting the merchant function which ended on March 31, 2010, the Company purchased natural gas from Vectren Source. Such purchases totaled $14.1 million during the six months ended June 30, 2010. Purchases subsequent to March 31, 2010 have been insignificant. Amounts charged by Vectren Source for gas supply services is comprised of the monthly NYMEX settlement price plus a fixed adder, as authorized by the PUCO. Amounts owed to Vectren Source at June 30, 2011 and December 31, 2010 are included in Payables to other Vectren companies.

ProLiance Holdings, LLC (ProLiance)

ProLiance, a nonutility energy marketing affiliate of Vectren and Citizens Energy Group (Citizens), 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 nonutility gas supply operations as well as Citizens’ utilities. ProLiance’s primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services. Vectren received regulatory approval on April 25, 2006, from the IURC for ProLiance to provide natural gas supply services to the Company’s Indiana utilities through March 2011. On March 17, 2011, an order was received by the IURC providing for ProLiance’s continued provision of gas supply services to the Company’s Indiana utilities and Citizens Energy Group through March 2016.

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Purchases from ProLiance for resale and for injections into storage for the three months ended June 30, 2011 and 2010 totaled $79.0 million and $76.4 million, respectively, and for the six months ended June 30, 2011 and 2010 totaled $198.3 million and $233.8 million, respectively. Amounts owed to ProLiance at June 30, 2011 and December 31, 2010 for those purchases were $27.6 million and $59.3 million, respectively, and are included in Accounts payable to affiliated companies in the Consolidated Balance Sheets. Amounts charged by ProLiance for gas supply services are established by supply agreements with each utility.

Support Services & 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 at cost. For the three months ended June 30, 2011 and 2010, Utility Holdings received corporate allocations totaling $12.4 million and $11.5 million, respectively. For the six months ending June 30, 2011 and 2010, Utility Holdings received corporate allocations totaling $26.2 million and $24.5 million, respectively.

7.	Financing Activities

On April 5, 2011, the Company entered into a private placement note purchase agreement pursuant to which various institutional investors have agreed to purchase the following tranches of notes: (i) $55 million of 4.67 percent Senior Guaranteed Notes, due November 30, 2021, (ii) $60 million of 5.02 percent Senior Guaranteed Notes, due November 30, 2026, and (iii) $35 million of 5.99 percent Senior Guaranteed Notes, due December 2, 2041. The proceeds received from the issuance of these senior notes will be used to partially refinance $250 million of long-term debt maturing December 1, 2011. The remainder of the maturing debt will be retired with short-term borrowings. These senior notes are unsecured and will be jointly and severally guaranteed by the Company’s regulated utility subsidiaries, Southern Indiana Gas and Electric Company, Indiana Gas Company, Inc., and Vectren Energy Delivery of Ohio, Inc. Subject to the satisfaction of customary conditions precedent, this financing is scheduled to close on or about November 30, 2011. The Company has reclassified $150 million of the $250 million debt redemption due in December 2011 to long-term debt in its June 30, 2011 Consolidated Balance Sheet to reflect the Company’s ability and intent to refinance that portion of the debt with this issuance.

8.	Commitments & Contingencies

The Company is party to various legal proceedings, audits, and reviews by taxing authorities and other government agencies arising in the normal course of business. In the opinion of management, there are no legal proceedings or other regulatory reviews or audits pending against the Company that are likely to have a material adverse effect on its financial position, results of operations or cash flows.

9.	Legislative & Environmental Matters

Indiana House Bill 1004

In May 2011, House Bill 1004 was signed into law. This legislation phases in over four years a two percent rate reduction to the Indiana Adjusted Gross Income Tax for corporations. Pursuant to House Bill 1004, the tax rate will be lowered by one-half percent each year beginning on July 1, 2012, to the final rate of six and one-half percent effective July 1, 2015. Pursuant to FASB guidance, the Company accounted for the effect of the change in tax law on its deferred taxes in the second quarter of 2011, the period of enactment. The impact was not material to results of operations.

Indiana Senate Bill 251

In April 2011, Senate Bill 251 was signed into law. While the bill is broad in scope, it allows for cost recovery outside of a base rate proceeding for federal government mandated projects and provides for a voluntary clean energy portfolio standard.

The legislation establishes a voluntary clean energy portfolio standard that provides incentives to electricity suppliers participating in the program. The goal of the program is that by 2025, at least 10 percent of the total electricity obtained by the supplier to meet the energy needs of its Indiana retail customers will be provided by clean energy sources, as defined. The financial incentives include an enhanced return on equity and tracking mechanisms to recover program costs. In advance of a federal portfolio standard and Senate Bill 251, SIGECO received regulatory approval to purchase a 3 MW landfill gas generation facility from a related entity. The facility was purchased in 2009 and is directly connected to the Company’s distribution system. In 2009, the Company also executed a long term purchase power commitment for 50 MW of wind energy. These transactions supplement a 30 MW wind energy purchase power agreement executed in 2008. The Company believes that SIGECO, as a result of these actions, is already at approximately 5 percent compared to the 10 percent 2025 goal.

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As it relates to the implementation of federal mandates, the law applies to both gas and electric utility operations and provides a framework to recover 80 percent of federally mandated costs through a periodic rate adjustment mechanism outside of a base rate increase. Such costs include construction, depreciation, operating and other costs. The remaining 20 percent of those costs are to be deferred until the utility’s next general rate case. Therefore, for qualifying expenditures, there is reasonable certainty of timely cost recovery ahead of base rate cases. The Company is currently evaluating the impact this law may have on its operations, including applicability to expenditures associated with the integrity, safety, and reliable operation of natural gas pipelines and facilities; ash disposal; water regulations; and air pollution, including greenhouse gas emissions, among other federally mandated projects and potential projects.

Ohio House Bill 95

Ohio House Bill 95 was recently signed into law. The law adjusts, among other things, the manner in which gas utilities file for rate changes, including the implementation of base rate changes, alternative rate plans, and automatic rate adjustment mechanisms. Outside of a base rate proceeding, the legislation permits a natural gas company to apply to implement a capital expenditure program for infrastructure expansion, upgrade, or replacement; installation, upgrade, or replacement of information technology systems; or any program necessary to comply with government regulation. Once such application is approved, the legislation authorizes recovery or deferral of program costs, such as depreciation, property taxes, and carrying costs. The Company is assessing the impact this legislation may have on its operations.

Clean Air Act

To comply with Indiana’s implementation plan of the Clean Air Act of 1990, Clean Air Interstate Regulations (CAIR), and regulation of mercury, SIGECO obtained IURC authority to invest in clean coal technology. Using this authorization, SIGECO has invested approximately $411 million starting in 2001 with the last equipment being placed into service on January 1, 2010. The pollution control equipment includes Selective Catalytic Reduction (SCR) systems, fabric filters, and an SO2 scrubber at its generating facility that is jointly owned with ALCOA (the Company’s portion is 150 MW). SCR technology is the most effective method of reducing NOx emissions where high removal efficiencies are required and fabric filters control particulate matter emissions. The unamortized portion of the $411 million clean coal technology investment was included in rate base for purposes of determining SIGECO’s new electric base rates approved in the latest base rate order recently obtained April 27, 2011. SIGECO’s coal fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOx.

CAIR is an allowance cap and trade program instituted in 2005 that required reductions from coal-burning power plants for NOx emissions beginning January 1, 2009 and SO2 emissions beginning January 1, 2010. On July 11, 2008, the US Court of Appeals for the District of Columbia vacated the federal CAIR regulations. Various parties filed motions for reconsideration, and on December 23, 2008, the Court reinstated the CAIR regulations and remanded the regulations back to the EPA for promulgation of revisions in accordance with the Court’s July 11, 2008 order. Thus, the original version of CAIR promulgated in March of 2005 remains effective while EPA revised it per the Court’s guidance. SIGECO is in compliance with the current CAIR Phase I annual NOx reduction requirements in effect on January 1, 2009, and the Phase I annual SO2 reduction requirements in effect on January 1, 2010.

Similarly, in March of 2005, EPA promulgated the Clean Air Mercury Rule (CAMR). CAMR is an allowance cap and trade program requiring further reductions in mercury emissions from coal-burning power plants. The CAMR regulations were vacated by the US Court of Appeals for the DC Circuit in July 2008. In response to the court decision, EPA announced that it intended to publish proposed Maximum Achievable Control Technology standards for mercury in 2011. In March 2011, the EPA released its proposed Hazardous Air Pollutants (HAPs) rule for the reduction of mercury, non-mercury particulate and acid gases. Based on initial review of the proposed regulation, the Company believes that it will be able to meet these new stringent emission reduction limits with its existing suite of pollution control equipment.

On July 7, 2011, the EPA finalized its revisions to CAIR, renamed the Cross State Air Pollution Rule. The rule finalizes the previously proposed 71 percent reduction of SO2 emissions compared to 2005 national levels and a 52 percent reduction of NOx emissions compared to 2005 national levels. These reductions are to be achieved with initial step reductions beginning in 2012 with final compliance to be achieved in 2014. Based upon an initial review of the final rule, the Company believes that it will be able to meet these requirements with its existing suite of pollution control equipment and the anticipated allotment of new emission allowances. However, it is possible some minor modifications to the control equipment will be required.

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Climate Change

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 EPA to determine whether greenhouse gas emissions from motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. In April of 2009, the EPA published its proposed endangerment finding for public comment. The proposed endangerment finding concludes that carbon emissions from mobile sources pose an endangerment to public health and the environment. The endangerment finding was finalized in December of 2009, and is the first step toward EPA regulating carbon emissions through the existing Clean Air Act in the absence of specific carbon legislation from Congress. Therefore, any new regulations would likely also impact major stationary sources of greenhouse gases. The EPA has promulgated two greenhouse gas regulations that apply to SIGECO’s generating facilities. In 2009, the EPA finalized a mandatory greenhouse gas emissions registry which will require reporting of emissions beginning in 2011 (for the emission year 2010). The EPA has also recently finalized a revision to the Prevention of Significant Deterioration (PSD) and Title V permitting rules which would require facilities that emit 75,000 tons or more of greenhouse gases a year to obtain a PSD permit for new construction or a significant modification of an existing facility.

Numerous competing federal legislative proposals have also been introduced in recent years that involve carbon, energy efficiency, and renewable energy. Comprehensive energy legislation at the federal level continues to be debated, but there has been little progress to date. The progression of regional initiatives throughout the United States has also slowed.

Impact of Legislative Actions & Other Initiatives is Unknown

If regulations are enacted by the EPA or other agencies or 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 and natural gas distribution businesses. 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 control greenhouse gas emissions. A preliminary investigation demonstrated costs to comply would be significant, first with regard to operating expenses and later for capital expenditures as technology becomes available to control greenhouse gas emissions. However, these compliance cost estimates are based on highly uncertain assumptions, including allowance prices if a cap and trade approach were employed, and energy efficiency targets. Costs to purchase allowances that cap greenhouse gas emissions or expenditures made to control emissions should be considered a cost of providing electricity, and as such, the Company believes such costs and expenditures would be recoverable from customers through Senate Bill 251. Customer rates may also be impacted should decisions be made to reduce the level of sales to municipal and other wholesale customers in order to meet emission targets.

Ash Ponds & Coal Ash Disposal Regulations

In June 2010, the EPA issued proposed regulations affecting the management and disposal of coal combustion products, such as ash generated by the Company’s coal-fired power plants. The proposed rules more stringently regulate these byproducts and would likely increase the cost of operating or expanding existing ash ponds and the development of new ash ponds. The EPA did not offer a preferred alternative, but is taking public comment on multiple alternative regulations. The Company estimates capital expenditures to comply could be as much as $30 million, and such expenditures could exceed $100 million if the most stringent of the alternatives is selected. Annual compliance costs could increase slightly or be impacted by as much as $5 million. The alternatives include regulating coal combustion by-products as hazardous waste. At this time, the majority of the Company’s ash is being beneficially reused. The proposals offered by EPA allow for the beneficial reuse of ash in certain circumstances. Costs for compliance with these regulations would likely qualify as federally mandated regulatory requirements under Senate Bill 251 referenced above.

Clean Water Act

Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” to minimize adverse environmental impacts. More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures used at electric generating facilities. In April of 2009, the U.S. Supreme Court affirmed that the EPA could, but was not required to, consider costs and benefits in making the evaluation as to the best technology available for existing generating facilities. The regulation was remanded back to the EPA for further consideration. Depending upon the approaches taken by the EPA when it reissues the regulation, capital investments could be in the $40 million range if new infrastructure, such as new cooling water towers, is required. In March 2011, the EPA released its proposed Section 316(b) regulations. The EPA did not mandate the retrofitting of cooling towers in the proposed regulation, but if finalized the regulation will leave it to the state to determine whether cooling towers should be required on a case by case basis. Similarly, costs for compliance with these regulations would likely qualify as federally mandated regulatory requirements under Senate Bill 251 referenced above.

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Potential Pipeline Safety Legislation

There are federal proposals currently pending that would increase the oversight of natural gas pipelines and lead to an investment in the inspection, and where necessary, modernization of pipeline infrastructure. At this time and in the absence of final legislation, compliance costs and other effects associated with increased pipeline safety regulations remain uncertain. However, any future legislative or regulatory actions taken to address pipeline safety could result in both operating expenses and capital expenditures associated with the Company’s natural gas distribution businesses. Compliance costs and capital investments associated with the Company’s Indiana gas utilities would likely qualify as federally mandated regulatory requirements under Senate Bill 251 referenced above. In Ohio, capital investments would likely qualify for timely recovery under House Bill 95.

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 owned or 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.

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 cumulative costs that it reasonably expects to incur totaling approximately $23.2 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 limit Indiana Gas’ costs at these 19 sites to between 28 percent and 50 percent. With respect to insurance coverage, Indiana Gas has received approximately $20.8 million from all known insurance carriers under insurance policies in effect when these plants were in operation.

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 was also named in a lawsuit, involving another waste disposal site subject to potential environmental remediation efforts. With respect to that lawsuit, SIGECO settled with the plaintiff during 2010 mitigating any future claims at this site. 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 recently settled lawsuit. In November the Court ruled on two motions for summary judgment, finding for SIGECO and against certain insurers on indemnification and defense obligations in the policies at issue.

SIGECO has recorded cumulative costs that it reasonably expects to incur related to these environmental matters, including the recent settlement discussed above, totaling approximately $16.1 million. However, the total costs that may be incurred in connection with addressing all of these sites cannot be determined at this time. With respect to insurance coverage, SIGECO has recorded approximately $14.1 million of expected insurance recoveries from certain of its insurance carriers under insurance policies in effect when these sites were in operation. While negotiations are ongoing with certain carriers, settlements have been reached with some carriers and $9.0 million in proceeds have been received.

The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others. 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. As of June 30, 2011 and December 31, 2010, respectively, approximately $5.0 million and $5.5 million of accrued, but not yet spent, costs are included in Other Liabilities related to both the Indiana Gas and SIGECO sites.

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10.	Rate & Regulatory Matters

Vectren South Electric Base Rate Filing

On December 11, 2009, Vectren South filed a request with the IURC to adjust its base electric rates. The requested increase in base rates addressed capital investments, a modified electric rate design that would facilitate a partnership between Vectren South and customers to pursue energy efficiency and conservation, and new energy efficiency programs to complement those currently offered for natural gas customers. On July 30, 2010, Vectren South revised downward its increase requested through the filing of its rebuttal position to approximately $34 million. The IURC issued an order in the case on April 27, 2011. The order provides for an approximate $28.6 million revenue increase to recover costs associated with approximately $325 million in system upgrades that were completed in the three years leading up to the December 2009 filing and modest increases in maintenance and operating expenses. The approved revenue increase is based on rate base of $1,295.6 million, return on equity of 10.4 percent and an overall rate of return of 7.29 percent. The new rates were effective May 3, 2011. The IURC, in its order, denied the Company’s request for implementation of the decoupled rate design, which is discussed further below. Addressing issues raised in the case concerning coal supply contracts and related costs, the IURC found that current coal contracts remain effective and that a prospective review process of future procurement decisions will be initiated.

Coal Procurement Procedures

Vectren South recently submitted a request for proposal regarding coal purchases for a four year period beginning in 2012. After negotiations with bidders, Vectren South has reached an agreement in principle for multi-year purchases with two suppliers, one of which is Vectren Fuels, Inc. Consistent with the IURC direction in the electric rate order, a sub docket proceeding has been established to review the Company’s prospective coal procurement procedures, and the Company expects to submit evidence related to its recent request for proposal and those coal procurement procedures to the IURC in August 2011.

Vectren South Electric Demand Side Management Program Filing

On August 16, 2010, Vectren South filed a petition with the IURC, seeking approval of its proposed electric Demand Side Management (DSM) Programs, recovery of the costs associated with these programs, recovery of lost margins as a result of implementing these programs for large customers, and recovery of performance incentives linked with specific measurement criteria on all programs. The DSM Programs proposed are consistent with a December 9, 2009 order issued by the IURC, which, among other actions, defined long-term conservation objectives and goals of DSM programs for all Indiana electric utilities under a consistent statewide approach. In order to meet these objectives, the IURC order divided the DSM programs into Core and Core Plus programs. Core programs are joint programs required to be offered by all Indiana electric utilities to all customers, including large industrial customers. Core Plus programs are those programs not required specifically by the IURC, but defined by each utility to meet the overall energy savings targets defined by the IURC.

In its August 2010 filing, Vectren South proposed a three-year DSM Plan that expands its current portfolio of Core and Core Plus DSM Programs in order to meet the energy savings goals established by the IURC. Vectren South requested recovery of these program costs under a current tracking mechanism. In addition, Vectren South proposed a performance incentive mechanism that is contingent upon the success of each of the DSM Programs in reducing energy usage to the levels defined by the IURC. This performance incentive would also be recovered in the same tracking mechanism. Finally, the Company proposed lost margin recovery associated with the implementation of DSM programs for large customers. All filings related to this matter have been made, and an order is expected in 2011.

The settlement currently pending also provides that impacts from energy efficiency programs associated with residential and general service customers be deferred for future recovery. Subject to the approval of the settlement currently before the IURC regarding large customers, the Company expects to propose a rate mechanism to recover residential and general service customer lost margins. This mechanism would be an alternative to the electric decoupling proposal that was denied by the IURC in the order received April 27, 2011.

Vectren North & Vectren South Gas Decoupling Extension Filing

On April 14, 2011, the Company’s Indiana based gas companies (Vectren North and Vectren South) filed with the IURC a joint settlement agreement with the OUCC on an extension of the offering of conservation programs and the supporting gas decoupling mechanism originally approved in December 2006. The settlement provides for new program offerings and the extension of the current decoupling mechanism through December 2015. Program costs will continue to be recovered through a periodic tracker mechanism. A hearing was held on June 22, 2011. An order is anticipated sometime during 2011.

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VEDO Gas Rate Design

The rate design approved by the PUCO on January 7, 2009, and initially implemented on February 22, 2009, allowed for the phased movement toward a straight fixed variable rate design, which places substantially all of the fixed cost recovery in the monthly customer service charge. This rate design mitigates most weather risk as well as the effects of declining usage, similar to the company’s lost margin recovery mechanism in place in the Indiana natural gas service territories and the mechanism in place in Ohio prior to this rate order. Since the straight fixed variable rate design was fully implemented in February 2010, nearly 90 percent of the combined residential and commercial base rate gas margins were recovered through the customer service charge. As a result, some margin previously recovered during the peak delivery winter months, such as January and the first half of February 2010, is more ratably recognized throughout the year.

In addition in 2010, the Company began recognizing a return on and of investments made to replace distribution risers and bare steel and cast iron infrastructure per a PUCO order.

VEDO Continues the Process to Exit the Merchant Function

On August 20, 2008, the PUCO approved the results of 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 standard pricing was comprised of the monthly NYMEX settlement price plus a fixed adder. This standard pricing, which was effective from October 1, 2008 through March 31, 2010, was the initial step in exiting the merchant function in the Company’s Ohio service territory. The approach eliminated the need for monthly gas cost recovery (GCR) filings and prospective PUCO GCR audits.

The second phase of the exit process began on April 1, 2010. During this phase, the Company no longer sells natural gas directly to customers. Rather, state-certified Competitive Retail Natural Gas Suppliers, that were successful bidders in a similar regulatory-approved auction, sell the gas commodity to specific customers for a 12 month period at auction-determined standard pricing. The first auction was conducted on January 12, 2010, and the auction results were approved by the PUCO on January 13, 2010. The plan approved by the PUCO required that the Company conduct at least two annual auctions during this phase. As such, the Company conducted another auction on January 18, 2011 in advance of the second 12-month term which commences on April 1, 2011. The results of that auction were approved by the PUCO on January 19, 2011. Vectren Source, the Company’s wholly owned nonutility retail gas marketer, was a successful bidder in both auctions winning one tranche of customers in the first auction and two tranches of customers in the second auction. Consistent with current practice, customers will continue to receive a single bill for the commodity as well as the delivery component of natural gas service from VEDO. The PUCO provided for an Exit Transition Cost rider, which allows the Company to recover costs associated with the transition process. Exiting the merchant function has not had a material impact on earnings or financial condition. It, however, has and will continue to reduce Gas utility revenues and have an equal and offsetting impact to Cost of gas sold and revenue related taxes recorded in Taxes other than income taxes as VEDO no longer purchases gas for resale to these customers.

11.	Fair Value Measurements

The carrying values and estimated fair values of the Company's other financial instruments follow:



	June 30, 2011				December 31, 2010
(In millions)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	1,304.5	$	1,401.6	$	1,304.8	$	1,392.9
Short-term borrowings		-		-		47.0		47.0
Cash & cash equivalents		13.3		13.3		2.4		2.4

For the balance sheet dates presented in these financial statements, the Company had no material assets or liabilities recorded at fair value outstanding, and no material assets or liabilities valued using Level 2 or Level 3 inputs.

Certain methods and assumptions must be used to estimate the fair value of financial instruments. The fair value of the Company's long-term debt was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics. Because of the maturity dates and variable interest rates of short-term borrowings and cash & cash equivalents, those carrying amounts approximate fair value. Because of the inherent difficulty of estimating interest rate and other market risks, the methods used to estimate fair value may not always be indicative of actual realizable value, and different methodologies could produce different fair value estimates at the reporting date.

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Under current regulatory treatment, call premiums on reacquisition of long-term debt are generally recovered in customer rates over the life of the refunding issue or over a 15-year period. Accordingly, any reacquisition would not be expected to have a material effect on the Company's results of operations.

12. Segment Reporting

The Company’s operations consist of regulated operations and other operations that provide information technology and other support services to those regulated operations. The Company segregates its regulated operations between 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 power operations. Regulated operations supply natural gas and/or electricity to over one million customers. In total, the Company is comprised of three operating segments: Gas Utility Services, Electric Utility Services, and Other Shared Service operations. Net income is the measure of profitability used by management for all operations. Information related to the Company’s business segments is summarized below:


	Three Months						Six Months
	Ended June 30,						Ended June 30,
(In millions)	2011			2010			2011			2010
Revenues
Gas Utility Services	$	134.0		$	122.9		$	490.7		$	591.0
Electric Utility Services		159.3			151.0			305.7			295.9
Other Operations		10.9			11.1			21.9			22.2
Eliminations		(10.4	)		(10.7	)		(20.9	)		(21.4	)
Total revenues	$	293.8		$	274.3		$	797.4		$	887.7

Profitability Measure - Net Income
Gas Utility Services	$	2.1		$	0.1		$	38.3		$	39.9
Electric Utility Services		13.6			14.3			22.3			26.7
Other Operations		0.6			1.8			4.3			5.0
Total net income	$	16.3		$	16.2		$	64.9		$	71.6

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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 as well as the Company’s 2010 annual report filed on Form 10-K.

In the second quarter of 2011, Utility Holdings earned $16.3 million which is comparable to the $16.2 million earned in 2010. Year to date in 2011, utility earnings were $64.9 million compared to $71.6 million in 2010, a decrease of $6.7 million. The year to date decrease is driven primarily by increased operating expenses associated with planned electric generating maintenance activities, warmer cooling weather in the prior year, and the expected first quarter impact of rate design changes implemented in February 2010 in the Ohio service territory. During the second quarter, increased margin from the Vectren South electric rate increase implementation largely offset these impacts.

In the Company’s electric territory, management estimates the margin impact of weather to be approximately $1.7 million favorable and $1.5 million favorable, compared to normal temperatures in the quarter and year to date in 2011, respectively. This compares to 2010, where management estimated a $3.4 million favorable impact on margin compared to normal in the second quarter and $4.2 million year to date.

Significant Fluctuations

Margin

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 sold. Electric Utility margin is calculated as Electric utility revenues less Cost of fuel & purchased power. The Company believes Gas Utility and Electric Utility margins are better indicators of relative contribution than revenues since gas prices, fuel, and purchased power costs can be volatile and are generally collected on a dollar-for-dollar basis from customers. Following is a discussion and analysis of margin generated from regulated utility operations.

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Gas Utility Margin (Gas utility revenues less Cost of gas sold)

Gas utility margin and throughput by customer type follows:


	Three Months				Six Months
	Ended June 30,				Ended June 30,
(In millions)	2011		2010		2011		2010
Gas utility revenues	$	134.0	$	122.9	$	490.7	$	591.0
Cost of gas sold		48.8		41.5		243.9		339.3
Total gas utility margin	$	85.2	$	81.4	$	246.8	$	251.7
Margin attributed to:
Residential & commercial customers	$	69.9	$	67.9	$	209.4	$	216.4
Industrial customers		12.0		10.1		29.7		26.3
Other		3.3		3.4		7.7		9.0
Total gas utility margin	$	85.2	$	81.4	$	246.8	$	251.7
Sold & transported volumes in MMDth attributed to:
Residential & commercial customers		11.7		8.9		64.5		63.5
Industrial customers		21.1		19.2		49.9		45.8
Total sold & transported volumes		32.8		28.1		114.4		109.3

Gas utility margins were $85.2 million and $246.8 million for the for the three and six months ended June 30, 2011, and compared to 2010 increased $3.8 in the quarter and decreased $4.9 million year to date. Management estimates a year to date decrease of $3.5 million due to Ohio rate design changes, as described below. Returns generated on investments in bare steel/ cast iron and distribution riser replacement in Ohio increased margins $0.6 million quarter over quarter and $1.4 million year to date. Large customer margin, net of the impacts of regulatory initiatives and tracked costs, increased by $1.7 million in the quarter and $3.1 million year to date due primarily to increased volumes sold, largely from ethanol producers. Margin increased $1.0 million in the quarter and decreased $4.8 million year to date due to lower revenue taxes and operating costs directly recovered in margin.

The rate design approved by the Public Utilities Commission of Ohio (PUCO) on January 7, 2009, and initially implemented on February 22, 2009, allowed for the phased movement toward a straight fixed variable rate design, which places substantially all of the fixed cost recovery in the monthly customer service charge. This rate design mitigates most weather risk as well as the effects of declining usage. Since the straight fixed variable rate design was fully implemented in mid February 2010, nearly 90 percent of the combined residential and commercial base rate gas margins are recovered through the customer service charge. However, margin recognized in the first quarter of 2010 that reflected a volumetric rate design during the peak delivery winter months of January and the first half of February 2010 is now more ratably recognized throughout the year.

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

Electric utility margin and volumes sold by customer type follows:


	Three Months				Six Months
	Ended June 30,				Ended June 30,
(In millions)	2011		2010		2011		2010

Electric utility revenues	$	159.3	$	151.0	$	305.7	$	295.9
Cost of fuel & purchased power		60.3		57.8		119.8		115.8
Total electric utility margin	$	99.0	$	93.2	$	185.9	$	180.1
Margin attributed to:
Residential & commercial customers	$	63.0	$	59.9	$	117.0	$	115.2
Industrial customers		25.5		24.4		48.9		46.9
Other customers		1.6		2.3		3.5		4.0
Subtotal: retail	$	90.1	$	86.6	$	169.4	$	166.1
Wholesale power & transmission system margin		8.9		6.6		16.5		14.0
Total electric utility margin	$	99.0	$	93.2	$	185.9	$	180.1
Electric volumes sold in GWh attributed to:
Residential & commercial customers		677.9		716.5		1,359.5		1,428.4
Industrial customers		680.9		697.1		1,342.8		1,307.5
Other customers		4.8		5.1		10.7		11.1
Total retail volumes sold		1,363.6		1,418.7		2,713.0		2,747.0

Retail

Electric retail utility margins were $90.1 million and $169.4 million for the three and six months ended June 30, 2011, and compared to 2010 increased over the prior year periods by $3.5 million and $3.3 million, respectively. The impact of new base rates increased margin $5.9 million in the quarter and year to date periods. Management estimates the impact of weather, which was warmer than normal but cooler compared to the prior year, to have decreased residential and commercial margin $1.7 million in the second quarter and $2.7 million year to date compared to the prior year periods.

Margin from Wholesale Electric Activities

Periodically, generation capacity is in excess of native load. The Company markets and sells this unutilized generating and transmission capacity to optimize the return on its owned assets. Substantially all off-system sales occur into the MISO Day Ahead and Real Time markets. Further detail of Wholesale activity follows:


	Three Months				Six Months
	Ended June 30,				Ended June 30,
(In millions)	2011		2010		2011		2010
Off-system sales	$	2.4	$	0.8	$	4.4	$	3.4
Transmission system sales		6.5		5.8		12.1		10.6
Total wholesale margin	$	8.9	$	6.6	$	16.5	$	14.0

The Company earns a return on electric transmission projects constructed by the Company in its service territory that meet the criteria of MISO’s regional transmission expansion plans. Margin associated with these projects, including the reconciliation of recovery mechanisms, and other transmission system operations, totaled $6.5 million and $12.1 million for the three and six months ended June 30, 2011, respectively, compared to $5.8 million and $10.6 million in both the three and six months ended June 30, 2010. Increases are primarily due to increased investment in qualifying projects.

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One such project currently under construction meeting these expansion plan criteria is an interstate 345 Kv transmission line that will connect Vectren’s A.B. Brown Generating Station to a station in Indiana owned by Duke Energy to the north and to a station in Kentucky owned by Big Rivers Electric Corporation to the south. During the construction of these transmission assets and while these assets are in service, SIGECO will recover an approximate 10 percent return, inclusive of the FERC approved equity rate of return of 12.38 percent, on capital investments through a rider mechanism which is projected annually and reconciled the following year based on actual results. Of the total investment, which is expected to approximate $100 million, the Company has invested approximately $64.0 million as of June 30, 2011. The north leg of this expansion was placed in service in November 2010, and the south leg of this project is expected to be operational in 2012.

For the three and six months ended June 30, 2011, margin from off-system sales were $2.4 million and $4.4, respectively, compared to $0.8 million and $3.4 million for the three and six months ended June 30, 2010. The base rate changes implemented in May 2011 require that wholesale margin from off-system sales earned above or below $7.5 million be shared equally with customers. This compares to a $10.5 million sharing threshold established in 2007. Results for the periods presented reflect the impact of that sharing. Off-system sales totaled 327 GWh and 344 GWh during the six months ended June 30, 2011 and 2010, respectively.

Operating Expenses

Other Operating

For the three and six months ended June 30, 2011, other operating expenses were $78.2 million and $165.1 million, which reflect increases of $7.0 million and $12.3 million respectively, compared to 2010. These increases result primarily from an $8.2 million increase in the quarter and a $12.1 million year to date increase associated with power supply operating costs, of which $6.2 million and $9.6 million, respectively, are planned outage maintenance.

Depreciation & Amortization

For the three and six months ended June 30, 2011, depreciation expense was $47.9 million and $96.1 million, which represents increases of $1.1 million and $2.8 million, respectively, compared to 2010. These increases reflect utility investments placed into service, which were offset by lower amortizations of certain deferred costs pursuant to the recent electric base rate order.

Taxes Other Than Income Taxes

For the three and six months ended June 30, 2011, taxes other than income taxes were $11.1 million and $29.1 million, respectively, which reflect decreases of $0.5 million for the quarter and $4.8 million year to date. The year to date decrease is primarily attributable to lower Ohio excise and usage taxes associated with that territory’s ongoing process of exiting the merchant function, which started in the second quarter of last year. Excise and usage related taxes are offset dollar-for-dollar with lower gas utility revenues.

Other Income-Net

Other income-net reflects income of $2.2 million and $3.9 million for the three and six months ended June 30, 2011, compared to $0.8 million and $3.0 million for the same periods in 2010. The increases primarily reflect greater post in service carrying costs on increased distribution replacement program spending.

Interest Expense

For the three and six months ended June 30, 2011, interest expense was $20.4 million and $40.8 million, and is generally flat compared to the prior year periods. Interest expense continues to reflect the current low interest rate environment and less reliance by Utility Holdings on short-term borrowings. At June 30, 2011 and 2010, Utility Holdings had no short-term borrowings outstanding.

Income Taxes

In 2011, federal and state income taxes were $13.0 million for the quarter and $41.6 million year to date. The increased expense of $3.3 million quarter over quarter reflects increased pre-tax income, the impact of a one time adjustment of $1.4 million, and the amortization of certain income tax related regulatory liabilities associated with the recently concluded electric base rate case. The year to date decrease of $1.8 million primarily reflects lower pre-tax income.

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Legislative & Environmental Matters

Indiana House Bill 1004

Indiana Senate Bill 251

Ohio House Bill 95

Clean Air Act

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Climate Change

Impact of Legislative Actions & Other Initiatives is Unknown

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Ash Ponds & Coal Ash Disposal Regulations

Clean Water Act

Potential Pipeline Safety Legislation

Environmental Remediation Efforts

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Rate & Regulatory Matters

Vectren South Electric Base Rate Filing

Coal Procurement Procedures

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Vectren South Electric Demand Side Management Program Filing

The settlement currently pending also provides that impacts from energy efficiency programs associated with residential and general service customers be deferred for future recovery. Subject to the approval of the settlement currently before the IURC regarding large customers , the Company expects to propose a rate mechanism to recover residential and general service customer lost margins. This mechanism would be an alternative to the electric decoupling proposal that was denied by the IURC in the order received April 27, 2011.

Vectren North & Vectren South Gas Decoupling Extension Filing

VEDO Gas Rate Design

In addition in 2010, the Company began recognizing a return on and of investments made to replace distribution risers and bare steel and cast iron infrastructure per a PUCO order.

VEDO Continues the Process to Exit the Merchant Function

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The PUCO provided for an Exit Transition Cost rider, which allows the Company to recover costs associated with the transition process. Exiting the merchant function has not had a material impact on earnings or financial condition. It, however, has and will continue to reduce Gas utility revenues and have an equal and offsetting impact to Cost of gas sold and revenue related taxes recorded in Taxes other than income taxes as VEDO no longer purchases gas for resale to these customers. In the three months and six months ended June 30, 2010, VEDO’s gas costs were $1.8 million and $84.6 million, respectively, while revenue taxes were $1.8 million and $10.5 million, respectively. In the three and six months ended June 30, 2011, gas costs were $1.7 million and $8.9 million, respectively, while revenue taxes were $1.9 million and $6.7 million, respectively. Therefore, generally there was no change in Gas utility revenues resulting from VEDO’s exit of the merchant function in the current quarter, and such revenues decreased approximately $79.5 million year to date.

Impact of Recently Issued Accounting Guidance

Comprehensive Income

In June 2011, the FASB issued new accounting guidance regarding the presentation of comprehensive income within financial statements. The new guidance will require entities to report components of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements. Under the two-statement approach, the first statement would include components of net income, which is consistent with the income statement format used today, and the second statement would include components of other comprehensive income (OCI). The guidance does not change the items that must be reported in OCI. The new guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 and retrospective application is required. The Company plans to early adopt this guidance for its annual reporting period ending December 31, 2011. The adoption of this guidance will have no material impacts to the Company’s financial statements.

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 consolidated financial statements. Utility Holdings’ had no short-term obligations outstanding at June 30, 2011. Utility Holdings’ long-term obligations outstanding at June 30, 2011 approximated $918 million. 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. SIGECO will also occasionally issue tax exempt debt to fund qualifying pollution control capital expenditures. Total Indiana Gas and SIGECO long-term debt outstanding at June 30, 2011, was $387 million.

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 June 30, 2011, are A-/A3 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/A1. 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. A security rating is not a recommendation to buy, sell, or hold securities. The rating is subject to revision or withdrawal at any time, and each rating should be evaluated independently of any other rating. Standard and Poor’s and Moody’s lowest level investment grade rating is BBB- and Baa3, respectively.

The Company’s consolidated equity capitalization objective is 45-60 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 51 percent and 50 percent of long-term capitalization at June 30, 2011 and December 31, 2010, respectively. Long-term capitalization includes long-term debt, including current maturities and debt subject to tender, as well as common shareholder’s equity.

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Both long-term and short-term borrowing arrangements contain customary default provisions; restrictions on liens, sale-leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage and interest coverage, among other restrictions. As an example, the Utility Holdings’ short-term debt agreement expiring in 2013 contains a covenant that the ratio of consolidated total debt to consolidated total capitalization will not exceed 65 percent. As of June 30, 2011, the Company was in compliance with all covenants.

Available Liquidity in Current Credit Conditions

The Company’s A-/A3 investment grade credit ratings have allowed it to access the capital markets as needed. Over the last three years, the Company has reduced its reliance on short-term borrowing capacity with the completion of several long-term financing transactions including issuances of long-term debt and the settlement of an equity forward contract. The Company anticipates funding future capital expenditures and dividends through internally generated funds. In addition, available liquidity is expected to continue to be enhanced by the extension of bonus depreciation legislation.

On April 5, 2011, the Company entered into a private placement note purchase agreement pursuant to which various institutional investors have agreed to purchase the following tranches of notes: (i) $55 million of 4.67 percent Senior Guaranteed Notes, due November 30, 2021, (ii) $60 million of 5.02 percent Senior Guaranteed Notes, due November 30, 2026, and (iii) $35 million of 5.99 percent Senior Guaranteed Notes, due December 2, 2041. The proceeds received from the issuance of these senior notes will be used to partially refinance $250 million of long-term debt maturing December 1, 2011. The remainder of the maturing debt will be retired with short-term borrowings. These senior notes are unsecured and will be jointly and severally guaranteed by the Company’s regulated utility subsidiaries, Southern Indiana Gas and Electric Company, Indiana Gas Company, Inc., and Vectren Energy Delivery of Ohio, Inc. Subject to the satisfaction of customary closing conditions precedent, the notes will be issued on or about November 30, 2011. The Company has reclassified $150 million of the $250 million debt redemption due in December 2011 to long-term debt in its June 30, 2011 Consolidated Balance Sheet to reflect the Company’s ability and intent to refinance that portion of the debt with this issuance.

Consolidated Short-Term Borrowing Arrangements

At June 30, 2011, the Company has $350 million of short-term borrowing capacity. No borrowings were outstanding at June 30, 2011. This facility is used to supplement working capital needs and also to fund capital investments and debt redemptions until financed on a long-term basis.

Following is certain information regarding these short-term borrowing arrangements.


(In millions)		2011			2010
Six Months Ended June 30
	Balance Outstanding	$	-		$	-
	Weighted Average Interest Rate		n/a			n/a
Six Months Ended June 30 Average
	Balance Outstanding	$	11.6		$	0.6
	Weighted Average Interest Rate		0.39	%		0.25	%
Maximum Month End Balance Outstanding		$	42.5		$	-

During the three months ended June 30, 2011 and 2010, there were no short-term borrowings outstanding.

Potential Uses of Liquidity

Planned Capital Expenditures

Utility capital expenditures are estimated at $125 million for the remainder of 2011.

Pension and Postretirement Funding Obligations

During the six months ended June 30, 2011, Vectren made $30.9 million in contributions to qualified pension plans, all of which was funded by Utility Holdings. Vectren anticipates $4.1 million of additional funding in 2011 which will be funded by Utility Holdings. Of the $35 million of anticipated funding in 2011, $25 million is made available from bonus depreciation opportunities. Vectren’s management currently estimates contributing $10 million to qualified pension plans in 2012, of which a majority will be funded by Utility Holdings. Contributions in 2012 and beyond are dependent on a variety of factors, including Vectren’s progress toward attaining its long-term goal of being fully funded related to the plans’ accrued benefit obligations and the available sources of cash to fund such additional contributions.

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Other Letters of Credit

As of June 30, 2011, Utility Holdings has letters of credit outstanding in support of two SIGECO tax exempt adjustable rate first mortgage bonds totaling $41.7 million. In the unlikely event the letters of credit were called, the Company could settle with the financial institutions supporting these letters of credit with general assets or by drawing from its credit facility that expires in September of 2013. Due to the long-term nature of the credit agreement, such debt is classified as long-term at June 30, 2011.

Comparison of 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 $217.6 million and $171.9 million during the six months ended June 30, 2011 and 2010, respectively. The $45.7 million increase in operating cash flow in 2011 compared to 2010 is primarily due to a greater level of cash generated from working capital compared to the prior year period. This increase is partially offset by increased contributions to Vectren’s pension and postretirement plans. The change in net income period over period was impacted by increases in noncash charges, such as depreciation and deferred taxes.

Financing Cash Flow

Net cash flow required for financing activities was $93.3 million and $54.1 million during the six months ended June 30, 2011 and 2010, respectively. This primarily reflects the payment of $45.8 million in dividends and the repayment of $47.0 million in short-term borrowings during 2011 compared to $39.5 million in dividends and the repayment of $16.4 million in short-term borrowings during 2010.

Investing Cash Flow

Cash flow required for investing activities was $113.4 million and $109.6 million during the six months ended June 30, 2011 and 2010, respectively. Capital expenditures are the primary component of investing activities and totaled $112.4 million and $111.4 during the six months ended June 30, 2011 and 2010, respectively.

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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”, “likely”, 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.

·	Catastrophic events such as fires, earthquakes, explosions, floods, ice storms, tornados, terrorist acts or other similar occurrences could adversely affect Vectren’s facilities, operations, financial condition and results of operations.

·	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 inflation rates, commodity prices, and monetary fluctuations.

Economic conditions surrounding the current economic uncertainty, including significantly lower levels of economic activity; uncertainty regarding energy prices and the capital and commodity markets; volatile changes in the demand for natural gas and electricity; impacts on both gas and electric large customers; lower residential and commercial customer counts; and higher operating expenses.

·	Volatile natural gas and coal 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, work stoppages, or pandemic illness.

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

·	Costs, fines, penalties and other effects of legal and administrative proceedings, settlements, investigations, claims, including, but not limited to, such matters involving 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 performance of projects undertaken by Vectren’s nonutility businesses and the success of efforts to invest in and develop new opportunities, including but not limited to, Vectren’s coal mining, gas marketing, and energy infrastructure strategies.

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 & 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 may also execute 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 Vectren Utility Holdings, Inc. 2010 Form 10-K and is therefore not presented herein.

ITEM 4. CONTROLS & PROCEDURES

Changes in Internal Controls over Financial Reporting

During the quarter ended June 30, 2011, 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 control over financial reporting.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

As of June 30, 2011, the Company conducted an evaluation under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of the effectiveness and the design and operation of the Company's disclosure controls and procedures. Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer have concluded that the Company's disclosure controls and procedures are effective as of June 30, 2011, 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 and audits and reviews by taxing authorities and other government agencies arising in the normal course of business. In the opinion of management, there are no legal proceedings or other regulatory reviews or audits pending against the Company that are likely to have a material adverse effect on its financial position, results of operations, or cash flows. See the notes to the consolidated financial statements regarding commitments and contingencies, environmental matters, rate and regulatory matters. The consolidated condensed financial statements are included in Part 1 Item 1.

ITEM 1A. RISK FACTORS

Investors should consider carefully factors that may impact the Company’s operating results and financial condition, causing them to be materially adversely affected. The Company’s risk factors have not materially changed from the information set forth in Item 1A Risk Factors included in the Vectren Utility Holdings 2010 Form 10-K and are therefore not presented herein.

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ITEM 6. EXHIBITS

Exhibits and Certifications

12 Ratio of Earnings to Fixed Charges

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

101 Interactive Data File

101.INS* XBRL Instance Document

101.SCH* XBRL Taxonomy Extension Schema

101.CAL* XBRL Taxonomy Extension Calculation Linkbase

101.LAB* XBRL Taxonomy Extension Label Linkbase

101.PRE* XBRL Taxonomy Extension Presentation Linkbase

* Users of the XBRL-related information in Exhibit 101 to this Quarterly Report on Form 10-Q are advised in accordance with Rule 406T of Regulation S-T promulgated by the Securities and Exchange Commission that this Interactive Data File is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections. The financial information contained in the XBRL-related documents is “unaudited” and “unreviewed.”

SIGNATURES

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

			VECTREN UTILITY HOLDINGS, INC.
			Registrant




	August 11, 2011		/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)