10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2012

OR

[_] 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.ýYesoNo

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).

ýYesoNo

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 oAccelerated filer o

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

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

oYesýNo

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, 2012
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	MISO: Midwest Independent System Operator
EPA:  United States Environmental Protection Agency	MMBTU:  millions of British thermal units
FAC:  Fuel Adjustment Clause	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	Throughput:  combined gas sales and gas transportation volumes
MDth / MMDth: thousands / millions of dekatherms	XBRL:  eXtensible Business Reporting Language

1

Table of Contents

Item Number		Page Number
	PART I.  FINANCIAL INFORMATION
1	Financial Statements (Unaudited)
	Vectren Utility Holdings, Inc. and Subsidiary Companies
	Condensed Consolidated Balance Sheets	3- 4
	Condensed Consolidated Statements of Income	5
	Condensed Consolidated Statements of Cash Flows	6
	Notes to Unaudited Condensed Consolidated Financial Statements	7
2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
3	Quantitative and Qualitative Disclosures About Market Risk	35
4	Controls and Procedures	35
	PART II.  OTHER INFORMATION
1	Legal Proceedings	36
1A	Risk Factors	36
2	Unregistered Sales of Equity Securities and Use of Proceeds	36
3	Defaults Upon Senior Securities	36
4	Mine Safety Disclosures	36
5	Other Information	36
6	Exhibits	37
	Signatures	38

2

PART I.  FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited – In millions)

	June 30, 2012		December 31, 2011
ASSETS
Current Assets
Cash & cash equivalents	$	4.1	$	6.0
Accounts receivable - less reserves of $5.4 & $5.9, respectively	56.2		95.5
Receivables due from other Vectren companies	0.1		0.2
Accrued unbilled revenues	35.5		90.8
Inventories	107.0		132.5
Recoverable fuel & natural gas costs	14.6		12.4
Prepayments & other current assets	29.0		69.3
Total current assets	246.5		406.7
Utility Plant
Original cost	5,091.0		4,979.9
Less:  accumulated depreciation & amortization	2,001.1		1,947.3
Net utility plant	3,089.9		3,032.6
Investments in unconsolidated affiliates	0.2		0.2
Other investments	32.1		31.8
Nonutility plant - net	145.7		156.6
Goodwill - net	205.0		205.0
Regulatory assets	119.3		100.0
Other assets	38.1		41.6
TOTAL ASSETS	$	3,876.8	$	3,974.5

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

3

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited – In millions)

	June 30, 2012		December 31, 2011
LIABILITIES & SHAREHOLDER'S EQUITY
Current Liabilities
Accounts payable	$	80.1	$	112.9
Accounts payable to affiliated companies	13.8		36.8
Payables to other Vectren companies	24.9		30.1
Refundable fuel & natural gas costs	5.0		—
Accrued liabilities	118.2		121.0
Short-term borrowings	61.5		142.8
Current maturities of long-term debt	5.0		—
Total current liabilities	308.5		443.6
Long-Term Debt - Net of Current Maturities	1,203.3		1,208.2
Deferred Income Taxes & Other Liabilities
Deferred income taxes	542.1		537.5
Regulatory liabilities	355.2		345.2
Deferred credits & other liabilities	92.1		93.4
Total deferred credits & other liabilities	989.4		976.1
Commitments & Contingencies (Notes 8 - 11)
Common Shareholder's Equity
Common stock (no par value)	778.1		774.6
Retained earnings	597.5		572.0
Total common shareholder's equity	1,375.6		1,346.6
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,876.8	$	3,974.5

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

4

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited – In millions)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2012		2011		2012		2011
OPERATING REVENUES
Gas utility	$	116.0	$	134.0	$	408.3	$	490.7
Electric utility	149.3		159.3		288.7		305.7
Other	0.5		0.5		0.9		1.0
Total operating revenues	265.8		293.8		697.9		797.4
OPERATING EXPENSES
Cost of gas sold	31.8		48.8		168.9		243.9
Cost of fuel & purchased power	47.0		60.3		91.7		119.8
Other operating	77.8		78.2		157.7		165.1
Depreciation & amortization	47.8		47.9		96.4		96.1
Taxes other than income taxes	11.6		11.1		27.5		29.1
Total operating expenses	216.0		246.3		542.2		654.0
OPERATING INCOME	49.8		47.5		155.7		143.4
Other income - net	0.7		2.2		2.9		3.9
Interest expense	18.0		20.4		35.7		40.8
INCOME BEFORE INCOME TAXES	32.5		29.3		122.9		106.5
Income taxes	12.4		13.0		46.8		41.6
NET INCOME	$	20.1	$	16.3	$	76.1	$	64.9

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

5

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited – In millions)

	Six Months Ended
	June 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	76.1		$	64.9
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization	96.4			96.1
Deferred income taxes & investment tax credits	21.9			28.2
Expense portion of pension & postretirement periodic benefit cost	2.5			2.3
Provision for uncollectible accounts	3.9			7.1
Other non-cash expense - net	4.7			4.3
Changes in working capital accounts:
Accounts receivable, including to Vectren companies                     & accrued unbilled revenue	90.7			120.6
Inventories	3.2			15.8
Recoverable/refundable fuel & natural gas costs	2.8			(1.3		)
Prepayments & other current assets	29.6			37.1
Accounts payable, including to Vectren companies                     & affiliated companies	(67.2		)	(120.8		)
Accrued liabilities	(2.8		)	(0.2		)
Changes in noncurrent assets	0.2			(3.9		)
Changes in noncurrent liabilities	(13.0		)	(32.6		)
Net cash flows from operating activities	249.0			217.6
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt - net of issuance costs	99.5			—
Additional capital contribution	3.5			—
Requirements for:
Dividends to parent	(50.5		)	(45.8		)
Retirement of long-term debt	—			(0.5		)
Net change in short-term borrowings, including from other           Vectren companies	(181.3		)	(47.0		)
Net cash flows from financing activities	(128.8		)	(93.3		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from other investing activities	2.2			0.3
Requirements for:
Capital expenditures, excluding AFUDC equity	(124.1		)	(112.4		)
Other investments	(0.2		)	(1.3		)
Net cash flows from investing activities	(122.1		)	(113.4		)
Net change in cash & cash equivalents	(1.9		)	10.9
Cash & cash equivalents at beginning of period	6.0			2.4
Cash & cash equivalents at end of period	$	4.1		$	13.3

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

6

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. Organization and 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 Vectren Energy Delivery of Ohio, Inc. (VEDO).  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 567,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 142,000 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.  VEDO provides energy delivery services to approximately 312,000 natural gas customers located near Dayton in west central Ohio.

2. Basis of Presentation

The interim condensed consolidated 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 condensed consolidated 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, 2011, filed with the Securities and Exchange Commission on March 2, 2012, 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 approximately $62 million is outstanding at June 30, 2012, and Utility Holdings’ has unsecured senior notes with a par value of $821 million outstanding at June 30, 2012.  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.

7

Condensed Consolidating Balance Sheet as of June 30, 2012 (in millions):

ASSETS	Subsidiary		Parent			Eliminations &
	Guarantors		Company			Reclassifications			Consolidated
Current Assets
Cash & cash equivalents	$	2.7	$	1.4		$	—		$	4.1
Accounts receivable - less reserves	56.2		—			—			56.2
Intercompany receivables	17.7		136.8			(154.5		)	—
Receivables due from other Vectren companies	—		0.1			—			0.1
Accrued unbilled revenues	35.5		—			—			35.5
Inventories	107.0		—			—			107.0
Recoverable fuel & natural gas costs	14.6		—			—			14.6
Prepayments & other current assets	31.7		5.0			(7.7		)	29.0
Total current assets	265.4		143.3			(162.2		)	246.5
Utility Plant
Original cost	5,091.0		—			—			5,091.0
Less:  accumulated depreciation & amortization	2,001.1		—			—			2,001.1
Net utility plant	3,089.9		—			—			3,089.9
Investments in consolidated subsidiaries	—		1,300.1			(1,300.1		)	—
Notes receivable from consolidated subsidiaries	—		679.7			(679.7		)	—
Investments in unconsolidated affiliates	0.2		—			—			0.2
Other investments	27.2		4.9			—			32.1
Nonutility property - net	2.8		142.9			—			145.7
Goodwill - net	205.0		—			—			205.0
Regulatory assets	96.3		23.0			—			119.3
Other assets	41.9		2.8			(6.6		)	38.1
TOTAL ASSETS	$	3,728.7	$	2,296.7		$	(2,148.6	)	$	3,876.8
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent			Eliminations &
	Guarantors		Company			Reclassifications			Consolidated
Current Liabilities
Accounts payable	$	67.9	$	12.2		$	—		$	80.1
Accounts payable to affiliated companies	13.8		—			—			13.8
Intercompany payables	31.3		—			(31.3		)	—
Payables to other Vectren companies	15.3		9.6			—			24.9
Refundable fuel & natural gas costs	5.0		—			—			5.0
Accrued liabilities	110.0		15.9			(7.7		)	118.2
Short-term borrowings	—		61.5			—			61.5
Intercompany short-term borrowings	105.6		17.6			(123.2		)	—
Current maturities of long-term debt payable to VUHI	5.0		—			—			5.0
Total current liabilities	353.9		116.8			(162.2		)	308.5
Long-Term Debt
Long-term debt - net of current maturities	382.3		821.0			—			1,203.3
Long-term debt due to VUHI	679.7		—			(679.7		)	—
Total long-term debt - net	1,062.0		821.0			(679.7		)	1,203.3
Deferred Income Taxes & Other Liabilities
Deferred income taxes	562.7		(20.6		)	—			542.1
Regulatory liabilities	352.9		2.3			—			355.2
Deferred credits & other liabilities	97.1		1.6			(6.6		)	92.1
Total deferred credits & other liabilities	1,012.7		(16.7		)	(6.6		)	989.4
Common Shareholder's Equity
Common stock (no par value)	791.3		778.1			(791.3		)	778.1
Retained earnings	508.8		597.5			(508.8		)	597.5
Total common shareholder's equity	1,300.1		1,375.6			(1,300.1		)	1,375.6
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,728.7	$	2,296.7		$	(2,148.6	)	$	3,876.8

8

Condensed Consolidating Balance Sheet as of December 31, 2011 (in millions):

ASSETS	Subsidiary		Parent			Eliminations &
	Guarantors		Company			Reclassifications			Consolidated
Current Assets
Cash & cash equivalents	$	5.3	$	0.7		$	—		$	6.0
Accounts receivable - less reserves	94.8		0.7			—			95.5
Intercompany receivables	—		206.0			(206.0		)	—
Receivables due from other Vectren companies	—		0.2			—			0.2
Accrued unbilled revenues	90.8		—			—			90.8
Inventories	132.5		—			—			132.5
Recoverable fuel & natural gas costs	12.4		—			—			12.4
Prepayments & other current assets	57.1		16.7			(4.5		)	69.3
Total current assets	392.9		224.3			(210.5		)	406.7
Utility Plant
Original cost	4,979.9		—			—			4,979.9
Less:  accumulated depreciation & amortization	1,947.3		—			—			1,947.3
Net utility plant	3,032.6		—			—			3,032.6
Investments in consolidated subsidiaries	—		1,272.2			(1,272.2		)	—
Notes receivable from consolidated subsidiaries	—		679.7			(679.7		)	—
Investments in unconsolidated affiliates	0.2		—			—			0.2
Other investments	26.8		5.0			—			31.8
Nonutility property - net	3.0		153.6			—			156.6
Goodwill - net	205.0		—			—			205.0
Regulatory assets	77.0		23.0			—			100.0
Other assets	44.2		4.0			(6.6		)	41.6
TOTAL ASSETS	$	3,781.7	$	2,361.8		$	(2,169.0	)	$	3,974.5
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent			Eliminations &
	Guarantors		Company			Reclassifications			Consolidated
Current Liabilities
Accounts payable	$	106.1	$	6.8		$	—		$	112.9
Accounts payable to affiliated companies	36.8		—			—			36.8
Intercompany payables	11.8		—			(11.8		)	—
Payables to other Vectren companies	30.1		—			—			30.1
Accrued liabilities	112.9		12.6			(4.5		)	121.0
Short-term borrowings	—		142.8			—			142.8
Intercompany short-term borrowings	158.5		35.7			(194.2		)	—
Total current liabilities	456.2		197.9			(210.5		)	443.6
Long-Term Debt
Long-term debt	387.2		821.0			—			1,208.2
Long-term debt due to VUHI	679.7		—			(679.7		)	—
Total long-term debt - net	1,066.9		821.0			(679.7		)	1,208.2
Deferred Income Taxes & Other Liabilities
Deferred income taxes	545.2		(7.7		)	—			537.5
Regulatory liabilities	342.6		2.6			—			345.2
Deferred credits & other liabilities	98.6		1.4			(6.6		)	93.4
Total deferred credits & other liabilities	986.4		(3.7		)	(6.6		)	976.1
Common Shareholder's Equity
Common stock (no par value)	787.8		774.6			(787.8		)	774.6
Retained earnings	484.4		572.0			(484.4		)	572.0
Total common shareholder's equity	1,272.2		1,346.6			(1,272.2		)	1,346.6
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,781.7	$	2,361.8		$	(2,169.0	)	$	3,974.5

9

Condensed Consolidating Statement of Income for the three months ended June 30, 2012 (in millions):

	Subsidiary Guarantors	Parent Company	Eliminations & Reclassifications		Consolidated
OPERATING REVENUES
Gas utility	116.0	—	—		116.0
Electric utility	149.3	—	—		149.3
Other	—	10.0	(9.5	)	0.5
Total operating revenues	265.3	10.0	(9.5	)	265.8
OPERATING EXPENSES
Cost of gas sold	31.8	—	—		31.8
Cost of fuel & purchased power	47.0	—	—		47.0
Other operating	86.3	0.5	(9.0	)	77.8
Depreciation & amortization	42.1	5.6	0.1		47.8
Taxes other than income taxes	11.2	0.3	0.1		11.6
Total operating expenses	218.4	6.4	(8.8	)	216.0
OPERATING INCOME	46.9	3.6	(0.7	)	49.8
Other income (loss) - net	0.2	9.9	(9.4	)	0.7
Interest expense	16.4	11.7	(10.1	)	18.0
INCOME BEFORE INCOME TAXES	30.7	1.8	—		32.5
Income taxes	12.2	0.2	—		12.4
Equity in earnings of consolidated companies, net of tax	—	18.5	(18.5	)	—
NET INCOME	18.5	20.1	(18.5	)	20.1

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

	Subsidiary Guarantors	Parent Company	Eliminations & 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 (loss) - net	1.8	12.7	(12.3	)	2.2
Interest expense	18.8	14.1	(12.5	)	20.4
INCOME BEFORE INCOME TAXES	26.8	2.5	—		29.3
Income taxes	11.1	1.9	—		13.0
Equity in earnings of consolidated companies, net of tax	—	15.7	(15.7	)	—
NET INCOME	15.7	16.3	(15.7	)	16.3

10

Condensed Consolidating Statement of Income for the six months ended June 30, 2012 (in millions):

	Subsidiary Guarantors		Parent Company			Eliminations & Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	408.3	$	—		$	—		$	408.3
Electric utility	288.7		—			—			288.7
Other	—		19.9			(19.0		)	0.9
Total operating revenues	697.0		19.9			(19.0		)	697.9
OPERATING EXPENSES
Cost of gas sold	168.9		—			—			168.9
Cost of fuel & purchased power	91.7		—			—			91.7
Other operating	175.9		0.5			(18.7		)	157.7
Depreciation & amortization	83.8		12.4			0.2			96.4
Taxes other than income taxes	26.7		0.7			0.1			27.5
Total operating expenses	547.0		13.6			(18.4		)	542.2
OPERATING INCOME	150.0		6.3			(0.6		)	155.7
Other income (loss) - net	2.2		20.5			(19.8		)	2.9
Interest expense	32.9		23.2			(20.4		)	35.7
INCOME BEFORE INCOME TAXES	119.3		3.6			—			122.9
Income taxes	47.7		(0.9		)	—			46.8
Equity in earnings of consolidated companies, net of tax	—		71.6			(71.6		)	—
NET INCOME	$	71.6	$	76.1		$	(71.6	)	$	76.1

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

	Subsidiary Guarantors		Parent Company		Eliminations & 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	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 - net	3.3		25.5		(24.9		)	3.9
Interest expense	37.7		28.4		(25.3		)	40.8
INCOME BEFORE INCOME TAXES	101.7		4.8		—			106.5
Income taxes	41.0		0.6		—			41.6
Equity in earnings of consolidated companies, net of tax	—		60.7		(60.7		)	—
NET INCOME	$	60.7	$	64.9	$	(60.7	)	$	64.9

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Condensed Consolidating Statement of Cash Flows for the six months ended June 30, 2012 (in millions):

	Subsidiary Guarantors			Parent Company			Eliminations			Consolidated
NET CASH FLOWS FROM OPERATING ACTIVITIES	$	233.3		$	15.7		$	—		$	249.0
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from
Additional capital contribution from parent	3.5			3.5			(3.5		)	3.5
Long-term debt - net of issuance costs	—			99.5			—			99.5
Requirements for:
Dividends to parent	(47.2		)	(50.5		)	47.2			(50.5		)
Net change in intercompany short-term borrowings	(52.9		)	17.7			35.2			—
Net change in short-term borrowings	—			(181.3		)	—			(181.3		)
Net cash flows from financing activities	(96.6		)	(111.1		)	78.9			(128.8		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from
Consolidated subsidiary distributions	—			47.2			(47.2		)	—
Other investing activities	—			2.2			—			2.2
Requirements for:
Capital expenditures, excluding AFUDC equity	(121.4		)	(2.7		)	—			(124.1		)
Consolidated subsidiary investments	—			(3.5		)	3.5			—
Other investing activities	(0.2		)	—			—			(0.2		)
Net change in short-term intercompany notes receivable	(17.7		)	52.9			(35.2		)	—
Net cash flows from investing activities	(139.3		)	96.1			(78.9		)	(122.1		)
Net change in cash & cash equivalents	(2.6		)	0.7			—			(1.9		)
Cash & cash equivalents at beginning of period	5.3			0.7			—			6.0
Cash & cash equivalents at end of period	$	2.7		$	1.4		$	—		$	4.1

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

	Subsidiary Guarantors			Parent 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

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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 $5.0 million and $5.4 million in the three months ended June 30, 2012 and 2011 respectively. For the six months ended June 30, 2012 and 2011, these taxes totaled $14.3 million and $16.4 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, 2012 and December 31, 2011, the Company has accruals related to utility and nonutility plant purchases totaling approximately $11.0 million and $9.2 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, 2012 and 2011 totaled $33.3 million and $42.5 million, respectively, and for the six months ended June 30, 2012 and 2011 totaled $58.2 million and $75.8 million, respectively.  Amounts owed to Vectren Fuels at June 30, 2012 and December 31, 2011 are included in Payables to other Vectren companies in the Consolidated Balance Sheets.

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 $11.5 million and $8.6 million for the three months ended June 30, 2012 and 2011, respectively, and for the six months ended June 30, 2012 and 2011 totaled $19.6 million and $13.2 million, respectively.  Amounts owed to Miller at June 30, 2012 and December 31, 2011 are included in Payables to other Vectren companies in the Consolidated Balance Sheets.

ProLiance Holdings, LLC (ProLiance)

ProLiance, a nonutilityenergy 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 as well as Citizens’ utilities.  ProLiance’s primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services. 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.

Purchases from ProLiance for resale and for injections into storage for the three months ended June 30, 2012 and 2011 totaled $50.2 million and $79.0 million, respectively, and for the six months ended June 30, 2012 and 2011 totaled $129.7 million and $198.3 million, respectively.  Amounts owed to ProLiance at June 30, 2012 and December 31, 2011 for those purchases were $13.8 million and $36.8 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.  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, 2012  and 2011, Utility Holdings received corporate allocations totaling $11.4 million and $12.4 million, respectively. For the six months ending June 30, 2012 and 2011, Utility Holdings received corporate allocations totaling $23.9 million and $26.2 million, respectively.

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The Company does not have share-based compensation plans and pension and other postretirement plans separate from Vectren and allocated costs include participation in Vectren’s plans.  The allocation methodology for retirement costs is consistent with FASB guidance related to “multiemployer” benefit accounting.

7. Financing Activities

On February 1, 2012, the Company issued $100 million of senior unsecured notes at an interest rate of 5.00 percent per annum and with a maturity date of February 3, 2042.  The notes were sold to various institutional investors pursuant to a private placement note purchase agreement executed in November 2011 with a delayed draw feature.  These senior notes are unsecured and jointly and severally guaranteed by Utility Holdings’ regulated utility subsidiaries, SIGECO, Indiana Gas, and VEDO.  The proceeds from the sale of the notes, net of issuance costs, totaled approximately $99.5 million.  These notes have no sinking fund requirements and interest payments are due semi-annually.  These notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Utility Holdings’ borrowing arrangements. As of December 31, 2011, the Company had reclassified $100 million of short-term borrowings as long-term debt to reflect those borrowings were refinanced with the proceeds received.

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 Matters

Pipeline Safety Law

On January 3, 2012 the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 was signed into law.  This new law, which reauthorizes federal pipeline safety programs through fiscal year 2015, provides for enhanced safety, reliability and environmental protection in the transportation of energy products by pipeline. The new law increases federal enforcement authority, grants the federal government expanded authority over pipeline safety, provides for new safety regulations and standards, and authorizes or requires the completion of several pipeline safety-related studies.  The DOT is required to promulgate a number of new regulatory requirements.  Those regulations may eventually lead to further regulatory or statutory requirements.

The Company continues to study the impact of the new law and potential new regulations associated with its implementation.  At this time, compliance costs and other effects associated with the increased pipeline safety regulations remain uncertain.  However, the new law is expected to result in further investment in pipeline inspections, and where necessary, additional modernization of pipeline infrastructure; and therefore, result in both increased levels of operating expenses and capital expenditures associated with the Company’s natural gas distribution businesses.  Operating expenses associated with expanded compliance requirements may grow to approximately $9 million annually, with $6 million attributable to the Indiana operations.  Related to the Indiana operations, the Company expects to seek recovery under Senate Bill 251 referenced below, or such costs may be recoverable through current tracking mechanisms.  Capital investments, driven by the pipeline safety regulations, associated with the Company’s Indiana gas utilities are expected to be approximately $80 million over the next five years, which would likely qualify as federally mandated regulatory requirements.  In Ohio, capital investments are expected to be approximately $55 million over the next five years.  The Company expects to seek recovery of capital investments associated with complying with these federal mandates in accordance with Senate Bill 251 in Indiana and House Bill 95 in Ohio (referenced below).

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 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 general rate case.  Such costs include construction,

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depreciation, operating and other costs.  The remaining 20 percent of those costs are to be deferred for recovery in the utility’s next general rate case.  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 control, including greenhouse gas emissions, among other federally mandated projects and potential projects. 

Ohio House Bill 95

In June 2011, Ohio House Bill 95 was 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 for recovery of 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 deferral of program costs, such as depreciation, property taxes, and debt-related carrying costs.  On February 3, 2012, the Company initiated a filing under House Bill 95.  This filing requests accounting authority to defer depreciation, debt-related post in service carrying costs and property taxes for its approximate $25 million fifteen month capital expenditure program ending on December 31, 2012.  The capital expenditure program includes infrastructure expansion and improvements not covered by the Company’s distribution replacement rider as well as expenditures necessary to comply with PUCO rules, regulations and orders.  The Company’s approach is consistent with approaches made by other Ohio utilities.  A procedural schedule associated with the filing has been set and all respective responses have been submitted.  It is anticipated the PUCO will act on the Company’s filing and the flings of the other Ohio utilities later this year.

10. Environmental Matters

Air Quality

Cross-State Air Pollution Rule (Formerly Clean Air Interstate Rule (CAIR))

On July 7, 2011, EPA finalized the Cross-State Air Pollution Rule (CSAPR).  CSPAR is the EPA’s response to the US Court of Appeals for the District of Columbia’s (the Court) remand of the Clean Air Interstate Rule (CAIR). CAIR was originally established in 2005 as an allowance cap and trade program that required reductions from coal-burning power plants for NOx emissions beginning January 1, 2009 and SO₂ emissions beginning January 1, 2010, with a second phase of reductions in 2015.

In an effort to address the Court’s finding that CAIR did not adequately ensure attainment of pollutants in certain downwind states due to unlimited trading of SO₂ and NOx allowances, CSPAR reduces the ability of facilities to meet emission reduction targets through allowance trading.  Like CAIR, CSPAR sets individual state caps for SO₂ and NOx emissions.  However, unlike CAIR in which states allocated allowances to generating units through state implementation plans, CSPAR allowances were allocated to individual units directly through the federal rule.  As finalized, CSAPR requires a 71 percent reduction of SO₂ emissions compared to 2005 national levels and a 52 percent reduction of NOx emissions compared to 2005 national levels and that such reductions are to be achieved with initial step reductions beginning January 1, 2012, with final compliance to be achieved in 2014.  Multiple administrative and judicial challenges were filed, including requests to stay CSPAR’s implementation. On December 30, 2011, the Court granted a stay of CSPAR and ordered expedited briefing. Briefing is completed and oral arguments were held in April. A final ruling is expected later this year.

Mercury and Air Toxics (MATS) Rule

On December 21, 2011, the EPA finalized the Utility MATS Rule.  The MATS Rule is the EPA’s response to the US Court of Appeals for the District of Columbia vacating the Clean Air Mercury Rule (CAMR) in 2008.  CAMR was originally established in 2005 as a nation-wide mercury emission allowance cap and trade system which sought to reduce utility emissions of mercury starting in 2010.

The MATS Rule sets emission limits for hazardous air pollutants for existing and new coal-fired power plants and identifies the following broad categories of hazardous air pollutants:  mercury, non-mercury hazardous air pollutants (primarily arsenic, chromium, cobalt, and selenium) and acid gases (hydrogen cyanide, hydrogen chloride, and hydrogen fluoride).  The rule imposes mercury emission limits for two sub-categories of coal, and proposed surrogate limits for non-mercury and acid gas hazardous air pollutants. The EPA did not grant blanket compliance extensions, but asserted that states have broad authority to

15

grant one year extensions for individual units where potential reliability impacts have been demonstrated.  Reductions are to be achieved within three years of publication of the final rule in the Federal register (April 2015).  Initiatives to suspend CSPAR’s implementation by the Congress also apply to the implementation of the MATS rule.  Multiple judicial challenges were filed and briefing is proceeding. The EPA also recently announced it will reconsider MATS requirements for new construction. Such requirements are more stringent than those for existing plants. Utilities planning new coal-fired generation had argued standards outlined in the MATS could not be attained even using the best available control technology.

Conclusions Regarding Air Regulations

To comply with Indiana’s implementation plan of the Clean Air Act, and other federal air quality standards, the Company obtained authority from the IURC to invest in clean coal technology.  Using this authorization, the Company invested approximately $411 million starting in 2001 with the last equipment being placed into service on January 1, 2010.  The pollution control equipment included 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 obtained April 27, 2011.  SIGECO’s coal fired generating fleet is 100 percent scrubbed for SO₂ and 90 percent controlled for NOx. 

Utilization of the Company’s NOx and SO₂  allowances can be impacted as these regulations are revised and implemented.  Most of these allowances were granted to the Company at zero cost; therefore, any reduction in carrying value that could result from future changes in regulations would be immaterial.

The Company is currently reviewing the sufficiency of its existing pollution control equipment in relation to the requirements described in CSPAR and the MATS Rule.  Based upon an initial review of the final rules, including minor revisions made to CSPAR in October 2011, 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 and additional operating expenses could be required.  The Company believes that such additional costs, if necessary, would be recoverable under Indiana Senate Bill 251 referenced above.

Notice of Violation Received

The Company received a notice of violation (NOV) from the EPA pertaining to its A.B. Brown power plant.  The NOV asserts that when the power plant was equipped with SCRs the correct permits were not obtained or the best available control technology to control incidental sulfuric acid mist was not installed.  Based on the Company’s understanding of the New Source Review reform in effect when the equipment was installed, it is the Company’s position that its SCR project was exempted from such requirements.  At this time the Company is reviewing the potential impact this NOV could have on operating costs.  To the extent costs to comply increase, they should be recoverable under Indiana law.

Water

Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” to minimize adverse environmental impacts in a body of water.  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 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.  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.  A final rule is expected in 2013.  Depending on the final rule and on the Company’s facts and circumstances, capital investments could be in the $40 million range if new infrastructure, such as new cooling water towers, is required.  Costs for compliance with these final regulations would likely qualify as federally mandated regulatory requirements under Indiana Senate Bill 251 referenced above.

Coal Ash Waste Disposal & Ash Ponds

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

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and would likely increase the cost of operating or expanding existing ash ponds and the development of new ash ponds.  The alternatives include regulating coal combustion by-products that are not being beneficially reused as hazardous waste.  The EPA did not offer a preferred alternative, but took public comment on multiple alternative regulations.  Rules may not be finalized in 2012 given oversight hearings, congressional interest, and other factors.

At this time, the majority of the Company’s ash is being beneficially reused.  However, the alternatives proposed would require modification to or closure of existing ash ponds.  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.  Costs for compliance with these regulations would likely qualify as federally mandated regulatory requirements under Senate Bill 251 referenced above. 

Climate Change

In April 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 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 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.  The EPA has promulgated two greenhouse gas regulations that apply to the Company’s generating facilities.  In 2009, the EPA finalized a mandatory greenhouse gas emissions registry which requires the reporting of emissions.  The EPA has also 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.  EPA's PSD and Title V permitting rules for GHG's were recently upheld by the US Court of Appeals for the District of Columbia. In April 2012, the EPA issued its proposed new source performance standards for greenhouse gases applicable to new construction.  This proposed rule does not apply to existing sources, such as Vectren’s generating facilities.  The EPA has not indicated when it intends to propose standards for existing sources.

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 or rulemaking, 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. 

Manufactured Gas Plants

In the past, the Company operated facilities to manufacture natural gas.  Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years.  Under current 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.

In the Indiana Gas service territory, the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites have been identified for which the Company may have some remedial responsibility.  A remedial investigation/

17

feasibility study (RI/FS) was completed 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.  The remaining sites have been submitted to the IDEM's Voluntary Remediation Program (VRP).  The Company has identified its involvement in five manufactured gas plant sites in SIGECO’s service territory, all of which are currently enrolled in the IDEM’s VRP.  The Company is currently conducting some level of remedial activities, including groundwater monitoring at certain sites.

The Company has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites.  While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, the Company has recorded cumulative costs that it reasonably expects to incur totaling approximately $41.7 million ($23.2 million at Indiana Gas and $18.5 million at SIGECO).  The estimated accrued costs are limited to the Company’s share of the remediation efforts and are therefore net of exposures of other potentially responsible parties (PRP).

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.  SIGECO filed a declaratory judgment action against its insurance carriers seeking a judgment finding its carriers liable under the policies for coverage of further investigation and any necessary remediation costs that SIGECO may accrue under the VRP program and/or another site subject to a lawsuit that has been settled.  In November 2011, 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 settlement agreements with all known insurance carriers and has recorded approximately $15.2 million of expected insurance recoveries.

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, 2012 and December 31, 2011, respectively, approximately $4.7 million and $6.5 million of accrued, but not yet spent, costs are included in Other Liabilities related to both the Indiana Gas and SIGECO sites.

11. 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.  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 would be initiated.

Coal Procurement Procedures

Vectren South submitted a request for proposal in April 2011 regarding coal purchases for a four year period beginning in 2012.  After negotiations with bidders, Vectren South 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 case, a sub docket proceeding was established to review the Company’s prospective coal procurement procedures, and the Company submitted evidence related to its recent request for proposal (RFP) and those coal procurement procedures to the IURC in September 2011.  In March 2012, the IURC issued its order in the sub docket.  The order concluded that Vectren South’s 2011 RFP process resulted in prices at the lowest fuel cost reasonably possible.  The IURC will continue to regularly monitor Vectren South’s procurement process in future fuel adjustment proceedings.

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Vectren South Electric Fuel Cost Reduction

In the spring of 2011, Vectren South secured contracts for lower coal costs through a formal bidding process. This lower-priced contract coal started being delivered to Vectren’s power plants during 2012. On December 5, 2011 within the quarterly FAC filing, Vectren South submitted a joint proposal with the OUCC to reduce its fuel costs by accelerating into 2012 the impact of lower cost coal under new term contracts effective after 2012. The cost difference will be deferred to a regulatory asset and recovered over a six-year period without interest beginning in 2014.  The IURC approved this proposal on January 25, 2012, with a positive impact to customer’s rates effective February 1, 2012.  The deferred amount includes a reduction in the value of the coal inventory at December 31, 2011 of approximately $17.7 million to reflect existing coal inventory at the new, lower price.  Deferrals related to coal purchases in 2012 have totaled approximately $22.4 million, bringing the total deferred balance as of June 30, 2012 to $40.1 million. In addition to coal purchased under these contracts, Vectren South has also recently contracted with Vectren Fuels, Inc. to purchase lower priced spot coal. This spot purchase was found to be reasonable in a recent FAC order.

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, and include some for 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.

On August 31, 2011 the IURC issued an order approving an initial three year DSM plan in the Vectren South service territory that complies with the IURC’s energy saving targets.  Consistent with the Company’s proposal, the order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; 3) lost margin recovery associated with the implementation of DSM programs for large customers; and 4) deferral of lost margin up to $1.0 million in 2011 associated with small customer DSM programs for subsequent recovery under a tracking mechanism to be proposed by the Company.  On June 20, 2012, the IURC issued an order approving a small customer lost margin recovery mechanism, inclusive of all previous deferrals. This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the Company's last base rate proceeding discussed earlier. 

Vectren South Electric Dense Pack Filing

On September 14, 2011, Vectren South filed a petition with the IURC seeking recovery of and return on the capital investment in dense pack technology to improve the efficiency of its A.B. Brown Generating Station.  This investment is expected to be approximately $32 million over the next two years, of which approximately $25.8 million has been invested to date.  This technology is expected to allow the A.B. Brown units to run at least 5 percent more efficient, thereby burning less fuel, and reducing fuel costs and emissions of pollutants.  In the Company’s base rate order issued in April 2011, the IURC authorized deferred accounting treatment associated with this investment. As a result of a subsequent filing by the Company seeking a current recovery mechanism in lieu of the deferred accounting treatment, the IURC issued an order on July 11, 2012, denying the Company's request for a current recovery mechanism stating that dense pack technology does not qualify as advanced technology under the statute. Although the Company believes that the investment does meet the requirements of the statute that would have allowed for timely recovery, it does not plan to appeal the decision and will employ the deferred accounting treatment ordered in the Company's last base rate order discussed earlier.

Vectren North Reporting Location Consolidation Proceeding

Vectren North implemented a reporting location consolidation plan in 2011 and  converted certain reporting locations into staging areas throughout the Vectren North territory.  On May 26, 2011, the International Brotherhood of Electrical Workers Local 1393, United Steel Workers Locals 12213 and 7441 and others (the “Complainants”) filed a formal complaint with the IURC claiming that implementation of the consolidation plan by Vectren North endangers public safety and impairs Vectren North's ability to provide adequate, safe and reliable service.  The Complainants asked the IURC to require Vectren North to reopen previously

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consolidated reporting locations and maintain and staff those locations.  A hearing in this case was held in February 2012.  Complainants submitted a proposed order in March and Vectren North submitted a reply brief and a proposed order in April.  The Company expects the IURC to issue a final order in this matter some time in 2012.

12. Fair Value Measurements

The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow:

	June 30, 2012				December 31, 2011
(In millions)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	1,208.3	$	1,390.0	$	1,208.2	$	1,345.7
Short-term borrowings	61.5		61.5		142.8		142.8
Cash & cash equivalents	4.1		4.1		6.0		6.0

For the balance sheet dates presented in these financial statements, the Company had material assets or liabilities recorded at fair value outstanding.

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.

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.

13. Impact of Recently Issued Accounting Principles

Other Comprehensive Income (OCI)

In 2011, the FASB issued new accounting guidance regarding the presentation of comprehensive income within financial statements.  The new guidance requires entities to report components of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements.  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 adopted this guidance, as amended for condensed quarterly reporting, for the quarterly reporting period ended March 31, 2012.  During the periods presented comprehensive income and net income were equal.

Goodwill Testing

In September 2011, the FASB issued new accounting guidance regarding testing goodwill for impairment.  The new guidance will allow the Company an option to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test.  Using the new guidance, the Company no longer would be required to calculate the fair value of a reporting unit unless the Company determines, based on that qualitative assessment, that it is more likely than not that its fair value is less than its carrying amount.  The Company considered this option during its quarterly reporting period ended March 31, 2012 and concluded the continuation of the use of a quantitative approach is appropriate.

Fair Value Measurement and Disclosure

In May 2011, the FASB issued accounting guidance to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and International Financial Reporting Standards (IFRS). The amendments are not intended to change the application of the current fair value requirements, but to clarify the

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application of existing requirements. The guidance does change particular principles or requirements for measuring fair value or disclosing information about fair value measurements. To improve consistency, language has been changed to ensure that U.S. GAAP and IFRS fair value measurement and disclosure requirements are described in the same way. The Company adopted this guidance for its quarterly reporting period ended March 31, 2012.  The adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.

14. 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 Gas Utility Services  and Electric Utility Services.  Gas Utility Services provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio.  Electric Utility Services provides electric distribution services 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 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 Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2012			2011			2012			2011
Revenues
Gas Utility Services	$	116.0		$	134.0		$	408.3		$	490.7
Electric Utility Services	149.3			159.3			288.7			305.7
Other Operations	10.0			10.9			19.9			21.9
Eliminations	(9.5		)	(10.4		)	(19.0		)	(20.9		)
Total revenues	$	265.8		$	293.8		$	697.9		$	797.4
Profitability Measure - Net Income
Gas Utility Services	$	1.3		$	2.1		$	38.8		$	38.3
Electric Utility Services	17.2			13.6			32.8			22.3
Other Operations	1.6			0.6			4.5			4.3
Total net income	$	20.1		$	16.3		$	76.1		$	64.9

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

Description of the Business

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 earns a return on shared 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 567,000 natural gas customers located in central and southern Indiana.  SIGECO provides energy delivery services to approximately 142,000 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.  VEDO provides energy delivery services to approximately 312,000 natural gas customers located near Dayton in west central Ohio.

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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 2011 annual report filed on Form 10-K.

In the second quarter of 2012, Utility Holdings' earnings were $20.1 million compared to $16.3 million in 2011. In the six months ended June 30, 2012, Utility Holdings' earned $76.1 million, compared to the $64.9 million in 2011. Increased year-over-year results reflect the impacts of new electric base rates implemented on May 3, 2011 and lower interest expense as a result of refinancing activity in the last quarter of 2011 and first quarter of 2012.

Gas Utility Services

During the second quarter of 2012, Gas Utility earnings were $1.3 million compared to earnings of $2.1 million in the second quarter of 2011. In the six months ended June 30, 2012, gas utility operations earned $38.8 million, compared to earnings of $38.3 million in 2011. Results in 2012 have been impacted by lower interest expense due to the recent refinancing activity, offset by higher depreciation and lower margins due primarily to lower gas costs with some impact from warmer winter weather.

Electric utility services

During the second quarter of 2012, Electric Utility earnings were $17.2 million compared to $13.6 million in the second quarter of 2011. Electric operations earned $32.8 million year to date in 2012, compared to earnings of $22.3 million for the six months endedJune 30, 2011. Improved results in 2012 reflect increased electric margin, primarily from base rate changes, and lower operating and interest costs.

Other utility operations

In the second quarter of 2012, earnings from Other Utility operations were $1.6 million compared to $0.6 million in 2011. In the six months ended June 30, 2012, earnings from these operations were $4.5 million compared to $4.3 million in 2011. The second quarter of 2011 includes a $1.4 million unfavorable tax adjustment.

Operating Trends

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.

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

Gas utility margin and throughput by customer type follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2012		2011		2012		2011
Gas utility revenues	$	116.0	$	134.0	$	408.3	$	490.7
Cost of gas sold	31.8		48.8		168.9		243.9
Total gas utility margin	$	84.2	$	85.2	$	239.4	$	246.8
Margin attributed to:
Residential & commercial customers	$	69.5	$	70.3	$	204.6	$	210.0
Industrial customers	12.4		11.9		28.9		29.5
Other	2.3		3.0		5.9		7.3
Total gas utility margin	$	84.2	$	85.2	$	239.4	$	246.8
Sold & transported volumes in MMDth attributed to:
Residential & commercial customers	$	10.2	$	11.7	$	51.0	$	64.5
Industrial customers	24.3		21.1		52.1		49.9
Total sold & transported volumes	$	34.5	$	32.8	$	103.1	$	114.4

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Gas Utility margins were $84.2 million and $239.4 million for the for the three and six months ended June 30, 2012, and compared to 2011 decreased $1.0 million quarter over quarter and $7.4 million year to date. The impact of low natural gas prices and mild weather on revenue taxes, late and reconnect fees, and volumetric pass through costs decreased gas utility margin $2.1 million quarter over quarter and $7.4 million year to date.  Returns generated on investments in bare steel/ cast iron and distribution riser replacement in Ohio increased margins $0.6 million in the quarter and $1.3 million year to date in 2012 compared to the prior year. With rate designs that substantially limit the impact of weather on margin, temperatures that were 71 percent of normal in Indiana and 82 percent of normal in Ohio during the peak winter heating season had a significant impact on volumes sold, but only a slightly negative impact on margin, reducing margin $0.7 million year over year.

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

Electric utility margin and volumes sold by customer type follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2012		2011		2012		2011
Electric utility revenues	$	149.3	$	159.3	$	288.7	$	305.7
Cost of fuel & purchased power	47.0		60.3		91.7		119.8
Total electric utility margin	$	102.3	$	99.0	$	197.0	$	185.9
Margin attributed to:
Residential & commercial customers	$	65.7	$	63.0	$	124.4	$	117.0
Industrial customers	26.8		25.5		52.1		48.9
Other customers	1.9		1.6		3.7		3.5
Subtotal: retail	$	94.4	$	90.1	$	180.2	$	169.4
Wholesale power & transmission system margin	7.9		8.9		16.8		16.5
Total electric utility margin	$	102.3	$	99.0	$	197.0	$	185.9
Electric volumes sold in GWh attributed to:
Residential & commercial customers	693.3		677.9		1,324.4		1,359.5
Industrial customers	713.4		680.9		1,395.1		1,342.8
Other customers	4.8		4.8		10.7		10.7
Total retail volumes sold	1,411.5		1,363.6		2,730.2		2,713.0

Retail

Electric retail utility margins were $94.4 million and $180.2 million for the three and six months ended June 30, 2012, and compared to 2011 increased by $4.3 million in the quarter and $10.8 million year to date.  Margin across all customer classes increased by $2.4 million in the quarter and $10.0 million year to date from new base rates effective May 3, 2011.  Large customer margin increased $1.2 million in the quarter and $1.9 million year to date on increasing volumes.  Quarter over quarter weather impacts increased margin by an estimated $1.6 million and year over year decreased margin by an estimated $1.8 million.

Electric results, which are not protected by weather mechanisms, were positively impacted in the second quarter of 2012. Such impacts have offset first quarter negative impacts. On a year to date basis, the impact of weather is essentially flat compared to normal temperatures. In the second quarter of 2012, cooling temperatures were 146 percent of normal; this compares to the second quarter of last year when cooling temperatures were 124 percent of normal. In the second quarter of 2012, the increase in electric margin attributable to warmer than normal temperatures was $3.3 million. In 2012, winter heating weather was 29 percent warmer than normal.

Since the most recent rate case effective May 3, 2011, cooling weather has been in excess of normal temperatures which has positively impacted electric retail sales and operating results. Indiana statute has a statutory mechanism that can limit a utility's rolling twelve month net operating income to that authorized in its last general rate order, as adjusted for previous net operating income levels that were below authorized levels. This earnings test limit mechanism has not resulted in material refunds in past periods. However, should weather or other factors continue to increase net operating income in future periods, the full benefit of

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those favorable impacts on the Company's electric utility may be limited by the statutory earnings test.

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 Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2012		2011		2012		2011
Off-system sales	$	0.7	$	2.4	$	3.7	$	4.4
Transmission system sales	7.2		6.5		13.1		12.1
Total wholesale margin	$	7.9	$	8.9	$	16.8	$	16.5

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 $13.1 million during the six months ended June 30, 2012, compared to $12.1 million for the same period in 2011.  During the 2012 second quarter earnings were $7.2 million compared to $6.5 million in the prior year second quarter. The increases in these transmission system revenue are principally due to the increased investment in qualifying projects.

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 $110 million, the Company has invested approximately $92.6 million as of June 30, 2012.  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 later in 2012. 

For the six months ended June 30, 2012, margin from off-system sales was $3.7 million, compared to $4.4 million for the six months ended June 30, 2011. 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.  The year to date period reflects lower volumes sold, offset by the impacts of sharing which increased margin $0.6 million. Off-system sales totaled 124.7 GWh and 326.9 GWh during the six months ended June 30, 2012 and 2011, respectively, reflecting reduced opportunities in 2012 due to unfavorable weather conditions when excess generation is more prevalent and the low cost of natural gas. In the second quarter of 2012 margin from off system sales was $0.7 million compared to $2.4 million in 2011, with the decrease being primarily related to the timing of sharing recognition.

Operating Expenses

Other Operating

For the six months ended June 30, 2012, other operating expenses were $157.7 million, a decrease of $7.4 million, compared to 2011.  The decrease results primarily from $3.4 million in lower uncollectible accounts expense driven by lower gas prices increasing customer’s ability to pay and $4.6 million lower power supply operating costs reflecting lower outage costs.  The remaining decrease is primarily attributable to lower pass through operating costs that are offset with lower Gas Utility margin. Quarter over quarter operating expenses decreased $0.4 million driven primarily by the lower outage costs.

Depreciation & Amortization

For the six months ended June 30, 2012, depreciation and amortization expense was $96.4 million, which represents an increase of $0.3 million compared to 2011.  Both the year to date and quarter over quarter periods reflect increased plant placed into service, offset by lower amortization of certain deferred costs pursuant to the May 2011 electric base rate order.  Such

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decreased amortizations in 2012 were $1.3 million year to date and $0.3 million in the quarter.

Taxes Other Than Income Taxes

Year to date in 2012, taxes other than income taxes were $27.5 million and in the quarter were $11.6 million. The year to date decrease of $1.6 million compared to the prior year was primarily due to lower usage taxes associated with lower gas and fuel costs. These expenses are offset dollar-for-dollar with lower gas utility and electric utility revenues.

Other Income-Net

Other income-net reflects income of $2.9 million year to date in 2012 and $0.7 million for the second quarter. Decreases compared to the prior year periods are primarily due to lower earnings on assets that fund benefit plans and the quarter was also impacted by reduced AFUDC on lower overall borrowing rates.

Interest Expense

Interest expense was $35.7 million for the six months ended June 30, 2012. Interest expense decreased $5.1 million year over year and $2.4 million in the quarter compared to 2011. The lower expense both year to date and in the quarter reflects fourth quarter of 2011 refinancing activity in which $250 million of long-term debt with a 6.625 percent interest rate matured and was replaced with $150 million of new long-term debt with an average interest rate of 5.12 percent and $100 million of short-term borrowings.  During the fourth quarter of 2011, the Company also called $96.2 million of long-term debt at a rate of 5.95 percent and replaced that issuance in February 2012 with new debt at a rate of 5.0 percent.

Income Taxes

In the six months ended June 30, 2012, federal and state income taxes were $46.8 million, an increase of $5.2 million compared to the prior year.  In the quarter federal and state taxes decreased $0.6 million. The year to date increase is primarily due to higher pre-tax income. The second quarter of 2011 included a one-time, unfavorable tax adjustment of $1.4 million.

Legislative Matters

Pipeline Safety Law

On January 3, 2012 the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 was signed into law.  This new law, which reauthorizes federal pipeline safety programs through fiscal year 2015, provides for enhanced safety, reliability and environmental protection in the transportation of energy products by pipeline. The new law increases federal enforcement authority, grants the federal government expanded authority over pipeline safety, provides for new safety regulations and standards, and authorizes or requires the completion of several pipeline safety-related studies.  The DOT is required to promulgate a number of new regulatory requirements.  Those regulations may eventually lead to further regulatory or statutory requirements.

The Company continues to study the impact of the new law and potential new regulations associated with its implementation.  At this time, compliance costs and other effects associated with the increased pipeline safety regulations remain uncertain.  However, the new law is expected to result in further investment in pipeline inspections, and where necessary, additional modernization of pipeline infrastructure; and therefore, result in both increased levels of operating expenses and capital expenditures associated with the Company’s natural gas distribution businesses.  Operating expenses associated with expanded compliance requirements may grow to approximately $9 million annually, with $6 million attributable to the Indiana operations.  Related to the Indiana operations, the Company expects to seek recovery under Senate Bill 251 referenced below, or such costs may be recoverable through current tracking mechanisms.  Capital investments, driven by the pipeline safety regulations, associated with the Company’s Indiana gas utilities are expected to be approximately $80 million over the next five years, which would likely qualify as federally mandated regulatory requirements.  In Ohio, capital investments are expected to be approximately $55 million over the next five years.  The Company expects to seek recovery of capital investments associated with complying with these federal mandates in accordance with Senate Bill 251 in Indiana and House Bill 95 in Ohio (referenced below).

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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 law applies to both gas and electric utility operations and provides a framework to recover 80 percent of federally mandated operating costs and capital investments through a periodic rate adjustment mechanism outside of a general rate case.  Such costs include depreciation, operating and other costs.  Construction costs receive a return on investment. The remaining 20 percent of those costs and capital investments are to be deferred for recovery in the utility’s next general rate case.  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 control, including greenhouse gas emissions, among other federally mandated projects and potential projects. 

Ohio House Bill 95

In June 2011, Ohio House Bill 95 was 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 for recovery of 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 deferral of program costs, such as depreciation, property taxes, and debt-related carrying costs.  On February 3, 2012, the Company initiated a filing under House Bill 95.  This filing requests accounting authority to defer depreciation, debt-related post in service carrying costs and property taxes for its approximate $25 million fifteen month capital expenditure program ending on December 31, 2012.  The capital expenditure program includes infrastructure expansion and improvements not covered by the Company’s distribution replacement rider as well as expenditures necessary to comply with PUCO rules, regulations and orders.  The Company’s approach is consistent with approaches made by other Ohio utilities.  A procedural schedule associated with the filing has been set and all respective responses have been submitted.  It is anticipated the PUCO will act on the Company’s filing and the flings of the other Ohio utilities later this year.

Environmental Matters

Air Quality

Cross-State Air Pollution Rule (Formerly Clean Air Interstate Rule (CAIR))

On July 7, 2011, EPA finalized the Cross-State Air Pollution Rule (CSAPR).  CSPAR is the EPA’s response to the US Court of Appeals for the District of Columbia’s (the Court) remand of the Clean Air Interstate Rule (CAIR). CAIR was originally established in 2005 as an allowance cap and trade program that required reductions from coal-burning power plants for NOx emissions beginning January 1, 2009 and SO₂ emissions beginning January 1, 2010, with a second phase of reductions in 2015.

In an effort to address the Court’s finding that CAIR did not adequately ensure attainment of pollutants in certain downwind states due to unlimited trading of SO₂ and NOx allowances, CSPAR reduces the ability of facilities to meet emission reduction targets through allowance trading.  Like CAIR, CSPAR sets individual state caps for SO₂ and NOx emissions.  However, unlike CAIR in which states allocated allowances to generating units through state implementation plans, CSPAR allowances were allocated to individual units directly through the federal rule.  As finalized, CSAPR requires a 71 percent reduction of SO₂ emissions compared to 2005 national levels and a 52 percent reduction of NOx emissions compared to 2005 national levels and that such reductions are to be achieved with initial step reductions beginning January 1, 2012, with final compliance to be achieved in 2014.  Multiple administrative and judicial challenges were filed, including requests to stay CSPAR’s implementation. On December 30, 2011, the Court granted a stay of CSPAR and ordered expedited briefing. Briefing is completed and oral arguments were held in April. A final ruling is expected later this year.

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Mercury and Air Toxics (MATS) Rule

On December 21, 2011, the EPA finalized the Utility MATS Rule.  The MATS Rule is the EPA’s response to the US Court of Appeals for the District of Columbia vacating the Clean Air Mercury Rule (CAMR) in 2008.  CAMR was originally established in 2005 as a nation-wide mercury emission allowance cap and trade system which sought to reduce utility emissions of mercury starting in 2010.

The MATS Rule sets emission limits for hazardous air pollutants for existing and new coal-fired power plants and identifies the following broad categories of hazardous air pollutants:  mercury, non-mercury hazardous air pollutants (primarily arsenic, chromium, cobalt, and selenium) and acid gases (hydrogen cyanide, hydrogen chloride, and hydrogen fluoride).  The rule imposes mercury emission limits for two sub-categories of coal, and proposed surrogate limits for non-mercury and acid gas hazardous air pollutants. The EPA did not grant blanket compliance extensions, but asserted that states have broad authority to grant one year extensions for individual units where potential reliability impacts have been demonstrated.  Reductions are to be achieved within three years of publication of the final rule in the Federal register (April 2015).  Initiatives to suspend CSPAR’s implementation by the Congress also apply to the implementation of the MATS rule.  Multiple judicial challenges were filed and briefing is proceeding. The EPA also recently announced it will reconsider MATS requirements for new construction. Such requirements are more stringent than those for existing plants. Utilities planning new coal-fired generation had argued standards outlined in the MATS could not be attained even using the best available control technology.

Conclusions Regarding Air Regulations

To comply with Indiana’s implementation plan of the Clean Air Act, and other federal air quality standards, the Company obtained authority from the IURC to invest in clean coal technology.  Using this authorization, the Company invested approximately $411 million starting in 2001 with the last equipment being placed into service on January 1, 2010.  The pollution control equipment included 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 obtained April 27, 2011.  SIGECO’s coal fired generating fleet is 100 percent scrubbed for SO₂ and 90 percent controlled for NOx. 

Utilization of the Company’s NOx and SO₂  allowances can be impacted as regulations are revised and implemented.  Most of these allowances were granted to the Company at zero cost; therefore, any reduction in carrying value that could result from future changes in regulations would be immaterial.

The Company is currently reviewing the sufficiency of its existing pollution control equipment in relation to the requirements described in CSPAR and the MATS Rule.  Based upon an initial review of the final rules, including minor revisions made to CSPAR in October 2011, 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 and additional operating expenses could be required.  The Company believes that such additional costs, if necessary, would be recoverable under Indiana Senate Bill 251 referenced above.

Notice of Violation Received

The Company received a notice of violation (NOV) from the EPA pertaining to its A.B. Brown power plant.  The NOV asserts that when the power plant was equipped with SCRs the correct permits were not obtained or the best available control technology to control incidental sulfuric acid mist was not installed.  Based on the Company’s understanding of the New Source Review reform in effect when the equipment was installed, it is the Company’s position that its SCR project was exempted from such requirements.  At this time the Company is reviewing the potential impact this NOV could have on operating costs.  To the extent costs to comply increase, they should be recoverable under Indiana law.

Water

Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” to minimize adverse environmental impacts in a body of water.  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 2009, the U.S.

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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.  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.  A final rule is expected in 2013.  Depending on the final rule and on the Company’s facts and circumstances, capital investments could be in the $40 million range if new infrastructure, such as new cooling water towers, is required.  Costs for compliance with these final regulations would likely qualify as federally mandated regulatory requirements under Indiana Senate Bill 251 referenced above.

Coal Ash Waste Disposal & Ash Ponds

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 alternatives include regulating coal combustion by-products that are not being beneficially reused as hazardous waste.  The EPA did not offer a preferred alternative, but took public comment on multiple alternative regulations.  Rules may not be finalized in 2012 given oversight hearings, congressional interest, and other factors.

At this time, the majority of the Company’s ash is being beneficially reused.  However, the alternatives proposed would require modification to or closure of existing ash ponds.  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.  Costs for compliance with these regulations would likely qualify as federally mandated regulatory requirements and be recovered under Senate Bill 251 referenced above. 

Climate Change

In April 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 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 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.  The EPA has promulgated two greenhouse gas regulations that apply to the Company’s generating facilities.  In 2009, the EPA finalized a mandatory greenhouse gas emissions registry which requires the reporting of emissions.  The EPA has also 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.  EPA's PSD and Title V permitting rules for GHG's were recently upheld by the US Court of Appeals for the District of Columbia. In April 2012, the EPA issued its proposed new source performance standards for greenhouse gases applicable to new construction.  This proposed rule does not apply to existing sources, such as Vectren’s generating facilities.  The EPA has not indicated when it intends to propose standards for existing sources.

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 or rulemaking, 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

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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. 

Manufactured Gas Plants

In the past, the Company operated facilities to manufacture natural gas.  Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years.  Under current 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.

In the Indiana Gas service territory, the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites have been identified for which the Company may have some remedial responsibility.  A remedial investigation/feasibility study (RI/FS) was completed 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.  The remaining sites have been submitted to the IDEM's Voluntary Remediation Program (VRP).  The Company has identified its involvement in five manufactured gas plant sites in SIGECO’s service territory, all of which are currently enrolled in the IDEM’s VRP.  The Company is currently conducting some level of remedial activities, including groundwater monitoring at certain sites.

The Company has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites.  While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, the Company has recorded cumulative costs that it reasonably expects to incur totaling approximately $41.7 million ($23.2 million at Indiana Gas and $18.5 million at SIGECO).  The estimated accrued costs are limited to the Company’s share of the remediation efforts and are therefore net of exposures of other potentially responsible parties (PRP).

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.  SIGECO filed a declaratory judgment action against its insurance carriers seeking a judgment finding its carriers liable under the policies for coverage of further investigation and any necessary remediation costs that SIGECO may accrue under the VRP program and/or another site subject to a lawsuit that has been settled.  In November 2011, 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 settlement agreements with all known insurance carriers and has recorded approximately $15.2 million of expected insurance recoveries.

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, 2012 and December 31, 2011, respectively, approximately $4.7 million and $6.5 million of accrued, but not yet spent, costs are included in Other Liabilities related to both the Indiana Gas and SIGECO sites.

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.  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

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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 would be initiated.

Coal Procurement Procedures

Vectren South submitted a request for proposal in April 2011 regarding coal purchases for a four year period beginning in 2012.  After negotiations with bidders, Vectren South 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 case, a sub docket proceeding was established to review the Company’s prospective coal procurement procedures, and the Company submitted evidence related to its recent request for proposal (RFP) and those coal procurement procedures to the IURC in September 2011.  In March 2012, the IURC issued its order in the sub docket.  The order concluded that Vectren South’s 2011 RFP process resulted in prices at the lowest fuel cost reasonably possible.  The IURC will continue to regularly monitor Vectren South’s procurement process in future fuel adjustment proceedings.

Vectren South Electric Fuel Cost Reduction

In the spring of 2011, Vectren South secured contracts for lower coal costs through a formal bidding process. This lower-priced contract coal started being delivered to Vectren’s power plants during 2012. On December 5, 2011 within the quarterly FAC filing, Vectren South submitted a joint proposal with the OUCC to reduce its fuel costs by accelerating into 2012 the impact of lower cost coal under new term contracts effective after 2012. The cost difference will be deferred to a regulatory asset and recovered over a six-year period without interest beginning in 2014.  The IURC approved this proposal on January 25, 2012, with a positive impact to customer’s rates effective February 1, 2012.  The deferred amount includes a reduction in the value of the coal inventory at December 31, 2011 of approximately $17.7 million to reflect existing coal inventory at the new, lower price.  Deferrals related to coal purchases in 2012 have totaled approximately $22.4 million, bringing the total deferred balance as of June 30, 2012 to $40.1 million. In addition to coal purchased under these contracts, Vectren South has also recently contracted with Vectren Fuels, Inc. to purchase lower priced spot coal. This spot purchase was found to be reasonable in a recent FAC order.

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, and include some for 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.

On August 31, 2011 the IURC issued an order approving an initial three year DSM plan in the Vectren South service territory that complies with the IURC’s energy saving targets.  Consistent with the Company’s proposal, the order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; 3) lost margin recovery associated with the implementation of DSM programs for large customers; and 4) deferral of lost margin up to $1 million in 2011 associated with small customer DSM programs for subsequent recovery under a tracking mechanism to be proposed by the Company.  On June 20, 2012, the IURC issued an order approving a small customer lost margin recovery mechanism, inclusive of all previous deferrals. This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the Company's last base rate proceeding discussed earlier. 

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Vectren South Electric Dense Pack Filing

On September 14, 2011, Vectren South filed a petition with the IURC seeking recovery of and return on the capital investment in dense pack technology to improve the efficiency of its A.B. Brown Generating Station.  This investment is expected to be approximately $32 million over the next two years, of which approximately $25.8 million has been invested to date.  This technology is expected to allow the A.B. Brown units to run at least 5 percent more efficient, thereby burning less fuel, and reducing fuel costs and emissions of pollutants.  In the Company’s base rate order issued in April 2011, the IURC authorized deferred accounting treatment associated with this investment. As a result of a subsequent filing by the Company seeking a current recovery mechanism in lieu of the deferred accounting treatment, the IURC issued an order on July 11, 2012, denying the Company's request for a current recovery mechanism stating that dense pack technology does not qualify as advanced technology under the statute. Although the Company believes that the investment does meet the requirements of the statute that would have allowed for timely recovery, it does not plan to appeal the decision and will employ the deferred accounting treatment ordered in the Company's last base rate order discussed earlier.

Vectren North Reporting Location Consolidation Proceeding

Vectren North implemented a reporting location consolidation plan in 2011 and  converted certain reporting locations into staging areas throughout the Vectren North territory.  On May 26, 2011, the International Brotherhood of Electrical Workers Local 1393, United Steel Workers Locals 12213 and 7441 and others (the “Complainants”) filed a formal complaint with the IURC claiming that implementation of the consolidation plan by Vectren North endangers public safety and impairs Vectren North's ability to provide adequate, safe and reliable service.  The Complainants asked the IURC to require Vectren North to reopen previously consolidated reporting locations and maintain and staff those locations.  A hearing in this case was held in February 2012.  Complainants submitted a proposed order in March and Vectren North submitted a reply brief and a proposed order in April.  The Company expects the IURC to issue a final order in this matter some time in 2012.

Impact of Recently Issued Accounting Guidance

Other Comprehensive Income (OCI)

In 2011, the FASB issued new accounting guidance regarding the presentation of comprehensive income within financial statements.  The new guidance requires entities to report components of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements.  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 adopted this guidance, as amended for condensed quarterly reporting, for the quarterly reporting period ended March 31, 2012.  During the periods presented comprehensive income and net income were equal.

Goodwill Testing

In September 2011, the FASB issued new accounting guidance regarding testing goodwill for impairment.  The new guidance will allow the Company an option to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test.  Using the new guidance, the Company no longer would be required to calculate the fair value of a reporting unit unless the Company determines, based on that qualitative assessment, that it is more likely than not that its fair value is less than its carrying amount.  The Company considered this option during its quarterly reporting period ended March 31, 2012 and concluded the continuation of the use of a quantitative approach is appropriate.

Fair Value Measurement and Disclosure

In May 2011, the FASB issued accounting guidance to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and International Financial Reporting Standards (IFRS). The amendments are not intended to change the application of the current fair value requirements, but to clarify the application of existing requirements. The guidance does change particular principles or requirements for measuring fair value or

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disclosing information about fair value measurements. To improve consistency, language has been changed to ensure that U.S. GAAP and IFRS fair value measurement and disclosure requirements are described in the same way. The Company adopted this guidance for its quarterly reporting period ended March 31, 2012.  The adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.

Financial Condition

Utility Holdings funds the short-term and long-term financing needs of its utility subsidiary 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’ long-term debt with a par value of $821 million and short-term obligations totaling $62 million were outstanding at June 30, 2012.  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, 2012, was $387 million.  Utility Holdings’ operations have historically been the primary funding source for Vectren’s common stock dividends.

The credit ratings of the senior unsecured debt of Utility Holdings and Indiana Gas, at June 30, 2012, 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 53 percent of long-term capitalization at both June 30, 2012 and December 31, 2011.  Long-term capitalization includes long-term debt, including current maturities and debt subject to tender, as well as common shareholder’s equity.

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.  Multiple debt agreements contain a covenant that the ratio of consolidated total debt to consolidated total capitalization will not exceed 65 percent.  As of June 30, 2012, the Company was in compliance with all debt 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.  The Company anticipates funding future capital expenditures and dividends primarily through internally generated funds.  Available liquidity has been enhanced by the extension of bonus depreciation legislation.  However, the resources required for capital investment remain uncertain for a variety of factors including pending legislative and regulatory initiatives involving gas pipeline modernization; and expanded EPA regulations for air, water, and fly ash.  The timing and amount of such investments depends on a variety of factors, including forecasted liquidity.  The company plans to enhance its liquidity as needed by accessing the capital markets.

Consolidated Short-Term Borrowing Arrangements

At June 30, 2012, the Company has $350 million of short-term borrowing capacity.  As reduced by borrowings currently outstanding, approximately $288 million was available at June 30, 2012.  This short-term borrowing facility was renewed in November 2011 and is available through September 2016.  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.  Liquidity was increased by the $100 million Utility Holdings debt issuance in February 2012, the net proceeds of which were used to repay short-term indebtedness.

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The Company has historically funded the short-term borrowing needs of Utility Holdings’ operations through the commercial paper market and expects to use the Utility Holdings short-term borrowing facility in instances where the commercial paper market is not efficient.  Following is certain information regarding these short-term borrowing arrangements.

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

(In millions)	2012	2011
Six Months Ended June 30
Balance Outstanding	$61.5	$—
Weighted Average Interest Rate	0.46%	n/a
Six Months Ended June 30 Average
Balance Outstanding	$72.4	$11.6
Weighted Average Interest Rate	0.49%	0.39%
Maximum Month End Balance Outstanding	$214.2	$42.5
(In millions)	2012	2011
Quarterly Average - June 30
Balance Outstanding	$61.5	$—
Weighted Average Interest Rate	0.46%	n/a
Maximum Month End Balance Outstanding	$214.2	$—

Utility Holdings 2012 Debt Issuance

On February 1, 2012, Utility Holdings issued $100 million of senior unsecured notes at an interest rate of 5.00 percent per annum and with a maturity date of February 3, 2042.  The notes were sold to various institutional investors pursuant to a private placement note purchase agreement executed in November 2011 with a delayed draw feature.  These senior notes are unsecured and jointly and severally guaranteed by Utility Holdings’ regulated utility subsidiaries, SIGECO, Indiana Gas, and VEDO.  The proceeds from the sale of the notes, net of issuance costs, totaled approximately $99.5 million.  These notes have no sinking fund requirements and interest payments are due semi-annually.  These notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Utility Holdings’ borrowing arrangements. As of December 31, 2011, the Company had reclassified $100 million of short-term borrowings as long-term debt to reflect that those borrowings were to be refinanced with the proceeds received from the February 1, 2012 long-term debt issuance.

Potential Uses of Liquidity

Planned Capital Expenditures

Utility capital expenditures are estimated at $125 million for the remainder of 2012.

Pension Funding Obligations

Vectren’s management currently estimates contributing $15 million to qualified pension plans in 2012, of which a portion may be funded by Utility Holdings; however, none was funded by Utility Holdings during the six months ended June 30, 2012.  Contributions in 2013 and beyond are dependent on a variety of factors, including the Company’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.

Other Letters of Credit

As of June 30, 2012, 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

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financial institutions supporting these letters of credit with general assets or by drawing from its credit facility that expires in September 2016.  Due to the long-term nature of the credit agreement, such debt is classified as long-term at June 30, 2012.

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 $249.0 million and $217.6 million during the six months endedJune 30, 2012 and 2011, respectively.  The $31.4 million increase in operating cash flow in 2012 compared to 2011 is primarily due to increased cash flow from working capital, increased earnings and reduced cash needs for other noncurrent liabilities of $19.6 million, reflecting greater contributions to Vectren’s pension plans in 2011.

Financing Cash Flow

Net cash flow required for financing activities was $128.8 million and $93.3 million during the six months endedJune 30, 2012 and 2011, respectively.  Financing activity in 2012 primarily reflects the $100 million debt issuance, the payment of dividends, and repayment of more short-term borrowings in 2012.

Investing Cash Flow

Cash flow required for investing activities was $122.1 million and $113.4 million during the six months endedJune 30, 2012 and 2011, respectively.  The current year period reflects an approximate $12 million increase in cash required for capital expenditures.  Warm, dry weather during the first half of 2012 allowed for greater capital expenditures for bare steel/cast iron projects. Capital expenditures associated with planned power supply outages also have increased year over year.  

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, tornadoes, 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.

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• Economic conditions surrounding the current economic uncertainty, including increased potential for 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.

• Risks associated with material business transactions such as mergers, acquisitions and divestitures, including, without limitation, legal and regulatory delays; the related time and costs of implementing such transactions; integrating operations as part of these transactions; and possible failures to achieve expected gains, revenue growth and/or expense savings from such transactions.

• 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, pipeline safety regulations, 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.

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. 2011 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, 2012, 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

35

As of June 30, 2012, 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, 2012, to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is:

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

2) accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

PART II.  OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS

The Company is party to various legal proceedings 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 condensed consolidated 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 2011 Form 10-K and are therefore not presented herein.

ITEM 2.  UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Not applicable.

ITEM 3.  DEFAULTS UPON SENIOR SECURITIES

Not Applicable

ITEM 4.  MINE SAFETY DISCLOSURES

Not Applicable

ITEM 5.  OTHER INFORMATION

Not Applicable

36

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.DEF*   XBRL Taxonomy Extension Definition Linkbase

101.LAB*   XBRL Taxonomy Extension Labels 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.”

37

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 14, 2012	/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)

38

EX-12

Exhibit 12

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

(In Thousands, Except Ratios)

	Twelve months		Twelve months		Twelve months		Six months		Six months
	Ended		Ended		Ended		Ended		Ended
	June 30,		December 31,		December 31,		June 30,		June 30,
	2012		2011		2010		2012		2011
Earnings: (1)
Net income	$	134,051	$	122,874	$	123,854	$	76,092	$	64,915
Income taxes	88,040		82,859		77,100		46,756		41,575
Fixed Charges (See below) (2)	75,485		80,650		81,803		35,825		40,990
Total adjusted earnings	$	297,576	$	286,383	$	282,757	$	158,673	$	147,480
Fixed charges: (2)
Total interest expense	$	75,127	$	80,281	$	81,425	$	35,654	$	40,808
Interest component of rents	358		369		378		171		182
Total fixed charges	$	75,485	$	80,650	$	81,803	$	35,825	$	40,990
Ratio of earnings to fixed charges	3.9		3.6		3.5		4.4		3.6

(1) For the purposes of computing these ratios, earnings consist of pretax net income before fixed charges.

(2) Fixed charges consist of total interest, amortization of debt discount, premium and expense, and the estimated portion of interest implicit in rentals.

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

CHIEF EXECUTIVE OFFICER CERTIFICATION

I, Carl L. Chapman, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Vectren Utility Holdings, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions)

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 14, 2012

/s/ Carl L. Chapman

Carl L. Chapman

Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

CHIEF FINANCIAL OFFICER CERTIFICATION

I, Jerome A. Benkert, Jr., certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Vectren Utility Holdings, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions)

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 14, 2012

/s/ Jerome A. Benkert, Jr.

Jerome A. Benkert, Jr.

Executive Vice President and Chief Financial Officer

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

CERTIFICATION

By signing below, each of the undersigned officers hereby certifies pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his or her knowledge, (i) this report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in this report fairly presents, in all material respects, the financial condition and results of operations of Vectren Utility Holdings, Inc.

Signed this 14th day of August, 2012.

/s/ Jerome A. Benkert, Jr.	/s/ Carl L. Chapman
(Signature of Authorized Officer)	(Signature of Authorized Officer)
Jerome A. Benkert, Jr.	Carl L. Chapman
(Typed Name)	(Typed Name)
Executive Vice President and Chief Financial Officer	Chief Executive Officer
(Title)	(Title)

XML

Rate & Regulatory Matters (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended	12 Months Ended
	Jun. 30, 2012	Dec. 31, 2011
Vectren South Electric Base Rate Filing [Abstract]
Amount of revised rate increase filed in rebuttal to original rate increase to IURC	$ 28.6
Amount of infrastructure construction in the three years leading up to December 2009 rate filing	325.0
Rate of return included in rate increase (in hundredths)	7.29%
Dollar amount of the rate base included in rate increase	1,295.6
Amount of rate of return on equity included in rate base (in hundredths)	10.40%
Vectren South Electric Demand Side Management Program Filing [Abstract]
Number of years in initial demand side management program approved by the IURC (in years)	3
Maximum deferral of lost margin associated with small customer demand side programs		1.0
Vectren South Electric Dense Pack Filing [Abstract]
Expected capital investment to improve the efficiency of generating station	32.0
Number of years in capital improvement program (in years)	2
Amount of expected capital investment invested to date	25.8
Expected increase in efficiency for generating station following improvement (in hundredths)	5.00%
Vectren South Electric Fuel Cost Reduction [Abstract]
Number of years for recovery of coal costs	6
Reduction to coal inventory balance related to deferral		17.7
Deferrals related to coal purchases in the current year	22.4
Cumulative total deferrals related to coal purchases	$ 40.1

XML

Subsidiary Guarantor and Consolidating Information Subsidiary Guarantor and Consolidating Information Income Statement (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
OPERATING REVENUES [Abstract]
Gas utility	$ 116.0	$ 134.0	$ 408.3	$ 490.7
Electric utility	149.3	159.3	288.7	305.7
Other	0.5	0.5	0.9	1.0
Total operating revenues	265.8	293.8	697.9	797.4
OPERATING EXPENSES [Abstract]
Cost of gas sold	31.8	48.8	168.9	243.9
Cost of fuel & purchased power	47.0	60.3	91.7	119.8
Other operating	77.8	78.2	157.7	165.1
Depreciation & Amortization	47.8	47.9	96.4	96.1
Taxes other than income taxes	11.6	11.1	27.5	29.1
Total operating expenses	216.0	246.3	542.2	654.0
OPERATING INCOME	49.8	47.5	155.7	143.4
Other income - net	0.7	2.2	2.9	3.9
Interest Expense	18.0	20.4	35.7	40.8
INCOME BEFORE INCOME TAXES	32.5	29.3	122.9	106.5
Income taxes	12.4	13.0	46.8	41.6
NET INCOME	20.1	16.3	76.1	64.9
Subsidiary Guarantors [Member]
OPERATING REVENUES [Abstract]
Gas utility	116.0	134.0	408.3	490.7
Electric utility	149.3	159.3	288.7	305.7
Other	0	0	0	0
Total operating revenues	265.3	293.3	697.0	796.4
OPERATING EXPENSES [Abstract]
Cost of gas sold	31.8	48.8	168.9	243.9
Cost of fuel & purchased power	47.0	60.3	91.7	119.8
Other operating	86.3	88.7	175.9	186.0
Depreciation & Amortization	42.1	40.9	83.8	82.3
Taxes other than income taxes	11.2	10.8	26.7	28.3
Total operating expenses	218.4	249.5	547.0	660.3
OPERATING INCOME	46.9	43.8	150.0	136.1
Other income - net	0.2	1.8	2.2	3.3
Interest Expense	16.4	18.8	32.9	37.7
INCOME BEFORE INCOME TAXES	30.7	26.8	119.3	101.7
Income taxes	12.2	11.1	47.7	41.0
Equity in earnings of consolidated companies, net of tax	0	0	0	0
NET INCOME	18.5	15.7	71.6	60.7
Parent Company [Member]
OPERATING REVENUES [Abstract]
Gas utility	0	0	0	0
Electric utility	0	0	0	0
Other	10.0	11.0	19.9	21.9
Total operating revenues	10.0	11.0	19.9	21.9
OPERATING EXPENSES [Abstract]
Cost of gas sold	0	0	0	0
Cost of fuel & purchased power	0	0	0	0
Other operating	0.5	0	0.5	0
Depreciation & Amortization	5.6	6.8	12.4	13.5
Taxes other than income taxes	0.3	0.3	0.7	0.7
Total operating expenses	6.4	7.1	13.6	14.2
OPERATING INCOME	3.6	3.9	6.3	7.7
Other income - net	9.9	12.7	20.5	25.5
Interest Expense	11.7	14.1	23.2	28.4
INCOME BEFORE INCOME TAXES	1.8	2.5	3.6	4.8
Income taxes	0.2	1.9	(0.9)	0.6
Equity in earnings of consolidated companies, net of tax	18.5	15.7	71.6	60.7
NET INCOME	20.1	16.3	76.1	64.9
Consolidation, Eliminations [Member]
OPERATING REVENUES [Abstract]
Gas utility	0	0	0	0
Electric utility	0	0	0	0
Other	(9.5)	(10.5)	(19.0)	(20.9)
Total operating revenues	(9.5)	(10.5)	(19.0)	(20.9)
OPERATING EXPENSES [Abstract]
Cost of gas sold	0	0	0	0
Cost of fuel & purchased power	0	0	0	0
Other operating	(9.0)	(10.5)	(18.7)	(20.9)
Depreciation & Amortization	0.1	0.2	0.2	0.3
Taxes other than income taxes	0.1	0	0.1	0.1
Total operating expenses	(8.8)	(10.3)	(18.4)	(20.5)
OPERATING INCOME	(0.7)	(0.2)	(0.6)	(0.4)
Other income - net	(9.4)	(12.3)	(19.8)	(24.9)
Interest Expense	(10.1)	(12.5)	(20.4)	(25.3)
INCOME BEFORE INCOME TAXES	0	0	0	0
Income taxes	0	0	0	0
Equity in earnings of consolidated companies, net of tax	(18.5)	(15.7)	(71.6)	(60.7)
NET INCOME	(18.5)	(15.7)	(71.6)	(60.7)
Consolidated Entities [Member]
OPERATING REVENUES [Abstract]
Gas utility	116.0	134.0	408.3	490.7
Electric utility	149.3	159.3	288.7	305.7
Other	0.5	0.5	0.9	1.0
Total operating revenues	265.8	293.8	697.9	797.4
OPERATING EXPENSES [Abstract]
Cost of gas sold	31.8	48.8	168.9	243.9
Cost of fuel & purchased power	47.0	60.3	91.7	119.8
Other operating	77.8	78.2	157.7	165.1
Depreciation & Amortization	47.8	47.9	96.4	96.1
Taxes other than income taxes	11.6	11.1	27.5	29.1
Total operating expenses	216.0	246.3	542.2	654.0
OPERATING INCOME	49.8	47.5	155.7	143.4
Other income - net	0.7	2.2	2.9	3.9
Interest Expense	18.0	20.4	35.7	40.8
INCOME BEFORE INCOME TAXES	32.5	29.3	122.9	106.5
Income taxes	12.4	13.0	46.8	41.6
Equity in earnings of consolidated companies, net of tax	0	0	0	0
NET INCOME	$ 20.1	$ 16.3	$ 76.1	$ 64.9

XML

Excise and Utility Receipts Taxes

6 Months Ended

Jun. 30, 2012

Excise and Utility Receipts Taxes [Abstract]

Excise and Utility Receipts Taxes

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 $5.0 million and $5.4 million in the three months ended June 30, 2012 and 2011 respectively. For the six months ended June 30, 2012 and 2011, these taxes totaled $14.3 million and $16.4 million, respectively.  Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.

XML

Transactions with Other Vectren Companies and Affiliates Transactions with Other Vectren Companies and Afffiliates (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011
Vectren Fuels Inc. [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Expenses from transactions with related party	$ 33.3	$ 42.5	$ 58.2	$ 75.8
Miller Pipeline LLC [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Expenses from transactions with related party	11.5	8.6	19.6	13.2
ProLiance [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Expenses from transactions with related party	50.2	79.0	129.7	198.3
Amounts owed to ProLiance for those purchases	13.8		13.8		36.8
Support Services & Purchases [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Cost of corporate and general and administrative services	$ 11.4	$ 12.4	$ 23.9	$ 26.2

XML

Accruals for Utility and NonUtility Plant Accruals for Utility and NonUtility Plant (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Accruals for Utility & Nonutility Plant [Abstract]
Public Utilities Accruals For Purchase Of Utility And Non Utility Plant Assets	$ 11.0	$ 9.2

XML

Financing Activities (Details) (Vectren Utility Holdings Inc [Member], Unsecured Debt [Member], Senior Guaranteed Note due 2042 [Member], USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012
Vectren Utility Holdings Inc [Member] | Unsecured Debt [Member] | Senior Guaranteed Note due 2042 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 100
Debt Instrument, Interest Rate, Stated Percentage	5.00%
Debt Instrument, Maturity Date	Feb. 03, 2042
Debt Instrument, Issuance Date	2/1/2012
Proceeds from Issuance of Debt	$ 99.5

XML

Legislative Matters (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012
Pipeline Safety Law [Member]
Legislative Matters [Line Items]
Estimated amount of operating expenses that could accumulate associated with expanded compliance requirements	$ 9.0
Pipeline Safety Law [Member] | Indiana [Member]
Legislative Matters [Line Items]
Estimated amount of operating expenses that could accumulate associated with expanded compliance requirements	6.0
Capital expenditures driven by the legislation	80.0
Period over which capital expenditures would accumulate (in years)	5
Pipeline Safety Law [Member] | Ohio [Member]
Legislative Matters [Line Items]
Capital expenditures driven by the legislation	55.0
Period over which capital expenditures would accumulate (in years)	5
Indiana Senate Bill 251 [Member]
Legislative Matters [Line Items]
Description of legislation	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.
Description of the goal of legislation	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 general rate case.  Such costs include construction, depreciation, operating and other costs.  The remaining 20 percent of those costs are to be deferred for recovery in the utility’s next general rate case.
Ohio House Bill 95 [Member]
Legislative Matters [Line Items]
Cost Of Defered Capital Expenditure Program	$ 25.0

XML

Subsidiary Guarantor and Consolidating Information

6 Months Ended

Jun. 30, 2012

Subsidiary Guarantor and Consolidating Information [Abstract]

Subsidiary Guarantor and Consolidating Information [Text Block]

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 approximately $62 million is outstanding at June 30, 2012, and Utility Holdings’ has unsecured senior notes with a par value of $821 million outstanding at June 30, 2012.  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.

Condensed Consolidating Balance Sheet as of June 30, 2012 (in millions):

ASSETS	Subsidiary		Parent			Eliminations &
	Guarantors		Company			Reclassifications			Consolidated
Current Assets
Cash & cash equivalents	$	2.7	$	1.4		$	—		$	4.1
Accounts receivable - less reserves	56.2		—			—			56.2
Intercompany receivables	17.7		136.8			(154.5		)	—
Receivables due from other Vectren companies	—		0.1			—			0.1
Accrued unbilled revenues	35.5		—			—			35.5
Inventories	107.0		—			—			107.0
Recoverable fuel & natural gas costs	14.6		—			—			14.6
Prepayments & other current assets	31.7		5.0			(7.7		)	29.0
Total current assets	265.4		143.3			(162.2		)	246.5
Utility Plant
Original cost	5,091.0		—			—			5,091.0
Less:  accumulated depreciation & amortization	2,001.1		—			—			2,001.1
Net utility plant	3,089.9		—			—			3,089.9
Investments in consolidated subsidiaries	—		1,300.1			(1,300.1		)	—
Notes receivable from consolidated subsidiaries	—		679.7			(679.7		)	—
Investments in unconsolidated affiliates	0.2		—			—			0.2
Other investments	27.2		4.9			—			32.1
Nonutility property - net	2.8		142.9			—			145.7
Goodwill - net	205.0		—			—			205.0
Regulatory assets	96.3		23.0			—			119.3
Other assets	41.9		2.8			(6.6		)	38.1
TOTAL ASSETS	$	3,728.7	$	2,296.7		$	(2,148.6	)	$	3,876.8
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent			Eliminations &
	Guarantors		Company			Reclassifications			Consolidated
Current Liabilities
Accounts payable	$	67.9	$	12.2		$	—		$	80.1
Accounts payable to affiliated companies	13.8		—			—			13.8
Intercompany payables	31.3		—			(31.3		)	—
Payables to other Vectren companies	15.3		9.6			—			24.9
Refundable fuel & natural gas costs	5.0		—			—			5.0
Accrued liabilities	110.0		15.9			(7.7		)	118.2
Short-term borrowings	—		61.5			—			61.5
Intercompany short-term borrowings	105.6		17.6			(123.2		)	—
Current maturities of long-term debt payable to VUHI	5.0		—			—			5.0
Total current liabilities	353.9		116.8			(162.2		)	308.5
Long-Term Debt
Long-term debt - net of current maturities	382.3		821.0			—			1,203.3
Long-term debt due to VUHI	679.7		—			(679.7		)	—
Total long-term debt - net	1,062.0		821.0			(679.7		)	1,203.3
Deferred Income Taxes & Other Liabilities
Deferred income taxes	562.7		(20.6		)	—			542.1
Regulatory liabilities	352.9		2.3			—			355.2
Deferred credits & other liabilities	97.1		1.6			(6.6		)	92.1
Total deferred credits & other liabilities	1,012.7		(16.7		)	(6.6		)	989.4
Common Shareholder's Equity
Common stock (no par value)	791.3		778.1			(791.3		)	778.1
Retained earnings	508.8		597.5			(508.8		)	597.5
Total common shareholder's equity	1,300.1		1,375.6			(1,300.1		)	1,375.6
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,728.7	$	2,296.7		$	(2,148.6	)	$	3,876.8

Condensed Consolidating Balance Sheet as of December 31, 2011 (in millions):

ASSETS	Subsidiary		Parent			Eliminations &
	Guarantors		Company			Reclassifications			Consolidated
Current Assets
Cash & cash equivalents	$	5.3	$	0.7		$	—		$	6.0
Accounts receivable - less reserves	94.8		0.7			—			95.5
Intercompany receivables	—		206.0			(206.0		)	—
Receivables due from other Vectren companies	—		0.2			—			0.2
Accrued unbilled revenues	90.8		—			—			90.8
Inventories	132.5		—			—			132.5
Recoverable fuel & natural gas costs	12.4		—			—			12.4
Prepayments & other current assets	57.1		16.7			(4.5		)	69.3
Total current assets	392.9		224.3			(210.5		)	406.7
Utility Plant
Original cost	4,979.9		—			—			4,979.9
Less:  accumulated depreciation & amortization	1,947.3		—			—			1,947.3
Net utility plant	3,032.6		—			—			3,032.6
Investments in consolidated subsidiaries	—		1,272.2			(1,272.2		)	—
Notes receivable from consolidated subsidiaries	—		679.7			(679.7		)	—
Investments in unconsolidated affiliates	0.2		—			—			0.2
Other investments	26.8		5.0			—			31.8
Nonutility property - net	3.0		153.6			—			156.6
Goodwill - net	205.0		—			—			205.0
Regulatory assets	77.0		23.0			—			100.0
Other assets	44.2		4.0			(6.6		)	41.6
TOTAL ASSETS	$	3,781.7	$	2,361.8		$	(2,169.0	)	$	3,974.5
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent			Eliminations &
	Guarantors		Company			Reclassifications			Consolidated
Current Liabilities
Accounts payable	$	106.1	$	6.8		$	—		$	112.9
Accounts payable to affiliated companies	36.8		—			—			36.8
Intercompany payables	11.8		—			(11.8		)	—
Payables to other Vectren companies	30.1		—			—			30.1
Accrued liabilities	112.9		12.6			(4.5		)	121.0
Short-term borrowings	—		142.8			—			142.8
Intercompany short-term borrowings	158.5		35.7			(194.2		)	—
Total current liabilities	456.2		197.9			(210.5		)	443.6
Long-Term Debt
Long-term debt	387.2		821.0			—			1,208.2
Long-term debt due to VUHI	679.7		—			(679.7		)	—
Total long-term debt - net	1,066.9		821.0			(679.7		)	1,208.2
Deferred Income Taxes & Other Liabilities
Deferred income taxes	545.2		(7.7		)	—			537.5
Regulatory liabilities	342.6		2.6			—			345.2
Deferred credits & other liabilities	98.6		1.4			(6.6		)	93.4
Total deferred credits & other liabilities	986.4		(3.7		)	(6.6		)	976.1
Common Shareholder's Equity
Common stock (no par value)	787.8		774.6			(787.8		)	774.6
Retained earnings	484.4		572.0			(484.4		)	572.0
Total common shareholder's equity	1,272.2		1,346.6			(1,272.2		)	1,346.6
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,781.7	$	2,361.8		$	(2,169.0	)	$	3,974.5

Condensed Consolidating Statement of Income for the three months ended June 30, 2012 (in millions):

	Subsidiary Guarantors	Parent Company	Eliminations & Reclassifications		Consolidated
OPERATING REVENUES
Gas utility	116.0	—	—		116.0
Electric utility	149.3	—	—		149.3
Other	—	10.0	(9.5	)	0.5
Total operating revenues	265.3	10.0	(9.5	)	265.8
OPERATING EXPENSES
Cost of gas sold	31.8	—	—		31.8
Cost of fuel & purchased power	47.0	—	—		47.0
Other operating	86.3	0.5	(9.0	)	77.8
Depreciation & amortization	42.1	5.6	0.1		47.8
Taxes other than income taxes	11.2	0.3	0.1		11.6
Total operating expenses	218.4	6.4	(8.8	)	216.0
OPERATING INCOME	46.9	3.6	(0.7	)	49.8
Other income (loss) - net	0.2	9.9	(9.4	)	0.7
Interest expense	16.4	11.7	(10.1	)	18.0
INCOME BEFORE INCOME TAXES	30.7	1.8	—		32.5
Income taxes	12.2	0.2	—		12.4
Equity in earnings of consolidated companies, net of tax	—	18.5	(18.5	)	—
NET INCOME	18.5	20.1	(18.5	)	20.1

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

	Subsidiary Guarantors	Parent Company	Eliminations & 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 (loss) - net	1.8	12.7	(12.3	)	2.2
Interest expense	18.8	14.1	(12.5	)	20.4
INCOME BEFORE INCOME TAXES	26.8	2.5	—		29.3
Income taxes	11.1	1.9	—		13.0
Equity in earnings of consolidated companies, net of tax	—	15.7	(15.7	)	—
NET INCOME	15.7	16.3	(15.7	)	16.3

Condensed Consolidating Statement of Income for the six months ended June 30, 2012 (in millions):

	Subsidiary Guarantors		Parent Company			Eliminations & Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	408.3	$	—		$	—		$	408.3
Electric utility	288.7		—			—			288.7
Other	—		19.9			(19.0		)	0.9
Total operating revenues	697.0		19.9			(19.0		)	697.9
OPERATING EXPENSES
Cost of gas sold	168.9		—			—			168.9
Cost of fuel & purchased power	91.7		—			—			91.7
Other operating	175.9		0.5			(18.7		)	157.7
Depreciation & amortization	83.8		12.4			0.2			96.4
Taxes other than income taxes	26.7		0.7			0.1			27.5
Total operating expenses	547.0		13.6			(18.4		)	542.2
OPERATING INCOME	150.0		6.3			(0.6		)	155.7
Other income (loss) - net	2.2		20.5			(19.8		)	2.9
Interest expense	32.9		23.2			(20.4		)	35.7
INCOME BEFORE INCOME TAXES	119.3		3.6			—			122.9
Income taxes	47.7		(0.9		)	—			46.8
Equity in earnings of consolidated companies, net of tax	—		71.6			(71.6		)	—
NET INCOME	$	71.6	$	76.1		$	(71.6	)	$	76.1

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

	Subsidiary Guarantors		Parent Company		Eliminations & 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	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 - net	3.3		25.5		(24.9		)	3.9
Interest expense	37.7		28.4		(25.3		)	40.8
INCOME BEFORE INCOME TAXES	101.7		4.8		—			106.5
Income taxes	41.0		0.6		—			41.6
Equity in earnings of consolidated companies, net of tax	—		60.7		(60.7		)	—
NET INCOME	$	60.7	$	64.9	$	(60.7	)	$	64.9

Condensed Consolidating Statement of Cash Flows for the six months ended June 30, 2012 (in millions):

	Subsidiary Guarantors			Parent Company			Eliminations			Consolidated
NET CASH FLOWS FROM OPERATING ACTIVITIES	$	233.3		$	15.7		$	—		$	249.0
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from
Additional capital contribution from parent	3.5			3.5			(3.5		)	3.5
Long-term debt - net of issuance costs	—			99.5			—			99.5
Requirements for:
Dividends to parent	(47.2		)	(50.5		)	47.2			(50.5		)
Net change in intercompany short-term borrowings	(52.9		)	17.7			35.2			—
Net change in short-term borrowings	—			(181.3		)	—			(181.3		)
Net cash flows from financing activities	(96.6		)	(111.1		)	78.9			(128.8		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from
Consolidated subsidiary distributions	—			47.2			(47.2		)	—
Other investing activities	—			2.2			—			2.2
Requirements for:
Capital expenditures, excluding AFUDC equity	(121.4		)	(2.7		)	—			(124.1		)
Consolidated subsidiary investments	—			(3.5		)	3.5			—
Other investing activities	(0.2		)	—			—			(0.2		)
Net change in short-term intercompany notes receivable	(17.7		)	52.9			(35.2		)	—
Net cash flows from investing activities	(139.3		)	96.1			(78.9		)	(122.1		)
Net change in cash & cash equivalents	(2.6		)	0.7			—			(1.9		)
Cash & cash equivalents at beginning of period	5.3			0.7			—			6.0
Cash & cash equivalents at end of period	$	2.7		$	1.4		$	—		$	4.1

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

	Subsidiary Guarantors			Parent 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

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Environmental Matters (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Air Quality [Abstract]
Cost of most of the allowances granted to company for NOx and SO2 inventory usage	$ 0
SIGECO investment in Property, Plant and Equipment, Pollution control equipment	411.0
Property, Plant and Equipment, amount of investment in pollution control equipment included in rate base	411.0
Percentage of coal fired generating fleet currently being scrubbed for SO2 (in hundredths)	100.00%
Percentage of coal fired generating fleet currently controlled for NOx (in hundredths)	90.00%
Percentage reduction of SO2 per Cross-State Air Pollution Rule (in hundredths)	71.00%
Percentage reduction of NOx per Cross-State Air Pollution Rule (in hundredths)	52.00%
Climate Changes [Abstract]
Maximum level of greenhouse gas emissions that prompts requirement to obtain permit for facilities to construct new facility of significant modification to existing facility (in tons)	75,000
Coal Ash Waste Disposal and Ash Ponds [Abstract]
Estimated capital expenditures to comply with ash pond and coal ash disposal regulations	30.0
Potential estimated capital expenditures to comply with ash pond and coal ash disposal regulations with stringent alternative	100.0
Estimated annual compliance costs maximum with ash pond and coal ash disposal regulation	5.0
Clean Water Act [Abstract]
Estimated capital expenditures related to Clean Water Act	40.0
Manufactured Gas Plants [Abstract]
Site contingency, accrual, undiscounted amount	41.7
Remediation cost accrued and not yet spent a the end of the period	4.7	6.5
Indiana Gas [Member]
Manufactured Gas Plants [Abstract]
Number of sites identified with potential remedial responsibility for entity (in number of sites)	26
Site contingency, accrual, undiscounted amount	23.2
Environmental cost recognized, recover from insurance carriers credited to expense	20.8
SIGECO [Member]
Manufactured Gas Plants [Abstract]
Number of sites identified with potential remedial responsibility for entity (in number of sites)	5
Site contingency, accrual, undiscounted amount	18.5
Environmental cost recognized, recover from insurance carriers credited to expense	$ 15.2

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CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Assets, Current [Abstract]
Cash & cash equivalents	$ 4.1	$ 6.0
Accounts receivable - less reserves of $5.4 & $5.9, respectively	56.2	95.5
Receivables due from other Vectren companies	0.1	0.2
Accrued unbilled revenues	35.5	90.8
Inventories	107.0	132.5
Recoverable fuel & natural gas costs	14.6	12.4
Prepayments & other current assets	29.0	69.3
Total current assets	246.5	406.7
Utility Plant [Abstract]
Original cost	5,091.0	4,979.9
Less: accumulated depreciation & amortization	2,001.1	1,947.3
Net utility plant	3,089.9	3,032.6
Investments in unconsolidated affiliates	0.2	0.2
Other investments	32.1	31.8
Nonutility plant - net	145.7	156.6
Goodwill - net	205.0	205.0
Regulatory assets	119.3	100.0
Other assets	38.1	41.6
TOTAL ASSETS	3,876.8	3,974.5
Current Liabilities [Abstract]
Accounts payable	80.1	112.9
Accounts payable to affiliated companies	13.8	36.8
Payables to other Vectren companies	24.9	30.1
Refundable fuel and natural gas costs	5.0	0
Accrued liabilities	118.2	121.0
Short-term borrowings	61.5	142.8
Current maturities of long-term debt	5.0	0
Total current liabilities	308.5	443.6
Long-Term Debt	1,203.3	1,208.2
Deferred Income Taxes & Other Liabilities [Abstract]
Deferred income taxes	542.1	537.5
Regulatory liabilities	355.2	345.2
Deferred credits & other liabilities	92.1	93.4
Total deferred credits and other liabilities	989.4	976.1
Commitments & Contingencies (Notes 8-11)
Common Shareholder's Equity [Abstract]
Common stock (no par value)	778.1	774.6
Retained earnings	597.5	572.0
Total common shareholders' equity	1,375.6	1,346.6
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	$ 3,876.8	$ 3,974.5

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Organization and Nature of Operations

6 Months Ended

Jun. 30, 2012

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Nature of Operations

Organization and 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 Vectren Energy Delivery of Ohio, Inc. (VEDO).  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 567,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 142,000 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.  VEDO provides energy delivery services to approximately 312,000 natural gas customers located near Dayton in west central Ohio.

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Segment Reporting (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Segment Reporting Information [Line Items]
Revenues	$ 265.8	$ 293.8	$ 697.9	$ 797.4
Profitability Measure - Net income (loss)	20.1	16.3	76.1	64.9
Utility Group [Member] | Gas Utility Services [Member]
Segment Reporting Information [Line Items]
Revenues	116.0	134.0	408.3	490.7
Profitability Measure - Net income (loss)	1.3	2.1	38.8	38.3
Utility Group [Member] | Electric Utility Services [Member]
Segment Reporting Information [Line Items]
Revenues	149.3	159.3	288.7	305.7
Profitability Measure - Net income (loss)	17.2	13.6	32.8	22.3
Utility Group [Member] | Other Operations [Member]
Segment Reporting Information [Line Items]
Revenues	10.0	10.9	19.9	21.9
Profitability Measure - Net income (loss)	1.6	0.6	4.5	4.3
Utility Group [Member] | Group Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	$ (9.5)	$ (10.4)	$ (19.0)	$ (20.9)

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Segment Reporting (Tables)

6 Months Ended

Jun. 30, 2012

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2012			2011			2012			2011
Revenues
Gas Utility Services	$	116.0		$	134.0		$	408.3		$	490.7
Electric Utility Services	149.3			159.3			288.7			305.7
Other Operations	10.0			10.9			19.9			21.9
Eliminations	(9.5		)	(10.4		)	(19.0		)	(20.9		)
Total revenues	$	265.8		$	293.8		$	697.9		$	797.4
Profitability Measure - Net Income
Gas Utility Services	$	1.3		$	2.1		$	38.8		$	38.3
Electric Utility Services	17.2			13.6			32.8			22.3
Other Operations	1.6			0.6			4.5			4.3
Total net income	$	20.1		$	16.3		$	76.1		$	64.9

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Subsidiary Guarantor and Consolidating Information Subsidiary Guarantor and Consolidating Information Balance Sheet (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012	Dec. 31, 2011	Jun. 30, 2011	Dec. 31, 2010
ASSETS
Cash & cash equivalents	$ 4.1	$ 6.0	$ 13.3	$ 2.4
Accounts receivable - less reserves	56.2	95.5
Receivables due from other Vectren companies	0.1	0.2
Accrued unbilled revenues	35.5	90.8
Inventories	107.0	132.5
Recoverable fuel & natural gas costs	14.6	12.4
Prepayments & other current assets	29.0	69.3
Total current assets	246.5	406.7
Original cost	5,091.0	4,979.9
Less: accumulated depreciation & amortization	2,001.1	1,947.3
Net utility plant	3,089.9	3,032.6
Investments in unconsolidated affiliates	0.2	0.2
Other investments	32.1	31.8
Nonutility property - net	145.7	156.6
Goodwill - net	205.0	205.0
Regulatory assets	119.3	100.0
Other assets	38.1	41.6
TOTAL ASSETS	3,876.8	3,974.5
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	80.1	112.9
Payables to other Vectren companies	24.9	30.1
Refundable fuel and natural gas costs	5.0	0
Accrued liabilities	118.2	121.0
Short-term borrowings	61.5	142.8
Current maturities of long-term debt payable to VUHI	5.0	0
Total current liabilities	308.5	443.6
Long-term Debt - Net of Current Maturities	1,203.3	1,208.2
Deferred income taxes	542.1	537.5
Regulatory liabilities	355.2	345.2
Deferred Credits and Other Liabilities	92.1	93.4
Total deferred credits and other liabilities	989.4	976.1
Common stock (no par value)	778.1	774.6
Retained earnings	597.5	572.0
Total common shareholders' equity	1,375.6	1,346.6
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	3,876.8	3,974.5
Line of Credit Facility, Maximum Borrowing Capacity	350
Subsidiary Ownership Percentage	100.00%
Subsidiary Guarantors [Member]
ASSETS
Cash & cash equivalents	2.7	5.3	2.1	2.0
Accounts receivable - less reserves	56.2	94.8
Intercompany Receivables	17.7	0
Receivables due from other Vectren companies	0	0
Accrued unbilled revenues	35.5	90.8
Inventories	107.0	132.5
Recoverable fuel & natural gas costs	14.6	12.4
Prepayments & other current assets	31.7	57.1
Total current assets	265.4	392.9
Original cost	5,091.0	4,979.9
Less: accumulated depreciation & amortization	2,001.1	1,947.3
Net utility plant	3,089.9	3,032.6
Investments in consolidated subsidiaries	0	0
Notes receivable from consolidated subsidiaries	0	0
Investments in unconsolidated affiliates	0.2	0.2
Other investments	27.2	26.8
Nonutility property - net	2.8	3.0
Goodwill - net	205.0	205.0
Regulatory assets	96.3	77.0
Other assets	41.9	44.2
TOTAL ASSETS	3,728.7	3,781.7
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	67.9	106.1
Accounts payable to affiliated companies	13.8	36.8
Intercompany Payables	31.3	11.8
Payables to other Vectren companies	15.3	30.1
Refundable fuel and natural gas costs	5.0
Accrued liabilities	110.0	112.9
Short-term borrowings	0	0
Intercompany short-term borrowings	105.6	158.5
Current maturities of long-term debt payable to VUHI	5.0
Total current liabilities	353.9	456.2
Long-term Debt - Net of Current Maturities	382.3	387.2
Long-term debt due to VUHI	679.7	679.7
Total long-term debt - net	1,062.0	1,066.9
Deferred income taxes	562.7	545.2
Regulatory liabilities	352.9	342.6
Deferred Credits and Other Liabilities	97.1	98.6
Total deferred credits and other liabilities	1,012.7	986.4
Common stock (no par value)	791.3	787.8
Retained earnings	508.8	484.4
Total common shareholders' equity	1,300.1	1,272.2
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	3,728.7	3,781.7
Parent Company [Member]
ASSETS
Cash & cash equivalents	1.4	0.7	11.2	0.4
Accounts receivable - less reserves	0	0.7
Intercompany Receivables	136.8	206.0
Receivables due from other Vectren companies	0.1	0.2
Accrued unbilled revenues	0	0
Inventories	0	0
Recoverable fuel & natural gas costs	0	0
Prepayments & other current assets	5.0	16.7
Total current assets	143.3	224.3
Original cost	0	0
Less: accumulated depreciation & amortization	0	0
Net utility plant	0	0
Investments in consolidated subsidiaries	1,300.1	1,272.2
Notes receivable from consolidated subsidiaries	679.7	679.7
Investments in unconsolidated affiliates	0	0
Other investments	4.9	5.0
Nonutility property - net	142.9	153.6
Goodwill - net	0	0
Regulatory assets	23.0	23.0
Other assets	2.8	4.0
TOTAL ASSETS	2,296.7	2,361.8
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	12.2	6.8
Accounts payable to affiliated companies	0	0
Intercompany Payables	0	0
Payables to other Vectren companies	9.6	0
Refundable fuel and natural gas costs	0
Accrued liabilities	15.9	12.6
Short-term borrowings	61.5	142.8
Intercompany short-term borrowings	17.6	35.7
Current maturities of long-term debt payable to VUHI	0
Total current liabilities	116.8	197.9
Long-term Debt - Net of Current Maturities	821.0	821.0
Long-term debt due to VUHI	0	0
Total long-term debt - net	821.0	821.0
Deferred income taxes	(20.6)	(7.7)
Regulatory liabilities	2.3	2.6
Deferred Credits and Other Liabilities	1.6	1.4
Total deferred credits and other liabilities	(16.7)	(3.7)
Common stock (no par value)	778.1	774.6
Retained earnings	597.5	572.0
Total common shareholders' equity	1,375.6	1,346.6
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	2,296.7	2,361.8
Line of Credit Facility, Amount Outstanding	62
Unsecured Debt	821
Consolidation, Eliminations [Member]
ASSETS
Cash & cash equivalents	0	0	0	0
Accounts receivable - less reserves	0	0
Intercompany Receivables	(154.5)	(206.0)
Receivables due from other Vectren companies	0	0
Accrued unbilled revenues	0	0
Inventories	0	0
Recoverable fuel & natural gas costs	0	0
Prepayments & other current assets	(7.7)	(4.5)
Total current assets	(162.2)	(210.5)
Original cost	0	0
Less: accumulated depreciation & amortization	0	0
Net utility plant	0	0
Investments in consolidated subsidiaries	(1,300.1)	(1,272.2)
Notes receivable from consolidated subsidiaries	(679.7)	(679.7)
Investments in unconsolidated affiliates	0	0
Other investments	0	0
Nonutility property - net	0	0
Goodwill - net	0	0
Regulatory assets	0	0
Other assets	(6.6)	(6.6)
TOTAL ASSETS	(2,148.6)	(2,169.0)
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	0	0
Accounts payable to affiliated companies	0	0
Intercompany Payables	(31.3)	(11.8)
Payables to other Vectren companies	0	0
Refundable fuel and natural gas costs	0
Accrued liabilities	(7.7)	(4.5)
Short-term borrowings	0	0
Intercompany short-term borrowings	(123.2)	(194.2)
Current maturities of long-term debt payable to VUHI	0
Total current liabilities	(162.2)	(210.5)
Long-term Debt - Net of Current Maturities	0	0
Long-term debt due to VUHI	(679.7)	(679.7)
Total long-term debt - net	(679.7)	(679.7)
Deferred income taxes	0	0
Regulatory liabilities	0	0
Deferred Credits and Other Liabilities	(6.6)	(6.6)
Total deferred credits and other liabilities	(6.6)	(6.6)
Common stock (no par value)	(791.3)	(787.8)
Retained earnings	(508.8)	(484.4)
Total common shareholders' equity	(1,300.1)	(1,272.2)
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	(2,148.6)	(2,169.0)
Consolidated Entities [Member]
ASSETS
Cash & cash equivalents	4.1	6.0	13.3	2.4
Accounts receivable - less reserves	56.2	95.5
Intercompany Receivables	0	0
Receivables due from other Vectren companies	0.1	0.2
Accrued unbilled revenues	35.5	90.8
Inventories	107.0	132.5
Recoverable fuel & natural gas costs	14.6	12.4
Prepayments & other current assets	29.0	69.3
Total current assets	246.5	406.7
Original cost	5,091.0	4,979.9
Less: accumulated depreciation & amortization	2,001.1	1,947.3
Net utility plant	3,089.9	3,032.6
Investments in consolidated subsidiaries	0	0
Notes receivable from consolidated subsidiaries	0	0
Investments in unconsolidated affiliates	0.2	0.2
Other investments	32.1	31.8
Nonutility property - net	145.7	156.6
Goodwill - net	205.0	205.0
Regulatory assets	119.3	100.0
Other assets	38.1	41.6
TOTAL ASSETS	3,876.8	3,974.5
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	80.1	112.9
Accounts payable to affiliated companies	13.8	36.8
Intercompany Payables	0	0
Payables to other Vectren companies	24.9	30.1
Refundable fuel and natural gas costs	5.0
Accrued liabilities	118.2	121.0
Short-term borrowings	61.5	142.8
Intercompany short-term borrowings	0	0
Current maturities of long-term debt payable to VUHI	5.0
Total current liabilities	308.5	443.6
Long-term Debt - Net of Current Maturities	1,203.3	1,208.2
Long-term debt due to VUHI	0	0
Total long-term debt - net	1,203.3	1,208.2
Deferred income taxes	542.1	537.5
Regulatory liabilities	355.2	345.2
Deferred Credits and Other Liabilities	92.1	93.4
Total deferred credits and other liabilities	989.4	976.1
Common stock (no par value)	778.1	774.6
Retained earnings	597.5	572.0
Total common shareholders' equity	1,375.6	1,346.6
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	$ 3,876.8	$ 3,974.5

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Basis of Presentation

6 Months Ended

Jun. 30, 2012

Basis of Presentation [Abstract]

Basis of Presentation

Basis of Presentation

The interim condensed consolidated 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 condensed consolidated 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, 2011, filed with the Securities and Exchange Commission on March 2, 2012, 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.

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CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited) (Parenthetical) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Assets, Current [Abstract]
Allowance for Doubtful Accounts Receivable, Current	$ 5.4	$ 5.9

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Fair Value Measurements

6 Months Ended

Jun. 30, 2012

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow:

	June 30, 2012				December 31, 2011
(In millions)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	1,208.3	$	1,390.0	$	1,208.2	$	1,345.7
Short-term borrowings	61.5		61.5		142.8		142.8
Cash & cash equivalents	4.1		4.1		6.0		6.0

For the balance sheet dates presented in these financial statements, the Company had material assets or liabilities recorded at fair value outstanding.

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.

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.

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Document and Entity Information	6 Months Ended
	Jun. 30, 2012	Jul. 31, 2012
Entity Information [Line Items]
Entity Registrant Name	VECTREN UTILITY HOLDINGS INC
Entity Central Index Key	0001129542
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		10
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q2
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2012

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Impact of Recently Issued Accounting Principles

6 Months Ended

Jun. 30, 2012

Impact of Recently Issued Accounting Principles [Abstract]

Impact of Recently Issued Accounting Principles

Impact of Recently Issued Accounting Principles

Other Comprehensive Income (OCI)

In 2011, the FASB issued new accounting guidance regarding the presentation of comprehensive income within financial statements.  The new guidance requires entities to report components of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements.  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 adopted this guidance, as amended for condensed quarterly reporting, for the quarterly reporting period ended March 31, 2012.  During the periods presented comprehensive income and net income were equal.

Goodwill Testing

In September 2011, the FASB issued new accounting guidance regarding testing goodwill for impairment.  The new guidance will allow the Company an option to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test.  Using the new guidance, the Company no longer would be required to calculate the fair value of a reporting unit unless the Company determines, based on that qualitative assessment, that it is more likely than not that its fair value is less than its carrying amount.  The Company considered this option during its quarterly reporting period ended March 31, 2012 and concluded the continuation of the use of a quantitative approach is appropriate.

Fair Value Measurement and Disclosure

In May 2011, the FASB issued accounting guidance to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and International Financial Reporting Standards (IFRS). The amendments are not intended to change the application of the current fair value requirements, but to clarify the application of existing requirements. The guidance does change particular principles or requirements for measuring fair value or disclosing information about fair value measurements. To improve consistency, language has been changed to ensure that U.S. GAAP and IFRS fair value measurement and disclosure requirements are described in the same way. The Company adopted this guidance for its quarterly reporting period ended March 31, 2012.  The adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.

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CONSOLIDATED CONDENSED STATEMENTS OF INCOME (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
OPERATING REVENUES [Abstract]
Gas utility	$ 116.0	$ 134.0	$ 408.3	$ 490.7
Electric utility	149.3	159.3	288.7	305.7
Other	0.5	0.5	0.9	1.0
Total operating revenues	265.8	293.8	697.9	797.4
OPERATING EXPENSES [Abstract]
Cost of gas sold	31.8	48.8	168.9	243.9
Cost of fuel & purchased power	47.0	60.3	91.7	119.8
Other operating	77.8	78.2	157.7	165.1
Depreciation & Amortization	47.8	47.9	96.4	96.1
Taxes other than income taxes	11.6	11.1	27.5	29.1
Total operating expenses	216.0	246.3	542.2	654.0
OPERATING INCOME	49.8	47.5	155.7	143.4
Nonoperating Income (Expense) [Abstract]
Other income - net	0.7	2.2	2.9	3.9
Interest Expense	18.0	20.4	35.7	40.8
INCOME BEFORE INCOME TAXES	32.5	29.3	122.9	106.5
Income taxes	12.4	13.0	46.8	41.6
NET INCOME	$ 20.1	$ 16.3	$ 76.1	$ 64.9

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Financing Activities

6 Months Ended

Jun. 30, 2012

Debt Disclosure [Abstract]

Financing Activities

Financing Activities

On February 1, 2012, the Company issued $100 million of senior unsecured notes at an interest rate of 5.00 percent per annum and with a maturity date of February 3, 2042.  The notes were sold to various institutional investors pursuant to a private placement note purchase agreement executed in November 2011 with a delayed draw feature.  These senior notes are unsecured and jointly and severally guaranteed by Utility Holdings’ regulated utility subsidiaries, SIGECO, Indiana Gas, and VEDO.  The proceeds from the sale of the notes, net of issuance costs, totaled approximately $99.5 million.  These notes have no sinking fund requirements and interest payments are due semi-annually.  These notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Utility Holdings’ borrowing arrangements. As of December 31, 2011, the Company had reclassified $100 million of short-term borrowings as long-term debt to reflect those borrowings were refinanced with the proceeds received.

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Transactions with Other Vectren Companies and Affiliates

6 Months Ended

Jun. 30, 2012

Transactions with Other Vectren Companies and Affiliates [Abstract]

Transactions With Other Vectren Companies and Affiliates [Text Block]

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, 2012 and 2011 totaled $33.3 million and $42.5 million, respectively, and for the six months ended June 30, 2012 and 2011 totaled $58.2 million and $75.8 million, respectively.  Amounts owed to Vectren Fuels at June 30, 2012 and December 31, 2011 are included in Payables to other Vectren companies in the Consolidated Balance Sheets.

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 $11.5 million and $8.6 million for the three months ended June 30, 2012 and 2011, respectively, and for the six months ended June 30, 2012 and 2011 totaled $19.6 million and $13.2 million, respectively.  Amounts owed to Miller at June 30, 2012 and December 31, 2011 are included in Payables to other Vectren companies in the Consolidated Balance Sheets.

ProLiance Holdings, LLC (ProLiance)

ProLiance, a nonutilityenergy 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 as well as Citizens’ utilities.  ProLiance’s primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services. 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.

Purchases from ProLiance for resale and for injections into storage for the three months ended June 30, 2012 and 2011 totaled $50.2 million and $79.0 million, respectively, and for the six months ended June 30, 2012 and 2011 totaled $129.7 million and $198.3 million, respectively.  Amounts owed to ProLiance at June 30, 2012 and December 31, 2011 for those purchases were $13.8 million and $36.8 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.  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, 2012  and 2011, Utility Holdings received corporate allocations totaling $11.4 million and $12.4 million, respectively. For the six months ending June 30, 2012 and 2011, Utility Holdings received corporate allocations totaling $23.9 million and $26.2 million, respectively.

The Company does not have share-based compensation plans and pension and other postretirement plans separate from Vectren and allocated costs include participation in Vectren’s plans.  The allocation methodology for retirement costs is consistent with FASB guidance related to “multiemployer” benefit accounting.

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Organization and Nature of Operations (Details)	6 Months Ended
	Jun. 30, 2012
Organization and Nature of Operations [Abstract]
Number of public utility subsidiaries owned by wholly owned subsidiary, Vectren Utility Holdings, Inc. (in number of subsidiaries)	3
Estimated number of natural gas customers located in central and southern Indiana serviced by Indiana Gas Company, Inc. (in number of customers)	567,000
Estimated number of electric customers located near Evansville in southwestern Indiana serviced by Southern Indiana Gas and Electric Company (in number of customers)	142,000
Estimated number of natural gas customers located near Evansville in southwestern Indiana serviced by Southern Indiana Gas and Electric Company (in number of customers)	110,000
Estimated number of natural gas customers located near Dayton in west central Ohio serviced by the Ohio operations (in number of customers)	312,000

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Segment Reporting

6 Months Ended

Jun. 30, 2012

Segment Reporting [Abstract]

Segment Reporting

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 Gas Utility Services  and Electric Utility Services.  Gas Utility Services provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio.  Electric Utility Services provides electric distribution services 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 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 Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2012			2011			2012			2011
Revenues
Gas Utility Services	$	116.0		$	134.0		$	408.3		$	490.7
Electric Utility Services	149.3			159.3			288.7			305.7
Other Operations	10.0			10.9			19.9			21.9
Eliminations	(9.5		)	(10.4		)	(19.0		)	(20.9		)
Total revenues	$	265.8		$	293.8		$	697.9		$	797.4
Profitability Measure - Net Income
Gas Utility Services	$	1.3		$	2.1		$	38.8		$	38.3
Electric Utility Services	17.2			13.6			32.8			22.3
Other Operations	1.6			0.6			4.5			4.3
Total net income	$	20.1		$	16.3		$	76.1		$	64.9

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Environmental Matters

6 Months Ended

Jun. 30, 2012

Environmental Matters Disclosure [Abstract]

Environmental Matters

Environmental Matters

Air Quality

Cross-State Air Pollution Rule (Formerly Clean Air Interstate Rule (CAIR))

On July 7, 2011, EPA finalized the Cross-State Air Pollution Rule (CSAPR).  CSPAR is the EPA’s response to the US Court of Appeals for the District of Columbia’s (the Court) remand of the Clean Air Interstate Rule (CAIR). CAIR was originally established in 2005 as an allowance cap and trade program that required reductions from coal-burning power plants for NOx emissions beginning January 1, 2009 and SO₂ emissions beginning January 1, 2010, with a second phase of reductions in 2015.

In an effort to address the Court’s finding that CAIR did not adequately ensure attainment of pollutants in certain downwind states due to unlimited trading of SO₂ and NOx allowances, CSPAR reduces the ability of facilities to meet emission reduction targets through allowance trading.  Like CAIR, CSPAR sets individual state caps for SO₂ and NOx emissions.  However, unlike CAIR in which states allocated allowances to generating units through state implementation plans, CSPAR allowances were allocated to individual units directly through the federal rule.  As finalized, CSAPR requires a 71 percent reduction of SO₂ emissions compared to 2005 national levels and a 52 percent reduction of NOx emissions compared to 2005 national levels and that such reductions are to be achieved with initial step reductions beginning January 1, 2012, with final compliance to be achieved in 2014.  Multiple administrative and judicial challenges were filed, including requests to stay CSPAR’s implementation. On December 30, 2011, the Court granted a stay of CSPAR and ordered expedited briefing. Briefing is completed and oral arguments were held in April. A final ruling is expected later this year.

Mercury and Air Toxics (MATS) Rule

On December 21, 2011, the EPA finalized the Utility MATS Rule.  The MATS Rule is the EPA’s response to the US Court of Appeals for the District of Columbia vacating the Clean Air Mercury Rule (CAMR) in 2008.  CAMR was originally established in 2005 as a nation-wide mercury emission allowance cap and trade system which sought to reduce utility emissions of mercury starting in 2010.

The MATS Rule sets emission limits for hazardous air pollutants for existing and new coal-fired power plants and identifies the following broad categories of hazardous air pollutants:  mercury, non-mercury hazardous air pollutants (primarily arsenic, chromium, cobalt, and selenium) and acid gases (hydrogen cyanide, hydrogen chloride, and hydrogen fluoride).  The rule imposes mercury emission limits for two sub-categories of coal, and proposed surrogate limits for non-mercury and acid gas hazardous air pollutants. The EPA did not grant blanket compliance extensions, but asserted that states have broad authority to grant one year extensions for individual units where potential reliability impacts have been demonstrated.  Reductions are to be achieved within three years of publication of the final rule in the Federal register (April 2015).  Initiatives to suspend CSPAR’s implementation by the Congress also apply to the implementation of the MATS rule.  Multiple judicial challenges were filed and briefing is proceeding. The EPA also recently announced it will reconsider MATS requirements for new construction. Such requirements are more stringent than those for existing plants. Utilities planning new coal-fired generation had argued standards outlined in the MATS could not be attained even using the best available control technology.

Conclusions Regarding Air Regulations

To comply with Indiana’s implementation plan of the Clean Air Act, and other federal air quality standards, the Company obtained authority from the IURC to invest in clean coal technology.  Using this authorization, the Company invested approximately $411 million starting in 2001 with the last equipment being placed into service on January 1, 2010.  The pollution control equipment included 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 obtained April 27, 2011.  SIGECO’s coal fired generating fleet is 100 percent scrubbed for SO₂ and 90 percent controlled for NOx. 

Utilization of the Company’s NOx and SO₂  allowances can be impacted as these regulations are revised and implemented.  Most of these allowances were granted to the Company at zero cost; therefore, any reduction in carrying value that could result from future changes in regulations would be immaterial.

The Company is currently reviewing the sufficiency of its existing pollution control equipment in relation to the requirements described in CSPAR and the MATS Rule.  Based upon an initial review of the final rules, including minor revisions made to CSPAR in October 2011, 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 and additional operating expenses could be required.  The Company believes that such additional costs, if necessary, would be recoverable under Indiana Senate Bill 251 referenced above.

Notice of Violation Received

The Company received a notice of violation (NOV) from the EPA pertaining to its A.B. Brown power plant.  The NOV asserts that when the power plant was equipped with SCRs the correct permits were not obtained or the best available control technology to control incidental sulfuric acid mist was not installed.  Based on the Company’s understanding of the New Source Review reform in effect when the equipment was installed, it is the Company’s position that its SCR project was exempted from such requirements.  At this time the Company is reviewing the potential impact this NOV could have on operating costs.  To the extent costs to comply increase, they should be recoverable under Indiana law.

Water

Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” to minimize adverse environmental impacts in a body of water.  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 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.  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.  A final rule is expected in 2013.  Depending on the final rule and on the Company’s facts and circumstances, capital investments could be in the $40 million range if new infrastructure, such as new cooling water towers, is required.  Costs for compliance with these final regulations would likely qualify as federally mandated regulatory requirements under Indiana Senate Bill 251 referenced above.

Coal Ash Waste Disposal & Ash Ponds

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 alternatives include regulating coal combustion by-products that are not being beneficially reused as hazardous waste.  The EPA did not offer a preferred alternative, but took public comment on multiple alternative regulations.  Rules may not be finalized in 2012 given oversight hearings, congressional interest, and other factors.

At this time, the majority of the Company’s ash is being beneficially reused.  However, the alternatives proposed would require modification to or closure of existing ash ponds.  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.  Costs for compliance with these regulations would likely qualify as federally mandated regulatory requirements under Senate Bill 251 referenced above. 

Climate Change

In April 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 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 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.  The EPA has promulgated two greenhouse gas regulations that apply to the Company’s generating facilities.  In 2009, the EPA finalized a mandatory greenhouse gas emissions registry which requires the reporting of emissions.  The EPA has also 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.  EPA's PSD and Title V permitting rules for GHG's were recently upheld by the US Court of Appeals for the District of Columbia. In April 2012, the EPA issued its proposed new source performance standards for greenhouse gases applicable to new construction.  This proposed rule does not apply to existing sources, such as Vectren’s generating facilities.  The EPA has not indicated when it intends to propose standards for existing sources.

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 or rulemaking, 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. 

Manufactured Gas Plants

In the past, the Company operated facilities to manufacture natural gas.  Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years.  Under current 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.

In the Indiana Gas service territory, the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites have been identified for which the Company may have some remedial responsibility.  A remedial investigation/feasibility study (RI/FS) was completed 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.  The remaining sites have been submitted to the IDEM's Voluntary Remediation Program (VRP).  The Company has identified its involvement in five manufactured gas plant sites in SIGECO’s service territory, all of which are currently enrolled in the IDEM’s VRP.  The Company is currently conducting some level of remedial activities, including groundwater monitoring at certain sites.

The Company has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites.  While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, the Company has recorded cumulative costs that it reasonably expects to incur totaling approximately $41.7 million ($23.2 million at Indiana Gas and $18.5 million at SIGECO).  The estimated accrued costs are limited to the Company’s share of the remediation efforts and are therefore net of exposures of other potentially responsible parties (PRP).

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.  SIGECO filed a declaratory judgment action against its insurance carriers seeking a judgment finding its carriers liable under the policies for coverage of further investigation and any necessary remediation costs that SIGECO may accrue under the VRP program and/or another site subject to a lawsuit that has been settled.  In November 2011, 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 settlement agreements with all known insurance carriers and has recorded approximately $15.2 million of expected insurance recoveries.

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, 2012 and December 31, 2011, respectively, approximately $4.7 million and $6.5 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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Commitments and Contingencies

6 Months Ended

Jun. 30, 2012

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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.

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Legislative Matters

6 Months Ended

Jun. 30, 2012

Legislative Matters Disclosure [Abstract]

Legislative Matters

Legislative Matters

Pipeline Safety Law

On January 3, 2012 the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 was signed into law.  This new law, which reauthorizes federal pipeline safety programs through fiscal year 2015, provides for enhanced safety, reliability and environmental protection in the transportation of energy products by pipeline. The new law increases federal enforcement authority, grants the federal government expanded authority over pipeline safety, provides for new safety regulations and standards, and authorizes or requires the completion of several pipeline safety-related studies.  The DOT is required to promulgate a number of new regulatory requirements.  Those regulations may eventually lead to further regulatory or statutory requirements.

The Company continues to study the impact of the new law and potential new regulations associated with its implementation.  At this time, compliance costs and other effects associated with the increased pipeline safety regulations remain uncertain.  However, the new law is expected to result in further investment in pipeline inspections, and where necessary, additional modernization of pipeline infrastructure; and therefore, result in both increased levels of operating expenses and capital expenditures associated with the Company’s natural gas distribution businesses.  Operating expenses associated with expanded compliance requirements may grow to approximately $9 million annually, with $6 million attributable to the Indiana operations.  Related to the Indiana operations, the Company expects to seek recovery under Senate Bill 251 referenced below, or such costs may be recoverable through current tracking mechanisms.  Capital investments, driven by the pipeline safety regulations, associated with the Company’s Indiana gas utilities are expected to be approximately $80 million over the next five years, which would likely qualify as federally mandated regulatory requirements.  In Ohio, capital investments are expected to be approximately $55 million over the next five years.  The Company expects to seek recovery of capital investments associated with complying with these federal mandates in accordance with Senate Bill 251 in Indiana and House Bill 95 in Ohio (referenced below).

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 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 general rate case.  Such costs include construction, depreciation, operating and other costs.  The remaining 20 percent of those costs are to be deferred for recovery in the utility’s next general rate case.  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 control, including greenhouse gas emissions, among other federally mandated projects and potential projects. 

Ohio House Bill 95

In June 2011, Ohio House Bill 95 was 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 for recovery of 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 deferral of program costs, such as depreciation, property taxes, and debt-related carrying costs.  On February 3, 2012, the Company initiated a filing under House Bill 95.  This filing requests accounting authority to defer depreciation, debt-related post in service carrying costs and property taxes for its approximate $25 million fifteen month capital expenditure program ending on December 31, 2012.  The capital expenditure program includes infrastructure expansion and improvements not covered by the Company’s distribution replacement rider as well as expenditures necessary to comply with PUCO rules, regulations and orders.  The Company’s approach is consistent with approaches made by other Ohio utilities.  A procedural schedule associated with the filing has been set and all respective responses have been submitted.  It is anticipated the PUCO will act on the Company’s filing and the flings of the other Ohio utilities later this year.

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Rate & Regulatory Matters

6 Months Ended

Jun. 30, 2012

Rate and Regulatory Matters [Abstract]

Rate and Regulatory Matters

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.  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 would be initiated.

Coal Procurement Procedures

Vectren South submitted a request for proposal in April 2011 regarding coal purchases for a four year period beginning in 2012.  After negotiations with bidders, Vectren South 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 case, a sub docket proceeding was established to review the Company’s prospective coal procurement procedures, and the Company submitted evidence related to its recent request for proposal (RFP) and those coal procurement procedures to the IURC in September 2011.  In March 2012, the IURC issued its order in the sub docket.  The order concluded that Vectren South’s 2011 RFP process resulted in prices at the lowest fuel cost reasonably possible.  The IURC will continue to regularly monitor Vectren South’s procurement process in future fuel adjustment proceedings.

Vectren South Electric Fuel Cost Reduction

In the spring of 2011, Vectren South secured contracts for lower coal costs through a formal bidding process. This lower-priced contract coal started being delivered to Vectren’s power plants during 2012. On December 5, 2011 within the quarterly FAC filing, Vectren South submitted a joint proposal with the OUCC to reduce its fuel costs by accelerating into 2012 the impact of lower cost coal under new term contracts effective after 2012. The cost difference will be deferred to a regulatory asset and recovered over a six-year period without interest beginning in 2014.  The IURC approved this proposal on January 25, 2012, with a positive impact to customer’s rates effective February 1, 2012.  The deferred amount includes a reduction in the value of the coal inventory at December 31, 2011 of approximately $17.7 million to reflect existing coal inventory at the new, lower price.  Deferrals related to coal purchases in 2012 have totaled approximately $22.4 million, bringing the total deferred balance as of June 30, 2012 to $40.1 million. In addition to coal purchased under these contracts, Vectren South has also recently contracted with Vectren Fuels, Inc. to purchase lower priced spot coal. This spot purchase was found to be reasonable in a recent FAC order.

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, and include some for 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.

On August 31, 2011 the IURC issued an order approving an initial three year DSM plan in the Vectren South service territory that complies with the IURC’s energy saving targets.  Consistent with the Company’s proposal, the order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; 3) lost margin recovery associated with the implementation of DSM programs for large customers; and 4) deferral of lost margin up to $1.0 million in 2011 associated with small customer DSM programs for subsequent recovery under a tracking mechanism to be proposed by the Company.  On June 20, 2012, the IURC issued an order approving a small customer lost margin recovery mechanism, inclusive of all previous deferrals. This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the Company's last base rate proceeding discussed earlier. 

Vectren South Electric Dense Pack Filing

On September 14, 2011, Vectren South filed a petition with the IURC seeking recovery of and return on the capital investment in dense pack technology to improve the efficiency of its A.B. Brown Generating Station.  This investment is expected to be approximately $32 million over the next two years, of which approximately $25.8 million has been invested to date.  This technology is expected to allow the A.B. Brown units to run at least 5 percent more efficient, thereby burning less fuel, and reducing fuel costs and emissions of pollutants.  In the Company’s base rate order issued in April 2011, the IURC authorized deferred accounting treatment associated with this investment. As a result of a subsequent filing by the Company seeking a current recovery mechanism in lieu of the deferred accounting treatment, the IURC issued an order on July 11, 2012, denying the Company's request for a current recovery mechanism stating that dense pack technology does not qualify as advanced technology under the statute. Although the Company believes that the investment does meet the requirements of the statute that would have allowed for timely recovery, it does not plan to appeal the decision and will employ the deferred accounting treatment ordered in the Company's last base rate order discussed earlier.

Vectren North Reporting Location Consolidation Proceeding

Vectren North implemented a reporting location consolidation plan in 2011 and  converted certain reporting locations into staging areas throughout the Vectren North territory.  On May 26, 2011, the International Brotherhood of Electrical Workers Local 1393, United Steel Workers Locals 12213 and 7441 and others (the “Complainants”) filed a formal complaint with the IURC claiming that implementation of the consolidation plan by Vectren North endangers public safety and impairs Vectren North's ability to provide adequate, safe and reliable service.  The Complainants asked the IURC to require Vectren North to reopen previously consolidated reporting locations and maintain and staff those locations.  A hearing in this case was held in February 2012.  Complainants submitted a proposed order in March and Vectren North submitted a reply brief and a proposed order in April.  The Company expects the IURC to issue a final order in this matter some time in 2012.

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Fair Value Measurements (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Recovery period for call premiums on reacquisition of utility long-term debt (in years)	15
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	$ 1,208.3	$ 1,208.2
Short-term Borrowings	61.5	142.8
Cash and cash equivalents	4.1	6.0
Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	1,390.0	1,345.7
Short-term Borrowings	61.5	142.8
Cash and cash equivalents	$ 4.1	$ 6.0

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2012

Fair Value Disclosures [Abstract]

Fair Value, by Balance Sheet Grouping [Table Text Block]

The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow:

	June 30, 2012				December 31, 2011
(In millions)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	1,208.3	$	1,390.0	$	1,208.2	$	1,345.7
Short-term borrowings	61.5		61.5		142.8		142.8
Cash & cash equivalents	4.1		4.1		6.0		6.0

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Subsidiary Guarantor and Consolidating Information Subsidiary Guarantor and Consolidating Information Cash Flows (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010
Net cash flows from operating activities		$ 249.0	$ 217.6
Additional capital contribution		3.5	0
Long-term debt - net of issuance costs		99.5	0
Dividends to parent		(50.5)	(45.8)
Retirement of long-term debt, including premiums paid		0	(0.5)
Net change in intercompany short-term borrowings		0
Net change in short-term borrowings		(181.3)	(47.0)
Net cash flows from financing activities		(128.8)	(93.3)
Consolidated subsidiary distributions	0
Other investing activities		2.2	0.3
Capital expenditures, excluding AFUDC equity		(124.1)	(112.4)
Other investing activities		(0.2)	(1.3)
Consolidated subsidiary investments		0
Net change in short term intercompany notes receivable		0
Net cash flows from investing activities		(122.1)	(113.4)
Net change in cash and cash equivalents		(1.9)	10.9
Cash & cash equivalents	4.1	4.1	13.3	6.0	2.4
Subsidiary Guarantors [Member]
Net cash flows from operating activities		233.3	218.7
Additional capital contribution		3.5
Long-term debt - net of issuance costs		0
Dividends to parent		(47.2)	(42.2)
Retirement of long-term debt, including premiums paid			(0.5)
Net change in intercompany short-term borrowings		(52.9)	(85.7)
Net change in short-term borrowings		0	0
Net cash flows from financing activities		(96.6)	(128.4)
Consolidated subsidiary distributions		0	0
Other investing activities		0	0.2
Capital expenditures, excluding AFUDC equity		(121.4)	(105.0)
Other investing activities		(0.2)	(1.3)
Consolidated subsidiary investments		0
Net change in long term intercompany notes receivable			0
Net change in short term intercompany notes receivable		(17.7)	15.9
Net cash flows from investing activities		(139.3)	(90.2)
Net change in cash and cash equivalents		(2.6)	0.1
Cash & cash equivalents	2.7	2.7	2.1	5.3	2.0
Parent Company [Member]
Net cash flows from operating activities		15.7	(1.1)
Additional capital contribution		3.5
Long-term debt - net of issuance costs		99.5
Dividends to parent		(50.5)	(45.8)
Retirement of long-term debt, including premiums paid			(0.5)
Net change in intercompany short-term borrowings		17.7	(15.9)
Net change in short-term borrowings		(181.3)	(47.0)
Net cash flows from financing activities		(111.1)	(109.2)
Consolidated subsidiary distributions		47.2	42.2
Other investing activities		2.2	0.1
Capital expenditures, excluding AFUDC equity		(2.7)	(7.4)
Other investing activities		0	0
Consolidated subsidiary investments		(3.5)
Net change in long term intercompany notes receivable			0.5
Net change in short term intercompany notes receivable		52.9	85.7
Net cash flows from investing activities		96.1	121.1
Net change in cash and cash equivalents		0.7	10.8
Cash & cash equivalents	1.4	1.4	11.2	0.7	0.4
Consolidation, Eliminations [Member]
Net cash flows from operating activities		0	0
Additional capital contribution		(3.5)
Long-term debt - net of issuance costs		0
Dividends to parent		47.2	42.2
Retirement of long-term debt, including premiums paid			0.5
Net change in intercompany short-term borrowings		35.2	101.6
Net change in short-term borrowings		0	0
Net cash flows from financing activities		78.9	144.3
Consolidated subsidiary distributions		(47.2)	(42.2)
Other investing activities		0	0
Capital expenditures, excluding AFUDC equity		0	0
Other investing activities		0	0
Consolidated subsidiary investments		3.5
Net change in long term intercompany notes receivable			(0.5)
Net change in short term intercompany notes receivable		(35.2)	(101.6)
Net cash flows from investing activities		(78.9)	(144.3)
Net change in cash and cash equivalents		0	0
Cash & cash equivalents	0	0	0	0	0
Consolidated Entities [Member]
Net cash flows from operating activities			217.6
Dividends to parent			(45.8)
Retirement of long-term debt, including premiums paid			(0.5)
Net change in intercompany short-term borrowings			0
Net change in short-term borrowings			(47.0)
Net cash flows from financing activities			(93.3)
Consolidated subsidiary distributions			0
Other investing activities			0.3
Capital expenditures, excluding AFUDC equity			(112.4)
Other investing activities			(1.3)
Net change in long term intercompany notes receivable			0
Net change in short term intercompany notes receivable			0
Net cash flows from investing activities			(113.4)
Net change in cash and cash equivalents			10.9
Cash & cash equivalents	$ 4.1	$ 4.1	$ 13.3	$ 6.0	$ 2.4

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CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (Unaudited) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
CASH FLOWS FROM OPERATING ACTIVITIES [Abstract]
Profitability Measure - Net income (loss)	$ 76.1	$ 64.9
Adjustments to Reconcile Net Income to Cash from Operating Activities [Abstract]
Depreciation & Amortization	96.4	96.1
Deferred income taxes & investment tax credits	21.9	28.2
Expense portion of pension & postretirement periodic benefit cost	2.5	2.3
Provision for uncollectible accounts	3.9	7.1
Other non-cash expense - net	4.7	4.3
Changes in working capital accounts [Abstract]
Accounts receivable, including to Vectren companies & accrued unbilled revenue	90.7	120.6
Inventories	3.2	15.8
Recoverable/refundable fuel & natural gas costs	2.8	(1.3)
Prepayments & other current assets	29.6	37.1
Accounts payable, including to Vectren companies & affiliated companies	(67.2)	(120.8)
Accrued liabilities	(2.8)	(0.2)
Changes in noncurrent ssets	0.2	(3.9)
Changes in noncurrent liabilities	(13.0)	(32.6)
Net cash flows from operating activities	249.0	217.6
Proceeds from:
Long-term debt - net of issuance costs	99.5	0
Additional capital contribution	3.5	0
Requirements for:
Dividends to parent	(50.5)	(45.8)
Retirement of long-term debt	0	(0.5)
Net change in short-term borrowings, including from other Vectren companies	(181.3)	(47.0)
Net cash flows from financing activities	(128.8)	(93.3)
CASH FLOWS FROM INVESTING ACTIVITIES [Abstract]
Proceeds from other investing activities	2.2	0.3
Requirements for:
Capital expenditures, excluding AFUDC equity	(124.1)	(112.4)
Other investments	(0.2)	(1.3)
Net cash flows from investing activities	(122.1)	(113.4)
Net change in cash and cash equivalents	(1.9)	10.9
Cash and cash equivalents at beginning of period	6.0	2.4
Cash and cash equivalents at end of period	$ 4.1	$ 13.3

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Accruals for Utility and NonUtility Plant

6 Months Ended

Jun. 30, 2012

Accruals for Utility & Nonutility Plant [Abstract]

Accruals for Utility and NonUtility Plant [Text Block]

Accruals for Utility & Nonutility Plant

As of June 30, 2012 and December 31, 2011, the Company has accruals related to utility and nonutility plant purchases totaling approximately $11.0 million and $9.2 million, respectively.

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Excise and Utility Receipts Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Excise and Utility Receipts Taxes [Abstract]
Excise and utility taxes collected and reported in operating revenue	$ 5.0	$ 5.4	$ 14.3	$ 16.4

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Subsidiary Guarantor and Consolidating Information Subsidiary Guarantor and Consolidating Information(Tables)

6 Months Ended

Jun. 30, 2012

Condensed Financial Information of Parent Company and Subsidiaries [Abstract]

Condensed consolidating balance sheets [Table Text Block]

Condensed Consolidating Balance Sheet as of June 30, 2012 (in millions):

ASSETS	Subsidiary		Parent			Eliminations &
	Guarantors		Company			Reclassifications			Consolidated
Current Assets
Cash & cash equivalents	$	2.7	$	1.4		$	—		$	4.1
Accounts receivable - less reserves	56.2		—			—			56.2
Intercompany receivables	17.7		136.8			(154.5		)	—
Receivables due from other Vectren companies	—		0.1			—			0.1
Accrued unbilled revenues	35.5		—			—			35.5
Inventories	107.0		—			—			107.0
Recoverable fuel & natural gas costs	14.6		—			—			14.6
Prepayments & other current assets	31.7		5.0			(7.7		)	29.0
Total current assets	265.4		143.3			(162.2		)	246.5
Utility Plant
Original cost	5,091.0		—			—			5,091.0
Less:  accumulated depreciation & amortization	2,001.1		—			—			2,001.1
Net utility plant	3,089.9		—			—			3,089.9
Investments in consolidated subsidiaries	—		1,300.1			(1,300.1		)	—
Notes receivable from consolidated subsidiaries	—		679.7			(679.7		)	—
Investments in unconsolidated affiliates	0.2		—			—			0.2
Other investments	27.2		4.9			—			32.1
Nonutility property - net	2.8		142.9			—			145.7
Goodwill - net	205.0		—			—			205.0
Regulatory assets	96.3		23.0			—			119.3
Other assets	41.9		2.8			(6.6		)	38.1
TOTAL ASSETS	$	3,728.7	$	2,296.7		$	(2,148.6	)	$	3,876.8
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent			Eliminations &
	Guarantors		Company			Reclassifications			Consolidated
Current Liabilities
Accounts payable	$	67.9	$	12.2		$	—		$	80.1
Accounts payable to affiliated companies	13.8		—			—			13.8
Intercompany payables	31.3		—			(31.3		)	—
Payables to other Vectren companies	15.3		9.6			—			24.9
Refundable fuel & natural gas costs	5.0		—			—			5.0
Accrued liabilities	110.0		15.9			(7.7		)	118.2
Short-term borrowings	—		61.5			—			61.5
Intercompany short-term borrowings	105.6		17.6			(123.2		)	—
Current maturities of long-term debt payable to VUHI	5.0		—			—			5.0
Total current liabilities	353.9		116.8			(162.2		)	308.5
Long-Term Debt
Long-term debt - net of current maturities	382.3		821.0			—			1,203.3
Long-term debt due to VUHI	679.7		—			(679.7		)	—
Total long-term debt - net	1,062.0		821.0			(679.7		)	1,203.3
Deferred Income Taxes & Other Liabilities
Deferred income taxes	562.7		(20.6		)	—			542.1
Regulatory liabilities	352.9		2.3			—			355.2
Deferred credits & other liabilities	97.1		1.6			(6.6		)	92.1
Total deferred credits & other liabilities	1,012.7		(16.7		)	(6.6		)	989.4
Common Shareholder's Equity
Common stock (no par value)	791.3		778.1			(791.3		)	778.1
Retained earnings	508.8		597.5			(508.8		)	597.5
Total common shareholder's equity	1,300.1		1,375.6			(1,300.1		)	1,375.6
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,728.7	$	2,296.7		$	(2,148.6	)	$	3,876.8

Condensed Consolidating Balance Sheet as of December 31, 2011 (in millions):

ASSETS	Subsidiary		Parent			Eliminations &
	Guarantors		Company			Reclassifications			Consolidated
Current Assets
Cash & cash equivalents	$	5.3	$	0.7		$	—		$	6.0
Accounts receivable - less reserves	94.8		0.7			—			95.5
Intercompany receivables	—		206.0			(206.0		)	—
Receivables due from other Vectren companies	—		0.2			—			0.2
Accrued unbilled revenues	90.8		—			—			90.8
Inventories	132.5		—			—			132.5
Recoverable fuel & natural gas costs	12.4		—			—			12.4
Prepayments & other current assets	57.1		16.7			(4.5		)	69.3
Total current assets	392.9		224.3			(210.5		)	406.7
Utility Plant
Original cost	4,979.9		—			—			4,979.9
Less:  accumulated depreciation & amortization	1,947.3		—			—			1,947.3
Net utility plant	3,032.6		—			—			3,032.6
Investments in consolidated subsidiaries	—		1,272.2			(1,272.2		)	—
Notes receivable from consolidated subsidiaries	—		679.7			(679.7		)	—
Investments in unconsolidated affiliates	0.2		—			—			0.2
Other investments	26.8		5.0			—			31.8
Nonutility property - net	3.0		153.6			—			156.6
Goodwill - net	205.0		—			—			205.0
Regulatory assets	77.0		23.0			—			100.0
Other assets	44.2		4.0			(6.6		)	41.6
TOTAL ASSETS	$	3,781.7	$	2,361.8		$	(2,169.0	)	$	3,974.5
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent			Eliminations &
	Guarantors		Company			Reclassifications			Consolidated
Current Liabilities
Accounts payable	$	106.1	$	6.8		$	—		$	112.9
Accounts payable to affiliated companies	36.8		—			—			36.8
Intercompany payables	11.8		—			(11.8		)	—
Payables to other Vectren companies	30.1		—			—			30.1
Accrued liabilities	112.9		12.6			(4.5		)	121.0
Short-term borrowings	—		142.8			—			142.8
Intercompany short-term borrowings	158.5		35.7			(194.2		)	—
Total current liabilities	456.2		197.9			(210.5		)	443.6
Long-Term Debt
Long-term debt	387.2		821.0			—			1,208.2
Long-term debt due to VUHI	679.7		—			(679.7		)	—
Total long-term debt - net	1,066.9		821.0			(679.7		)	1,208.2
Deferred Income Taxes & Other Liabilities
Deferred income taxes	545.2		(7.7		)	—			537.5
Regulatory liabilities	342.6		2.6			—			345.2
Deferred credits & other liabilities	98.6		1.4			(6.6		)	93.4
Total deferred credits & other liabilities	986.4		(3.7		)	(6.6		)	976.1
Common Shareholder's Equity
Common stock (no par value)	787.8		774.6			(787.8		)	774.6
Retained earnings	484.4		572.0			(484.4		)	572.0
Total common shareholder's equity	1,272.2		1,346.6			(1,272.2		)	1,346.6
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,781.7	$	2,361.8		$	(2,169.0	)	$	3,974.5

Condensed consolidating statements fo income [Table Text Block]

Condensed Consolidating Statement of Income for the three months ended June 30, 2012 (in millions):

	Subsidiary Guarantors	Parent Company	Eliminations & Reclassifications		Consolidated
OPERATING REVENUES
Gas utility	116.0	—	—		116.0
Electric utility	149.3	—	—		149.3
Other	—	10.0	(9.5	)	0.5
Total operating revenues	265.3	10.0	(9.5	)	265.8
OPERATING EXPENSES
Cost of gas sold	31.8	—	—		31.8
Cost of fuel & purchased power	47.0	—	—		47.0
Other operating	86.3	0.5	(9.0	)	77.8
Depreciation & amortization	42.1	5.6	0.1		47.8
Taxes other than income taxes	11.2	0.3	0.1		11.6
Total operating expenses	218.4	6.4	(8.8	)	216.0
OPERATING INCOME	46.9	3.6	(0.7	)	49.8
Other income (loss) - net	0.2	9.9	(9.4	)	0.7
Interest expense	16.4	11.7	(10.1	)	18.0
INCOME BEFORE INCOME TAXES	30.7	1.8	—		32.5
Income taxes	12.2	0.2	—		12.4
Equity in earnings of consolidated companies, net of tax	—	18.5	(18.5	)	—
NET INCOME	18.5	20.1	(18.5	)	20.1

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

	Subsidiary Guarantors	Parent Company	Eliminations & 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 (loss) - net	1.8	12.7	(12.3	)	2.2
Interest expense	18.8	14.1	(12.5	)	20.4
INCOME BEFORE INCOME TAXES	26.8	2.5	—		29.3
Income taxes	11.1	1.9	—		13.0
Equity in earnings of consolidated companies, net of tax	—	15.7	(15.7	)	—
NET INCOME	15.7	16.3	(15.7	)	16.3

Condensed Consolidating Statement of Income for the six months ended June 30, 2012 (in millions):

	Subsidiary Guarantors		Parent Company			Eliminations & Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	408.3	$	—		$	—		$	408.3
Electric utility	288.7		—			—			288.7
Other	—		19.9			(19.0		)	0.9
Total operating revenues	697.0		19.9			(19.0		)	697.9
OPERATING EXPENSES
Cost of gas sold	168.9		—			—			168.9
Cost of fuel & purchased power	91.7		—			—			91.7
Other operating	175.9		0.5			(18.7		)	157.7
Depreciation & amortization	83.8		12.4			0.2			96.4
Taxes other than income taxes	26.7		0.7			0.1			27.5
Total operating expenses	547.0		13.6			(18.4		)	542.2
OPERATING INCOME	150.0		6.3			(0.6		)	155.7
Other income (loss) - net	2.2		20.5			(19.8		)	2.9
Interest expense	32.9		23.2			(20.4		)	35.7
INCOME BEFORE INCOME TAXES	119.3		3.6			—			122.9
Income taxes	47.7		(0.9		)	—			46.8
Equity in earnings of consolidated companies, net of tax	—		71.6			(71.6		)	—
NET INCOME	$	71.6	$	76.1		$	(71.6	)	$	76.1

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

	Subsidiary Guarantors		Parent Company		Eliminations & 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	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 - net	3.3		25.5		(24.9		)	3.9
Interest expense	37.7		28.4		(25.3		)	40.8
INCOME BEFORE INCOME TAXES	101.7		4.8		—			106.5
Income taxes	41.0		0.6		—			41.6
Equity in earnings of consolidated companies, net of tax	—		60.7		(60.7		)	—
NET INCOME	$	60.7	$	64.9	$	(60.7	)	$	64.9

Condensed consolidating statements of cash flows [Table Text Block]

Condensed Consolidating Statement of Cash Flows for the six months ended June 30, 2012 (in millions):

	Subsidiary Guarantors			Parent Company			Eliminations			Consolidated
NET CASH FLOWS FROM OPERATING ACTIVITIES	$	233.3		$	15.7		$	—		$	249.0
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from
Additional capital contribution from parent	3.5			3.5			(3.5		)	3.5
Long-term debt - net of issuance costs	—			99.5			—			99.5
Requirements for:
Dividends to parent	(47.2		)	(50.5		)	47.2			(50.5		)
Net change in intercompany short-term borrowings	(52.9		)	17.7			35.2			—
Net change in short-term borrowings	—			(181.3		)	—			(181.3		)
Net cash flows from financing activities	(96.6		)	(111.1		)	78.9			(128.8		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from
Consolidated subsidiary distributions	—			47.2			(47.2		)	—
Other investing activities	—			2.2			—			2.2
Requirements for:
Capital expenditures, excluding AFUDC equity	(121.4		)	(2.7		)	—			(124.1		)
Consolidated subsidiary investments	—			(3.5		)	3.5			—
Other investing activities	(0.2		)	—			—			(0.2		)
Net change in short-term intercompany notes receivable	(17.7		)	52.9			(35.2		)	—
Net cash flows from investing activities	(139.3		)	96.1			(78.9		)	(122.1		)
Net change in cash & cash equivalents	(2.6		)	0.7			—			(1.9		)
Cash & cash equivalents at beginning of period	5.3			0.7			—			6.0
Cash & cash equivalents at end of period	$	2.7		$	1.4		$	—		$	4.1

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

	Subsidiary Guarantors			Parent 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