10-Q/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q/A

AMENDMENT #1

(Mark One)

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

For the quarterly period ended June30, 2013

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 o                                                                                                        Accelerated 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).

o Yes    ý No

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	July31, 2013
Class	Number of Shares	Date

Explanatory Note

The purpose of this Amendment No. 1 on Form 10-Q/A (the “Amendment”) is to correct errors in Item 1 of Part 1, and the related Exhibit 101, that occurred during the third-party managed EDGAR conversion process for the Quarterly Report on Form 10-Q of Vectren Utility Holdings, Inc. (the “Company”) for the quarter ended June 30, 2013, which was filed on August 9, 2013 (the “Original Filing”). None of the remaining items included in the Original Filing has been amended, but we have repeated these remaining items in this Amendment solely for the reader’s convenience. This Amendment is presented as of the date of the Original Filing and does not purport to otherwise update the Original Filing or to discuss any developments subsequent to the filing of the Original Filing. All references to Form 10-Q that follow, including, without limiting the foregoing, exhibits filed pursuant to Items 601(b)(31) and 601(b)(32) of Regulation S-K, are intended to refer to the Amendment.

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, Indiana47708 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: Midcontinent Independent System Operator (formerly Midwest Independent System Operator)
EPA: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

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	22
3	Quantitative and Qualitative Disclosures About Market Risk	36
4	Controls and Procedures	36
	PART II.OTHER INFORMATION
1	Legal Proceedings	36
1A	Risk Factors	37
2	Unregistered Sales of Equity Securities and Use of Proceeds	37
3	Defaults Upon Senior Securities	37
4	Mine Safety Disclosures	37
5	Other Information	37
6	Exhibits	38
	Signatures	39

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, 2013		December 31, 2012
ASSETS
Current Assets
Cash & cash equivalents	$	3.9	$	13.3
Accounts receivable - less reserves of $5.8 &$5.0, respectively	72.9		81.8
Receivables due from other Vectren companies	6.9		—
Accrued unbilled revenues	35.7		93.6
Inventories	91.7		114.0
Recoverable fuel & natural gas costs	18.6		25.3
Prepayments & other current assets	45.8		52.3
Total current assets	275.5		380.3
Utility Plant
Original cost	5,265.0		5,176.8
Less:accumulated depreciation & amortization	2,104.4		2,057.2
Net utility plant	3,160.6		3,119.6
Investments in unconsolidated affiliates	0.2		0.2
Other investments	33.5		32.6
Nonutility plant - net	142.1		146.9
Goodwill - net	205.0		205.0
Regulatory assets	126.9		126.5
Other assets	29.4		35.7
TOTAL ASSETS	$	3,973.2	$	4,046.8

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)

	June30, 2013		December31, 2012
LIABILITIES & SHAREHOLDER'S EQUITY
Current Liabilities
Accounts payable	$	67.1	$	121.0
Accounts payable to affiliated companies	—		29.7
Payables to other Vectren companies	27.6		25.1
Accrued liabilities	122.2		139.3
Short-term borrowings	124.0		116.7
Current maturities of long-term debt	100.0		105.0
Total current liabilities	440.9		536.8
Long-Term Debt - Net of Current Maturities	1,057.8		1,103.4
Deferred Income Taxes & Other Liabilities
Deferred income taxes	600.4		578.5
Regulatory liabilities	376.4		364.2
Deferred credits & other liabilities	78.0		73.9
Total deferred credits & other liabilities	1,054.8		1,016.6
Commitments & Contingencies (Notes 8 - 10)
Common Shareholder's Equity
Common stock (no par value)	784.6		781.6
Retained earnings	635.1		608.4
Total common shareholder's equity	1,419.7		1,390.0
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,973.2	$	4,046.8

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
	June30,				June30,
	2013		2012		2013		2012
OPERATING REVENUES
Gas utility	$	138.0	$	116.0	$	453.9	$	408.3
Electric utility	154.7		149.3		304.2		288.7
Other	0.1		0.5		0.2		0.9
Total operating revenues	292.8		265.8		758.3		697.9
OPERATING EXPENSES
Cost of gas sold	50.7		31.8		207.9		168.9
Cost of fuel & purchased power	53.9		47.0		104.1		91.7
Other operating	76.1		77.8		162.9		157.7
Depreciation & amortization	48.7		47.8		97.1		96.4
Taxes other than income taxes	12.2		11.6		29.7		27.5
Total operating expenses	241.6		216.0		601.7		542.2
OPERATING INCOME	51.2		49.8		156.6		155.7
Other income - net	3.0		0.7		4.8		2.9
Interest expense	15.7		18.0		33.6		35.7
INCOME BEFORE INCOME TAXES	38.5		32.5		127.8		122.9
Income taxes	14.3		12.4		48.5		46.8
NET INCOME	$	24.2	$	20.1	$	79.3	$	76.1

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
	June30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	79.3		$	76.1
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization	97.1			96.4
Deferred income taxes & investment tax credits	16.5			21.9
Expense portion of pension & postretirement periodic benefit cost	2.7			2.5
Provision for uncollectible accounts	3.9			3.9
Other non-cash expense - net	2.9			4.7
Changes in working capital accounts:
Accounts receivable& accrued unbilled revenue	56.1			90.7
Inventories	22.3			3.2
Recoverable/refundable fuel & natural gas costs	6.7			2.8
Prepayments & other current assets	6.7			29.6
Accounts payable, including to Vectren companies & affiliated companies	(88.0		)	(67.2		)
Accrued liabilities	(6.4		)	(2.8		)
Changes in noncurrent assets	(0.6		)	0.2
Changes in noncurrent liabilities	(2.1		)	(13.0		)
Net cash provided by operating activities	197.1			249.0
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt - net of issuance costs	122.3			99.5
Additional capital contribution	3.0			3.5
Requirements for:
Dividends to parent	(52.6		)	(50.5		)
Retirement of long-term debt	(175.7		)	—
Other financing activities	—			—
Net change in short-term borrowings	7.3			(181.3		)
Net cash used in financing activities	(95.7		)	(128.8		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from other investing activities	0.1			2.2
Requirements for:
Capital expenditures, excluding AFUDC equity	(110.9		)	(124.1		)
Other investments	—			(0.2		)
Net cash used in investing activities	(110.8		)	(122.1		)
Net change in cash & cash equivalents	(9.4		)	(1.9		)
Cash & cash equivalents at beginning of period	13.3			6.0
Cash & cash equivalents at end of period	$	3.9		$	4.1

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 573,000 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 313,000 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, 2012, filed with the Securities and Exchange Commission on March 1, 2013, 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 $124 million is outstanding at June30, 2013, and Utility Holdings’ has unsecured senior notes with a par value of $825 million outstanding at June30, 2013.The guarantees are full and unconditional and joint and several, and Utility Holdings has no direct 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 June30, 2013 (in millions):

ASSETS	Subsidiary		Parent			Eliminations &
	Guarantors		Company			Reclassifications			Consolidated
Current Assets
Cash & cash equivalents	$	3.5	$	0.4		$	—		$	3.9
Accounts receivable - less reserves	72.9		—			—			72.9
Intercompany receivables	1.7		192.5			(194.2		)	—
Receivables due from other Vectren companies	—		6.9			—			6.9
Accrued unbilled revenues	35.7		—			—			35.7
Inventories	91.8		(0.1		)	—			91.7
Recoverable fuel & natural gas costs	18.6		—			—			18.6
Prepayments & other current assets	41.5		76.4			(72.1		)	45.8
Total current assets	265.7		276.1			(266.3		)	275.5
Utility Plant
Original cost	5,265.0		—			—			5,265.0
Less:accumulated depreciation & amortization	2,104.4		—			—			2,104.4
Net utility plant	3,160.6		—			—			3,160.6
Investments in consolidated subsidiaries	—		1,364.7			(1,364.7		)	—
Notes receivable from consolidated subsidiaries	—		572.1			(572.1		)	—
Investments in unconsolidated affiliates	0.2		—			—			0.2
Other investments	28.9		4.6			—			33.5
Nonutility property - net	2.4		139.7			—			142.1
Goodwill - net	205.0		—			—			205.0
Regulatory assets	104.5		22.4			—			126.9
Other assets	35.3		1.3			(7.2		)	29.4
TOTAL ASSETS	$	3,802.6	$	2,380.9		$	(2,210.3	)	$	3,973.2
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent			Eliminations &
	Guarantors		Company			Reclassifications			Consolidated
Current Liabilities
Accounts payable	$	62.7	$	4.4		$	—		$	67.1
Intercompany payables	10.6		—			(10.6		)	—
Payables to other Vectren companies	25.6		2.0			—			27.6
Accrued liabilities	132.4		12.8			(23.0		)	122.2
Short-term borrowings	—		124.0			—			124.0
Intercompany short-term borrowings	183.6		—			(183.6		)	—
Current maturities of long-term debt	—		100.0			—			100.0
Total current liabilities	414.9		243.2			(217.2		)	440.9
Long-Term Debt
Long-term debt - net of current maturities	382.3		724.6			(49.1		)	1,057.8
Long-term debt due to VUHI	572.1		—			(572.1		)	—
Total long-term debt - net	954.4		724.6			(621.2		)	1,057.8
Deferred Income Taxes & Other Liabilities
Deferred income taxes	610.9		(10.5		)	—			600.4
Regulatory liabilities	374.7		1.7			—			376.4
Deferred credits & other liabilities	83.0		2.2			(7.2		)	78.0
Total deferred credits & other liabilities	1,068.6		(6.6		)	(7.2		)	1,054.8
Common Shareholder's Equity
Common stock (no par value)	797.8		784.6			(797.8		)	784.6
Retained earnings	566.9		635.1			(566.9		)	635.1
Total common shareholder's equity	1,364.7		1,419.7			(1,364.7		)	1,419.7
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,802.6	$	2,380.9		$	(2,210.3	)	$	3,973.2

8

Condensed Consolidating Balance Sheet as of December 31, 2012 (in millions):

ASSETS	Subsidiary		Parent			Eliminations &
	Guarantors		Company			Reclassifications			Consolidated
Current Assets
Cash & cash equivalents	$	12.5	$	0.8		$	—		$	13.3
Accounts receivable - less reserves	81.8		—			—			81.8
Intercompany receivables	—		145.1			(145.1		)	—
Accrued unbilled revenues	93.6		—			—			93.6
Inventories	114.0		—			—			114.0
Recoverable fuel & natural gas costs	25.3		—			—			25.3
Prepayments & other current assets	52.0		5.8			(5.5		)	52.3
Total current assets	379.2		151.7			(150.6		)	380.3
Utility Plant
Original cost	5,176.6		0.2			—			5,176.8
Less:accumulated depreciation & amortization	2,057.2		—			—			2,057.2
Net utility plant	3,119.4		0.2			—			3,119.6
Investments in consolidated subsidiaries	—		1,329.2			(1,329.2		)	—
Notes receivable from consolidated subsidiaries	—		679.7			(679.7		)	—
Investments in unconsolidated affiliates	0.2		—			—			0.2
Other investments	27.8		4.8			—			32.6
Nonutility property - net	2.6		144.3			—			146.9
Goodwill - net	205.0		—			—			205.0
Regulatory assets	104.1		22.4			—			126.5
Other assets	40.4		1.7			(6.4		)	35.7
TOTAL ASSETS	$	3,878.7	$	2,334.0		$	(2,165.9	)	$	4,046.8
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent			Eliminations &
	Guarantors		Company			Reclassifications			Consolidated
Current Liabilities
Accounts payable	$	114.8	$	6.2		$	—		$	121.0
Accounts payable to affiliated companies	29.7		—			—			29.7
Intercompany payables	10.6		—			(10.6		)	—
Payables to other Vectren companies	25.1		—			—			25.1
Accrued liabilities	131.3		13.5			(5.5		)	139.3
Short-term borrowings	—		116.7			—			116.7
Intercompany short-term borrowings	134.5		—			(134.5		)	—
Current maturities of long-term debt	5.0		100.0			—			105.0
Total current liabilities	451.0		236.4			(150.6		)	536.8
Long-Term Debt
Long-term debt - net of current maturities	382.3		721.1			—			1,103.4
Long-term debt due to VUHI	679.7		—			(679.7		)	—
Total long-term debt - net	1,062.0		721.1			(679.7		)	1,103.4
Deferred Income Taxes & Other Liabilities
Deferred income taxes	595.4		(16.9		)	—			578.5
Regulatory liabilities	362.2		2.0			—			364.2
Deferred credits & other liabilities	78.9		1.4			(6.4		)	73.9
Total deferred credits & other liabilities	1,036.5		(13.5		)	(6.4		)	1,016.6
Common Shareholder's Equity
Common stock (no par value)	787.8		781.6			(787.8		)	781.6
Retained earnings	541.4		608.4			(541.4		)	608.4
Total common shareholder's equity	1,329.2		1,390.0			(1,329.2		)	1,390.0
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,878.7	$	2,334.0		$	(2,165.9	)	$	4,046.8

9

Condensed Consolidating Statement of Income for the three months ended June30, 2013 (in millions):

	Subsidiary Guarantors		Parent Company		Eliminations & Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	138.0	$	—	$	—		$	138.0
Electric utility	154.7		—		—			154.7
Other	—		9.5		(9.4		)	0.1
Total operating revenues	292.7		9.5		(9.4		)	292.8
OPERATING EXPENSES
Cost of gas sold	50.7		—		—			50.7
Cost of fuel & purchased power	53.9		—		—			53.9
Other operating	85.2		—		(9.1		)	76.1
Depreciation & amortization	43.3		5.3		0.1			48.7
Taxes other than income taxes	11.8		0.4		—			12.2
Total operating expenses	244.9		5.7		(9.0		)	241.6
OPERATING INCOME	47.8		3.8		(0.4		)	51.2
Other income - net	1.8		9.1		(7.9		)	3.0
Interest expense	13.8		10.2		(8.3		)	15.7
INCOME BEFORE INCOME TAXES	35.8		2.7		—			38.5
Income taxes	14.0		0.3		—			14.3
Equity in earnings of consolidated companies, net of tax	—		21.8		(21.8		)	—
NET INCOME	$	21.8	$	24.2	$	(21.8	)	$	24.2

Condensed Consolidating Statement of Income for the three months ended June30, 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 - 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

10

Condensed Consolidating Statement of Income for the six months ended June30, 2013 (in millions):

	Subsidiary Guarantors	Parent Company		Eliminations & Reclassifications		Consolidated
OPERATING REVENUES
Gas utility	453.9	—		—		453.9
Electric utility	304.2	—		—		304.2
Other	—	19.0		(18.8	)	0.2
Total operating revenues	758.1	19.0		(18.8	)	758.3
OPERATING EXPENSES
Cost of gas sold	207.9	—		—		207.9
Cost of fuel & purchased power	104.1	—		—		104.1
Other operating	181.2	—		(18.3	)	162.9
Depreciation & amortization	86.4	10.5		0.2		97.1
Taxes other than income taxes	28.9	0.8		—		29.7
Total operating expenses	608.5	11.3		(18.1	)	601.7
OPERATING INCOME	149.6	7.7		(0.7	)	156.6
Other income - net	3.7	18.8		(17.7	)	4.8
Interest expense	30.0	22.0		(18.4	)	33.6
INCOME BEFORE INCOME TAXES	123.3	4.5		—		127.8
Income taxes	48.8	(0.3	)	—		48.5
Equity in earnings of consolidated companies, net of tax	—	74.5		(74.5	)	—
NET INCOME	74.5	79.3		(74.5	)	79.3

Condensed Consolidating Statement of Income for the six months ended June30, 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 - 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

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Condensed Consolidating Statement of Cash Flows for the six months ended June30, 2013 (in millions):

	Subsidiary Guarantors			Parent Company			Eliminations			Consolidated
NET CASH PROVIDED BY OPERATING ACTIVITIES	$	199.1		$	(2.0	)	$	—		$	197.1
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from
Long-term debt - net of issuance costs	60.0			124.4			(62.1		)	122.3
Additional capital contribution from parent	10.0			3.0			(10.0		)	3.0
Requirements for:
Dividends to parent	(49.0		)	(52.6		)	49.0			(52.6		)
Retirement of long term debt	(174.8		)	(121.6		)	120.7			(175.7		)
Net change in intercompany short-term borrowings	49.0			—			(49.0		)	—
Net change in short-term borrowings	—			7.3			—			7.3
Net cash used in financing activities	(104.8		)	(39.5		)	48.6			(95.7		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from
Consolidated subsidiary distributions	—			49.0			(49.0		)	—
Other investing activities	—			0.1			—			0.1
Requirements for:
Capital expenditures, excluding AFUDC equity	(103.3		)	(7.6		)	—			(110.9		)
Consolidated subsidiary investments	—			(10.0		)	10.0			—
Net change in long-term intercompany notes receivable	—			58.6			(58.6		)	—
Net change in short-term intercompany notes receivable	—			(49.0		)	49.0			—
Net cash used in investing activities	(103.3		)	41.1			(48.6		)	(110.8		)
Net change in cash & cash equivalents	(9.0		)	(0.4		)	—			(9.4		)
Cash & cash equivalents at beginning of period	12.5			0.8			—			13.3
Cash & cash equivalents at end of period	$	3.5		$	0.4		$	—		$	3.9

Condensed Consolidating Statement of Cash Flows for the six months ended June30, 2012 (in millions):

	Subsidiary Guarantors			Parent Company			Eliminations			Consolidated
NET CASH PROVIDED BY OPERATING ACTIVITIES	$	233.3		$	15.7		$	—		$	249.0
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Additional capital contribution to 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 used in 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 used in 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

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4. Excise and Utility Receipts Taxes

Excise taxes and a portion of utility receipts taxes are included in rates charged to customers.Accordingly, the Company records these taxes received as a component of operating revenues, which totaled $5.4 million and $5.0 million in the three months ended June30, 2013 and 2012, respectively.  For the six months ended June30, 2013 and 2012, these taxes totaled $16.1 million and $14.3 million, respectively. Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.

5. Supplemental Cash Flow Information

As of June30, 2013 and December 31, 2012, the Company has accruals related to utility and nonutility plant purchases totaling approximately $9.2 million and $7.1 million, respectively.

6. Transactions with Other Vectren Companies and Affiliates

Vectren Fuels, Inc. (Vectren Fuels)

Vectren Fuels, 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 June30, 2013 and 2012 totaled $31.7 million and $33.3 million, respectively, and for the six months ended June30, 2013 and 2012 totaled $51.6 million and $58.2 million, respectively.Amounts owed to Vectren Fuels at June30, 2013 and December 31, 2012 are included in Payables to other Vectren companies in the Condensed Consolidated Balance Sheets.

Miller Pipeline, LLC (Miller)

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 $12.8 million and $11.5 million for the three months ended June30, 2013 and 2012, respectively, and for the six months ended June30, 2013 and 2012 totaled $23.2 million and $19.6 million, respectively.Amounts owed to Miller at June30, 2013 and December 31, 2012 are included in Payables to other Vectren companies in the Condensed Consolidated Balance Sheets.

Minnesota Limited, LLC (Minnesota Limited)

Minnesota Limited, a wholly owned subsidiary of Vectren, provides transmission pipeline construction and maintenance; pump station, compressor station, terminal and refinery construction; and hydrostatic testing to customers generally in the northern Midwest region.  Minnesota Limited's customers include Utility Holdings' utilities.  Fees incurred by Utility Holdings and its subsidiaries were insignificant for the three months and six months ended June30, 2013 and 2012.

ProLiance Holdings, LLC (ProLiance)

Vectren has an investment in ProLiance, a nonutility affiliate of Vectren and Citizens Energy Group (Citizens).  On June18, 2013, ProLiance exited the natural gas marketing business through the disposition of certain of the net assets of its energy marketing business, ProLiance Energy, LLC (ProLiance Energy).  ProLiance Energy provided services to a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions located throughout the Midwest and Southeast United States.ProLiance Energy’s customers included, among others, Vectren’s Indiana utilities as well as Citizens’ utilities.

Purchases from ProLiance for resale and for injections into storage for the three months ended June30, 2013 and 2012 totaled $92.9 million and $50.2 million, respectively and for the six months ended June30, 2013 and 2012 totaled $200.5 million and $129.7 million, respectively.The Company did not have any amounts owed to ProLiance for those purchases at June30, 2013 and amounts owed to ProLiance at December 31, 2012 were $29.7 million and are included in Accounts payable to affiliated companies in the Condensed Consolidated Balance Sheets.

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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 each of the three months ended June30, 2013and 2012, Utility Holdings received corporate allocations totaling $11.4 million.  For the six months ending June30, 2013 and 2012, Utility Holdings received corporate allocations totaling $26.3 million and $23.9 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.

7. Financing Activities

SIGECO 2013 Debt Refund and Reissuance

During the second quarterof 2013, approximately $111 million of SIGECO's tax-exempt long-term debt was redeemed at par plus accrued interest.  Approximately $62 million of tax-exempt long-term debt was reissued on April26, 2013 at interest rates that are fixed to maturity, receiving proceeds, net of issuance costs, of approximately $60 million.  The terms are $22.2 million at 4.00 percent per annum due in 2038, and $39.6 million at 4.05 percent per annum due in 2043.  The remaining approximately $49 million of the called debt is held by Utility Holdings and planned for remarketing in the third quarter of 2013, and is treated as extinguished in the consolidated financial statements as of June30, 2013.

Utility Holdings Debt Transactions

On April1, 2013, the Company executed an early redemption at par of $121.6 million 6.25 percent senior unsecured notes due in 2039. This debt was refinanced on June5, 2013, with proceeds from a private placement note purchase agreement entered into on December20, 2012 with a delayed draw feature.  It provides for the following tranches of notes: (i) $45 million 3.20 percent senior guaranteed notes, due June5, 2028 and (ii) $80 million 4.25 percent senior guaranteed notes, due June5, 2043. The notes are unconditionally guaranteed by Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company and Vectren Energy Delivery of Ohio, Inc.

On July25, 2013, VUHI announced that it priced $150 million10-year senior unsecured notes.  The notes were sold to various institutional investors through the private placement market and included a delayed draw feature.  VUHI will issue $150 million of 3.72 percent senior notes due December5, 2023.  The proceeds received from the issuance of the senior notes will be used to refinance $100 million of existing 5.25 percent senior notes that mature August1, 2013, for capital expenditures, and for general corporate purposes.  Subject to the satisfaction of customary conditions precedent, the notes will be funded on or about December5, 2013, as a result of the delayed draw feature.  As of June30, 2013 the $100 million was classified as Current maturities of long-term debt.

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.

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9. Rate & Regulatory Matters

Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement

The Company monitors and maintains its natural gas distribution system to ensure that natural gas is delivered in a safe and efficient manner. The Company's natural gas utilities are currently engaged in replacement programs in both Indiana and Ohio, the primary purpose of which is preventive maintenance and continual renewal and operational improvement.Laws in both Indiana and Ohio were passed that expand the ability of utilities to recover certain costs of federally mandated projects and other infrastructure improvement projects, outside of a base rate proceeding.Utilization of these recovery mechanisms is discussed below.

Ohio Recovery and Deferral Mechanisms

The PUCO order approving the Company's 2009 base rate case in the Ohio service territory authorized a distribution replacement rider (DRR).  The DRR's primary purpose is recovery of investments in utility plant and related operating expenses associated with replacing bare steel and cast iron pipelines and certain other infrastructure.  This rider is updated annually for qualifying capital expenditures and allows for a return to be earned on those capital expenditures based on the rate of return approved in the 2009 base rate case.  In addition, deferral of depreciation and the ability to accrue debt-related post in service carrying costs is also allowed until the related capital expenditures are recovered through the DRR.  The order also established a prospective bill impact evaluation on the annual deferrals, limiting the deferrals at a level which would equal a change over the prior year rate of $1.00 per residential and general service customer per month.  To date, the Company has made capital investments under this rider totaling $94 million.  Regulatory assets associated with post in service carrying costs and depreciation deferrals were $7.9 million and $6.5 million at June30, 2013 and December 31, 2012, respectively.  The DRR's initial five year term expires in early 2014.  The Company filed in July 2013 a notice that it will request to extend the term of the DRR.

In June 2011, Ohio House Bill 95 was signed into law.  Outside of a base rate proceeding, this legislation permits a natural gas company to apply for recovery of much of its capital expenditure program. The legislation also allows for the deferral of costs, such as depreciation, property taxes, and debt-related post in service carrying costs. On December 31, 2012, the PUCO issued an order approving the Company's initial application using this law, reflecting its $23.5 million capital expenditure program covering the fifteen month period ending December 31, 2012. Such capital expenditures include infrastructure expansion and improvements not covered by the DRR as well as expenditures necessary to comply with PUCO rules, regulations, orders, and system expansion to some new customers.  The order also established a prospective bill impact evaluation on the cumulative deferrals, limiting the total deferrals at a level which would equal $1.50 per residential and general service customer per month.  The Company will file annually for the accounting treatment described above for its annual capital expenditure program.  Included in the notice filed in July 2013, the Company indicated an application will be filed in the near term seeking authority to expand the DRR to include recovery of other infrastructure investments to improve the reliability of its system.

Indiana Recovery and Deferral Mechanisms

The Company's Indiana natural gas utilities received orders in 2008 and 2007 associated with the most recent base rate cases.  These orders authorized the deferral of financial impacts associated with bare steel and cast iron replacement activities.  The orders provide for the deferral of depreciation and post in service carrying costs on qualifying projects totaling $20 million annually at Vectren North and $3 million annually at Vectren South.  The debt-related post in service carrying costs are recognized in the Condensed Consolidated Statements of Income currently.  Such deferral is limited by individual qualifying project to three years after being placed into service at Vectren South and four years after being placed into service at Vectren North.

In April 2011, Senate Bill 251 was signed into Indiana law. The law 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 a return on the federally mandated capital investment, along with recovery of depreciation and other operating costs associated with these mandates.  The remaining 20 percent of those costs are to be deferred for future recovery in the utility's next general rate case.

In April 2013, Senate Bill 560 was signed into law. This legislation supplements Senate Bill 251 described above, which addressed federally-mandated investment, provides for cost recovery outside of a base rate proceeding for projects that either improve electric and gas system reliability and safety or are economic development projects that provide rural areas with access

15

to gas service. Provisions of the legislation require that, among other things, requests for recovery include a seven year project plan. Once the plan is approved by the IURC, 80 percent of such costs are eligible for recovery using a periodic rate adjustment mechanism. Recoverable costs include a return on and of the investment, as well as property taxes and operating expenses. The remaining 20 percent of project costs are to be deferred for future recovery in the Company's next general rate case. The adjustment mechanism is capped at an annual increase in retail revenues of no more than two percent.

Pipeline Safety Law

On January 3, 2012, the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (Pipeline Safety Law) was signed into law. The Pipeline Safety 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 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 over the next two years.  Those regulations may eventually lead to further regulatory or statutory requirements.

The Company continues to study the impact of the Pipeline Safety 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 law is expected to result in further investment in pipeline inspections, and where necessary, additional investments in 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 by approximately $9 million annually, with $6 million attributable to the Indiana operations.

Vectren North Pipeline Safety Investigation

On April 11, 2012, the IURC's pipeline safety division filed a complaint against Vectren North alleging several violations of safety regulations pertaining to damage that occurred at a residence in Vectren North's service territory during a pipeline replacement project.  The Company negotiated a settlement with the IURC's pipeline safety division, agreeing to a fine and several modifications to the Company's operating policies.  The amount of the fine was not material to the Company's financial results.  The IURC approved the settlement but modified certain terms of the settlement and added a requirement that Company employees conduct inspections of pipeline excavations.  The Company sought and was granted a request for rehearing on the sole issue related to the requirement to use Company employees to inspect excavations. The Company seeks further clarity on the scope of the requirement and the ability to also use contractors to perform certain inspections.  The Company submitted testimony in the case in April 2013.  A hearing will be conducted in November 2013.

10. Environmental Matters

Indiana Senate Bill 251 is also applicable to federal environmental mandates impacting Vectren South's electric operations. The Company is currently evaluating the impact Senate Bill 251 may have on its operations, including applicability of the stricter regulations the EPA is currently considering involving air quality, fly ash disposal, cooling tower intake facilities, waste water discharges, and greenhouse gases.  These issues are further discussed below.

Air Quality

Clean Air Interstate Rule / Cross-State Air Pollution Rule

In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR).CSAPR was 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, CSAPR reduced the ability of facilities to meet emission reduction targets through allowance trading.Like CAIR, CSAPR set individual state caps for SO2 and NOx emissions.  However, unlike CAIR in which states allocated allowances to generating units through state implementation plans, CSAPR allowances were allocated to individual units directly through the federal rule.CSAPR reductions were to be achieved with initial step reductions beginning January 1, 2012, and final compliance to be achieved in 2014.Multiple administrative and judicial

16

challenges were filed.  On December 30, 2011, the Court granted a stay of CSAPR and left CAIR in place pending its review.  On August 21, 2012, the Court vacated CSAPR and directed the EPA to continue to administer CAIR.  In October 2012, the EPA filed its request for a hearing before the full federal appeals court that struck down the CSAPR. EPA's request for rehearing was denied by the Court on January 24, 2013.  In March 2013, the EPA filed a petition for review with the US Supreme Court, and in June 2013 the Supreme Court agreed to review the lower court decision.  A decision by the Supreme Court is expected in 2014.  The Company remains in full compliance with CAIR (see additional information below "Conclusions Regarding Air Regulations").

Mercury and Air Toxics (MATS) Rule

On December 21, 2011, the EPA finalized the Utility MATS Rule.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 electric generating 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 CSAPR'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 agreed to 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.  The EPA issued its revised emission limits for new construction in March 2013.

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 Generating Corporation (AGC), a subsidiary of 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 SO2allowances 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 received a notice of violation (NOV) from the EPA in November 2011 pertaining to its A.B. Brown power plant. The NOV asserts that when the power plant was equipped with SCRsthe 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.

The Company continues to review the sufficiency of its existing pollution control equipment in relation to the requirements described in the MATS Rule, the 2015 requirement imposed by CAIR, and the NOV discussed above.Due to the correlation amongst the various requirements set forth, it is possible some operational modifications to the control equipment will be required.  Additional capital investments, operating expenses, and possibly the purchase of emission allowances may be required and could be significant depending on the required method of compliance with the requirements.The Company has not yet quantified what the additional costs may be associated with these efforts.  However, as the compliance is required by government regulation, the Company believes that such additional costs, if incurred, should be recoverable under Senate Bill 251 referenced above.

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Information Request

SIGECO and AGC own a 300 MW Unit 4 at the Warrick Power Plant as tenants in common.AGC and SIGECO also share equally in the cost of operation and output of the unit.In January 2013, AGC received an information request from the EPA under Section 114 of the Clean Air Act for historical operational information on the Warrick Power Plant.  In April 2013, ALCOA filed a timely response to the information request.

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 approximate $40 million if new infrastructure, such as new cooling water towers, is required. Costs for compliance with these final regulations should qualify as federally mandated regulatory requirements and be recovered under Indiana Senate Bill 251 referenced above.

Under the Clean Water Act, EPA sets technology-based guidelines for water discharges from new and existing facilities.  EPA is currently in the process of revising the existing steam electric effluent limitation guidelines that set the technology-based water discharge limits for the electric power industry.  EPA is focusing its rulemaking on wastewater generated primarily by pollution control equipment necessitated by the comprehensive air regulations.  The EPA released proposed rules on April 19, 2013 and the Company is reviewing the proposal.  At this time, it is not possible to estimate what potential costs may be required to meet these new water discharge limits, however costs for compliance with these regulations should qualify as federally mandated regulatory requirements and be recovered under 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 have not been finalized 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 should 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 (GHG's) meet the definition of "air pollutant" under the Clean Air Act and ordered the EPA to determine whether GHG 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 the EPA regulating carbon emissions through the existing Clean Air Act in the absence of specific carbon legislation from Congress.

The EPA has promulgated two GHG regulations that apply to the Company's generating facilities. In 2009, the EPA finalized a mandatory GHG 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

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more of GHG's a year to obtain a PSD permit for new construction or a significant modification of an existing facility.The EPA's PSD and Title V permitting rules for GHG's were upheld by the US Court of Appeals for the District of Columbia.  In 2012, the EPA proposed New Source Performance Standards (NSPS) for GHG's for new electric generating facilities under Clean Air Act Section 111(b).  In July 2013, the President announced a Climate Action Plan, which calls on the EPA to re-propose and finalize the new source rule expeditiously, and by June 2014 propose, and by June 2015 finalize, NSPS standards for GHG's for existing electric generating units which would apply to Vectren's power plants.  States must have their implementation plans to the EPA no later than June 2016.  The President's Climate Action Plan did not provide any detail as to actual emission targets or compliance requirements.  The Company anticipates that these initial standards will focus on power plant efficiency and other coal fleet carbon intensity reduction measures.  The Company believes that such additional costs, if necessary, should be recoverable under Indiana Senate Bill 251 referenced above.

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 GHG's 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 GHG emissions or obtaining renewable energy sources remain uncertain. The Company has gathered preliminary estimates of the costs to control GHG 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 GHG 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 GHG 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 should be recoverable from customers through Senate Bill 251.

Senate Bill 251 also established a voluntary clean energy portfolio standard that provides incentives to electricity suppliers participating in the program. The goal of the program is that by 2025, at least 10 percent of the total electricity obtained by the supplier to meet the energy needs of Indiana retail customers will be provided by clean energy sources, as defined.  In advance of a federal portfolio standard and Senate Bill 251, SIGECO received regulatory approval to purchase a 3 MW landfill gas generation facility from a related entity. The facility was purchased in 2009 and is directly connected to the Company's distribution system. In 2008 and 2009, the Company executed long term purchase power commitments for a total of 80 MW of wind energy.  The Company currently has approximately 5 percent of its electricity being provided by clean energy sources due to the long-term wind contracts and landfill gas investment.

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.

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

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time, the Company has recorded cumulative costs that it has incurred or reasonably expects to incur totaling approximately $42.4 million ($23.2 million at Indiana Gas and $19.2 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.Likewise, SIGECO has settlement agreements with all known insurance carriers and has received to date approximately $14.2 million of the expected $15.7 million in 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 remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery.As of June30, 2013 and December 31, 2012, approximately $5.1 million and $4.6 million, respectively, of accrued, but not yet spent, costs are included in Other Liabilities related to the Indiana Gas and SIGECO sites.

11. Fair Value Measurements

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

	June30, 2013				December31, 2012
(In millions)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	1,157.8	$	1,259.1	$	1,208.4	$	1,372.6
Short-term borrowings	124.0		124.0		116.7		116.7
Cash & cash equivalents	3.9		3.9		13.3		13.3

For the balance sheet dates presented in these financial statements, the Company had no material assets or liabilities marked to fair value.

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 of this debt would not be expected to have a material effect on the Company's results of operations.

12. Impact of Recently Issued Accounting Principles

Offsetting Assets and Liabilities

In January 2013, the FASB issued new accounting guidance on disclosures of offsetting assets and liabilities.  This guidance amends prior requirements to add clarification to the scope of the offsetting disclosures. The amendment clarifies that the scope applies to derivative instruments accounted for in accordance with reporting topics on derivatives and hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with US GAAP or subject to an enforceable master netting arrangement or similar agreement.  This guidance is effective for fiscal years beginning on or after January 1, 2013 and interim periods within annual periods.  The Company adopted this guidance as of January 1, 2013.  The adoption of this guidance did not have a material impact on the Company's financial statements.

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Accumulated Other Comprehensive Income (AOCI)

In February 2013, the FASB issued new accounting guidance on the reporting of reclassifications from AOCI.  The guidance requires an entity to report the effect of significant reclassification from AOCI on the respective line items in net income if the amount being reclassified is required under US GAAP to be reclassified in its entirety to net income.  For other amounts that are not required under US GAAP to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference to other disclosures required that provide additional details about these amounts. The new guidance is effective for fiscal years, and interim periods within annual periods, beginning after December 15, 2012.As this guidance provides only disclosure requirements, the adoption of this standard did not impact the company's results of operations, cash flows or financial position.

Unrecognized Tax Benefit Presentation

In July 2013, the FASB issued new accounting guidance on presenting an unrecognized tax benefit when net operating loss carryforwards exist.  The new standard was issued in an effort to eliminate diversity in practice resulting from a lack of guidance on this topic in the current US GAAP.  The update provides that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward, except under certain circumstances outlined in the update.  The amendments in the update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013, with early adoption permitted.  The adoption of this guidance will have no material impact on the Company's financial statements.

 13. 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 Servicesand 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
	June30,						June30,
(In millions)	2013			2012			2013			2012
Revenues
Gas Utility Services	$	138.0		$	116.0		$	453.9		$	408.3
Electric Utility Services	154.7			149.3			304.2			288.7
Other Operations	142.0			10.0			151.5			19.9
Eliminations	(141.9		)	(9.5		)	(151.3		)	(19.0		)
Total revenues	$	292.8		$	265.8		$	758.3		$	697.9
Profitability Measure - Net Income (Loss)
Gas Utility Services	$	2.9		$	1.3		$	41.0		$	38.8
Electric Utility Services	18.9			17.2			33.5			32.8
Other Operations	2.4			1.6			4.8			4.5
Total net income	$	24.2		$	20.1		$	79.3		$	76.1

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ITEM 2.MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS ANDFINANCIAL 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 Vectren Energy Delivery of Ohio, Inc. (VEDO).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 573,000 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 313,000 natural gas customers located near Dayton in west central Ohio.  The Company segregates its regulatory utility operations between a Gas Utility Services operating segment and an Electric Utility Services operating segment.

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 2012 annual report filed on Form 10-K.

In the second quarter of 2013, Utility Holding's earnings were $24.2 million compared to $20.1 million in 2012.  In the six months ended June30, 2013, Utility Holdings' earned $79.3 million, compared to $76.1 million in 2012.  The improved results in 2013 are primarily related to increased gas utility margins from small and large customers, return on electric transmission investment, and lower interest expense.

Gas Utility Services

During the second quarter of 2013, Gas Utility Services earnings were $2.9 million compared to earnings of $1.3 million in the second quarter of 2012. In the six months ended June30, 2013, Gas Utility Services earned $41.0 million, compared to earnings of $38.8 million in 2012.  Results in 2013 have been impacted by small customer growth and increased large customer margin.  Results also continue to be favorably impacted by returns earned on increased investment in bare steel and cast iron pipe replacements, particularly in Ohio, and by lower interest expense.

Electric Utility Services

During the second quarter of 2013, Electric Utility Services earnings were $18.9 million, compared to $17.2 million in the second quarter of 2012.  Electric Utility Services earned $33.5 million year to date in 2013, compared to earnings of $32.8 million for the six months ended June30, 2012.  The timing of power supply operating expenses favorably impacted second quarter results, and year to date operating expenses are relatively flat.  In both the second quarter and year to date periods, results were favorable impacted by lower interest expense and increased return on transmission investment.  These favorable impacts were somewhat offset by lower electric small customer margin resulting from conservation initiatives, net of lost margin recovery.

Other Utility Operations

In the second quarter of 2013, earnings from Other Utility operations were $2.4 million compared to $1.6 million in 2012.  In the six months ended June30, 2013, earnings from these operations were $4.8 million compared to $4.5 million in 2012.

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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 and 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.

In addition, the Company separately shows Regulatory expense recovery mechanisms within Gas utility margin and Electric utility margin. These amounts represent dollar-for-dollar recovery of operating expenses.  The Company utilizes these approved regulatory mechanisms to recover variations in operating expenses from the amounts reflected in base rates and are generally expenses that are subject to volatility. For example, demand side management and conservation expenses for both the gas and electric utilities; MISO administrative expenses for the Company's electric operations; uncollectible expense associated with the Company's Ohio gas customers; and recoveries of state mandated revenue taxes in both Indiana and Ohio are included in these amounts.  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
	June30,				June30,
(In millions)	2013		2012		2013		2012
Gas utility revenues	$	138.0	$	116.0	$	453.9	$	408.3
Cost of gas sold	50.7		31.8		207.9		168.9
Total gas utility margin	$	87.3	$	84.2	$	246.0	$	239.4
Margin attributed to:
Residential & commercial customers	$	66.5	$	64.9	$	187.0	$	182.7
Industrial customers	12.5		12.1		29.8		27.9
Other	2.4		2.0		5.4		5.4
Regulatory expense recovery mechanisms	5.9		5.2		23.8		23.4
Total gas utility margin	$	87.3	$	84.2	$	246.0	$	239.4
Sold & transported volumes in MMDth attributed to:
Residential & commercial customers	$	12.0	$	10.2	$	67.1	$	51.0
Industrial customers	25.1		24.3		56.1		52.1
Total sold & transported volumes	$	37.1	$	34.5	$	123.2	$	103.1

Gas Utility margins were $87.3 million and $246.0 million for the three and six months ended June30, 2013, and compared to 2012 increased $3.1 million quarter over quarter and $6.6 million year to date.  Excluding the impact of regulatory expense recovery mechanisms, small customer margins increased $1.6 million quarter over quarter and $4.3 million year to date, compared to the prior year.  With rate designs that substantially limit the impact of weather on margin, heating degree days that were 103 percent of normal in Ohio and 101 percent of normal in Indiana during the six months ended June 30, 2013, compared to 82 percent of normal in Ohio and 70 percent of normal in Indiana during 2012, had only a small favorable impact to small customer margin of approximately $0.7 million.  Growth in residential and commercial customers favorably impacted small customer margins by approximately $0.8 million for the quarter and $1.9 million for the year to date.  In addition, margin related to investments in infrastructure in Ohio increased margin $0.8 million and $1.7 million in the quarter and year to date periods, respectively, compared to prior year.  Large customer margins increased $0.4 million and $1.9 million in the quarter and year to date periods, respectively, compared to the prior year, on increasing volumes.

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

Electric utility margin and volumes sold by customer type follows:

	Three Months Ended					Six Months Ended
	June30,					June30,
(In millions)	2013		2012			2013		2012
Electric utility revenues	$	154.7	$	149.3		$	304.2	$	288.7
Cost of fuel & purchased power	53.9		47.0			104.1		91.7
Total electric utility margin	$	100.8	$	102.3		$	200.1	$	197.0
Margin attributed to:
Residential & commercial customers	$	60.5	$	65.4		$	121.2	$	123.1
Industrial customers	27.8		28.0			53.9		54.6
Other customers	0.9		(0.3		)	1.7		0.5
Regulatory expense recovery mechanisms	2.0		1.3			4.5		2.0
Subtotal: retail	$	91.2	$	94.4		$	181.3	$	180.2
Wholesale power & transmission system margin	9.6		7.9			18.8		16.8
Total electric utility margin	$	100.8	$	102.3		$	200.1	$	197.0
Electric volumes sold in GWh attributed to:
Residential & commercial customers	631.2		693.3			1,302.5		1,324.4
Industrial customers	698.0		713.4			1,357.3		1,395.1
Other customers	4.8		4.8			10.6		10.7
Total retail volumes sold	1,334.0		1,411.5			2,670.4		2,730.2

Retail

Electric retail utility margins were $91.2 million and $181.3 million for the three and six months ended June30, 2013, and compared to 2012 decreased by $3.2 million in the quarter and increased $1.1 million year to date.  Excluding the impact of regulatory expense recovery mechanisms, small customer margins decreased by $4.9 million for the quarter and $1.9 million year to date compared to 2012.  Electric results are not protected by weather mechanisms.  Cooling degree days in the second quarter of 2013 were 107 percent of normal compared to 146 percent of normal in the second quarter of 2012, resulting in a $2.7 million decrease in small customer margin.  For the year to date period, electric results were positively impacted by weather, resulting in a year to date increase of $1.2 million in small customer margins over the prior year.  In addition, $2.3 million of the decline in small customer margin for the quarter and $3.1 million for the year to date were the result of conservation beyond approved lost margin recovery mechanisms.  Large customer margins for the second quarter of 2013 declined $0.2 million from the prior year, and for 2013 year to date were down $0.7 million from 2012 on decreasing volumes.  Other margin was higher in both the quarter and year to date periods due to refunds during 2012 resulting from statutory net operating income limits.  Margin from regulatory expense recovery mechanisms increased $0.7 million for the second quarter and $2.5 million year to date from 2012, driven by increased operating expenses associated with the electric state-mandated conservation programs.  This is offset by a corresponding increase in operating expenses when compared to 2012.

Margin from Wholesale Electric Activities

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 and also markets and sells its generating and transmission capacity to optimize the return on its owned assets.Substantially all off-system sales are generated in the MISO Day Ahead and Real Time markets when sales into the MISO in a given hour are greater than amounts purchased for native load.Further detail of MISO off-system margin and transmission system margin follows:

	Three Months Ended				Six Months Ended
	June30,				June30,
(In millions)	2013		2012		2013		2012
Transmission system sales	$	7.9	$	7.2	$	14.5	$	13.1
Off-system sales	1.7		0.7		4.3		3.7
Total wholesale margin	$	9.6	$	7.9	$	18.8	$	16.8

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Transmission system margin associated with qualifying projects, including the reconciliation of recovery mechanisms, and other transmission system operations, totaled $14.5 million and $13.1 million during the six months ended June30, 2013 and 2012, respectively. During the 2013 second quarter, transmission system margin was $7.9 million compared to $7.2 million for the same period in 2012.  Increases are primarily due to increased investment in qualifying projects.  As of June 30, 2013, the Company had invested $157 million in qualifying projects.  These projects include an interstate345 Kv transmission line that connects Vectren’s A.B. Brown Generating Station to a generating station in Indiana owned by Duke Energy to the north and to a generating station in Kentucky owned by Big Rivers Electric Corporation to the south; a substation; and another transmission line.  Once placed into service, these projects earn a FERC approved equity rate of return of 12.38percent on the net plant balance, and operating expenses are also recovered.  The 345 Kv project is the largest of these qualifying projects, with a cost of $107 million that earned the FERC approved equity rate of return, including while under construction.  The last segment of that project was placed into service in December 2012.

For the six months ended June30, 2013, margin from off-system sales was $4.3 million, compared to $3.7 million for the six months ended June30, 2012.  In the second quarter of 2013, margin from off system sales was $1.7 million compared to $0.7 million in 2012.  The base rate changes implemented in May 2011 require that wholesale margin from off-system sales earned above or below $7.5 million per year be shared equally with customers.Results for the periods presented reflect the impact of that sharing.

Operating Expenses

Other Operating

During the second quarter of 2013, other operating expenses decreased $1.7 million, partially related to the timing of power supply operating costs.  For the six months ended June30, 2013, other operating expenses were $162.9 million, an increase of $5.2 million, compared to 2012.  Excluding pass through costs, other operating expenses increased $4.2 million year to date, compared to the same period in 2012, primarily associated with increased expense related to company stock price driven performance based compensation.  For the full year 2013, the Company expects to be on track to meet its annual goal of generally flat operating expenses, driven largely by continued focus on performance management initiatives.

Depreciation & Amortization

In the second quarter of 2013, depreciation and amortization expense was $48.7 million, compared to $47.8 million in 2012.  For the six months ended June 30, 2013, depreciation and amortization expense was $97.1 million, which represents an increase of $0.7 million compared to 2012.  Both the year to date and quarter periods reflect increased plant placed into service.

Taxes Other Than Income Taxes

Taxes other than income taxes were $12.2 million for the second quarter of 2013, an increase of $0.6 million, compared to 2012.  Year to date, taxes other than income taxes were $29.7 million compared to $27.5 million for the year to date period in 2012.  The year to date increase of $2.2 million is primarily due to higher revenue taxes associated with higher gas costs.  These expenses are offset dollar-for-dollar with lower gas utility and electric utility revenues.

Rate & Regulatory Matters

Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement

The Company monitors and maintains its natural gas distribution system to ensure that natural gas is delivered in a safe and efficient manner. The Company's natural gas utilities are currently engaged in replacement programs in both Indiana and Ohio, the primary purpose of which is preventive maintenance and continual renewal and operational improvement.Laws in both Indiana and Ohio were passed that expand the ability of utilities to recover certain costs of federally mandated projects and other infrastructure improvement projects, outside of a base rate proceeding.Utilization of these recovery mechanisms is discussed below.

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Ohio Recovery and Deferral Mechanisms

The PUCO order approving the Company's 2009 base rate case in the Ohio service territory authorized a distribution replacement rider (DRR).  The DRR's primary purpose is recovery of investments in utility plant and related operating expenses associated with replacing bare steel and cast iron pipelines and certain other infrastructure.  This rider is updated annually for qualifying capital expenditures and allows for a return to be earned on those capital expenditures based on the rate of return approved in the 2009 base rate case.  In addition, deferral of depreciation and the ability to accrue debt-related post in service carrying costs is also allowed until the related capital expenditures are recovered through the DRR.  The order also established a prospective bill impact evaluation on the annual deferrals, limiting the deferrals at a level which would equal a change over the prior year rate of $1.00 per residential and general service customer per month.  To date, the Company has made capital investments under this rider totaling $94 million.  Regulatory assets associated with post in service carrying costs and depreciation deferrals were $7.9 million and $6.5 million at June30, 2013 and December 31, 2012, respectively.  The DRR's initial five year term expires in early 2014.  The Company filed in July 2013 a notice that it will request to extend the term of the DRR.

In June 2011, Ohio House Bill 95 was signed into law.  Outside of a base rate proceeding, this legislation permits a natural gas company to apply for recovery of much of its capital expenditure program. The legislation also allows for the deferral of costs, such as depreciation, property taxes, and debt-related post in service carrying costs. On December 12, 2012, the PUCO issued an order approving the Company's initial application using this law, reflecting its $23.5 million capital expenditure program covering the fifteen month period ending December 31, 2012. Such capital expenditures include infrastructure expansion and improvements not covered by the DRR as well as expenditures necessary to comply with PUCO rules, regulations, orders, and system expansion to some new customers.  The order also established a prospective bill impact evaluation on the cumulative deferrals, limiting the total deferrals at a level which would equal $1.50 per residential and general service customer per month.  The Company will file annually for the accounting treatment described above for its annual capital expenditure program.  Included in the notice filed in July 2013, the Company indicated an application will be filed in the near term seeking authority to expand the DRR to include recovery of other infrastructure investments to improve the reliability of its system.

Indiana Recovery and Deferral Mechanisms

The Company's Indiana natural gas utilities received orders in 2008 and 2007 associated with the most recent base rate cases.  These orders authorized the deferral of financial impacts associated with bare steel and cast iron replacement activities.  The orders provide for the deferral of depreciation and post in service carrying costs on qualifying projects totaling $20 million annually at Vectren North and $3 million annually at Vectren South.  The debt-related post in service carrying costs are recognized in the Condensed Consolidated Statements of Income currently.  Such deferral is limited by individual qualifying project to three years after being placed into service at Vectren South and four years after being placed into service at Vectren North.

In April 2011, Senate Bill 251 was signed into Indiana law. The law 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 a return on the federally mandated capital investment, along with recovery of depreciation and other operating costs associated with these mandates.  The remaining 20 percent of those costs are to be deferred for future recovery in the utility's next general rate case.

In April 2013, Senate Bill 560 was signed into law. This legislation supplements Senate Bill 251 described above, which addressed federally-mandated investment, provides for cost recovery outside of a base rate proceeding for projects that either improve electric and gas system reliability and safety or are economic development projects that provide rural areas with access to gas service. Provisions of the legislation require that, among other things, requests for recovery include a seven year project plan. Once the plan is approved by the IURC, 80 percent of such costs are eligible for recovery using a periodic rate adjustment mechanism. Recoverable costs include a return on and of the investment, as well as property taxes and operating expenses. The remaining 20 percent of project costs are to be deferred for future recovery in the Company's next general rate case. The adjustment mechanism is capped at an annual increase in retail revenues of no more than two percent.

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Pipeline Safety Law

On January 3, 2012, the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (Pipeline Safety Law) was signed into law. The Pipeline Safety 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 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 over the next two years.  Those regulations may eventually lead to further regulatory or statutory requirements.

The Company continues to study the impact of the Pipeline Safety 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 law is expected to result in further investment in pipeline inspections, and where necessary, additional investments in 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 by approximately $9 million annually, with $6 million attributable to the Indiana

Request for Recovery Under Regulatory Mechanisms

The Company plans to utilize the mechanisms described above to recover certain costs of federally mandated projects and other capital investment projects outside of base rate proceedings.  The Company has filed a notice indicating an application will be filed in the near term seeking authority to extend the term of the DRR and expand the DRR to include for recovery of other infrastructure investments to improve the reliability of its system.  The Company also expects to seek authority to recover appropriate costs using the mechanisms allowed under Senate Bill 251 and Senate Bill 560 in the latter half of 2013.  Capital investments, associated with the Pipeline Safety Law, are expected to be significant and the Company expects to seek recovery in Indiana under Senate Bill 251 and Senate Bill 560, as applicable, and under Ohio House Bill 95, or other currently authorized recovery mechanisms, as soon as practical following the finalization of regulations and the completion of a compliance plan.

Vectren North Pipeline Safety Investigation

On April 11, 2012, the IURC's pipeline safety division filed a complaint against Vectren North alleging several violations of safety regulations pertaining to damage that occurred at a residence in Vectren North's service territory during a pipeline replacement project.  The Company negotiated a settlement with the IURC's pipeline safety division, agreeing to a fine and several modifications to the Company's operating policies.  The amount of the fine was not material to the Company's financial results.  The IURC approved the settlement but modified certain terms of the settlement and added a requirement that Company employees conduct inspections of pipeline excavations.  The Company sought and was granted a request for rehearing on the sole issue related to the requirement to use Company employees to inspect excavations. The Company seeks further clarity on the scope of the requirement and the ability to also use contractors to perform certain inspections.  The Company submitted testimony in the case in April 2013.  A hearing will be conducted in November 2013.

Environmental Matters

Indiana Senate Bill 251 is also applicable to federal environmental mandates impacting Vectren South's electric operations. The Company is currently evaluating the impact Senate Bill 251 may have on its operations, including applicability of the stricter regulations the EPA is currently considering involving air quality, fly ash disposal, cooling tower intake facilities, waste water discharges, and greenhouse gases.  These issues are further discussed below.

Air Quality

Clean Air Interstate Rule / Cross-State Air Pollution Rule

In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR).CSAPR was 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

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downwind states due to unlimited trading of SO2 and NOx allowances, CSAPR reduced the ability of facilities to meet emission reduction targets through allowance trading.Like CAIR, CSAPR set individual state caps for SO2 and NOx emissions.  However, unlike CAIR in which states allocated allowances to generating units through state implementation plans, CSAPR allowances were allocated to individual units directly through the federal rule.CSAPR reductions were to be achieved with initial step reductions beginning January 1, 2012, and final compliance to be achieved in 2014.Multiple administrative and judicial challenges were filed.  On December 30, 2011, the Court granted a stay of CSAPR and left CAIR in place pending its review.  On August 21, 2012, the Court vacated CSAPR and directed the EPA to continue to administer CAIR.  In October 2012, the EPA filed its request for a hearing before the full federal appeals court that struck down the CSAPR. EPA's request for rehearing was denied by the Court on January 24, 2013.  In March 2013, the EPA filed a petition for review with the US Supreme Court, and in June 2013 the Supreme Court agreed to review the lower court decision.  A decision by the Supreme Court is expected in 2014.  The Company remains in full compliance with CAIR (see additional information below "Conclusions Regarding Air Regulations").

Mercury and Air Toxics (MATS) Rule

On December 21, 2011, the EPA finalized the Utility MATS Rule.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 electric generating 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 CSAPR'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 agreed to 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.  The EPA issued its revised emission limits for new construction in March 2013.

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 Generating Corporation (AGC), a subsidiary of 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 SO2allowances 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 received a notice of violation (NOV) from the EPA in November 2011 pertaining to its A.B. Brown power plant. The NOV asserts that when the power plant was equipped with SCRsthe 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.

The Company continues to review the sufficiency of its existing pollution control equipment in relation to the requirements described in the MATS Rule, the 2015 requirement imposed by CAIR, and the NOV discussed above.Due to the correlation amongst the various requirements set forth, it is possible some operational modifications to the control equipment will be required.  Additional capital investments, operating expenses, and possibly the purchase of emission allowances may be

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required and could be significant depending on the required method of compliance with the requirements.The Company has not yet quantified what the additional costs may be associated with these efforts.  However, as the compliance is required by government regulation, the Company believes that such additional costs, if incurred, should be recoverable under Senate Bill 251 referenced above.

Information Request

SIGECO and AGC own a 300 MW Unit 4 at the Warrick Power Plant as tenants in common.AGC and SIGECO also share equally in the cost of operation and output of the unit.In January 2013, AGC received an information request from the EPA under Section 114 of the Clean Air Act for historical operational information on the Warrick Power Plant.  In April 2013, ALCOA filed a timely response to the information request.

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 approximate $40 million if new infrastructure, such as new cooling water towers, is required. Costs for compliance with these final regulations should qualify as federally mandated regulatory requirements and be recovered under Indiana Senate Bill 251 referenced above.

Under the Clean Water Act, EPA sets technology-based guidelines for water discharges from new and existing facilities.  EPA is currently in the process of revising the existing steam electric effluent limitation guidelines that set the technology-based water discharge limits for the electric power industry.  EPA is focusing its rulemaking on wastewater generated primarily by pollution control equipment necessitated by the comprehensive air regulations.  The EPA released proposed rules on April 19, 2013 and the Company is reviewing the proposal.  At this time, it is not possible to estimate what potential costs may be required to meet these new water discharge limits, however costs for compliance with these regulations should qualify as federally mandated regulatory requirements and be recovered under 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 have not been finalized 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 should 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 (GHG's) meet the definition of "air pollutant" under the Clean Air Act and ordered the EPA to determine whether GHG 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

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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 the EPA regulating carbon emissions through the existing Clean Air Act in the absence of specific carbon legislation from Congress.

The EPA has promulgated two GHG regulations that apply to the Company's generating facilities. In 2009, the EPA finalized a mandatory GHG 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 GHG's a year to obtain a PSD permit for new construction or a significant modification of an existing facility.The EPA's PSD and Title V permitting rules for GHG's were upheld by the US Court of Appeals for the District of Columbia.  In 2012, the EPA proposed New Source Performance Standards (NSPS) for GHG's for new electric generating facilities under Clean Air Act Section 111(b).  In July 2013, the President announced a Climate Action Plan, which calls on the EPA to re-propose and finalize the new source rule expeditiously, and by June 2014 propose, and by June 2015 finalize, NSPS standards for GHG's for existing electric generating units which would apply to Vectren's power plants.  States must have their implementation plans to the EPA no later than June 2016.  The President's Climate Action Plan did not provide any detail as to actual emission targets or compliance requirements.  The Company anticipates that these initial standards will focus on power plant efficiency and other coal fleet carbon intensity reduction measures.  The Company believes that such additional costs, if necessary, should be recoverable under Indiana Senate Bill 251 referenced above.

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 GHG's 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 GHG emissions or obtaining renewable energy sources remain uncertain. The Company has gathered preliminary estimates of the costs to control GHG 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 GHG 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 GHG 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 should be recoverable from customers through Senate Bill 251.

Senate Bill 251 also established a voluntary clean energy portfolio standard that provides incentives to electricity suppliers participating in the program.  The goal of the program is that by 2025, at least 10 percent of the total electricity obtained by the supplier to meet the energy needs of Indiana retail customers will be provided by clean energy sources, as defined.  In advance of a federal portfolio standard and Senate Bill 251, SIGECO received regulatory approval to purchase a 3 MW landfill gas generation facility from a related entity. The facility was purchased in 2009 and is directly connected to the Company's distribution system. In 2008 and 2009, the Company executed long term purchase power commitments for a total of 80 MW of wind energy.  The Company currently has approximately 5 percent of its electricity being provided by clean energy sources due to the long-term wind contracts and landfill gas investment.

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.

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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 has incurred or reasonably expects to incur totaling approximately $42.4 million ($23.2 million at Indiana Gas and $19.2 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.Likewise, SIGECO has settlement agreements with all known insurance carriers and has received to date approximately $14.2 million of the expected $15.7 million in 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 remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery.As of June30, 2013 and December 31, 2012, approximately $5.1 million and $4.6 million, respectively, of accrued, but not yet spent, costs are included in Other Liabilities related to the Indiana Gas and SIGECO sites.

Impact of Recently Issued Accounting Guidance

Offsetting Assets and Liabilities

In January 2013, the FASB issued new accounting guidance on disclosures of offsetting assets and liabilities.  This guidance amends prior requirements to add clarification to the scope of the offsetting disclosures. The amendment clarifies that the scope applies to derivative instruments accounted for in accordance with reporting topics on derivatives and hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with US GAAP or subject to an enforceable master netting arrangement or similar agreement.  This guidance is effective for fiscal years beginning on or after January 1, 2013 and interim periods within annual periods.  The Company adopted this guidance as of January 1, 2013.  The adoption of this guidance did not have a material impact on the Company's financial statements.

Accumulated Other Comprehensive Income (AOCI)

In February 2013, the FASB issued new accounting guidance on the reporting of reclassifications from AOCI.  The guidance requires an entity to report the effect of significant reclassification from AOCI on the respective line items in net income if the amount being reclassified is required under US GAAP to be reclassified in its entirety to net income.  For other amounts that are not required under US GAAP to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference to other disclosures required that provide additional details about these amounts. The new guidance is effective for fiscal years, and interim periods within annual periods, beginning after December 15, 2012.As this guidance provides only disclosure requirements, the adoption of this standard did not impact the Company's results of operations, cash flows, or financial position.

Unrecognized Tax Benefit Presentation

In July 2013, the FASB issued new accounting guidance on presenting an unrecognized tax benefit when net operating loss carryforwards exist.  The new standard was issued in an effort to eliminate diversity in practice resulting from a lack of guidance on this topic in the current US GAAP.  The update provides that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss

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carryforward, a similar tax loss, or a tax credit carryforward, except under certain circumstances outlined in the update.  The amendments in the update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013, with early adoption permitted.  The adoption of this guidance will have no material impact on the Company's financial statements.

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 direct 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, inclusive of current maturities, with a par value of $825 million and short-term obligations totaling $124 million were outstanding at June30, 2013.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, including current maturities, outstanding at June30, 2013, approximates $382 million, inclusive of the $49 million on SIGECO's tax exempt long-term debt currently being held by Utility Holdings that is planned for remarketing in the third quarter of 2013.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 June30, 2013, 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.Standard and Poor's affirmed its rating of the Company on July 19, 2013.  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 55 percent of long-term capitalization at June30, 2013 and 53 percent at December 31, 2012.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, 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 June30, 2013, 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, and the Company believes it will have the ability to continue to do so.Given the Company's intent to maintain a balanced long-term capitalization ratio, it anticipates funding future capital expenditures and dividends principally through internally generated funds, which have recently been enhanced by bonus depreciation legislation, and refinancing maturing or callable debt using the capital markets.  However, the resources required for capital investment remain uncertain for a variety of factors including pending legislative and regulatory initiatives involving gas pipeline infrastructure replacement; and expanded EPA regulations for air, water, and fly ash. These regulations may result in the need to raise additional capital in the coming years.  The timing and amount of such investments depends on a variety of factors, including available liquidity.

Specifically for 2013, the Company has accessed and will continue to assess the capital markets to refinance debt maturities or debt that is callable.  During the second quarterof 2013, approximately $111.0 million of SIGECO's tax-exempt long-term debt was redeemed at par plus accrued interest.  Approximately $62 million of tax-exempt long-term debt was reissued on April26,

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2013 at interest rates that are fixed to maturity, receiving proceeds, net of issuance costs, of approximately $60 million.  The terms are $22.2 million at 4.00 percent per annum due in 2038, and $39.6 million at 4.05 percent per annum due in 2043.  The remaining approximately $49 million of the called debt is held by Utility Holdings and planned for remarketing in the third quarter of 2013, and is treated as extinguished in the consolidated financial statements as of June 30, 2013.

On April1, 2013, the Company executed an early redemption at par of $121.6 million 6.25 percent senior unsecured notes due in 2039. This debt was refinanced on June5, 2013, with proceeds from a private placement note purchase agreement entered into on December20, 2012, with a delayed draw feature.  It provides for the following tranches of notes: (i) $45 million 3.2 percent senior guaranteed notes, due June5, 2028 and (ii) $80 million 4.25 percent senior guaranteed notes, due June5, 2043. The notes are unconditionally guaranteed by Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company and Vectren Energy Delivery of Ohio, Inc.

On July25, 2013, VUHI announced that it priced $150 million10-year senior unsecured notes.  The notes were sold to various institutional investors through the private placement market and included a delayed draw feature.  VUHI will issue $150 million of 3.72 percent senior notes due December5, 2023.  The proceeds received from the issuance of the senior notes will be used to refinance $100 million of existing 5.25 percent senior notes that mature August1, 2013, for capital expenditures, and for general corporate purposes.  Subject to the satisfaction of customary conditions precedent, the notes will be funded on or about December5, 2013, as a result of the delayed draw feature.  As of June30, 2013 the $100 million was classified as Current maturities of long-term debt.

Consolidated Short-Term Borrowing Arrangements

At June30, 2013, the Company has $350 million of short-term borrowing capacity.As reduced by borrowings currently outstanding, approximately $226 million was available at June30, 2013.This short-term borrowing facility 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.

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)	2013	2012
Six Months Ended June 30
Balance Outstanding	$124.0	$61.5
Weighted Average Interest Rate	0.34%	0.46%
Six Months Ended June 30 Average
Balance Outstanding	$105.0	$72.4
Weighted Average Interest Rate	0.36%	0.49%
Maximum Month End Balance Outstanding	$174.8	$214.2
(In millions)	2013	2012
Quarterly Average - June 30
Balance Outstanding	$146.4	$31.5
Weighted Average Interest Rate	0.35%	0.46%
Maximum Month End Balance Outstanding	$174.8	$214.2

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Potential Uses of Liquidity

Planned Capital Expenditures

Utility capital expenditures are estimated at $172 million for the remainder of 2013.

Pension Funding Obligations

Vectren's management currently estimates contributing approximately $10 million to qualified pension plans in 2013.  A portion of this funding will be from Utility Holdings and occurs through a routine cash settlement process with its parent.

Other Letters of Credit

As of June30, 2013, Utility Holdings has letters of credit outstanding in support of two SIGECO tax exempt adjustable rate first mortgage bonds totaling $41.7 million.In the unlikely event the letters of credit were called, the Company could settle with the financial institutions supporting these letters of credit with general assets or by drawing from its credit facility that expires in September 2016.Due to the long-term nature of the credit agreement, such debt is classified as long-term at June30, 2013.

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 $197.1 million and $249.0 million during the six months ended June30, 2013 and 2012, respectively.The decrease is primarily due to lower cash flows from working capital of $58.9 million.

Financing Cash Flow

Net cash flow required for financing activities was $95.7 million and $128.8 million during the six months ended June30, 2013 and 2012, respectively.The decrease in cash required for financing activities reflects the recent debt refinancing activity and greater reliance on short-term borrowings, until long-term debt is issued later in the year.  Financing activity in both periods presented reflects the payment of dividends.

Investing Cash Flow

Cash flow required for investing activities was $110.8 million and $122.1 million during the six months ended June30, 2013 and 2012, respectively.The decreased cash required for investing activities during the current year period reflects the timing of capital expenditures year over year.

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Forward-Looking Information

A “safe harbor” for forward-looking statements is provided by the Private Securities Litigation Reform Act of 1995 (Reform Act of 1995).The Reform Act of 1995 was adopted to encourage such forward-looking statements without the threat of litigation, provided those statements are identified as forward-looking and are accompanied by meaningful cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement.Certain matters described in Management’s Discussion and Analysis of Results of Operations and Financial Condition are forward-looking statements.Such statements are based on management’s beliefs, as well as assumptions made by and information currently available to management.When used in this filing, the words “believe”, “anticipate”, “endeavor”, “estimate”, “expect”, “objective”, “projection”, “forecast”, “goal”, “likely”, and similar expressions are intended to identify forward-looking statements.In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause the Company’s actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:

•   Factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unusual maintenance or repairs; unanticipated changes to fossil fuel costs; unanticipated changes to gas transportation and storage costs, or availability due to higher demand, shortages, transportation problems or other developments; environmental or pipeline incidents; transmission or distribution incidents; unanticipated changes to electric energy supply costs, or availability due to demand, shortages, transmission problems or other developments; or electric transmission or gas pipeline system constraints.

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

•   Increased competition in the energy industry, including the effects of industry restructuring and unbundling.

•   Regulatory factors such as unanticipated changes in rate-setting policies or procedures, recovery of investments and costs made under traditional regulation, and the frequency and timing of rate increases.

•   Financial, regulatory or accounting principles or policies imposed by the Financial Accounting Standards Board; the Securities and Exchange Commission; the Federal Energy Regulatory Commission; state public utility commissions; state entities which regulate electric and natural gas transmission and distribution, natural gas gathering and processing, electric power supply; and similar entities with regulatory oversight.

•   Economic conditions including the effects of inflation rates, commodity prices, and monetary fluctuations.

•   Economic conditions surrounding the current economic uncertainty, including 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.

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•   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 realize value from, invest in and develop new opportunities, including but not limited to, Vectren’s infrastructure services, energy services, coal mining, and remaining energy marketing businesses and/or assets.

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. 2012 Form 10-K and is therefore not presented herein.

ITEM 4.CONTROLS & PROCEDURES

Changes in Internal Controls over Financial Reporting

During the quarter ended June30, 2013, there have been no changes to the Company’s internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

As of June30, 2013, 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 June30, 2013, 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.

36

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 2012 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

37

ITEM 6.EXHIBITS

Exhibits and Certifications

12Ratio of Earnings to Fixed Charges

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

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

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

101Interactive Data File.

101.INSXBRL Instance Document

101.SCHXBRL Taxonomy Extension Schema

101.CALXBRL Taxonomy Extension Calculation Linkbase

101.DEFXBRL Taxonomy Extension Definition Linkbase

101.LABXBRL Taxonomy Extension Labels Linkbase

101.PREXBRL Taxonomy Extension Presentation Linkbase

38

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 12, 2013	/s/ M. Susan Hardwick
	M. Susan Hardwick
	Senior Vice President, Finance and Assistant Treasurer
	(Principal Accounting Officer)

39

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,
	2013		2012		2011		2013		2012
Earnings: (1)
Net income	$	141,142	$	137,975	$	122,874	$	79,259	$	76,092
Income taxes	87,051		85,301		82,859		48,506		46,756
Fixed Charges (See below) (2)	69,809		71,862		80,650		33,772		35,825
Total adjusted earnings	$	298,002	$	295,138	$	286,383	$	161,537	$	158,673
Fixed charges: (2)
Total interest expense	$	69,418	$	71,475	$	80,281	$	33,597	$	35,654
Interest component of rents	391		387		369		175		171
Total fixed charges	$	69,809	$	71,862	$	80,650	$	33,772	$	35,825
Ratio of earnings to fixed charges	4.3		4.1		3.6		4.8		4.4

(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 12, 2013

/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 12, 2013

/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 12th day of August, 2013.

/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

Impact of Recently Issued Accounting Principles

6 Months Ended

Jun. 30, 2013

Impact of Recently Issued Accounting Principles [Abstract]

Impact of Recently Issued Accounting Principles

Impact of Recently Issued Accounting Principles

Offsetting Assets and Liabilities

In January 2013, the FASB issued new accounting guidance on disclosures of offsetting assets and liabilities. This guidance amends prior requirements to add clarification to the scope of the offsetting disclosures. The amendment clarifies that the scope applies to derivative instruments accounted for in accordance with reporting topics on derivatives and hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with US GAAP or subject to an enforceable master netting arrangement or similar agreement. This guidance is effective for fiscal years beginning on or after January 1, 2013 and interim periods within annual periods. The Company adopted this guidance as of January 1, 2013. The adoption of this guidance did not have a material impact on the Company's financial statements.

Accumulated Other Comprehensive Income (AOCI)

In February 2013, the FASB issued new accounting guidance on the reporting of reclassifications from AOCI. The guidance requires an entity to report the effect of significant reclassification from AOCI on the respective line items in net income if the amount being reclassified is required under US GAAP to be reclassified in its entirety to net income. For other amounts that are not required under US GAAP to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference to other disclosures required that provide additional details about these amounts.  The new guidance is effective for fiscal years, and interim periods within annual periods, beginning after December 15, 2012.  As this guidance provides only disclosure requirements, the adoption of this standard did not impact the company's results of operations, cash flows or financial position.

Unrecognized Tax Benefit Presentation

In July 2013, the FASB issued new accounting guidance on presenting an unrecognized tax benefit when net operating loss carryforwards exist. The new standard was issued in an effort to eliminate diversity in practice resulting from a lack of guidance on this topic in the current US GAAP. The update provides that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward, except under certain circumstances outlined in the update. The amendments in the update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013, with early adoption permitted. The adoption of this guidance will have no material impact on the Company's financial statements.

XML

CONSOLIDATED CONDENSED STATEMENTS OF INCOME (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
OPERATING REVENUES [Abstract]
Gas utility	$ 138.0	$ 116.0	$ 453.9	$ 408.3
Electric utility	154.7	149.3	304.2	288.7
Other	0.1	0.5	0.2	0.9
Total operating revenues	292.8	265.8	758.3	697.9
OPERATING EXPENSES [Abstract]
Cost of gas sold	50.7	31.8	207.9	168.9
Cost of fuel & purchased power	53.9	47.0	104.1	91.7
Other operating	76.1	77.8	162.9	157.7
Depreciation & Amortization	48.7	47.8	97.1	96.4
Taxes other than income taxes	12.2	11.6	29.7	27.5
Total operating expenses	241.6	216.0	601.7	542.2
OPERATING INCOME	51.2	49.8	156.6	155.7
Nonoperating Income (Expense) [Abstract]
Other income - net	3.0	0.7	4.8	2.9
Interest Expense	15.7	18.0	33.6	35.7
INCOME BEFORE INCOME TAXES	38.5	32.5	127.8	122.9
Income taxes	14.3	12.4	48.5	46.8
NET INCOME	$ 24.2	$ 20.1	$ 79.3	$ 76.1

XML

Accruals for Utility and NonUtility Plant

6 Months Ended

Jun. 30, 2013

Accruals for Utility & Nonutility Plant [Abstract]

Accruals for Utility and NonUtility Plant [Text Block]

As of June 30, 2013 and December 31, 2012, the Company has accruals related to utility and nonutility plant purchases totaling approximately $9.2 million and $7.1 million, respectively.

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, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
OPERATING REVENUES [Abstract]
Gas utility	$ 138.0	$ 116.0	$ 453.9	$ 408.3
Electric utility	154.7	149.3	304.2	288.7
Other	0.1	0.5	0.2	0.9
Total operating revenues	292.8	265.8	758.3	697.9
OPERATING EXPENSES [Abstract]
Cost of gas sold	50.7	31.8	207.9	168.9
Cost of fuel & purchased power	53.9	47.0	104.1	91.7
Other operating	76.1	77.8	162.9	157.7
Depreciation & Amortization	48.7	47.8	97.1	96.4
Taxes other than income taxes	12.2	11.6	29.7	27.5
Total operating expenses	241.6	216.0	601.7	542.2
OPERATING INCOME	51.2	49.8	156.6	155.7
Other income - net	3.0	0.7	4.8	2.9
Interest Expense	15.7	18.0	33.6	35.7
INCOME BEFORE INCOME TAXES	38.5	32.5	127.8	122.9
Income taxes	14.3	12.4	48.5	46.8
NET INCOME	24.2	20.1	79.3	76.1
Subsidiary Guarantors [Member]
OPERATING REVENUES [Abstract]
Gas utility	138.0	116.0	453.9	408.3
Electric utility	154.7	149.3	304.2	288.7
Other	0	0	0	0
Total operating revenues	292.7	265.3	758.1	697.0
OPERATING EXPENSES [Abstract]
Cost of gas sold	50.7	31.8	207.9	168.9
Cost of fuel & purchased power	53.9	47.0	104.1	91.7
Other operating	85.2	86.3	181.2	175.9
Depreciation & Amortization	43.3	42.1	86.4	83.8
Taxes other than income taxes	11.8	11.2	28.9	26.7
Total operating expenses	244.9	218.4	608.5	547.0
OPERATING INCOME	47.8	46.9	149.6	150.0
Other income - net	1.8	0.2	3.7	2.2
Interest Expense	13.8	16.4	30.0	32.9
INCOME BEFORE INCOME TAXES	35.8	30.7	123.3	119.3
Income taxes	14.0	12.2	48.8	47.7
Equity in earnings of consolidated companies, net of tax	0	0	0	0
NET INCOME	21.8	18.5	74.5	71.6
Parent Company [Member]
OPERATING REVENUES [Abstract]
Gas utility	0	0	0	0
Electric utility	0	0	0	0
Other	9.5	10.0	19.0	19.9
Total operating revenues	9.5	10.0	19.0	19.9
OPERATING EXPENSES [Abstract]
Cost of gas sold	0	0	0	0
Cost of fuel & purchased power	0	0	0	0
Other operating	0	0.5	0	0.5
Depreciation & Amortization	5.3	5.6	10.5	12.4
Taxes other than income taxes	0.4	0.3	0.8	0.7
Total operating expenses	5.7	6.4	11.3	13.6
OPERATING INCOME	3.8	3.6	7.7	6.3
Other income - net	9.1	9.9	18.8	20.5
Interest Expense	10.2	11.7	22.0	23.2
INCOME BEFORE INCOME TAXES	2.7	1.8	4.5	3.6
Income taxes	0.3	0.2	(0.3)	(0.9)
Equity in earnings of consolidated companies, net of tax	21.8	18.5	74.5	71.6
NET INCOME	24.2	20.1	79.3	76.1
Consolidation, Eliminations [Member]
OPERATING REVENUES [Abstract]
Gas utility	0	0	0	0
Electric utility	0	0	0	0
Other	(9.4)	(9.5)	(18.8)	(19.0)
Total operating revenues	(9.4)	(9.5)	(18.8)	(19.0)
OPERATING EXPENSES [Abstract]
Cost of gas sold	0	0	0	0
Cost of fuel & purchased power	0	0	0	0
Other operating	(9.1)	(9.0)	(18.3)	(18.7)
Depreciation & Amortization	0.1	0.1	0.2	0.2
Taxes other than income taxes	0	0.1	0	0.1
Total operating expenses	(9.0)	(8.8)	(18.1)	(18.4)
OPERATING INCOME	(0.4)	(0.7)	(0.7)	(0.6)
Other income - net	(7.9)	(9.4)	(17.7)	(19.8)
Interest Expense	(8.3)	(10.1)	(18.4)	(20.4)
INCOME BEFORE INCOME TAXES	0	0	0	0
Income taxes	0	0	0	0
Equity in earnings of consolidated companies, net of tax	(21.8)	(18.5)	(74.5)	(71.6)
NET INCOME	(21.8)	(18.5)	(74.5)	(71.6)
Consolidated Entities [Member]
OPERATING REVENUES [Abstract]
Gas utility	138.0	116.0	453.9	408.3
Electric utility	154.7	149.3	304.2	288.7
Other	0.1	0.5	0.2	0.9
Total operating revenues	292.8	265.8	758.3	697.9
OPERATING EXPENSES [Abstract]
Cost of gas sold	50.7	31.8	207.9	168.9
Cost of fuel & purchased power	53.9	47.0	104.1	91.7
Other operating	76.1	77.8	162.9	157.7
Depreciation & Amortization	48.7	47.8	97.1	96.4
Taxes other than income taxes	12.2	11.6	29.7	27.5
Total operating expenses	241.6	216.0	601.7	542.2
OPERATING INCOME	51.2	49.8	156.6	155.7
Other income - net	3.0	0.7	4.8	2.9
Interest Expense	15.7	18.0	33.6	35.7
INCOME BEFORE INCOME TAXES	38.5	32.5	127.8	122.9
Income taxes	14.3	12.4	48.5	46.8
Equity in earnings of consolidated companies, net of tax	0	0	0	0
NET INCOME	$ 24.2	$ 20.1	$ 79.3	$ 76.1

XML

Segment Reporting

6 Months Ended

Jun. 30, 2013

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)	2013			2012			2013			2012
Revenues
Gas Utility Services	$	138.0		$	116.0		$	453.9		$	408.3
Electric Utility Services	154.7			149.3			304.2			288.7
Other Operations	142.0			10.0			151.5			19.9
Eliminations	(141.9		)	(9.5		)	(151.3		)	(19.0		)
Total revenues	$	292.8		$	265.8		$	758.3		$	697.9
Profitability Measure - Net Income (Loss)
Gas Utility Services	$	2.9		$	1.3		$	41.0		$	38.8
Electric Utility Services	18.9			17.2			33.5			32.8
Other Operations	2.4			1.6			4.8			4.5
Total net income	$	24.2		$	20.1		$	79.3		$	76.1

XML

Accruals for Utility and NonUtility Plant Accruals for Utility and NonUtility Plant (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Accruals for Utility & Nonutility Plant [Abstract]
Public Utilities Accruals For Purchase Of Utility And Non Utility Plant Assets	$ 9.2	$ 7.1

XML

Excise and Utility Receipts Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Excise and Utility Receipts Taxes [Abstract]
Excise and utility taxes collected and reported in operating revenue	$ 5.4	$ 5.0	$ 16.1	$ 14.3

XML

Environmental Matters (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2013 MW	Dec. 31, 2012
Air Quality [Abstract]
SIGECO investment in Property, Plant and Equipment, Pollution control equipment	$ 411
Property, Plant and Equipment, amount of investment in pollution control equipment included in rate base	411
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%
Cost of most of the allowances granted to company for NOx and SO2 inventory usage	0
Clean Water Act [Abstract]
Estimated capital expenditures related to Clean Water Act	40
Coal Ash Waste Disposal and Ash Ponds [Abstract]
Estimated capital expenditures to comply with ash pond and coal ash disposal regulations	30
Potential estimated capital expenditures to comply with ash pond and coal ash disposal regulations with stringent alternative	100
Estimated annual compliance costs maximum with ash pond and coal ash disposal regulation	5
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
Indiana Senate Bill 251 [Abstract]
Description of legislation	Senate Bill 251 also established a voluntary clean energy portfolio standard that provides incentives to electricity suppliers participating in the program.
Description of the goal of legislation	The goal of the program is that by 2025, at least 10 percent of the total electricity obtained by the supplier to meet the energy needs of Indiana retail customers will be provided by clean energy sources, as defined.
Power generation capacity for acquired landfill gas generations facility (in megawatts)	3
Long term contract for purchase of electric power generated by wind energy (in megawatts)	80
Percentage of total electricity obtained by the supplier to meet the energy needs of its retail customers provided by clean energy sources (in hundredths)	5.00%
Manufactured Gas Plants
Site contingency, accrual, undiscounted amount	42.4
Remediation cost accrued and not yet spent a the end of the period	5.1	4.6
Indiana Gas [Member]
Manufactured Gas Plants
Number of sites identified with potential remedial responsibility for entity (in number of sites)	26
Site contingency, accrual, undiscounted amount	23.2
Site Contingency Recovery From Insurance Carriers Of Environmental Remediation Cost	20.8
SIGECO [Member]
Manufactured Gas Plants
Number of sites identified with potential remedial responsibility for entity (in number of sites)	5
Site contingency, accrual, undiscounted amount	19.2
Site Contingency Recovery From Insurance Carriers Of Environmental Remediation Cost	14.2
Expected Site Contingency Recovery from Insurance Carriers of Environmental Remediation Costs	$ 15.7

XML

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, 2013	Jun. 30, 2013	Jun. 30, 2012	Dec. 31, 2012	Dec. 31, 2011
Net cash provided by operating activities		$ 197.1	$ 249.0
Long-term debt - net of issuance costs		122.3	99.5
Additional capital contribution		3.0	3.5
Dividends to parent		(52.6)	(50.5)
Repayments of Long-term Debt		(175.7)	0
Net change in intercompany short-term borrowings		0
Net change in short-term borrowings		7.3	(181.3)
Net cash used in financing activities		(95.7)	(128.8)
Consolidated subsidiary distributions	0
Other investing activities		0.1	2.2
Capital expenditures, excluding AFUDC equity		(110.9)	(124.1)
Consolidated subsidiary investments		0
Other investments		0	(0.2)
Net change in long-term intercompany notes receivable		0
Net change in short term intercompany notes receivable		0
Net cash used in investing activities		(110.8)	(122.1)
Net change in cash and cash equivalents		(9.4)	(1.9)
Cash & cash equivalents	3.9	3.9	4.1	13.3	6.0
Subsidiary Guarantors [Member]
Net cash provided by operating activities		199.1	233.3
Long-term debt - net of issuance costs		60.0	0
Additional capital contribution		10.0	3.5
Dividends to parent		(49.0)	(47.2)
Repayments of Long-term Debt		(174.8)
Net change in intercompany short-term borrowings		49.0	(52.9)
Net change in short-term borrowings		0	0
Net cash used in financing activities		(104.8)	(96.6)
Consolidated subsidiary distributions		0	0
Other investing activities		0	0
Capital expenditures, excluding AFUDC equity		(103.3)	(121.4)
Consolidated subsidiary investments		0	0
Other investments			(0.2)
Net change in long-term intercompany notes receivable		0
Net change in short term intercompany notes receivable		0	(17.7)
Net cash used in investing activities		(103.3)	(139.3)
Net change in cash and cash equivalents		(9.0)	(2.6)
Cash & cash equivalents	3.5	3.5	2.7	12.5	5.3
Parent Company [Member]
Net cash provided by operating activities		(2.0)	15.7
Long-term debt - net of issuance costs		124.4	99.5
Additional capital contribution		3.0	3.5
Dividends to parent		(52.6)	(50.5)
Repayments of Long-term Debt		(121.6)
Net change in intercompany short-term borrowings		0	17.7
Net change in short-term borrowings		7.3	(181.3)
Net cash used in financing activities		(39.5)	(111.1)
Consolidated subsidiary distributions		49.0	47.2
Other investing activities		0.1	2.2
Capital expenditures, excluding AFUDC equity		(7.6)	(2.7)
Consolidated subsidiary investments		(10.0)	(3.5)
Other investments			0
Net change in long-term intercompany notes receivable		58.6
Net change in short term intercompany notes receivable		(49.0)	52.9
Net cash used in investing activities		41.1	96.1
Net change in cash and cash equivalents		(0.4)	0.7
Cash & cash equivalents	0.4	0.4	1.4	0.8	0.7
Consolidation, Eliminations [Member]
Net cash provided by operating activities		0	0
Long-term debt - net of issuance costs		(62.1)	0
Additional capital contribution		(10.0)	(3.5)
Dividends to parent		49.0	47.2
Repayments of Long-term Debt		120.7
Net change in intercompany short-term borrowings		(49.0)	35.2
Net change in short-term borrowings		0	0
Net cash used in financing activities		48.6	78.9
Consolidated subsidiary distributions		(49.0)	(47.2)
Other investing activities		0	0
Capital expenditures, excluding AFUDC equity		0	0
Consolidated subsidiary investments		10.0	3.5
Other investments			0
Net change in long-term intercompany notes receivable		(58.6)
Net change in short term intercompany notes receivable		49.0	(35.2)
Net cash used in investing activities		(48.6)	(78.9)
Net change in cash and cash equivalents		0	0
Cash & cash equivalents	0	0	0	0	0
Consolidated Entities [Member]
Net cash provided by operating activities			249.0
Long-term debt - net of issuance costs			99.5
Additional capital contribution			3.5
Dividends to parent			(50.5)
Net change in intercompany short-term borrowings			0
Net change in short-term borrowings			(181.3)
Net cash used in financing activities			(128.8)
Consolidated subsidiary distributions			0
Other investing activities			2.2
Capital expenditures, excluding AFUDC equity			(124.1)
Consolidated subsidiary investments			0
Other investments			(0.2)
Net change in short term intercompany notes receivable			0
Net cash used in investing activities			(122.1)
Net change in cash and cash equivalents			(1.9)
Cash & cash equivalents	$ 3.9	$ 3.9	$ 4.1	$ 13.3	$ 6.0

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Organization and Nature of Operations

6 Months Ended

Jun. 30, 2013

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 573,000 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 313,000 natural gas customers located near Dayton in west central Ohio.

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Subsidiary Guarantor and Consolidating Information

6 Months Ended

Jun. 30, 2013

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 $124 million is outstanding at June 30, 2013, and Utility Holdings’ has unsecured senior notes with a par value of $825 million outstanding at June 30, 2013.  The guarantees are full and unconditional and joint and several, and Utility Holdings has no direct 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, 2013 (in millions):

ASSETS	Subsidiary		Parent			Eliminations &
	Guarantors		Company			Reclassifications			Consolidated
Current Assets
Cash & cash equivalents	$	3.5	$	0.4		$	—		$	3.9
Accounts receivable - less reserves	72.9		—			—			72.9
Intercompany receivables	1.7		192.5			(194.2		)	—
Receivables due from other Vectren companies	—		6.9			—			6.9
Accrued unbilled revenues	35.7		—			—			35.7
Inventories	91.8		(0.1		)	—			91.7
Recoverable fuel & natural gas costs	18.6		—			—			18.6
Prepayments & other current assets	41.5		76.4			(72.1		)	45.8
Total current assets	265.7		276.1			(266.3		)	275.5
Utility Plant
Original cost	5,265.0		—			—			5,265.0
Less:  accumulated depreciation & amortization	2,104.4		—			—			2,104.4
Net utility plant	3,160.6		—			—			3,160.6
Investments in consolidated subsidiaries	—		1,364.7			(1,364.7		)	—
Notes receivable from consolidated subsidiaries	—		572.1			(572.1		)	—
Investments in unconsolidated affiliates	0.2		—			—			0.2
Other investments	28.9		4.6			—			33.5
Nonutility property - net	2.4		139.7			—			142.1
Goodwill - net	205.0		—			—			205.0
Regulatory assets	104.5		22.4			—			126.9
Other assets	35.3		1.3			(7.2		)	29.4
TOTAL ASSETS	$	3,802.6	$	2,380.9		$	(2,210.3	)	$	3,973.2
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent			Eliminations &
	Guarantors		Company			Reclassifications			Consolidated
Current Liabilities
Accounts payable	$	62.7	$	4.4		$	—		$	67.1
Intercompany payables	10.6		—			(10.6		)	—
Payables to other Vectren companies	25.6		2.0			—			27.6
Accrued liabilities	132.4		12.8			(23.0		)	122.2
Short-term borrowings	—		124.0			—			124.0
Intercompany short-term borrowings	183.6		—			(183.6		)	—
Current maturities of long-term debt	—		100.0			—			100.0
Total current liabilities	414.9		243.2			(217.2		)	440.9
Long-Term Debt
Long-term debt - net of current maturities	382.3		724.6			(49.1		)	1,057.8
Long-term debt due to VUHI	572.1		—			(572.1		)	—
Total long-term debt - net	954.4		724.6			(621.2		)	1,057.8
Deferred Income Taxes & Other Liabilities
Deferred income taxes	610.9		(10.5		)	—			600.4
Regulatory liabilities	374.7		1.7			—			376.4
Deferred credits & other liabilities	83.0		2.2			(7.2		)	78.0
Total deferred credits & other liabilities	1,068.6		(6.6		)	(7.2		)	1,054.8
Common Shareholder's Equity
Common stock (no par value)	797.8		784.6			(797.8		)	784.6
Retained earnings	566.9		635.1			(566.9		)	635.1
Total common shareholder's equity	1,364.7		1,419.7			(1,364.7		)	1,419.7
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,802.6	$	2,380.9		$	(2,210.3	)	$	3,973.2

Condensed Consolidating Balance Sheet as of December 31, 2012 (in millions):

ASSETS	Subsidiary		Parent			Eliminations &
	Guarantors		Company			Reclassifications			Consolidated
Current Assets
Cash & cash equivalents	$	12.5	$	0.8		$	—		$	13.3
Accounts receivable - less reserves	81.8		—			—			81.8
Intercompany receivables	—		145.1			(145.1		)	—
Accrued unbilled revenues	93.6		—			—			93.6
Inventories	114.0		—			—			114.0
Recoverable fuel & natural gas costs	25.3		—			—			25.3
Prepayments & other current assets	52.0		5.8			(5.5		)	52.3
Total current assets	379.2		151.7			(150.6		)	380.3
Utility Plant
Original cost	5,176.6		0.2			—			5,176.8
Less:  accumulated depreciation & amortization	2,057.2		—			—			2,057.2
Net utility plant	3,119.4		0.2			—			3,119.6
Investments in consolidated subsidiaries	—		1,329.2			(1,329.2		)	—
Notes receivable from consolidated subsidiaries	—		679.7			(679.7		)	—
Investments in unconsolidated affiliates	0.2		—			—			0.2
Other investments	27.8		4.8			—			32.6
Nonutility property - net	2.6		144.3			—			146.9
Goodwill - net	205.0		—			—			205.0
Regulatory assets	104.1		22.4			—			126.5
Other assets	40.4		1.7			(6.4		)	35.7
TOTAL ASSETS	$	3,878.7	$	2,334.0		$	(2,165.9	)	$	4,046.8
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent			Eliminations &
	Guarantors		Company			Reclassifications			Consolidated
Current Liabilities
Accounts payable	$	114.8	$	6.2		$	—		$	121.0
Accounts payable to affiliated companies	29.7		—			—			29.7
Intercompany payables	10.6		—			(10.6		)	—
Payables to other Vectren companies	25.1		—			—			25.1
Accrued liabilities	131.3		13.5			(5.5		)	139.3
Short-term borrowings	—		116.7			—			116.7
Intercompany short-term borrowings	134.5		—			(134.5		)	—
Current maturities of long-term debt	5.0		100.0			—			105.0
Total current liabilities	451.0		236.4			(150.6		)	536.8
Long-Term Debt
Long-term debt - net of current maturities	382.3		721.1			—			1,103.4
Long-term debt due to VUHI	679.7		—			(679.7		)	—
Total long-term debt - net	1,062.0		721.1			(679.7		)	1,103.4
Deferred Income Taxes & Other Liabilities
Deferred income taxes	595.4		(16.9		)	—			578.5
Regulatory liabilities	362.2		2.0			—			364.2
Deferred credits & other liabilities	78.9		1.4			(6.4		)	73.9
Total deferred credits & other liabilities	1,036.5		(13.5		)	(6.4		)	1,016.6
Common Shareholder's Equity
Common stock (no par value)	787.8		781.6			(787.8		)	781.6
Retained earnings	541.4		608.4			(541.4		)	608.4
Total common shareholder's equity	1,329.2		1,390.0			(1,329.2		)	1,390.0
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,878.7	$	2,334.0		$	(2,165.9	)	$	4,046.8

Condensed Consolidating Statement of Income for the three months endedJune 30, 2013 (in millions):

	Subsidiary Guarantors		Parent Company		Eliminations & Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	138.0	$	—	$	—		$	138.0
Electric utility	154.7		—		—			154.7
Other	—		9.5		(9.4		)	0.1
Total operating revenues	292.7		9.5		(9.4		)	292.8
OPERATING EXPENSES
Cost of gas sold	50.7		—		—			50.7
Cost of fuel & purchased power	53.9		—		—			53.9
Other operating	85.2		—		(9.1		)	76.1
Depreciation & amortization	43.3		5.3		0.1			48.7
Taxes other than income taxes	11.8		0.4		—			12.2
Total operating expenses	244.9		5.7		(9.0		)	241.6
OPERATING INCOME	47.8		3.8		(0.4		)	51.2
Other income - net	1.8		9.1		(7.9		)	3.0
Interest expense	13.8		10.2		(8.3		)	15.7
INCOME BEFORE INCOME TAXES	35.8		2.7		—			38.5
Income taxes	14.0		0.3		—			14.3
Equity in earnings of consolidated companies, net of tax	—		21.8		(21.8		)	—
NET INCOME	$	21.8	$	24.2	$	(21.8	)	$	24.2

Condensed Consolidating Statement of Income for the three months endedJune 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 - 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 six months endedJune 30, 2013 (in millions):

	Subsidiary Guarantors	Parent Company		Eliminations & Reclassifications		Consolidated
OPERATING REVENUES
Gas utility	453.9	—		—		453.9
Electric utility	304.2	—		—		304.2
Other	—	19.0		(18.8	)	0.2
Total operating revenues	758.1	19.0		(18.8	)	758.3
OPERATING EXPENSES
Cost of gas sold	207.9	—		—		207.9
Cost of fuel & purchased power	104.1	—		—		104.1
Other operating	181.2	—		(18.3	)	162.9
Depreciation & amortization	86.4	10.5		0.2		97.1
Taxes other than income taxes	28.9	0.8		—		29.7
Total operating expenses	608.5	11.3		(18.1	)	601.7
OPERATING INCOME	149.6	7.7		(0.7	)	156.6
Other income - net	3.7	18.8		(17.7	)	4.8
Interest expense	30.0	22.0		(18.4	)	33.6
INCOME BEFORE INCOME TAXES	123.3	4.5		—		127.8
Income taxes	48.8	(0.3	)	—		48.5
Equity in earnings of consolidated companies, net of tax	—	74.5		(74.5	)	—
NET INCOME	74.5	79.3		(74.5	)	79.3

Condensed Consolidating Statement of Income for the six months endedJune 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 - 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 Cash Flows for the six months endedJune 30, 2013 (in millions):

	Subsidiary Guarantors			Parent Company			Eliminations			Consolidated
NET CASH PROVIDED BY OPERATING ACTIVITIES	$	199.1		$	(2.0	)	$	—		$	197.1
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from
Long-term debt - net of issuance costs	60.0			124.4			(62.1		)	122.3
Additional capital contribution from parent	10.0			3.0			(10.0		)	3.0
Requirements for:
Dividends to parent	(49.0		)	(52.6		)	49.0			(52.6		)
Retirement of long term debt	(174.8		)	(121.6		)	120.7			(175.7		)
Net change in intercompany short-term borrowings	49.0			—			(49.0		)	—
Net change in short-term borrowings	—			7.3			—			7.3
Net cash used in financing activities	(104.8		)	(39.5		)	48.6			(95.7		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from
Consolidated subsidiary distributions	—			49.0			(49.0		)	—
Other investing activities	—			0.1			—			0.1
Requirements for:
Capital expenditures, excluding AFUDC equity	(103.3		)	(7.6		)	—			(110.9		)
Consolidated subsidiary investments	—			(10.0		)	10.0			—
Net change in long-term intercompany notes receivable	—			58.6			(58.6		)	—
Net change in short-term intercompany notes receivable	—			(49.0		)	49.0			—
Net cash used in investing activities	(103.3		)	41.1			(48.6		)	(110.8		)
Net change in cash & cash equivalents	(9.0		)	(0.4		)	—			(9.4		)
Cash & cash equivalents at beginning of period	12.5			0.8			—			13.3
Cash & cash equivalents at end of period	$	3.5		$	0.4		$	—		$	3.9

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

	Subsidiary Guarantors			Parent Company			Eliminations			Consolidated
NET CASH PROVIDED BY OPERATING ACTIVITIES	$	233.3		$	15.7		$	—		$	249.0
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Additional capital contribution to 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 used in 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 used in 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

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Transactions with Other Vectren Companies and Affiliates

6 Months Ended

Jun. 30, 2013

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)

Vectren Fuels, 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, 2013 and 2012 totaled $31.7 million and $33.3 million, respectively, and for the six months endedJune 30, 2013 and 2012 totaled $51.6 million and $58.2 million, respectively.  Amounts owed to Vectren Fuels at June 30, 2013 and December 31, 2012 are included in Payables to other Vectren companies in the Condensed Consolidated Balance Sheets.

Miller Pipeline, LLC (Miller)

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 $12.8 million and $11.5 million for the three months ended June 30, 2013 and 2012, respectively, and for the six months endedJune 30, 2013 and 2012 totaled $23.2 million and $19.6 million, respectively.  Amounts owed to Miller at June 30, 2013 and December 31, 2012 are included in Payables to other Vectren companies in the Condensed Consolidated Balance Sheets.

Minnesota Limited, LLC (Minnesota Limited)

Minnesota Limited, a wholly owned subsidiary of Vectren, provides transmission pipeline construction and maintenance; pump station, compressor station, terminal and refinery construction; and hydrostatic testing to customers generally in the northern Midwest region. Minnesota Limited's customers include Utility Holdings' utilities. Fees incurred by Utility Holdings and its subsidiaries were insignificant for the three months and six months endedJune 30, 2013 and 2012.

ProLiance Holdings, LLC (ProLiance)

Vectren has an investment in ProLiance, a nonutility affiliate of Vectren and Citizens Energy Group (Citizens). On June 18, 2013, ProLiance exited the natural gas marketing business through the disposition of certain of the net assets of its energy marketing business, ProLiance Energy, LLC (ProLiance Energy). ProLiance Energy provided services to a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions located throughout the Midwest and Southeast United States.  ProLiance Energy’s customers included, among others, Vectren’s Indiana utilities as well as Citizens’ utilities. 

Purchases from ProLiance for resale and for injections into storage for the three months ended June 30, 2013 and 2012 totaled $92.9 million and $50.2 million, respectively and for the six months endedJune 30, 2013 and 2012 totaled $200.5 million and $129.7 million, respectively.  The Company did not have any amounts owed to ProLiance for those purchases at June 30, 2013 and amounts owed to ProLiance at December 31, 2012 were $29.7 million and are included in Accounts payable to affiliated companies in the Condensed Consolidated Balance Sheets.  

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 each of the three months ended June 30, 2013 and 2012, Utility Holdings received corporate allocations totaling $11.4 million. For the six months ending June 30, 2013 and 2012, Utility Holdings received corporate allocations totaling $26.3 million and $23.9 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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Excise and Utility Receipts Taxes

6 Months Ended

Jun. 30, 2013

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 $5.4 million and $5.0 million in the three months ended June 30, 2013 and 2012, respectively. For the six months endedJune 30, 2013 and 2012, these taxes totaled $16.1 million and $14.3 million, respectively.  Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.

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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, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012	Dec. 31, 2012
Vectren Fuels Inc. [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Expenses from transactions with related party	$ 31.7	$ 33.3	$ 51.6	$ 58.2
Miller Pipeline LLC [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Expenses from transactions with related party	12.8	11.5	23.2	19.6
ProLiance [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Expenses from transactions with related party	92.9	50.2	200.5	129.7
Amounts owed to ProLiance for those purchases					29.7
Date equity method investment disposed of a group of assets			Jun. 18, 2013
Support Services & Purchases [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Cost of corporate and general and administrative services	$ 11.4	$ 11.4	$ 26.3	$ 23.9

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Fair Value Measurements (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2012	Dec. 31, 2011
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Period over which call premium on reacquisition of long-term debt	15
Long-term Debt - Net of Current Maturities And Debt Subject to Tender	$ 1,057.8	$ 1,103.4
Short-term borrowings	124.0	116.7
Cash and Cash Equivalents, at Carrying Value	3.9	13.3	4.1	6.0
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	1,157.8	1,208.4
Short-term Borrowings	124.0	116.7
Cash and cash equivalents	3.9	13.3
Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	1,259.1	1,372.6
Short-term Borrowings	124.0	116.7
Cash and cash equivalents	$ 3.9	$ 13.3

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CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited) (Parenthetical) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Assets, Current [Abstract]
Allowance for Doubtful Accounts Receivable, Current	$ 5.8	$ 5.0

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Rate & Regulatory Matters

6 Months Ended

Jun. 30, 2013

Rate and Regulatory Matters [Abstract]

Rate and Regulatory Matters

Rate & Regulatory Matters

Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement

The Company monitors and maintains its natural gas distribution system to ensure that natural gas is delivered in a safe and efficient manner. The Company's natural gas utilities are currently engaged in replacement programs in both Indiana and Ohio, the primary purpose of which is preventive maintenance and continual renewal and operational improvement. Laws in both Indiana and Ohio were passed that expand the ability of utilities to recover certain costs of federally mandated projects and other infrastructure improvement projects, outside of a base rate proceeding.  Utilization of these recovery mechanisms is discussed below.

Ohio Recovery and Deferral Mechanisms

The PUCO order approving the Company's 2009 base rate case in the Ohio service territory authorized a distribution replacement rider (DRR). The DRR's primary purpose is recovery of investments in utility plant and related operating expenses associated with replacing bare steel and cast iron pipelines and certain other infrastructure. This rider is updated annually for qualifying capital expenditures and allows for a return to be earned on those capital expenditures based on the rate of return approved in the 2009 base rate case. In addition, deferral of depreciation and the ability to accrue debt-related post in service carrying costs is also allowed until the related capital expenditures are recovered through the DRR. The order also established a prospective bill impact evaluation on the annual deferrals, limiting the deferrals at a level which would equal a change over the prior year rate of $1.00 per residential and general service customer per month. To date, the Company has made capital investments under this rider totaling $94 million. Regulatory assets associated with post in service carrying costs and depreciation deferrals were $7.9 million and $6.5 million at June 30, 2013 and December 31, 2012, respectively. The DRR's initial five year term expires in early 2014. The Company filed in July 2013 a notice that it will request to extend the term of the DRR.

In June 2011, Ohio House Bill 95 was signed into law. Outside of a base rate proceeding, this legislation permits a natural gas company to apply for recovery of much of its capital expenditure program. The legislation also allows for the deferral of costs, such as depreciation, property taxes, and debt-related post in service carrying costs. On December 31, 2012, the PUCO issued an order approving the Company's initial application using this law, reflecting its $23.5 million capital expenditure program covering the fifteen month period ending December 31, 2012. Such capital expenditures include infrastructure expansion and improvements not covered by the DRR as well as expenditures necessary to comply with PUCO rules, regulations, orders, and system expansion to some new customers. The order also established a prospective bill impact evaluation on the cumulative deferrals, limiting the total deferrals at a level which would equal $1.50 per residential and general service customer per month. The Company will file annually for the accounting treatment described above for its annual capital expenditure program. Included in the notice filed in July 2013, the Company indicated an application will be filed in the near term seeking authority to expand the DRR to include recovery of other infrastructure investments to improve the reliability of its system.

Indiana Recovery and Deferral Mechanisms

The Company's Indiana natural gas utilities received orders in 2008 and 2007 associated with the most recent base rate cases. These orders authorized the deferral of financial impacts associated with bare steel and cast iron replacement activities. The orders provide for the deferral of depreciation and post in service carrying costs on qualifying projects totaling $20 million annually at Vectren North and $3 million annually at Vectren South. The debt-related post in service carrying costs are recognized in the Condensed Consolidated Statements of Income currently. Such deferral is limited by individual qualifying project to three years after being placed into service at Vectren South and four years after being placed into service at Vectren North.

In April 2011, Senate Bill 251 was signed into Indiana law. The law 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 a return on the federally mandated capital investment, along with recovery of depreciation and other operating costs associated with these mandates. The remaining 20 percent of those costs are to be deferred for future recovery in the utility's next general rate case.

In April 2013, Senate Bill 560 was signed into law.  This legislation supplements Senate Bill 251 described above, which addressed federally-mandated investment, provides for cost recovery outside of a base rate proceeding for projects that either improve electric and gas system reliability and safety or are economic development projects that provide rural areas with access to gas service.  Provisions of the legislation require that, among other things, requests for recovery include a seven year project plan.  Once the plan is approved by the IURC, 80 percent of such costs are eligible for recovery using a periodic rate adjustment mechanism.  Recoverable costs include a return on and of the investment, as well as property taxes and operating expenses.  The remaining 20 percent of project costs are to be deferred for future recovery in the Company's next general rate case.  The adjustment mechanism is capped at an annual increase in retail revenues of no more than two percent.

Pipeline Safety Law

On January 3, 2012, the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (Pipeline Safety Law) was signed into law. The Pipeline Safety 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 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 over the next two years. Those regulations may eventually lead to further regulatory or statutory requirements.

The Company continues to study the impact of the Pipeline Safety 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 law is expected to result in further investment in pipeline inspections, and where necessary, additional investments in 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 by approximately $9 million annually, with $6 million attributable to the Indiana operations.

Vectren North Pipeline Safety Investigation

On April 11, 2012, the IURC's pipeline safety division filed a complaint against Vectren North alleging several violations of safety regulations pertaining to damage that occurred at a residence in Vectren North's service territory during a pipeline replacement project. The Company negotiated a settlement with the IURC's pipeline safety division, agreeing to a fine and several modifications to the Company's operating policies. The amount of the fine was not material to the Company's financial results. The IURC approved the settlement but modified certain terms of the settlement and added a requirement that Company employees conduct inspections of pipeline excavations. The Company sought and was granted a request for rehearing on the sole issue related to the requirement to use Company employees to inspect excavations. The Company seeks further clarity on the scope of the requirement and the ability to also use contractors to perform certain inspections. The Company submitted testimony in the case in April 2013. A hearing will be conducted in November 2013.

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CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (Unaudited) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
CASH FLOWS FROM OPERATING ACTIVITIES [Abstract]
Profitability Measure - Net income (loss)	$ 79.3	$ 76.1
Adjustments to Reconcile Net Income to Cash from Operating Activities [Abstract]
Depreciation & Amortization	97.1	96.4
Deferred income taxes & investment tax credits	16.5	21.9
Expense portion of pension & postretirement periodic benefit cost	2.7	2.5
Provision for uncollectible accounts	3.9	3.9
Other non-cash expense - net	2.9	4.7
Changes in working capital accounts [Abstract]
Accounts receivable & accrued unbilled revenue	56.1	90.7
Inventories	22.3	3.2
Recoverable/refundable fuel & natural gas costs	6.7	2.8
Prepayments & other current assets	6.7	29.6
Accounts payable, including to Vectren companies & affiliated companies	(88.0)	(67.2)
Accrued liabilities	(6.4)	(2.8)
Changes in noncurrent ssets	(0.6)	0.2
Changes in noncurrent liabilities	(2.1)	(13.0)
Net cash provided by operating activities	197.1	249.0
Proceeds from:
Long-term debt - net of issuance costs	122.3	99.5
Additional capital contribution	3.0	3.5
Requirements for:
Dividends to parent	(52.6)	(50.5)
Repayments of Long-term Debt	(175.7)	0
Other financing activities	0	0
Net change in short-term borrowings	7.3	(181.3)
Net cash used in financing activities	(95.7)	(128.8)
CASH FLOWS FROM INVESTING ACTIVITIES [Abstract]
Proceeds from other investing activities	0.1	2.2
Requirements for:
Capital expenditures, excluding AFUDC equity	(110.9)	(124.1)
Other investments	0	(0.2)
Net cash used in investing activities	(110.8)	(122.1)
Net change in cash and cash equivalents	(9.4)	(1.9)
Cash and cash equivalents at beginning of period	13.3	6.0
Cash and cash equivalents at end of period	$ 3.9	$ 4.1

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CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Assets, Current [Abstract]
Cash & cash equivalents	$ 3.9	$ 13.3
Accounts receivable - less reserves of $5.8 & $5.0, respectively	72.9	81.8
Receivables due from other Vectren companies	6.9	0
Accrued unbilled revenues	35.7	93.6
Inventories	91.7	114.0
Recoverable fuel & natural gas costs	18.6	25.3
Prepayments & other current assets	45.8	52.3
Total current assets	275.5	380.3
Utility Plant [Abstract]
Original cost	5,265.0	5,176.8
Less: accumulated depreciation & amortization	2,104.4	2,057.2
Net utility plant	3,160.6	3,119.6
Investments in unconsolidated affiliates	0.2	0.2
Other investments	33.5	32.6
Nonutility plant - net	142.1	146.9
Goodwill - net	205.0	205.0
Regulatory assets	126.9	126.5
Other assets	29.4	35.7
TOTAL ASSETS	3,973.2	4,046.8
Current Liabilities [Abstract]
Accounts payable	67.1	121.0
Accounts payable to affiliated companies	0	29.7
Payables to other Vectren companies	27.6	25.1
Accrued liabilities	122.2	139.3
Short-term borrowings	124.0	116.7
Current maturities of long-term debt	100.0	105.0
Total current liabilities	440.9	536.8
Long-term Debt - Net of Current Maturities	1,057.8	1,103.4
Deferred Income Taxes & Other Liabilities [Abstract]
Deferred income taxes	600.4	578.5
Regulatory liabilities	376.4	364.2
Deferred credits & other liabilities	78.0	73.9
Total deferred credits and other liabilities	1,054.8	1,016.6
Commitments & Contingencies (Notes 8 - 10)
Common Shareholder's Equity [Abstract]
Common stock (no par value)	784.6	781.6
Retained earnings	635.1	608.4
Total common shareholders' equity	1,419.7	1,390.0
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	$ 3,973.2	$ 4,046.8

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Financing Activities (Details) (USD $) In Millions, unless otherwise specified			6 Months Ended
	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2013 Vectren Utility Holdings Inc [Member] Unsecured Debt [Member] FixedRateSeniorGuaranteedNotes2028320 [Member]	Jun. 30, 2013 Vectren Utility Holdings Inc [Member] Unsecured Debt [Member] FixedRateSeniorGuaranteedNotes2043425 [Member]	Jun. 30, 2013 Vectren Utility Holdings Inc [Member] Unsecured Debt [Member] Fixed Rate Senior Unsecured Notes 2039625 [Member]	Jun. 30, 2013 Vectren Utility Holdings Inc [Member] Unsecured Debt [Member] Fixed Rate Senior Unsecure Notes 2023372 [Member]	Jun. 30, 2013 Vectren Utility Holdings Inc [Member] Unsecured Debt [Member] Fixed Rate Senior Unsecured Notes 2013525 [Member]	Jun. 30, 2013 SIGECO [Member] First Mortgage Bonds [Member]	Jun. 30, 2013 SIGECO [Member] First Mortgage Bonds [Member] Tax Exempt Debt, 4.00%, due 2038 [Member]	Jun. 30, 2013 SIGECO [Member] First Mortgage Bonds [Member] Tax Exempt Debt, 4.05%, due 2043 [Member]
Debt Instrument [Line Items]
Debt redemption date					Apr. 01, 2013
Face amount			$ 45.0	$ 80.0	$ 121.6	$ 150.0		$ 62.0	$ 22.2	$ 39.6
Long-term Debt, Current Maturities	100.0	105.0			121.6
Stated percentage rate (in hundredths)			3.20%	4.25%	6.25%	3.72%	5.25%		4.00%	4.05%
Maturity date			Jun. 05, 2028	Jun. 05, 2043		Dec. 05, 2023	Aug. 01, 2013
Maturity date year					2039				2038	2043
Issuance date			Jun. 05, 2013	Jun. 05, 2013		Dec. 05, 2013			Apr. 26, 2013	Apr. 26, 2013
Proceeds from Issuance of Debt								60.0
Amount of debt to be re-marketed								49.0
Debt re-market date								third quarter of 2013
Debt Instrument, Offering Date						Jul. 25, 2013
Current portion of long-term debt that will either be refinanced or retired							$ 100.0

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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, 2013	Dec. 31, 2012	Jun. 30, 2012	Dec. 31, 2011
ASSETS
Cash & cash equivalents	$ 3.9	$ 13.3	$ 4.1	$ 6.0
Accounts receivable - less reserves	72.9	81.8
Receivables due from other Vectren companies	6.9	0
Accrued unbilled revenues	35.7	93.6
Inventories	91.7	114.0
Recoverable fuel & natural gas costs	18.6	25.3
Prepayments & other current assets	45.8	52.3
Total current assets	275.5	380.3
Original cost	5,265.0	5,176.8
Less: accumulated depreciation & amortization	2,104.4	2,057.2
Net utility plant	3,160.6	3,119.6
Investments in unconsolidated affiliates	0.2	0.2
Other investments	33.5	32.6
Nonutility property - net	142.1	146.9
Goodwill - net	205.0	205.0
Regulatory assets	126.9	126.5
Other assets	29.4	35.7
TOTAL ASSETS	3,973.2	4,046.8
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	67.1	121.0
Accounts payable to affiliated companies	0	29.7
Payables to other Vectren companies	27.6	25.1
Accrued liabilities	122.2	139.3
Short-term borrowings	124.0	116.7
Current maturities of long-term debt	100.0	105.0
Total current liabilities	440.9	536.8
Long-term Debt - Net of Current Maturities	1,057.8	1,103.4
Deferred income taxes	600.4	578.5
Regulatory liabilities	376.4	364.2
Deferred Credits and Other Liabilities	78.0	73.9
Total deferred credits and other liabilities	1,054.8	1,016.6
Common stock (no par value)	784.6	781.6
Retained earnings	635.1	608.4
Total common shareholders' equity	1,419.7	1,390.0
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	3,973.2	4,046.8
Line of Credit Facility, Maximum Borrowing Capacity	350
Subsidiary Ownership Percentage	100.00%
Subsidiary Guarantors [Member]
ASSETS
Cash & cash equivalents	3.5	12.5	2.7	5.3
Accounts receivable - less reserves	72.9	81.8
Intercompany Receivables	1.7	0
Receivables due from other Vectren companies	0
Accrued unbilled revenues	35.7	93.6
Inventories	91.8	114.0
Recoverable fuel & natural gas costs	18.6	25.3
Prepayments & other current assets	41.5	52.0
Total current assets	265.7	379.2
Original cost	5,265.0	5,176.6
Less: accumulated depreciation & amortization	2,104.4	2,057.2
Net utility plant	3,160.6	3,119.4
Investments in consolidated subsidiaries	0	0
Notes receivable from consolidated subsidiaries	0	0
Investments in unconsolidated affiliates	0.2	0.2
Other investments	28.9	27.8
Nonutility property - net	2.4	2.6
Goodwill - net	205.0	205.0
Regulatory assets	104.5	104.1
Other assets	35.3	40.4
TOTAL ASSETS	3,802.6	3,878.7
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	62.7	114.8
Intercompany Payables	10.6	10.6
Accounts payable to affiliated companies		29.7
Payables to other Vectren companies	25.6	25.1
Accrued liabilities	132.4	131.3
Short-term borrowings	0	0
Intercompany short-term borrowings	183.6	134.5
Current maturities of long-term debt	0	5.0
Total current liabilities	414.9	451.0
Long-term Debt - Net of Current Maturities	382.3	382.3
Long-term debt due to VUHI	572.1	679.7
Total long-term debt - net	954.4	1,062.0
Deferred income taxes	610.9	595.4
Regulatory liabilities	374.7	362.2
Deferred Credits and Other Liabilities	83.0	78.9
Total deferred credits and other liabilities	1,068.6	1,036.5
Common stock (no par value)	797.8	787.8
Retained earnings	566.9	541.4
Total common shareholders' equity	1,364.7	1,329.2
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	3,802.6	3,878.7
Parent Company [Member]
ASSETS
Cash & cash equivalents	0.4	0.8	1.4	0.7
Accounts receivable - less reserves	0	0
Intercompany Receivables	192.5	145.1
Receivables due from other Vectren companies	6.9
Accrued unbilled revenues	0	0
Inventories	(0.1)	0
Recoverable fuel & natural gas costs	0	0
Prepayments & other current assets	76.4	5.8
Total current assets	276.1	151.7
Original cost	0	0.2
Less: accumulated depreciation & amortization	0	0
Net utility plant	0	0.2
Investments in consolidated subsidiaries	1,364.7	1,329.2
Notes receivable from consolidated subsidiaries	572.1	679.7
Investments in unconsolidated affiliates	0	0
Other investments	4.6	4.8
Nonutility property - net	139.7	144.3
Goodwill - net	0	0
Regulatory assets	22.4	22.4
Other assets	1.3	1.7
TOTAL ASSETS	2,380.9	2,334.0
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	4.4	6.2
Intercompany Payables	0	0
Accounts payable to affiliated companies		0
Payables to other Vectren companies	2.0	0
Accrued liabilities	12.8	13.5
Short-term borrowings	124.0	116.7
Intercompany short-term borrowings	0	0
Current maturities of long-term debt	100.0	100.0
Total current liabilities	243.2	236.4
Long-term Debt - Net of Current Maturities	724.6	721.1
Long-term debt due to VUHI	0	0
Total long-term debt - net	724.6	721.1
Deferred income taxes	(10.5)	(16.9)
Regulatory liabilities	1.7	2.0
Deferred Credits and Other Liabilities	2.2	1.4
Total deferred credits and other liabilities	(6.6)	(13.5)
Common stock (no par value)	784.6	781.6
Retained earnings	635.1	608.4
Total common shareholders' equity	1,419.7	1,390.0
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	2,380.9	2,334.0
Line of Credit Facility, Amount Outstanding	124
Unsecured Debt	825
Consolidation, Eliminations [Member]
ASSETS
Cash & cash equivalents	0	0	0	0
Accounts receivable - less reserves	0	0
Intercompany Receivables	(194.2)	(145.1)
Receivables due from other Vectren companies	0
Accrued unbilled revenues	0	0
Inventories	0	0
Recoverable fuel & natural gas costs	0	0
Prepayments & other current assets	(72.1)	(5.5)
Total current assets	(266.3)	(150.6)
Original cost	0	0
Less: accumulated depreciation & amortization	0	0
Net utility plant	0	0
Investments in consolidated subsidiaries	(1,364.7)	(1,329.2)
Notes receivable from consolidated subsidiaries	(572.1)	(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	(7.2)	(6.4)
TOTAL ASSETS	(2,210.3)	(2,165.9)
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	0	0
Intercompany Payables	(10.6)	(10.6)
Accounts payable to affiliated companies		0
Payables to other Vectren companies	0	0
Accrued liabilities	(23.0)	(5.5)
Short-term borrowings	0	0
Intercompany short-term borrowings	(183.6)	(134.5)
Current maturities of long-term debt	0	0
Total current liabilities	(217.2)	(150.6)
Long-term Debt - Net of Current Maturities	(49.1)	0
Long-term debt due to VUHI	(572.1)	(679.7)
Total long-term debt - net	(621.2)	(679.7)
Deferred income taxes	0	0
Regulatory liabilities	0	0
Deferred Credits and Other Liabilities	(7.2)	(6.4)
Total deferred credits and other liabilities	(7.2)	(6.4)
Common stock (no par value)	(797.8)	(787.8)
Retained earnings	(566.9)	(541.4)
Total common shareholders' equity	(1,364.7)	(1,329.2)
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	(2,210.3)	(2,165.9)
Consolidated Entities [Member]
ASSETS
Cash & cash equivalents	3.9	13.3	4.1	6.0
Accounts receivable - less reserves	72.9	81.8
Intercompany Receivables	0	0
Receivables due from other Vectren companies	6.9
Accrued unbilled revenues	35.7	93.6
Inventories	91.7	114.0
Recoverable fuel & natural gas costs	18.6	25.3
Prepayments & other current assets	45.8	52.3
Total current assets	275.5	380.3
Original cost	5,265.0	5,176.8
Less: accumulated depreciation & amortization	2,104.4	2,057.2
Net utility plant	3,160.6	3,119.6
Investments in consolidated subsidiaries	0	0
Notes receivable from consolidated subsidiaries	0	0
Investments in unconsolidated affiliates	0.2	0.2
Other investments	33.5	32.6
Nonutility property - net	142.1	146.9
Goodwill - net	205.0	205.0
Regulatory assets	126.9	126.5
Other assets	29.4	35.7
TOTAL ASSETS	3,973.2	4,046.8
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	67.1	121.0
Intercompany Payables	0	0
Accounts payable to affiliated companies		29.7
Payables to other Vectren companies	27.6	25.1
Accrued liabilities	122.2	139.3
Short-term borrowings	124.0	116.7
Intercompany short-term borrowings	0	0
Current maturities of long-term debt	100.0	105.0
Total current liabilities	440.9	536.8
Long-term Debt - Net of Current Maturities	1,057.8	1,103.4
Long-term debt due to VUHI	0	0
Total long-term debt - net	1,057.8	1,103.4
Deferred income taxes	600.4	578.5
Regulatory liabilities	376.4	364.2
Deferred Credits and Other Liabilities	78.0	73.9
Total deferred credits and other liabilities	1,054.8	1,016.6
Common stock (no par value)	784.6	781.6
Retained earnings	635.1	608.4
Total common shareholders' equity	1,419.7	1,390.0
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	$ 3,973.2	$ 4,046.8

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2013

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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Rate & Regulatory Matters (Details) (USD $)	6 Months Ended
	Jun. 30, 2013	Dec. 31, 2012
Pipeline Safety Law [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Estimated amount of operating expenses that could accumulate associated with expanded compliance requirements	$ 9,000,000
Indiana [Member] | Indiana Recovery and Deferral Mechanisms [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Allowable capital expenditures under Vectren North Program	20,000,000
Allowable expenditures under Vectren South program	3,000,000
Indiana [Member] | Senate Bill 251 [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Description of Legislation - Senate Bill 560	n April 2011, Senate Bill 251 was signed into Indiana law. The law 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 a return on the federally mandated capital investment, along with recovery of depreciation and other operating costs associated with these mandates. The remaining 20 percent of those costs are to be deferred for future recovery in the utility's next general rate case.
Indiana [Member] | Pipeline Safety Law [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Estimated amount of operating expenses that could accumulate associated with expanded compliance requirements	6,000,000
Indiana [Member] | Indiana Senate Bill 560 [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Additional legislation surrounding rate approval	In April 2013, Senate Bill 560 was signed into law.  This legislation supplements Senate Bill 251 described above, which addressed federally-mandated investment, provides for cost recovery outside of a base rate proceeding for projects that either improve electric and gas system reliability and safety or are economic development projects that provide rural areas with access to gas service.  Provisions of the legislation require that, among other things, requests for recovery include a seven year project plan.
Percentage of costs eligible for recovery using periodic rate recovery mechanism	80.00%
Percentage of project costs to be deferred for future recovery	20.00%
Adjustment mechanism cap % based on annual retail revenue increase	2.00%
Indiana [Member] | SIGECO [Member] | Indiana Recovery and Deferral Mechanisms [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Limitations of deferrals of debt-related post in service carrying costs	3
Indiana [Member] | Indiana Gas [Member] | Indiana Recovery and Deferral Mechanisms [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Limitations of deferrals of debt-related post in service carrying costs	4
Ohio [Member] | Ohio DRR [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Cumulative gross plant invesment made under Distribution Replacement Rider	94,000,000
Regulatory Asset associated with DRR deferrals of depreciation and post in-service carrying costs	7,900,000	6,500,000
Bill impact per customer per month	1.00
Initial DRR term	5
Ohio [Member] | Ohio House Bill 95 [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Bill impact per customer per month	1.50
Estimated budget related to Ohio capital expenditure program	$ 23,500,000
Time period (in months) included in VEDO application	15

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Fair Value Measurements

6 Months Ended

Jun. 30, 2013

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, 2013				December 31, 2012
(In millions)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	1,157.8	$	1,259.1	$	1,208.4	$	1,372.6
Short-term borrowings	124.0		124.0		116.7		116.7
Cash & cash equivalents	3.9		3.9		13.3		13.3

For the balance sheet dates presented in these financial statements, the Company had no material assets or liabilities marked to fair value.

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 of this debt would not be expected to have a material effect on the Company's results of operations.

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Financing Activities

6 Months Ended

Jun. 30, 2013

Debt Disclosure [Abstract]

Financing Activities

Financing Activities

SIGECO 2013 Debt Refund and Reissuance

During the second quarterof 2013, approximately $111 million of SIGECO's tax-exempt long-term debt was redeemed at par plus accrued interest. Approximately $62 million of tax-exempt long-term debt was reissued on April 26, 2013 at interest rates that are fixed to maturity, receiving proceeds, net of issuance costs, of approximately $60 million. The terms are $22.2 million at 4.00 percent per annum due in 2038, and $39.6 million at 4.05 percent per annum due in 2043. The remaining approximately $49 million of the called debt is held by Utility Holdings and planned for remarketing in the third quarter of 2013, and is treated as extinguished in the consolidated financial statements as of June 30, 2013.

Utility Holdings Debt Transactions

On April 1, 2013, the Company executed an early redemption at par of $121.6 million6.25 percent senior unsecured notes due in 2039. This debt was refinanced on June 5, 2013, with proceeds from a private placement note purchase agreement entered into on December 20, 2012 with a delayed draw feature. It provides for the following tranches of notes:  (i) $45 million3.20 percent senior guaranteed notes, due June 5, 2028 and (ii) $80 million4.25 percent senior guaranteed notes, due June 5, 2043.  The notes are unconditionally guaranteed by Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company and Vectren Energy Delivery of Ohio, Inc.

On July 25, 2013, VUHI announced that it priced $150 million10-year senior unsecured notes. The notes were sold to various institutional investors through the private placement market and included a delayed draw feature. VUHI will issue $150 million of 3.72 percent senior notes due December 5, 2023. The proceeds received from the issuance of the senior notes will be used to refinance $100 million of existing 5.25 percent senior notes that mature August 1, 2013, for capital expenditures, and for general corporate purposes. Subject to the satisfaction of customary conditions precedent, the notes will be funded on or about December 5, 2013, as a result of the delayed draw feature. As of June 30, 2013 the $100 million was classified as Current maturities of long-term debt.

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Basis of Presentation

6 Months Ended

Jun. 30, 2013

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, 2012, filed with the Securities and Exchange Commission on March 1, 2013, 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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Segment Reporting (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Segment Reporting Information [Line Items]
Portion of Indiana that is provided natural gas distribution and transportation services by the Gas Utility Services segment (in hundredths)	66.66667%		66.66667%
Revenues	$ 292.8	$ 265.8	$ 758.3	$ 697.9
Profitability Measure - Net income (loss)	24.2	20.1	79.3	76.1
Utility Group [Member]
Segment Reporting Information [Line Items]
Number of Reportable Segments			3
Utility Group [Member] | Gas Utility Services [Member]
Segment Reporting Information [Line Items]
Revenues	138.0	116.0	453.9	408.3
Profitability Measure - Net income (loss)	2.9	1.3	41.0	38.8
Utility Group [Member] | Electric Utility Services [Member]
Segment Reporting Information [Line Items]
Revenues	154.7	149.3	304.2	288.7
Profitability Measure - Net income (loss)	18.9	17.2	33.5	32.8
Utility Group [Member] | Other Operations [Member]
Segment Reporting Information [Line Items]
Revenues	142.0	10.0	151.5	19.9
Profitability Measure - Net income (loss)	2.4	1.6	4.8	4.5
Utility Group [Member] | Group Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	$ (141.9)	$ (9.5)	$ (151.3)	$ (19.0)

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

6 Months Ended

Jun. 30, 2013

Condensed Financial Information of Parent Company and Subsidiaries [Abstract]

Condensed consolidating balance sheets [Table Text Block]

Condensed Consolidating Balance Sheet as of June 30, 2013 (in millions):

ASSETS	Subsidiary		Parent			Eliminations &
	Guarantors		Company			Reclassifications			Consolidated
Current Assets
Cash & cash equivalents	$	3.5	$	0.4		$	—		$	3.9
Accounts receivable - less reserves	72.9		—			—			72.9
Intercompany receivables	1.7		192.5			(194.2		)	—
Receivables due from other Vectren companies	—		6.9			—			6.9
Accrued unbilled revenues	35.7		—			—			35.7
Inventories	91.8		(0.1		)	—			91.7
Recoverable fuel & natural gas costs	18.6		—			—			18.6
Prepayments & other current assets	41.5		76.4			(72.1		)	45.8
Total current assets	265.7		276.1			(266.3		)	275.5
Utility Plant
Original cost	5,265.0		—			—			5,265.0
Less:  accumulated depreciation & amortization	2,104.4		—			—			2,104.4
Net utility plant	3,160.6		—			—			3,160.6
Investments in consolidated subsidiaries	—		1,364.7			(1,364.7		)	—
Notes receivable from consolidated subsidiaries	—		572.1			(572.1		)	—
Investments in unconsolidated affiliates	0.2		—			—			0.2
Other investments	28.9		4.6			—			33.5
Nonutility property - net	2.4		139.7			—			142.1
Goodwill - net	205.0		—			—			205.0
Regulatory assets	104.5		22.4			—			126.9
Other assets	35.3		1.3			(7.2		)	29.4
TOTAL ASSETS	$	3,802.6	$	2,380.9		$	(2,210.3	)	$	3,973.2
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent			Eliminations &
	Guarantors		Company			Reclassifications			Consolidated
Current Liabilities
Accounts payable	$	62.7	$	4.4		$	—		$	67.1
Intercompany payables	10.6		—			(10.6		)	—
Payables to other Vectren companies	25.6		2.0			—			27.6
Accrued liabilities	132.4		12.8			(23.0		)	122.2
Short-term borrowings	—		124.0			—			124.0
Intercompany short-term borrowings	183.6		—			(183.6		)	—
Current maturities of long-term debt	—		100.0			—			100.0
Total current liabilities	414.9		243.2			(217.2		)	440.9
Long-Term Debt
Long-term debt - net of current maturities	382.3		724.6			(49.1		)	1,057.8
Long-term debt due to VUHI	572.1		—			(572.1		)	—
Total long-term debt - net	954.4		724.6			(621.2		)	1,057.8
Deferred Income Taxes & Other Liabilities
Deferred income taxes	610.9		(10.5		)	—			600.4
Regulatory liabilities	374.7		1.7			—			376.4
Deferred credits & other liabilities	83.0		2.2			(7.2		)	78.0
Total deferred credits & other liabilities	1,068.6		(6.6		)	(7.2		)	1,054.8
Common Shareholder's Equity
Common stock (no par value)	797.8		784.6			(797.8		)	784.6
Retained earnings	566.9		635.1			(566.9		)	635.1
Total common shareholder's equity	1,364.7		1,419.7			(1,364.7		)	1,419.7
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,802.6	$	2,380.9		$	(2,210.3	)	$	3,973.2

Condensed Consolidating Balance Sheet as of December 31, 2012 (in millions):

ASSETS	Subsidiary		Parent			Eliminations &
	Guarantors		Company			Reclassifications			Consolidated
Current Assets
Cash & cash equivalents	$	12.5	$	0.8		$	—		$	13.3
Accounts receivable - less reserves	81.8		—			—			81.8
Intercompany receivables	—		145.1			(145.1		)	—
Accrued unbilled revenues	93.6		—			—			93.6
Inventories	114.0		—			—			114.0
Recoverable fuel & natural gas costs	25.3		—			—			25.3
Prepayments & other current assets	52.0		5.8			(5.5		)	52.3
Total current assets	379.2		151.7			(150.6		)	380.3
Utility Plant
Original cost	5,176.6		0.2			—			5,176.8
Less:  accumulated depreciation & amortization	2,057.2		—			—			2,057.2
Net utility plant	3,119.4		0.2			—			3,119.6
Investments in consolidated subsidiaries	—		1,329.2			(1,329.2		)	—
Notes receivable from consolidated subsidiaries	—		679.7			(679.7		)	—
Investments in unconsolidated affiliates	0.2		—			—			0.2
Other investments	27.8		4.8			—			32.6
Nonutility property - net	2.6		144.3			—			146.9
Goodwill - net	205.0		—			—			205.0
Regulatory assets	104.1		22.4			—			126.5
Other assets	40.4		1.7			(6.4		)	35.7
TOTAL ASSETS	$	3,878.7	$	2,334.0		$	(2,165.9	)	$	4,046.8
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent			Eliminations &
	Guarantors		Company			Reclassifications			Consolidated
Current Liabilities
Accounts payable	$	114.8	$	6.2		$	—		$	121.0
Accounts payable to affiliated companies	29.7		—			—			29.7
Intercompany payables	10.6		—			(10.6		)	—
Payables to other Vectren companies	25.1		—			—			25.1
Accrued liabilities	131.3		13.5			(5.5		)	139.3
Short-term borrowings	—		116.7			—			116.7
Intercompany short-term borrowings	134.5		—			(134.5		)	—
Current maturities of long-term debt	5.0		100.0			—			105.0
Total current liabilities	451.0		236.4			(150.6		)	536.8
Long-Term Debt
Long-term debt - net of current maturities	382.3		721.1			—			1,103.4
Long-term debt due to VUHI	679.7		—			(679.7		)	—
Total long-term debt - net	1,062.0		721.1			(679.7		)	1,103.4
Deferred Income Taxes & Other Liabilities
Deferred income taxes	595.4		(16.9		)	—			578.5
Regulatory liabilities	362.2		2.0			—			364.2
Deferred credits & other liabilities	78.9		1.4			(6.4		)	73.9
Total deferred credits & other liabilities	1,036.5		(13.5		)	(6.4		)	1,016.6
Common Shareholder's Equity
Common stock (no par value)	787.8		781.6			(787.8		)	781.6
Retained earnings	541.4		608.4			(541.4		)	608.4
Total common shareholder's equity	1,329.2		1,390.0			(1,329.2		)	1,390.0
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,878.7	$	2,334.0		$	(2,165.9	)	$	4,046.8

Condensed consolidating statements fo income [Table Text Block]

	Subsidiary Guarantors		Parent Company		Eliminations & Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	138.0	$	—	$	—		$	138.0
Electric utility	154.7		—		—			154.7
Other	—		9.5		(9.4		)	0.1
Total operating revenues	292.7		9.5		(9.4		)	292.8
OPERATING EXPENSES
Cost of gas sold	50.7		—		—			50.7
Cost of fuel & purchased power	53.9		—		—			53.9
Other operating	85.2		—		(9.1		)	76.1
Depreciation & amortization	43.3		5.3		0.1			48.7
Taxes other than income taxes	11.8		0.4		—			12.2
Total operating expenses	244.9		5.7		(9.0		)	241.6
OPERATING INCOME	47.8		3.8		(0.4		)	51.2
Other income - net	1.8		9.1		(7.9		)	3.0
Interest expense	13.8		10.2		(8.3		)	15.7
INCOME BEFORE INCOME TAXES	35.8		2.7		—			38.5
Income taxes	14.0		0.3		—			14.3
Equity in earnings of consolidated companies, net of tax	—		21.8		(21.8		)	—
NET INCOME	$	21.8	$	24.2	$	(21.8	)	$	24.2

Condensed Consolidating Statement of Income for the three months endedJune 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 - 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 six months endedJune 30, 2013 (in millions):

	Subsidiary Guarantors	Parent Company		Eliminations & Reclassifications		Consolidated
OPERATING REVENUES
Gas utility	453.9	—		—		453.9
Electric utility	304.2	—		—		304.2
Other	—	19.0		(18.8	)	0.2
Total operating revenues	758.1	19.0		(18.8	)	758.3
OPERATING EXPENSES
Cost of gas sold	207.9	—		—		207.9
Cost of fuel & purchased power	104.1	—		—		104.1
Other operating	181.2	—		(18.3	)	162.9
Depreciation & amortization	86.4	10.5		0.2		97.1
Taxes other than income taxes	28.9	0.8		—		29.7
Total operating expenses	608.5	11.3		(18.1	)	601.7
OPERATING INCOME	149.6	7.7		(0.7	)	156.6
Other income - net	3.7	18.8		(17.7	)	4.8
Interest expense	30.0	22.0		(18.4	)	33.6
INCOME BEFORE INCOME TAXES	123.3	4.5		—		127.8
Income taxes	48.8	(0.3	)	—		48.5
Equity in earnings of consolidated companies, net of tax	—	74.5		(74.5	)	—
NET INCOME	74.5	79.3		(74.5	)	79.3

Condensed Consolidating Statement of Income for the six months endedJune 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 - 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 Cash Flows for the six months endedJune 30, 2013 (in millions):

Condensed consolidating statements of cash flows [Table Text Block]

Condensed Consolidating Statement of Cash Flows for the six months endedJune 30, 2013 (in millions):

	Subsidiary Guarantors			Parent Company			Eliminations			Consolidated
NET CASH PROVIDED BY OPERATING ACTIVITIES	$	199.1		$	(2.0	)	$	—		$	197.1
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from
Long-term debt - net of issuance costs	60.0			124.4			(62.1		)	122.3
Additional capital contribution from parent	10.0			3.0			(10.0		)	3.0
Requirements for:
Dividends to parent	(49.0		)	(52.6		)	49.0			(52.6		)
Retirement of long term debt	(174.8		)	(121.6		)	120.7			(175.7		)
Net change in intercompany short-term borrowings	49.0			—			(49.0		)	—
Net change in short-term borrowings	—			7.3			—			7.3
Net cash used in financing activities	(104.8		)	(39.5		)	48.6			(95.7		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from
Consolidated subsidiary distributions	—			49.0			(49.0		)	—
Other investing activities	—			0.1			—			0.1
Requirements for:
Capital expenditures, excluding AFUDC equity	(103.3		)	(7.6		)	—			(110.9		)
Consolidated subsidiary investments	—			(10.0		)	10.0			—
Net change in long-term intercompany notes receivable	—			58.6			(58.6		)	—
Net change in short-term intercompany notes receivable	—			(49.0		)	49.0			—
Net cash used in investing activities	(103.3		)	41.1			(48.6		)	(110.8		)
Net change in cash & cash equivalents	(9.0		)	(0.4		)	—			(9.4		)
Cash & cash equivalents at beginning of period	12.5			0.8			—			13.3
Cash & cash equivalents at end of period	$	3.5		$	0.4		$	—		$	3.9

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

	Subsidiary Guarantors			Parent Company			Eliminations			Consolidated
NET CASH PROVIDED BY OPERATING ACTIVITIES	$	233.3		$	15.7		$	—		$	249.0
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Additional capital contribution to 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 used in 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 used in 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

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Environmental Matters

6 Months Ended

Jun. 30, 2013

Environmental Matters Disclosure [Abstract]

Environmental Matters

Environmental Matters

Indiana Senate Bill 251 is also applicable to federal environmental mandates impacting Vectren South's electric operations. The Company is currently evaluating the impact Senate Bill 251 may have on its operations, including applicability of the stricter regulations the EPA is currently considering involving air quality, fly ash disposal, cooling tower intake facilities, waste water discharges, and greenhouse gases. These issues are further discussed below.

Air Quality

Clean Air Interstate Rule / Cross-State Air Pollution Rule

In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR).  CSAPR was 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, CSAPR reduced the ability of facilities to meet emission reduction targets through allowance trading.  Like CAIR, CSAPR set individual state caps for SO₂ and NOx emissions. However, unlike CAIR in which states allocated allowances to generating units through state implementation plans, CSAPR allowances were allocated to individual units directly through the federal rule.  CSAPR reductions were to be achieved with initial step reductions beginning January 1, 2012, and final compliance to be achieved in 2014.  Multiple administrative and judicial challenges were filed. On December 30, 2011, the Court granted a stay of CSAPR and left CAIR in place pending its review. On August 21, 2012, the Court vacated CSAPR and directed the EPA to continue to administer CAIR. In October 2012, the EPA filed its request for a hearing before the full federal appeals court that struck down the CSAPR.  EPA's request for rehearing was denied by the Court on January 24, 2013. In March 2013, the EPA filed a petition for review with the US Supreme Court, and in June 2013 the Supreme Court agreed to review the lower court decision. A decision by the Supreme Court is expected in 2014. The Company remains in full compliance with CAIR (see additional information below "Conclusions Regarding Air Regulations").

Mercury and Air Toxics (MATS) Rule

On December 21, 2011, the EPA finalized the Utility MATS Rule.  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 electric generating 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 CSAPR'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 agreed to 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. The EPA issued its revised emission limits for new construction in March 2013.

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 Generating Corporation (AGC), a subsidiary of 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 received a notice of violation (NOV) from the EPA in November 2011 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.  

The Company continues to review the sufficiency of its existing pollution control equipment in relation to the requirements described in the MATS Rule, the 2015 requirement imposed by CAIR, and the NOV discussed above.  Due to the correlation amongst the various requirements set forth, it is possible some operational modifications to the control equipment will be required. Additional capital investments, operating expenses, and possibly the purchase of emission allowances may be required and could be significant depending on the required method of compliance with the requirements.  The Company has not yet quantified what the additional costs may be associated with these efforts. However, as the compliance is required by government regulation, the Company believes that such additional costs, if incurred, should be recoverable under Senate Bill 251 referenced above.

Information Request

SIGECO and AGC own a 300 MW Unit 4 at the Warrick Power Plant as tenants in common.  AGC and SIGECO also share equally in the cost of operation and output of the unit.  In January 2013, AGC received an information request from the EPA under Section 114 of the Clean Air Act for historical operational information on the Warrick Power Plant. In April 2013, ALCOA filed a timely response to the information request.

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 approximate $40 million if new infrastructure, such as new cooling water towers, is required.  Costs for compliance with these final regulations should qualify as federally mandated regulatory requirements and be recovered under Indiana Senate Bill 251 referenced above.

Under the Clean Water Act, EPA sets technology-based guidelines for water discharges from new and existing facilities. EPA is currently in the process of revising the existing steam electric effluent limitation guidelines that set the technology-based water discharge limits for the electric power industry. EPA is focusing its rulemaking on wastewater generated primarily by pollution control equipment necessitated by the comprehensive air regulations. The EPA released proposed rules on April 19, 2013 and the Company is reviewing the proposal. At this time, it is not possible to estimate what potential costs may be required to meet these new water discharge limits, however costs for compliance with these regulations should qualify as federally mandated regulatory requirements and be recovered under 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 have not been finalized 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 should 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 (GHG's) meet the definition of "air pollutant" under the Clean Air Act and ordered the EPA to determine whether GHG 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 the EPA regulating carbon emissions through the existing Clean Air Act in the absence of specific carbon legislation from Congress.  

The EPA has promulgated two GHG regulations that apply to the Company's generating facilities.  In 2009, the EPA finalized a mandatory GHG 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 GHG's a year to obtain a PSD permit for new construction or a significant modification of an existing facility.  The EPA's PSD and Title V permitting rules for GHG's were upheld by the US Court of Appeals for the District of Columbia. In 2012, the EPA proposed New Source Performance Standards (NSPS) for GHG's for new electric generating facilities under Clean Air Act Section 111(b). In July 2013, the President announced a Climate Action Plan, which calls on the EPA to re-propose and finalize the new source rule expeditiously, and by June 2014 propose, and by June 2015 finalize, NSPS standards for GHG's for existing electric generating units which would apply to Vectren's power plants. States must have their implementation plans to the EPA no later than June 2016. The President's Climate Action Plan did not provide any detail as to actual emission targets or compliance requirements. The Company anticipates that these initial standards will focus on power plant efficiency and other coal fleet carbon intensity reduction measures. The Company believes that such additional costs, if necessary, should be recoverable under Indiana Senate Bill 251 referenced above.

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 GHG's 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 GHG emissions or obtaining renewable energy sources remain uncertain.  The Company has gathered preliminary estimates of the costs to control GHG 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 GHG 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 GHG 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 should be recoverable from customers through Senate Bill 251. 

Senate Bill 251 also established a voluntary clean energy portfolio standard that provides incentives to electricity suppliers participating in the program.The goal of the program is that by 2025, at least 10 percent of the total electricity obtained by the supplier to meet the energy needs of Indiana retail customers will be provided by clean energy sources, as defined. In advance of a federal portfolio standard and Senate Bill 251, SIGECO received regulatory approval to purchase a 3 MW landfill gas generation facility from a related entity. The facility was purchased in 2009 and is directly connected to the Company's distribution system. In 2008 and 2009, the Company executed long term purchase power commitments for a total of 80 MW of wind energy. The Company currently has approximately 5 percent of its electricity being provided by clean energy sources due to the long-term wind contracts and landfill gas investment.

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.

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 has incurred or reasonably expects to incur totaling approximately $42.4 million ($23.2 million at Indiana Gas and $19.2 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.  Likewise, SIGECO has settlement agreements with all known insurance carriers and has received to date approximately $14.2 million of the expected $15.7 million in 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 remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery.  As of June 30, 2013 and December 31, 2012, approximately $5.1 million and $4.6 million, respectively, of accrued, but not yet spent, costs are included in Other Liabilities related to the Indiana Gas and SIGECO sites.

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Organization and Nature of Operations (Details)	6 Months Ended
	Jun. 30, 2013
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)	573,000
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)	313,000

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2013

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, 2013				December 31, 2012
(In millions)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	1,157.8	$	1,259.1	$	1,208.4	$	1,372.6
Short-term borrowings	124.0		124.0		116.7		116.7
Cash & cash equivalents	3.9		3.9		13.3		13.3

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Document and Entity Information	6 Months Ended
	Jun. 30, 2013	Jul. 31, 2013
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	2013
Document Fiscal Period Focus	Q2
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2013

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Segment Reporting (Tables)

6 Months Ended

Jun. 30, 2013

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)	2013			2012			2013			2012
Revenues
Gas Utility Services	$	138.0		$	116.0		$	453.9		$	408.3
Electric Utility Services	154.7			149.3			304.2			288.7
Other Operations	142.0			10.0			151.5			19.9
Eliminations	(141.9		)	(9.5		)	(151.3		)	(19.0		)
Total revenues	$	292.8		$	265.8		$	758.3		$	697.9
Profitability Measure - Net Income (Loss)
Gas Utility Services	$	2.9		$	1.3		$	41.0		$	38.8
Electric Utility Services	18.9			17.2			33.5			32.8
Other Operations	2.4			1.6			4.8			4.5
Total net income	$	24.2		$	20.1		$	79.3		$	76.1