Edgar Filing: VECTREN CORP

vvc_10q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2012

[_]	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: 1-15467

VECTREN CORPORATION

(Exact name of registrant as specified in its charter)

[Missing Graphic Reference]

INDIANA		35-2086905
(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. x Yes o No

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

x Yes o No

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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 x Accelerated filer o

Non-accelerated filer o (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 x 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	81,993,361	April 30, 2012
Class	Number of Shares	Date

Access to Information

Vectren Corporation makes available all SEC filings and recent annual reports free of charge through its website at www.vectren.com as soon as reasonably practicable after electronically filing or furnishing the reports to the SEC, or by request, directed to Investor Relations at the mailing address, phone number, or email address that follows:

Mailing Address:

One Vectren Square

Evansville, Indiana 47708

Phone Number:

(812) 491-4000

Investor Relations Contact:

Robert L. Goocher

Treasurer and Vice President, Investor Relations

rgoocher@vectren.com

Definitions

BCF: billions of cubic feet	MSHA: Mine Safety and Health Administration
BTU: British thermal units	MW: megawatts
EPA: Environmental Protection Agency	MWh / GWh: megawatt hours / thousands of megawatt hours (gigawatt hours)
FASB: Financial Accounting Standards Board	OUCC: Indiana Office of the Utility Consumer Counselor
FERC: Federal Energy Regulatory Commission	PUCO: Public Utilities Commission of Ohio
IDEM: Indiana Department of Environmental Management	Throughput: combined gas sales and gas transportation volumes
IURC: Indiana Utility Regulatory Commission	XBRL: eXtensible Business Reporting Language
MISO: Midwest Independent System Operator

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Table of Contents

Item Number		Page Number
	PART I. FINANCIAL INFORMATION
1	Financial Statements (Unaudited)
	Vectren Corporation and Subsidiary Companies
	Consolidated Condensed Balance Sheets	4-5
	Consolidated Condensed Statements of Income	6
	Consolidated Condensed Statements of Comprehensive Income	7
	Consolidated Condensed Statements of Cash Flows	8
	Notes to Unaudited Consolidated Condensed Financial Statements	9
2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
3	Quantitative and Qualitative Disclosures About Market Risk	43
4	Controls and Procedures	44

	PART II. OTHER INFORMATION
1	Legal Proceedings	44
1A	Risk Factors	44
2	Unregistered Sales of Equity Securities and Use of Proceeds	45
3	Defaults Upon Senior Securities	45
4	Mine Safety Disclosures	45
5	Other Information	45
6	Exhibits	45
	Signatures	46

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

VECTREN CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited – In millions)


	March 31,		December 31,
	2012		2011

ASSETS

Current Assets
Cash & cash equivalents	$	14.2	$	8.6
Accounts receivable - less reserves of $6.1 & $6.7, respectively		214.6		221.3
Accrued unbilled revenues		67.8		121.5
Inventories		147.5		161.9
Recoverable fuel & natural gas costs		9.5		12.4
Prepayments & other current assets		41.6		84.3
Total current assets		495.2		610.0

Utility Plant
Original cost		5,033.8		4,979.9
Less: accumulated depreciation & amortization		1,975.9		1,947.3
Net utility plant		3,057.9		3,032.6

Investments in unconsolidated affiliates		88.2		92.9
Other utility & corporate investments		35.5		34.4
Other nonutility investments		24.6		29.6
Nonutility plant - net		562.0		550.8
Goodwill - net		262.3		262.3
Regulatory assets		232.8		226.0
Other assets		39.6		40.3
TOTAL ASSETS	$	4,798.1	$	4,878.9

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

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VECTREN CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited – In millions)


	March 31,			December 31,
	2012			2011

LIABILITIES & SHAREHOLDERS' EQUITY

Current Liabilities
Accounts payable	$	141.6		$	185.8
Accounts payable to affiliated companies		19.3			36.8
Refundable fuel & natural gas costs		2.6			-
Accrued liabilities		183.6			181.1
Short-term borrowings		174.7			227.1
Current maturities of long-term debt		61.6			62.7
Total current liabilities		583.4			693.5


Long-term Debt - Net of Current Maturities		1,559.3			1,559.6

Deferred Income Taxes & Other Liabilities
Deferred income taxes		575.4			575.7
Regulatory liabilities		350.5			345.2
Deferred credits & other liabilities		238.1			239.4
Total deferred credits & other liabilities		1,164.0			1,160.3

Commitments & Contingencies (Notes 7, 9-12)

Common Shareholders' Equity
Common stock (no par value) – issued & outstanding 82.0 & 81.9 shares, respectively		694.4			692.6
Retained earnings		808.7			786.2
Accumulated other comprehensive income (loss)		(11.7	)		(13.3	)
Total common shareholders' equity		1,491.4			1,465.5

TOTAL LIABILITIES & SHAREHOLDERS' EQUITY	$	4,798.1		$	4,878.9

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

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VECTREN CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED CONDENSED STATEMENTS OF INCOME

(Unaudited – in millions, except per share amounts)


	Three Months
	Ended March 31,
	2012			2011
OPERATING REVENUES
Gas utility	$	292.3		$	356.7
Electric utility		139.4			146.4
Nonutility		172.9			179.5
Total operating revenues		604.6			682.6
OPERATING EXPENSES
Cost of gas sold		137.1			195.1
Cost of fuel & purchased power		44.7			59.5
Cost of nonutility revenues		59.5			105.1
Other operating		173.2			141.6
Depreciation & amortization		63.6			59.1
Taxes other than income taxes		16.6			18.9
Total operating expenses		494.7			579.3
OPERATING INCOME		109.9			103.3
OTHER INCOME (EXPENSE)
Equity in (losses) of unconsolidated affiliates		(7.6	)		(10.9	)
Other income – net		3.3			2.4
Total other income (expense)		(4.3	)		(8.5	)

INTEREST EXPENSE		24.0			26.6

INCOME BEFORE INCOME TAXES		81.6			68.2

INCOME TAXES		30.3			23.6

NET INCOME	$	51.3		$	44.6

AVERAGE COMMON SHARES OUTSTANDING		82.0			81.7
DILUTED COMMON SHARES OUTSTANDING		82.0			81.7

EARNINGS PER SHARE OF COMMON STOCK:
BASIC	$	0.63		$	0.55
DILUTED	$	0.62		$	0.55


DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$	0.350		$	0.345

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

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VECTREN CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited – in millions)


	Three Months
	Ended March 31,
	2012			2011
Net income	$	51.3		$	44.6
Other comprehensive income (loss), before tax:
Comprehensive income of unconsolidated affiliates		2.9			2.3
Cash flow hedges		-			(3.2	)
Other comprehensive income (loss), before tax		2.9			(0.9	)
Income taxes related to items of other comprehensive income		(1.3	)		0.3
Other comprehensive income (loss), net of tax		1.6			(0.6	)
Total comprehensive income	$	52.9		$	44.0

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

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VECTREN CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited – In millions)



	Three Months Ended March 31,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	51.3		$	44.6
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization		63.6			59.1
Deferred income taxes & investment tax credits		13.7			18.5
Equity in losses of unconsolidated affiliates		7.6			10.9
Provision for uncollectible accounts		2.3			5.9
Expense portion of pension & postretirement benefit cost		2.7			2.2
Other non-cash charges - net		1.9			3.2
Changes in working capital accounts:
Accounts receivable & accrued unbilled revenues		58.1			31.5
Inventories		4.7			54.7
Recoverable/refundable fuel & natural gas costs		5.5			5.1
Prepayments & other current assets		30.4			39.0
Accounts payable, including to affiliated companies		(66.1	)		(86.8	)
Accrued liabilities		2.4			23.8
Employer contributions to pension & postretirement plans		(4.9	)		(29.2	)
Changes in noncurrent assets		0.8			8.0
Changes in noncurrent liabilities		(5.2	)		(2.1	)
Net cash flows from operating activities		168.8			188.4
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt, net of issuance costs		99.5			-
Dividend reinvestment plan & other common stock issuances		1.6			1.7
Requirements for:
Dividends on common stock		(28.7	)		(28.2	)
Retirement of long-term debt		(1.5	)		(0.1	)
Other financing activities		-			(1.4	)
Net change in short-term borrowings		(152.4	)		4.0
Net cash flows from financing activities		(81.5	)		(24.0	)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Other collections		5.5			0.3
Requirements for:
Capital expenditures, excluding AFUDC equity		(87.2	)		(57.7	)
Business acquisition, net of cash acquired		-			(82.9	)
Net cash flows from investing activities		(81.7	)		(140.3	)
Net change in cash & cash equivalents		5.6			24.1
Cash & cash equivalents at beginning of period		8.6			10.4
Cash & cash equivalents at end of period	$	14.2		$	34.5

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

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VECTREN CORPORATION AND SUBSIDIARY COMPANIES

NOTES TO THE CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

(UNAUDITED)

1.	Organization and Nature of Operations

Vectren Corporation (the Company or Vectren), an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana. The Company’s wholly owned subsidiary, Vectren Utility Holdings, Inc. (Utility Holdings), serves as the intermediate holding company for three 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. Utility Holdings’ consolidated operations are collectively referred to as the Utility Group. Both Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 2005 (Energy Act). Vectren was incorporated under the laws of Indiana on June 10, 1999.

Indiana Gas provides energy delivery services to approximately 570,000 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 over 313,000 natural gas customers located near Dayton in west central Ohio.

The Company, through Vectren Enterprises, Inc. (Enterprises), is involved in nonutility activities in four primary business areas: Infrastructure Services, Energy Services, Coal Mining, and Energy Marketing. Infrastructure Services provides underground construction and repair services. Energy Services provides performance contracting and renewable energy services. Coal Mining mines and sells coal. Energy Marketing markets and supplies natural gas and provides energy management services. Enterprises also has other legacy businesses that have invested in energy-related opportunities and services, real estate, and leveraged leases, among other investments. All of the above are collectively referred to as the Nonutility Group. Enterprises supports the Company’s regulated utilities pursuant to service contracts by providing natural gas supply services, coal, and infrastructure services.

2.	Basis of Presentation

The interim consolidated condensed financial statements included in this report have been prepared by the Company, without audit, as provided in the rules and regulations of the Securities and Exchange Commission and include a review of subsequent events through the date the financial statements were issued. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been omitted as provided in such rules and regulations. The information in this report reflects all adjustments which are, in the opinion of management, necessary to fairly state the interim periods presented, inclusive of adjustments that are normal and recurring in nature. These consolidated condensed financial statements and related notes should be read in conjunction with the Company’s audited annual consolidated financial statements for the year ended December 31, 2011, filed with the Securities and Exchange Commission on February 16, 2012, on Form 10-K. Because of the seasonal nature of the Company’s 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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3.	Earnings Per Share

The Company uses the two class method to calculate earnings per share (EPS). The two class method is an earnings allocation formula that treats a participating security as having rights to earnings that otherwise would have been available to common shareholders. Under the two class method, earnings for a period are allocated between common shareholders and participating security holders based on their respective rights to receive dividends as if all undistributed book earnings for the period were distributed. Basic EPS is computed by dividing net income attributable to only the common shareholders by the weighted-average number of common shares outstanding for the period. Diluted EPS includes the impact of stock options and other equity based instruments to the extent the effect is dilutive. The following table illustrates the basic and dilutive EPS calculations for the periods presented in these financial statements.


	Three Months
	Ended March 31,
(In millions, except per share data)	2012		2011
Numerator:
Reported net income (Numerator for Basic and Diluted EPS)	$	51.3	$	44.6
Denominator:
Weighted average common shares outstanding (Denominator for Basic and Diluted EPS)		82.0		81.7
Basic EPS	$	0.63	$	0.55
Diluted EPS	$	0.62	$	0.55

For the three months ended March 31, 2011, options to purchase 288,320 additional shares of the Company’s common stock were outstanding, but were not included in the computation of diluted EPS because their effect would be antidilutive. The exercise prices for these options were $26.63 to $27.15 for the three months ended March 31, 2011. For the three months ended March 31, 2012, all options were dilutive.

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 $9.3 million and $11.1 million in the three months ended March 31, 2012 and 2011, respectively. Expenses associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.

5.	Retirement Plans & Other Postretirement Benefits

The Company maintains three qualified defined benefit pension plans, a nonqualified supplemental executive retirement plan (SERP), and three other postretirement benefit plans. The defined benefit pension and other postretirement benefit plans, which cover eligible full-time regular employees, are primarily noncontributory. The postretirement health care and life insurance plans are a combination of self-insured and fully insured plans. The qualified pension plans and the SERP are aggregated under the heading “Pension Benefits.” Other postretirement benefit plans are aggregated under the heading “Other Benefits.”

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Net Periodic Benefit Costs

A summary of the components of net periodic benefit cost follows:


	Three Months Ended March 31,
	Pension Benefits						Other Benefits
(In millions)	2012			2011			2012			2011
Service cost	$	1.9		$	1.7		$	0.1		$	0.1
Interest cost		3.9			4.0			0.9			1.1
Expected return on plan assets		(5.3	)		(5.3	)		-			-
Amortization of prior service cost		0.4			0.4			(0.2	)		(0.2	)
Amortization of transitional obligation		-			-			0.3			0.3
Amortization of actuarial loss		1.7			1.0			0.1			0.1
Net periodic benefit cost	$	2.6		$	1.8		$	1.2		$	1.4

Employer Contributions to Qualified Pension Plans

Currently, the Company expects to contribute approximately $15 million to its pension plan trusts for 2012. During the three months ended March 31, 2012, contributions of $3.4 million have been made.

6.	Supplemental Cash Flow Information

As of March 31, 2012 and December 31, 2011, the Company has accruals related to utility and nonutility plant purchases totaling approximately $17.1 million and $15.9 million, respectively.

7.	ProLiance Holdings, LLC

ProLiance Holdings, LLC (ProLiance), a nonutility energy marketing affiliate of Vectren and Citizens Energy Group (Citizens), provides services to a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions located throughout the Midwest and Southeast United States. ProLiance’s customers include Vectren’s Indiana utilities as well as Citizens’ utilities. ProLiance’s primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services. Consistent with its ownership percentage, Vectren is allocated 61 percent of ProLiance’s profits and losses; however, governance and voting rights remain at 50 percent for each member; and therefore, the Company accounts for its investment in ProLiance using the equity method of accounting.

Summarized Financial Information


	Three Months
	Ended March 31,
(In millions)	2012			2011
Summarized statement of income information:
Revenues	$	352.7		$	500.6
Operating (loss)		(10.9	)		(17.2	)
ProLiance's net (loss)		(12.4	)		(17.4	)

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	As of
	March 31,			December 31,
(In millions)	2012			2011
Summarized balance sheet information:
Current assets	$	248.4		$	381.9
Noncurrent assets		55.5			56.1
Current liabilities		171.7			298.5
Noncurrent liabilities		1.0			0.7
Members' equity		149.1			161.5
Accumulated other comprehensive (loss)		(21.3	)		(26.0	)
Noncontrolling interest		3.4			3.3

Vectren records its 61 percent share of ProLiance’s results in Equity in earnings (losses) of unconsolidated affiliates. Interest expense and income taxes associated with the investment are recorded separately within the statements of income in those line items. As of March 31, 2012 and December 31, 2011, the Company’s investment balance, inclusive of its share of ProLiance’s accumulated other comprehensive loss and certain historical book basis differences, is $80.7 million and $85.4 million, respectively. The amounts recorded to Equity in earnings (losses) of unconsolidated affiliates related to ProLiance’s operations totaled a pre-tax loss of $7.6 million and $10.6 million for the three months ended March 31, 2012 and 2011, respectively.

Investment in Liberty Gas Storage

Liberty Gas Storage, LLC (Liberty), a joint venture between a subsidiary of ProLiance and a subsidiary of Sempra Energy (SE), is a development project for salt-cavern natural gas storage facilities. ProLiance is the minority member with a 25 percent interest, which it accounts for using the equity method. The project was expected to include 17 Bcf of capacity in its North site, and an additional capacity of at least 17 Bcf at the South site. The South site also has the potential for further expansion. The Liberty pipeline system is currently connected with several interstate pipelines, including the Cameron Interstate Pipeline operated by Sempra U.S. Gas & Power, and will connect area LNG regasification terminals to an interstate natural gas transmission system and storage facilities.

In late 2008, the project at the North site was halted due to subsurface and well-completion problems, resulting in an impairment charge related to the North site being recorded in 2009. ProLiance’s ability to meet the needs of its customers has not been, nor does it expect it to be, impacted. Approximately 12 Bcf of the storage at the South site, which comprises three of the four FERC certified caverns, is fully completed and tested. As a result of the issues encountered at the North site, Liberty requested and the FERC approved the separation of the North site from the South site. As of March 31, 2012 and December 31, 2011, ProLiance’s investment in Liberty approximated $34.6 million and $35.1 million, respectively.

Liberty received a Demand for Arbitration from Williams Midstream Natural Gas Liquids, Inc. (“Williams”) on February 8, 2011 related to a Sublease Agreement (“Sublease”) between Liberty and Williams at the North site. Williams alleges that Liberty was negligent in its attempt to convert certain salt caverns to natural gas storage and thereby damaged the caverns. Williams alleges damages of $56.7 million. Liberty believes that it has complied with all of its obligations to Williams, including properly terminating the Sublease. Liberty intends to vigorously defend itself and has asserted counterclaims substantially in excess of the amounts asserted by Williams.

Transactions with ProLiance

Purchases from ProLiance for resale and for injections into storage for the three months ended March 31, 2012 and 2011 totaled $79.5 million and $120.1 million, respectively. Amounts owed to ProLiance at March 31, 2012 and December 31, 2011, for those purchases were $19.3 million and $36.8 million, respectively, and are included in Accounts payable to affiliated companies in the Consolidated Condensed Balance Sheets. Vectren received regulatory approval on April 25, 2006, from the IURC for ProLiance to provide natural gas supply services to the Company’s Indiana utilities through March 2011. On March 17, 2011, an order was received from the IURC providing for ProLiance’s continued provision of gas supply services to the Company’s Indiana utilities and Citizens Energy Group through March 2016. Amounts charged by ProLiance for gas supply services are established by supply agreements with each utility.

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8.	Financing Activities

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

9.	Commitments & Contingencies

Corporate Guarantees

The Company issues parent level guarantees to certain vendors and customers of its wholly owned subsidiaries and unconsolidated affiliates. These guarantees do not represent incremental consolidated obligations; rather, they represent parental guarantees of subsidiary and unconsolidated affiliate obligations in order to allow those subsidiaries and affiliates the flexibility to conduct business without posting other forms of collateral. At March 31, 2012, parent level guarantees support a maximum of $25 million of ESG’s performance contracting commitments and warranty obligations and $28 million of other project guarantees. The broader scope of ESG’s performance contracting obligations, including those not guaranteed by the parent company, are described below. In addition, the parent company has approximately $23 million of other guarantees outstanding supporting other consolidated subsidiary operations, of which $19 million represent letters of credit supporting other nonutility operations. Guarantees issued and outstanding on behalf of unconsolidated affiliates approximated $3 million at March 31, 2012. These guarantees relate primarily to arrangements between ProLiance and various natural gas pipeline operators. The Company has not been called upon to satisfy any obligations pursuant to these parental guarantees and has accrued no significant liabilities related to these guarantees.

As a result of the sale of Vectren Source on December 31, 2011, the Company had $56 million of outstanding guarantees related to this formerly wholly owned subsidiary that remained in effect for 90 days after the closing. The buyer’s parent will hold the Company harmless if any amounts are required to be paid pursuant to these guarantees and, within the 90 day period, the buyer was required to provide its own guarantees in substitution for the Company guarantees. This arrangement expired on March 31, 2012.

Performance Guarantees & Product Warranties

In the normal course of business, wholly owned subsidiaries, including ESG, issue performance bonds or other forms of assurance that commit them to timely install infrastructure, operate facilities, pay vendors or subcontractors, and/or support warranty obligations. Based on a history of meeting performance obligations and installed products operating effectively, no significant liability or cost has been recognized for the periods presented.

Specific to ESG, in its role as a general contractor in the performance contracting industry, at March 31, 2012, there are 73 open surety bonds supporting future performance. The average face amount of these obligations is $3.6 million, and the largest obligation has a face amount of $23.7 million. The maximum exposure of these obligations is less than these amounts for several factors, including the level of work already completed. At March 31, 2012, approximately 65 percent of work was completed on projects with open surety bonds. A significant portion of these commitments will be fulfilled within one year. In instances where ESG operates facilities, project guarantees extend over a longer period. In addition to its performance obligations, ESG also warrants the functionality of certain installed infrastructure generally for one year and the associated energy savings over a specified number of years. The Company has no significant accruals for these warranty obligations as of March 31, 2012.

Legal & Regulatory Proceedings

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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10.	Legislative Matters

Pipeline Safety Law

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

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

Indiana Senate Bill 251

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

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

Ohio House Bill 95

In June 2011, Ohio House Bill 95 was signed into law. The law adjusts, among other things, the manner in which gas utilities file for rate changes, including the implementation of base rate changes, alternative rate plans, and automatic rate adjustment mechanisms. Outside of a base rate proceeding, the legislation permits a natural gas company to apply for recovery of a capital expenditure program for infrastructure expansion, upgrade, or replacement; installation, upgrade, or replacement of information technology systems; or any program necessary to comply with government regulation. Once such application is approved, the legislation authorizes deferral of program costs, such as depreciation, property taxes, and debt-related carrying costs. On February 3, 2012, the Company initiated a filing under House Bill 95. This filing requests accounting authority to defer depreciation, debt-related post in service carrying costs and property taxes for its approximate $25 million fifteen month capital expenditure program ending on December 31, 2012. The capital expenditure program includes infrastructure expansion and improvements not covered by the Company’s distribution replacement rider as well as expenditures necessary to comply with PUCO rules, regulations and orders. The Company’s approach is consistent with approaches made by other Ohio utilities. A procedural schedule associated with the filing has been set and all respective responses have been submitted. It is anticipated the PUCO will act on the Company’s filing and the flings of the other Ohio utilities later this year.

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11.	Environmental Matters

Air Quality

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

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

In an effort to address the Court’s finding that CAIR did not adequately ensure attainment of pollutants in certain downwind states due to unlimited trading of SO2and NOx allowances, CSPAR reduces the ability of facilities to meet emission reduction targets through allowance trading. Like CAIR, CSPAR sets individual state caps for SO2and NOx emissions. However, unlike CAIR in which states allocated allowances through state implementation plans, CSPAR allowances were allocated to individual units directly through the federal rule. As finalized, CSAPR requires a 71 percent reduction of SO2 emissions compared to 2005 national levels and a 52 percent reduction of NOx emissions compared to 2005 national levels and that such reductions are to be achieved with initial step reductions beginning January 1, 2012, with final compliance to be achieved in 2014. Multiple administrative and judicial challenges have been filed, including requests to stay CSPAR’s implementation.

On December 30, 2011, the Court granted a stay of CSPAR and ordered expedited briefing schedules be submitted by January 18, 2012, which allowed for completion of briefing and a hearing in April 2012. Two primary issues are before the Court for review: (1) EPA’s use of air modeling data (as opposed to exclusive reliance on actual monitoring data) to support state contribution levels, and (2) EPA’s allocation of allowances directly through a federal implementation plan as opposed to setting state caps and providing states the opportunity to submit individual state implementation plans. In addition, there are initiatives in the Congress that, if adopted, would suspend CSPAR’s implementation. A final ruling is expected later this year.

Utility Hazardous Air Pollutants (HAPs) Rule

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

The HAPs rule sets emission limits for hazardous air pollutants for existing and new coal-fired power plants and identifies the following broad categories of hazardous air pollutants: mercury, non-mercury hazardous air pollutants (primarily arsenic, chromium, cobalt, and selenium) and acid gases (hydrogen cyanide, hydrogen chloride, and hydrogen fluoride). The rule imposes mercury emission limits for two sub-categories of coal, and proposed surrogate limits for non-mercury and acid gas hazardous air pollutants. The EPA did not grant blanket compliance extensions, but asserted that states have broad authority to grant one year extensions for individual units where potential reliability impacts have been demonstrated. Reductions are to be achieved within three years of publication of the final rule in the Federal register (April 2015). Initiatives to suspend CSPAR’s implementation by the Congress also apply to the implementation of the HAPs rule. The reviewing court has yet to rule on any requests to stay the implementation of the HAPs rule.

Conclusions Regarding Air Regulations

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

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

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The Company is currently reviewing the sufficiency of its existing pollution control equipment in relation to the requirements described in CSPAR and the Utility HAPs Rule. Based upon an initial review of the final rules, including minor revisions made to CSPAR in October 2011, the Company believes that it will be able to meet these requirements with its existing suite of pollution control equipment and the anticipated allotment of new emission allowances. However, it is possible some minor modifications to the control equipment and additional operating expenses could be required. The Company believes that such additional costs, if necessary, would be recoverable under Indiana Senate Bill 251 referenced above.

Notice of Violation Received

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

Water

Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” to minimize adverse environmental impacts in a body of water. More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures used at electric generating facilities. In April 2009, the U.S. Supreme Court affirmed that the EPA could, but was not required to, consider costs and benefits in making the evaluation as to the best technology available for existing generating facilities. The regulation was remanded back to the EPA for further consideration. In March 2011, the EPA released its proposed Section 316(b) regulations. The EPA did not mandate the retrofitting of cooling towers in the proposed regulation, but if finalized the regulation will leave it to the state to determine whether cooling towers should be required on a case by case basis. A final rule is expected in 2012. Depending on the final rule and on the Company’s facts and circumstances, capital investments could be in the $40 million range if new infrastructure, such as new cooling water towers, is required. Costs for compliance with these final regulations would likely qualify as federally mandated regulatory requirements under Indiana Senate Bill 251 referenced above.

Coal Ash Waste Disposal & Ash Ponds

In June 2010, the EPA issued proposed regulations affecting the management and disposal of coal combustion products, such as ash generated by the Company’s coal-fired power plants. The proposed rules more stringently regulate these byproducts and would likely increase the cost of operating or expanding existing ash ponds and the development of new ash ponds. The alternatives include regulating coal combustion by-products that are not being beneficially reused as hazardous waste. The EPA did not offer a preferred alternative, but took public comment on multiple alternative regulations. Rules may not be finalized in 2012 given oversight hearings, congressional interest, and other factors.

At this time, the majority of the Company’s ash is being beneficially reused. However, the alternatives proposed would require some retrofitting or closure of existing ash ponds. The Company estimates capital expenditures to comply could be as much as $30 million, and such expenditures could exceed $100 million if the most stringent of the alternatives is selected. Annual compliance costs could increase slightly or be impacted by as much as $5 million. Costs for compliance with these regulations would likely qualify as federally mandated regulatory requirements under Senate Bill 251 referenced above.

Climate Change

In April 2007, the US Supreme Court determined that greenhouse gases meet the definition of "air pollutant" under the Clean Air Act and ordered the EPA to determine whether greenhouse gas emissions from motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. In April 2009, the EPA published its proposed endangerment finding for public comment. The proposed endangerment finding concludes that carbon emissions from mobile sources pose an endangerment to public health and the environment. The endangerment finding was finalized in December 2009, and is the first step toward EPA regulating carbon emissions through the existing Clean Air Act in the absence of specific carbon legislation from Congress. The EPA has promulgated two greenhouse gas regulations that apply to the Company’s generating facilities. In 2009, the EPA finalized a mandatory greenhouse gas emissions registry which requires the reporting of emissions. The EPA has also finalized a revision to the Prevention of Significant Deterioration (PSD) and Title V permitting rules which would require facilities that emit 75,000 tons or more of greenhouse gases a year to obtain a PSD permit for new construction or a significant modification of an existing facility. In April 2012, the USEPA issued its proposed new source performance standards for greenhouse gases applicable to new construction. This proposed rule does not apply to existing sources, such as Vectren’s generating facilities. The USEPA has not indicated when it intends to propose standards for existing sources.

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

Impact of Legislative Actions & Other Initiatives is Unknown

If regulations are enacted by the EPA or other agencies or if legislation requiring reductions in CO2 and other greenhouse gases or legislation mandating a renewable energy portfolio standard is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants, nonutility coal mining operations, and natural gas distribution businesses. At this time and in the absence of final legislation or rulemaking, compliance costs and other effects associated with reductions in greenhouse gas emissions or obtaining renewable energy sources remain uncertain. The Company has gathered preliminary estimates of the costs to control greenhouse gas emissions. A preliminary investigation demonstrated costs to comply would be significant, first with regard to operating expenses and later for capital expenditures as technology becomes available to control greenhouse gas emissions. However, these compliance cost estimates are based on highly uncertain assumptions, including allowance prices if a cap and trade approach were employed, and energy efficiency targets. Costs to purchase allowances that cap greenhouse gas emissions or expenditures made to control emissions should be considered a cost of providing electricity, and as such, the Company believes such costs and expenditures would be recoverable from customers through Senate Bill 251. Customer rates may also be impacted should decisions be made to reduce the level of sales to municipal and other wholesale customers in order to meet emission targets.

Manufactured Gas Plants

In the past, the Company operated facilities to manufacture natural gas. Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years. Under current environmental laws and regulations, those that owned or operated these facilities may now be required to take remedial action if certain contaminants are found above the regulatory thresholds at these sites.

In the Indiana Gas service territory, the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites have been identified for which the Company may have some remedial responsibility. A remedial investigation/feasibility study (RI/FS) was completed at one of the sites under an agreed order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. The remaining sites have been submitted to the IDEM's Voluntary Remediation Program (VRP). The Company has identified its involvement in five manufactured gas plants sites in SIGECO’s service territory, all of which are currently enrolled in the IDEM’s VRP. The Company is currently conducting some level of remedial activities, including groundwater monitoring at certain sites.

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

With respect to insurance coverage, Indiana Gas has received approximately $20.8 million from all known insurance carriers under insurance policies in effect when these plants were in operation. SIGECO filed a declaratory judgment action against its insurance carriers seeking a judgment finding its carriers liable under the policies for coverage of further investigation and any necessary remediation costs that SIGECO may accrue under the VRP program and/or another site subject to a lawsuit that has been settled. In November 2011, the Court ruled on two motions for summary judgment, finding for SIGECO and against certain insurers on indemnification and defense obligations in the policies at issue. SIGECO has settlement agreements with all known insurance carriers and has recorded approximately $15.2 million of expected insurance recoveries.

The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others. While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require some level of additional remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery. As of March 31, 2012 and December 31, 2011, respectively, approximately $4.7 million and $6.5 million of accrued, but not yet spent, costs are included in Other Liabilities related to both the Indiana Gas and SIGECO sites.

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12.	Rate & Regulatory Matters

Vectren South Electric Base Rate Filing

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

Coal Procurement Procedures

Vectren South submitted a request for proposal in April 2011 regarding coal purchases for a four year period beginning in 2012. After negotiations with bidders, Vectren South has reached an agreement in principle for multi-year purchases with two suppliers, one of which is Vectren Fuels, Inc. Consistent with the IURC direction in the electric rate case, a sub docket proceeding was established to review the Company’s prospective coal procurement procedures, and the Company submitted evidence related to its recent request for proposal (RFP) and those coal procurement procedures to the IURC in September 2011. In March 2012, the IURC issued its order in the sub docket. The order concluded that Vectren South’s 2011 RFP process resulted in prices at the lowest fuel cost reasonably possible. The IURC will continue to regularly monitor Vectren South’s procurement process in future fuel adjustment proceedings.

Vectren South Electric Fuel Cost Reduction

In the spring of 2011, Vectren secured contracts for lower coal costs through a formal bidding process. This lower-priced coal is expected to start being delivered and used at Vectren’s power plants by late 2012 to early 2013 and beyond. On December 5, 2011 within the quarterly FAC filing, Vectren South submitted a joint proposal with the OUCC to reduce its fuel costs by accelerating the impact of lower cost coal contracts to be effective after 2012. The agreement to accelerate savings into early 2012 means that the existing 2012 coal costs that are above the new, lower prices will be deferred to a regulatory asset and recovered over a six-year period without interest beginning in 2014. The IURC approved this proposal on January 25, 2012, with a positive impact to customer’s rates effective February 1, 2012. Deferrals also include a reduction in the value of the coal inventory at December 31, 2011 of approximately $17.7 million to reflect existing coal inventory at the new, lower price. Deferrals related to coal purchases in 2012 have totaled approximately $9.7 million, bringing the total deferred balance as of March 2012 to $27.4 million.

Vectren South Electric Demand Side Management Program Filing

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

On August 31, 2011 the IURC issued an order approving an initial three year DSM plan in the Vectren South service territory that complies with the IURC’s energy saving targets. Consistent with the Company’s proposal, the order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; 3) lost margin recovery associated with the implementation of DSM programs; and 4) deferral of lost margin up to $1 million in 2011 associated with small customer DSM programs for subsequent recovery under a tracking mechanism to be proposed by the Company. This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the order received April 27, 2011. On January 26, 2012, the Company requested approval from the IURC of a recovery mechanism within the existing Demand Side Management Adjustment (DSMA) for lost margins resulting from small customer participation in the Company’s DSM programs. The filing included a request for recovery of the $1 million deferred in 2011, and a request for continued deferral of lost margins in 2012 until such point as these lost margins are included in DSMA rates. The evidentiary hearing in this matter is scheduled for June 5, 2012.

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Vectren South Electric Dense Pack Filing

On September 14, 2011, Vectren South filed a petition with the IURC seeking recovery of and return on the capital investment in dense pack technology to improve the efficiency of its A.B. Brown Generating Station. This investment is expected to be approximately $32 million over the next two years, of which approximately $22 million has been invested to date. This technology is expected to allow the A.B. Brown units to run at least 5 percent more efficient, thereby burning less fuel, and reducing fuel costs and emissions of pollutants. In the Company’s base rate order issued in April 2011, the IURC authorized deferred accounting treatment associated with this investment. Indiana statute also provides for timely recovery of investments, with a return, in instances where the investment increases the efficiency of existing generating plants that are fueled by coal. Several parties have intervened in the case and are requesting that the IURC deny recovery of these project costs outside of a base rate proceeding. A hearing was held by the IURC in February 2012 and proposed orders were submitted by the parties in March 2012. An order on timely recovery is expected later in 2012.

Vectren North Reporting Location Consolidation Proceeding

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

VEDO Continues the Process to Exit the Merchant Function

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

The second phase of the exit process began on April 1, 2010. During this phase, the Company no longer sells natural gas directly to customers. Rather, state-certified Competitive Retail Natural Gas Suppliers, that are successful bidders in a similar regulatory-approved auction, sell the gas commodity to specific customers for a 12-month period at auction-determined standard pricing. During the second phase, VEDO conducted its third retail auction on January 31, 2012 to address the 12-month term beginning April 1, 2012. The results of that auction were approved by the PUCO on February 1, 2012. Consistent with current practice, customers continue to receive a single bill for the commodity as well as the delivery component of natural gas service from VEDO.

The PUCO provided for an Exit Transition Cost rider, which allows the Company to recover costs associated with the transition process. Exiting the merchant function has not had a material impact on earnings or financial condition.

13.	Impact of Recently Issued Accounting Principles

Other Comprehensive Income (OCI)

In 2011, the FASB issued new accounting guidance regarding the presentation of comprehensive income within financial statements. The new guidance will require entities to report components of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements. Under the two-statement approach, the first statement would include components of net income, which is consistent with the income statement format used today, and the second statement would include components of OCI. The guidance does not change the items that must be reported in OCI. The new guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 and retrospective application is required. The Company adopted this guidance, as amended for condensed quarterly reporting, for the quarterly reporting period ending March 31, 2012 by reporting comprehensive income as required.

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Goodwill Testing

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

Fair Value Measurement and Disclosure

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

14.	Fair Value Measurements

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


	March 31, 2012				December 31, 2011
(In millions)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	1,620.9	$	1,776.5	$	1,622.3	$	1,804.4
Short-term borrowings		174.7		174.7		227.1		227.1
Cash & cash equivalents		14.2		14.2		8.6		8.6

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

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

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

Because of the customized nature of notes receivable investments and lack of a readily available market, it is not practical to estimate the fair value of these financial instruments at specific dates without considerable effort and cost. At March 31, 2012 and December 31, 2011, the fair value for these financial instruments was not estimated. The carrying value of notes receivable, inclusive of any accrued interest and net of impairment reserves, was approximately $2.1 million at March 31, 2012 and December 31, 2011.

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15.	Segment Reporting

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

The Utility Group is comprised of Vectren Utility Holdings, Inc.’s operations, which consist of the Company’s regulated operations and other operations that provide information technology and other support services to those regulated operations. The Company segregates its regulated operations 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 Utility Group reports three segments: Gas Utility Services, Electric Utility Services, and Other operations.

The Nonutility Group reports five segments: Infrastructure Services, Energy Services, Coal Mining, Energy Marketing, and Other Businesses. Segment information below reflects the March 31, 2011 acquisition of Minnesota Limited, Inc. in the Infrastructure Services segment and the December 31, 2011 sale of Vectren Source in Energy Marketing segment.

Corporate and Other includes unallocated corporate expenses such as advertising and charitable contributions, among other activities, that benefit the Company’s other operations. Net income is the measure of profitability used by management for all operations. Information related to the Company’s reportable segments is summarized as follows:


	Three Months
	Ended March 31,
(In millions)	2012			2011
Revenues
Utility Group
Gas Utility Services	$	292.3		$	356.7
Electric Utility Services		139.4			146.4
Other Operations		9.9			11.0
Eliminations		(9.5	)		(10.5	)
Total Utility Group		432.1			503.6
Nonutility Group
Infrastructure Services		117.5			47.2
Energy Services		22.2			23.6
Coal Mining		58.5			69.4
Energy Marketing		-			74.0
Other Businesses		0.1			-
Total Nonutility Group		198.3			214.2
Eliminations		(25.8	)		(35.2	)
Consolidated Revenues	$	604.6		$	682.6

Profitability Measure - Net Income
Utility Group
Gas Utility Services	$	37.5		$	36.1
Electric Utility Services		15.6			8.6
Other Operations		2.9			3.9
Utility Group Net Income		56.0			48.6
Nonutility Group Net Income (Loss)
Infrastructure Services		3.0			(2.9	)
Energy Services		(1.7	)		(1.4	)
Coal Mining		(0.3	)		1.6
Energy Marketing		(5.9	)		(0.4	)
Other Businesses		0.1			(0.3	)
Nonutility Group Net Income (Loss)		(4.8	)		(3.4	)
Corporate & Other Group Net Income (Loss)		0.1			(0.6	)
Consolidated Net Income	$	51.3		$	44.6

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

Vectren Corporation (the Company or Vectren), an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana. The Company’s wholly owned subsidiary, Vectren Utility Holdings, Inc. (Utility Holdings), serves as the intermediate holding company for three 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. Utility Holdings’ consolidated operations are collectively referred to as the Utility Group. Both Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 2005 (Energy Act). Vectren was incorporated under the laws of Indiana on June 10, 1999.

Executive Summary of Consolidated Results of Operations

In this discussion and analysis, the Company analyzes contributions to consolidated earnings and earnings per share from its Utility Group and Nonutility Group separately since each operates independently requiring distinct competencies and business strategies, offers different energy and energy related products and services, and experiences different opportunities and risks.

The Utility Group generates revenue primarily from the delivery of natural gas and electric service to its customers. The primary source of cash flow for the Utility Group results from the collection of customer bills and the payment for goods and services procured for the delivery of gas and electric services. The activities of, and revenues and cash flows generated by, the Nonutility Group are closely linked to the utility industry, and the results of those operations are generally impacted by factors similar to those impacting the overall utility industry. In addition, there are other operations, referred to herein as Corporate and Other, that include unallocated corporate expenses such as advertising and charitable contributions, among other activities.

The Company has in place a disclosure committee that consists of senior management as well as financial management. The committee is actively involved in the preparation and review of the Company’s SEC filings. The following discussion and analysis should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto as well as the Company’s 2011 annual report filed on Form 10-K.

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Net income and earnings per share, in total and by group, for the three months ended March 31, 2012 and 2011 follow:


	Three Months
	Ended March 31,
(In millions, except per share data)	2012			2011
Net income (loss)	$	51.3		$	44.6
Attributed to:
Utility Group		56.0			48.6
Nonutility Group		(4.8	)		(3.4	)
Corporate & other		0.1			(0.6	)

Basic EPS	$	0.63		$	0.55
Attributed to:
Utility Group		0.69			0.59
Nonutility Group		(0.06	)		(0.04	)
Corporate & other		-			-

Utility Group

In 2012, the Utility Group’s first quarter earnings were $56.0 million compared to $48.6 million in 2011, an increase of $7.4 million. The first quarter of 2012 has been positively impacted by new electric base rates implemented on May 3, 2011 and negatively impacted by extremely mild winter weather. The Utility Group also was impacted by lower interest expense as a result of refinancing’s occurring in the last quarter of 2011 and first quarter of 2012 and lower other operating costs.

Gas Utility Services

Gas utility services earned $37.5 million during the three months ended March 31, 2012, compared to earnings of $36.1 million in the first quarter of 2011. Results in 2012 have been impacted by lower uncollectible accounts expense driven primarily by lower gas costs and lower interest expense due to the recent refinancing activity. With rate designs that substantially limit the impact of weather on margin, heating degree days that were 71 percent of normal in Indiana and 82 percent of normal in Ohio had only a slightly negative impact on margin.

Electric utility services

The electric operations earned $15.6 million during the three months ended March 31, 2012, compared to $8.6 million in the prior year period. Factors impacting electric results were consistent with those impacting the overall Utility Group including increased base rates, mild weather, and lower other operating and interest costs.

Management estimates the impact of very mild weather on retail electric customer electric margin, compared to normal temperatures, to be approximately $3.6 million unfavorable in the first quarter of 2012. This compares to the first quarter of 2011, where management estimated a $0.2 million unfavorable impact on margin compared to normal.

Other utility operations

Year to date in 2012 earnings from other utility operations were $2.9 million compared to $3.9 million in 2011.

Nonutility Group

In the first quarter of 2012, the Nonutility Group incurred a net loss of $4.8 million, which compares to a net loss of $3.4 million in 2011. Infrastructure Services results increased $5.9 million quarter over quarter, reflective of increased demand for services. ProLiance’s results increased quarter over quarter as well, while Coal Mining and Energy Services results have decreased quarter over quarter. Seasonal earnings in the first quarter of 2011 were $7.1 million from retail energy marketer Vectren Source, which was sold on December 31, 2011, and $2.8 million for the full year in 2011.

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Dividends

Dividends declared for the three months ended March 31, 2012 were $0.350 per share, compared to $0.345 per share for the same period in 2011.

Use of Non-GAAP Performance Measures and Per Share Measures

Per share earnings contributions of the Utility Group, Nonutility Group, and Corporate and Other are presented and are non-GAAP measures. Such per share amounts are based on the earnings contribution of each group included in Vectren’s consolidated results divided by Vectren’s basic average shares outstanding during the period. The earnings per share of the groups do not represent a direct legal interest in the assets and liabilities allocated to the groups, but rather represent a direct equity interest in Vectren Corporation's assets and liabilities as a whole. These non-GAAP measures are used by management to evaluate the performance of individual businesses. In addition, other items giving rise to period over period variances, such as weather, may be presented on an after tax and per share basis. These amounts are calculated at a statutory tax rate divided by Vectren’s basic average shares outstanding during the period. Accordingly, management believes these measures are useful to investors in understanding each business’ contribution to consolidated earnings per share and in analyzing consolidated period to period changes and the potential for earnings per share contributions in future periods. Reconciliations of the non-GAAP measures to their most closely related GAAP measure of consolidated earnings per share are included throughout this discussion and analysis. The non-GAAP financial measures disclosed by the Company should not be considered a substitute for, or superior to, financial measures calculated in accordance with GAAP, and the financial results calculated in accordance with GAAP.

Detailed Discussion of Results of Operations

Following is a more detailed discussion of the results of operations of the Company’s Utility and Nonutility operations. The detailed results of operations for these groups are presented and analyzed before the reclassification and elimination of certain intersegment transactions necessary to consolidate those results into the Company’s Consolidated Condensed Statements of Income.

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Results of Operations of the Utility Group

The Utility Group is comprised of Utility Holdings’ operations and consists of the Company’s regulated operations and other operations that provide information technology and other support services to those regulated operations. Regulated operations consist of a natural gas distribution business that provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio and an electric transmission and distribution business, which provides electric distribution services to southwestern Indiana, and the Company’s power generating and wholesale power operations. In total, these regulated operations supply natural gas and/or electricity to over one million customers. Utility Group operating results before certain intersegment eliminations and reclassifications for the three months ended March 31, 2012 and 2011, follow:


	Three Months
	Ended March 31,
(In millions, except per share data)	2012		2011
OPERATING REVENUES
Gas utility	$	292.3	$	356.7
Electric utility		139.4		146.4
Other		0.4		0.5
Total operating revenues		432.1		503.6
OPERATING EXPENSES
Cost of gas sold		137.1		195.1
Cost of fuel & purchased power		44.7		59.5
Other operating		79.9		86.9
Depreciation & amortization		48.6		48.2
Taxes other than income taxes		15.9		18.0
Total operating expenses		326.2		407.7

OPERATING INCOME		105.9		95.9

OTHER INCOME - NET		2.2		1.7

INTEREST EXPENSE		17.7		20.4

INCOME BEFORE INCOME TAXES		90.4		77.2

INCOME TAXES		34.4		28.6

NET INCOME	$	56.0	$	48.6

CONTRIBUTION TO VECTREN BASIC EPS	$	0.69	$	0.59

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Utility Group 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.

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

Gas utility margin and throughput by customer type follows:


	Three Months
	Ended March 31,
(In millions)	2012		2011
Gas utility revenues	$	292.3	$	356.7
Cost of gas sold		137.1		195.1
Total gas utility margin	$	155.2	$	161.6
Margin attributed to:
Residential & commercial customers	$	135.1	$	139.7
Industrial customers		16.5		17.6
Other		3.6		4.3
Total gas utility margin	$	155.2	$	161.6
Sold & transported volumes in MMDth attributed to:
Residential & commercial customers		40.8		52.8
Industrial customers		27.8		28.8
Total sold & transported volumes		68.6		81.6

For the three months ended March 31, 2012, gas utility margins were $155.2 million and compared to 2011 decreased $6.4 million. Approximately $5.4 million of this decrease results from the impact of low natural gas prices and mild weather on revenue taxes, late and reconnect fees, and volumetric pass through costs. Large customer margin, net of the impacts of regulatory initiatives and tracked costs, decreased by $0.9 million due primarily to lower volumes sold, largely due to warmer weather. Weather also had some impact on small customers, reducing margin $0.7 million quarter over quarter. Returns generated on investments in bare steel/ cast iron and distribution riser replacement in Ohio increased margins $0.7 million quarter over quarter.

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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 March 31,
(In millions)	2012		2011

Electric utility revenues	$	139.4	$	146.4
Cost of fuel & purchased power		44.7		59.5
Total electric utility margin	$	94.7	$	86.9
Margin attributed to:
Residential & commercial customers	$	58.7	$	54.0
Industrial customers		25.3		23.4
Other customers		1.8		1.9
Subtotal: retail	$	85.8	$	79.3
Wholesale power & transmission system margin		8.9		7.6
Total electric utility margin	$	94.7	$	86.9
Electric volumes sold in GWh attributed to:
Residential & commercial customers		631.1		681.6
Industrial customers		681.7		661.9
Other customers		5.9		5.9
Total retail volumes sold		1,318.7		1,349.4

Retail

Electric retail utility margins were $85.8 million for the three months ended March 31, 2012, and compared to 2011 increased by $6.5 million. Margin across all customer classes increased by $7.6 million from new base rates effective May 3, 2011. Large customer margin increased $0.7 million on increasing volumes. Increases were offset primarily by the impacts of mild weather which reduced residential and commercial usage and margin.

Margin from Wholesale Electric Activities

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


	Three Months
	Ended March 31,
(In millions)	2012		2011
Off-system sales	$	3.0	$	2.0
Transmission system sales		5.9		5.6
Total wholesale margin	$	8.9	$	7.6

The Company earns a return on electric transmission projects constructed by the Company in its service territory that meet the criteria of MISO’s regional transmission expansion plans. Margin associated with these projects, including the reconciliation of recovery mechanisms, and other transmission system operations, totaled $5.9 million during the three months ended March 31, 2012, compared to $5.6 million for the same period in 2011. The increase in these transmission system sales is principally due to the increased investment in qualifying projects.

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One such project currently under construction meeting these expansion plan criteria is an interstate 345 Kv transmission line that will connect Vectren’s A.B. Brown Generating Station to a station in Indiana owned by Duke Energy to the north and to a station in Kentucky owned by Big Rivers Electric Corporation to the south. During the construction of these transmission assets and while these assets are in service, SIGECO will recover an approximate 10 percent return, inclusive of the FERC approved equity rate of return of 12.38 percent, on capital investments through a rider mechanism which is projected annually and reconciled the following year based on actual results. Of the total investment, which is expected to approximate $105 million, the Company has invested approximately $83 million as of March 31, 2012. The north leg of this expansion was placed in service in November 2010, and the south leg of this project is expected to be operational later in 2012.

For the three months ended March 31, 2012, margin from off-system sales was $3.0 million, compared to $2.0 million for the three months ended March 31, 2011. The base rate changes implemented in May 2011 require that wholesale margin from off-system sales earned above or below $7.5 million be shared equally with customers. This compares to a $10.5 million sharing threshold established in 2007. Results for the periods presented reflect the impact of that sharing recognized during the 2012 first quarter which increased margin year over year and offset the effects of lower volumes sold. Off-system sales totaled 48.7 GWh and 183.9 GWh during the three months ended March 31, 2012 and 2011, respectively, reflecting reduced opportunities in 2012 due to the mild weather.

Utility Group Operating Expenses

Other Operating

For the three months ended March 31, 2012, other operating expenses were $79.9 million, a decrease of $7.0 million, compared to 2011. The decrease results primarily from a $3.7 million in lower uncollectible accounts expense driven by lower gas prices increasing customer’s ability to pay and lower power supply operating costs of $1.5 million driven primarily by reduced variable production costs associated with mild winter weather. The remaining decrease is primarily attributable to lower pass through operating costs that are offset with lower Gas utility margin.

Depreciation & Amortization

For the three months ended March 31, 2012, depreciation and amortization expense was $48.6 million, compared to $48.2 million in 2011. The increase reflects increased plant placed into service, offset by lower amortization of certain deferred costs pursuant to the May 2011 electric base rate order. Such decreased amortizations were $0.9 million in 2012.

Taxes Other Than Income Taxes

Taxes other than income taxes were $15.9 million for the quarter, a decrease of $2.1 million compared to the prior year quarter. The decrease is primarily attributable to lower usage taxes associated with lower gas and fuel costs. These expenses are offset dollar-for-dollar with lower gas utility and electric utility revenues.

Other Income-Net

Other income-net reflects income of $2.2 million for the quarter, an increase of $0.5 million compared to the prior year quarter. The increase reflects increased AFUDC on gas utility construction projects.

Interest Expense

Interest expense was $17.7 million for the first quarter of 2012, a decrease of $2.7 million compared to 2011. The lower expense reflects fourth quarter of 2011 refinancing activity in which $250 million of long-term debt with a 6.625 percent interest rate matured and was replaced with $150 million of new long-term debt with an average interest rate of 5.12 percent and $100 million of short-term borrowings. During the fourth quarter of 2011, the Company also called $96.2 million of long-term debt at a rate of 5.95 percent and replaced that issuance in February 2012 with new debt at a rate of 5.0 percent.

Income Taxes

In 2012, federal and state income taxes were $34.4 million for the quarter, an increase of $5.8 million compared to the prior year quarter. The increase is primarily due to higher pre-tax income.

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Legislative Matters

Pipeline Safety Law

Indiana Senate Bill 251

Ohio House Bill 95

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Environmental Matters

Air Quality

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

In an effort to address the Court’s finding that CAIR did not adequately ensure attainment of pollutants in certain downwind states due to unlimited trading of SO2 and NOx allowances, CSPAR reduces the ability of facilities to meet emission reduction targets through allowance trading. Like CAIR, CSPAR sets individual state caps for SO2 and NOx emissions. However, unlike CAIR in which states allocated allowances through state implementation plans, CSPAR allowances were allocated to individual units directly through the federal rule. As finalized, CSAPR requires a 71 percent reduction of SO2 emissions compared to 2005 national levels and a 52 percent reduction of NOx emissions compared to 2005 national levels and that such reductions are to be achieved with initial step reductions beginning January 1, 2012, with final compliance to be achieved in 2014. Multiple administrative and judicial challenges have been filed, including requests to stay CSPAR’s implementation.

Utility Hazardous Air Pollutants (HAPs) Rule

Conclusions Regarding Air Regulations

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Notice of Violation Received

Water

Coal Ash Waste Disposal & Ash Ponds

Climate Change

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Impact of Legislative Actions & Other Initiatives is Unknown

Manufactured Gas Plants

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Rate & Regulatory Matters

Vectren South Electric Base Rate Filing

Coal Procurement Procedures

Vectren South Electric Fuel Cost Reduction

Vectren South Electric Demand Side Management Program Filing

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Vectren South Electric Dense Pack Filing

Vectren North Reporting Location Consolidation Proceeding

VEDO Continues the Process to Exit the Merchant Function

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Results of Operations of the Nonutility Group

The Nonutility Group operates in four primary business areas: Infrastructure Services, Energy Services, Coal Mining, and Energy Marketing. Infrastructure Services provides underground construction and repair. Energy Services provides performance contracting and renewable energy services. Coal Mining mines and sells coal. Energy Marketing markets and supplies natural gas and provides energy management services. There are also other legacy businesses that have invested in energy-related opportunities and services, real estate, and leveraged leases, among other investments. The Nonutility Group supports the Company’s regulated utilities pursuant to service contracts by providing natural gas supply services, coal, and infrastructure services. Nonutility Group earnings for the three ended March 31, 2012 and 2011 follow:


	Three Months
	Ended March 31,
(In millions, except per share amounts)	2012			2011
NET INCOME (LOSS)	$	(4.8	)	$	(3.4	)
CONTRIBUTION TO VECTREN BASIC EPS	$	(0.06	)	$	(0.04	)
NET INCOME (LOSS) ATTRIBUTED TO:
Infrastructure Services	$	3.0		$	(2.9	)
Energy Services		(1.7	)		(1.4	)
Coal Mining		(0.3	)		1.6
Energy Marketing
Vectren Source		-			7.1
ProLiance		(5.9	)		(7.5	)
Other Businesses		0.1			(0.3	)

Infrastructure Services

Infrastructure Services provides underground construction and repair services through Miller Pipeline (Miller) and Minnesota Limited, which was acquired on March 31, 2011. Inclusive of holding company costs, results from Infrastructure’s operations for the three months ended March 31, 2012 were earnings of $3.0 million, compared to a loss of $2.9 million year to date in 2011. The $5.9 million increase in earnings reflects increased demand across all infrastructure business areas and the acquisition of Minnesota Limited. The warm weather provided for the ability to earn a profit during a period that traditionally operates at a seasonal loss. Revenues in the first quarter of 2012 were $117.5 million. These operations had first quarter revenues in 2011 of $68.3 million, including $21.1 million from Minnesota Limited prior to its acquisition. Construction activity generally is expected to remain strong in 2012 and beyond as utilities and pipeline operators continue to replace their aging natural gas and oil infrastructure and as the need for shale gas and oil infrastructure becomes more prevalent.

Acquisition of Minnesota Limited

On March 31, 2011, the Company purchased Minnesota Limited, Inc., excluding certain assets. Minnesota Limited is a specialty contractor focusing on transmission pipeline construction and maintenance; pump station, compressor station, terminal and refinery construction; gas distribution; and hydrostatic testing. Minnesota Limited is headquartered in Big Lake, Minnesota and the majority of its customers are generally located in the northern Midwest region. The purchase price was approximately $83.4 million and included $14.8 million of net working capital, $34.4 million of property plant and equipment and $39.4 million of intangible assets, including goodwill. This acquisition positions the Company for anticipated growth in demand for gas and oil transmission construction resulting from the need to transport new sources of natural gas and oil found in shale formations and the need to upgrade the nation’s aging pipelines.

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Energy Services

Energy Services provides energy performance contracting and renewable energy services through Energy Systems Group, LLC (ESG). Inclusive of holding company costs, Energy Services’ operations contributed a loss of $1.7 million during the first quarter of 2012, compared to a loss of $1.4 million in 2011.

The lower results in 2012 reflect increased operating expenses associated with the continued ramp up of performance contracting personnel. ESG placed its first “build and own” anaerobic digester project into service in the first quarter of 2012. Two additional anaerobic digester projects are under construction and are expected to be placed into service later this year. As of March 31, 2012, performance contracting backlog was $73 million compared to $82 million on December 31, 2011, and $122 million on March 31, 2011. The lower backlog reflects some slowing in the demand for performance contracting projects. However, the national focus on energy conservation, renewable energy, and sustainability are expected to create favorable conditions for long-term growth in this business.

Coal Mining

Coal Mining owns mines that produce and sell coal to the Company’s utility operations and to third parties through its wholly owned subsidiary Vectren Fuels, Inc. (Vectren Fuels). Coal Mining, inclusive of holding company costs, operated at loss of $0.3 million during the quarter ended March 31, 2012, compared to earnings of $1.6 million in 2011. Results have been impacted by reduced productivity at the Prosperity mine where a thin coal seam and other unfavorable mining conditions have negatively impacted costs. These increased costs offset very favorable cost per ton results at Oaktown during the period. Revenues decreased as expected due to reduced pricing to customers associated with contracts that had price reopener clauses effective for 2012. Also, sales in the quarter were lower than expected due to the mild weather. Coal sold in the first quarter of 2012 was 1.1 million tons compared to 1.3 million tons in the first quarter of last year. Through March 31, 2012, Coal Mining segment revenues were $58.5 million, a $10.9 million decrease compared to 2011.

Vectren Fuels continues negotiation with a number of customers regarding sales in 2012 and beyond. Coal sales in 2012 are now estimated at 5.6 million tons, with 70 percent sold. The impact of lower prices is expected to result in earnings from Coal Mining operations in 2012 substantially lower than the results in 2011. However, long term, reduced volumes from Central Appalachia and the large number of scrubbers to be installed should drive strong demand for Illinois Basin coal. Changes in market conditions or other circumstances could cause actual results to be materially different from this expectation.

Coal Reserves

As of March 31, 2012 management estimates the Company’s total Illinois Basin coal reserves to be approximately 131 million tons. Of this amount, approximately 39 million tons are attributable to a mine that is currently under construction located at the Company’s Oaktown mining complex and is expected to open later in 2012. However, Vectren Fuels may continue to adjust this timing as it evaluates the impacts of market conditions. Once this mine is in production, Vectren Fuels underground mines are capable of producing about 7.5 million tons of coal per year.

Mine Safety Information

The Company, through Vectren Fuels, owns coal mines and related assets located in Indiana. The Company has retained independent third party contract mining companies to operate its coal mines. Five Star Mining LLC ("Five Star") is the contract mining company at the Prosperity underground mine and Black Panther Mining LLC ("Black Panther") is the contract mining company at the Oaktown underground mines. While in operation, Vigo-Cypress Creek, LLC was the contract mining company at Cypress Creek surface mine. The contract mining companies are the mine “operator”, as that term is used in both the Federal Mine Safety and Health Act of 1977 (the “Mine Act”) and the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010. All employees at the coal mines are hired, supervised, and paid by the contract mining companies. As the mine operator, the contract mining companies make all regulatory filings required by the MSHA. In most circumstances, however, the cost of fines and penalties assessed by MSHA are contractually passed through from the contract mining company to Vectren Fuels. The process of settling such claims can take years in certain circumstances. During the quarter ended March 31, 2012, the Company paid approximately $0.1 million related to assessments issued to the mine operators.

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On April 30, 2012, Five Star received a citation referred to as an “imminent danger” citation for high levels of methane near one of the roof bolting machines operating in the Prosperity Mine. The machine was idled for approximately two hours while the methane levels were lowered by adjusting airflow near the equipment. Other mining operations continued during this period. No injuries or property damage resulted from the incident.

More detailed information about the Company’s mines, including safety-related data, can be found at MSHA’s website, www.MSHA.gov. Prosperity operates under the MSHA identification number 1202249; Oaktown 1 operates under the identification number 1202394; Oaktown 2’s identification number is 1202418; and Cypress Creek’s identification number is 1202178. Mine safety-related data included on the MSHA website is influenced by the size of the mine, the level of activity at the mine, and the mine inspector’s judgment, among other factors. These factors can impact the comparability of information from mine to mine and time period to time period. Given the recent incidents at coal mines of other companies, a significant increase in the frequency and scope of MSHA inspections continues. In addition, both houses of Congress are considering new mine safety legislation. The Company is currently assessing the impact new laws and regulations may have on its investments.

Energy Marketing

Vectren Source

Earnings in the first quarter of 2011 from retail energy marketer Vectren Source, which was sold on December 31, 2011, were $7.1 million. Due to the seasonality of the retail gas marketing business and the mild weather, Vectren Source earned $2.8 million for the full year in 2011.

ProLiance

ProLiance, a nonutility energy marketing affiliate of Vectren and Citizens, provides services to a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions located throughout the Midwest and Southeast United States. ProLiance’s customers include Vectren’s Indiana utilities and Citizens’ utilities. ProLiance’s primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services. Consistent with its ownership percentage, Vectren is allocated 61 percent of ProLiance’s profits and losses; however, governance and voting rights remain at 50 percent for each member. Therefore, the Company accounts for its investment in ProLiance using the equity method of accounting. On March 17, 2011, an order was received from the IURC providing for ProLiance’s continued provision of gas supply services to the Company’s Indiana utilities and Citizens Energy Group through March 2016.

Vectren Energy Marketing and Services, Inc (EMS), a wholly owned subsidiary, holds the Company’s investment in ProLiance. Within the consolidated entity, EMS is responsible for certain financing costs associated with ProLiance and is also responsible for income taxes and allocated corporate expenses related to the Company’s portion of ProLiance’s results. During the three ended March 31, 2012 and 2011, EMS’ results related to the Company’s share of ProLiance’s results, which include financing costs income taxes, and other holding company costs, was a loss of approximately $5.9 million, compared to a loss of $7.5 million in 2011.

The reduced quarter over quarter loss primarily reflects the reduction in demand costs for both storage and transportation contracts. Current market have resulted in plentiful natural gas supply and lower and less volatile natural gas prices. Historical basis differences between physical and financial markets and summer and winter prices remain narrow compared to historical trends but have improved somewhat. As an example, the summer-winter strip spread was approximately $0.80 per dekatherm as of March 31, 2012, compared to approximately $0.50 per dekatherm as of March 31, 2011.

Efforts to lower the cost of pipeline and storage demand costs continue. Through negotiations and by dropping some uneconomical contracts as they expire, pipeline transportation and storage costs have been lowered to approximately $55 million for all of 2012, compared to $73 million in 2011. In addition to these reductions, additional opportunities exist to renegotiate or drop remaining contracts, including those with annual demand costs of $18 million that are scheduled to expire through 2015. At March 31, 2012, ProLiance had approximately $149 million of members’ equity on its balance sheet, no long-term debt outstanding and borrowings of $45 million on its short-term credit facility. Depressed market conditions continue, but the savings in demand costs and other actions are expected to continue to reduce ProLiance’s annual losses in 2012 compared to 2011. Changes in these market conditions or other circumstances could cause actual results to be materially above or below this range.

For the three months ended March 31, 2012 and 2011, the amounts recorded to Equity in earnings (losses) of unconsolidated affiliates related to ProLiance’s operations totaled a pre-tax loss of $7.6 million and $10.6 million, respectively.

Investment in Liberty Gas Storage

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Other Businesses

Within the Nonutility business segment, there are legacy investments involved in energy-related opportunities and services, real estate, leveraged leases, and other ventures. Other Businesses experienced earnings of $0.1 million during the three months ended March 31, 2012, compared to a loss of $0.3 million in 2011.

Impact of Recently Issued Accounting Guidance

Other Comprehensive Income (OCI)

Goodwill Testing

Fair Value Measurement and Disclosure

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Financial Condition

Within Vectren’s consolidated group, Utility Holdings primarily funds the short-term and long-term financing needs of the Utility Group operations, and Vectren Capital Corp (Vectren Capital) funds short-term and long-term financing needs of the Nonutility Group and corporate operations. Vectren Corporation guarantees Vectren Capital’s debt, but does not guarantee Utility Holdings’ debt. Vectren Capital’s long-term debt, including current maturities, and short-term obligations outstanding at March 31, 2012 approximated $410 million and $125 million, respectively. Utility Holdings’ outstanding long-term and short-term borrowing arrangements are jointly and severally guaranteed by Indiana Gas, SIGECO, and VEDO. Utility Holdings’ long-term debt and short-term obligations outstanding at March 31, 2012 approximated $822 million and $50 million, respectively. Additionally, prior to Utility Holdings’ formation, Indiana Gas and SIGECO funded their operations separately, and therefore, have long-term debt outstanding funded solely by their operations. SIGECO will also occasionally issue tax exempt debt to fund qualifying pollution control capital expenditures. Total Indiana Gas and SIGECO long-term debt outstanding at March 31, 2012, was $388 million.

The Company’s common stock dividends are primarily funded by utility operations. Nonutility operations have demonstrated profitability and the ability to generate cash flows. These cash flows are primarily reinvested in other nonutility ventures, but are also used to fund a portion of the Company’s dividends, and from time to time may be reinvested in utility operations or used for corporate expenses.

The credit ratings of the senior unsecured debt of Utility Holdings and Indiana Gas, at March 31, 2012, are A-/A3 as rated by Standard and Poor's Ratings Services (Standard and Poor’s) and Moody’s Investors Service (Moody’s), respectively. The credit ratings on SIGECO's secured debt are A/A1. Utility Holdings’ commercial paper has a credit rating of A-2/P-2. The current outlook of both Moody’s and Standard and Poor’s is stable. A security rating is not a recommendation to buy, sell, or hold securities. The rating is subject to revision or withdrawal at any time, and each rating should be evaluated independently of any other rating. Standard and Poor’s and Moody’s lowest level investment grade rating is BBB- and Baa3, respectively.

The Company’s consolidated equity capitalization objective is 45-55 percent of long-term capitalization. This objective may have varied, and will vary, depending on particular business opportunities, capital spending requirements, execution of long-term financing plans, and seasonal factors that affect the Company’s operations. The Company’s equity component was 48 percent and 47 percent of long-term capitalization at March 31, 2012 and December 31, 2011, respectively. Long-term capitalization includes long-term debt, including current maturities and debt subject to tender, as well as common shareholders’ equity.

Both long-term and short-term borrowing arrangements contain customary default provisions; restrictions on liens, sale-leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage and interest coverage, among other restrictions. Multiple debt agreements contain a covenant that the ratio of consolidated total debt to consolidated total capitalization will not exceed 65 percent. As of March 31, 2012, the Company was in compliance with all debt covenants.

Available Liquidity in Current Credit Conditions

The Company’s A-/A3 investment grade credit ratings have allowed it to access the capital markets as needed. The Company anticipates funding future capital expenditures and dividends principally through internally generated funds. Available liquidity has been enhanced by the extension of bonus depreciation legislation. However, the resources required for capital investment remain uncertain for a variety of factors including pending legislative and regulatory initiatives involving gas pipeline modernization; coal mine safety; and expanded EPA regulations for air, water, and fly ash. In addition, the Company may expand its businesses through acquisitions and/or joint venture investment. The timing and amount of such investments depends on a variety of factors, including the availability of acquisition targets and forecasted liquidity. The Company plans to enhance its liquidity as needed by accessing the capital markets. The Company may also consider disposing of certain assets, investments, or businesses to enhance or accelerate internally generated cash flow.

Consolidated Short-Term Borrowing Arrangements

At March 31, 2012, the Company has $600 million of short-term borrowing capacity, including $350 million for the Utility Group and $250 million for the wholly owned Nonutility Group and corporate operations. As reduced by borrowings currently outstanding, approximately $300 million was available for the Utility Group operations and approximately $125 million was available for the wholly owned Nonutility Group and corporate operations. Both Vectren Capital’s and Utility Holdings’ short-term credit facilities were renewed in November 2011 and are available through September 2016. These facilities are used to supplement working capital needs and also to fund capital investments and debt redemptions until financed on a long-term basis. Liquidity was increased by the $100 million Utility Holdings debt issuance in February 2012, the net proceeds of which were used to repay short-term indebtedness. Nonutility long-term debt totaling $35 million matured on April 25, 2012 and was replaced with short-term borrowings.

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


	Utility Group Borrowings						Nonutility Group Borrowings
(In millions)	2012			2011			2012			2011
Quarter End
Balance Outstanding	$	49.7		$	-		$	125.0		$	122.3
Weighted Average Interest Rate		0.43	%		n/a			1.42	%		2.01	%
Quarterly Average
Balance Outstanding	$	113.4		$	23.3		$	76.1		$	49.7
Weighted Average Interest Rate		0.49	%		0.39	%		1.42	%		2.04	%
Maximum Month End Balance Outstanding	$	214.2		$	42.5		$	125.0		$	122.3

ProLiance Short-Term Borrowing Arrangements

ProLiance, a nonutility energy marketing affiliate of the Company, has separate borrowing capacity available through a syndicated credit facility. This facility was renewed on May 18, 2011 at a $130 million capacity level as adjusted for letters of credit and current inventory and receivable balances. This new one year credit facility, which expires on May 24, 2012, reflects the impact of lower gas prices and resulting lower working capital need. As of March 31, 2012, $45 million in borrowings were outstanding. The facility is not guaranteed by Vectren or Citizens. ProLiance is currently working with financial institutions on replacement of the facility before its expiration with a new asset-based lending facility.

New Share Issues

The Company may periodically issue new common shares to satisfy the dividend reinvestment plan, stock option plan and other employee benefit plan requirements. New issuances added additional liquidity of $1.6 million and $1.7 million in the three months ended March 31, 2012 and 2011, respectively.

Utility Holdings 2012 Debt Issuance

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

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Potential Uses of Liquidity

Pension Funding Obligations

Management currently estimates contributing approximately $15 million to qualified pension plans in 2012. Contributions in 2013 and beyond are dependent on a variety of factors, including the Company’s progress toward attaining its long-term goal of being fully funded related to the plans’ accrued benefit obligations and the available sources of cash to fund such additional contributions. In the three months ended March 31, 2012, contributions to qualified plans totaled $3.4 million.

Corporate Guarantees

Performance Guarantees & Product Warranties

Specific to ESG, in its role as a general contractor in the performance contracting industry, at March 31, 2012, there are 73 open surety bonds supporting future performance. The average face amount of these bonds is $3.6 million, and the largest obligation has a face amount of $23.7 million. The maximum exposure of these obligations is less than these amounts for several factors, including the level of work already completed. At March 31, 2012, approximately 65 percent of work was completed on projects with open surety bonds. A significant portion of these commitments will be fulfilled within one year. In instances where ESG operates facilities, project guarantees extend over a longer period. In addition to its performance obligations, ESG also warrants the functionality of certain installed infrastructure generally for one year and the associated energy savings over a specified number of years.

Other Letters of Credit

As of March 31, 2012, Utility Holdings has letters of credit outstanding in support of two SIGECO tax exempt adjustable rate first mortgage bonds totaling $41.7 million. In the unlikely event the letters of credit were called, the Company could settle with the 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 March 31, 2012.

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Planned Capital Expenditures & Investments

Utility capital expenditures are estimated at $190 million for the remainder of 2012. Nonutility capital expenditures and investments are estimated at $105 million for the remainder of 2012.

Comparison of Historical Sources & Uses of Liquidity

Operating Cash Flow

The Company's primary source of liquidity to fund working capital requirements has been cash generated from operations, which totaled $168.8 million and $188.4 million for the three months ended March 31, 2012 and 2011, respectively. The reduced cash flow in 2012 reflects lower utility and coal sales in the quarter (and thus higher inventory balances) as impacted by the mild weather. In 2011, the seasonal decline in inventory at Vectren Source resulted in operating cash flow of approximately $22 million. The less cash generated by working capital was partially offset by lower contributions to pension and postretirement plans in 2012.

Financing Cash Flow

Net cash flow required for financing activities was $81.5 million during the three months ended March 31, 2012 compared to requirements of $24.0 million in 2011. Financing activity in 2012 primarily reflects the $100 million debt issuance by Utility Holdings, the payment of dividends, and repayment of short-term borrowings. Less short term borrowings were repaid in in 2011 due primarily to cash needs to acquire Minnesota Limited.

Investing Cash Flow

Cash flow required for investing activities was $81.7 million and $140.3 million during the three months ended March 31, 2012 and 2011, respectively. The prior year investing activities reflect the purchase of Minnesota Limited. The current year period reflects an approximate $30 million increase in cash required for capital expenditures. Mild weather during the first quarter allowed for greater capital expenditures for bare steel/cast iron projects and planned power supply outages. In addition, the increase in capital expenditures reflects additional investment in the Company’s coal mines.

Forward-Looking Information

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

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

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

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

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·	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, electricity, coal, and other nonutility products and services; impacts on both gas and electric large customers; lower residential and commercial customer counts; higher operating expenses; and further reductions in the value of certain nonutility real estate and other legacy investments.

·	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.

·	The performance of projects undertaken by the Company’s nonutility businesses and the success of efforts to invest in and develop new opportunities, including but not limited to, the Company’s infrastructure, energy services, coal mining, and energy marketing strategies.

Factors affecting coal mining operations including MSHA guidelines and interpretations of those guidelines, as well as additional mine regulations and more frequent and broader inspections that could result from the recent mining incidents at coal mines of other companies; geologic, equipment, and operational risks; the ability to execute and negotiate new sales contracts and resolve contract interpretations; volatile coal market prices and demand; supplier and contract miner performance; the availability of key equipment, contract miners and commodities; availability of transportation; and the ability to access/replace coal reserves.

·	Factors affecting the Company’s investment in ProLiance including natural gas price volatility and basis; the ability to lower fixed contract costs; and availability of credit.

·	Employee or contractor workforce factors including changes in key executives, collective bargaining agreements with union employees, aging workforce issues, work stoppages, or pandemic illness.

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

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

·	Changes in or additions to federal, state or local legislative requirements, such as changes in or additions to tax laws or rates, pipeline safety regulations, environmental laws, including laws governing greenhouse gases, mandates of sources of renewable energy, and other regulations.

The 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 AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to various business risks associated with commodity prices, interest rates, and counter-party credit. These financial exposures are monitored and managed by the Company as an integral part of its overall risk management program. The Company’s risk management program includes, among other things, the use of derivatives. The Company 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.

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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 2011 Form 10-K and is therefore not presented herein.

ITEM 4. CONTROLS AND PROCEDURES

Changes in Internal Controls over Financial Reporting

During the quarter ended March 31, 2012, there have been no changes to the Company’s internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

As of March 31, 2012, the Company conducted an evaluation under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of the effectiveness and the design and operation of the Company's disclosure controls and procedures. Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer have concluded that the Company's disclosure controls and procedures are effective as of March 31, 2012, to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is:

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

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

PART II

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, and rate and regulatory matters. The consolidated condensed financial statements are included in Part 1 Item 1.

ITEM 1A. RISK FACTORS

Investors should consider carefully factors that may impact the Company’s operating results and financial condition, causing them to be materially adversely affected. The Company’s risk factors have not materially changed from the information set forth in Item 1A Risk Factors included in the Vectren 2011 Form 10-K and are therefore not presented herein.

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

Periodically, the Company purchases shares from the open market to satisfy share requirements associated with the Company’s share-based compensation plans. The following chart contains information regarding open market purchases made by the Company to satisfy share-based compensation requirements during the quarter ended March 31, 2012.


			Total Number of	Maximum Number
	Number of		Shares Purchased as	of Shares That May
	Shares	Average Price	Part of Publicly	Be Purchased Under
Period	Purchased	Paid Per Share	Announced Plans	These Plans
January 1-31	-	$-	-	-
February 1-29	3,784	29.62	-	-
March 1-31	-	-	-	-

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Not Applicable

ITEM 4. MINE SAFETY DISCLOSURES

Not Applicable

ITEM 5. OTHER INFORMATION

Not Applicable

ITEM 6. EXHIBITS

Exhibits and Certifications

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

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

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

101 Interactive Data File.

101.INS* XBRL Instance Document

101.SCH* XBRL Taxonomy Extension Schema

101.CAL* XBRL Taxonomy Extension Calculation Linkbase

101.DEF* XBRL Taxonomy Extension Definition Linkbase

101.LAB* XBRL Taxonomy Extension Labels Linkbase

101.PRE* XBRL Taxonomy Extension Presentation Linkbase

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

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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 CORPORATION
			Registrant




	May 3, 2012		/s/Jerome A. Benkert, Jr.
			Jerome A. Benkert, Jr.
			Executive Vice President and Chief Financial Officer
			(Principal Financial Officer)



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