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, 2009

[_]	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)

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 □ No

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 r

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

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

□ 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	81,041,060	April 30, 2009
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:

Steven M. Schein

Vice President, Investor Relations

sschein@vectren.com

Definitions

AFUDC: allowance for funds used during construction	MMBTU: millions of British thermal units
APB: Accounting Principles Board	MW: megawatts
EITF: Emerging Issues Task Force	MWh / GWh: megawatt hours / thousands of megawatt hours (gigawatt hours)
FASB: Financial Accounting Standards Board	OCC: Ohio Office of the Consumer Counselor
FERC: Federal Energy Regulatory Commission	OUCC: Indiana Office of the Utility Consumer Counselor
IDEM: Indiana Department of Environmental Management	PUCO: Public Utilities Commission of Ohio
IURC: Indiana Utility Regulatory Commission	SFAS: Statement of Financial Accounting Standards
MCF / BCF: thousands / billions of cubic feet	USEPA: United States Environmental Protection Agency
MDth / MMDth: thousands / millions of dekatherms	Throughput: combined gas sales and gas transportation volumes
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 Cash Flows	7
	Notes to Unaudited Consolidated Condensed Financial Statements	8
2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
3	Quantitative and Qualitative Disclosures About Market Risk	42
4	Controls and Procedures	43

	PART II. OTHER INFORMATION
1	Legal Proceedings	43
1A	Risk Factors	43
2	Unregistered Sales of Equity Securities and Use of Proceeds	43
6	Exhibits	43
	Signatures	44

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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,
	2009		2008

ASSETS

Current Assets
Cash & cash equivalents	$	19.4	$	93.2
Accounts receivable - less reserves of $6.1 &
$5.6, respectively		214.9		226.7
Accrued unbilled revenues		83.0		197.0
Inventories		92.7		131.0
Recoverable fuel & natural gas costs		-		3.1
Prepayments & other current assets		40.8		124.6
Total current assets		450.8		775.6

Utility Plant
Original cost		4,411.2		4,335.3
Less: accumulated depreciation & amortization		1,642.7		1,615.0
Net utility plant		2,768.5		2,720.3

Investments in unconsolidated affiliates		164.9		179.1
Other utility & corporate investments		26.6		25.7
Other nonutility investments		46.0		45.9
Nonutility property - net		410.3		390.2
Goodwill - net		240.3		240.2
Regulatory assets		203.1		216.7
Other assets		35.1		39.2
TOTAL ASSETS	$	4,345.6	$	4,632.9

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,
	2009			2008

LIABILITIES & SHAREHOLDERS' EQUITY

Current Liabilities
Accounts payable	$	131.3		$	266.1
Accounts payable to affiliated companies		38.0			75.2
Refundable fuel & natural gas costs		25.6			4.1
Accrued liabilities		217.8			175.0
Short-term borrowings		113.6			519.5
Current maturities of long-term debt		0.4			0.4
Long-term debt subject to tender		80.0			80.0
Total current liabilities		606.7			1,120.3


Long-term Debt - Net of Current Maturities &
Debt Subject to Tender		1,438.6			1,247.9

Deferred Income Taxes & Other Liabilities
Deferred income taxes		357.0			353.4
Regulatory liabilities		318.2			315.1
Deferred credits & other liabilities		239.2			244.6
Total deferred credits & other liabilities		914.4			913.1

Commitments & Contingencies (Notes 7, 9-11)

Common Shareholders' Equity
Common stock (no par value) – issued & outstanding
81.0 & 81.0, respectively		660.8			659.1
Retained earnings		758.5			712.8
Accumulated other comprehensive income (loss)		(33.4	)		(20.3	)
Total common shareholders' equity		1,385.9			1,351.6

TOTAL LIABILITIES & SHAREHOLDERS' EQUITY	$	4,345.6		$	4,632.9

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 data)


	Three Months Ended March 31,
	2009		2008
OPERATING REVENUES
Gas utility	$	527.4	$	633.6
Electric utility		125.0		127.2
Nonutility revenues		142.8		141.3
Total operating revenues		795.2		902.1
OPERATING EXPENSES
Cost of gas sold		354.6		462.0
Cost of fuel & purchased power		47.0		46.0
Cost of nonutility revenues		74.2		95.3
Other operating		122.7		115.8
Depreciation & amortization		51.4		47.4
Taxes other than income taxes		23.5		26.8
Total operating expenses		673.4		793.3
OPERATING INCOME		121.8		108.8
OTHER INCOME
Equity in earnings of unconsolidated affiliates		12.6		14.0
Other income – net		2.4		3.0
Total other income		15.0		17.0

INTEREST EXPENSE		22.7		25.3

INCOME BEFORE INCOME TAXES		114.1		100.5

INCOME TAXES		41.3		36.5

NET INCOME	$	72.8	$	64.0

AVERAGE COMMON SHARES OUTSTANDING		80.6		76.0
DILUTED COMMON SHARES OUTSTANDING		80.7		76.1

EARNINGS PER SHARE OF COMMON STOCK:
BASIC	$	0.90	$	0.84
DILUTED	$	0.90	$	0.84

DIVIDENDS DECLARED PER SHARE OF
COMMON STOCK	$	0.34	$	0.33

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,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	72.8		$	64.0
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization		51.4			47.4
Deferred income taxes & investment tax credits		11.3			12.7
Equity in earnings of unconsolidated affiliates		(12.6	)		(14.0	)
Provision for uncollectible accounts		4.3			5.3
Expense portion of pension & postretirement periodic benefit cost		2.6			1.9
Other non-cash charges - net		1.0			2.0
Changes in working capital accounts:
Accounts receivable & accrued unbilled revenues		120.7			(26.8	)
Inventories		38.8			96.8
Recoverable/refundable fuel & natural gas costs		24.7			(3.4	)
Prepayments & other current assets		83.2			91.7
Accounts payable, including to affiliated companies		(167.0	)		(74.4	)
Accrued liabilities		43.4			84.3
Unconsolidated affiliate dividends		4.3			2.9
Changes in noncurrent assets		14.8			5.9
Changes in noncurrent liabilities		(9.2	)		(7.9	)
Net cash flows from operating activities		284.5			288.4
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt, net of issuance costs		191.2			171.5
Stock option exercises & other		1.5			-
Requirements for:
Dividends on common stock		(27.1	)		(24.7	)
Retirement of long-term debt		(0.6	)		(103.2	)
Net change in short-term borrowings		(405.9	)		(251.9	)
Net cash flows from financing activities		(240.9	)		(208.3	)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Other collections		0.9			1.9
Requirements for:
Capital expenditures, excluding AFUDC equity		(117.4	)		(69.6	)
Unconsolidated affiliate investments		(0.1	)		(0.1	)
Other investments		(0.8	)		(7.7	)
Net cash flows from investing activities		(117.4	)		(75.5	)
Net change in cash & cash equivalents		(73.8	)		4.6
Cash & cash equivalents at beginning of period		93.2			20.6
Cash & cash equivalents at end of period	$	19.4		$	25.2

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

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VECTREN CORPORATION AND SUBSIDIARY COMPANIES

NOTES TO 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 operating public utilities: Indiana Gas Company, Inc. (Indiana Gas or Vectren North), Southern Indiana Gas and Electric Company (SIGECO or Vectren South), and the Ohio operations (VEDO or Vectren Ohio). Utility Holdings also has other assets that provide information technology and other services to the three utilities. 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 over 567,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to over 141,000 electric customers and approximately 111,000 gas customers located near Evansville in southwestern Indiana. SIGECO also owns and operates electric generation to serve its electric customers and optimizes those assets in the wholesale power market. Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana. The Ohio operations provide energy delivery services to approximately 317,000 natural gas customers located near Dayton in west central Ohio. The Ohio operations are owned as a tenancy in common by Vectren Energy Delivery of Ohio, Inc. (VEDO), a wholly owned subsidiary of Utility Holdings (53 percent ownership), and Indiana Gas (47 percent ownership). The Ohio operations generally do business as Vectren Energy Delivery of Ohio.

The Company, through Vectren Enterprises, Inc. (Enterprises), is involved in nonutility activities in three primary business areas: Energy Marketing and Services, Coal Mining and Energy Infrastructure Services. Energy Marketing and Services markets and supplies natural gas and provides energy management services. Coal Mining mines and sells coal. Energy Infrastructure Services provides underground construction and repair services and performance contracting and renewable energy services. Enterprises also has other legacy businesses that have invested in energy-related opportunities and services, real estate, and leveraged leases, among other investments. These operations 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. 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, 2008, filed with the Securities and Exchange Commission on February 19, 2009, on Form 10-K. Because of the seasonal nature of the Company’s utility operations, the results shown on a quarterly basis are not necessarily indicative of annual results.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

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3.	Comprehensive Income

Comprehensive income consists of the following:


	Three Months Ended March 31,
(In millions)	2009			2008
Net income	$	72.8		$	64.0
Comprehensive loss of unconsolidated affiliates		(21.9	)		(10.1	)
Cash flow hedges
Unrealized gains/(losses)		0.1			-
Reclassifications to net income		(0.1	)		(0.2	)
Income tax benefit		8.9			4.0
Total comprehensive income	$	59.8		$	57.7

Accumulated other comprehensive income arising from unconsolidated affiliates is primarily the Company’s portion of ProLiance Holdings, LLC’s accumulated comprehensive income related to use of cash flow hedges. (See Note 7 for more information on ProLiance.)

4.	Earnings Per Share

Earnings per share (EPS) is calculated in accordance with SFAS 128, “Earnings Per Share” and its related interpretations. Basic earnings per share is computed by dividing net income available to common shareholders by the weighted-average number of common shares outstanding for the period. Diluted earnings per share 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 earnings per share calculations for the periods presented in these financial statements.

	Three Months Ended March 31,
(In millions, except per share data)	2009			2008

Numerator:
Reported net income	$	72.8		$	64.0
Less: Income allocated to participating share-based securities		(0.2	)		(0.2	)
Reported net income (Basic & Diluted EPS)	$	72.6		$	63.8

Denominator:
Weighted average common shares outstanding (Basic EPS)		80.6			76.0
Conversion of stock options		0.1			0.1
Adjusted weighted average shares outstanding and
assumed conversions outstanding (Diluted EPS)		80.7			76.1

Basic earnings per share	$	0.90		$	0.84
Diluted earnings per share	$	0.90		$	0.84

For the three months ended March 31, 2009, options to purchase 837,100 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 ranged from $23.19 to $27.15. For the three months ended March 31, 2008, all options were dilutive. For the three months ended March 31, 2008, the effect of an equity forward was antidilutive and was therefore excluded from the calculation of diluted EPS.

Participating Securities

On January 1, 2009, the Company adopted FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (FSP EITF 03-6-1). FSP EITF 03-6-1 clarified that unvested share-based payment awards that contain rights to nonforfeitable dividends participate in undistributed earnings with common shareholders. Awards of this nature that impact the EPS calculation are participating securities. The presence of a participating security requires EPS to be calculated using the two-class method.

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Of the approximate 81 million shares outstanding as of March 31, 2009, unvested share-based payment awards that contain rights to nonforfeitable dividends comprise less than one percent. The Company recently prospectively changed share-based payment awards such that dividends on awards granted in 2009 and beyond are subject to forfeiture.

As a result of the insignificant level of participating securities subject to the two-class method of computing earnings per share, the adoption of FSP EITF 03-6-1 had immaterial impacts to both current and prior period earnings per share calculations.

5.	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 $15.9 million and $19.3 in the three months ended March 31, 2009 and 2008, respectively. Expenses associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.

6.	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 qualified pension plans and the SERP are aggregated under the heading “Pension Benefits.” Other postretirement benefit plans are aggregated under the heading “Other Benefits.”

Net Periodic Benefit Cost

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

	Three Months Ended March 31,
	Pension Benefits						Other Benefits
(In millions)	2009			2008			2009			2008
Service cost	$	1.6		$	1.5		$	0.1		$	0.1
Interest cost		3.9			3.8			1.1			1.0
Expected return on plan assets		(4.1	)		(4.1	)		(0.1	)		(0.1	)
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		0.6			-			0.1			-
Net periodic benefit cost	$	2.4		$	1.6		$	1.3		$	1.1

Employer Contributions to Qualified Pension Plans

Currently, the Company expects to contribute approximately $25 to $30 million to its pension plan trusts for 2009. Through March 31, 2009, contributions of $4.7 million have been made to the pension plan trusts.

7.	Transactions with 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 and nonutility gas supply operations as well as Citizens’ utilities. ProLiance’s primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services. 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.

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Summarized Financial Information

Summarized financial information related to ProLiance is presented below:


	Three Months Ended March 31,
(In millions)	2009			2008
Summarized statement of income information:
Revenues	$	658.8		$	809.6
Operating income		21.3			23.3
ProLiance's earnings		21.8			23.6

	As of March 31,			As of December 31,
(In millions)	2009			2008
Summarized balance sheet information:
Current assets	$	442.9		$	661.5
Noncurrent assets		104.3			104.2
Current liabilities		316.7			514.0
Noncurrent liabilities		3.7			3.6
Members' equity		310.5			295.8
Accumulated other comprehensive income (loss)		(83.7	)		(47.7	)

Vectren records its 61 percent share of ProLiance’s earnings after income taxes and an interest expense allocation.

Regulatory Matter

ProLiance self reported to the Federal Energy Regulatory Commission (FERC) in October 2007 possible non-compliance with the FERC’s capacity release policies. ProLiance has taken corrective actions to assure that current and future transactions are compliant. ProLiance is committed to full regulatory compliance and is cooperating fully with the FERC regarding these issues. ProLiance believes that it has adequately reserved for this matter. Although the outcome of any legal or regulatory proceedings resulting from these matters cannot be predicted, the final resolution of these matters is not expected to have a material impact on the Company’s consolidated operating results, financial position or cash flows.

Investment in Liberty Gas Storage

Liberty Gas Storage, LLC (Liberty) is a joint venture between a subsidiary of ProLiance and a subsidiary of Sempra Energy (SE). ProLiance is the minority member with a 25 percent interest, which it accounts for using the equity method. Liberty, as currently permitted, is a 17 BCF salt dome facility in southern Louisiana, near Sulphur, Louisiana. Liberty also owns a second site near Hackberry, Louisiana with the potential to develop an additional 17 BCF of storage. ProLiance has a long term contract for approximately 5 Bcf of working gas capacity. The total project cost incurred at the Sulphur site through March 31, 2009 is approximately $200 million. ProLiance’s portion of the cost incurred is approximately $50 million.

In late 2008, SE advised ProLiance that the completion of this phase of Liberty’s development at the Sulphur site has been delayed by subsurface and well-completion problems. To date, corrective measures have been unsuccessful. Among other options, other corrective measures are being evaluated but it is possible that the salt-cavern facility may not go into service, or may have reduced capacity when placed in service. ProLiance estimates the maximum exposure of its investment in the Sulphur site is $35 million. The Company’s proportionate share would be $12 million after tax. The Company believes that such a charge, should it occur, would not have a material adverse effect on either the Company’s or ProLiance’s financial position, cash flows, or liquidity, but it could be material to net income in any one accounting period. Further, it is not expected that the delay in Liberty’s development will impact ProLiance’s ability to meet the needs of its customers.

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Transactions with ProLiance

Purchases from ProLiance for resale and for injections into storage for the three months ended March 31, 2009 and 2008 totaled $202.9 million and $289.4 million, respectively. Amounts owed to ProLiance at March 31, 2009, and December 31, 2008, for those purchases were $38.0 million and $75.1 million, respectively, and are included in Accounts payable to affiliated companies. 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.

Amounts charged by ProLiance for gas supply services are established by supply agreements with each utility.

8.	2009 Long-Term Debt Transactions

Post March 31, 2009 Utility Holdings Debt Issuance

On April 7, 2009, Utility Holdings entered into a private placement Note Purchase Agreement pursuant to which institutional investors purchased from Utility Holdings $100 million in 6.28 percent senior unsecured notes due April 7, 2020 (2020 Notes). The 2020 Notes are guaranteed by Utility Holdings’ three utilities: SIGECO, Indiana Gas, and VEDO. These guarantees are full and unconditional and joint and several. The proceeds from the sale of the 2020 Notes and net of issuance costs totaled approximately $99.3 million. Since this issuance occurred after March 31, 2009, its impact is not reflected in the consolidated balance sheet.

The 2020 Notes have no sinking fund requirements, and interest payments are due semi-annually. The 2020 Notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in the Utility Holdings’ $515 million short-term credit facility.

SIGECO 2009 Debt Issuance

On March 26, 2009, SIGECO remarketed the remaining $41.3 million of long-term debt held in treasury at December 31, 2008, receiving proceeds, net of issuance costs of approximately $40.6 million. The remarketed notes have a variable rate interest rate which is reset weekly and are supported by a standby letter of credit backed by Utility Holdings’ $515 million short-term credit facility. The notes are collateralized by SIGECO’s utility plant, and $9.8 million are due in 2015 and $31.5 million are due in 2025. The initial interest rate paid to investors was 0.55 percent. The equivalent rate of the debt at inception, inclusive of interest, weekly remarketing fees, and letter of credit fees approximated 1 percent.

Vectren Capital Corp. 2009 Debt Issuance

On March 11, 2009, Vectren and Vectren Capital Corp., its wholly-owned subsidiary (Vectren Capital), entered into a private placement Note Purchase Agreement (the “2009 Note Purchase Agreement”) pursuant to which various institutional investors purchased the following tranches of notes from Vectren Capital: (i) $30 million in 6.37 percent senior notes, Series A due 2014, (ii) $60 million in 6.92 percent senior notes, Series B due 2016 and (iii) $60 million in 7.30 percent senior notes, Series C due 2019. These senior notes are unconditionally guaranteed by Vectren, the parent of Vectren Capital. These notes have no sinking fund requirements, and interest payments are due semi-annually. The proceeds from the sale of the notes and net of issuance costs totaled approximately $149.0 million.

The 2009 Note Purchase Agreement contains customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in the Vectren Capital $255 million short-term credit facility.

On March 11, 2009, Vectren and Vectren Capital also entered into a first amendment with respect to prior note purchase agreements for the remaining outstanding Vectren Capital debt, other than the $22.5 million series due in 2010, to conform the covenants in certain respects to those contained in the 2009 Note Purchase Agreement.

9.	Commitments & Contingencies

Guarantees

In the normal course of business, Vectren Corporation issues guarantees supporting the performance of its consolidated subsidiaries as well as its unconsolidated affiliates. Such guarantees which contain varying terms generally allow those subsidiaries and affiliates to execute transactions on more favorable terms than the subsidiaries and affiliates could obtain without such a guarantee. Guarantees may include posted letters of credit, leasing guarantees, and contract performance guarantees.

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Related specifically to guarantees supporting the performance and activities of unconsolidated affiliates, as of March 31, 2009, such guarantees approximated $3 million. These guarantees relate primarily to arrangements between ProLiance and various natural gas pipeline operators. The Company has accrued no liabilities for these unconsolidated affiliate guarantees as they were executed prior to the adoption of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.”

Legal Proceedings

10.	Environmental Matters

Clean Air Act

The Clean Air Interstate Rule (CAIR) is an allowance cap and trade program requiring further reductions from coal-burning power plants in NOx emissions beginning January 1, 2009 and SO2 emissions beginning January 1, 2010, with a second phase of reductions in 2015. On July 11, 2008, the US Court of Appeals for the District of Columbia vacated the federal CAIR regulations. Various parties filed motions for reconsideration, and on December 23, 2008, the Court reinstated the CAIR regulations and remanded the regulations back to the USEPA for promulgation of revisions in accordance with the Court’s July 11, 2008 Order. Thus, the original version of CAIR promulgated in March of 2005 remains effective while USEPA revises it per the Court’s guidance. It is possible that a revised CAIR will require further reductions in NOx and SO2 from SIGECO’s generating units. SIGECO is in compliance with the current CAIR Phase I annual NOx reduction requirements in effect on January 1, 2009. Utilization of the Company’s inventory of NOx and SO2 allowances may also be impacted if CAIR is further revised; however, most of the these allowances were granted to the Company at zero cost, so a reduction in carrying value is not expected.

Similarly, in March of 2005, USEPA promulgated the Clean Air Mercury Rule (CAMR). CAMR is an allowance cap and trade program requiring further reductions in mercury emissions from coal-burning power plants. The CAMR regulations were vacated by the US Court of Appeals for the DC Circuit in July 2008. It is possible that the vacatur of the CAMR regulations will lead to increased support for the passage of a multi-pollutant bill in Congress. It is also possible that the USEPA will promulgate a revised mercury regulation in 2009.

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

Further, the IURC granted SIGECO authority to invest in an SO2 scrubber at its generating facility that is jointly owned with ALCOA (the Company’s portion is 150 MW). The order allows SIGECO to recover an approximate 8 percent return on capital investments through a rider mechanism which is periodically updated for actual costs incurred less post in-service depreciation expense. Through March 31, 2009, the Company has invested approximately $100 million in this project. The scrubber was placed into service on January 1, 2009. Recovery through a rider mechanism of associated operating expenses including depreciation expense associated with the scrubber also began on January 1, 2009. With the SO2 scrubber fully operational, SIGECO is positioned for compliance with the additional SO2 reductions required by Phase I CAIR commencing on January 1, 2010.

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SIGECO’s coal fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOx. SIGECO's investments in scrubber, SCR and fabric filter technology allows for compliance with existing regulations and should position it to comply with future reasonable pollution control legislation, if and when, reductions in mercury and further reductions in NOx and SO2 are promulgated by USEPA.

Climate Change

There are currently several forms of legislation being circulated at the federal level addressing the climate change issue. These proposals generally involve either: 1) a “cap and trade” approach where there is a progressive cap on greenhouse gas emissions and an auctioning and subsequent trading of allowances among those that emit greenhouse gases or 2) a carbon tax. Most proposed legislation also includes a federal renewable energy portfolio standard. Currently no legislation has passed either house of Congress. However, The U.S. House of Representatives is currently debating a comprehensive energy bill proposal that includes a carbon cap and trade program, a federal renewable portfolio standard, and utility energy efficiency targets.

In the absence of federal legislation, several regional initiatives throughout the United States are in the process of establishing regional cap and trade programs. While no climate change legislation is pending in the State of Indiana, the State is an observer of the Midwestern Regional Greenhouse Gas Reduction Accord, and in the recently completed 2009 session, its legislature debated, but did not pass, a renewable energy portfolio standard.

In April of 2007, the US Supreme Court determined that greenhouse gases meet the definition of "air pollutant" under the Clean Air Act and ordered the USEPA to determine whether greenhouse gas emissions from new motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. In April of 2009, the USEPA 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. Upon finalization, the endangerment finding is the first step toward USEPA regulating carbon emissions through the existing Clean Air Act in the absence of specific carbon legislation from Congress. Therefore, any new regulations would likely also impact major stationary sources of greenhouse gases. The USEPA has also proposed a significant new mandatory greenhouse gas emissions registry.

Impact of Legislative Actions and Other Initiatives is Unknown

If legislation requiring reductions in CO2 and other greenhouse gases or legislation mandating a renewable energy portfolio standard is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants, nonutility coal mining operations, and possibly natural gas distribution businesses. Further, any legislation would likely impact the Company’s generation resource planning decisions. At this time and in the absence of final legislation, compliance costs and other effects associated with reductions in greenhouse gas emissions or obtaining renewable energy sources remain uncertain. The Company has gathered preliminary estimates of the costs to comply with a cap and trade approach to controlling greenhouse gas emissions. A preliminary investigation demonstrated costs to comply would be significant, first to operating expenses for the purchase of allowances, and later to capital expenditures as technology becomes available to control greenhouse gas emissions. However, these compliance cost estimates are very sensitive to highly uncertain assumptions, including allowance prices and energy efficiency targets. Costs to purchase allowances that cap greenhouse gas emissions should be considered a cost of providing electricity, and as such, the Company believes recovery should be timely reflected in rates charged to customers. Approximately 22 percent of electric volumes sold in 2008 were delivered to municipal and other wholesale customers. As such, the Company has some flexibility to modify the level of these transactions to reduce overall emissions and reduce costs associated with complying with new environmental regulations.

Environmental Remediation Efforts

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

Indiana Gas identified the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites for which it may have some remedial responsibility. Indiana Gas completed a remedial investigation/feasibility study (RI/FS) at one of the sites under an agreed order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. Indiana Gas submitted the remainder of the sites to the IDEM's Voluntary Remediation Program (VRP) and is currently conducting some level of remedial activities, including groundwater monitoring at certain sites, where deemed appropriate, and will continue remedial activities at the sites as appropriate and necessary.

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Indiana Gas accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, Indiana Gas has recorded cumulative costs that it reasonably expects to incur totaling approximately $22.2 million. The estimated accrued costs are limited to Indiana Gas’ share of the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26 sites with other potentially responsible parties (PRP), which limit Indiana Gas’ costs at these 19 sites to between 20 percent and 50 percent.

With respect to insurance coverage, Indiana Gas has received and recorded settlements from all known insurance carriers under insurance policies in effect when these plants were in operation in an aggregate amount approximating $20.5 million.

In October 2002, SIGECO received a formal information request letter from the IDEM regarding five manufactured gas plants that it owned and/or operated and were not enrolled in the IDEM’s VRP. In October 2003, SIGECO filed applications to enter four of the manufactured gas plant sites in IDEM's VRP. The remaining site is currently being addressed in the VRP by another Indiana utility. SIGECO added those four sites into the renewal of the global Voluntary Remediation Agreement that Indiana Gas has in place with IDEM for its manufactured gas plant sites. That renewal was approved by the IDEM in February 2004. SIGECO is also named in a lawsuit filed in federal district court in May 2007, involving another site subject to potential environmental remediation efforts.

SIGECO has filed a declaratory judgment action against its insurance carriers seeking a judgment finding its carriers liable under the policies for coverage of further investigation and any necessary remediation costs that SIGECO may accrue under the VRP program and/or related to the site subject to the May 2007 lawsuit. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, SIGECO has recorded cumulative costs that it reasonably expects to incur totaling approximately $9.2 million. With respect to insurance coverage, SIGECO has received and recorded settlements from insurance carriers under insurance policies in effect when these sites were in operation in an aggregate amount of $8.1 million.

Environmental remediation costs related to Indiana Gas’ and SIGECO’s manufactured gas plants and other sites have had a minor impact on results of operations or financial condition since cumulative costs recorded to date approximate PRP and insurance settlement recoveries. Such cumulative costs 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, 2009 and December 31, 2008, approximately $6.0 million and $6.5 million, respectively, of accrued, but not yet spent, remediation costs are included in Other Liabilities related to both the Indiana Gas and SIGECO sites.

11.	Rate & Regulatory Matters

Vectren Energy Delivery of Ohio, Inc. (VEDO) Gas Base Rate Order Received

On January 7, 2009, the PUCO issued an order approving the stipulation reached in the VEDO rate case. The order provides for a rate increase of nearly $14.8 million, an overall rate of return of 8.89 percent on rate base of about $235 million; an opportunity to recover costs of a program to accelerate replacement of cast iron and bare steel pipes, as well as certain service risers; and base rate recovery of an additional $2.9 million in conservation program spending.

The order also adjusted the rate design used to collect the agreed-upon revenue from VEDO's customers. The order allows for the phased movement toward a straight fixed variable rate design which places substantially all of the fixed cost recovery in the customer service charge. A straight fixed variable design mitigates most weather risk as well as the effects of declining usage, similar to the Company’s lost margin recovery mechanism, which expired when this new rate design went into effect on February 22, 2009. In 2008, annual results include approximately $4.3 million of revenue from a lost margin recovery mechanism that does continue once this base rate increase is in effect. After year one, nearly 90 percent of the combined residential and commercial base rate margins will be recovered through the customer service charge. The OCC has filed a request for rehearing on the rate design finding by the PUCO. The rehearing request mirrors similar requests filed by the OCC in each case where the PUCO has approved similar rate designs, and all such requests have been denied.

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With this rate order the Company has in place for its Ohio gas territory rates that allow for the phased implementation of a straight fixed variable rate design that mitigates both weather risk and lost margin; tracking of bad debt and percent of income payment plan (PIPP) expenses; base rate recovery of pipeline integrity management expense; timely recovery of costs associated with the accelerated replacement of bare steel and cast iron pipes, as well as certain service risers; and expanded conservation programs now totaling up to $5 million in annual expenditures.

MISO

Since 2002 and with the IURC’s approval, the Company has been a member of the Midwest Independent System Operator, Inc. (MISO), a FERC approved regional transmission organization. The MISO serves the electrical transmission needs of much of the Midwest and maintains operational control over the Company’s electric transmission facilities as well as that of other Midwest utilities. Since April 1, 2005, the Company has been an active participant in the MISO energy markets, bidding its owned generation into the Day Ahead and Real Time markets and procuring power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market.

The Company is typically in a net sales position with MISO as generation capacity is in excess of that needed to serve native load and is only occasionally in a net purchase position. When the Company is a net seller such net revenues are included in Electric Utility revenues and when the Company is a net purchaser such net purchases are included in Cost of fuel and purchased power. Net positions are determined on an hourly basis. Since the Company became an active MISO member, its generation optimization strategies primarily involve the sale of excess generation into the MISO day ahead and real-time markets. Net revenues from wholesale activities included in Electric Utility revenues totaled $12.9 million and $21.4 million in the three months ended March 31, 2009 and 2008 respectively.

The Company also receives transmission revenue that results from other members’ use of the Company’s transmission system. These revenues are also included in Electric Utility revenues. Generally, these transmission revenues along with costs charged by the MISO are considered components of base rates and any variance from that included in base rates is recovered/refunded through tracking mechanisms.

As a result of MISO’s operational control over much of the Midwestern electric transmission grid, including SIGECO’s transmission facilities, SIGECO’s continued ability to import power, when necessary, and export power to the wholesale market has been, and may continue to be, impacted. Given the nature of MISO’s policies regarding use of transmission facilities, as well as ongoing FERC initiatives, and a Day 3 ancillary services market (ASM), where MISO began providing a bid-based regulation and contingency operating reserve markets on January 6, 2009, it is difficult to predict near term operational impacts. The IURC has approved the Company’s participation in the ASM and has granted authority to defer costs associated with ASM. To date impacts from the ASM have been minor.

The need to expend capital for improvements to the regional transmission system, both to SIGECO’s facilities as well as to those facilities of adjacent utilities, over the next several years is expected to be significant. Beginning in June 2008, the Company began timely recovering its investment in certain new electric transmission projects that benefit the MISO infrastructure at a FERC approved rate of return. Such revenues recorded in Electric Utility revenues associated with projects meeting the criteria of MISO’s transmission expansion plans totaled $2.1 million for the three months March 31, 2009.

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Vectren South Electric Lost Margin Recovery Filing

In 2008, the Company made an initial filing with the IURC requesting a multi-year program to promote energy conservation and expanded demand side management programs within its Vectren South electric utility. As proposed, costs associated with these programs would be recovered through a tracking mechanism. The implementation of these programs is designed to work in tandem with a lost margin recovery mechanism. This mechanism, as proposed, allows recovery of a portion of rates from residential and commercial customers based on the level of customer revenues established in Vectren South’s last electric general rate case. This program is similar to programs authorized by the IURC in the Company’s Indiana natural gas service territories. In April of 2009, all filings were completed, and the Company would expect an IURC decision to occur during 2009.

12.	Derivatives

Adoption of SFAS 161

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133” (SFAS 161). SFAS 161 describes enhanced disclosures under SFAS 133 and requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation in order to better convey the purpose of derivative use in terms of the risks that the entity is intending to manage. The Company adopted the qualitative and quantitative disclosures required in both interim and annual financial statements described in SFAS 161 on January 1, 2009.

Accounting Policy for Derivatives

The Company occasionally executes derivative contracts in the normal course of operations while buying and selling commodities to be used in operations, optimizing its generation assets, and managing risk. The Company accounts for its derivative contracts in accordance with SFAS 133, “Accounting for Derivatives” and its related amendments and interpretations. In most cases, SFAS 133 requires a derivative to be recorded on the balance sheet as an asset or liability measured at its market value and that a change in the derivative's market value be recognized currently in earnings unless specific hedge criteria are met.

When an energy contract that is a derivative is designated and documented as a normal purchase or normal sale (NPNS), it is exempted from mark-to-market accounting. Most energy contracts executed by the Company are subject to the NPNS exclusion. Such energy contracts include real time and day ahead purchase and sale contracts with the MISO, natural gas purchases from ProLiance and others, and wind farm and other electric generating capacity contracts.

When the Company engages in energy contracts and financial contracts that are derivatives and are not subject to the NPNS or other exclusions identified in SFAS 133, such contracts are recorded at market value as current or noncurrent assets or liabilities depending on their value and on when the contracts are expected to be settled. Contracts and any associated collateral with counter-parties subject to master netting arrangements are presented net in the Consolidated Balance Sheets. The offset resulting from carrying the derivative at fair value on the balance sheet is charged to earnings unless it qualifies as a hedge or is subject to SFAS 71. When hedge accounting is appropriate, the Company assesses and documents hedging relationships between the derivative contract and underlying risks as well as its risk management objectives and anticipated effectiveness. When the hedging relationship is highly effective, derivatives are designated as hedges. The market value of the effective portion of the hedge is marked to market in accumulated other comprehensive income for cash flow hedges. Ineffective portions of hedging arrangements are marked-to-market through earnings. For fair value hedges, both the derivative and the underlying hedged item are marked to market through earnings. The offset to contracts affected by SFAS 71 are marked-to-market as a regulatory asset or liability. Market value for derivative contracts is determined using quoted market prices from independent sources. The Company rarely enters into contracts where internal models are used calculate fair values that impact the financial statements.

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Derivative Use in Risk Mitigation Strategies

Following is a more detailed discussion of activities where the Company may use derivatives to mitigate risk.

Emission Allowance Risk Management

The Company’s wholesale power marketing operations are exposed to price risk associated with emission allowances. To mitigate this risk, the Company executed call options to hedge wholesale SO2 emission allowance utilization in future periods. The Company designated and documented these derivatives as cash flow hedges. At March 31, 2009, a deferred gain of approximately $0.1 million remains in accumulated comprehensive income related to these call options which will be recognized in earnings as emission allowances are utilized. As of and for the periods reported in these financial statements, ending values and activity relating to emission allowance derivatives affecting the statements of income and cash flows were not significant.

Natural Gas Procurement Risk Management

The Company’s regulated operations have limited exposure to commodity price risk for purchases and sales of natural gas and electricity for retail customers due to current Indiana and Ohio regulations which, subject to compliance with those regulations, allow for recovery of such purchases through natural gas and fuel cost adjustment and other mechanisms. Although regulated operations are exposed to limited commodity price risk, volatile natural gas prices can still have negative economic impacts, including higher interest costs. The Company may mitigate these economic risks by using derivative contracts. These contracts are subject to regulation which allows for reasonable and prudent hedging costs to be recovered through rates. When regulation is involved, SFAS 71 controls when the offset to mark-to-market accounting is recognized in earnings.

The Company’s wholly owned gas retail operations also mitigate price risk associated with forecasted natural gas purchases by using derivatives. These nonregulated gas retail operations may also from time-to-time execute weather derivatives to mitigate extreme weather affecting unregulated gas retail sales.

As of and for the periods reported in these financial statements, ending values and activity relating to natural gas procurement derivatives affecting the statements of income and cash flows were not significant.

Interest Rate Risk Management

The Company is exposed to interest rate risk associated with its borrowing arrangements. Its risk management program seeks to reduce the potentially adverse effects that market volatility may have on interest expense. The Company has used interest rate swaps and treasury locks to hedge forecasted debt issuances and other interest rate swaps to manage interest rate exposure.

As of March 31, 2009 and December 31, 2008, no interest rate swaps were outstanding. Related to derivative instruments associated with completed debts issuances, an approximate $7.8 million net regulatory asset remains at March 31, 2009. In the three months ended March 31, 2009 and 2008, $0.1 million was reclassified as a decrease to interest expense. The Company estimates a $0.3 million reduction to interest expense will occur in 2009 related to the amortization of this net position.

Credit Features

Master agreements in place with certain counterparties contain provisions involving the Company’s credit ratings. If ratings were to fall below investment grade, counterparties to these arrangements could request immediate payment or demand immediate and ongoing full overnight collateralization on net liability positions. Currently, contracts to purchase natural gas by the Company’s nonutility retail gas marketer to fulfill its retail sales are the only significant derivative-like instruments impacted by credit contingent features. Such contracts are subject to the NPNS exclusion. Generally, the natural gas supply period supported by these arrangements is 60 days, but in some instances, may include forecasted purchases up to 12 months in advance. If the credit-risk-related contingent features underlying these agreements were triggered, the Company would be required to post approximately $5 million of additional collateral at March 31, 2009.

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13.	Fair Value Measurements

Financial assets and liabilities and certain nonfinancial assets and liabilities that are revalued at fair value on a recurring basis are valued and disclosed in accordance with SFAS No. 157, “Fair Value Measurements” (SFAS 157). SFAS 157 defines a hierarchy for disclosing fair value measurements based primarily on the level of public data used in determining fair value. Level 1 inputs include quoted market prices in active markets for identical assets or liabilities; Level 2 inputs include inputs other than Level 1 inputs that are directly or indirectly observable; and Level 3 inputs include unobservable inputs using estimates and assumptions developed using internal models, which reflect what a market participant would use to determine fair value. For the balance sheet dates presented in these financial statements, other than $75 million invested in money market funds and included in Cash and cash equivalents as of December 31, 2008, the Company had no material assets or liabilities recorded at fair value outstanding, and none outstanding valued using Level 3 inputs. The money market investments were valued using Level 1 inputs, and none were outstanding at March 31, 2009.

On January 1, 2009, the Company adopted the provisions of SFAS 157 as they relate to nonfinancial assets and nonfinancial liabilities that are measured at fair value on a nonrecurring basis, such as the initial measurement of an asset retirement obligation or the use of fair value goodwill, intangible assets and long-lived assets impairment tests. This adoption had no significant impact on the Company’s operating results or financial condition.

14.	Impact of Other Newly Adopted and Newly Issued Accounting Principles

SFAS 141R

On January 1, 2009, the Company adopted SFAS No. 141, “Business Combinations” (SFAS 141R). SFAS 141R establishes principles and requirements for how the acquirer of an entity (1) recognizes and measures the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree (2) recognizes and measures acquired goodwill or a bargain purchase gain and (3) determines what information to disclose in its financial statements in order to enable users to assess the nature and financial effects of the business combination. SFAS 141R applies to all transactions or other events in which one entity acquires control of one or more businesses and applies to all business entities. Because the provisions of this standard are applied prospectively, the impact to the Company cannot be determined until the transactions occur.

SFAS 160

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements-an Amendment of ARB No. 51” (SFAS 160). SFAS 160 establishes accounting and reporting standards that require ownership percentages in material subsidiaries held by parties other than the parent be clearly identified, labeled, and presented separately from the parent’s equity in the equity section of the consolidated balance sheet; the amount of consolidated net income attributable to the parent and the noncontrolling interest to be clearly identified and presented on the face of the consolidated income statement; that changes in the parent’s ownership interest while it retains control over its subsidiary be accounted for consistently; that when a subsidiary is deconsolidated, any retained noncontrolling equity investment be initially measured at fair value; and that sufficient disclosure is made to clearly identify and distinguish between the interests of the parent and the noncontrolling owners. The adoption of SFAS 160 on January 1, 2009 had an immaterial impact to the Company’s presentation of its financial position and operating results.

EITF 08-05

On January 1, 2009, the Company adopted EITF Issue No. 08-5, “Issuer's Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement” (EITF 08-5). EITF 08-5 states that companies should not include the effect of third-party credit enhancements in the fair value measurement of the related liabilities. EITF 08-5 also requires companies with outstanding liabilities measured or disclosed at fair value to disclose the existence of credit enhancements, to disclose valuation techniques used to measure liabilities and to include a discussion of changes, if any, from the valuation techniques used to measure liabilities in prior periods.

As of March 31, 2009, the Company has approximately $251.1 million of debt instruments that are supported by a third party credit enhancement feature such as insurance from a monoline insurer or a letter of credit posted by third party that supports the Company’s credit facilities. It is not anticipated, the Company’s valuation techniques will change materially at a result of the adoption of EITF 08-5.

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FASB Staff Position (FSP) 142-3

In April 2008, the FASB issued FSP No. 142-3, Determination of the Useful Life of Intangible Assets. FSP No. 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, Goodwill and Other Intangible Assets. The Company adopted FSP No. 142-3 as of January 1, 2009 and such adoption did not have a material impact on the consolidated financial statements.

FASB Staff Positions on Fair Value Accounting and Disclosure

In April 2009 the FASB released FSP No. FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (FSP 107-1) to require an entity to disclose in the body or in the accompanying notes of its summarized financial information for interim reporting periods and in its financial statements for annual reporting periods the fair value of all financial instruments for which it is practicable to estimate that value, whether recognized or not recognized in the statement of financial position, as required by FASB Statement No. 107. FSP 107-1 is effective for interim reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FSP 107-1 does not require disclosures for earlier periods presented for comparative purposes at initial adoption. In periods after initial adoption, FSP 107-1 requires comparative disclosures only for periods ending after initial adoption.

An entity may early adopt FSP 107-1 only if it also elects to early adopt FSP FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly which provides additional guidance for estimating fair value in accordance with FASB Statement No. 157 when the volume and level of activity for the asset or liability have significantly decreased and also includes guidance on identifying circumstances that indicate a transaction is not orderly and FSP FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” which impacts the impairment testing of debt securities held for investment purposes and the presentation and disclosure requirements for debt and equity securities described in FASB Statement 115.

The Company will adopt these FSP’s for its 2009 second quarter reporting. It is not expected the impact of adoption will be material to its cash flows, operations, or financial condition, but will impact interim period fair value disclosures.

FSP No. FAS 132(R)-1

In December 2008, the FASB issued FSP No. FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (FSP 132(R)-1). FSP 132(R)-1 amends the plan asset disclosures required under FAS Statement No. 132(R) to provide guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. Guidance provided by this FSP relates to disclosures about investment policies and strategies, categories of plan assets, fair value measurements of plan assets, and significant concentrations of risk. FSP FAS 132(R)-1 is effective for fiscal years ending after December 15, 2009. The Company will include FSP FAS 132(R)-1’s disclosure requirements in its 2009 annual financial statements.

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 into a Gas Utility Services operating segment and an Electric Utility Services operating segment. The Gas Utility Services segment provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio. The Electric Utility Services segment provides electric distribution services primarily to southwestern Indiana, and includes the Company’s power generating and wholesale power operations. The Company manages its regulated operations as separated between Energy Delivery, which includes the gas and electric transmission and distribution functions, and Power Supply, which includes the power generating and wholesale power operations. In total, regulated operations supply natural gas and /or electricity to over one million customers.

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The Nonutility Group is comprised of one operating segment that includes various subsidiaries and affiliates investing in energy marketing and services, coal mining, and energy infrastructure services, among other energy-related opportunities.

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

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

	Three Months Ended March 31,
(In millions)	2009			2008
Revenues
Utility Group
Gas Utility Services	$	527.4		$	633.6
Electric Utility Services		125.0			127.2
Other Operations		10.7			11.7
Eliminations		(10.3	)		(11.1	)
Total Utility Group		652.8			761.4
Nonutility Group		191.2			169.7
Eliminations		(48.8	)		(29.0	)
Consolidated Revenues	$	795.2		$	902.1


Profitability Measure - Net Income
Gas Utility Services	$	41.2		$	42.3
Electric Utility Services		11.9			12.6
Other Operations		3.1			3.1
Utility Group Net Income		56.2			58.0
Nonutility Group Net Income		16.5			6.3
Corporate & Other Group Net Income		0.1			(0.3	)
Consolidated Net Income	$	72.8		$	64.0

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Table of Contents

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

Description of the Business

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. Nonutility Group operations are discussed below as primary operations and other operations. Primary nonutility operations denote areas of management’s forward looking focus.

Per share earnings contributions of the Utility Group, Nonutility Group, and Corporate and Other are presented. 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. Accordingly management believes these measures are useful to investors in understanding each business’ contribution to consolidated earnings per share and analyzing period to period changes.

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.

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Table of Contents

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.

Executive Summary of Consolidated Results of Operations

The following discussion and analysis should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto as well as the Company’s 2008 annual report filed on Form 10-K.


		Three Months Ended March 31,
(In millions, except per share data)		2009		2008
Net income		$	72.8	$	64.0
Attributed to:	Utility Group		56.2		58.0
	Nonutility Group		16.5		6.3
	Corporate & other		0.1		(0.3	)
Basic earnings per share		$	0.90	$	0.84
Attributed to:	Utility Group		0.70		0.76
Nonutility Group			0.20		0.08
Corporate & other			-		-

Results

For the three months ended March 31, 2009, net income was $72.8 million, or $0.90 per share, compared to $64.0 million, or $0.84 per share for the three months ended March 31, 2008. Year over year increases in primary nonutility operations offset lower Utility Group results. Earnings per share are $0.04 per share lower due to the increased number of common shares outstanding as a result of the issuance of common shares in June 2008.

Utility Group

In 2009, the Utility Group’s earnings were $56.2 million compared to $58.0 million in 2008, a decrease of $1.8 million. The decrease resulted primarily from lower customer usage and from wholesale power sales, both of which have been impacted by the recession. Increased revenues associated with regulatory initiatives and lower interest costs partially offset these declines.

Nonutility Group

The Nonutility Group’s 2009 first quarter earnings were $16.5 million compared to $6.3 million in 2008. The increase is due to earnings from the primary nonutility operations. The Company’s primary nonutility operations contributed $17.7 million in the first quarter of 2009, compared to $4.9 million in the first quarter of 2008. Primary nonutility operations are Energy Marketing and Services companies, Coal Mining operations, and Energy Infrastructure Services companies.

Of the $12.8 million increase in primary nonutility group earnings, $6.4 million is attributable to Energy Marketing and Services and $3.7 million is attributable to Coal Mining. The increase in Energy Marketing and Services’ earnings primarily results from increased retail gas marketing earnings. Coal Mining earnings have increased as expected as contracts reflecting the higher Illinois Basin coal market prices began on January 1st. Seasonal losses associated with Energy Infrastructure Services narrowed approximately $2.7 million quarter over quarter to $0.5 million.

Dividends

Dividends declared for the three months ended March 31, 2009, were $0.335 per share compared to $0.325 per share for the same period in 2008.

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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 operations are presented and analyzed before the reclassification and elimination of certain intersegment transactions necessary to consolidate those results into the Company’s Consolidated Statements of Income.

Results of Operations of the Utility Group

The Utility Group is comprised of Utility Holdings’ operations. The operations of the Utility Group consist 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 primarily 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, 2009 and 2008 follow:


	Three Months Ended March 31,
(In millions, except per share data)	2009		2008
OPERATING REVENUES
Gas utility	$	527.4	$	633.6
Electric utility		125.0		127.2
Other		0.4		0.6
Total operating revenues		652.8		761.4
OPERATING EXPENSES
Cost of gas sold		354.6		462.0
Cost of fuel & purchased power		47.0		46.0
Other operating		79.3		74.0
Depreciation & amortization		43.9		40.7
Taxes other than income taxes		22.8		26.2
Total operating expenses		547.6		648.9

OPERATING INCOME		105.2		112.5

OTHER INCOME - NET		1.5		2.0

INTEREST EXPENSE		18.7		20.8

INCOME BEFORE INCOME TAXES		88.0		93.7

INCOME TAXES		31.8		35.7

NET INCOME	$	56.2	$	58.0

CONTRIBUTION TO VECTREN BASIC EPS	$	0.70	$	0.76

Significant Fluctuations

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. 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 costs can be volatile and are generally collected on a dollar-for-dollar basis from customers.

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Sales of natural gas and electricity to residential and commercial customers are seasonal and are impacted by weather. Trends in average use among natural gas residential and commercial customers have tended to decline in recent years as more efficient appliances and furnaces are installed and the price of natural gas have been volatile. Normal temperature adjustment (NTA) and lost margin recovery mechanisms largely mitigate the effect on Gas Utility margin that would otherwise be caused by variations in volumes sold to these customers due to weather and changing consumption patterns. Indiana Gas’ territory has both an NTA since 2005 and lost margin recovery since 2006. SIGECO’s natural gas territory has an NTA since 2005 and lost margin recovery since 2007. The Ohio service territory had lost margin recovery since 2006. The Ohio lost margin recovery mechanism ended when new base rates went into effect in February 2009. This mechanism was replaced by a rate design, commonly referred to as a straight fixed variable rate design, which is more dependent on service charge revenues and less dependent on volumetric revenues than previous rate designs. This new rate design, which will be fully phased in February 2010, will eventually mitigate most weather risk in Ohio. SIGECO’s electric service territory has neither NTA nor lost margin recovery mechanisms.

Gas and electric margin generated from sales to large customers (generally industrial and other contract customers) is primarily impacted by overall economic conditions and changes in demand for those customers’ products. The recent recession has had and may continue to have some negative impact on both gas and electric large customers. This impact has included, and may continue to include, tempered growth, significant conservation measures, and perhaps even plant closures or bankruptcies. While no one industrial customer comprises 10 percent of consolidated margin, the top five industrial electric customers comprise approximately 11 percent of electric utility margin in the three months ended March 31, 2009, and therefore any significant decline in their collective margin could adversely impact operating results. Deteriorating economic conditions may also lead to continued lower residential and commercial customer counts.

Margin is also impacted by the collection of state mandated taxes, which fluctuate with gas and fuel costs, as well as other tracked expenses. Expenses subject to tracking mechanisms include Ohio bad debts and percent of income payment plan expenses, costs associated with exiting the merchant function and to perform riser replacement in Ohio, Indiana gas pipeline integrity management costs, costs to fund Indiana energy efficiency programs, MISO transmission revenues and costs, as well as the gas cost component of bad debt expense based on historical experience and unaccounted for gas. Unaccounted for gas is also tracked in the Ohio service territory. Certain operating costs, including depreciation, associated with operating environmental compliance equipment and regional transmission investments are also tracked.

Electric wholesale activities are primarily affected by market conditions, the level of excess generating capacity, and electric transmission availability. Following is a discussion and analysis of margin generated from regulated utility operations.

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

Gas Utility margin and throughput by customer type follows:

	Three Months Ended March 31,
(In millions)	2009		2008

Gas utility revenues	$	527.4	$	633.6
Cost of gas sold		354.6		462.0
Total gas utility margin	$	172.8	$	171.6
Margin attributed to:
Residential & commercial customers	$	152.6	$	150.9
Industrial customers		15.1		16.5
Other		5.1		4.2
Sold & transported volumes in MMDth attributed to:
Residential & commercial customers		52.6		57.8
Industrial customers		24.1		28.7
Total sold & transported volumes		76.7		86.5

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For the quarter ended March 31, 2009, gas utility margins were $172.8 million, increasing $1.2 million over the prior year. Margin increases associated with regulatory initiatives including the full impact of the Vectren North base rate increase effective in February 14, 2008 and the Vectren Ohio base rate increase effective February 22, 2009, were $3.5 million. Increases were offset by impacts of the recession, including an estimated $1.9 million decrease in industrial customer margin and slightly lower residential and commercial customer counts, which decreased margin approximately $0.6 million. The impact of operating costs, including revenue and usage taxes, recovered in margin was generally flat year over year and reflects lower revenue taxes offset by higher pass through operating expenses. The average cost per dekatherm of gas purchased for the three months ended March 31, 2009, was $7.39 compared to $9.44 in 2008.

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

Electric Utility margin and volumes sold by customer type follows:

	Three Months Ended March 31,
(In millions)	2009		2008

Electric utility revenues	$	125.0	$	127.2
Cost of fuel & purchased power		47.0		46.0
Total electric utility margin	$	78.0	$	81.2
Margin attributed to:
Residential & commercial customers	$	52.5	$	51.3
Industrial customers		19.1		20.2
Other customers		0.7		1.6
Subtotal: retail & firm wholesale	$	72.3	$	73.1
Wholesale power marketing	$	5.7	$	8.1

Electric volumes sold in GWh attributed to:
Residential & commercial customers		671.6		715.2
Industrial customers		509.0		600.7
Other customers		5.1		36.6
Total retail & firm wholesale volumes sold		1,185.7		1,352.5

Retail Margin

Electric retail and firm wholesale utility margins were $72.3 million for the three months ended March 31, 2009, a decrease over the prior year of $0.8 million. Increased margin associated with returns on pollution control investments totaled $0.5 million; margin associated with tracked costs such as recovery of pollution control and MISO operating expenses increased $2.6 million. Management estimates other usage declines associated with the weak economy to have decreased margin approximately $1.4 million for residential and commercial customers and $2.0 million for industrial customers.

Margin from Wholesale 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. A majority of the margin generated from these activities is associated with wholesale off-system sales, and 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)	2009		2008
Off-system sales	$	2.7	$	7.2
Transmission system sales		3.0		0.9
Total wholesale power marketing	$	5.7	$	8.1

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For the quarter ended March 31, 2009, total wholesale margins were $5.7 million, representing a decrease of $2.4 million, compared to 2008.

During 2009, margin from off-system sales retained by the Company decreased $4.5 million compared to 2008. The Company experienced lower wholesale power marketing margins due to lower wholesale prices, coupled with increasing coal costs. Off-system sales totaled 341.6 GWh in 2009, compared to 463.4 GWh in 2008. The base rate case effective August 17, 2007, requires that wholesale margin from off-system sales earned above or below $10.5 million be shared equally with customers as measured on a fiscal year ending in August, and results reflect the impact of that sharing.

Beginning in June 2008, the Company began earning a return on electric transmission projects constructed by the Company in its service territory that benefit reliability throughout the region. Margin associated with these projects totaled $2.1 million in 2009.

Utility Group Operating Expenses

Other Operating Expenses

For the three months ended March 31, 2009, other operating expenses were $79.3 million, an increase of $5.3 million, compared to 2008. Substantially all of the increase results from increased costs directly recovered through utility margin. Examples of such tracked costs include Ohio bad debts, Indiana gas pipeline integrity management costs, costs to fund Indiana energy efficiency programs, and MISO transmission revenues and costs, among others. Other operating costs were generally flat.

Depreciation & Amortization

Depreciation expense was $43.9 million for the quarter, an increase of $3.2 million compared to 2008. Plant additions include the approximate $100 million SO2 scrubber placed into service January 1, 2009 for which depreciation totaling $1.1 million is directly recovered in electric utility margin.

Taxes Other Than Income Taxes

Taxes other than income taxes were $22.8 million for the quarter, a decrease of $3.4 million compared to the prior year quarter. The decrease is attributable to lower utility receipts, excise, and usage taxes caused principally by lower gas prices and is tracked in revenues.

Other Income-Net

Other-net reflects income of $1.5 million for the quarter, a decrease of $0.5 million compared to the prior year quarter. The decrease is primarily attributable to lower capitalization of funds used during construction as a result of lower borrowing costs.

Interest Expense

Interest expense was $18.7 million for the quarter, a decrease of $2.1 million compared to the prior year quarter. The decrease reflects lower short-term interest rates and lower average short-term debt balances.

Income Taxes

In 2009, federal and state income taxes were $31.8 million for the quarter, a decrease of $3.9 million compared to the prior year quarter. The lower taxes are primarily due to lower pretax income.

Environmental Matters

Clean Air Act

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Climate Change

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

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

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

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

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

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

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

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Current Initiatives to Increase Conservation and Reduce Emissions

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

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

·	Recently executing long-term contracts to purchase 80MW of wind energy generated by wind farms in Benton County, Indiana;

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

·	Implementing conservation initiatives in the Company’s Indiana and Ohio gas utility service territories;

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

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

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

·	Developing renewable energy and energy efficiency performance contracting projects through its wholly owned subsidiary, Energy Systems Group.

Legislative Actions and Other Climate Change Initiatives

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Impact of Legislative Actions and Other Initiatives is Unknown

If legislation requiring reductions in CO2 and other greenhouse gases or legislation mandating a renewable energy portfolio standard is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants, nonutility coal mining operations, and possibly natural gas distribution businesses. Further, any legislation would likely impact the Company’s generation resource planning decisions. At this time and in the absence of final legislation, compliance costs and other effects associated with reductions in greenhouse gas emissions or obtaining renewable energy sources remain uncertain. The Company has gathered preliminary estimates of the costs to comply with a cap and trade approach to controlling greenhouse gas emissions. A preliminary investigation demonstrated costs to comply would be significant, first to operating expenses for the purchase of allowances and energy efficiency targets, and later to capital expenditures as technology becomes available to control greenhouse gas emissions. However, these compliance cost estimates are very sensitive to highly uncertain assumptions, including allowance prices. Costs to purchase allowances that cap greenhouse gas emissions should be considered a cost of providing electricity, and as such, the Company believes recovery should be timely reflected in rates charged to customers. Approximately 22 percent of electric volumes sold in 2008 were delivered to municipal and other wholesale customers. As such, the Company has some flexibility to modify the level of these transactions to reduce overall emissions and reduce costs associated with complying with new environmental regulations.

Environmental Remediation Efforts

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Rate and Regulatory Matters

Vectren Energy Delivery of Ohio, Inc. (VEDO) Gas Base Rate Order Received

MISO

Since February 2002 and with the IURC’s approval, the Company has been a member of the Midwest Independent System Operator, Inc. (MISO), a FERC approved regional transmission organization. The MISO serves the electrical transmission needs of much of the Midwest and maintains operational control over the Company’s electric transmission facilities as well as that of other Midwest utilities. Since April 1, 2005, the Company has been an active participant in the MISO energy markets, bidding its owned generation into the Day Ahead and Real Time markets and procuring power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market.

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One such project currently under construction is an interstate 345 kilovolt transmission line that will connect Vectren’s A B Brown 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. Throughout the project, SIGECO is to 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 updated annually for estimated costs to be incurred. Of the total investment, which is expected to approximate $70 million, as of March 31, 2009, the Company has invested approximately $4.6 million. The Company expects this project to be operational in 2011. At that time, any operating expenses including depreciation expense are also expected to be recovered through a FERC approved rider mechanism. Further, the approval allows for recovery of expenditures made even in the event currently unforeseen difficulties delay or permanently halt the project.

Vectren South Electric Lost Margin Recovery Filing

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Results of Operations of the Nonutility Group

The Nonutility Group operates in three primary business areas: Energy Marketing and Services, Coal Mining, and Energy Infrastructure Services. Energy Marketing and Services markets and supplies natural gas and provides energy management services. Coal Mining mines and sells coal. Energy Infrastructure Services provides underground construction and repair and provides performance contracting and renewable energy 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 months ended March 31, 2009 and 2008, follow:

	Three Months Ended March 31,
(In millions, except per share amounts)	2009			2008
NET INCOME	$	16.5		$	6.3
CONTRIBUTION TO VECTREN BASIC EPS	$	0.20		$	0.08

NET INCOME ATTRIBUTED TO:
Energy Marketing & Services	$	15.4		$	9.0
Mining Operations		2.8			(0.9	)
Energy Infrastructure Services		(0.5	)		(3.2	)
Other Businesses		(1.2	)		1.4

Energy Marketing and Services

Energy Marketing and Services is comprised of the Company’s gas marketing operations, energy management services, and retail gas supply operations. Results, inclusive of holding company costs, from Energy Marketing and Services for the quarter ended March 31, 2009, were earnings of $15.4 million compared to $9.0 million in 2008.

ProLiance Energy, LLC (ProLiance)

ProLiance Energy, 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 nonutility gas supply operations 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; and therefore, the Company accounts for its investment in ProLiance using the equity method of accounting. Vectren received regulatory approval on April 25, 2006, from the IURC for ProLiance to continue to provide natural gas supply services to the Company’s Indiana utilities through March 2011.

For the three months ended March 31, 2009 and 2008, the amounts recorded to Equity in earnings of unconsolidated affiliates related to ProLiance totaled $13.3 million and $14.4 million, respectively. ProLiance’s net earnings contribution, which consists of those earnings accounted for using the equity method, less allocated financing costs and related income taxes effects was $7.0 million compared to $7.8 million in 2008. The $0.8 million decrease in 2009 compared to 2008 reflects lower margin due to lower seasonal spreads locked in last year. Current year seasonal spreads have improved and will be realized in the fourth quarter of 2009 and the first quarter of 2010. ProLiance’s storage capacity is 46 BCF compared to 42 BCF at December 31, 2008.

Regulatory Matter

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Investment in Liberty Gas Storage

In late 2008, SE advised ProLiance that the completion of this phase of Liberty’s development at the Sulphur site has been delayed by subsurface and well-completion problems. To date, corrective measures have been unsuccessful. Among other options, other corrective measures are being evaluated but it is possible that the salt-cavern facility may not go into service, or may have reduced capacity when placed in service. ProLiance estimates the maximum exposure to its investment in the Sulphur site is $35 million. The Company’s proportionate share would be $12 million after tax. The Company believes that such a charge, should it occur, would not have a material adverse effect on either the Company’s or ProLiance’s financial position, cash flows, or liquidity, but it could be material to net income in any one accounting period. Further, it is not expected that the delay in Liberty’s development will impact ProLiance’s ability to meet the needs of its customers.

Vectren Source

Vectren Retail, LLC (d/b/a Vectren Source), a wholly owned subsidiary, provides natural gas and other related products and services to customers opting for choice among energy providers. Vectren Source earned approximately $8.6 million in the first quarter of 2009, compared to $2.0 million in 2008, an increase of approximately $6.6 million. Results were positively impacted by higher margins. These higher margins resulted primarily from favorable market conditions, over the course of the quarter as revenues on variable priced sales contracts fell more slowly than gas costs. Due to the seasonal nature of the retail gas supply business and due to prices charged to customers more fully reflecting the current lower gas prices, such higher earnings are not expected to continue for the remainder of 2009. Vectren Source’s customer count at March 31, 2009 was approximately 171,000 customers, compared to 157,000 customers at March 31, 2008.

Coal Mining Operations

Coal Mining mines and sells coal to the Company’s utility operations and to third parties through its wholly owned subsidiary Vectren Fuels, Inc. (Fuels). Coal Mining, inclusive of holding company costs, earned approximately $2.8 million in the first quarter of 2009, compared to a loss of $0.9 million in 2008. Coal Mining earnings have increased as expected as contracts reflecting the higher Illinois Basin coal market prices beginning January 1st. Contracts reflecting higher market prices are in place on approximately 70 percent of 2009. The impact of higher revenues have been somewhat offset by increased costs per ton mined. This anticipated increase in costs incurred during the first quarter is reflective of efforts to reconfigure the mining operation at Prosperity mine in order to improve future productivity. Based on the expected improved productivity and increasing volumes to be sold, Coal Mining earnings are expected to grow throughout 2009.

Progress continues at the underground mines currently under construction near Vincennes, Indiana. Production is expected to begin in late in the second quarter of 2009, with the second mine opening in late 2010. Reserves at the two mines are estimated at 88 million tons of recoverable number-five coal at 11,200 BTU (British thermal units) and less than 6-pound sulfur dioxide. The reserves at these new mines bring total coal reserves to approximately 120 million tons at March 31, 2009. Once in production, the two new mines are expected to produce 5 million tons of coal per year. Of the total $170 million investment management estimates to access the reserves, the Company has invested $90 million in the new mines through March 31, 2009.

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Energy Infrastructure Services

Energy Infrastructure Services provides underground construction and repair to utility infrastructure through Miller Pipeline Corporation (Miller) and energy performance contracting and renewable energy services through Energy Systems Group, LLC (ESG). Inclusive of holding company costs, Energy Infrastructure Services operated at a seasonal loss of $0.5 million during the quarter ended March 31, 2009, compared to a loss of $3.2 million in 2008.

Miller Pipeline

Miller’s 2009 year to date loss was $0.4 million compared to a loss of $1.7 million in 2008. The smaller loss is due to favorable weather conditions which allowed for more efficient completion of winter projects and lower interest rates.

Energy Systems Group

ESG earned approximately $0.1 million year to date in 2009, compared to a loss of $1.1 million in 2008. Results in 2009 were further favorably impacted by Energy Efficient Commercial Building federal income tax deductions, associated with the installation of energy efficient equipment. Results also reflect higher margin percentages that include an early completion bonus. At March 31, 2009, ESG’s backlog was $58 million, compared to $65 million at December 31, 2008 and $43 million at March 31, 2008. The national focus on a comprehensive energy strategy as evidenced by the Energy Independence and Security Act of 2007 and the American Recovery and Reinvestment Act of 2009 is likely to create favorable conditions for ESG’s growth and resulting earnings.

Other Businesses

Other nonutility businesses, which include legacy real estate and other investments, operated at a loss of $1.2 million in the first quarter of 2009 compared to earnings of $1.4 million in 2008. The decrease in earnings is primarily due to favorable adjustments recorded in 2008 related to income tax true-ups.

Impact of Recently Issued Accounting Guidance

SFAS 157

On January 1, 2009, the Company adopted the provisions of SFAS No. 157, “Fair Value Measurements” (SFAS 157) as they relate to nonfinancial assets and nonfinancial liabilities that are measured at fair value on a nonrecurring basis, such as the initial measurement of an asset retirement obligation or the use of fair value goodwill, intangible assets and long-lived assets impairment tests. This adoption had no significant impact on the Company’s operating results or financial condition.

SFAS 160

On January 1, 2009, the Company adopted SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements-an Amendment of ARB No. 51” (SFAS 160). SFAS 160 establishes accounting and reporting standards that require ownership percentages in material subsidiaries held by parties other than the parent be clearly identified, labeled, and presented separately from the parent’s equity in the equity section of the consolidated balance sheet; the amount of consolidated net income attributable to the parent and the noncontrolling interest to be clearly identified and presented on the face of the consolidated income statement; that changes in the parent’s ownership interest while it retains control over its subsidiary be accounted for consistently; that when a subsidiary is deconsolidated, any retained noncontrolling equity investment be initially measured at fair value; and that sufficient disclosure is made to clearly identify and distinguish between the interests of the parent and the noncontrolling owners. Because of the diminimus level of entities that are controlled by the Company but are less than wholly-owned, the adoption of SFAS 160 had a minimal impact to the Company’s presentation of its financial position and operating results.

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SFAS 161

On January 1, 2009, the Company adopted the qualitative and quantitative disclosures required in both interim and annual financial statements described in SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133” (SFAS 161). SFAS 161 describes enhanced disclosures under SFAS 133 and requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation in order to better convey the purpose of derivative use in terms of the risks that the entity is intending to manage. These disclosures are included in Note 12 to the consolidated condensed financial statements.

SFAS 141R

FSP EITF 03-6-1

On January 1, 2009, the Company adopted FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (FSP EITF 03-6-1). FSP EITF 03-6-1 clarified that unvested share-based payment awards that contain rights to nonforfeitable dividends participate in undistributed earnings with common shareholders. Awards of this nature that impact the calculation of EPS are participating securities. The presence of a participating security requires EPS to be calculated using the two-class method.

EITF 08-05

FASB Staff Position (FSP) 142-3

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FASB Staff Positions on Fair Value Accounting and Disclosure

FSP No. FAS 132(R)-1

Financial Condition

Within Vectren’s consolidated group, Utility Holdings 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 and short-term obligations outstanding at March 31, 2009 approximated $333 million and $81 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 and short-term obligations outstanding at March 31, 2009 approximated $823 million and $33 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.

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.

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The credit ratings of the senior unsecured debt of Utility Holdings and Indiana Gas, at March 31, 2009, are A-/Baa1 as rated by Standard and Poor's Ratings Services (Standard and Poor’s) and Moody’s Investors Service (Moody’s), respectively. The credit ratings on SIGECO's secured debt are A/A3. Utility Holdings’ commercial paper has a credit rating of A-2/P-2. The current outlook of both Moody’s and Standard and Poor’s is stable. These ratings and outlooks have not changed since December 31, 2008. 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 50 percent of long-term capitalization at March 31, 2009 and December 31, 2008, respectively. Long-term capitalization includes long-term debt, including current maturities and debt subject to tender, as well as common shareholders’ equity.

As of March 31, 2009, the Company was in compliance with all financial covenants.

Available Liquidity in Current Credit Conditions

The Company’s A-/Baa1 investment grade credit ratings have allowed it to access the capital markets as needed during this period of credit market volatility. Over the last twelve months, the Company has restored its short-term borrowing capacity with the completion of several long-term financing transactions including the issuance of long-term debt in both 2008 and 2009 and the settlement of an equity forward contract in 2008. The liquidity provided by these transactions, when coupled with existing cash and expected internally generated funds, is expected to be sufficient over the near term to fund anticipated capital expenditures, investments, and debt security redemptions.

Regarding debt redemptions, they are insignificant for the remainder of 2009 and total $48 million in 2010. In addition, holders of certain debt instruments have the one-time option to put $80 million of debt to the Company during the remainder of 2009 and $10 million in 2010.

Long-term debt transactions completed in 2009 include a $150 million issuance by Vectren Capital and a $100 million issuance by Vectren Utility Holdings. SIGECO also recently remarketed $41.3 million of long-term debt. These transactions are more fully described below.

Consolidated Short-Term Borrowing Arrangements

At March 31, 2009, the Company had $905 million of short-term borrowing capacity, including $520 million for the Utility Group and $385 million for the wholly owned Nonutility Group and corporate operations. As reduced by outstanding letters of credit, approximately $445 million was available for the Utility Group operations and approximately $301 million was available for the wholly owned Nonutility Group and corporate operations. Of the $520 million in Utility Group capacity, $515 million is available through November, 2010; and of the $385 million in Nonutility capacity, $120 million is available through September, 2009 and $255 million is available through November, 2010.

Historically, the Company has funded the short-term borrowing needs of Utility Holdings’ operations through the commercial paper market. In 2008, the Company’s access to longer term commercial paper was significantly reduced as a result of the continued turmoil and volatility in the financial markets. As a result, the Company met working capital requirements through a combination of A2/P2 commercial paper issuances and draws on Utility Holdings’ $515 million commercial paper back-up credit facilities. In addition, the Company increased its cash investments by approximately $75 million during the fourth quarter of 2008. These cash positions were liquidated in January 2009 based upon improvements in the short-term debt and commercial paper markets. Their liquidation resulted in an increase to the available short-term debt capacity for the Utility Group by $40 million and for the Nonutility Group by $35 million.

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Post March 31, 2009 Utility Holdings Debt Issuance

The 2020 Notes have no sinking fund requirements, and interest payments are due semi-annually. The 2020 Notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage restrictions contained in the Utility Holdings’ $515 million short-term credit facility.

As this issuance occurred after March 31, 2009, its impact of increasing available short-term capacity and increasing cash on hand is not reflected in the consolidated balance sheet at March 31, 2009.

ProLiance Short-Term Borrowing Arrangements

ProLiance, a nonutility energy marketing affiliate of Vectren and Citizens, has separate borrowing capacity available through a syndicated credit facility. The terms of the facility allow for $300 million of capacity from April 1 through September 30, and $400 million during the October 1 through March 31 heating season, as adjusted for letters of credit and current inventory and receivable balances. This unutilized capacity, when coupled with internally generated funds, is expected to provide sufficient liquidity to meet ProLiance's operational needs. The facility expires June 2009, at which time, ProLiance anticipates having a new credit facility in place to support its future working capital requirements. Future working capital requirements may be less than the level of the current credit line given the recent decline in natural gas prices. As of March 31, 2009 no amounts were outstanding. The current facility is not guaranteed by Vectren or Citizens.

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 $1.5 million in the first quarter of 2009. Throughout 2009, new issuances required to meet these various plan requirements are estimated to be approximately $6 million.

Potential Uses of Liquidity

Planned Capital Expenditures & Investments

Utility capital expenditures are estimated at $160 to $180 million for the remainder of 2009. Nonutility capital expenditures and investments, principally for coal mine development, are estimated at $75 million for the remainder of 2009.

Pension and Postretirement Funding Obligations

Due to the recent significant asset value declines experienced by pension plan trusts, asset values for qualified plans as of December 31, 2008 were approximately 61 percent of the projected benefit obligation. In order to increase the funded status, management currently estimates the qualified pension plans require Company contributions of $25 to $30 million in 2009. Under current market conditions, the Company expects funding a lesser level in 2010. Through March 31, 2009, approximately $4.6 million in contributions were made.

Other Guarantees and Letters of Credit

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Credit Contingent Features

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 $284.5 million in 2009, compared to $288.4 million in 2008, a decrease of $3.9 million. The decrease was primarily due to changes in working capital. This unfavorable change in working capital principally results from changes in the timing of natural gas inventory sales and purchases due to exiting the merchant function in the Ohio service territory in October of 2008. The decrease was partially offset by higher earnings and other changes.

Financing Cash Flow

Although working capital requirements are generally funded by cash flow from operations, the Company uses short-term borrowings to supplement working capital needs when accounts receivable balances are at their highest and gas storage is refilled. Additionally, short-term borrowings are required for capital projects and investments until they are financed on a long-term basis.

Net cash flow required for financing activities was $240.9 million in 2009. The increased cash required for financing activities during 2009 compared to 2008 is reflective of the impact of completed long-term financing transactions and liquidation of $75 million of cash positions on hand at the end of 2008.

SIGECO 2009 Debt Issuance

Vectren Capital Corp. 2009 Debt Issuance

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Investing Cash Flow

Cash flow required for investing activities was $117.4 million in 2009 and $75.5 million in 2008. Capital expenditures are the primary component of investing activities and totaled $117.4 million in 2009, compared to $69.6 million in 2008. The increase in capital expenditures reflects increased expenditures for coal mine development and also was impacted by the January 2009 ice storm that resulted in approximately $20 million in capital expenditures.

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.

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

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

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

·	Economic conditions including the effects of an economic downturn, inflation rates, commodity prices, and monetary fluctuations.

Economic conditions surrounding the current recession, which may be more prolonged and more severe than cyclical downturns, including significantly lower levels of economic activity; uncertainty regarding energy prices and the capital and commodity markets; decreases in 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.

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·	Increased 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 coal mining, gas marketing, and energy infrastructure strategies.

Factors affecting coal mining operations including MSHA guidelines and interpretations of those guidelines; geologic, equipment, and operational risks; sales contract negotiations and interpretations; volatile coal market prices; 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.

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

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

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

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

The 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.

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 2008 Form 10-K and is therefore not presented herein.

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ITEM 4. CONTROLS AND PROCEDURES

Changes in Internal Controls over Financial Reporting

During the quarter ended March 31, 2009, 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, 2009, 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, 2009, to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is:

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

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

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The Company is party to various legal proceedings arising in the normal course of business. In the opinion of management, there are no legal proceedings pending against the Company that are likely to have a material adverse effect on its financial position, results of operations, or cash flows. See the notes to the consolidated financial statements regarding commitments and contingencies, environmental matters, rate and regulatory matters.

The consolidated condensed financial statements are included in Part 1 Item 1.

ITEM 1A. RISK FACTORS

Investors should consider carefully factors that may impact the Company’s operating results and financial condition, causing them to be materially adversely affected. The Company’s risk factors have not materially changed from the information set forth in Item 1A Risk Factors included in the Vectren 2008 Form 10-K and are therefore not presented herein.

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; however, no such open market purchases were made during the quarter ended March 31, 2009.

ITEM 6. EXHIBITS

Exhibits and Certifications

4.1

Note Purchase Agreement, dated April 7, 2009, among Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company and Vectren Energy Delivery of Ohio, Inc. and the purchasers named therein. (Filed and designated in Form 8-K dated April 7, 2009 File No. 1-15467, as Exhibit 4.5)

4.2	Note Purchase Agreement, dated March 11, 2009, among Vectren Corporation, Vectren Capital, Corp. and each of the purchasers named therein. (Filed and designated in Form 8-K dated March 16, 2009 File No. 1-15467, as Exhibit 4.5)

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Table of Contents

4.3	First Amendment, dated March 11, 2009, to Note Purchase Agreement dated October 11, 2005, among Vectren Corporation, Vectren Capital, Corp. and each of the holders named herein. (Filed and designated in Form 8-K dated March 16, 2009 File No. 1-15467, as Exhibit 4.6)

4.4

Second Amendment, dated March 11, 2009, to Note Purchase Agreement, dated April 25, 1997, among Vectren Corporation, Vectren Capital, Corp. and the holder named therein as amended by the First Amendment thereto, dated October 11, 2005. (Filed and designated in Form 8-K dated March 16, 2009 File No. 1-15467, as Exhibit 4.7)

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

SIGNATURES

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

			VECTREN CORPORATION
			Registrant




	May 1, 2009		/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)