10-Q

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 September 30, 2011

OR

[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from __________________ to __________________

Commission file number:   1-15467

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   o No

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

x  Yes  o  No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.  (Check one):

Large accelerated filer x                                                                                                                  Accelerated filer o

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

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

o Yes    x No

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

Common Stock- Without Par Value	81,851,704	October 31, 2011
Class	Number of Shares	Date

Access to Information

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

Mailing Address: One Vectren Square Evansville, Indiana  47708 Phone Number: (812) 491-4000 Investor Relations Contact: Robert L. Goocher Treasurer and Vice President, Investor Relations rgoocher@vectren.com

Definitions

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

-2-

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	23
3	Quantitative and Qualitative Disclosures About Market Risk	47
4	Controls and Procedures	47
	PART II.  OTHER INFORMATION
1	Legal Proceedings	47
1A	Risk Factors	47
2	Unregistered Sales of Equity Securities and Use of Proceeds	47
5	Other Information	48
6	Exhibits	48
	Signatures	49

-3-

PART I.  FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

VECTREN CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited – In millions)

	September 30,		December 31,
	2011		2010
ASSETS
Current Assets
Cash & cash equivalents	$	6.4	$	10.4
Accounts receivable - less reserves of $6.5 &           $5.3, respectively		219.8		176.6
Accrued unbilled revenues		62.2		162.0
Inventories		207.3		187.1
Recoverable fuel & natural gas costs		16.0		7.9
Prepayments & other current assets		110.8		101.2
Total current assets		622.5		645.2
Utility Plant
Original cost		4,937.6		4,791.7
Less:  accumulated depreciation & amortization		1,922.2		1,836.3
Net utility plant		3,015.4		2,955.4
Investments in unconsolidated affiliates		98.0		135.2
Other utility & corporate investments		34.4		34.1
Other nonutility investments		41.3		40.9
Nonutility plant - net		537.3		488.3
Goodwill - net		262.3		242.0
Regulatory assets		181.3		189.4
Other assets		45.9		33.7
TOTAL ASSETS	$	4,838.4	$	4,764.2

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

-4-

VECTREN CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited – In millions)

	September 30,			December 31,
	2011			2010
LIABILITIES & SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable	$	142.2		$	183.7
Accounts payable to affiliated companies		25.4			59.6
Accrued liabilities		176.7			178.4
Short-term borrowings		216.4			118.3
Current maturities of long-term debt		138.0			250.7
Long-term debt subject to tender		-			30.0
Total current liabilities		698.7			820.7
Long-term Debt - Net of Current Maturities &      Debt Subject to Tender		1,581.1			1,435.2
Deferred Income Taxes & Other Liabilities
Deferred income taxes		564.8			515.3
Regulatory liabilities		341.0			333.5
Deferred credits & other liabilities		200.5			220.6
Total deferred credits & other liabilities		1,106.3			1,069.4
Commitments & Contingencies (Notes 11-13)
Common Shareholders' Equity
Common stock (no par value) – issued & outstanding           81.8 & 81.7 shares, respectively		689.3			683.4
Retained earnings		769.6			759.9
Accumulated other comprehensive income (loss)		(6.6	)		(4.4	)
Total common shareholders' equity		1,452.3			1,438.9
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY	$	4,838.4		$	4,764.2

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

-5-

VECTREN CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED CONDENSED STATEMENTS OF INCOME

(Unaudited – in millions, except per share amounts)

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2011			2010			2011			2010
OPERATING REVENUES
Gas utility	$	102.1		$	101.8		$	592.8		$	692.8
Electric utility		186.7			173.2			492.4			469.1
Nonutility		250.6			147.7			612.6			403.5
Total operating revenues		539.4			422.7			1,697.8			1,565.4
OPERATING EXPENSES
Cost of gas sold		30.5			32.4			274.4			371.7
Cost of fuel & purchased power		67.1			64.5			186.9			180.3
Cost of nonutility revenues		93.0			60.7			266.6			170.6
Other operating		180.6			137.2			485.5			398.4
Depreciation & amortization		61.7			57.6			182.0			170.6
Taxes other than income taxes		12.4			11.7			43.4			46.9
Total operating expenses		445.3			364.1			1,438.8			1,338.5
OPERATING INCOME		94.1			58.6			259.0			226.9
OTHER INCOME (EXPENSE)
Equity in (losses) of unconsolidated affiliates		(11.7	)		(8.2	)		(34.6	)		(13.9	)
Other income – net		0.7			1.6			5.9			2.0
Total other income (expense)		(11.0	)		(6.6	)		(28.7	)		(11.9	)
INTEREST EXPENSE		27.1			26.0			80.7			78.0
INCOME BEFORE INCOME TAXES		56.0			26.0			149.6			137.0
INCOME TAXES		20.7			9.6			54.6			48.7
NET INCOME	$	35.3		$	16.4		$	95.0		$	88.3
AVERAGE COMMON SHARES OUTSTANDING		81.8			81.2			81.7			81.1
DILUTED COMMON SHARES OUTSTANDING		81.9			81.4			81.8			81.3
EARNINGS PER SHARE OF COMMON STOCK:
BASIC	$	0.43		$	0.20		$	1.16		$	1.09
DILUTED	$	0.43		$	0.20		$	1.16		$	1.09
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$	0.345		$	0.340		$	1.035		$	1.020

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

-6-

VECTREN CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited – In millions)

	Nine Months Ended September 30,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	95.0		$	88.3
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization		182.0			170.6
Deferred income taxes & investment tax credits		56.5			33.9
Equity in losses of unconsolidated affiliates		34.6			13.9
Provision for uncollectible accounts		9.1			13.2
Expense portion of pension & postretirement benefit cost		6.8			6.7
Other non-cash charges - net		9.5			19.4
Changes in working capital accounts:
Accounts receivable & accrued unbilled revenues		68.6			106.7
Inventories		(20.2	)		(20.5	)
Recoverable/refundable fuel & natural gas costs		(8.1	)		(34.8	)
Prepayments & other current assets		(1.0	)		(16.4	)
Accounts payable, including to affiliated companies		(83.8	)		(82.9	)
Accrued liabilities		(3.4	)		15.7
Unconsolidated affiliate dividends		0.1			42.7
Employer contributions to pension & postretirement plans		(37.2	)		(12.4	)
Changes in noncurrent assets		(8.4	)		(9.8	)
Changes in noncurrent liabilities		(8.6	)		(11.9	)
Net cash flows from operating activities		291.5			322.4
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Dividend reinvestment plan & other common stock issuances		5.2			7.2
Requirements for:
Dividends on common stock		(84.6	)		(82.7	)
Retirement of long-term debt		(2.2	)		(2.1	)
Other financing activities		(1.4	)		-
Net change in short-term borrowings		98.1			(56.2	)
Net cash flows from financing activities		15.1			(133.8	)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Unconsolidated affiliate distributions		0.5			0.5
Other collections		1.0			10.2
Requirements for:
Capital expenditures, excluding AFUDC equity		(227.8	)		(200.9	)
Business acquisition, net of cash acquired		(83.4	)		-
Other investments		(0.9	)		(3.1	)
Net cash flows from investing activities		(310.6	)		(193.3	)
Net change in cash & cash equivalents		(4.0	)		(4.7	)
Cash & cash equivalents at beginning of period		10.4			11.9
Cash & cash equivalents at end of period	$	6.4		$	7.2

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

-7-

VECTREN CORPORATION AND SUBSIDIARY COMPANIES

NOTES TO THE CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

(UNAUDITED)

1.     Organization and Nature of Operations

Vectren Corporation (the Company or Vectren), an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana.  The Company’s wholly owned subsidiary, Vectren Utility Holdings, Inc. (Utility Holdings), serves as the intermediate holding company for three public utilities:  Indiana Gas Company, Inc. (Indiana Gas or Vectren North), Southern Indiana Gas and Electric Company (SIGECO or Vectren South), and the Ohio operations.  Utility Holdings also has other assets that provide information technology and other services to the three utilities.  Utility Holdings’ consolidated operations are collectively referred to as the Utility Group.  Both Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 2005 (Energy Act).  Vectren was incorporated under the laws of Indiana on June 10, 1999.

Indiana Gas provides energy delivery services to approximately 562,000 natural gas customers located in central and southern Indiana.  SIGECO provides energy delivery services to approximately 141,000 electric customers and approximately 110,000 gas customers located near Evansville in southwestern Indiana.  SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market.  Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana.  The Ohio operations provide energy delivery services to over 310,000 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 four primary business areas:  Infrastructure Services, Energy Services, Coal Mining, and Energy Marketing.  Infrastructure Services provides underground construction and repair services.  Energy Services provides performance contracting and renewable energy services.  Coal Mining mines and sells coal.  Energy Marketing markets and supplies natural gas and provides energy management services.  Enterprises also has other legacy businesses that have invested in energy-related opportunities and services, real estate, and leveraged leases, among other investments.  All of the above are collectively referred to as the Nonutility Group.  Enterprises supports the Company’s regulated utilities pursuant to service contracts by providing natural gas supply services, coal, and infrastructure services.

2.     Basis of Presentation

The interim consolidated condensed financial statements included in this report have been prepared by the Company, without audit, as provided in the rules and regulations of the Securities and Exchange Commission and include a review of subsequent events through the date the financial statements were issued.  Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been omitted as provided in such rules and regulations.  The information in this report reflects all adjustments which are, in the opinion of management, necessary to fairly state the interim periods presented, inclusive of adjustments that are normal and recurring in nature.  These consolidated condensed financial statements and related notes should be read in conjunction with the Company’s audited annual consolidated financial statements for the year ended December 31, 2010, filed with the Securities and Exchange Commission on February 17, 2011, on Form 10-K.  Because of the seasonal nature of the Company’s operations, the results shown on a quarterly basis are not necessarily indicative of annual results.

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

-8-

3.     Comprehensive Income

Comprehensive income consists of the following:

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
(In millions)	2011			2010			2011			2010
Net income	$	35.3		$	16.4		$	95.0		$	88.3
Comprehensive loss of unconsolidated affiliates		(5.2	)		(6.3	)		(1.8	)		(4.4	)
Cash flow hedges
Unrealized gains		0.5			4.1			1.4			4.3
Reclassifications to net income		0.1			-			(3.2	)		-
Income taxes		1.8			0.9			1.4			(0.1	)
Total comprehensive income	$	32.5		$	15.1		$	92.8		$	88.1

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 9 for more information on ProLiance.)

4.     Earnings Per Share

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

	Three Months				Nine Months
	Ended September 30,				Ended September 30,
(In millions, except per share data)	2011		2010		2011		2010
Numerator:
Reported net income (Numerator for Basic and Diluted EPS)	$	35.3	$	16.4	$	95.0	$	88.3
Denominator:
Weighted average common shares outstanding (Basic EPS)		81.8		81.2		81.7		81.1
Conversion of share based compensation arrangements		0.1		0.2		0.1		0.2
Adjusted weighted average shares outstanding and      assumed conversions outstanding (Diluted EPS)		81.9		81.4		81.8		81.3
Basic EPS	$	0.43	$	0.20	$	1.16	$	1.09
Diluted EPS	$	0.43	$	0.20	$	1.16	$	1.09

-9-

For the three and nine months ended September 30, 2011, options to purchase 1,920 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, compared to 308,000 and 517,800 shares for the three and nine months ended September 30, 2010, respectively.  The exercise prices for these options were $27.15 for the three and nine months ended September 30, 2011.  The exercise prices for these options ranged from $24.90 to $27.15 for the three months ended September 30, 2010 and $24.74 to $27.15 for the nine months ended September 30, 2010.

5.     Acquisition of Minnesota Limited, Inc.

On March 31, 2011, the Company, through its wholly owned subsidiary Vectren Infrastructure Services Company, Inc., purchased Minnesota Limited, Inc., excluding certain assets.  Minnesota Limited is a specialty contractor focusing on transmission pipeline construction and maintenance; pump station, compressor station, terminal and refinery construction; gas distribution; and hydrostatic testing.  Minnesota Limited is headquartered in Big Lake, Minnesota and the majority of its customers are generally located in the northern Midwest region.

Along with the Company’s wholly owned subsidiary, Miller Pipeline LLC, Minnesota Limited is included in the Company’s nonutility Infrastructure Services operating segment.  This acquisition positions the Company for anticipated growth in demand for gas transmission construction resulting from the need to transport new sources of natural gas and oil found in shale formations and the need to upgrade the nation’s aging pipelines.

The Company accounted for the cash acquisition in accordance with FASB authoritative guidance for business combinations, which requires the Company to recognize the assets acquired and the liabilities assumed, measured at their fair values as of the date of acquisition.  The following table summarizes the allocation of the purchase price to the fair value of the assets acquired and liabilities assumed.

(In millions)
Working capital assets	$	21.5
Working capital liabilities		(6.7	)
Net working capital		14.8
Property, plant & equipment		34.4
Identifiable intangible assets		19.1
Goodwill		20.3
Net assets acquired		88.6
Debt obligation assumed		(5.2	)
Cash paid in acquisition, net of cash acquired	$	83.4

As of November 4, 2011, the purchase price and its allocation remain preliminary and could change in subsequent periods.  Any subsequent material changes to the purchase price and its allocation will be adjusted pursuant to FASB guidance. Since the initial purchase price allocation was disclosed only minor adjustments have been made.  The final purchase price and the allocation are dependent on final reconciliations of working capital and other items.

Level 3 market inputs, such as discounted cash flows, revenue growth rates, royalty rates, and dealer and auction values of used equipment, were used to derive the preliminary fair values of the identifiable intangible assets and property plant and equipment.  Identifiable intangible assets include back log, long-term customer relationships, and trade name.  The Company intends to use the acquired assets for an extended period and is amortizing them on a straight-line basis over their estimated useful lives.  Goodwill arising from the purchase represents intangible value the Company expects to realize over time.  This value includes but is not limited to: 1) expected synergies from more efficient utilization of equipment and human resources within the combined entities; 2) the experience and size of the acquired work force; and 3) the reputation of the current Minnesota Limited management team.  The goodwill, which does not amortize pursuant to FASB guidance, is deductible over a 15 year period for purposes of computing current income tax expense.

-10-

Transaction costs associated with the acquisition and expensed by the Company totaled approximately $0.5 million, of which $0.2 million are included in other operating expenses during the nine months ended September 30, 2011 and the remainder was expensed in 2010.  For the period from April 1, 2011 through September 30, 2011, Minnesota Limited contributed approximately $75.2 million and $6.3 million to the Company's revenue and net income, respectively.  During the three months ended September 30, 2011, Minnesota Limited contributed approximately $53.2 million and $5.8 million to the Company's revenue and net income, respectively.

The following table presents the Company's unaudited proforma results of operations for the three months ended September 30, 2010 and nine months ended September 30, 2011 and 2010 as if the acquisition had occurred on January 1, 2010.

	Three Months		Nine Months
	Ended September 30,		Ended September 30,
(In millions, except per share data)	2010		2011		2010
Total operating revenues	$	460.6	$	1,718.9	$	1,645.2
Net income	$	18.6	$	94.8	$	89.7
Basic earnings per share	$	0.23	$	1.16	$	1.11
Diluted earnings per share	$	0.23	$	1.16	$	1.10

In addition to the incremental revenues and expenses recorded by Minnesota Limited during this period, the proforma financial data for all periods presented contain several adjustments including the following: recording the additional amortization expense from the identifiable intangible assets; adjusting the estimated tax provision of the proforma combined results; and adjusting for the issuance of short-term debt to facilitate the acquisition.  The Company prepared the proforma financial information for the combined entities for comparative purposes only, and it may not be indicative of what actual results would have been if the acquisition had taken place on the proforma date, or of future results.

Concurrent with the purchase agreement, the Company executed a lease arrangement at fair value for the Minnesota Limited corporate headquarters, which is owned by a member of the Minnesota Limited management team and certain family members.  The lease obligates the Company to pay approximately $83,333 per month for 10 years along with certain executory costs for taxes and other operating expenses.  Pursuant to FASB guidance, the Company accounts for the obligation as an operating lease, expensing the lease payments and executory costs as incurred.

6.     Excise and Utility Receipts Taxes

Excise taxes and a portion of utility receipts taxes are included in rates charged to customers.  Accordingly, the Company records these taxes received as a component of operating revenues, which totaled $5.0 million and $4.8 million in the three months ended September 30, 2011 and 2010, respectively.  During the nine months ended September 30, 2011 and 2010, these taxes totaled $21.6 million and $25.2 million, respectively.  Expenses associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.

7.     Retirement Plans & Other Postretirement Benefits

The Company maintains three qualified defined benefit pension plans, a nonqualified supplemental executive retirement plan (SERP), and three other postretirement benefit plans.  The defined benefit pension and other postretirement benefit plans, which cover eligible full-time regular employees, are primarily noncontributory.  The postretirement health care and life insurance plans are a combination of self-insured and fully insured plans.  The Company has a Voluntary Employee Beneficiary Association (VEBA) Trust Agreement for the partial funding of postretirement health benefits for retirees and their eligible dependents and beneficiaries in one of the three plans.  Annual VEBA funding is discretionary; however, no further funding is anticipated.  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.”

-11-

Net Periodic Benefit Costs

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

	Three Months Ended September 30,
	Pension Benefits						Other Benefits
(In millions)	2011			2010			2011			2010
Service cost	$	1.7		$	1.5		$	0.1		$	0.2
Interest cost		3.9			4.0			1.1			1.1
Expected return on plan assets		(5.3	)		(4.6	)		-			-
Amortization of prior service cost		0.5			0.4			(0.2	)		(0.2	)
Amortization of transitional obligation		-			-			0.2			0.3
Amortization of actuarial loss		1.0			0.5			0.2			-
Net periodic benefit cost	$	1.8		$	1.8		$	1.4		$	1.4

	Nine Months Ended September 30,
	Pension Benefits						Other Benefits
(In millions)	2011			2010			2011			2010
Service cost	$	5.2		$	4.7		$	0.4		$	0.4
Interest cost		11.9			11.9			3.2			3.4
Expected return on plan assets		(15.9	)		(13.8	)		-			(0.2	)
Amortization of prior service cost		1.3			1.2			(0.6	)		(0.6	)
Amortization of transitional obligation		-			-			0.8			0.9
Amortization of actuarial loss		2.9			1.5			0.5			0.3
Net periodic benefit cost	$	5.4		$	5.5		$	4.3		$	4.2

Employer Contributions to Qualified Pension Plans

Currently, the Company expects to contribute approximately $35 million to its pension plan trusts for 2011.  During the nine months ended September 30, 2011, contributions of $32.6 million have been made.

8.     Supplemental Cash Flow Information

As of September 30, 2011 and December 31, 2010, the Company has accruals related to utility and nonutility plant purchases totaling approximately $12.6 million and $13.9 million, respectively.

9.     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.

-12-

Summarized Financial Information

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
(In millions)	2011			2010			2011			2010
Summarized statement of income information:
Revenues	$	283.0		$	289.3		$	1,074.8		$	1,095.1
Operating income (loss)	$	(19.4	)	$	(12.8	)	$	(56.7	)	$	(12.2	)
ProLiance's earnings (loss)	$	(19.5	)	$	(12.9	)	$	(57.2	)	$	(12.3	)

	As of
	September 30,			December 31,
(In millions)	2011			2010
Summarized balance sheet information:
Current assets	$	301.3		$	441.4
Noncurrent assets	$	58.2		$	59.1
Current liabilities	$	217.9		$	298.1
Noncurrent liabilities	$	0.4		$	0.4
Members' equity	$	151.6		$	208.9
Accumulated other comprehensive income (loss)	$	(13.6	)	$	(10.8	)
Noncontrolling interest	$	3.2		$	3.9

Vectren records its 61 percent share of ProLiance’s results in Equity in losses of unconsolidated affiliates.  Interest expense and income taxes associated with the investment are recorded separately within the statements of income in those line items.   As of September 30, 2011 and December 31, 2010, the Company’s investment balance is $86.6 million and $123.2 million, respectively.    For the three and nine months ended September 30, 2011, the amounts recorded to Equity in losses of unconsolidated affiliates related to ProLiance’s operations totaled a pre-tax loss of $11.9 million and $34.9 million, respectively.  For the three and nine months ended September 30, 2010, the amounts recorded to Equity in losses of unconsolidated affiliates related to ProLiance’s operations totaled a pretax loss of $8.2 million and $8.0 million, respectively.  Lower natural gas prices, resulting in narrowed summer/winter spreads and locational margins, have negatively impacted ProLiance’s results. 

Investment in Liberty Gas Storage

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

In late 2008, the project at the North site was halted due to subsurface and well-completion problems, resulting in Liberty recording a $132 million impairment charge related to the North site in 2009.  ProLiance recorded its share of the charge in 2009 totaling $33 million; the Company recorded its share of the charge in 2009 totaling $11.9 million after tax.  ProLiance’s ability to meet the needs of its customers has not been, nor does it expect it to be, impacted.  Approximately 12 Bcf of the storage at the South site, which comprises three of the four FERC certified caverns, is fully completed and tested.  As a result of the issues encountered at the North site, Liberty requested and the FERC approved the separation of the North site from the South site.  As of September 30, 2011 and December 31, 2010, ProLiance’s investment in Liberty approximated $36.9 million and $36.7 million, respectively.

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

-13-

Transactions with ProLiance

Purchases from ProLiance for resale and for injections into storage for the three months ended September 30, 2011 and 2010 totaled $80.5 million and $78.0 million, respectively, and for the nine months ended September 30, 2011 and 2010, totaled $281.6 and $319.2 million.  Amounts owed to ProLiance at September 30, 2011 and December 31, 2010, for those purchases were $25.4 million and $59.6 million, respectively, and are included in Accounts payable to affiliated companies in the Consolidated Balance Sheets.  Vectren received regulatory approval on April 25, 2006, from the IURC for ProLiance to provide natural gas supply services to the Company’s Indiana utilities through March 2011.  On March 17, 2011, an order was received from the IURC providing for ProLiance’s continued provision of gas supply services to the Company’s Indiana utilities and Citizens Energy Group through March 2016.  Amounts charged by ProLiance for gas supply services are established by supply agreements with each utility.

10.   Financing Activities

Utility Holdings Long Term Debt

On October 21, 2011, Utility Holdings priced $100 million of senior unsecured notes at an interest rate of 5.00 percent per annum and with a maturity date of February 3, 2042.  The notes will be sold to various institutional investors pursuant to a private placement note purchase agreement expected to be entered into in November 2011.  These senior notes will be unsecured and will be jointly and severally guaranteed by Utility Holdings’ regulated utility subsidiaries, Southern Indiana Gas and Electric Company, Indiana Gas Company, Inc., and Vectren Energy Delivery of Ohio, Inc.  The proceeds received from the issuance of the senior notes will be used to refinance Utility Holdings' $96.2 million 5.95 percent senior notes due 2036, that are expected to be called at par and retired on or about November 21, 2011.  Subject to the satisfaction of customary closing conditions, the new notes will be issued on or about February 1, 2012.

On April 5, 2011, Utility Holdings entered into a private placement note purchase agreement pursuant to which various institutional investors have agreed to purchase the following tranches of notes:  (i) $55 million of 4.67 percent Senior Guaranteed Notes, due November 30, 2021, (ii) $60 million of 5.02 percent Senior Guaranteed Notes, due November 30, 2026, and (iii) $35 million of 5.99 percent Senior Guaranteed Notes, due December 2, 2041.  The proceeds received from the issuance of these senior notes will be used to partially refinance $250 million of Utility Holdings 6.625 percent long-term debt maturing December 1, 2011.  The remainder of the maturing debt will be replaced with short-term borrowings.  These senior notes are unsecured and will be jointly and severally guaranteed by Utility Holdings’ regulated utility subsidiaries, Southern Indiana Gas and Electric Company, Indiana Gas Company, Inc., and Vectren Energy Delivery of Ohio, Inc.  Subject to the satisfaction of customary conditions precedent, this financing is scheduled to close on or about November 30, 2011.  The Company has reclassified $150 million of the $250 million debt redemption due in December 2011 to long-term debt in its September 30, 2011 Consolidated Balance Sheet to reflect the Company’s ability and intent to refinance that portion of the debt with this issuance.

11.   Commitments & Contingencies

Corporate Guarantees

The Company issues parent level guarantees to certain vendors and customers of its wholly owned subsidiaries and unconsolidated affiliates.  These guarantees do not represent incremental consolidated obligations; rather, they represent parental guarantees of subsidiary and unconsolidated affiliate obligations in order to allow those subsidiaries and affiliates the flexibility to conduct business without posting other forms of collateral.  At September 30, 2011, parent level guarantees support a maximum of $25 million of ESG’s performance contracting commitments and warranty obligations and $27 million of other project guarantees.  The broader scope of ESG’s performance contracting obligations, including those not guaranteed by the parent company, are described below.  In addition, the parent company has approximately $78 million of other guarantees outstanding supporting other consolidated subsidiary operations, of which $53 million support the operations of Vectren Source, a wholly owned non-regulated retail gas marketer and $20 million represent letters of credit supporting other nonutility operations.  Guarantees issued and outstanding on behalf of unconsolidated affiliates approximated $3 million at September 30, 2011.  These guarantees relate primarily to arrangements between ProLiance and various natural gas pipeline operators.  The Company has not been called upon to satisfy any obligations pursuant to these parental guarantees and has accrued no significant liabilities related to these guarantees.

-14-

Performance Guarantees & Product Warranties

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

Specific to ESG, in its role as a general contractor in the performance contracting industry, at September 30, 2011, there are 81 open surety bonds supporting future performance.  The average face amount of these obligations is $4.0 million, and the largest obligation has a face amount of $30.8 million.  The maximum exposure of these obligations is less than these amounts for several factors, including the level of work already completed.  At September 30, 2011, over 50 percent of work was completed on projects with open surety bonds.  A significant portion of these commitments will be fulfilled within one year.  In instances where ESG operates facilities, project guarantees extend over a longer period.  In addition to its performance obligations, ESG also warrants the functionality of certain installed infrastructure generally for one year and the associated energy savings over a specified number of years.  The Company has no significant accruals for these warranty obligations as of September 30, 2011.

Legal & Regulatory Proceedings

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

12.   Legislative & Environmental Matters

Indiana House Bill 1004

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

Indiana Senate Bill 251

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

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

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

Ohio House Bill 95

In June 2011, Ohio House Bill 95 was signed into law.  The law adjusts, among other things, the manner in which gas utilities file for rate changes, including the implementation of base rate changes, alternative rate plans, and automatic rate adjustment mechanisms.  Outside of a base rate proceeding, the legislation permits a natural gas company to apply to implement a capital expenditure program for infrastructure expansion, upgrade, or replacement; installation, upgrade, or replacement of information technology systems; or any program necessary to comply with government regulation.  Once such application is approved, the legislation authorizes recovery or deferral of program costs, such as depreciation, property taxes, and carrying costs.  The Company is assessing the impact this legislation may have on its operations.

-15-

Clean Air Act

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

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

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

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

Climate Change

In April 2007, the US Supreme Court determined that greenhouse gases meet the definition of "air pollutant" under the Clean Air Act and ordered the EPA to determine whether greenhouse gas emissions from motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare.  In April 2009, the EPA published its proposed endangerment finding for public comment.  The proposed endangerment finding concludes that carbon emissions from mobile sources pose an endangerment to public health and the environment.  The endangerment finding was finalized in December 2009, and is the first step toward EPA regulating carbon emissions through the existing Clean Air Act in the absence of specific carbon legislation from Congress.  Therefore, any new regulations would likely also impact major stationary sources of greenhouse gases.  The EPA has promulgated two greenhouse gas regulations that apply to SIGECO’s generating facilities.  In 2009, the EPA finalized a mandatory greenhouse gas emissions registry which will require reporting of emissions beginning in 2011 (for the emission year 2010).  The EPA has also finalized a revision to the Prevention of Significant Deterioration (PSD) and Title V permitting rules which would require facilities that emit 75,000 tons or more of greenhouse gases a year to obtain a PSD permit for new construction or a significant modification of an existing facility. 

-16-

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

Impact of Legislative Actions & Other Initiatives is Unknown

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

Ash Ponds & Coal Ash Disposal Regulations

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

Clean Water Act

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

Potential Pipeline Safety Legislation

The U.S Senate has passed a pipeline safety bill that would increase, beyond levels required by current law, the oversight of natural gas pipelines and lead to an investment in the further inspection, and where necessary, additional modernization of pipeline infrastructure.  The U.S. House of Representatives continues to debate legislation similar to the Senate bill as well as alternatives.  At this time and in the absence of final legislation, compliance costs and other effects associated with increased pipeline safety regulations remain uncertain.  However, any future legislative or regulatory actions taken to address pipeline safety could result in both increased levels of operating expenses and capital expenditures associated with the Company’s natural gas distribution businesses.  Compliance costs and capital investments associated with the Company’s Indiana gas utilities would likely qualify as federally mandated regulatory requirements recoverable under Senate Bill 251 referenced above.  In Ohio, capital investments would likely qualify for timely recovery under House Bill 95 referenced above.

-17-

Environmental Remediation Efforts

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

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

Indiana Gas accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites.  While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, Indiana Gas has recorded cumulative costs that it has incurred or reasonably expects to incur totaling approximately $23.1 million.  The estimated accrued costs are limited to Indiana Gas’ share of the remediation efforts.  Indiana Gas has arrangements in place for 19 of the 26 sites with other potentially responsible parties (PRP), which limit Indiana Gas’ costs at these 19 sites to between 28 percent and 50 percent.  With respect to insurance coverage, Indiana Gas has received approximately $20.8 million from all known insurance carriers under insurance policies in effect when these plants were in operation.

In October 2002, SIGECO received a formal information request letter from the IDEM regarding five manufactured gas plants that it owned and/or operated and were not enrolled in the IDEM’s VRP.  In October 2003, SIGECO filed applications to enter four of the manufactured gas plant sites in IDEM's VRP.  The remaining site is currently being addressed in the VRP by another Indiana utility.  SIGECO added those four sites into the renewal of the global Voluntary Remediation Agreement that Indiana Gas has in place with IDEM for its manufactured gas plant sites.  That renewal was approved by the IDEM in February 2004.  SIGECO was also named in a lawsuit, involving another waste disposal site subject to potential environmental remediation efforts.  With respect to that lawsuit, SIGECO settled with the plaintiff during 2010 mitigating any future claims at this site.  SIGECO has filed a declaratory judgment action against its insurance carriers seeking a judgment finding its carriers liable under the policies for coverage of further investigation and any necessary remediation costs that SIGECO may accrue under the VRP program and/or related to the site subject to the settled lawsuit.  In November the Court ruled on two motions for summary judgment, finding for SIGECO and against certain insurers on indemnification and defense obligations in the policies at issue.

SIGECO has recorded cumulative costs that it has incurred or reasonably expects to incur related to these environmental matters, including the recent settlement discussed above, totaling approximately $17.0 million.  However, the total costs that may be incurred in connection with addressing these sites cannot be determined at this time.  With respect to insurance coverage, SIGECO has recorded approximately $14.2 million of expected insurance recoveries from certain of its insurance carriers under insurance policies in effect when these sites were in operation.  While negotiations are ongoing with certain carriers, settlements have been reached with some carriers and $9.0 million in proceeds have been received.

The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others.  While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require some level of additional remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery.  As of September 30, 2011 and December 31, 2010, respectively, approximately $5.4 million and $5.5 million of accrued, but not yet spent, costs are included in Other Liabilities related to both the Indiana Gas and SIGECO sites.

13.   Rate & Regulatory Matters

Vectren South Electric Base Rate Filing

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

-18-

Coal Procurement Procedures

Vectren South submitted a request for proposal in April 2011 regarding coal purchases for a four year period beginning in 2012.  After negotiations with bidders, Vectren South has reached an agreement in principle for multi-year purchases with two suppliers, one of which is Vectren Fuels, Inc.  Consistent with the IURC direction in the electric rate case, a sub docket proceeding has been established to review the Company’s prospective coal procurement procedures, and the Company submitted evidence related to its recent request for proposal (RFP) and those coal procurement procedures to the IURC in September 2011.  In October 2011, the OUCC filed its testimony which, while suggesting enhancements to the process to be considered, does not challenge the results of the RFP and the resulting new contracts.  A hearing in this proceeding is scheduled for December 2011.

Vectren South Electric Demand Side Management Program Filing

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

On August 31, 2011 the IURC issued an order approving an initial three year DSM plan in the Vectren South service territory that complies with the IURC’s energy saving targets.  Consistent with the Company’s proposal, the order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; 3) lost margin recovery associated with the implementation of DSM programs for large customers; and 4) deferral of lost margin up to $1 million in 2011 associated with small customer DSM programs for subsequent recovery under a tracking mechanism to be proposed by the Company.  This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the order received April 27, 2011.  The Company is in the initial phases of implementing electric conservation initiatives.

Vectren South Electric Dense Pack Filing

On September 14, 2011, Vectren South filed a petition with the IURC seeking recovery of and return on the capital investment in dense pack technology to improve the efficiency of its A.B. Brown Generating Station.  This investment is expected to be approximately $32 million over the next two years, of which approximately $17 million has been invested to date.  This technology is expected to allow the A.B. Brown units to run at least 5 percent more efficient, thereby burning less fuel, and reducing fuel costs and emissions of pollutants.  Indiana statute provides for timely recovery of these investments, with a return, in instances where the investment increases the efficiency of existing generating plants that are fueled by coal.  The IURC will conduct a hearing in early 2012.

Vectren North & Vectren South Gas Decoupling Extension Filing

On April 14, 2011, the Company’s Indiana based gas companies (Vectren North and Vectren South) filed with the IURC a joint settlement agreement with the OUCC on an extension of the offering of conservation programs and the supporting gas decoupling mechanism originally approved in December 2006.  On August 18, 2011, the IURC issued an order approving the settlement as filed, granting the extension of the current decoupling mechanism in place at both gas companies and recovery of new conservation program costs through December 2015.

VEDO Gas Rate Design

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

-19-

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

VEDO Continues the Process to Exit the Merchant Function

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

The second phase of the exit process began on April 1, 2010.  During this phase, the Company no longer sells natural gas directly to customers.  Rather, state-certified Competitive Retail Natural Gas Suppliers, that were successful bidders in a similar regulatory-approved auction, sell the gas commodity to specific customers for a 12 month period at auction-determined standard pricing.  The first auction was conducted on January 12, 2010, and the auction results were approved by the PUCO on January 13, 2010.  The plan approved by the PUCO required that the Company conduct at least two annual auctions during this phase.  As such, the Company conducted another auction on January 18, 2011 in advance of the second 12-month term which commenced on April 1, 2011.  The results of that auction were approved by the PUCO on January 19, 2011.Vectren Source, the Company’s wholly owned nonutility retail gas marketer, was a successful bidder in both auctions winning one tranche of customers in the first auction and two tranches of customers in the second auction.  Each tranche of customers equates to approximately 28,000 customers.  Consistent with current practice, customers will continue to receive a single bill for the commodity as well as the delivery component of natural gas service from VEDO.

The PUCO provided for an Exit Transition Cost rider, which allows the Company to recover costs associated with the transition process.  Exiting the merchant function has not had a material impact on earnings or financial condition.  It, however, has and will continue to reduce Gas utility revenues and have an equal and offsetting impact to Cost of gas sold and revenue related taxes recorded in Taxes other than income taxes as VEDO no longer purchases gas for resale to these customers.

14.   Fair Value Measurements

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

	September 30, 2011				December 31, 2010
(In millions)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	1,719.1	$	1,874.9	$	1,715.9	$	1,841.2
Short-term borrowings		216.4		216.4		118.3		118.3
Cash & cash equivalents		6.4		6.4		10.4		10.4

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

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

-20-

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

Because of the customized nature of notes receivable investments and lack of a readily available market, it is not practical to estimate the fair value of these financial instruments at specific dates without considerable effort and cost.  At September 30, 2011 and December 31, 2010, the fair value for these financial instruments was not estimated.  The carrying value of notes receivable, inclusive of any accrued interest and net of impairment reserves, was approximately $11.0 million at September 30, 2011 and $10.9 million at December 31, 2010.

The fair value table in Note 18 of the financial statements in the 2010 Form 10-K excluded the estimated fair value of a long-term debt instrument.  The chart above now includes the amount and reflects an increase in the estimated fair value of long-term debt of approximately $73.9 million.  This change in the disclosed fair value of long-term debt had no effect on the carrying value of debt included in the consolidated balance sheet.

15.   Impact of Recently Issued Accounting Principles

Other Comprehensive Income (OCI)

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

Goodwill Testing

In September 2011, the FASB issued new accounting guidance regarding testing goodwill for impairment.  The new guidance will allow the Company an option to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test.  Using the new guidance, the Company no longer would be required to calculate the fair value of a reporting unit unless the Company determines, based on that qualitative assessment, that it is more likely than not that its fair value is less than its carrying amount.  The new guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011.  The adoption of this guidance will have no material impact to the Company’s financial statements.

Multiemployer Pension Plan Disclosures

In September 2011, the FASB issued new accounting guidance that requires enhanced disclosures regarding an employer’s participation in multiemployer pension plans.  For plans that are individually significant, these enhanced disclosures include the legal name of the plan, the plan’s Employer Identification Number, the employer’s contributions made to the plan, the expiration date(s) of the collective-bargaining agreement(s) requiring contributions to the plan, the most recently available certified zone status provided by the plan, and several other disclosures.  The new disclosure requirements are effective for fiscal years ending after December 15, 2011, so they will be effective for the Company’s 2011 financial statements.  The Company participates in several multiemployer pension plans and is currently assessing the impact these new disclosure requirements will have on its financial statements.

16.   Segment Reporting

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

The Utility Group is comprised of Vectren Utility Holdings, Inc.’s operations, which consist of the Company’s regulated operations and other operations that provide information technology and other support services to those regulated operations.  The Company segregates its regulated operations between a Gas Utility Services operating segment and an Electric Utility Services operating segment.  The Gas Utility Services segment provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio.  The Electric Utility Services segment provides electric distribution services primarily to southwestern Indiana, and includes the Company’s power generating and wholesale power operations.  Regulated operations supply natural gas and/or electricity to over one million customers.  In total, the Utility Group is comprised of three operating segments:  Gas Utility Services, Electric Utility Services, and Other operations.

-21-

Consistent with a reporting structure implemented during 2010, the Nonutility Group is comprised of five operating segments.  Prior segment disclosures reported the Nonutility Group as a single operating segment, and for comparison purposes those prior periods are conformed to the current year presentation.  The operating segments of the Nonutility Group are Infrastructure Services, Energy Services, Coal Mining, Energy Marketing, and Other Businesses.

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.  The acquisition of Minnesota Limited was completed on March 31, 2011 (See Note 5) and is included in the Infrastructure Services nonutility operating segment.  Information related to the Company’s business segments is summarized as follows:

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
(In millions)	2011			2010			2011			2010
Revenues
Utility Group
Gas Utility Services	$	102.1		$	101.8		$	592.8		$	692.8
Electric Utility Services		186.7			173.2			492.4			469.1
Other Operations		11.0			11.1			32.9			33.3
Eliminations		(10.5	)		(10.7	)		(31.4	)		(32.1	)
Total Utility Group		289.3			275.4			1,086.7			1,163.1
Nonutility Group
Infrastructure Services		151.6			69.9			293.4			171.1
Energy Services		48.5			46.7			111.5			107.7
Coal Mining		81.0			57.5			221.2			159.7
Energy Marketing		10.5			7.8			105.4			96.2
Total Nonutility Group		291.6			181.9			731.5			534.7
Eliminations		(41.5	)		(34.6	)		(120.4	)		(132.4	)
Consolidated Revenues	$	539.4		$	422.7		$	1,697.8		$	1,565.4
Profitability Measure - Net Income (Loss)
Utility Group
Gas Utility Services	$	(4.8	)	$	(6.3	)	$	33.5		$	32.0
Electric Utility Services		30.8			23.1			53.1			51.4
Other Operations		1.9			1.9			6.2			6.9
Utility Group Net Income		27.9			18.7			92.8			90.3
Nonutility Group Net Income (Loss)
Infrastructure Services		11.9			3.2			11.1			2.2
Energy Services		2.3			2.8			1.6			4.2
Coal Mining		5.8			2.5			15.9			8.1
Energy Marketing		(12.2	)		(10.4	)		(24.3	)		(9.1	)
Other Businesses		(0.2	)		(0.3	)		(0.9	)		(7.3	)
Nonutility Group Net Income (Loss)		7.6			(2.2	)		3.4			(1.9	)
Corporate & Other Group Net Income (Loss)		(0.2	)		(0.1	)		(1.2	)		(0.1	)
Consolidated Net Income	$	35.3		$	16.4		$	95.0		$	88.3

-22-

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

Vectren Corporation (the Company or Vectren), an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana.  The Company’s wholly owned subsidiary, Vectren Utility Holdings, Inc. (Utility Holdings), serves as the intermediate holding company for three public utilities:  Indiana Gas Company, Inc. (Indiana Gas or Vectren North), Southern Indiana Gas and Electric Company (SIGECO or Vectren South), and the Ohio operations.  Utility Holdings also has other assets that provide information technology and other services to the three utilities.  Utility Holdings’ consolidated operations are collectively referred to as the Utility Group.  Both Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 2005 (Energy Act).  Vectren was incorporated under the laws of Indiana on June 10, 1999.

Indiana Gas provides energy delivery services to approximately 562,000 natural gas customers located in central and southern Indiana.  SIGECO provides energy delivery services to approximately 141,000 electric customers and approximately 110,000 gas customers located near Evansville in southwestern Indiana.  SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market.  Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana.  The Ohio operations provide energy delivery services to over 310,000 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.  In total, the Utility Group is comprised of three operating segments:  Gas Utility Services, Electric Utility Services, and Other operations.  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.  Other operations provide information technology and other support services to those regulated operations.

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

Executive Summary of Consolidated Results of Operations

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

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

The Company has in place a disclosure committee that consists of senior management as well as financial management.  The committee is actively involved in the preparation and review of the Company’s SEC filings.

The following discussion and analysis should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto as well as the Company’s 2010 annual report filed on Form 10-K.

-23-

Summary results for the three and nine months ended September 30, 2011 and 2010 follow:

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
(In millions, except per share data)	2011			2010			2011			2010
Net income (loss)	$	35.3		$	16.4		$	95.0		$	88.3
Attributed to:
Utility Group		27.9			18.7			92.8			90.3
Nonutility Group		7.6			(2.2	)		3.4			(1.9	)
Corporate & other		(0.2	)		(0.1	)		(1.2	)		(0.1	)
Basic EPS	$	0.43		$	0.20		$	1.16		$	1.09
Attributed to:
Utility Group		0.34			0.22			1.13			1.11
Nonutility Group		0.09			(0.02	)		0.04			(0.02	)
Corporate & other		-			-			(0.01	)		-

Results

For the three months ended September 30, 2011, net income was $35.3 million, or $0.43 per share, compared to a net income of $16.4 million, or $0.20 per share for the three months ended September 30, 2010.  For the nine months ended September 30, 2011, net income was $95.0 million, or $1.16 per share, compared to net income of $88.3 million, or $1.09 per share for the same period in 2010.  The increase in the quarter is driven by increased Utility Group earnings and results from nonutility operations, primarily Infrastructure Services and Coal Mining.

Utility Group

During the third quarter, Utility Group earnings increased to $27.9 million in 2011 from $18.7 million earned in 2010.  In the nine months ended September 30, 2011, the Utility Group earned $92.8 million, compared to the $90.3 million earned in 2010. These results reflect milder cooling weather in 2011.  The year to date increase is driven by increased earnings from both gas and electric operations.

Gas utility services

During the 2011 third quarter, the gas utility segment operated at a seasonal loss of $4.8 million compared to a loss of $6.3 million in 2010.  The gas utility segment earned $33.5 million during the nine months ended September 30, 2011 compared to earnings of $32.0 million in the prior year period. The $1.5 million year over year increase, as well as the quarterly increase, is due to continued growth in large customer margin from ethanol plants in the Vectren South territory and return on bare steel, cast iron, and distribution riser replacement activities in Ohio.  The year to date period in 2011 also reflects the expected first quarter impact of rate design changes implemented in February 2010 in the Ohio service territory.

Electric utility services

The electric operations earned $30.8 million in the third quarter of 2011, compared to $23.1 million in the prior year quarter and earned $53.1 million in the nine months ended September 30, 2011 compared to $51.4 million in the prior year period.  The quarterly and year to date periods in 2011 have been positively impacted by new electric base rates implemented on May 3, 2011 and negatively impacted by weather that, while warmer than normal, was cooler than the prior year.  The year to date period earnings in 2011 were reduced by increased power supply operating expenses associated with planned electric generating maintenance activities. Increased maintenance costs generally incurred in the first half of the year were in preparation for the high volume summer cooling season.

Management estimates the electric margin impact of weather to be approximately $3.0 million favorable and $4.5 million favorable, compared to normal temperatures in the quarter and year to date in 2011, respectively.  This compares to 2010, where management estimated a $5.7 million favorable impact on margin compared to normal in the third quarter and $9.9 million year to date.  Although temperatures were warmer than normal, period over period, there was a decline in earnings of approximately $1.6 million after tax, or $0.02 per share, in the quarter and $3.2 million after tax, or $0.04 per share, year to date.

-24-

Nonutility Group

The Nonutility Group’s 2011 third quarter earnings were $7.6 million compared to a loss of $2.2 million in 2010.  Year to date in 2011, nonutility earnings were $3.4 million compared to a loss of $1.9 million in 2010.   The 2010 year to date period includes charges against legacy investments totaling $6.9 million.  Infrastructure Services earnings have increased $8.7 million in the quarter and $8.9 million year to date driven by increased demand and the Minnesota Limited acquisition.  Coal Mining earnings have also increased $3.3 million in the quarter and $7.8 million year to date due to increased third party sales resulting from the opening of Oaktown 1.

Dividends

Dividends declared for the three months ended September 30, 2011, were $0.345 per share compared to $0.340 per share for the same period in 2010.  Dividends declared for the nine months ended September 30, 2011, were $1.035 per share compared to $1.020 per share for the same period in 2010.  In November 2011, the Company’s board of directors increased its quarterly dividend to $0.350 per share from $0.345 per share.  The increase marks the 52nd consecutive year in which Vectren and predecessor companies’ have increased annual dividends paid.

Use of Non-GAAP Performance Measures and Per Share Measures

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

Detailed Discussion of Results of Operations

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

-25-

Results of Operations of the Utility Group

Utility Group operating results before certain intersegment eliminations and reclassifications for the three and nine months ended September 30, 2011 and 2010 follow:

	Three Months				Nine Months
	Ended September 30,				Ended September 30,
(In millions, except per share data)	2011		2010		2011		2010
OPERATING REVENUES
Gas utility	$	102.1	$	101.8	$	592.8	$	692.8
Electric utility		186.7		173.2		492.4		469.1
Other		0.5		0.4		1.5		1.2
Total operating revenues		289.3		275.4		1,086.7		1,163.1
OPERATING EXPENSES
Cost of gas sold		30.5		32.4		274.4		371.7
Cost of fuel & purchased power		67.1		64.5		186.9		180.3
Other operating		66.7		70.5		231.8		223.3
Depreciation & amortization		47.8		47.2		143.9		140.5
Taxes other than income taxes		11.6		11.2		40.7		45.1
Total operating expenses		223.7		225.8		877.7		960.9
OPERATING INCOME		65.6		49.6		209.0		202.2
OTHER INCOME - NET		0.1		0.9		4.0		3.9
INTEREST EXPENSE		20.4		20.4		61.2		61.0
INCOME BEFORE INCOME TAXES		45.3		30.1		151.8		145.1
INCOME TAXES		17.4		11.4		59.0		54.8
NET INCOME	$	27.9	$	18.7	$	92.8	$	90.3
CONTRIBUTION TO VECTREN BASIC EPS	$	0.34	$	0.22	$	1.13	$	1.11

Utility Group Margin

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

-26-

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

Gas utility margin and throughput by customer type follows:

	Three Months				Nine Months
	Ended September 30,				Ended September 30,
(In millions)	2011		2010		2011		2010
Gas utility revenues	$	102.1	$	101.8	$	592.8	$	692.8
Cost of gas sold		30.5		32.4		274.4		371.7
Total gas utility margin	$	71.6	$	69.4	$	318.4	$	321.1
Margin attributed to:
Residential & commercial customers	$	58.5	$	57.2	$	267.9	$	273.6
Industrial customers		11.5		10.4		41.2		36.7
Other		1.6		1.8		9.3		10.8
Total gas utility margin	$	71.6	$	69.4	$	318.4	$	321.1
Sold & transported volumes in MMDth attributed to:
Residential & commercial customers		6.5		5.9		71.0		69.4
Industrial customers		20.7		19.3		70.6		65.1
Total sold & transported volumes		27.2		25.2		141.6		134.5

Gas utility margins were $71.6 million and $318.4 million for the for the three and nine months ended September 30, 2011, and compared to 2010 increased $2.2 million in the quarter and decreased $2.7 million year to date.  Management estimates a year to date decrease of $3.5 million due to Ohio rate design changes, as described below.  Returns generated on investments in bare steel/ cast iron and distribution riser replacement in Ohio increased margins $0.8 million quarter over quarter and $2.2 million year to date.  Large customer margin, net of the impacts of regulatory initiatives and tracked costs, increased by $0.9 million in the quarter and $4.0 million year to date due primarily to ethanol producers in the Vectren South territory.  Margin decreased $4.4 million year to date due to lower revenue taxes and operating costs directly recovered in margin.

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

-27-

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

Electric utility margin and volumes sold by customer type follows:

	Three Months				Nine Months
	Ended September 30,				Ended September 30,
(In millions)	2011		2010		2011		2010
Electric utility revenues	$	186.7	$	173.2	$	492.4	$	469.1
Cost of fuel & purchased power		67.1		64.5		186.9		180.3
Total electric utility margin	$	119.6	$	108.7	$	305.5	$	288.8
Margin attributed to:
Residential & commercial customers	$	82.1	$	73.3	$	199.1	$	188.5
Industrial customers		27.7		27.0		76.6		73.9
Other customers		2.2		1.6		5.7		5.6
Subtotal: retail	$	112.0	$	101.9	$	281.4	$	268.0
Wholesale power & transmission system margin		7.6		6.8		24.1		20.8
Total electric utility margin	$	119.6	$	108.7	$	305.5	$	288.8
Electric volumes sold in GWh attributed to:
Residential & commercial customers		863.5		886.9		2,223.0		2,315.3
Industrial customers		731.8		712.2		2,074.6		2,019.7
Other customers		5.6		4.9		16.3		16.0
Total retail volumes sold		1,600.9		1,604.0		4,313.9		4,351.0

Retail

Electric retail utility margins were $­­­112.0 million and $281.4 million for the three and nine months ended September 30, 2011, and compared to 2010 increased over the prior year periods by $10.1 million and $13.4 million, respectively.  The impact of new base rates increased margin $10.9 million in the quarter and $16.8 year to date.  Management estimates the impact of weather, which was warmer than normal but cooler compared to the prior year, to have decreased residential and commercial margin $2.7 million in the third quarter and $5.4 million year to date compared to the prior year periods.  Margin increased $0.9 million in the quarter and $1.8 million year to date due to increased MISO operating costs that are directly recovered in margin.

Margin from Wholesale Electric Activities

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

	Three Months				Nine Months
	Ended September 30,				Ended September 30,
(In millions)	2011		2010		2011		2010
Off-system sales	$	0.7	$	2.6	$	5.1	$	6.0
Transmission system sales		6.9		4.2		19.0		14.8
Total wholesale margin	$	7.6	$	6.8	$	24.1	$	20.8

The Company earns a return on electric transmission projects constructed by the Company in its service territory that meet the criteria of MISO’s regional transmission expansion plans.  Margin associated with these projects, including the reconciliation of recovery mechanisms, and other transmission system operations, totaled $6.9 million and $19.0 million for the three and nine months ended September 30, 2011, respectively, compared to $4.2 million and $14.8 million in both the three and nine months ended September 30, 2010.  Increases are primarily due to increased investment in qualifying projects.

-28-

One such project currently under construction meeting these expansion plan criteria is an interstate 345 Kv transmission line that will connect Vectren’s A.B. Brown Generating Station to a station in Indiana owned by Duke Energy to the north and to a station in Kentucky owned by Big Rivers Electric Corporation to the south.  During the construction of these transmission assets and while these assets are in service, SIGECO will recover an approximate 10 percent return, inclusive of the FERC approved equity rate of return of 12.38 percent, on capital investments through a rider mechanism which is projected annually and reconciled the following year based on actual results.  Of the total investment, which is expected to approximate $100 million, the Company has invested approximately $70 million as of September 30, 2011.  The north leg of this expansion was placed in service in November 2010, and the south leg of this project is expected to be operational in 2012. 

For the three and nine months ended September 30, 2011, margin from off-system sales were $0.7 million and $5.1, respectively, compared to $2.6 million and $6.0 million for the three and nine months ended September 30, 2010.  The base rate changes implemented in May 2011 require that wholesale margin from off-system sales earned above or below $7.5 million be shared equally with customers.  This compares to a $10.5 million sharing threshold established in 2007.  Results for the periods presented reflect the impact of that sharing.  Off-system sales totaled 469 GWh and 466 GWh during the nine months ended September 30, 2011 and 2010, respectively.

Utility Group Operating Expenses

Other Operating

For the three and nine months ended September 30, 2011, other operating expenses were $66.7 million and $231.8 million, and compared to 2010 reflect a decrease in the quarter of $3.8 million and a year to date increase of $8.5 million.  The changes primarily reflect variation in electric power supply operating expenses.  Such expenses decreased $1.7 million in the quarter with $1.1 million attributable to planned outage maintenance, and such expenses increased $10.3 million year to date with $8.6 million attributed to planned outage maintenance.  The timing of uncollectible accounts expense reflects lower costs in the quarter by $1.1 million and $2.4 million year to date.  The remaining variances are primarily driven by higher pass through operating costs and lower variable compensation.

Depreciation & Amortization

For the three and nine months ended September 30, 2011, depreciation and amortization expense was $47.8 million and $143.9 million, increasing $0.6 million and $3.4 million, respectively, compared to 2010.  These increases reflect utility investments placed into service, which were offset by lower amortizations of certain deferred costs pursuant to the recent electric base rate order.  Such decreased amortizations were $0.9 million in the quarter and $1.6 million year to date.

Taxes Other Than Income Taxes

For the three and nine months ended September 30, 2011, taxes other than income taxes were $11.6 million and $40.7 million, respectively, which reflects a slight increase in the quarter of $0.4 million and a year to date decrease of $4.4 million.  The year to date decrease is primarily attributable to lower Ohio excise and usage taxes associated with that territory’s ongoing process of exiting the merchant function, which started in the second quarter of last year.  Excise and usage related taxes are offset dollar-for-dollar with lower gas utility revenues.

Utility Group Other Income-Net

Other income-net reflects income of $0.1 million and $4.0 million for the three and nine months ended September 30, 2011, compared to $0.9 million and $3.9 million for the same periods in 2010.  The decrease in the quarter primarily reflects market declines on investments that fund certain benefit plans.

Utility Group Interest Expense

For the three and nine months ended September 30, 2011, interest expense was $20.4 million and $61.2 million, and is generally flat compared to the prior year periods.  Interest expense in all periods reflects the current low interest rate environment and a lower reliance by the Utility Group on short-term borrowings.

Utility Group Income Taxes

In 2011, Utility Group federal and state income taxes were $17.4 million for the quarter and $59.0 million year to date.  The increased expense of $6.0 million quarter over quarter and $4.2 million year to date primarily reflects increased pre-tax income.  The year to date period in 2011 reflects a $1.4 million adjustment that increased income taxes.

-29-

Legislative & Environmental Matters

Indiana House Bill 1004

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

Indiana Senate Bill 251

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

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

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

Ohio House Bill 95

In June 2011, Ohio House Bill 95 was signed into law.  The law adjusts, among other things, the manner in which gas utilities file for rate changes, including the implementation of base rate changes, alternative rate plans, and automatic rate adjustment mechanisms.  Outside of a base rate proceeding, the legislation permits a natural gas company to apply to implement a capital expenditure program for infrastructure expansion, upgrade, or replacement; installation, upgrade, or replacement of information technology systems; or any program necessary to comply with government regulation.  Once such application is approved, the legislation authorizes recovery or deferral of program costs, such as depreciation, property taxes, and carrying costs.  The Company is assessing the impact this legislation may have on its operations.

Clean Air Act

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

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

-30-

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

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

Climate Change

In April 2007, the US Supreme Court determined that greenhouse gases meet the definition of "air pollutant" under the Clean Air Act and ordered the EPA to determine whether greenhouse gas emissions from motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare.  In April 2009, the EPA published its proposed endangerment finding for public comment.  The proposed endangerment finding concludes that carbon emissions from mobile sources pose an endangerment to public health and the environment.  The endangerment finding was finalized in December 2009, and is the first step toward EPA regulating carbon emissions through the existing Clean Air Act in the absence of specific carbon legislation from Congress.  Therefore, any new regulations would likely also impact major stationary sources of greenhouse gases.  The EPA has promulgated two greenhouse gas regulations that apply to SIGECO’s generating facilities.  In 2009, the EPA finalized a mandatory greenhouse gas emissions registry which will require reporting of emissions beginning in 2011 (for the emission year 2010).  The EPA has also finalized a revision to the Prevention of Significant Deterioration (PSD) and Title V permitting rules which would require facilities that emit 75,000 tons or more of greenhouse gases a year to obtain a PSD permit for new construction or a significant modification of an existing facility. 

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

Impact of Legislative Actions & Other Initiatives is Unknown

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

Ash Ponds & Coal Ash Disposal Regulations

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

-31-

Clean Water Act

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

Potential Pipeline Safety Legislation

The U.S Senate has passed a pipeline safety bill that would increase, beyond levels required by current law, the oversight of natural gas pipelines and lead to an investment in the further inspection, and where necessary, additional modernization of pipeline infrastructure.  The U.S. House of Representatives continues to debate legislation similar to the Senate bill as well as alternatives.  At this time and in the absence of final legislation, compliance costs and other effects associated with increased pipeline safety regulations remain uncertain.  However, any future legislative or regulatory actions taken to address pipeline safety could result in both increased levels of operating expenses and capital expenditures associated with the Company’s natural gas distribution businesses.  Compliance costs and capital investments associated with the Company’s Indiana gas utilities would likely qualify as federally mandated regulatory requirements recoverable under Senate Bill 251 referenced above.  In Ohio, capital investments would likely qualify for timely recovery under House Bill 95 referenced above.

Environmental Remediation Efforts

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

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

Indiana Gas accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites.  While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, Indiana Gas has recorded cumulative costs that it has incurred or reasonably expects to incur totaling approximately $23.1 million.  The estimated accrued costs are limited to Indiana Gas’ share of the remediation efforts.  Indiana Gas has arrangements in place for 19 of the 26 sites with other potentially responsible parties (PRP), which limit Indiana Gas’ costs at these 19 sites to between 28 percent and 50 percent.  With respect to insurance coverage, Indiana Gas has received approximately $20.8 million from all known insurance carriers under insurance policies in effect when these plants were in operation.

In October 2002, SIGECO received a formal information request letter from the IDEM regarding five manufactured gas plants that it owned and/or operated and were not enrolled in the IDEM’s VRP.  In October 2003, SIGECO filed applications to enter four of the manufactured gas plant sites in IDEM's VRP.  The remaining site is currently being addressed in the VRP by another Indiana utility.  SIGECO added those four sites into the renewal of the global Voluntary Remediation Agreement that Indiana Gas has in place with IDEM for its manufactured gas plant sites.  That renewal was approved by the IDEM in February 2004.  SIGECO was also named in a lawsuit, involving another waste disposal site subject to potential environmental remediation efforts.  With respect to that lawsuit, SIGECO settled with the plaintiff during 2010 mitigating any future claims at this site.  SIGECO has filed a declaratory judgment action against its insurance carriers seeking a judgment finding its carriers liable under the policies for coverage of further investigation and any necessary remediation costs that SIGECO may accrue under the VRP program and/or related to the site subject to the settled lawsuit.  In November the Court ruled on two motions for summary judgment, finding for SIGECO and against certain insurers on indemnification and defense obligations in the policies at issue.

-32-

SIGECO has recorded cumulative costs that it has incurred or reasonably expects to incur related to these environmental matters, including the recent settlement discussed above, totaling approximately $17.0 million.  However, the total costs that may be incurred in connection with addressing these sites cannot be determined at this time.  With respect to insurance coverage, SIGECO has recorded approximately $14.2 million of expected insurance recoveries from certain of its insurance carriers under insurance policies in effect when these sites were in operation.  While negotiations are ongoing with certain carriers, settlements have been reached with some carriers and $9.0 million in proceeds have been received.

The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others.  While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require some level of additional remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery.  As of September 30, 2011 and December 31, 2010, respectively, approximately $5.4 million and $5.5 million of accrued, but not yet spent, costs are included in Other Liabilities related to both the Indiana Gas and SIGECO sites.

Rate & Regulatory Matters

Vectren South Electric Base Rate Filing

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

Coal Procurement Procedures

Vectren South submitted a request for proposal in April 2011 regarding coal purchases for a four year period beginning in 2012.  After negotiations with bidders, Vectren South has reached an agreement in principle for multi-year purchases with two suppliers, one of which is Vectren Fuels, Inc.  Consistent with the IURC direction in the electric rate case, a sub docket proceeding has been established to review the Company’s prospective coal procurement procedures, and the Company submitted evidence related to its recent request for proposal (RFP) and those coal procurement procedures to the IURC in September 2011.  In October 2011, the OUCC filed its testimony which, while suggesting enhancements to the process to be considered, does not challenge the results of the RFP and the resulting new contracts.  A hearing in this proceeding is scheduled for December 2011.

Vectren South Electric Demand Side Management Program Filing

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

-33-

On August 31, 2011 the IURC issued an order approving an initial three year DSM plan in the Vectren South service territory that complies with the IURC’s energy saving targets.  Consistent with the Company’s proposal, the order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; 3) lost margin recovery associated with the implementation of DSM programs for large customers; and 4) deferral of lost margin up to $1 million in 2011 associated with small customer DSM programs for subsequent recovery under a tracking mechanism to be proposed by the Company.  This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the order received April 27, 2011.  The Company is in the initial phases of implementing electric conservation initiatives.

Vectren South Electric Dense Pack Filing

On September 14, 2011, Vectren South filed a petition with the IURC seeking recovery of and return on the capital investment in dense pack technology to improve the efficiency of its A.B. Brown Generating Station.  This investment is expected to be approximately $32 million over the next two years, of which approximately $17 million has been invested to date.  This technology is expected to allow the A.B. Brown units to run at least 5 percent more efficient, thereby burning less fuel, and reducing fuel costs and emissions of pollutants.  Indiana statute provides for timely recovery of these investments, with a return, in instances where the investment increases the efficiency of existing generating plants that are fueled by coal.  The IURC will conduct a hearing in early 2012.

Vectren North & Vectren South Gas Decoupling Extension Filing

On April 14, 2011, the Company’s Indiana based gas companies (Vectren North and Vectren South) filed with the IURC a joint settlement agreement with the OUCC on an extension of the offering of conservation programs and the supporting gas decoupling mechanism originally approved in December 2006.  On August 18, 2011, the IURC issued an order approving the settlement as filed, granting the extension of the current decoupling mechanism in place at both gas companies and recovery of new conservation program costs through December 2015.

VEDO Gas Rate Design

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

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

VEDO Continues the Process to Exit the Merchant Function

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

The second phase of the exit process began on April 1, 2010.  During this phase, the Company no longer sells natural gas directly to customers.  Rather, state-certified Competitive Retail Natural Gas Suppliers, that were successful bidders in a similar regulatory-approved auction, sell the gas commodity to specific customers for a 12 month period at auction-determined standard pricing.  The first auction was conducted on January 12, 2010, and the auction results were approved by the PUCO on January 13, 2010.  The plan approved by the PUCO required that the Company conduct at least two annual auctions during this phase.  As such, the Company conducted another auction on January 18, 2011 in advance of the second 12-month term which commenced on April 1, 2011.  The results of that auction were approved by the PUCO on January 19, 2011.Vectren Source, the Company’s wholly owned nonutility retail gas marketer, was a successful bidder in both auctions winning one tranche of customers in the first auction and two tranches of customers in the second auction.  Each tranche of customers equates to approximately 28,000 customers.  Consistent with current practice, customers will continue to receive a single bill for the commodity as well as the delivery component of natural gas service from VEDO.

-34-

The PUCO provided for an Exit Transition Cost rider, which allows the Company to recover costs associated with the transition process.  Exiting the merchant function has not had a material impact on earnings or financial condition.  It, however, has and will continue to reduce Gas utility revenues and have an equal and offsetting impact to Cost of gas sold and revenue related taxes recorded in Taxes other than income taxes as VEDO no longer purchases gas for resale to these customers.In the three months and nine months ended September 30, 2010, VEDO’s gas costs were $0.7 million and $85.3 million, respectively, while revenue taxes were $1.6 million and $12.1 million, respectively.  In the three and nine months ended September 30, 2011, gas costs were $0.7 million and $9.6 million, respectively, while revenue taxes were $1.7 million and $8.4 million, respectively.  Therefore, generally there was no change in Gas utility revenues resulting from VEDO’s exit of the merchant function in the current quarter, and such revenues decreased approximately $79.4 million year to date.

Results of Operations of the Nonutility Group

Nonutility Group earnings for the three and nine months ended September 30, 2011 and 2010 follow:

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
(In millions, except per share amounts)	2011			2010			2011			2010
NET INCOME (LOSS)	$	7.6		$	(2.2	)	$	3.4		$	(1.9	)
CONTRIBUTION TO VECTREN BASIC EPS	$	0.09		$	(0.02	)	$	0.04		$	(0.02	)
NET INCOME (LOSS) ATTRIBUTED TO:
Infrastructure Services	$	11.9		$	3.2		$	11.1		$	2.2
Energy Services		2.3			2.8			1.6			4.2
Coal Mining		5.8			2.5			15.9			8.1
Energy Marketing		(12.2	)		(10.4	)		(24.3	)		(9.1	)
Other Businesses		(0.2	)		(0.3	)		(0.9	)		(7.3	)

Infrastructure Services

Infrastructure Services provides underground construction and repair to utility infrastructure through Miller Pipeline (Miller) and Minnesota Limited, which was acquired on March 31, 2011.  Inclusive of holding company costs, results from Infrastructure’s operations for the three and nine months ended September 30, 2011 were earnings of $11.9 million and $11.1 million, respectively and reflect increases of $8.7 million and $8.9 million, respectively.  In the 2011 quarter and year to date periods, Minnesota Limited contributed earnings of $5.8 million and $6.3 million, respectively, and reflects increased demand for work on transmission pipeline repairs.  The remainder of the increase, totaling $2.9 million and $2.6 million in the quarter and year to date periods, relates to Miller Pipeline’s ongoing operations and is representative of increased demand.  Construction activity, particularly in Minnesota Limited’s market area, is high during the summer months and begins to decline due to weather conditions during the fourth quarter.  However, construction activity generally is expected to remain strong as utilities and pipelines operators continue to replace their aging natural gas and oil infrastructure and as the need for shale gas and oil infrastructure becomes more prevalent.

Acquisition of Minnesota Limited

On March 31, 2011, the Company, through its wholly owned subsidiary Vectren Infrastructure Services Company, Inc., purchased Minnesota Limited, Inc., excluding certain assets.  Minnesota Limited is a specialty contractor focusing on transmission pipeline construction and maintenance; pump station, compressor station, terminal and refinery construction; gas distribution; and hydrostatic testing.  Minnesota Limited is headquartered in Big Lake, Minnesota and the majority of its customers are generally located in the northern Midwest region.  This acquisition positions the Company for anticipated growth in demand for gas transmission construction resulting from the need to transport new sources of natural gas and oil found in shale formations and the need to upgrade the nation’s aging pipelines.

-35-

The Company accounted for the cash acquisition in accordance with FASB authoritative guidance for business combinations, which requires the Company to recognize the assets acquired and the liabilities assumed, measured at their fair values as of the date of acquisition.  The following table summarizes the allocation of the purchase price to the fair value of the assets acquired and liabilities assumed.

(In millions)
Working capital assets	$	21.5
Working capital liabilities		(6.7	)
Net working capital		14.8
Property, plant & equipment		34.4
Identifiable intangible assets		19.1
Goodwill		20.3
Net assets acquired		88.6
Debt obligation assumed		(5.2	)
Cash paid in acquisition, net of cash acquired	$	83.4

As of November 4, 2011, the purchase price and its allocation remain preliminary and could change in subsequent periods.  Any subsequent material changes to the purchase price and its allocation will be adjusted pursuant to FASB guidance.  Since the initial purchase price allocation was disclosed only minor adjustments have been made.  The final purchase price and the allocation are dependent on final reconciliations of working capital and other items.

Level 3 market inputs, such as discounted cash flows, revenue growth rates, royalty rates, and dealer and auction values of used equipment, were used to derive the preliminary fair values of the identifiable intangible assets and property plant and equipment.  Identifiable intangible assets include back log, long-term customer relationships, and trade name.  The Company intends to use the acquired assets for an extended period and is amortizing them on a straight-line basis over their estimated useful lives.  Goodwill arising from the purchase represents intangible value the Company expects to realize over time.  This value includes but is not limited to: 1) expected synergies from more efficient utilization of equipment and human resources within the combined entities; 2) the experience and size of the acquired work force; and 3) the reputation of the current Minnesota Limited management team.  The goodwill, which does not amortize pursuant to FASB guidance, is deductible over a 15 year period for purposes of computing current income tax expense.

Transaction costs associated with the acquisition and expensed by the Company totaled approximately $0.5 million, of which $0.2 million are included in other operating expenses during the nine months ended September 30, 2011 and the remainder was expensed in 2010.  During the three months ended September 30, 2011 and for the period from April 1, 2011 through September 30, 2011, Minnesota Limited contributed approximately $53.2 million and $75.2 million to the Company's revenues, respectively.

-36-

The following table presents the Company's unaudited proforma results of operations for the three months ended September 30, 2010 and nine months ended September 30, 2011 and 2010 as if the acquisition had occurred on January 1, 2010.

	Three Months		Nine Months
	Ended September 30,		Ended September 30,
(In millions, except per share data)	2010		2011		2010
Total operating revenues	$	460.6	$	1,718.9	$	1,645.2
Net income	$	18.6	$	94.8	$	89.7
Basic earnings per share	$	0.23	$	1.16	$	1.11
Diluted earnings per share	$	0.23	$	1.16	$	1.10

In addition to the incremental revenues and expenses recorded by Minnesota Limited during this period, the proforma financial data for all periods presented contain several adjustments including the following: recording the additional amortization expense from the identifiable intangible assets; adjusting the estimated tax provision of the proforma combined results; and adjusting for the issuance of short-term debt to facilitate the acquisition.  The Company prepared the proforma financial information for the combined entities for comparative purposes only, and it may not be indicative of what actual results would have been if the acquisition had taken place on the proforma date, or of future results.

Concurrent with the purchase agreement, the Company executed a lease arrangement at fair value for the Minnesota Limited corporate headquarters, which is owned by a member of the Minnesota Limited management team and certain family members.  The lease obligates the Company to pay approximately $83,333 per month for 10 years along with certain executory costs for taxes and other operating expenses.  Pursuant to FASB guidance, the Company accounts for the obligation as an operating lease, expensing the lease payments and executory costs as incurred.

Energy Services

Energy Services provides energy performance contracting and renewable energy services through Energy Systems Group, LLC (ESG).  Inclusive of holding company costs, Energy Services’ operations contributed earnings of $2.3 million during the third quarter of 2011, compared to earnings of $2.8 million in 2010.  Year to date earnings were $1.6 million in 2011, compared to earnings of $4.2 million in 2010.

The lower results in 2011 are primarily due to increased operating and recruitment costs related to the ramp up of the sales force in order to facilitate faster growth.  At September 30, 2011, backlog was $100 million compared to $118 million at December 31, 2010, and $64 million at September 30, 2010.  The national focus on a comprehensive energy strategy and a continued focus on energy conservation, renewable energy, and sustainability are expected to create favorable conditions for future growth in this area.

Coal Mining

Coal Mining owns mines that produce and sell coal to the Company’s utility operations and to third parties through its wholly owned subsidiary Vectren Fuels, Inc. (Vectren Fuels).  Coal Mining, inclusive of holding company costs, earned approximately $5.8 million during the quarter ended September 30, 2011, compared to $2.5 million in 2010, an increase of $3.3 million.  Year to date, Coal Mining results were $15.9 million compared to earnings of $8.1 million in 2010, an increase of $7.8 million. 

Coal Mining revenues were $81.0 million in the quarter and $221.2 million year to date in 2011 and represent increases of $23.5 million and $61.5 million compared to prior year periods, respectively.  The increases reflect increased sales to third parties as a result of opening Oaktown 1 in 2010.  The anticipated 2011 coal production and sales are expected to exceed 5 million tons.

Vectren Fuels is currently in negotiation with a number of customers regarding sales in 2012 and beyond.  Vectren Fuels and Vectren South have adjusted both the price and quantity of coal through the remaining terms of contracts that had price reopener clauses.  Pursuant to the supply contracts, Vectren Fuels expects to supply Vectren South, including its plant jointly owned with ALCOA, approximately 1.5 million tons in 2012.  Sales to Vectren South are expected to be at least 2.3 million tons in both 2013 and 2014.  At this time, approximately 70 percent of Vectren Fuel’s planned 2012 production has been subscribed.

-37-

Coal Reserves

As of September 30, 2011 management estimates the Company’s total Illinois Basin coal reserves to be approximately 133 million tons.  Of this amount, approximately 39 million tons are attributable to a mine located at the Company’s Oaktown mining complex that is currently under construction and is expected to open in mid-2012, or later.  However, Vectren Fuels may continue to adjust this timing as it evaluates the impacts of market conditions.  The Company estimates approximately $15 million of additional capital is required to complete the mine.  Once this mine is in production, Vectren Fuels underground mines are capable of producing about 7.5 million tons of coal per year.

Mine Safety Information

The Company, through its wholly owned subsidiary Vectren Fuels, Inc., owns coal mines and related assets located in Indiana.  The Company has retained independent third party contract mining companies to operate its coal mines.  Five Star Mining LLC ("Five Star") is the contract mining company at the Prosperity underground mine and Black Panther Mining LLC ("Black Panther") is the contract mining company at the Oaktown underground mines.  While in operation, Vigo-Cypress Creek, LLC was the contract mining company at Cypress Creek surface mine.  The contract mining companies are the mine “operator”, as that term is used in both the Federal Mine Safety and Health Act of 1977 (the “Mine Act”) and the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010.  All employees at the coal mines are hired, supervised, and paid by the contract mining companies.  As the mine operator, the contract mining companies make all regulatory filings required by the MSHA.  In most circumstances, however, the cost of fines and penalties assessed by MSHA are contractually passed through from the contract mining company to Vectren Fuels.  The process of settling such claims can take years in certain circumstances.  During the nine months ended September 30, 2011, the Company paid approximately $0.2 million related to assessments issued to the mine operators.

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

Energy Marketing

Energy Marketing is comprised of the Company’s gas marketing operations, energy management services, and retail gas supply operations.  Inclusive of holding company costs, results from Energy Marketing for the quarter ended September 30, 2011, were a loss of $12.2 million, compared to a loss of $10.4 million in 2010.  For the nine months ended September 30, 2011, losses were $24.3 million compared to a loss of $9.1 million in 2010.

ProLiance

ProLiance, a nonutility energy marketing affiliate of Vectren and Citizens, provides services to a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions located throughout the Midwest and Southeast United States.  ProLiance’s customers include Vectren’s Indiana utilities and 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.  Therefore, the Company accounts for its investment in ProLiance using the equity method of accounting.  On March 17, 2011, an order was received from the IURC providing for ProLiance’s continued provision of gas supply services to the Company’s Indiana utilities and Citizens Energy Group through March 2016. 

Vectren Energy Marketing and Services, Inc (EMS), a wholly owned subsidiary, holds the Company’s investment in ProLiance.  Within the consolidated entity, EMS is responsible for certain financing costs associated with ProLiance and is also responsible for income taxes and allocated corporate expenses related to the Company’s portion of ProLiance’s results.  During the quarter ended September 30, 2011, EMS’ results related to the Company’s share of ProLiance’s results, which include financing costs and income taxes, was a loss of approximately $8.6 million compared to a loss of $6.9 million in 2010.  During the nine months ended September 30, 2011, results at EMS related to ProLiance was a loss of approximately $25.3 million compared to a loss of $9.9 million in 2010.

-38-

The $1.7 million quarter over quarter and $15.4 million year to date increased loss reflects the impact on the market of new natural gas sources from shale and greater transmission capacity, as well as the impacts of reduced industrial demand for natural gas in the Midwest and is consistent with trends experienced dating back to the latter part of 2010.  These conditions have resulted in plentiful natural gas supply and lower and less volatile natural gas prices.  Historical basis differences between physical and financial markets and summer and winter prices have narrowed.  As a result, there have been reduced opportunities to optimize ProLiance’s firm transportation and storage capacity.  ProLiance has structured optimization activities to remain flexible to maximize potential opportunities if market conditions improve.

Various profit improvement initiatives are underway, including efforts to lower the cost of pipeline and storage demand costs through ongoing renegotiations.  Through these negotiations and by dropping some uneconomical contracts as they expire, pipeline and storage costs have been lowered by $25 million annually starting in 2012.  ProLiance had approximately $80 million of annual fixed costs related to its transportation and storage contracts prior to these actions.  In addition to this reduction, additional opportunities exist to renegotiate or drop the remaining contracts, including those with annual demand costs of $18 million that are scheduled to expire through 2015.  At September 30, 2011, ProLiance had just over $140 million of equity on its balance sheet, no long-term debt outstanding, and minimal borrowings on its short-term credit facility.  As depressed market conditions have continued for longer than expected, it is now anticipated that ProLiance will operate at a loss of $0.25 to $0.35 per share in 2011.  Changes in these market conditions or other circumstances could cause actual results to be materially above or below this range.

For the three and nine months ended September 30, 2011, the amounts recorded to Equity in losses of unconsolidated affiliates related to ProLiance’s operations totaled a pre-tax loss of $11.9 million and $34.9 million, respectively.  For the three and nine months ended September 30, 2010, the amounts recorded to Equity in losses of unconsolidated affiliates related to ProLiance’s operations totaled a pretax loss of $8.2 million and $8.0 million, respectively.

Investment in Liberty Gas Storage

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

In late 2008, the project at the North site was halted due to subsurface and well-completion problems, resulting in Liberty recording a $132 million impairment charge related to the North site in 2009.  ProLiance recorded its share of the charge in 2009 totaling $33 million; the Company recorded its share of the charge in 2009 totaling $11.9 million after tax.  ProLiance’s ability to meet the needs of its customers has not been, nor does it expect it to be, impacted.  Approximately 12 Bcf of the storage at the South site, which comprises three of the four FERC certified caverns, is fully completed and tested.  As a result of the issues encountered at the North site, Liberty requested and the FERC approved the separation of the North site from the South site.  As of September 30, 2011 and December 31, 2010, ProLiance’s investment in Liberty approximated $36.9 million and $36.7 million, respectively.

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

-39-

Vectren Source

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 incurred a seasonal loss of approximately $3.6 million in the third quarter of 2011 and a seasonal loss of $3.5 million in 2010.  Year to date, Vectren Source has earned $1.0 million in 2011 compared to $0.8 million in 2010.  Vectren Source’s contribution to annual earnings is also expected to be generally consistent with the prior year; however, changes in customer count, weather, the cost of gas or other factors and circumstances could cause actual results to be materially above or below the prior year.Vectren Source’s customer count at September 30, 2011, was approximately 261,000 customers, compared to 204,000 customers at September 30, 2010.  The 2011 customer count reflects nearly 140,000 customers in Vectren Energy Delivery of Ohio’s (VEDO) service territory that have either voluntarily opted to choose their natural gas supplier or are supplied natural gas by Vectren Source but remain customers of the regulated utility as part of VEDO’s exit from the merchant function process.  As a result of a supplier choice auction held on January 18, 2011 in VEDO’s service territory, Vectren Source increased its customer base by 28,000 in the second quarter of 2011.

Other Businesses

Third quarter results in both 2011 and 2010 include losses from Other nonutility businesses, which include legacy real estate and other investments.  During the nine months ended September 30, 2011, Other nonutility businesses operated at a loss of $0.9 million compared to a loss of $7.3 million in 2010.  The lower results in 2010 reflect a second quarter $4.0 million after tax charge related to a decline in the fair value of an energy-related investment originally made in 2004 by Haddington Energy Partners.  The lower results in 2010 also reflect a first quarter $2.9 million after tax charge related to the reduction in value of a note receivable recorded in 2002 related to a previously exited business.

Haddington Energy Partnerships

The Company has an approximate 40 percent ownership interest in Haddington Energy Partners, LP (Haddington I) and Haddington Energy Partners II, LP (Haddington II).  These Haddington ventures have interests in two remaining mid-stream energy related investments.  Both Haddington ventures are investment companies accounted for using the equity method of accounting. 

In the second quarter of 2010, the Company was notified by Haddington’s management that the fair value of its investment in a liquefied natural gas facility (LNG) had declined, and Haddington reflected that decline in its financial statements.  The Company recorded its share of the decline in fair value and also impaired a note receivable associated with the LNG investment.  In total, the pre-tax charge was approximately $6.5 million, of which, $6.1 million is reflected in Equity in earnings of unconsolidated affiliates and $0.4 million is reflected in Other-net, for the nine months ended September 30, 2010.  At September 30, 2011, the Company’s remaining $3.4 million investment in the Haddington ventures is related to payments to be received associated with the sale of a compressed air storage facility sold in 2009.  The Company has no further commitments to invest in either Haddington I or II.  

Impact of Recently Issued Accounting Guidance

Other Comprehensive Income (OCI)

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

Goodwill Testing

In September 2011, the FASB issued new accounting guidance regarding testing goodwill for impairment.  The new guidance will allow the Company an option to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test.  Using the new guidance, the Company no longer would be required to calculate the fair value of a reporting unit unless the Company determines, based on that qualitative assessment, that it is more likely than not that its fair value is less than its carrying amount.  The new guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011.  The adoption of this guidance will have no material impact to the Company’s financial statements.

-40-

Multiemployer Pension Plan Disclosures

In September 2011, the FASB issued new accounting guidance that requires enhanced disclosures regarding an employer’s participation in multiemployer pension plans.  For plans that are individually significant, these enhanced disclosures include the legal name of the plan, the plan’s Employer Identification Number, the employer’s contributions made to the plan, the expiration date(s) of the collective-bargaining agreement(s) requiring contributions to the plan, the most recently available certified zone status provided by the plan, and several other disclosures.  The new disclosure requirements are effective for fiscal years ending after December 15, 2011, so they will be effective for the Company’s 2011 financial statements.  The Company participates in several multiemployer pension plans and is currently assessing the impact these new disclosure requirements will have on its financial statements.

Financial Condition

Within Vectren’s consolidated group, Utility Holdings primarily funds the short-term and long-term financing needs of the Utility Group operations, and Vectren Capital Corp (Vectren Capital) funds short-term and long-term financing needs of the Nonutility Group and corporate operations.  Vectren Corporation guarantees Vectren Capital’s debt, but does not guarantee Utility Holdings’ debt.  Vectren Capital’s long-term debt, including current maturities, and short-term obligations outstanding at September 30, 2011 approximated $410 million and $178 million, respectively.  Utility Holdings’ outstanding long-term and short-term borrowing arrangements are jointly and severally guaranteed by Indiana Gas, SIGECO, and VEDO.  Utility Holdings’ long-term debt, including current maturities, and short-term obligations outstanding at September 30, 2011 approximated $918 million and $38 million, respectively.  Additionally, prior to Utility Holdings’ formation, Indiana Gas and SIGECO funded their operations separately, and therefore, have long-term debt outstanding funded solely by their operations.  SIGECO will also occasionally issue tax exempt debt to fund qualifying pollution control capital expenditures.  Total Indiana Gas and SIGECO long-term debt outstanding at September 30, 2011, was $388 million.

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

The credit ratings of the senior unsecured debt of Utility Holdings and Indiana Gas, at September 30, 2011, are A-/A3 as rated by Standard and Poor's Ratings Services (Standard and Poor’s) and Moody’s Investors Service (Moody’s), respectively.  The credit ratings on SIGECO's secured debt are A/A1.  Utility Holdings’ commercial paper has a credit rating of A-2/P-2.  The current outlook of both Moody’s and Standard and Poor’s is stable.  A security rating is not a recommendation to buy, sell, or hold securities.  The rating is subject to revision or withdrawal at any time, and each rating should be evaluated independently of any other rating.  Standard and Poor’s and Moody’s lowest level investment grade rating is BBB- and Baa3, respectively.

The Company’s consolidated equity capitalization objective is 45-55 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 46 percent of long-term capitalization at both September 30, 2011 and December 31, 2010.  Long-term capitalization includes long-term debt, including current maturities and debt subject to tender, as well as common shareholders’ equity.

As of September 30, 2011, the Company was in compliance with all debt covenants.

Available Liquidity in Current Credit Conditions

The Company’s A-/A3 investment grade credit ratings have allowed it to access the capital markets as needed.  Since 2008, the Company has reduced its reliance on short-term borrowing capacity with the completion of several long-term financing transactions including issuances of long-term debt and the settlement of an equity forward contract.  The Company anticipates funding future capital expenditures and dividends through internally generated funds.  In addition, available liquidity is expected to be enhanced by the extension of bonus depreciation legislation.

-41-

On October 21, 2011, Utility Holdings priced $100 million of senior unsecured notes at an interest rate of 5.00 percent per annum and with a maturity date of February 3, 2042.  The notes will be sold to various institutional investors pursuant to a private placement note purchase agreement expected to be entered into in November 2011.  These senior notes will be unsecured and will be jointly and severally guaranteed by Utility Holdings’ regulated utility subsidiaries, Southern Indiana Gas and Electric Company, Indiana Gas Company, Inc., and Vectren Energy Delivery of Ohio, Inc.  The proceeds received from the issuance of the senior notes will be used to refinance Utility Holdings' $96.2 million 5.95 percent senior notes due 2036, that are expected to be called at par and retired on or about November 21, 2011.  Subject to the satisfaction of customary closing conditions, the new notes will be issued on or about February 1, 2012.

On April 5, 2011, Utility Holdings entered into a private placement note purchase agreement pursuant to which various institutional investors have agreed to purchase the following tranches of notes:  (i) $55 million of 4.67 percent Senior Guaranteed Notes, due November 30, 2021, (ii) $60 million of 5.02 percent Senior Guaranteed Notes, due November 30, 2026, and (iii) $35 million of 5.99 percent Senior Guaranteed Notes, due December 2, 2041.  The proceeds received from the issuance of these senior notes will be used to partially refinance $250 million of Utility Holdings 6.625 percent long-term debt maturing December 1, 2011.  The remainder of the maturing debt will be replaced with short-term borrowings.  These senior notes are unsecured and will be jointly and severally guaranteed by Utility Holdings’ regulated utility subsidiaries, Southern Indiana Gas and Electric Company, Indiana Gas Company, Inc., and Vectren Energy Delivery of Ohio, Inc.  Subject to the satisfaction of customary closing conditions precedent, the notes will be issued on or about November 30, 2011.  The Company has reclassified $150 million of the $250 million debt redemption due in December 2011 to long-term debt in its September 30, 2011 Consolidated Balance Sheet to reflect the Company’s ability and intent to refinance that portion of the debt on a long-term basis with this issuance.

Consolidated Short-Term Borrowing Arrangements

At September 30, 2011, the Company has $600 million of short-term borrowing capacity, including $350 million for the Utility Group and $250 million for the wholly owned Nonutility Group and corporate operations.  As reduced by borrowings currently outstanding, approximately $312 million was available for the Utility Group operations.  As reduced by borrowings currently outstanding which includes impacts from the Minnesota Limited acquisition, approximately $72 million was available for the wholly owned Nonutility Group and corporate operations.  These facilities are used to supplement working capital needs and also to fund capital investments and debt redemptions until financed on a long-term basis.

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

	Utility Group Borrowings						Nonutility Group Borrowings
(In millions)	2011			2010			2011			2010
Nine Months Ended September 30
Balance Outstanding	$	38.3		$	26.0		$	178.1		$	131.3
Weighted Average Interest Rate		0.41	%		0.40	%		2.03	%		2.01	%
Nine Months Ended September 30 Average
Balance Outstanding	$	14.0		$	5.0		$	110.6		$	151.4
Weighted Average Interest Rate		0.40	%		0.40	%		2.01	%		0.64	%
Maximum Month End Balance Outstanding	$	42.5		$	26.0		$	178.1		$	174.6

	Utility Group Borrowings						Nonutility Group Borrowings
(In millions)	2011			2010			2011			2010
Quarterly Average - September 30
Balance Outstanding	$	18.8		$	13.5		$	152.9		$	121.3
Weighted Average Interest Rate		0.41	%		0.41	%		2.01	%		0.67	%
Maximum Month End Balance Outstanding	$	38.3		$	26.0		$	178.1		$	131.3

-42-

ProLiance Short-Term Borrowing Arrangements

ProLiance, a nonutility energy marketing affiliate of the Company, has separate borrowing capacity available through a syndicated credit facility.  This facility was renewed on May 18, 2011 at a $130 million capacity level as adjusted for letters of credit and current inventory and receivable balances.  This new one year credit facility reflects the impact of lower gas prices and resulting lower working capital need.  As of September 30, 2011, $25.0 million in borrowings were outstanding.  The 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 $5.2 million and $7.2 million in the nine months ended September 30, 2011 and 2010, respectively.  Throughout 2011, new issuances required to meet these various plan requirements are estimated to be approximately $6 to $7 million.

Vectren Capital Financing

In December 2010, the Company, through Vectren Capital, issued $125 million of senior unsecured notes.  The proceeds were used to refinance maturing long-term debt, to permanently finance coal mine investments, and to provide sufficient liquidity for the growth in the Nonutility Group, such as the Minnesota Limited acquisition.  The Company currently has no near term plans for additional permanent financing for its nonutility operations.

Potential Uses of Liquidity

Pension & Postretirement Funding Obligations

During the nine months ended September 30, 2011, $32.6 million in contributions to qualified pension plans were made.  The Company anticipates $2.4 million of additional funding in 2011.  Of the $35 million of anticipated funding in 2011, $25 million is made available from bonus depreciation opportunities.  Management currently estimates contributing $10 million to qualified pension plans in 2012.  Contributions in 2012 and beyond are dependent on a variety of factors, including the Company’s progress toward attaining its long-term goal of being fully funded related to the plans’ accrued benefit obligations and the available sources of cash to fund such additional contributions.

Corporate Guarantees

The Company issues parent level guarantees to certain vendors and customers of its wholly owned subsidiaries and unconsolidated affiliates.  These guarantees do not represent incremental consolidated obligations; rather, they represent parental guarantees of subsidiary and unconsolidated affiliate obligations in order to allow those subsidiaries and affiliates the flexibility to conduct business without posting other forms of collateral.  At September 30, 2011, parent level guarantees support a maximum of $25 million of ESG’s performance contracting commitments and warranty obligations and $27 million of other project guarantees.  The broader scope of ESG’s performance contracting obligations, including those not guaranteed by the parent company, are described below.  In addition, the parent company has approximately $78 million of other guarantees outstanding supporting other consolidated subsidiary operations, of which $53 million support the operations of Vectren Source, a wholly owned non-regulated retail gas marketer and $20 million represent letters of credit supporting other nonutility operations.  Guarantees issued and outstanding on behalf of unconsolidated affiliates approximated $3 million at September 30, 2011.  These guarantees relate primarily to arrangements between ProLiance and various natural gas pipeline operators.  The Company has not been called upon to satisfy any obligations pursuant to these parental guarantees and has accrued no significant liabilities related to these guarantees.

Performance Guarantees & Product Warranties

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

-43-

Specific to ESG, in its role as a general contractor in the performance contracting industry, at September 30, 2011, there are 81 open surety bonds supporting future performance.  The average face amount of these bonds is $4.0 million, and the largest obligation has a face amount of $30.8 million.  The maximum exposure of these obligations is less than these amounts for several factors, including the level of work already completed.  At September 30, 2011, over 50 percent of work was completed on projects with open surety bonds.  A significant portion of these commitments will be fulfilled within one year.  In instances where ESG operates facilities, project guarantees extend over a longer period.  In addition to its performance obligations, ESG also warrants the functionality of certain installed infrastructure generally for one year and the associated energy savings over a specified number of years.

Other Letters of Credit

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

Planned Capital Expenditures & Investments

Utility capital expenditures are estimated at $60 million for the remainder of 2011.  Nonutility capital expenditures and investments are estimated at $35 million for the remainder of 2011.

Comparison of Historical Sources & Uses of Liquidity

Operating Cash Flow

The Company's primary source of liquidity to fund working capital requirements has been cash generated from operations, which totaled $291.5 million and $322.4 million for the nine months ended September 30, 2011 and 2010, respectively.  The lower level of cash generated during the nine months ended September 30, 2011 is primarily attributable to increased contributions to pension plans in 2011.

Financing Cash Flow

Net cash flow required for financing activities was $15.1 million during the nine months ended September 30, 2011 and reflects the payment of dividends and some increased nonutility borrowings related to the acquisition of Minnesota Limited.  This compares to $133.8 million of cash required for financing activities in the prior year, which reflects the repayment of short-term borrowings.

Investing Cash Flow

Cash flow required for investing activities was $310.6 million and $193.3 million during the nine months ended September 30, 2011 and 2010, respectively.  The increase in cash required for investing activity reflects the Nonutility Group infrastructure business acquisition more fully described in Note 5 to the consolidated financial statements and some increase in capital expenditures associated with planned outages in the Utility Group and additional investment in equipment for the Infrastructure Services business in the Nonutility Group.

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:

-44-

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

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

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

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

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

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

·   Economic conditions surrounding the current economic uncertainty, including significantly lower levels of economic activity; uncertainty regarding energy prices and the capital and commodity markets; volatile changes in the demand for natural gas, electricity, coal, and other nonutility products and services; impacts on both gas and electric large customers; lower residential and commercial customer counts; higher operating expenses; and further reductions in the value of certain nonutility real estate and other legacy investments.

·   Volatile natural gas and coal commodity prices and the potential impact on customer consumption, uncollectible accounts expense, unaccounted for gas and interest expense.

·   Changing market conditions and a variety of other factors associated with physical energy and financial trading activities including, but not limited to, price, basis, credit, liquidity, volatility, capacity, interest rate, and warranty risks.

·   Direct or indirect effects on the Company’s business, financial condition, liquidity and results of operations resulting from changes in credit ratings, changes in interest rates, and/or changes in market perceptions of the utility industry and other energy-related industries.

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

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

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

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

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

·   Changes in or additions to federal, state or local legislative requirements, such as changes in or additions to tax laws or rates, 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.

-45-

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 2010 Form 10-K and is therefore not presented herein.

ITEM 4.  CONTROLS AND PROCEDURES

Changes in Internal Controls over Financial Reporting

During the quarter ended September 30, 2011, there have been no changes to the Company’s internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

As of September 30, 2011, the Company conducted an evaluation under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of the effectiveness and the design and operation of the Company's disclosure controls and procedures.  Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer have concluded that the Company's disclosure controls and procedures are effective as of September 30, 2011, to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is:

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

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

      regarding required disclosure.

PART II

ITEM 1.  LEGAL PROCEEDINGS

The Company is party to various legal proceedings and audits and reviews by taxing authorities and other government agencies arising in the normal course of business.  In the opinion of management, there are no legal proceedings or other regulatory reviews or audits pending against the Company that are likely to have a material adverse effect on its financial position, results of operations, or cash flows.  See the notes to the consolidated financial statements regarding commitments and contingencies, environmental matters, and rate and regulatory matters.  The consolidated condensed financial statements are included in Part 1 Item 1.

ITEM 1A.  RISK FACTORS

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

-46-

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 September 30, 2011.

ITEM 5. OTHER INFORMATION

Corporate Code of Conduct

The Company’s Corporate Governance Guidelines, its charters for each of its Audit, Compensation and Benefits and Nominating and Corporate Governance Committees, its Corporate Code of Conduct that covers the Company’s officers and employees, and its Board Code of Ethics & Code of Conduct that covers the Company’s directors are available in the Corporate Governance section of the Company’s website, www.vectren.com.  The Corporate Code of Conduct (titled “Corp Code of Conduct”) contains specific codes of ethics pertaining to executive officers.  A separate code of conduct (titled “Board Code of Ethics & Code of Conduct”) contains specific codes of ethics pertaining to the Board of Directors.  A copy will be mailed upon request to Investor Relations, Attention: Robert L. Goocher, One Vectren Square, Evansville, Indiana 47708.  The Company intends to disclose any amendments to the Corporate Code of Conduct/Board Code of Ethics & Code of Conduct or waivers of the Corporate Code of Conduct/ on behalf of the Company’s directors or officers including, but not limited to, the principal executive officer, principal financial officer, principal accounting officer and persons performing similar functions on the Company’s website at the internet address set forth above promptly following the date of such amendment or waiver and such information will also be available by mail upon request to the address listed above.

ITEM 6.  EXHIBITS

Exhibits and Certifications

10.1   Amendment No. 1 to Coal Supply Agreement for Warrick 4 Generating Station between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., effective October 31, 2011.  (Filed and designated in Form 8-K dated November 1, 2011, File No. 1-15467, as Exhibit 10.1.)  Portions of the document have been omitted pursuant to a request for confidential treatment filed separately with the Securities and Exchange Commission.

10.2   Amendment No. 2 to Coal Supply Agreement for F.B. Culley Generating Station between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., effective October 31, 2011.  (Filed and designated in Form 8-K dated November 1, 2011, File No. 1-15467, as Exhibit 10.2.)  Portions of the document have been omitted pursuant to a request for confidential treatment filed separately with the Securities and Exchange Commission.

10.3   Amendment No. 2 to Coal Supply Agreement for A.B. Brown Generating Station between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., effective October 31, 2011.  (Filed and designated in Form 8-K dated November 1, 2011, File No. 1-15467, as Exhibit 10.3.)  Portions of the document have been omitted pursuant to a request for confidential treatment filed separately with the Securities and Exchange Commission.

10.4   Gas Sales and Portfolio Administration Agreement between Indiana Gas Company, Inc. and ProLiance Energy, LLC, effective April 1, 2011.  (Filed and designated in Form 8-K dated November 1, 2011, File No. 1-15467, as Exhibit 10.1.)

10.5   Gas Sales and Portfolio Administration Agreement between Southern Indiana Gas and Electric Company and ProLiance Energy, LLC, effective April 1, 2011.  (Filed and designated in Form 8-K dated November 1, 2011, File No. 1-15467, as Exhibit 10.2.)

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

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

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

101   Interactive Data File.

-47-

101.INS*    XBRL Instance Document

101.SCH*  XBRL Taxonomy Extension Schema

101.CAL*   XBRL Taxonomy Extension Calculation Linkbase

101.DEF*   XBRL Taxonomy Extension Definition Linkbase

101.LAB*   XBRL Taxonomy Extension Labels Linkbase

101.PRE*   XBRL Taxonomy Extension Presentation Linkbase

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

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	VECTREN CORPORATION
	Registrant
November 4, 2011	/s/Jerome A. Benkert, Jr.
	Jerome A. Benkert, Jr.
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)
	/s/M. Susan Hardwick
	M. Susan Hardwick
	Vice President, Controller and Assistant Treasurer
	(Principal Accounting Officer)

-48-

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

CHIEF EXECUTIVE OFFICER CERTIFICATION

I, Carl L. Chapman, certify that:

1.   I have reviewed this Quarterly Report on Form 10-Q of Vectren Corporation;

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

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

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

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

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

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

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

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

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

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

Date: November 4, 2011

/s/ Carl L. Chapman

Carl L. Chapman

Chairman, President, and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

CHIEF FINANCIAL OFFICER CERTIFICATION

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

1.   I have reviewed this Quarterly Report on Form 10-Q of Vectren Corporation;

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

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

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

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

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

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

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

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

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

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

Date: November 4, 2011

/s/ Jerome A. Benkert, Jr.

Jerome A. Benkert, Jr.

Executive Vice President and Chief Financial Officer

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

CERTIFICATION

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

Signed this 4th day of November, 2011.

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

XML

CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited) (Parenthetical) (USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Current Assets
Reserves	$ 6.5	$ 5.3
Common Shareholders' Equity
Common Stock, No Par Value
Common Stock, Shares, Issued	81.8	81.7
Common Stock, Shares, Outstanding	81.8	81.7

XML

CONSOLIDATED CONDENSED STATEMENTS OF INCOME (Unaudited) (USD $) In Millions, except Per Share data	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
OPERATING REVENUES
Gas utility	$ 102.1	$ 101.8	$ 592.8	$ 692.8
Electric utility	186.7	173.2	492.4	469.1
Nonutility	250.6	147.7	612.6	403.5
Total operating revenues	539.4	422.7	1,697.8	1,565.4
OPERATING EXPENSES
Cost of gas sold	30.5	32.4	274.4	371.7
Cost of fuel and purchased power	67.1	64.5	186.9	180.3
Cost of nonutility revenues	93.0	60.7	266.6	170.6
Other operating	180.6	137.2	485.5	398.4
Depreciation and amortization	61.7	57.6	182.0	170.6
Taxes other than income taxes	12.4	11.7	43.4	46.9
Total operating expenses	445.3	364.1	1,438.8	1,338.5
OPERATING INCOME	94.1	58.6	259.0	226.9
OTHER INCOME (EXPENSE)
Equity in (losses) of unconsolidated affiliates	(11.7)	(8.2)	(34.6)	(13.9)
Other income - net	0.7	1.6	5.9	2.0
Total other income (expense)	(11.0)	(6.6)	(28.7)	(11.9)
INTEREST EXPENSE	27.1	26.0	80.7	78.0
INCOME BEFORE INCOME TAXES	56.0	26.0	149.6	137.0
INCOME TAXES	20.7	9.6	54.6	48.7
NET INCOME	$ 35.3	$ 16.4	$ 95.0	$ 88.3
AVERAGE COMMON SHARES OUTSTANDING (in shares)	81.8	81.2	81.7	81.1
DILUTED COMMON SHARES OUTSTANDING (in shares)	81.9	81.4	81.8	81.3
EARNINGS (LOSS) PER SHARE OF COMMON STOCK:
BASIC (in dollars per share)	$ 0.43	$ 0.20	$ 1.16	$ 1.09
DILUTED (in dollars per share)	$ 0.43	$ 0.20	$ 1.16	$ 1.09
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$ 0.345	$ 0.340	$ 1.035	$ 1.020

XML

Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2011

Earnings Per Share [Abstract]

Basic and dilutive EPS

The following table illustrates the basic and dilutive EPS calculations for the periods presented in these financial statements.

	Three Months				Nine Months
	Ended September 30,				Ended September 30,
(In millions, except per share data)	2011		2010		2011		2010
Numerator:
Reported net income (Numerator for Basic and Diluted EPS)	$	35.3	$	16.4	$	95.0	$	88.3
Denominator:
Weighted average common shares outstanding (Basic EPS)		81.8		81.2		81.7		81.1
Conversion of share based compensation arrangements		0.1		0.2		0.1		0.2
Adjusted weighted average shares outstanding and      assumed conversions outstanding (Diluted EPS)		81.9		81.4		81.8		81.3
Basic EPS	$	0.43	$	0.20	$	1.16	$	1.09
Diluted EPS	$	0.43	$	0.20	$	1.16	$	1.09

XML

Document And Entity Information (USD $)	9 Months Ended
	Sep. 30, 2011	Oct. 31, 2011	Jun. 30, 2010
Entity Registrant Name	VECTREN CORP
Entity Central Index Key	0001096385
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	No
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 1,913,186,088
Entity Common Stock, Shares Outstanding		81,851,704
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2011

XML

ProLiance Holdings, LLC (Tables)

9 Months Ended

Sep. 30, 2011

ProLiance Holdings, LLC [Abstract]

Equity Method Investments Disclosure

Summarized Financial Information

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
(In millions)	2011			2010			2011			2010
Summarized statement of income information:
Revenues	$	283.0		$	289.3		$	1,074.8		$	1,095.1
Operating income (loss)	$	(19.4	)	$	(12.8	)	$	(56.7	)	$	(12.2	)
ProLiance's earnings (loss)	$	(19.5	)	$	(12.9	)	$	(57.2	)	$	(12.3	)

	As of
	September 30,			December 31,
(In millions)	2011			2010
Summarized balance sheet information:
Current assets	$	301.3		$	441.4
Noncurrent assets	$	58.2		$	59.1
Current liabilities	$	217.9		$	298.1
Noncurrent liabilities	$	0.4		$	0.4
Members' equity	$	151.6		$	208.9
Accumulated other comprehensive income (loss)	$	(13.6	)	$	(10.8	)
Noncontrolling interest	$	3.2		$	3.9

XML

Retirement Plans and Other Postretirement Benefits

9 Months Ended

Sep. 30, 2011

Retirement Plans and Other Postretirement Benefits [Abstract]

Retirement Plans and Other Postretirement Benefits

7.     Retirement Plans & Other Postretirement Benefits

The Company maintains three qualified defined benefit pension plans, a nonqualified supplemental executive retirement plan (SERP), and three other postretirement benefit plans.  The defined benefit pension and other postretirement benefit plans, which cover eligible full-time regular employees, are primarily noncontributory.  The postretirement health care and life insurance plans are a combination of self-insured and fully insured plans.  The Company has a Voluntary Employee Beneficiary Association (VEBA) Trust Agreement for the partial funding of postretirement health benefits for retirees and their eligible dependents and beneficiaries in one of the three plans.  Annual VEBA funding is discretionary; however, no further funding is anticipated.  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 Costs

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

	Three Months Ended September 30,
	Pension Benefits						Other Benefits
(In millions)	2011			2010			2011			2010
Service cost	$	1.7		$	1.5		$	0.1		$	0.2
Interest cost		3.9			4.0			1.1			1.1
Expected return on plan assets		(5.3	)		(4.6	)		-			-
Amortization of prior service cost		0.5			0.4			(0.2	)		(0.2	)
Amortization of transitional obligation		-			-			0.2			0.3
Amortization of actuarial loss		1.0			0.5			0.2			-
Net periodic benefit cost	$	1.8		$	1.8		$	1.4		$	1.4

	Nine Months Ended September 30,
	Pension Benefits						Other Benefits
(In millions)	2011			2010			2011			2010
Service cost	$	5.2		$	4.7		$	0.4		$	0.4
Interest cost		11.9			11.9			3.2			3.4
Expected return on plan assets		(15.9	)		(13.8	)		-			(0.2	)
Amortization of prior service cost		1.3			1.2			(0.6	)		(0.6	)
Amortization of transitional obligation		-			-			0.8			0.9
Amortization of actuarial loss		2.9			1.5			0.5			0.3
Net periodic benefit cost	$	5.4		$	5.5		$	4.3		$	4.2

Employer Contributions to Qualified Pension Plans

Currently, the Company expects to contribute approximately $35 million to its pension plan trusts for 2011.  During the nine months ended September 30, 2011, contributions of $32.6 million have been made.

XML

Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2011

Fair Value Measurements [Abstract]

Carrying values and estimated fair values of other financial instruments

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

	September 30, 2011				December 31, 2010
(In millions)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	1,719.1	$	1,874.9	$	1,715.9	$	1,841.2
Short-term borrowings		216.4		216.4		118.3		118.3
Cash & cash equivalents		6.4		6.4		10.4		10.4

XML

Commitments and Contingencies (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2011
Commitments and Contingencies [Abstract]
Maximum exposure by parent company on performance contract guarantees	$ 25.0
Maximum exposure by parent company on other projects' guarantees	27.0
Guarantor Obligations, Maximum Exposure, Undiscounted	78.0
Guarantor Obligations Nonregulated retail gas supply operations, Maximum Exposure, Undiscounted	53.0
Guarantor Obligations unconsolidated affiliates, Maximum Exposure, Undiscounted	3.0
Letters of credit, nonutility operations	20.0
Number of surety bonds wholly owned subsidiary has outstanding in role as general contractor (in number of surety bonds)	81
Average face amount of surety bonds wholly owned subsidiary has outstanding	4.0
Maximum face amount of surety bond wholly owned subsidiary has outstanding	$ 30.8
Percentage of work completed on projects covered by open surety bonds	over 50 percent
Timeframe when significant portion of performance guarantee commitments will be fulfilled	within one year
Time period of warranty of functionality of certain installed infrastructure (in years)	one year

XML

Retirement Plans and Other Postretirement Benefits (Tables)

9 Months Ended

Sep. 30, 2011

Retirement Plans and Other Postretirement Benefits [Abstract]

Schedule of defined benefit plans disclosures

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

	Three Months Ended September 30,
	Pension Benefits						Other Benefits
(In millions)	2011			2010			2011			2010
Service cost	$	1.7		$	1.5		$	0.1		$	0.2
Interest cost		3.9			4.0			1.1			1.1
Expected return on plan assets		(5.3	)		(4.6	)		-			-
Amortization of prior service cost		0.5			0.4			(0.2	)		(0.2	)
Amortization of transitional obligation		-			-			0.2			0.3
Amortization of actuarial loss		1.0			0.5			0.2			-
Net periodic benefit cost	$	1.8		$	1.8		$	1.4		$	1.4

	Nine Months Ended September 30,
	Pension Benefits						Other Benefits
(In millions)	2011			2010			2011			2010
Service cost	$	5.2		$	4.7		$	0.4		$	0.4
Interest cost		11.9			11.9			3.2			3.4
Expected return on plan assets		(15.9	)		(13.8	)		-			(0.2	)
Amortization of prior service cost		1.3			1.2			(0.6	)		(0.6	)
Amortization of transitional obligation		-			-			0.8			0.9
Amortization of actuarial loss		2.9			1.5			0.5			0.3
Net periodic benefit cost	$	5.4		$	5.5		$	4.3		$	4.2

XML

Legislative and Environmental Matters

9 Months Ended

Sep. 30, 2011

Legislative Matters And Environmental Loss Contingency Disclosure Abstract

Legislative and Environmental Matters

12.   Legislative & Environmental Matters

Indiana House Bill 1004

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

Indiana Senate Bill 251

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

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

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

Ohio House Bill 95

In June 2011, Ohio House Bill 95 was signed into law.  The law adjusts, among other things, the manner in which gas utilities file for rate changes, including the implementation of base rate changes, alternative rate plans, and automatic rate adjustment mechanisms.  Outside of a base rate proceeding, the legislation permits a natural gas company to apply to implement a capital expenditure program for infrastructure expansion, upgrade, or replacement; installation, upgrade, or replacement of information technology systems; or any program necessary to comply with government regulation.  Once such application is approved, the legislation authorizes recovery or deferral of program costs, such as depreciation, property taxes, and carrying costs.  The Company is assessing the impact this legislation may have on its operations.

Clean Air Act

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

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

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

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

Climate Change

In April 2007, the US Supreme Court determined that greenhouse gases meet the definition of "air pollutant" under the Clean Air Act and ordered the EPA to determine whether greenhouse gas emissions from motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare.  In April 2009, the EPA published its proposed endangerment finding for public comment.  The proposed endangerment finding concludes that carbon emissions from mobile sources pose an endangerment to public health and the environment.  The endangerment finding was finalized in December 2009, and is the first step toward EPA regulating carbon emissions through the existing Clean Air Act in the absence of specific carbon legislation from Congress.  Therefore, any new regulations would likely also impact major stationary sources of greenhouse gases.  The EPA has promulgated two greenhouse gas regulations that apply to SIGECO's generating facilities.  In 2009, the EPA finalized a mandatory greenhouse gas emissions registry which will require reporting of emissions beginning in 2011 (for the emission year 2010).  The EPA has also finalized a revision to the Prevention of Significant Deterioration (PSD) and Title V permitting rules which would require facilities that emit 75,000 tons or more of greenhouse gases a year to obtain a PSD permit for new construction or a significant modification of an existing facility. 

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

Impact of Legislative Actions & Other Initiatives is Unknown

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

Ash Ponds & Coal Ash Disposal Regulations

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

Clean Water Act

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

Potential Pipeline Safety Legislation

The U.S Senate has passed a pipeline safety bill that would increase, beyond levels required by current law, the oversight of natural gas pipelines and lead to an investment in the further inspection, and where necessary, additional modernization of pipeline infrastructure.  The U.S. House of Representatives continues to debate legislation similar to the Senate bill as well as alternatives.  At this time and in the absence of final legislation, compliance costs and other effects associated with increased pipeline safety regulations remain uncertain.  However, any future legislative or regulatory actions taken to address pipeline safety could result in both increased levels of operating expenses and capital expenditures associated with the Company's natural gas distribution businesses.  Compliance costs and capital investments associated with the Company's Indiana gas utilities would likely qualify as federally mandated regulatory requirements recoverable under Senate Bill 251 referenced above.  In Ohio, capital investments would likely qualify for timely recovery under House Bill 95 referenced above.

Environmental Remediation Efforts

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

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

Indiana Gas accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites.  While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, Indiana Gas has recorded cumulative costs that it has incurred or reasonably expects to incur totaling approximately $23.1 million.  The estimated accrued costs are limited to Indiana Gas' share of the remediation efforts.  Indiana Gas has arrangements in place for 19 of the 26 sites with other potentially responsible parties (PRP), which limit Indiana Gas' costs at these 19 sites to between 28 percent and 50 percent.  With respect to insurance coverage, Indiana Gas has received approximately $20.8 million from all known insurance carriers under insurance policies in effect when these plants were in operation.

In October 2002, SIGECO received a formal information request letter from the IDEM regarding five manufactured gas plants that it owned and/or operated and were not enrolled in the IDEM's VRP.  In October 2003, SIGECO filed applications to enter four of the manufactured gas plant sites in IDEM's VRP.  The remaining site is currently being addressed in the VRP by another Indiana utility.  SIGECO added those four sites into the renewal of the global Voluntary Remediation Agreement that Indiana Gas has in place with IDEM for its manufactured gas plant sites.  That renewal was approved by the IDEM in February 2004.  SIGECO was also named in a lawsuit, involving another waste disposal site subject to potential environmental remediation efforts.  With respect to that lawsuit, SIGECO settled with the plaintiff during 2010 mitigating any future claims at this site.  SIGECO has filed a declaratory judgment action against its insurance carriers seeking a judgment finding its carriers liable under the policies for coverage of further investigation and any necessary remediation costs that SIGECO may accrue under the VRP program and/or related to the site subject to the settled lawsuit.  In November the Court ruled on two motions for summary judgment, finding for SIGECO and against certain insurers on indemnification and defense obligations in the policies at issue.

SIGECO has recorded cumulative costs that it has incurred or reasonably expects to incur related to these environmental matters, including the recent settlement discussed above, totaling approximately $17.0 million.  However, the total costs that may be incurred in connection with addressing these sites cannot be determined at this time.  With respect to insurance coverage, SIGECO has recorded approximately $14.2 million of expected insurance recoveries from certain of its insurance carriers under insurance policies in effect when these sites were in operation.  While negotiations are ongoing with certain carriers, settlements have been reached with some carriers and $9.0 million in proceeds have been received.

The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others.  While the Company's utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require some level of additional remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery.  As of September 30, 2011 and December 31, 2010, respectively, approximately $5.4 million and $5.5 million of accrued, but not yet spent, costs are included in Other Liabilities related to both the Indiana Gas and SIGECO sites.

XML

Comprehensive Income

9 Months Ended

Sep. 30, 2011

Comprehensive Income [Abstract]

Comprehensive Income

3.     Comprehensive Income

Comprehensive income consists of the following:

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
(In millions)	2011			2010			2011			2010
Net income	$	35.3		$	16.4		$	95.0		$	88.3
Comprehensive loss of unconsolidated affiliates		(5.2	)		(6.3	)		(1.8	)		(4.4	)
Cash flow hedges
Unrealized gains		0.5			4.1			1.4			4.3
Reclassifications to net income		0.1			-			(3.2	)		-
Income taxes		1.8			0.9			1.4			(0.1	)
Total comprehensive income	$	32.5		$	15.1		$	92.8		$	88.1

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 9 for more information on ProLiance.)

XML

Supplemental Cash Flow Information (Details) (USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Supplemental Cash Flow Information [Abstract]
Accruals related to utility and nonutility plant purchases	$ 12.6	$ 13.9

XML

ProLiance Holdings, LLC

9 Months Ended

Sep. 30, 2011

ProLiance Holdings, LLC [Abstract]

ProLiance Holdings, LLC

9.     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.

Summarized Financial Information

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
(In millions)	2011			2010			2011			2010
Summarized statement of income information:
Revenues	$	283.0		$	289.3		$	1,074.8		$	1,095.1
Operating income (loss)	$	(19.4	)	$	(12.8	)	$	(56.7	)	$	(12.2	)
ProLiance's earnings (loss)	$	(19.5	)	$	(12.9	)	$	(57.2	)	$	(12.3	)

	As of
	September 30,			December 31,
(In millions)	2011			2010
Summarized balance sheet information:
Current assets	$	301.3		$	441.4
Noncurrent assets	$	58.2		$	59.1
Current liabilities	$	217.9		$	298.1
Noncurrent liabilities	$	0.4		$	0.4
Members' equity	$	151.6		$	208.9
Accumulated other comprehensive income (loss)	$	(13.6	)	$	(10.8	)
Noncontrolling interest	$	3.2		$	3.9

Vectren records its 61 percent share of ProLiance's results in Equity in losses of unconsolidated affiliates.  Interest expense and income taxes associated with the investment are recorded separately within the statements of income in those line items.   As of September 30, 2011 and December 31, 2010, the Company's investment balance is $86.6 million and $123.2 million, respectively.    For the three and nine months ended September 30, 2011, the amounts recorded to Equity in losses of unconsolidated affiliates related to ProLiance's operations totaled a pre-tax loss of $11.9 million and $34.9 million, respectively.  For the three and nine months ended September 30, 2010, the amounts recorded to Equity in losses of unconsolidated affiliates related to ProLiance's operations totaled a pretax loss of $8.2 million and $8.0 million, respectively.  Lower natural gas prices, resulting in narrowed summer/winter spreads and locational margins, have negatively impacted ProLiance's results. 

Investment in Liberty Gas Storage

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

In late 2008, the project at the North site was halted due to subsurface and well-completion problems, resulting in Liberty recording a $132 million impairment charge related to the North site in 2009.  ProLiance recorded its share of the charge in 2009 totaling $33 million; the Company recorded its share of the charge in 2009 totaling $11.9 million after tax.  ProLiance's ability to meet the needs of its customers has not been, nor does it expect it to be, impacted.  Approximately 12 Bcf of the storage at the South site, which comprises three of the four FERC certified caverns, is fully completed and tested.  As a result of the issues encountered at the North site, Liberty requested and the FERC approved the separation of the North site from the South site.  As of September 30, 2011 and December 31, 2010, ProLiance's investment in Liberty approximated $36.9 million and $36.7 million, respectively.

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

Transactions with ProLiance

Purchases from ProLiance for resale and for injections into storage for the three months ended September 30, 2011 and 2010 totaled $80.5 million and $78.0 million, respectively, and for the nine months ended September 30, 2011 and 2010, totaled $281.6 and $319.2 million.  Amounts owed to ProLiance at September 30, 2011 and December 31, 2010, for those purchases were $25.4 million and $59.6 million, respectively, and are included in Accounts payable to affiliated companies in the Consolidated Balance Sheets.  Vectren received regulatory approval on April 25, 2006, from the IURC for ProLiance to provide natural gas supply services to the Company's Indiana utilities through March 2011.  On March 17, 2011, an order was received from the IURC providing for ProLiance's continued provision of gas supply services to the Company's Indiana utilities and Citizens Energy Group through March 2016.  Amounts charged by ProLiance for gas supply services are established by supply agreements with each utility.

XML

Fair Value Measurements

9 Months Ended

Sep. 30, 2011

Fair Value Measurements [Abstract]

Fair Value Measurements

14.   Fair Value Measurements

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

	September 30, 2011				December 31, 2010
(In millions)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	1,719.1	$	1,874.9	$	1,715.9	$	1,841.2
Short-term borrowings		216.4		216.4		118.3		118.3
Cash & cash equivalents		6.4		6.4		10.4		10.4

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

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

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

Because of the customized nature of notes receivable investments and lack of a readily available market, it is not practical to estimate the fair value of these financial instruments at specific dates without considerable effort and cost.  At September 30, 2011 and December 31, 2010, the fair value for these financial instruments was not estimated.  The carrying value of notes receivable, inclusive of any accrued interest and net of impairment reserves, was approximately $11.0 million at September 30, 2011 and $10.9 million at December 31, 2010.

The fair value table in Note 18 of the financial statements in the 2010 Form 10-K excluded the estimated fair value of a long-term debt instrument.  The chart above now includes the amount and reflects an increase in the estimated fair value of long-term debt of approximately $73.9 million.  This change in the disclosed fair value of long-term debt had no effect on the carrying value of debt included in the consolidated balance sheet.

XML

Financing Activities

9 Months Ended

Sep. 30, 2011

Financing Activities [Abstract]

Financing Activities

10.   Financing Activities

Utility Holdings Long Term Debt

On October 21, 2011, Utility Holdings priced $100 million of senior unsecured notes at an interest rate of 5.00 percent per annum and with a maturity date of February 3, 2042.  The notes will be sold to various institutional investors pursuant to a private placement note purchase agreement expected to be entered into in November 2011.  These senior notes will be unsecured and will be jointly and severally guaranteed by Utility Holdings' regulated utility subsidiaries, Southern Indiana Gas and Electric Company, Indiana Gas Company, Inc., and Vectren Energy Delivery of Ohio, Inc.  The proceeds received from the issuance of the senior notes will be used to refinance Utility Holdings' $96.2 million 5.95 percent senior notes due 2036, that are expected to be called at par and retired on or about November 21, 2011.  Subject to the satisfaction of customary closing conditions, the new notes will be issued on or about February 1, 2012.

On April 5, 2011, Utility Holdings entered into a private placement note purchase agreement pursuant to which various institutional investors have agreed to purchase the following tranches of notes:  (i) $55 million of 4.67 percent Senior Guaranteed Notes, due November 30, 2021, (ii) $60 million of 5.02 percent Senior Guaranteed Notes, due November 30, 2026, and (iii) $35 million of 5.99 percent Senior Guaranteed Notes, due December 2, 2041.  The proceeds received from the issuance of these senior notes will be used to partially refinance $250 million of Utility Holdings 6.625 percent long-term debt maturing December 1, 2011.  The remainder of the maturing debt will be replaced with short-term borrowings.  These senior notes are unsecured and will be jointly and severally guaranteed by Utility Holdings' regulated utility subsidiaries, Southern Indiana Gas and Electric Company, Indiana Gas Company, Inc., and Vectren Energy Delivery of Ohio, Inc.  Subject to the satisfaction of customary conditions precedent, this financing is scheduled to close on or about November 30, 2011.  The Company has reclassified $150 million of the $250 million debt redemption due in December 2011 to long-term debt in its September 30, 2011 Consolidated Balance Sheet to reflect the Company's ability and intent to refinance that portion of the debt with this issuance.

XML

Acquisition of Minnesota Limited, Inc. (Details) (USD $)	3 Months Ended		9 Months Ended		3 Months Ended	6 Months Ended	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011 Minnesota Limited, Inc. [Member]	Sep. 30, 2011 Minnesota Limited, Inc. [Member]	Sep. 30, 2011 Minnesota Limited, Inc. [Member]	Mar. 31, 2011 Minnesota Limited, Inc. [Member]
Acquisition of Minnesota Limited, Inc. [Abstract]
Acquisition date			March 31, 2011
Purchase price allocation [Abstract]
Working capital assets								$ 21,500,000
Working capital liabilities								(6,700,000)
Net Working Capital								14,800,000
Property, plant and equipment								34,400,000
Identifiable intangible assets								19,100,000
Goodwill								20,300,000
Net assets acquired								88,600,000
Debt obligation assumed								(5,200,000)
Business acquisition, net of cash acquired			83,400,000	0
Number of years goodwill is deductible (which does not amortize pursuant to FASB guidance) for computing current income tax expense (in years)							15
Total transaction costs to date associated with the acquisition					500,000	500,000	500,000
Transaction costs associated with the acquisition during the current period	180,600,000	137,200,000	485,500,000	398,400,000			200,000
Lease Obligation					83,333	83,333	83,333
Number of years the company is obligated to lease acquiree's corporate headquarters					10	10	10
Nonutility	250,600,000	147,700,000	612,600,000	403,500,000	53,200,000	75,200,000
Net income (loss)	35,300,000	16,400,000	95,000,000	88,300,000	5,800,000	6,300,000
Business Acquisition, Pro Forma Revenue		460,600,000	1,718,900,000	1,645,200,000
Business Acquisition, Pro Forma Net Income (Loss)		$ 18,600,000	$ 94,800,000	$ 89,700,000
Business Acquisition, Pro Forma Earnings Per Share, Basic		$ 0.23	$ 1.16	$ 1.11
Business Acquisition, Pro Forma Earnings Per Share, Diluted		$ 0.23	$ 1.16	$ 1.10

XML

Supplemental Cash Flow Information

9 Months Ended

Sep. 30, 2011

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

8.     Supplemental Cash Flow Information

As of September 30, 2011 and December 31, 2010, the Company has accruals related to utility and nonutility plant purchases totaling approximately $12.6 million and $13.9 million, respectively.

XML

Organization and Nature of Operations

9 Months Ended

Sep. 30, 2011

Organization and Nature of Operations [Abstract]

Organization and Nature of Operations

1.     Organization and Nature of Operations

Vectren Corporation (the Company or Vectren), an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana.  The Company's wholly owned subsidiary, Vectren Utility Holdings, Inc. (Utility Holdings), serves as the intermediate holding company for three public utilities:  Indiana Gas Company, Inc. (Indiana Gas or Vectren North), Southern Indiana Gas and Electric Company (SIGECO or Vectren South), and the Ohio operations.  Utility Holdings also has other assets that provide information technology and other services to the three utilities.  Utility Holdings' consolidated operations are collectively referred to as the Utility Group.  Both Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 2005 (Energy Act).  Vectren was incorporated under the laws of Indiana on June 10, 1999.

Indiana Gas provides energy delivery services to approximately 562,000 natural gas customers located in central and southern Indiana.  SIGECO provides energy delivery services to approximately 141,000 electric customers and approximately 110,000 gas customers located near Evansville in southwestern Indiana.  SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market.  Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana.  The Ohio operations provide energy delivery services to over 310,000 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 four primary business areas:  Infrastructure Services, Energy Services, Coal Mining, and Energy Marketing.  Infrastructure Services provides underground construction and repair services.  Energy Services provides performance contracting and renewable energy services.  Coal Mining mines and sells coal.  Energy Marketing markets and supplies natural gas and provides energy management services.  Enterprises also has other legacy businesses that have invested in energy-related opportunities and services, real estate, and leveraged leases, among other investments.  All of the above are collectively referred to as the Nonutility Group.  Enterprises supports the Company's regulated utilities pursuant to service contracts by providing natural gas supply services, coal, and infrastructure services.

XML

Earnings Per Share

9 Months Ended

Sep. 30, 2011

Earnings Per Share [Abstract]

Earnings Per Share

4.     Earnings Per Share

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

	Three Months				Nine Months
	Ended September 30,				Ended September 30,
(In millions, except per share data)	2011		2010		2011		2010
Numerator:
Reported net income (Numerator for Basic and Diluted EPS)	$	35.3	$	16.4	$	95.0	$	88.3
Denominator:
Weighted average common shares outstanding (Basic EPS)		81.8		81.2		81.7		81.1
Conversion of share based compensation arrangements		0.1		0.2		0.1		0.2
Adjusted weighted average shares outstanding and      assumed conversions outstanding (Diluted EPS)		81.9		81.4		81.8		81.3
Basic EPS	$	0.43	$	0.20	$	1.16	$	1.09
Diluted EPS	$	0.43	$	0.20	$	1.16	$	1.09

For the three and nine months ended September 30, 2011, options to purchase 1,920 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, compared to 308,000 and 517,800 shares for the three and nine months ended September 30, 2010, respectively.  The exercise prices for these options were $27.15 for the three and nine months ended September 30, 2011.  The exercise prices for these options ranged from $24.90 to $27.15 for the three months ended September 30, 2010 and $24.74 to $27.15 for the nine months ended September 30, 2010.

XML

Rate and Regulatory Matters (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2011	May 03, 2011	Jul. 30, 2010
Rate and Regulatory Matters [Abstract]
Amount of revised rate increase filed in rebuttal to original rate increase to IURC			$ 34.0
Authorized increase in revenue from utility service		28.6
Amount of infrastructure construction in the three years leading up to December 2009 rate filing	325.0
Rate of return included in rate increase (in hundredths)		7.29%
Dollar amount of the rate base included in rate increase		1,295.6
Amount of rate of return on equity included in rate base (in hundredths)		10.40%
Percentage of residential and commercial base rate covered by customer service charge (in hundredths)	90.00%
Length of contract for customers who purchase natural gas through state certified natural gas suppliers (in months)	12 month
Number of years in initial demand side management program approved by the IURC (in years)	3 Y
Maximum deferral of lost margin associated with small customer demand side programs	1.0
Number of auctions requirement related to the plan approved by the PUCO (in number of auctions)	2
Number of tranches of customers secured in first auction	1
Number of tranches of customers secured in second auction	2
Approximate number of customers in a tranche (in number of customers)	28,000
Vectren South Electric Dense Pack Filing [Abstract]
Expected capital investment to improve the efficiency of generating station	32.0
Number of years in capital improvement program (in years)	2 Y
Amount of expected capital investment invested to date	$ 17.0
Expected increase in efficiency for generating station following improvement (in hundredths)	5.00%

XML

Earnings Per Share (Details) (USD $) In Millions, except Share data	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Numerator [Abstract]
Numerator for basic EPS	$ 35.3	$ 16.4	$ 95.0	$ 88.3
Net income (loss)	$ 35.3	$ 16.4	$ 95.0	$ 88.3
Denominator [Abstract]
Weighted average common shares outstanding (Basic EPS) (in shares)	81,800,000	81,200,000	81,700,000	81,100,000
Conversion of share based compensation arrangements (in shares)	100,000	200,000	100,000	200,000
Adjusted weighted average shares outstanding and assumed conversions outstanding (Diluted EPS) (in shares)	81,900,000	81,400,000	81,800,000	81,300,000
Basic EPS (in dollars per share)	$ 0.43	$ 0.20	$ 1.16	$ 1.09
Diluted EPS (in dollars per share)	$ 0.43	$ 0.20	$ 1.16	$ 1.09
Antidilutive securities excluded from computation of earnings per share, amount (in shares)	1,920	308,000	1,920	517,800
Antidilutive securities excluded from computation of earnings per share, option minimum exercise price (in dollars per share)	$ 27.15	$ 24.90	$ 27.15	$ 24.74
Antidilutive securities excluded from computation of earnings per share, option maximum exercise price (in dollars per share)	$ 27.15	$ 27.15	$ 27.15	$ 27.15

XML

Acquisition of Minnesota Limited, Inc.

9 Months Ended

Sep. 30, 2011

Acquisition of Minnesota Limited, Inc. [Abstract]

Acquisition of Minnesota Limited, Inc.

5.     Acquisition of Minnesota Limited, Inc.

On March 31, 2011, the Company, through its wholly owned subsidiary Vectren Infrastructure Services Company, Inc., purchased Minnesota Limited, Inc., excluding certain assets.  Minnesota Limited is a specialty contractor focusing on transmission pipeline construction and maintenance; pump station, compressor station, terminal and refinery construction; gas distribution; and hydrostatic testing.  Minnesota Limited is headquartered in Big Lake, Minnesota and the majority of its customers are generally located in the northern Midwest region.

Along with the Company's wholly owned subsidiary, Miller Pipeline LLC, Minnesota Limited is included in the Company's nonutility Infrastructure Services operating segment.  This acquisition positions the Company for anticipated growth in demand for gas transmission construction resulting from the need to transport new sources of natural gas and oil found in shale formations and the need to upgrade the nation's aging pipelines.

The Company accounted for the cash acquisition in accordance with FASB authoritative guidance for business combinations, which requires the Company to recognize the assets acquired and the liabilities assumed, measured at their fair values as of the date of acquisition.  The following table summarizes the allocation of the purchase price to the fair value of the assets acquired and liabilities assumed.

(In millions)
Working capital assets	$	21.5
Working capital liabilities		(6.7	)
Net working capital		14.8
Property, plant & equipment		34.4
Identifiable intangible assets		19.1
Goodwill		20.3
Net assets acquired		88.6
Debt obligation assumed		(5.2	)
Cash paid in acquisition, net of cash acquired	$	83.4

As of November 4, 2011, the purchase price and its allocation remain preliminary and could change in subsequent periods.  Any subsequent material changes to the purchase price and its allocation will be adjusted pursuant to FASB guidance. Since the initial purchase price allocation was disclosed only minor adjustments have been made.  The final purchase price and the allocation are dependent on final reconciliations of working capital and other items.

Level 3 market inputs, such as discounted cash flows, revenue growth rates, royalty rates, and dealer and auction values of used equipment, were used to derive the preliminary fair values of the identifiable intangible assets and property plant and equipment.  Identifiable intangible assets include back log, long-term customer relationships, and trade name.  The Company intends to use the acquired assets for an extended period and is amortizing them on a straight-line basis over their estimated useful lives.  Goodwill arising from the purchase represents intangible value the Company expects to realize over time.  This value includes but is not limited to: 1) expected synergies from more efficient utilization of equipment and human resources within the combined entities; 2) the experience and size of the acquired work force; and 3) the reputation of the current Minnesota Limited management team.  The goodwill, which does not amortize pursuant to FASB guidance, is deductible over a 15 year period for purposes of computing current income tax expense.

Transaction costs associated with the acquisition and expensed by the Company totaled approximately $0.5 million, of which $0.2 million are included in other operating expenses during the nine months ended September 30, 2011 and the remainder was expensed in 2010.  For the period from April 1, 2011 through September 30, 2011, Minnesota Limited contributed approximately $75.2 million and $6.3 million to the Company's revenue and net income, respectively.  During the three months ended September 30, 2011, Minnesota Limited contributed approximately $53.2 million and $5.8 million to the Company's revenue and net income, respectively.

The following table presents the Company's unaudited proforma results of operations for the three months ended September 30, 2010 and nine months ended September 30, 2011 and 2010 as if the acquisition had occurred on January 1, 2010.

	Three Months		Nine Months
	Ended September 30,		Ended September 30,
(In millions, except per share data)	2010		2011		2010
Total operating revenues	$	460.6	$	1,718.9	$	1,645.2
Net income	$	18.6	$	94.8	$	89.7
Basic earnings per share	$	0.23	$	1.16	$	1.11
Diluted earnings per share	$	0.23	$	1.16	$	1.10

In addition to the incremental revenues and expenses recorded by Minnesota Limited during this period, the proforma financial data for all periods presented contain several adjustments including the following: recording the additional amortization expense from the identifiable intangible assets; adjusting the estimated tax provision of the proforma combined results; and adjusting for the issuance of short-term debt to facilitate the acquisition.  The Company prepared the proforma financial information for the combined entities for comparative purposes only, and it may not be indicative of what actual results would have been if the acquisition had taken place on the proforma date, or of future results.

Concurrent with the purchase agreement, the Company executed a lease arrangement at fair value for the Minnesota Limited corporate headquarters, which is owned by a member of the Minnesota Limited management team and certain family members.  The lease obligates the Company to pay approximately $83,333 per month for 10 years along with certain executory costs for taxes and other operating expenses.  Pursuant to FASB guidance, the Company accounts for the obligation as an operating lease, expensing the lease payments and executory costs as incurred.

XML

Segment Reporting (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Segment Reporting [Abstract]
Number of groups (in number of groups)	3		3
Portion of Indiana that is provided natural gas distribution and transportation services by the Gas Utility Services segment (in hundredths)	67.00%		67.00%
Segment Reporting Information [Line Items]
Revenues	$ 539.4	$ 422.7	$ 1,697.8	$ 1,565.4
Profitability Measure - Net Income (Loss)	35.3	16.4	95.0	88.3
Utility Group [Member]
Segment Reporting Information [Line Items]
Revenues	289.3	275.4	1,086.7	1,163.1
Profitability Measure - Net Income (Loss)	27.9	18.7	92.8	90.3
Utility Group [Member] | Gas Utility Services [Member]
Segment Reporting Information [Line Items]
Revenues	102.1	101.8	592.8	692.8
Profitability Measure - Net Income (Loss)	(4.8)	(6.3)	33.5	32.0
Utility Group [Member] | Electric Utility Services [Member]
Segment Reporting Information [Line Items]
Revenues	186.7	173.2	492.4	469.1
Profitability Measure - Net Income (Loss)	30.8	23.1	53.1	51.4
Utility Group [Member] | Other Operations [Member]
Segment Reporting Information [Line Items]
Revenues	11.0	11.1	32.9	33.3
Profitability Measure - Net Income (Loss)	1.9	1.9	6.2	6.9
Utility Group [Member] | Group Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	(10.5)	(10.7)	(31.4)	(32.1)
Nonutility Group [Member]
Segment Reporting Information [Line Items]
Revenues	291.6	181.9	731.5	534.7
Profitability Measure - Net Income (Loss)	7.6	(2.2)	3.4	(1.9)
Nonutility Group [Member] | Infastructure Services [Member]
Segment Reporting Information [Line Items]
Revenues	151.6	69.9	293.4	171.1
Profitability Measure - Net Income (Loss)	11.9	3.2	11.1	2.2
Nonutility Group [Member] | Energy Services [Member]
Segment Reporting Information [Line Items]
Revenues	48.5	46.7	111.5	107.7
Profitability Measure - Net Income (Loss)	2.3	2.8	1.6	4.2
Nonutility Group [Member] | Coal Mining [Member]
Segment Reporting Information [Line Items]
Revenues	81.0	57.5	221.2	159.7
Profitability Measure - Net Income (Loss)	5.8	2.5	15.9	8.1
Nonutility Group [Member] | Energy Marketing [Member]
Segment Reporting Information [Line Items]
Revenues	10.5	7.8	105.4	96.2
Profitability Measure - Net Income (Loss)	(12.2)	(10.4)	(24.3)	(9.1)
Nonutility Group [Member] | Other Businesses [Member]
Segment Reporting Information [Line Items]
Profitability Measure - Net Income (Loss)	(0.2)	(0.3)	(0.9)	(7.3)
Corporate and Other Group [Member]
Segment Reporting Information [Line Items]
Profitability Measure - Net Income (Loss)	(0.2)	(0.1)	(1.2)	(0.1)
Corporate Elimination [Member]
Segment Reporting Information [Line Items]
Revenues	$ (41.5)	$ (34.6)	$ (120.4)	$ (132.4)

XML

Segment Reporting (Tables)

9 Months Ended

Sep. 30, 2011

Segment Reporting [Abstract]

Schedule of segment reporting information by segment

Information related to the Company's business segments is summarized as follows:

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
(In millions)	2011			2010			2011			2010
Revenues
Utility Group
Gas Utility Services	$	102.1		$	101.8		$	592.8		$	692.8
Electric Utility Services		186.7			173.2			492.4			469.1
Other Operations		11.0			11.1			32.9			33.3
Eliminations		(10.5	)		(10.7	)		(31.4	)		(32.1	)
Total Utility Group		289.3			275.4			1,086.7			1,163.1
Nonutility Group
Infrastructure Services		151.6			69.9			293.4			171.1
Energy Services		48.5			46.7			111.5			107.7
Coal Mining		81.0			57.5			221.2			159.7
Energy Marketing		10.5			7.8			105.4			96.2
Total Nonutility Group		291.6			181.9			731.5			534.7
Eliminations		(41.5	)		(34.6	)		(120.4	)		(132.4	)
Consolidated Revenues	$	539.4		$	422.7		$	1,697.8		$	1,565.4
Profitability Measure - Net Income (Loss)
Utility Group
Gas Utility Services	$	(4.8	)	$	(6.3	)	$	33.5		$	32.0
Electric Utility Services		30.8			23.1			53.1			51.4
Other Operations		1.9			1.9			6.2			6.9
Utility Group Net Income		27.9			18.7			92.8			90.3
Nonutility Group Net Income (Loss)
Infrastructure Services		11.9			3.2			11.1			2.2
Energy Services		2.3			2.8			1.6			4.2
Coal Mining		5.8			2.5			15.9			8.1
Energy Marketing		(12.2	)		(10.4	)		(24.3	)		(9.1	)
Other Businesses		(0.2	)		(0.3	)		(0.9	)		(7.3	)
Nonutility Group Net Income (Loss)		7.6			(2.2	)		3.4			(1.9	)
Corporate & Other Group Net Income (Loss)		(0.2	)		(0.1	)		(1.2	)		(0.1	)
Consolidated Net Income	$	35.3		$	16.4		$	95.0		$	88.3

XML

Excise and Utility Receipts Taxes (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Excise and Utility Receipts Taxes [Abstract]
Excise and utility taxes collected and reported in operating revenue	$ 5.0	$ 4.8	$ 21.6	$ 25.2

XML

Fair Value Measurements (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2011	Dec. 31, 2010
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Recovery period for call premiums on reacquisition of utility long-term debt (in years)	15
Carrying value of notes receivable, inclusive of any accrued interest and net of impairment reserves	$ 11.0	$ 10.9
Error corrections and prior period adjustment, description	The fair value table in Note 18 of the financial statements in the 2010 Form 10-K excluded the estimated fair value of a long-term debt instrument. The chart above now includes the amount and reflects an increase in the estimated fair value of long-term debt of approximately $73.9 million. This change in the disclosed fair value of long-term debt had no effect on the carrying value of debt included in the consolidated balance sheet.
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	1,719.1	1,715.9
Short-term Borrowings	216.4	118.3
Cash and cash equivalents	6.4	10.4
Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	1,874.9	1,841.2
Short-term Borrowings	216.4	118.3
Cash and cash equivalents	$ 6.4	$ 10.4

XML

Comprehensive Income (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Comprehensive Income [Abstract]
Net income	$ 35.3	$ 16.4	$ 95.0	$ 88.3
Comprehensive income of unconsolidated affiliates	(5.2)	(6.3)	(1.8)	(4.4)
Cash flow hedges [Abstract]
Unrealized gains (losses)	0.5	4.1	1.4	4.3
Reclassifications to net income	0.1	0	(3.2)	0
Income taxes	1.8	0.9	1.4	(0.1)
Total comprehensive income	$ 32.5	$ 15.1	$ 92.8	$ 88.1

XML

Rate and Regulatory Matters

9 Months Ended

Sep. 30, 2011

Rate and Regulatory Matters [Abstract]

Rate and Regulatory Matters

13.   Rate & Regulatory Matters

Vectren South Electric Base Rate Filing

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

Coal Procurement Procedures

Vectren South submitted a request for proposal in April 2011 regarding coal purchases for a four year period beginning in 2012.  After negotiations with bidders, Vectren South has reached an agreement in principle for multi-year purchases with two suppliers, one of which is Vectren Fuels, Inc.  Consistent with the IURC direction in the electric rate case, a sub docket proceeding has been established to review the Company's prospective coal procurement procedures, and the Company submitted evidence related to its recent request for proposal (RFP) and those coal procurement procedures to the IURC in September 2011.  In October 2011, the OUCC filed its testimony which, while suggesting enhancements to the process to be considered, does not challenge the results of the RFP and the resulting new contracts.  A hearing in this proceeding is scheduled for December 2011.

Vectren South Electric Demand Side Management Program Filing

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

On August 31, 2011 the IURC issued an order approving an initial three year DSM plan in the Vectren South service territory that complies with the IURC's energy saving targets.  Consistent with the Company's proposal, the order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; 3) lost margin recovery associated with the implementation of DSM programs for large customers; and 4) deferral of lost margin up to $1 million in 2011 associated with small customer DSM programs for subsequent recovery under a tracking mechanism to be proposed by the Company.  This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the order received April 27, 2011.  The Company is in the initial phases of implementing electric conservation initiatives.

Vectren South Electric Dense Pack Filing

On September 14, 2011, Vectren South filed a petition with the IURC seeking recovery of and return on the capital investment in dense pack technology to improve the efficiency of its A.B. Brown Generating Station.  This investment is expected to be approximately $32 million over the next two years, of which approximately $17 million has been invested to date.  This technology is expected to allow the A.B. Brown units to run at least 5 percent more efficient, thereby burning less fuel, and reducing fuel costs and emissions of pollutants.  Indiana statute provides for timely recovery of these investments, with a return, in instances where the investment increases the efficiency of existing generating plants that are fueled by coal.  The IURC will conduct a hearing in early 2012.

Vectren North & Vectren South Gas Decoupling Extension Filing

On April 14, 2011, the Company's Indiana based gas companies (Vectren North and Vectren South) filed with the IURC a joint settlement agreement with the OUCC on an extension of the offering of conservation programs and the supporting gas decoupling mechanism originally approved in December 2006.  On August 18, 2011, the IURC issued an order approving the settlement as filed, granting the extension of the current decoupling mechanism in place at both gas companies and recovery of new conservation program costs through December 2015.

VEDO Gas Rate Design

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

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

VEDO Continues the Process to Exit the Merchant Function

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

The second phase of the exit process began on April 1, 2010.  During this phase, the Company no longer sells natural gas directly to customers.  Rather, state-certified Competitive Retail Natural Gas Suppliers, that were successful bidders in a similar regulatory-approved auction, sell the gas commodity to specific customers for a 12 month period at auction-determined standard pricing.  The first auction was conducted on January 12, 2010, and the auction results were approved by the PUCO on January 13, 2010.  The plan approved by the PUCO required that the Company conduct at least two annual auctions during this phase.  As such, the Company conducted another auction on January 18, 2011 in advance of the second 12-month term which commenced on April 1, 2011.  The results of that auction were approved by the PUCO on January 19, 2011.Vectren Source, the Company's wholly owned nonutility retail gas marketer, was a successful bidder in both auctions winning one tranche of customers in the first auction and two tranches of customers in the second auction.  Each tranche of customers equates to approximately 28,000 customers.  Consistent with current practice, customers will continue to receive a single bill for the commodity as well as the delivery component of natural gas service from VEDO.

The PUCO provided for an Exit Transition Cost rider, which allows the Company to recover costs associated with the transition process.  Exiting the merchant function has not had a material impact on earnings or financial condition.  It, however, has and will continue to reduce Gas utility revenues and have an equal and offsetting impact to Cost of gas sold and revenue related taxes recorded in Taxes other than income taxes as VEDO no longer purchases gas for resale to these customers.

XML

Excise and Utility Receipts Taxes

9 Months Ended

Sep. 30, 2011

Excise and Utility Receipts Taxes [Abstract]

Excise and Utility Receipts Taxes

6.     Excise and Utility Receipts Taxes

Excise taxes and a portion of utility receipts taxes are included in rates charged to customers.  Accordingly, the Company records these taxes received as a component of operating revenues, which totaled $5.0 million and $4.8 million in the three months ended September 30, 2011 and 2010, respectively.  During the nine months ended September 30, 2011 and 2010, these taxes totaled $21.6 million and $25.2 million, respectively.  Expenses associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.

XML

Segment Reporting

9 Months Ended

Sep. 30, 2011

Segment Reporting [Abstract]

Segment Reporting

16.   Segment Reporting

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

The Utility Group is comprised of Vectren Utility Holdings, Inc.'s operations, which consist of the Company's regulated operations and other operations that provide information technology and other support services to those regulated operations.  The Company segregates its regulated operations between a Gas Utility Services operating segment and an Electric Utility Services operating segment.  The Gas Utility Services segment provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio.  The Electric Utility Services segment provides electric distribution services primarily to southwestern Indiana, and includes the Company's power generating and wholesale power operations.  Regulated operations supply natural gas and/or electricity to over one million customers.  In total, the Utility Group is comprised of three operating segments:  Gas Utility Services, Electric Utility Services, and Other operations.

Consistent with a reporting structure implemented during 2010, the Nonutility Group is comprised of five operating segments.  Prior segment disclosures reported the Nonutility Group as a single operating segment, and for comparison purposes those prior periods are conformed to the current year presentation.  The operating segments of the Nonutility Group are Infrastructure Services, Energy Services, Coal Mining, Energy Marketing, and Other Businesses.

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.  The acquisition of Minnesota Limited was completed on March 31, 2011 (See Note 5) and is included in the Infrastructure Services nonutility operating segment.  Information related to the Company's business segments is summarized as follows:

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
(In millions)	2011			2010			2011			2010
Revenues
Utility Group
Gas Utility Services	$	102.1		$	101.8		$	592.8		$	692.8
Electric Utility Services		186.7			173.2			492.4			469.1
Other Operations		11.0			11.1			32.9			33.3
Eliminations		(10.5	)		(10.7	)		(31.4	)		(32.1	)
Total Utility Group		289.3			275.4			1,086.7			1,163.1
Nonutility Group
Infrastructure Services		151.6			69.9			293.4			171.1
Energy Services		48.5			46.7			111.5			107.7
Coal Mining		81.0			57.5			221.2			159.7
Energy Marketing		10.5			7.8			105.4			96.2
Total Nonutility Group		291.6			181.9			731.5			534.7
Eliminations		(41.5	)		(34.6	)		(120.4	)		(132.4	)
Consolidated Revenues	$	539.4		$	422.7		$	1,697.8		$	1,565.4
Profitability Measure - Net Income (Loss)
Utility Group
Gas Utility Services	$	(4.8	)	$	(6.3	)	$	33.5		$	32.0
Electric Utility Services		30.8			23.1			53.1			51.4
Other Operations		1.9			1.9			6.2			6.9
Utility Group Net Income		27.9			18.7			92.8			90.3
Nonutility Group Net Income (Loss)
Infrastructure Services		11.9			3.2			11.1			2.2
Energy Services		2.3			2.8			1.6			4.2
Coal Mining		5.8			2.5			15.9			8.1
Energy Marketing		(12.2	)		(10.4	)		(24.3	)		(9.1	)
Other Businesses		(0.2	)		(0.3	)		(0.9	)		(7.3	)
Nonutility Group Net Income (Loss)		7.6			(2.2	)		3.4			(1.9	)
Corporate & Other Group Net Income (Loss)		(0.2	)		(0.1	)		(1.2	)		(0.1	)
Consolidated Net Income	$	35.3		$	16.4		$	95.0		$	88.3

XML

Legislative and Environmental Matters (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2011	Dec. 31, 2010
Environmental Remediation [Line Items]
Description Of Legislation In Indiana House Bill 1004	This legislation phases in over four years a two percent rate reduction to the Indiana Adjusted Gross Income Tax for corporations. Pursuant to House Bill 1004, the tax rate will be lowered by one-half percent each year beginning on July 1, 2012, to the final rate of six and one-half percent effective July 1, 2015.
Indiana Senate Bill 251 [Abstract]
Description of legislation	The legislation establishes a voluntary clean energy portfolio standard that provides incentives to electricity suppliers participating in the program.
Description of the goal of legislation	The law applies to both gas and electric utility operations and provides a framework to recover 80 percent of federally mandated costs through a periodic rate adjustment mechanism outside of a general rate case. The remaining 20 percent of those costs are to be deferred for recovery in the utility's next general rate case. The legislation establishes a voluntary clean energy portfolio standard that provides incentives to electricity suppliers participating in the program. The goal of the program is that by 2025, at least 10 percent of the total electricity obtained by the supplier to meet the energy needs of its Indiana retail customers will be provided by clean energy sources, as defined.
Environmental Remediation Efforts [Abstract]
Remediation cost accrued and not yet spent at end of period	$ 5.4	$ 5.5
Indiana Gas [Member]
Environmental Remediation Efforts [Abstract]
Number of sites identified with potential remedial responsibility for entity (in number of sites)	26
Number of sites identified with some remedial responsibility and has made arrangement along with other potentially responsible parties to cleanup (in number of sites)	19
Minimum percentage of responsibility for remediation cost for certain sites identified (in hundredths)	28.00%
Maximum percentage of responsibility for remediation cost for certain sites identified (in hundredths)	50.00%
Site Contingency Cumulative Costs Amount	23.1
Environmental cost recognized, recovery from insurance carriers credited to expense	20.8
SIGECO [Member]
Indiana Senate Bill 251 [Abstract]
Power generating capacity for acquired landfill gas generation facility (in megawatts)	3
Long-term Contract for Purchase of Electric Power generated by wind energy (in megawatts)	50
Purchased Electric Power generated by wind energy (in megawatts)	30
Percentage of total electricity obtained by the supplier to meet the energy needs of its retail customers provided by clean energy sources (in hundredths)	5.00%
Clean Air Act [Abstract]
SIGECO investment in Property, Plant and Equipment, Pollution control equipment	411.0
Property, Plant and Equipment, Amount of investment in pollution control equipment included in rate base	411.0
Percent of coal fired generating fleet currently being scrubbed for SO2 (in hundredths)	100.00%
Percent of coal fired generating fleet currently controlled for Nox (in hundredths)	90.00%
Percentage reduction in SO2 per Cross-State Air Pollution Rule (in hundredths)	71.00%
Percentage reduction in NOx per Cross-State Air Pollution Rule (in hundredths)	52.00%
Climate Changes [Abstract]
Maximum level of greenhouse gas emission that prompts requirement to obtain permit for facilities to construct new facility of significant modification to existing facility (in tons)	75,000
Ash Ponds and Coal Ash Disposal Regulations [Abstract]
Estimated capital expenditures to comply with ash pond and coal ash disposal regulations	30.0
Potential estimated capital expenditures to comply with ash pond and coal ash disposal regulations with most stringent alternative	100.0
Estimated annual compliance costs maximum with ash pond and coal ash disposal regulation	5.0
Clean Water Act [Abstract]
Estimated capital expenditures related to Clean Water Act	40.0
Environmental Remediation Efforts [Abstract]
Number of sites identified with potential remedial responsibility for entity (in number of sites)	5
Number of sites identified with some remedial responsibility and has made arrangement along with other potentially responsible parties to cleanup (in number of sites)	4
Site Contingency Cumulative Costs Amount	17.0
Environmental cost recognized, recovery from insurance carriers credited to expense	14.2
Site contingency recovery from third party of environmental remediation cost	$ 9.0

XML

Organization and Nature of Operations (Details)	9 Months Ended
	Sep. 30, 2011
Organization and Nature of Operations [Abstract]
Number of public utility subsidiaries owned by wholly owned subsidiary, Vectren Utility Holdings, Inc. (in number of subsidiaries)	3
Estimated number of natural gas customers located in central and southern Indiana serviced by Indiana Gas Company, Inc. (in number of customers)	562,000
Estimated number of electric customers located near Evansville in southwestern Indiana serviced by Southern Indiana Gas and Electric Company (in number of customers)	141,000
Estimated number of natural gas customers located near Evansville in southwestern Indiana serviced by Southern Indiana Gas and Electric Company (in number of customers)	110,000
Estimated number of natural gas customers located near Dayton in west central Ohio serviced by the Ohio operations (in number of customers)	310,000
Majority ownership percentage of Ohio operations owned as a tenancy in common by Vectren Energy Delivery of Ohio, Inc., a wholly owned subsidiary of Vectren Utility Holdings, Inc. (in hundredths)	53.00%
Minority ownership percentage of Ohio operations owned as a tenancy in common by Indiana Gas, a subsidiary of Vectren Utility Holdings, Inc. (in hundredths)	47.00%

XML

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (Unaudited) (USD $) In Millions	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ 95.0	$ 88.3
Adjustments to reconcile net income to cash from operating activities:
Depreciation and amortization	182.0	170.6
Deferred income taxes and investment tax credits	56.5	33.9
Equity in losses of unconsolidated affiliates	34.6	13.9
Provision for uncollectible accounts	9.1	13.2
Expense portion of pension and postretirement benefit cost	6.8	6.7
Other non-cash charges - net	9.5	19.4
Changes in working capital accounts:
Accounts receivable and accrued unbilled revenues	68.6	106.7
Inventories	(20.2)	(20.5)
Recoverable/refundable fuel and natural gas costs	(8.1)	(34.8)
Prepayments and other current assets	(1.0)	(16.4)
Accounts payable, including to affiliated companies	(83.8)	(82.9)
Accrued liabilities	(3.4)	15.7
Unconsolidated affiliate dividends	0.1	42.7
Employer contributions to pension and postretirement plans	(37.2)	(12.4)
Changes in noncurrent assets	(8.4)	(9.8)
Changes in noncurrent liabilities	(8.6)	(11.9)
Net cash flows from operating activities	291.5	322.4
Proceeds from:
Dividend reinvestment plan and other common stock issuances	5.2	7.2
Requirements for:
Dividends on common stock	(84.6)	(82.7)
Retirement of long-term debt	(2.2)	(2.1)
Other Financing Activities	(1.4)	0
Net change in short-term borrowings	98.1	(56.2)
Net cash flows from financing activities	15.1	(133.8)
CASH FLOWS FROM INVESTING ACTIVITIES
Unconsolidated affiliate distributions	0.5	0.5
Other collections	1.0	10.2
Requirements for:
Capital expenditures, excluding AFUDC equity	(227.8)	(200.9)
Business acquisition, net of cash acquired	(83.4)	0
Other investments	(0.9)	(3.1)
Net cash flows from investing activities	(310.6)	(193.3)
Net change in cash and cash equivalents	(4.0)	(4.7)
Cash and cash equivalents at beginning of period	10.4	11.9
Cash and cash equivalents at end of period	$ 6.4	$ 7.2

XML

Comprehensive Income (Tables)

9 Months Ended

Sep. 30, 2011

Comprehensive Income [Abstract]

Components of comprehensive income

Comprehensive income consists of the following:

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
(In millions)	2011			2010			2011			2010
Net income	$	35.3		$	16.4		$	95.0		$	88.3
Comprehensive loss of unconsolidated affiliates		(5.2	)		(6.3	)		(1.8	)		(4.4	)
Cash flow hedges
Unrealized gains		0.5			4.1			1.4			4.3
Reclassifications to net income		0.1			-			(3.2	)		-
Income taxes		1.8			0.9			1.4			(0.1	)
Total comprehensive income	$	32.5		$	15.1		$	92.8		$	88.1

XML

Acquisition of Minnesota Limited, Inc. (Tables)

9 Months Ended

Sep. 30, 2011

Acquisition of Minnesota Limited, Inc. [Abstract]

Schedule of business acquisitions, by acquisition

The following table summarizes the allocation of the purchase price to the fair value of the assets acquired and liabilities assumed.

(In millions)
Working capital assets	$	21.5
Working capital liabilities		(6.7	)
Net working capital		14.8
Property, plant & equipment		34.4
Identifiable intangible assets		19.1
Goodwill		20.3
Net assets acquired		88.6
Debt obligation assumed		(5.2	)
Cash paid in acquisition, net of cash acquired	$	83.4

Business Acquisition, Pro Forma Information [Table Text Block]

The following table presents the Company's unaudited proforma results of operations for the three months ended September 30, 2010 and nine months ended September 30, 2011 and 2010 as if the acquisition had occurred on January 1, 2010.

	Three Months		Nine Months
	Ended September 30,		Ended September 30,
(In millions, except per share data)	2010		2011		2010
Total operating revenues	$	460.6	$	1,718.9	$	1,645.2
Net income	$	18.6	$	94.8	$	89.7
Basic earnings per share	$	0.23	$	1.16	$	1.11
Diluted earnings per share	$	0.23	$	1.16	$	1.10

XML

Basis of Presentation

9 Months Ended

Sep. 30, 2011

Basis of Presentation [Abstract]

Basis of Presentation

2.     Basis of Presentation

The interim consolidated condensed financial statements included in this report have been prepared by the Company, without audit, as provided in the rules and regulations of the Securities and Exchange Commission and include a review of subsequent events through the date the financial statements were issued.  Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been omitted as provided in such rules and regulations.  The information in this report reflects all adjustments which are, in the opinion of management, necessary to fairly state the interim periods presented, inclusive of adjustments that are normal and recurring in nature.  These consolidated condensed financial statements and related notes should be read in conjunction with the Company's audited annual consolidated financial statements for the year ended December 31, 2010, filed with the Securities and Exchange Commission on February 17, 2011, on Form 10-K.  Because of the seasonal nature of the Company's operations, the results shown on a quarterly basis are not necessarily indicative of annual results.

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

XML

Commitments and Contingencies

9 Months Ended

Sep. 30, 2011

Commitments and Contingencies [Abstract]

Commitments and Contingencies

11.   Commitments & Contingencies

Corporate Guarantees

The Company issues parent level guarantees to certain vendors and customers of its wholly owned subsidiaries and unconsolidated affiliates.  These guarantees do not represent incremental consolidated obligations; rather, they represent parental guarantees of subsidiary and unconsolidated affiliate obligations in order to allow those subsidiaries and affiliates the flexibility to conduct business without posting other forms of collateral.  At September 30, 2011, parent level guarantees support a maximum of $25 million of ESG's performance contracting commitments and warranty obligations and $27 million of other project guarantees.  The broader scope of ESG's performance contracting obligations, including those not guaranteed by the parent company, are described below.  In addition, the parent company has approximately $78 million of other guarantees outstanding supporting other consolidated subsidiary operations, of which $53 million support the operations of Vectren Source, a wholly owned non-regulated retail gas marketer and $20 million represent letters of credit supporting other nonutility operations.  Guarantees issued and outstanding on behalf of unconsolidated affiliates approximated $3 million at September 30, 2011.  These guarantees relate primarily to arrangements between ProLiance and various natural gas pipeline operators.  The Company has not been called upon to satisfy any obligations pursuant to these parental guarantees and has accrued no significant liabilities related to these guarantees.

Performance Guarantees & Product Warranties

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

Specific to ESG, in its role as a general contractor in the performance contracting industry, at September 30, 2011, there are 81 open surety bonds supporting future performance.  The average face amount of these obligations is $4.0 million, and the largest obligation has a face amount of $30.8 million.  The maximum exposure of these obligations is less than these amounts for several factors, including the level of work already completed.  At September 30, 2011, over 50 percent of work was completed on projects with open surety bonds.  A significant portion of these commitments will be fulfilled within one year.  In instances where ESG operates facilities, project guarantees extend over a longer period.  In addition to its performance obligations, ESG also warrants the functionality of certain installed infrastructure generally for one year and the associated energy savings over a specified number of years.  The Company has no significant accruals for these warranty obligations as of September 30, 2011.

Legal & Regulatory Proceedings

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

XML

Retirement Plans and Other Postretirement Benefits (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Expected contribution to defined benefit plans for current year by employer	$ 35.0		$ 35.0
Contribution to date to defined benefit plans by employer			32.6
Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	1.7	1.5	5.2	4.7
Interest cost	3.9	4.0	11.9	11.9
Expected return on plan assets	(5.3)	(4.6)	(15.9)	(13.8)
Amortization of prior service cost	0.5	0.4	1.3	1.2
Amortization of transitional obligation	0	0	0	0
Amortization of actuarial loss	1.0	0.5	2.9	1.5
Net periodic benefit cost	1.8	1.8	5.4	5.5
Other Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	0.1	0.2	0.4	0.4
Interest cost	1.1	1.1	3.2	3.4
Expected return on plan assets	0	0	0	(0.2)
Amortization of prior service cost	(0.2)	(0.2)	(0.6)	(0.6)
Amortization of transitional obligation	0.2	0.3	0.8	0.9
Amortization of actuarial loss	0.2	0	0.5	0.3
Net periodic benefit cost	$ 1.4	$ 1.4	$ 4.3	$ 4.2

XML

Impact of Recently Issued Accounting Principles

9 Months Ended

Sep. 30, 2011

Impact of Recently Issued Accounting Principles [Abstract]

Recently Issued Accounting Standards

15.   Impact of Recently Issued Accounting Principles

Other Comprehensive Income (OCI)

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

Goodwill Testing

In September 2011, the FASB issued new accounting guidance regarding testing goodwill for impairment.  The new guidance will allow the Company an option to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test.  Using the new guidance, the Company no longer would be required to calculate the fair value of a reporting unit unless the Company determines, based on that qualitative assessment, that it is more likely than not that its fair value is less than its carrying amount.  The new guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011.  The adoption of this guidance will have no material impact to the Company's financial statements.

Multiemployer Pension Plan Disclosures

In September 2011, the FASB issued new accounting guidance that requires enhanced disclosures regarding an employer's participation in multiemployer pension plans.  For plans that are individually significant, these enhanced disclosures include the legal name of the plan, the plan's Employer Identification Number, the employer's contributions made to the plan, the expiration date(s) of the collective-bargaining agreement(s) requiring contributions to the plan, the most recently available certified zone status provided by the plan, and several other disclosures.  The new disclosure requirements are effective for fiscal years ending after December 15, 2011, so they will be effective for the Company's 2011 financial statements.  The Company participates in several multiemployer pension plans and is currently assessing the impact these new disclosure requirements will have on its financial statements.

XML

CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited) (USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Current Assets
Cash and cash equivalents	$ 6.4	$ 10.4
Accounts receivable - less reserves of $6.5 and $5.3, respectively	219.8	176.6
Accrued unbilled revenues	62.2	162.0
Inventories	207.3	187.1
Recoverable fuel and natural gas costs	16.0	7.9
Prepayments and other current assets	110.8	101.2
Total current assets	622.5	645.2
Utility Plant
Original cost	4,937.6	4,791.7
Less: accumulated depreciation and amortization	1,922.2	1,836.3
Net utility plant	3,015.4	2,955.4
Investments in unconsolidated affiliates	98.0	135.2
Other utility and corporate investments	34.4	34.1
Other nonutility investments	41.3	40.9
Nonutility plant - net	537.3	488.3
Goodwill - net	262.3	242.0
Regulatory assets	181.3	189.4
Other assets	45.9	33.7
TOTAL ASSETS	4,838.4	4,764.2
Current Liabilities
Accounts payable	142.2	183.7
Accounts payable to affiliated companies	25.4	59.6
Accrued liabilities	176.7	178.4
Short-term borrowings	216.4	118.3
Current maturities of long-term debt	138.0	250.7
Long-term debt subject to tender	0	30.0
Total current liabilities	698.7	820.7
Long-term Debt - Net of Current Maturities and Debt Subject to Tender	1,581.1	1,435.2
Deferred Income Taxes & Other Liabilities
Deferred income taxes	564.8	515.3
Regulatory liabilities	341.0	333.5
Deferred credits and other liabilities	200.5	220.6
Total deferred credits and other liabilities	1,106.3	1,069.4
Commitments and Contingencies (Notes 11-13)
Common Shareholders' Equity
Common stock (no par value) - issued and outstanding 81.8 and 81.7 shares, respectively	689.3	683.4
Retained earnings	769.6	759.9
Accumulated other comprehensive income (loss)	(6.6)	(4.4)
Total common shareholders' equity	1,452.3	1,438.9
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	$ 4,838.4	$ 4,764.2

XML

ProLiance Holdings, LLC (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2009	Dec. 31, 2010
ProLiance Holdings, LLC [Abstract]
Equity method investment, profit and loss ownership percentage (in hundredths)	61.00%		61.00%
Equity method investment, ownership percentage (in hundredths)	50.00%		50.00%
Summarized statement of income information [Abstract]
Revenues	$ 283.0	$ 289.3	$ 1,074.8	$ 1,095.1
Operating income (loss)	(19.4)	(12.8)	(56.7)	(12.2)
ProLiance's earnings (loss)	(19.5)	(12.9)	(57.2)	(12.3)
Summarized balance sheet information [Abstract]
Current assets	301.3		301.3			441.4
Noncurrent assets	58.2		58.2			59.1
Current liabilities	217.9		217.9			298.1
Noncurrent liabilities	0.4		0.4			0.4
Members' equity	151.6		151.6			208.9
Accumulated other comprehensive income (loss)	(13.6)		(13.6)			(10.8)
Noncontrolling Interest	3.2		3.2			3.9
Equity method investment holding minority interest in equity method investment (in hundredths)	25.00%		25.00%
Impairment charge recorded by an investee of the company's equity method investments					132.0
Impairment charge recorded by one of the companies equity method investments					33.0
Equity Method Investment Unusual Item Gain Or Loss Net Of Tax Attributable To Noncontrolling Interest					11.9
Equity method investment minority interest in joint ventures	36.9		36.9			36.7
Loss contingency, damages sought value from a party that is an investment of an equity method investee			56.7
Related party transaction, expenses from transactions with related party	80.5	78.0	281.6	319.2
Accounts payable, Proliance	25.4		25.4			59.6
Amounts recorded to Equity in losses of unconsolidated affiliates	(11.7)	(8.2)	(34.6)	(13.9)
Proliance Holdings Llc [Member]
Summarized balance sheet information [Abstract]
Equity investment balance	86.6		86.6			123.2
Amounts recorded to Equity in losses of unconsolidated affiliates	$ 11.9	$ 8.2	$ 34.9	$ 8.0

XML

Financing Activities (Details) (Vectren Utility Holdings Inc [Member], Unsecured Debt [Member], USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2011
Debt Instrument [Line Items]
Amount of current debt that has been reclassified to long-term debt to reflect the company's ability and intent to refinance from the proceeds received from the issuance of the senior notes	$ 150.0
Senior Guaranteed Note due 2021 [Member]
Debt Instrument [Line Items]
Face amount	55.0
Stated percentage rate (in hundredths)	4.67%
Maturity date	Nov. 30, 2021
Issuance date	November 30, 2011
Senior Guaranteed Note due 2026 [Member]
Debt Instrument [Line Items]
Face amount	60.0
Stated percentage rate (in hundredths)	5.02%
Maturity date	Nov. 30, 2026
Issuance date	November 30, 2011
Senior Guaranteed Note due 2041 [Member]
Debt Instrument [Line Items]
Face amount	35.0
Stated percentage rate (in hundredths)	5.99%
Maturity date	Dec. 02, 2041
Issuance date	November 30, 2011
Senior Guaranteed Note due 2042 [Member]
Debt Instrument [Line Items]
Face amount	100.0
Stated percentage rate (in hundredths)	5.00%
Maturity date	Feb. 03, 2042
Issuance date	February 1 2012
Senior Guaranteed Note due 2036 [Member]
Debt Instrument [Line Items]
Face amount	96.2
Stated percentage rate (in hundredths)	5.95%
Maturity date year	2036
Call date	November 21, 2011
Senior Guaranteed Note due 2011 [Member]
Debt Instrument [Line Items]
Face amount	$ 250.0
Stated percentage rate (in hundredths)	6.625%
Maturity date	Dec. 01, 2011