vectren corp 10-q 10/31/05

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, 2005

[_]	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, Indiana, 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. Yes x No __

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes x No __

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes __ No x

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	76,095,245	October 31, 2005
Class	Number of Shares	Date

Table of Contents

Item Number		Page Number
	PART I. FINANCIAL INFORMATION
1	Financial Statements (Unaudited)
	Vectren Corporation and Subsidiary Companies
	Consolidated Condensed Balance Sheets	3-4
	Consolidated Condensed Statements of Income	5
	Consolidated Condensed Statements of Cash Flows	6
	Notes to Unaudited Consolidated Condensed Financial Statements	7
2	Management’s Discussion and Analysis of Results of Operations and Financial Condition	21
3	Quantitative and Qualitative Disclosures about Market Risk	41
4	Controls and Procedures	41

	PART II. OTHER INFORMATION
1	Legal Proceedings	42
2	Unregistered Sales of Equity Securities and Use of Proceeds	42
6	Exhibit Index	42
	Signatures	43

Access to Information

Vectren Corporation makes available all SEC filings and recent annual reports free of charge, including those of its wholly owned subsidiary, Vectren Utility Holdings, Inc., through its website at www.vectren.com, or by request, directed to Investor Relations at the mailing address, phone number, or email address that follows:

Mailing Address:

One Vectren Square

Evansville, Indiana 47708

Phone Number:

(812) 491-4000

Investor Relations Contact:

Steven M. Schein

Vice President, Investor Relations

sschein@vectren.com

Definitions

AFUDC: allowance for funds used during construction	MMBTU: millions of British thermal units
APB: Accounting Principles Board	MW: megawatts
EITF: Emerging Issues Task Force	MWh / GWh: megawatt hours / thousands of megawatt hours (gigawatt hours)
FASB: Financial Accounting Standards Board	NOx: nitrogen oxide
FERC: Federal Energy Regulatory Commission	OUCC: Indiana Office of the Utility Consumer Counselor
IDEM: Indiana Department of Environmental Management	PUCO: Public Utilities Commission of Ohio
IURC: Indiana Utility Regulatory Commission	SFAS: Statement of Financial Accounting Standards
MCF / BCF: thousands / billions of cubic feet	USEPA: United States Environmental Protection Agency
MDth / MMDth: thousands / millions of dekatherms	Throughput: combined gas sales and gas transportation volumes

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

VECTREN CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited - In millions)


		September 30, 2005		December 31, 2004

ASSETS

Current Assets
Cash & cash equivalents	$	4.1	$	9.6
Accounts receivable - less reserves of $2.4 &
$2.0, respectively		97.2		173.5
Accrued unbilled revenues		53.5		176.6
Inventories		89.2		67.6
Recoverable fuel & natural gas costs		17.1		17.7
Prepayments & other current assets		180.7		141.3
Total current assets		441.8		586.3

Utility Plant
Original cost		3,563.5		3,465.2
Less: accumulated depreciation & amortization		1,361.5		1,309.0
Net utility plant		2,202.0		2,156.2

Investments in unconsolidated affiliates		183.2		180.0
Other investments		116.2		115.1
Non-utility property - net		242.4		229.2
Goodwill - net		207.1		207.1
Regulatory assets		88.0		82.5
Other assets		26.3		30.5
TOTAL ASSETS	$	3,507.0	$	3,586.9

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

VECTREN CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited - In millions)


	September 30,			December 31,
	2005			2004

LIABILITIES & SHAREHOLDERS' EQUITY

Current Liabilities
Accounts payable	$ 92.7			$ 123.8
Accounts payable to affiliated companies	82.0			109.3
Refundable fuel & natural gas costs	11.0			6.3
Accrued liabilities	117.9			125.8
Short-term borrowings	369.1			412.4
Current maturities of long-term debt	38.4			38.5
Long-term debt subject to tender	-			10.0
Total current liabilities	711.1			826.1

Long-term Debt - Net of Current Maturities &
Debt Subject to Tender	1,026.6			1,016.6

Deferred Income Taxes & Other Liabilities
Deferred income taxes	227.7			234.0
Regulatory liabilities	266.0			251.7
Deferred credits & other liabilities	168.6			163.2
Total deferred credits & other liabilities	662.3			648.9

Minority Interest in Subsidiary	0.4			0.4

Commitments & Contingencies (Notes 8 -11)

Cumulative, Redeemable Preferred Stock of a Subsidiary	-			0.1

Common Shareholders' Equity
Common stock (no par value) – issued & outstanding
76.1 and 75.9 shares, respectively		529.3			526.8
Retained earnings		601.1			583.0
Accumulated other comprehensive loss		(23.8	)		(15.0	)
Total common shareholders' equity		1,106.6			1,094.8

TOTAL LIABILITIES & SHAREHOLDERS' EQUITY	$	3,507.0		$	3,586.9

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

VECTREN CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED CONDENSED STATEMENTS OF INCOME

(Unaudited - In millions, except per share data)


		Three Months Ended September 30,						Nine Months Ended September 30,
		2005			2004			2005		2004
OPERATING REVENUES
Gas utility	$	136.8		$	112.3		$	839.5	$	771.6
Electric utility		128.7			102.3			320.3		280.2
Energy services & other		45.3			39.8			154.4		124.6
Total operating revenues		310.8			254.4			1,314.2		1,176.4
OPERATING EXPENSES
Cost of gas sold		81.6			67.2			568.8		529.8
Fuel for electric generation		39.3			25.8			95.6		72.4
Purchased electric energy		8.8			5.3			14.7		16.6
Cost of energy services & other		32.5			27.0			115.5		90.1
Other operating		67.2			59.6			204.1		190.8
Depreciation & amortization		41.2			36.2			116.8		103.6
Taxes other than income taxes		10.3			9.9			44.4		43.3
Total operating expenses		280.9			231.0			1,159.9		1,046.6
OPERATING INCOME		29.9			23.4			154.3		129.8
OTHER INCOME - NET
Equity in earnings of unconsolidated affiliates		5.4			1.5			12.5		13.5
Other income – net		1.6			3.3			5.6		2.1
Total other income - net		7.0			4.8			18.1		15.6
Interest expense		21.0			19.4			60.8		57.5
INCOME BEFORE INCOME TAXES		15.9			8.8			111.6		87.9
Income taxes		(0.6	)		(0.9	)		25.6		20.0
Minority interest in & preferred dividend
requirements of subsidiaries		-			-			-		0.1
NET INCOME	$	16.5		$	9.7		$	86.0	$	67.8

AVERAGE COMMON SHARES OUTSTANDING		75.7			75.6			75.6		75.5
DILUTED COMMON SHARES OUTSTANDING		76.2			76.0			76.2		75.9

EARNINGS PER SHARE OF COMMON STOCK:
BASIC	$	0.22		$	0.13		$	1.14	$	0.90
DILUTED		0.22			0.13			1.13		0.89

DIVIDENDS DECLARED PER SHARE OF
COMMON STOCK	$	0.30		$	0.29		$	0.89	$	0.86

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

VECTREN CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited - In millions)


	Nine Months Ended September 30,
		2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	86.0		$	67.8
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization		116.8			103.6
Deferred income taxes & investment tax credits		(5.5	)		(5.4	)
Equity in earnings of unconsolidated affiliates		(12.5	)		(13.5	)
Net unrealized loss/(gain) on derivative instruments		(1.4	)		1.0
Pension & postretirement periodic benefit cost		13.5			12.3
Other non-cash charges - net		13.2			16.1
Changes in working capital accounts:
Accounts receivable & accrued unbilled revenue		189.3			126.0
Inventories		(21.6	)		(7.0	)
Recoverable fuel & natural gas costs		5.3			(18.2	)
Prepayments & other current assets		(33.1	)		(21.3	)
Accounts payable, including to affiliated companies		(58.4	)		(22.5	)
Accrued liabilities		(7.6	)		(12.8	)
Changes in noncurrent assets		(5.7	)		(6.1	)
Changes in noncurrent liabilities		(9.4	)		(13.4	)
Net cash flows from operating activities		268.9			206.6
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Stock option exercises & other stock plans		-			4.5
Requirements for:
Dividends on common stock		(67.3	)		(64.6	)
Retirement of long-term debt, including premiums paid		(0.4	)		(12.5	)
Redemption of preferred stock of subsidiary		(0.1	)		(0.1	)
Other financing activities		(0.5	)		-
Net change in short-term borrowings		(43.3	)		34.9
Net cash flows from financing activities		(111.6	)		(37.8	)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Unconsolidated affiliate distributions		9.3			23.6
Notes receivable & other collections		0.9			8.9
Requirements for:
Capital expenditures, excluding AFUDC equity		(158.4	)		(189.3	)
Unconsolidated affiliate investments		(14.6	)		(15.7	)
Notes receivable & other investments		-			(3.8	)
Net cash flows from investing activities		(162.8	)		(176.3	)
Net decrease in cash & cash equivalents		(5.5	)		(7.5	)
Cash & cash equivalents at beginning of period		9.6			15.3
Cash & cash equivalents at end of period	$	4.1		$	7.8

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

VECTREN CORPORATION AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

(UNAUDITED)

1.	Organization and Nature of Operations

Vectren Corporation (the Company or Vectren), an Indiana corporation, is an energy and applied technology holding company headquartered in Evansville, Indiana. The Company’s wholly owned subsidiary, Vectren Utility Holdings, Inc. (Utility Holdings), serves as the intermediate holding company for three operating public utilities: Indiana Gas Company, Inc. (Indiana Gas), Southern Indiana Gas and Electric Company (SIGECO), 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 exempt from registration pursuant to Section 3(a) (1) and 3(c) of the Public Utility Holding Company Act of 1935.

Indiana Gas provides energy delivery services to approximately 555,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 136,000 electric customers and approximately 110,000 natural gas customers located near Evansville in southwestern Indiana. SIGECO also owns and operates electric generation to serve its electric customers and optimizes those assets in the wholesale power market. Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana. The Ohio operations provide energy delivery services to approximately 315,000 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, (53% ownership) and Indiana Gas (47% ownership). The Ohio operations generally do business as Vectren Energy Delivery of Ohio.

The Company, through Vectren Enterprises, Inc. (Enterprises), is also involved in nonregulated activities in three primary business areas: Energy Marketing and Services, Coal Mining, and Utility Infrastructure Services. Energy Marketing and Services markets natural gas and provides energy management services, including energy performance contracting services. Coal Mining mines and sells coal and generates IRS Code Section 29 tax credits relating to the production of coal-based synthetic fuels. Utility Infrastructure Services provides underground construction and repair, facilities locating, and meter reading services. In addition, there are other businesses that invest in broadband communication services, energy-related opportunities, real estate, and leveraged leases, among other activities. These operations are collectively referred to as the Nonregulated Group. Enterprises supports the Company’s regulated utilities pursuant to service contracts by providing natural gas supply services, coal, utility infrastructure services, and other services.

2.	Basis of Presentation

The interim consolidated condensed financial statements included in this report have been prepared by the Company, without audit, as provided in the rules and regulations of the Securities and Exchange Commission. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been omitted as provided in such rules and regulations. The Company believes that the information in this report reflects all adjustments necessary to fairly state the results of the interim periods reported. 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, 2004, filed March 2, 2005, on Form 10-K. Because of the seasonal nature of the Company’s utility operations, the results shown on a quarterly basis are not necessarily indicative of annual results. Certain amounts from the prior period reported in this Quarterly Report on Form 10-Q have been reclassified to conform to the 2005 financial statement presentation. These reclassifications had no impact on reported net income or cash flows.

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

3.	Share-Based Compensation

The Company applies APB Opinion 25, “Accounting for Stock Issued to Employees” (APB 25) and related interpretations when measuring compensation expense for its share-based compensation plans.

Stock Option Plans

The exercise price of stock options awarded under the Company’s stock option plans is equal to the fair market value of the underlying common stock on the date of grant. Accordingly, no compensation expense has been recognized for stock option plans. Options to purchase 289,294 shares of common stock at an exercise price of $26.63 were issued to management during 2005. The grants vest over three years.

Other Plans

In addition to its stock option plans, the Company maintains restricted stock and phantom stock plans for executives, strategic employees, and non-employee directors. During the nine months ended September 30, 2005, the Company issued 150,719 restricted shares to management and 13,950 restricted shares to non-employee members of Vectren’s Board of Directors. Management shares vest over four years. The shares issued to non-employee directors vest in one year.

Compensation expense associated with these restricted stock and phantom stock plans for the three months ended September 30, 2005 and 2004, was $1.7 million ($1.0 million after tax) and $1.1 million ($0.6 million after tax), respectively, and for the nine months ended September 30, 2005 and 2004, was $3.7 million ($2.2 million after tax) and $2.4 million ($1.4 million after tax), respectively. The amount of expense is consistent with the amount of expense that would have been recognized if the Company used the fair value based method described in SFAS No. 123 “Accounting for Stock Based Compensation” (SFAS 123), as amended, to value these awards.

Pro forma Information

Following is the effect on net income and earnings per share as if the fair value based method described in SFAS 123 had been applied to all share-based compensation plans:


	Three Months Ended September 30,					Nine Months Ended September 30,
(In millions, except per share amounts)		2005		2004		2005		2004
Net Income:
As reported	$	16.5	$	9.7	$	86.0	$	67.8
Add: Share-based employee compensation included
in reported net income - net of tax		1.0		0.6		2.2		1.4
Deduct: Total share-based employee compensation
expense determined under fair value based
method for all awards - net of tax		1.2		0.8		2.8		2.0
Pro forma net income	$	16.3	$	9.5	$	85.4	$	67.2

Basic Earnings Per Share:
As reported	$	0.22	$	0.13	$	1.14	$	0.90
Pro forma		0.22		0.13		1.13		0.89

Diluted Earnings Per Share:
As reported	$	0.22	$	0.13	$	1.13	$	0.89
Pro forma		0.21		0.13		1.12		0.89

SFAS 123 (revised 2004) and related interpretations

In December 2004, the FASB issued Statement 123 (revised 2004), “Share-Based Payments” (SFAS 123R) that will require compensation costs related to all share-based payment transactions to be recognized in the financial statements. With limited exceptions, the amount of compensation cost will be measured based on the grant-date fair value of the equity or liability instruments issued. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. SFAS 123R replaces SFAS 123 and supersedes APB 25. In April 2005, the SEC extended the effective date of SFAS 123R to January 1, 2006 for calendar year companies like the Company. SFAS 123R provides for multiple transition methods, and the Company is still evaluating potential methods for adoption. The adoption of this standard and subsequent interpretations of the standard is not expected to have a material effect on the Company’s operating results or financial condition.

4.	Earnings Per Share

Basic earnings per share is computed by dividing net income available to common shareholders by the weighted-average number of common shares outstanding for the period. Diluted earnings per share assumes the conversion of stock options into common shares and the lifting of restrictions on issued restricted shares using the treasury stock method to the extent the effect would be dilutive. The following table sets forth the computation of basic and diluted earnings per share calculations for the three and nine months ended September 30, 2005 and 2004:


		Three Months Ended September 30,				Nine Months Ended September 30,
(In millions, except per share data)		2005		2004		2005		2004
Numerator:
Numerator for basic and diluted EPS - Net income	$	16.5	$	9.7	$	86.0	$	67.8
Denominator:
Denominator for basic EPS - Weighted average
common shares outstanding		75.7		75.6		75.6		75.5
Conversion of stock options and lifting of
restrictions on issued restricted stock		0.5		0.4		0.6		0.4
Denominator for diluted EPS - Adjusted weighted
average shares outstanding and assumed
conversions outstanding		76.2		76.0		76.2		75.9

Basic earnings per share	$	0.22	$	0.13	$	1.14	$	0.90
Diluted earnings per share	$	0.22	$	0.13	$	1.13	$	0.89

For the three months ended September 30, 2004, options to purchase an additional 22,274 shares of the Company’s common stock were outstanding, but were excluded from the computation of diluted earnings per share. Options to purchase an additional 241,274 shares of the Company’s common stock were outstanding, but were excluded from the computation of diluted earnings per share for the nine months ended September 30, 2004. These options were excluded from the earnings per share computation because their effect would have been antidilutive. Exercise prices for options excluded from the computation ranged from $24.74 to $25.59 in 2004. For the three and nine months ended September 30, 2005, all options were dilutive.

5.	Comprehensive Income

Comprehensive income consists of the following:


		Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)		2005			2004			2005			2004
Net income	$	16.5		$	9.7		$	86.0		$	67.8
Comprehensive (loss) income of
unconsolidated affiliates- net of tax		(6.5	)		(1.2	)		(8.8	)		(1.5	)
Total comprehensive income (loss)	$	10.0		$	8.5		$	77.2		$	66.3

Other comprehensive income of unconsolidated affiliates is the Company’s portion of ProLiance Energy, LLC’s and Reliant Services, LLC’s accumulated other comprehensive income related to their use of cash flow hedges, including commodity contracts and interest rate swaps, and the Company’s portion of Haddington Energy Partners, LP’s accumulated other comprehensive income related to its unrealized gains and losses of “available for sale securities,” as defined by SFAS 115, “Accounting for Certain Investments in Debt and Equity Securities.”

6.	Financing Activities

Utility Holdings

In anticipation of a debt issuance, in October 2005, Utility Holdings filed a shelf registration statement with the Securities and Exchange Commission for $275 million aggregate principal amount of unsecured senior notes and previously executed forward starting interest rate swaps with a notional value of $75 million that expire in December 2005. When issued, the unsecured notes will be guaranteed by Utility Holdings’ three operating utility companies: SIGECO, Indiana Gas, and VEDO. These guarantees will be full and unconditional and joint and several.

Vectren Capital Corp.

On October 11, 2005, Vectren and Vectren Capital, Corp., its wholly-owned subsidiary (Vectren Capital), entered into a private placement Note Purchase Agreement (2005 Note Purchase Agreement) pursuant to which various institutional investors have agreed to purchase the following tranches of notes from Vectren Capital: (i) $25 million 4.99% Guaranteed Senior Notes, Series A due 2010, (ii) $25 million 5.13% Guaranteed Senior Notes, Series B due 2012 and (iii) $75 million 5.31% Guaranteed Senior Notes, Series C due 2015. These Guaranteed Senior Notes will be unconditionally guaranteed by Vectren, the parent of Vectren Capital. Subject to the satisfaction of customary conditions precedent, this financing is scheduled to close on or about December 15, 2005. This Note Purchase Agreement contains customary representations, warranties and covenants, including a covenant to the effect that the ratio of consolidated total debt to consolidated total capitalization will not exceed 75%.

On October 11, 2005, Vectren and Vectren Capital entered into First Amendments with respect to a Note Purchase Agreement dated as of December 31, 2000 pursuant to which Vectren Capital issued to institutional investors the following tranches of notes: (i) $38 million 7.67% Senior Notes due 2005, (ii) $17.5 million 7.83% Senior Notes due 2007, (iii) $22.5 million 7.98% Senior Notes due 2010 and (iv) a Note Purchase Agreement, dated April 25, 1997, pursuant to which Vectren Capital issued to an institutional investor a $35 million 7.43% Senior Note due 2012. The First Amendments (i) conform the covenants to those contained in the 2005 Note Purchase Agreement, (ii) eliminate a credit ratings trigger which would have afforded noteholders the option to require prepayment if the ratings of Indiana Gas or SIGECO fell below a certain level, (iii) substitute the unconditional guarantee by Vectren of the notes for the more limited support agreement previously in place and (iv) provide for a 100 basis point increase in interest rates if the ratio of consolidated total debt to total capitalization exceeds 65%.

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 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)		2005			2004			2005			2004
Service cost	$	1.4		$	1.7		$	0.3		$	0.3
Interest cost		3.5			3.4			1.3			1.5
Expected return on plan assets		(3.3	)		(3.4	)		(0.1	)		(0.2	)
Amortization of prior service cost		0.4			0.2			-			-
Amortization of transitional (asset) obligation		-			(0.1	)		0.7			0.7
Amortization of actuarial loss (gain)		0.4			0.3			(0.1	)		(0.3	)
Net periodic benefit cost	$	2.4		$	2.1		$	2.1		$	2.0


		Nine Months Ended September 30,
	Pension Benefits							Other Benefits
(In millions)		2005			2004			2005			2004
Service cost	$	4.2		$	4.9		$	0.9		$	0.7
Interest cost		10.4			10.1			3.9			4.4
Expected return on plan assets		(9.9	)		(10.1	)		(0.3	)		(0.5	)
Amortization of prior service cost		1.2			0.7			-			-
Amortization of transitional (asset) obligation		-			(0.2	)		2.1			2.2
Amortization of actuarial loss (gain)		1.3			0.7			(0.3	)		(0.6	)
Net periodic benefit cost	$	7.2		$	6.1		$	6.3		$	6.2

Employer Contributions to Qualified Pension Plans

Currently, the Company expects to contribute approximately $3.7 million to its pension plan trusts for 2005. Through September 30, 2005, approximately $3.0 million has been contributed to its pension plan trusts.

Amendment to Plans

Pension and postretirement periodic cost has increased from approximately $13 million in 2002 to over $16 million in 2004. Preliminary estimates of 2005 periodic cost approximated $18 million. In January 2005, the Company announced the amendment of certain postretirement benefit plans, effective January 1, 2006. The amendment resulted in an estimated $4 million decrease in 2005 periodic cost, reducing the preliminary $18 million estimate. Two of the unions that represent bargaining employees at the Company’s regulated subsidiaries have advised the Company that it is their position that these changes are not permitted under the existing collective bargaining agreements which govern the relationship between the employees and the affected subsidiaries. Management has analyzed the unions’ position and continues to believe that the Company has reserved the right to amend the affected plans and that changing these benefits for retirees is not a mandatory subject of bargaining. Future changes in health care costs, work force demographics, interest rates, or plan changes could significantly affect the estimated cost of these future benefits.

8.	ProLiance Energy, LLC

ProLiance Energy, LLC (ProLiance), a nonregulated energy marketing affiliate of Vectren and Citizens Gas and Coke Utility (Citizens Gas), 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 utilities and nonregulated gas supply operations and Citizens Gas. ProLiance’s primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services. The Company, including its retail gas supply operations, contracted for all natural gas purchases through ProLiance in all periods presented. The Company accounts for its investment in ProLiance using the equity method of accounting.

As part of a settlement agreement approved by the IURC during July 2002, the gas supply agreements with Indiana Gas and SIGECO, were approved and extended through March 31, 2007. Under the provisions of that agreement, the utilities may decide to conduct a “request for proposal” (RFP) for a new supply administrator, or they may decide to make an alternative proposal for procurement of gas supply. That decision will be made by December 2005. To the extent an RFP is conducted, ProLiance is fully expected to participate in the RFP process for service to the utilities after March 31, 2007.

As required by a June 14, 2005, PUCO order (See Note 11), VEDO solicited bids for its gas supply/portfolio administration services and has selected a different provider under a one year contract. ProLiance’s obligation to supply these services to VEDO ended October 31, 2005. The Company believes this change will not materially affect ProLiance’s or Vectren’s future earnings, financial position, or cash flows.

Transactions with ProLiance

Purchases from ProLiance for resale and for injections into storage for the three months ended September 30, 2005 and 2004, totaled $208.7 million and $171.6 million, respectively, and for the nine months ended September 30, 2005 and 2004, totaled $680.8 million and $621.5 million, respectively. Amounts owed to ProLiance at September 30, 2005, and December 31, 2004, for those purchases were $79.2 million and $108.2 million, respectively, and are included in Accounts payable to affiliated companies. Amounts charged by ProLiance for gas supply services are established by supply agreements with each utility.

ProLiance Contingency

In 2002, a civil lawsuit was filed in the United States District Court for the Northern District of Alabama by the City of Huntsville, Alabama d/b/a Huntsville Utilities, Inc. (Huntsville Utilities) against ProLiance. Huntsville Utilities asserted claims based on alleged breach of contract with respect to the provision of portfolio services and/or pricing advice, fraud, fraudulent inducement, and other theories, including conversion and violations under the Racketeering, Influenced and Corrupt Organizations Act (RICO). These claims related generally to: (1) alleged breach of contract in providing advice and/or administering portfolio arrangements; (2) alleged promises to provide gas at a below-market rate; (3) the creation and repayment of a “winter levelizing program” instituted by ProLiance in conjunction with the Manager of Huntsville’s Gas Utility to allow Huntsville Utilities to pay its natural gas bills from the winter of 2000-2001 over an extended period of time coupled with the alleged ignorance about the program on the part of Huntsville Utilities’ Gas Board and other management, and; (4) conversion of Huntsville Utilities’ gas storage supplies to repay the balance owed on the winter levelizing program and the alleged lack of authority of Huntsville Utilities’ gas manager to approve those sales.

In early 2005, a jury trial commenced and on February 10, 2005, the jury returned a verdict largely in favor of Huntsville Utilities and awarded Huntsville Utilities compensatory damages of $8.2 million and punitive damages of $25.0 million. The jury rejected Huntsville Utilities’ claim of conversion. The jury also rejected a counter claim by ProLiance for payment of amounts due from Huntsville Utilities. Following that verdict, there were a number of issues presented to the judge for resolution. Huntsville made a claim under federal law that it was entitled to have the compensatory damage award trebled. The judge rejected that request. ProLiance made a claim against Huntsville for unjust enrichment, which was also rejected by the judge. The judge also determined that attorneys’ fees and prejudgment interest are owed by ProLiance to Huntsville Utilities. The verdict, as affected by the judge’s subsequent rulings, totals $38.9 million, and ProLiance has posted an appeal bond for that estimated amount. ProLiance’s management believes there are reasonable grounds for appeal which offer a basis for reversal of the entire verdict, and initiated the appeal process on July 26, 2005. The appeal is not likely to be fully briefed until early 2006, and an appellate decision may be issued in the second half of 2006.

While it is reasonably possible that a liability has been incurred by ProLiance, it is not possible to predict the ultimate outcome of an appeal of the verdict. ProLiance recorded a reserve of $3.9 million as of December 31, 2004, reflective of their assessment of the lower end of the range of potential exposure on certain issues identified in the case and inclusive of estimated ongoing litigation costs. Amounts due from Huntsville Utilities were fully reserved by ProLiance in 2003.

As an equity investor in ProLiance, the Company reflected its share of the charge, or $1.4 million after tax, in its 2004 fourth quarter results. That charge does not reflect the possibility that actual losses might be recovered from insurance carriers, as to which there can be no assurance. It is not expected that an unfavorable outcome on appeal will have a material adverse effect on the Company’s consolidated financial position or its liquidity, but an unfavorable outcome could be material to the Company’s earnings.

Commodity Prices

In response to the anticipated effects of higher gas costs, ProLiance obtained an approximate $112.5 million short-term credit facility for the October 2005 to March 2006 heating season from its existing lenders. This additional line increased ProLiance’s total borrowing capacity to $362.5 million. Neither ProLiance’s $250 million annual credit facility nor the $112.5 million additional line of credit is guaranteed by Vectren Corporation.

9.	Commitments & Contingencies

Legal Proceedings

IRS Section 29 Tax Credit Recent Developments

Vectren’s Coal Mining operations are comprised of Vectren Fuels, Inc. (Fuels), which includes its coal mines and related operations and Vectren Synfuels, Inc. (Synfuels). Synfuels holds one limited partnership unit (an 8.3% interest) in Pace Carbon Synfuels Investors, LP (Pace Carbon), a Delaware limited partnership formed to develop, own, and operate four projects to produce and sell coal-based synthetic fuel utilizing Covol technology.

Under Section 29 of the Internal Revenue Code, manufacturers such as Pace Carbon receive a tax credit for every ton of synthetic fuel sold. To qualify for the credits, the synthetic fuel must meet three primary conditions: 1) there must be a significant chemical change in the coal feedstock, 2) the product must be sold to an unrelated person, and 3) the production facility must have been placed in service before July 1, 1998.

In past rulings, the Internal Revenue Service (IRS) has concluded that the synthetic fuel produced at the Pace Carbon facilities should qualify for Section 29 tax credits. The IRS issued a private letter ruling with respect to the four projects on November 11, 1997, and subsequently issued an updated private letter ruling on September 23, 2002. As a partner in Pace Carbon, Vectren has reflected total tax credits under Section 29 in its consolidated results from inception through September 30, 2005, of approximately $74 million. To date, Vectren has been in a position to fully earn the credits generated. Primarily from the use of these credits, the Company generated an Alternative Minimum Tax (AMT) carryforward in 2004 and expects to be in that position in 2005. As a result, the Company has an accumulated AMT credit carryforward of approximately $36 million at September 30, 2005.

During June 2001, the IRS began a tax audit of Pace Carbon for the 1998 tax year and later expanded the audit to include tax years 1999, 2000, and 2001. In May 2004, the IRS completed its audit of the 1998 to 2001 tax returns of Pace Carbon requesting only minor modifications to previously filed returns. There were no changes to any of the filed Section 29 tax credit calculations. The Permanent Subcommittee on Investigations of the U.S. Senate’s Committee on Governmental Affairs, however, has an ongoing investigation related to Section 29 tax credits.

Further, Section 29 tax credits are only available when the price of oil is less than a base price specified by the tax code, as adjusted for inflation. The Company does not believe that credits realized in prior years will be affected by the limitation. However, an average NYMEX price of approximately $76 per barrel for the remainder of 2005, or an average NYMEX annual price of approximately $60 per barrel in 2006, could begin to limit Section 29 tax credits in those years. In January 2005, the Company executed an insurance arrangement that partially limits the Company’s exposure if a limitation on the availability of tax credits were to occur in 2005 and/or 2006 due to oil prices. The insurance policy protects approximately two-thirds of the expected 2005 and one-third of the expected 2006 tax credits.

Vectren believes it is justified in its reliance on the private letter rulings and most recent IRS audit results for the Pace Carbon facilities. Additionally, the Company does not currently expect oil price limitations on the credits in 2005. Therefore, the Company will continue to recognize Section 29 tax credits as they are earned.

United States Securities and Exchange Commission Inquiry into PUHCA Exemption

In July 2004, the Company received a letter from the SEC regarding its exempt status under the Public Utility Holding Company Act of 1935 (PUHCA). The letter asserts that Vectren's out of state electric power sales exceed the amount previously determined by the SEC to be acceptable in order to qualify for the exemption. There is pending a request by Vectren for an order of exemption under Section 3(a)(1) of the PUHCA. Vectren also claims the benefit of the exemption pursuant to Rule 2 under Section 3(a)(1) of the PUHCA by filing an annual statement on SEC Form U-3A-2. The Company has responded to the SEC inquiry and filed an amended Form U-3A-2 for the year ended December 31, 2003. The amendment changed the method of aggregating wholesale power sales and purchases outside of Indiana from that previously reported. The new method is to aggregate by delivery point. The amendment also submitted clarifications as to activity outside of Indiana related to gas utility operations. Form U-3A-2 for the year ended December 31, 2004 was filed on February 28, 2005.

On June 21, 2005, the Company amended its Form U-1 to further clarify its assertion that the Company and its utility holding company subsidiary, Utility Holdings, both qualify for the PUHCA exemption and to request an order of exemption under Section 3(a)(1) of the PUHCA.

On August 8, 2005, comprehensive energy legislation, the Domenici - Barton Energy Policy Act of 2005 (Energy Act), was signed into law. Among other things, the Energy Act provides for the repeal of PUHCA effective six months after its enactment, in February 2006. The Energy Act gives the FERC the ability to regulate holding companies previously subject to PUHCA. Although the Company cannot be certain how the FERC will implement any final regulations, such regulations, as they are currently proposed, are not expected to materially affect the Company’s financial position or operations.

Guarantees & Product Warranties

Vectren Corporation issues guarantees to third parties on behalf of its unconsolidated affiliates. Such guarantees allow those affiliates to execute transactions on more favorable terms than the affiliate could obtain without such a guarantee. Guarantees may include posted letters of credit, leasing guarantees, and performance guarantees. As of September 30, 2005, guarantees issued and outstanding on behalf of unconsolidated affiliates approximated $6 million. The Company has also issued a guarantee approximating $4 million related to the residual value of an operating lease that expires in 2006.

Vectren Corporation has accrued no liabilities for these guarantees as they relate to guarantees issued among related parties or were executed prior to the adoption of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” Liabilities accrued for, and expenses related to, product warranties are not significant.

10. Enviromental Matters

Clean Air Act

NOx SIP Call Matter

The Company has taken steps to comply with Indiana’s State Implementation Plan (SIP) of the Clean Air Act (the Act). These steps include installing Selective Catalytic Reduction (SCR) systems at Culley Generating Station Unit 3 (Culley), Warrick Generating Station Unit 4, and A.B. Brown Generating Station Units 1 and 2. SCR systems reduce flue gas NOx emissions to atmospheric nitrogen and water using ammonia in a chemical reaction. This technology is known to currently be the most effective method of reducing nitrogen oxide (NOx) emissions where high removal efficiencies are required.

The IURC has issued orders that approve:

·	the Company’s project to achieve environmental compliance by investing in clean coal technology;

·	a total capital cost investment for this project up to $250 million (excluding AFUDC and administrative overheads), subject to periodic review of the actual costs incurred;

·	a mechanism whereby, prior to an electric base rate case, the Company may recover through a rider that is updated every six months, an 8% return on its weighted capital costs for the project; and

·	ongoing recovery of operating costs, including depreciation and purchased emission allowances, related to the clean coal technology once the facility is placed into service.

Through September 30, 2005, capital investments approximating the level approved by the IURC have been made. Related annual operating expenses, including depreciation expense, are estimated to be between $24 million and $27 million.

The Company has achieved timely compliance through the reduction of the Company’s overall NOx emissions to levels compliant with Indiana’s NOx emissions budget allotted by the USEPA. Therefore, the Company has recorded no accrual for potential penalties that may result from noncompliance.

Clean Air Interstate Rule &Clean Air Mercury Rule

In March of 2005 USEPA finalized two new air emission reduction regulations. The Clean Air Interstate Rule (CAIR) is an allowance cap and trade program requiring further reductions in Nitrogen Oxides (NOx) and Sulfur Dioxide (SO₂) emissions from coal-burning power plants. The Clean Air Mercury Rule (CAMR) is an allowance cap and trade program requiring further reductions in mercury emissions from coal-burning power plants. Both sets of regulations require emission reductions in two phases. The first phase deadline for both rules is 2010 (2009 for NOx under CAIR), and the second phase deadline for compliance with the emission reductions required under CAIR is 2015, while the second phase deadline for compliance with the emission reduction requirements of CAMR is 2018. The Company is evaluating compliance options and fully expects to be in compliance by the required deadlines.

In May 2005, Vectren’s utility subsidiary, SIGECO, filed a new multi-emission compliance plan with the IURC. If approved, SIGECO’s coal-fired plants will be 100% scrubbed for SO₂, 90% scrubbed for NOx, and mercury emissions will be reduced to meet the new mercury reduction standards. On October 20, 2005, the Company and the OUCC filed with the IURC a settlement agreement concerning the regulatory treatment and recovery of the investment required by this plan. If the settlement agreement is approved, the Company will recover a return on its capital investments, which are expected to approximate $110 million, and related operating expenses through a rider mechanism. This rider mechanism will operate similar to the rider used to recover NOx-related capital investments and operating expenses. The Company expects a final order from the IURC related to this settlement agreement before the end of 2005.

Information Request

On January 23, 2001, SIGECO received an information request from the USEPA under Section 114 of the Clean Air Act for historical operational information on the Warrick and A.B. Brown generating stations. SIGECO has provided all information requested with the most recent correspondence provided on March 26, 2001.

Manufactured Gas Plants

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, Indiana Gas, SIGECO, and others may now be required to take remedial action if certain byproducts are found above the regulatory thresholds at these sites.

Indiana Gas has 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 has 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. Although Indiana Gas has not begun an RI/FS at additional sites, Indiana Gas has submitted several 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.

In conjunction with data compiled by environmental consultants, Indiana Gas has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, Indiana Gas has recorded costs that it reasonably expects to incur totaling approximately $20.4 million.

The estimated accrued costs are limited to Indiana Gas’ proportionate share of the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26 sites with other potentially responsible parties (PRP), which serve to limit Indiana Gas’ share of response costs at these 19 sites to between 20% and 50%.

With respect to insurance coverage, Indiana Gas has received and recorded settlements from all known insurance carriers in an aggregate amount approximating $20.4 million.

Environmental matters related to manufactured gas plants have had no material impact on earnings since costs recorded to date approximate PRP and insurance settlement recoveries. While Indiana Gas has recorded all costs which it presently expects 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.

In October 2002, the Company received a formal information request letter from the IDEM regarding five manufactured gas plants owned and/or operated by SIGECO and not currently enrolled in the IDEM’s VRP. In response, SIGECO submitted to the IDEM the results of preliminary site investigations conducted in the mid-1990’s. These site investigations confirmed that based upon the conditions known at the time, the sites posed no risk to human health or the environment. Follow up reviews have been initiated by the Company to confirm that the sites continue to pose no such risk.

On October 6, 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 on February 24, 2004. On July 13, 2004, SIGECO filed a declaratory judgment action against its insurance carriers seeking a judgment finding its carriers liable under the policies for coverage of further investigation and any necessary remediation costs that SIGECO may accrue under the VRP program. The total investigative costs, and if necessary, costs of remediation at the four SIGECO sites, as well as the amount of any PRP or insurance recoveries, cannot be determined at this time.

Jacobsville Superfund Site

On July 22, 2004, the USEPA listed the Jacobsville Neighborhood Soil Contamination site in Evansville, Indiana, on the National Priorities List under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). The USEPA has identified four sources of historic lead contamination. These four sources shut down manufacturing operations years ago. When drawing up the boundaries for the listing, the USEPA included a 250 acre block of properties surrounding the Jacobsville neighborhood, including Vectren's Wagner Operations Center. Vectren's property has not been named as a source of the lead contamination, nor does the USEPA's soil testing to date indicate that the Vectren property contains lead contaminated soils. Vectren's own soil testing, completed during the construction of the Operations Center, did not indicate that the Vectren property contains lead contaminated soils. At this time, Vectren anticipates only additional soil testing, if required by the USEPA.

11.

Rate & Regulatory Matters

Normal Temperature Adjustment Order

On October 5, 2005, the IURC approved the establishment of a normal temperature adjustment (NTA) mechanism for Vectren Energy Delivery of Indiana. The Indiana Office of Utility Consumer Counselor (OUCC) had previously entered into a settlement agreement with Vectren Energy Delivery of Indiana providing for the NTA. The NTA affects the Company’s Indiana regulated residential and commercial natural gas customers and should mitigate weather risk in those customer classes during the October to April peak heating season. These Indiana customer classes represent approximately 60-65% of the Company’s total natural gas heating load.

The NTA mechanism will mitigate volatility in distribution charges created by fluctuations in weather by lowering customer bills when weather is colder than normal and increasing customer bills when weather is warmer than normal. The NTA will be applied to meters read and bills rendered after October 15, 2005. Each subsequent monthly bill for the seven month heating season will be adjusted using the NTA.

The order provides that the Company will make, on a monthly basis, a commitment of $125,000 to a universal service fund program or other low income assistance program for the duration of the NTA or until a general rate case.

Gas Utility Base Rate Settlements

On June 30, 2004, the IURC approved a $5.7 million base rate increase for SIGECO’s gas distribution business, and on November 30, 2004, approved a $24 million base rate increase for Indiana Gas’ gas distribution business. On April 13, 2005, the PUCO approved a $15.7 million base rate increase for VEDO’s gas distribution business. The new rate designs in all three territories include a larger service charge, which is intended to address to some extent earnings volatility related to weather. The base rate change in SIGECO’s service territory was implemented on July 1, 2004; the base rate change in Indiana Gas’ service territory was implemented on December 1, 2004; and the base rate change in VEDO’s service territory was implemented on April 14, 2005.

The orders also permit SIGECO and Indiana Gas to recover the on-going costs to comply with the Pipeline Safety Improvement Act of 2002. The Pipeline Safety Improvement Tracker provides for the recovery of incremental non-capital dollars, capped at $750,000 the first year and $500,000 thereafter for SIGECO and $2.5 million per year for Indiana Gas. Any costs incurred in excess of these annual caps are to be deferred for future recovery. VEDO’s new base rates provide for the recovery of on-going costs to comply with the Pipeline Safety Improvement Act of 2002 as well as the funding of conservation programs.

MISO

Since February, 2002 and with the IURC’s approval, the Company has been a member of the Midwest Independent System Operator, Inc. (MISO), a FERC approved regional transmission organization. The MISO serves the electrical transmission needs of much of the Midwest and maintains operational control over the Company’s electric transmission facilities as well as that of other Midwest utilities. Pursuant to an order from the IURC received in December 2001, certain MISO startup costs (referred to as Day 1 costs) have been deferred for future recovery in the next general rate case.

On April 1, 2005, the MISO energy market commenced operation (the Day 2 energy market). As a result of being a market participant, the Company now bids its owned generation into the Day Ahead and Real Time markets and procures power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market.

On June 1, 2005, Vectren, together with three other Indiana electric utilities, received regulatory authority from the IURC that allows recovery of fuel related costs and deferral of other costs associated with the Day 2 energy market. The order allows fuel related costs to be passed through to customers in Vectren’s existing fuel cost recovery proceedings. The other non-fuel and MISO administrative related costs are to be deferred for recovery as part of the next electric general rate case proceeding.

Gas Cost Recovery (GCR) Audit

On June 14, 2005, the PUCO issued an order disallowing the recovery of approximately $9.6 million of gas costs relating to the two year audit period ended November 2002. That audit period provided the PUCO staff its initial review of the portfolio administration arrangement between VEDO and ProLiance. The disallowance includes approximately $1.3 million relating to pipeline refunds and penalties and approximately $4.5 million of costs for winter delivery services purchased by VEDO to ensure reliability over the two year period. The PUCO also held that ProLiance should have credited to VEDO an additional $3.8 million more than credits actually received for the right to use VEDO’s gas transportation capacity periodically during the periods when it was not required for serving VEDO’s customers. The PUCO also directed VEDO to either submit its receipt of portfolio administration services to a request for proposal process or to in-source those functions.

During the fourth quarter of 2004, the Company recorded a reserve of $1.5 million for this matter. An additional pretax charge of $3.0 million was recorded in Cost of Gas Sold in the second quarter of 2005. The reserve reflects management’s assessment of the impact of the June 14 decision, an estimate of any current impact that decision may have on subsequent audit periods, and an estimate of a sharing in any final disallowance by Vectren’s partner in ProLiance.

Notwithstanding the additional charge, Vectren management believes that there exists a sound basis to challenge the aspects of the decision related to the $4.5 million winter delivery service issue and the $3.8 million portfolio administration issue. VEDO filed its request for rehearing on July 14, 2005, and on August 10, 2005, the PUCO granted rehearing to further consider the $3.8 million portfolio administration issue and all interest on the findings, but denied rehearing on all other aspects of the case. On October 7, 2005, the Company filed an appeal with the Ohio Supreme Court requesting that the $4.5 million disallowance related to the winter delivery service issue be reversed. A schedule to file briefs with the court has yet to be determined. In addition, the Company solicited and received bids for VEDO’s gas supply and portfolio administration services and has selected a third party provider, who began providing services to VEDO on November 1, 2005, under a one year contract.

Commodity Prices

Commodity prices for natural gas purchases are expected to increase for the 2005 - 2006 heating season, primarily due to tight supplies. Subject to compliance with applicable state laws, the Company's utility subsidiaries are allowed recovery of such changes in purchased gas costs from their retail customers through commission-approved gas cost adjustment mechanisms, and margin on gas sales should not be impacted. However, it is reasonably possible that as a result of this near term change in the commodity price for natural gas the Company’s utility subsidiaries will experience increased interest expense due to higher working capital requirements; increased uncollectible accounts expense and unaccounted for gas; and some level of price sensitive reduction in volumes sold. In response to higher gas prices, the Company is seeking to increase its utility-related credit facilities and ProLiance increased its credit facility (See Note 8).

Indiana Decoupling/Conservation Filing

On October 25, 2005, Vectren Energy Delivery of Indiana filed with the IURC for approval of a conservation program and a conservation adjustment rider in its two Indiana service territories. If approved, the plan outlined in the petition will better align the interests of the Company with its customers through the promotion of natural gas conservation. The petition requests the use of a tracker mechanism to recover the costs of funding the design and implementation of conservation efforts, such as consumer education programs and rebates for high efficiency equipment. The conservation tracker works in tandem with a decoupling mechanism. The decoupling mechanism would allow the Company to recover the distribution portion of its rates from residential and commercial customers based on the level of customer usage established in each utility’s last general rate case. The Company proposed that both the conservation tracker and decoupling mechanism begin before the end of 2005. A pre-hearing conference with regard to this matter has not been scheduled.

12.

Impact of Recently Issued Accounting Guidance

SFAS No. 154

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections - a Replacement of APB Opinion No. 20 and FASB Statement No. 3” (SFAS 154). This statement changes the requirements for the accounting for and reporting of a change in accounting principle and applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement in the instance that the pronouncement does not include specific transition provisions. SFAS 154 requires retrospective application to prior periods’ financial statements of the direct effects caused by a change in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. Further, changes in depreciation, amortization or depletion methods for long-lived, nonfinancial assets are to be accounted for as a change in accounting estimate affected by a change in accounting principle. SFAS 154 is effective for accounting changes and corrections made in fiscal years beginning after December 15, 2005, with early adoption permitted. The adoption of this standard, beginning in fiscal year 2006, is not expected to have any material effect on the Company’s operating results or financial condition.

FIN 47

In March 2005, the FASB issued FASB Interpretation No. 47 (FIN 47), an interpretation of SFAS 143. The interpretation is effective for the Company no later than December 31, 2005. FIN 47 clarifies that a legal obligation to perform an asset retirement activity that is conditional on a future event is within SFAS 143’s scope. It also clarifies the meaning of the term “conditional asset retirement obligation” as a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. Accordingly, an entity is required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event if the liability’s fair value can be reasonably estimated. The interpretation provides examples of conditional asset retirement obligations that may need to be recognized under the provisions of FIN 47, including asbestos and utility pole removal and dismantling plant. The interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 requires the reassessment of whether a portion of accrued removal costs should be recharacterized as a liability under generally accepted accounting principles. FIN 47 may also require the accrual of additional liabilities and could result in increased near-term expense. The Company is currently assessing the impact this interpretation will have on its financial statements.

EITF 04-06

At its March 2005 meeting, the EITF Task Force reached a consensus on EITF 04-06, “Accounting for Stripping Costs Incurred during Production in the Mining Industry”(EITF 04-06) that stripping costs incurred during the production phase of a strip mine are variable production costs that should be included in the costs of the inventory produced (that is, extracted) during the period that the stripping costs are incurred. EITF 04-06 is effective for the first reporting period in fiscal years beginning after December 15, 2005, with early adoption permitted. If material, any unamortized costs that cannot be reclassified to inventory must be charged to earnings as a cumulative effect of change in accounting principle. The Company expects that the adoption of EITF 04-06 will have no current impact on its operating results or financial condition.

13.

Segment Reporting

The Company’s utility operations are conducted by Vectren Utility Holdings, Inc, (Utility Holdings) and its nonregulated operations are conducted by Vectren Enterprises, Inc. (Enterprises). In addition, there other unallocated corporate expenses, such as branding and charitable contributions, that benefit both Utility Holdings and Enterprises. Utility Holdings’ consolidated operations are collectively referred to as the Utility Group, and Enterprises’ operations are collectively referred to as the Nonregulated Group.

The operations of the Utility Group consist of the Company’s regulated operations (the Gas Utility Services and Electric Utility Services operating segments), and other operations that provide information technology and other support services to those regulated operations. In total, the Utility Group has three operating segments as defined by SFAS 131, “Disclosure About Segments of an Enterprise and Related Information” (SFAS 131). Gas Utility Services provides natural gas distribution and transportation services in nearly two-thirds of Indiana and to west central Ohio. Electric Utility Services provides electricity primarily to southwestern Indiana, and includes the Company’s power generating and marketing operations. For these regulated operations the Company uses after tax operating income as a measure of profitability, consistent with regulatory reporting requirements. The Company cross manages its regulated operations as separated between Energy Delivery, which includes the gas and electric transmission and distribution functions, and Power Supply, which includes the power generating and marketing operations. For the Utility Group’s other operations, net income is used as the measure of profitability.

The Nonregulated Group is comprised of one operating segment as defined by SFAS 131 that includes various subsidiaries and affiliates offering and investing in energy marketing and services, coal mining and utility infrastructure services, among other broadband and energy-related opportunities.

Unallocated corporate expenses (referred to as Corporate and Other) comprise one operating segment as defined by SFAS 131.

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


		Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)		2005			2004			2005			2004
Revenues
Utility Group
Gas Utility Services	$	136.8		$	112.3		$	839.5		$	771.6
Electric Utility Services		128.7			102.3			320.3			280.2
Other Operations		8.9			7.5			27.1			25.5
Eliminations		(8.7	)		(7.4	)		(26.6	)		(25.0	)
Total Utility Group		265.7			214.7			1,160.3			1,052.3
Nonregulated Group		69.9			61.8			227.8			186.3
Corporate & Other		-			-			-			-
Eliminations		(24.8	)		(22.1	)		(73.9	)		(62.2	)
Consolidated Revenues	$	310.8		$	254.4		$	1,314.2		$	1,176.4

Profitability Measure
Utility Group: Regulated Operating Income
(Operating Income Less Applicable Income Taxes)
Gas Utility Services	$	(2.5	)	$	(4.2	)	$	48.3		$	43.0
Electric Utility Services		24.7			21.7			56.5			48.2
Total Regulated Operating Income		22.2			17.5			104.8			91.2
Regulated other income - net		1.0			1.3			1.2			1.8
Regulated interest expense & preferred dividends		(16.2	)		(15.7	)		(47.3	)		(46.9	)
Regulated Net Income		7.0			3.1			58.7			46.1
Other Operations Net Income		1.9			1.4			6.1			5.8
Utility Group Net Income		8.9			4.5			64.8			51.9
Nonregulated Group Net Income		8.5			5.9			23.1			17.2
Corporate & Other Net Loss		(0.9	)		(0.7	)		(1.9	)		(1.3	)
Consolidated Net Income	$	16.5		$	9.7		$	86.0		$	67.8

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

Description of the Business

Utility Holdings generates revenue primarily from the delivery of natural gas and electric service to its customers. Utility Holdings’ primary source of cash flow results from the collection of customer bills and the payment for goods and services procured for the delivery of gas and electric services. Utility Holdings’ results are impacted by weather patterns in its Indiana and Ohio service territories and general economic conditions both in its service territories as well as nationally.

The Company, through Vectren Enterprises, Inc. (Enterprises), is also involved in nonregulated activities in three primary business areas: Energy Marketing and Services, Coal Mining, and Utility Infrastructure Services. Energy Marketing and Services markets natural gas and provides energy management services, including energy performance contracting services. Coal Mining mines and sells coal and generates IRS Code Section 29 tax credits relating to the production of coal-based synthetic fuels. Utility Infrastructure Services provides underground construction and repair, facilities locating, and meter reading services. In addition, there are other businesses that invest in broadband communication services, energy-related opportunities, real estate, and leveraged leases among other activities. These operations are collectively referred to as the Nonregulated Group. Enterprises supports the Company’s regulated utilities pursuant to service contracts by providing natural gas supply services, coal, utility infrastructure services, and other services.

The Nonregulated Group generates revenue or earnings from the provision of services to customers. The activities of the Nonregulated 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 this discussion and analysis of results of operations, the results of the Utility Group and Nonregulated Group are presented on a per share basis. Such per share amounts are based on the earnings contribution of each group included in Vectren’s consolidated results divided by Vectren’s 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 either group but rather represent a direct equity interest in Vectren Corporation's assets and liabilities as a whole.

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

Executive Summary of Consolidated Results of Operations

The following discussion and analysis should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto.


		Three Months						Nine Months
		Ended September 30,						Ended September 30,
(In millions, except per share data)		2005			2004			2005			2004
Net income	$	16.5		$	9.7		$	86.0		$	67.8
Attributed to:
Utility Group	$	8.9		$	4.5		$	64.8		$	51.9
Nonregulated Group		8.5			5.9			23.1			17.2
Corporate & Other		(0.9	)		(0.7	)		(1.9	)		(1.3	)
Basic earnings per share	$	0.22		$	0.13		$	1.14		$	0.90
Attributed to:
Utility Group	$	0.12		$	0.06		$	0.86		$	0.69
Nonregulated Group		0.11			0.08			0.31			0.23
Corporate & Other		(0.01	)		(0.01	)		(0.03	)		(0.02	)

Results

For the three months ended September 30, 2005, net income was $16.5 million, or $0.22 per share compared to net income of $9.7 million, or $0.13 per share for the same period last year, an increase of $6.8 million. For the nine months ended September 30, 2005, reported earnings were $86.0 million, or $1.14 per share compared to $67.8 million, or $0.90 per share, for the same period in 2004, an increase of $18.2 million.

Utility Group earnings were $8.9 million for the quarter compared to $4.5 million in the prior year and $64.8 million for the nine months ended September 30, 2005 compared to $51.9 million in 2004. The improved performance is primarily due to gas base rate increases implemented in 2004 and early 2005 and higher electric revenues associated with recovery of pollution control investments. In addition, the year-to-date period reflects increased margins from generation asset optimization activities. Gas base rate increases added revenue of $8.1 million, or $4.8 million after tax, during the quarter and $25.1 million, or $14.9 million after tax, for the nine months ended September 30, 2005, compared to the prior year. Increased revenues associated with recovery of pollution control investments, net of related operating and depreciation expense, increased operating income $3.6 million or $2.1 million after tax, for the quarter and $7.4 million, or $4.4 million after tax, for the nine month period. The improved margins were partially offset by higher operating and depreciation expense. The year-to-date 2005 results also reflect a $3.0 million, $1.8 million after tax, charge recorded in the second quarter pursuant to the disallowance of Ohio gas costs.

Management estimates that the after tax impact of weather on third quarter 2005 was favorable $0.2 million and unfavorable $2.5 million in 2004. The unfavorable after tax impact of weather for the nine month periods ended September 30 is estimated to be $3.5 million and $4.9 million for 2005 and 2004, respectively.

For the three and nine months ended September 30, 2005, Nonregulated Group earnings were $8.5 million and $23.1 million, respectively. Increases over the prior year of $2.6 million for the quarter and $5.9 million year-to-date primarily relate to earnings from the Company’s primary business groups: Energy Marketing and Services, Coal Mining, and Utility Infrastructure Services. Earnings from these primary business groups increased by $3.0 million for both the three and nine month periods. The remaining increase in the nine month period relates to net charges in the prior year for the write down of broadband investments and gains recorded from the Company’s investment in the Haddington Energy Partnerships.

Dividends

Dividends declared for the three months ended September 30, 2005, were $0.295 per share compared to $0.285 per share for the same period in 2004. Dividends declared for the nine months ended September 30, 2005, were $0.885 per share compared to $0.855 per share for the same period in 2004.

Detailed Discussion of Results of Operations

Following is a more detailed discussion of the results of operations of the Company’s Utility Group and Nonregulated Group. The detailed results of operations for the Utility Group and Nonregulated Group 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. Corporate and other results are not significant.

Results of Operations of the Utility Group

The Utility Group is comprised of Utility Holdings’ operations. The operations of the Utility Group consist of the Company’s regulated operations and other operations that provide information technology and other support services to those regulated operations. The Company segregates its regulated operations into a Gas Utility Services operating segment and an Electric Utility Services operating segment. The Gas Utility Services segment provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio. The Electric Utility Services segment provides electric distribution services primarily to southwestern Indiana, and includes the Company’s power generating and marketing operations. In total, these regulated operations supply natural gas and/or electricity to nearly one million customers. The results of operations of the Utility Group before certain intersegment eliminations and reclassifications for the three and nine months ended September 30, 2005 and 2004, follow:


		Three Months				Nine Months
		Ended September 30,				Ended September 30,
(In millions, except per share amounts)		2005		2004		2005		2004
OPERATING REVENUES
Gas revenues	$	136.8	$	112.3	$	839.5	$	771.6
Electric revenues		128.7		102.3	$	320.3		280.2
Other revenues		0.2		0.1		0.5		0.5
Total operating revenues		265.7		214.7		1,160.3		1,052.3
OPERATING EXPENSES
Cost of gas		81.6		67.2		568.8		529.8
Fuel for electric generation		39.3		25.8		95.6		72.4
Purchased electric energy		8.8		5.3		14.7		16.6
Other operating		58.9		52.0		179.7		167.7
Depreciation & amortization		36.3		33.1		104.2		94.5
Taxes other than income taxes		10.1		9.6		43.6		42.4
Total operating expenses		235.0		193.0		1,006.6		923.4
OPERATING INCOME		30.7		21.7		153.7		128.9
OTHER INCOME - NET
Equity in earnings of unconsolidated affiliates		-		-		-		0.2
Other income – net		1.3		2.3		4.6		5.7
Total other income - net		1.3		2.3		4.6		5.9
Interest expense		17.5		16.7		50.8		50.2
INCOME BEFORE INCOME TAXES		14.5		7.3		107.5		84.6
Income taxes		5.6		2.8		42.7		32.7
NET INCOME	$	8.9	$	4.5	$	64.8	$	51.9

CONTRIBUTION TO VECTREN BASIC EPS	$	0.12	$	0.06	$	0.86	$	0.69

Utility Group earnings for the third quarter of 2005 were $8.9 million compared to $4.5 million for the same period last year. Utility Group earnings were $64.8 million for the nine months ended September 30, 2005, compared to $51.9 million in the prior year. The $4.4 million and $12.9 million increases for the respective three and nine month periods were primarily due to higher gas base rate revenues from base rate increases implemented in 2004 and early 2005 and higher electric operating income associated with recovery of pollution control investments. In addition, the year-to-date period reflects increased margins from generation asset optimization activities. Increases were partially offset by higher operating and depreciation expense. Year-to-date results also reflect a $3.0 million, $1.8 million after tax, charge recorded in the second quarter pursuant to the disallowance of Ohio gas costs.

For the three and nine months ended September 30, 2005 compared to 2004, incremental revenues associated with gas base rate increases were $8.1 million ($4.8 million after tax) and $25.1 million ($14.9 million after tax), respectively. Incremental operating income associated with recovery of pollution control investments was $2.1 million after tax and $4.4 million after tax, respectively, for the three and nine months ended September 30, 2005 compared to 2004. Weather was estimated to be favorable approximately $2.7 million after tax for the quarter and $1.5 million after tax year-to-date, compared to last year.

Throughout this discussion, the terms Gas Utility margin and Electric Utility margin are used. Gas Utility margin and Electric Utility margin could be considered non-GAAP measures of income. Gas Utility margin is calculated as Gas utility revenues less the Cost of gas. Electric Utility margin is calculated as Electric utility revenues less Fuel for electric generation and Purchased electric energy. These measures exclude Other operating expenses, Depreciation and amortization, and Taxes other than income taxes, which are included in the calculation of operating income. The Company believes Gas Utility and Electric Utility margins are better indicators of relative contribution than revenues since gas prices and fuel costs can be volatile and are generally collected on a dollar-for-dollar basis from customers. Margins should not be considered an alternative to, or a more meaningful indicator of, operating performance than operating income or net income as determined in accordance with accounting principles generally accepted in the United States.

Significant Fluctuations

Utility Group Margin

Margin generated from the sale of natural gas and electricity to residential and commercial customers is seasonal and impacted by weather patterns in the Company’s service territories. Margin generated from sales to large customers (generally industrial, other contract, and firm wholesale customers) is primarily impacted by overall economic conditions. Margin is also impacted by the collection of state taxes, which fluctuate with gas costs, and is also impacted by some level of price sensitivity in volumes sold. Electric generating asset optimization activities are primarily affected by market conditions, the level of excess generating capacity, and electric transmission availability. Following is a discussion and analysis of margin generated from regulated utility operations.

Gas Utility Margin (Gas Utility Revenues less Cost of Gas Sold)

Gas Utility margin and throughput by customer type follows:


		Three Months					Nine Months
		Ended September 30,					Ended September 30,
(In millions)		2005		2004			2005		2004

Residential & Commercial	$	44.8	$	36.5		$	230.4	$	205.9
Industrial		9.1		8.8			34.4		32.9
Other		1.3		(0.2	)		5.9		3.0
Total gas utility margin	$	55.2	$	45.1		$	270.7	$	241.8

Sold & transported volumes in MMDth:
To residential & commercial customers		6.8		7.0			75.3		78.9
To industrial customers		17.4		17.1			63.4		62.4
Total throughput		24.2		24.1			138.7		141.3

Gas utility margins were $55.2 million and $270.7 million for the three and nine months ended September 30, 2005. This represents an increase in gas utility margin in the third quarter, a non-heating base load quarter, of $10.1 million and a year-to-date increase of $28.9 million compared to the same periods in 2004. The increases are primarily due to the favorable impact of gas base rate increases. Year-to-date results were also impacted by additional pass through expenses and revenue taxes recovered in margins of $2.4 million and $0.6 million, respectively, compared to last year. Year-to-date results reflect a $3.0 million additional charge recorded in the second quarter of 2005 as the estimated impact of the disallowance of Ohio gas costs ordered by the PUCO. In the fourth quarter of 2004, the Company had previously recorded a charge of $1.5 million with respect to the matters raised in the order.

For the nine month period, weather was 9% warmer and similar to the prior year and decreased margin an estimated $0.7 million compared to 2004. Gas sold and transported volumes were 2% lower for the nine months ended September 30, 2005 as compared to last year primarily due to reduced residential volumes. The average cost per dekatherm of gas purchased for the nine months ended September 30, 2005, was $7.79 compared to $6.76 in 2004.

Electric Utility Margin (Electric Utility Revenues less Fuel for Electric Generation and Purchased Electric Energy)

Electric Utility margin by revenue type follows:


		Three Months				Nine Months
		Ended September 30,				Ended September 30,
(In millions)		2005		2004		2005		2004

Residential & commercial	$	54.4	$	45.5	$	131.2	$	120.2
Industrial		18.0		16.9		49.6		47.5
Municipalities & other		4.9		4.5		14.1		13.9
Total retail & firm wholesale		77.3		66.9		194.9		181.6
Asset optimization		3.3		4.3		15.1		9.6
Total electric utility margin	$	80.6	$	71.2	$	210.0	$	191.2

Retail & Firm Wholesale Margin

Electric retail and firm wholesale utility margins were $77.3 million and $194.9 million for the three and nine months ended September 30, 2005. This represents an increase over the prior year periods of $10.4 million and $13.3 million, respectively. The recovery of pollution control related investments and associated operating expenses and related depreciation increased margins $5.4 million quarter over quarter and $11.5 million for the nine month period. Cooling weather for the quarter and nine months ended was 14% and 7% warmer than normal, respectively. Cooling weather, compared to last year, was 50% and 19% warmer for the three and nine months ended September 30, 2005, respectively. The estimated increase in margins due to weather was $5.0 million and $3.2 million for the three and nine month periods, respectively, compared to the prior year. Retail residential and commercial volumes sold increased 15 percent during the quarter and 3 percent for the nine month period. Industrial sales volumes sold increased 5 percent during the quarter and 2 percent for the nine month period. During the nine months ended September 30, 2005, volumes sold to residential, commercial, and industrial customers were 4,738.4 GWh compared to 4,596.1 GWh in 2004.

Margin from Asset Optimization Activities

Periodically, generation capacity is in excess of that needed to serve native load and firm wholesale customers. The Company markets this unutilized capacity to optimize the return on its owned generation assets. Substantially the entire margin from these activities is generated from contracts that are integrated with portfolio requirements around power supply and delivery and are short-term purchase and sale transactions that expose the Company to limited market risk.

Following is a reconciliation of asset optimization activity:


		Three Months						Nine Months
		Ended September 30,						Ended September 30,
(In millions)		2005			2004			2005			2004
Beginning of Period Net Balance Sheet Position	$	3.2		$	2.2		$	(0.6	)	$	(0.4	)
Statement of Income Activity
Net mark-to-market (losses) gains realized		(1.4	)		(1.8	)		1.4			(1.0	)
Net realized gains		4.7			6.1			13.7			10.6
Asset optimization margin		3.3			4.3			15.1			9.6
Net cash received & other adjustments		(4.9	)		(6.8	)		(12.9	)		(9.5	)
End of Period Net Balance Sheet Position	$	1.6		$	(0.3	)	$	1.6		$	(0.3	)

For the three and nine month periods ended September 30, 2005, net asset optimization margins were $3.3 million and $15.1 million, which represents a decrease for the quarter of $1.0 million and a year-to-date increase of $5.5 million, as compared to 2004. Increased retail load experienced during the three months ended September 30, 2005, reduced available wholesale capacity. The increase in year-to-date margin results primarily from an increase in available capacity and mark to market gains. The availability of excess capacity was reduced in 2004 by scheduled outages of owned generation related to the installation of environmental compliance equipment.

Utility Group Operating Expenses

Other Operating

Other operating expenses for the three and nine months ended September 30, 2005, increased $6.9 million and $12.0 million, respectively, compared to 2004. The increases are primarily attributable to compensation and benefit costs increases, including performance and share-based compensation, of $2.8 million for the quarter and $5.5 million year-to-date. Amortization of rate case expenses, expenses associated with Ohio “Choice” and integrity management programs and expenses recovered directly in margin such as bad debt expense in Ohio and NOx related operating expenses increased $1.7 million during the quarter and $5.2 million year to date. The quarter was also impacted by an additional $1.5 million of bad debt expense related to the Company’s Indiana service territories when compared to the prior year, bringing the year-to-date bad debt expense to $6.4 million in 2005, compared to $6.8 million in 2004.

Depreciation & Amortization

Depreciation expense increased $3.2 million and $9.7 million for the three and nine month periods ended September 30, 2005, as compared to 2004. In addition to depreciation on additions to plant in service, the increases were primarily due to incremental depreciation expense associated with environmental compliance equipment additions of $1.5 million for the quarter and $4.5 million for the year to date period, respectively,. Year-to-date 2004 was also $1.8 million lower due to an adjustment of Ohio depreciation rates and amortization of Indiana regulatory assets.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $0.5 million and $1.2 million for the three and nine months ended September 30, 2005, respectively, compared to 2004. The year to date increase is primarily attributable to revenue taxes resulting from higher revenues.

Utility Group Income Taxes

For the three and nine months ended September 30, 2005, Federal and state income taxes increased $2.8 million and $10.0 million, respectively, primarily due to higher pre-tax income.

Environmental Matters

Clean Air Act

NOx SIP Call Matter

The IURC has issued orders that approve:

·	the Company’s project to achieve environmental compliance by investing in clean coal technology;

·	a total capital cost investment for this project up to $250 million (excluding AFUDC and administrative overheads), subject to periodic review of the actual costs incurred;

·	a mechanism whereby, prior to an electric base rate case, the Company may recover through a rider that is updated every six months, an 8% return on its weighted capital costs for the project; and

·	ongoing recovery of operating costs, including depreciation and purchased emission allowances, related to the clean coal technology once the facility is placed into service.

Through September 30, 2005, capital investments approximating the level approved by the IURC have been made. Related operating expenses, including depreciation expense, are estimated to be between $24 million and $27 million once the installed equipment is operational for an entire year.

Clean Air Interstate Rule & Clean Air Mercury Rule

Information Request

Manufactured Gas Plants

With respect to insurance coverage, Indiana Gas has received and recorded settlements from all known insurance carriers in an aggregate amount approximating $20.4 million.

Jacobsville Superfund Site

Rate & Regulatory Matters

Normal Temperature Adjustment Order

Gas Utility Base Rate Settlements

MISO

As a result of MISO’s operational control over much of the Midwestern electric transmission grid, including SIGECO’s transmission facilities, SIGECO’s continued ability to import power, when necessary, and export power to the wholesale market has been, and may continue to be, impacted. Given the nature of MISO’s policies regarding use of transmission facilities, as well as ongoing FERC initiatives and uncertainties around Day 2 energy market operations, it is difficult to predict near term operational impacts. However, as stated above, it is believed that MISO’s regional operation of the transmission system will ultimately lead to reliability improvements.

The potential need to expend capital for improvements to the transmission system, both to SIGECO’s facilities as well as to those facilities of adjacent utilities, over the next several years will become more predictable as MISO completes studies related to regional transmission planning and improvements. Such expenditures may be significant.

Gas Cost Recovery (GCR) Audit

Indiana Decoupling/Conservation Filing

Other Operating Matters

United States Securities and Exchange Commission Inquiry into PUHCA Exemption

On August 8, 2005, comprehensive energy legislation, the Domenici - Barton Energy Policy Act of 2005 (Energy Act), was signed into law. Among other things, the Energy Act provides for the repeal of PUHCA effective six months after its enactment, in February 2006. The Energy Act gives the FERC the ability to regulate holding companies previously regulated by PUHCA. Although the Company cannot be certain how the FERC will implement any final regulations, such regulations, as they are currently proposed, are not expected to materially affect the Company’s financial position or operations.

Results of Operations of the Nonregulated Group

The Nonregulated Group is comprised of Vectren Enterprises’ operations. The Nonregulated Group operates in three primary business areas: Energy Marketing and Services, Coal Mining, and Utility Infrastructure Services. Energy Marketing and Services markets natural gas and provides energy management services, including energy performance contracting services. Coal Mining mines and sells coal and generates IRS Code Section 29 tax credits relating to the production of coal-based synthetic fuels. Utility Infrastructure Services provides underground construction and repair, facilities locating, and meter reading services. In addition, there are other businesses that invest in broadband communication services, energy-related opportunities, real estate, and leveraged leases, among other activities. The Nonregulated Group supports the Company’s regulated utilities pursuant to service contracts by providing natural gas supply services, coal, utility infrastructure services, and other services. The results of operations of the Nonregulated Group for the three and nine months ended September 30, 2005 and 2004, follow:


		Three Months						Nine Months
		Ended September 30,						Ended September 30,
(In millions, except per share amounts)		2005			2004			2005			2004

NET INCOME	$	8.5		$	5.9		$	23.1		$	17.2

CONTRIBUTION TO VECTREN BASIC EPS	$	0.11		$	0.08		$	0.31		$	0.23
NET INCOME (LOSS) ATTRIBUTED TO:
Energy Marketing & Services	$	3.3		$	1.2		$	10.0		$	9.1
Coal Mining		4.9			3.6			14.0			11.1
Utility Infrastructure		1.0			1.4			0.5			1.3
Other Businesses		(0.7	)		(0.3	)		(1.4	)		(4.3	)

For the three and nine months ended September 30, 2005, Nonregulated Group earnings were $8.5 million and $23.1 million, respectively. Increases over the prior year of $2.6 million for the quarter and $5.9 million year-to-date primarily relate to earnings from the Company’s primary business groups: Energy Marketing and Services, Coal Mining, and Utility Infrastructure Services. The 2004 year-to-date period also reflect broadband related impairment changes, net of gains from the Company’s investment in the Haddington Energy Partnerships.

Energy Marketing & Services

Energy Marketing and Services is comprised of the Company’s gas marketing operations, performance contracting operations, and retail gas supply operations.

Gas marketing operations are performed through the Company’s investment in ProLiance Energy LLC (ProLiance). ProLiance, a nonregulated energy marketing affiliate of Vectren and Citizens Gas and Coke Utility (Citizens Gas), 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 utilities and nonregulated gas supply operations and Citizens Gas. ProLiance’s primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services. The Company accounts for its investment in ProLiance using the equity method of accounting.

As required by a June 14, 2005, PUCO order (See Utility Holdings, Rate and Regulatory Matters discussion), VEDO solicited bids for its gas supply/portfolio administration services and has selected a different provider under a one year contract. ProLiance’s obligation to supply these services to VEDO ended October 31, 2005. The Company believes this change will not materially affect ProLiance’s or Vectren’s future earnings, financial position, or cash flows.

Energy Systems Group, LLC (ESG), a wholly owned subsidiary, provides energy performance contracting and facility upgrades through its design and installation, as well as operation, of energy-efficient equipment throughout the Midwest and Southeast United States.

Vectren Retail, LLC (d/b/a Vectren Source), a wholly owned subsidiary, provides natural gas and other related products and services in Ohio and Indiana, serving approximately 120,000 customers opting for choice among energy providers.

Net income generated by Energy Marketing and Services for the quarter ended September 30, 2005, was $3.3 million compared to $1.2 million in 2004. Net income generated by Energy Marketing and Services for the nine months ended September 30, 2005, was $10.0 million compared to $9.1 million in 2004. In the periods presented, gas marketing operations, performed through ProLiance, provided the primary earnings contribution, totaling $4.9 million for the quarter ended September 30, 2005 and $13.4 million year-to-date. ProLiance increased its earnings contribution over 2004 by $3.3 million for the quarter and $3.2 million for the year-to-date period, primarily due to increased arbitrage opportunities provided by wider basis differentials between physical and financial markets during the quarter. Year-to-date results reflect pre-verdict legal fees associated with litigation between ProLiance and the City of Huntsville Alabama (Huntsville Utilities). The increased earnings from ProLiance have been partially offset by ESG net losses of $1.1 million during the year-to-date period. In the quarter ended September 30, 2005, ESG contributed earnings of $0.3 million. These results represent decreases from the prior year of approximately $1.1 million during the quarter and $2.3 million year-to-date and are primarily attributable to the delay in the closing of new contracts and increased overhead from the Progress Energy Solutions’ acquisition completed in 2004. For the quarter, Vectren Source’s retail gas supply operations operated at a seasonal loss of $0.9 million, compared to losses of $1.2 million last year. Year-to-date, Vectren Source’s losses totaled $0.6 million in 2005 compared to losses of $0.9 million in 2004. Margin from customer growth of approximately 30,000 year over year was offset by the impact of warmer than normal weather, primarily in the first quarter.

ProLiance Contingency

In early 2005, a jury trial commenced and on February 10, 2005, the jury returned a verdict largely in favor of Huntsville Utilities and awarded Huntsville Utilities compensatory damages of $8.2 million and punitive damages of $25.0 million. The jury rejected Huntsville Utilities’ claim of conversion. The jury also rejected a counter claim by ProLiance for payment of amounts due from Huntsville Utilities. Following that verdict, there were a number of issues presented to the judge for resolution. Huntsville made a claim under federal law that it was entitled to have the compensatory damage award trebled. The judge rejected that request. ProLiance made a claim against Huntsville for unjust enrichment, which was also rejected by the judge. The judge also determined that attorneys’ fees and prejudgment interest are owed by ProLiance to Huntsville Utilities. The verdict, as affected by the judge’s subsequent rulings, totals $38.9 million, and ProLiance has posted an appeal bond for that estimated amount. . ProLiance’s management believes there are reasonable grounds for appeal which offer a basis for reversal of the entire verdict, and initiated the appeal process on July 26, 2005. The appeal is not likely to be fully briefed until early 2006, and an appellate decision may be issued in the second half of 2006.

Commodity Prices

Coal Mining

The Coal Mining group mines and sells coal to the Company’s utility operations and to third parties through its wholly owned subsidiary Vectren Fuels, Inc. (Fuels). The Coal Mining Group also generates IRS Code Section 29 tax credits resulting from the production of coal-based synthetic fuels through its 8.3% ownership interest in Pace Carbon Synfuels, LP (Pace Carbon). In addition, Fuels receives synfuel-related fees from synfuel producers unrelated to Pace Carbon for a portion of its coal production.

Coal Mining net income for the three months ended September 30, 2005, was $4.9 million compared to $3.6 million in 2004. Coal Mining net income for the nine months ended September 30, 2005, was $14.0 million compared to $11.1 million in 2004. Earnings from the mining operations were $1.6 million and $0.2 million for the quarter ended September 30, 2005 and 2004, respectively. Mining operations contributed $4.2 million and $1.5 million for the nine month periods ended September 30, 2005 and 2004, respectively. Despite rising costs for steel, explosives and fuel, mining operations increased $1.4 million for the quarter and $2.7 million year-to-date, primarily due to higher productivity, improved yield, and higher prices. Synfuel-related quarterly results, which include earnings from Pace Carbon and synfuel processing fees earned by Fuels, were $3.3 million and $9.8 million for the quarter and nine months of 2005 and have varied slightly over the prior year.

IRS Section 29 Tax Credit Recent Developments

Utility Infrastructure Services

Utility Infrastructure Services provides underground construction and repair to gas, water, and telecommunications companies primarily through its investment in Reliant Services, LLC (Reliant) and Reliant’s 100 percent ownership in Miller Pipeline Corporation. Reliant is a 50 percent owned strategic alliance with an affiliate of Cinergy Corporation. and is accounted for using the equity method of accounting. For the three and nine months ended September 30, 2005, Infrastructure’s net income decreased $0.4 million and $0.8 million, respectively, compared to the same periods last year. These year-to-date and quarterly decreases are primarily attributable to fewer large pipeline projects and customer requested delays in the start of awarded waste water projects.

Other Businesses

The Other Businesses Group includes a variety of operations and investments including investments in Broadband and the Haddington Energy Partnerships (Haddington). Broadband invests in communication services, such as cable television, high-speed internet, and advanced local and long distance phone services.

Other Businesses reported a net loss of $0.7 million for the three months ended September 30, 2005, compared to a net loss of $0.3 million in 2004. For the nine months ended September 30, 2005, Other Businesses reported a net loss of $1.4 million compared to a net loss of $4.3 million in 2004. The 2004 losses result principally from transactions occurring that involved the Company’s investment in Haddington and a writedown of the Company’s broadband investments.

In 2004, the Company recorded broadband-related impairment charges totaling $6.0 million after tax. In addition, in 2004, the Company recorded a net after tax gain related to its investments in Haddington Energy Partnerships of $1.8 million.

Impact of Recently Issued Accounting Guidance

SFAS No. 154

SFAS 123 (revised 2004) and related interpretations

FIN 47

In March 2005, the FASB issued FASB Interpretation No. 47 (FIN 47), an interpretation of SFAS 143. The interpretation is effective for the Company no later than December 31, 2005. FIN 47 clarifies that a legal obligation to perform an asset retirement activity that is conditional on a future event is within SFAS 143’s scope. It also clarifies the meaning of the term “conditional asset retirement obligation” as a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. Accordingly, an entity is required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event if the liability’s fair value can be estimated reasonably. The interpretation provides examples of conditional asset retirement obligations that may need to be recognized under the provisions of FIN 47, including asbestos and utility pole removal and dismantling plant. The interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 requires the reassessment of whether a portion of accrued removal costs should be recharacterized as a liability under generally accepted accounting principles. FIN 47 may also require the accrual of additional liabilities and could result in increased near-term expense. The Company is currently assessing the impact this interpretation will have on its financial statements.

EITF 04-06

Financial Condition

Within Vectren’s consolidated group, Utility Holdings funds the short-term and long-term financing needs of the Utility Group, and Vectren Capital Corp. (Vectren Capital) funds short-term and long-term financing needs of the Nonregulated Group and other corporate operations. Vectren Corporation guarantees Vectren Capital’s debt, but does not guarantee Utility Holdings’ debt. Vectren Capital’s long-term and short-term obligations outstanding at September 30, 2005, totaled $113.0 million and $121.1 million, respectively. Utility Holdings’ outstanding long-term and short-term borrowing arrangements are jointly and severally guaranteed by Indiana Gas, SIGECO, and VEDO. Utility Holdings’ long-term and short-term obligations outstanding at September 30, 2005, totaled $550.0 million and $248.0 million, respectively. Additionally, prior to Utility Holdings’ formation, Indiana Gas and SIGECO funded their operations separately, and therefore, have long-term debt outstanding funded solely by their operations.

The Company’s common stock dividends are primarily funded by utility operations. Nonregulated operations have demonstrated sustained profitability and the ability to generate cash flows. These cash flows are primarily reinvested in other nonregulated 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.

Utility Holdings’ and Indiana Gas’ credit ratings on outstanding senior unsecured debt at September 30, 2005, are A-/Baa1 as rated by Standard and Poor's Ratings Services (Standard and Poor’s) and Moody’s Investors Service (Moody’s), respectively. SIGECO’s credit ratings on outstanding senior unsecured debt are A-/Baa1. SIGECO's credit ratings on outstanding secured debt are A/A3. Utility Holdings’ commercial paper has a credit rating of A-2/P-2. Vectren Capital’s senior unsecured debt is rated BBB+/Baa2. Although the parent company has no debt outstanding, Standard and Poor’s rates Vectren as A-. The current outlook of both Moody’s and Standard and Poor’s is stable and are categorized as investment grade. Standard and Poor’s revised its current outlook to stable from negative in January 2005 and in March 2005 revised SIGECO’s secured debt rating to A from A- and its unsecured debt to A- from BBB+. 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% of total capitalization. This objective may have varied, and will vary, depending on particular business opportunities, capital spending requirements, and seasonal factors that affect the Company’s operations. The Company’s equity component was 51% of total capitalization, including current maturities of long-term debt and long-term debt subject to tender, at both September 30, 2005, and December 31, 2004, respectively.

Financing Transactions

Utility Holdings

In anticipation of a debt issuance to occur in 2005 or early in 2006, Utility Holdings filed a shelf registration statement with the Securities and Exchange Commission for $275 million aggregate principal amount of unsecured senior notes in October 2005 and has executed forward starting interest rate swaps with a notional value of $75 million that expire in December 2005. When issued, the unsecured notes will be guaranteed by Utility Holdings’ three operating utility companies: SIGECO, Indiana Gas, and VEDO. These guarantees of Utility Holdings’ debt will be full and unconditional and joint and several.

Vectren Capital Corp.

On October 11, 2005, Vectren and Vectren Capital Corp., its wholly-owned subsidiary (Vectren Capital), entered into a private placement Note Purchase Agreement (2005 Note Purchase Agreement) pursuant to which various institutional investors have agreed to purchase the following tranches of notes from Vectren Capital: (i) $25 million 4.99% Guaranteed Senior Notes, Series A due 2010, (ii) $25 million 5.13% Guaranteed Senior Notes, Series B due 2012 and (iii) $75 million 5.31% Guaranteed Senior Notes, Series C due 2015. These Guaranteed Senior Notes will be unconditionally guaranteed by Vectren, the parent of Vectren Capital. Subject to the satisfaction of customary conditions precedent, this financing is scheduled to close on or about December 15, 2005. This Note Purchase Agreement contains customary representations, warranties and covenants, including a covenant to the effect that the ratio of consolidated total debt to consolidated total capitalization will not exceed 75%.

Sources & Uses of Liquidity

Operating Cash Flow

The Company’s primary and historical source of liquidity to fund working capital requirements has been cash generated from operations, which for the nine months ended September 30, 2005 and 2004, was $268.9 million and $206.6 million, respectively. The increase of $62.3 million is primarily the result of increased earnings before non-cash charges and recovery of deferred natural gas and fuel costs.

Financing Cash Flow

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

Cash flow required for financing activities was $111.6 million for the nine months ended September 30, 2005 compared to $37.8 million in the prior period. The increased requirements include the repayment of short term borrowings and increased common stock dividends compared to 2004. In 2005, short-term borrowings have been retired with the greater operating cash flow.

Investing Cash Flow

Cash flow required for investing activities was $162.8 million for the nine months ended September 30, 2005 compared to $176.3 million in 2004. For the nine months ended September 30, 2005 and 2004, requirements for capital expenditures were $158.4 million and $189.3 million, respectively. The decrease in capital expenditures reflects the near completion of pollution control investments addressing NOx compliance. In addition, greater unconsolidated affiliate distributions were received in 2004 due to an approximate $13 million distribution from the Haddington Energy Partnerships, which it generated from a 2004 first quarter sale of an investment.

Available Sources of Liquidity

At September 30, 2005, the Company has $615.0 million of short-term borrowing capacity, including $355.0 million for the Utility Group and $260.0 million for the wholly owned Nonregulated Group and corporate operations, of which approximately $107.0 million is available for the Utility Group operations and approximately $139.0 million is available for the wholly owned Nonregulated Group and corporate operations.

The Company periodically issues new shares to satisfy dividend reinvestment plan and stock option plan requirements. New issuances added additional liquidity of $4.5 million in 2004.

In response to higher natural gas prices, Utility Holdings is seeking to increase its available short-term borrowing capacity from the current level of $355 million to the $475 million level. The Company has obtained commitments from multiple lenders to expand the facility beyond the level sought and is likely to accept a portion of those commitments in excess of the $475 million level. In addition, Utility Holdings expects to extend the maturity of this amended credit facility until November, 2010. Completion of the amendments to its short-term credit facility is expected in mid November, 2005.

Potential Uses of Liquidity

Planned Capital Expenditures & Investments

Investments in nonregulated unconsolidated affiliates and total company capital expenditures for the remainder of 2005 are estimated to be approximately $117.0 million.

Ratings Triggers

At September 30, 2005, $113.0 million of Vectren Capital’s senior unsecured notes were subject to cross-default and ratings trigger provisions that would provide that the full balance outstanding is subject to prepayment if the ratings of Indiana Gas or SIGECO declined to BBB/Baa2. In addition, accrued interest and a make whole amount based on the discounted value of the remaining payments due on the notes would also become payable. The credit rating of Indiana Gas’ senior unsecured debt and SIGECO’s secured debt remains one level and three levels, respectively, above the ratings trigger. These ratings triggers were eliminated in October 2005 in conjunction with long-term debt transactions described above.

Other Guarantees and Letters of Credit

In the normal course of business, Vectren Corporation issues guarantees to third parties on behalf of its consolidated subsidiaries and unconsolidated affiliates. Such guarantees allow those subsidiaries and affiliates to execute transactions on more favorable terms than the subsidiary or affiliate could obtain without such a guarantee. Guarantees may include posted letters of credit, leasing guarantees, and performance guarantees. As of September 30, 2005, guarantees issued and outstanding on behalf of unconsolidated affiliates approximated $6 million. In addition, the Company has also issued a guarantee approximating $4 million related to the residual value of an operating lease that expires in 2006. Through September 30, 2005, the Company has not been called upon to satisfy any obligations pursuant to its guarantees.

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” and similar expressions are intended to identify forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause the Company’s actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:

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

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

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

·	Increased natural gas 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.

The performance of projects undertaken by the Company’s nonregulated businesses and the success of efforts to invest in and develop new opportunities, including but not limited to, the realization of Section 29 income tax credits and the Company’s coal mining, gas marketing, and broadband strategies.

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

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

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

·	Costs and other effects of legal and administrative proceedings, settlements, investigations, claims, and other matters, including, but not limited to, those described in Management’s Discussion and Analysis of Results of Operations and Financial Condition.

·	Changes in Federal, state or local legislature requirements, such as changes in tax laws or rates, environmental laws and regulations.

The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of changes in actual results, changes in assumptions, or other factors affecting such statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Additional information on market-related risks are set forth in Item 7A Qualitative and Quantitative Disclosures About Market Risk included in the Vectren 2004 Form 10-K.

ITEM 4. CONTROLS AND PROCEDURES

Changes in Internal Controls over Financial Reporting

During the quarter ended September 30, 2005, 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 controls over financial reporting.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

As of September 30, 2005, 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 at providing reasonable assurance that material information relating to the Company required to be disclosed by the Company in its filings under the Securities Exchange Act of 1934 (Exchange Act) is brought to their attention on a timely basis.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The Company is party to various legal proceedings arising in the normal course of business. In the opinion of management, there are no legal proceedings pending against the Company that are likely to have a material adverse effect on its financial position. See the notes to the consolidated financial statements regarding investments in unconsolidated affiliates, commitments and contingencies, environmental matters, and rate and regulatory matters. The consolidated condensed financial statements are included in Part 1 Item 1.

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

Periodically, the Company purchases shares from the open market to satisfy share requirements associated with the Company’s share-based compensation plans. The following chart contains information regarding open market purchases made by the Company to satisfy share-based compensation requirements during the quarter ended September 30, 2005.


			Total Number of	Maximum Number
	Number of		Shares Purchased as	of Shares That May
	Shares	Average Price	Part of Publicly	Be Purchased Under
Period	Purchased	Paid Per Share	Announced Plans	These Plans
July 1-31	18,206	$28.87	-	-
August 1-31	14,628	$28.98	-	-
September 1-30	-	-	-	-

ITEM 6. EXHIBITS

Certifications

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

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

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

SIGNATURES

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

VECTREN CORPORATION
Registrant




	November 3, 2005	/s/ Jerome A. Benkert, Jr.
		Jerome A. Benkert, Jr.
		Executive Vice President &
		Chief Financial Officer
		(Principal Financial Officer)



		/s/ M. Susan Hardwick
		M. Susan Hardwick
		Vice President & Controller
		(Principal Accounting Officer)

/s/ Jerome A. Benkert, Jr.		/s/ Niel C. Ellerbrook
(Signature of Authorized Officer)		(Signature of Authorized Officer)
Jerome A. Benkert, Jr.		Niel C. Ellerbrook
(Typed Name)		(Typed Name)
Executive Vice President & Chief Financial Officer		Chairman, President, & Chief Executive Officer
(Title)		(Title)