8-K

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of

The Securities Exchange Act of 1934

Date of Report (Date of earliest event reported) April 5, 2006

VECTREN CORPORATION

(Exact name of registrant as specified in its charter)

Commission File No.	Registrant, State of Incorporation, Address, and Telephone Number	I.R.S Employer Identification No.
1-15467	Vectren Corporation	35-2086905
	(An Indiana Corporation)
	One Vectren Square
	Evansville, Indiana 47708
	(812) 491-4000
1-16739	Vectren Utility Holdings, Inc.	35-2104850
	(An Indiana Corporation)
	One Vectren Square
	Evansville, Indiana 47708
	(812) 491-4000

Former name or address, if changed since last report: N/A

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 7.01 Regulation FD Disclosure

Included herein are the audited financial statements of Southern Indiana Gas & Electric Company (SIGECO) and Indiana Gas Company, Inc. (Indiana Gas), wholly owned subsidiaries of Vectren Utility Holdings, Inc. (Utility Holdings). Utility Holdings is a wholly owned subsidiary of Vectren Corporation (the Company).

The SIGECO and Indiana Gas financial statements include footnotes thereto, abbreviated analysis of results of operations, segment information and operating statistics. The financial statements of SIGECO are included as Exhibit 99.1 and the Indiana Gas financial statements are included as Exhibit 99.2 to this Current Report on Form 8-K. These financial statements are not intended to comply with Regulation S-X or Regulation S-K as neither SIGECO nor Indiana Gas are registrants.

In accordance with SEC Release No. 33-8176, the information contained in the audited financial statements shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended.

In connection with the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995, the Company is hereby furnishing cautionary statements identifying important factors that could cause actual results of the Company and its subsidiaries, including Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., and Southern Indiana Gas and Electric Company, to differ materially from those projected in forward-looking statements of the Company and its subsidiaries made by, or on behalf of, the Company and its subsidiaries. These cautionary statements are attached as Exhibit 99.3.

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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 hereunto duly authorized.

	VECTREN CORPORATION  VECTREN UTILITY HOLDINGS, INC.
April 5, 2006
		By: /s/ M. Susan Hardwick
		M. Susan Hardwick
		Vice President and Controller

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INDEX TO EXHIBITS

Exhibit Number	Description
99.1	Financial statements of Southern Indiana Gas & Electric Company, Inc.
99.2	Financial statements of Indiana Gas Company, Inc.
99.3	Cautionary Statement for Purposes of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995

EX-99.1

Ex. 99.1

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

REPORTING PACKAGE

For the year ended December 31, 2005

Contents

	Page Number
Audited Financial Statements
Independent Auditors’ Report	2
Balance Sheets	3-4
Statements of Income	5
Statements of Cash Flows	6
Statements of Common Shareholder’s Equity	7
Notes to Financial Statements	8
Results of Operations	24
Selected Operating Statistics	28

Additional Information

This annual reporting package should be read in conjunction with the annual reports of Vectren Corporation (Vectren) and Vectren Utility Holdings, Inc. (Utility Holdings), the parent companies of SIGECO, filed on report Form 10-K for the year ended December 31, 2005. Vectren and Utility Holdings make available their Securities and Exchange Commission filings and recent annual reports free of charge through Vectren’s website at www.vectren.com.

Frequently Used Terms

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	SFAS: Statement of Financial Accounting Standards
IURC: Indiana Utility Regulatory Commission	USEPA: United States Environmental Protection Agency
MCF / MMCF / BCF: thousands / millions / billions of cubic feet	Throughput:combined gas sales and gas transportation volumes
MDth / MMDth: thousands / millions of dekatherms

INDEPENDENT AUDITORS’ REPORT

To the Shareholder and Board of Directors of Southern Indiana Gas & Electric Company:

We have audited the accompanying balance sheets of Southern Indiana Gas & Electric Company (the “Company”) as of December 31, 2005 and 2004, and the related statements of income, common shareholder’s equity, and cash flows for the years then ended.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing standards as established by the Auditing Standards Board (United States) and in accordance with the auditing standards of the Public Company Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting.  Accordingly, we express no such opinion.An audit also includes examining,on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Southern Indiana Gas & Electric Company as of December 31, 2005 and 2004, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. 

DELOITTE & TOUCHE LLP

Indianapolis, Indiana

February 16, 2006

March 22, 2006 (as to Note 5)

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FINANCIAL STATEMENTS

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

BALANCE SHEETS

(In thousands)

	December 31,
	2005		2004
ASSETS
Utility Plant
Original cost	$	1,899,535	$	1,804,843
Less: Accumulated depreciation & amortization		798,727		761,256
Net utility plant		1,100,808		1,043,587
Current Assets
Cash & cash equivalents		1,123		1,777
Accounts receivable - less reserves of $1,290 &
$1,148 respectively		50,756		54,813
Receivables from other Vectren companies		374		1,547
Accrued unbilled revenues		40,725		36,402
Inventories		48,182		41,228
Recoverable fuel & natural gas costs		10,411		-
Prepayments & other current assets		18,393		3,032
Total current assets		169,964		138,799
Investments in unconsolidated affiliates		150		150
Other investments		6,768		9,481
Non-utility property - net		3,367		3,568
Goodwill - net		5,557		5,557
Regulatory assets		56,256		50,252
Other assets		912		83
TOTAL ASSETS	$	1,343,782	$	1,251,477

The accompanying notes are an integral part of these financial statements

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SOUTHERN INDIANA GAS & ELECTRIC COMPANY

BALANCE SHEETS

(In thousands)

	December 31,
	2005		2004
LIABILITIES & SHAREHOLDER'S EQUITY
Common shareholder's equity
Common stock (no par value)	$	253,263	$	128,263
Retained earnings		272,240		265,935
Accumulated comprehensive income		4,050		-
Total common shareholder's equity		529,553		394,198
Cumulative redeemable preferred stock		-		112
Long-term debt payable to third parties - net of
debt subject to tender		226,144		226,028
Long-term debt payable to Utility Holdings		148,465		148,484
Total long-term debt, net		374,609		374,512
Commitments & Contingencies (Notes 3, 6, 7 & 8)
Current Liabilities
Accounts payable		34,489		37,159
Accounts payable to affiliated companies		21,780		11,266
Payables to other Vectren companies		7,467		8,800
Refundable fuel & natural gas costs		-		6,322
Accrued liabilities		40,755		32,610
Short-term borrowings		-		339
Short-term borrowings payable to Utility Holdings		93,343		170,171
Total current liabilities		197,834		266,667
Deferred Income Taxes & Other Liabilities
Deferred income taxes		133,758		121,917
Regulatory liabilities		55,380		51,439
Deferred credits & other liabilities		52,648		42,632
Total deferred income taxes & other liabilities		241,786		215,988
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	1,343,782	$	1,251,477

The accompanying notes are an integral part of these financial statements

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SOUTHERN INDIANA GAS & ELECTRIC COMPANY

STATEMENTS OF INCOME

(In thousands)

	Year Ended December 31,
	2005		2004
OPERATING REVENUES
Electric utility	$	421,362	$	371,279
Gas utility		132,618		110,373
Total operating revenues		553,980		481,652
COST OF OPERATING REVENUES
Fuel for electric generation		126,235		96,132
Purchased electric energy		17,772		20,655
Cost of gas sold		97,034		78,314
Total cost of operating revenues		241,041		195,101
TOTAL OPERATING MARGIN		312,939		286,551
OPERATING EXPENSES
Other operating		122,986		112,113
Depreciation & amortization		62,156		58,484
Taxes other than income taxes		14,696		13,334
Total operating expenses		199,838		183,931
OPERATING INCOME		113,101		102,620
Other income – net		2,381		3,266
Interest expense		27,911		25,333
INCOME BEFORE INCOME TAXES		87,571		80,553
Income taxes		35,783		31,974
NET INCOME		51,788		48,579
Preferred stock dividends		4		13
NET INCOME APPLICABLE TO COMMON SHAREHOLDER	$	51,784	$	48,466

The accompanying notes are an integral part of these financial statements

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SOUTHERN INDIANA GAS & ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	51,788		$	48,579
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization		62,156			58,484
Deferred income taxes & investment tax credits		11,834			14,370
Expense portion of pension & postretirement periodic benefit cost		1,814			1,913
Provision for uncollectible accounts		2,220			1,850
Other non-cash charges - net		496			(241	)
Changes in working capital accounts:
Accounts receivable, including to Vectren companies & accrued unbilled revenue		(1,313	)		(27,557	)
Inventories		(6,949	)		(3,401	)
Recoverable fuel & natural gas costs		(16,746	)		10,222
Prepayments & other current assets		(5,637	)		1,637
Accounts payable, including to Vectren companies & affiliated companies		16,939			3,090
Accrued liabilities		4,057			(5,857	)
Changes in noncurrent assets		(7,595	)		2,514
Changes in noncurrent liabilities		(649	)		(6,950	)
Net cash flows from operating activities		112,415			98,653
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Additional capital contribution		125,000			-
Requirements for:
Dividends to parent		(45,479	)		(49,542	)
Retirement of long-term debt, including premiums paid		(64	)		(450	)
Redemption of preferred stock		(112	)		(116	)
Dividends on preferred stock		(4	)		(13	)
Net change in short-term borrowings, including from Utility Holdings		(77,167	)		86,751
Net cash flows from financing activities		2,174			36,630
CASH FLOWS FROM INVESTING ACTIVITIES
Requirements for capital expenditures		(118,732	)		(138,302	)
Proceeds from other investments		3,489			1,121
Net cash flows from investing activities		(115,243	)		(137,181	)
Net decrease in cash & cash equivalents		(654	)		(1,898	)
Cash & cash equivalents at beginning of period		1,777			3,675
Cash & cash equivalents at end of period	$	1,123		$	1,777
Cash paid during the year for:
Income taxes	$	24,057		$	26,486
Interest		26,810			24,422

The accompanying notes are an integral part of these financial statements

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SOUTHERN INDIANA GAS & ELECTRIC COMPANY

STATEMENTS COMMON SHAREHOLDER’S EQUITY

(In thousands)

						Accumulated
						Other
	Common		Retained			Comprehensive
	Stock		Earnings			Income (Loss)		Total
Balance at January 1, 2004	$	128,258	$	266,911		$	-	$	395,169
Net income & comprehensive income				48,579					48,579
Common stock:
Dividends to parent				(49,542	)				(49,542	)
Other		5							5
Preferred stock dividends				(13	)				(13	)
Balance at December 31, 2004	$	128,263	$	265,935		$	-	$	394,198
Comprehensive income
Net income				51,788					51,788
Cash flow hedges - net of tax							4,050		4,050
Total comprehensive income									55,838
Common stock:
Additional capital contribution		125,000							125,000
Dividends to parent				(45,479	)				(45,479	)
Preferred stock dividends				(4	)				(4	)
Balance at December 31, 2005	$	253,263	$	272,240		$	4,050	$	529,553

The accompanying notes are an integral part of these financial statements

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SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

NOTES TO THE FINANCIAL STATEMENTS

1.   Organization and Nature of Operations

Southern Indiana Gas and Electric Company (the Company or SIGECO), an Indiana corporation, provides energy delivery services to approximately 140,000 electric customers and approximately 112,000 gas customers located near Evansville in southwestern Indiana. SIGECO also owns and operates electric generation to serve its electric customers and optimizes those assets in the wholesale power market. SIGECO is a direct, wholly owned subsidiary of Vectren Utility Holdings, Inc. (Utility Holdings). Utility Holdings is a direct, wholly owned subsidiary of Vectren Corporation (Vectren). SIGECO generally does business as Vectren Energy Delivery of Indiana, Inc. Vectren is an energy and applied technology holding company headquartered in Evansville, Indiana.

2.   Summary of Significant Accounting Policies

A.   Cash & Cash Equivalents

All highly liquid investments with an original maturity of three months or less at the date of purchase are considered cash equivalents.

B.   Inventories

Inventories consist of the following:

	At December 31,
(In thousands)	2005		2004
Materials & supplies	$	26,504	$	24,431
Fuel (coal and oil) for electric generation		14,060		8,762
Gas in storage – at LIFO cost		7,474		7,727
Emission allowances		144		308
Total inventories	$	48,182	$	41,228

Based on the average cost of gas purchased during December, the cost of replacing gas in storage carried at LIFO cost exceeded LIFO cost at December 31, 2005, and 2004, by approximately $70.0 million and $30.4 million, respectively. All other inventories are carried at average cost.

C.   Utility Plant & Depreciation

Utility plant is stated at historical cost, including AFUDC. Depreciation rates, which include a cost of removal component, are established through regulatory proceedings and are applied to all in-service utility plant. The original cost of utility plant, together with depreciation rates expressed as a percentage of original cost, follows:

	At and For the Year Ended At December 31,
(In thousands)	2005					2004
	Original Cost		Depreciation Rates as a Percent of Original Cost			Original Cost		Depreciation Rates as a Percent of Original Cost
Electric utility plant	$	1,611,419		3.7	%	$	1,458,063		3.6	%
Gas utility plant		183,901		3.0	%		175,353		3.0	%
Common utility plant		44,200		2.6	%		44,126		2.7	%
Construction work in progress		60,015		-			127,301		-
Total original cost	$	1,899,535				$	1,804,843

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AFUDC represents the cost of borrowed and equity funds used for construction purposes and is charged to construction work in progress during the construction period. AFUDC is included in Other income (expense) - net in the Statements of Income. The total AFUDC capitalized into Utility plant and the portion of which was computed on borrowed and equity funds for all periods reported follows:

	Year Ended December 31,
(In thousands)	2005		2004
AFUDC – borrowed funds	$	1,384	$	1,310
AFUDC – equity funds		160		1,515
Total AFUDC capitalized	$	1,544	$	2,825

Maintenance and repairs, including the cost of removal of minor items of property and planned major maintenance projects, are charged to expense as incurred. When property that represents a retirement unit is replaced or removed, the remaining historical value of such property is charged to Utility plant, with an offsetting charge to Accumulated depreciation and Regulatory liabilities for the cost of removal. Costs to dismantle and remove retired property are recovered through the depreciation rates identified above.

Jointly Owned Plant

SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of ALCOA, own the 270 MW Unit 4 at the Warrick Power Plant as tenants in common. SIGECO's share of the cost of this unit at December 31, 2005 is $63.2 million with accumulated depreciation totaling $40.2 million. AGC and SIGECO also share equally in the cost of operation and output of the unit. SIGECO's share of operating costs is included in Other operating expenses in the Statements of Income.

D.   Impairment Review of Long-Lived Assets

Long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired. This review is performed in accordance with SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS 144). SFAS 144 establishes one accounting model for all impaired long-lived assets and long-lived assets to be disposed of by sale or otherwise. SFAS 144 requires that the evaluation for impairment involve the comparison of an asset’s carrying value to the estimated future cash flows that the asset is expected to generate over its remaining life. If this evaluation were to conclude that the carrying value of the asset is impaired, an impairment charge would be recorded based on the difference between the asset’s carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations.

E.   Goodwill

Goodwill arising from business combinations is accounted for in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142). SFAS 142 uses impairment-only approach to account for the effect of goodwill on the operating results.

Goodwill is tested for impairment at a reporting unit level at least annually and that test is performed at the beginning of each year. The impairment review consists of a comparison of the fair value of a reporting unit to its carrying amount. If the fair value of a reporting unit is less than its carrying amount, an impairment loss is recognized in operations. Through December 31, 2005, no goodwill impairment has been recorded. The Company’s goodwill is included in the Gas Utility Services operating segment.

F.   Asset Retirement Obligations

SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143) requires entities to record the fair value of a liability for a legal asset retirement obligation (ARO) in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss. To the extent regulation is involved, such gain or loss may be deferred.

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In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations — an interpretation of FASB Statement No. 143” (FIN 47). 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 ARO that is conditional on a future event if the liability’s fair value can be estimated reasonably. The interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.

The Company adopted this interpretation on December 31, 2005. The primary issue resulting from FIN 47’s adoption was the reassessment of whether a portion of removal costs accrued through depreciation rates established in regulatory proceedings should be recharacterized as an ARO. The adoption of this interpretation established an approximate $7 million ARO for interim retirements of gas utility pipeline, utility poles and certain asbestos-related issues. The ARO is included in Other liabilities and deferred credits. Adoption also resulted in an increase to Utility plant of approximately $3 million. Because of the effects of regulation, the difference was recorded to Regulatory assets and liabilities.

G.   Regulation

SFAS 71

Retail public utility operations affecting Indiana customers are subject to regulation by the IURC. The Company’s accounting policies give recognition to the rate-making and accounting practices of this agency and to accounting principles generally accepted in the United States, including the provisions of SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation” (SFAS 71).

Refundable or Recoverable Gas Costs, Fuel for Electric Production & Purchased Power

All metered gas rates contain a gas cost adjustment clause that allows the Company to charge for changes in the cost of purchased gas. Metered electric rates contain a fuel adjustment clause that allows for adjustment in charges for electric energy to reflect changes in the cost of fuel. The net energy cost of purchased power, subject to an agreed upon benchmark, is also recovered through regulatory proceedings. The Company records any under-or-over-recovery resulting from gas and fuel adjustment clauses each month in revenues. A corresponding asset or liability is recorded until the under-or-over-recovery is billed or refunded to utility customers. The cost of gas sold is charged to operating expense as delivered to customers, and the cost of fuel for electric generation is charged to operating expense when consumed.

Regulatory Assets and Liabilities

Regulatory liabilities represent probable expenditures by the Company for removal costs or future reductions in revenues associated with amounts that are to be credited to customers through the rate-making process. Regulatory assets represent probable future revenues associated with certain incurred costs, which will be recovered from customers through the rate-making process. The Company assesses the recoverability of costs recognized as regulatory assets and the ability to continue to account for its activities based on the criteria set forth in SFAS 71. Based on current regulation, the Company believes such accounting is appropriate. If all or part of the Company's operations cease to meet the criteria of SFAS 71, a write-off of related regulatory assets and liabilities could be required. In addition, the Company would be required to determine any impairment to the carrying value of its utility plant and other regulated assets.

Regulatory liabilities consist of the following:

 At December 31,

(In thousands)	2005		2004
Cost of removal	$	49,681	$	51,439
Asset retirement obligation timing difference		2,542		-
MISO-related costs		3,157		-
Total regulatory liabilities	$	55,380	$	51,439

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Cost of Removal

The Company collects an estimated cost of removal of its utility plant through depreciation rates established by regulatory proceedings. The Company records amounts expensed in advance of payments as a regulatory liability because the liability does not meet the threshold of a legal ARO as defined by SFAS 143

Regulatory assets consist of the following:

	At December 31,
(In thousands)	2005			2004
Amounts currently recovered through base rates:
Unamortized debt issue costs	$	4,826		$	5,105
Premiums paid to reacquire debt		5,275			5,712
Demand side management programs & other		2,401			3,028
		12,502			13,845
Amounts deferred for future recovery:
Demand side management programs		26,702			25,878
MISO-related costs		9,443			3,140
Other		2,955			2,955
		39,100			31,973
Future amounts recoverable from ratepayers:
Income taxes		3,295			3,354
Asset retirement obligations & other		1,695			962
		4,990			4,316
Amounts currently recovered through authorized tracking mechanisms		(336	)		118
Total regulatory assets	$	56,256		$	50,252

Of the $12.5 million currently being recovered through base rates, approximately $12.0 million is earning a return with a weighted average recovery period of 14.0 years. The Company has rate orders for deferred costs not yet in rates and therefore believes that future recovery is probable.

H.   Comprehensive Income

Comprehensive income is a measure of all changes in equity that result from the transactions or other economic events during the period from non-shareholder transactions. This information is reported in the Statements of Common Shareholder’s Equity. A summary of the components of and changes in Accumulated other comprehensive income follows:

	2004						2005
	Beginning		Changes		End		Changes			End
	of Year		During		of Year		During			of Year
(In millions)	Balance		Year		Balance		Year			Balance
Cash flow hedges	$	-	$	-	$	-	$	6,809		$	6,809
Deferred income taxes		-		-		-		(2,759	)		(2,759	)
Accumulated other comprehensive income	$	-	$	-	$	-	$	4,050		$	4,050

I.   Revenues

Revenues are recorded as products and services are delivered to customers. To more closely match revenues and expenses, the Company records revenues for all gas and electricity delivered to customers but not billed at the end of the accounting period.

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J.Utility Receipts Taxes

A portion of utility receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes received as a component of Operating revenues. Utility receipts taxes expensed are recorded as a component of Taxes other than income taxes.

K.   Earnings Per Share

Earnings per share are not presented as SIGECO’s common stock is wholly owned by Vectren Utility Holdings, Inc.

L.   Other Significant Policies

Included elsewhere in these notes are significant accounting policies related to intercompany allocations and income taxes (Note 3) and derivatives (Note 9).

M.   Use of Estimates

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 financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

N.   Reclassifications

Certain amounts included in prior years’ balance sheet and the statements of income and cash flows have been reclassified to conform the to the current year presentation. These reclassifications had no effect on reported total assets, liabilities, shareholders’ equity, or net income. Reclassifications made to the consolidated statement of cash flows decreased net cash flows provided by operating activities and decreased net cash flows required for investing activities by $17.5 million in 2004.  Reclassifications made to the statement of cash flows decreased net cash flows provided by operating activities and decreased net cash flows required for investing activities by $17.5 million in 2004.

3.   Transactions with Other Vectren Companies

Support Services and Purchases

Vectren and certain subsidiaries of Vectren provided corporate and general and administrative services to the Company including legal, technology, finance, tax, risk management, human resources, and charges for share-based compensation and for pension and other postretirement benefits not directly charged to subsidiaries. In addition, the Company receives a charge for the use of common corporate assets, such as office space and computer hardware and software. These costs have been allocated using various allocators, primarily number of employees, number of customers and/or revenues. Allocations are primarily based on cost. SIGECO received corporate allocations totaling $47.7 million and $45.9 million for the years ended December 31, 2005, and 2004, respectively.

Vectren Fuels, Inc., a wholly owned subsidiary of Vectren, owns and operates coal mines from which SIGECO purchases substantially all of its fuel used for electric generation. Amounts paid for such purchases for the years ended December 31, 2005, and 2004, totaled $96.4 million and $79.0 million, respectively. Amounts charged by Vectren Fuels, Inc. are established by supply agreements with the utility that are negotiated with the OUCC and filed with the IURC.

Retirement Plans and Other Postretirement Benefits

Vectren has multiple defined benefit pension plans and postretirement plans that require accounting as described in SFAS No. 87 “Employers’ Accounting for Pensions” and SFAS No. 106 “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” respectively. A cost allocation is determined by Vectren’s actuaries, comprised of only service cost and interest on that service cost, by subsidiary based on headcount at each measurement date. These costs are directly charged to individual subsidiaries. Other components of costs (such as interest cost and asset returns) are charged to individual subsidiaries through the corporate allocation process discussed above. Neither plan assets nor the FAS 87/106 liability is allocated to individual subsidiaries since these assets and obligations are derived from corporate level decisions. Further, Vectren satisfies the future funding requirements of plans and the payment of benefits from general corporate assets. This allocation methodology is consistent with “multiemployer” benefit accounting as described in SFAS 87 and 106.

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For the years ended December 31, 2005 and 2004, periodic pension costs totaling $2.1 million and $2.0 million, respectively, was directly charged by Vectren to the Company. For the years ended December 31, 2005 and 2004, other periodic postretirement benefit costs totaling $0.4 million and $0.6 million, respectively, was directly charged by Vectren to the Company. As of December 31, 2005 and 2004, $28.0 million and $25.9 million, respectively, is included in Deferred credits & other liabilities and represents costs directly charged to the Company that is yet to be funded to Vectren.

Cash Management Arrangements

The Company participates in a centralized cash management program with Vectren, other wholly owned subsidiaries, and banks. See Note 5 regarding long-term and short-term intercompany borrowing arrangements.

Share-Based Incentive Plans

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 SIGECO. The Company intends to adopt SFAS 123R using the modified prospective method. 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.

Guarantees of Parent Company Debt

Vectren’s three operating utility companies, SIGECO, Indiana Gas Company, Inc. (Indiana Gas) and Vectren Energy Delivery of Ohio, Inc. are guarantors of Utility Holdings’ $515 million in short-term credit facilities, of which approximately $226.9 million is outstanding at December 31, 2005, and Utility Holdings’ $700 million unsecured senior notes outstanding at December 31, 2005. The guarantees are full and unconditional and joint and several, and Utility Holdings has no subsidiaries other than the subsidiary guarantors.

Income Taxes

Vectren files a consolidated federal income tax return. Pursuant to a subsidiary tax sharing agreement and for financial reporting purposes, SIGECO’s current and deferred tax expense is computed on a separate company basis. Current taxes payable/receivable are settled with Vectren in cash.

The components of income tax expense and utilization of investment tax credits follow:

	Year Ended December 31,
(In thousands)	2005			2004
Current:
Federal	$	18,051		$	12,390
State		5,898			5,214
Total current taxes		23,949			17,604
Deferred:
Federal		10,308			14,033
State		3,015			1,579
Total deferred taxes		13,323			15,612
Amortization of investment tax credits		(1,489	)		(1,242	)
Total income tax expense		35,783			31,974

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The liability method of accounting is used for income taxes under which deferred income taxes are recognized to reflect the tax effect of temporary differences between the book and tax bases of assets and liabilities at currently enacted income tax rates. Significant components of the net deferred tax liability follow:

	At December 31,
(In thousands)	2005			2004
Noncurrent deferred tax liabilities (assets):
Depreciation & cost recovery timing differences	$	129,645		$	117,886
Regulatory assets recoverable through future rates		9,571			9,115
Demand side management		7,687			12,535
Other comprehensive income		2,759			-
Employee benefit obligations		(11,747	)		(11,085	)
Regulatory liabilities to be settled through future rates		(6,276	)		(5,762	)
Other – net		2,119			(772	)
Net noncurrent deferred tax liability		133,758			121,917
Current deferred tax liability:
Deferred fuel costs - net		5,693			1,729
Net deferred tax liability	$	139,451		$	123,646

A reconciliation of the federal statutory rate to the effective income tax rate follows:

	Year Ended December 31,
	2005			2004
Statutory rate		35.0	%		35.0	%
State & local taxes, net of federal benefit		5.3			5.5
Amortization of investment tax credit		(1.7	)		(1.5	)
All other - net		2.3			0.7
Effective tax rate		40.9	%		39.7	%

At December 31, 2005 and 2004, investment tax credits totaling $9.2 million and $10.7 million, respectively, are included in Deferred credits and other liabilities. These investment tax credits are amortized over the lives of the related investments.

4.   Transactions with Vectren Affiliates

ProLiance Energy, LLC

ProLiance Energy, LLC (ProLiance), a nonregulated energy marketing affiliate of Vectren and Citizens Gas and Coke Utility (Citizens Gas), provides natural gas and related services to SIGECO, other Vectren companies, Citizens Gas and a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions. ProLiance’s primary business is optimizing the gas portfolios of utilities and providing services to large end use customers.

Transactions with ProLiance

Purchases from ProLiance for resale and for injections into storage for the years ended December 31, 2005, and 2004, totaled $99.7 million and $79.1 million, respectively. Amounts owed to ProLiance at December 31, 2005, and 2004, for those purchases were $21.1 million and $11.3 million, respectively, and are included in Accounts payable to affiliated companies in the Balance Sheets. Amounts charged by ProLiance for gas supply services are established by supply agreements with the utility.

As part of a settlement agreement approved by the IURC during July 2002, the gas supply agreement with the Company was approved and extended through March 31, 2007. On February 1, 2006, the Company, Citizens Gas, and three consumer representatives, including the OUCC, filed a settlement agreement with the IURC providing for ProLiance to be the continued supplier of gas supply services to the Company through March 2011. The settlement is subject to approval by the IURC.

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Other Affiliate Transactions

Vectren has ownership interests in other affiliated companies accounted for using the equity method of accounting that perform underground construction and repair, facilities locating, and meter reading services to the Company. For the years ended December 31, 2005, and 2004, fees for these services and construction-related expenditures paid by the Company to Vectren were not significant. Amounts charged by these affiliates are market based. Amounts owed to affiliated companies other than ProLiance totaled approximately $0.7 million and less than $0.1 million at December 31, 2005, and 2004, respectively.

5.   Borrowing Arrangements & Other Financing Transactions

Long-Term Debt

Senior unsecured obligations and first mortgage bonds outstanding and classified as long-term follow:

	At December 31,
(In thousands)	2005			2004
Senior Unsecured Notes Payable to Utility Holdings:
2011, 6.625%	$	86,584		$	86,584
2018, 5.75%		61,881			61,900
Total long-term debt payable to Utility Holdings	$	148,465		$	148,484
First Mortgage Bonds Payable to Third Parties:
2016, 1986 Series, 8.875%	$	13,000		$	13,000
2023, 1993 Environmental Improvement Series B, current adjustable rate 3.70%,
tax exempt, auction rate mode, 2005 weighted average: 2.66%		22,550			22,550
2029, 1999 Senior Notes, 6.72%		80,000			80,000
2015, 1985 Pollution Control Series A, current adjustable rate 3.35%, tax
exempt, auction rate mode, 2005 weighted average: 2.46%		9,775			9,775
2020, 1998 Pollution Control Series B, 4.50%, tax exempt		4,640			4,640
2024, 2000 Environmental Improvement Series A, 4.65%, tax exempt		22,500			22,500
2025, 1998 Pollution Control Series A, adjustable rate presently
4.75%, tax exempt, next rate adjustment: 2006		31,500			31,500
2030, 1998 Pollution Control Series C, adjustable rate presently
5.00%, tax exempt, next rate adjustment: 2006		22,200			22,200
2030, 1998 Pollution Control Series B, 5.00%, tax exempt		22,000			22,000
Total first mortgage bonds payable to third parties		228,165			228,165
Unamortized debt premium & discount & other - net		(2,021	)		(2,137	)
Long-term debt payable to third parties - net	$	226,144		$	226,028

Long-Term Debt Sinking Fund Requirements & Maturities

The annual sinking fund requirement of SIGECO's first mortgage bonds is one percent of the greatest amount of bonds outstanding under the Mortgage Indenture. This requirement may be satisfied by certification to the Trustee of unfunded property additions in the prescribed amount as provided in the Mortgage Indenture. SIGECO intends to meet the 2006 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2006 is excluded from Current liabilities in the Balance Sheets. At December 31, 2005, $549.4 million of SIGECO's utility plant remained unfunded under SIGECO's Mortgage Indenture.

There are no maturities and/or sinking fund requirements on long-term debt during the five years following 2005, except as described above.

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Long-Term Debt Put & Call Provisions

Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity. The put or call provisions are not triggered by specific events, but are based upon dates stated in the note agreements, such as when notes are re-marketed. Debt which may be put to the Company during the years following 2005 (in millions) is zero in 2006, 2007, and 2008, $80.0 in 2009, zero in 2010 and thereafter. Debt that may be put to the Company within one year is classified as Long-term debt subject to tender in current liabilities.

As of December 31, 2005, the Company had $53.7 million of long-term debt which was subject to tender to the Company in 2006, if the Company was not able to remarket the bonds. During March 2006, the Company successfully remarketed these bonds on a long-term basis and has therefore classified them in Long-term debt. Prior to the remarketing, the $31.5 million bond, due in 2025, had an interest rate of 4.75%, and the $22.2 million bond, due in 2030, had an interest rate of 5.00%. Subsequent to the remarketing effort, the interest rate is now reset weekly through an auction process.

Other Financing Transactions

During 2004, the Company remarketed two first mortgage bonds. The remarketing effort converted $32.8 million of outstanding fixed rate debt into variable rate debt where interest rates reset weekly. One bond, due in 2023, had a principal amount of $22.8 million and an interest rate of 6%. The other bond, due in 2015, had a principal amount of $10.0 million and an interest rate of 4.3%. These bonds are classified in Long-term debt.

Covenants

Both long-term and short-term borrowing arrangements contain customary default provisions; restrictions on liens, sale leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage and interest coverage, among other restrictions. As of December 31, 2005, the Company was in compliance with all financial covenants.

Short-Term Borrowings

SIGECO mainly relies on the short-term borrowing arrangements of Utility Holdings for its short-term working capital needs. Borrowings, including third party borrowings, outstanding at December 31, 2005 and 2004, were $93.3 million and $170.5 million, respectively. The intercompany credit line is limited by Utility Holdings’ available capacity, which is $293.0 million at December 31, 2005. The line is subject to the same terms and conditions as Utility Holdings’ commercial paper program. Short-term borrowings bear interest at Utility Holdings’ weighted average daily cost of short-term funds. Additionally, at December 31, 2005, the Company has available approximately $5 million of short-term borrowing capacity with third parties to supplement its intercompany borrowing arrangements. See the table below for interest rates and outstanding balances:

	Year ended December 31,
	2005			2004
Weighted average total outstanding during
the year payable to Utility Holdings (in thousands)	$	146,467		$	111,756
Weighted average total outstanding during
the year payable to third parties (in thousands)	$	423		$	580
Weighted average interest rates during the year:
Utility Holdings		3.26	%		1.69	%
Bank loans		4.01	%		2.19	%

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6.   Commitments & Contingencies

Commitments

Firm purchase commitment for utility and non-utility plant total $13.0 million in 2006.

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 or results of operations. See Note 7 regarding environmental matters.

7.   Environmental 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 December 31, 2005, capital investments approximating the level approved by the IURC have been made. The last SCR was placed into service in May, 2005.  Related annual operating expenses, including depreciation expense, were $15.4 million in 2005, $9.7 million in 2004 and $1.2 million in 2003. Such operating expenses could approximate $24 to $27 million once all installed equipment is operational for an entire year. In September 2005, SIGECO received an additional capital contribution of $125 million from Utility Holdings, which was used to finance, on a long-term basis, these environmental compliance and other capital expenditures that were originally financed with short-term borrowings.

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.

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In February 2006, the IURC approved a multi-emission compliance plan filed by the Company’s utility subsidiary, SIGECO. Once the plan is implemented, 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. The order, as previously agreed to by the OUCC and Citizens Action Coalition, allows SIGECO to recover an approximate 8% 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 order also stipulates that SIGECO study renewable energy alternatives and include a carbon forecast in future filings with regard to new generation and further environmental compliance plans, among other initiatives.

Culley Generating Station Litigation

During 2003, the U.S. District Court for the Southern District of Indiana entered a consent decree among SIGECO, the Department of Justice (DOJ), and the USEPA that resolved a lawsuit originally brought by the USEPA against SIGECO. The lawsuit alleged violations of the Clean Air Act by SIGECO at its Culley Generating Station for (1) making modifications to generating station without obtaining required permits, (2) making major modifications to the generating station without installing the best available emission control technology, and (3) failing to notify the USEPA of the modifications.

Under the terms of the agreement, the DOJ and USEPA agreed to drop all challenges of past maintenance and repair activities at the Culley Generating Station. In reaching the agreement, SIGECO did not admit to any allegations in the government’s complaint, and SIGECO continues to believe that it acted in accordance with applicable regulations and conducted only routine maintenance on the units. SIGECO entered into this agreement to further its continued commitment to improve air quality and avoid the cost and uncertainties of litigation.

Under the agreement, SIGECO committed to:

·   either repower Culley Unit 1 (50 MW) with natural gas and equip it with SCR control technology for further reduction of nitrogen oxide, or cease operation of the unit by December 31, 2006;

·   operate the existing SCR control technology recently installed on Culley Unit 3 (287 MW) year round at a lower emission rate than that currently required under the NOx SIP Call, resulting in further nitrogen oxide reductions;

·   enhance the efficiency of the existing scrubber at Culley Units 2 and 3 for additional removal of sulphur dioxide emissions;

·   install a baghouse for further particulate matter reductions at Culley Unit 3 by June 30, 2007;

·   conduct a Sulphuric Acid Reduction Demonstration Project as an environmental mitigation project designed to demonstrate an advance in pollution control technology for the reduction of sulfate emissions; and

·   pay a $600,000 civil penalty.

The Company notified the USEPA of its intention to shut down Culley Unit 1 effective December 31, 2006. The Company does not believe that implementation of the settlement will have a material effect to its results from operations or financial condition. The $600,000 civil penalty was accrued during 2003.

Manufactured Gas Plants

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. 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. The total costs accrued to date, including investigative costs, have been immaterial.

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8.   Rate & Regulatory Matters

Gas Base Rate Settlements

On June 30, 2004, the IURC approved a $5.7 million base rate increase for SIGECO’s gas distribution business. The new rate designs include a larger service charge, which is intended to address to some extent earnings volatility related to weather.

The order also permits SIGECO 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. Any costs incurred in excess of these annual caps are to be deferred for future recovery.

Decoupling/Conservation Filing

On October 25, 2005, SIGECO, along with Indiana Gas, filed with the IURC for approval of a conservation program and a conservation adjustment rider in their 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 its last general rate case. The Company will file its evidence in March 2006 and a hearing is set for June 2006.

Weather Normalization

On October 5, 2005, the IURC approved the establishment of a normal temperature adjustment (NTA) mechanism for SIGECO. The OUCC had previously entered into a settlement agreement with the Company providing for the NTA. The NTA affects the Company’s residential and commercial natural gas customers and should mitigate weather risk in those customer classes during the October to April heating season. These customer classes represent approximately 85% of the Company’s total natural gas margin.

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 has been 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 $15,000 to a universal service fund program or other low income assistance program for the duration of the NTA or until a general rate case.

Commodity Prices

Commodity prices for natural gas purchases have remained above historic levels and have become more volatile. Subject to compliance with applicable state laws, the Company is allowed recovery of such changes in purchased gas costs from its retail customers through a commission-approved gas cost adjustment mechanism, and margin on gas sales are not expected to be impacted. Nevertheless, it is possible the regulator may disallow recovery of a portion of gas costs for a variety of reasons, including, but not limited to, a finding by the regulator that natural gas was not prudently procured. In addition, it is reasonably possible that as a result of this near term change in the natural gas commodity price, the Company may 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 or delivered. In response to higher gas prices, Utility Holdings increased its credit facilities, on which the Company relies for its short-term working capital needs.

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.

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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, the Company, 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 the Company’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.

9.   Derivatives & Other Financial Instruments

Accounting Policy for Derivatives

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

When an energy contract that is a derivative is designated and documented as a normal purchase or normal sale (normal exception), it is exempted from mark-to-market accounting. Otherwise, energy contracts and financial contracts that are derivatives are recorded at market value as current or noncurrent assets or liabilities depending on their value and on when the contracts are expected to be settled. The offset resulting from carrying the derivative at fair value on the balance sheet is charged to earnings unless it qualifies as a hedge or is subject to SFAS 71. When hedge accounting is appropriate, the Company assesses and documents hedging relationships between the derivative contract and underlying risks as well as its risk management objectives and anticipated effectiveness. When the hedging relationship is highly effective, derivatives are designated as hedges. The market value of the effective portion of the hedge is marked to market in accumulated other comprehensive income for cash flow hedges or as an adjustment to the underlying’s basis for fair value hedges. The ineffective portion of hedging arrangements is marked-to-market through earnings. The offset to contracts affected by SFAS 71 are marked-to-market as a regulatory asset or liability. Market value for derivative contracts is determined using quoted market prices from independent sources. Following is a more detailed discussion of the Company’s use of mark-to-market accounting related to asset optimization, SO₂ emission allowance risk management, and natural gas procurement.

Asset Optimization

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 all of the 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. Contracts with counter-parties subject to master netting arrangements are presented net in the Balance Sheets. Asset optimization contracts are recorded at market value. Beginning in April 2005, substantially all off-system sales occur into the MISO day-ahead market.

Asset optimization contracts recorded at market value at December 31, 2005, totaled $1.3 million in Prepayments & other current assets and zero in Accrued liabilities, compared to $2.5 million in Prepayments & other current assets and $3.1 million in Accrued liabilities at December 31, 2004.

The proceeds received and paid upon settlement of both purchase and sale contracts along with changes in market value of open contracts are recorded in Electric utility revenues. Net revenues from asset optimization activities totaled $38.0 million in 2005 and $23.8 million in 2004.

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SO₂ Emission Allowance Risk Management

The Company’s wholesale power marketing operations are exposed to price risk associated with SO₂ emission allowances. During 2004 and 2005, emission allowances became more volatile and prices increased. To hedge this risk, the Company executed call options to hedge wholesale emission allowance utilization in future periods. The Company designated and documented these derivatives as cash flow hedges. At December 31, 2005, a deferred gain of approximately $3.2 million remains in Accumulated comprehensive income which will be recognized in earnings as emission allowances are utilized. At December 31, 2005, outstanding call options hedging a forecasted 2006 transaction, have a fair value of $3.9 million and are recorded in Prepayments and other current assets. Hedge ineffectiveness totaling $0.8 million of expense is included in 2005’s earnings, and the effective portion of outstanding hedges totaling $3.6 million resides in Accumulated comprehensive income.

Natural Gas Procurement Activity

The Company has limited exposure to commodity price risk for purchases and sales of natural gas and electricity for retail customers due to current Indiana regulations which, subject to compliance with those regulations, allow for recovery of such purchases through natural gas and fuel cost adjustment mechanisms. Although the Company is exposed to limited commodity price risk, volatile natural gas prices can result in higher working capital requirements, increased expenses including unrecoverable interest costs, uncollectible accounts expense, and unaccounted for gas, and some level of price- sensitive reduction in volumes sold. The Company mitigates these risks by executing derivative contracts that manage the price volatility of forecasted natural gas purchases. These contracts are subject to regulation which allows for reasonable and prudent hedging costs to be recovered through rates. When regulation is involved, SFAS 71 controls when the offset to mark-to-market accounting is recognized in earnings. At December 31, 2005 and 2004, the market values of these contracts were not significant.

Fair Value of Other Financial Instruments

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

	At December 31,
	2005				2004
(In thousands)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long term debt	$	228,165	$	241,695	$	228,165	$	240,294
Long term debt payable to VUHI		148,465		156,006		148,484		159,519
Short-term borrowings		-		-		339		339
Short-term borrowings from VUHI		93,343		93,343		170,171		170,171

Certain methods and assumptions must be used to estimate the fair value of financial instruments. The fair value of the Company's long-term debt was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics. Because of the maturity dates and variable interest rates of short-term borrowings, its carrying amount approximates its fair value.

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

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10.   Additional Operational & Balance Sheet Information

Other - net in the Statements of Income consists of the following:

	Year ended December 31,
(In thousands)	2005			2004
AFUDC (See Note 2C)	$	1,544		$	2,825
Interest & other investment income		862			502
Donations		(204	)		(85	)
Other, net		179			24
Total other - net	$	2,381		$	3,266

Accrued liabilities in the Balance Sheets consist of the following:

	At December 31,
(In thousands)	2005		2004
Accrued taxes	$	8,500	$	7,978
Customers advances & deposits		7,895		6,918
Deferred income taxes		5,693		1,729
Accrued interest		5,680		5,587
Refundable emission credit costs		4,475		2,036
Accrued salaries & other		8,512		8,362
Total accrued liabilities	$	40,755	$	32,610

11.   Segment Reporting

The Company has two operating segments: (1) Gas Utility Services and (2) Electric Utility Services 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 southwestern Indiana, including counties surrounding Evansville. Electric Utility Services provides electricity primarily to southwestern Indiana, and includes the Company’s power generating and marketing operations. For its operations the Company uses after tax operating income as a measure of profitability, consistent with regulatory reporting requirements. The Company cross manages its 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. The Company makes decisions on finance and dividends at the corporate level. Information related to the Company’s business segments is summarized below:

	Year Ended December 31,
(In thousands)	2005		2004
Revenues
Electric Utility Services	$	421,362	$	371,279
Gas Utility Services		132,618		110,373
Total operating revenues	$	553,980	$	481,652

22

	Year Ended December 31,
(In thousands)	2005		2004
Profitability Measure
Regulated Operating Income
(Operating Income Less Applicable Income Taxes)
Electric Utility Services	$	72,371	$	65,697
Gas Utility Services		5,217		5,070
Total regulated operating income		77,588		70,767
Less regulated income taxes		35,513		31,853
Total operating income	$	113,101	$	102,620
Amounts Included in Profitability Measures
Depreciation & Amortization
Electric Utility Services	$	56,868	$	53,341
Gas Utility Services		5,288		5,143
Total depreciation & amortization	$	62,156	$	58,484
Income Taxes
Electric Utility Services	$	33,539	$	30,770
Gas Utility Services		1,974		1,083
Unallocated taxes		270		121
Total income taxes	$	35,783	$	31,974
Capital Expenditures
Electric Utility Services	$	100,009	$	150,586
Gas Utility Services		9,664		5,228
Non-cash costs & changes in accruals		9,059		(17,512	)
Total capital expenditures	$	118,732	$	138,302
		At December 31,
(In thousands)		2005		2004
Assets
Electric Utility Services	$	1,176,027	$	1,090,130
Gas Utility Services		167,755		161,347
Total assets	$	1,343,782	$	1,251,477

12.   Adoption of Other Accounting Standards

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.

*******************************************************************************************************************************************

23

The following discussion and analysis should be read in conjunction with the financial statements and notes thereto and the annual reports filed on Forms 10-K of both Vectren and Utility Holdings.

Executive Summary of Results of Operations

SIGECO generates revenue primarily from the delivery of natural gas and electric service to its customers. The 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. Results are impacted by weather patterns in its service territory and general economic conditions both in its service territory as well as nationally.

For the year ended December 31, 2005, earnings were $51.8 million as compared to $48.6 million in 2004. The 2005 results reflect the impact of a regulatory strategy that includes a gas utility base rate increase, the recovery of pollution control investments, and a normal temperature adjustment mechanism implemented in October 2005, among other initiatives. Gas utility base rate increases added revenues of approximately $2.7 million, or $1.6 million after tax, in 2005 compared to 2004. Increased revenues associated with recovery of pollution control investments, net of related operating and depreciation expenses, increased operating income $8.7 million, or $5.2 million after tax, in 2005 compared to 2004. Results for the year ended December 31 2005, also reflect increased margins from generation asset optimization activities. Higher operating costs and depreciation expense offset increased margins.

Management estimates that the after tax impact of weather on the electric and gas utility businesses, including the effects of the recently implemented normal temperature adjustment mechanism, was favorable $0.3 million after tax in 2005 and unfavorable $2.1 million after tax in 2004.

Significant Fluctuations

Throughout this discussion, the terms Gas Utility margin and Electric Utility margin are used. Gas Utility margin is calculated as Gas utility revenues less the Cost of gas. Electric Utility margin is calculated as Electric utility revenues less Fuel for electric generation and Purchased electric energy. These measures exclude Other operating expenses, Depreciation and amortization, Income taxes, 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.

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. The weather impact in the Company’s gas utility service territories is mitigated somewhat by a normal temperature adjustment mechanism, which was implemented in the fourth quarter of 2005. 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 mandated taxes, which fluctuate with gas costs, as well as other tracked expenses 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.

24

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

Electric Utility margin by revenue type follows:

	Year Ended December 31,
(In millions)	2005		2004
Electric utility revenues	$	421,362	$	371,279
Fuel for electric generation		126,235		96,132
Purchased electric energy		17,772		20,655
Total electric utility margin	$	277,355	$	254,492
Margin attributed to:
Residential & commercial customers	$	170,764	$	157,260
Industrial customers		66,885		63,740
Municipalities & other customers		19,871		18,538
Subtotal: Retail & firm wholesale	$	257,520	$	239,538
Asset optimization	$	19,835	$	14,954
Electric volumes sold in MWh attributed to:
Residential & commercial customers		2,933,189		2,830,879
Industrial customers		2,575,925		2,511,211
Municipal & other customers		689,900		645,939
Total retail & firm wholesale volumes sold		6,199,014		5,988,029

Retail & Firm Wholesale Margin

Electric retail and firm wholesale utility margin was $257.5 million for the year ended December 31, 2005, an increase over the prior year of $17.9 million. The recovery of pollution control related investments and associated operating expenses and depreciation expense increased margins $14.3 million compared to 2004. Cooling weather was 9% warmer than normal and 21% warmer than last year. The estimated increase in electric margin related to weather was $4.0 million compared to the prior year ($3.8 million related to cooling weather and $0.2 million related to heating weather).

Margin from Asset Optimization Activities

Periodically, generation capacity is in excess of that needed to serve retail load and firm wholesale customers. The Company markets this unutilized capacity to optimize the return on its owned generation assets. Substantially all of the 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. Beginning in April 2005, substantially all off-system sales occur into the MISO day-ahead market.

25

Following is a reconciliation of asset optimization activity:

	Year Ended December 31,
(In thousands)	2005			2004
Beginning of year net balance sheet position	$	(626	)	$	(424	)
Statement of income activity:
Mark-to-market gains (losses) recognized		540			(1,399	)
Realized gains (losses)		19,295			16,353
Net activity in electric utility margin		19,835			14,954
Net cash received & other adjustments		(17,912	)		(15,156	)
End of year net balance sheet position	$	1,297		$	(626	)

For the year ended December 31, 2005, net asset optimization margins were $19.8 million, which represents an increase of $4.9 million, as compared to 2004. The increase in margin results primarily from the timing of available capacity and mark to market gains.

In 2005, the Company experienced increased availability of the generating units. The availability of excess capacity was reduced in 2004 by scheduled outages of owned generation related to the installation of environmental compliance equipment. Off-system sales totaled 1,208.1 GWh in 2005 compared to 670.4 GWh in 2004.

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

Gas Utility margin and throughput by customer type follows:

	Year Ended December 31,
(In millions)	2005		2004
Gas utility revenues	$	132,618	$	110,373
Cost of gas sold		97,034		78,314
Total gas utility margin	$	35,584	$	32,059
Margin attributed to:
Residential & commercial customers	$	29,866	$	28,096
Industrial customers		4,899		4,146
Other customers		819		(183	)
Sold & transported volumes in MDth attributed to:
Residential & commercial customers		11,312		12,049
Industrial customers		18,645		18,200
Total sold & transported volumes		29,957		30,249

Gas utility margins were $35.6 million for the year ended December 31, 2005, an increase of $3.5 million compared to 2004. The increase is primarily due to the favorable impact of a gas base rate increase of $2.8 million and additional pass through expenses and revenue taxes recovered in margins of $0.4 million compared to last year. For the year ended December 31, 2005, weather was 6% warmer than normal but 2% colder than the prior year. Management estimates that weather, including of the effects of the normal temperature adjustment mechanism, increased margin an estimated $0.1 million compared to 2004. Though estimated to be modest to date and net of customer growth, management has seen evidence of gas customer usage declines in 2005, assumed to be driven primarily by price sensitivity. With the current outlook for continued high gas commodity prices, management expects that trend to continue and/or accelerate in 2006. The average cost per dekatherm of gas purchased was $8.62 in 2005 and $6.31 in 2004.

26

Operating Expenses

Other Operating

Other operating expenses increased $10.9 million for the year ended December 31, 2005, compared to 2004. Higher maintenance and chemical costs account for $5.5 million of the increase. Administrative costs, including compensation and benefit costs increases and legal expenses, increased $3.8 million in 2005 as compared to 2004. Increased bad debt expense, costs associated with recent rate increases and other costs account for the remaining increase.

Depreciation & Amortization

For the year ended December 31, 2005, depreciation expense increased $3.7 million 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. Depreciation expense associated with environmental compliance equipment, which is recovered in Electric Utility margins, totaled $12.1 million in 2005 compared to $6.2 million in 2004. Results for 2004 include $3.6 million of additional depreciation due to an adjustment of amortization of regulatory assets

Income Taxes

For the year ended December 31, 2005, income taxes were $1.8 million higher than 2004 primarily due to an increased earnings.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $1.4 million in 2005 compared to 2004. The increase is primarily attributable to increased collections of utility receipts due to higher revenues.

Other Income

Total other income - net decreased $0.9 million in 2005 compared to 2004 due primarily to lower amounts of AFUDC as environmental compliance equipment was placed into service.

Interest Expense

Interest expense increased $2.6 million in 2005 compared to 2004. The increase was driven by rising interest rates and higher levels of short term borrowings due in part to higher working capital requirements resulting from the increased gas commodity prices.

27

SELECTED ELECTRIC OPERATING STATISTICS:

SIGECO ELECTRIC
SELECTED ELECTRIC UTILITY OPERATING STATISTICS
(Unaudited)
	For the Year Ended
	December 31,
	2005			2004
OPERATING REVENUES (In thousands):
Residential	$	135,322		$	118,751
Commercial		95,772			86,201
Industrial		119,462			106,435
Misc. Revenue		7,055			12,495
Total System		357,611			323,882
Municipals		25,786			23,561
Other Wholesale		37,965			23,836
	$	421,362		$	371,279
MARGIN (In thousands):
Residential	$	102,978		$	93,706
Commercial		67,786			63,554
Industrial		66,885			63,740
Misc. Revenue		6,788			4,677
Total System		244,437			225,677
Municipals		13,083			13,861
Other Wholesale		19,835			14,954
	$	277,355		$	254,492
ELECTRIC SALES (In MWh):
Residential		1,564,940			1,495,360
Commercial		1,368,249			1,335,519
Industrial		2,575,925			2,511,211
Misc. Sales		19,563			20,014
Total System		5,528,677			5,362,104
Municipals		670,337			625,925
Other Wholesale		3,049,228			3,526,005
		9,248,242			9,514,034
YEAR END CUSTOMERS:
Residential		120,679			119,970
Commercial		18,677			18,522
Industrial		107			107
All others		51			21
		139,514			138,620
WEATHER AS A % OF NORMAL:
Cooling Degree Days		109	%		90	%

28

SELECTED GAS OPERATING STATISTICS:

SIGECO
SELECTED GAS UTILITY OPERATING STATISTICS
(Unaudited)
	For the Year Ended
	December 31,
	2005			2004
OPERATING REVENUES (In thousands):
Residential	$	84,677		$	72,657
Commercial		42,989			34,333
Industrial		4,899			4,146
Misc. Revenue		53			(763	)
	$	132,618		$	110,373
MARGIN (In thousands):
Residential	$	22,274		$	21,240
Commercial		7,592			6,856
Industrial		4,899			4,146
Misc. Revenue		819			(183	)
	$	35,584		$	32,059
GAS SOLD & TRANSPORTED (In MDth):
Residential		7,275			7,938
Commercial		4,037			4,111
Industrial		18,645			18,200
		29,957			30,249
YEAR END CUSTOMERS:
Residential		101,641			101,668
Commercial		10,388			10,399
Industrial		77			68
		112,106			112,135
WEATHER AS A % OF NORMAL:
Heating Degree Days		94	%		92	%

EX-99.2

Ex 99.2

INDIANA GAS COMPANY, INC.

REPORTING PACKAGE

For the year ended December 31, 2005

Contents

	Page  Number
Audited Financial Statements
Independent Auditors’ Report	2
Balance Sheets	3-4
Statements of Income	5
Statements of Cash Flows	6
Statements of Common Shareholder’s Equity	7
Notes to Financial Statements	8
Results of Operations	21
Selected Operating Statistics	23

Additional Information

This annual reporting package should be read in conjunction with the annual reports of Vectren Corporation (Vectren) and Vectren Utility Holdings, Inc. (Utility Holdings), the parent companies of Indiana Gas, filed on Form 10-K for the year ended December 31, 2005. Vectren and Utility Holdings make available their Securities and Exchange Commission filings and recent annual reports free of charge through Vectren's website at www.vectren.com.

Frequently Used Terms

AFUDC: allowance for funds used during construction	MCF / MMCF / BCF: thousands / millions / billions of cubic feet
APB: Accounting Principles Board	MDth / MMDth: thousands / millions of dekatherms
EITF: Emerging Issues Task Force	OUCC: Indiana Office of the Utility Consumer Counselor
FASB: Financial Accounting Standards Board	PUCO: Public Utilities Commission of Ohio
FERC: Federal Energy Regulatory Commission	SFAS: Statement of Financial Accounting Standards
IDEM: Indiana Department of Environmental Management	USEPA: United States Environmental Protection Agency
IURC: Indiana Utility Regulatory Commission	Throughput: combined gas sales and gas transportation volumes

1

INDEPENDENT AUDITORS’ REPORT

To the Shareholder and Board of Directors of Indiana Gas Company, Inc.:

We have audited the accompanying balance sheets of Indiana Gas Company, Inc. (the “Company”) as of December 31, 2005 and 2004, and the related statements of income, common shareholder’s equity, and cash flows for the years then ended.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing standards as established by the Auditing Standards Board (United States) and in accordance with the auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting.  Accordingly, we express no such opinion.An audit also includes examining,on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Indiana Gas Company, Inc. as of December 31, 2005 and 2004, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. 

DELOITTE & TOUCHE LLP

Indianapolis, Indiana

February 16, 2006

2

FINANCIAL STATEMENTS

INDIANA GAS COMPANY, INC.

BALANCE SHEETS

(In thousands)

	December 31,
	2005		2004
ASSETS
Utility Plant
Original cost	$	1,300,342	$	1,251,508
Less: accumulated depreciation & amortization		451,038		424,118
Net utility plant		849,304		827,390
Current Assets
Cash & cash equivalents		5,609		1,624
Accounts receivable - less reserves of $1,282 &
$718, respectively		72,208		58,554
Receivables due from other Vectren companies		551		234
Accrued unbilled revenues		121,462		86,334
Inventories		14,818		14,074
Recoverable fuel & natural gas costs		4,953		13,728
Prepayments & other current assets		79,502		66,442
Total current assets		299,103		240,990
Investment in the Ohio operations		226,249		220,779
Other investments		5,538		3,050
Non-utility property - net		101		152
Regulatory assets		19,962		19,890
Other assets		5,380		3,123
TOTAL ASSETS	$	1,405,637	$	1,315,374

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

3

INDIANA GAS COMPANY, INC.

BALANCE SHEETS

(In thousands)

	December 31,
	2005		2004
LIABILITIES & SHAREHOLDER'S EQUITY
Common Shareholder's Equity
Common stock (no par value)	$	367,995	$	367,995
Retained earnings		90,599		86,582
Total common shareholder's equity		458,594		454,577
Long-term debt payable to third parties - net
debt subject to tender		127,500		167,417
Long-term debt payable to Utility Holdings		184,437		184,448
Total long-term debt, net		311,937		351,865
Commitments & Contingencies (Notes 3, 4, 7, 8 & 9)
Current Liabilities
Accounts payable		28,424		32,111
Accounts payable to affiliated companies		117,189		62,549
Payables to other Vectren companies		7,749		5,690
Accrued liabilities		57,893		49,339
Short-term borrowings payable to Utility Holdings		162,845		109,211
Long-term debt subject to tender		-		10,000
Total current liabilities		374,100		268,900
Deferred Income Taxes & Other Liabilities
Deferred income taxes		81,980		75,576
Regulatory liabilities		142,994		132,825
Deferred credits & other liabilities		36,032		31,631
Total deferred income taxes & other liabilities		261,006		240,032
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	1,405,637	$	1,315,374

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

4

INDIANA GAS COMPANY, INC.

STATEMENTS OF INCOME

(In thousands)

	Year Ended December 31,
	2005			2004
OPERATING REVENUES	$	831,741		$	686,103
COST OF GAS		595,940			474,452
GAS OPERATING MARGIN		235,801			211,651
OPERATING EXPENSES
Other operating		94,762			89,820
Depreciation & amortization		46,778			45,049
Taxes other than income taxes		21,616			18,453
Total operating expenses		163,156			153,322
OPERATING INCOME		72,645			58,329
OTHER INCOME (EXPENSE)
Equity in earnings of the
Ohio operations - net of tax		5,470			7,207
Other income (expense) - net		(901	)		(1,028	)
Total other income		4,569			6,179
Interest expense		27,785			29,157
INCOME BEFORE INCOME TAXES		49,429			35,351
Income taxes		17,088			10,915
NET INCOME	$	32,341		$	24,436

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

5

INDIANA GAS COMPANY, INC.

STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	32,341		$	24,436
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization		46,778			45,049
Provision for uncollectible accounts		7,044			5,603
Deferred income taxes & investment tax credits		5,170			11,252
Expense portion of pension & postretirement periodic benefit cost		1,218			1,143
Equity in earnings of the Ohio operations - net of tax		(5,470	)		(7,207	)
Other non-cash charges - net		1,114			1,093
Changes in working capital accounts:
Accounts receivable, including due from Vectren companies & accrued unbilled revenue		(56,143	)		(42,059	)
Inventories		(415	)		1,104
Recoverable fuel & natural gas costs		8,775			2,412
Prepayments & other current assets		(13,060	)		3,827
Accounts payable, including to Vectren companies & affiliated companies		51,332			21,490
Accrued liabilities		7,900			10,212
Distributions from Ohio operations		-			8,448
Changes in noncurrent assets		(2,257	)		(362	)
Changes in noncurrent liabilities		(5,271	)		(5,822	)
Net cash flows from operating activities		79,056			80,619
CASH FLOWS FROM FINANCING ACTIVITIES
Requirements for:
Retirement of long-term debt, including premiums paid		(49,911	)		(37,500	)
Dividend to parent		(28,324	)		(26,504	)
Net change in short-term borrowings, including from VUHI		53,634			45,237
Net cash flows from financing activities		(24,601	)		(18,767	)
CASH FLOWS FROM INVESTING ACTIVITIES
Requirements for :
Capital expenditures		(48,617	)		(63,084	)
Other investments		(1,853	)		-
Net cash flows from investing activities		(50,470	)		(63,084	)
Cash & cash equivalents:
Net increase (decrease) in cash & cash equivalents		3,985			(1,232	)
Cash & cash equivalents at beginning of period		1,624			2,856
Cash & cash equivalents at end of period	$	5,609		$	1,624
Cash paid during the year for:
Interest	$	26,462		$	28,087
Income taxes		18,369			17,342

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

6

INDIANA GAS COMPANY, INC.

STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

(In thousands)

	Common		Retained
	Stock		Earnings			Total
Balance at January 1, 2004	$	367,995	$	88,650		$	456,645
Net income & comprehensive income				24,436			24,436
Common stock:
Dividends to parent				(26,504	)		(26,504	)
Balance at December 31, 2004	$	367,995	$	86,582		$	454,577
Net income & comprehensive income				32,341			32,341
Common stock:
Dividends to parent				(28,324	)		(28,324	)
Balance at December 31, 2005	$	367,995	$	90,599		$	458,594

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

7

INDIANA GAS COMPANY, INC.

NOTES TO THE FINANCIAL STATEMENTS

1.   Organization and Nature of Operations

Indiana Gas Company, Inc. (the Company or Indiana Gas), an Indiana corporation, provides energy delivery services to approximately 562,000 natural gas customers located in central and southern Indiana. Indiana Gas is a direct, wholly owned subsidiary of Vectren Utility Holdings, Inc. (Utility Holdings). Utility Holdings is a direct, wholly owned subsidiary of Vectren Corporation (Vectren). Indiana Gas generally does business as Vectren Energy Delivery of Indiana, Inc. Vectren is an energy and applied technology holding company headquartered in Evansville, Indiana.

Investment in the Ohio Operations

The Company holds a 47% interest in the Ohio operations, and the remaining 53% is held by Vectren Energy Delivery of Ohio, Inc. (VEDO). VEDO is also a wholly owned subsidiary of Utility Holdings. The Ohio operations provide energy delivery services to approximately 318,000 natural gas customers located near Dayton in west central Ohio. VEDO is the operator of the assets, and the Ohio operations generally do business as Vectren Energy Delivery of Ohio, Inc.

Indiana Gas’ ownership is accounted for using the equity method in accordance with APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock” and is included in Investment in the Ohio operations, and its interest in the results of operations is included in Equity in earnings of the Ohio operations. Additional information on the Company’s investment in the Ohio operations is included in Note 3.

2.   Summary of Significant Accounting Policies

A.   Cash & Cash Equivalents

All highly liquid investments with an original maturity of three months or less at the date of purchase are considered cash equivalents.

B.   Inventories

Inventories consist of the following:

	At December 31,
(In thousands)	2005		2004
Gas in storage - at LIFO cost	$	11,338	$	11,138
Materials & supplies		2,691		1,914
Other		789		1,022
Total inventories	$	14,818	$	14,074

Based on the average cost of gas purchased during December, the cost of replacing gas in storage carried at LIFO cost exceeded LIFO cost at December 31, 2005, and 2004, by approximately $47 million and $26 million, respectively. All other inventories are carried at average cost.

C.   Utility Plant & Depreciation

Utility plant is stated at historical cost, including AFUDC. Depreciation rates, which include a cost of removal component, are established through regulatory proceedings and are applied to all in-service utility plant. The

8

original cost of utility plant, together with depreciation rates expressed as a percentage of original cost, follows:

	At and For the Year Ended December 31,
(In thousands)	2005					2004
	Original Cost		Depreciation Rates as a Percent of Original Cost			Original Cost		Depreciation Rates as a Percent of Original Cost
Utility plant	$	1,271,259		3.7	%	$	1,214,245		3.7	%
Construction work in progress		29,083		-			37,263		-
Total original cost	$	1,300,342				$	1,251,508

AFUDC represents the cost of borrowed and equity funds used for construction purposes, and is charged to construction work in progress during the construction period and is included in Other - net in the Statements of Income. The total AFUDC capitalized into utility plant and the portion of which was computed on borrowed and equity funds for all periods reported follows:

	Year Ended December 31,
(In thousands)	2005		2004
AFUDC – borrowed funds	$	231	$	230
AFUDC – equity funds		73		125
Total AFUDC capitalized	$	304	$	355

Maintenance and repairs, including the cost of removal of minor items of property and planned major maintenance projects, are charged to expense as incurred. When property that represents a retirement unit is replaced or removed, the cost of such property is charged to Utility plant, with an offsetting charge to Accumulated depreciation, and Regulatory liabilities for the cost of removal. Costs to dismantle and remove retired property are recovered through the depreciation rates identified above.

D.   Impairment Review of Long-Lived Assets

Long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired. This review is performed in accordance with SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS 144). SFAS 144 establishes one accounting model for all impaired long-lived assets and long-lived assets to be disposed of by sale or otherwise. SFAS 144 requires the evaluation for impairment involve the comparison of an asset’s carrying value to the estimated future cash flows the asset is expected to generate over its remaining life. If this evaluation were to conclude that the carrying value of the asset is impaired, an impairment charge would be recorded based on the difference between the asset’s carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations.

E.   Asset Retirement Obligations

SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143) requires entities to record the fair value of a liability for a legal asset retirement obligation (ARO) in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss. To the extent regulation is involved, such gain or loss may be deferred.

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations — an interpretation of FASB Statement No. 143” (FIN 47). 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 ARO that is conditional on a future event if the liability’s fair value can be estimated reasonably. The interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.

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The Company adopted this interpretation on December 31, 2005. The primary issue resulting from FIN 47’s adoption was the reassessment of whether a portion of removal costs accrued through depreciation rates established in regulatory proceedings should be recharacterized as an ARO. The adoption of this interpretation established an approximate $7 million ARO for interim retirements of gas utility pipelines. The ARO is included in Other liabilities and deferred credits. Adoption also resulted in a corresponding increase to Utility plant of approximately $7 million.

F.   Regulation

Retail public utility operations affecting Indiana customers are subject to regulation by the IURC, and retail public utility operations affecting customers of the Ohio operations are subject to regulation by the PUCO. The Company’s accounting policies give recognition to the rate-making and accounting practices of these agencies and to accounting principles generally accepted in the United States, including the provisions of SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation” (SFAS 71).

Regulatory Assets and Liabilities

Regulatory liabilities represent probable expenditures by the Company for removal costs or future reductions in revenues associated with amounts that are to be credited to customers through the rate-making process. Regulatory assets represent probable future revenues associated with certain incurred costs, which will be recovered from customers through the rate-making process. The Company assesses the recoverability of costs recognized as regulatory assets and the ability to continue to account for its activities based on the criteria set forth in SFAS 71. Based on current regulation, the Company believes such accounting is appropriate. If all or part of the Company's operations cease to meet the criteria of SFAS 71, a write-off of related regulatory assets and liabilities could be required. In addition, the Company would be required to determine any impairment to the carrying value of its utility plant and other regulated assets.

Regulatory assets consist of the following:

	At December 31,
(In thousands)	2005		2004
Amounts currently recovered through base rates:
Unamortized debt issue costs & premiums paid to reacquire debt	$	9,768	$	10,876
Rate case expenses		360		548
		10,128		11,424
Future amounts recoverable from ratepayers:
Income taxes		7,831		8,176
Amounts currently recovered through authorized tracking mechanisms		2,003		290
Total regulatory assets	$	19,962	$	19,890

Of the $10.1 million currently being recovered through base rates, approximately $9.8 million is earning a return with a weighted average recovery period of 9.5 years. The Company has rate orders for deferred costs not yet in rates and therefore believes that future recovery is probable.

Regulatory liabilities consist of the following:

	At December 31,
(In thousands)	2005		2004
Cost of removal	$	136,317	$	132,825
Asset retirement obligations & other		6,677		-
Total regulatory liabilities	$	142,994	$	132,825

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Cost of Removal

The Company collects an estimated cost of removal of its utility plant through depreciation rates established by regulatory proceedings. The Company records amounts expensed in advance of payments as a regulatory liability because the liability does not meet the threshold of a legal asset retirement obligation (ARO) as defined by SFAS No. 143.

Refundable or Recoverable Gas Costs

All metered gas rates contain a gas cost adjustment clause that allows the Company to charge for changes in the cost of purchased gas. The Company records any under-or-over-recovery resulting from gas adjustment clauses each month in revenues. A corresponding asset or liability is recorded until the under-or-over-recovery is billed or refunded to utility customers. The cost of gas sold is charged to operating expense as delivered to customers.

G.   Revenues

Revenues are recorded as products and services are delivered to customers. To more closely match revenues and expenses, the Company records revenues for all gas delivered to customers but not billed at the end of the accounting period.

H.   Utility Receipts Taxes

A portion of utility receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes received as a component of Operating revenues. Utility receipts taxes expensed are recorded as a component of Taxes other than income taxes.

I.   Earnings Per Share

Earnings per share are not presented as Indiana Gas’ common stock is wholly owned by Vectren Utility Holdings, Inc.

J.   Other Significant Policies

Included elsewhere in these notes are significant accounting policies related to the investment in the Ohio operations (Note 3), intercompany allocations and income taxes (Note 4) and derivatives (Note 10).

K.   Use of Estimates

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 financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

L.   Reclassifications

Certain amounts included in prior years’ balance sheet and the statements of income and cash flows have been reclassified to conform to the current year presentation. These reclassifications had no effect on reported total assets, liabilities, shareholders’ equity, or net income.

3.   Investment in the Ohio Operations

The Company’s investment in the Ohio operations is accounted for using the equity method of accounting, and the investment is periodically examined for other than temporary declines in value. The Company’s share of the Ohio operations after tax earnings is recorded in equity in earnings of the Ohio operations. Because the Ohio operations is responsible for its income taxes and is also within Vectren’s consolidated tax group, no additional tax provision for these earnings is included in these financial statements. Dividends are recorded as a reduction of the carrying value of the investment when received. Goodwill which is a component of the Company’s net investment is accounted for in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142). SFAS 142 uses an impairment-only approach to account for the effect of goodwill on the operating results.

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Following is summarized financial data of the Ohio operations:

	Year Ended December 31,
(In thousands)	2005		2004
Operating revenues	$	395,383	$	329,729
Gas operating margin		115,057		104,020
Operating income		11,230		15,600
Net income		11,637		15,334
		At December 31,
(In thousands)		2005		2004
Net utility plant	$	301,399	$	285,244
Current assets		171,715		142,341
Goodwill - net		199,457		199,457
Other non-current assets		11,099		9,826
Total assets	$	683,670	$	636,868
Owners' net investment	$	431,218	$	431,618
Current liabilities		141,510		110,264
Noncurrent liabilities		110,942		94,986
Total liabilities & owners' net investment	$	683,670	$	636,868

Gas Cost Recovery (GCR) Audit Proceedings

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, which is the operator of the Ohio operations, 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 2003, the Company recorded a reserve of $1.1 million for this matter. An additional pretax charge of $4.2 million was recorded in Cost of Gas Sold in 2005. The reserve reflects management’s assessment of the impact of the PUCO decisions, 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.

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. On December 21, 2005, the PUCO granted in part VEDO’s rehearing request, and reduced the $3.8 million disallowance related to portfolio administration to $1.98 million. The Company has filed an appeal on that decision as well. The brief on both issues is due May 1, 2006 and briefing should be complete in June, 2006.

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.

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VEDO Base Rate Settlement

On April 13, 2005, the PUCO approved a $15.7 million base rate increase for VEDO’s gas distribution business. The new rate design includes a larger service charge, which is intended to address to some extent earnings volatility related to weather. The base rate change in VEDO’s service territory was implemented on April 14, 2005. 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.

4.   Transactions with Other Vectren Companies

Support Services and Purchases

Vectren and certain subsidiaries of Vectren provide corporate and general and administrative services to the Company including legal, technology, finance, tax, risk management, and human resources, which includes charges for restricted stock compensation and for pension and other postretirement benefits not directly charged to subsidiaries. In addition, the Company receives a charge for the use of common corporate assets, such as office space and computer hardware and software. These costs have been allocated using various allocators, primarily number of employees, number of customers and/or revenues. Allocations are primarily based on cost. Indiana Gas received corporate allocations totaling $60.7 million and $56.7 million for the years ended December 31, 2005, and 2004, respectively.

Retirement Plans and Other Postretirement Benefits

Vectren has multiple defined benefit pension plans and postretirement plans that require accounting as described in SFAS No. 87 “Employers’ Accounting for Pensions” and SFAS No. 106 “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” respectively. An allocation of cost is determined by Vectren’s actuaries, comprised of only service cost and interest on that service cost, by subsidiary based on headcount at each measurement date. These costs are directly charged to individual subsidiaries. Other components of costs (such as interest cost and asset returns) are charged to individual subsidiaries through the corporate allocation process discussed above. Neither plan assets nor the SFAS 87/106 liability is allocated to individual subsidiaries since these assets and obligations are derived from corporate level decisions. Further, Vectren satisfies the future funding requirements of plans and the payment of benefits from general corporate assets. This allocation methodology is consistent with “multiemployer” benefit accounting as described in SFAS 87 and 106.

For the years ended December 31, 2005, and 2004, periodic pension costs totaling $1.4 million and $1.3 million, respectively, were directly charged by Vectren to the Company. For the years ended December 31, 2005, and 2004, other periodic postretirement benefit costs totaling approximately $0.3 million were directly charged by Vectren to the Company. As of December 31, 2005, and 2004, $14.5 million and $18.3 million, respectively, is included in Deferred credits & other liabilities and represents costs directly charged to the Company that is yet to be funded to Vectren, and $3.0 million and $2.4 million, respectively, is included in Other assets for amounts funded in advance to Vectren.

Cash Management and Borrowing Arrangements

The Company participates in a centralized cash management program with Vectren and other wholly owned subsidiaries. See Note 6 regarding long-term and short-term intercompany borrowing arrangements.

Share-Based Incentive Plans

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 Indiana Gas. The Company intends to adopt SFAS 123R using the modified prospective method. 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.

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Guarantees of Parent Company Debt

Vectren’s three operating utility companies, Indiana Gas, Southern Indiana Gas and Electric Company, Inc. (SIGECO) and VEDO are guarantors of Utility Holdings’ $515 million in short-term credit facilities, of which approximately $226.9 million is outstanding at December 31, 2005, and Utility Holdings’ $700 million unsecured senior notes outstanding at December 31, 2005. The guarantees are full and unconditional and joint and several, and Utility Holdings has no subsidiaries other than the subsidiary guarantors.

Income Taxes

Vectren files a consolidated federal income tax return. Pursuant to a subsidiary tax sharing agreement and for financial reporting purposes, Indiana Gas’s current and deferred tax expense is computed on a separate company basis. Current taxes payable/receivable are settled with Vectren in cash.

A reconciliation of the federal statutory rate to the effective income tax rate follows:

	Year Ended December 31,
	2005			2004
Statutory rate		35.0	%		35.0	%
State & local taxes, net of federal benefit		6.2			7.4
Amortization of investment tax credit		(2.1	)		(3.2	)
Adjustment to income tax accruals & other, net		(0.2	)		(0.4	)
Effective tax rate		38.9	%		38.8	%

The components of income tax expense and utilization of investment tax credits follow:

	Year Ended December 31,
(In thousands)	2005			2004
Current:
Federal	$	8,367		$	(1,800	)
State		3,551			1,463
Total current taxes		11,918			(337	)
Deferred:
Federal		4,968			10,422
State		1,106			1,744
Total deferred taxes		6,074			12,166
Amortization of investment tax credits		(904	)		(914	)
Total income taxes	$	17,088		$	10,915

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The liability method of accounting is used for income taxes under which deferred income taxes are recognized to reflect the tax effect of temporary differences between the book and tax bases of assets and liabilities at currently enacted income tax rates. Significant components of the net deferred tax liability follow:

	At December 31,
(In thousands)	2005			2004
Non-current deferred tax liabilities (assets):
Depreciation & cost recovery timing differences	$	81,808		$	78,826
Regulatory assets recoverable through future rates		9,625			10,080
Regulatory liabilities to be settled through future rates		(1,793	)		(1,904	)
Employee benefit obligations		(6,959	)		(9,982	)
Other – net		(701	)		(1,444	)
Net non-current deferred tax liability		81,980			75,576
Current deferred tax liability:
Deferred fuel costs - net		2,055			2,729
Net deferred tax liability	$	84,035		$	78,305

At December 31, 2005, and 2004, investment tax credits totaling $2.6 million and $3.5 million, respectively, are included in Deferred credits and other liabilities. These investment tax credits are amortized over the lives of the related investments.

5.   Transactions with Vectren Affiliates

ProLiance Energy, LLC

ProLiance Energy, LLC (ProLiance), a nonregulated energy marketing affiliate of Vectren and Citizens Gas and Coke Utility (Citizens Gas), provides natural gas and related services to Indiana Gas, other Vectren companies, Citizens Gas and a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions. ProLiance’s primary business is optimizing the gas portfolios of utilities and providing services to large end use customers.

Transactions with ProLiance

Purchases from ProLiance for resale and for injections into storage for the years ended December 31, 2005, and 2004, totaled $604.6 million and $479.5 million, respectively. Amounts owed to ProLiance at December 31, 2005, and 2004, for those purchases were $115.7 million and $61.8 million, respectively, and are included in Accounts payable to affiliated companies in the Balance Sheets. Amounts charged by ProLiance for gas supply services are established by supply agreements with the utility.

As part of a settlement agreement approved by the IURC during July 2002, the gas supply agreement with the Company was approved and extended through March 31, 2007. On February 1, 2006, the Company, Citizens Gas, and three consumer representatives, including the OUCC, filed a settlement agreement with the IURC providing for ProLiance to be the continued supplier of gas supply services to the Company through March 2011. The settlement is subject to approval by the IURC.

Other Affiliate Transactions

Vectren has ownership interests in other affiliated companies accounted for using the equity method of accounting that perform underground construction and repair, facilities locating, and meter reading services to the Company. For the years ended December 31, 2005, and 2004, fees for these services and construction-related expenditures paid by the Company to Vectren affiliates totaled approximately $12.0 million and $20.9 million, respectively. Amounts charged by these affiliates are market based. Amounts owed to unconsolidated affiliates of Vectren, other than ProLiance, totaled $1.5 million and $0.8 million at December 31, 2005, and 2004, respectively, and are included in Accounts payable to affiliated companies in the Balance Sheets.

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6.   Borrowing Arrangements & Other Financing Transactions

Short-Term Borrowings

As of December 31, 2005, the Company has no short-term borrowing arrangements with third parties and relies entirely on the short-term borrowing arrangements of Utility Holdings for short-term working capital needs. Borrowings outstanding at December 31, 2005, and 2004, were $162.8 million and $109.2 million, respectively. The intercompany credit line is limited by Utility Holdings’ available capacity, which is $293.0 million at December 31, 2005. The line is subject to the same terms and conditions as Utility Holdings’ commercial paper program. Short-term borrowings bear interest at Utility Holdings’ weighted average daily cost of short-term funds.

See the table below for interest rates and outstanding balances.

	Year ended December 31,
(In thousands)	2005			2004
Weighted average total outstanding during
the year due from Utility Holdings (in thousands)	$	48,336		$	31,151
Weighted average interest rates during the year:
Utility Holdings		3.61	%		1.86	%

Long-Term Debt

Senior unsecured obligations outstanding and classified as long-term follow:

	At December 31,
(In thousands)	2005		2004
Fixed Rate Senior Unsecured Notes Payable to Utility Holdings:
2011, 6.625%	$	98,953	$	98,953
2018, 5.75%		37,129		37,140
2031, 7.25%		48,355		48,355
Total long-term debt payable to Utility Holdings	$	184,437	$	184,448
Fixed Rate Senior Unsecured Notes Payable to Third Parties:
2007, Series E, 6.54%	$	6,500	$	6,500
2013, Series E, 6.69%		5,000		5,000
2015, Series E, 7.15%		5,000		5,000
2015, Series E, 6.69%		5,000		5,000
2015, Series E, 6.69%		10,000		10,000
2025, Series E, 6.53%		10,000		10,000
2027, Series E, 6.42%		5,000		5,000
2027, Series E, 6.68%		1,000		1,000
2027, Series F, 6.34%		20,000		20,000
2028, Series F, 6.36%		10,000		10,000
2028, Series F, 6.55%		20,000		20,000
2029, Series G, 7.08%		30,000		30,000
2030, Insured Quarterly, 7.45%		-		49,917
Total long-term debt outstanding payable to third parties		127,500		177,417
Debt subject to tender		-		(10,000	)
Long-term debt payable to third parties - net of current maturities & debt subject to tender	$	127,500	$	167,417

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Debt Call

In 2005, the Company called at par $49.9 million of Indiana Gas insured quarterly senior unsecured notes originally due in 2030, and in 2004, called at par $20.0 million of Indiana Gas insured quarterly senior unsecured notes originally due in 2015. The notes called in 2005 and 2004 had stated interest rates of 7.45% and 7.15%, respectively.

Long-Term Debt Sinking Fund Requirements & Maturities

Maturities and sinking fund requirements on long-term debt during the five years following 2005 (in millions) are zero in 2006, $6.5 in 2007, and zero in 2008, 2009 and 2010.

Long-Term Debt Put & Call Provisions

Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity. The put or call provisions are not triggered by specific events, but are based upon dates stated in the note agreements. Debt which may be put to the Company during the years following 2005 (in millions) is zero in 2006, $20.0 in 2007, zero in 2008 and 2009, $10.0 million in 2010, and $30.0 thereafter. Debt that may be put to the Company within one year is classified as Long-term debt subject to tender in current liabilities.

Covenants

Borrowing arrangements contain customary default provisions; restrictions on liens, sale leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage and interest coverage, among other restrictions. As of December 31, 2005, the Company was in compliance with all financial covenants.

7.   Commitments & Contingencies

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 or results of operations. See Note 8 regarding environmental matters.

8.   Environmental Matters

In the past, Indiana Gas 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 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.

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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.

9.   Rate & Regulatory Matters

Gas Base Rate Settlement

On November 30, 2004, the IURC approved a $24 million base rate increase for Indiana Gas’ gas distribution business. The new rate design includes a larger service charge, which is intended to address to some extent earnings volatility related to weather.

The order also permits 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 $2.5 million per year thereafter. Any costs incurred in excess of these annual caps are to be deferred for future recovery.

Decoupling/Conservation Filing

On October 25, 2005, Indiana Gas, along with SIGECO, filed with the IURC for approval of a conservation program and a conservation adjustment rider in their 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 will file its evidence in March 2006 and a hearing is set for June 2006.

Weather Normalization

On October 5, 2005, the IURC approved the establishment of a normal temperature adjustment (NTA) mechanism for Indiana Gas. The OUCC had previously entered into a settlement agreement with the Company providing for the NTA. The NTA affects the Company’s residential and commercial natural gas customers and should mitigate weather risk in those customer classes during the October to April heating season. These customer classes represent approximately 88% of the Company’s total natural gas margin.

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 has been 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 $110,000 to a universal service fund program or other low income assistance program for the duration of the NTA or until a general rate case.

Commodity Prices

Commodity prices for natural gas purchases have remained above historic levels and have become more volatile. Subject to compliance with applicable state laws, the Company is allowed recovery of such changes in purchased gas costs from its retail customers through a commission-approved gas cost adjustment mechanism, and margin on gas sales are not expected to be impacted. Nevertheless, it is possible the regulator may disallow recovery of a portion of gas costs for a variety of reasons, including, but not limited to, a finding by the regulator that natural gas was not prudently procured. In addition, it is reasonably possible that as a result of this near term change in the natural gas commodity price, the Company may 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 or delivered. In response to higher gas prices, Utility Holdings increased its credit facilities, on which the Company relies for its short-term working capital needs.

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10.   Derivatives & Other Financial Instruments

Accounting Policy for Derivatives

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

When an energy contract that is a derivative is designated and documented as a normal purchase or normal sale (normal exception), it is exempted from mark-to-market accounting. Otherwise, energy contracts and financial contracts that are derivatives are recorded at market value as current or noncurrent assets or liabilities depending on their value and on when the contracts are expected to be settled. The offset resulting from carrying the derivative at fair value on the balance sheet is charged to earnings unless it qualifies as a hedge or is subject to SFAS 71. When hedge accounting is appropriate, the Company assesses and documents hedging relationships between the derivative contract and underlying risks as well as its risk management objectives and anticipated effectiveness. When the hedging relationship is highly effective, derivatives are designated as hedges. The market value of the effective portion of the hedge is marked to market in accumulated other comprehensive income for cash flow hedges or as an adjustment to the underlying’s basis for fair value hedges. The ineffective portion of hedging arrangements is marked-to-market through earnings. The offset to contracts affected by SFAS 71 are marked-to-market as a regulatory asset or liability. Market value for derivative contracts is determined using quoted market prices from independent sources. Following is a more detailed discussion of the Company’s use of mark-to-market accounting related to natural gas procurement.

The Company has limited exposure to commodity price risk for purchases and sales of natural gas for retail customers due to current Indiana regulations which, subject to compliance with those regulations, allow for recovery of such purchases through natural gas adjustment mechanisms. Although the Company is exposed to limited commodity price risk, volatile natural gas prices can result in higher working capital requirements, increased expenses including unrecoverable interest costs, uncollectible accounts expense, and unaccounted for gas, and some level of price- sensitive reduction in volumes sold. The Company mitigates these risks by executing derivative contracts that manage the price volatility of forecasted natural gas purchases. These contracts are subject to regulation which allows for reasonable and prudent hedging costs to be recovered through rates. When regulation is involved, SFAS 71 controls when the offset to mark-to-market accounting is recognized in earnings. At December 31, 2005 and 2004, the market values of these contracts were not significant.

Fair Value of Other Financial Instruments

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

	At December 31,
	2005				2004
(In thousands)	Carrying Amount Est. Fair Value				Carrying Amount Est. Fair Value
Long-term debt due to third parties	$	127,500	$	137,048	$	177,417	$	184,300
Long-term debt due to Utility Holdings		184,437		193,970		184,448		202,406
Short-term debt due to Utility Holdings		162,845		162,845		109,211		109,211

Certain methods and assumptions must be used to estimate the fair value of financial instruments. The fair value of the Company's other financial instruments was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics. Because of the maturity dates and variable interest rates of short-term borrowings, its carrying amount approximates its fair value.

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

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11.   Additional Operational & Balance Sheet Information

Other - net in the Statements of Income consists of the following:

	Year Ended December 31,
(In thousands)	2005			2004
AFUDC	$	304		$	355
Other income		868			381
Donations		(1,929	)		(1,635	)
Other expense		(144	)		(129	)
Total other – net	$	(901	)	$	(1,028	)

Prepayments and other current assets in the Balance Sheets consist of the following:

	At December 31,
(In thousands)	2005		2004
Prepaid gas delivery service	$	69,330	$	58,490
Prepaid taxes		10,165		7,069
Other prepayments & current assets		7		883
Total prepayments & other current assets	$	79,502	$	66,442

Accrued liabilities in the Balance Sheets consist of the following:

	At December 31,
(In thousands)	2005		2004
Customer advances & deposits	$	17,008	$	13,618
Accrued gas imbalance		10,784		7,811
Accrued taxes		10,557		11,125
Accrued interest		4,551		4,204
Deferred income taxes		2,055		2,729
Accrued salaries & other		12,938		9,852
Total accrued liabilities	$	57,893	$	49,339

12. Adoption of Other Accounting Standards

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.

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The following discussion and analysis should be read in conjunction with the financial statements and notes thereto and the annual reports filed on Forms 10-K of both Vectren and Utility Holdings.

Executive Summary of Results of Operations

Indiana Gas generates revenue primarily from the delivery of natural gas service to its customers. The 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 services. Results are impacted by weather patterns in its service territory and general economic conditions both in its service territory as well as nationally.

For the year ended December 31, 2005, earnings were $32.3 million as compared to $24.4 million in 2004. The 2005 results reflect the impact of a regulatory strategy that includes a gas utility base rate increase and a normal temperature adjustment mechanism implemented in October 2005, among other initiatives. Gas utility base rate increases added revenues of approximately $19.9 million, or $11.8 million after tax, in 2005 compared to 2004. The increase was partially offset by higher operating expenses and lower earnings from the Ohio operations.

Management estimates that the impact of weather, including the effects of the recently implemented normal temperature adjustment mechanism, was unfavorable $3.6 million after tax in 2005 and $4.3 million after tax in 2004.

Significant Fluctuations

Gas Operating Margin

Margin generated from the sale of natural gas to residential and commercial customers is seasonal and impacted by weather patterns in the Company’s service territories. The weather impact is mitigated somewhat by a normal temperature adjustment mechanism, which was implemented in the fourth quarter of 2005. Margin generated from sales to large customers (generally industrial and other contract customers) is primarily impacted by overall economic conditions. Margin is also impacted by the collection of state mandated taxes, which fluctuate with gas costs, and is also impacted by some level of price sensitivity in volumes sold. Following is a discussion and analysis of margin generated from regulated utility operations.

	Year Ended December 31,
(In millions)	2005		2004
Gas utility revenues	$	831,741	$	686,103
Cost of gas sold		595,940		474,452
Total gas utility margin	$	235,801	$	211,651
Margin attributed to:
Residential & commercial customers	$	203,864	$	183,646
Industrial customers		27,046		26,652
Other customers		4,891		1,353
Sold & transported volumes in MDth attributed to:
Residential & commercial customers		64,111		63,755
Industrial customers		51,510		50,898
Total sold & transported volumes		115,621		114,653

Gas utility margins were $235.8 million for the year ended December 31, 2005, an increase of $24.1 million compared to 2004. The increase is primarily due to the favorable impact of the gas base rate increase of $19.9 million, higher miscellaneous revenues of $1.5 million, and additional pass through revenue taxes recovered in margins of $2.2 million compared to last year. Management estimates that weather, including of the effects of the normal temperature adjustment mechanism, increased margin an estimated $1.2 million compared to 2004. Though estimated to be modest to date and net of customer growth, management has seen evidence of gas customer usage declines in 2005, assumed to be driven primarily by price sensitivity. With the current outlook for continued high gas commodity prices, management expects that trend to continue and/or accelerate in 2006. The average cost per dekatherm of gas purchased was $9.15 in 2005 and $7.10 in 2004.

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Operating Expenses

Other Operating

Other operating expenses increased $4.9 million for the year ended December 31, 2005, as compared to 2004. The increase is attributable to higher administrative costs, including performance-based compensation and benefit costs increases, of $3.0 million, increased uncollectible accounts of $1.4 million, and higher maintenance expenses of $0.5 million as compared to 2004.

Depreciation & Amortization

For the year ended December 31, 2005, depreciation expense increased $1.7 million compared to 2004. The increase resulted primarily from normal additions to utility plant.

Income Taxes

For the year ended December 31, 2005, income taxes increased $6.2 million compared to 2004, primarily due to increased earnings before taxes.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $3.2 million in 2005 compared to 2004. The increase is primarily due to increased collections of utility receipts taxes due to higher revenues.

Other Income

Equity in Earnings of the Ohio Operations

Equity in earnings of the Ohio operations represents Indiana Gas’ 47% interest in the Ohio operations’ net income. The financing costs associated with VEDO’s 53% ownership interest are not included in the Ohio operations’ equity in earnings. The Ohio operations’ net income was $11.6 million in 2005 and $15.3 million in 2004. Indiana Gas’ share of those earnings was $5.5 million and $7.2 million, respectively. The effects of a base rate increase was more than offset by a $4.2 million ($2.5 million after tax) charge recorded pursuant to the disallowance of Ohio gas costs in 2005, as well as higher operating expenses and depreciation expense. Depreciation expense in 2004 was affected by a true-up of depreciation rates to existing regulatory orders which decreased depreciation expense in that year. Interest costs arising from financing arrangements utilized for the purchase of the Ohio operations are not reflected in the above financial information. Had the financing arrangements of Indiana Gas and VEDO used to facilitate the purchase of the Ohio operations been pushed down, the Ohio operations’ net income would have been approximately $2.3 million and $6.0 million for the years ended December 31, 2005 and 2004, respectively. 

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SELECTED GAS OPERATING STATISTICS:

INDIANA GAS
SELECTED UTILITY
OPERATING STATISTICS
(Unaudited)
	For the Year Ended
	December 31,
	2005			2004
OPERATING REVENUES (In thousands):
Residential	$	561,809		$	466,106
Commercial		229,440			184,578
Industrial		35,599			34,065
Misc Revenue		4,893			1,354
	$	831,741		$	686,103
MARGIN (In thousands):
Residential	$	155,825		$	141,875
Commercial		48,039			41,771
Industrial		27,046			26,652
Misc Revenue		4,891			1,353
	$	235,801		$	211,651
GAS SOLD & TRANSPORTED (In MDth):
Residential		44,623			44,660
Commercial		19,488			19,095
Industrial		51,510			50,898
		115,621			114,653
YEAR END CUSTOMERS:
Residential		511,926			507,139
Commercial		49,259			48,588
Industrial		869			889
		562,054			556,616
WEATHER AS A % OF NORMAL:
Heating Degree Days		95	%		91	%

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EX-99.3

Ex 99.3

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 and unaccounted for gas and interest expense.

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

·    Direct or indirect effects on our business, financial condition or liquidity resulting from achange 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.