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 7, 2008

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 Indiana Gas Company, Inc. (Indiana Gas), a wholly owned subsidiary of Vectren Utility Holdings, Inc. (Utility Holdings).  Utility Holdings is a wholly owned subsidiary of Vectren Corporation (the Company).

The Indiana Gas financial statements include footnotes thereto, abbreviated analysis of results of operations, segment information and operating statistics.  The financial statements of Indiana Gas are included as Exhibit 99.1 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 Indiana Gas is not a registrant.

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 and Indiana Gas Company, Inc., 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 99.2.

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 7, 2008
		By:  /s/ M. Susan Hardwick
		M. Susan Hardwick
		Vice President, Controller and Assistant Treasurer

INDEX TO EXHIBITS

The following Exhibits are furnished as part of this Report to the extent described in Item 7.01:

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

EX-99.1

Exhibit 99.1

INDIANA GAS COMPANY, INC.

 REPORTING PACKAGE

For the year ended December 31, 2007

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	25

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 Company, Inc., filed on Forms 10-K for the year ended December 31, 2007.  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

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, 2007 and 2006, 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, 2007 and 2006, 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 19, 2008

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FINANCIAL STATEMENTS

INDIANA GAS COMPANY, INC.

BALANCE SHEETS

(In thousands)

	December 31,
	2007		2006
ASSETS
Utility Plant
Original cost	$	1,430,999	$	1,347,388
Less:  accumulated depreciation & amortization		514,868		481,072
Net utility plant		916,131		866,316
Current Assets
Cash & cash equivalents		2,249		2,653
Accounts receivable - less reserves of $1,218 &
$1,107, respectively		50,580		58,244
Receivables due from other Vectren companies		74		6,050
Accrued unbilled revenues		69,083		65,322
Inventories		11,690		17,285
Prepayments & other current assets		70,715		70,466
Total current assets		204,391		220,020
Investment in the Ohio operations		238,462		231,821
Other investments		6,355		5,699
Nonutility property - net		-		51
Regulatory assets		35,243		22,830
Other assets		7,651		8,379
TOTAL ASSETS	$	1,408,233	$	1,355,116

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

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INDIANA GAS COMPANY, INC.

BALANCE SHEETS

(In thousands)

	December 31,
		2007		2006
LIABILITIES & SHAREHOLDER'S EQUITY
Common Shareholder's Equity
Common stock (no par value)		$	367,995	$	367,995
Retained earnings			102,026		99,286
Total common shareholder's equity			470,021		467,281
Long-term debt payable to third parties - net of current maturities &
debt subject to tender			121,000		101,000
Long-term debt payable to Utility Holdings			257,855		243,838
Total long-term debt, net			378,855		344,838
Commitments & Contingencies (Notes 3, 4, 7, 8 & 9)
Current Liabilities
Accounts payable			52,055		41,656
Accounts payable to affiliated companies			56,954		56,362
Payables to other Vectren companies			15,422		2,510
Refundable natural gas costs			11,933		26,052
Accrued liabilities			54,054		55,626
Short-term borrowings payable to Utility Holdings			86,234		66,626
Current maturities of long-term debt			-		6,500
Long-term debt subject to tender			-		20,000
Total current liabilities			276,652		275,332
Deferred Income Taxes & Other Liabilities
Deferred income taxes			88,263		81,242
Regulatory liabilities			162,775		152,801
Deferred credits & other liabilities			31,667		33,622
Total deferred income taxes & other liabilities			282,705		267,665
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY		$	1,408,233	$	1,355,116

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

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INDIANA GAS COMPANY, INC.

STATEMENTS OF INCOME

(In thousands)

	Year Ended December 31,
	2007			2006
OPERATING REVENUES	$	762,858		$	739,161
COST OF GAS		512,800			503,025
GAS OPERATING MARGIN		250,058			236,136
OPERATING EXPENSES
Other operating		101,350			94,263
Depreciation & amortization		50,272			48,458
Taxes other than income taxes		20,740			20,276
Total operating expenses		172,362			162,997
OPERATING INCOME		77,696			73,139
Other expense - net		(575	)		(863	)
Interest expense		27,087			28,865
INCOME BEFORE INCOME TAXES		50,034			43,411
Income taxes		23,132			14,942
Equity in earnings of the
Ohio operations - net of tax		6,641			5,572
NET INCOME	$	33,543		$	34,041

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

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INDIANA GAS COMPANY, INC.

STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	33,543		$	34,041
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization		50,272			48,458
Provision for uncollectible accounts		6,743			7,548
Deferred income taxes & investment tax credits		5,706			(5,705	)
Expense portion of pension & postretirement periodic benefit cost		1,207			1,269
Equity in earnings of the Ohio operations - net of tax		(6,641	)		(5,572	)
Other non-cash charges - net		2,267			530
Changes in working capital accounts:
Accounts receivable, including due from Vectren companies
& accrued unbilled revenue		3,136			57,057
Inventories		5,595			(2,467	)
Recoverable/refundable natural gas costs		(14,119	)		31,005
Prepayments & other current assets		111			10,755
Accounts payable, including to Vectren companies
& affiliated companies		23,685			(51,543	)
Accrued liabilities		(1,572	)		(3,242	)
Changes in noncurrent assets		(12,325	)		(2,999	)
Changes in noncurrent liabilities		(6,725	)		(8,620	)
Net cash flows from operating activities		90,883			110,515
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term term debt payable to Utility Holdings		14,017			107,755
Requirements for:
Retirement of long-term debt		(6,500	)		(48,354	)
Dividend to parent		(30,803	)		(25,354	)
Net change in short-term borrowings, including from Utility Holdings		19,608			(96,219	)
Net cash flows from financing activities		(3,678	)		(62,172	)
CASH FLOWS FROM INVESTING ACTIVITIES
Requirements for :
Capital expenditures		(87,136	)		(51,299	)
Other investments		(473	)		-
Net cash flows from investing activities		(87,609	)		(51,299	)
Net change in cash & cash equivalents		(404	)		(2,956	)
Cash & cash equivalents at beginning of period		2,653			5,609
Cash & cash equivalents at end of period	$	2,249		$	2,653
Cash paid during the year for:
Interest	$	26,399		$	27,189
Income taxes		17,276			13,162

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

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INDIANA GAS COMPANY, INC.

STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

(In thousands)

	Common		Retained
	Stock		Earnings			Total
Balance at January 1, 2006	$	367,995	$	90,599		$	458,594
Net income & comprehensive income				34,041			34,041
Common stock:
Dividends to parent				(25,354	)		(25,354	)
Balance at December 31, 2006	$	367,995	$	99,286		$	467,281
Net income & comprehensive income				33,543			33,543
Common stock:
Dividends to parent				(30,803	)		(30,803	)
Balance at December 31, 2007	$	367,995	$	102,026		$	470,021

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

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INDIANA GAS COMPANY, INC.

NOTES TO THE FINANCIAL STATEMENTS

1.     Organization and Nature of Operations

Indiana Gas Company, Inc. (the Company, Indiana Gas or Vectren North), an Indiana corporation, provides energy delivery services to over 568,000 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 holding company headquartered in Evansville, Indiana.

Investment in the Ohio Operations

The Company holds a 47 percent interest in the Ohio operations, which provide energy delivery services to approximately 318,000 natural gas customers located near Dayton in west central Ohio. The remaining 53 percent ownership in the Ohio operations interest is held by Vectren Energy Delivery of Ohio, Inc. (VEDO or Vectren Ohio), and VEDO is the operator of the assets.  VEDO is also a wholly owned subsidiary of Utility Holdings.  The Ohio operations typically 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)	2007		2006
Gas in storage - at LIFO cost	$	8,336	$	14,333
Materials & supplies		2,666		2,174
Other		688		778
Total inventories	$	11,690	$	17,285

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, 2007, and 2006, by approximately $26 million and $30 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:

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	At and For the Year Ended December 31,
(In thousands)	2007					2006
	Original Cost		Depreciation Rates as a Percent of  Original Cost			Original Cost		Depreciation Rates as a Percent of  Original Cost
Utility plant	$	1,402,680		3.8	%	$	1,321,367		3.9	%
Construction work in progress		28,319		-			26,021		-
Total original cost	$	1,430,999				$	1,347,388

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)	2007		2006
AFUDC – borrowed funds	$	838	$	758
AFUDC – equity funds		27		-
Total AFUDC capitalized	$	865	$	758

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 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 carrying amount of the asset 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.     Regulation

Retail public utility operations affecting Indiana Gas’ 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).

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.

Regulatory Assets and Liabilities

Regulatory assets represent probable future revenues associated with certain incurred costs, which will be recovered from customers through the ratemaking process.  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 ratemaking process.  The Company assesses the recoverability of costs recognized as regulatory assets and liabilities 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.

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Regulatory assets consist of the following:

	At December 31,
(In thousands)	2007		2006
Amounts currently recovered through customer rates related to:
Authorized trackers	$	18,841	$	5,788
Unamortized debt issue costs & premiums paid to reacquire debt		7,788		8,659
Rate case expenses		-		172
		26,629		14,619
Future amounts recoverable from ratepayers related to:
Income taxes		8,614		8,211
Total regulatory assets	$	35,243	$	22,830

Indiana Gas is not earning a return on the $26.6 million currently being recovered through base rates.  The Company has rate orders for deferred costs not yet in rates and therefore believes that future recovery is probable.

Regulatory liabilities

At December 31, 2007 and 2006, the Company has approximately $162.8 million and $152.8 million, respectively, in regulatory liabilities.  Of these amounts, $156.4 million and $146.3 million relate to cost of removal obligations.  The Company collects an estimated cost of removal of its utility plant through depreciation rates established in regulatory proceedings.  The Company records amounts expensed in advance of payments as a Regulatory liability because the liability does not meet the threshold of an asset retirement obligation as defined by SFAS No. 143, “Accounting for Asset Retirement Obligations” and its related interpretations (SFAS 143).

F.     Asset Retirement Obligations

A portion of removal costs related to interim retirements of gas utility pipeline meet the definition of an asset retirement obligation (ARO).  SFAS No. 143 requires entities to record the fair value of a liability for a legal 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.  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.

Asset retirement obligations total $7.5 million at December 31, 2007 and $7.1 million at December 31, 2006, and are included in Deferred credits and other liabilities.  During both 2007 and 2006, the Company recorded accretion of $0.4 million.

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.

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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 information is not presented herein.  The common stock of Indiana Gas 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.

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.

Following is summarized financial data of the Ohio operations:

	Year Ended December 31,
(In thousands)	2007		2006
Operating revenues	$	374,320	$	360,711
Gas operating margin		128,848		114,652
Operating income		14,882		12,131
Net income		14,129		11,856
	At December 31,
(In thousands)	2007		2006
Net utility plant	$	336,489	$	311,997
Current assets		146,312		135,913
Goodwill - net		199,457		199,457
Other non-current assets		20,095		19,751
Total assets	$	702,353	$	667,118
Owners' net investment	$	433,520	$	429,268
Current liabilities		134,578		114,299
Noncurrent liabilities		134,255		123,551
Total liabilities & owners' net investment	$	702,353	$	667,118

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Vectren Energy Delivery of Ohio, Inc. (VEDO) Gas Base Rate Case Filing

In November 2007, VEDO filed with the PUCO a request for an increase in its base rates and charges for it’s distribution business in its 17-county service area in west central Ohio.  The filing indicates that an increase in base rates of approximately $27 million is necessary to cover the ongoing cost of operating, maintaining and expanding the approximately 5,200-mile distribution system used to serve 318,000 customers.

In addition, VEDO is seeking to increase the level of the monthly service charge as well as extending the lost margin recovery mechanism currently in place to be able to encourage customer conservation and is also seeking approval of expanded conservation-oriented programs, such as rebate offerings on high-efficiency natural gas appliances for existing and new home construction, to help customers lower their natural gas bills.  VEDO is also seeking approval of a multi-year bare steel and cast iron capital replacement program.

VEDO anticipates an order from the PUCO in late 2008.

Ohio Lost Margin Recovery/Conservation Filings

In June 2007, the Public Utilities Commission of Ohio (PUCO) approved a settlement that provides for the implementation of a lost margin recovery mechanism and a related conservation program for VEDO's operations.  This order confirms the guidance the PUCO previously provided in a September 2006 decision.  The conservation program, as outlined in the September 2006 PUCO order and as affirmed in this order, provides for a two year, $2 million total conservation program to be paid by VEDO, as well as a sales reconciliation rider intended to be a recovery mechanism for the difference between the weather normalized revenues actually collected by VEDO and the revenues approved by the PUCO in it's most recent rate case.  Approximately 60 percent of VEDO's customers are eligible for the conservation programs.  The Ohio Consumer Counselor (OCC) and another intervener requested a rehearing of the June 2007 order and the PUCO granted that request in order to have additional time to consider the merits of the request.  In accordance with accounting authorization previously provided by the PUCO, VEDO began recognizing the impact of the September 2006 order on October 1, 2006, and has recognized cumulative revenues of $4.6 million, of which $3.3 million was recorded in 2007.  The OCC appealed the PUCO’s accounting authorization to the Ohio Supreme Court, but that appeal has been dismissed as premature pending the PUCO’s consideration of issues raised in the OCC’s request for rehearing.  Since October 1, 2006, VEDO has been ratably accruing its $2 million commitment.

Gas Cost Recovery (GCR) Audit Proceedings

In 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 October 2002 and in 2006, an additional $0.8 million was disallowed related to the audit period ending October 2005.  The initial audit period provided the PUCO staff its initial review of the portfolio administration arrangement between VEDO and ProLiance Holdings, LLC (ProLiance).  Since November 1, 2005, VEDO has used a provider other than ProLiance for these services.

Through a series of rehearings and appeals, including action by the Ohio Supreme Court in the first quarter of 2007, VEDO was required to refund $8.6 million to customers.  In total, VEDO has reflected $6.2 million in Cost of gas sold related to this matter, of which $1.1 million, $4.1 million and $1.0 million were recorded in 2007, 2005, and 2003, respectively.  The impact of the disallowance includes a sharing of the ordered refund by Vectren’s partner in ProLiance.  As of December 31, 2007, all amounts have been refunded to customers.

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, including number of employees, number of customers and/or the level of payroll, revenue contribution and capital expenditures.  Allocations are based on cost.  Indiana Gas received corporate allocations totaling $69.3 million and $61.0 million for the years ended December 31, 2007, and 2006, respectively.

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Miller Pipeline Corporation

Effective July 1, 2006, Vectren purchased the remaining 50% ownership in Miller Pipeline Corporation (Miller), making Miller a wholly owned subsidiary of Vectren.  Prior to the transaction, Miller was 50% owned by Vectren and was accounted for by Vectren using the equity method of accounting.  Miller performs natural gas and water distribution, transmission, and construction repair and rehabilitation primarily in the Midwest and the repair and rehabilitation of gas, water, and wastewater facilities nationwide.  Miller’s customers include Indiana Gas.  Fees paid by Indiana Gas totaled $31.4 million in 2007 and $13.4 million in 2006.  Amounts owed to Miller at December 31, 2007 and 2006 are included in Payables to other Vectren companies.

Retirement Plans and Other Postretirement Benefits

Vectren has multiple defined benefit pension plans and postretirement plans that require accounting as described in SFAS No. 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans-an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (SFAS 158), which it adopted on December 31, 2006.  An allocation of expense is determined, 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 ending 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, 2007, and 2006, periodic pension costs totaling $1.5 million in both years were directly charged by Vectren to the Company.  For the years ended December 31, 2007, and 2006, other periodic postretirement benefit costs totaling approximately $0.2 million in both years were directly charged by Vectren to the Company.  As of December 31, 2007, and 2006, $6.4 million and $10.1 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 $4.5 million and $5.9 million, respectively, is included in Other assets for amounts funded in advance to Vectren.

Cash Management and Borrowing Arrangements

The Company participates in Vectren’s centralized cash management program.  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 required compensation costs related to all share-based payment transactions to be recognized in the financial statements.  With limited exceptions, the amount of compensation cost is measured based on the grant-date fair value of the equity or liability instruments issued.  Compensation cost is recognized over the period that an employee provides service in exchange for the award.  SFAS 123R replaced SFAS 123 and superseded APB 25.  The Company adopted SFAS 123R using the modified prospective method on January 1, 2006.  The adoption of this standard, and subsequent interpretations of the standard, did not have a material effect on the Company’s operating results or financial condition.  Indiana Gas does not have share-based compensation plans separate from Vectren.

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 $386 million is outstanding at December 31, 2007, and Utility Holdings’ $700 million unsecured senior notes outstanding at December 31, 2007.  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.

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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)	2007			2006
Non-current deferred tax liabilities (assets):
Depreciation & cost recovery timing differences	$	80,776		$	76,856
Regulatory assets recoverable through future rates		9,412			9,449
Regulatory liabilities to be settled through future rates		(798	)		(1,238	)
Employee benefit obligations		(5,214	)		(6,828	)
Other – net		4,087			3,003
Net non-current deferred tax liability		88,263			81,242
Current deferred tax assets:
Deferred fuel costs - net		(37	)		(1,170	)
Other – net		(2,042	)		(549	)
Net deferred tax liability	$	86,184		$	79,523

At December 31, 2007, and 2006, investment tax credits totaling $1.2 million and $1.8 million, respectively, are included in Deferred credits and other liabilities.  These investment tax credits are amortized over the lives of the related investments.

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

	Year Ended December 31,
(In thousands)	2007			2006
Current:
Federal	$	12,781		$	16,091
State		4,645			4,556
Total current taxes		17,426			20,647
Deferred:
Federal		5,171			(4,721	)
State		1,181			(170	)
Total deferred taxes		6,352			(4,891	)
Amortization of investment tax credits		(646	)		(814	)
Total income taxes	$	23,132		$	14,942

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

	Year Ended December 31,
	2007			2006
Statutory rate		35.0	%		35.0	%
State & local taxes, net of federal benefit		6.2			7.1
Amortization of investment tax credit		(1.3	)		(1.9	)
Adjustment to federal income tax accruals & other, net		6.3			(5.8	)
Effective tax rate		46.2	%		34.4	%

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Accounting for Uncertainty in Income Taxes

On January 1, 2007, the Company adopted FASB Interpretation No. 48 (FIN 48) “Accounting for Uncertainty in Income Taxes” an interpretation of SFAS 109, “Accounting for Income Taxes.”  FIN 48 prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of tax positions taken or expected to be taken in an income tax return.  FIN 48 also provides guidance related to reversal of tax positions, balance sheet classification, interest and penalties, interim period accounting, disclosure and transition. 

The adoption of FIN 48 did not have a material impact on the Company.  The liability for gross unrecognized tax benefits of $0.7 million upon adoption generally resulted from the reclassification of Deferred income taxes to Other liabilities.

Following is a reconciliation of the total amount of unrecognized tax benefits as of December 31, 2007:

(in thousands)
Unrecognized tax benefits at January 1, 2007	$	660
Gross Decreases - tax positions in prior periods		(104	)
Unrecognized tax benefits at December 31, 2007	$	556

The entire amount of unrecognized tax benefits if recognized, would impact the effective tax rate as of December 31, 2007.  Any remaining unrecognized tax benefit relates to tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility.  Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority.

The Company accrues interest and penalties associated with unrecognized tax benefits in Income taxes.  During the year ended December 31, 2007, the Company recognized expense related to interest and penalties totaling approximately $0.1 million.  The Company had approximately $0.1 million for the payment of interest and penalties accrued as of December 31, 2007.  Prior to the adoption of FIN 48, Vectren’s policy was not to push down interest and penalties to its subsidiaries.

The liability included in Other liabilities on the Balance Sheet for unrecognized tax benefits inclusive of interest, penalties and net of secondary impacts, which are benefits, totaled $0.6 million at December 31, 2007.

From time to time, the Company may consider changes to filed positions that could impact its unrecognized tax benefits.  However, it is not expected that such changes would have a significant impact on earnings and would only affect the timing of payments to taxing authorities.

Indiana Gas does not file federal or state income tax returns separate from those filed by its ultimate parent, Vectren Corporation.  Vectren and/or certain of its subsidiaries file income tax returns in the U.S. federal jurisdiction and various states.  The Internal Revenue Service (IRS) has conducted examinations of the Company’s U.S. federal income tax returns for tax years through December 31, 2004.  The State of Indiana, the Company’s primary state tax jurisdiction, has conducted examinations of state income tax returns for tax years through December 31, 2002.  On February 15, 2008, Vectren was notified by the IRS of their intent to perform a limited scope examination of Vectren’s 2005 consolidated tax return. 

5.     Transactions with ProLiance Holdings, LLC

ProLiance Holdings, LLC (ProLiance), a nonutility 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 businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services.  Indiana Gas purchases all of its natural gas through ProLiance and has regulatory approval from the IURC to continue to do so through March 2011.

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Purchases from ProLiance for resale and for injections into storage for the years ended December 31, 2007 and 2006 totaled $506.2 million and $501.3 million, respectively.  Amounts owed to ProLiance at December 31, 2007 and 2006, for those purchases were $56.9 million and $56.4 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.

6.     Borrowing Arrangements & Other Financing Transactions

Long-Term Debt

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

			At December 31,
(In thousands)			2007	2006
	Fixed Rate Senior Unsecured Notes Payable to Utility Holdings:
		2011, 6.625%	$            98,954	$            98,954
		2018, 5.75%	37,129	37,129
		2015, 5.45%	24,716	24,716
		2035, 6.10%	50,569	50,569
		2036, 5.95%	46,487	32,470
		Total long-term debt payable to Utility Holdings	$        257,855	$       243,838
	Fixed Rate Senior Unsecured Notes Payable to Third Parties:
		2007, Series E, 6.54%	$                     -	$             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
Total long-term debt outstanding payable to third parties			121,000	127,500
	Current maturities		-	(6,500)
	Debt subject to tender		-	(20,000)
Long-term debt payable to third parties - net of
	current maturities & debt subject to tender		$ 121,000	$ 101,000

Issuances payable to Utility Holdings

In December 2007, the Company issued a note payable to Utility Holdings for an additional $14 million related to the 2036 Notes discussed below.

In March 2006, the Company issued two notes payable to Utility Holdings for $24.7 million (2015 Notes) and $50.6 million (2035 Notes), and in December 2006, the Company issued a note payable to Utility Holdings for $32.5 million (2036 Notes).

The terms of these notes are identical to the terms of the notes issued by Utility Holdings in October 2005 and October 2006.  The 2015 Notes and 2035 Notes have an aggregate principle amount of $150 million in two $75 million tranches.  The first tranche was 10-year notes due December 2015, with an interest rate of 5.45% priced at 99.799% to yield 5.47% to maturity (2015 Notes).  The second tranche was 30-year notes due December 2035 with an interest rate of 6.10% priced at 99.799% to yield 6.11% to maturity (2035 Notes).  The notes have no sinking fund requirements, and interest payments are due semi-annually.  The notes may be called by Utility Holdings, in whole or in part, at any time for an amount equal to accrued and unpaid interest, plus the greater of 100% of the principal amount or the sums of the present value of the remaining scheduled payments of principal and interest, discounted to the redemption date on a semi-annual basis at the Treasury Rate, as defined in the indenture, plus 20 basis points for the 2015 Notes and 25 basis points for the 2035 Notes.

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The 2036 Notes have an aggregate principle amount of $100 million with an interest rate of 5.95%, priced at par.  The 2036 Notes have no sinking fund requirements, and interest payments are due quarterly.  The notes may be called by Utility Holdings, in whole or in part, at any time on or after October 1, 2011, at 100% of the principal amount plus accrued interest.  Utility Holdings adjusts the interest rate it charges to its subsidiaries from those stated in it financing arrangements to account for debt issuance costs and any related hedging arrangements.

Debt Call

In 2006, Utility Holdings called $100 million of senior unsecured notes originally due in 2031.  Utility Holdings required Indiana Gas to repay $48.4 million in notes associated with this transaction.

Long-Term Debt Sinking Fund Requirements & Maturities

The Company has no sinking fund requirements on long-term debt during the five years following 2007.  Long-term debt maturities in the five years following 2007 total $99.0 million in 2011.

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 2007 (in millions) is zero in 2008 and 2009, $10.0 million in 2010, $30.0 in 2011, and zero 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, 2007, the Company was in compliance with all financial covenants.

Short-Term Borrowings

As of December 31, 2007, 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, 2007 and 2006 were $86.2 million and $66.6 million, respectively.  The intercompany credit line totals $325 million, but is limited to Utility Holdings’ available capacity ($134 million at December 31, 2007) and 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)	2007			2006
Weighted average total outstanding during
the year due to Utility Holdings (in thousands)	$	36,115		$	54,558
Weighted average interest rates during the year:
Utility Holdings		5.52	%		4.88	%

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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, those that operated these facilities may now be required to take remedial action if certain contaminants are found above the regulatory thresholds at these sites.

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

Indiana Gas accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites.  While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, Indiana Gas has recorded costs that it reasonably expects to incur totaling approximately $21 million.

The estimated accrued costs are limited to Indiana Gas’ share of the remediation efforts.  Indiana Gas has arrangements in place for 19 of the 26 sites with other potentially responsible parties (PRP), which serve to limit Indiana Gas’ share of response costs at these 19 sites to between 20 percent and 50 percent.  With respect to insurance coverage, Indiana Gas has received and recorded settlements from all known insurance carriers under insurance policies in effect when these plants were in operation in an aggregate amount approximating $20 million.

Environmental remediation costs related to Indiana Gas’ manufactured gas plants and other sites have had no material impact on results of operations or financial condition since costs recorded to date approximate PRP and insurance settlement recoveries.  While the Company 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 and those costs may not be subject to PRP or insurance recovery.

9.     Rate & Regulatory Matters

Gas Base Rate Order Received

On February 13, 2008, the Company received an order from the IURC which approved its base rate case.  The order provided for a base rate increase of $16.3 million and an ROE of 10.2 percent, with an overall rate of return of 7.8 percent on rate base of approximately $793 million.  The settlement also provides for the recovery of $10.6 million of costs through separate cost recovery mechanisms rather than base rates.

Further, additional expenditures for a multi-year bare steel and cast iron capital replacement program will be afforded certain accounting treatment that mitigates earnings attrition from the investment between rate cases.  The accounting treatment allows for the continuation of the accrual for allowance for funds used during construction (AFUDC) and the deferral of depreciation expense after the projects go in service but before they are included in base rates.  To qualify for this treatment, the annual expenditures are limited to $20 million and the treatment cannot extend beyond four years on each project.

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With this order, the Company has in place weather normalization, a conservation and lost margin recovery tariff, tracking of gas cost expense related to bad debts and unaccounted for gas through the existing gas cost adjustment mechanism, and tracking of pipeline integrity expense. 

Lost Margin Recovery/Conservation Filings

In December 2006, the IURC approved a settlement agreement that provides for a five-year energy efficiency program.  It allows the Company to recover a majority of the costs of promoting the conservation of natural gas through conservation trackers that work in tandem with a lost margin recovery mechanism.  The order was implemented in December 2006, and provides for recovery of 85 percent of the difference between weather normalized revenues actually collected by the Company and the revenues approved in the Company’s most recent rate case.  Energy efficiency programs began in December 2006.  The recent base rate order also allows for full recovery of the difference between weather normalized revenues collected by the Company and the revenues provided for in that settlement, superseding the original December 2006 order.  While most expenses associated with these programs are recoverable, in the first program year the Company incurred $0.6 million in program costs without recovery, of which $0.5 million was expensed in 2007.

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, 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.  Contracts with counter-parties subject to master netting arrangements are presented net in the Balance Sheets.  The offset resulting from carrying the derivative at fair value on the balance sheet is charged to earnings unless it qualifies as a hedge or is subject to SFAS 71.  When hedge accounting is appropriate, the Company assesses and documents hedging relationships between the derivative contract and underlying risks as well as its risk management objectives and anticipated effectiveness.  When the hedging relationship is highly effective, derivatives are designated as hedges.  The market value of the effective portion of the hedge is marked to market in accumulated other comprehensive income for cash flow hedges.  Ineffective portions of hedging arrangements are marked-to-market through earnings.  For fair value hedges, both the derivative and the underlying are marked to market through earnings.  The offset to contracts affected by SFAS 71 are marked-to-market as a regulatory asset or liability.  Market value for derivative contracts is determined using quoted market prices from independent sources.  Following is a more detailed discussion of the Company’s use of mark-to-market accounting in the natural gas procurement area.

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

At December 31, 2007 and 2006, the market values of these contracts were not significant.

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Fair Value of Other Financial Instruments

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

	At December 31,
	2007				2006
(In thousands)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt due to third parties	$	121,000	$	124,042	$	127,500	$	132,691
Long-term debt due to Utility Holdings		257,855		255,504		243,838		244,796
Short-term debt due to Utility Holdings		86,234		86,234		66,626		66,626

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.

11.   Additional Operational & Balance Sheet Information

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

	Year Ended December 31,
(In thousands)	2007			2006
AFUDC	$	865		$	758
Other income		761			602
Donations & regulatory expenses		(2,201	)		(2,223	)
Total other – net	$	(575	)	$	(863	)

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

	At December 31,
(In thousands)	2007		2006
Prepaid gas delivery service	$	65,169	$	66,235
Prepaid taxes & other		5,546		4,231
Total prepayments & other current assets	$	70,715	$	70,466

Accrued liabilities in the Balance Sheets consist of the following:

	At December 31,
(In thousands)	2007		2006
Customer advances & deposits	$	21,468	$	22,146
Accrued gas imbalance		6,838		9,918
Accrued taxes		15,697		9,074
Accrued interest		5,565		5,289
Accrued salaries & other		4,486		9,199
Total accrued liabilities	$	54,054	$	55,626

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12. Adoption of Other Accounting Standards

SFAS No. 157

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS 157).  SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements.  This statement does not require any new fair value measurements; however, the standard will impact how other fair value based GAAP is applied.  SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007.  However, in December 2007, the FASB issued proposed FSP FAS 157-b which would delay the effective date of SFAS 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually).  This proposed FSP partially defers the effective date of Statement 157 to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years for items within the scope of this FSP.  The Company adopted SFAS 157 on January 1, 2008, except as it applies to those nonfinancial assets and nonfinancial liabilities as noted in proposed FSP FAS 157-b.  The partial adoption of SFAS 157 did not have a material impact on the Company’s financial position, results of operations or cash flows.

SFAS 159

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115” (SFAS 159).  SFAS 159 permits entities to measure many financial instruments and certain other items at fair value.  Items eligible for the fair value measurement option include: financial assets and financial liabilities with certain exceptions; firm commitments that would otherwise not be recognized at inception and that involve only financial instruments; nonfinancial insurance contracts and warranties that the insurer can settle by paying a third party to provide those goods or services; and host financial instruments resulting from separation of an embedded financial derivative instrument from a nonfinancial hybrid instrument.  The fair value option may be applied instrument by instrument, with few exceptions, is an irrevocable election and is applied only to entire instruments.  SFAS 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007.  The Company adopted SFAS 159 on January 1, 2008, but did not opt to apply the fair value option to any of its eligible items.

SFAS 141 (Revised 2007)

In December 2007, the FASB issued SFAS 141, “Business Combinations” (SFAS 141).  SFAS 141 establishes principles and requirements for how the acquirer of an entity (1) recognizes and measures the identifiable assets acquired, the liabilities assumed, and any Noncontrolling interest in the acquiree (2) recognizes and measures acquired goodwill or a bargain purchase gain and (3) determines what information to disclose in its financial statements in order to enable users to assess the nature and financial effects of the business combination.  SFAS 141 applies to all transactions or other events in which one entity acquires control of one or more businesses and applies to all business entities.  SFAS 141 applies prospectively to business combinations with an acquisition date on or after the beginning of the first annual reporting period beginning on or after December 15, 2008.  Early adoption is not permitted.  The Company will adopt SFAS 141 on January 1, 2009, and because the provisions of this standard are applied prospectively, the impact to the Company cannot be determined until the transactions occur.

SFAS 160

In December 2007, the FASB issued SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements-an Amendment of ARB No. 51” (SFAS 160).  SFAS 160 establishes accounting and reporting standards that require that the ownership percentages in subsidiaries held by parties other than the parent be clearly identified, labeled, and presented separately from the parent’s equity in the equity section of the consolidated balance sheet; the amount of consolidated net income attributable to the parent and the noncontrolling interest to be clearly identified and presented on the face of the consolidated income statement; that changes in the parents ownership interest while it retains control over its subsidiary be accounted for consistently; that when a subsidiary is deconsolidated, any retained noncontrolling equity investment be initially measured at fair value; and that sufficient disclosure is made to clearly identify and distinguish between the interests of the parent and the noncontrolling owners.  SFAS 160 applies to all entities that prepare consolidated financial statements, except for non-profit entities.  SFAS 160 is effective for fiscal years beginning after December 31, 2008.  Early adoption is not permitted.  The Company will adopt SFAS 160 on January 1, 2009, and is currently assessing the impact this statement will have on its financial statements and results of operations.

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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 reflect the impact of a constructive regulatory environment.  The Company received orders in the fourth quarter of 2006 that authorize lost margin recovery and has in place a normal temperature adjustment (NTA) mechanism.  These orders collectively mitigate substantially all the base rate impact associated with weather and other usage volatility in residential and commercial customer classes.  Sales to industrial customers are impacted by general economic conditions in the service territory as well as nationally.

For the year ended December 31, 2007, earnings of $33.5 million were relatively flat compared to earnings of $34.0 million in 2006.  Increased revenues associated with usage and lost margin recovery were offset by increased depreciation, operating costs and income taxes.

Significant Fluctuations

Margin

Gas Utility margin is calculated as Gas Utility revenues less Cost of gas sold.  This measure excludes Other operating expenses, Depreciation and amortization, and Taxes other than income taxes, which are included in the calculation of operating income.  The Company believes Gas Utility margin is a better indicator of relative contribution than revenues since gas prices can be volatile and are generally collected on a dollar-for-dollar basis from customers.

Sales of natural gas to residential and commercial customers are seasonal and are impacted by weather.  Trends in average use among natural gas residential and commercial customers have tended to decline in recent years as more efficient appliances and furnaces are installed and the price of natural gas has increased.  Normal temperature adjustment (NTA) and lost margin recovery mechanisms largely mitigate the effect on Gas Utility margin that would otherwise be caused by variations in volumes sold due to weather and changing consumption patterns.  The Company has both an NTA since 2005 and lost margin recovery since December 2006. 

Gas 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, as well as other tracked expenses.  Expenses subject to tracking mechanisms include pipeline integrity management costs and costs to fund energy efficiency programs.  Following is a discussion and analysis of margin generated from regulated utility operations.

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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 thousands)	2007		2006
Gas utility revenues	$	762,858	$	739,161
Cost of gas sold		512,800		503,025
Total gas utility margin	$	250,058	$	236,136
Margin attributed to:
Residential & commercial customers	$	217,202	$	204,741
Industrial customers		26,838		26,716
Other customers		6,018		4,679
Sold & transported volumes in MDth attributed to:
Residential & commercial customers		62,267		55,524
Industrial customers		51,423		49,487
Total sold & transported volumes		113,690		105,011

Gas utility margins were $250.1 million for the year ended December 31, 2007, an increase of $13.9 million compared to 2006.  Residential and commercial customer usage, including lost margin recovery, increased margin $9.7 million year over year.  Operating costs, including revenue taxes recovered dollar for dollar in margin, increased margin approximately $2.9 million.  The remaining increase is primarily due to volatility in unaccounted for gas.  The average cost per dekatherm of gas purchased was $8.04 in 2007 and $8.61 in 2006.

Operating Expenses

Other Operating

For the year ended December 31, 2007, Other operating expenses were $101.3 million, which represents an increase of $7.1 million, compared to 2006.  Operating costs recovered dollar for dollar in margin, including costs funding new energy efficiency programs, increased $3.0 million year over year.  Legal expenses increased $1.2 million related to the settlement of a lawsuit.  The remaining increase is primarily related to higher wage and benefit costs.

Depreciation & Amortization

For the year ended December 31, 2007, depreciation expense increased $1.8 million compared to 2006.  The increase resulted primarily from normal additions to utility plant.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $0.5 million in 2007 compared to 2006 due to higher property taxes.

Income Taxes

For the year ended December 31, 2007, income taxes increased $8.2 million compared to 2006.  The increase in income taxes is due to a lower effective tax rate in 2006 and higher pretax income in 2007. Income taxes in 2006 include favorable adjustments to reflect income taxes reported on final state and federal income tax returns while adjustments recorded in 2007 were unfavorable.

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 Ohio operations’ net income was $14.1 million in 2007 and $11.9 million in 2006.  Indiana Gas’ share of those earnings was $6.6 million and $5.6 million, respectively.  Of the $14 million increase in margin at the Ohio operations, increased usage and lost margin recovery, as well as favorable weather and recovery of gas storage carrying costs, contributed margin increases of $8 million, which were partially offset by higher operating costs, including depreciation.

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In addition, during 2007, the Ohio operations resolved all remaining issues related to a 2005 disallowance by the PUCO of gas costs, resulting in an additional charge of $1.1 million.  Interest costs arising from financing arrangements utilized by Indiana Gas and VEDO for the purchase of the Ohio operations are not reflected in the above earnings data.  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 $5.3 million and $2.7 million for the years ended December 31, 2007 and 2006, respectively. 

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SELECTED GAS OPERATING STATISTICS:

	INDIANA GAS COMPANY
	SELECTED UTILITY
	OPERATING STATISTICS
	(Unaudited)
			For the Year Ended
			December 31,
			2007	2006
	OPERATING REVENUES (In thousands):
		Residential	$   522,783	$ 498,832
		Commercial	201,499	201,763
		Industrial	32,557	33,886
		Misc Revenue	6,019	4,680
			$   762,858	$ 739,161
	MARGIN (In thousands):
		Residential	$   167,042	$ 156,051
		Commercial	50,160	48,690
		Industrial	26,838	26,716
		Misc Revenue	6,018	4,679
			$   250,058	$ 236,136
	GAS SOLD & TRANSPORTED (In MDth):
		Residential	43,016	38,211
		Commercial	19,251	17,313
		Industrial	51,423	49,487
			113,690	105,011
	AVERAGE CUSTOMERS:
		Residential	509,645	504,936
		Commercial	49,076	49,088
		Industrial	847	866
			559,568	554,890
	WEATHER AS A % OF NORMAL(1):
	Heating Degree Days		91%	86%
(1)The impact of weather on residential & commercial customers is mitigated by an NTA mechanism.

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EX-99.2

Exhibit  99.2

Cautionary Statement for Purposes of the "Safe Harbor" provisions of the Private Securities Litigation Reform Act of 1995.

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.  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 transportation and storage costs, or availability due to higher demand, shortages, transportation problems or other developments; environmental or pipeline incidents; transmission or distribution incidents; unanticipated changes to electric energy supply costs, or availability due to demand, shortages, transmission problems or other developments; or electric transmission or gas pipeline system constraints.

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

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

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

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

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

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

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

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

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

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

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

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