Exhibit 99.2

INDIANA GAS COMPANY, INC.

REPORTING PACKAGE

For the year ended December 31, 2006

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	24

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, 2006. 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, 2006 and 2005, 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, 2006 and 2005, 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, 2007

2

FINANCIAL STATEMENTS

INDIANA GAS COMPANY, INC.

BALANCE SHEETS

(In thousands)

	December 31,
	2006		2005
ASSETS
Utility Plant
Original cost	$	1,347,388	$	1,300,342
Less: accumulated depreciation & amortization		481,072		451,038
Net utility plant		866,316		849,304
Current Assets
Cash & cash equivalents		2,653		5,609
Accounts receivable - less reserves of $1,107 &
$1,282, respectively		58,244		72,208
Receivables due from other Vectren companies		6,050		551
Accrued unbilled revenues		65,322		121,462
Inventories		17,285		14,818
Recoverable natural gas costs		-		4,953
Prepayments & other current assets		70,466		79,502
Total current assets		220,020		299,103
Investment in the Ohio operations		231,821		226,249
Other investments		5,699		5,538
Non utility property - net		51		101
Regulatory assets		22,830		19,962
Other assets		8,379		5,380
TOTAL ASSETS	$	1,355,116	$	1,405,637

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

3

INDIANA GAS COMPANY, INC.

BALANCE SHEETS

(In thousands)

	December 31,
	2006		2005
LIABILITIES & SHAREHOLDER'S EQUITY
Common Shareholder's Equity
Common stock (no par value)	$	367,995	$	367,995
Retained earnings		99,286		90,599
Total common shareholder's equity		467,281		458,594
Long-term debt payable to third parties - net of current maturities &
debt subject to tender		101,000		127,500
Long-term debt payable to Utility Holdings		243,838		184,437
Total long-term debt, net		344,838		311,937
Commitments & Contingencies (Notes 3, 4, 7, 8 & 9)
Current Liabilities
Accounts payable		41,656		28,424
Accounts payable to affiliated companies		56,362		117,189
Payables to other Vectren companies		2,510		7,749
Refundable natural gas costs		26,052		-
Accrued liabilities		55,626		57,893
Short-term borrowings payable to Utility Holdings		66,626		162,845
Current maturities of long-term debt		6,500		-
Long-term debt subject to tender		20,000		-
Total current liabilities		275,332		374,100
Deferred Income Taxes & Other Liabilities
Deferred income taxes		81,242		81,980
Regulatory liabilities		152,801		142,994
Deferred credits & other liabilities		33,622		36,032
Total deferred income taxes & other liabilities		267,665		261,006
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	1,355,116	$	1,405,637

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,
	2006			2005
OPERATING REVENUES	$	739,161		$	831,741
COST OF GAS		503,025			595,940
GAS OPERATING MARGIN		236,136			235,801
OPERATING EXPENSES
Other operating		94,263			94,762
Depreciation & amortization		48,458			46,778
Taxes other than income taxes		20,276			21,616
Total operating expenses		162,997			163,156
OPERATING INCOME		73,139			72,645
Other expense - net		(863	)		(901	)
Interest expense		28,865			27,785
INCOME BEFORE INCOME TAXES		43,411			43,959
Income taxes		14,942			17,088
Equity in earnings of the Ohio operations - net of tax		5,572			5,470
NET INCOME	$	34,041		$	32,341

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,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	34,041		$	32,341
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization		48,458			46,778
Provision for uncollectible accounts		7,548			7,044
Deferred income taxes & investment tax credits		(5,705	)		5,170
Expense portion of pension & postretirement periodic benefit cost		1,269			1,218
Equity in earnings of the Ohio operations - net of tax		(5,572	)		(5,470	)
Other non-cash charges - net		530			1,114
Changes in working capital accounts:
Accounts receivable, including due from Vectren companies
& accrued unbilled revenue		57,057			(56,143	)
Inventories		(2,467	)		(415	)
Recoverable/refundable natural gas costs		31,005			8,775
Prepayments & other current assets		10,755			(13,060	)
Accounts payable, including to Vectren companies
& affiliated companies		(51,543	)		51,332
Accrued liabilities		(3,242	)		7,900
Changes in noncurrent assets		(2,999	)		(2,257	)
Changes in noncurrent liabilities		(8,620	)		(5,271	)
Net cash flows from operating activities		110,515			79,056
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term term debt payable to Utility Holdings		107,755			-
Requirements for:
Retirement of long-term debt		(48,354	)		(49,911	)
Dividend to parent		(25,354	)		(28,324	)
Net change in short-term borrowings, including from Utility Holdings		(96,219	)		53,634
Net cash flows from financing activities		(62,172	)		(24,601	)
CASH FLOWS FROM INVESTING ACTIVITIES
Requirements for :
Capital expenditures		(51,299	)		(48,617	)
Other investments		-			(1,853	)
Net cash flows from investing activities		(51,299	)		(50,470	)
Cash & cash equivalents:
Net increase (decrease) in cash & cash equivalents		(2,956	)		3,985
Cash & cash equivalents at beginning of period		5,609			1,624
Cash & cash equivalents at end of period	$	2,653		$	5,609
Cash paid during the year for:
Interest	$	27,189		$	26,462
Income taxes		13,162			18,369

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, 2005	$	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
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

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 565,000 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% 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)	2006		2005
Gas in storage - at LIFO cost	$	14,333	$	11,338
Materials & supplies		2,174		2,691
Other		778		789
Total inventories	$	17,285	$	14,818

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, 2006, and 2005, by approximately $30 million and $47 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)	2006					2005
	Original Cost		Depreciation Rates as a Percent of Original Cost			Original Cost		Depreciation Rates as a Percent of Original Cost
Utility plant	$	1,321,367		3.8	%	$	1,271,259		3.7	%
Construction work in progress		26,021		-			29,083		-
Total original cost	$	1,347,388				$	1,300,342

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)	2006		2005
AFUDC – borrowed funds	$	758	$	231
AFUDC – equity funds		-		73
Total AFUDC capitalized	$	758	$	304

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 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 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. 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.

Asset retirement obligations total $7.1 million at December 31, 2006 and $6.7 million at December 31, 2005, and are included in Other Liabilities. During 2006, the Company recorded accretion of $0.4 million. In 2005, the Company did not record any accretion and recorded additional liabilities of $6.7 million, related to the adoption of FASB Interpretation No. 47.

F.     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).

9

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.

Regulatory assets consist of the following:

	At December 31,
(In thousands)	2006		2005
Amounts currently recovered through base rates:
Unamortized debt issue costs & premiums paid to reacquire debt	$	8,659	$	9,768
Rate case expenses		172		360
		8,831		10,128
Future amounts recoverable from ratepayers:
Income taxes		8,211		7,831
Amounts currently recovered through authorized tracking mechanisms		5,788		2,003
Total regulatory assets	$	22,830	$	19,962

Indiana Gas is not earning a return on the $8.8 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 consist of the following:

	At December 31,
(In thousands)	2006		2005
Cost of removal	$	146,296	$	136,317
Asset retirement obligations & other		6,505		6,677
Total regulatory liabilities	$	152,801	$	142,994

Cost of Removal

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).

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 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.

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)	2006		2005
Operating revenues	$	360,711	$	395,383
Gas operating margin		114,652		115,057
Operating income		12,131		11,230
Net income		11,856		11,637
At December 31,
(In thousands)		2006		2005
Net utility plant	$	311,997	$	301,399
Current assets		135,913		171,715
Goodwill - net		199,457		199,457
Other non-current assets		19,751		11,099
Total assets	$	667,118	$	683,670
Owners' net investment	$	429,268	$	431,218
Current liabilities		114,299		141,510
Noncurrent liabilities		123,551		110,942
Total liabilities & owners' net investment	$	667,118	$	683,670

11

Ohio Lost Margin Recovery/Conservation Filing

In September 2006, the PUCO approved a conservation proposal that would implement a decoupling approach, including a related conservation program, for the Ohio operations. The PUCO decision was issued following a hearing process and the submission of a settlement by VEDO, the Ohio Consumer Counselor (OCC) and the Ohio Partners for Affordable Energy (OPAE). That settlement was contested by the PUCO Staff. In the decision, the PUCO addressed decoupling by approving a two year, $2 million total, low-income conservation program to be funded 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 the company and the revenues approved by the PUCO in VEDO’s most recent rate case. The decision produced an outcome that was different from the settlement. Following the decision, VEDO and the OPAE advised the PUCO that they would accept the outcome even though it differed from the terms of the settlement. The OCC sought rehearing of the decision, which was denied in December, and thereafter the OCC advised the PUCO that the OCC was withdrawing from the settlement. At that point the OCC also initiated the process for appealing the PUCO’s September and December decisions to the Ohio Supreme Court. Thereafter, VEDO, the OPAE and the PUCO Staff advised the PUCO that they accepted the terms provided in the September decision, as affirmed by the December rehearing decision. Since that time there have been a number of procedural filings by the parties and presently the company is awaiting a further decision from the PUCO. VEDO believes that the PUCO had the necessary legal basis for its decisions and thus should confirm the outcome provided in the September decision.

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 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 2003, VEDO recorded a reserve of $1.1 million for this matter. An additional pretax charge of $4.1 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, VEDO 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. VEDO has appealed the $1.98 million disallowance to the Ohio Supreme Court as well. Briefings of all matters and oral arguments were completed in November 2006, and the parties are awaiting the Court’s ruling.

With respect to the most recent GCR audit covering the period of November 1, 2002 through October 31, 2005, the PUCO staff recommended a disallowance of approximately $830,000 related solely to the retention of a reserve margin for the winter of 2002/2003. VEDO had previously reserved for the possible disallowance given the June 2005 PUCO order but has contested the disallowance. The PUCO will issue a decision on that issue in 2007.

As a result of the June 2005 PUCO order, an annual bidding process for VEDO’s gas supply and portfolio administration services has been established. Since November 1, 2005, VEDO has used a third party provider for these services.

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 some level of on-going costs to comply with the Pipeline Safety Improvement Act of 2002 as well as the funding of conservation programs.

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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 $61.0 million and $60.7 million for the years ended December 31, 2006, and 2005, respectively.

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 $13.4 million in 2006 and $11.6 million in 2005. Amounts owed to Miller at December 31, 2006 are included in Payables to other Vectren companies and at December 31, 2005 are included in Accounts payable to affiliated 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 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 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, 2006, and 2005, periodic pension costs totaling $1.5 million and $1.4 million, respectively, were directly charged by Vectren to the Company. For the years ended December 31, 2006, and 2005, other periodic postretirement benefit costs totaling approximately $0.2 and $0.3 million, respectively, were directly charged by Vectren to the Company. As of December 31, 2006, and 2005, $10.1 million and $14.5 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 $5.9 million and $3.0 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 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.

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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 $270.1 million is outstanding at December 31, 2006, and Utility Holdings’ $700 million unsecured senior notes outstanding at December 31, 2006. 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.

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)	2006			2005
Non-current deferred tax liabilities (assets):
Depreciation & cost recovery timing differences	$	76,856		$	81,808
Regulatory assets recoverable through future rates		9,449			9,625
Regulatory liabilities to be settled through future rates		(1,238	)		(1,793	)
Employee benefit obligations		(6,828	)		(6,959	)
Other – net		3,003			(701	)
Net non-current deferred tax liability		81,242			81,980
Current deferred tax liability:
Deferred fuel costs - net		(1,170	)		2,055
Other – net		(549	)		-
Net deferred tax liability	$	79,523		$	84,035

At December 31, 2006, and 2005, investment tax credits totaling $1.8 million and $2.6 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)	2006			2005
Current:
Federal	$	16,091		$	8,367
State		4,556			3,551
Total current taxes		20,647			11,918
Deferred:
Federal		(4,721	)		4,968
State		(170	)		1,106
Total deferred taxes		(4,891	)		6,074
Amortization of investment tax credits		(814	)		(904	)
Total income taxes	$	14,942		$	17,088

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

	Year Ended December 31,
	2006			2005
Statutory rate		35.0	%		35.0	%
State & local taxes, net of federal benefit		7.1			6.2
Amortization of investment tax credit		(1.9	)		(2.1	)
Adjustment to income tax accruals & other, net		(5.8	)		(0.2	)
Effective tax rate		34.4	%		38.9	%

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, 2006, and 2005, totaled $501.3 million and $604.6 million, respectively. Amounts owed to ProLiance at December 31, 2006, and 2005, for those purchases were $56.4 million and $115.7 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. Regulatory approval was received on April 25, 2006, from the IURC for ProLiance to provide natural gas supply services to the Company through March 2011.

Other Affiliate Transactions

Vectren has ownership interests in other affiliated companies accounted for using the equity method of accounting that performed facilities locating and meter reading services to the Company. For the years ended December 31, 2006, and 2005, fees for these services paid by the Company to Vectren were less than $0.1 million and $0.3 million, respectively. Amounts charged by these affiliates are market based. Amounts owed to unconsolidated affiliates of Vectren, other than ProLiance, totaled zero and $0.6 million at December 31, 2006, and 2005, respectively.

6.     Borrowing Arrangements & Other Financing Transactions

Short-Term Borrowings

As of December 31, 2006, 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, 2006, and 2005, were $66.6 million and $162.8 million, respectively. The intercompany credit line totals $325 million, but is limited to Utility Holdings’ available capacity ($245 million at December 31, 2006) 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.

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See the table below for interest rates and outstanding balances.

	Year ended December 31,
(In thousands)	2006			2005
Weighted average total outstanding during
the year due from Utility Holdings (in thousands)	$	54,558		$	48,336
Weighted average interest rates during the year:
Utility Holdings		4.88	%		3.61	%

Long-Term Debt

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

	At December 31,
(In thousands)	2006			2005
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			-
2031, 7.25%		-			48,354
2035, 6.10%		50,569			-
2036, 5.95%		32,470			-
Total long-term debt payable to Utility Holdings	$	243,838		$	184,437
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
Total long-term debt outstanding payable to third parties		127,500			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	$	101,000		$	127,500

Issuances payable to Utility Holdings

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 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. In 2005, the Company called at par $49.9 million of Indiana Gas insured quarterly senior unsecured notes originally due in 2030, which had a stated interest rate of 7.45%.

Long-Term Debt Sinking Fund Requirements & Maturities

Maturities and sinking fund requirements on long-term debt during the five years following 2006 (in millions) are $6.5 in 2007, zero in 2008, 2009, 2010 and $ 99.0 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 2006 (in millions) is $20.0 in 2007, 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, 2006, 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, those that operated these facilities may now be required to take remedial action if certain byproducts 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. 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.

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In conjunction with data compiled by environmental consultants, 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 $20.4 million.

The estimated accrued costs are limited to Indiana Gas’ proportionate share of the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26 sites with other potentially responsible parties (PRP), which serve to limit Indiana Gas’ share of response costs at these 19 sites to between 20% and 50%. With respect to insurance coverage, Indiana Gas has received and recorded settlements from all known insurance carriers in an aggregate amount approximating $20.4 million.

Environmental matters related to Indiana Gas’ manufactured gas plants 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 they presently expect to incur in connection with activities at these sites, it is possible that future events may require some level of additional remedial activities which are not presently foreseen.

9.     Rate & Regulatory Matters

Lost Margin Recovery/Conservation Filings

In December 2006, the IURC approved a settlement agreement between the Company and the OUCC that provides for a 5-year energy efficiency program to be implemented. The order allows the Company to recover the costs of promoting the conservation of natural gas through conservation trackers that work in tandem with a lost margin recovery mechanism that would provide for recovery of 85% of the difference between revenues actually collected by the Company and the revenues approved in the Company’s most recent rate case. The order was implemented in the Company’s service territory in December 2006. While most expenses associated with these programs are recoverable, in the first program year, the Company is required to fund $1.2 million in program costs without recovery.

Weather Normalization

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

The NTA mechanism will mitigate volatility in distribution charges created by fluctuations in weather by lowering customer bills when weather is colder than normal and increasing customer bills when weather is warmer than normal. The NTA 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 $125,000 to a universal service fund program or other low-income assistance program for the duration of the NTA or until a general rate case.

Rate structures in VEDO’s gas territory do not include weather normalization-type clauses.

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.

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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. 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.

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 and fuel cost adjustment mechanisms. Although its regulated operations are exposed to limited commodity price risk, volatile natural gas prices can result in higher working capital requirements, increased expenses includingunrecoverable 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, 2006 and 2005, 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,
	2006				2005
(In thousands)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt due to third parties	$	127,500	$	132,691	$	127,500	$	137,048
Long-term debt due to Utility Holdings		243,838		244,796		184,437		193,970
Short-term debt due to Utility Holdings		66,626		66,626		162,845		162,845

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)	2006			2005
AFUDC	$	758		$	304
Other income		602			868
Donations & regulatory expenses		(2,223	)		(2,073	)
Total other – net	$	(863	)	$	(901	)

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

	At December 31,
(In thousands)		2006		2005
Prepaid gas delivery service		$	66,235	$	69,330
Prepaid taxes & other			4,231		10,172
Total prepayments & other current assets		$	70,466	$	79,502

Accrued liabilities in the Balance Sheets consist of the following:

             

	At December 31,
(In thousands)	2006		2005
Customer advances & deposits	$	22,146	$	17,008
Accrued gas imbalance		9,918		10,784
Accrued taxes		9,074		10,557
Accrued interest		5,289		4,551
Deferred income taxes		-		2,055
Accrued salaries & other		9,199		12,938
Total accrued liabilities	$	55,626	$	57,893

12. Adoption of Other Accounting Standards

SFAS No. 159

In February 2007, the FASB issued Statement No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159). SFAS 159 permits entities to choose to measure certain financial assets and financial liabilities at fair value. Fair value measurement would be applied to eligible items at specified election dates with unrealized gains and losses on such items reported in earnings at each subsequent reporting date. The fair value option may be applied instrument by instrument with few exceptions, must be applied to entire instruments and not to portions of thereof, and is irrevocable. SFAS 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. Early adoption is permitted when certain conditions are met. Application of this standard is prospective, unless it is adopted early, and then retrospective application is allowed. The Company is currently assessing the impact of this standard and does not expect to adopt it early.

SFAS No. 158

On December 31, 2006, and after calculating the balance sheet impact of Vectren’s retirement plans using the accounting guidance prescribed by SFAS 87 and SFAS 106, the Company adopted 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).  SFAS 158 required Vectren to recognize the funded status of its pension plans and postretirement plans. SFAS 158 defines the funded status of a defined benefit plan as its assets less its projected benefit obligation, which includes projected salary increases, and defines the funded status of a postretirement plan as its assets less its accumulated postretirement benefit obligation. The impacts of adopting this standard were recorded at Vectren and are not reflected at the Indiana Gas level.

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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, and interim periods within those fiscal years with early adoption encouraged.The Company is currently assessing the impact this statement will have on its financial statements and results of operations, and does not expect to adopt it early.

FIN 48

In June 2006, the FASB issued 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 interpretation is effective for fiscal years beginning after December 15, 2006. The adoption of this standard is not expected to have a material impact on operating results or financial condition.

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

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 in the fourth quarter of 2005 for a normal temperature adjustment mechanism (NTA). 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, 2006, earnings were $34.0 million as compared to $32.3 million in 2005, an increase of $1.7 million. The NTA and lost margin recovery provided increased earnings of $3.8 million after tax. The effects of this increase along with a lower effective tax rate were partially offset by continuing usage declines and increased depreciation and interest costs.

Significant Fluctuations

Gas Operating Margin

Volumetric sales to residential and commercial customers are seasonal and are also impacted by weather and price sensitive reductions in volumes sold. The NTA and lost margin recovery mechanisms, however, somewhat mitigate the margin effect that would otherwise be caused by volumetric variations. 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. Following is a discussion and analysis of margin generated from regulated utility operations.

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	Year Ended December 31,
(In millions)	2006		2005
Gas utility revenues	$	739,161	$	831,741
Cost of gas sold		503,025		595,940
Total gas utility margin	$	236,136	$	235,801
Margin attributed to:
Residential & commercial customers	$	204,741	$	203,864
Industrial customers		26,716		27,046
Other customers		4,679		4,891
Sold & transported volumes in MDth attributed to:
Residential & commercial customers		55,524		64,111
Industrial customers		49,487		51,510
Total sold & transported volumes		105,011		115,621

Gas utility margins were $236.1 million for the year ended December 31, 2006, an increase of $0.3 million compared to 2005. The effects of the NTA implemented in late 2005 and the lost margin recovery authorization implemented in the fourth quarter of 2006 offset the effects of warm weather and lower usage.

For the year ended December 31, 2006, compared to 2005, management estimates that weather 14 percent warmer than normal and 9 percent warmer than prior year would have decreased margins $8.1 million compared to the prior year, had the NTA not been in effect. Weather, net of the NTA, resulted in an approximate $5.8 million year over year increase in gas utility margin. Incremental revenue associated with the lost margin recovery totaled $0.7 million in 2006. The average cost per dekatherm of gas purchased was $8.61 in 2006 and $9.15 in 2005.

Operating Expenses

Other Operating

Other operating expenses decreased $0.5 million for the year ended December 31, 2006, as compared to 2005. The decrease is primarily attributable to lower property insurance and legal and administrative costs, partially offset by higher maintenance and bad debt expenses.

Depreciation & Amortization

For the year ended December 31, 2006, depreciation expense increased $1.7 million compared to 2005. The increase resulted primarily from normal additions to utility plant.

Taxes Other Than Income Taxes

Taxes other than income taxes decreased $1.3 million in 2006 compared to 2005. The decrease is primarily attributable to decreased collections of utility receipts taxes due to lower revenues.

Income Taxes

For the year ended December 31, 2006, income taxes decreased $2.1 million compared to 2005. Income taxes in 2006 include adjustments to reflect income taxes reported on final state and federal income tax returns.

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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 $11.9 million in 2006 and $11.6 million in 2005. Indiana Gas’ share of those earnings was $5.6 million and $5.5 million, respectively. The effects of a base rate increase, which increased margin $4.2 million year over year, and a $4.1 million ($2.5 million after tax) charge recorded pursuant to the disallowance of Ohio gas costs in 2005 more than offset the effect of unfavorable weather and declining usage. 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 $2.7 million and $2.3 million for the years ended December 31, 2006 and 2005, respectively. 

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SELECTED GAS OPERATING STATISTICS:

INDIANA GAS COMPANY
SELECTED UTILITY
OPERATING STATISTICS
(Unaudited)
	For the Year Ended
	December 31,
	2006			2005
OPERATING REVENUES (In thousands):
Residential	$	498,832		$	561,809
Commercial		201,763			229,440
Industrial		33,886			35,599
Misc Revenue		4,680			4,893
	$	739,161		$	831,741
MARGIN (In thousands):
Residential	$	156,051		$	155,825
Commercial		48,690			48,039
Industrial		26,716			27,046
Misc Revenue		4,679			4,891
	$	236,136		$	235,801
GAS SOLD & TRANSPORTED (In MDth):
Residential		38,211			44,623
Commercial		17,313			19,488
Industrial		49,487			51,510
		105,011			115,621
YEAR END CUSTOMERS:
Residential		515,016			511,926
Commercial		49,449			49,259
Industrial		849			869
		565,314			562,054
WEATHER AS A % OF NORMAL:
Heating Degree Days		86	%		95	%

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