Vectren (VVC) 8-K Regulation FD Disclosure

Exhbit 99.1

INDIANA GAS COMPANY, INC.

 REPORTING PACKAGE

For the year ended December 31, 2009

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	22
Selected Operating Statistics	25

Additional Information

This annual reporting package provides additional information regarding the operations Indiana Gas Company, Inc. (Indiana Gas) that is supplemental to the information contained in the 2009 annual reports filed on Form 10-K of Vectren Corporation (Vectren) and Vectren Utility Holdings, Inc. (Utility Holdings), the parent companies of  Indiana Gas.  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	MDth / MMDth:  thousands / millions of dekatherms
FASB:  Financial Accounting Standards Board	OUCC:  Indiana Office of the Utility Consumer Counselor
FERC:  Federal Energy Regulatory Commission	PUCO:  Public Utilities Commission of Ohio
IDEM:  Indiana Department of Environmental Management	USEPA:  United States Environmental Protection Agency
IURC:  Indiana Utility Regulatory Commission	Throughput:  combined gas sales and gas transportation volumes
MCF / MMCF / BCF:  thousands / millions / billions of cubic feet

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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, 2009 and 2008, and the related statements of income, common shareholder’s equity, and cash flows for the years then ended.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing standards as established by the Auditing Standards Board (United States) and in accordance with the auditing standards of the Public Company 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, 2009 and 2008, 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

March 16, 2010

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FINANCIAL STATEMENTS

INDIANA GAS COMPANY, INC.

BALANCE SHEETS

(In thousands)

	December 31,
	2009		2008
ASSETS
Utility Plant
Original cost	$	1,560,387	$	1,503,756
Less:  accumulated depreciation & amortization		589,121		551,004
Net utility plant		971,266		952,752
Current Assets
Cash & cash equivalents		3,240		2,712
Accounts receivable - less reserves of $1,928 &
$2,736, respectively		33,475		65,955
Receivables due from other Vectren companies		-		3,686
Accrued unbilled revenues		53,617		86,837
Inventories		17,624		16,225
Prepayments & other current assets		43,388		76,248
Total current assets		151,344		251,663
Investment in the Ohio operations		254,280		245,965
Other investments		8,326		6,626
Regulatory assets		25,145		32,382
Other assets		9,052		5,650
TOTAL ASSETS	$	1,419,413	$	1,495,038

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,
	2009		2008
LIABILITIES & SHAREHOLDER'S EQUITY
Common Shareholder's Equity
Common stock (no par value)	$	367,995	$	367,995
Retained earnings		75,631		106,997
Total common shareholder's equity		443,626		474,992
Long-term debt payable to third parties - net of current maturities &
debt subject to tender		111,000		121,000
Long-term debt payable to Utility Holdings		279,584		279,935
Total long-term debt, net		390,584		400,935
Commitments & Contingencies (Notes 6, 9-11)
Current Liabilities
Accounts payable		40,688		56,650
Accounts payable to affiliated companies		46,055		61,022
Payables to other Vectren companies		18,585		16,654
Refundable natural gas costs		8,021		1,618
Accrued liabilities		51,965		62,994
Short-term borrowings payable to Utility Holdings		58,328		116,887
Long-term debt subject to tender		10,000		-
Total current liabilities		233,642		315,825
Deferred Income Taxes & Other Liabilities
Deferred income taxes		135,809		100,729
Regulatory liabilities		182,199		172,099
Deferred credits & other liabilities		33,553		30,458
Total deferred income taxes & other liabilities		351,561		303,286
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	1,419,413	$	1,495,038

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,
	2009		2008
OPERATING REVENUES	$	664,163	$	864,955
COST OF GAS		394,003		594,890
		270,160		270,065
OPERATING EXPENSES
Other operating		116,252		105,826
Depreciation & amortization		54,655		52,951
Taxes other than income taxes		18,253		20,254
Total operating expenses		189,160		179,031
OPERATING INCOME		81,000		91,034
Other income (expense) - net		1,982		(547	)
Interest expense		27,488		29,217
INCOME BEFORE INCOME TAXES		55,494		61,270
Income taxes		22,209		24,878
Equity in earnings of the
Ohio operations - net of tax		8,315		7,503
NET INCOME	$	41,600	$	43,895

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,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	41,600		$	43,895
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization		54,655			52,951
Provision for uncollectible accounts		6,278			7,003
Deferred income taxes & investment tax credits		34,173			16,281
Expense portion of pension & postretirement periodic benefit cost		1,997			860
Equity in earnings of the Ohio operations - net of tax		(8,315	)		(7,503	)
Other non-cash charges - net		5,380			3,120
Changes in working capital accounts:
Accounts receivable, including due from Vectren companies
& accrued unbilled revenue		59,079			(43,745	)
Inventories		(1,307	)		(5,439	)
Recoverable/refundable natural gas costs		6,404			(10,316	)
Prepayments & other current assets		34,914			(7,612	)
Accounts payable, including to Vectren companies
& affiliated companies		(30,497	)		10,216
Accrued liabilities		(9,141	)		6,758
Changes in noncurrent assets		2,669			3,726
Changes in noncurrent liabilities		(7,620	)		(10,302	)
Net cash flows from operating activities		190,269			59,893
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term term debt payable to Utility Holdings		-			22,220
Requirements for:
Retirement of long-term debt		(351	)		(140	)
Dividend to parent		(72,966	)		(38,924	)
Net change in short-term borrowings, including from Utility Holdings		(58,559	)		30,653
Net cash flows from financing activities		(131,876	)		13,809
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Other investments		-			339
Requirements for :
Capital expenditures		(57,588	)		(71,963	)
Other investments		(277	)		(1,615	)
Net cash flows from investing activities		(57,865	)		(73,239	)
Net change in cash & cash equivalents		528			463
Cash & cash equivalents at beginning of period		2,712			2,249
Cash & cash equivalents at end of period	$	3,240		$	2,712

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, 2008	$	367,995	$	102,026		$	470,021
Net income & comprehensive income				43,895			43,895
Common stock:
Dividends to parent				(38,924	)		(38,924	)
Balance at December 31, 2008	$	367,995	$	106,997		$	474,992
Net income & comprehensive income				41,600			41,600
Common stock:
Dividends to parent				(72,966	)		(72,966	)
Balance at December 31, 2009	$	367,995	$	75,631		$	443,626

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 567,000 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 315,000 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 FASB guidance 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 5.

2.     Summary of Significant Accounting Policies

In applying its accounting policies, the Company makes judgments, assumptions, and estimates that affect the amounts reported in these financial statements and related footnotes.  Examples of transactions for which estimation techniques are used include unbilled revenue, uncollectible accounts, regulatory assets and liabilities, reclamation liabilities, and derivatives and other financial instruments.  Estimates also impact the depreciation of utility plant and testing other assets for impairment.  Recorded estimates are revised when better information becomes available or when actual amounts can be determined.  Actual results could differ from current estimates.

Subsequent Events Review

Management performs a review of subsequent events for any events occurring after the balance sheet date but prior to the date the financial statements are available to be issued.  The Company’s management has performed a review of subsequent events through March 16, 2010.

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.  Cash and cash equivalents are stated at cost plus accrued interest to approximate fair value.

Allowance for Uncollectible Accounts

The Company maintains allowances for uncollectible accounts for estimated losses resulting from the inability of its customers to make required payments. The Company estimates the allowance for uncollectible accounts based on a variety of factors including the length of time receivables are past due, the financial health of its customers, unusual macroeconomic conditions, and historical experience.  If the financial condition of its customers deteriorates or other circumstances occur that result in an impairment of customers’ ability to make payments, the Company records additional allowances as needed.

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Inventories

Inventories consist of the following:

	At December 31,
(In thousands)	2009		2008
Gas in storage - at LIFO cost	$	13,279	$	12,096
Materials & supplies		3,537		3,313
Other		808		816
Total inventories	$	17,624	$	16,225

Based on the average cost of gas purchased during December, the cost of replacing gas in storage carried at LIFO cost exceeded that carrying value at December 31, 2009 and 2008, by approximately $­­13 million and $21 million, respectively.  All other inventories are carried at average cost.

Utility Plant & Related Depreciation

The Company’s Utility Plant is stated at historical cost, inclusive of financing costs and direct and indirect construction costs, less accumulated depreciation and when necessary, impairment charges.  The cost of renewals and betterments that extend the useful life are capitalized.  Maintenance and repairs, including the cost of removal of minor items of property and planned major maintenance projects, are charged to expense as incurred.

The IURC allows the Company to capitalize financing costs associated with Utility Plant based on a computed interest cost and a designated cost of equity funds.  These financing costs are commonly referred to as AFUDC and are capitalized for ratemaking purposes and for financial reporting purposes instead of amounts that would otherwise be capitalized when acquiring nonutility plant.  The Company reports both the debt and equity components of AFUDC in Other – net in the Statements of Income.

When property that represents a retirement unit is replaced or removed, the remaining historical value of such property is charged to Utility plant, with an offsetting charge to Accumulated depreciation, resulting in no gain or loss.  Costs to dismantle and remove retired property are recovered through the depreciation rates as determined by the IURC.

Impairment Reviews

Property, plant and equipment along with other long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired.  This impairment review involves the comparison of an asset’s (or group of assets’) carrying value to the estimated future cash flows the asset (or asset group) is expected to generate over a remaining life.  If this evaluation were to conclude that the carrying value is impaired, an impairment charge would be recorded based on the difference between the 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.

Regulation

Retail public utility operations are subject to regulation by the IURC.  The Company’s accounting policies give recognition to the ratemaking and accounting practices authorized by this agency.

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 the gas adjustment clause 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 & 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 continually assesses the recoverability of costs recognized as regulatory assets and liabilities and the ability to recognize new regulatory assets and liabilities associated with its regulated utility operations.  Given the current regulatory environment in its jurisdiction, the Company believes such accounting is appropriate.

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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.

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).  The Company records 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 Company 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, the Company settles the obligation for its recorded amount or incurs a gain or loss.  To the extent regulation is involved, regulatory assets and liabilities result when accretion and amortization is adjusted to match rates established by regulators and any gain or loss is subject to deferral.

ARO’s included in Other liabilities total $13.3 million and $11.9 million at December 31, 2009 and 2008, respectively.  During 2009, the Company recorded accretion of $0.7 million and increases in estimates, net of cash payments of $0.7 million.  During 2008, the Company recorded accretion of $0.4 million and increases in estimates, net of cash payments of $4.0 million.

Energy Contracts & Derivatives

The Company occasionally executes derivative contracts in the normal course of operations while buying and selling commodities to be used in operations and managing risk.  In most cases, a derivative is recognized on the balance sheet as an asset or liability measured at its fair market value and the change in the derivative's fair market value is 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 (NPNS), it is exempted from mark-to-market accounting.  Most energy contracts executed by the Company are subject to the NPNS exclusion or are not considered derivatives.  Such energy contracts include natural gas purchases from ProLiance Holdings, LLC (ProLiance) and others.

When the Company engages in energy contracts and financial contracts that are derivatives and are not subject to the NPNS or other exclusions, such contracts 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 and any associated collateral 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 regulatory accounting treatment.  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 hedged item are marked to market through earnings.  The offset to contracts affected by regulatory accounting treatment 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 rarely enters into contracts that have a significant impact to the financial statements where internal models are used to calculate fair value.  As of and for the periods presented, related derivative activity is not significant to these financial statements.

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.

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, which totaled $9.2 million in 2009 and $12.1 million in 2008.  Expense associated with utility receipts taxes are recorded as a component of Taxes other than income taxes.

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Fair Value Measurements

Certain financial assets and liabilities as well as certain nonfinancial assets and liabilities, such as the initial measurement of an asset retirement obligation or the use of fair value in goodwill, intangible assets and long-lived assets impairment tests, are valued and/or disclosed at fair value.  The Company describes its fair value measurements using a hierarchy of inputs based primarily on the level of public data used.  Level 1 inputs include quoted market prices in active markets for identical assets or liabilities; Level 2 inputs include inputs other than Level 1 inputs that are directly or indirectly observable; and Level 3 inputs include unobservable inputs using estimates and assumptions developed using internal models, which reflect what a market participant would use to determine fair value. 

Earnings Per Share

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

Other Significant Policies

Included elsewhere in these notes are significant accounting policies related to the investment in the Ohio operations (Note 5) and intercompany allocations and income taxes (Note 6).

3.     Utility Plant & Depreciation

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

	At and For the Year Ended December 31,
(In thousands)	2009					2008
	Original Cost		Depreciation Rates as a Percent of  Original Cost			Original Cost		Depreciation Rates as a Percent of  Original Cost
Utility plant	$	1,532,252		3.9	%	$	1,453,408		3.8	%
Construction work in progress		28,135		-			50,348		-
Total original cost	$	1,560,387				$	1,503,756

4.     Regulatory Assets & Liabilities

Regulatory Assets

Regulatory assets consist of the following:

	At December 31,
(In thousands)	2009		2008
Amounts currently recovered through customer rates related to:
Authorized trackers	$	9,520	$	16,263
Unamortized debt issue costs & premiums paid to reacquire debt		6,047		6,918
Rate case expenses		321		597
		15,888		23,778
Future amounts recoverable from ratepayers related to:
Deferred income taxes		8,558		8,578
Other		699		26
Total regulatory assets	$	25,145	$	32,382

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Indiana Gas is not earning a return on the $15.9 million currently being recovered through base rates.  The weighted average recovery period of regulatory assets currently being recovered is 14 years.  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, 2009 and 2008, the Company has approximately $182.2 million and $172.1 million, respectively, in regulatory liabilities.  Of these amounts, $170.4 million and $161.9 million relate to cost of removal obligations.  The remaining amounts primarily relate to timing differences associated with asset retirement obligations.

5.     Investment in the Ohio Operations

The Company’s investment in the Ohio operations is accounted for using the equity method of accounting.  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 FASB guidance which 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)	2009		2008
Operating revenues	$	291,259	$	408,098
Operating income after income taxes		16,114		15,623
Net income		17,691		15,965
	At December 31,
(In thousands)		2009		2008
Net utility plant	$	379,735	$	346,567
Current assets		131,964		194,700
Goodwill - net		199,457		199,457
Other non-current assets		18,024		21,171
Total assets	$	729,180	$	761,895
Owners' net investment	$	445,061	$	442,874
Current liabilities		112,694		167,103
Noncurrent liabilities		171,425		151,918
Total liabilities & owners' net investment	$	729,180	$	761,895

VEDO Gas Base Rate Order Received

On January 7, 2009, the PUCO issued an order approving the stipulation reached in the VEDO rate case.  The order provides for a rate increase of nearly $14.8 million, an overall rate of return of 8.89 percent on rate base of about $235 million; an opportunity to recover costs of a program to accelerate replacement of cast iron and bare steel pipes, as well as certain service risers; and base rate recovery of an additional $2.9 million in conservation program spending.

The order also adjusted the rate design used to collect the agreed-upon revenue from VEDO's customers.  The order allows for the phased movement toward a straight fixed variable rate design which places substantially all of the fixed cost recovery in the customer service charge.  A straight fixed variable design mitigates most weather risk as well as the effects of declining usage, similar to the Company’s lost margin recovery mechanism, which expired when this new rate design went into effect on February 22, 2009.  In 2008, annual results include approximately $4.3 million of revenue from a lost margin recovery mechanism that did not continue once this base rate increase went into effect.  After year one, nearly 90 percent of the combined residential and commercial base rate margins were recovered through the customer service charge.  The OCC has filed a request for rehearing on the rate design finding by the PUCO.  The rehearing request mirrors similar requests filed by the OCC in each case where the PUCO has approved similar rate designs.  The Ohio Supreme Court has yet to act on the OCC’s request in this instance, but in two similar cases, the Court denied such requests.

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With this rate order the Company has in place for its Ohio gas territory rates that allow for the phased implementation of a straight fixed variable rate design that mitigates both weather risk and lost margin; tracking of uncollectible accounts and percent of income payment plan (PIPP) expenses; base rate recovery of pipeline integrity management expense; timely recovery of costs associated with the accelerated replacement of bare steel and cast iron pipes, as well as certain service risers; and expanded conservation programs now totaling up to $5 million in annual expenditures.  The straight fixed variable rate design will be fully phased in by February 2010.

VEDO Continues the Process to Exit the Merchant Function

On August 20, 2008, the PUCO approved an auction selecting qualified wholesale suppliers to provide the gas commodity to the Company for resale to its customers at auction-determined standard pricing.  This standard pricing is comprised of the monthly NYMEX settlement price plus a fixed adder.  This auction, which is effective from October 1, 2008 through March 31, 2010, is the initial step in exiting the merchant function in the Company’s Ohio service territory.  The approach eliminated the need for monthly gas cost recovery (GCR) filings and prospective PUCO GCR audits.  On October 1, 2008, VEDO’s entire natural gas inventory was transferred, receiving proceeds of approximately $107 million.

The second phase of the exit process begins on April 1, 2010, during which the Company will no longer sell natural gas directly to these customers.  Rather, state-certified Competitive Retail Natural Gas Suppliers, that are successful bidders in a second regulatory-approved auction, will sell the gas commodity to specific customers for 12 months at auction-determined standard pricing.  That auction was conducted on January 12, 2010, and the auction results were approved by the PUCO on January 13.  The plan approved by the PUCO requires that the Company conduct at least two auctions during this phase.  As such, the Company will conduct another auction in advance of the second 12-month term, which will commence on April 1, 2011.  Consistent with current practice, customers will continue to receive one bill for the delivery of natural gas service. 

The PUCO has also provided for an Exit Transition Cost rider, which allows the Company to recover costs associated with the transition.  As the cost of gas is currently passed through to customers through a PUCO approved recovery mechanism, the impact of exiting the merchant function should not have a material impact on Company earnings or financial condition.

6.     Transactions with Other Vectren Companies

Support Services and Purchases

Vectren and Utility Holdings provide corporate and general and administrative assets and services to the Company and allocates costs to the Company, including costs for share-based compensation and for pension and other postretirement benefits that are not directly charged to subsidiaries.  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 at cost.  Indiana Gas received corporate allocations totaling $71.0 million and $73.8 million for the years ended December 31, 2009, and 2008, respectively.  Amounts owed to Vectren and Utility Holdings at December 31, 2009 and 2008 are included in Payables to other Vectren companies.

Retirement Plans & Other Postretirement Benefits

Vectren has multiple defined benefit pension plans and postretirement plans that require accounting in accordance with FASB guidance related to employers’ accounting for defined benefit pension and other postretirement plans.  An allocation of cost 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 FASB guidance related to “multiemployer” benefit accounting.

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For the years ended December 31, 2009 and 2008, periodic pension costs totaling $1.3 million and $0.9 million, respectively, were directly charged by Vectren to the Company.  For the years ended December 31, 2009 and 2008, other periodic postretirement benefit costs totaling $0.2 million and $0.3 million, respectively, were directly charged by Vectren to the Company.  As of December 31, 2008, $2.8 million is included in Deferred credits & other liabilities and represents costs directly charged to the Company that is yet to be funded to Vectren.  At December 31, 2009 and 2008, $8.7 million and $3.2 million, respectively, is included in Other assets for amounts funded in advance to Vectren.

Share-Based Incentive Plans & Deferred Compensation Plans

Indiana Gas does not have share-based compensation plans separate from Vectren.  The Company recognizes its allocated portion of expenses related to share-based incentive plans and deferred compensation plans in accordance with FASB guidance and to the extent these awards are expected to be settled in cash that liability is pushed down to Indiana Gas.  As of December 31, 2009 and 2008, $13.0 million and $12.3 million, respectively, is included in Deferred credits & other liabilities and represents obligations that are yet to be funded to Vectren.

Cash Management Arrangements

The Company participates in Vectren’s centralized cash management program.  See Note 8 regarding long-term and short-term intercompany borrowing arrangements.

Guarantees of Parent Company Debt

Vectren’s three operating utility companies, Southern Indiana Gas Company, Inc., Indiana Gas, and Vectren Energy Delivery of Ohio, Inc. are guarantors of Utility Holdings’ $515 million in short-term credit facilities, of which approximately $16 million is outstanding at December 31, 2009, and Utility Holdings’ $920 million unsecured senior notes outstanding at December 31, 2009.  The guarantees are full and unconditional and joint and several, and Utility Holdings has no subsidiaries other than the subsidiary guarantors.

Miller Pipeline Corporation

Miller Pipeline Corporation (Miller), a wholly owned subsidiary of Vectren, 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 $23.4 million in 2009 and $26.8 million in 2008.  Amounts owed to Miller at December 31, 2009 and 2008 are included in Payables to other Vectren companies.

Income Taxes

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

Deferred income taxes are provided for temporary differences between the tax basis (adjusted for related unrecognized tax benefits, if any) of an asset or liability and its reported amount in the financial statements.  Deferred tax assets and liabilities are computed based on the currently-enacted statutory income tax rates that are expected to be applicable when the temporary differences are scheduled to reverse.  The Company’s rate-regulated utilities recognize regulatory liabilities for deferred taxes provided in excess of the current statutory tax rate and regulatory assets for deferred taxes provided at rates less than the current statutory tax rate.  Such tax-related regulatory assets and liabilities are reported at the revenue requirement level and amortized to income as the related temporary differences reverse, generally over the lives of the related properties.  A valuation allowance is recorded to reduce the carrying amounts of deferred tax assets unless it is more likely than not that the deferred tax assets will be realized.  

Tax benefits associated with income tax positions taken, or expected to be taken, in a tax return are recorded only when the more-likely-than-not recognition threshold is satisfied and measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement.  The Company reports interest and penalties associated with unrecognized tax benefits within Income taxes in the Statements of Income and reports tax liabilities related to unrecognized tax benefits as part of Deferred credits & other liabilities.

Investment tax credits (ITCs) are deferred and amortized to income over the approximate lives of the related property in accordance with the regulatory treatment.  

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Significant components of the net deferred tax liability follow:

	At December 31,
(In thousands)	2009			2008
Non-current deferred tax liabilities (assets):
Depreciation & cost recovery timing differences	$	125,243		$	94,778
Regulatory assets recoverable through future rates		9,824			10,693
Regulatory liabilities to be settled through future rates		(2,510	)		(3,136	)
Employee benefit obligations		(913	)		(6,956	)
Other – net		4,165			5,350
Net non-current deferred tax liability		135,809			100,729
Current deferred tax liabilities (assets):
Deferred fuel costs - net		(99	)		4,710
Other – net		(1,956	)		(2,527	)
Net current deferred tax liability (asset)		(2,055	)		2,183
Net deferred tax liability	$	133,754		$	102,912

At December 31, 2009 and 2008, investment tax credits totaling $0.5 million and $0.7 million, respectively, are included in Deferred credits and other liabilities.  These investment tax credits are amortized over the lives of the related investments.

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

		Year Ended December 31,
		2009		2008
Statutory rate		35.0	%	35.0	%
State & local taxes, net of federal benefit		5.0		5.3
Amortization of investment tax credit		(0.4)		(0.7)
Adjustment to federal income tax accruals & other, net		0.4		1.0
	Effective tax rate	40.0	%	40.6	%

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

	Year Ended December 31,
(In thousands)	2009			2008
Current:
Federal	$	(12,672	)	$	3,844
State		708			4,753
Total current taxes		(11,964	)		8,597
Deferred:
Federal		30,074			15,444
State		4,305			1,270
Total deferred taxes		34,379			16,714
Amortization of investment tax credits		(206	)		(433	)
Total income taxes	$	22,209		$	24,878

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Uncertain Tax Positions

Following is a roll forward of the total amount of unrecognized tax benefits for the two years ended December 31, 2009 and 2008:

(in thousands)	2009			2008
Unrecognized tax benefits at January 1	$	-		$	556
Gross increases - tax positions in prior periods		80			112
Gross decreases - tax positions in prior periods		(382	)		(668	)
Gross increases - current period tax positions		3,424			-
Gross decreases - current period tax positions		-			-
Settlements		104			-
Lapse of statute of limitations		329			-
Unrecognized tax benefits at December 31	$	3,555		$	-

Of the change in unrecognized tax benefits during 2009 and 2008, almost none impacted the effective rate.  The amount of unrecognized tax benefits, which if recognized, that would impact the effective tax rate was insignificant at December 31, 2009 and $0.2 million at December 31, 2008.

As of December 31, 2009, the 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 recognized expense related to interest and penalties totaling approximately $0.2 million in 2009 and none in 2008.  The Company had approximately $0.1 million for the payment of interest and penalties accrued as of December 31, 2009 and 2008.

Unrecognized tax benefits inclusive of interest, penalties and net of secondary impacts which are a component of the Deferred income taxes, totaled $3.4 million and $0.2 million, respectively, at December 31, 2009 and 2008.

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 parent, Vectren Corporation.  Vectren files a consolidated U.S. federal income tax return, and Vectren and/or certain of its subsidiaries file returns in various states.  The Internal Revenue Service (IRS) has conducted examinations of Vectren’s U.S. federal income tax returns for tax years through December 31, 2005.  Subsequent to the year ended December 31, 2009, Vectren received a notice from the IRS that year ended December 31, 2008 is under audit.  The State of Indiana, Vectren’s primary state tax jurisdiction, has conducted examinations of state income tax returns for tax years through December 31, 2007.  The statutes of limitations for assessment of federal and Indiana income tax have expired with respect to tax years through 2002.  

7.     Transactions with ProLiance

ProLiance, a nonutilityenergy marketing affiliate of Vectren and Citizens Energy Group (Citizens), provides services to a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions located throughout the Midwest and Southeast United States.  ProLiance’s customers include Vectren’s Indiana utilities and nonutility gas supply operations as well as Citizens’ utilities.  ProLiance’s primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services. 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 made from ProLiance for resale and for injections into storage for the years ended December 31, 2009 and 2008, totaled $361.3 million and $606.4 million, respectively.  Amounts owed to ProLiance at December 31, 2009 and 2008, for those purchases were $46.1 million and $61.0 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.

8.     Borrowing Arrangements & Other Financing Transactions

Long-Term Debt

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

			At December 31,
(In thousands)			2009			2008
Fixed Rate Senior Unsecured Notes Payable to Utility Holdings:
		2011, 6.625%	$	98,954		$	98,954
		2015, 5.45%		24,716			24,716
		2018, 5.75%		37,129			37,129
		2035, 6.10%		50,569			50,569
		2036, 5.95%		46,487			46,487
		2039, 6.25%		21,729			22,080
	Total long-term debt payable to Utility Holdings		$	279,584		$	279,935
Fixed Rate Senior Unsecured Notes Payable to Third Parties:
	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		$	121,000
Debt subject to tender				(10,000	)		-
Long-term debt payable to third parties - net of
current maturities & debt subject to tender			$	111,000		$	121,000

2039 Notes Payable to Utility Holdings

In March 2008, the Company issued a note payable to Utility Holdings. The term of the note is identical to the terms of notes issued by Utility Holdings in March 2008.  These notes issued by Utility Holdings have an aggregate principal amount of $125 million, are priced at par with an interest rate of 6.25%, and are due April 1, 2039.  The notes have no sinking fund requirements, and interest payments are due monthly.  The notes may be called by Utility Holdings, in whole or in part, at any time on or after April 1, 2013, at 100 percent of principal amount plus accrued interest.  During 2007, Utility Holdings entered into several interest rate hedges with an $80 million notional amount.  Upon issuance of the notes, these instruments were settled resulting in the payment of approximately $9.6 million, which was recorded as a Regulatory asset pursuant to existing regulatory orders.  The value paid is being amortized as an increase to interest expense over the life of the issue.  The proceeds from the sale of these notes less settlement of the hedging arrangements and payments of issuance costs amounted to approximately $111.1 million, of which $22.1 million was issued to Indiana Gas.  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.

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Long-Term Debt Sinking Fund Requirements & Maturities

The Company has no sinking fund requirements on long-term debt during the five years following 2009.  Long-term debt maturities in the five years following 2009 total $99.0 million in 2011 and $5.0 million in 2013.

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.  Other than certain instruments that can be put to the Company upon the death of the holder (death puts), these put or call provisions are not triggered by specific events, but are based upon dates stated in the note agreements.  During 2009 and 2008, the Company repaid approximately $0.4 million and $0.1 million, respectively, related to death puts.  Debt which may be put to the Company for reasons other than a death during the years following 2009 (in millions) is zero in 2009, $10.0 in 2010, $30.0 in 2011, zero in 2012 and thereafter.  Debt that may be put to the Company within one year is classified as Long-term debt subject to tender in current liabilities.

Short-Term Borrowings

Indiana Gas relies entirely on the short-term borrowing arrangements of Utility Holdings for its short-term working capital needs.  Borrowings outstanding at December 31, 2009 and 2008 were $58.3 million and $116.9 million, respectively.  The intercompany credit line totals $325 million, but is limited to Utility Holdings’ available capacity ($462 million at December 31, 2009) and is subject to the same terms and conditions as Utility Holdings’ short term borrowing arrangements, including its 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,
	2009			2008
Weighted average total outstanding during
the year due to Utility Holdings (in thousands)	$	34,711		$	46,864
Weighted average interest rates during the year:
Utility Holdings		0.80	%		3.80	%

Covenants

Both long-term and short-term borrowing arrangements contain customary default provisions; restrictions on liens, sale-leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage and interest coverage, among other restrictions.  As of December 31, 2009, the Company was in compliance with all financial covenants.

9.     Commitments & Contingencies

Legal Proceedings

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

10.   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 owned or operated these facilities may now be required to take remedial action if certain contaminants are found above the regulatory thresholds at these sites.

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

Indiana Gas accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites.  While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, Indiana Gas has recorded cumulative costs that it reasonably expects to incur totaling approximately $23.2 million.  The estimated accrued costs are limited to Indiana Gas’ share of the remediation efforts.  Indiana Gas has arrangements in place for 19 of the 26 sites with other potentially responsible parties (PRP), which limit Indiana Gas’ costs at these 19 sites to between 20 percent and 50 percent.

With respect to insurance coverage, Indiana Gas has settled with all known insurance carriers under insurance policies in effect when these plants were in operation in an aggregate amount approximating $20.8 million.

Environmental remediation costs related to Indiana Gas’ manufactured gas plants and other sites have had a minor impact on results of operations or financial condition since cumulative costs recorded to date approximate PRP and insurance settlement recoveries.  Such cumulative costs are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others.  While the Company 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.  As of December 31, 2009 and December 31, 2008, approximately $3.1 million and $2.9 million, respectively, of accrued, but not yet spent, remediation costs are included in Other Liabilities related to the remediation of these sites.

11.   Rate & Regulatory Matters

Gas Base Rate Order Received

On February 13, 2008, the Company received an order from the IURC which approved the settlement agreement reached in its Vectren North gas rate case.  The order provided for a base rate increase of $16.3 million and a return on equity (ROE) of 10.2 percent, with an overall rate of return of 7.8 percent on rate base of approximately $793 million.  The order 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 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.

With this order, the Company has in place for its North gas territory weather normalization, a conservation and lost margin recovery tariff, tracking of gas cost expense related to a uncollectible accounts expense level based on historical experience and unaccounted for gas through the existing gas cost adjustment mechanism, and tracking of pipeline integrity management expense. 

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12.   Fair Value Measurements

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

	At December 31,
	2009				2008
(In thousands)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt due to third parties	$	121,000	$	131,890	$	121,000	$	113,599
Long-term debt due to Utility Holdings		279,584		292,134		279,935		244,261
Short-term debt due to Utility Holdings		58,328		58,328		116,887		116,887
Cash & cash equivalents		3,240		3,240		2,712		2,712

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

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

13.   Additional Balance Sheet & Operational Information

Accrued liabilities in the Balance Sheets consist of the following:

	At December 31,
(In thousands)	2009		2008
Customer advances & deposits	$	27,579	$	24,955
Accrued gas imbalance		3,306		6,974
Accrued taxes		14,410		22,335
Accrued interest		3,507		3,834
Deferred income taxes		-		2,183
Accrued salaries & other		3,163		2,713
Total accrued liabilities	$	51,965	$	62,994

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

	At December 31,
(In thousands)	2009		2008
Prepaid gas delivery service	$	38,699	$	74,987
Deferred income taxes		2,055		-
Prepaid taxes & other		2,634		1,261
Total prepayments & other current assets	$	43,388	$	76,248

-20-

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

	Year Ended December 31,
(In thousands)	2009			2008
AFUDC - borrowed funds	$	495		$	427
AFUDC - equity funds		174			-
Other income/(expense)		1,597			(599	)
Donations & regulatory expenses		(284	)		(375	)
Total other – net	$	1,982		$	(547	)

Supplemental Cash Flow Information:

	Year Ended December 31,
(In thousands)	2009			2008
Cash paid (received) for:
Interest	$	27,815		$	28,475
Income taxes		(7,654	)		2,973

As of December 31, 2009 and 2008, the Company has accruals related to utility plant purchases totaling approximately $0.7 million and $4.5 million, respectively.

14.   Adoption of Other Accounting Standards

Variable Interest Entities

In June 2009, the FASB issued new accounting guidance regarding variable interest entities (VIE’s).  This new guidance is effective for annual reporting periods beginning after November 15, 2009.  This guidance requires a qualitative analysis of which holder of a variable interest controls the VIE and if that interest holder must consolidate a VIE.  Additionally, it requires additional disclosures and an ongoing reassessment of who must consolidate a VIE.  The Company adopted this guidance on January 1, 2010. The Company does not expect the adoption will have a material impact on the financial statements.

Fair Value Measurements & Disclosures

In January 2010, the FASB issued new accounting guidance on improving disclosures about fair market value.  This guidance amends prior disclosure requirements involving fair value measurements to add new requirements for disclosures about transfers into and out of Levels 1 and 2 and separate disclosures about purchases, sales, issuances, and settlements relating to Level 3 measurements. The guidance also clarifies existing fair value disclosures in regard to the level of disaggregation and about inputs and valuation techniques used to measure fair value.  The guidance also amends prior disclosure requirements regarding postretirement benefit plan assets to require that disclosures be provided by classes of assets instead of major categories of assets.  This guidance is effective for the first reporting period beginning after December 15, 2009.  The Company will adopt this guidance in its first quarter 2010 reporting.  The Company does not expect the adoption will have a material impact on the financial statements.

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

The following discussion and analysis  provides additional information regarding Indiana Gas’ results of operations that is supplemental to the information provided in Vectren Corporation’s and Utility Holdings’ management’s discussion and analysis of results of operations and financial condition contained in those 2009 annual reports filed on Forms 10-K, which  include forward looking statement disclaimers.  The following discussion and analysis should be read in conjunction with Indiana Gas’ financial statements and notes thereto.

Executive Summary of Results of Operations

Indiana Gas generates revenue primarily from the delivery of natural gas to its customers, and Indiana gas’ 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. 

Indiana Gas has in place a disclosure committee that consists of senior management as well as financial management.  The committee is actively involved in the preparation and review of Indiana Gas’ financial statements.

Operating Results

In 2009, Indiana Gas had $41.6 million in net income compared to net income of $43.9 million in 2008.  The $2.3 million decrease compared to 2008 reflects recessionary decreases in large customer usage and an increase in operating expenses, including depreciation expense associated with rate base growth.  A decrease in interest expense, coupled with the return of market values associated with investments related to benefit plans, partially offset these declines.

Significant Fluctuations

Margin

Throughout this discussion, the term Gas Utility margin is used.  Gas Utility margin is calculated as Gas utility revenues less the Cost of gas sold.  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.

Rate Design Strategies

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 been volatile.  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 to these customers due to weather and changing consumption patterns.  Indiana Gas’ territory has both an NTA since 2005 and lost margin recovery since 2006. 

Tracked Operating Expenses

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 gas pipeline integrity management costs, costs to fund Indiana energy efficiency programs, as well as the gas cost component of uncollectible accounts expense based on historical experience and unaccounted for gas.

Recessionary Impacts

Gas margin generated from sales to large customers (generally industrial and other contract customers) is primarily impacted by overall economic conditions and changes in demand for those customers’ products.  The recent recession has had and may continue to have some negative impact on sales to and usage by gas large customers.  This impact has included, and may continue to include, tempered growth, significant conservation measures, and increased plant closures and bankruptcies.  Deteriorating economic conditions may also lead to continued lower residential and commercial customer counts.

-22-

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

Gas Utility margin and throughput by customer type follows:

	Year Ended December 31,
(In thousands)	2009		2008
Gas utility revenues	$	664,163	$	864,955
Cost of gas		394,003		594,890
Total gas utility margin	$	270,160	$	270,065
Margin attributed to:
Residential & commercial customers	$	236,577	$	234,091
Industrial customers		26,766		28,936
Other customers		6,817		7,038
Sold & transported volumes in MDth attributed to:
Residential & commercial customers		61,860		66,791
Industrial customers		44,706		53,241
Total sold & transported volumes		106,566		120,032

Gas utility margins totaling $270.2 million for the year ended December 31, 2009 were essentially flat compared to 2008.  Margin increases associated with regulatory initiatives, including the base rate increase, effective February 14, 2008, were $2.7 million year over year.  Operating costs directly recovered in margin, including revenue and usage taxes, increased margin $2.0 million year over year, reflecting the recovery of higher pass through operating expenses offset by lower revenue taxes.  Management estimates a $2.8 million year over year decrease in margin associated with lower industrial volumes sold, and slightly lower residential and commercial counts decreased margin $0.8 million year over year.   The remaining decrease primarily relates to lower miscellaneous revenues associated with reconnection fees.  The lower fees as well as the lower revenue and usage taxes correlate with lower year over year gas costs.   The average cost per dekatherm of gas purchased was $5.59 in 2009 and $8.35 in 2008.

Operating Expenses

Other Operating

For the year ended December 31, 2009, Other operating expenses were $116.3 million, which is an increase of $10.4 million, compared to 2008.  Approximately $4.9 million of the increase results from  higher costs directly recovered through utility margin.  Examples of such tracked costs include gas pipeline integrity management costs and costs to fund energy efficiency programs.  Increases in other operating expenses in 2009, not directly recovered in margin, include an approximate $3.1 million increase in charges for the use of shared assets and a $2.6 million increase in accruals associated with environmental matters.  Despite significantly lower gas costs due to the recession, uncollectible accounts expense was slightly favorable compared to 2008.

Depreciation & Amortization

For the year ended December 31, 2009, depreciation expense increased $1.7 million compared to 2008.  The increase resulted from normal additions to utility plant.

Taxes Other Than Income Taxes

Taxes other than income taxes decreased $2.0 million in 2009 compared to 2008.  The decrease is primarily attributable to volatility in revenues, inclusive of lower natural gas prices and gas lower volumes sold.  These tax expenses are recovered through revenue.

-23-

Other Income (Expense)– Net

Other income (expense)– net was income of $2.0 million in 2009, a favorable increase of  $2.5million compared to 2008.  The increase is primarily due to the return of market values associated with investments related to benefit plans.

Interest Expense

For the year ended December 31, 2009, interest expense was $27.5 million, a decrease of $1.7 million compared to 2008. Lower short-term interest rates and lower average short-term debt balances have favorably affected interest expense year over year.  The lower average borrowings outstanding are reflective of lower gas prices.

Income Taxes

For the year ended December 31, 2009, income taxes decreased $2.7 million compared to 2008.  The decrease in income taxes is due to lower pre tax income and a lower effective tax rate.

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 $17.7 million in 2009 and $16.0 million in 2008.  Indiana Gas’ share of those earnings was $8.3 million and $7.5 million, respectively.  The increase results from regulatory initiatives, including a base rate increase effective February 22, 2009, offset by recessionary impacts.

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 $9.0 million and $7.2 million for the years ended December 31, 2009 and 2008, respectively. 

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SELECTED GAS OPERATING STATISTICS:

INDIANA GAS COMPANY
SELECTED UTILITY
OPERATING STATISTICS
(Unaudited)
	For the Year Ended
	December 31,
	2009			2008
OPERATING REVENUES (In thousands):
Residential	$	455,278		$	589,736
Commercial		170,361			232,411
Industrial		31,707			36,206
Misc Revenue		6,817			6,602
	$	664,163		$	864,955
MARGIN (In thousands):
Residential	$	181,371		$	179,323
Commercial		55,206			55,201
Industrial		26,766			28,940
Misc Revenue		6,817			6,601
	$	270,160		$	270,065
GAS SOLD & TRANSPORTED (In MDth):
Residential		42,494			45,978
Commercial		19,366			20,813
Industrial		44,706			53,241
		106,566			120,032
AVERAGE CUSTOMERS:
Residential		509,125			510,764
Commercial		49,026			49,363
Industrial		857			849
		559,008			560,976
WEATHER AS A % OF NORMAL:(1)
Heating Degree Days		94	%		99	%
(1) The impact of weather on residential and commercial customers is mitigated by an NTA mechanism

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