VECTREN CORP - FORM 8-K - EX-99.1 - EXHIBIT 99.1

Attached files

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8-K - VVC 8K IGC YEAR END REPORTING - VECTREN CORP	vvc_vuhi8k.htm
EX-99.2 - EXHIBIT 99.2 - VECTREN CORP	ex99_2.htm

INDIANA GAS COMPANY, INC.

REPORTING PACKAGE

For the year ended December 31, 2010

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). This information is supplemental to Vectren Corporation’s (Vectren) annual report for the year ended December 31, 2010, filed on Form 10-K with the Securities and Exchange Commission on February 17, 2011 and Vectren Utility Holdings, Inc.’s (Utility Holdings) 10-K filed on March 4, 2011. Vectren and Utility Holdings make available their Securities and Exchange Commission filings and recent annual reports free of charge through its 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	EPA: United States Environmental Protection Agency
IURC: Indiana Utility Regulatory Commission
MCF / MMCF / BCF: thousands / millions / billions of cubic feet	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”) (a wholly owned subsidiary of Vectren Utility Holdings, Inc.) as of December 31, 2010 and 2009, 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, 2010 and 2009, 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.

/s/ DELOITTE & TOUCHE LLP

Indianapolis, Indiana

March 22, 2011

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FINANCIAL STATEMENTS

INDIANA GAS COMPANY, INC.

BALANCE SHEETS

(In thousands)


	December 31,
	2010		2009
ASSETS
Utility Plant
Original cost	$	1,598,799	$	1,560,387
Less: accumulated depreciation & amortization		629,571		589,121
Net utility plant		969,228		971,266

Current Assets
Cash & cash equivalents		332		3,240
Accounts receivable - less reserves of $2,594 &
$1,928, respectively		36,926		33,475
Receivables due from other Vectren companies		4		-
Accrued unbilled revenues		61,926		53,617
Inventories		19,550		17,624
Recoverable natural gas costs		5,356		-
Prepayments & other current assets		45,236		43,388
Total current assets		169,330		151,344

Investment in the Ohio operations		262,761		254,280
Other investments		9,390		8,326
Regulatory assets		30,884		25,145
Other assets		15,045		9,052
TOTAL ASSETS	$	1,456,638	$	1,419,413

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,
	2010		2009
LIABILITIES & SHAREHOLDER'S EQUITY
Common Shareholder's Equity
Common stock (no par value)	$	369,536	$	367,995
Retained earnings		80,444		75,631
Total common shareholder's equity		449,980		443,626
Long-term debt payable to third parties - net of current maturities &
debt subject to tender		91,000		111,000
Long-term debt payable to Utility Holdings		180,499		279,584
Total long-term debt, net		271,499		390,584
Commitments & Contingencies (Notes 6, 8-9)
Current Liabilities
Accounts payable		38,070		40,688
Accounts payable to affiliated companies		49,699		46,055
Payables to other Vectren companies		17,737		18,585
Refundable natural gas costs		-		8,021
Accrued liabilities		54,370		51,965
Short-term borrowings payable to Utility Holdings		74,177		58,328
Current maturities of long-term debt payable to Utility Holdings		98,954		-
Long-term debt subject to tender		30,000		10,000
Total current liabilities		363,007		233,642
Deferred Income Taxes & Other Liabilities
Deferred income taxes		149,540		135,809
Regulatory liabilities		191,932		182,199
Deferred credits & other liabilities		30,680		33,553
Total deferred income taxes & other liabilities		372,152		351,561

TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	1,456,638	$	1,419,413

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,
	2010		2009

OPERATING REVENUES	$	624,300	$	664,163
OPERATING EXPENSES
Cost of gas sold		355,345		394,003
Other operating		110,856		116,252
Depreciation & amortization		56,227		54,655
Taxes other than income taxes		17,816		18,253
Total operating expenses		540,244		583,163

OPERATING INCOME		84,056		81,000

Other income - net		728		1,982

Interest expense		27,337		27,488

INCOME BEFORE INCOME TAXES		57,447		55,494

Income taxes		23,613		22,209

Equity in earnings of the
Ohio operations - net of tax		8,481		8,315

NET INCOME	$	42,315	$	41,600

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,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	42,315		$	41,600
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization		56,227			54,655
Provision for uncollectible accounts		6,706			6,278
Deferred income taxes & investment tax credits		15,965			34,173
Expense portion of pension & postretirement periodic benefit cost		1,007			1,997
Equity in earnings of the Ohio operations - net of tax		(8,481	)		(8,315	)
Other non-cash charges - net		2,609			5,380
Changes in working capital accounts:
Accounts receivable, including due from Vectren companies
& accrued unbilled revenue		(18,470	)		59,079
Inventories		(1,926	)		(1,307	)
Recoverable/refundable natural gas costs		(13,377	)		6,404
Prepayments & other current assets		(3,595	)		34,914
Accounts payable, including to Vectren companies
& affiliated companies		(590	)		(30,497	)
Accrued liabilities		2,420			(9,141	)
Changes in noncurrent assets		(12,482	)		2,669
Changes in noncurrent liabilities		(9,878	)		(7,620	)
Net cash flows from operating activities		58,450			190,269
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from capital contributed from Utility Holdings		1,541			-
Requirements for:
Retirement of long-term debt		(131	)		(351	)
Dividend to Utility Holdings		(37,502	)		(72,966	)
Net change in short-term borrowings, including from Utility Holdings		15,849			(58,559	)
Net cash flows from financing activities		(20,243	)		(131,876	)
CASH FLOWS FROM INVESTING ACTIVITIES
Requirements for :
Capital expenditures, excluding AFUDC equity		(40,734	)		(57,588	)
Other investments		(381	)		(277	)
Net cash flows from investing activities		(41,115	)		(57,865	)
Net change in cash & cash equivalents		(2,908	)		528
Cash & cash equivalents at beginning of period		3,240			2,712
Cash & cash equivalents at end of period	$	332		$	3,240

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, 2009	$	367,995	$	106,997		$	474,992

Net income & comprehensive income				41,600			41,600
Common stock:
Dividends to Utility Holdings				(72,966	)		(72,966	)
Balance at December 31, 2009	$	367,995	$	75,631		$	443,626

Net income & comprehensive income				42,315			42,315
Common stock:
Capital contribution from Utility Holdings		1,541					1,541
Dividends to Utility Holdings				(37,502	)		(37,502	)
Balance at December 31, 2010	$	369,536	$	80,444		$	449,980

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 570,000 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 314,000 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 of 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 issued. The Company’s management has performed a review of subsequent events through March 22, 2011.

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.

Inventories

In most circumstances, the Company’s inventory components are recorded using an average cost method; however, natural gas in storage is recorded using the Last In – First Out (LIFO) method. Inventory is valued at historical cost consistent with ratemaking treatment. Materials and supplies are recorded as inventory when purchased and subsequently charged to expense or capitalized to plant when installed.

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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.

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.

-9-

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).

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 material 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 $8.6 million in 2010 and $9.2 million in 2009. Expense associated with utility receipts taxes are recorded as a component of Taxes other than income taxes.

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).

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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)	2010					2009
	Original Cost		Depreciation Rates as a Percent of Original Cost			Original Cost		Depreciation Rates as a Percent of Original Cost
Utility plant	$	1,585,118		3.9	%	$	1,532,252		3.9	%
Construction work in progress		13,681		-			28,135		-
Total original cost	$	1,598,799				$	1,560,387

4.	Regulatory Assets & Liabilities

Regulatory Assets

Regulatory assets consist of the following:


	At December 31,
(In thousands)	2010		2009
Amounts currently recovered through customer rates related to:
Authorized trackers	$	14,369	$	9,520
Unamortized debt issue costs & premiums paid to reacquire debt		5,208		6,047
Rate case expenses		46		321
		19,623		15,888
Future amounts recoverable from ratepayers related to:
Deferred income taxes		8,923		8,558
Other		2,338		699
Total regulatory assets	$	30,884	$	25,145

Indiana Gas is not earning a return on the $19.6 million currently being recovered through base rates. The weighted average recovery period of regulatory assets currently being recovered is 15 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, 2010 and 2009, the Company has approximately $191.9 million and $182.2 million, respectively, in regulatory liabilities. Of these amounts, $180.6 million and $170.4 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.

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Following is summarized financial data of the Ohio operations:


	Year Ended December 31,
(In thousands)	2010		2009
Operating revenues	$	224,226	$	291,259
Operating income after income taxes		16,637		16,114
Net income		18,045		17,691

	At December 31,
(In thousands)		2010		2009
Net utility plant	$	407,130	$	379,735
Current assets		129,371		131,964
Goodwill - net		199,457		199,457
Other non-current assets		12,724		18,024
Total assets	$	748,682	$	729,180

Owners' net investment	$	455,617	$	445,061
Current liabilities		101,921		112,694
Noncurrent liabilities		191,144		171,425
Total liabilities & owners' net investment	$	748,682	$	729,180

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. Since the straight fixed variable rate design was fully implemented in February 2010, nearly 90 percent of the combined residential and commercial base rate margins were recovered through the customer service charge. The OCC appealed this rate order to the Ohio Supreme Court, which had affirmed PUCO orders authorizing straight fixed variable rate design in two other cases. On December 23, 2010, the Ohio Supreme Court affirmed the PUCO order authorizing straight fixed variable rate design in VEDO’s case.

With this rate order, VEDO has in place 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.

VEDO Continues the Process to Exit the Merchant Function

On August 20, 2008, the PUCO approved the results of 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 was comprised of the monthly NYMEX settlement price plus a fixed adder. This standard pricing, which was effective from October 1, 2008 through March 31, 2010, was the initial step in exiting the merchant function. The approach eliminated the need for monthly gas cost recovery (GCR) filings and prospective PUCO GCR audits.

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The second phase of the exit process began on April 1, 2010. During this phase, VEDO no longer sells natural gas directly to customers. Rather, state-certified Competitive Retail Natural Gas Suppliers, that were successful bidders in a similar regulatory-approved auction, sell the gas commodity to specific customers for a 12 month period at auction-determined standard pricing. The first auction was conducted on January 12, 2010, and the auction results were approved by the PUCO on January 13, 2010. The plan approved by the PUCO required that VEDO conduct at least two annual auctions during this phase. As such, VEDO conducted another auction on January 18, 2011 in advance of the second 12-month term which commences on April 1, 2011. The results of that auction were approved by the PUCO on January 19, 2011. Consistent with current practice, customers will continue to receive a single bill for the commodity as well as the delivery component of natural gas service from VEDO. Vectren Source, Vectren’s wholly owned nonutility retail gas marketer, was a successful bidder in both auctions.

The PUCO provided for an Exit Transition Cost rider, which allows VEDO to recover costs associated with the transition process. Exiting the merchant function should not have a material impact on earnings or financial condition. It, however, has and will continue to reduce VEDO’s Gas utility revenues and have an equal and offsetting impact to its Cost of gas sold as VEDO no longer purchases gas for resale to these customers.

6.	Transactions with Other Vectren Companies & Affiliates

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 $62.9 million and $71.0 million for the years ended December 31, 2010, and 2009, respectively. Amounts owed to Vectren and Utility Holdings at December 31, 2010 and 2009 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 labor 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.

For the years ended December 31, 2010 and 2009, periodic pension costs totaling $1.2 million and $1.3 million, respectively, were directly charged by Vectren to the Company. For the years ended December 31, 2010 and 2009, other periodic postretirement benefit costs totaling $0.2 million in each period were directly charged by Vectren to the Company. At December 31, 2010 and 2009, $14.6 million and $8.7 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, 2010 and 2009, $8.9 million and $13.0 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.

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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’ $350 million in short-term credit facilities, of which approximately $47 million is outstanding at December 31, 2010, and Utility Holdings’ $919 million unsecured senior notes outstanding at December 31, 2010. 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 $14.3 million in 2010 and $23.4 million in 2009. Amounts owed to Miller at December 31, 2010 and 2009 are included in Payables to other Vectren companies.

ProLiance

ProLiance, a nonutility energy 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. Vectren received regulatory approval on April 25, 2006, from the IURC for ProLiance to provide natural gas supply services to the Company through March 2011. On March 17, 2011, an order was received by the IURC providing for ProLiance’s continued provision of gas supply services to the Company and Citizens Gas for the period of April 1, 2011 through March 31, 2016. Indiana Gas purchases all of its natural gas through ProLiance with regulatory approval from the IURC.

Purchases made from ProLiance for resale and for injections into storage for the years ended December 31, 2010 and 2009, totaled $358.2 million and $361.3 million, respectively. Amounts owed to ProLiance at December 31, 2010 and 2009, for those purchases were $49.7 million and $46.1 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.

Income Taxes

Vectren files a consolidated federal income tax return. Pursuant to a subsidiary tax sharing agreement and for financial reporting purposes, Indiana Gas’ 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. Indiana Gas recognizes 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)	2010			2009
Non-current deferred tax liabilities (assets):
Depreciation & cost recovery timing differences	$	138,928		$	125,243
Regulatory assets recoverable through future rates		9,171			9,824
Regulatory liabilities to be settled through future rates		(1,858	)		(2,510	)
Employee benefit obligations		1,763			(913	)
Other – net		1,536			4,165
Net non-current deferred tax liability		149,540			135,809
Current deferred tax liabilities (assets):
Deferred fuel costs - net		2,004			(99	)
Other – net		(2,312	)		(1,956	)
Net current deferred tax liability (asset)		(308	)		(2,055	)
Net deferred tax liability	$	149,232		$	133,754

At December 31, 2010 and 2009, investment tax credits totaling $0.4 million and $0.5 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,
	2010			2009
Statutory rate		35.0	%		35.0	%
State & local taxes, net of federal benefit		6.3			5.0
Amortization of investment tax credit		(0.2	)		(0.4	)
Adjustment to federal income tax accruals & other, net		-			0.4
Effective tax rate		41.1	%		40.0	%

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


	Year Ended December 31,
(In thousands)	2010			2009
Current:
Federal	$	3,757		$	(12,672	)
State		3,891			708
Total current taxes		7,648			(11,964	)
Deferred:
Federal		14,708			30,074
State		1,395			4,305
Total deferred taxes		16,103			34,379
Amortization of investment tax credits		(138	)		(206	)
Total income taxes	$	23,613		$	22,209

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Uncertain Tax Positions

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 income tax 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. Tax years 2006 and 2008 are currently under IRS exam. 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 income tax have expired with respect to tax years through 2005 and through 2006 for Indiana income tax.

Following is a roll forward of the total amount of unrecognized tax benefits for the two years ended December 31, 2010 and 2009:


(in thousands)	2010			2009
Unrecognized tax benefits at January 1	$	3,555		$	-
Gross increases - tax positions in prior periods		672			80
Gross decreases - tax positions in prior periods		(67	)		(382	)
Gross increases - current period tax positions		431			3,424
Settlements		-			104
Lapse of statute of limitations		(124	)		329
Unrecognized tax benefits at December 31	$	4,467		$	3,555

Of the change in unrecognized tax benefits during 2010 and 2009, 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, 2010 and December 31, 2009. As of December 31, 2010, 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. Thus, it is not expected that any changes to these tax positions would have a significant impact on earnings.

The Company recognized expense related to interest and penalties totaling approximately $0.1 million in 2010 and $0.2 million in 2009. The Company had approximately $0.2 million and $0.1 million for the payment of interest and penalties accrued as of December 31, 2010 and 2009, respectively.

The net liability on the Balance Sheet for unrecognized tax benefits inclusive of interest, penalties and net of secondary impacts which are a component of the Deferred income taxes and are benefits, totaled $4.3 million and $3.4 million, respectively, at December 31, 2010 and 2009.

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7.	Borrowing Arrangements & Other Financing Transactions

Long-Term Debt

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


			At December 31,
(In thousands)			2010	2009
	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%	21,598	21,729
	Total long-term debt payable to Utility Holdings		$ 279,453	$ 279,584
		Current maturities	(98,954)	-
	Long-term debt payable to Utility Holdings - net of current maturities		$ 180,499	$ 279,584

	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	(30,000)	(10,000)
	Long-term debt payable to third parties - net of debt subject to tender		$ 91,000	$ 111,000

Long-Term Debt Sinking Fund Requirements & Maturities

The Company has no sinking fund requirements on long-term debt during the five years following 2010. Long-term debt maturities in the five years following 2010 total $99.0 million in 2011, zero in 2012, $5.0 million in 2013, zero in 2014, and $44.7 million in 2015.

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 2010 and 2009, the Company repaid approximately $0.1 million and $0.4 million, respectively, related to death puts. Debt which may be put to the Company for reasons other than a death during the years following 2010 (in millions) is $30.0 in 2011 and 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.

Covenants

Long-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, 2010, the Company was in compliance with all financial covenants.

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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, 2010 and 2009 were $74.2 million and $58.3 million, respectively. The intercompany credit line totals $325 million, but is limited to Utility Holdings’ available capacity ($303 million at December 31, 2010) 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:


		Intercompany Borrowings
(In millions)		2010			2009
Year End
	Balance Outstanding	$	74.2		$	58.3
	Weighted Average Interest Rate		0.41	%		0.25	%
Annual Average
	Balance Outstanding	$	53.4		$	34.7
	Weighted Average Interest Rate		0.30	%		0.80	%
Maximum Month End Balance Outstanding		$	82.8		$	89.6

8.	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.

9.	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.

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 $23.1 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 received approximately $20.8 million from all known insurance carriers under insurance policies in effect when these plants were in operation.

The costs the Company expects to incur 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 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 and those costs may not be subject to PRP or insurance recovery. As of December 31, 2010 and 2009, respectively, approximately $2.8 million and $3.1 million of accrued, but not yet spent, costs are included in Other Liabilities related to the remediation of these sites.

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10.	Fair Value Measurements

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


	At December 31,
	2010				2009
(In thousands)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt due to third parties	$	121,000	$	137,145	$	121,000	$	131,890
Long-term debt due to Utility Holdings		279,453		292,034		279,584		292,134
Short-term debt due to Utility Holdings		74,177		74,177		58,328		58,328
Cash & cash equivalents		332		332		3,240		3,240

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.

11.	Additional Balance Sheet & Operational Information

Inventories consist of the following:


	At December 31,
(In thousands)	2010		2009
Gas in storage - at LIFO cost	$	15,386	$	13,279
Materials & supplies		3,367		3,537
Other		797		808
Total inventories	$	19,550	$	17,624

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, 2010 and 2009, by approximately $10 million and $13 million, respectively. All other inventories are carried at average cost.

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


	At December 31,
(In thousands)	2010		2009
Prepaid gas delivery service	$	40,720	$	38,699
Deferred income taxes		308		2,055
Prepaid taxes & other		4,208		2,634
Total prepayments & other current assets	$	45,236	$	43,388

Accrued liabilities in the Accrued Liabilities in the Balance Sheets consist of the following:


	At December 31,
(In thousands)	2010		2009
Customer advances & deposits	$	27,944	$	27,579
Accrued gas imbalance		2,187		3,306
Accrued taxes		17,857		14,410
Accrued interest		3,345		3,507
Accrued salaries & other		3,037		3,163
Total accrued liabilities	$	54,370	$	51,965

Asset retirement obligations included in Deferred credits & other liabilities in the Balance Sheets roll forward as follows:


(In thousands)	2010		2009
Asset retirement obligation, January 1	$	13,305	$	11,923
Accretion		856		652
Increases (decreases) in estimates, net of cash payments		-		730
Asset retirement obligation, December 31	$	14,161	$	13,305

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


	Year Ended December 31,
(In thousands)	2010			2009
AFUDC - borrowed funds	$	156		$	495
AFUDC - equity funds		-			174
Other income/(expense)		792			1,597
Regulatory expenses		(220	)		(284	)
Total other – net	$	728		$	1,982

Supplemental Cash Flow Information:

	Year Ended December 31,
(In thousands)	2010		2009
Cash paid (received) for:
Interest	$	27,499	$	27,815
Income taxes		7,119		(7,654	)

As of December 31, 2010 and 2009, the Company has accruals related to utility plant purchases totaling approximately $1.4 million and $0.7 million, respectively.

-20-

12.	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 adoption did not have any impact on the consolidated 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 adopted this guidance for its 2010 reporting. Due to the low level of items carried at fair value in the Company’s financial statements, the adoption has not had any material impact.

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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 2010 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 2010, Indiana Gas had $42.3 million in net income compared to net income of $41.6 million in 2009. The $0.7 million increase compared to 2009 reflects the return of large customer usage and a decrease in other operating expenses. Increased depreciation, an increase in the effective tax rate, and volatility in investments that fund deferred compensation benefit plans partially offset the increase.

Trends in Operations

The Regulatory Environment

Gas operations, with regard to retail rates and charges, terms of service, accounting matters, financing, and certain other operational matters are regulated by the IURC. The Company obtained its most recent base rate order in February of 2008. The order authorizes a return on equity of 10.2%. The authorized return reflects the impact of innovative rate design strategies having been authorized by the IURC. Outside of a full base rate proceeding, these innovative approaches to some extent mitigate the impacts of investments in government-mandated projects, operating costs that are volatile or that increase with government mandates, and changing consumption patterns.

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 as more efficient appliances and furnaces are installed, the Company has implemented conservation programs, and the price of natural gas has been volatile. Normal temperature adjustment (NTA) and lost margin recovery mechanisms largely mitigate the effect that would otherwise be caused by variations in volumes sold to these customers due to weather and changing consumption patterns.

Tracked Operating Expenses

Gas costs incurred to serve customers are one of the Company’s most significant operating expenses. Rates charged to natural gas customers contain a gas cost adjustment (GCA) clause. The GCA clause allows the Company to timely charge for changes in the cost of purchased gas, inclusive of unaccounted for gas expense based on historical experience. GCA procedures involve periodic filings and IURC hearings to establish the amount of price adjustments for a designated future period. The procedures also provide for inclusion in later periods of any variances between actual recoveries representing the estimated costs and actual costs incurred. The IURC has also applied the statute authorizing GCA procedures to reduce rates when necessary to limit net operating income to a level authorized in its last general rate order through the application of an earnings test. These earnings tests have not had any material impact to the Company’s recent operating results and are not expected to have any material impact in the foreseeable future.

In addition to timely gas cost recovery, just over $17 million of the Company’s approximate $111 million in other operating expenses incurred during 2010 are subject to a recovery mechanisms outside of base rates. Gas pipeline integrity management costs, costs to fund energy efficiency programs, and the gas cost component of uncollectible accounts expense based on historical experience are recovered by mechanisms outside of standard base rate recovery. Revenues and margins are also impacted by the collection of state mandated taxes, which primarily fluctuate with gas costs.

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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. Following is a discussion and analysis of margin generated from operations.

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)	2010		2009

Gas utility revenues	$	624,300	$	664,163
Cost of gas		355,345		394,003
Total gas utility margin	$	268,955	$	270,160
Margin attributed to:
Residential & commercial customers	$	234,534	$	236,577
Industrial customers		28,005		26,766
Other customers		6,416		6,817
Sold & transported volumes in MDth attributed to:
Residential & commercial customers		62,092		61,860
Industrial customers		49,566		44,706
Total sold & transported volumes		111,658		106,566

Gas utility margins totaling $269.0 million for the year ended December 31, 2010 decreased approximately $1.2 million compared to 2009. Margin decreased $1.5 million due to lower miscellaneous revenues and other revenues associated with lower gas costs. In addition, margin decreased $1.4 million due to lower operating expenses and revenue taxes directly recovered in margin. These decreases were partially offset by an increase in large customer margin, net of the impacts of regulatory initiatives and tracked costs, of $1.4 million due primarily to increased volumes sold. The average cost per dekatherm of gas purchased was $5.74 in 2010 and $5.59 in 2009.

Operating Expenses

Other Operating

For the year ended December 31, 2010, Other operating expenses were $110.9 million, which is a decrease of $5.4 million, compared to 2009. Approximately $0.8 million of the decrease results from lower costs directly recovered through utility margin. Examples of such tracked costs include gas pipeline integrity management costs and costs to fund energy efficiency programs. Accrual adjustments associated with receivables and manufactured gas plant sites totaled $7.3 million in 2009. These decreases were offset by higher levels of performance and share based compensation.

Depreciation & Amortization

For the year ended December 31, 2010, depreciation expense increased $1.6 million compared to 2009. The increase resulted from normal additions to utility plant.

-23-

Taxes Other Than Income Taxes

Taxes other than income taxes decreased $0.4 million in 2010 compared to 2009. The decrease is primarily attributable to volatility in revenues. These tax expenses are recovered through revenue.

Other Income – Net

Other income – net was $0.7 million in 2010, a decrease of $1.3 million compared to 2009. The higher earnings in 2009 reflect the partial recovery from the 2008 market declines associated with investments related to benefit plans.

Income Taxes

For the year ended December 31, 2010, income taxes increased $1.4 million compared to 2009. The higher taxes reflect the increase in pre-tax income and also a lower effective tax rate in 2009. The lower effective tax rate in 2009 reflects adjustments associated with a greater share of Vectren consolidated taxable income being in states with low, or no, state income taxes.

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 $18.0 million in 2010 and $17.7 million in 2009. Indiana Gas’ share of those earnings was $8.5 million and $8.3 million, respectively. The slight increase results from rate design changes in the Ohio service territory and higher industrial margins offset by increased depreciation associated with rate base growth and higher allocated operating expenses.

-24-

SELECTED GAS OPERATING STATISTICS:

INDIANA GAS COMPANY
SELECTED UTILITY
OPERATING STATISTICS
(Unaudited)

	For the Year Ended
	December 31,
	2010		2009

OPERATING REVENUES (In thousands):

Residential	$	428,276	$	455,278
Commercial		158,237		170,361
Industrial		31,341		31,707
Other Revenue		6,446		6,817
	$	624,300	$	664,163

MARGIN (In thousands):

Residential	$	180,330	$	181,371
Commercial		54,204		55,206
Industrial		28,005		26,766
Other		6,416		6,817
	$	268,955	$	270,160

GAS SOLD & TRANSPORTED (In MDth):

Residential		43,022		42,494
Commercial		19,070		19,366
Industrial		49,566		44,706
		111,658		106,566

AVERAGE CUSTOMERS:

Residential		511,598		509,125
Commercial		48,976		49,026
Industrial		862		857
		561,436		559,008

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