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

Attached files

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8-K - IGC REPORTING PKG - VECTREN CORP	vvc_8k.htm
EX-99.2 - EXHIBIT 99.2 - VECTREN CORP	ex99_2.htm

Exhibit 99.1

INDIANA GAS COMPANY, INC. AND SUBSIDIARY

REPORTING PACKAGE

For the year ended December 31, 2011

Contents

		Page Number

	Audited Financial Statements
	Independent Auditors’ Report	2
	Consolidated Balance Sheets	3-4
	Consolidated Statements of Income	5
	Consolidated Statements of Cash Flows	6
	Consolidated Statements of Common Shareholder’s Equity	7
	Notes to Consolidated Financial Statements	8
	Results of Operations	23
	Selected Operating Statistics	26

Additional Information

This annual reporting package provides additional information regarding the operations Indiana Gas Company, Inc. (Indiana Gas) and its subsidiary. This information is supplemental to Vectren Corporation’s (Vectren) annual report for the year ended December 31, 2011, filed on Form 10-K with the Securities and Exchange Commission on February 16, 2012 and Vectren Utility Holdings, Inc.’s (Utility Holdings) 10-K filed on March 2, 2012. 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	IURC: Indiana Utility Regulatory Commission
DOT: Department of Transportation	MCF / MMCF / BCF: thousands / millions / billions of cubic feet
EPA: Environmental Protection Agency	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	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 consolidated balance sheets of Indiana Gas Company, Inc. and subsidiary company (the “Company”) (a wholly owned subsidiary of Vectren Utility Holdings, Inc.) as of December 31, 2011 and 2010, and the related consolidated 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 consolidated financial statements present fairly, in all material respects, the financial position of Indiana Gas Company, Inc. and subsidiary company as of December 31, 2011 and 2010, and the results of their operations and their 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 19, 2012

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FINANCIAL STATEMENTS

INDIANA GAS COMPANY, INC. AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

(In thousands)


	December, 31
	2011		2010
ASSETS
Utility Plant
Original cost	$	1,648,251	$	1,598,799
Less: accumulated depreciation & amortization		667,808		629,571
Net utility plant		980,443		969,228

Current Assets
Cash & cash equivalents		3,088		332
Accounts receivable - less reserves of $3,174 &
$2,594, respectively		32,759		36,926
Receivables due from other Vectren companies		-		4
Accrued unbilled revenues		40,750		61,926
Inventories		22,176		19,550
Recoverable natural gas costs		9,768		5,356
Prepayments & other current assets		44,712		45,236
Total current assets		153,253		169,330

Investment in the Ohio operations		-		262,761
Other investments		9,345		9,390
Regulatory assets		31,534		30,884
Other assets		27,266		15,045
TOTAL ASSETS	$	1,201,841	$	1,456,638

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

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INDIANA GAS COMPANY, INC. AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

(In thousands)


	December 31,
	2011		2010
LIABILITIES & SHAREHOLDER'S EQUITY
Common Shareholder's Equity
Common stock (no par value)	$	259,536	$	369,536
Retained earnings		92,205		80,444
Total common shareholder's equity		351,741		449,980
Long-term debt payable to third parties - net of current maturities &
debt subject to tender		121,000		91,000
Long-term debt payable to Utility Holdings		133,951		180,499
Total long-term debt, net		254,951		271,499
Commitments & Contingencies (Notes 6, 8-11)
Current Liabilities
Accounts payable		36,592		38,070
Accounts payable to affiliated companies		31,538		49,699
Payables to other Vectren companies		13,876		17,737
Accrued liabilities		52,789		54,370
Short-term borrowings payable to Utility Holdings		63,478		74,177
Current maturities of long-term debt payable to Utility Holdings		-		98,954
Long-term debt subject to tender		-		30,000
Total current liabilities		198,273		363,007
Deferred Income Taxes & Other Liabilities
Deferred income taxes		165,819		149,540
Regulatory liabilities		202,078		191,932
Deferred credits & other liabilities		28,979		30,680
Total deferred income taxes & other liabilities		396,876		372,152
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	1,201,841	$	1,456,638

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

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INDIANA GAS COMPANY, INC. AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF INCOME

(In thousands)


	Year Ended December 31,
	2011		2010

OPERATING REVENUES	$	584,152	$	624,300
OPERATING EXPENSES
Cost of gas sold		314,675		355,345
Other operating		110,125		110,856
Depreciation & amortization		57,894		56,227
Taxes other than income taxes		16,648		17,816
Total operating expenses		499,342		540,244

OPERATING INCOME		84,810		84,056

Other income - net		302		728

Interest expense		26,406		27,337

INCOME BEFORE INCOME TAXES		58,706		57,447

Income taxes		24,160		23,613

Equity in earnings of the
Ohio operations - net of tax		8,248		8,481

NET INCOME	$	42,794	$	42,315

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

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INDIANA GAS COMPANY, INC. AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Year Ended December 31,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	42,794		$	42,315
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization		57,894			56,227
Provision for uncollectible accounts		3,525			6,706
Deferred income taxes & investment tax credits		22,584			15,965
Expense portion of pension & postretirement periodic benefit cost		1,099			1,007
Equity in earnings of the Ohio operations - net of tax		(8,248	)		(8,481	)
Other non-cash charges - net		3,495			2,609
Changes in working capital accounts:
Accounts receivable, including due from Vectren companies
& accrued unbilled revenue		21,818			(18,470	)
Inventories		(2,626	)		(1,926	)
Recoverable/refundable natural gas costs		(4,411	)		(13,377	)
Prepayments & other current assets		218			(3,595	)
Accounts payable, including to Vectren companies
& affiliated companies		(21,049	)		(590	)
Accrued liabilities		(3,839	)		2,420
Changes in noncurrent assets		(20,616	)		(12,482	)
Changes in noncurrent liabilities		(4,879	)		(9,878	)
Net cash flows from operating activities		87,759			58,450
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt		107,328			-
Capital contributed from Utility Holdings		-			1,541
Requirements for:
Retirement of long-term debt		(145,502	)		(131	)
Dividend to Utility Holdings		(31,033	)		(37,502	)
Net change in short-term borrowings, including from Utility Holdings		42,982			15,849
Net cash flows from financing activities		(26,225	)		(20,243	)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from other investments		61			-
Requirements for :
Capital expenditures, excluding AFUDC equity		(58,839	)		(40,734	)
Other investments		-			(381	)
Net cash flows from investing activities		(58,778	)		(41,115	)
Net change in cash & cash equivalents		2,756			(2,908	)
Cash & cash equivalents at beginning of period		332			3,240
Cash & cash equivalents at end of period	$	3,088		$	332

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

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INDIANA GAS COMPANY, INC. AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

(In thousands)

	Common			Retained
	Stock			Earnings			Total

Balance at January 1, 2010	$	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

Net income & comprehensive income					42,794			42,794
Common stock:
Transfer of Ohio operations investment (see Note 1)		(110,000	)					(110,000	)
Dividends to Utility Holdings					(31,033	)		(31,033	)
Balance at December 31, 2011	$	259,536		$	92,205		$	351,741

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

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INDIANA GAS COMPANY, INC. AND SUBSIDIARY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1.	Organization and Nature of Operations

Indiana Gas Company, Inc. and subsidiary company (the Company, Indiana Gas or Vectren North), an Indiana corporation, provides energy delivery services to approximately 563,000 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

Prior to December 31, 2011, the Company held a 47 percent interest in the Ohio operations, which provide energy delivery services to over 310,000 natural gas customers located near Dayton in west central Ohio. The remaining 53 percent ownership in the Ohio operations interest was 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. On December 31, 2011, the Company transferred its ownership interest and related financing arrangements in the Ohio operations to VEDO. In accordance with FASB guidance associated with related party transactions, the transfer occurred at book value. The book value of the Company’s investment at the time of transfer was $271.0 million and was financed with long-term debt of $107.3 million, short-term borrowings of $53.7 million, and equity of $110.0 million. This noncash transfer is excluded from the statement of cash flows.

Indiana Gas’ ownership was 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 consolidated 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.

Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its wholly owned subsidiary, after elimination of intercompany transactions.

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 19, 2012.

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

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.

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 Consolidated 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. There were no impairments related to property, plant and equipment during the periods presented.

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.

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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 Consolidated 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 consolidated 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 $8.1 million in 2011 and $8.6 million in 2010. 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.

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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)	2011					2010
	Original Cost		Depreciation Rates as a Percent of Original Cost			Original Cost		Depreciation Rates as a Percent of Original Cost
Utility plant	$	1,637,291		3.8	%	$	1,585,118		3.9	%
Construction work in progress		10,960		-			13,681		-
Total original cost	$	1,648,251				$	1,598,799

4.	Regulatory Assets & Liabilities

Regulatory Assets

Regulatory assets consist of the following:


	At December 31,
(In thousands)	2011		2010
Amounts currently recovered through customer rates related to:
Authorized trackers	$	20,558	$	14,369
Unamortized debt issue costs & premiums paid to reacquire debt		4,498		5,208
Rate case expenses		-		46
		25,056		19,623

Amounts deferred for future recovery		762		-

Future amounts recoverable from ratepayers related to:
Deferred income taxes		1,172		8,923
Other		4,544		2,338
Total regulatory assets	$	31,534	$	30,884

Indiana Gas is not earning a return on the $25.1 million currently being recovered through rates. The weighted average recovery period of regulatory assets currently being recovered is 16 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, 2011 and 2010, the Company has approximately $202.1 million and $191.9 million, respectively, in regulatory liabilities. Of these amounts, $191.2 million and $180.6 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 was accounted for using the equity method of accounting. The Company’s share of the Ohio operations after tax earnings was 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 consolidated 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. On December 31, 2011, the Company transferred its ownership interest in the Ohio operations to VEDO.

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Following is summarized financial data of the Ohio operations:

	Year Ended December 31,
(In thousands)	2011		2010
Operating revenues	$	139,606	$	224,226
Operating income after income taxes		15,260		16,637
Net income		17,505		18,045

	At December 31,
(In thousands)	2010
Net utility plant	$	407,130
Current assets		129,371
Goodwill - net		199,457
Other non-current assets		12,724
Total assets	$	748,682

Owners' net investment	$	455,617
Current liabilities		101,921
Noncurrent liabilities		191,144
Total liabilities & owners' net investment	$	748,682

The Ohio Operations Continue 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 in the Company’s Ohio service territory. The approach eliminated the need for monthly gas cost recovery (GCR) filings and prospective PUCO GCR audits.

The second phase of the exit process began on April 1, 2010. During this phase, the Company 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 the Company conduct at least two annual auctions during this phase. As such, the Company conducted another auction on January 18, 2011 in advance of the second 12-month term which commenced on April 1, 2011. The results of that auction were approved by the PUCO on January 19, 2011. Consistent with current practice, customers continue to receive a single bill for the commodity as well as the delivery component of natural gas service from VEDO.

The PUCO provided for an Exit Transition Cost rider, which allows the Company to recover costs associated with the transition process. Exiting the merchant function has not had a material impact on earnings or financial condition. It, however, has and will continue to reduce Gas utility revenues and have an equal and offsetting impact to Cost of gas sold and revenue related taxes recorded in Taxes other than income taxes as VEDO no longer purchases gas for resale to these customers.

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6.	Transactions with Other Vectren Companies & Affiliates

Miller Pipeline, LLC

Miller Pipeline, LLC (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 incurred by Indiana Gas totaled $23.4 million in 2011 and $12.9 million in 2010. Amounts owed to Miller at December 31, 2011 and 2010 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 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’s Indiana utilities 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’s Indiana utilities and Citizens Energy Group through March 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, 2011 and 2010, totaled $318.1 million and $358.2 million, respectively. Amounts owed to ProLiance at December 31, 2011 and 2010, for those purchases were $31.5 million and $49.7 million, respectively, and are included in Accounts payable to affiliated companies in the Consolidated Balance Sheets. Amounts charged by ProLiance for gas supply services are established by supply agreements with the utility.

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 $55.3 million and $62.9 million for the years ended December 31, 2011, and 2010, respectively. Amounts owed to Vectren and Utility Holdings at December 31, 2011 and 2010 are included in Payables to other Vectren companies.

Retirement Plans & Other Postretirement Benefits

At December 31, 2011, Vectren maintains three qualified defined benefit pension plans (Vectren Corporation Non-Bargaining Retirement Plan, The Indiana Gas Company, Inc. Bargaining Unit Retirement Plan, Pension Plan for Hourly Employees of Southern Indiana Gas and Electric Company), a nonqualified supplemental executive retirement plan, and three other postretirement benefit plans. The defined benefit pension and other postretirement benefit plans, which cover the Company’s eligible full-time regular employees, are primarily noncontributory. The postretirement health care and life insurance plans are a combination of self-insured and fully insured plans. Utility Holdings and its subsidiaries, which includes the Company, comprise the vast majority of the participants and retirees covered by these plans. In September 2011, the FASB issued new accounting guidance that requires enhanced disclosures regarding an employer’s participation in defined benefit pension plans accounted for as “multiemployer” plans. The Company has adopted this guidance for the Company’s 2011 consolidated financial statements as required which resulted in expanded disclosures.

Vectren satisfies the future funding requirements and the payment of benefits from general corporate assets and, as necessary, relies on the Company to support the funding of these obligations. However, the Company has no contractual funding commitment. For the years ended December 31, 2011 and 2010, the Company contributed approximately $10.9 million and $3.8 million, respectively, to Vectren’s defined benefit pension plans. Such contributions are made to Vectren in total and are not plan specific. The combined funded status of Vectren’s plans was 83 percent at both December 31, 2011 and 2010.

Vectren allocates the periodic cost of its retirement plans calculated pursuant to US GAAP to its subsidiaries. Periodic cost, comprised of service cost and interest on that service cost, is directly charged to subsidiaries based on labor at each measurement date and that cost is charged to operating expense and capital projects, using labor charges as the allocation method. For the years ended December 31, 2011 and 2010, costs totaling $1.6 million and $1.4 million, respectively, were directly charged to the Company. Other components of periodic costs (such as interest cost, asset returns, and amortizations) and the service cost related to Vectren and Utility Holdings corporate operations are charged to subsidiaries through the allocation process discussed above. Any difference between funding requirements and allocated periodic costs is recognized as an asset or liability until reflected in periodic costs.

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Neither plan assets nor the ending liability is allocated to individual subsidiaries since these assets and obligations are derived from corporate level decisions. The allocation methodology is consistent with FASB guidance related to “multiemployer” benefit accounting. As impacted by increased funding of pension plans in 2011, the Company has $27.1 million included in Other Assets representing defined benefit funding by the Company that is yet to be reflected in costs, compared to $14.6 million at December 31, 2010.

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, 2011 and 2010, $9.6 million and $8.9 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 7 regarding long-term and short-term intercompany borrowing arrangements.

Guarantees of Parent Company Debt

Utility Holdings’ 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 short-term credit facility, of which approximately $243 million is outstanding at December 31, 2011, and Utility Holdings’ $722 million unsecured senior notes outstanding at December 31, 2011. The guarantees are full and unconditional and joint and several, and Utility Holdings has no subsidiaries other than the subsidiary guarantors.

Income Taxes

Vectren files a consolidated federal income tax return. Pursuant to a subsidiary tax sharing agreement and for financial reporting purposes, Indiana Gas’ 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 consolidated 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 Consolidated 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.

-14-

Significant components of the net deferred tax liability follow:


	At December 31,
(In thousands)	2011			2010
Non-current deferred tax liabilities (assets):
Depreciation & cost recovery timing differences	$	151,768		$	138,928
Regulatory assets recoverable through future rates		6,469			9,171
Regulatory liabilities to be settled through future rates		(2,214	)		(1,858	)
Employee benefit obligations		5,978			1,763
Other – net		3,818			1,536
Net non-current deferred tax liability		165,819			149,540

Current deferred tax liabilities (assets):
Deferred fuel costs - net		3,754			2,004
Other – net		(1,495	)		(2,312	)
Net current deferred tax liability (asset)		2,259			(308	)
Net deferred tax liability	$	168,078		$	149,232

At December 31, 2011 and 2010, investment tax credits totaling $0.3 million and $0.4 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,
	2011			2010
Statutory rate		35.0	%		35.0	%
State & local taxes, net of federal benefit		6.3			6.3
Amortization of investment tax credit		(0.2	)		(0.2	)
Adjustment to federal income tax accruals & other, net		0.1			-
Effective tax rate		41.2	%		41.1	%

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


	Year Ended December 31,
(In thousands)	2011			2010
Current:
Federal	$	(1,795	)	$	3,757
State		3,371			3,891
Total current taxes		1,576			7,648
Deferred:
Federal		20,822			14,708
State		1,881			1,395
Total deferred taxes		22,703			16,103
Amortization of investment tax credits		(119	)		(138	)
Total income taxes	$	24,160		$	23,613

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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 concluded 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 primary focus of the IRS examination is certain repairs and maintenance deductions, an area of particular focus by the IRS throughout the utility industry. Vectren received Notices of Assessment from the IRS related to these deductions. Vectren responded to the assessments in January 2012 and continues to follow industry activities in this area. However, in the event the IRS assessments related to these deductions are upheld, any impact is not expected to be material to the Company’s results of operations or financial condition. 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 2007 for Indiana income tax.

Following is a roll forward of the total amount of unrecognized tax benefits for the two years ended December 31, 2011 and 2010:


(in thousands)	2011			2010
Unrecognized tax benefits at January 1	$	4,467		$	3,555
Gross increases - tax positions in prior periods		-			672
Gross decreases - tax positions in prior periods		(3,367	)		(67	)
Gross increases - current period tax positions		118			431
Settlements		(44	)		-
Lapse of statute of limitations		20			(124	)
Unrecognized tax benefits at December 31	$	1,194		$	4,467

Of the change in unrecognized tax benefits during 2011 and 2010, 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, 2011 and December 31, 2010. As of December 31, 2011, 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 doesn’t expect any changes to this liability for unrecognized income tax benefits within the next 12 months that would significantly impact the Company’s results of operations or financial condition.

The Company recognized income related to interest and penalties totaling approximately $0.1 million in 2011 and expense totaling $0.1 million in 2010. The Company had approximately $0.1 million and $0.2 million for the payment of interest and penalties accrued as of December 31, 2011 and 2010, respectively.

The net liability on the Consolidated 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 $1.2 million and $4.3 million, respectively, at December 31, 2011 and 2010.

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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)			2011	2010
	Fixed Rate Senior Unsecured Notes Payable to Utility Holdings:
		2011, 6.625%	$ -	$ 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
		2039, 6.25%	21,537	21,598
	Total long-term debt payable to Utility Holdings		$ 133,951	$ 279,453
		Current maturities	-	(98,954)
	Long-term debt payable to Utility Holdings - net of current maturities		$ 133,951	$ 180,499

	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)
	Long-term debt payable to third parties - net of debt subject to tender		$ 121,000	$ 91,000

Long-term Debt Issuances

On December 30, 2011, the Company issued three notes payable to Utility Holdings with the following terms: (i) $49.7 million of 5.00 percent notes due 2042, (ii) $36.7 million of 5.02 percent notes due 2026, and (iii) $20.8 million of 5.99 percent notes due 2041. 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. Related to the transfer of the investment in the Ohio operations (see Note 5), these notes were transferred to VEDO at the same terms.

Long-Term Debt Sinking Fund Requirements & Maturities

The Company has no sinking fund requirements on long-term debt during the five years following 2011. Long-term debt maturities in the five years following 2011 total zero in 2012, $5.0 million in 2013, zero in 2014, $44.7 million in 2015, and zero in 2016.

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. Certain instruments can be put to the Company upon the death of the holder (death puts). During 2011 and 2010, the Company repaid approximately $0.1 million and $0.1 million, respectively, related to death puts.

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On October 21, 2011, Utility Holdings notified holders of Utility Holdings $96.2 million 5.95 percent senior notes due 2036, of its intent to call those notes. This call option was exercised at par on November 21, 2011. As a result, IGC retired $46.5 million of debt related to this call.

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, 2011, the Company was in compliance with all debt covenants.

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, 2011 and 2010 were $63.5 million and $74.2 million, respectively. The intercompany credit line totals $325 million, but is limited to Utility Holdings’ available capacity ($107 million at December 31, 2011) 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 thousands)		2011			2010
Year End
	Balance Outstanding	$	63,478		$	74,177
	Weighted Average Interest Rate		0.57	%		0.41	%
Annual Average
	Balance Outstanding	$	53,648		$	53,413
	Weighted Average Interest Rate		0.45	%		0.30	%
Maximum Month End Balance Outstanding		$	119,615		$	82,840

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.	Legislative Matters

Pipeline Safety Law

On January 3, 2012 the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 was signed into law. This new law, which reauthorizes federal pipeline safety programs through fiscal year 2015, provides for enhanced safety, reliability and environmental protection in the transportation of energy products by pipeline. The new law increases federal enforcement authority, grants the federal government expanded authority over pipeline safety, provides for new safety regulations and standards, and authorizes or requires the completion of several pipeline safety-related studies. The DOT is required to promulgate a number of new regulatory requirements. The direction of those regulations will be based on the results of the studies and reports required or authorized by the new law and may eventually lead to further regulatory or statutory requirements.

The Company continues to study the impact of the new law and potential new regulations associated with its implementation. At this time, compliance costs and other effects associated with the increased pipeline safety regulations remain uncertain. However, the new law is expected to result in further investment in pipeline inspections, and where necessary, additional modernization of pipeline infrastructure; and therefore, result in both increased levels of operating expenses and capital expenditures associated with the Company’s natural gas distribution businesses. Operating expenses associated with expanded compliance requirements may grow to approximately $5 million annually. Capital investments, driven by the pipeline safety regulations, are expected to be approximately $55 million over the next five years, which would likely qualify as federally mandated regulatory requirements. The Company expects to seek recovery of capital investments associated with complying with these federal mandates in accordance with Senate Bill 251 (referenced below). Operating expenses are expected to be recovered through Senate Bill 251 or through current tracking mechanisms.

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Indiana House Bill 1004

In May 2011, House Bill 1004 was signed into law. This legislation phases in over four years a two percent rate reduction to the Indiana Adjusted Gross Income Tax for corporations. Pursuant to House Bill 1004, the tax rate will be lowered by one-half percent each year beginning on July 1, 2012, to the final rate of six and one-half percent effective July 1, 2015. Pursuant to FASB guidance, the Company accounted for the effect of the change in tax law on its deferred taxes in the second quarter of 2011, the period of enactment. The impact was not material to results of operations or financial condition as the decrease in Deferred tax liabilities was generally offset by a $6.7 million decrease in Regulatory assets.

Indiana Senate Bill 251

In April 2011, Senate Bill 251 was signed into law. While the bill is broad in scope, it allows for cost recovery outside of a base rate proceeding for federal government mandated projects.

The law provides a framework to recover 80 percent of federally mandated costs through a periodic rate adjustment mechanism outside of a general rate case. Such costs include construction, depreciation, operating and other costs. The remaining 20 percent of those costs are to be deferred for recovery in the utility’s next general rate case. The Company is currently evaluating the impact this law may have on its operations, including applicability to expenditures associated with the integrity, safety, and reliable operation of natural gas pipelines and facilities, among other federally mandated projects and potential projects.

10.	Environmental Matters

In the past, the Company operated facilities to manufacture natural gas. Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years. Under current 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.

The existence, location, and certain general characteristics of 26 gas manufacturing and storage sites have been identified for which the Company may have some remedial responsibility. A remedial investigation/feasibility study (RI/FS) was completed 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. The remaining sites have been submitted to the IDEM's Voluntary Remediation Program (VRP). The Company is currently conducting some level of remedial activities, including groundwater monitoring at certain sites.

The Company has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, the Company has recorded cumulative costs that it reasonably expects to incur totaling approximately $23.1 million. The estimated accrued costs are limited to the Company’s share of the remediation efforts and are therefore net of exposures of other potentially responsible parties (PRP). 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, 2011 and 2010, respectively, approximately $2.6 million and $2.8 million of accrued, but not yet spent, costs are included in Other Liabilities related to these sites.

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11.	Rate & Regulatory Matters

Reporting Location Consolidation Proceeding

The Company implemented a reporting location consolidation plan in 2011 and closed certain locations. On May 26, 2011, the International Brotherhood of Electrical Workers Local 1393, United Steel Workers Locals 12213 and 7441 and others filed a formal complaint with the IURC claiming that the consolidation and simultaneous closing by the Company of select reporting locations endangers public safety and impairs the Company’s ability to provide adequate, safe and reliable service. These parties have asked the IURC to require the Company to reopen previously consolidated reporting locations and maintain and staff those locations. A hearing in this case was held in February 2012, and the Company expects the IURC to act some time in 2012.

Gas Decoupling Extension Filing

On April 14, 2011, the Company filed with the IURC a joint settlement agreement with the OUCC on an extension of the offering of conservation programs and the supporting gas decoupling mechanism originally approved in December 2006. On August 18, 2011, the IURC issued an order approving the settlement as filed, granting the extension of the current decoupling mechanism and recovery of new conservation program costs through December 2015.

12.	Fair Value Measurements

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


	At December 31,
	2011				2010
(In thousands)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt due to third parties	$	121,000	$	143,710	$	121,000	$	137,145
Long-term debt due to Utility Holdings		133,951		159,981		279,453		292,034
Short-term debt due to Utility Holdings		63,478		63,478		74,177		74,177
Cash & cash equivalents		3,088		3,088		332		332

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

Inventories consist of the following:


	At December 31,
(In thousands)	2011		2010
Gas in storage - at LIFO cost	$	18,569	$	15,386
Materials & supplies		2,865		3,367
Other		742		797
Total inventories	$	22,176	$	19,550

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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, 2011 and 2010, by approximately $9 million and $10 million, respectively. All other inventories are carried at average cost.

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


	At December 31,
(In thousands)	2011		2010
Prepaid gas delivery service	$	42,421	$	40,720
Deferred income taxes		-		308
Prepaid taxes & other		2,291		4,208
Total prepayments & other current assets	$	44,712	$	45,236

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

	At December 31,
(In thousands)	2011		2010
Customer advances & deposits	$	29,194	$	27,944
Accrued gas imbalance		2,650		2,187
Accrued taxes		8,549		12,830
Accrued interest		3,271		3,345
Deferred income taxes		2,259		-
Tax collections payable		4,200		5,027
Accrued salaries & other		2,666		3,037
Total accrued liabilities	$	52,789	$	54,370

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


(In thousands)	2011		2010
Asset retirement obligation, January 1	$	14,161	$	13,305
Accretion		911		856
Asset retirement obligation, December 31	$	15,072	$	14,161

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


	Year Ended December 31,
(In thousands)	2011			2010
AFUDC - borrowed funds	$	235		$	156
AFUDC - equity funds		9			-
Other income		481			792
Regulatory expenses		(423	)		(220	)
Total other – net	$	302		$	728

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Supplemental Cash Flow Information:

	Year Ended December 31,
(In thousands)	2011		2010
Cash paid (received) for:
Interest	$	26,480	$	27,499
Income taxes		2,827		7,119

As of December 31, 2011 and 2010, the Company has accruals related to utility plant purchases totaling approximately $0.1 million and $1.4 million, respectively.

14.	Adoption of Other Accounting Standards

Other Comprehensive Income (OCI)

In June 2011, the FASB issued new accounting guidance regarding the presentation of comprehensive income within financial statements. The new guidance will require entities to report components of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements. Under the two-statement approach, the first statement would include components of net income, which is consistent with the income statement format used today, and the second statement would include components of OCI. The guidance does not change the items that must be reported in OCI. The new guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 and retrospective application is required. The Company will adopt this guidance for its quarterly reporting period ending March 31, 2012. The adoption of this guidance will have no material impacts to the Company’s consolidated financial statements.

Fair Value Measurement and Disclosure

In May 2011, the FASB issued accounting guidance to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and International Financial Reporting Standards (IFRS). The amendments are not intended to change the application of the current fair value requirements, but to clarify the application of existing requirements. The guidance does change particular principles or requirements for measuring fair value or disclosing information about fair value measurements. To improve consistency, language has been changed to ensure that U.S. GAAP and IFRS fair value measurement and disclosure requirements are described in the same way. The guidance will be effective for interim and annual periods beginning after December 15, 2011. The Company will adopt this guidance for its quarterly reporting period ending March 31, 2012. The adoption of this guidance is not expected to have a material impact on the Company’s financial position, results of operations or cash flows.

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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 2011 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’ consolidated 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’ consolidated financial statements.

Operating Results

In 2011, Indiana Gas had $42.8 million in net income compared to net income of $42.3 million in 2010. The $0.5 million increase compared to 2010 reflects increased large customer margin driven by higher volumes sold, and lower bad debt expense, which is driven by lower gas costs. In 2011, increased operating expenses associated with planned maintenance activities, environmental remediation efforts, and a brief work stoppage unfavorably impacted year over year results.

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. In addition to timely gas and fuel cost recovery, approximately $11 million of the approximate $110 million in Other operating expenses incurred during 2011 are subject to a recovery mechanism outside of base rates. In 2011, an Indiana state law was passed that expands the ability of utilities to recover certain costs of federally mandated projects outside of a base rate proceeding. Therefore, utilization of these mechanisms will likely increase in the coming years.

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. The IURC has authorized a bare steel and cast iron replacement program.

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.

-23-

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.

Operating Trends

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)	2011		2010

Gas utility revenues	$	584,152	$	624,300
Cost of gas		314,675		355,345
Total gas utility margin	$	269,477	$	268,955
Margin attributed to:
Residential & commercial customers	$	233,690	$	234,327
Industrial customers		28,774		27,854
Other customers		7,013		6,774
Sold & transported volumes in MDth attributed to:
Residential & commercial customers		58,310		62,092
Industrial customers		51,456		49,566
Total sold & transported volumes		109,766		111,658

Gas utility margins totaling $269.5 million for the year ended December 31, 2011 increased approximately $0.5 million compared to 2010. Large customer margin, net of the impacts of regulatory initiatives and tracked costs, increased by $0.9 million, related to higher volumes sold. The increase was partially offset by lower revenues associated with lower gas costs. The average cost per dekatherm of gas purchased was $5.33 in 2011 and $5.74 in 2010.

Operating Expenses

Other Operating

For the year ended December 31, 2011, Other operating expenses were $110.1 million, which is a decrease of $0.7 million, compared to 2010. The decrease primarily reflects lower bad debt expense of $3.5 million which is offset by increased expenses associated with planned maintenance activities and a brief work stoppage.

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Depreciation & Amortization

For the year ended December 31, 2011, depreciation and amortization expense increased $1.7 million compared to 2010. The increase resulted from normal additions to utility plant.

Taxes Other Than Income Taxes

Taxes other than income taxes decreased $1.2 million in 2011 compared to 2010. The year to date decrease is attributable to volatility in revenues and lower property taxes. The tax expense associated with the volatility in revenues is recovered through revenue.

Other Income – Net

Other income – net was $0.3 million in 2011, a decrease of $0.4 million compared to 2010. The decrease reflects lower returns associated with investments that fund benefit plans.

Income Taxes

For the year ended December 31, 2011, income taxes increased $0.5 million compared to 2010. The higher taxes reflect the increase in pre-tax income.

Equity in Earnings of the Ohio Operations

Equity in earnings of the Ohio operations represents Indiana Gas’ former 47% interest in the Ohio operations’ net income. The Ohio operations’ net income was $17.5 million in 2011 and $18.0 million in 2010. Indiana Gas’ share of those earnings was $8.2 million and $8.5 million, respectively. The decrease in earnings is primarily attributable to rate design changes implemented in the first quarter of 2010, offset by increased large customer margin and return on new investments in bare steel/cast iron replacement activities. On December 31, 2011, the Company transferred its ownership interest and related consolidated financing arrangements in the Ohio operations to VEDO. See Note 1 to the Company’s consolidated financial statements for more information regarding this transaction.

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SELECTED GAS OPERATING STATISTICS:

SELECTED UTILITY
OPERATING STATISTICS
(Unaudited)

	For the Year Ended
	December 31,
	2011		2010

OPERATING REVENUES (In thousands):

Residential	$	398,989	$	428,914
Commercial		145,971		157,493
Industrial		32,178		31,118
Other Revenue		7,014		6,775
	$	584,152	$	624,300

MARGIN (In thousands):

Residential	$	180,486	$	180,938
Commercial		53,204		53,389
Industrial		28,774		27,854
Other		7,013		6,774
	$	269,477	$	268,955

GAS SOLD & TRANSPORTED (In MDth):

Residential		40,215		43,022
Commercial		18,095		19,070
Industrial		51,456		49,566
		109,766		111,658

AVERAGE CUSTOMERS:

Residential		513,438		511,598
Commercial		49,141		48,976
Industrial		866		862
		563,445		561,436

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