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

Attached files

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8-K - 8-K - VECTREN CORP	igc2012reportingpackage8k.htm
EX-99.2 - EXHIBIT 99.2 - VECTREN CORP	exhibit992-2012igcreportin.htm

INDIANA GAS COMPANY, INC. AND SUBSIDIARY

REPORTING PACKAGE

For the year ended December 31, 2012

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, 2012, filed on Form 10-K with the Securities and Exchange Commission on February 15, 2013 and Vectren Utility Holdings, Inc.’s (Utility Holdings) 10-K/A filed on March 1, 2013. 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 financial statements of Indiana Gas Company, Inc. and subsidiary company (the “Company”) (a wholly owned subsidiary of Vectren Utility Holdings, Inc.), which comprise the consolidated balance sheets as of December 31, 2012 and 2011, and the related consolidated statements of income, common shareholder’s equity, and cash flows for the years then ended, and the related notes to the consolidated financial statements.

Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the Company's preparation and fair presentation of the consolidated financial statements in order to design 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. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Indiana Gas Company, Inc. and subsidiary company as of December 31, 2012 and 2011, 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 18, 2013

FINANCIAL STATEMENTS

INDIANA GAS COMPANY, INC. AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

(In thousands)



			December, 31
			2012		2011
ASSETS
Utility Plant
Original cost			$	1,700,112	$	1,648,251
Less: accumulated depreciation & amortization			708,000		667,808
Net utility plant			992,112		980,443

Current Assets
	Cash & cash equivalents		4,092		3,088
	Accounts receivable - less reserves of $2,098 &
		$3,174, respectively	27,828		32,759
	Accrued unbilled revenues		46,273		40,750
	Inventories		15,075		22,176
	Recoverable natural gas costs		20,118		9,768
	Prepayments & other current assets		33,487		44,712
		Total current assets	146,873		153,253

Other investments			9,847		9,345
Regulatory assets			37,237		31,534
Other assets			25,543		27,266
TOTAL ASSETS			$	1,211,612	$	1,201,841

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

INDIANA GAS COMPANY, INC. AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

(In thousands)



				December 31,
					2012		2011
LIABILITIES & SHAREHOLDER'S EQUITY
	Common Shareholder's Equity
		Common stock (no par value)			$	259,536	$	259,536
		Retained earnings			112,847		92,205
			Total common shareholder's equity		372,383		351,741
	Long-term debt payable to third parties - net of current maturities				116,000		121,000
	Long-term debt payable to Utility Holdings				133,948		133,951
			Total long-term debt, net		249,948		254,951
Commitments & Contingencies (Notes 6, 8-10)
Current Liabilities
	Accounts payable				36,202		36,592
	Accounts payable to affiliated companies				25,860		31,538
	Payables to other Vectren companies				10,606		13,876
	Accrued liabilities				55,722		52,789
	Short-term borrowings payable to Utility Holdings				46,916		63,478
	Current maturities of long-term debt				5,000		—
		Total current liabilities			180,306		198,273
Deferred Income Taxes & Other Liabilities
	Deferred income taxes				174,441		165,819
	Regulatory liabilities				213,340		202,078
	Deferred credits & other liabilities				21,194		28,979
		Total deferred income taxes & other liabilities			408,975		396,876

TOTAL LIABILITIES & SHAREHOLDER'S EQUITY					$	1,211,612	$	1,201,841

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

INDIANA GAS COMPANY, INC. AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF INCOME

(In thousands)



			Year Ended December 31,
			2012		2011

OPERATING REVENUES			$	522,187	$	584,152
OPERATING EXPENSES
	Cost of gas sold		255,346		314,675
	Other operating		103,362		110,125
	Depreciation & amortization		59,255		57,894
	Taxes other than income taxes		16,062		16,648
		Total operating expenses	434,025		499,342

OPERATING INCOME			88,162		84,810
Other income - net			2,040		302
Interest expense			17,333		26,406
INCOME BEFORE INCOME TAXES			72,869		58,706

Income taxes			29,459		24,160

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

NET INCOME			$	43,410	$	42,794

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

INDIANA GAS COMPANY, INC. AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)



						Year Ended December 31,
						2012				2011
CASH FLOWS FROM OPERATING ACTIVITIES
	Net income				$	43,410			$	42,794
	Adjustments to reconcile net income to cash from operating activities:
		Depreciation & amortization				59,255				57,894
		Deferred income taxes & investment tax credits				13,393				22,584
		Expense portion of pension & postretirement periodic benefit cost				1,207				1,099
		Equity in earnings of the Ohio operations - net of tax				—				(8,248		)
		Provision for uncollectible accounts				1,120				3,525
		Other non-cash charges - net				1,217				3,495
		Changes in working capital accounts:
			Accounts receivable, including due from Vectren companies
				& accrued unbilled revenue		(1,711		)		21,818
			Inventories			7,101				(2,626		)
			Recoverable/refundable natural gas costs			(10,351		)		(4,411		)
			Prepayments & other current assets			11,226				218
			Accounts payable, including to Vectren companies
				& affiliated companies		(11,688		)		(21,049		)
			Accrued liabilities			(2,100		)		(3,839		)
		Changes in noncurrent assets				(4,819		)		(20,616		)
		Changes in noncurrent liabilities				(4,948		)		(4,879		)
			Net cash flows from operating activities			102,312				87,759
CASH FLOWS FROM FINANCING ACTIVITIES
	Proceeds from:
		Long-term debt				—				107,328
	Requirements for:
		Dividend to Utility Holdings				(22,768		)		(31,033		)
		Retirement of long-term debt				(3		)		(145,502		)
	Net change in short-term borrowings, including from Utility Holdings					(16,562		)		42,982
			Net cash flows from financing activities			(39,333		)		(26,225		)
CASH FLOWS FROM INVESTING ACTIVITIES
	Requirements for :
		Capital expenditures, excluding AFUDC equity				(61,975		)		(58,839		)
		Other investments				—				61
			Net cash flows from investing activities			(61,975		)		(58,778		)
Net change in cash & cash equivalents						1,004				2,756
Cash & cash equivalents at beginning of period						3,088				332
Cash & cash equivalents at end of period						$	4,092			$	3,088

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

INDIANA GAS COMPANY, INC. AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

(In thousands)



		Common			Retained
		Stock			Earnings			Total

Balance at January 1, 2011		$	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
Net income & comprehensive income					43,410			43,410
Common stock:
	Dividends to Utility Holdings				(22,768		)	(22,768		)
Balance at December 31, 2012		$	259,536		$	112,847		$	372,383

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

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 566,000 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 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 18, 2013.

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.

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.

Energy Contracts & Derivatives

The Company will periodically execute 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 $7.1 million in 2012 and $8.1 million in 2011. Expense associated with utility receipts taxes are recorded as a component of Taxes other than income taxes.

Fair Value Measurements

Certain assets and liabilities are valued and/or disclosed at fair value. Financial assets include securities held in trust by the Company’s pension plans. Nonfinancial assets and liabilities include the initial measurement of an asset retirement obligation or the use of fair value in goodwill, intangible assets, and long-lived assets impairment tests. FASB guidance provides the framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are described as follows:



Level 1	Inputs to the valuation methodology are unadjusted quoted prices for identical assets or liabilities in active markets that the Company has the ability to access.
Level 2	Inputs to the valuation methodology include · quoted prices for similar assets or liabilities in active markets; · quoted prices for identical or similar assets or liabilities in inactive markets; · inputs other than quoted prices that are observable for the asset or liability; · inputs that are derived principally from or corroborated by observable market data by correlation or other means If the asset or liability has a specified (contractual) term, the Level 2 input must be observable for substantially the full term of the asset or liability.
Level 3	Inputs to the valuation methodology are unobservable and significant to the fair value measurement.

Earnings Per Share

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

Other Significant Policies

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


3.	Utility Plant & Depreciation

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



		At and For the Year Ended December 31,
(In thousands)		2012				2011
		Original Cost		Depreciation Rates as a Percent of Original Cost		Original Cost		Depreciation Rates as a Percent of Original Cost
Utility plant		$	1,684,812	3.9	%	$	1,637,291	3.8	%
Construction work in progress		15,300		—		10,960		—
	Total original cost	$	1,700,112			$	1,648,251


4.	Regulatory Assets & Liabilities

Regulatory Assets

Regulatory assets consist of the following:



		At December 31,
(In thousands)		2012		2011
Amounts currently recovered through customer rates related to:
	Authorized trackers	$	24,287	$	20,558
	Unamortized debt issue costs & premiums paid to reacquire debt	3,802		4,498
		28,089		25,056
Amounts deferred for future recovery		7,476		(762		)
Future amounts recoverable from ratepayers related to:
	Deferred income taxes	1,397		2,696
	Other	275		4,544
	Total regulatory assets	$	37,237	$	31,534

Indiana Gas is not earning a return on the $28.1 million currently being recovered through rates. The weighted average recovery period of regulatory assets currently being recovered in base rates, which totals $3.8 million, is 16 years. The remainder of the regulatory assets is being timely recovered through tracking mechanisms. 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, 2012 and 2011, the Company has approximately $213.3 million and $202.1 million, respectively, in regulatory liabilities. Of these amounts, $208.6 million and $191.2 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 were recorded as a reduction of the carrying value of the investment when received. Goodwill, which was a component of the Company’s net investment, was 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. For the year ended December 31, 2011, the Ohio operations had revenues of $139.6 million, operating income after taxes of $15.3 million, and net income of $17.5 million.


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 $22.7 million in 2012 and $23.4 million in 2011. Amounts owed to Miller at December 31, 2012 and 2011 are included in Payables to other Vectren companies.

Minnesota Limited, Inc.

Minnesota Limited, Inc. (Minnesota Limited), a wholly owned subsidiary of Vectren through an acquisition on March 31, 2011, provides transmission pipeline construction and maintenance; pump station, compressor station, terminal and refinery construction; and hydrostatic testing to customers generally in the northern Midwest region. Minnesota Limited’s customers include Indiana Gas. Fees incurred by Indiana Gas totaled $1.2 million in 2012. There were no transactions with Minnesota Limited prior to 2012. Amounts owed to Minnesota Limited at December 31, 2012 and 2011 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. 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. Amounts charged by ProLiance for gas supply services are established by supply agreements with the utility.

Purchases made from ProLiance for resale and for injections into storage for the years ended December 31, 2012 and 2011, totaled $233.5 million and $318.1 million, respectively. Amounts owed to ProLiance at December 31, 2012 and 2011, for those

purchases were $25.9 million and $31.5 million, respectively, and are included in Accounts payable to affiliated companies in the Consolidated Balance Sheets.

Support Services and Purchases

Vectren and Utility Holdings provide corporate and general and administrative assets and services to the Company and allocates certain 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 are 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 $52.2 million and $55.3 million for the years ended December 31, 2012, and 2011, respectively. Amounts owed to Vectren and Utility Holdings at December 31, 2012 and 2011 are included in Payables to other Vectren companies.

Retirement Plans & Other Postretirement Benefits

At December 31, 2012, 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 a postretirement benefit plan. The defined benefit pension plan and postretirement benefit plan, 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.

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 and did not contribute to Vectren’s defined benefit pension plans during 2012. For the year ended December 31, 2011, the Company contributed approximately $10.9 million 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 approximately 82 percent at December 31, 2012 and 83 percent at December 31, 2011.

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 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, 2012 and 2011, costs totaling $1.7 million and $1.6 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 based on labor. Any difference between funding requirements and allocated periodic costs is recognized as an asset or liability until reflected in periodic costs.

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 $25.3 million and $27.1 million included in Other Assets representing defined benefit funding by the Company that is yet to be reflected in costs at December 31, 2012 and 2011, respectively.

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, 2012 and 2011, $8.5 million and $9.6 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 $117 million is outstanding at December 31, 2012, and Utility Holdings’ $822 million unsecured senior notes outstanding at December 31, 2012. The guarantees are full and unconditional and joint and several, and Utility Holdings has no subsidiaries other than the subsidiary guarantors.

Income Taxes

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 have recently been examined by the IRS, and such examination resulted in no assessments but is in IRS Joint Committee review currently. The primary focus of the IRS examination was certain repairs and maintenance deductions, an area of particular focus by the IRS throughout the utility industry. In 2012, the IRS suspended all examinations related to this issue generally, resulting in the elimination of the audit risk in this area for Vectren through 2012. To the extent IRS guidance changes in this area, any impact is not expected to be material to the Company’s result 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 2008 for Indiana income tax.

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.

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.

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



		Year Ended December 31,
(In thousands)		2012			2011
Current:
	Federal	$	11,365		$	(1,795	)
	State	4,701			3,371
Total current taxes		16,066			1,576
Deferred:
	Federal	12,004			20,822
	State	1,472			1,881
Total deferred taxes		13,476			22,703
Amortization of investment tax credits		(83		)	(119		)
	Total income taxes	$	29,459		$	24,160

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



		Year Ended December 31,
		2012		2011
Statutory rate		35.0	%	35.0	%
State & local taxes, net of federal benefit		5.9		6.3
Amortization of investment tax credit		(0.1	)	(0.2	)
Adjustment to federal income tax accruals & other, net		(0.4	)	0.1
	Effective tax rate	40.4	%	41.2	%

Significant components of the net deferred tax liability follow:



			At December 31,
(In thousands)			2012			2011
Non-current deferred tax liabilities (assets):
	Depreciation & cost recovery timing differences		$	157,128		$	151,768
	Regulatory assets recoverable through future rates		9,347			6,469
	Regulatory liabilities to be settled through future rates		(5,321		)	(2,214		)
	Employee benefit obligations		7,233			5,978
	Other – net		6,054			3,818
		Net non-current deferred tax liability	174,441			165,819

Current deferred tax liabilities (assets):
	Deferred fuel costs - net		7,727			3,754
	Other – net		(547		)	(1,495		)
		Net current deferred tax liability	7,180			2,259
		Net deferred tax liability	$	181,621		$	168,078

At December 31, 2012 and 2011, investment tax credits totaling $0.2 million and $0.3 million, respectively, are included in Deferred credits and other liabilities. These investment tax credits are amortized over the lives of the related investments.

Uncertain Tax Positions

Following is a roll forward of the total amount of unrecognized tax benefits for the years ended December 31, 2012 and 2011:



(in thousands)	2012			2011
Unrecognized tax benefits at January 1	$	1,194		$	4,467
Gross increases - tax positions in prior periods	40			—
Gross decreases - tax positions in prior periods	(944		)	(3,367		)
Gross increases - current period tax positions	510			118
Settlements	—			(44		)
Lapse of statute of limitations	—			20
Unrecognized tax benefits at December 31	$	800		$	1,194

Of the change in unrecognized tax benefits during 2012 and 2011, almost none impacted the effective rate. The amount of unrecognized tax benefits, which if recognized, that would impact the effective tax rate was zero at December 31, 2012 and December 31, 2011. As of December 31, 2012, the unrecognized tax benefit relates to tax positions for which the ultimate deductibility is more likely than not 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 both 2012 and 2011. The Company had approximately $0.1 million for the payment of interest and penalties accrued as of December 31, 2011 and none accrued as of December 31, 2012.

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 $0.8 million and $1.2 million, respectively, at December 31, 2012 and 2011.


7.	Borrowing Arrangements & Other Financing Transactions

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, 2012 and 2011 were $46.9 million and $63.5 million, respectively. The intercompany credit line totals $325 million, but is limited to Utility Holdings’ available capacity ($233 million at December 31, 2012) 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)		2012			2011
Year End
	Balance Outstanding	$	46,916		$	63,478
	Weighted Average Interest Rate	0.4		%	0.57		%
Annual Average
	Balance Outstanding	$	18,428		$	53,648
	Weighted Average Interest Rate	0.47		%	0.45		%
Maximum Month End Balance Outstanding		$	46,916		$	119,615

Long-Term Debt

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



			At December 31,
(In thousands)			2012			2011
	Fixed Rate Senior Unsecured Notes Payable to Utility Holdings:
		2015, 5.45%	24,716			24,716
		2018, 5.75%	37,128			37,129
		6/10/2035	50,569			50,569
		6/25/2039	21,535			21,537
	Total long-term debt payable to Utility Holdings		$	133,948		$	133,951

	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
	Current maturities		(5,000		)	—
	Long-term debt payable to third parties - net of debt subject to tender		$	116,000		$	121,000

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 2012. Long-term debt maturities in the five years following 2012 total $5.0 in 2013, zero in 2014, $44.7 in 2015, and zero in 2016 and 2017.

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. As an example, certain instruments can be put to the Company upon the death of the holder (death puts) or at specific dates. During 2012, the Company repaid an insignificant amount related to death puts. During 2011, the Company repaid approximately $0.1 million related to death puts. On February 4, 2013, Utility Holdings notified holders of Utility Holdings $121.6 million 6.25 percent senior unsecured notes due 2039, which contained both a put and call provision, of its intent to call the debt at par on April 1, 2013. A portion of these notes had been pushed down to Indiana Gas and were the only issue outstanding at December 31, 2012 with a put provision.

On November 21, 2011, Utility Holdings exercised a call option on Utility Holdings’ $96.2 million 5.95 percent senior notes due 2036.

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, 2012, the Company was in compliance with all debt covenants.


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.	Rate & Regulatory Matters

Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement

The Company monitors and maintains its natural gas distribution system to ensure that natural gas is delivered in a safe and efficient manner. The Company is currently engaged in replacement programs, the primary purpose of which is preventive maintenance and continual renewal and operational improvement. In 2011, a law in Indiana was passed that expands the ability of utilities to recover certain costs of federally mandated projects outside of a base rate proceeding. Utilization of this recovery mechanism is discussed below.

Indiana Recovery and Deferral Mechanisms

The Company received an order in 2008 associated with the most recent base rate case. This order authorized the deferral of financial impacts associated with bare steel and cast iron replacement activities. The order provides for the deferral of depreciation and post in service carrying costs on qualifying projects totaling $20 million annually. For USGAAP accounting purposes only the debt-related post in service carrying costs are recognized in the Consolidated Statements of Income currently. Such deferral is limited by individual qualifying project to four years after being placed into service. The debt-related post in service rate used to calculate the deferral is based on a current cost of funds. At December 31, 2012 and 2011, the Company has USGAAP regulatory assets totaling $7.5 million and $4.0 million, respectively, associated with the deferral of depreciation and debt-related post in service carrying cost activities.

In April 2011, Senate Bill 251 was signed into Indiana law. 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 a return on the federally mandated capital investment, along with recovery of depreciation and other operating costs associated with these mandates. The remaining 20 percent of those costs are to be deferred for future recovery in the utility's next general rate case. To date, the Company has not initiated a filing requesting authority to recover costs using the Senate Bill 251 approach and continues to study its applicability to expenditures associated with its natural gas distribution operations.

Pipeline Safety Law

On January 3, 2012, the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (Pipeline Safety Law) was signed into law. The Pipeline Safety 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 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 over the next two years Those regulations may eventually lead to further regulatory or statutory requirements.

The Company continues to study the impact of the Pipeline Safety 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 law is expected to result in further investment in pipeline inspections, and where necessary, additional investments in 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 by approximately $5 million annually. The Company expects to seek recovery under Senate Bill 251, or such costs may be recoverable through current tracking mechanisms. Capital investments, associated with the Pipeline Safety Law, are expected to be significant. The Company expects to seek recovery of capital investments associated with complying with these federal mandates in accordance with Senate Bill 251.

Pipeline Safety Investigation

On April 11, 2012, the IURC's pipeline safety division filed a complaint against Vectren North alleging several violations of safety regulations pertaining to damage that occurred at a residence in Vectren North's service territory during a pipeline replacement project. The Company negotiated a settlement with the IURC's pipeline safety division, agreeing to a fine and several modifications to the Company's operating policies. The amount of the fine was not material to the Company's financial results. The IURC approved the settlement but modified certain terms of the settlement and added a requirement that Company employees conduct inspections of pipeline excavations. The Company sought and was granted a request for rehearing on the sole issue related to the requirement to use Company employees to inspect excavations. The Company seeks further clarity on the scope of the requirement and the ability to also use contractors to perform certain inspections. A schedule for the rehearing will be set in March 2013.

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.


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 has incurred or reasonably expects to incur totaling approximately $23.2 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, 2012 and 2011, respectively, approximately $1.4 million and $2.6 million of accrued, but not yet spent, costs are included in Other Liabilities related to these sites.


11.	Fair Value Measurements

The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow:



		At December 31,
		2012				2011
(In thousands)		Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
	Long-term debt due to third parties	$	121,000	$	147,228	$	121,000	$	143,710
	Long-term debt due to Utility Holdings	133,948		145,451		133,951		159,981
	Short-term debt due to Utility Holdings	46,916		46,916		63,478		63,478
	Cash & cash equivalents	4,092		4,092		3,088		3,088

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.


12.	Additional Balance Sheet & Operational Information

Inventories consist of the following:



		At December 31,
(In thousands)		2012		2011
Gas in storage - at LIFO cost		$	11,222	$	18,569
Materials & supplies		2,760		2,865
Other		1,093		742
	Total inventories	$	15,075	$	22,176

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, 2012 and 2011, by approximately $9 million. 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)		2012		2011
Prepaid gas delivery service		$	28,487	$	42,421
Prepaid taxes & other		5,000		2,291
	Total prepayments & other current assets	$	33,487	$	44,712

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



		At December 31,
(In thousands)		2012		2011
Customer advances & deposits		$	27,708	$	29,194
Accrued gas imbalance		2,457		2,650
Accrued taxes		8,775		8,549
Accrued interest		3,132		3,271
Deferred income taxes		7,180		2,259
Tax collections payable		3,821		4,200
Accrued salaries & other		2,649		2,666
	Total accrued liabilities	$	55,722	$	52,789

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



(In thousands)	2012			2011
Asset retirement obligation, January 1	$	15,072		$	14,161
Accretion	969			911
Changes in estimates, net of cash payments	(5,696		)	—
Asset retirement obligation, December 31	$	10,345		$	15,072

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



		Year Ended December 31,
(In thousands)		2012			2011
AFUDC - borrowed funds		$	1,588		$	235
AFUDC - equity funds		421			9
Other income		702			481
Regulatory expenses		(671		)	(423		)
	Total other – net	$	2,040		$	302

Supplemental Cash Flow Information:



	Year Ended December 31,
(In thousands)	2012		2011
Cash paid for:
Interest	$	17,472	$	26,480
Income taxes	18,759		2,827

As of December 31, 2012, the Company had insignificant accruals related to utility plant purchases, compared to $0.1 million at December 31, 2011.


13.	Adoption of Other Accounting Standards

Other Comprehensive Income (OCI)

In 2011, the FASB issued new accounting guidance regarding the presentation of comprehensive income within financial statements. The new guidance requires 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 adopted this guidance for the quarterly reporting period ended March 31, 2012; however, other comprehensive income, including its individual components, was not material to the financial statements taken as a whole and thus a statement of comprehensive income is not provided.

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 Company adopted this guidance for its quarterly reporting period ended March 31, 2012. The adoption of this guidance did not have a material impact on the Company’s financial position, results of operations, or cash flows.

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

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 2012 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 2012, Indiana Gas had $43.4 million in net income compared to net income of $42.8 million in 2011. Excluding earnings and the impact of long-term financing arrangements related to the Company’s investment in the Ohio operations in the prior year, results in 2011 were earnings of $38.6 million. The $4.8 million increase in 2012 on this more comparable basis is primarily attributable to lower interest expense and operating expenses that has been somewhat offset by lower miscellaneous revenues. The lower miscellaneous revenues are primarily attributable to lower gas costs.

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 $9 million of the approximate $103 million in Other operating expenses incurred during 2012 are subject to a recovery mechanism outside of base rates.

Rate Design Strategies

Sales of natural gas to residential and commercial customers are largely 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 and the Company has implemented conservation programs. Normal temperature adjustment (NTA) and decoupling 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 is the Company’s most significant operating expense. 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.

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.

In 2011, a state law was passed in Indiana that expands the ability of utilities to recover certain costs of federally mandated projects outside of a base rate proceeding. Utilization of this mechanism will likely increase in the coming years.

See Note 9 to the financial statements for more specific information on significant proceedings involving the Company.

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)			2012		2011

Gas utility revenues			$	522,187	$	584,152
Cost of gas			255,346		314,675
	Total gas utility margin		$	266,841	$	269,477
Margin attributed to:
	Residential & commercial customers		$	231,674	$	233,690
	Industrial customers		29,459		28,774
	Other customers		5,708		7,013
Sold & transported volumes in MDth attributed to:
	Residential & commercial customers		52,835		58,310
	Industrial customers		55,027		51,456
		Total sold & transported volumes	107,862		109,766

Gas utility margins totaling $266.8 million for the year ended December 31, 2012 decreased approximately $2.6 million compared to 2011. The impact of low natural gas prices and mild weather on revenue taxes, late and reconnect fees, and volumetric pass through costs decreased gas utility margin $4.5 million in 2012 compared to 2011. The average cost per dekatherm of gas purchased during 2012 was $4.46, compared to $5.33 in 2011. This decrease in margin was partially offset by increased large customer margin, which net of the impacts of regulatory initiatives and tracked costs increased by $1.0 million, related to higher volumes sold.

Operating Expenses

Other Operating

For the year ended December 31, 2012, Other operating expenses were $103.4 million, which is a decrease of $6.8 million, compared to 2011. The year to date decrease results from lower pass through operating costs of $1.6 million that are offset with lower Gas utility margin and lower uncollectible accounts expense of $2.5 million driven by lower gas prices increasing customer’s ability to pay. The remaining decrease is primarily related to lower allocated costs associated with shared assets.

Depreciation & Amortization

For the year ended December 31, 2012, depreciation and amortization expense increased $1.4 million compared to 2011. The increase resulted from normal additions to utility plant.

Taxes Other Than Income Taxes

Taxes other than income taxes decreased $0.6 million in 2012 compared to 2011. The decrease is primarily attributable to lower usage taxes associated with lower gas costs. These expenses are offset dollar-for-dollar with lower gas utility revenues.

Other Income – Net

Other income – net was $2.0 million in 2012, an increase of $1.7 million compared to 2011. The increase reflects increased AFUDC in 2012 which reflects the impact of recent infrastructure replacement investments and changes in the level of short-term borrowings outstanding.

Interest Expense

For the year ended December 31, 2012, interest expense was $17.3 million, a decrease of $9.1 million compared to 2011. The lower expense primarily reflects the impact of transferring ownership in the Ohio operations to VEDO and fourth quarter 2011 refinancing activity. As a result of these events long-term debt of approximately $150 million with an average rate of 6.4% was either retired or transferred to VEDO. In the prior year, the Company estimated long-term interest expense of approximately $6.5 million during the year ended December 31, 2011 was attributed to the Ohio operations. Excluding impacts from the Ohio transfer, interest expense has decreased an additional $2.6 million during 2012. The lower interest expense is reflective of debt that was called in November 2011 and debt that matured in December 2011 and is currently financed with short term borrowings at a lower rate.

Income Taxes

For the year ended December 31, 2012, income taxes increased $5.3 million compared to 2011. 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. Indiana Gas’ share of those earnings was $8.2 million. On December 31, 2011, the Company transferred its ownership interest and related financing arrangements in the Ohio operations to VEDO. See Note 1 to the Company’s consolidated financial statements for more information regarding this transaction.

SELECTED GAS OPERATING STATISTICS:



		For the Year Ended
		December 31,
		2,012		2,011

OPERATING REVENUES (In thousands):

	Residential	$	355,568	$	398,989
	Commercial	128,890		145,971
	Industrial	32,022		32,178
	Other Revenue	5,707		7,014
		$	522,187	$	584,152

MARGIN (In thousands):

	Residential	$	178,945	$	180,486
	Commercial	52,729		53,204
	Industrial	29,459		28,774
	Other	5,708		7,013
		$	266,841	$	269,477

GAS SOLD & TRANSPORTED (In MDth):

	Residential	36,303		40,215
	Commercial	16,532		18,095
	Industrial	55,027		51,456
		107,862		109,766

AVERAGE CUSTOMERS:

	Residential	515,649		513,438
	Commercial	49,359		49,141
	Industrial	888		866
		565,896		563,445

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