VECTREN CORP - FORM 8-K - EX-99.1 - EXHIBIT 99.1 2014 IGC REPORTING PACKAGE

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8-K - 8-K 2014 IGC REPORTING PACKAGE - VECTREN CORP	igc2014reportingpackage8k.htm
EX-99.2 - EXHIBIT 99.2 2014 IGC REPORTING PACKAGE - VECTREN CORP	exhibit992-2014igcreportin.htm

INDIANA GAS COMPANY, INC. AND SUBSIDIARY

REPORTING PACKAGE

For the year ended December 31, 2014

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 of Indiana Gas Company, Inc. (the Company, Indiana Gas or Vectren North) and its subsidiary. This information is supplemental to Vectren Corporation’s (Vectren) annual report for the year ended December 31, 2014, filed on Form 10-K with the Securities and Exchange Commission on February 17, 2015 and Vectren Utility Holdings, Inc.’s (Utility Holdings) 10-K filed on March 5, 2015. 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	IDEM: Indiana Department of Environmental Management
ASC: Accounting Standards Codification	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	Throughput: combined gas sales and gas transportation volumes
GAAP: Generally Accepted Accounting Principles

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 its subsidiary (the “Company”), which comprise the consolidated balance sheets as of December 31, 2014 and 2013, 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 its subsidiary as of December 31, 2014 and 2013, and the results of their operations and their cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Indianapolis, Indiana

March 24, 2015

FINANCIAL STATEMENTS

INDIANA GAS COMPANY, INC. AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

(In thousands)



	December, 31
	2014		2013
ASSETS
Utility Plant
Original cost	$	1,901,776	$	1,777,413
Less: accumulated depreciation & amortization	792,012		750,166
Net utility plant	1,109,764		1,027,247

Current Assets
Cash & cash equivalents	2,964		3,622
Accounts receivable - less reserves of $2,051 &
$2,503, respectively	47,625		41,478
Accrued unbilled revenues	62,384		58,070
Inventories	27,443		23,499
Recoverable natural gas costs	9,824		5,490
Prepayments & other current assets	56,592		33,571
Total current assets	206,832		165,730

Other investments	7,591		7,927
Regulatory assets	31,213		37,045
Other assets	21,836		23,646
TOTAL ASSETS	$	1,377,236	$	1,261,595

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,
		2014		2013
LIABILITIES & SHAREHOLDER'S EQUITY
Common Shareholder's Equity
Common stock (no par value)		$	259,536	$	259,536
Retained earnings		131,411		123,461
Total common shareholder's equity		390,947		382,997
Long-term debt payable to third parties - net of current maturities		96,000		116,000
Long-term debt payable to Utility Holdings - net of current maturities		187,104		137,282
Total long-term debt		283,104		253,282
Commitments & Contingencies (Notes 5, 7-9)
Current Liabilities
Accounts payable		62,090		67,141
Payables to other Vectren companies		21,894		12,593
Accrued liabilities		55,784		53,932
Short-term borrowings payable to Utility Holdings		50,178		62,024
Current maturities of long-term debt		20,000		—
Current maturities long-term debt payable to Utility Holdings		24,716		—
Total current liabilities		234,662		195,690
Deferred Income Taxes & Other Liabilities
Deferred income taxes		191,960		179,289
Regulatory liabilities		237,820		225,495
Deferred credits & other liabilities		38,743		24,842
Total deferred income taxes & other liabilities		468,523		429,626
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY		$	1,377,236	$	1,261,595

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,
	2014		2013

OPERATING REVENUES	$	680,409	$	577,617
OPERATING EXPENSES
Cost of gas sold	392,568		300,174
Other operating	123,938		115,789
Depreciation & amortization	63,799		61,563
Taxes other than income taxes	18,396		16,311
Total operating expenses	598,701		493,837

OPERATING INCOME	81,708		83,780
Other income - net	2,229		1,212
Interest expense	18,901		16,197
INCOME BEFORE INCOME TAXES	65,036		68,795
Income taxes	25,878		28,121
NET INCOME	$	39,158	$	40,674

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,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	39,158		$	40,674
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization	63,799			61,563
Deferred income taxes & investment tax credits	18,356			1,263
Expense portion of pension & postretirement periodic benefit cost	1,163			1,328
Provision for uncollectible accounts	3,969			3,043
Other non-cash charges - net	1,491			207
Changes in working capital accounts:
Accounts receivable, including due from Vectren companies
& accrued unbilled revenue	(14,429		)	(28,489		)
Inventories	(3,944		)	(8,424		)
Recoverable/refundable natural gas costs	(4,334		)	14,628
Prepayments & other current assets	(22,608		)	(84		)
Accounts payable, including to Vectren companies
& affiliated companies	6,666			4,222
Accrued liabilities	(1,460		)	3,308
Changes in noncurrent assets	6,824			5,622
Changes in noncurrent liabilities	(3,546		)	(4,407		)
Net cash flows from operating activities	91,105			94,454
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt	74,538			24,869
Requirements for:
Dividend to Utility Holdings	(31,208		)	(30,060		)
Retirement of long-term debt	—			(26,535		)
Net change in short-term borrowings, including from Utility Holdings	(11,846		)	15,108
Net cash flows from financing activities	31,484			(16,618		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from other investing activities	—			218
Requirements for capital expenditures,
excluding AFUDC equity	(123,247		)	(78,524		)
Net cash flows from investing activities	(123,247		)	(78,306		)
Net change in cash & cash equivalents	(658		)	(470		)
Cash & cash equivalents at beginning of period	3,622			4,092
Cash & cash equivalents at end of period	$	2,964		$	3,622

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, 2013	$	259,536	$	112,847		$	372,383
Net income & comprehensive income			40,674			40,674
Common stock:
Dividends to Utility Holdings			(30,060		)	(30,060		)
Balance at December 31, 2013	$	259,536	$	123,461		$	382,997
Net income & comprehensive income			39,158			39,158
Common stock:
Dividends to Utility Holdings			(31,208		)	(31,208		)
Balance at December 31, 2014	$	259,536	$	131,411		$	390,947

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), an Indiana corporation, provides energy delivery services to approximately 575,000 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.


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, and reclamation liabilities. 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 consolidated financial statements are issued. The Company’s management has performed a review of subsequent events through March 24, 2015.

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 income – 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. Since 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. 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.

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 consolidated 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 in Accrued unbilled revenues.

Utility Receipts Taxes

A portion of utility receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes received as a component of operating revenues, which totaled $9.4 million in 2014 and $8.3 million in 2013. 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. Nonfinancial assets and liabilities include the initial measurement of an asset retirement obligation or the use of fair value in 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 Company's retirement plans and post retirement benefits and intercompany allocations and income taxes (Note 5).


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)	2014				2013
	Original Cost		Depreciation Rates as a Percent of Original Cost		Original Cost		Depreciation Rates as a Percent of Original Cost
Utility plant	$	1,889,944	3.6	%	$	1,767,176	3.8	%
Construction work in progress	11,832		—		10,237		—
Total original cost	$	1,901,776			$	1,777,413


4.	Regulatory Assets & Liabilities

Regulatory Assets

Regulatory assets consist of the following:



	At December 31,
(In thousands)	2014			2013
Amounts currently recovered through customer rates related to:
Authorized trackers	$	15,871		$	23,244
Unamortized debt issue costs & premiums paid to reacquire debt	2,765			3,251
	18,636			26,495
Amounts deferred for future recovery	15,972			10,702
Future amounts recoverable/(refundable) from ratepayers related to:
Net deferred income taxes	(3,394		)	138
Other	(1		)	(290		)
Total regulatory assets	$	31,213		$	37,045

Indiana Gas is not earning a return on the $18.6 million currently being recovered through rates. The weighted average recovery period of regulatory assets currently being recovered in base rates, which totals $2.8 million, is 18 years. The remainder of the regulatory assets are 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, 2014 and 2013, the Company has approximately $237.8 million and $225.5 million, respectively, in regulatory liabilities. Of these amounts, $220.5 million and $220.1 million relate to cost of removal obligations. The remaining amounts primarily relate to timing differences associated with asset retirement obligations.


5.	Transactions with Other Vectren Companies & Affiliates

Vectren Infrastructure Services Corporation (VISCO)

VISCO, a wholly owned subsidiary of Vectren, provides underground pipeline construction and repair services. VISCO’s customers include Indiana Gas and fees incurred by Indiana Gas totaled $51.2 million in 2014 and $30.7 million in 2013. Amounts owed to VISCO at December 31, 2014 and 2013 are included in Payables to other Vectren companies.

ProLiance Holdings, LLC (ProLiance)

Vectren has an investment in ProLiance, a nonutility affiliate of Vectren and Citizens Energy Group (Citizens). On June 18, 2013, ProLiance exited the natural gas marketing business through the disposition of certain of the net assets of its energy marketing business, ProLiance Energy, LLC (ProLiance Energy). ProLiance Energy provided services to a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions located throughout the Midwest and Southeast United States. ProLiance Energy’s customers included, among others, Vectren’s Indiana utilities as well as Citizens’ utilities.

The Company had no purchases from ProLiance for resale and for injections into storage for the year ended December 31, 2014, as a result of ProLiance exiting the natural gas marketing business. For the year ended December 31, 2013, the Company had purchases totaling $167.1 million. After the exit of the energy marketing business by ProLiance, the Company purchases gas supply from third parties and 86 percent is from a single third party for the year ended December 31, 2014.

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 $57.1 million and $54.3 million for the years ended December 31, 2014, and 2013, respectively. Amounts owed to Vectren and Utility Holdings at December 31, 2014 and 2013 are included in Payables to other Vectren companies.

Retirement Plans & Other Postretirement Benefits

At December 31, 2014, 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 plans 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 2014 or 2013. The combined funded status of Vectren’s plans was approximately 87 percent at December 31, 2014 and 101 percent at December 31, 2013. Vectren's management has made contributions of $20 million to the qualified plans in 2015.

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, 2014 and 2013, costs totaling $1.7 million and $1.9 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. At December 31, 2014 and 2013, the Company has $21.8 million and $23.4 million, respectively, included in Other assets representing defined benefit funding by the Company that is yet to be reflected in costs.

Share-Based Incentive Plans & Deferred Compensation Plans

Indiana Gas does not have share-based or deferred compensation plans separate from Vectren. The Company recognizes its allocated portion of expenses related to 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, 2014 and 2013, $13.2 million and $10.5 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 Utility Holdings' centralized cash management program. See Note 6 regarding long-term and short-term intercompany borrowing arrangements.

Guarantees of Parent Company Debt

Utility Holdings’ three operating utility companies, SIGECO, Indiana Gas, and Vectren Energy Delivery of Ohio, Inc. are guarantors of Utility Holdings’ $350 million short-term credit facility, of which approximately $156 million is outstanding at December 31, 2014, and Utility Holdings’ $875 million unsecured senior notes outstanding at December 31, 2014. 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. Pursuant to a tax sharing agreement and for financial reporting purposes, Vectren subsidiaries record income taxes on a separate company basis. The Company's allocated share of tax effects resulting from it being a part of Vectren's consolidated tax group are recorded at the Utility Holdings parent company level. Current taxes payable/receivable are settled with Vectren in cash quarterly and after filing the consolidated federal and state income tax returns.

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.

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



	Year Ended December 31,
(In thousands)	2014			2013
Current:
Federal	$	2,994		$	19,618
State	4,528			7,239
Total current tax expense	7,522			26,857
Deferred:
Federal	17,976			1,992
State	417			(674		)
Total deferred taxes	18,393			1,318
Amortization of investment tax credits	(37		)	(54		)
Total income tax expense	$	25,878		$	28,121

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



	Year Ended December 31,
	2014		2013
Statutory rate	35.0	%	35.0	%
State & local taxes, net of federal benefit	5.4		5.7
Amortization of investment tax credit	(0.1	)	—
Adjustment to federal income tax accruals & other, net	(0.5	)	0.2
Effective tax rate	39.8	%	40.9	%

Significant components of the net deferred tax liability follow:



	At December 31,
(In thousands)	2014			2013
Non-current deferred tax liabilities (assets):
Depreciation & cost recovery timing differences	$	181,259		$	164,920
Regulatory assets recoverable through future rates	11,265			9,653
Regulatory liabilities to be settled through future rates	(9,402		)	(6,271		)
Employee benefit obligations	2,604			3,976
Other – net	6,234			7,011
Net non-current deferred tax liability	191,960			179,289

Current deferred tax liabilities (assets):
Deferred fuel costs - net	3,501			1,902
Other – net	1,892			179
Net current deferred tax liability	5,393			2,081
Net deferred tax liability	$	197,353		$	181,370

At both December 31, 2014 and 2013, investment tax credits totaled $0.1 million, and are included in Deferred credits and other liabilities.

Uncertain Tax Positions

Following is a roll forward of the total amount of unrecognized tax benefits for the years ended December 31, 2014 and 2013:



(in thousands)	2014			2013
Unrecognized tax benefits at January 1	$	1,074		$	800
Gross increases - tax positions in prior periods	—			—
Gross decreases - tax positions in prior periods	(1,074		)	(122		)
Gross increases - current period tax positions	—			396
Unrecognized tax benefits at December 31	$	—		$	1,074

Of the change in unrecognized tax benefits during 2014 and 2013, 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, 2014 and 2013.

The Company recognized no income related to a reversal of interest expense previously accrued and net of penalties in 2014 or 2013. The Company had zero accrued for the payment of interest and penalties as of December 31, 2014 and 2013.

Vectren and/or certain of its subsidiaries file income tax returns in U.S. federal jurisdiction and 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, 2008. The IRS is currently examining the 2009-2012 federal income tax returns as part of a routine review by the Joint Committee on Taxation. The State of Indiana, Vectren's primary state tax jurisdiction, has conducted examinations of state income tax returns for tax years through December 31, 2008. The statutes of limitations for assessment of federal income tax and Indiana income tax have expired with respect to tax years through 2008.

Final Federal Income Tax Regulations

In September 2013, the Internal Revenue Service released final tangible property regulations regarding the deduction and capitalization of expenditures related to tangible property. The final regulations are generally effective for tax years beginning on or after January 1, 2014, and will be adopted on the 2014 federal income tax return. The IRS has been working with the utility industry to provide industry specific guidance concerning the deductibility and capitalization of expenditures related to tangible property. The IRS has indicated that it expects to issue updated or new guidance with respect to natural gas transmission and distribution assets during 2015. The Company continues to evaluate the impact adoption of the regulations and industry guidance will have on its consolidated financial statements. As of this date, the Company does not expect the adoption of the regulations to have a material impact on its consolidated financial statements.

Indiana Senate Bill 1

In March 2014, Indiana Senate Bill 1 was signed into law. This legislation phases in a 1.6 percent rate reduction to the Indiana Adjusted Gross Income Tax Rate for corporations over a six year period. Pursuant to this legislation, the tax rate will be lowered by 0.25 percent each year for the first five years and 0.35 percent in year six beginning on July 1, 2016 to the final rate of 4.9 percent effective July 1, 2021. Pursuant to FASB guidance, the Company accounted for the effect of the change in tax law on its deferred taxes in the first quarter of 2014, the period of enactment. The impact was not material to results of operations.


6.	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, 2014 and 2013 were $50.2 million and $62.0 million, respectively. The intercompany credit line totals $325 million, but is limited to Utility Holdings’ available capacity ($194 million at December 31, 2014) 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)	2014			2013
Year End
Balance Outstanding	$	50,178		$	62,024
Weighted Average Interest Rate	0.50		%	0.30		%
Annual Average
Balance Outstanding	$	6,847		$	21,662
Weighted Average Interest Rate	0.37		%	0.34		%
Maximum Month End Balance Outstanding	$	50,178		$	62,024

Long-Term Debt

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



	At December 31,
(In thousands)	2014			2013
Fixed Rate Senior Unsecured Notes Payable to Utility Holdings:
2015, 5.45%	$	24,716		$	24,716
2018, 5.75%	37,128			37,128
2023, 3.72%	74,538			—
2028, 3.20%	8,953			8,953
2035, 6.10%	50,569			50,569
2043, 4.25%	15,916			15,916
Total long-term debt payable to Utility Holdings	$	211,820		$	137,282
Current maturities	(24,716		)	—
Long-term debt payable to Utility Holdings - net of current maturities	$	187,104		$	137,282

Fixed Rate Senior Unsecured Notes Payable to Third Parties:
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	$	116,000		$	116,000
Current maturities	(20,000		)	—
Long-term debt payable to third parties - net of current maturities	$	96,000		$	116,000

Issuance payable to Utility Holdings

On April 1, 2013, VUHI exercised a call option at par on $121.6 million 6.25 percent senior unsecured notes due in 2039. This debt was refinanced on June 5, 2013, with proceeds from a private placement note purchase agreement entered into on December 20, 2012 with a delayed draw feature. It provides for the following tranches of notes: (i) $45 million, 3.20 percent senior guaranteed notes, due June 5, 2028 and (ii) $80 million, 4.25 percent senior guaranteed notes, due June 5, 2043. Total proceeds received from these notes, net of issuance costs, were $44.8 million and $79.6 million, respectively, of which $9.0 million and $15.9 million, respectively, were reloaned to Indiana Gas. The notes are unconditionally guaranteed by SIGECO, Indiana Gas, and VEDO.

On August 22, 2013, VUHI entered into a private placement note purchase agreement with a delayed draw feature, pursuant to which institutional investors agreed to purchase $150 million of senior guaranteed notes with a fixed interest rate of 3.72 percent per annum, due December 5, 2023. The notes were unconditionally guaranteed by Indiana Gas, SIGECO, and VEDO. On December 5, 2013, the VUHI received net proceeds of $149.1 million from the issuance of the senior guaranteed notes which were used to refinance $100 million of 5.25 percent senior notes that matured August 1, 2013, for capital expenditures, and for general corporate purposes. In January 2014, $74.5 million of this debt was reloaned to Indiana Gas.

Long-Term Debt Sinking Fund Requirements & Maturities

The Company has no sinking fund requirements on long-term debt during the five years following 2014. Long-term debt maturities in the five years following 2014 total $44.7 million in 2015, zero in 2016 and 2017, $37.1 in 2018, and zero in 2019.

Covenants

Both long-term and short-term borrowing arrangements contain customary default provisions; restrictions on liens, sale-leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage, among other restrictions. As of December 31, 2014, the Company was in compliance with all financial debt covenants.


7.	Commitments & Contingencies

Purchase Commitments

The Company has both firm and non-firm commitments to purchase natural gas, as well as certain transportation and storage rights and certain contracts are firm commitments under five and ten year arrangements. Costs arising from these commitments, while significant, are pass-through costs, generally collected dollar-for-dollar from retail customers through regulator-approved cost recovery mechanisms. Because of the pass through nature of these costs, they have not been included in the listing of contractual obligations.

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.


8.	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 programs to replace bare steel and cast iron infrastructure and other activities to mitigate risk, improve the system, and comply with applicable regulations, many of which are a result of federal pipeline safety requirements. Laws were passed that provide utilities the opportunity to timely recover costs of federally mandated projects and other infrastructure improvement projects outside of a base rate proceeding.

In April 2011, Indiana Senate Bill 251 (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 is deferred for future recovery in the utility's next general rate case.

In April 2013, Indiana Senate Bill 560 (Senate Bill 560) was signed into Indiana law. This legislation supplements Senate Bill 251 described above, and provides for cost recovery outside of a base rate proceeding for projects that either improve electric and gas system reliability and safety or are economic development projects that provide rural areas with access to gas service. Provisions of the legislation require that, among other things, requests for recovery include a seven-year project plan. Once the plan is approved by the IURC, 80 percent of such costs are eligible for current recovery using a periodic rate adjustment mechanism. Recoverable costs include a return on and of the investment, as well as property taxes and operating expenses. The remaining 20 percent of project costs is deferred and recovered in the utility’s next general rate case, which must be filed

before the expiration of the seven-year plan. The adjustment mechanism is capped at an annual increase in retail revenues of no more than two percent.

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. The debt-related post-in-service carrying costs are recognized in the Consolidated Statements of Income currently. The recording of post-in-service carrying costs and depreciation deferral is limited by individual qualifying project to four years after being placed into service. At December 31, 2014 and 2013, the Company has regulatory assets totaling $14.5 million and $10.7 million, respectively, associated with the deferral of depreciation and debt-related post-in-service carrying cost activities. Beginning in 2014, all bare steel and cast iron replacement activities are now part of the Company’s seven-year capital investment plan filed pursuant to Senate Bill 251, discussed further below.

Requests for Recovery Under Indiana Regulatory Mechanisms

On August 27, 2014, the Commission issued an Order approving the Company’s seven-year capital infrastructure replacement and improvement plan, beginning in 2014, and the proposed accounting authority and recovery, pursuant to Senate Bill 251 and 560. As provided in the two laws, the Order approved semi-annual filings for rate recovery of 100 percent of the costs, inclusive of return, related to these capital investments and operating expenses associated with pipeline safety rules, with 80 percent of the costs recovered currently via an approved tracking mechanism and 20 percent of the costs deferred and recovered in the Company’s next base rate proceeding. In addition, the Order established guidelines to update the seven-year capital investment plan annually, with detailed estimates provided for the upcoming calendar year. Finally, the Order approved the Company’s proposal to recover eligible costs via a fixed monthly charge per residential customer. On September 26, 2014, the Indiana Office of Utility Consumer Counselor (OUCC) filed a Notice of Appeal with the Indiana Court of Appeals in response to the IURC's Order. On January 28, 2015, the OUCC filed its appellate brief raising an issue regarding the treatment of retired assets within the recovery mechanism. An appeal was also filed in response to the IURC's Order in Northern Indiana Public Service Company's (NIPSCO) Senate Bill 560 electric infrastructure proceeding, pertaining to certain issues regarding the Commission's authority to approve NIPSCO's infrastructure plan. The outcome of either appeal and the implications to the Company’s Order, if any, cannot be determined.

On January 14, 2015, the Commission issued an Order approving the Company’s initial request for recovery of the revenue requirement associated with capital investment and applicable operating costs through June 30, 2014 as part of its approved seven-year plan. As the next step of the recovery process, as outlined in the legislation, this Order initiates the rates and charges necessary to begin cash recovery of 80 percent of the revenue requirement, with the remaining 20 percent deferred for recovery in the Company's next rate cases. Also, consistent with the guidelines set forth in the original August 2014 Order, the Commission approved the Company’s update to its seven-year plan, to reflect changes to project prioritization as a result of both additional risk modeling and cost increases. The updated plan reflects capital expenditures of approximately $700 million, an increase of $30 million from the previous plan and is inclusive of an estimated $30 million of economic development related expenditures, over the seven-year period beginning in 2014. The plan also includes approximately $10 million of annual operating costs associated with pipeline safety rules.

Other Regulatory Matters

GCA Cost Recovery Issue

On July 1, 2014, the Company filed its recurring quarterly Gas Cost Adjustment (GCA) mechanism, which included recovery of gas cost variances incurred for the period January through March 2014. In August 2014, the OUCC filed testimony opposing the recovery of approximately $3.9 million of natural gas commodity purchases incurred during this period on the basis that a gas cost incentive calculation had not been properly performed. The calculation at issue is performed by the Company's supply administrator. In the winter period at issue, a pipeline force majeure event caused the gas to be priced at a location that was impacted by the extreme winter temperatures. After further review, the OUCC had modified its position in testimony filed on November 5, 2014, and now suggests a reduced disallowance of $3 million. The Commission moved this specific issue to a sub-docket proceeding, and on March 20, 2015 the parties reached an agreement in principle to settle the remaining issues by

agreeing on a credit to customers that would be funded by the Company's supply administrator. The parties will file the settlement agreement with the Commission for approval.

Gas Decoupling Extension Filing

On August 18, 2011, the IURC issued an Order granting the extension of the current decoupling mechanism in place and recovery of new conservation program costs through December 2015. On March 2, 2015, the Company and the OUCC filed a joint settlement agreement for approval by the Commission to extend the decoupling mechanism through 2020.

9. 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 remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery. As of December 31, 2014 and 2013, approximately $0.9 million and $1.3 million, respectively, of accrued, but not yet spent, costs are included in Other liabilities related to these sites.

10. 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,
	2014				2013
(In thousands)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt payable to third parties	$	116,000	$	144,785	$	116,000	$	136,459
Long-term debt payable to Utility Holdings	211,820		235,124		137,282		146,052
Short-term debt payable to Utility Holdings	50,178		50,178		62,024		62,024
Cash & cash equivalents	2,964		2,964		3,622		3,622

For the balance sheet dates presented in these consolidated financial statements, the Company had no material assets or liabilities recorded at fair value outstanding, and no material assets or liabilities valued using Level 3 inputs.

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

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

11. Additional Balance Sheet & Operational Information

Inventories in the Consolidated Balance Sheets consist of the following:



	At December 31,
(In thousands)	2014		2013
Gas in storage - at LIFO cost	$	22,894	$	19,672
Materials & supplies	2,797		2,805
Other	1,752		1,022
Total inventories	$	27,443	$	23,499

Based on the average cost of gas purchased during December, the cost of replacing gas in storage carried at LIFO cost exceeded the carrying value at December 31, 2014 and 2013, by approximately $6 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)	2014		2013
Prepaid gas delivery service	$	40,660	$	32,852
Prepaid taxes & other	15,932		719
Total prepayments & other current assets	$	56,592	$	33,571

The increase in prepaid taxes in 2014 was due to the timing of passage of the federal legislation that extended bonus depreciation retroactively for the year.

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



	At December 31,
(In thousands)	2014		2013
Customer advances & deposits	$	28,216	$	26,392
Accrued gas imbalance	1,410		2,594
Accrued taxes	9,849		12,462
Accrued interest	3,003		2,998
Deferred income taxes	5,392		2,081
Tax collections payable	5,146		4,818
Accrued salaries & other	2,768		2,587
Total accrued liabilities	$	55,784	$	53,932

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



(In thousands)	2014		2013
Asset retirement obligation, January 1	$	11,823	$	10,345
Accretion	742		699
Changes in estimates, net of cash payments	12,050		779
Asset retirement obligation, December 31	$	24,615	$	11,823

The increase in the asset retirement obligation during the year related to changes in estimates, net of cash payments, is primarily driven by a change in the methodology of how sections of gas pipeline are replaced.

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



	Year Ended December 31,
(In thousands)	2014			2013
AFUDC - borrowed funds	$	2,414		$	1,277
AFUDC - equity funds	701			408
Other income	418			695
Regulatory expenses	(1,304		)	(1,168		)
Total other income – net	$	2,229		$	1,212

Supplemental Cash Flow Information:



	Year Ended December 31,
(In thousands)	2014		2013
Cash paid for:
Interest	$	18,896	$	16,331
Income taxes	26,414		18,239

As of December 31, 2014 and 2013, the Company had accruals related to utility plant purchases totaling approximately $1.3 million and $3.1 million, respectively.

12. Adoption of Other Accounting Standards

Revenue Recognition Guidance

In May 2014, the FASB issued new accounting guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for GAAP and IFRS. The amendments in this guidance state that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This new guidance requires improved disclosures to help users of financial statements better understand the nature, amount, timing, and uncertainty of revenue that is recognized. For a public entity, the guidance is effective for annual reporting periods beginning after December 15, 2016, with early adoption not permitted. An entity should apply the amendments in this update retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying this update recognized at the date of initial application. The Company is currently evaluating the standard to understand the overall impact it will have on the financial statements.

Financial Reporting of Discontinued Operations

In April 2014, the FASB issued new accounting guidance on reporting discontinued operations and disclosures of disposals of a company or entity. The guidance changes the criteria for reporting discontinued operations and provides for enhanced disclosures in this area. Under the new guidance, only disposals representing a strategic shift in operations should be presented as discontinued operations. Those strategic shifts should have a major effect on the organization's operations and financial results. Additionally, the new guidance requires expanded disclosures about discontinued operations to provide more information about the assets, liabilities, income, and expenses of discontinued operations. The new guidance also requires disclosure of the pre-tax income attributable to a disposal of a significant part of an organization that does not qualify for discontinued operations reporting. This guidance is effective for fiscal years beginning on or after December 15, 2014, with early adoption permitted. The Company is currently evaluating the impact of this guidance, if any.

Financial Reporting of Going Concern

In August 2014, the FASB issued new accounting guidance with respect to reporting on an entity's ability to continue as a going concern. This new guidance requires management to assess an entity's ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in U.S. auditing standards, which requires disclosure surrounding what constitutes substantial doubt for the entity, including disclosure of management's plans to mitigate and alleviate substantial doubt. This guidance is effective for annual periods beginning after December 15, 2016, and for annual and interim periods thereafter, with early application permitted. Adoption of this guidance will not have a material impact on the Company’s financial statements.

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

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 2014 annual reports filed on Form 10-K, which includes 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 2014, Indiana Gas had $39.2 million in net income compared to net income of $40.7 million in 2013. Though customer margin increased in 2014 from customer growth and usage, increased operating costs offset those margin increases. The increased operating costs were primarily the result of increased performance-based compensation expense and increased weather-related maintenance during the first half of 2014. Depreciation expense increased reflecting the additions of plant in service. Interest expense was unfavorably impacted by the increase in intercompany long-term debt in 2014 compared to 2013.

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.

In the Company’s service territory, normal temperature adjustment (NTA) and decoupling mechanisms largely mitigate the effect that would otherwise be caused by variations in volumes sold to residential and commercial customers due to weather and changing consumption patterns. In addition to these mechanisms, the Commission has authorized specific bare steel and cast iron replacement programs and an expanded gas infrastructure replacement program, which allow for recovery of these investments outside of a base rate case proceeding. Further, rates charged to customers contain a gas cost adjustment (GCA) clause. This cost tracker mechanism allows for the timely adjustment in charges to reflect changes in the cost of gas. The Company utilizes similar mechanisms for other material operating costs, which allow for changes in revenue outside of a base rate case. The implementation of these various mechanisms has allowed the Company to avoid regulatory proceedings to increase base rates since 2008.

Rate Design Strategies

Sales of natural gas to residential and commercial customers are largely seasonal and are impacted by weather. Trends in the average consumption among residential and commercial customers have tended to decline as more efficient furnaces are installed and the Company has implemented conservation programs. In the Company’s service territory, normal temperature adjustment 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.

In the Company's service territory, the Commission has authorized bare steel and cast iron replacement programs. State laws were passed in 2012 and 2013 that expand the ability of utilities to recover, outside of a base rate proceeding, certain costs of federally mandated projects and other significant gas distribution and transmission infrastructure replacement investments. The Company has received approval to implement these mechanisms.

Tracked Operating Expenses

Gas costs incurred to serve customers are one of the Company’s most significant operating expenses. Rates charged to customers contain a gas cost adjustment 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 actual experience and subject to caps that are based on historical experience.

GCA procedures involve periodic filings and IURC hearings to establish 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.

Gas pipeline integrity management operating 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 typical base rate recovery. In addition, certain operating costs, including depreciation, associated with federally mandated investments, and gas distribution and transmission infrastructure replacement investments, not in base rates are also recovered by mechanisms outside of typical base rate recovery.

Revenues and margins are also impacted by the collection of state mandated taxes, which primarily fluctuate with gas costs.

Base Rate Orders

The Company received an order and implemented rates in 2008. This order authorizes a return on equity of 10.2%. The authorized returns reflect the impact of rate design strategies that have been authorized by the IURC.

See Note 8 to the consolidated 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)	2014		2013

Gas utility revenues	$	680,409	$	577,617
Cost of gas	392,568		300,174
Total gas utility margin	$	287,841	$	277,443
Margin attributed to:
Residential & commercial customers	$	220,874	$	219,099
Industrial customers	33,082		31,360
Other	6,624		5,867
Regulatory expense recovery mechanisms	27,261		21,117
Total gas utility margin	$	287,841	$	277,443
Sold & transported volumes in MDth attributed to:
Residential & commercial customers	72,391		65,980
Industrial customers	62,796		59,961
Total sold & transported volumes	135,187		125,941

Gas utility margins were $287.8 million for the year ended December 31, 2014, and compared to 2013, increased $10.4 million. Customer margin increased approximately $3.5 million in 2014 from customer growth and usage. The impact of higher natural gas prices and colder weather on revenue taxes, late and reconnect fees, and volumetric pass through costs increased gas utility margin $6.1 million in 2014 compared to 2013. With rate designs that substantially limit the impact of weather on margin, heating degree days in 2014 that were 107 percent of normal compared to 102 percent in 2013, had a significant impact on residential and commercial customer volumes sold, but had relatively no impact, excluding pass-through regulatory recovery mechanisms, on residential and commercial customer margin.

Operating Expenses

Other Operating

For the year ended December 31, 2014, Other operating expenses were $123.9 million, which is an increase of $8.1 million, compared to 2013. Excluding operating expenses recovered through margin, expenses increased $4.0 million, primarily associated with an increase in performance-based compensation expense and increased expenses related to gas system maintenance largely due to the harsh winter weather in the first half of 2014.

Depreciation & Amortization

For the year ended December 31, 2014, depreciation and amortization expense increased $2.2 million compared to 2013. The increase in expense resulted from additional utility plant investments placed into service.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $2.1 million in 2014 compared to 2013. The increase is attributable to higher usage taxes associated with higher gas costs. These expenses are offset dollar-for-dollar with higher gas utility revenues.

Other Income – Net

Other income – net was $2.2 million in 2014, a increase of $1.0 million compared to 2013. The increase reflects increased allowance for funds used during construction (AFUDC). The higher AFUDC reflects an increased AFUDC rate as well as increased capital expenditures related to infrastructure replacement investments.

Interest Expense

For the year ended December 31, 2014, interest expense was $18.9 million, an increase of $2.7 million compared to 2013. Interest expense was unfavorably impacted by the increase in intercompany long-term debt in 2014 compared to 2013.

Income Taxes

For the year ended December 31, 2014, income taxes decreased $2.2 million compared to 2013. The decrease in income taxes reflect lower pre-tax earnings as well as a decrease in the state tax rate.

SELECTED GAS OPERATING STATISTICS:



	For the Year Ended
	December 31,
	2014		2013

OPERATING REVENUES (In thousands):
Residential	$	462,812	$	391,784
Commercial	174,272		145,349
Industrial	36,698		34,571
Other	6,627		5,913
	$	680,409	$	577,617

MARGIN (In thousands):
Residential	$	171,011	$	169,571
Commercial	49,863		49,528
Industrial	33,082		31,360
Other	6,624		5,867
Regulatory expense recovery mechanisms	27,261		21,117
	$	287,841	$	277,443

GAS SOLD & TRANSPORTED (In MDth):
Residential	49,520		45,137
Commercial	22,871		20,843
Industrial	62,796		59,961
	135,187		125,941

AVERAGE CUSTOMERS:
Residential	523,134		519,026
Commercial	50,785		50,448
Industrial	908		899
	574,827		570,373

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