Exhibit

This annual reporting package provides additional information regarding the operations of Indiana Gas Company, Inc. (the Company, Indiana Gas or Vectren Energy Delivery of Indiana - North) and its subsidiary. This information is supplemental to Vectren Corporation’s (Vectren) annual report for the year ended December 31, 2015, filed on Form 10-K with the Securities and Exchange Commission on February 23, 2016 and Vectren Utility Holdings, Inc.’s (Utility Holdings) 10-K filed on March 9, 2016. 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.



AFUDC: allowance for funds used during construction	IDEM: Indiana Department of Environmental Management
ASC: Accounting Standards Codification	IURC: Indiana Utility Regulatory Commission
ASU: Accounting Standards Update	MCF / MMCF / BCF: thousands / millions / billions of cubic feet
DOT: Department of Transportation	MDth / MMDth: thousands / millions of dekatherms
FASB: Financial Accounting Standards Board	MMBTU: millions of British thermal units
FERC: Federal Energy Regulatory Commission	OUCC: Indiana Office of the Utility Consumer Counselor
GAAP: Generally Accepted Accounting Principles	Throughput: combined gas sales and gas transportation volumes
GCA: Gas Cost Adjustment

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, 2015 and 2014, 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 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.

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.

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, 2015 and 2014, 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.



	December, 31
	2015		2014
ASSETS
Utility Plant
Original cost	$	2,052,417	$	1,901,776
Less: accumulated depreciation & amortization	841,558		792,012
Net utility plant	1,210,859		1,109,764

Current Assets
Cash & cash equivalents	2,422		2,964
Accounts receivable - less reserves of $1,292 &
$2,051, respectively	33,213		47,625
Accrued unbilled revenues	37,899		62,384
Inventories	27,166		27,443
Recoverable natural gas costs	—		9,824
Prepayments & other current assets	30,031		56,592
Total current assets	130,731		206,832

Other investments	7,116		7,591
Regulatory assets	46,016		31,213
Other assets	26,604		21,836
TOTAL ASSETS	$	1,421,326	$	1,377,236



	December 31,
		2015		2014
LIABILITIES & SHAREHOLDER'S EQUITY
Common Shareholder's Equity
Common stock (no par value)		$	259,536	$	259,536
Retained earnings		143,606		131,411
Total common shareholder's equity		403,142		390,947
Long-term debt payable to third parties - net of current maturities		96,000		96,000
Long-term debt payable to Utility Holdings - net of current maturities		226,893		187,104
Total long-term debt		322,893		283,104
Commitments & Contingencies (Notes 5, 7-9)
Current Liabilities
Accounts payable		62,497		62,090
Payables to other Vectren companies		13,235		21,894
Refundable natural gas costs		3,559		—
Accrued liabilities		47,117		50,391
Short-term borrowings payable to Utility Holdings		67,447		50,178
Current maturities of long-term debt		—		20,000
Current maturities long-term debt payable to Utility Holdings		—		24,716
Total current liabilities		193,855		229,269
Deferred Income Taxes & Other Liabilities
Deferred income taxes		211,336		197,353
Regulatory liabilities		250,096		237,820
Deferred credits & other liabilities		40,004		38,743
Total deferred income taxes & other liabilities		501,436		473,916
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY		$	1,421,326	$	1,377,236



	Year Ended December 31,
	2015		2014

OPERATING REVENUES	$	551,968	$	680,409
OPERATING EXPENSES
Cost of gas sold	261,049		392,568
Other operating	120,459		123,938
Depreciation & amortization	66,933		63,799
Taxes other than income taxes	16,292		18,396
Total operating expenses	464,733		598,701

OPERATING INCOME	87,235		81,708
Other income - net	2,432		2,229
Interest expense	18,514		18,901
INCOME BEFORE INCOME TAXES	71,153		65,036
Income taxes	28,394		25,878
NET INCOME	$	42,759	$	39,158



	Year Ended December 31,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	42,759		$	39,158
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization	66,933			63,799
Deferred income taxes & investment tax credits	14,120			18,356
Expense portion of pension & postretirement periodic benefit cost	1,228			1,163
Provision for uncollectible accounts	2,526			3,969
Other non-cash charges - net	1,354			1,491
Changes in working capital accounts:
Accounts receivable, including due from Vectren companies
& accrued unbilled revenues	36,371			(14,429		)
Inventories	277			(3,944		)
Recoverable/refundable natural gas costs	13,383			(4,334		)
Prepayments & other current assets	26,562			(22,608		)
Accounts payable, including to Vectren companies
& affiliated companies	(8,528		)	6,666
Accrued liabilities	(3,274		)	(1,460		)
Changes in noncurrent assets	(17,071		)	6,824
Changes in noncurrent liabilities	(4,365		)	(3,546		)
Net cash provided by operating activities	172,275			91,105
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt, net of issuance costs	39,789			74,538
Requirements for:
Dividends to Utility Holdings	(30,564		)	(31,208		)
Retirement of long-term debt	(44,716		)	—
Net change in short-term borrowings, including from Utility Holdings	17,269			(11,846		)
Net cash flows from financing activities	(18,222		)	31,484
CASH FLOWS FROM INVESTING ACTIVITIES
Requirements for capital expenditures, excluding AFUDC equity	(154,595		)	(123,247		)
Net cash used in investing activities	(154,595		)	(123,247		)
Net change in cash & cash equivalents	(542		)	(658		)
Cash & cash equivalents at beginning of period	2,964			3,622
Cash & cash equivalents at end of period	$	2,422		$	2,964



	Common		Retained
	Stock		Earnings			Total

Balance at January 1, 2014	$	259,536	$	123,461		$	382,997
Net 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
Net income			42,759			42,759
Common stock:
Dividends to Utility Holdings			(30,564		)	(30,564		)
Balance at December 31, 2015	$	259,536	$	143,606		$	403,142

Indiana Gas Company, Inc. and subsidiary company (the Company, Indiana Gas, or Vectren Energy Delivery of Indiana - North), an Indiana corporation, provides energy delivery services to approximately 580,000 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.

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 valuing deferred tax obligations, unbilled revenue, uncollectible accounts, regulatory assets and liabilities, asset retirement obligations, and derivatives and other financial instruments. Estimates also impact the depreciation of utility plant and the testing of 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.

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.

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.

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.

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.

All metered gas rates contain a gas cost adjustment clause (GCA) 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 GCA 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 represent certain incurred costs, which will result in probable future cash recoveries 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.

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.

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 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.

Certain assets and liabilities are valued and 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.

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)	2015				2014
	Original Cost		Depreciation Rates as a Percent of Original Cost		Original Cost		Depreciation Rates as a Percent of Original Cost
Utility plant	$	2,035,105	3.6	%	$	1,889,944	3.6	%
Construction work in progress	17,312		—		11,832		—
Total original cost	$	2,052,417			$	1,901,776

Regulatory assets consist of the following:



	At December 31,
(In thousands)	2015			2014
Future amounts recoverable from ratepayer related to:
Net deferred income taxes	$	(3,560	)	$	(3,394	)
Other	—			(1		)
	(3,560		)	(3,395		)
Amounts deferred for future recovery related to:
Cost recovery riders & other	19,817			15,972
	19,817			15,972
Amounts currently recovered through customer rates related to:
Authorized trackers	27,357			15,871
Unamortized debt issue costs & premiums paid to reacquire debt	2,402			2,765
	29,759			18,636
Total regulatory assets	$	46,016		$	31,213

Of the $29.8 million currently being recovered in rates charged to customers, no amounts are earning return. The weighted average recovery period of regulatory assets currently being recovered in base rates, which totals $2.4 million, is 18 years. The remainder of the regulatory assets are being timely recovered through tracking mechanisms. The Company has rate orders for all deferred costs not yet in rates and therefore believes that future recovery is probable.

Vectren and Utility Holdings provide corporate and general and administrative assets and services to the Company and allocate 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 $56.9 million and $57.1 million for the years ended December 31, 2015, and 2014, respectively. Amounts owed to Vectren and Utility Holdings at December 31, 2015 and 2014 are included in Payables to other Vectren companies.

At December 31, 2015, Vectren maintains three closed 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

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. Although the Company has no contractual funding obligation, the Company contributed $6.6 million to Vectren's defined benefit pension plans during 2015 and did not contribute in 2014. The combined funded status on a GAAP basis of Vectren’s plans was approximately 90 percent at December 31, 2015 and 87 percent at December 31, 2014. A contribution of $15 million was made by Vectren to the qualified pension plans in 2016. Indiana Gas has funded a portion of this contribution.

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, 2015 and 2014, costs totaling $1.8 million and $1.7 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, 2015 and 2014, the Company has $26.6 million and $21.8 million, respectively, included in Other assets representing defined benefit and other postretirement benefit funding by the Company that is yet to be reflected in costs.

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 both December 31, 2015 and 2014, $13.2 million is included in Deferred credits & other liabilities and represents obligations that are yet to be funded to Vectren.

Utility Holdings’ three operating utility companies, Southern Indiana Gas and Electric Company (SIGECO), Indiana Gas, and Vectren Energy Delivery of Ohio, Inc. (VEDO) are guarantors of Utility Holdings’ $350 million short-term credit facility, of which approximately $15 million is outstanding at December 31, 2015, and Utility Holdings’ $1 billion unsecured senior notes outstanding at December 31, 2015. The majority of Utility Holdings' unsecured senior notes outstanding are allocated to the operating utility companies. The guarantees are full and unconditional and joint and several, and Utility Holdings has no subsidiaries other than the subsidiary guarantors.

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.

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.

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



	Year Ended December 31,
(In thousands)	2015			2014
Current:
Federal	$	8,967		$	2,994
State	5,333			4,528
Total current tax expense	14,300			7,522
Deferred:
Federal	14,435			17,976
State	(311		)	417
Total deferred tax expense	14,124			18,393
Amortization of investment tax credits	(30		)	(37		)
Total income tax expense	$	28,394		$	25,878

Significant components of the net deferred tax liability follow:



	At December 31,
(In thousands)	2015			2014
Noncurrent deferred tax liabilities (assets):
Depreciation & cost recovery timing differences	$	199,107		$	181,259
Regulatory assets recoverable through future rates	11,507			11,265
Regulatory liabilities to be settled through future rates	(9,652		)	(9,402		)
Employee benefit obligations	3,017			2,604
Deferred fuel costs - net	(82		)	3,501
Other – net	7,439			8,126
Net deferred tax liability	$	211,336		$	197,353

The Company has presented its deferred tax assets and deferred tax liabilities as non-current in the tables above and in the balance sheet, in accordance with ASU 2015-17, Balance Sheet Classification of Deferred Taxes. The Company early adopted ASU 2015-17 in the current year as the new standard simplifies current accounting guidance, which required entities to separately present deferred tax assets and deferred tax liabilities as current and non-current. This guidance was adopted for the year ended December 31, 2015, and has been applied retrospectively to all periods presented. The effect of this change on the December 31, 2015 and 2014 Balance Sheets is a reclassification from current deferred tax liability to long-term deferred tax liability of $2.0 million and $5.4 million, respectively.

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, 2012. The State of Indiana, Vectren's primary state tax jurisdiction, has conducted examinations of state income tax returns for tax years through December 31, 2010. The statutes of limitations for assessment of federal income tax and Indiana income tax have expired with respect to tax years through 2011 except to the extent of refunds claimed on amended tax returns. The statutes of limitations for assessment of the 2009-2011 tax years related to the amended federal and Indiana income tax returns will expire in 2016 and 2017.

In September 2013, the IRS 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 were 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 2016. The Company continues to evaluate the impact adoption and industry guidance will have on its consolidated financial statements. As of this date, the Company does not expect the industry guidance to have a material impact on its consolidated financial statements.

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.

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, 2015 and 2014 were $67.4 million and $50.2 million, respectively. The intercompany credit line totals $350 million, but is limited to Utility Holdings’ available capacity ($335 million at December 31, 2015) 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)	2015			2014
Year End
Balance Outstanding	$	67,447		$	50,178
Weighted Average Interest Rate	0.55		%	0.50		%
Annual Average
Balance Outstanding	$	21,347		$	6,847
Weighted Average Interest Rate	0.41		%	0.37		%
Maximum Month End Balance Outstanding	$	68,338		$	50,178



	At December 31,
(In thousands)	2015		2014
Fixed Rate Senior Unsecured Notes Payable to Utility Holdings:
2015, 5.45%	$	—	$	24,716
2018, 5.75%	37,128		37,128
2023, 3.72%	74,538		74,538
2028, 3.20%	8,953		8,953
2035, 6.10%	50,569		50,569
2035, 3.90%	8,289		—
2043, 4.25%	15,916		15,916
2045, 4.36%	15,750		—
2055, 4.51%	15,750		—
Total long-term debt payable to Utility Holdings	$	226,893	$	211,820
Current maturities	—		(24,716		)
Total long-term debt payable to Utility Holdings - net	$	226,893	$	187,104

Fixed Rate Senior Unsecured Notes Payable to Third Parties:
2015, Series E, 7.15%	$	—	$	5,000
2015, Series E, 6.69%	—		5,000
2015, Series E, 6.69%	—		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 payable to third parties	$	96,000	$	116,000
Current maturities	—		(20,000		)
Total long-term debt payable to third parties - net	$	96,000	$	96,000

On December 15, 2015, VUHI issued Guaranteed Senior Notes in a private placement to various institutional investors in the following tranches: (i) $25 million of 3.90 percent Guaranteed Senior Notes, Series A, due December 15, 2035, (ii) $135 million of 4.36 percent Guaranteed Senior Notes, Series B, due December 15, 2045, and (iii) $40 million of 4.51 percent Guaranteed Senior Notes, Series C, due December 15, 2055. The notes are unconditionally guaranteed by Indiana Gas, SIGECO and VEDO. In December 2015, $39.8 million of this debt was reloaned to Indiana Gas.

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.

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.

The Company monitors and maintains its natural gas distribution system to ensure natural gas is delivered in a safe and efficient manner. The Company's natural gas utilities are 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 in Indiana 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, based on the overall rate of return most recently approved by the Commission, 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 the investment that reflects the current capital structure and associated costs, with the exception of the rate of return on equity, which remains fixed at the rate determined in the Company's last rate case. Recoverable costs also include recovery of depreciation and other operating expenses. The remaining 20 percent of project costs are 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.

The Company received an Order in 2008 associated with the most recent base rate cases. 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, 2015 and December 31, 2014, the Company has regulatory assets totaling $17.7 million and $14.5 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 and 560, discussed further below.

On August 27, 2014, the IURC issued an Order (August 2014 Order) approving the Company’s seven-year capital infrastructure replacement and improvement plan, beginning in 2014, and the proposed accounting authority and recovery. Compliance projects and other infrastructure improvement projects were approved pursuant to Senate Bill 251 and 560, respectively. 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, with 80 percent of the costs, including a return, 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 annually update the seven-year capital investment plan. 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 OUCC filed an appeal of the IURC's finding that the remaining value of retired assets replaced during the infrastructure projects should not be netted against the cost being recovered in the tracking mechanism. In June 2015, the Indiana Court of Appeals issued an opinion in favor of the Company that affirmed the IURC's August 2014 Order approving the infrastructure plan.

On January 14, 2015, the IURC issued an Order approving the Company’s initial request for recovery of the revenue requirement through June 30, 2014 as part of its approved seven-year plan. Also, consistent with the guidelines set forth in the original August 2014 Order, the IURC 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 changes to estimated project costs.

On April 1, 2015, the Company filed its second request for recovery of the revenue requirement associated with capital investment and applicable operating costs through December 31, 2014. On June 1, 2015, the Company amended its case to delay the recovery of a portion of the investment associated with Senate Bill 560 made from July 2014 to December 2014, until its third filing when it committed to provide additional project detail for the later years of the plan. This commitment was as a result of an Indiana Court of Appeals decision regarding the approval of Northern Indiana Public Service Company's (NIPSCO) proposed electric Transmission, Distribution, and Storage Improvement Charge (TDSIC) plan, and challenges to TDSIC plans filed by other Indiana utilities.

On July 22, 2015, the IURC issued an Order, approving the recovery of these investments consistent with the Company's proposal, with modification, specifically to the rate of return applicable to the Senate Bill 251 compliance component. The IURC found that the overall rate of return to be applied to the investment in determining the revenue requirement is to be updated with each filing, reflecting the current capital structure and associated costs, with the exception of the rate of return on equity, which remains fixed at the rate determined in the Company's last base rate case. This IURC interpretation of the overall rate of return to be used is the same as that already in place for the Senate Bill 560 component.

On October 1, 2015, the Company filed its third request for recovery of the revenue requirement associated with capital investment and applicable operating costs through June 30, 2015, including investment associated with Senate Bill 560 made from July 2014 to December 2014 that had been delayed in the second request. The Company provided an update to its seven-year plan, as well as additional detail on the planned investments included in the plan. The updated plan reflects capital expenditures of approximately $775 million, an increase of $95 million from the previous plan, of which $207 million has been spent as of December 31, 2015. The ability to include new projects as part of an updated Senate Bill 560 plan has been challenged in this case.

As of December 31, 2015, the Commission has approved project categories that encompass planned infrastructure investments during the plan term of approximately $600 million of the proposed $775 million of capital spend. The remaining proposed amount is now pending approval in the third request for recovery. Pursuant to the process outlined in Senate Bill 560, the Company expects an order in early 2016.

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 modified its position in testimony filed on November 5, 2014, and suggested a reduced disallowance of $3 million. The IURC moved this specific issue to a sub-docket proceeding. On April 1, 2015, a stipulation and settlement agreement between the Company, the OUCC, and the Company’s supply administrator was filed in this proceeding. The IURC issued an Order on June 10, 2015 which approved the stipulation and settlement agreement, which resulted in recovery of approximately $1.4 million of the disputed amount via the Company’s GCA mechanism, with the remaining $1.6 million received from the gas supply administrator.

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.

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 upon 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, 2015 and December 31, 2014, approximately $0.8 million and $0.9 million, respectively, of accrued, but not yet spent, costs are included in Other Liabilities related to these sites.



	At December 31,
	2015				2014
(In thousands)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt payable to third parties	$	96,000	$	117,234	$	116,000	$	144,785
Long-term debt payable to Utility Holdings	226,893		240,989		211,820		235,124
Short-term borrowings payable to Utility Holdings	67,447		67,447		50,178		50,178
Cash & cash equivalents	2,422		2,422		2,964		2,964

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.

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, 2015 and 2014, by approximately $4 million and $6 million, respectively. Rates charged to customers contain a gas cost adjustment clause that allows the Company to timely charge for changes in the cost of purchased gas. The Company purchases most of its gas supply from a single third party.

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



	At December 31,
(In thousands)	2015		2014
Customer advances & deposits	$	28,826	$	28,216
Accrued gas imbalance	1,236		1,410
Accrued taxes	8,417		9,849
Accrued interest	2,611		3,003
Tax collections payable	3,285		5,146
Accrued salaries & other	2,742		2,767
Total accrued liabilities	$	47,117	$	50,391

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.

On July 9, 2015, the FASB approved a one year deferral that became effective through an Accounting Standard Update in August and changed the effective date to annual reporting periods beginning after December 15, 2017, including interim periods, with early adoption permitted, but not before the original effective date of December 15, 2016. The Company is currently evaluating the standard to determine application date, transition method, and impact the standard will have on the financial statements.

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 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 adopted this guidance on January 1, 2015. The adoption of this guidance had no impact on the Company's financial statements.

In April 2015, the FASB issued new accounting guidance on accounting for debt issuance costs which changes the presentation of debt issuance costs in financial statements. This ASU requires an entity to present such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. Amortization of the costs will continue to be reported as interest expense. This ASU is effective for annual reporting periods beginning after December 15, 2015. Early adoption is permitted. The new guidance will be applied retrospectively to each prior period presented. Upon adoption, the Company will revise its current presentation of debt issuance costs in the Consolidated Balance Sheets; however, the Company does not expect a material impact on its future financial condition, results of operations, or cash flows as a result of the adoption.

In November 2015, the FASB issued new accounting guidance on the presentation of deferred income taxes that requires deferred tax assets and liabilities, along with related valuation allowances, to be classified as noncurrent on the balance sheet. As a result, each tax jurisdiction will now only have one net noncurrent deferred tax asset or liability. The new guidance does not change the existing requirement that prohibits offsetting deferred tax liabilities from one jurisdiction against deferred tax assets of another jurisdiction. This guidance was early adopted for the year ended December 31, 2015, and has been applied retrospectively to all periods presented. The effect of this change on the December 31, 2015 and 2014 Balance Sheets is a reclassification from current deferred tax liability to long-term deferred tax liability of $2.0 million and $5.4 million, respectively.

In February 2016, the FASB issued new accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. This ASU requires the recognition of lease assets and liabilities for those leases currently classified as operating leases while also refining the definition of a lease. In addition, lessees will be required to disclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements. This ASU is effective for the interim

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 2015 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.

In 2015, Indiana Gas had $42.8 million in net income compared to net income of $39.2 million in 2014. The improved results in the periods presented are primarily due to increased returns on the infrastructure replacement programs as the investment in those programs continues to increase. Increased earnings in 2015 also resulted from growth in small customer count and a decrease in performance-based compensation expense.

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 a 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.

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, 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.

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.

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.

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.

In addition, the Company separately reflects regulatory expense recovery mechanisms within Gas utility margin. These amounts represent dollar-for-dollar recovery of other operating expenses. The Company utilizes these approved regulatory mechanisms to recover variations in operating expenses from the amounts reflected in base rates and are generally expenses that are subject to volatility. Following is a discussion and analysis of margin.

Margin and throughput by customer type follows:



	Year Ended December 31,
(In thousands)	2015		2014

Revenues	$	551,968	$	680,409
Cost of gas sold	261,049		392,568
Total margin	$	290,919	$	287,841
Margin attributed to:
Residential & commercial customers	$	228,212	$	220,874
Industrial customers	34,427		33,082
Other	5,409		6,624
Regulatory expense recovery mechanisms	22,871		27,261
Total margin	$	290,919	$	287,841
Sold & transported volumes in MDth attributed to:
Residential & commercial customers	61,534		72,391
Industrial customers	66,470		62,796
Total sold & transported volumes	128,004		135,187

Margins were $290.9 million for the year ended December 31, 2015, and compared to 2014, increased $3.1 million. With rate designs that substantially limit the impact of weather on margin, heating degree days in 2015 that were 88 percent of normal compared to 107 percent in 2014, 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. The increase in margin was largely due to increased returns on infrastructure replacement programs as investment in those programs continues to increase.

Other income – net was $2.4 million in 2015, an increase of $0.2 million compared to 2014. The increase reflects increased allowance for funds used during construction (AFUDC) from increased capital expenditures related to infrastructure replacement investments. This increase was somewhat offset with decreases in returns on assets that fund certain benefit plans.



	For the Year Ended
	December 31,
	2015		2014

OPERATING REVENUES (In thousands):
Residential	$	374,289	$	462,812
Commercial	135,854		174,272
Industrial	36,516		36,698
Other	5,309		6,627
	$	551,968	$	680,409

MARGIN (In thousands):
Residential	$	176,990	$	171,011
Commercial	51,222		49,863
Industrial	34,427		33,082
Other	5,409		6,624
Regulatory expense recovery mechanisms	22,871		27,261
	$	290,919	$	287,841

GAS SOLD & TRANSPORTED (In MDth):
Residential	41,983		49,520
Commercial	19,551		22,871
Industrial	66,470		62,796
	128,004		135,187

AVERAGE CUSTOMERS:
Residential	527,904		523,134
Commercial	50,942		50,785
Industrial	932		908
	579,778		574,827



		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	25
	Selected Operating Statistics	28



	At December 31,
(In thousands)	2015		2014
Gas in storage - at LIFO cost	$	22,858	$	22,894
Materials & supplies	3,014		2,797
Other	1,294		1,752
Total inventories	$	27,166	$	27,443



(In thousands)	2015		2014
Asset retirement obligation, January 1	$	24,615	$	11,823
Accretion	1,283		742
Changes in estimates, net of cash payments	—		12,050
Asset retirement obligation, December 31	$	25,898	$	24,615



	Year Ended December 31,
(In thousands)	2015			2014
AFUDC - borrowed funds	$	3,382		$	2,414
AFUDC - equity funds	833			701
Other income (expense)	(264		)	418
Regulatory expenses	(1,519		)	(1,304		)
Total other income – net	$	2,432		$	2,229


1.	Organization and Nature of Operations


2.	Summary of Significant Accounting Policies


5.	Transactions with Other Vectren Companies & Affiliates


6.	Borrowing Arrangements & Other Financing Transactions