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

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EX-99.2 - EXHIBIT 99.2 - VECTREN CORP	exhibit992-2016igcreportin.htm
8-K - 8-K - VECTREN CORP	igc2016reportingpackage8k.htm

INDIANA GAS COMPANY, INC. AND SUBSIDIARY

REPORTING PACKAGE

For the year ended December 31, 2016

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 the Consolidated Financial Statements	8
	Results of Operations	23
	Selected Gas Operating Statistics	26

Additional Information

This annual reporting package provides additional information regarding the operations of Indiana Gas Company, Inc. (the Company, or Indiana Gas) and its subsidiary. This information is supplemental to Vectren Corporation’s (Vectren) annual report for the year ended December 31, 2016, filed on Form 10-K with the Securities and Exchange Commission on February 23, 2017 and Vectren Utility Holdings, Inc.’s (Utility Holdings or the Company's parent) 10-K filed on March 9, 2017. Vectren and the Company's parent 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	GCA: Gas Cost Adjustment
ASC: Accounting Standards Codification	IDEM: Indiana Department of Environmental Management
ASU: Accounting Standards Update	IURC: Indiana Utility Regulatory Commission
DOT: Department of Transportation	MDth / MMDth: thousands / millions of dekatherms
FASB: Financial Accounting Standards Board	OUCC: Indiana Office of the Utility Consumer Counselor
FERC: Federal Energy Regulatory Commission	PHMSA: Pipeline Hazardous Materials Safety Administration
GAAP: Generally Accepted Accounting Principles	Throughput: combined gas sales and gas transportation volumes

INDEPENDENT AUDITORS’ REPORT

To the Shareholder and Board of Directors of Indiana Gas Company, Inc.:

We have audited the accompanying consolidated financial statements of Indiana Gas Company, Inc. and its subsidiary (the “Company”), which comprise the consolidated balance sheets as of December 31, 2016 and 2015, and the related consolidated statements of income, cash flow, and common shareholder’s equity 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, 2016 and 2015, 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 27, 2017

FINANCIAL STATEMENTS

INDIANA GAS COMPANY, INC. AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

(In thousands)



	December, 31
	2016		2015
ASSETS
Utility Plant
Original cost	$	2,247,223	$	2,052,417
Less: accumulated depreciation & amortization	895,459		841,558
Net utility plant	1,351,764		1,210,859

Current Assets
Cash & cash equivalents	4,307		2,422
Accounts receivable - less reserves of $2,411 &
$1,292, respectively	35,790		33,213
Accrued unbilled revenues	49,629		37,899
Inventories	25,446		27,166
Recoverable natural gas costs	22,867		—
Prepayments & other current assets	26,837		30,031
Total current assets	164,876		130,731

Other investments	7,378		7,116
Regulatory assets	71,884		46,016
Other assets	30,595		26,604
TOTAL ASSETS	$	1,626,497	$	1,421,326

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,
		2016		2015
LIABILITIES & SHAREHOLDER'S EQUITY
Common Shareholder's Equity
Common stock (no par value)		$	284,536	$	259,536
Retained earnings		184,153		143,606
Total common shareholder's equity		468,689		403,142
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		266,689		226,893
Total long-term debt		362,689		322,893
Commitments & Contingencies (Notes 5, 7-9)
Current Liabilities
Accounts payable		80,468		62,497
Payables to other Vectren companies		17,033		13,235
Refundable natural gas costs		—		3,559
Accrued liabilities		51,478		47,117
Short-term borrowings payable to Utility Holdings		84,741		67,447
Total current liabilities		233,720		193,855
Deferred Credits & Other Liabilities
Deferred income taxes		253,235		211,336
Regulatory liabilities		264,127		250,096
Deferred credits & other liabilities		44,037		40,004
Total deferred credits & other liabilities		561,399		501,436
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY		$	1,626,497	$	1,421,326

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,
	2016		2015

OPERATING REVENUES	$	535,089	$	551,968
OPERATING EXPENSES
Cost of gas sold	228,788		261,049
Other operating	119,596		120,459
Depreciation & amortization	73,166		66,933
Taxes other than income taxes	15,789		16,292
Total operating expenses	437,339		464,733

OPERATING INCOME	97,750		87,235
Other income - net	3,549		2,432
Interest expense	19,546		18,514
INCOME BEFORE INCOME TAXES	81,753		71,153
Income taxes	32,210		28,394
NET INCOME	$	49,543	$	42,759

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,
	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	49,543		$	42,759
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization	73,166			66,933
Deferred income taxes & investment tax credits	42,407			14,120
Expense portion of pension & postretirement periodic benefit cost	1,017			1,228
Provision for uncollectible accounts	2,611			2,526
Other non-cash charges - net	1,504			1,354
Changes in working capital accounts:
Accounts receivable, including due from Vectren companies
& accrued unbilled revenues	(16,918		)	36,371
Inventories	1,720			277
Recoverable/refundable natural gas costs	(26,426		)	13,383
Prepayments & other current assets	3,193			26,562
Accounts payable, including to Vectren companies
& affiliated companies	17,534			(8,528		)
Accrued liabilities	4,362			(3,274		)
Contributions to pension & postretirement plans	(5,100		)	(6,600		)
Changes in noncurrent assets	(23,188		)	(10,471		)
Changes in noncurrent liabilities	(848		)	(4,365		)
Net cash provided by operating activities	124,577			172,275
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt, net of issuance costs	39,796			39,789
Capital contributed from Utility Holdings	25,000			—
Requirements for:
Dividends to Utility Holdings	(8,996		)	(30,564		)
Retirement of long-term debt	—			(44,716		)
Net change in short-term borrowings, including from Utility Holdings	17,294			17,269
Net cash flows from financing activities	73,094			(18,222		)
CASH FLOWS FROM INVESTING ACTIVITIES
Requirements for capital expenditures, excluding AFUDC equity	(195,786		)	(154,595		)
Net cash used in investing activities	(195,786		)	(154,595		)
Net change in cash & cash equivalents	1,885			(542		)
Cash & cash equivalents at beginning of period	2,422			2,964
Cash & cash equivalents at end of period	$	4,307		$	2,422

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, 2015	$	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
Net income			49,543			49,543
Common stock:
Additional capital contribution from Utility Holdings	25,000					25,000
Dividends to Utility Holdings			(8,996		)	(8,996		)
Balance at December 31, 2016	$	284,536	$	184,153		$	468,689

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, or Indiana Gas), an Indiana corporation, provides energy delivery services to approximately 587,000 natural gas customers located in central and southern Indiana. Indiana Gas is a direct, wholly owned subsidiary of Vectren Utility Holdings, Inc. (Utility Holdings or the Company's parent). The Company's parent 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 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.

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 consolidated 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 27, 2017.

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.

Property, Plant, & Equipment

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.

Utility Plant & Related Depreciation

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 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 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 (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 & Liabilities

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 to be credited to customers through the ratemaking process. The Company continually assesses the recoverability of costs recognized as regulatory assets and liabilities and the ability to recognize new regulatory assets and liabilities associated with its regulated utility operations. Given the current regulatory environment in its jurisdiction, the Company believes such accounting is appropriate.

The Company collects an estimated cost of removal of its utility plant through depreciation rates established in regulatory proceedings. The Company records amounts expensed in advance of payments as a Regulatory liability because the liability does not meet the threshold of an asset retirement obligation.

Asset Retirement Obligations

A portion of removal costs related to interim retirements of gas utility pipeline meet the definition of an asset retirement obligation (ARO). The Company records the fair value of a liability for a legal ARO in the period in which it is incurred. When the liability is initially recorded, the Company capitalizes a cost by increasing the carrying amount of the related long-lived asset. The liability is accreted, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the Company settles the obligation for its recorded amount or incurs a gain or loss. To the extent regulation is involved, regulatory assets and liabilities result when accretion and amortization is adjusted to match rates established by regulators and any gain or loss is subject to deferral.

Energy Contracts & Derivatives

The Company will periodically execute derivative contracts in the normal course of operations while buying and selling commodities to be used in operations and managing risk. 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 exempt 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 an 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 $7.1 million in 2016 and $7.8 million in 2015. 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 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 asset or liability’s fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Valuation techniques used maximize the use of observable inputs and minimize the use of unobservable inputs.

Earnings Per Share

Earnings per share are not presented as the Company's common stock is wholly owned by the Company's parent and not publicly traded.

Other Significant Policies

Included elsewhere in these notes are significant accounting policies related to retirement plans and other postretirement benefits, 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)	2016				2015
	Original Cost		Depreciation Rates as a Percent of Original Cost		Original Cost		Depreciation Rates as a Percent of Original Cost
Utility plant	$	2,223,270	3.6	%	$	2,035,105	3.6	%
Construction work in progress	23,953		—		17,312		—
Total original cost	$	2,247,223			$	2,052,417


4.	Regulatory Assets & Liabilities

Regulatory Assets

Regulatory assets consist of the following:



	At December 31,
(In thousands)	2016			2015
Future amounts recoverable from ratepayer related to:
Net deferred income taxes	$	(4,096	)	$	(3,560	)
	(4,096		)	(3,560		)
Amounts deferred for future recovery related to:
Cost recovery riders & other	27,431			19,817
	27,431			19,817
Amounts currently recovered in customer rates related to:
Authorized trackers	46,356			27,357
Unamortized debt issue costs & premiums paid to reacquire debt	2,193			2,402
	48,549			29,759
Total regulatory assets	$	71,884		$	46,016

Of the $48.5 million currently being recovered in rates charged to customers, the majority of the balance is not earning a return. The weighted average recovery period of regulatory assets currently being recovered in base rates, which totals $2.2 million, is 18 years. The remainder of the regulatory assets are being recovered timely through periodic recovery mechanisms. The Company has rate orders for all deferred costs not yet in rates and therefore believes future recovery is probable.

Regulatory Liabilities

At December 31, 2016 and 2015, the Company has approximately $264.1 million and $250.1 million, respectively, in Regulatory Liabilities. Amounts in both periods primarily relate to cost of removal 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 the Company and fees incurred by the Company totaled $69.7 million in 2016 and $62.3 million in 2015. Amounts owed to VISCO at December 31, 2016 and 2015 are included in Payables to other Vectren companies.

Support Services and Purchases

Vectren and the Company's parent 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. The Company received corporate allocations totaling $61.4 million and $56.9 million for the years ended December 31, 2016, and 2015, respectively. Amounts owed to Vectren and the Company's parent at December 31, 2016 and 2015 are included in Payables to other Vectren companies.

Retirement Plans & Other Postretirement Benefits

At December 31, 2016, 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 (SERP), 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. Current and former employees of the Company's parent and its subsidiaries, which include 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. Although the Company has no contractual funding obligation, the Company contributed $5.1 million and $6.6 million to Vectren's defined benefit pension plans during 2016 and 2015, respectively. The combined funded status of Vectren’s plans was approximately 92 percent at December 31, 2016 and 90 percent at December 31, 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, 2016 and 2015, costs totaling $1.6 million and $1.8 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 corporate operations of Vectren and the Company's parent are charged to subsidiaries through the allocation process discussed above based on labor. Any difference between funding requirements and allocated periodic costs is recognized as an asset or liability until reflected in periodic costs.

Neither plan assets nor the ending liability is allocated to individual subsidiaries since these assets and obligations are derived from corporate level decisions. The allocation methodology is consistent with FASB guidance related to “multiemployer” benefit accounting. As impacted by increased funding of pension plans, at December 31, 2016 and 2015, the Company has $30.6 million and $26.6 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.

Share-Based Incentive Plans & Deferred Compensation Plans

The Company does not have share-based or deferred compensation plans separate from Vectren. The Company recognizes its allocated portion of expenses related to share-based incentive plans and deferred compensation plans in accordance with FASB guidance and to the extent these awards are expected to be settled in cash that liability is pushed down to the Company. As of December 31, 2016 and 2015, $15.3 and $13.2 million, respectively, is included in Accrued Liabilities and Deferred credits & other liabilities and represents obligations that are yet to be funded to Vectren.

Cash Management Arrangements

The Company participates in the centralized cash management program of the Company's parent. See Note 6 regarding long-term and short-term intercompany borrowing arrangements.

Guarantees of Parent Company Debt

The parent company's three operating utility companies, Southern Indiana Gas and Electric Company (SIGECO), Indiana Gas, and Vectren Energy Delivery of Ohio, Inc. (VEDO) are guarantors of its $350 million short-term credit facility, of which approximately $194 million is outstanding at December 31, 2016, and its $1 billion in unsecured senior notes outstanding at December 31, 2016. The majority of the unsecured senior notes outstanding of the Company's parent are allocated to the operating utility companies. The guarantees are full and unconditional and joint and several, and the Company's parent has no subsidiaries other than the subsidiary guarantors.

Income Taxes

The Company does not file federal or state income tax returns separate from those filed by Vectren. 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 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. The Company 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)	2016			2015
Current:
Federal	$	(12,563	)	$	8,967
State	2,366			5,333
Total current tax expense	(10,197		)	14,300
Deferred:
Federal	40,453			14,435
State	1,978			(311		)
Total deferred tax expense	42,431			14,124
Amortization of investment tax credits	(24		)	(30		)
Total income tax expense	$	32,210		$	28,394

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



	Year Ended December 31,
	2016		2015
Statutory rate	35.0	%	35.0	%
State & local taxes, net of federal benefit	4.5		4.9
All other - net	(0.1	)	—
Effective tax rate	39.4	%	39.9	%

Significant components of the net deferred tax liability follow:



	At December 31,
(In thousands)	2016			2015
Noncurrent deferred tax liabilities (assets):
Depreciation & cost recovery timing differences	$	225,979		$	199,107
Regulatory assets recoverable through future rates	6,226			11,507
Regulatory liabilities to be settled through future rates	(4,566		)	(9,652		)
Employee benefit obligations	4,054			3,017
Deferred fuel costs	11,622			(82		)
Other – net	9,920			7,439
Net deferred tax liability	$	253,235		$	211,336

At both December 31, 2016 and 2015, investment tax credits totaled $0.1 million, and are included in Deferred credits and other liabilities.

Uncertain Tax Positions

Unrecognized tax benefits for all periods presented were not material to the Company. There were no unrecognized tax benefits inclusive of interest and penalties at December 31, 2016 and 2015, 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 2012 except to the extent of refunds claimed on amended tax returns. The statutes of limitations for assessment of the 2009, 2011 and 2012 tax years related to the amended Indiana income tax returns will expire in 2018 for tax years 2009 and 2011, and 2019 for the tax year 2012.

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

The Company relies entirely on the short-term borrowing arrangements of the parent company for its short-term working capital needs. Borrowings outstanding at December 31, 2016 and 2015 were $84.7 million and $67.4 million, respectively. The intercompany credit line totals $350 million, but is limited to the available capacity of the Company's parent ($156 million at December 31, 2016) and is subject to the same terms and conditions as its short-term borrowing arrangements, including its commercial paper program. Short-term borrowings bear interest at the parent company's weighted average daily cost of short-term funds.

See the table below for interest rates and outstanding balances:



	Intercompany Borrowings
(In thousands)	2016			2015
Year End
Balance Outstanding	$	84,741		$	67,447
Weighted Average Interest Rate	1.05		%	0.55		%
Annual Average
Balance Outstanding	$	30,158		$	21,347
Weighted Average Interest Rate	0.69		%	0.41		%
Maximum Month End Balance Outstanding	$	84,741		$	68,338

Long-Term Debt

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



	At December 31,
(In thousands)	2016		2015
Fixed Rate Senior Unsecured Notes Payable to Utility Holdings:
2018, 5.75%	$	37,128	$	37,128
2023, 3.72%	74,540		74,538
2028, 3.20%	8,953		8,953
2035, 6.10%	50,569		50,569
2035, 3.90%	8,290		8,289
2043, 4.25%	15,915		15,916
2045, 4.36%	55,543		15,750
2055, 4.51%	15,751		15,750
Total long-term debt payable to Utility Holdings	$	266,689	$	226,893

Fixed Rate Senior Unsecured Notes Payable to Third Parties:
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	$	96,000

Indiana Gas Unsecured Note Retirement

On March 15, 2015, a $5 million senior unsecured note matured. The Series E note carried a fixed interest rate of 7.15 percent. The repayment of debt was funded by the commercial paper program of the Company's parent.

Issuance payable to the Company's Parent

On December 15, 2015, the Company's parent 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 the Company, SIGECO and VEDO. In December 2015, $39.8 million of this debt was reloaned to the Company; in January 2016, another $39.8 million was reloaned to the Company.

Long-Term Debt Sinking Fund Requirements & Maturities

The Company has no sinking fund requirements on long-term debt during the five years following 2016. Maturities of long-term debt during the five years following 2016 are $37.1 million in 2018 and $325.6 thereafter. There are no maturities of long-term debt in 2017, 2019, 2020 or 2021.

Covenants

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, 2016, the Company was in compliance with all financial debt covenants.


7.	Commitments & Contingencies

Purchase Commitments

The Company has firm commitments to purchase natural gas for up to a ten year term, with the majority of these commitments being two years or less. The Company has pipeline transportation and storage contracts for various terms up to a twenty year period. 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. Firm purchase commitments for utility plant total $0.7 in 2017 and zero thereafter.

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 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 the 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.

Indiana Senate Bill 251 (Senate Bill 251) 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 IURC, 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.

Indiana Senate Bill 560 (Senate Bill 560) 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, 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.

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 currently recognized in the Consolidated Statements of Income. 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, 2016 and December 31, 2015, the Company has regulatory assets totaling $19.6 million and $17.7 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 discussed below.

Requests for Recovery under Regulatory Mechanisms

In August 2014, the IURC issued an Order approving the Company’s seven-year capital infrastructure replacement and improvement plan (the 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 assigned to the residential customer class via a fixed monthly charge per residential customer.

In March 2016, the IURC issued an Order re-approving approximately $660 million of the Company’s gas infrastructure modernization projects requested in the third update of the Plan, and approving the inclusion in rates of actual investments made through June 30, 2015. While most of the proposed capital spend has been approved as proposed, approximately $75 million of projects were not approved for recovery through the mechanisms pursuant to these filings. Specifically, the Company proposed to add a new project to its Plan pursuant to Senate Bill 560 totaling approximately $65 million. The project, which consists of a 20-mile transmission line and other related investments required to support industrial customer growth and ongoing system reliability in the Lafayette, Indiana area, as well as allows the Company to further diversify its gas supply portfolio via access to shale gas in the Marcellus and Utica reserves, was excluded for recovery under the Plan. The IURC stated because the project was not in the original plan filed in 2013, it does not qualify for cost recovery under this law. In the Order, the IURC did pre-approve the project for rate base inclusion upon the filing of the next base rate case. The Company believes such plan updates should be expected to accommodate new projects that emerge during the term of the plan as ongoing risk assessments determine new projects are required. The Company filed an appeal of the March 2016 Order on April 29, 2016 to challenge the IURC's finding which limits the scope of the Plan updates. The outcome of the appeal is expected in the first half of 2017.

Subsequent to the March 2016 Order, the Company has received two additional Orders approving plan investments. On June 29, 2016, the IURC issued an Order approving the inclusion in rates of investments made from July 2015 to December 2015. On January 25, 2017 the IURC issued an Order (January 2017 Order) approving the inclusion in rates of investments made from January 2016 to June 2016. Through the January 2017 Order, approximately $263 million of the approved capital investment plan has been incurred and included for recovery. The January 2017 Order also approved the Company's plan update, which is now $700 million through 2020. The plan increase of $40 million is due to additional investment related to pipeline safety and compliance requirements under Senate Bill 251.

At December 31, 2016 and December 31, 2015, the Company has regulatory assets related to the Plan totaling $38.8 million and $21.4 million, respectively.

Pipeline and Hazardous Materials Safety Administration (PHMSA)

In March of 2016, PHMSA published a notice of proposed rulemaking (NPRM) on the safety of gas transmission and gathering lines. The proposed rule addresses many of the remaining requirements of the 2011 Pipeline Safety Act, with a particular focus on extending integrity management rules to address a much larger portion of the natural gas infrastructure and adds requirements to address broader threats to the integrity of a pipeline system. The Company is evaluating the impact these proposed rules will have on its integrity management programs and transmission and distribution systems. In December of 2016, PHMSA issued final rules related to integrity management for storage operations. These rules are being

evaluated with efforts underway to implement the new requirements. Further, the Company reviewed the Underground Natural Gas Storage Safety Recommendations from a joint Department of Energy and PHMSA led interagency task force. PHMSA has final rules pending that address requirements related to plastic pipe, operator qualifications, valve installation and rupture detection, and incident notification. Each of these rules is expected to be published by PHMSA in 2017. Additionally, PHMSA has recently finalized a rule on excess flow valves, which will go into effect in April 2017. These rules will increase the potential for capital expenditures and increase operating and maintenance expenses. The Company believes the cost to comply with these new rules should be recoverable using the regulatory recovery mechanisms referenced above.

9. Environmental Matters

Carbon Regulation

The Company currently reports greenhouse gas emissions attributed to its distribution and transmission systems pursuant to the EPA’s greenhouse gas emission reporting requirements. In 2016, the Company became a founding member of the EPA’s voluntary Methane Challenge Program, which establishes best practices for reducing emissions of methane across the natural gas distribution and transmission systems.

Manufactured Gas Plants

0In 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 the Company 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 $23.9 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, the Company 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, 2016 and December 31, 2015, approximately $1.5 million and $0.8 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,
	2016				2015
(In thousands)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt payable to third parties	$	96,000	$	121,423	$	96,000	$	117,234
Long-term debt payable to Utility Holdings	266,689		285,825		226,893		240,989
Short-term borrowings payable to Utility Holdings	84,741		84,741		67,447		67,447
Cash & cash equivalents	4,307		4,307		2,422		2,422

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 the life of the refunding issue. 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)	2016		2015
Gas in storage - at LIFO cost	$	20,912	$	22,858
Materials & supplies	3,234		3,014
Other	1,300		1,294
Total inventories	$	25,446	$	27,166

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 both December 31, 2016 and 2015, by approximately $4 million. 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.

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



	At December 31,
(In thousands)	2016		2015
Prepaid gas delivery service	$	26,449	$	30,029
Prepaid taxes & other	388		2
Total prepayments & other current assets	$	26,837	$	30,031

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



	At December 31,
(In thousands)	2016		2015
Customer advances & deposits	$	27,624	$	28,826
Accrued gas imbalance	2,615		1,236
Accrued taxes	8,907		8,417
Accrued interest	2,604		2,611
Tax collections payable	3,931		3,285
Accrued salaries & other	5,797		2,742
Total accrued liabilities	$	51,478	$	47,117

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



(In thousands)	2016		2015
Asset retirement obligation, January 1	$	25,898	$	24,615
Accretion	1,352		1,283
Changes in estimates, net of cash payments	3,177		—
Asset retirement obligation, December 31	$	30,427	$	25,898

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



	Year Ended December 31,
(In thousands)	2016			2015
AFUDC - borrowed funds	$	2,680		$	3,382
AFUDC - equity funds	731			833
Other income (expense)	1,007			(264		)
Regulatory expenses	(869		)	(1,519		)
Total other income – net	$	3,549		$	2,432

Supplemental Cash Flow Information:



	Year Ended December 31,
(In thousands)	2016			2015
Cash paid (received) for:
Interest	$	19,553		$	18,906
Income taxes	(9,781		)	(1,139		)

As of December 31, 2016 and 2015, the Company had accruals related to utility plant purchases totaling approximately $6.6 million and $1.7 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. 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. The guidance can be applied retrospectively to each prior reporting period presented (full retrospective method) or retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of initial adoption (modified retrospective method). While the Company continues to assess the standard and initial conclusions could change based on completion of that assessment, the Company preliminarily plans to adopt the guidance under the modified retrospective method.

On July 9, 2015, the FASB approved a one year deferral that became effective through an ASU 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 assessing the impacts this guidance may have on the Consolidated Balance Sheets, Consolidated Statements of Operations, and disclosures including the ability to recognize revenue for certain contracts, and its accounting for contributions in aid of construction (CIAC). While management will continue to analyze the impact of this new standard and the related ASUs that clarify guidance in the standard, at this time, management does not believe adoption of the standard will have a significant impact on the Company's pattern of revenue recognition. The Company plans to adopt the guidance effective January 1, 2018.

Leases

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 and annual reporting periods beginning January 1, 2019, although it can be early adopted, with a modified retrospective approach for leases that commenced prior to the date of adoption. The Company is currently evaluating the standard to determine the impact it will have on the financial statements.

Stock Compensation

In March 2016, the FASB issued new accounting guidance which is intended to simplify several aspects of accounting for share-based payment transactions, including the income tax consequences. This ASU is effective for annual periods beginning after December 15, 2016, and relevant interim periods. Early application is permitted. The Company does not have share-based compensation plans separate from Vectren; the Company is however allocated costs associated with these plans. Pursuant to these plans, share based awards are settled via cash payments and are therefore not impacted by this standard. The Company does not anticipate adoption of the standard to have a significant impact on the financial statements.

Other Recently Issued Standards

Management believes other recently issued standards, which are not yet effective, will not have a material impact on the Company's financial position, results of operations, or cash flows upon adoption.

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

The following discussion and analysis provides additional information regarding the Company's 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 2016 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

The Company generates revenue primarily from the delivery of natural gas to its customers, and the Company's 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.

Vectren 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 the Company's consolidated financial statements.

Operating Results

In 2016, the Company had $49.5 million in net income compared to net income of $42.8 million in 2015. The increased earnings in 2016 are primarily due to increased returns on the gas infrastructure replacement program as the investment in that program continues to increase. Earnings in 2016 also reflect increased large customer usage.

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 a gas infrastructure replacement program, which allows 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, 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.

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 GCA. 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. In the periods presented, the Company has not been impacted by the 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 return 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 regulatory 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.

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 (Gas utility revenues less Cost of gas sold)

Margin and throughput by customer type follows:



	Year Ended December 31,
(In thousands)	2016		2015

Revenues	$	535,089	$	551,968
Cost of gas sold	228,788		261,049
Total margin	$	306,301	$	290,919
Margin attributed to:
Residential & commercial customers	$	243,630	$	228,212
Industrial customers	38,309		34,427
Other	4,147		5,409
Regulatory expense recovery mechanisms	20,215		22,871
Total margin	$	306,301	$	290,919
Sold & transported volumes in MDth attributed to:
Residential & commercial customers	57,562		61,534
Industrial customers	66,350		66,470
Total sold & transported volumes	123,912		128,004

Margins were $306.3 million for the year ended December 31, 2016, and compared to 2015, increased $15.4 million. The increase in margin was largely due to increased returns on the gas infrastructure replacement program for all customer classes as investments in that program continue to increase. With rate designs that substantially limit the impact of weather on residential and commercial customer margin, heating degree days in 2016 that were 84 percent of normal compared to 88 percent in 2015 had relatively no impact on customer margin.

Operating Expenses

Other Operating

For the year ended December 31, 2016, Other operating expenses were $119.6 million, which is a decrease of $0.9 million, compared to 2015. Excluding operating expenses recovered through margin, expenses increased $0.3 million.

Depreciation & Amortization

For the year ended December 31, 2016, depreciation and amortization expense increased $6.2 million compared to 2015. The increase in 2016 resulted from additional utility plant investments placed into service.

SELECTED GAS OPERATING STATISTICS:



	For the Year Ended
	December 31,
	2016		2015

OPERATING REVENUES (In thousands):
Residential	$	360,637	$	374,289
Commercial	130,021		135,854
Industrial	40,219		36,516
Other	4,212		5,309
	$	535,089	$	551,968

MARGIN (In thousands):
Residential	$	189,234	$	176,990
Commercial	54,396		51,222
Industrial	38,309		34,427
Other	4,147		5,409
Regulatory expense recovery mechanisms	20,215		22,871
	$	306,301	$	290,919

GAS SOLD & TRANSPORTED (In MDth):
Residential	39,089		41,983
Commercial	18,473		19,551
Industrial	66,350		66,470
	123,912		128,004

AVERAGE CUSTOMERS:
Residential	534,315		527,904
Commercial	51,277		50,942
Industrial	950		932
	586,542		579,778

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