VECTREN CORP - FORM 8-K - EX-99.1 - EXHIBIT 99.1 - IGC 2017 REPORTING PACKAGE

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EX-99.2 - EXHIBIT 99.2 - IGC 2017 REPORTING PACKAGE - VECTREN CORP	exhibit992-2017igcreportin.htm
8-K - 8-K - IGC 2017 REPORTING PACKAGE (SHELL) - VECTREN CORP	igc2017reportingpackage8k.htm

INDIANA GAS COMPANY, INC. AND SUBSIDIARY

REPORTING PACKAGE

For the year ended December 31, 2017

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	24
	Selected Gas Operating Statistics	27

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, 2017, filed on Form 10-K with the Securities and Exchange Commission on February 21, 2018 and Vectren Utility Holdings, Inc.’s (Utility Holdings or the Company's parent) 10-K filed on March 8, 2018. 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	IDEM: Indiana Department of Environmental Management
ASC: Accounting Standards Codification	IURC: Indiana Utility Regulatory Commission
ASU: Accounting Standards Update	MDth / MMDth: thousands / millions of dekatherms
DOT: Department of Transportation	OUCC: Indiana Office of the Utility Consumer Counselor
FASB: Financial Accounting Standards Board	PHMSA: Pipeline Hazardous Materials Safety Administration
FERC: Federal Energy Regulatory Commission	TCJA: Tax Cuts and Jobs Act
GAAP: Generally Accepted Accounting Principles	Throughput: combined gas sales and gas transportation volumes
GCA: Gas Cost Adjustment

INDEPENDENT AUDITORS’ REPORT

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

We have audited the accompanying consolidated financial statements of Indiana Gas Company, Inc. and subsidiary (the "Company"), which comprise the consolidated balance sheets as of December 31, 2017 and 2016, 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, 2017 and 2016, 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 29, 2017

FINANCIAL STATEMENTS

INDIANA GAS COMPANY, INC. AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

(In thousands)



	December, 31
	2017		2016
ASSETS
Utility Plant
Original cost	$	2,452,209	$	2,247,223
Less: accumulated depreciation & amortization	955,437		895,459
Net utility plant	1,496,772		1,351,764

Current Assets
Cash & cash equivalents	4,048		4,307
Accounts receivable - less reserves of $1,922 &
$2,411, respectively	42,150		35,790
Receivables from other Vectren companies	5		—
Accrued unbilled revenues	57,889		49,629
Inventories	22,919		25,446
Recoverable natural gas costs	9,384		22,867
Prepayments & other current assets	27,242		26,837
Total current assets	163,637		164,876

Other investments	9,748		7,378
Regulatory assets	102,560		71,884
Other assets	23,103		30,595
TOTAL ASSETS	$	1,795,820	$	1,626,497

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,
		2017		2016
LIABILITIES & SHAREHOLDER'S EQUITY
Common Shareholder's Equity
Common stock (no par value)		$	324,536	$	284,536
Retained earnings		239,830		184,153
Total common shareholder's equity		564,366		468,689
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		324,030		266,689
Total long-term debt		420,030		362,689
Commitments & Contingencies (Notes 5, 7-9)
Current Liabilities
Accounts payable		65,204		80,468
Payables to other Vectren companies		17,286		17,033
Accrued liabilities		65,262		51,478
Short-term borrowings payable to Utility Holdings		391		84,741
Current maturities long-term debt payable to Utility Holdings		37,128		—
Total current liabilities		185,271		233,720
Deferred Credits & Other Liabilities
Deferred income taxes		132,665		253,235
Regulatory liabilities		422,691		264,127
Deferred credits & other liabilities		70,797		44,037
Total deferred credits & other liabilities		626,153		561,399
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY		$	1,795,820	$	1,626,497

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,
	2017		2016

OPERATING REVENUES	$	564,995	$	535,089
OPERATING EXPENSES
Cost of gas sold	231,408		228,788
Other operating	126,139		119,596
Depreciation & amortization	81,022		73,166
Taxes other than income taxes	17,708		15,789
Total operating expenses	456,277		437,339

OPERATING INCOME	108,718		97,750
Other income - net	2,658		3,549
Interest expense	20,403		19,546
INCOME BEFORE INCOME TAXES	90,973		81,753
Income taxes	35,296		32,210
NET INCOME	$	55,677	$	49,543

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,
	2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	55,677		$	49,543
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization	81,022			73,166
Deferred income taxes & investment tax credits	15,786			42,407
Expense portion of pension & postretirement periodic benefit cost	1,945			1,017
Provision for uncollectible accounts	2,140			2,611
Other non-cash charges - net	1,908			1,504
Changes in working capital accounts:
Accounts receivable, including due from Vectren companies
& accrued unbilled revenues	(15,442		)	(16,918		)
Inventories	2,527			1,720
Recoverable/refundable natural gas costs	13,483			(26,426		)
Prepayments & other current assets	(405		)	3,193
Accounts payable, including to Vectren companies
& affiliated companies	(16,531		)	17,534
Accrued liabilities	13,783			4,362
Contributions to pension & postretirement plans	—			(5,100		)
Changes in noncurrent assets	(14,357		)	(23,188		)
Changes in noncurrent liabilities	17,185			(848		)
Net cash from operating activities	158,721			124,577
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt, net of issuance costs	94,469			39,796
Capital contributed from Utility Holdings	40,000			25,000
Requirements for:
Dividends to Utility Holdings	—			(8,996		)
Net change in short-term borrowings, including from Utility Holdings	(84,350		)	17,294
Net cash flows from financing activities	50,119			73,094
CASH FLOWS FROM INVESTING ACTIVITIES
Requirements for capital expenditures, excluding AFUDC equity	(209,099		)	(195,786		)
Net cash from investing activities	(209,099		)	(195,786		)
Net change in cash & cash equivalents	(259		)	1,885
Cash & cash equivalents at beginning of period	4,307			2,422
Cash & cash equivalents at end of period	$	4,048		$	4,307

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, 2016	$	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
Net income			55,677			55,677
Common stock:
Additional capital contribution from Utility Holdings	40,000					40,000
Dividends to Utility Holdings			—			—
Balance at December 31, 2017	$	324,536	$	239,830		$	564,366

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 592,400 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 29, 2018.

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. 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. The offset to contracts affected by regulatory accounting treatment, which includes most of the Company's executed and financial contracts, are marked to market as a regulatory asset or liability. Market value for derivative contracts is determined using quoted market prices from independent sources or from internal models. 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 $7.9 million in 2017 and $7.1 million in 2016. 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.

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)	2017				2016
	Original Cost		Depreciation Rates as a Percent of Original Cost		Original Cost		Depreciation Rates as a Percent of Original Cost
Utility plant	$	2,413,253	3.6	%	$	2,200,329	3.6	%
Construction work in progress	17,390		—		23,953		—
Asset Retirement Obligations	21,566		—		22,941		—
Total original cost	$	2,452,209			$	2,247,223


4.	Regulatory Assets & Liabilities

Regulatory Assets

Regulatory assets consist of the following:



	At December 31,
(In thousands)	2017		2016
Future amounts recoverable from ratepayer related to:
Net deferred income taxes & other	$	7,363	$	(4,096	)
	7,363		(4,096		)
Amounts deferred for future recovery related to:
Cost recovery riders & other	37,587		27,431
	37,587		27,431
Amounts currently recovered in customer rates related to:
Authorized trackers	55,624		46,356
Unamortized debt issue costs, reacquisition premiums & hedging proceeds	1,986		2,193
	57,610		48,549
Total regulatory assets	$	102,560	$	71,884

Of the $57.6 million currently being recovered in rates charged to customers, no amounts are earning a return. The weighted average recovery period of regulatory assets currently being recovered in base rates, which totals $2.0 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, 2017 and 2016, the Company had Regulatory Liabilities of approximately $422.7 million and $264.1 million, respectively, of which cost of removal obligations represented $277.2 million and $264.1 million, respectively, and at December 31, 2017, $145.5 million related to excess deferred income taxes. The deferred income tax regulatory liability is the result of the revaluation of deferred taxes at December 31, 2017 at the reduced federal corporate tax rate. These regulatory liabilities are expected to be refunded to customers over time following state regulator approval.


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 $97.4 million in 2017 and $69.7 million in 2016. The increase in 2017 is due to a large pipeline project that VISCO was awarded in a competitive process. Amounts owed to VISCO at December 31, 2017 and 2016 are included in Payables to other Vectren companies.

Support Services and Purchases

Vectren and the Company's parent provide corporate and general and administrative services to the Company and allocates certain costs to the Company. 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 $66.7 million and $61.4 million for the years ended December 31, 2017, and 2016, respectively. Amounts owed to Vectren and the Company's parent at December 31, 2017 and 2016 are included in Payables to other Vectren companies.

Retirement Plans & Other Postretirement Benefits

At December 31, 2017, Vectren maintains three qualified defined benefit pension plans (Vectren Corporation Non-Bargaining Retirement Plan, The Indiana Gas Company, Inc. Bargaining Unit Retirement Plan, Pension Plan for Hourly Employees of Southern Indiana Gas and Electric Company), a nonqualified supplemental executive retirement plan (SERP), and a postretirement benefit plan. The pension and SERP plans are closed to new participants. 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 Vectren and its subsidiaries, which include the Company, comprise the participants and retirees covered by these plans.

Vectren satisfies the future funding requirements for funded plans and the payment of benefits for unfunded plans from general corporate assets and, as necessary, relies on the Company to support the funding of these obligations. However, the Company has no contractual funding obligation. In 2016, the Company contributed $5.1 million to Vectren's defined benefit pension plans. No contributions were made in 2017. The combined funded status of Vectren's plans was approximately 92 percent at December 31, 2017 and December 31, 2016.

Vectren allocates retirement plan and other postretirement benefit plan periodic cost calculated pursuant to US GAAP to its subsidiaries, which is also how the Company recovers retirement plan periodic costs through base rates. Periodic cost is charged to the Company following a labor cost allocation methodology and results in retirement costs being allocated to both operating expense and capital projects. For the years ended December 31, 2017 and 2016, costs totaling $3.0 million and $1.6 million, respectively, were charged to the Company.

Any difference between funding requirements and allocated periodic costs is recognized as an asset or liability. Neither plan assets nor plan obligations as calculated pursuant to US GAAP are 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 of December 31, 2017 and 2016, the Company had $23.1 million and $30.6 million, respectively, included in Other assets representing defined benefit pension funding by the Company that is yet to be reflected in costs. As of December 31, 2017 and 2016, the Company had $17.6 million and zero, respectively, included in Deferred credits & other liabilities representing costs related to other postretirement benefits charged to the Company that is yet to be funded to Vectren. The Company's labor allocation methodology is used to compute the funding of the defined benefit retirement and other postretirement plans, which is consistent with the regulatory ratemaking processes of the Company.

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, 2017 and 2016, $20.4 million and $15.3 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 $400 million short-term credit facility, of which approximately $180 million is outstanding at December 31, 2017, and its $1.2 billion in unsecured senior notes outstanding at December 31, 2017. 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.

On December 22, 2017, the United States government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (“TCJA”). The TCJA makes broad and complex changes to the Internal Revenue Code (“IRC”), many of which are effective on January 1, 2018, including, but not limited to, (1) reducing the federal corporate income tax rate from 35 percent to 21 percent, (2) eliminating the use of bonus depreciation for regulated utilities, while permitting full expensing of qualified property for non-regulated entities, (3) eliminating the domestic production activities deduction previously allowable under Section 199 of the IRC, (4) creating a new limitation on the deductibility of interest expense for non-regulated businesses, (5) eliminating the corporate Alternative Minimum Tax (“AMT”) and changing how existing AMT credits can be realized, (6) limiting the deductibility of certain executive compensation, (7) restricting the deductibility of entertainment and lobbying-related

expenses, (8) requiring regulated entities to employ the average rate assumption method (“ARAM”) to refund excess deferred taxes created by the rate change to their customers, and (9) changing the rules under Section 118 of the IRC regarding taxability of contributions made by government or civic groups.

In addition, the reduction in the federal corporate rate results in $105.6 million in excess federal deferred income taxes.

The Company currently recovers corporate income tax expense in Commission approved rates charged to customers. The IURC issued an order which initiated a proceeding to investigate the impact of the TCJA on utility companies and customers within the state. In addition, the IURC ordered the Company to establish regulatory assets and liabilities to record all estimated impacts of tax reform starting January 1, 2018. The Company is complying with the order. The IURC held an initial conference of parties on February 6, 2018, and an order was issued by the Commission on February 16, 2018, outlining the process the utility companies are to follow. In accordance with the order, the Company filed on March 26, 2018 for proposed changes to its rates and charges to consider the impact of the lower corporate federal income tax rate. The proceeding, if unchallenged, will result in new rates by the beginning of May 2018.

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



	Year Ended December 31,
(In thousands)	2017			2016
Current:
Federal	$	14,775		$	(12,563	)
State	4,735			2,366
Total current tax expense	19,510			(10,197		)
Deferred:
Federal	15,313			40,453
State	490			1,978
Total deferred tax expense	15,803			42,431
Amortization of investment tax credits	(17		)	(24		)
Total income tax expense	$	35,296		$	32,210

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



	Year Ended December 31,
	2017		2016
Statutory rate	35.0	%	35.0	%
State & local taxes, net of federal benefit	4.3		4.5
All other - net	(0.5	)	(0.1	)
Effective tax rate	38.8	%	39.4	%

Significant components of the net deferred tax liability follow:



	At December 31,
(In thousands)	2017			2016
Noncurrent deferred tax liabilities (assets):
Depreciation & cost recovery timing differences	$	149,950		$	225,979
Regulatory assets recoverable through future rates	3,225			6,226
Regulatory liabilities to be settled through future rates	(36,731		)	(4,566		)
Employee benefit obligations	262			4,054
Deferred fuel costs	6,640			11,622
Other – net	9,319			9,920
Net deferred tax liability	$	132,665		$	253,235

At both December 31, 2017 and 2016, 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 was at December 31, 2017 and 2016, 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 2014 except to the extent of refunds claimed on amended tax returns. The statutes of limitations for assessment of the 2013 tax year related to the amended Indiana income tax returns will expire in 2020. The statutes of limitations for assessment of the 2009 and 2011 through 2014 tax years related to the amended Indiana income tax returns will expire in 2018 through 2020. On February 28, 2018, the Company was notified by the Indiana Department of Revenue that the Company was selected for a routine compliance audit for the tax periods January 1, 2015 through December 31, 2017.

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 has been lowered by 0.25 percent each year for the first five years and 0.35 percent in year six that began 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 on the short-term borrowing arrangements of the parent company for its short-term working capital needs. Borrowings outstanding at December 31, 2017 and 2016 were $0.4 million and $84.7 million, respectively. The intercompany credit line totals $400 million, but is limited to the available capacity of the Company's parent ($220 million at December 31, 2017) 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)	2017			2016
Year End
Balance Outstanding	$	391		$	84,741
Weighted Average Interest Rate	1.91		%	1.05		%
Annual Average
Balance Outstanding	$	37,686		$	30,158
Weighted Average Interest Rate	1.21		%	0.69		%
Maximum Month End Balance Outstanding	$	81,414		$	84,741

Long-Term Debt

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



	At December 31,
(In thousands)	2017			2016
Fixed Rate Senior Unsecured Notes Payable to Utility Holdings:
2018, 5.75%	$	37,128		$	37,128
2023, 3.72%	74,540			74,540
2028, 3.20%	8,953			8,953
2032, 3.26%	24,862			—
2035, 6.10%	50,569			50,569
2035, 3.90%	8,290			8,290
2043, 4.25%	15,915			15,915
2045, 4.36%	55,543			55,543
2047, 3.93%	69,607			—
2055, 4.51%	15,751			15,751
Total long-term debt payable to Utility Holdings	$	361,158		$	266,689
Current maturities	(37,128		)	—
Total long-term debt payable to Utility Holdings	$	324,030		$	266,689

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

Issuance payable to the Company's Parent

On July 14, 2017, the Company's parent entered into a private placement Note Purchase Agreement pursuant to which institutional investors agreed to purchase the following tranches of notes: (i) $100 million of 3.26 percent Guaranteed Senior Notes, Series A, due August 28, 2032 and (ii) $100 million of 3.93 percent Guaranteed Senior Notes, Series B, due November 29, 2047. The notes are jointly and severally guaranteed by the Company, SIGECO, and VEDO. The Series A note proceeds were received on August 28, 2017 and the Series B proceeds were received on November 29, 2017. In September 2017, $24.9 million of this debt was reloaned to the Company; in December 2017, another $69.6 million of this debt 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 2017. Maturities of long-term debt during the five years following 2017 are $37.1 million in 2018, no maturities in 2019 through 2022, and $420.0 thereafter.

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, 2017, 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 six 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.

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, through a base rate case or other proceeding, 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 for future recovery 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, 2017 and December 31, 2016, the Company has regulatory assets totaling $20.4 million and $19.6 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 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 future 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 is now complete, 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 Senate Bill 560. In the Order, the IURC did pre-approve the project for rate base inclusion upon the filing of the next base rate case. On April 27, 2017, the Indiana Court of Appeals affirmed the IURC Order. The Company does not expect similar issues related to updating future plan filings as the project inclusion process is now better understood by all parties.

Subsequent to the March 2016 Order, the Company has received additional Orders approving plan investments. On January 24, 2018, the IURC issued an order (January 2018 order) approving the inclusion in rates of investments made from January 2017 to June 2017. Through the January 2018 Order, approximately $369 million of the approved capital investment has been incurred and included for recovery. The January 2018 Order also approved the Company's plan update, which now totals $752 million through 2020. The plan increase is for additional investments related to pipeline safety and compliance requirements under Senate Bill 251.

In December 2016, PHMSA issued interim final rules related to integrity management for storage operations. Efforts are 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 task force. On August 3, 2017, the Company filed for authority to recover the associated costs using the mechanism allowed under Senate Bill 251. The request includes approximately $8 million of operating expenses and $9 million of capital investments over a four-year period beginning in 2018. The Company received the IURC Order approving the request for recovery on December 28, 2017.

At December 31, 2017 and December 31, 2016, the Company has regulatory assets related to the Plan totaling $61.6 million and $38.8 million, respectively.

Pipeline and Hazardous Materials Safety Administration (PHMSA)

In March 2016, PHMSA published a notice of proposed rulemaking (NOPR) 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 continues to evaluate the impact these proposed rules will have on its integrity management programs and transmission and distribution systems. Progress on finalizing the rule continues to work through the administrative process. The rule is expected to be finalized in 2019 and the Company believes the costs to comply with the new rules would be considered federally mandated and therefore should be recoverable under Senate Bill 251.

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

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 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, 2017 and 2016, approximately $1.4 million and $1.5 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,
	2017				2016
(In thousands)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt payable to third parties	$	96,000	$	122,027	$	96,000	$	121,423
Long-term debt payable to Utility Holdings	361,158		388,603		266,689		285,825
Short-term borrowings payable to Utility Holdings	391		391		84,741		84,741
Natural gas purchase instrument assets ⁽¹⁾	455		455		—		—
Natural gas purchase instrument liabilities ⁽²⁾	4,134		4,134		—		—
Cash & cash equivalents	4,048		4,048		4,307		4,307

⁽¹⁾ Presented in "Other investments" on the Consolidated Balance Sheets.

⁽²⁾ Presented in "Deferred credits & other liabilities" on the Consolidated Balance Sheets.

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 utility-related long-term debt are generally recovered in customer rates over the life of the refunding issue. Accordingly, any reacquisition of this debt would not be expected to have a material effect on the Company's results of operations.

The Company entered into two five-year forward purchase arrangements to hedge the variable price of natural gas for a portion of the Company’s gas supply. These arrangements, approved by the IURC, replaced normal purchase or normal sale long-term physical fixed-price purchases. The Company values these contracts using a pricing model that incorporates market-based information, and are classified within Level 2 of the fair value hierarchy. Gains and losses on these derivative contracts are deferred as regulatory liabilities or assets and are refunded to or collected from customers through the Company’s gas cost recovery mechanism.

11. Additional Balance Sheet & Operational Information

Inventories in the Consolidated Balance Sheets consist of the following:



	At December 31,
(In thousands)	2017		2016
Gas in storage - at LIFO cost	$	18,542	$	20,912
Materials & supplies	3,100		3,234
Other	1,277		1,300
Total inventories	$	22,919	$	25,446

Based on the average cost of gas purchased during December 2017 and 2016, the cost of replacing gas in storage carried at LIFO cost exceeded the carrying value at December 31, 2017 and 2016 by approximately $2 million and $4 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.

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



	At December 31,
(In thousands)	2017		2016
Prepaid gas delivery service	$	26,634	$	26,449
Prepaid taxes & other	608		388
Total prepayments & other current assets	$	27,242	$	26,837

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



	At December 31,
(In thousands)	2017		2016
Customer advances & deposits	$	28,438	$	27,624
Accrued taxes	22,004		8,907
Accrued interest	2,702		2,604
Tax collections payable	4,660		3,931
Accrued salaries & other	7,458		8,412
Total accrued liabilities	$	65,262	$	51,478

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



(In thousands)	2017			2016
Asset retirement obligation, January 1	$	30,427		$	25,898
Accretion	1,534			1,352
Changes in estimates, net of cash payments	(1,374		)	3,177
Asset retirement obligation, December 31	$	30,587		$	30,427

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



	Year Ended December 31,
(In thousands)	2017		2016
AFUDC - borrowed funds	$	1,910	$	2,680
AFUDC - equity funds	546		731
Other income	202		138
Total other income – net	$	2,658	$	3,549

Supplemental Cash Flow Information:



	Year Ended December 31,
(In thousands)	2017		2016
Cash paid (received) for:
Interest	$	20,305	$	19,553
Income taxes	7,875		(9,781		)

As of December 31, 2017 and 2016, the Company had accruals related to utility plant purchases totaling approximately $8.6 million and $6.6 million, respectively.

12. Adoption of Other Accounting Standards

Revenue Recognition

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 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). The Company plans to adopt the guidance under the modified retrospective method. The cumulative effect adjustment to retained earnings will be immaterial.

In July 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 has finalized the assessment process of all revenue streams for the standard’s impact on the Consolidated Balance Sheets, Consolidated Statements of Operations, and disclosures and has identified all material revenue streams. The Company has determined that all material revenue streams fall under the scope of the standard. The standard will result in no significant changes to the Company's pattern of revenue recognition. The Company has adopted 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 and will adopt the guidance effective January 1, 2019.

Stock Compensation

In March 2016, the FASB issued new accounting guidance intended to simplify several aspects of accounting for share-based payment transactions, including the income tax consequences. This ASU was effective for annual periods beginning after December 15, 2016, and interim periods therein. 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 adoption of this standard by the Company's parent did not have a material impact on the financial statements.

Presentation of Net Periodic Pension and Postretirement Benefit Costs

In March 2017, the FASB issued new accounting guidance to improve the presentation of net periodic pension and postretirement benefit costs. This ASU is effective for annual periods beginning after December 15, 2017, and relevant interim periods. This ASU requires the Company to report the service cost component incurred by Vectren and allocated to the Company in the same line items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost allocated to the Company are required to be presented in the income statement separately from the service cost component and outside of income from operations. Capitalization of net benefit cost is limited to only the service cost component of benefit costs, when applicable.

The ASU requires retrospective presentation of the service and non-service costs components in the income statement and prospective application regarding the capitalization of only the service cost component of net benefit costs. The Company has finalized its assessment of the standard and the adoption will have an immaterial impact on the financial statements. The Company has adopted the guidance effective January 1, 2018.

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 condition, 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 2017 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.

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.

Executive Summary of Results of Operations

Operating Results

In 2017, the Company had $55.7 million in net income compared to net income of $49.5 million in 2016. The increased earnings in 2017 are primarily due to increased returns on the gas infrastructure replacement program and large customer margins.

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)	2017		2016

Revenues	$	564,995	$	535,089
Cost of gas sold	231,408		228,788
Total margin	$	333,587	$	306,301
Margin attributed to:
Residential & commercial customers	$	260,864	$	243,630
Industrial customers	44,021		38,309
Other	5,008		4,147
Regulatory expense recovery mechanisms	23,694		20,215
Total margin	$	333,587	$	306,301
Sold & transported volumes in MDth attributed to:
Residential & commercial customers	58,022		57,562
Industrial customers	67,095		66,350
Total sold & transported volumes	125,117		123,912

Margins were $333.6 million for the year ended December 31, 2017, and compared to 2016, increased $27.3 million. The increase in margin was due to increased returns on the gas infrastructure replacement programs of $16.0 million, increased large customer margin of $4.8 million primarily from returns on a pipeline investment constructed to serve a new customer, increased regulatory expense recovery mechanisms of $3.5 million, and increased small customer count of $2.2 million. Weather has relatively no impact on customer margins due to the Company's rate design.

Operating Expenses

Other Operating

For the year ended December 31, 2017, Other operating expenses were $126.1 million, which is an increase of $6.5 million, compared to 2016. Excluding operating expenses recovered through margin, expenses increased $3.7 million, from increased labor expenses driven by headcount and higher performance-based compensation expense driven by the increase in the Company's stock price.

Depreciation & Amortization

For the year ended December 31, 2017, depreciation and amortization expense increased $7.8 million compared to 2016. The increase in 2016 resulted from additional utility plant investments placed into service.

SELECTED GAS OPERATING STATISTICS:



	For the Year Ended
	December 31,
	2017		2016

OPERATING REVENUES (In thousands):
Residential	$	378,473	$	360,637
Commercial	135,302		130,021
Industrial	46,211		40,219
Other	5,009		4,212
	$	564,995	$	535,089

MARGIN (In thousands):
Residential	$	202,195	$	189,234
Commercial	58,669		54,396
Industrial	44,021		38,309
Other	5,008		4,147
Regulatory expense recovery mechanisms	23,694		20,215
	$	333,587	$	306,301

GAS SOLD & TRANSPORTED (In MDth):
Residential	39,434		39,089
Commercial	18,588		18,473
Industrial	67,095		66,350
	125,117		123,912

AVERAGE CUSTOMERS:
Residential	540,013		534,315
Commercial	51,514		51,277
Industrial	957		950
	592,484		586,542

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